20-F 1 u06412e20vf.htm 20-F 

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549 

FORM 20-F 

(Mark One) 

OR

For the fiscal year ended 31 December 2008 

OR

OR

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) 

Dr Byron E Grote 

BP p.l.c. 1 St James’s Square, 

London SW1Y 4PD 

United Kingdom 

Tel +44 (0) 20 7496 4000 

Fax +44 (0) 20 7496 4630

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person) 

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

None

 REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g)

OF THE SECURITIES EXCHANGE ACT OF 1934

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

 

 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 

EXCHANGE ACT OF 1934

 SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES 

EXCHANGE ACT OF 1934

Title of each class Name of each exchange on which registered

Ordinary Shares of 25c each New York Stock Exchange*

4 7/8% Guaranteed Notes due 2010 New York Stock Exchange

Floating Rate Guaranteed Extendible Notes New York Stock Exchange

Floating Rate Guaranteed Notes due 2010 New York Stock Exchange

Substitute Floating Rate Guaranteed Notes due July 10 2009 New York Stock Exchange

Substitute Floating Rate Guaranteed Notes due October 9 2009 New York Stock Exchange

5.25% Guaranteed Notes due 2013 New York Stock Exchange

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

Exchange Commission

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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. 

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

Yes 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 

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 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): 

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: International 

Financial Reporting Standards as issued by the 

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has 

elected to follow. 

Item 17  Item 18 

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 

Ordinary Shares of 25c each 18,730,307,315

Cumulative First Preference Shares of £1 each 7,232,838

Cumulative Second Preference Shares of £1 each 5,473,414

Large accelerated filer Accelerated filer  Non-accelerated filer 

U.S. GAAP  International Accounting Standards Board Other 

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Cross reference to Form 20-F 

2 

Page

Item 1. Identity of Directors, Senior Management and Advisors n/a 

Item 2. Offer Statistics and Expected Timetable n/a

Item 3. Key Information

A. Selected financial data 6

B. Capitalization and indebtedness n/a

 C. Reasons for the offer and use of proceeds n/a 

D. Risk factors 8-10

Item 4. Information on the Company

A. History and development of the company 11-12

B. Business overview 13-45

 C. Organizational structure 45 

Appendix A to Item 4D 7, 16-18, 185-190, 192

D. Property, plants and equipment 45

Item 4A. Unresolved Staff Comments None

Item 5. Operating and Financial Review and Prospects

 A. Operating results 46-53 

B. Liquidity and capital resources 54

C. Research and development, patent and licenses 36,130

D. Trend information 54-55

E. Off-balance sheet arrangements 55-56

 F. Tabular disclosure of contractual commitments 56 

G. Safe harbour 10

Item 6. Directors, Senior Management and Employees 

A. Directors and senior management 62-64

B. Compensation 73-83, 170-171

 C. Board practices 61-71, 62, 81, 170-171 

D. Employees 44-45

 E. Share ownership 72, 79-80, 86-87, 166-170 

Item 7. Major Shareholders and Related Party Transactions

A. Major shareholders 87

 B. Related party transactions 88, 138-139 

C. Interests of experts and counsel n/a

Item 8. Financial Information 

A. Consolidated financial statements and other financial information 88-89, 99-193

B. Significant changes None

Item 9. The Offer and Listing 

A. Offer and listing details 89-90

 B. Plan of distribution n/a 

C. Markets 89-90

D. Selling shareholders n/a

 E. Dilution n/a 

F. Expenses of the issue n/a

Item 10. Additional Information 

A. Share capital n/a

B. Memorandum and articles of association 91-92

C. Material contracts None

D. Exchange controls 92

 E. Taxation 92-94 

F. Dividends and paying agents n/a

G. Statements by experts n/a

H. Documents on display 94

I. Subsidiary information n/a

Item 11. Quantitative and Qualitative Disclosures about Market Risk 140-145, 148-153 

Item 12. Description of securities other than equity securities n/a

Item 13. Defaults, Dividend Arrearages and Delinquencies None

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds 94

Item 15. Controls and Procedures 94-95

Item 16A. Audit Committee Financial Expert 95 

Item 16B. Code of Ethics 95

Item 16C. Principal Accountant Fees and Services 95

Item 16D. Exemptions from the Listing Standards for Audit Committees n/a

Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchases 97

Item 16G Corporate governance practices 95-96 

Item 17. Financial Statements n/a

Item 18. Financial Statements 16-18, 99-193

Item 19. Exhibits 98

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Contents 

 

 

5 Performance review

61 Board performance and biographies

73 Directors’ remuneration report

85 Additional information for 

shareholders

99 Financial statements

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Certain definitions 

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

Oil and natural gas reserves 

Oil and gas reserves 

Proved reserves are defined by the Securities and Exchange Commission (SEC) in Rule 410(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: 

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 shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. 

Proved reserves for other undrilled units can be 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 for proved undeveloped reserves attributable to any 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. 

4 

(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.

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Performance review 

 

 

6 Selected financial and operating 

information

8 Risk factors

10 Forward-looking statements

10 Statements regarding competitive 

position

11 Information on the company

13 Exploration and Production

27 Refining and Marketing

33 Other businesses and corporate

36 Research and technology

37 Regulation of the group's business

37 Safety

39 Environment

44 Employees

45 Social and community issues

45 Essential contracts

45 Property, plants and equipment

45 Organizational structure

46 Financial and operating performance

54 Liquidity and capital resources

57 Critical accounting policies

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Performance review

 

Selected financial and operating information 

Revised definition of net debt

6 

$ million except per share amounts

2008 2007 2006 2005 2004

Income statement data

Total revenuesa 365,700 288,951 270,602 243,948 194,919 

Profit before interest and taxation from continuing operationsa 35,239 32,352 35,658 32,182 25,746

Profit from continuing operationsa 21,666 21,169 22,626 22,133 17,884

Profit for the year 21,666 21,169 22,601 22,317 17,262

Profit for the year attributable to BP shareholders 21,157 20,845 22,315 22,026 17,075

Capital expenditure and acquisitionsb 30,700 20,641 17,231 14,149 16,651 

Per ordinary share – cents

Profit for the year attributable to BP shareholders

Basic 112.59 108.76 111.41 104.25 78.24

Diluted 111.56 107.84 110.56 103.05 76.87

Profit from continuing operations attributable to BP shareholdersa 

Basic 112.59 108.76 111.54 103.38 81.09

Diluted 111.56 107.84 110.68 102.19 79.66

Dividends paid per share – cents 55.05 42.30 38.40 34.85 27.70

– pence 29.387 20.995 21.104 19.152 15.251

Ordinary share datac

Average number outstanding of 25 cent ordinary shares (shares million undiluted) 18,790 19,163 20,028 21,126 21,821

Average number outstanding of 25 cent ordinary shares (shares million diluted) 18,963 19,327 20,195 21,411 22,293

Balance sheet data

Total assets 228,238 236,076 217,601 206,914 194,630

Net assets 92,109 94,652 85,465 80,450 78,235

Share capital 5,176 5,237 5,385 5,185 5,403

BP shareholders’ equity 91,303 93,690 84,624 79,661 76,892

Finance debt due after more than one year 17,464 15,651 11,086 10,230 12,907 

Net debt to net debt plus equityd 21% 22% 20% 17% 22%

aExcludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2004, 2005 and 2006.

b2008 included capital expenditure of $2,822 million and an asset exchange of $1,909 million, both in respect of our transaction with Husky, as well as capital expenditure of $3,667 million in respect of our transactions 

with Chesapeake (see page 47). 2007 included $1,132 million for the acquisition of Chevron’s Netherlands manufacturing company. Capital expenditure in 2006 included $1 billion in respect of our investment in 

Rosneft. Capital expenditure and acquisitions for 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. With the exception of the shares issued to Alfa Group and Access Renova (AAR) in connection with TNK-BP (2004-2006), all capital expenditure and acquisitions 

during the past five years have been financed from cash flow from operations, disposal proceeds and external financing.

cThe number of ordinary shares shown has been used to calculate per share amounts.

dNet debt and the ratio of net debt to net debt plus equity ratio are non-GAAP measures. We believe that these measures provide useful information to investors. Net debt enables investors to see the economic effect of 

gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. Net debt has been redefined to include the 

fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on 

the balance sheet within the headings ‘Derivative financial instruments’. Amounts for comparative periods are presented on a consistent basis. 

 $ million 

 2007 2006 2005 2004 

As reported 

Net debt 27,483 21,420 16,202 21,732

Equity 94,652 85,465 80,450 78,235

Ratio of net debt to net debt plus equity 23% 20% 17% 22% 

As amended

Net debt 26,817 21,122 16,373 21,732

Equity 94,652 85,465 80,450 78,235

Ratio of net debt to net debt plus equity 22% 20% 17% 22% 

This information, insofar as it relates to 2008, has been extracted or derived 

from the audited financial statements of the BP group presented on pages 99-

184. Note 1 to the Financial statements includes details on the basis of 

preparation of these financial statements. The selected information should be 

read in conjunction with the audited financial statements and related Notes 

elsewhere herein. 

BP sold its Innovene operations in December 2005. 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. 

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Production and net proved oil and natural gas reserves

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

Production and net proved reservesa

During 2008, 1,085 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 937mmboe, BP’s proved reserves for subsidiaries were 12,562mmboe at 31 

December 2008. These proved reserves are mainly located in the US (44%), Rest of Americas (17%), Asia Pacific (10%), Africa (11%) and the UK (8%). 

 For equity-accounted entities, 646mmboe were added to proved reserves (excluding purchases and sales), production was 491mmboe and proved reserves 

were 5,585mmboe at 31 December 2008. 

7

Performance review

2008f 2007 2006 2005 2004 

Crude oil production for subsidiaries (thousand barrels per day) 1,263 1,304 1,351 1,423 1,480

Crude oil production for equity-accounted entities (thousand barrels per day) 1,138 1,110 1,124 1,139 1,051

Natural gas production for subsidiaries (million cubic feet per day) 7,277 7,222 7,412 7,512 7,624 

Natural gas production for equity-accounted entities (million cubic feet per day) 1,057 921 1,005 912 879

Estimated net proved crude oil reserves for subsidiaries (million barrels)b 5,665 5,492 5,893 6,360 6,755

Estimated net proved crude oil reserves for equity-accounted entities (million barrels)c 4,688 4,581 3,888 3,205 3,179

Estimated net proved natural gas reserves for subsidiaries (billion cubic feet)d 40,005 41,130 42,168 44,448 45,650

Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet)e 5,203 3,770 3,763 3,856 2,857 

aCrude oil includes natural gas liquids (NGLs) and condensate. Production and proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the 

underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations. 

bIncludes 21 million barrels (20 million barrels at 31 December 2007 and 23 million barrels at 31 December 2006) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

c

Includes 216 million barrels (210 million barrels at 31 December 2007 and 179 million barrels at 31 December 2006) in respect of the 6.80% minority interest in TNK-BP (6.51% at 31 December 2007 and 6.29% at 31 

December 2006). 

dIncludes 3,108 billion cubic feet of natural gas (3,211 billion cubic feet at 31 December 2007 and 3,537 billion cubic feet at 31 December 2006) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

eIncludes 131 billion cubic feet (68 billion cubic feet at 31 December 2007 and 99 billion cubic feet at 31 December 2006) in respect of the 5.92% minority interest in TNK-BP (5.88% at 31 December 2007 and 7.77% at 

31 December 2006). 

fBP estimates proved reserves for reporting purposes in accordance with SEC rules and relevant guidance. As currently required, these proved reserve estimates are based on prices and costs as of the date the 

estimate is made. There was a rapid and substantial decline in oil prices in the fourth quarter of 2008 that was not matched by a similar reduction in operating costs by the end of the year. BP does not expect that these 

economic conditions will continue. However, our 2008 reserves are calculated on the basis of operating activities that would be undertaken were year-end prices and costs to persist.

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

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8 

Performance review

Risk factors 

We urge you to consider carefully the risks described below. If any of these 

risks 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 could lose all or part of your investment.

 In the current global financial crisis and uncertain economic 

environment, certain risks may gain more prominence either individually or 

when taken together. Oil and gas prices and margins are likely to remain lower 

than in recent times due to reduced demand; the impact of this situation will 

also depend on the degree to which producers reduce production. At the same 

time, governments will be facing greater pressure on public finances leading to 

the risk of increased taxation. These factors may also lead to intensified 

competition for market share and available margin, with consequential 

potential adverse effects on volumes. The financial and economic situation 

may have a negative impact on third parties with whom we do, or may do, 

business. Any of these factors may affect our results of operations, financial 

condition and liquidity. 

 If there is an extended period of constraint in the capital markets, with 

debt markets in particular experiencing lack of liquidity, at a time when cash 

flows from our business operations may be under pressure, this may impact 

our ability to maintain our long-term investment programme with a consequent 

effect on our growth rate, and may impact shareholder returns, including 

dividends and share buybacks, or share price. Decreases in the funded levels 

of our pension plans may also increase our pension funding requirements. 

 Our system of risk management provides the response to risks of group 

significance through the establishment of standards and other controls. 

Inability to identify, assess and respond to risks through this and other controls 

could lead to an inability to capture opportunities, threats materializing, 

inefficiency and non-compliance with laws and regulations. 

 The risks are categorized against the following areas: strategic; 

compliance and control; and operational. 

Strategic risks 

Access and renewal 

Successful execution of our group plan depends critically on implementing 

activities to renew and reposition our portfolio. The challenges to renewal of 

our upstream portfolio are growing due to increasing competition for access to 

opportunities globally. Lack of material positions in new markets and/or 

inability to complete disposals could result in an inability to grow or even 

maintain our production. 

Prices and markets 

Oil, gas and product prices are subject to international supply and demand. 

Political developments and the outcome of meetings of OPEC can particularly 

affect world supply and oil prices. Previous oil price increases have resulted in 

increased fiscal take, cost inflation and more onerous terms for access to 

resources. As a result, increased oil prices may not improve margin 

performance. In addition to the adverse effect on revenues, margins and 

profitability from any fall in oil and natural gas prices, a prolonged period of low 

prices or other indicators would lead to further reviews for impairment of the 

group’s oil and natural gas properties. Such reviews would reflect 

management’s view of long-term oil and natural gas prices and 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. Rapid material and/or 

sustained change in oil, gas and product prices can impact the validity of the 

assumptions on which strategic decisions are based and, as a result, the 

ensuing actions derived from those decisions may no longer be appropriate. A 

prolonged period of low oil prices may impact our ability to maintain our longterm investment programme with a consequent effect on our growth rate and 

may impact shareholder returns, including dividends and share buybacks, or 

share price. 

Periods of global recession could impact the demand for our products, the 

prices at which they can be sold and affect the viability of the markets in which 

we operate.

 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 a consequent effect on prices and profitability. 

Climate change and carbon pricing 

Compliance with changes in laws, regulations and obligations relating to 

climate change could result in substantial capital expenditure, reduced 

profitability from changes in operating costs, and revenue generation and 

strategic growth opportunities being impacted. 

Socio-political 

We have operations in countries where political, economic and social 

transition is taking place. Some countries have experienced political instability, 

changes to the regulatory environment, expropriation or nationalization of 

property, civil strife, strikes, acts of war and insurrections. Any of these 

conditions occurring could disrupt or terminate our operations, causing our 

development activities to be curtailed or terminated in these areas or our 

production to decline and could cause us to incur additional costs. In 

particular, our investments in Russia could be adversely affected by 

heightened political and economic environment 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. If it is perceived that we are not respecting or advancing the 

economic and social progress of the communities in which we operate, our 

reputation and shareholder value could be damaged. 

Competition 

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. The implementation of group strategy requires continued 

technological advances and innovation including advances in exploration, 

production, refining, petrochemicals manufacturing technology and advances 

in technology related to energy usage. Our performance could be impeded if 

competitors developed or acquired intellectual property rights to technology 

that we required or if our innovation lagged the industry. 

Investment efficiency 

Our organic growth is dependent on creating a portfolio of quality options and 

investing in the best options. Ineffective investment selection could lead to 

loss of value and higher capital expenditure. 

Reserves replacement 

Successful execution of our group strategy depends critically on sustaining 

long-term reserves replacement. If upstream resources are not progressed to 

proved reserves in a timely and efficient manner, we will be unable to sustain 

long-term replacement of reserves. 

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9

Performance review

Liquidity, financial capacity and financial exposure 

The group has established a financial framework to ensure that it is able to 

maintain an appropriate level of liquidity and financial capacity and to 

constrain the level of assessed capital at risk for the purposes of positions 

taken in financial instruments. Failure to operate within our financial framework 

could lead to the group becoming financially distressed leading to a loss of 

shareholder value. Commercial credit risk is measured and controlled to 

determine the group’s total credit risk. Inability to determine adequately our 

credit exposure could lead to financial loss. A credit crisis affecting banks and 

other sectors of the economy could impact the ability of counterparties to meet 

their financial obligations to the group. It could also affect our ability to raise 

capital to fund growth. 

 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 and revenues. 

 For more information on financial instruments and financial risk factors 

see Financial statements – Note 28 on page 140 and Note 34 on page 148. 

Compliance and control risks 

Regulatory 

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 and health and safety protection controls, controls over the 

development and decommissioning of a field (including restrictions on 

production) and, possibly, nationalization, expropriation, cancellation or nonrenewal of contract rights. We buy, sell and trade oil and gas products in 

certain regulated commodity markets. 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, or we 

could incur additional costs. 

 For more information on environmental regulation, see Environment on 

page 39. 

Ethical misconduct and non-compliance 

Our code of conduct, which applies to all employees, defines our commitment 

to integrity, compliance with all applicable legal requirements, high ethical 

standards and the behaviours and actions we expect of our businesses and 

people wherever we operate. Incidents of ethical misconduct or noncompliance with applicable laws and regulations could be damaging to our 

reputation and shareholder value. Multiple events of non-compliance could call 

into question the integrity of our operations. 

 For certain legal proceedings involving the group, see Legal 

proceedings on page 88. 

Liabilities and provisions 

Changes in the external environment, such as new laws and regulations, 

market volatility or other factors, could affect the adequacy of our provisions 

for pensions, tax, environmental and legal liabilities. 

Reporting 

External reporting of financial and non-financial data is reliant on the integrity 

of systems and people. Failure to report data accurately and in compliance 

with external standards could result in regulatory action, legal liability and 

damage to our reputation. 

Operational risks 

Process safety 

Inherent in our operations are hazards that require continuous oversight and 

control. There are risks of technical integrity failure and loss of containment of 

hydrocarbons and other hazardous material at operating sites or pipelines. 

Failure to manage these risks could result in injury or loss of life, 

environmental damage, or loss of production and could result in regulatory 

action, legal liability and damage to our reputation. 

Personal safety 

Inability to provide safe environments for our workforce and the public could 

lead to injuries or loss of life and could result in regulatory action, legal liability 

and damage to our reputation. 

Environmental 

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, we could fail to live up to our aspirations of no or minimal 

damage to the environment and contributing to human progress. 

Security 

Security threats require continuous oversight and control. Acts of terrorism 

against our plants and offices, pipelines, transportation or computer systems 

could severely disrupt business and operations and could cause harm to 

people. 

Product quality 

Supplying customers with on-specification products is critical to maintaining 

our licence to operate and our reputation in the marketplace. Failure to meet 

product quality standards throughout the value chain could lead to harm to 

people and the environment and loss of customers. 

Drilling and production 

Exploration and production require high levels of investment and 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. 

Transportation 

All modes of transportation of hydrocarbons contain inherent risks. A loss of 

containment of hydrocarbons and other hazardous material could occur during 

transportation by road, rail, sea or pipeline. This is a significant risk due to the 

potential impact of a release on the environment and people and given the 

high volumes involved. 

Major project delivery 

Successful execution of our group plan (see page 11) depends critically on 

implementing the activities to deliver the major projects over the plan period. 

Poor delivery of any major project that underpins production growth and/or a 

major programme designed to enhance shareholder value could adversely 

affect our financial performance. 

Digital infrastructure 

The reliability and security of our digital infrastructure are critical to maintaining 

our business applications availability. A breach of our digital security could 

cause serious damage to business operations and, in some circumstances, 

could result in injury to people, damage to assets, harm to the environment 

and breaches of regulations. 

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Business continuity and disaster recovery 

Contingency plans are required to continue or recover operations following a 

disruption or incident. Inability to restore or replace critical capacity to an 

agreed level within an agreed timeframe would prolong the impact of any 

disruption and could severely affect business and operations. 

Crisis management 

Crisis management plans and capability are essential to deal with 

emergencies at every level of our operations. If we do not respond or are 

perceived not to respond in an appropriate manner to either an external or 

internal crisis, our business and operations could be severely disrupted. 

People and capability 

Employee training, development and successful recruitment of new staff, in 

particular petroleum engineers and scientists, are key to implementing our 

plans. Inability to develop the human capacity and capability across the 

organization could jeopardize performance delivery.

Treasury and trading activities 

In the normal course of business, we are subject to operational risk around our 

treasury and trading activities. Control of these activities is highly dependent 

on our ability to process, manage and monitor a large number of complex 

transactions across many markets and currencies. Shortcomings or failures in 

our systems, risk management methodology, internal control processes or 

people could lead to disruption of our business, financial loss, regulatory 

intervention or damage to our reputation. 

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’, ‘aims’, ‘should’, 

‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar 

expressions. In particular, among other statements, (i) certain statements in 

Performance review (pages 6-56) with regard to strategy, management aims 

and objectives, future capital expenditure, future hydrocarbon production 

volume, date(s) or period(s) in which production is scheduled or expected to 

come onstream or a project or action is scheduled or expected to begin or be 

completed, capacity of planned plants or facilities and impact of health, safety 

and environmental regulations; (ii) the statements in Performance review 

(pages 6-45) with regard to planned expansion, investment or other projects 

and future regulatory actions; and (iii) the statements in Performance review 

(pages 46-59) with regard to the plans of the group, the cost of and provision 

for future remediation programmes, taxation, liquidity and costs for providing 

pension and other post-retirement benefits; and including under ‘Liquidity and 

capital resources’ with regard to oil prices, production, demand for refining 

products, refining volumes and margins and impact on the petrochemicals 

sector, refining availability, continuing priority of safe, compliant and reliable 

operations, and focus on cost efficiency, cost deflation, capital expenditure, 

expected disposal proceeds, cash flows, shareholder distributions, gearing, 

working capital, guarantees, expected payments under contractual and 

commercial commitments and purchase obligations; 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 onstream; 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’ on pages 8-10. In addition to factors set forth 

elsewhere in this report, those set out 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 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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Information on the company 

General 

Unless otherwise indicated, information in this document reflects 100% of the 

assets and operations of the company and its subsidiaries that were 

consolidated at the date or for the periods indicated, including minority 

interests. Also, unless otherwise indicated, figures for total revenues include 

sales between BP businesses.

 The company was incorporated in 1909 in England and Wales and 

changed its name to BP p.l.c. in 2001. 

 BP is one of the world’s leading oil companies on the basis of market 

capitalization and proved reserves. Our worldwide headquarters is located at 1 

St James’s Square, London SW1Y 4PD, UK, tel +44 (0)20 7496 4000. Our 

agent in the US is BP America Inc., 501 Westlake Park Boulevard, Houston, 

Texas 77079, tel +1281 366 2000. 

Overview of the group 

 BP is a global group, with interests and activities held or operated 

through subsidiaries, jointly controlled entities or associates established in, 

and subject to the laws and regulations of, many different jurisdictions. These 

interests and activities covered two business segments in 2008: Exploration 

and Production and Refining and Marketing. With effect from 1 January 2008, 

the former Gas, Power and Renewables segment ceased to report separately 

(see Resegmentation in 2008 on page 12). 

 A separate business, Alternative Energy, reported in Other businesses 

and corporate, handles BP’s low-carbon businesses and future growth options 

outside oil and gas. 

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), as well 

as the marketing and trading of natural gas (including LNG), power and 

natural gas liquids (NGLs). The activities of Refining and Marketing include the 

refining, manufacturing, supply and trading, marketing and transportation of 

crude oil, petroleum and petrochemicals products and related services. The 

group provides high-quality technological support for all its businesses through 

its research and engineering activities. 

 All these activities are supported by a number of other organizational 

elements comprising group functions and regions. Group functions serve the 

business segments, aiming to achieve coherence across the group, manage 

risks effectively and achieve economies of scale. In addition, each regional 

head provides the required integration and co-ordination of group activities 

and represents BP to external parties. 

Internal control 

The group’s system of internal control is designed to meet the expectations of 

internal control of the Combined Code in the UK and of COSO (committee of 

the sponsoring organizations for the Treadway Commission) in the US. The 

system of internal control is the complete set of management systems, 

organizational structures, processes, standards and behaviours that are 

employed to conduct the business of BP and deliver returns to shareholders. 

The design of the system of internal control addresses risks and how to 

respond to them. Each component of the system is in itself a device to 

respond to a particular type or collection of risks. 

Strategy 

The group strategy describes the group’s strategic objectives and the 

assumptions made by BP about the future. It describes strategic risks and 

opportunities that arise from making such assumptions and the actions to be 

taken to manage or mitigate the risks. The board delegates to the group chief 

executive responsibility for developing BP’s strategy and its implementation 

through the group plan that determines the setting of priorities and allocation 

of resources. The group chief 

executive is obliged to discuss with the board, on the basis of the strategy and 

group plan, all material matters currently or prospectively affecting BP’s 

performance 

 During 2008, we continued to pursue our three strategic priorities of 

‘Safety’, ‘People’ and ‘Performance’, which underpin BP’s ‘forward agenda’. 

 Through this, we have taken steps to restore revenues, reduce 

complexity and manage costs and have made significant progress towards 

closing the competitive performance gap to our peer group. Looking forward, 

our strategy is to create value for shareholders by investing to deliver growth 

in Exploration and Production, together with high-quality earnings and returns 

throughout our operations. Our first priority will always be to ensure the safety 

and integrity of our operations. 

 We expect Exploration and Production to be our core source of growth. 

We intend to re-invest competitively in Exploration and Production to secure 

and grow high-quality oil and gas resources. This investment is intended to be 

focused on strengthening our position further by securing new access and 

achieving exploration success. It is also intended to be targeted on a renewed 

focus on increasing recovery from fields in which we already operate. We 

expect to make investment across the full life cycle of our assets with an 

increased emphasis on technology as a source of productivity, access and 

competitive advantage. 

 In Refining and Marketing, we expect to continue building our business 

around advantaged assets in material and significant energy markets. We 

intend to continue investing in improving the safety and reliability of our 

operations. Additionally, we intend to drive further operational performance 

and productivity by investing in the upgrade of manufacturing capabilities 

within our integrated fuels value chains. We also intend to invest selectively in 

international businesses, including lubricants and petrochemicals, where we 

believe there is the potential to deliver strong returns. 

 In Alternative Energy, we are focusing our investment activity in new 

energy technology and low-carbon energy businesses that we believe will 

provide long-term options to meet energy demand and provide BP with 

significant long-term growth potential. These are wind, solar, biofuels and 

carbon capture and storage. 

 We are dependent on our people and technology to deliver on our 

strategy. We intend to invest in ensuring that we have people with the right 

capability and experience to meet all of our objectives and the technology to 

support the delivery of competitive business performance and new business 

development. BP is committed to delivering its strategy by operating safely, 

reliably, in compliance with the law and within the discipline of a clear financial 

framework. 

Geographical presence 

We have well-established operations in Europe, the US, Canada, Russia, 

South America, Australasia, Asia and parts of Africa. Currently, around 67% of 

the group’s capital is invested in Organisation for Economic Cooperation and 

Development (OECD) countries, with around 41% of our fixed assets located 

in the US and around 20% located in Europe. 

 We believe that BP has a strong portfolio of assets: 

• In Exploration and Production, we have upstream interests in 29 countries. 

Exploration and Production activities are managed through operating units 

that are accountable for the day-to-day management of the segment’s 

activities. An operating unit is accountable for one or more fields. Our current 

areas of major development include the deepwater Gulf of Mexico, 

Azerbaijan, Algeria, Angola, Egypt and Asia Pacific where we believe we 

have competitive advantage and the foundation for volume growth and 

improved margins in the future. We also have significant midstream activities 

to support our upstream interests. Additionally, we undertake natural gas, 

power and NGLs marketing and trading activity and LNG activity, which are 

focused on identifying and capturing worldwide opportunities for our 

upstream natural gas reserves, and we have an NGLs processing business 

in North America.

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Through non-US subsidiaries or other non-US entities, during the period 

covered by this report, BP conducted limited marketing, licensing and trading 

activities in, or with persons from, certain countries identified by the US 

Department of State as State Sponsors of Terrorism. BP believes that these 

activities are immaterial to the group. 

BP has interests in, and is the operator of, two fields and a pipeline located 

outside Iran in which the National Iranian Oil Company (NIOC) and an 

affiliated entity have interests. In Iran, BP buys small quantities of crude oil. 

This is primarily for sale to third parties in Europe and a small portion is used 

by BP in its own refineries in South Africa and Europe. In addition, BP sells 

small quantities of crude oil into Iran and blends and markets small quantities 

of lubricants for sale to domestic consumers through a joint venture there, 

which has a blending facility. However, BP does not seek to obtain from the 

government of Iran licences or agreements for oil and gas projects in Iran, is 

not conducting any technical studies in Iran and does not own or operate any 

refineries or chemicals plants in Iran. 

 BP sells small quantities of lubricants in Cuba through a 50/50 joint venture 

there. In Syria, small quantities of lubricants are sold through a distributor and 

BP obtains small volumes of crude oil supplies for sale to third parties in 

Europe. In addition, BP sells small quantities of crude oil into Syria. These 

sales and purchases are insignificant and BP does not provide other goods, 

technologies or services in these countries. 

Market context 

Our market is a complex and fast-moving environment. In 2008, volatile 

energy price movements mirrored unsettled financial markets and wider 

economic uncertainty (see Risk factors on page 8). World oil consumption fell 

in 2008, with growing demand in fast growing non-OECD countries more than 

offset by falling consumption in the OECD countries. Gas consumption grew in 

the major markets. Anxieties around energy security continued, with individual 

consumer countries facing specific issues related to cost, geography and 

political relationships with producers. In terms of supply, substantial global 

reserves of oil and gas are in place but government, energy companies and 

industry must work together to bring these to market. There is also a clear 

need for greater energy diversity to address the competing challenges of 

growing demand and climate change. In terms of human resources, the 

energy industry also faces a shortage of professionals such as petroleum 

engineers and scientists. 

• In Refining and Marketing, we have a strong presence in the US and 

Europe. In the US, we market under the Amoco and BP brands in the 

midwest, east and south-east and under the ARCO brand on the west coast, 

and in Europe, under the BP and Aral brands. We have a long-established 

supply and trading activity responsible for delivering value across the crude 

and oil products supply chain. Our Aromatics & 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 and 

Castrol brands, including a strong global lubricants portfolio and other 

business-to-business marketing businesses (aviation and marine) covering 

the mobility sectors. We continue to seek opportunities to broaden our 

activities in growth markets such as China and India.

Acquisitions and disposals

There were no significant acquisitions in 2006, 2007 or 2008. 

 In 2008, we completed an asset exchange with Husky Energy Inc., and 

asset purchases from Chesapeake Energy Corporation as described on page 

47. 

 In 2007, BP acquired Chevron’s Netherlands manufacturing company, 

Texaco Raffiniderij Pernis B.V. The acquisition included Chevron’s 31% 

minority shareholding in Nerefco, its 31% shareholding in the 22.5MW wind 

farm co-located at the refinery as well as a 22.8% shareholding in the TEAM 

joint venture terminal and shareholdings in two local pipelines linking the 

TEAM terminal to the refinery. Disposal proceeds were $4,267 million, which 

included $1,903 million from the sale of the Coryton refinery and $605 million 

from the sale of our exploration and production gas infrastructure business in 

the Netherlands. 

 In 2006, BP purchased 9.6% of the shares issued under Rosneft’s IPO 

for a consideration of $1 billion (included in capital expenditure). This 

represented an interest of around 1.4% in Rosneft. Disposal proceeds were 

$6,254 million, which included $2.1 billion on the sale of our interest in the 

Shenzi discovery and around $1.3 billion from the sale of our producing 

properties on the Outer Continental Shelf of the Gulf of Mexico to Apache 

Corporation. 

Resegmentation in 2008 

On 11 October 2007, BP announced that it was to simplify its organizational 

structure by reducing the number of business segments. 

 From 1 January 2008, BP has two business segments: Exploration and 

Production and Refining and Marketing. A separate business, Alternative 

Energy, handles BP’s low-carbon businesses and future growth options 

outside oil and gas and reports under Other businesses and corporate. 

 As a result, and with effect from 1 January 2008: 

• The former Gas, Power and Renewables segment ceased to report 

separately.

• The NGLs, LNG and gas and power marketing and trading businesses were 

transferred from the Gas, Power and Renewables segment to the 

Exploration and Production segment.

• The Alternative Energy business was transferred from the Gas, Power and 

Renewables segment to Other businesses and corporate.

• The Emerging Consumers Marketing Unit was transferred from Refining and 

Marketing to Alternative Energy (which is reported in Other businesses and 

corporate).

• The Biofuels business was transferred from Refining and Marketing to 

Alternative Energy (which is reported in Other businesses and corporate).

• The Shipping business was transferred from Refining and Marketing to Other 

businesses and corporate.

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Exploration and Production 

Our Exploration and Production segment includes upstream and midstream 

activities in 29 countries, including Angola, Azerbaijan, Canada, Egypt, 

Russia, Trinidad & Tobago (Trinidad), the UK, the US and locations within 

Asia Pacific, Latin America, North Africa and the Middle East, as well as gas 

marketing and trading activities, primarily in Canada, Europe, the UK and the 

US. Upstream activities involve oil and natural gas exploration and field 

development and production. Our exploration programme is currently focused 

around Algeria, Angola, Azerbaijan, Canada, Egypt, the deepwater Gulf of 

Mexico, Libya, the North Sea and onshore US. Major development areas 

include Algeria, Angola, Asia Pacific, Azerbaijan, Egypt and the deepwater 

Gulf of Mexico. During 2008, production came from 21 countries. The principal 

areas of production are Angola, Asia Pacific, Azerbaijan, Egypt, Latin America, 

the Middle East, Russia, Trinidad, the UK and the US. 

 Midstream activities involve the ownership and management of crude oil 

and natural gas pipelines, processing facilities and export terminals, LNG 

processing facilities and transportation, and our NGL extraction businesses in 

the US and UK. Our most significant midstream pipeline interests are the 

Trans-Alaska Pipeline System in the US, 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. Major LNG activities are located in Trinidad, Indonesia 

and Australia. BP is also investing in the LNG business in Angola. 

 Additionally, our activities include the marketing and trading of natural 

gas, power and natural gas liquids in the US, Canada, UK and Europe. These 

activities provide routes into liquid markets for BP’s gas and power, and 

generate margins and fees associated with the provision of physical and 

financial products to third parties and additional income from asset 

optimization and trading. 

 Our oil and natural gas production assets are located onshore and 

offshore and include wells, gathering centres, in-field flow lines, processing 

facilities, storage facilities, offshore platforms, export systems (e.g. transit 

lines), pipelines and LNG plant facilities. 

 Upstream operations in Argentina, Bolivia, Abu Dhabi, Kazakhstan and 

TNK-BP and some of the Sakhalin operations in Russia, as well as some of 

our operations in Canada, Indonesia and Venezuela, are conducted through 

equity-accounted entities. 

Our performance in 2008 

Profit before interest and tax for 2008 was $37.9 billion, an increase of 37% 

compared with 2007. The increase was primarily driven by higher oil and gas 

realizations. Our financial results are discussed in more detail on pages 48-49.

 In 2008, nine major projects came onstream. Production commenced at 

the Thunder Horse field, with four wells in operation by the end of the year, 

producing around 200,000boe/d (gross) making us the largest producer in the 

Gulf of Mexico. We also started oil production on our Deepwater Gunashli 

platform in the Azerbaijan sector of the Caspian Sea. Other significant 

successes included the start of oil and gas production at the Saqqara and 

Taurt fields in Egypt. Production from our established centres including the 

North Sea, Alaska, North America Gas and Trinidad & Tobago, was on plan. 

We are also increasing our ability to get more from fields by improving our 

overall recovery rates through developing and applying new technology. 

In terms of the continued renewal of our oil and natural gas resource base, 

2008 was one of our best years this decade for new discoveries. 

 Total capital expenditure including acquisitions in 2008 was $22.2 billion 

(2007 $14.2 billion and 2006 $13.3 billion). In 2008, there were no significant 

acquisitions. Capital expenditure included $2.8 billion relating to the formation 

of an integrated North American oil sands business with Husky Energy Inc. It 

also included $3.7 billion relating to the purchase of all Chesapeake Energy 

Corporation’s interest in the Woodford Shale assets in the Arkoma basin, and 

the purchase of a 25% interest in Chesapeake’s Fayetteville Shale assets, 

enabling further growth of our North American gas business. 

 There were no significant acquisitions in 2006 and 2007. Capital 

expenditure in 2006 included our investment of $1 billion in Rosneft. 

 Development expenditure incurred in 2008, excluding midstream 

activities, was $11,767 million, compared with $10,153 million in 2007 and 

$9,109 million in 2006. 

 Looking ahead, our priorities remain the same: safety, people and 

performance. We will continue to strive to deliver safe, reliable and efficient 

operations while maintaining our flexibility so we can respond to oil price 

volatility. 

 In 2009, oil and gas prices are expected to be significantly lower than 

2008. In response we will aim to use the operational momentum generated in 

2008 to continue to increase the efficiency of our cost base and to build 

capability for the future. We intend to retain our rigour around capital 

investment, in particular pacing our development to take advantage of any 

cost reductions in a deflationary environment, and supporting our strategy of 

growing the upstream business. We believe that our portfolio of assets is 

strong and is well positioned to compete and grow in a range of external 

conditions. 

 Comparative information presented in the table on the following page 

has been restated, where appropriate, to reflect the resegmentation, following 

transfers of certain businesses between segments, that was effective from 1 

January 2008. See page 12 for more details. 

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Key statistics 

Total revenues are analysed in more detail below. 

$ million

2008 2007 2006

Total revenuesa 89,902 69,376 71,868

Profit before interest and tax from continuing 

operationsb 37,915 27,729 30,953 

Total assets 136,665 125,736 124,803

Capital expenditure and acquisitions 22,227 14,207 13,252

 

million barrels of oil equivalent

Net proved reserves – group 12,562 12,583 13,163

Net proved reserves – equity-accounted 

entities 5,585 5,231 4,537 

thousand barrels per day

Liquids production – group 1,263 1,304 1,351

Liquids production – equity-accounted 1,138 1,110 1,124 

 entities

million cubic feet per day

Natural gas production – group 7,277 7,222 7,412 

Natural gas production – equity-accounted 

entities 1,057 921 1,005

 

$ per barrel

Average BP crude oil realizationsc 95.43 69.98 61.91

Average BP NGL realizationsc 52.30 46.20 37.17

Average BP liquids realizationsc d 90.20 67.45 59.23 

Average West Texas Intermediate oil price 100.06 72.20 66.02

Average Brent oil price 97.26 72.39 65.14 

 

$ per thousand cubic feet

Average BP natural gas realizationsc 6.00 4.53 4.72

Average BP US natural gas 6.77 5.43 5.74

realizationsc

$ per million British thermal units

Average Henry Hub gas pricee 9.04 6.86 7.24

 

pence per therm

Average UK National Balancing Point gas price 58.12 29.95 42.19

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

cRealizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted 

entities. 

dCrude oil and natural gas liquids.

eHenry Hub First of Month Index.

 

$ million

2008 2007 2006

Sales and other operating revenues 86,170 65,740 67,950

Earnings from equity-accounted entities (after 

interest and tax), interest and other revenues 3,732 3,636 3,918 

 89,902 69,376 71,868 

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, excluding lease acquisitions, in 

2008 were $2,290 million, compared with $1,892 million in 2007 and 

$1,765 million in 2006. 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. Approximately 51% of 2008 exploration and appraisal costs were 

directed towards appraisal activity. In 2008, we participated in 83 gross (34 

net) exploration and appraisal wells in 11 countries. The principal areas of 

activity were Algeria, Angola, Azerbaijan, Canada, Egypt, the deepwater Gulf 

of Mexico, Libya, the North Sea and onshore US. 

 Total exploration expense in 2008 of $882 million (2007 $756 million 

and 2006 $1,045 million) included the write-off of expenses related to 

unsuccessful drilling activities in Azerbaijan ($105 million), Faeroes 

($83 million), Egypt ($64 million), deepwater Gulf of Mexico ($38 million), and 

others ($33 million). 

 In 2008, we obtained upstream rights in several new tracts, which 

include the following: 

In 2008, we were involved in a number of discoveries. In most cases, reserves 

bookings from these fields will depend on the results of ongoing technical and 

commercial evaluations, including appraisal drilling. Our most significant 

discoveries in 2008 included the following: 

Reserves and production 

Compliance 

IFRS does not provide specific guidance on reserves disclosures. 

BP estimates proved reserves in accordance with SEC Rule 4-10 (a) of 

Regulation S-X and relevant guidance notes and letters issued by the SEC 

staff. As currently required, these proved reserve estimates are based on 

prices and costs as of the date the estimate is made. 

 On 31 December 2008, the SEC published a revised set of rules for the 

estimation of reserves. These revised rules will be used for the 2009 year-end 

estimation of reserves, and have not been used in the determination of 

reserves for year-end 2008. 

 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, changes in operating and development costs 

and the continued availability of additional development capital. 

• In the Gulf of Mexico, we were awarded 125 blocks through the Outer 

Continental Shelf Lease Sales 205, 206 and 207.

• In the US Lower 48 states, we acquired 225,000 net acres of shale gas 

assets from Chesapeake Energy Corporation.

• In Canada, BP acquired three licences, covering a total of approximately 

6,000 square kilometres in the Canadian Beaufort Sea.

• In India, BP acquired one block on the East Coast in the New Exploration 

Licensing Policy seventh round.

• In Angola, we made further discoveries in the ultra deepwater (greater than 

1,500 metres) Block 31 (BP 26.7% and operator) with the Portia and Dione 

wells, bringing the total number of discoveries in Block 31 to 16.

• In Algeria, we discovered natural gas in the Tin Zaouatene-1 well in the 

Bourarhet Sud Blocks 230 and 231 (BP 49% and operator).

• In Egypt, we made a discovery with the Satis (BP 50% and operator) well.

• In the UK, we made two discoveries with the South West Foinaven (BP 72% 

and operator) and the Kinnoull (BP 77% and operator) wells.

• In the deepwater Gulf of Mexico, we made two discoveries with the Kodiak 

(BP 63.75% and operator) and Freedom (BP 25% and operator) wells.

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All the group’s oil and gas reserves held in consolidated companies have been 

estimated by the group’s petroleum engineers. Of the equity-accounted 

volumes in 2008, 18% were based on estimates prepared by group petroleum 

engineers and 82% were based on estimates prepared by independent 

engineering consultants, although all of the group’s oil and gas reserves held 

in equity-accounted entities are reviewed by the group’s petroleum engineers 

before making the assessment of volumes to be booked by BP. 

 Our proved reserves are associated with both concessions (tax and 

royalty arrangements) and agreements where the group is exposed to the 

upstream risks and rewards of ownership, but where title to the hydrocarbons 

is not conferred, such as production-sharing agreements (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. Sixteen per cent of 

our proved reserves are associated with PSAs. The main countries in which 

we operate under PSAs are Algeria, Angola, Azerbaijan, Egypt, Indonesia and 

Vietnam. 

 We separately disclose our share of reserves held in equity-accounted 

entities (jointly controlled entities and associates), although we do not control 

these entities or the assets held by such entities. 

Resource progression 

BP manages its hydrocarbon resources in three major categories: prospect 

inventory, non-proved resources and proved reserves. When a discovery is 

made, volumes usually 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 typically 

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, typically within three years. Where, on occasion, the group 

decides to book reserves where development is scheduled to commence after 

three years, these reserves will be booked only where they satisfy the SEC’s 

criteria for attribution of proved status. 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 of PUD reserves 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. 

Governance 

BP’s centrally controlled process for proved reserves estimation approval 

forms part of a holistic and integrated system of internal control. It consists of 

the following elements: 

• Accountabilities of certain officers of the group to ensure that there is review 

and approval of proved reserves bookings independent of the operating 

business and that there are effective controls in the approval process and 

verification that the proved reserves estimates and the related financial 

impacts are reported in a timely manner.

For the executive directors and senior management, no specific portion of 

compensation bonuses is directly related to oil and natural gas reserves 

targets. Additions to proved reserves is one of several indicators by which the 

performance of the Exploration and Production segment is assessed by the 

remuneration committee for the purposes of determining compensation 

bonuses for the executive directors. 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 segment is based on individual performance 

contracts. Individual performance contracts are based on agreed items from 

the business performance plan, one of which, if chosen, could relate to oil and 

gas reserves. 

Reserve replacement 

Total hydrocarbon proved reserves, on an oil equivalent basis and excluding 

equity-accounted entities, comprised 12,562mmboe at 31 December 2008, a 

decrease of 0.2% compared with 31 December 2007. Natural gas represents 

about 55% of these reserves. The decrease includes a net decrease from 

acquisitions and divestments of 169mmboe, largely comprising a number of 

assets in Venezuela and the US. 

 Total hydrocarbon proved reserves, on an oil equivalent basis for 

equity-accounted entities alone, comprised 5,585mmboe at 31 

December 2008, an increase of 6.8% compared with 31 December 2007. 

Natural gas represents about 16% of these proved reserves. The increase 

includes a net increase from acquisitions and divestments of 199mmboe, 

largely comprising a number of assets in Venezuela. The proved reserves 

replacement ratio (also known as the production replacement ratio) is the 

extent to which production is replaced by proved reserves additions. This ratio 

is expressed in oil equivalent terms and includes changes resulting from 

revisions to previous estimates, improved recovery and extensions and 

discoveries, and may be expressed as a replacement ratio excluding 

acquisitions and divestments or as a total replacement ratio including 

acquisitions and divestments. 

 BP estimates proved reserves for reporting purposes in accordance with 

SEC rules and relevant guidance. As currently required, these proved reserve 

estimates are based on prices and costs as of the date the estimate is made. 

There was a rapid and substantial decline in oil prices in the fourth quarter of 

2008 that was not matched by a similar reduction in operating costs by the 

end of the year. BP does not expect that these economic conditions will 

continue. However, our 2008 reserves are calculated on the basis of operating 

activities that would be undertaken were year-end prices and costs to persist. 

• 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.

• 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.

• Approval hierarchy, whereby proved reserves changes above certain 

threshold volumes require central authorization and periodic reviews. 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.

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Performance review

In 2008, net additions to the group’s proved reserves (excluding sales and 

purchases of reserves-in-place and equity-accounted entities) amounted to 

1,085mmboe, principally through improved recovery from, and extensions to, 

existing fields and discoveries of new fields. Of the reserves additions through 

improved recovery from, and extensions to, existing fields and discoveries of 

new fields, approximately half are associated with new projects and are 

proved undeveloped reserves additions. The remainder are in existing 

developments where they represent a mixture of proved developed and 

proved undeveloped reserves. The principal reserves additions were in the US 

(Arkoma, Thunder Horse, Wamsutter), Trinidad (Mango), Asia-Pacific 

(Tangguh), Angola (Plutão, Saturno, Vênus and Marte, and Angola LNG) and 

Azerbaijan (ACG). 

Production 

Our total hydrocarbon production during 2008 averaged 2,517 thousand 

barrels of oil equivalent per day (mboe/d) for subsidiaries and 1,321mboe/d for 

equity-accounted entities, a decrease of 1.2% and an increase of 4.0% 

respectively compared with 2007. For subsidiaries, 36% of our production was 

in the US and 12% in the UK. For equity-accounted entities, 70% of production 

was from TNK-BP. 

 Total production is expected to be somewhat higher in 2009. The actual 

growth rate will depend on a number of factors, including our pace of capital 

spending, the efficiency of that spend (in turn depending on industry cost 

deflation), the oil price and its impact on PSAs as well as OPEC quota 

restrictions. 

 The following tables show BP’s estimated net proved reserves as at 31 

December 2008. 

 % 

2008 2007 2006 

Proved reserves replacement ratio, excluding 

equity-accounted entities 116 44 34

Proved reserves replacement ratio, excluding 

equity-accounted entities, including sales and 

purchases of reserves-in-place 98 38 11

Proved reserves replacement ratio, for equityaccounted entities 132 248 272

Proved reserves replacement ratio, for equityaccounted entities, including sales and 

purchases of reserves-in-place 172 248 239

 

million barrels of oil equivalent

Additions to proved developed reserves, 

excluding equity-accounted entities, including 

sales and purchases of reserves-in-placea 826 929 675

Additions to proved developed reserves, for 

equity-accounted entities, including sales and 

purchases of reserves-in-placea 751 473 936

%

Proved developed reserves replacement ratio, 

excluding equity-accounted entities, including 

sales and purchases of reserves-in-place 88 99 70

Proved developed reserves replacement ratio, for 

equity-accounted entities, including sales and 

purchases of reserves-in-place 153 101 195

aThis includes some reserves that were previously classified as proved undeveloped.

Estimated net proved reserves of liquids at 31 December 2008a b c

Estimated net proved reserves of natural gas at 31 December 2008a b c

Net proved reserves on an oil equivalent basis 

million barrels

Developed Undeveloped Total

UK 410 119 529

Rest of Europe 81 194 275

US 1,717 1,273 2,990d

Rest of Americas 58 56 114e

Asia Pacific 77 69 146

Africa 464 496 960

Russia – – –

Other 174 477 651

Group 2,981 2,684 5,665

Equity-accounted entities 3,125 1,563 4,688f

billion cubic feet

Developed Undeveloped Total

UK 1,822 582 2,404

Rest of Europe 61 402 463

US 9,059 5,473 14,532

Rest of Americas 3,975 7,902 11,877g

Asia Pacific 2,482 4,275 6,757

Africa 1,050 1,382 2,432

Russia – – –

Other 507 1,033 1,540

Group 18,956 21,049 40,005

Equity-accounted entities 3,234 1,969 5,203h

mmboe

Developed Undeveloped Total

Group 6,249 6,313 12,562

Equity-accounted entities 3,683 1,902 5,585

aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty 

owner has a direct interest in the underlying production and the option and ability to make lifting and 

sales arrangements independently, 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.

bIn 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 analogous 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 shortterm flow test. Historically, proved reserves recorded using these methods have been validated by 

actual production levels. As at the end of 2008, BP had proved reserves in 20 fields in the deepwater 

Gulf of Mexico that had been initially booked prior to production flow testing. Of these fields, 18 are in 

production and two, Dorado and Great White, are expected to begin production in 2009. Six other fields 

are in the early stages of appraisal and development. 

cThe 2008 year-end marker prices used were Brent $36.55/bbl (2007 $96.02/bbl and 2006 $58.93/bbl) 

and Henry Hub $5.63/mmBtu (2007 $7.10/mmBtu and 2006 $5.52/mmBtu). 

dProved reserves in the Prudhoe Bay field in Alaska include an estimated 54 million barrels on which a 

net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay 

Royalty Trust.

eIncludes 21 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago 

LLC. 

f

Includes 216 million barrels of crude oil in respect of the 6.80% minority interest in TNK-BP.

gIncludes 3,108 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and 

Tobago LLC. 

hIncludes 131 billion cubic feet of natural gas in respect of the 5.92% minority interest in TNK-BP.

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The following tables show BP’s production by major field for 2008, 2007 and 2006. 

Liquids 

17

Performance review

% thousand barrels per day

BP net share of production a

Field or Area Interest 2008 2007 2006

Alaska Prudhoe Bayb 26.4 72 74 71

Kuparuk Various 48 52 57

Northstarb 98.6 22 28 38

 Milne Pointb Various 27 28 31 

Other Various 28 27 27

Total Alaska 197 209 224

Lower 48 onshorec Various Various 97 108 125

Gulf of Mexico deepwaterc Na Kikab Various 29 32 41

Thunder Horseb 75.0 24 – –

Horn Mountainb 100.0 18 18 23

 Kingb 100.0 23 22 28 

Mars 28.5 28 30 19

Mad Dogb 60.5 31 25 17

Atlantisb 56.0 42 2 –

Other Various 49 67 70

Total Gulf of Mexico 244 196 198

Total US 538 513 547

UK offshorec ETAPd Various 27 32 49 

Foinavenb Various 26 37 37

Magnusb 85.0 18 16 30

Schiehallion/Loyalb Various 18 20 26

Clairb 28.6 13 9 7

 Hardingb 70.0 11 14 17 

Andrewb 62.8 7 8 7

Other Various 37 50 62

Total UK offshore 157 186 235 

Onshore Wytch Farmb 67.8 16 15 18 

Total UK 173 201 253

Netherlandsc Various Various – – 1

Norway Valhallb 28.1 14 17 21

 Draugen 18.4 13 14 15 

Ulab 80.0 8 12 14

 Other Various 8 8 10 

Total Rest of Europe 43 51 61 

Angola Dalia 16.7 34 31 –

Girassol 16.7 6 14 17

 Greater Plutoniob 50.0 69 12 –

Kizomba A 26.7 15 36 54

Kizomba B 26.7 16 35 58

Other Various 62 12 4

Australia Various 15.8 29 34 34

Azerbaijan Azeri-Chirag-Gunashlib 34.1 97 200 145 

Shah Denizb 25.5 8 5 –

Canadac Variousb Various 9 8 8

Colombia Variousb Various 24 28 34

Egypt Various Various 57 43 42

Trinidad & Tobago Variousb 100.0 37 30 40 

Venezuelac Various Various 4 16 26

Otherc Various Various 42 35 28

Total Rest of World 509 539 490 

Total groupe 1,263 1,304 1,351 

Equity-accounted entities (BP share) 

Abu Dhabif Various Various 210 192 163

Argentina – Pan American Energy Various Various 70 69 69 

Russia – TNK-BPc Various Various 826 832 876

Otherc Various Various 32 17 16

Total equity-accounted entities 1,138 1,110 1,124

aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements 

independently. 

bBP-operated.

c

In 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position and TNK-BP disposed of some non-core interests. In 2007, BP divested 

its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. In 2006, BP divested its producing 

properties on the Outer Continental Shelf of the Gulf of Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in the Boqueron, Desarollo Zulia Occidental (DZO) and Jusepin projects in 

Venezuela were reduced following a decision by the Venezuelan government. TNK-BP disposed of its non-core interests in the Udmurtneft assets. 

dVolumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell.

eIncludes 19 net mboe/d of NGLs from processing plants in which BP has an interest (2007 54mboe/d and 2006 55mboe/d). 

fThe BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. During the second quarter of 2007, we updated our reporting policy in Abu 

Dhabi to be consistent with general industry practice and as a result have started reporting production and reserves there gross of production taxes.

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Natural gas

18 

Performance review

% million cubic feet per day

BP net share of productiona

Field or Area Interest 2008 2007 2006

Lower 48 onshoreb San Juanc Various 682 694 765

Arkomac Various 240 204 225

Hugotonc Various 91 123 137

Tuscaloosac Various 65 78 86

 Wamsutterc 66.6 136 120 113 

Jonahc Various 221 173 133

Other Various 451 458 461

Total Lower 48 onshore 1,886 1,850 1,920 

Gulf of Mexico deepwaterb Na Kikac 51.9 62 50 97 

Marlinc 78.2 46 13 16

 Other Various 122 205 210 

Gulf of Mexico Shelfb Other Various – 1 66

Total Gulf of Mexico 230 269 389

Alaska Various Various 41 55 67

Total US 2,157 2,174 2,376

UK offshoreb Braes Various 75 69 101

Brucec 37.0 65 72 107

West Solec 100.0 51 55 56

 Marnockc 62.1 24 25 42 

Britannia 9.0 30 37 42

Shearwater 27.5 17 19 31

Armada 18.2 16 16 28

Other Various 481 475 529

Total UK 759 768 936

Netherlandsb P/18-2 48.7 – – 23

Other Various – 3 33

Norway Various Various 23 26 35

Total Rest of Europe 23 29 91

Australia Various 15.8 380 376 364 

Canadab Variousc Various 245 255 282

China Yachengc 34.3 91 85 102

Egypt Ha'pyc 50.0 94 108 99 

Other Various 278 206 172

Indonesia Sanga-Sanga (direct)c 26.3 69 75 84 

Otherc 46.0 98 81 80

Sharjah Sajaac 40.0 65 83 111

 Other 40.0 8 9 9

Azerbaijan Shah Denizc 25.5 143 73 –

Trinidad & Tobago Kapokc 100.0 619 984 946 

Mahoganyc 100.0 323 454 321

Amherstiac 100.0 288 155 176

 Parangc 100.0 – – 120 

Immortellec 100.0 136 153 219

 Cassiac 100.0 5 25 30 

Otherc 100.0 1,075 663 453

Otherb Various Various 421 466 441

Total Rest of World 4,338 4,251 4,009

Total groupd 7,277 7,222 7,412 

Equity-accounted entities (BP share) 

Argentina – Pan American Energy Various Various 385 379 362

Russia – TNK-BPb Various Various 564 451 544 

Otherb Various Various 108 91 99

Total equity-accounted entitiesd 1,057 921 1,005

aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements 

independently. 

bIn 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position. In 2007, BP divested its producing properties in the Netherlands and 

some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. In 2006, BP divested its producing properties on the Outer Continental Shelf of the Gulf of 

Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in the Boqueron, Desarollo Zulia Occidental (DZO) and Jusepin projects in Venezuela were reduced following a decision by the 

Venezuelan government. TNK-BP disposed of its non-core interests in the Udmurtneft assets.

cBP-operated. 

dNatural 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.

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19

Performance review

United States 

2008 liquids production at 538mb/d increased 4.9% from 2007, while natural 

gas production at 2,157mmcf/d decreased 0.8% compared with 2007. 

 Crude oil production increased by 32mb/d, an increase of 8% from 

2007, primarily driven by major projects in the Gulf of Mexico, partly offset by 

natural reservoir decline and the impact of hurricanes in the third quarter. 

 The NGLs component of liquids production decreased by 7mb/d, driven 

mainly by plant turnarounds and operational issues resulting from the 

hurricanes in the third quarter. BP operates or has interests in NGL extraction 

plants with a processing capacity of 6.4bcf/d. These facilities are located in 

major production areas across North America, including Alberta, Canada, the 

US Rockies, the San Juan basin and the Gulf of Mexico. We also own or have 

an interest in fractionation plants (that separate the NGL into its component 

products) in Canada and the US. 

 Gas production was 17mmcf/d lower because of natural reservoir 

decline and the impact of hurricanes, which was partly offset by production 

from shale acquisitions. 

 Development expenditure in the US (excluding midstream) during 2008 

was $4,914 million, compared with $3,861 million in 2007 and $3,579 million in 

2006. The year-on-year increase is the result of various development projects 

in progress. 

 Our activities within the US take place in three main areas: deepwater 

Gulf of Mexico, the Lower 48 states and Alaska. Significant events during 

2008 within each of these are indicated below. 

Deepwater Gulf of Mexico 

Deepwater Gulf of Mexico is our largest area of growth in the US. In 2008, our 

deepwater Gulf of Mexico liquids production was 244mb/d and gas production 

was 40mboe/d

 Significant events were: 

• On 14 June 2008, first oil was achieved at Thunder Horse (BP 75% and 

operator). Thunder Horse is the world’s largest semi-submersible production 

facility, and is located 150 miles south-east of New Orleans. It is designed to 

process 250,000 barrels of oil per day and 200 million cubic feet per day of 

natural gas. In 2008 four wells started up with production of around 

200,000boe/d (gross) at the year-end, signalling the completion of 

commissioning. Production started up in the Thunder Horse North field in 

February 2009.

• On 3 April 2008, BP announced an oil discovery at its Kodiak prospect (BP 

63.75% and operator). The well, located in Mississippi Canyon block 771, 

approximately 60 miles south-east of the Louisiana Coast, is in about 1,500 

metres of water.

• In September 2008, Hurricanes Gustav and Ike resulted in most of the Gulf 

of Mexico’s oil production being shut down. There was minimal damage to 

most of BP’s platforms other than to the drilling derrick on the Mad Dog 

platform, located approximately 190 miles south of New Orleans. The 

production impact of both hurricanes was a reduction equivalent to 

approximately 24mboe/d for the year.

• In October 2008, BP announced an oil discovery with its Freedom well (BP 

25% and operator). The well, located in Mississippi Canyon Block 948, 

approximately 70 miles south-east of the Louisiana Coast, is in about 1,860 

metres of water. It is believed that Freedom straddles Mississippi Canyon 

Block 948 and Mississippi Canyon Block 992. BP owns a 67.75% interest in 

Block 992.

Lower 48 states 

In the Lower 48 states (onshore), our 2008 natural gas production was 

325mboe/d, which was up 2% compared with 2007. Liquids production was 

97mb/d, down 10% compared with 2007. Total 2008 production, excluding the 

impacts from the 2008 hurricanes, was broadly flat compared with 2007. 

 In 2008, we drilled approximately 540 wells as operator and continued 

to maintain a stable programme of drilling activity throughout the year. 

 Production is derived from two main areas: 

 Significant events were: 

Alaska 

In Alaska, BP net oil production in 2008 was 197mb/d, a decrease of 6% from 

2007, due to normal decline in the large mature fields, partially offset by 

continued strong reservoir and well performance. 

 BP operates 13 North Slope oil fields (including Prudhoe Bay, Northstar 

and Milne Point) and four North Slope pipelines and owns a significant interest 

in six other producing fields 

 In addition, two key aspects of BP’s business strategy in Alaska are 

commercializing the large undeveloped natural gas resource within our 26.4% 

interest in Prudhoe Bay and unlocking the large undeveloped heavy oil 

resources within existing North Slope fields through the application of 

advanced technology. 

 Significant events in 2008 were: 

• In the western basins (Colorado, New Mexico and Wyoming), our assets 

produced 224mboe/d in 2008.

• In the Gulf Coast and mid-continental basins (Kansas, Louisiana, Oklahoma 

and Texas), our assets produced 198mboe/d in 2008.

• In August 2008, BP acquired all Chesapeake Energy Corporation’s interest 

in approximately 90,000 net acres of leasehold and producing natural gas 

properties in the Arkoma basin Woodford Shale area for $1.75 billion. BP 

took over production operations on 1 November and retained three drilling 

rigs as part of the deal.

• In September 2008, BP acquired a 25% non-operated interest in 

Chesapeake’s Fayetteville Shale assets for $1.9 billion comprising 

$1.1 billion in cash at closing and an $800 million commitment to fund 

Chesapeake’s 75% share of drilling and completion costs. $183 million of 

this commitment was met in 2008, with the balance expected to be paid by 

the end of 2009. The assets include approximately 135,000 net acres of 

leasehold.

• In September 2008, in anticipation of Hurricane Gustav, operations and 

activity were shut down in the Pascagoula NGL plant, South Louisiana 

(Tuscaloosa field) and East Texas Exploration and Production operations. 

Also in September, Hurricane Ike resulted in every field location across 

South Louisiana, East Texas and the Permian Basin having production shut 

in. Four NGL plants, Pascagoula, Block 31, Crane and Midland, were shut 

down while other plants suffered production impacts due to widespread 

outages and disruptions in the midstream infrastructure. The impact of both 

hurricanes on production was a reduction equivalent to approximately 

2mboe/d for the year.

• In October 2008, BP sanctioned the Wamsutter Full Field Development plan 

(Phase ll). This builds on the operational and technological results of 

extensive field trials conducted during the past three years.

• In July 2008, BP announced the commencement of development activities 

for the Liberty oilfield, which is located on federal leases about six miles 

offshore in the Beaufort Sea, and east of the Prudhoe Bay oilfield. The 

planned development includes up to six ultra-extended reach wells, including 

four producers and two injectors. These wells are expected to be the longest 

horizontal wells ever drilled in the world, extending two miles deep and as far 

as eight miles horizontally, guided by 3-D seismic imagery. A specialized rig 

for drilling in the Arctic is being built for the project. Drilling is expected to 

start in 2010, from an existing satellite pad that is being expanded for

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20 

Performance review

United Kingdom 

We are the largest producer of oil, the second largest producer of gas and the 

largest overall producer of hydrocarbons in the UK. In 2008, total liquids 

production was 173mb/d, a 14% decrease on 2007, and gas production was 

759mmcf/d, a 1% decrease on 2007. This decrease in production was driven 

by natural decline. Key aspects of our activities in the North Sea include a 

focus on in-field drilling and selected new field developments. Our 

development expenditure (excluding midstream) in the UK was $907 million in 

2008, compared with $804 million in 2007 and $794 million in 2006. BP 

operates one NGL plant in the UK. 

 Significant events in 2008 were: 

the project at the BP-operated Endicott oilfield. BP drilled the Liberty 

discovery well in 1997, and is the operator and sole owner of the field.

• In August 2008, BP successfully tested Cold Heavy Oil Production with Sand 

(CHOPS) technology for the first time in Alaska, initiating a four-well 

production test programme during the period from August 2008 until the end 

of 2009. This first test at Milne Point S Pad brought oil and sand to the 

surface, where it was processed using temporary field facilities, combined 

with other light oil production, and shipped down the Trans-Alaska Pipeline 

System (TAPS). The CHOPS well tests are part of a multi-year programme 

to determine the technical and commercial feasibility of a large scale heavy 

oil development project on the North Slope using existing cold and thermal 

technologies.

• During 2008, all four of the Prudhoe Bay Oil Transit Line segments that were 

targeted for replacement in response to the oil spills in the Prudhoe Bay field 

in March and August 2006 were completed and placed in service.

• In February 2008, BP and its partner, Marathon Petroleum West of 

Shetlands Ltd, announced a new oil discovery in UK Continental Shelf Block 

204/23 (BP 72%), following drilling on the South West Foinaven prospect. 

BP, together with its partner, is evaluating the discovery and the potential for 

a two-well subsea development, tied back to the Foinaven Floating 

Production Storage and Offloading vessel (FPSO).

• In May 2008, BP and its co-venturers made an oil discovery in North Sea 

Block 16/23s (BP 77.07%), named Kinnoull. The Kinnoull discovery and 

potential development options, including a subsea development tied back to 

BP’s Andrew field, are being evaluated.

• During the third quarter, the first phase of offshore removal activity for the 

North West Hutton platform decommissioning programme was completed. 

This is BP’s biggest decommissioning project so far in the North Sea and 

has seen the removal of 22 separate topsides modules, which were then 

taken away by barges to the Able UK yard on Teesside for recycling and 

disposal. It is estimated that around 97% of the material recovered will be 

recycled and/or reused.

• In December 2008, BP and BG Group agreed to exchange a package of 

North Sea assets. This is expected to strengthen BP’s position as a major 

operator in the Southern North Sea and to facilitate development activity and 

investment in the UK Continental Shelf. BP agreed to acquire BG’s 24.2% 

interest in the BP-operated Amethyst field and all its interests in the 

Easington Catchment Area (ECA) fields, including a 73.3% interest in the 

Mercury field, a 79% interest in the Neptune field, a 65% interest in the 

Minerva, Apollo and Artemis fields and BG’s 30.8% interest in the BPoperated Whittle and Wollaston fields. BG Group agreed to acquire BP’s 

interest and operatorship in the Everest (BP 21.1%) and Lomond (BP 

22.2%) fields, BP’s 18.2% interest in the BG-operated Armada field and 32% 

of the Chevron-operated Erskine field (BP will retain 18% equity in Erskine). 

The deal is subject to government, regulatory and partner approvals and 

completion is expected in the second quarter of 2009.

Rest of Europe

Our activities in the Rest of Europe are now centred on Norway. Until 

February 2007, we also held exploration and production and gas infrastructure 

interests in the Netherlands. Development expenditure (excluding midstream) 

in the Rest of Europe was $695 million, compared with $443 million in 2007 

and $214 million in 2006. In 2008, our total production in Norway was 

47mboe/d, a 16% decrease on 2007. This decrease in production was driven 

by natural decline. In Norway, progress continued as planned on the Skarv 

and Valhall Redevelopment projects. 

Rest of World 

Development expenditure in Rest of World (excluding midstream) was 

$5,251 million in 2008, compared with $5,045 million in 2007 and 

$4,522 million in 2006. 

Rest of Americas 

Canada 

Trinidad 

• In Canada, our natural gas and liquids production was 51mboe/d in 2008, a 

decrease of 1% compared with 2007. The year-on-year decrease in 

production is mainly due to natural field decline.

• On 31 March 2008, BP and Husky Energy Inc. (Husky) completed a deal to 

create an integrated North American oil sands business by means of two 

separate 50:50 joint ventures, BP-Husky Refinery LLC, operated by BP, and 

the Sunrise Oil Sands Partnership (SOSP), operated by Husky. BP’s capital 

expenditure in respect of the creation of SOSP amounted to $2.8 billion.

• In June 2008, BP successfully acquired three of five exploration licences on 

offer in the Canadian section of the Beaufort Sea through a Call for Bids 

process issued by The Department of Indian and Northern Affairs of Canada. 

The leases awarded to BP cover about 611,000 hectares of the Beaufort 

seabed, north of Tuktoyaktuk, Northwest Territories. These are in addition to 

the 15 significant discovery licences that BP currently holds in the Beaufort 

Sea, and two exploration licences currently in moratorium. The term for 

exploration licences issued from this Call for Bids is nine years consisting of 

two consecutive periods. There is a $300 million work obligation associated 

with acquiring these exploration licences.

• In Trinidad, natural gas production volumes increased from 420mboe/d in 

2007 to 422mboe/d in 2008. The increase was a result of improved 

operating efficiency on the Atlantic LNG Trains combined with increased 

demand from the domestic market and full ramp-up of two new fields, Mango 

and Cashima. Liquids production increased by 7mb/d (23%) to 37mb/d in 

2008 from 30mb/d in 2007 as a result of an increase in NGLs associated 

with higher throughput for the Trains, increased crude and condensate from 

the two new fields and liquid optimization activities.

• In December 2008, a new oil export pipeline was commissioned to transport 

liquids from offshore fields to onshore delivery points. BP owns 100% of the 

capacity of the pipeline.

• Progress on Savonette, BP’s next field development in Trinidad, continued 

throughout the year and first gas is expected to be delivered in 2009.

• In 2008, the Day Away from Work Case injury frequency (per 200,000 work 

hours) has been reduced from 0.12 in 2003 to zero in 2008 and the 

recordable injury frequency has more than halved in the same period. This 

has come about through the development and implementation of a 

comprehensive multi-year safety plan, focused on coaching safety leaders, 

workforce communication, standard implementation and continuous learning.

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21

Performance review

Venezuela

Colombia 

Argentina, Bolivia and Chile 

• In Venezuela, despite the transition since 2006 of BP’s interests to 

incorporated joint venture (IJV) entities with the state oil company Petróleos 

de Venezuela, S.A. (PDVSA), and OPEC quotas, 2008 liquids production 

increased by 3mb/d compared with 2007.

• In the second quarter of 2008, BP concluded the migration of the Cerro 

Negro operations to an IJV with PDVSA while retaining the same equity 

interest.

• In Colombia, BP’s net production averaged 38mboe/d. The reduction of 

8mboe/d compared with 2007 is mainly due to natural field decline and lower 

gas transfers from Recetor (BP 50%) to Santiago de las Atalayas (BP 31%). 

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.

• On 20 June 2008, the National Hydrocarbon Agency gave its official 

approval for equalization of RC4 and RC5 Caribbean offshore blocks with 

partners Ecopetrol and Petrobras, with the main objective of simplifying 

partner relations and agreements. New equity interests resulting from this 

approval are BP 40.6%, Ecopetrol 32% and Petrobras 27.4%. Seismic 

operations for these two blocks were completed successfully. Processing 

and interpretation of the data to determine potential prospects for offshore 

field developments and drilling operations is under way and is expected to 

be completed in 2009.

• In Argentina, Bolivia and Chile, activity is conducted through Pan American 

Energy (PAE), a joint venture company in which BP holds a 60% interest, 

and which is accounted for by the equity method. In 2008, total PAE gross 

production of 250mboe/d represented an increase of 3% compared with 

2007. Most of this production comes from the Cerro Dragón field in the 

provinces of Chubut and Santa Cruz. The field is now producing at its 

highest level since inception of the licence area in 1958. PAE also has other 

assets producing gas and liquids in the Argentine provinces of Salta, 

Neuguén and Tierra del Fuego, and in Bolivia, as well as interests in 

exploration areas, pipelines, electricity generation plants and other 

midstream infrastructure assets, primarily in Argentina.

• In 2007 and early 2008, PAE was granted extensions of the two principal 

Cerro Dragón licence areas by the provinces of Chubut and Santa Cruz in 

exchange for material long-term investment commitments in exploration and 

production, and for long-term commitments to local community and supplier 

development. The licence expiry dates have been extended from 2017 to 

2027, with further extension potential to 2047.

• In May 2008, following its decree of 2006 requiring all private owners of 

shares in Bolivian oil and gas companies to transfer back a majority 

shareholding to the Bolivian national oil company Yacimientos Petrolíferos 

Fiscales Bolivianos (YPFB), the Bolivian government issued a second 

decree requiring this transfer to be made with immediate effect. PAE, as the 

majority shareholder of Empresa Petrolera Chaco S.A. (Chaco), a company 

created in the 1990s, was affected by these decrees. PAE was required to 

sell approximately 1% of the share capital of Chaco to YPFB, such that 

YPFB would own 50% plus one share of the total. From May 2008 and into 

January 2009, PAE was in discussions with the government regarding the 

decrees and options for implementation. However, on 23 January 2009, the 

president of Bolivia issued a decree nationalizing PAE’s shareholding in 

Chaco. PAE is currently evaluating all options to preserve the value of its 

shareholding.

Africa 

Algeria 

Angola 

• On 26 November 2008, the Argentine government issued a decree creating 

a new regime called Petróleo PLUS. This regime is aimed at increasing oil 

production and reserves. The detailed rules of Petróleo PLUS were issued 

on 4 December 2008. On 15 December 2008, PAE made its first 

applications under Petróleo PLUS for fiscal credit certificates with the 

Secretary of Energy.

• BP, through its joint operatorships of the In Salah Gas (33.15%) and In 

Amenas (12.5%) projects, supplied 33mboe/d (BP net) to markets in Algeria 

and southern Europe during 2008. This is a decrease of 15% from 39mboe/d 

in 2007 as a result of lower gross volumes at In Salah due to planned 

turnaround maintenance and the impact of lower entitlement in our PSAs 

driven by higher prices, partly offset by improved operating efficiency at In 

Amenas. Further, BP, through its joint operatorship of the Rhourde El Baguel 

field, received 4.4mboe/d (BP net) of oil in 2008.

• Sonatrach and BP announced an exploration success with the Tin 

Zaouatene-1 (TZN-1) discovery in the Bourarhet Sud Blocks 230 and 231. 

On 24 September 2008, BP moved into the second prospecting period, 

which lasts for a further two years.

• In Angola, BP net production in 2008 was 202mboe/d, an increase of 45% 

from 2007 due to the start-up of the Mondo, Saxi and Batuque (Kizomba C, 

BP 26.67%) fields, and the ramp-up of the Greater Plutonio field (BP 50% 

and operator), more than offsetting the impact of lower entitlement in our 

PSAs driven by higher prices in existing fields. We expect to have invested 

over $15 billion in our Angolan business by 2010.

• In January 2008, the Kizomba C project (BP 26.67%) came onstream with 

the start-up of the Mondo field, followed by first production from the Saxi and 

Batuque fields in July 2008. The Kizomba C development is located 

approximately 140 kilometres off the coast of Angola in water depths of 

nearly 800 metres.

• In June 2008, the Plutão, Saturno, Vênus and Marte (PSVM) project was 

authorized by Sonangol. The programme is expected to comprise four fields 

that lie in the north east sector of Block 31 (BP 26.67% and operator), in a 

water depth of approximately 2,000 metres, some 400 kilometres north west 

of Luanda. Contracts have been awarded and construction work started 

during 2008.

• During the third quarter of 2008, production was shut down at the Greater 

Plutonio FPSO located in deepwater Block 18 (BP 50% and operator), 

offshore Angola, due to operational issues. Production was restarted on 12 

October 2008. The adverse impact on full-year production was 14mb/d.

• In the ultra deepwater Block 31 (BP 26.67% and operator), there was further 

exploration success with the Portia and Dione wells, bringing the total 

successes for Block 31 to 16. The Portia well is located in a water depth of 

approximately 2,000 metres, some 386 kilometres north-west of Luanda. 

The Dione well is located in a water depth of approximately 1,700 metres, 

some 390 kilometres north-west of Luanda.

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Performance review

Egypt

Libya 

Asia Pacific 

Indonesia 

• In Egypt, BP net production was 121mboe/d, an increase of 25% from 

97mboe/d in 2007. This increase was mainly due to the start-up of two new 

fields, Saqqara and Taurt, and the full-year impact from Denise, which 

started up at the end of 2007.

• In January 2008, BP completed drilling a successful exploration well, Satis-1, 

in the North El Burg offshore concession (BP 50% and operator). The Satis1 well was drilled in approximately 90 metres of water, some 50 kilometres 

offshore, and is in the Oligocene formation.

• In January 2008, an oil discovery was announced in the North Shadwan (BP 

50% and operator) concession located in the southern part of the Gulf of 

Suez. The NS394-1A exploration well was drilled in shallow water seven 

kilometres from the Hilal field. This discovery is the first new oil discovery in 

the south-eastern area of the Gulf of Suez in more than 10 years and is also 

the first discovery drilled by BP which has been facilitated by modern, highquality, ocean-bottom cable (OBC) seismic data.

• On 15 May 2008, oil production from the Saqqara field (BP 100%) started. 

The Saqqara field, operated by the Gulf of Suez Petroleum Company 

(GUPCO), a joint venture operating company between BP and the Eygptian 

General Petroleum Corporation (EGPC), is located 13 kilometres offshore in 

the central Gulf of Suez. Natural gas production commenced on 26 

July 2008. The Saqqara development includes a jacket and unmanned 

topsides, three wells, and a 13-kilometre pipeline to a new dedicated 

onshore separation and gas processing plant at Ras Shukeir on the Gulf of 

Suez. Local contractors were used for design, onshore construction and 

offshore fabrication work.

• In July 2008, natural gas production began from the Taurt field (BP 50%). 

The Taurt field is located between the Ras El Bar Concession (BP 50% and 

operator) and the Temsah Concession (BP 50%), 70 kilometres offshore to 

the north-east of Port Said, East Nile Delta. Gross Taurt production ramped 

up to 230mmcf/d in August. The Taurt development includes a Subsea 

Production System (SPS), two subsea wells, and a 70-kilometre pipeline and 

control umbilical back to upgraded facilities at the existing West Harbor 

processing plant. Taurt is BP’s first subsea development in Egypt and also 

the first of a planned programme of future subsea developments. Local 

contractors were used for onshore design/modifications and subsea 

structure construction.

• In Libya, BP and its partner, the Libyan Investment Corporation 

(LIC) commenced seismic operations on the acreage covered under the 

exploration and production-sharing agreement ratified in December 2007. In 

September 2008, the offshore seismic acquisition survey commenced in the 

Mediterranean waters of Libya’s Gulf of Sirt. At the end of 2008, the onshore 

seismic operations commenced in the northern Ghadames block.

• BP produces crude oil in, and supplies natural gas to, the island of Java 

through its holding in the Offshore Northwest Java PSA (BP 46%). In 2008, 

BP net production was 22mboe/d, an increase of 18% from 18.6mboe/d in 

2007 as a result of improved operating efficiencies and increased gas 

demand in Java.

• BP is operator of the Tangguh LNG project (BP 37.2%), which includes 

offshore platforms, pipelines and an LNG plant with two production trains 

with a total capacity of 7.6 million tonnes per annum (mtpa). In May 2008, 

gas was introduced from one of the two offshore platforms into the Onshore 

Receiving Facility (ORF). First commercial delivery of LNG is expected in the 

second quarter of 2009.

Vietnam 

China 

Australia 

• BP has a 50% interest in Virginia Indonesia Company LLC (Vico), the 

operator of the Sanga-Sanga PSA (BP 38%) supplying feedgas to 

Indonesia’s largest LNG export facility, the Bontang LNG plant in 

Kalimantan.

• BP participates in one of the country’s largest foreign investment projects, 

the Nam Con Son gas project. This is an integrated resource and 

infrastructure project, which includes offshore gas production, a pipeline 

transportation system and a power plant. At midnight on 31 December 2007, 

the operation of the Nam Con Son Pipeline (BP 32.67%) transferred from BP 

to PetroVietnam (PVN). In September 2008, capacity of the Nam Con Son 

Pipeline was increased by 30% to allow for additional current and future 

expected volumes.

• In 2008, BP net natural gas production was 61mmcf/d, a decrease of 26% 

from 82mmcf/d in 2007, primarily due to lower PSA entitlements. Gas sales 

from Block 6.1 (BP 35% and operator) are made under a long-term 

agreement for electricity generation at the Phu My 3 power plant (BP 

33.3%).

• BP has determined that its licences in Blocks 5.2 (BP 55.9% and operator) 

and 5.3 (BP 75% and operator) do not fit within its current portfolio and has 

decided to withdraw from them. BP is currently in active discussions with 

PVN, the Vietnamese government and joint venture partners to progress this 

withdrawal.

• In 2008, natural gas production was 91mmcf/d BP net, an increase of 7% 

compared with 2007. This increase was mainly due to increased gas 

demand. A new development project was sanctioned in late 2008 to help 

meet the expected increase in demand in 2010 and beyond.

• The Yacheng offshore gas field (BP 34.3%) supplies Castle Peak Power 

Company with feedgas for up to 70% of Hong Kong’s gas-fired electricity 

generation. Additional gas is also sold to the Fuel & Chemical Company of 

Hainan.

• In March 2007, the National People’s Congress reduced the rate of 

corporation tax from 33% to 25% with effect from 1 January 2008.

• BP is one of seven partners in the North West Shelf (NWS) venture. Six 

partners (including BP) hold an equal 16.67% interest in the infrastructure 

and oil reserves and an equal 15.78% interest in the gas and condensate 

reserves, with a seventh partner owning the remaining 5.32% of gas and 

condensate reserves. The NWS venture is currently the principal supplier to 

the domestic market in Western Australia and one of the largest LNG export 

projects in Asia with five LNG Trains in operation.

• In 2008, BP net gas production was 380mmcf/d, an increase of 1% from 

2007 primarily due to increased domestic gas demand in Western Australia 

and the startup of NWS Train 5 and the Angel platform in the third quarter. 

BP net liquids production was 29mb/d, a decrease of 15% from 2007 due to 

natural field decline.

• In March 2008, the North Rankin 2 (NR2) project was sanctioned. This links 

a second platform via a 100-metre bridge to the existing North Rankin A 

(NRA) platform. On completion, NRA and NR2 platforms are expected to be 

operated as a single integrated facility and to recover low pressure gas from 

the North Rankin and Perseus gas fields.

• In September 2008, a fifth LNG train was successfully completed and 

commenced production at the Karratha gas plant. Train 5 increases NWS 

total annual production capacity from 11.9 to 16.3 million tonnes.

• The Angel platform (BP 16.67%) was successfully commissioned and started 

producing gas during October 2008. Angel has a gross production capacity 

of 800 million standard cubic feet of raw gas and up to 50,000 barrels of 

condensate per day.

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Performance review

Russia 

TNK-BP 

• TNK-BP, a joint venture between BP (50%) and Alfa Group and AccessRenova (AAR) (50%), is an integrated oil company operating in Russia and 

the Ukraine. The TNK-BP group’s major assets are held in OAO TNK-BP 

Holding. Other assets include the BP-branded retail sites in Moscow and the 

Moscow region and interests in OAO Rusia Petroleum and the OAO Slavneft 

group. The workforce comprises more than 60,000 people.

• BP’s investment in TNK-BP is held by the Exploration and Production 

segment and the results of TNK-BP are accounted for under the equity 

method in this segment.

• TNK-BP has proved reserves of 7.1 billion barrels of oil equivalent (including 

its 49.9% equity share of Slavneft), of which 5 billion are developed. In 2008, 

TNK-BP’s average liquids production was 1.65mmb/d, a decrease of just 

under 1% compared with 2007. The production base is largely centred in 

West Siberia (Samotlor, Nyagan and Megion), which contributes about 

1.2mmboe/d, together with Volga Urals (Orenburg) contributing some 

0.4mmboe/d. About 40% of total oil production is currently exported as crude 

oil and 20% as refined product.

• Downstream, TNK-BP has interests in six refineries in Russia and the 

Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl refinery), 

with throughput of approximately 34 million tonnes per year. During 2008, 

TNK-BP purchased additional retail and other downstream assets in Russia 

and the Ukraine from a number of small companies. TNK-BP supplies 

approximately 1,400 branded filling stations in Russia and the Ukraine and, 

with the additional sites, is expected to have more than 20% market share of 

the Moscow retail market.

• On 9 January 2009, BP reached final agreement on amendments to the 

shareholder agreement with its Russian partners in TNK-BP. The revised 

agreement is aimed at improving the balance of interests between the 

company’s 50:50 owners, BP and Alfa Access-Renova (AAR), and focusing 

the business more explicitly on value growth.

• The former evenly-balanced main board structure has been replaced by one 

with four representatives each from BP and AAR, plus three independent 

directors. Unanimous board support is required for certain matters including 

substantial acquisitions, divestments and contracts, and projects outside the 

business plan, together with approval of key changes to the TNK-BP group’s 

financial framework and of related party transactions. A number of other 

matters will be decided by approval of a majority of the board, so that the 

independent directors will have the ability to decide in the event of 

disagreement between the shareholder representatives on the board. BP will 

continue to nominate the chief executive, subject to main board approval, 

and AAR will continue to appoint the chairman. The three independent 

directors appointed to the restructured main board are Gerhard Schroeder, 

former chancellor of the Federal Republic of Germany, James Leng, former 

chairman of Corus Steel and Alexander Shokhin, president of the Russian 

Union of Industrialists and Entrepreneurs. In addition, significant TNK-BP 

subsidiaries will have directors appointed by BP and AAR on their boards. 

Our investment in TNK-BP will be reclassified from a jointly controlled entity 

to an associate with effect from 9 January 2009.

• The parties have confirmed their agreement to a potential future sale of up to 

20% of a subsidiary of TNK-BP through an initial public offering (IPO) at an 

appropriate future point, subject to certain conditions and the consent of the 

Russian authorities.

• In 2007, BP and TNK-BP signed heads of terms to create strategic business 

alliances with OAO Gazprom. Under the terms of this agreement, TNK-BP 

agreed to sell to Gazprom its stake in OAO Rusia Petroleum, the company 

that owns the licence for the Kovykta gas condensate field in East Siberia 

and its interest in East Siberia Gas Company. Discussions to conclude this 

disposal continue.

Sakhalin 

Other 

Azerbaijan

Middle East and South Asia 

• BP and its Russian partner Rosneft agreed two Shareholder and Operating 

Agreements (SOAs) on 28 April 2008, recognizing BP as a 49% equity 

interest holder with Rosneft holding the remaining 51% interest in the two 

newly formed joint venture companies, Vostok Shmidt Neftegaz and Zapad 

Shmidt Neftegaz. BP also continues to hold a 49% equity interest in its third 

joint venture company at Sakhalin, Elvary Neftegaz, with Rosneft holding the 

remaining 51%. During the year, each of the three joint ventures held 

Geological and Geophysical Studies licences with the Russian Ministry of 

Natural Resources (MNR) to perform exploration seismic and drilling 

operations in these licence areas off the east coast of Russia. To date, 3D 

seismic data has been acquired in relation to all three licences. In the Elvary 

Neftegaz licence additional commitment 2D seismic data was acquired 

during 2008 in preparation for future drilling commitments. Exploration wells 

have been drilled in the Zapad-Shmidt Neftegaz and Elvary Neftegaz 

licences. In 2008, it was agreed by both shareholders to allow the ZapadShmidt Neftegaz licence to lapse at the end of its normal term.

• In Azerbaijan, BP’s net production in 2008 was 130mboe/d, a net decrease 

of 40% from 2007. The primary elements of this were the effects of 

significantly higher prices resulting in a change in profit oil entitlement in line 

with the terms of the PSA and reduced cost oil entitlement, partially offset by 

an increase following the start-up of the Deepwater Gunashli (DWG) 

platform, the ramping up of three Azeri oil-producing platforms and the Shah 

Deniz condensate gas platform commencing production in 2007.

• The DWG platform complex successfully started oil production on schedule 

on 20 April 2008. DWG completes the third phase of development of the 

Azeri-Chirag-Gunashli (ACG) field (BP 34.1% and operator) in the 

Azerbaijan sector of the Caspian Sea. The DWG complex is located in a 

water depth of 175 metres on the east side of the Gunashli field. The 

complex comprises two platforms – a drilling and production platform linked 

by a bridge to a water injection and gas compression platform.

• On 17 September 2008, a subsurface gas release occurred below the 

Central Azeri platform. As a precautionary measure, all personnel on the 

platform were safely transferred onshore. The Central Azeri platform was 

shut down until 19 December 2008, when following comprehensive 

investigation and recovery work, BP began to resume oil and gas production. 

Central Azeri processes oil and gas from West Azeri, and West Azeri was 

also temporarily shut down and then restored to normal operations on 9 

October 2008. Operations of the Compressor and Water Injection Platform 

(CWP), which is linked by a bridge to Central Azeri, and the provision of 

power and injection water across three Azeri field platforms were reestablished on 12 October 2008.

• Production in the Middle East consists principally 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 2008, 

BP’s share of production in Abu Dhabi was 210mb/d, up 9% from 2007 as a 

result of higher overall OPEC demand despite cuts implemented in the fourth 

quarter of 2008.

• In July 2008, BP Sharjah signed a farm-out agreement with RAK Petroleum 

for the East Sajaa concession. Drilling of the first exploration well is expected 

in 2009.

• In Block 61 in Oman, the challenges posed by the world’s largest onshore 

azimuth 3D seismic survey led the BP Oman team to use a ground-breaking 

new technique known as Distance Separated Simultaneous Sweeping 

(DS3). This technique allows the acquisition

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24 

Performance review

Midstream activities 

Oil and natural gas transportation 

The group has direct or indirect interests in certain crude oil transportation 

systems, the principal ones being the Trans-Alaska Pipeline System (TAPS) in 

the US, the Forties Pipelines System (FPS) in the UK sector of the North Sea 

and the Baku-Tbilisi-Ceyhan (BTC) oil pipeline. 

 In addition to these, we also operate the Central Area Transmission 

System (CATS) for natural gas in the UK sector of the North Sea, the Western 

Export Route Pipeline between Azerbaijan and the Black Sea coast of Georgia 

(as operator of AIOC), and, as technical operator, the South Caucasus 

Pipeline (SCP) (BP 25.5%), which takes gas from Azerbaijan through Georgia 

to the Turkish border. 

 BP’s onshore US crude oil and product pipelines and related 

transportation assets are included under Refining and Marketing (see page 

27). 

 Assets and activity during 2008 included: 

Alaska 

in a single day of as much seismic data as previously obtained in a week. 

The invention of DS3 along with some other innovations allowed an efficient 

and cost effective survey of the Block to be completed within a six-month 

period. The first appraisal well was spudded in September 2008.

• In Pakistan, BP’s net oil production in 2008 was 8.2mboe/d, an increase of 

30% from 2007, and BP’s net gas production was 28.2mboe/d, an increase 

of 34% from 2007 as a result of the full-year impact of BP increasing its 

equity in the onshore Badin asset in 2007 to 84%.

• In Pakistan, BP received an 18-month extension until January 2010 in Phase 

1 of the initial term of Exploration Licences in respect of the offshore Indus 

PSA.

• On 30 December 2008, BP signed completion documents with Orient 

Petroleum International Inc., to acquire a 51.3% working interest, along with 

operatorship, in two joint venture blocks, Mirpurkhas and Khipro, located in 

the southern Sindh province of Pakistan.

• On 22 December 2008, BP signed a production-sharing contract with the 

Indian government for a deepwater exploration block in the KrishnaGodavari Basin, offshore eastern India, which was awarded under the New 

Exploration Licensing Policy Seventh round. BP is the designated operator 

with a 30% working interest in the block. Reliance Industries Limited holds 

the remaining 70% working interest.

• BP owns a 46.9% interest in TAPS, with the balance owned by four other 

companies. Production transported by TAPS from Alaska North Slope fields 

averaged 700mb/d during 2008.

• Work on the strategic reconfiguration project to upgrade and automate four 

TAPS pump stations continued to progress in 2008. This project is installing 

electrically-driven pumps at four critical pump stations, along with increased 

automation and upgraded control systems. Two of the reconfigured pump 

stations came online during 2007. The remaining two reconfigured pump 

stations are expected to come online sequentially, one in 2009 and one in 

2010.

• On 8 April 2008, BP and ConocoPhillips announced the formation of a joint 

venture company called Denali – The Alaska Gas Pipeline. The joint venture 

has begun work on an Alaska gas pipeline project consisting of a gas 

treatment plant on Alaska’s North Slope, a large-diameter pipeline that is 

intended to pass through Alaska into Canada, and should it be required, a 

large-diameter pipeline from Alberta to the Lower 48 United States. When 

completed, the pipeline is expected to move approximately 4 billion cubic 

feet of natural gas per day to market. The joint venture plans to spend up to 

$600 million prior to reaching the first major project milestone, an ‘open 

season’, before the end of 2010. An open season is a process during which

the joint venture seeks customers to make firm, long-term transportation 

commitments to the project. Should the open season be successful, the joint 

venture will seek certification from the Federal Energy Regulatory 

Commission (FERC) of the US and the National Energy Board (NEB) of 

Canada to move forward with project construction. The new joint venture 

company will manage the project, and will own and operate the pipeline 

when completed. BP and ConocoPhillips may consider other equity partners, 

including pipeline companies, who can add value to the project and help 

manage the risks involved. On 22 May 2008, the office of the Governor of 

Alaska announced that it would be supporting an alternative gas pipeline 

project proposed by TransCanada Alaska Company in response to the State 

of Alaska’s request for bids under the Alaska Gas Inducement Act (AGIA) in 

2007. BP’s commitment to move forward with the Denali project is 

independent of any decisions made or inducement offered by the State 

under the AGIA process and BP believes that the Denali project offers the 

best opportunity for a successful Alaska gas pipeline project.

• Alaska state courts issued two noteworthy rulings in 2008, related to 

challenges filed by in-state refiners against BP and the other TAPS carriers, 

regarding intrastate tariffs charged for shipping oil through TAPS during the 

period from 1997 through 2003. These rulings are related to long-standing 

challenges that were originally filed with the Regulatory Commission of 

Alaska (RCA). In 2002, the RCA issued Order 151, which determined that 

TAPS transportation rates charged from the beginning of 1997 were 

excessive, and that refunds should be paid. BP and the other TAPS carriers 

appealed the RCA's 2002 ruling in the State of Alaska court system. In the 

interim, the RCA issued Order 34, which imposed intrastate tariff rates 

consistent with Order 151, effective from 1 July 2003 forward. On 15 

February 2008, the Alaska Supreme Court affirmed the determination in 

RCA's Order 151, and on 26 February 2008, the Alaska Superior Court 

affirmed the RCA's Order 34, and imposed the application of Order 151 to 

intrastate tariff rates charged from 2001 forward. BP and the other TAPS 

carriers decided not to appeal these matters any further in the courts, and on 

25 March 2008, BP Pipelines Alaska paid refunds to intrastate shippers 

totalling $71 million covering the period 1997 through 2000. During the third 

quarter of 2008, BP Pipelines Alaska paid out an additional $75 million to 

intrastate shippers covering the period from 2001 through 30 June 2003. In 

2008, intrastate transport made up approximately 13.7% of total TAPS 

throughput.

• Tariffs for interstate transportation of oil through TAPS are calculated using 

the TAPS Tariff Settlement Methodology (TSM), which is defined in an 

agreement entered into with the State of Alaska in 1985. The TSM was also 

accepted at that time by the Regulatory Commission of Alaska (RCA) and 

the Federal Energy Regulatory Commission (FERC). Since then, Anadarko, 

Tesoro, and the State of Alaska have challenged the interstate tariffs 

charged by BP and the other TAPS carriers in the years 2005, 2006 and 

2007 with the FERC. Anadarko and the State of Alaska have also 

challenged the 2008 tariffs. In 2006, the FERC consolidated the proceedings 

related to the years 2005-2006, and determined that the challenges 

pertaining to 2007 tariff rates would be held in abeyance until a decision was 

issued in the proceedings on 2005 and 2006 tariff rates. The FERC’s 

hearings on the consolidated proceedings commenced in October 2006 and 

concluded in January 2007. On 17 May 2007, a FERC Administrative Law 

Judge (ALJ) issued an initial decision on 2005 and 2006 tariff rates that was 

adverse to BP and the other TAPS carriers, and established a floor of 

$3.01/bbl for the 2005-2006 period, as this was the last uncontested tariff 

rate. On 20 June 2008, the FERC issued a ruling on the 2005-2006 period, 

which substantially affirmed the initial ruling by the ALJ, and ordered the 

TAPS carriers to pay refunds to shippers. On 20 November 2008, the FERC 

affirmed its 20 June 2008 ruling in response to applications for rehearing 

filed by BP and the other TAPS carriers. Accordingly, in December 2008 BP 

as

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Performance review

North Sea 

Asia (including the former Soviet Union) 

a TAPS carrier paid third party shippers tariff refunds of $52 million; and BP 

as a TAPS shipper received tariff refunds from third party carriers of 

$27 million. The FERC’s 20 November 2008 ruling also concluded that a 

unified tariff rate should be established for interstate transportation through 

TAPS, and the TAPS carriers were ordered to implement a revenue pooling 

methodology in the TAPS Operating Agreement. Some TAPS carriers other 

than BP have filed legal challenges to this aspect of the FERC’s 20 

November 2008 ruling, which are still pending. As of the end of 2008, there 

have been no proceedings in the challenges to BP’s and the other TAPS 

carriers’ 2007 and 2008 tariff rates. In 2008, interstate transport made up 

approximately 86% of total TAPS throughput.

• FPS (BP 100%) is an integrated oil and NGLs transportation and processing 

system that handles production from more than 50 fields in the Central North 

Sea. The system has a capacity of more than one million barrels per day, 

with average throughput in 2008 of 662mb/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 1,700mmcf/d to a natural gas terminal at Teesside 

in north-east England. CATS offers natural gas transportation and 

processing services. In 2008, throughput was 836mmcf/d (gross), 

247mmcf/d (net).

• BP operates the Dimlington/Easington gas processing terminal (BP 100%) 

on Humberside and the Sullom Voe oil and gas terminal in Shetland.

• BP as operator, manages and holds a 30.1% interest in the BTC oil pipeline. 

The 1,768-kilometre pipeline transports oil from the BP-operated ACG oil 

field in the Caspian Sea to the eastern Mediterranean port of Ceyhan. The 

Turkish section of the pipeline is operated by Botas.

• On 6 August 2008, the Baku-Tbilisi-Ceyhan (BTC) pipeline was shut down 

for 14 days as a result of a fire that occurred at Block Valve 30, located in 

the Erzincan province in Eastern Turkey. The pipeline restarted on 20 

August 2008. The Azeri-Chirag-Gunashli (ACG) and Shah Deniz (SD) fields 

reduced offshore production to manage stock levels at the Sangachal 

Terminal. Some exports were maintained via the Northern Route Export 

Pipeline (NREP) and by rail through Georgia.

• BP is technical operator of, and holds a 25.5% interest in, the 693-kilometre 

South Caucasus Pipeline (SCP), which takes gas from Azerbaijan through 

Georgia to the Turkish border. During August 2008, the South Caucasus gas 

and Western Route oil export pipelines were shut down for a short period as 

a precautionary measure during a period of military activity in the region.

• In February 2008, BP, on behalf of AIOC, handed over operatorship of the 

Azerbaijani section of the NREP between Azerbaijan and Russia to the State 

Oil Company of Azerbaijan Republic (SOCAR).

• Through the LukArco joint venture, BP holds a 5.75% interest in the Caspian 

Pipeline Consortium (CPC) pipeline and a 2.3% interest in Tengizchevroil 

(TCO). CPC is a 1,510-kilometre pipeline from Kazakhstan to the Russian 

port of Novorossiysk and carries crude oil from a number of Kazakh fields, 

including Tengiz. In addition to our interest in LukArco, we hold a separate 

0.87% interest in CPC through a 49% holding in Kazakhstan Pipeline 

Ventures (KPV). In 2008, CPC total throughput reached 32.2 million tonnes. 

During 2008, the majority of shareholders in CPC agreed on the commercial 

terms for expansion of CPC to 67 million tonnes. These terms strongly 

favour the upstream, and as BP has no additional volumes of Kazakh crude 

to ship in an expanded CPC, BP has been unable to support these new 

commercial terms. In order not to delay the expansion of CPC, BP has 

obtained the agreement of its KPV joint venture partners and CPC 

shareholders to dispose of its interest in KPV

Liquefied natural gas 

Our LNG activities are focused on building competitively advantaged 

liquefaction projects, establishing diversified market positions to create 

maximum value for our upstream natural gas resources and capturing third 

party LNG supply to complement our equity flows. 

 Assets and activity during 2008 included: 

and is seeking the agreement of its joint venture partners, CPC shareholders 

and TCO partners to dispose of its interest in LukArco.

• On 25 September 2008, Chevron announced that Tengizchevroil had 

completed a major expansion at the Tengiz field in Kazakhstan in which BP 

holds a 2.3% interest through its joint venture with LukArco. The completion 

of the expansion brings daily crude capacity of the field to 540mb/d.

• In Trinidad, BP’s net share of the capacity of Atlantic LNG Trains 1, 2, 3 and 

4 is 6 million tonnes of LNG per year (292 billion cubic feet equivalent regasified), with the Atlantic LNG Train 4 (BP 37.8%) designed to produce 

5.2 million tonnes (253 billion cubic feet) per year of LNG. All of the LNG 

from Atlantic Train 1 and most of the LNG from Trains 2 and 3 is sold to third 

parties in the US and Spain under long-term contracts. All of BP’s LNG 

entitlement from Atlantic LNG Train 4 and some of its LNG entitlement from 

Trains 2 and 3 is marketed via BP’s LNG marketing and trading business to 

a variety of markets including the US, the Dominican Republic, Spain, the 

UK and the Far East.

• We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction 

Company, which in 2008 supplied 5.8 million tonnes (298.746mmcf) of LNG, 

up 3% from 2007.

• BP has a 13.6% share in the Angola LNG project, which is expected to 

receive approximately one billion cubic feet of associated gas per day from 

offshore producing blocks and to produce 5.2 million tonnes gross per year 

of LNG, as well as related gas liquids products. With the completion of the 

necessary agreements and the approval of the Angolan government, the 

project investors have authorized Angola LNG Limited to proceed with the 

construction and implementation of the project.

• In Indonesia, BP is involved in two of the three LNG centres in the country. 

BP participates in Indonesia’s LNG exports through its holdings in the 

Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently delivers around 13% 

of the total gas feed to Bontang, one of the world’s largest LNG plants. The 

Bontang plant produced 18.4 million tonnes of LNG in 2008.

• Also in Indonesia, BP has interests in the Tangguh LNG joint venture (BP 

37.2% and operator) and in each of the Wiriagar (BP 38% and operator), 

Berau (BP 48% and operator) and Muturi (BP 1%) PSAs in north-west 

Papua that are expected to supply feed gas to the Tangguh LNG plant. 

During 2008, construction continued on two LNG trains and the offshore 

facilities, with commercial delivery planned in the second quarter of 2009. 

Tangguh will be the third LNG centre in Indonesia, with an expected initial 

capacity of 7.6 million tonnes of LNG (388,000mmcf) per year. Tangguh has 

signed LNG sales contracts for delivery to China, Korea and North America.

• In Australia, we are one of seven partners in the North West Shelf 

(NWS) venture. The joint venture operation covers offshore production 

platforms, an FPSO, trunklines, onshore gas and LNG processing plants and 

LNG carriers. BP’s net share of the capacity of NWS LNG Trains 1-5 is 

2.7 million tonnes of LNG per year.

• BP has a 30% equity stake in the 7 million tonne per annum capacity 

Guangdong LNG re-gasification and pipeline project in south-east China, 

making it the only foreign partner in China’s LNG import business. In addition 

to LNG supplied under a long-term contract with Australia’s NWS project, the 

terminal took delivery of an additional eight spot LNG cargoes during 2008, 

to meet rapidly growing local demand for gas.

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Performance review

Gas marketing and trading activities 

Gas and power marketing and trading activity is undertaken primarily in the 

US, Canada, the UK and Europe to market both BP production and third-party 

natural gas and manage market price risk as well as to create incremental 

trading opportunities 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. 

 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 

marketplace. 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. Natural gas futures and options are traded through exchanges, while 

over-the-counter (OTC) options and swaps are used for both gas and power 

transactions through bilateral and/or centrally cleared arrangements. Futures 

and options are primarily used to trade the key index prices such as Henry 

Hub, while swaps can be tailored to price with reference to specific delivery 

locations where gas and power can be bought and sold. OTC 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 both to sell production into the wholesale markets and as 

trading instruments to buy and sell gas and power in future periods. Storage 

and transportation contracts allow the group to store and transport gas, and 

transmit power between these locations. The group has developed a risk 

governance framework to manage and oversee the financial risks associated 

with this trading activity, which is described in Note 28 to the Financial 

statements on pages 140-145. 

 The range of contracts that the group enters into is described below in 

more detail: 

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 total revenues for accounting purposes.

OTC contracts 

These contracts are typically in the form of forwards, swaps and options. 

Some of these contracts are traded bilaterally between counterparties; others 

may be cleared by a central clearing counterparty. These contracts can be 

used for both trading and risk management activities. Realized and unrealized 

gains and losses on OTC contracts are included in total revenues for 

accounting purposes. 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 

• BP Shipping took delivery of four LNG ships during 2007 and 2008. The 

‘Gem’ class ships can carry 155,000m3 of LNG and are among the first ships 

in the industry to be powered by low-emission, fuel-efficient, diesel-electric 

propulsion. BP Shipping provides safe, environmentally responsible marine 

and shipping solutions in support of BP group activities.

• In both the Atlantic and Asian regions, BP is marketing LNG using BP LNG 

shipping and contractual rights to access import terminal capacity in the 

liquid markets of the US (via Cove Point and Elba Island) and the UK (via the 

Isle of Grain), and is supplying Asian customers in Japan, South Korea and 

Taiwan.

delivery and settlement at a future date. Typically, these contracts specify 

delivery terms for the underlying commodity. Certain 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 dispatch. The contracts contain standard 

terms such as delivery point, pricing mechanism, settlement terms and 

specification of the commodity. Typically, volume and price are the main 

variable terms. Swaps can be contractual obligations to exchange cash flows 

between two parties. One usually references a floating price and 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 natural gas products 

or power 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. 

Spot and term contracts 

Spot contracts are contracts to purchase or sell a commodity at the market 

price, typically an index price prevailing on the delivery date when title to the 

inventory passes. 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. 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. Spot and term sales 

are included in total revenues, when title passes. Similarly, spot and term 

purchases are included in purchases for accounting purposes. 

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Performance review

Refining and Marketing 

Our Refining and Marketing business is responsible for the supply and trading, 

refining, manufacturing, marketing and transportation of crude oil, petroleum, 

chemicals products and related services to wholesale and retail customers. 

BP markets its products in more than 100 countries. We operate primarily in 

Europe and North America and also manufacture and market our products 

across Australasia, in China and other parts of Asia, Africa and Central and 

South America. 

 In 2008 we restructured the Refining and Marketing organization into 

two main business groupings: fuels value chains (FVCs) and international 

businesses (IBs). The FVCs integrate the activities of refining, logistics, 

marketing, supply and trading, on a regional basis, recognizing that the 

markets for our main fuels products operate regionally. This shift to a more 

geographic and integrated model represents a major simplification step and 

the opportunity to create better value from our physical assets (refineries, 

terminals, pipelines and retail stations). The IBs include the manufacturing, 

supply and marketing of lubricants, petrochemicals, liquefied petroleum gas 

(LPG) and aviation and marine fuels. We believe each of these IBs is 

competitively advantaged in the markets in which we have chosen to 

participate. Such advantage is derived from several factors, including location, 

proximity of manufacturing assets to markets, physical asset quality, 

operational efficiency, technology advantage and the strength of our brands. 

Each business has a clear strategy focused on investing in its key assets and 

market positions in order to deliver value to its customers and outperform its 

competitors. 

 During the past five years, our focus has been on process safety, 

upgrading organizational capability and significant integrity management 

investment. The construction of new production units at many of our refineries 

as well as upgrades of existing conversion units at a number of our facilities 

has positioned our assets to produce the high-quality fuels needed to meet 

today’s heightened product specifications. 

Our performance in 2008 

The 2008 environment in which the segment operated was very challenging, 

characterized by high and volatile crude and product prices, which resulted in 

substantial margin volatility as well as higher energy costs in manufacturing. 

Crude prices fell significantly in the second half of the year and at the end of 

the year, prices were around $50/bbl lower than the start of the year. Refining 

margins in the US were significantly weaker than 2007 due to weaker gasoline 

demand. Conversely, in Europe, where diesel accounts for a larger share of 

regional demand, margins were stronger than a year ago. Demand for fuels 

has fallen, initially due to high oil prices and subsequently due to the slowing 

of global economies and the impact of the financial crisis. During the fourth 

quarter, we saw a dramatic decline in the demand for our petrochemicals 

products as a consequence of the economic slowdown. The year also saw 

material swings in foreign exchange rates, particularly in the second half, that 

affected our results. 

 Our 2008 performance reflects the benefits of the fundamental 

improvements we are making across the business, including the measures we 

have taken to restore the availability of our refining system, reduce costs and 

simplify the organization. The loss before interest and tax was $1.9 billion for 

2008, compared with a profit before interest and tax of $6.1 billion in 2007. 

The decrease was primarily driven by inventory-holding losses. Our financial 

results are discussed in more detail on pages 50-51. 

Safety, both process and personal, remains our top priority. During 2008, we 

started the migration to the new BP Operating Management System 

(OMS) with an increased focus on process safety and continuous 

improvement. The OMS is described in further detail on page 40. At the end of 

the year, two of our petrochemicals plants in the US and two of our refineries 

in Europe were operating on OMS. Within our US refineries, we continue to 

implement the recommendations from the BP US Refineries Independent 

Safety Review Panel. We have worked closely with the independent expert, L 

Duane Wilson. The number of major incidents associated with integrity 

management has decreased by 90% since 2005. We have also reduced the 

number of oil spills by 60% and the recordable injury rate by more than 57% 

since 1999. Regrettably, in 2008 there were four workforce fatalities 

associated with our operations, one of which was a process safety incident. 

 In 2008, we saw the first substantial benefits of our operational 

improvements. The Whiting refinery was restored to its full clean fuel capability 

of 360mb/d in March 2008 following the compressor failure and fire that took 

place during 2007. Texas City was also restored to full economic capability by 

the end of the year. In Europe and Rest of World, we commissioned new 

upgrading units at the Rotterdam and Kwinana refineries, enhanced 

processing capability at the Gelsenkirchen refinery, reconfigured the Bayernoil 

refinery for more efficient and competitive operation, and completed 

construction of a new coker at the Castellón refinery. During the next five 

years, we intend to continue the focus on process safety, improve the 

competitive performance of our refineries and complete the previously 

announced investment in the Whiting refinery to increase its ability to process 

Canadian heavy crude. 

 In total, our 17 refineries worldwide, including those partially owned, 

achieved throughputs of 2,155mb/d on average, a 5% increase on 2007 after 

adjusting for the net loss of throughput from previous disposals and 

acquisitions. The performance of Texas City was impacted by Hurricane Ike in 

September, which meant we had to shut down the refinery in advance as a 

precautionary measure, along with other refineries in the area. Operational 

disruption was minimized as crude processing was restored in seven days and 

full operations restored within three weeks. This was due to a terrific response 

from employees and also reflected the improvements we have made to our 

assets at Texas City over the last few years. 

 During 2008, we fully integrated our refining, logistics, marketing, supply 

and trading activities, establishing six refining-to-marketing integrated FVCs 

focused on refining and selling ground transportation fuels in each region. This 

has enabled us to simplify internal interfaces, optimize margins, reduce 

overhead costs and drive continuous improvement. During the year, we 

continued the implementation of our ampm convenience retail franchise model 

in the US, which we expect to provide reliable long-term sales growth for our 

refinery systems, together with reduced costs and lower levels of capital 

investment. In Europe, where we are one of the largest forecourt convenience 

retailers, with about 2,500 shops in 10 countries, we are growing our food-onthe-go and fresh grocery services through BP-owned brands and partnerships 

with leading retailers such as Marks & Spencer. 

 In relation to our IBs during 2008, in the lubricants business we focused 

on enhancing our customer relationships and brand distinctiveness, together 

with simplifying operations and improving efficiency. Although 2008 was a 

difficult year for the aviation industry, in Air BP, we simplified our footprint by 

exiting non-core countries resulting in a reduction in working capital and 

improved returns on operating capital employed. During the year, the 

environment in which our petrochemicals businesses operate became more 

challenging as deterioration in the global economic market led to reduced 

demand for our products. 

 We are simplifying the structure of our organization, improving the 

efficiency of our back office and reducing our headcount, including the number 

of senior management positions. 

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Looking ahead, in 2009 the overall economic environment is expected to be 

challenging with reduced demand for our products leading to lower volumes 

and pressure on margins. The impact is expected to be greatest in the 

petrochemicals sector. 

 Against this background, we intend to continue actively managing our 

cost base, simplifying our marketing footprint and developing the market 

positions where we have competitive advantage based on brand and 

technology strengths. We also intend to improve the efficiency of our back 

office, including customer service, accounting services and procurement 

systems, by centralizing these activities in a few global centres to remove 

duplication and reduce cost. We intend to focus on cash generation through 

active management of our working capital and credit exposure. 

 We intend to limit our capital investment to maintaining and improving 

our core positions. To continue the progress we have made in recent years, 

our top priority for spending will remain safety and operational integrity. The 

other area of focus will be delivering integrated value in our key markets 

through investment in terminals and pipeline infrastructure. Our largest 

investment is expected to be at the Whiting refinery, where we have started a 

major upgrading and modernization programme that will enable the refinery to 

operate on Canadian heavy crude oil. We also intend to complete the planned 

projects in petrochemicals (see page 32). 

 Comparative information presented in the table below has been 

restated, where appropriate, to reflect the resegmentation, following transfers 

of businesses between segments, that was effective from 1 January 2008. 

See page 12 for further details. 

Key statistics 

Total revenues are analysed in more detail below. 

$ million

2008 2007 2006

Total revenuesa 320,458 250,897 232,833

Profit before interest and tax from continuing 

operationsb (1,884) 6,076 5,419

Total assets 75,329 95,311 80,738

Capital expenditure and acquisitions 6,634 5,495 3,127 

$ per barrel

Global Indicator Refining Marginc 6.50 9.94 8.39

a Includes sales between businesses.

b Includes profit after interest and tax of equity-accounted entities.

c 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 analyzing 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.

$ million

2008 2007 2006

Sale of crude oil through spot and term 

contracts 54,901 43,004 38,577

Marketing, spot and term sales of refined 

products 248,561 194,979 177,995

Other sales and operating revenues 16,577 12,238 15,814 

Earnings from equity-accounted entities (after 

interest and tax), interest, and other 

revenues 419 676 447 

 320,458 250,897 232,833

thousand barrels per day

Sale of crude oil through spot and term 

contracts 1,689 1,885 2,110

Marketing, spot and term sales of refined 

products 5,698 5,624 5,801 

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

Marketing volumes were 3,711mb/d, slightly lower than last year, reflecting the 

impacts from the slowing of global economies and reduced industry demand in 

the US and Europe. 

Fuels value chains 

Following our reorganization we have six integrated FVCs. They are organized 

regionally, covering the West Coast and Mid-West regions of the US, the 

Rhine region, Southern Africa, Australasia (ANZ) and Iberia. Each of these is 

a material business, optimizing activities across the supply chain – from crude 

delivery to the refineries; manufacture of high-quality fuels to meet market 

demand; pipeline and terminal infrastructure and the marketing and sales to 

our customers. The Texas City refinery is operated as a standalone 

predominantly merchant refining business that also supports our marketing 

operations on the east and gulf coasts. 

Refining 

The group’s global refining strategy is to own and 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 its competitive 

position through sustainable, safe, reliable and efficient operations of the 

refining system and disciplined investment for integrity management, to 

achieve competitively advantaged configuration and growth. 

 For BP, the strategic advantage of a refinery relates to its location, scale 

and configuration to produce fuels from lower-cost feedstocks in line with the 

demand of the region. Strategic investments in our refineries are focused on 

securing the safety and reliability of our assets while improving our competitive 

position. In addition, we continue to invest to develop the capability to produce 

the cleaner fuels that meet the requirements of our customers and their 

communities. 

thousand barrels per day

Sales of refined productsa 2008 2007 2006

Marketing sales

UKb 310 339 356

Rest of Europe 1,256 1,294 1,340 

US 1,460 1,533 1,595

Rest of World 685 640 581

Total marketing salesc 3,711 3,806 3,872 

Trading/supply salesd 1,987 1,818 1,929

Total refined products 5,698 5,624 5,801

 $ million 

Proceeds from sale of refined products 248,561 194,979 177,995 

a Excludes sales to other BP businesses, sales of Aromatics & Acetyls products and Olefins & 

Derivatives sales through equity-accounted entities.

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 and 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.

thousand barrels per day

Marketing sales by refined product 2008 2007 2006

Aviation fuel 501 490 488

Gasolines 1,500 1,572 1,603 

Middle distillates 1,055 1,119 1,170

Fuel oil 460 429 388

Other products 195 196 223

Total marketing sales 3,711 3,806 3,872

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The following table summarizes the BP group’s interests in refineries and crude distillation capacities at 31 December 2008. 

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 is summarized. 

29

Performance review

thousand barrels per day

Crude distillation capacitiesa

Group interestb BP

Refinery Fuels value chain % Total share

Rest of Europe

Germany Bayernoil Rhine 22.5% 215 48

Gelsenkirchen* Rhine 50.0% 266 133

 Karlsruhe Rhine 12.0% 323 39

Lingen* Rhine 100.0% 93 93

Schwedt Rhine 18.8% 226 42

Netherlands Rotterdam* Rhine 100.0% 386 386

Spain Castellón* Iberia 100.0% 110 110

Total Rest of Europe 1,619 851

US 

California Carson* US West Coast 100.0% 266 266

Washington Cherry Point* US West Coast 100.0% 234 234

Indiana Whiting* US Mid-West 100.0% 405 405

Ohio Toledo* US Mid-West 50.0% 155 78

Texas Texas City* – 100.0% 475 475

Total US 1,535 1,458 

Rest of World

Australia Bulwer* ANZ 100.0% 102 102

 Kwinana* ANZ 100.0% 137 137

New Zealand Whangerei ANZ 23.7% 102 24

Kenya Mombasac Southern Africa 17.1% 94 16

South Africa Durban Southern Africa 50.0% 180 90

Total Rest of World 615 369

Total 3,769 2,678

*Indicates refineries operated by BP.

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

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

cOn 15 January 2008, it was announced that Essar Energy Overseas Ltd, a subsidiary of Essar Oil Limited, had entered into an agreement to acquire 50% of Kenya Petroleum Refineries Ltd. 

 The transaction was initially expected to be finalized in 2008, but has since been delayed in negotiations.

thousand barrels per day

Refinery throughputsa 2008 2007 2006 

UK – 67 165

Rest of Europe 739 691 648

US 1,121 1,064 1,110

Rest of World 295 305 275

Total 2,155 2,127 2,198

Refinery capacity utilization

Crude distillation capacity at 31 Decemberb 2,678 2,769 2,823

Crude distillation capacity utilizationc 78% 72% 76%

US 72% 62% 70%

Europe 85% 84% 87%

Rest of World 83% 84% 78%

aRefinery throughputs reflect crude and other feedstock volumes.

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

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

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Excluding portfolio impacts, underlying refining throughputs in 2008 increased 

by 5% relative to 2007, driven principally by improved operational performance 

in the US. Higher US throughputs were attributable to the recoveries at the 

Texas City and Whiting refineries, partially offset by the reduced equity 

interest in the Toledo refinery stemming from the Husky joint venture (see 

below). The improvement achieved in the US was lower than it would have 

been as crude runs were reduced as a result of the low-margin environment 

as well as the disruption at the Texas City refinery in September caused by 

Hurricane Ike. 

 The increase in Rest of Europe throughputs in 2008 is primarily related 

to the purchase of Chevron’s 31% interest in the Rotterdam refinery in 2007. 

The decrease in UK throughputs is due to the sale of the Coryton refinery to 

Petroplus. 

 Significant events in Refining were as follows: 

Fuels marketing, supply and logistics 

Our fuels marketing strategy focuses on optimizing the integrated value of 

each fuels value chain that is responsible for the delivery of ground fuels to the 

market. We do this by co-ordinating our marketing, refining and trading 

activities to maximize synergies across the whole value chain. Our priorities 

are to operate an advantaged infrastructure and logistics network (which 

includes pipelines, storage terminals and road or rail tankers), drive excellence 

in operating and transactional processes and deliver compelling customer 

offers in the various markets where we operate. The fuels business markets a 

comprehensive range of refined oil products primarily focused on the ground 

fuels sector. 

 On 29 August 2008, BP announced an agreement with Enbridge Inc. to 

build and reconfigure a pipeline system to transport Canadian heavy crude oil 

from Flanagan, Illinois, to Houston and Texas City, Texas. The system is 

expected to be in service by late 2012 with an initial capacity of 250mb/d. The 

joint investment of the phased capacity additions is expected to be in the 

range of $1-2 billion. 

 The ground fuels business supplies fuel and related convenience 

services to retail consumers through company-owned and franchised retail 

sites as well as other channels including wholesalers and jobbers. It also 

supplies commercial customers within the road and rail transport sectors. 

 BP’s value creation in ground fuels is obtained through the integration of 

the value chain from the refinery gates or import hubs across retail and 

commercial channels to market. Convenience retail offers are focused on 

delivering appealing convenience offers across the various markets in which 

we operate, through the BP Connect, ampm and Aral brands. 

• On 21 March 2008, the Whiting refinery in the US was restored to its full 

clean fuel capability of 360mb/d.

• BP completed recommissioning the Texas City refinery in the US. With the 

successful return to service of Ultraformer No. 3 in the fourth quarter, the 

site’s full economic capability was restored.

• On 31 March 2008, we completed a deal with Husky Energy Inc. to create an 

integrated North American oil sands business by means of two separate joint 

ventures, one of which entailed Husky taking a 50% interest in BP’s Toledo 

refinery. The Toledo refinery is intended to be expanded to process 

approximately 170mb/d of heavy oil and bitumen by 2015.

• In July, a final investment decision was taken to progress the significant 

upgrade of the Whiting refinery. This project repositions Whiting 

competitively by increasing its Canadian heavy crude processing capability 

by 260mb/d and modernizing it with equipment of significant size and scale.

• On 17 March 2008, BP and Irving Oil entered into a memorandum of 

understanding to work together on evaluating the feasibility of the proposed 

Eider Rock refinery in Saint John, New Brunswick, Canada.

Our retail network is largely concentrated in Europe and the US, and also has 

established operations in Australasia and southern and eastern Africa. We are 

developing networks in China in two separate joint ventures, one with 

Petrochina and the other with China Petroleum and Chemical Corporation 

(Sinopec). 

At 31 December 2008, BP’s worldwide network consisted of some 22,600 

locations branded BP, Amoco, ARCO and Aral, around the same as in the 

previous year. We continue to improve the efficiency of our retail network and 

increase the consistency of our site offer through a process of regular review. 

In 2008, we sold 470 company-owned sites to dealers, jobbers and 

franchisees who continue to operate these sites under the BP brand. We also 

divested an additional 160 company-owned sites to third parties. 

 At 31 December 2008, BP’s retail network in the US comprised 

approximately 11,700 sites, of which approximately 9,200 were owned by 

jobbers and 900 operated under a franchise agreement. In November 2007, 

BP announced that it would sell all of its company-owned and companyoperated convenience sites in the US. Despite the challenges in the global 

credit market, we expect the sale of these sites to be completed by the end of 

2009. At the end of 2008, sales of 293 of sites had been successfully 

completed. The sites will continue to market BP-branded fuels in the eastern 

US and ARCO-branded fuels in the western US. The franchise agreement has 

a term of 20 years and requires sites to be supplied with BP- or ARCObranded fuels for the term of the contract. 

 At the end of 2008, our European retail network consisted of 

approximately 8,600 sites and we had approximately 2,300 sites in the Rest of 

World. 

 Our retail convenience operations offer consumers a range of food, 

drink and other consumables and services on the fuel forecourt in a safe, 

convenient and innovative manner. With operations in both Europe and the 

US, using recognized and distinctive brands, BP is working to maximize the 

efficiency and effectiveness of its retail network in each of its chosen market 

areas. By the end of 2008, we completed the roll-out of more than 100 Marks 

& Spencer Simply Food sites as an integral part of the convenience network in 

the UK, while a refresh of the Petit Bistro brand in Germany and the Wild Bean 

Café brand in other European locations has re-energized consumers’ 

convenience shopping choices. In the US, BP has embarked on a roll-out of 

its successful ampm brand across all targeted national markets as its single 

convenience flagship; this programme roll-out is intended to be completed by 

the end of 2009. 

Number of retail sites operated under a BP brand

Retail sitesa b 2008 2007 2006 

UK 1,200 1,200 1,300 

Rest of Europe 7,400 7,400 7,700

US (excluding jobbers) 2,500 2,500 2,700

US jobbers 9,200 9,700 9,600 

Rest of World 2,300 2,500 2,600

Total 22,600 23,300 23,900

aChanges in the number of retail sites over time are affected by, among other things, dealer/jobberowned sites that move to or from the BP brand as their fuel supply agreements expire and are 

renegotiated in the normal course of business.

bExcludes our interest in equity-accounted entities. Comparative information has been amended to this 

basis.

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Supply and trading

The group has a long-established integrated supply and trading function 

responsible for delivering value across the overall crude and oil products 

supply chain. This structure enables BP to maintain a single face to the oil 

trading markets and to operate with a single set of trading compliance 

processes, systems and controls. Operating through trading offices located in 

Europe, the US and Asia, the function is able to maintain a presence in the 

regionally connected global markets. 

 The function seeks to identify the best markets and prices for our crude 

oil, source optimal feedstocks for our refineries and provide competitive supply 

for our marketing businesses. In addition, where refinery production is surplus 

to marketing requirements or can be sourced more competitively, it is sold into 

the market. Wherever possible, the group will look to optimize value across 

the supply chain. For example, BP will often sell its own crude production into 

the market and purchase alternative crude for its refineries where this will 

provide incremental margin. 

 In addition to the supply activity described above, the function seeks to 

create incremental trading opportunities. It enters into the full range of 

exchange-traded commodity derivatives, over-the-counter (OTC) contracts 

and spot and term contracts that are described in detail below. In order to 

facilitate the generation of trading margin from arbitrage, blending and storage 

opportunities, it also both owns and contracts for storage and transport 

capacity. The group has developed a risk governance framework to manage 

and oversee the financial risks associated with this trading activity, which is 

described in the Financial statements – Note 28 on pages 140-145. 

 The range of transactions that the group enters into is described below: 

Exchange-traded commodity derivatives 

These contracts are typically in the form of futures and options traded on a 

recognized exchange, such as Nymex, SGX, ICE 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 gasoil. 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 oil and refined products. Realized and unrealized gains and losses 

on exchange-traded commodity derivatives are included in total revenues for 

accounting purposes. 

OTC contracts 

These contracts are typically in the form of forwards, swaps and options. 

Some of these contracts are traded bilaterally between counterparties; others 

may be cleared by a central clearing counterparty. 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 total revenues 

for accounting purposes. 

 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 or BFO). Although the contracts specify physical 

delivery terms for each crude blend, a significant volume are not settled 

physically. The contracts typically contain standard delivery, pricing and 

settlement terms. Additionally, the BFO contract specifies a standard volume 

and tolerance given that the physically settled transactions are delivered by 

cargo. 

Swaps are often contractual obligations to exchange cash flows between two 

parties: a typical swap transaction usually references a floating price and 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. 

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 when title to the 

inventory is taken. 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. These transactions result in physical delivery with operational and price 

risk. Spot and term contracts relate typically to purchases of crude for a 

refinery, purchases of products for marketing, sales of the group’s oil 

production and sales of the group’s oil products. For accounting purposes, 

spot and term sales are included in total revenues, when title passes. 

Similarly, spot and term purchases are included in purchases for accounting 

purposes. 

International businesses 

Our IBs provide quality products and offers to customers in more than 100 

countries worldwide with a significant focus on Europe, North America and 

Asia. Our products include aviation and marine fuels, lubricants that meet the 

needs of various industries and consumers, LPG, and a range of 

petrochemicals that are sold for use in the manufacture of other products such 

as fabrics, fibres and various plastics. 

Lubricants 

We manufacture and market lubricants and related products and services to 

the automotive, industrial, marine and energy markets across the world. 

Following a decision to simplify and focus our channels of trade, we now sell 

products direct to our customers in around 50 countries and use approved 

local distributors for the remaining locations. Customer focus, distinctive 

brands, superior technology and relationships remain the cornerstones of our 

long-term strategy. 

 BP markets primarily through its major brands of Castrol and BP, plus 

the Aral brand in some specific markets. Castrol is recognized as one of the 

most powerful lubricants brands worldwide and we believe it provides us with 

a significant competitive advantage. In the automotive lubricants sector, we 

supply lubricants and other related products and services to intermediate 

customers such as retailers and workshops. These, in turn, serve endconsumers such as car, truck and motorcycle owners in the mature markets of 

Western Europe and North America as well as the markets of Russia, China, 

India, the Middle East, South America and Africa, which we believe have the 

potential for significant long-term growth. 

 BP’s marine lubricants business is a global market leader, supplying 

many types of vessels from deep-sea fleets to marine leisure-craft from 

around 1,200 ports across the globe. BP’s industrial lubricants business is a 

leading supplier to those sectors of the market involved in the manufacture of 

automobiles, trucks, machinery components and steel. BP is also a leading 

supplier of lubricants for the offshore oil and aviation industries. 

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Petrochemicals

Our petrochemicals operations are comprised of the global Aromatics & 

Acetyls businesses (A&A) and the Olefins & Derivatives (O&D) businesses, 

predominantly in Asia. New investments are targeted principally in the higher 

growth Asian markets. 

 In A&A, we manufacture and market three main product lines: purified 

terephthalic acid (PTA), paraxylene (PX) and acetic acid. Our A&A strategy is 

to leverage our industry-leading technology in selected markets, to grow the 

business and to deliver industry-leading returns. PTA is a raw material used in 

the manufacture of polyesters used in fibres, textiles and film, and PET 

bottles. Acetic acid is a versatile intermediate chemical used in a variety of 

products such as paints, adhesives and solvents, as well as its use in the 

production of PTA. We have a strong global market share in the PTA and 

acetic markets with a major manufacturing presence in Asia, particularly 

China. PX is a feedstock for PTA production. 

 In O&D, we manufacture ethylene and propylene from naphtha and also 

produce a number of downstream derivative products.

 Our O&D business has operations in both China and Malaysia. In 

China, our SECCO joint venture between BP, Sinopec and its subsidiary, 

Shanghai Petrochemical Company is the largest foreign-invested olefins 

cracker in China. SECCO is BP’s single largest investment in China. This 

naphtha cracker produces ethylene and propylene plus derivatives 

acrylonitrile, polyethylene, polypropylene, styrene, polystyrene, and other 

products. In Malaysia, BP participates in two joint-ventures: Ethylene Malaysia 

Sdn. Bhd. (EMSB), which produces ethylene from gas feedstock in a joint 

venture between BP, Petronas and Idemitsu; while Polyethylene Malaysia 

Sdn. Bhd. (PEMSB) produces polyethylene in a joint venture between BP and 

Petronas. Each of these ventures has demonstrated a strong track record of 

project delivery and performance. BP also owns one other naphtha cracker 

outside Asia, which is integrated with our Gelsenkirchen refinery in Germany. 

 The following table shows BP’s petrochemicals production capacity at 

31 December 2008. This production capacity is based on the original design 

capacity of the plants plus expansions. 

BP share of capacity

During 2008, the environment in which our petrochemicals businesses operate 

became more challenging as deterioration in the global economic environment 

has led to a reduced demand for our products. 

thousand tonnes per year

Acetic

Geographic area PTA PX acid Other O&D Total

US 2,385 2,373 546 151 – 5,455

Europe 1,075 622 544 158 1,629 4,028 

Asia (excluding China) 2,209 – 815 56 257 3,337

China 1,554 – 215 51 2,290 4,110 

 7,223 2,995 2,120 416 4,176 16,930 

Significant events in petrochemicals were as follows:

Aviation and marine fuels 

Air BP is one of the world’s largest and best known aviation fuels suppliers, 

serving all the major commercial airlines as well as the general aviation and 

military sectors. During 2008, which was a tough year for the aviation industry, 

we simplified our geographical footprint by exiting non-core countries and now 

supply customers in approximately 70 countries. We have annual marketing 

sales in excess of 27 billion litres and we have relationships with many of the 

world’s major commercial airlines. Air BP’s strategic aim is to grow its position 

in the core locations of Europe, the US, Australasia and the Middle East, while 

focusing its portfolio towards airports that offer long-term competitive 

advantage. BP’s marine fuels business focuses on the distribution and sale of 

refined fuel oils to the shipping industry at locations in more than 100 ports 

across the world. During 2008, this business performed well, supported by 

strong growth in the shipping market. 

LPG 

The LPG business sells bulk, bottled, automotive and wholesale LPG products 

to a wide range of customers in 13 countries. During the past few years, our 

LPG business has consolidated its position in established markets, pursued 

opportunities in new and emerging markets such as China and announced the 

exit from the Vietnam market in December 2008. LPG product sales in 2008 

were approximately 68mbpd.

• The second PTA plant at the BP Zhuhai Chemical Company Limited site in 

Guangdong province (China) successfully completed commissioning in the 

first quarter of 2008. This 900+ ktepa plant is the single largest PTA 

manufacturing train in the world and employs BP’s latest, proprietary 

technology.

• Construction continued on the new 500ktepa acetic acid plant in Jiangsu 

province (China) by BP YPC Acetyls Company (Nanjing) Limited (BYACO). 

This is a BP joint venture with Yangzi Petrochemical Co. Ltd (a subsidiary of 

Sinopec). Construction is scheduled to be completed in June 2009 with 

commercial sales expected to begin in the third quarter of 2009.

• Commissioning of our expanded Geel (Belgium) PTA facility commenced at 

the end of 2008. The 350ktepa expansion improves overall operating costs 

and increases the site’s PTA capacity to 1,425ktepa.

• In January 2008, BP and Sinopec signed a memorandum of understanding 

to add a new acetic acid plant at their Yangtze River Acetyls Co. 

(YARACO) joint venture site in Chongqing (China). This world-scale 

(650ktepa) acetic acid plant will use BP’s leading CativaTM technology. The 

expected plant start-up date, which was originally anticipated to be during 

2011, is under review due to the market conditions. When complete, total 

production at the YARACO site is expected to be well over one million 

tonnes per annum, making this one of the largest acetic acid production 

locations in the world.

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Other businesses and corporate 

Other businesses and corporate comprizes Treasury (which includes interest 

income on the group’s cash and cash equivalents) and corporate activities 

worldwide, the group’s aluminium asset, the Alternative Energy business and 

Shipping. 

 Comparative information presented in the table below has been 

restated, where appropriate, to reflect the resegmentation, following transfers 

of businesses between segments, that was effective from 1 January 2008. 

See page 12 for more details. 

Key statistics 

Treasury 

Treasury co-ordinates the management of the group’s major financial assets 

and liabilities. From locations in the UK, the US 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. 

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 are therefore borne as they arise, rather than being spread over time 

through insurance premiums with attendant transaction costs. This position is 

reviewed periodically. 

Aluminium 

Our aluminium business is a non-integrated producer and marketer of rolled 

aluminium products, headquartered in Louisville, Kentucky, US. Production 

facilities are located in Logan County, Kentucky, and are jointly owned with 

Novelis. The primary activity of our aluminium business is the supply of 

aluminium coil to the beverage can business, which it manufactures primarily 

from recycled aluminium. 

$ million

2008 2007 2006

Total revenuesa 5,040 3,972 3,703

Profit (loss) before interest and tax from 

continuing operationsb (1,258) (1,233) (779)

Total assets 19,079 20,595 16,315

Capital expenditure and acquisitions 1,839 939 852

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

Alternative Energy 

BP invested $1.4 billion in our Alternative Energy business during 2008, 

bringing the total investment in this business to $2.9 billion since its launch in 

2005. We expect to fulfil our original 2005 commitment to invest a total of 

$8 billion over 10 years. In 2008, we prioritized four areas with significant longterm growth potential – wind, solar, biofuels and carbon capture and storage 

(CCS). We have also developed a fifth area – gas-fired power – that offers 

synergies with other BP operations. We have concentrated our 2008 

investment in these areas. 

Wind 

Since the launch of Alternative Energy we have substantially grown our wind 

portfolio, increasing from 32 megawatts (MW) in operation to 432MW (785MW 

gross) at the end of 2008. In total, we have more than 500MW (1,000MW 

gross) of installed capacity. This increase in capacity was led by the US with 

installations at Cedar Creek, Silver Star, Sherbino and Edom Hills. 

 To accelerate our growth in the US wind energy market, we acquired 

two fully integrated wind power development companies – Greenlight Energy 

Inc. and Orion Energy LLC, during 2006. To secure the continuing availability 

of turbines we have signed agreements with Nordex (Germany) and GE (the 

US) for a combined 900MW to be delivered during the next two years. This is 

in addition to a five-year wind turbine contract we previously signed with 

Clipper Windpower Inc. in 2006. 

 We also operate wind farms in the Netherlands and in Maharashtra, 

India. 

Solar 

We continued to implement BP Solar’s strategy to invest in lower cost 

manufacturing and technology to enable energy sourced from our products to 

compete with conventional electricity. Our global business model spans the 

entire solar ‘value chain’ – from the acquisition of silicon as a raw material, the 

production of wafers and cells to the creation of solar panels that are then sold 

and distributed as solar systems on the roofs of residential homes, large 

commercial buildings and on vacant land. 

 Today, BP Solar’s main production facilities are located in Maryland 

(US), Madrid (Spain), Xi’an (China) and Bangalore (India). During 2008, due to 

increasingly competitive market conditions, BP Solar announced plans to 

refocus operations at larger scale plants to achieve lower-cost manufacturing. 

This resulted in the start of an intensive programme of operational efficiency 

improvement in the remaining BP Solar plants and plans to close our 

manufacturing plant in Australia. During 2008, BP Solar signed contracts with 

a select set of third-party strategic partners in Asia who specialize in the 

production of low-cost, high-quality wafers, cells and modules. 

 During 2008, BP Solar achieved sales of 162MW, an increase of 41% 

from 115MW in 2007. The slight decrease in solar production capacity was 

due to fire damage in a section of our manufacturing plant in India. 

2008 2007 2006

Wind – net rated capacity as at year-end 

(megawatts)a 432 172 43

Solar – cell production capacity as at year-end 

(megawatts)b 213 228 201 

aNet wind capacity is the sum of the rated capacities of the assets/turbines that have entered into 

commercial operation, including BP’s share of equity-accounted entities. The equivalent capacities on a 

gross-JV basis (which includes 100% of the capacity of equity-accounted entities where BP has partial 

ownership) were 785MW in 2008, 373MW in 2007 and 43MW in 2006.

bSolar capacity is the theoretical cell production capacity per annum of in-house manufacturing facilities.

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More than 70% of our sales volume is through third-party distributors in the 

residential markets in Europe, the US and Australasia. We have continued to 

roll out our Certified Installer Programme (CIP), first established in Germany, 

to ensure the safe, high-quality installation of products by third parties. The 

CIP has grown rapidly in Germany and this year has been rolled out in Spain 

and Australia. 

 In the US, in 2008, we continued to supply large corporations with 

sustainable energy solutions, completing a second solar system for FedEx 

Freight in California and a further six installations for Wal-Mart. In Europe, we 

expanded the relationship with Banco Santander to jointly build and finance a 

number of solar plants in Spain, with the construction of an 8 megawatts-peak 

(MWp) solar farm in Toledo and a 6MWp project in Tenerife. In Asia, we 

completed the installation of a solar power demonstration project (SolarSail) at 

the Guangdong Science Center; the SolarSail absorbs sunlight to produce 

power, while providing cool shade for visitors. In Australia, the largest roof-top 

solar system (100 kilowatt) in New South Wales commenced operation in 

February 2008, representing the first commercial solar power installation for 

the Blacktown Solar City Project. The Solar Cities Programme is a 

government initiative to implement distributed solar and other energy efficient 

technologies in seven Australian cities. 

 We are developing a new silicon growth process named Mono2 TM, 

which will increase cell efficiency over traditional multicrystalline-based solar 

cells. We have moved from a prototype to low-volume production and have 

converted our casting stations in Frederick, Maryland, delivering 1.2MW 

Mono2 TM. From the trials, we are seeing significant improvement in power and 

generated kWh when compared with multicrystalline-based solar cells 

particularly when modules are used where sunlight is low. 

 BP Solar has long-term relationships with world-class universities and 

invests in research programmes with organizations including the University of 

Delaware, California Institute of Technology (Cal Tech) and the Fraunhofer 

Institute (Germany). BP Solar was selected for the Solar America Initiative 

(SAI) award from the US Department of Energy – a $40-million research and 

development programme aimed at decreasing the cost of solar cells and 

increasing their efficiency. BP Solar is also a member of the broad consortium 

led by DuPont in conjunction with the University of Delaware, funded by the 

Defense Advanced Research Projects Agency (DARPA), to develop highefficiency solar cells. 

Biofuels 

BP has a key role to play in enabling the transport sector to respond to the 

dual challenges of energy security and climate change. Our investments are 

focused on sustainable feedstocks that minimize pressure on food supplies 

and on research into advanced technologies and practices to make good 

biofuels even better. 

 We have embarked on a focused programme of biofuels development 

based around the most efficient transformation of sustainable and low-cost 

sugars into a range of fuel molecules. These include bioethanol from Brazilian 

sugar cane, more efficient fuel molecules like biobutanol and advanced 

biofuels like lignocellulosic bioethanol produced from non-food energy grasses 

and ‘for-purpose’ feedstocks such as miscanthus and energy cane. 

 BP has announced it has plans to invest in excess of $1 billion in 

building our own biofuels business operations, including partnerships with 

other companies to develop the technologies, feedstocks and processes 

required to produce advanced biofuels. 

These investments include: a 50% stake in Tropical BioEnergia, a joint 

venture with Santelisa Vale and Maeda Group, to produce bioethanol from 

sugar cane; and a $90-million investment and strategic alliance with Verenium 

Corporation to accelerate the development and commercialization of biofuels 

produced from lignocellulosic bioethanol. We have been working with DuPont 

since 2003 to explore new approaches to the development of biofuels. The 

first product from this collaboration will be an advanced fuel molecule called 

biobutanol, which has a higher energy content than ethanol. We have 

partnered with ABF (British Sugar) and DuPont to construct a world-scale 

biofuels plant in Hull. 

 Innovation begins with research. In 2006, we announced plans to invest 

$500 million over 10 years in the Energy Biosciences Institute (EBI), at which 

biotechnologists are investigating applications of biotechnology to energy, 

including advanced fuels. This amount is incremental to the $1 billion of 

investments mentioned above. Our partners are the University of California, 

Berkeley and the University of Illinois at Urbana Champaign and the Lawrence 

Berkeley National Laboratory. The EBI is focusing on the integrated 

development of better crops, better processing technologies and better 

biofuels, leading to cleaner energy. 

Hydrogen power 

In May 2007, BP and Rio Tinto announced the formation of a new jointly 

owned company, Hydrogen Energy International Limited, which will develop 

decarbonized energy projects around the world. The venture will initially focus 

on hydrogen-fuelled power generation, using fossil fuels and CCS technology 

to produce new large-scale supplies of clean electricity. 

 Hydrogen Energy is working on developing low-carbon power plants 

with projects in Abu Dhabi and California – manufacturing hydrogen for power 

generation. In both instances, the captured CO2 will be transported to nearby 

oil fields for use in enhanced oil recovery, with the CO2 stored deep 

underground. General Electric and BP have formed a global alliance to jointly 

develop and deploy technology for hydrogen power plants that could 

significantly reduce emissions of the greenhouse gas CO2 from electricity 

generation. 

 Through these initiatives, BP intends to continue to shape the 

development of the CCS value chain and to seek to minimize the carbon 

footprint exposure of the BP group as carbon pricing and policy develops 

globally. 

Gas-fired power 

Our gas-fired power activities comprise modern combined cycle gas turbine 

plants, which emit around 50% less CO2 than a conventional coal plant of the 

same capacity, and several low-carbon co-generation gas power facilities. We 

have stakes in eight plants worldwide and this year increased the total power 

they are capable of producing from 5GW to 6GW and, where possible, we 

integrate plants with other BP production facilities. The Whiting Clean Energy 

facility, acquired in July 2008, now provides a reliable source of steam for our 

Whiting refinery and we are adding a 250MW steam turbine to our existing 

plant at our Texas City refinery. Our combined cycle plants are providing 

base-load demand for BP’s major upstream gas production developments. 

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Shipping 

We transport our products across oceans, around coastlines and along 

waterways, using a combination of BP-operated, time-chartered and spotchartered vessels. All vessels conducting BP activities are subject to our 

health, safety, security and environmental requirements. 

International fleet 

At the end of 2008, we had an international fleet of 54 vessels (37 mediumsize crude and product carriers, four very large crude carriers, one North Sea 

shuttle tanker, eight LNG carriers and four LPG carriers). All these ships are 

double-hulled. Of the eight LNG carriers, BP manages one on behalf of a joint 

venture in which it is a participant and operates seven LNG carriers. 

Regional and specialist vessels 

In Alaska, during 2008, we redelivered one of our time-chartered vessels back 

to the owner, leaving a fleet of four double-hulled vessels. In the Lower 48, the 

two remaining heritage Amoco barges were phased out of BP’s service. 

Outside the US, at the end of 2008, we had 14 specialist vessels (two doublehulled lubricants oil barges and 12 offshore support vessels). 

Time-charter vessels 

At the end of 2008, BP had 115 hydrocarbon-carrying vessels above 600 

deadweight tonnes on time-charter, of which 107 are double-hulled and one is 

double-bottomed. All these vessels participate in BP’s Time Charter 

Assurance Programme. 

Spot-charter vessels 

BP spot-charters vessels, typically for single voyages. These vessels are 

always vetted for safety assurance prior to use. 

Other vessels 

BP uses various craft such as tugs, crew boats and seismic vessels in support 

of the group’s business. We also use sub-600 deadweight tonne barges to 

carry hydrocarbons on inland waterways. 

Maritime security issues 

2008 has seen a significant escalation in piracy activity, specifically off the 

north coast of Somalia. At a strategic level, BP avoids known areas of pirate 

attack or armed robbery; where this is not possible for trading reasons and we 

consider it safe to do so, we will continue to trade vessels through areas of 

known piracy, subject to the adoption of heightened security measures. BP will 

continue to route vessels through the Gulf of Aden for as long as it considers it 

to be safe to do so, having regard to available military and government agency 

advice. At present, we are following such advice and are participating in 

protective group transits through the Gulf of Aden Maritime Security Patrol 

Area transit corridor. 

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Research and technology 

Research and technology (R&T) has a critical role to play in addressing the 

world’s energy challenges, from fundamental research through to wide-scale 

deployment. The full breadth of these R&T activities is carried out by each of 

the business segments. We also conduct long-term research within the central 

R&T group. 

 Inside the segments, research and technology activities are in service of 

competitive business performance and new business development, through 

the research, development or acquisition of new technologies. The central 

R&T group provides leadership for scientific and technological activities 

throughout the group and, in particular, provides input to the group’s long-term 

strategy. It ensures that the right capability is in place in critical areas and 

ensures the quality of BP’s major technology programmes. It also illuminates 

the potential of emerging technologies and conducts research and 

development (R&D) in support of BP’s long-term corporate renewal. In 

addition, a group of eminent industrialists and academics forms the 

Technology Advisory Council, which advises the board and executive 

management on the state of research and technology within the group and 

helps to identify current trends and future developments in technology. 

 Research and development (R&D) 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 ideas and 

technologies to be considered and implemented, improving the impact of 

research and development activities. 

 Across the group, expenditure on R&D for 2008 was $595 million, 

compared with $566 million in 2007 and $395 million in 2006. See Financial 

statements note 15 on page 130. The 5% increase in 2008 compared with 

2007 reflects increased investment in biosciences, conversion and carbon 

capture and storage technologies. 

 Beyond R&D, we also invest in technologies to get them to the point of 

commercial readiness: this includes field trials, support for technology 

deployment, specialist technical services and central investment in functional 

excellence and capability development have deepened our current areas of 

technology leadership. 

 In our Exploration and Production segment, we have organized leading 

technologies under 10 flagship programmes, each with the potential to add 

more than 1 billion boe to reserves through their development and deployment 

in our assets worldwide. These technologies contributed to exploration and 

production success in Algeria, Angola, Azerbaijan, Egypt, the North Sea and 

the Gulf of Mexico deepwater. Our advanced seismic imaging expertise, which 

is one of these programmes, continues to lead the industry, pioneering new 

wide-azimuth seismic acquisition and processing in deepwater Angola, Egypt 

and the Gulf of Mexico. In addition, BP has developed new technologies that 

have significantly reduced the time needed for land seismic acquisition in 

Oman, and these are now being deployed in Libya. Our enhanced oil recovery 

technologies are pushing recovery factors to new limits. For example, 

recovery factors have already increased from 40% to 60% in Alaska, where 

BP operates the world’s largest miscible gas enhanced oil recovery project. 

BP also leads the industry in the application of new inter-well polymer 

treatments aimed at improving waterflood recovery, with more than 25 

treatments delivering an increase of around five million barrels. Also in Alaska, 

BP’s first hexalateral well came online in 2008 in the Orion field, which is 

capable of producing 9,500 barrels of oil per day – the largest producer in 

BP’s operations on the North Slope; while our first well using cold heavy oil 

production with sand (CHOPS) technology began producing heavy oil at a 

production rate of 100 barrels of oil per day. Unconventional gas is another 

area of focus; for example, using new technologies, BP has drilled in 17 

unconventional coalbed methane basins around the world, including some of 

the largest reservoirs in North America. Another flagship programme is our 

use of digital technologies to optimize production and improve recovery, where 

BP has established an industry-leading position. In 2008, BP’s oil and gas 

operations, enabled by real-time data and Field-of-the-Future®

technologies 

delivered an extra 30,000 to 50,000 boepd gross production. Also in 2008, as 

part of its Inherently Reliable Facilities flagship, BP completed a field trial of a 

new fibre-optic system that represents a step-change in onshore pipeline 

monitoring, and which will now be deployed in Azerbaijan, Canada and 

Scotland. 

 In our Refining and Marketing segment, technology advancements are 

enabling our refineries to understand and process feedstocks of varying 

quality and optimize our assets in real time, enhancing the flexibility and 

reliability of our refineries and, in turn, improving the margins of our existing 

asset base. In 2008, BP began upgrading its Whiting refinery in Indiana to 

process heavy crude oil from Canada using one of the industry’s most 

technologically advanced coking operations. In Naperville, US, we opened a 

new refining R&D centre, installing more than 50 new pilot units at the 

forefront of experimental technology and modelling. We have installed 

predictive analytics technology for fault detection and prediction on critical 

machinery across seven of our refineries reducing losses from machinery 

failure. BP’s leading technologies in fuels and lubricants mean that it can keep 

ahead of increasingly stringent regulations, balancing greater fuel efficiency 

and performance and developing superior formulations across its entire 

product slate. For example, our BP Ultimate fuels deliver performance benefits 

such as improved fuel economy, lower emissions and a cleaner engine; and 

we have launched Greendeck and Greenfield, a suite of high-performance and 

environmentally friendly marine and offshore lubricants. Our proprietary 

processing technologies and operational experience continue to reduce the 

manufacturing costs and environmental impact of our petrochemicals plants, 

helping to maintain competitive advantage. For example, our new 900ktepa 

purified terephthalic acid (PTA) plant in Zhuhai, China was officially opened in 

2008, occupying a plot just half the size of its older, neighbouring plant, but 

with double the production capacity. In the field of conversion technology, our 

Nikiski Fischer-Tropsch demonstration plant in Alaska operated at levels to 

prove that we have a working catalyst at industrial scale. 

 In Alternative Energy, our low-carbon research and technology activity 

continues apace. In 2008, we filed patents covering biofuels, carbon capture 

and storage (CCS), and hydrogen membranes. Our solar business produced 

the first prototype of a cut-cell high voltage module, giving a 5% increase in 

power over conventional modules. Working as part of the UK’s Energy 

Technologies Institute – a public/private partnership to accelerate low-carbon 

technology development – BP is proceeding with investments in projects to 

develop new offshore wind and marine turbines. We also published results of 

the satellite monitoring programme, verified by well and tracer detection, of the 

CCS project at the In Salah gas field in Algeria with our partners Sonatrach. 

 Collaboration plays an important role across the breadth of BP’s 

research and development activities, but particularly in those areas that 

benefit from fundamental scientific research. BP has 11 significant long-term 

research programmes with major universities and research institutions around 

the world, exploring areas from energy bioscience and conversion technology 

to carbon mitigation and nanotechnology in solar power. In 2008, our Energy 

Biosciences Institute at Berkeley (see page 34) became fully operational, with 

49 research projects, all focused on lignocellulosic biofuel production; we 

announced the renewal of our Carbon Mitigation Initiative at Princeton; and 

signed the joint venture agreement for the Clean Energy Commercialisation 

Centre with the Chinese Academy of Sciences. 

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Regulation of the group’s business 

BP’s activities, including its oil and gas exploration and production, pipelines 

and transportation, refining and marketing, petrochemicals production, trading, 

alternative energy and shipping activities, are conducted in many different 

countries and are therefore subject to a broad range of EU, US, international, 

regional and local legislation and regulations, including legislation that 

implements international conventions and protocols. These cover virtually all 

aspects of our activities and include matters such as licence acquisition, 

production rates, royalties, environmental, health and safety protection, fuel 

specifications and transportation, trading, pricing, anti-trust, export, taxes and 

foreign exchange. 

 The terms and conditions of the leases, licences and contracts under 

which our 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 with governmental or state 

entities usually take the form of licences or production-sharing agreements. 

Arrangements with private property owners are usually in the form of leases. 

 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. 

Less typically, BP may explore for and exploit hydrocarbons under a service 

agreement with the host entity in exchange for reimbursement of costs and/or 

a fee paid in cash rather than production. 

 PSAs entered into with a government entity or state company generally 

require 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 US, which typically 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. 

 Frequently, BP conducts its exploration and production activities in joint 

venture with other international oil companies, state companies or private 

companies. 

 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 on 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 & Tobago. 

 For a discussion of environmental and certain health and safety 

regulations and environmental proceedings, see Environment on page 39. 

See also Legal proceedings on page 88. 

Safety 

This section reviews BP’s safety performance in 2008. 

 There were five workforce fatalities in 2008, compared with seven in 

2007. One resulted from fatal injuries sustained during operations at our 

Texas City refinery; one was the result of a fall from height at the Tangguh 

operations in Indonesia; one fatality was on a land farm near Texas City, and 

two were driving fatalities incidents in Mozambique and South Africa. We 

deeply regret this loss of life. By learning from these incidents and 

implementing appropriate improvement actions, we continue to seek to secure 

the safety of all members of our workforce. Our workforce reported recordable 

injury frequency, which measures the number of injuries per 200,000 hours 

worked, was 0.43 in 2008. This was a good improvement on the rate of 0.48 

recorded in both 2007 and 2006. 

 Throughout 2008, senior leadership across the group continued to hold 

safety as their highest priority. Site visits, in which safety was a focus, were 

undertaken by the group chief executive (GCE) and members of the executive 

team to reinforce the importance of their commitment to safe and reliable 

operations. 

Management systems 

We continue to implement our new operating management system (OMS), a 

framework for operations across BP that is integral to improving safety and 

operating performance in every site. 

 When fully implemented, OMS will be the single framework within which 

we will operate, consolidating BP’s requirements relating to process safety, 

environmental performance, legal compliance in operations, and personal, 

marine and driving safety. It embraces recommendations made by the BP US 

Refineries Independent Safety Review Panel (the panel), which reported in 

January 2007 on safety management at our US refineries and our safety 

management culture. 

 The OMS establishes a set of requirements, and provides sites with a 

systematic way to improve operating performance on a continuous basis. BP 

businesses implementing OMS must work to integrate group requirements 

within their local system to meet legal obligations, address local stakeholder 

needs, reduce risk and improve efficiency and reliability. A number of 

mandatory operating and engineering technical requirements have been 

defined within the OMS, to address process safety and related risks. 

 All operated businesses plan to transition to OMS by the end of 2010. 

Eight sites completed the transition to OMS in 2008; two petrochemicals 

plants, Cooper River and Decatur, two refineries, Lingen and Gelsenkirchen 

and four Exploration and Production sites, North America Gas, the Gulf of 

Mexico, Colombia and the Endicott field in Alaska. Implementation is 

continuing across the group and a number of other sites, including all 

refineries not already operating the OMS, are expected to complete the 

transition in 2009. 

 For the sites already involved, implementing OMS has involved detailed 

planning, including gap assessments supported by external facilitators. A core 

aspect of OMS implementation is that each site produces its own ‘local OMS’, 

which takes account of relevant risks at the site and details the site’s approach 

to managing those risks. As part of its transition to OMS, a site issues its local 

OMS handbook, and this summarizes its approach to risk management. Each 

site also develops a plan to close gaps that is reviewed annually. The 

transition to OMS, at local and group level, has been handled in a formal and 

systematic way, to ensure the change is managed safely and 

comprehensively. 

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Experience so far has supported our expectation that having one integrated 

and coherent system brings benefits of simplification and clarity, and that the 

process of change is supporting our renewed commitment to safe operations. 

 We are on track to meet our target of implementing OMS across the 

group by the end of 2010. 

Capability development 

In addition to ongoing training programmes we are undertaking a group wide 

programme to enhance the capability of our staff from front line to executive 

level to deliver operational excellence. 

 Almost 1,000, around a third, of our front-line supervisors have started 

the Operating Essentials programme, which includes training on leadership, 

process safety, operating culture, practices and coaching and effective 

performance conversations. 

 More than 190, around half, of our operations leaders started the 

Operations Academy programme in 2008. The academy, which has been 

established in partnership with the Massachusetts Institute of Technology 

(MIT), provides participants with a total of six weeks of operations training, 

concentrating on the management of change and continuous improvement. 

 The Executive Operations programme, which seeks to increase insight 

into manufacturing and operation activities among senior business leaders, 

has built on its successful launch with the first group, which included the group 

chief executive and his executive team. By the end of 2008, 99 executives had 

attended the three-day programme. 

 In addition, new cadres of projects and engineering staff have 

progressed through the Project and Engineering Academy at MIT and 13 

process safety courses have been delivered for project and project 

engineering managers at the Project Management College. We have 

continued to develop training on hazard evaluation and risk assessment 

techniques for all engineers, operators and HSSE professionals. 

Process safety management 

We remain fully committed to becoming a recognized industry leader in 

process safety management and are working to achieve this. We have taken a 

range of steps, including acting on the recommendations from both the panel 

and those within the first annual report of the independent expert. 

 Our actions can be summarized in three principal areas: 

• We have made progress in reducing process safety risk at our US refineries. 

For example, we have completed and learned from safety and operations 

audits, relocated workers to lower-risk accommodation and implemented 

fatigue reduction programmes.

• Executive management has taken a range of actions to demonstrate their 

leadership and commitment to safety. The group chief executive has 

consistently emphasized that safety, people, and performance are our top 

priority, a belief made clear in his 2007 announcement of a forward agenda 

for simplification and cultural change in BP. Safety performance has been 

scrutinized by the Group Operations Risk Committee (the GORC), chaired 

by the group chief executive and tasked with assuring the group chief 

executive that group operational risks are identified and managed 

appropriately. We continued to build our team of safety and operations 

auditors. A team of 45 auditors is now in place, with 36 audits completed in 

2008.

• Many of the process-safety related improvements recommended by the 

panel are being implemented across the group through the OMS. The group 

essentials within the OMS (which cover diverse aspects of operating activity 

including legal compliance, process and environmental safety and basic 

operating practices) in some cases go beyond the panel’s process safety 

recommendations, a point noted by the independent expert in his first report.

In addition to action in these areas, we have continued to participate in 

industry-wide forums on process safety and have made efforts to share our 

learning with other organizations. 

 The independent expert has been tasked with reporting to the board on 

BP’s progress in implementing the panel’s recommendations. We welcome 

the independent expert’s view expressed in his first report (May 2008) that BP 

‘appears to be making substantial progress in changing culture and 

addressing needed process safety improvements’. However, we also 

acknowledge his observation that ‘a significant amount of work remains to be 

done on the process safety journey’ and that ‘successful completion of the 

task will require the continued support and involvement of the board, executive 

management, and refinery leadership along with a sustained effort over an 

extended period of time’. The independent expert’s second report is expected 

in the first half of 2009. 

Operational integrity 

We continue to implement the six-point plan launched in 2006 to address 

immediate priorities for improving process safety and minimizing risk at our 

operations worldwide. 

 We have met our commitment to remove occupied portable buildings 

(OPBs) from high-risk zones within onshore process plant areas and to 

remove all blow-down stacks in heavier-than-air, light hydrocarbon service. All 

major sites and our fuels value chains have completed major accident risk 

assessments, which identify major accident risks and develop mitigation plans 

to manage and respond to them. 

 We continue to implement the Control of Work and Integrity 

Management standards. We have made progress in ensuring our operations 

meet the requirements of a group framework designed to ensure we stay in 

compliance with legal requirements on health and safety. We are continuing to 

take steps to close out past audit actions. Leadership competency 

assessments, which involve assessment of the experience of BP management 

teams responsible for major production sites or manufacturing plant, have 

been completed in Exploration and Production and in all major Refining and 

Marketing manufacturing sites. 

 Implementation of these actions is expected to be largely complete by 

the end of 2009, with some aspects of implementation being incorporated into 

the transition to the OMS, expected to be completed by the end of 2010. The 

GORC regularly monitors progress against the plan. 

 We monitor and report separately on major incidents such as those 

covering fatal accidents, significant property damage or significant 

environmental impact. We also track and analyze ‘high potential’ incidents – 

those that could have resulted in a major incident. All major incidents and 

many high-potential incidents are discussed by the GORC and we continue to 

seek to learn as much as possible from each incident. 

 A total of 21 major incidents were reported in 2008. Two of the major 

incidents were related to hurricanes and eight were related to driving 

incidents. 

 There were 335 oil spills of one barrel or more in 2008, similar to 2007 

performance of 340 oil spills. The volume of oil spilled in 2008 was 

approximately 3.5 million litres, an increase of 2.5 million litres, compared with 

2007. This was largely the result of two incidents, one at Texas City and one 

at the Whiting refinery, which accounted for two-thirds of the total reported 

volume of oil spilled, the great majority of which remained contained and the 

oil recovered. 

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Performance indicators 

We have well-developed systems, processes and metrics for reporting 

personal safety and environmental metrics that support internal performance 

management as well as public reporting. 

 We introduced several new metrics in 2008 that aim to enhance our 

monitoring of process safety performance within BP’s operating entities. 

These include, for example, a process safety incident index, as recommended 

by the panel, which uses weighted severity scores to record and assess 

process safety events, and a measure to record any loss of hydrocarbon from 

primary containment. 

 Our indicators include industry-aligned ‘lagging’ process safety metrics 

that register events that have already occurred, and ‘leading’ indicators that 

focus on the strength of our controls to prevent undesired events in future. A 

suite of indicators is regularly reported to the GORC within the quarterly ‘HSE 

and Operations Integrity Report’ and several new metrics have also been 

piloted. To further enhance the management of health risks across the group, 

we began the systematic reporting of recordable illness rates within the HSE 

and Operations Integrity Report. We continue to work with industry bodies 

such as the Centre for Chemical Process Safety and the American Petroleum 

Institute on the development of process safety metrics, definitions and 

guidance. 

Continuing to focus on health 

In addition to our efforts to improve process safety performance, we strive to 

protect the personal health and safety of our workforce, recognizing that 

healthy performance is delivered through healthy people, healthy processes 

and healthy plant. 

 In the course of 2008, we defined health ‘group essentials’, which 

specify requirements designed to prevent harm to the health of employees, 

contractors, visitors and local communities. These were incorporated within 

the OMS framework. Our health strategy and plan was also refreshed in 2008. 

Priorities include reducing significant occupational exposure and infectious 

disease risks, maintaining robust regulatory compliance in product health and 

safety and addressing the issue of fatigue management raised by the panel by 

providing training and awareness-raising. 

Environment 

Regulation and claims 

We are subject to extensive international, national, state and local 

environmental regulations concerning our products, operations and activities. 

Current and proposed fuel and product specifications, emission controls and 

climate change programmes under a number of environmental laws will have 

a significant effect on the production, sale and profitability of many of our 

products. Environmental laws also require us to remediate the environmental 

impacts of prior disposal or releases of chemicals or petroleum substances by 

the group or other parties. Such contingencies may exist for various locations 

where products are, or have been, produced, processed, stored, distributed, 

sold or disposed of, such as refineries, chemical plants, natural gas 

processing plants, oil and natural gas fields, service stations, terminals and 

waste disposal sites. Some of these obligations relate to prior asset sales or 

closed facilities. Provisions for environmental restoration and remediation are 

made when a clean-up is probable and the amount of the obligation can be 

reliably estimated. Generally this coincides with 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 to meet 

known requirements. 

 The extent and cost of future environmental restoration, remediation 

and abatement programmes are often inherently difficult to estimate. They 

often depend on the extent of contamination, and the associated impact and 

timing of the corrective actions required, technological feasibility and BP’s 

share of liability. Though the costs of future programmes 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 or liquidity. See Financial 

statements – Note 37 on page 156 for the amounts provided in respect of 

environmental remediation and decommissioning. 

 We are also subject to environmental and common law claims for 

personal injury and property damage alleging the release or exposure to 

hazardous substances. A number of 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 in aggregate, expected to be material 

to the group’s results of operations or financial position. 

 We cannot accurately predict the effect of future developments, such as 

stricter environmental laws or enforcement policies on the group’s operations, 

products or profitability. A risk of increased environmental costs and 

operational impacts is inherent in grouping our businesses and there can be 

no assurance that material liabilities and costs will not be incurred in the 

future. We believe that the group’s activities are in material compliance with 

applicable environmental laws and regulations, or that the group has disclosed 

such non-compliance and is working with the relevant regulatory authorities to 

ensure compliance. For a discussion of the group’s environmental expenditure 

see page 53. 

 BP operates in more than 90 countries worldwide. In each of these 

areas, BP has, or is developing, processes designed to ensure compliance 

with applicable regulations. In addition, each employee is required to comply 

with BP health, safety and environmental policies as embedded in the BP 

code of conduct. Our partners, suppliers and contractors are also encouraged 

to adopt them. 

 This Environment section focuses primarily on the US and the EU, 

where around 61% of our fixed assets are located, and on issues of a global 

nature such as our operations and the environment, climate change 

programmes and maritime oil spills regulations. 

Our operations and the environment 

During 2008, we continued to use environmental management systems to 

seek improvements on a wide range of environmental issues. Except at two 

locations, the operations at our major operating sites are covered 

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by certification to the ISO 14001 international environmental management 

system standard. The Texas City refinery, after completing planned work to 

strengthen its environmental management systems, is planning to seek 

recertification in 2009. Our Angola business is working towards an expansion 

of its existing ISO 14001 certificate to include its offshore production facilities 

by the end of 2009. Progressive implementation of the Operating Management 

System (OMS), including ISO 14001, will also help us strengthen our 

management of environmental performance. 

 In support of ongoing risk management, one element of the OMS 

applies, at least annually, a formal systematic process to identify and assess 

risks; this process provides to identify emerging issues including those with an 

environmental impact. To assist us in measuring the effectiveness of our risk 

mitigation actions we have established environmental metrics, which are 

available within BP Sustainability Report 2008, at www.bp.com/sustainability. 

The 2008 information is planned to be available in conjunction with the 

publication of our 2008 Sustainability Report. 

 After two years of implementation, our Environmental Requirements for 

New Projects (ERNP) practice has been updated in line with the OMS. We 

have simplified applicability, clarified the governance process and updated the 

text to reflect organizational changes. This practice, now called the 

Environmental Group Defined Practice (GDP) is a full life cycle environmental 

assessment process. It requires all new major projects and projects in 

sensitive areas, to undertake screening to determine the potential 

environmental sensitivities associated with the proposed projects. 

Requirements and project recommendations now extend to include 

appropriate considerations for decommissioning of assets. A new project with 

the highest level of environmental sensitivity requires more rigorous and 

specific environmental management activities. The board-appointed Safety, 

Environment and Ethics Assurance Committee reviewed the progress of 

ERNP during summer 2008. This review included the 12 projects that have 

been classified as requiring management at the highest level of sensitivity. We 

are currently integrating social considerations into the Environmental GDP and 

plan to issue this in 2009 as an integrated set of requirements addressing 

social and environmental issues. 

 In 2008, BP used the ERNP to review risks and establish mitigation 

measures prior to entry in connection with the decision to develop adjacent to 

a Protected Area at Hamble Oil Terminal in the UK. We intend to make a 

summary of the risk assessment publicly available at the end of April 2009. 

 Our focus on asset decommissioning is demonstrated by the North 

West Hutton offshore platform project in the North Sea. 2008 saw the topsides 

of the North West Hutton platform safely brought onshore for further 

dismantling. This decommissioning is expected to result in 20,000 tonnes of 

recycled steel, in line with our aim to have 97% of the decommissioned 

materials recycled and/or reused. 

 We seek to limit the environmental impact of our operations by using 

resources responsibly and reducing waste and emissions. 

Climate change programmes 

In response to rising concerns about climate change, governments continue to 

identify fiscal and regulatory measures at local, national and international 

levels. 

 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 international 

legally-binding targets for the first commitment period of 2008-2012. In 2005, 

the Kyoto protocol came into force, committing the 176 participating countries 

to emissions targets. However, Kyoto was only designed as a first step and 

policymakers continue to discuss what new agreement might follow it after 

2012, most recently at the UNFCCC conference in Poznan, Poland in 

December 2008. 

 Many of our larger EU stationary assets are subject to the EU 

Emissions Trading Scheme (EU ETS), which was extended to Norway by 

reciprocal agreement. After inclusion of our Norwegian assets, around onefifth of our reported 2008 global CO2 emissions are now covered by this 

scheme. 

 At the March 2007 European Council, the European Heads of 

Government decided to adopt their Climate Action and Renewable Energy 

Package. This legislation was voted through by the European Parliament in 

December 2008. The package includes a commitment to reduce greenhouse 

gas (GHG) emissions by 20% by 2020 (the target being 30% if an international 

agreement is reached), as well as an improved energy efficiency within the EU 

Member States of 20% by 2020 and a 20% renewable energy target by 2020. 

 The Australian government has set a target to reduce GHG emissions 

by 60% below 2000 levels by 2050. In December 2008, the Australian 

government released its Carbon Pollution Reduction Scheme White Paper, 

outlining the design of an emissions trading scheme that will go into effect in 

mid-2010; draft legislation is expected in early 2009. The Australian 

government proposes to cover 70% of emissions sources and sectors via a 

combination of direct obligations on facilities with large emissions, and 

obligations on upstream fuel suppliers for the emissions resulting from the 

combustion of fuel. In December the government also announced 2020 GHG 

emission targets that range from a 5 to 15% reduction from 2000 levels. The 

scheme builds on the existing National Greenhouse and Energy Reporting 

System, the Australian mandatory reporting system for corporate greenhouse 

gas emissions and energy production and consumption. The first reporting 

period commenced on 1 July 2008. 

 The US congress continues to propose new climate change legislation 

and regulation. A new bill became law in December 2007, that includes stricter 

corporate average fuel emissions standards for automobiles sold in the US 

and biofuel mandates. Other bills currently under consideration propose 

stricter emissions limits on large GHG sources and/or the introduction of a 

cap-and-trade programme on CO2 and other GHG emissions. 

 An April 2007 US Supreme Court decision will require the US 

Environmental Protection Agency (EPA) to reconsider its determination that it 

is not required to regulate GHGs from motor vehicles under the Clean Air Act 

(CAA). The Supreme Court’s ruling is expected to result in the EPA regulating 

motor vehicle GHG emissions. It is also expected to increase pressure on the 

EPA to regulate stationary sources of GHGs (e.g. refineries and chemical 

plants) under other provisions of the CAA. 

 In response to the US Supreme Court’s decision, the EPA issued an 

Advanced Notice of Proposed Rulemaking (ANPR). The ANPR addresses 

complexities involved in controlling greenhouse gases under the CAA 

including potential overlap between future legislation and regulation under the 

existing CAA. 

 In its Fiscal Year 2008 Consolidated Appropriations Act, US Congress 

directed the EPA to publish a mandatory GHG reporting rule, issuing a 

proposed rule within nine months (by September 2008), and a final rule within 

18 months (by June 2009). The EPA has developed draft language and the 

proposed rule could be released early in the new US administration. 

 Congress will likely develop new legislation for GHG regulation, and 

new regulation under the CAA will likely proceed as well. Additional GHG 

regulation may also be issued under other laws, such as the National 

Environmental Protection Act (NEPA) and Endangered Species Act (ESA). 

 In December 2008, the California Air Resources Board 

(CARB) approved the final Proposed Scoping Plan for implementing Assembly 

Bill 32, California’s law to reduce GHG emissions to 1990 levels by 2020. 

Implementation measures are due to be developed by 2012. In advance of the 

Scoping Plan, CARB has taken early actions with the development of 

mandatory GHG reporting and a Low Carbon Fuel Standard (LCFS). The 

LCFS will require all refiners, producers, blenders and importers to reduce the 

carbon intensity of transport fuel sold in California by 10% by 2020. CARB 

released draft LCFS regulations in October 2008, with final regulations 

expected to be taken up in March 2009. 

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In March 2008, the Canadian federal government updated its April 2007 

Framework Report with an Action Plan to address climate change and reduce 

emissions 20% below 2006 levels by 2020 and by greater than 60% by 2050, 

through both a sector approach and domestic development and deployment of 

new technologies and projects. For the conventional oil and gas industry, the 

intensity based targets as included in the plan of the April 2007 Framework 

Report remain likely. For the oil sands industry, more stringent requirements 

are likely to emerge for upcoming projects that may include requirements for 

significant reductions, including the implementation of large scale carbon 

capture and sequestration. Since the conclusion of the recent Canadian and 

US Federal elections there has been increased discussion on the possibility of 

aligning regulations, including possible inclusion of a North America wide capand-trade system. 

 Since 1997, BP has been actively involved in the 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 GHG 

emissions: operational emissions, which are generated from our operations 

such as refineries, chemicals plants and production facilities; and product 

emissions, generated by our customers when they use the fuels and products 

that we sell. Since 2001, we have been focusing on measuring and improving 

the carbon intensity of our operations as well as developing sustainable lowcarbon technologies and businesses. 

 After seven years, we estimate that our operations have delivered some 

7.5 million tonnes (Mte) of GHG reductions. Our 2008 operational GHG 

emissions were 61.4Mte of CO2 equivalent on a direct equity basis, nearly 

2.1Mte lower than the reported figure of 63.5Mte in 2007. The primary reason 

for the lower reported emissions is a reporting protocol change for BP 

Shipping (1.9Mte) to align us more closely with industry practice. 

 In 2007, as part of our technology development, two major BP-backed 

research institutes came into full operation: the Energy Biosciences Institute 

(EBI) in the US, and the Energy Technologies Institute (ETI) in the UK. The 

EBI is a strategic partnership between BP, the University of California, 

Berkeley, the Lawrence Berkeley National Laboratory and the University of 

Illinois, Urbana-Champaign to conduct research into the production of new 

and cleaner energy, initially focusing on advanced biofuels for road transport. 

The EBI will also pursue bioscience-based research into the conversion of 

heavy hydrocarbons to clean fuels, improved recovery from existing oil and 

gas reservoirs and carbon sequestration. In the UK, the ETI has been 

established as a 50:50 public private partnership, funded equally by member 

companies, including BP, and the government. The ETI aims to accelerate the 

development, demonstration and eventual commercial deployment of a 

focused portfolio of energy technologies, which will increase energy efficiency, 

reduce GHG emissions and help achieve energy security and climate change 

goals. The ETI has issued its first invitation for expressions of interest to 

participate in programmes to develop new technologies for offshore wind and 

for marine, tidal and wave energy. BP established the Carbon Mitigation 

Initiative in 2000 at Princeton University in the US to research the fundamental 

scientific, environmental, and technological issues that will determine how 

carbon is managed in the future and examine the policy impact of different 

options. BP’s original 10-year commitment initially funded the programme at 

$1.5 million per year and later increased it to more than $2 million per year. In 

October 2008, BP committed to a five-year renewal of the partnership and to 

support Princeton to at least its current level of funding for the years 2011 to 

2015. 

Maritime oil spill regulations 

Within the US, the Oil Pollution Act of 1990 (OPA 90) imposes oil spill 

prevention and planning requirements liability for tankers and barges 

transporting oil and for offshore facilities such as platforms and onshore 

terminals. To ensure adequate funding for oil spill response and 

compensation, OPA 90 created the Oil Spill Liability Trust Fund that is 

financed by a tax on imported and domestic oil. In 2006, the Coast Guard and 

Maritime Transportation Act 2006, increased the size of the fund from the 

original amount of $1 billion to $2.7 billion. In late 2008, as part of the 

Emergency Economic Stabilization Act, further amendments were made to 

increase the per-barrel contribution rate of tax and to remove the provision for 

cessation of the tax when the fund reached $2.7 billion. There is now no limit 

on the size of the fund. The same 2008 legislation amended the termination 

date of this tax from 31 December 2014 to 31 December 2017. The 2006 

legislation also increased the OPA limitation amount relating to the liability of 

double-hulled tankers from $1,200 per gross tonne to $1,900 per gross tonne. 

In addition to the spill liabilities imposed by OPA 90 on the owners and 

operators of carrying vessels, some states, including Alaska, Washington, 

Oregon and California, impose additional liability on the shippers or owners of 

oil spilled from such vessels. 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. At the end of 2008, 

BP owned four double-hulled tankers built between 2004 and 2006, demisechartered to and operated by Alaska Tanker Company, L.L.C. (ATC), which 

transports BP Alaskan crude oil from Valdez. 

 Outside of US territorial waters, 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 Cooperation requires vessels to have adequate spill response plans and 

resources for response anywhere the vessel travels. 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 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 OPA 90 and outside the US under the 1969/1992 

International Convention on Civil Liability for Oil Pollution Damage (CLC) are 

covered by marine liability insurance, having a maximum limit of $1 billion for 

each accident or occurrence. This insurance cover is provided by three mutual 

insurance associations (P&I Clubs): The United Kingdom Steam Ship 

Assurance Association (Bermuda) Limited; The Britannia Steam Ship 

Insurance Association Limited; and The Standard Steamship Owners’ 

Protection and Indemnity Association (Bermuda) Limited. With effect from 20 

February 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 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 $30 million) for 

a ship at or below 29,548 gross tonnes, 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, that is, an 

additional liability of up to 273.5 million Special Drawing Rights (around $405 

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, so benefiting from those clubs’ pooling 

and reinsurance arrangements. All BP Shipping’s managed and timechartered vessels participate in STOPIA and TOPIA. 

 For information regarding maritime security issues, see Shipping on 

page 35. 

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US 

The following is a summary of significant US environmental issues and 

environment and health and safety legislation or regulations affecting BP. 

 The CAA and its regulations, administered by the United States 

Environmental Protection Agency (EPA) require, among other things: stringent 

air emission limits and operating permits for chemicals plants, refineries, 

marine and distribution terminals and exploration and production facilities, 

strict fuel specifications and sulphur reductions; enhanced monitoring of major 

sources of specified pollutants; and risk management plans for storage of 

hazardous substances. This law affects BP facilities producing, storing, 

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, lead and 

Reid Vapor Pressure affect BP’s activities and products. Under the CAA all 

gasoline produced by BP is subject to the EPA’s stringent low-sulphur 

standards. By June 2006, at least 80% of the highway diesel fuel produced 

each year by BP was required to meet a sulphur cap of 15 parts per million 

(ppm). By June 2007, all non-road locomotive and marine diesel fuel produced 

each year by BP was required to meet a sulphur cap of 500ppm. Additionally, 

states have separate laws similar to the CAA. 

 The Energy Policy Act of 2005 affects the US fuels market by: 

eliminating the Federal Reformulated Gasoline (RFG) oxygen requirement in 

May 2006; establishing a renewable fuels mandate (4 billion gallons in 2006, 

increasing to 7.5 billion in 2012); consolidating the summertime RFG volatile 

organic compound (VOC) standards for EPA Regions 1 and 2; allowing the 

Ozone Transport Commission states on the east coast to opt any area into 

RFG; and allowing states to repeal the 1psi Reid Vapor Pressure waiver for 

10% ethanol blends. 

 The Energy Independence and Security Act of 2007 increased the 

renewable fuel mandate to 9 billion gallons in 2008 and further each year to a 

maximum of 36 billion gallons in 2022. 

 In 2001, BP entered into a consent decree with the EPA and several 

states that settled alleged violations of various CAA requirements related 

largely to emissions of sulphur dioxide and nitrogen oxides at BP’s US 

refineries. Implementation of the decree’s requirements continues. 

 In 2001, BP’s US refineries entered into a civil consent decree with the 

EPA to resolve alleged violations of the CAA. The decree applies to all the US 

refineries of BP Products North America Inc. (BP Products). On 19 

February 2009, the EPA and US Department of Justice (DOJ) lodged an 

amendment to the 2001 decree. The amendment applies only to the Texas 

City refinery and resolves alleged violations of both the 2001 decree and the 

CAA. The decree requires that BP Products pays a $12 million civil fine, funds 

a $6 million supplemental environmental project and takes steps at the Texas 

City refinery to enhance compliance with CAA rules. 

The estimated cost of these compliance measures is approximately 

$150 million. The decree amendment is subject to court approval. 

 The Clean Water Act (CWA) and its regulations, administered by EPA 

and the US Coast Guard, regulate the discharge of wastewater, stormwater 

and toxic discharges from BP’s onshore and offshore operations to navigable 

waters. Facilities are required to obtain discharge permits, install control 

equipment and implement operational controls and preventative measures. 

Additionally, states have separate laws similar to the CWA. 

 The Resource Conservation and Recovery Act (RCRA) and its 

regulations, administered by the EPA, regulate the storage, handling, 

treatment, transportation and disposal of hazardous and non-hazardous 

wastes and require the investigation and remediation of locations at a facility 

where such wastes have been managed. Many BP facilities generate and 

manage wastes regulated by RCRA and several include locations that are 

subject to investigation and corrective action. Additionally, states have 

separate laws similar to RCRA. 

 Under the Comprehensive Environmental Response, Compensation 

and Liability Act (CERCLA or Superfund), persons who arranged to dispose of 

hazardous substances at a site, persons who currently own or operate a site 

where such substances have been 

disposed and certain other parties are strictly liable for the cost of responding 

to related hazardous substance contamination. EPA administers CERCLA. 

Additionally, states have separate laws similar to CERCLA. 

 BP has been identified as a Potentially Responsible Party (PRP) under 

CERCLA or otherwise named under similar state statutes at approximately 

809 sites. A PRP or named party can incur 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 50 

of these sites. For the remaining sites, BP is one of many potentially 

responsible parties, and BP expects its share of remediation costs at these 

sites to be small in comparison with the major sites. BP has estimated its 

potential exposure at all sites where it has been identified as a PRP or is 

otherwise named at a site is approximately $1.7 billion. 

 BP is also subject to claims for natural resource damages (NRD) under 

CERCLA, the OPA 90 and other federal and state laws. NRD claims have 

been asserted by government trustees against a number of BP operations. 

Many environmental clean-ups are driven by state and federal groundwater 

protection standards. Contamination or the threat of contamination of current 

or potential potable (and occasionally non-potable) water resources can result 

in stringent clean-up requirements. 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 legislation that significantly affect BP operations includes: the 

Toxic Substances Control Act, administered by EPA, which regulates the 

development, testing, import, export and introduction of new chemical 

products into commerce; the Occupational Safety and Health Act, 

administered by the Occupational Safety and Health Administration, which 

imposes workplace safety and health, training and process safety 

requirements to reduce the risks of physical and chemical hazards and injury 

to employees; the CAA, which created the US Chemical Safety and Hazard 

Investigation Board which investigates the causes of chemical accidents and 

makes non-binding recommendations to industry, government and nongovernmental organizations; and the Emergency Planning and Community 

Right-to-Know Act, administered by the EPA, which requires emergency 

planning and hazardous substance release notification as well as public 

disclosure of chemical usage and emissions. In addition, the US Department 

of Transportation (DOT) regulates the transportation of the BP’s petroleum 

products such as crude oil, gasoline and chemicals. 

 BP is subject to the Marine Transportation Security Act (MTSA) and 

regulations and the DOT Hazardous Materials (HAZMAT) security compliance 

regulations. These regulations require many of BP’s businesses to conduct 

security vulnerability assessments and prepare security mitigation plans that 

require upgrades to security measures, the appointment and training of 

security personnel and the submission of plans for approval and inspection by 

government agencies. 

The US government through the Department of Homeland Security, in an 

effort to further mitigate the threat of terrorism to critical US infrastructure, has 

implemented two new security legislation initiatives, that began in 2007 and 

has continued through 2008: 

CFATS is intended to provide an enhanced security posture for US facilities 

that manufacture or store Chemicals of Interest, including gasoline. 

Additionally, in the future, it will cover facilities that have national economic 

impact to the US, should these facilities be a target for terrorism. A number of 

BP facilities may be required to conduct a detailed security vulnerability 

assessment and a detailed security plan for each facility impacted. 

 TWIC requires all designated personnel with unescorted access to 

restricted areas of MTSA designated facilities to submit to a background 

screening programme and to obtain a biometric identification card. All of 

• Chemical Facility Anti-Terrorism Standard (CFATS).

• Transportation Workers Identification Credential (TWIC).

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BP’s MTSA-regulated facilities will be impacted and will be required to comply 

by the end of 2008 or beginning of 2009 in a phased approach. 

 The BP Americas Response Team consists of approximately 210 

trained emergency responders at BP locations throughout North America. In 

addition, there are five Regional Response Incident Management Teams, a 

number of HAZMAT Teams and emergency response teams at BP’s major 

facilities. Collectively, these teams are ready to assist in a response to a major 

incident. 

 In 2008, BP Products obtained and renewed environmental permits that 

enabled it to commence construction on the project to upgrade the Whiting 

refinery. Various environmental groups have challenged these permits in state 

and federal proceedings. 

 In November 2007, the EPA began issuing a series of notices of 

violations, alleging clean air act violations, to the Whiting, Toledo, Carson and 

Cherry Point refineries. Settlement negotiations continue between BP 

Products, the EPA and the DOJ in an effort to resolve these matters. In 

October 2008, the EPA issued an amended notice of violation alleging that BP 

Products began construction on the Whiting upgrade in 2005 prior to receiving 

the necessary permits. This allegation has been incorporated into the permit 

challenges filed by the environmental groups. The subject matter of the 

notices of violation could be resolved as an amendment to the 2001 EPA 

consent decree or as a separate matter. 

 See also Legal proceedings on page 88. 

European Union 

The following is a summary of significant EU level environmental legislation 

and UK health and safety legislation affecting BP. 

 At the March 2007 European Council, the European Heads of 

Government decided to adopt: 

 In December 2008, the European Parliament approved the ‘Climate 

Action and Renewable Energy Package’, which: 

BP was involved at the highest levels in the preparation of the ‘Climate Action 

and Renewable Energy Package’, as part of our efforts to actively contribute 

to the formulation of energy security and climate change policy in the EU. 

 An EC directive for a system of integrated pollution prevention and 

control (IPPC) was adopted in 1996. This system requires certain listed 

industrial installations, including most activities and processes undertaken by 

the oil and petrochemicals industry within the EU, to obtain an IPPC permit, 

which is designed to address an installation’s environmental impacts, air 

emissions, water discharges and waste in a comprehensive and integrated 

fashion. The permit requires, among other things, the application of Best 

Available Techniques (BAT), taking into account the costs and benefits, unless 

an applicable environmental quality standard requires more stringent 

restrictions, and an assessment of existing environmental impacts and future 

site closure obligations. All such plants had to obtain such a permit by 30 

October 2007 and permits included an environmental improvement 

programme where necessary. 

 In December 2007, the EC issued a proposal for the revision to the 

IPPC Directive with the aims of streamlining legislation on industrial 

emissions, improving the implementation of BATs across Europe, and 

• a commitment to reduce GHG emissions by at least 20% by 2020 as 

compared with 1990 levels and the objective of a 30% reduction by 2020, 

subject to the conclusion of a comprehensive international climate change 

agreement; and

• a mandatory EU target of 20% renewable energy by 2020 including a 10% 

biofuels target.

• revises the EU’s Emissions Trading System to establish auctioning of 

emission allowances from 2013;

• sets binding national targets for each EU member state; • equips power 

plants to capture and store CO2 underground;

• sets mandatory national targets for each EU member state with the goal of 

delivering 20% renewable energy target by 2020; and

• provides for a revised Fuel Quality Directive requiring fuel suppliers to 

reduce the life cycle emission of the fuels they provide by up to 10% by 

2020.

contributing to the achievement of the targets set in the EC’s Thematic 

Strategies on Air, Soil and Waste. The proposal merges and revises several 

separate directives related to industrial emissions (including the Large 

Combustion Plant Directive) into one Directive. It proposes tighter minimum 

standards for emissions from large combustion plant (>50MW), and introduces 

a mandatory requirement to achieve emission limit values indicated by use of 

‘Best Available Techniques’ (with derogations from this requirement allowed 

where justified).

 The proposal would also extend the scope of IPPC to specifically cover 

organic chemical manufacture by biological treatment (biofuels) and may open 

the way for NOx and SOx trading by member states. 

 The EC proposal has triggered considerable debate and the timetable 

for the completion of the legislative process and the likely outcome are not 

clear. However, the revision has already triggered a greater focus on the 

information sharing process that is used to determine and document the BAT 

for each industry sector, and will raise the profile of the outputs from this 

process – the BAT Reference Documents (BREFs). 

 In 2005, the EC published its Thematic Strategy on Air Pollution, which 

outlines EU-wide targets for health and environmental benefits from improved 

air quality to be achieved through further controls on emissions of fine 

particulates (PM 2.5 – particulate matter less than 2.5 microns diameter), 

sulphur dioxide, oxides of nitrogen, volatile organic compounds and ammonia. 

Associated with this is the revision to the National Emissions Ceiling Directive 

(NECD), which would introduce new emissions ceilings for each member state 

for fine particles and tighten existing ceilings for sulphur dioxide, oxides of 

nitrogen, volatile organic compounds and ammonia. There is currently 

uncertainty regarding the costs to industry of implementing possible outcomes 

from the NECD and IPPC revisions. 

 The proposed revision of the current EU Fuel Quality Directive is 

referred to in the Climate Change Programmes section above. In addition to 

its provisions regarding life cycle GHG emission reductions, it would also 

facilitate the introduction of biofuels into gasoline and diesel. 

 Registration, Evaluation and Authorization of Chemicals 

(REACH) legislation became effective 1 June 2007 across all member states 

of the EU. All chemical substances manufactured within, or imported into, the 

EU in quantities above 1 tonne per annum must be registered fully by each 

manufacturer/importer with the new European Chemical Agency (ECHA). 

Failure to comply with REACH in respect of such a substance will immediately 

remove a company’s legal right to manufacture or import that substance. 

Initially all existing manufactured and imported substances had to be preregistered by 1 December 2008, to qualify for a timed phase-in for full 

registration during the period 2010-2018, with the exact timing being 

determined by the volumes of chemicals manufactured/imported, and by the 

health, safety and environmental hazards the chemical may possess. Failure 

to pre-register an existing chemical will result in an immediate requirement to 

register fully the chemical with the ECHA prior to continued manufacture 

within, or import into, the EU. Time-limited authorizations may be granted for 

substances of ‘high concern’ and in some cases restrictions in use may apply. 

Crude oil and natural gas are exempt from registration requirements, while 

fuels are exempt from authorization but not registration. In BP, REACH affects 

our refining, petrochemicals and other chemical manufacturing operations, 

with many other businesses, such as lubricants, also being impacted in their 

roles as major importers and downstream users of chemicals. In 2008, BP 

submitted around 700 pre-registrations, covering approximately 250 individual 

chemical substances. For almost 60% of these, ‘full’ registration dossiers must 

be submitted to ECHA by 1 December 2010, the balance being required in the 

period 2013-2018. Total REACH registration fees to be incurred by BP’s 

businesses are estimated to be in the region of $15 million and these 

contribute to an estimated overall cost of $60 million during the period 2008-

2018 for pre-registration, registration and provision of additional testing 

requirements. 

 In the UK, significant health and safety legislation affecting BP includes 

the Health and Safety at Work Act and regulations made thereunder and the 

Control of Major Accident Hazards Regulations. 

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 Rest of Rest of 

Number of employees at 31 December UK Europe US World Total

2008

Exploration and Production 3,600 700 7,700 9,400 21,400

Refining and Marketing 9,000 18,000 19,000 15,500 61,500

Other businesses and corporate 3,300 700 2,600 2,500 9,100

 15,900 19,400 29,300 27,400 92,000

2007

Exploration and Production 3,800 700 7,800 9,500 21,800

Refining and Marketing 9,700 18,400 22,700 16,400 67,200

Other businesses and corporatea 3,500 800 2,500 2,300 9,100 

17,000 19,900 33,000 28,200 98,100

2006

Exploration and Production 3,600 1,000 7,600 9,200 21,400

Refining and Marketing 10,200 18,600 23,800 15,400 68,000 

Other businesses and corporate 3,100 600 2,300 1,600 7,600

16,900 20,200 33,700 26,200 97,000

aA minor amendment has been made to the comparative figure for Rest of the World to correct headcount data.

People and their capabilities are fundamental to our sustainability as a 

business. To build an enduring business in an increasingly complex and 

competitive industry, we need people with world-class capabilities, ranging 

from deepwater drilling and operating refineries to negotiating with 

governments and planning wind farms. 

 Our 2008 focus has been on reducing complexity and embedding the 

performance culture throughout the company. We have implemented 

structured transformational programmes in a number of strategic performance 

units (SPUs) and the major functions. We have stopped activity that was being 

repeated at multiple layers, removed layers of management and have 

established the SPUs as the principal units of delivery. 

 There is a greater focus on individual performance management. We 

have simplified the performance management process and can clearly identify 

and reward top performing businesses and individuals. Our incentive plans 

provide a direct link between SPU performance, the individual’s contribution, 

and the bonus outcome. 

 We had approximately 92,000 employees at 31 December 2008, 

compared with approximately 98,100 at 31 December 2007. 

 In managing our people, we seek to attract, develop and retain highly 

talented individuals in order to maintain BP’s capability to deliver our strategy 

and plans. Our three-year graduate development programme currently has 

1,200 participants from all over the world. 

 We are focusing on the need for deep specialist skills. Accordingly, we 

have increased external hiring in infrastructure and technical areas. The 

energy industry faces a shortage of professionals such as petroleum 

engineers. The number of experienced workers retiring is expected to exceed 

that of new graduate hires. To help address this issue we are developing more 

robust resourcing plans supported by initiatives aimed at increasing the 

numbers of recruits and diversifying the sources from which we recruit. The 

external hiring initiatives are supported by plans for accelerated discipline 

development, prioritized deployment and retention schemes. 

 The continuous improvement we are making to performance 

management and reward will help ensure that BP meets the expectations of 

these new recruits who are highly mobile and are more conscious that they 

have a choice about where to work. 

 Our policy is to ensure equal opportunity in recruitment, career 

development, promotion, training and reward for all employees, including 

those with disabilities. Where existing employees become disabled, our policy 

is to provide continuing employment and training wherever practicable. 

In 2008, a global diversity and inclusion (D&I) council was established. This 

council, chaired by Tony Hayward, is supported by a North American regional 

council and segment councils. The aim is to harmonize processes and tools 

for managing D&I across all Segments and Functions. Responsibility for 

delivering D&I plans sits at the business/SPU level. 

 The group people committee, formed in 2007, continues to take overall 

responsibility for policy decisions relating to employees. In 2008, these ranged 

from senior level talent review and succession planning, embedding of 

diversity and inclusion plans in the businesses and the structure of long-term 

incentive plans. 

 We continue to increase the number of local leaders and employees in 

our operations so that they reflect the communities in which we operate. For 

example, in Colombia, national employees now make up 98% of BP’s team, 

while in Azerbaijan, the equivalent proportion is 83%. By 2020, more than half 

our operations are expected to be in non-OECD countries and we see this as 

an opportunity to develop a new generation of experts and skilled employees. 

 At the end of 2008, 14% of our top 583 leaders were female and 19% 

came from countries other than the UK and the US. When we started tracking 

the composition of our group leadership in 2000, these percentages were 9% 

and 14% respectively. We continue to raise our senior level leaders’ 

awareness of D&I, and further training is planned in 2009. 

 We aim to develop our leaders internally, although we recruit outside 

the group when we do not have specialist skills in-house or when exceptional 

people are available. In 2008, we appointed 73 people to positions in the 

group leadership population. Of these, 39 were internal candidates. 

 We provide development opportunities for our employees, including 

training courses, international assignments, mentoring, team development 

days, workshops, seminars and online learning. We encourage all employees 

to take five training days per year. 

 A leadership, development and learning steering group was set up in 

2008. This body of senior executives has responsibility for guiding and 

advising on leadership and management development. As part of this, the 

steering group oversees the Managing Essentials programme, which was 

successfully rolled out in 2007. 

 Through our award-winning ShareMatch plan, run in more than 70 

countries, we match BP shares purchased by employees. 

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Communications with employees include magazines, intranet sites, DVDs, 

targeted emails and face-to-face communication. Team meetings are the core 

of our employee consultation, complemented by formal processes through 

works councils in parts of Europe. These communications, along with training 

programmes, are designed to contribute to employee development and 

motivation by raising awareness of financial, economic, social and 

environmental factors affecting our performance. 

 The group seeks to maintain constructive relationships with labour 

unions. 

 ‘Pulse’ surveys conducted in 2008 among samples of employees 

indicated that BP’s safety culture is growing but that overall satisfaction levels 

have fallen. The surveys also revealed that more work needs to be done to 

ensure all employees fully understand what they need to do to deliver 

sustainable high performance. 

 We continue to make significant efforts to communicate the intent and 

progress of the forward agenda to reduce the potential negative impacts of 

this change on the business. We have moved quickly, but our management of 

change practices keep the focus on safety and ensure that the changes are 

sustainable. These improvements are expected to continue in 2009, but we 

have already delivered material reductions in activity, cost and headcount. 

The code of conduct 

We have a code of conduct designed to ensure that all employees comply with 

legal requirements and our own standards. The code defines what BP expects 

of its people in key areas such as safety, workplace behaviour, bribery and 

corruption and financial integrity. Our employee concerns programme, 

OpenTalk, enables employees to seek guidance on the code of conduct as 

well as to report suspected breaches of compliance or other concerns. The 

number of cases raised through OpenTalk in 2008 was 925, compared with 

973 in 2007. 

 In the US, former US district court judge Stanley Sporkin acts as an 

ombudsperson. Employees and contractors can contact him confidentially to 

report any suspected breach of compliance, ethics or the code of conduct, 

including safety concerns. 

 We take steps to identify and correct areas of non-compliance and take 

disciplinary action where appropriate. In 2008, 765 dismissals were reported 

by BP’s businesses for non-compliance or unethical behaviour. This number 

excludes dismissals of staff employed at our retail service station sites, for 

incidents such as thefts of small amounts of money. 

 BP continues to apply a policy that the group will not participate directly 

in party political activity or make any political contributions, whether in cash or 

in kind. BP specifically made no donations to UK or other EU political parties 

or organizations in 2008. 

Social and community issues 

Contributing to communities 

We aim to make a difference in the communities where we operate in a 

manner that brings benefits to BP as well as the local society. Investment in 

education, for example, promotes sustainable development as well as 

providing skilled workers for BP and other companies. Support for local 

enterprise drives economic growth as well as helping local companies qualify 

as our suppliers. 

 BP operates in a diverse range of locations with varying levels of 

economic and national development. We contribute to communities in ways 

that are relevant to local circumstances, and which offer opportunities for 

mutual benefit to our business. Given the scale of our business, our impact 

often reaches beyond the local community to the national and, in some cases, 

the international level. 

 We support education because it creates opportunities for communities, 

while at the same time providing skills that are critical to BP business and the 

wider industry. Our interventions in education 

are diverse and wide-ranging. We help fund a range of educational 

programmes, from early years learning to advanced university research, 

building skills and capability in communities as well advancing knowledge on 

issues such as climate change and effective economic management of natural 

resource rich countries. In further and higher education, a major driver for our 

involvement is the need to encourage more people to develop the particular 

skills needed for the energy industry. In supporting school education, BP looks 

to develop children’s awareness of links between energy and the environment 

as well as stimulating interest in science and engineering. In addition to its 

investment in the formal learning system, BP supports public education on 

specific pressing social issues when there is a particular need within a local 

community. 

 Through training and financing programmes, BP seeks to support the 

development of local suppliers by building their skills, sharing internal 

standards and practice and stimulating business development. This enables 

greater participation in the supply chain by local business and greater 

competitiveness overall. 

 We support several initiatives designed to promote the effectiveness of 

natural resource led national development. Through the support of the Oxford 

Centre for the Analysis of Resource Rich Economies, we seek to improve the 

understanding of the development challenges and policy options available to 

emerging economies that are rich in natural resources such as oil and gas. 

We remain a member of the Extractive Industries Transparency Initiative 

(EITI), which supports the creation of a standardized process for transparent 

reporting of company payments and government revenues from oil, gas and 

mining. 

 In the US, amongst various other initiatives in 2008, we provided more 

than $17 million to assist with relief and recovery efforts for the wider 

community following Hurricanes Ike and Gustav in the Gulf of Mexico. 

 We make direct contributions to communities through community 

programmes. Our total contribution in 2008 was $125.6 million. This included 

$0.2 million contributed by BP to UK charities. The growing focus of this is on 

education, the development of local enterprise and providing access to energy 

in remote locations. 

 In 2008, we spent $59.5 million promoting education, with investment in 

three broad areas: energy and the environment; business leadership skills; 

and basic education in developing countries where we operate large projects. 

Essential contracts 

BP has contractual and other arrangements with numerous third parties in 

support of its business activities. This report does not contain information 

about any of these third parties as none of our arrangements with them are 

considered to be essential to the business of BP. 

Property, plants and equipment 

BP has freehold and leasehold interests in real estate in numerous countries, 

but no individual property is significant to the group as a whole. See 

Exploration and Production on page 13 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 section. 

Organizational structure 

The significant subsidiaries of the group at 31 December 2008 and to the 

group percentage of ordinary share capital (to the nearest whole number) are 

set out in Financial statements – Note 46 on page 173. See Financial 

statements – Notes 26 and 27 on pages 138 and 139 respectively for 

information on significant jointly controlled entities and associates of the 

group. 

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Financial and operating performance 

Group operating results 

The following summarizes the group’s operating results. 

46 

Performance review

 

$ million except per share amounts

2008 2007 2006

Total revenuesa 365,700 288,951 270,602

Profit from continuing operationsa 21,666 21,169 22,626

Profit for the year 21,666 21,169 22,601 

Profit for the year attributable to BP shareholders 21,157 20,845 22,315

Profit attributable to BP shareholders per ordinary share – cents 112.59 108.76 111.41

Dividends paid per ordinary share – cents 55.05 42.30 38.40

a Excludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2004, 2005 and 2006.

Business environment 

Crude oil prices reached new record highs in 2008, in nominal terms. The 

average dated Brent price for the year rose to $97.26 per barrel, an increase 

of 34% over the $72.39 per barrel average seen in 2007. Daily prices began 

the year at $96.02 per barrel, peaked at $144.22 per barrel on 3 July 2008, 

and fell to $36.55 per barrel at year-end. The sharp drop in prices was due to 

falling demand in the second half of the year, caused by the OECD falling into 

recession and the lagged effect on demand of high prices in the first half of the 

year. OPEC had increased production significantly through the first three 

quarters; and, as a result of falling consumption and rising OPEC production, 

inventories rose. As prices continued to decline, OPEC responded with 

successive announcements of production cuts in September, October, and 

December. 

 Natural gas prices in the US and the UK increased in 2008. The Henry 

Hub First of Month Index averaged $9.04/mmBtu, 32% higher than the 2007 

average of $6.86/mmBtu. Prices peaked at $13.11/mmBtu in July amid robust 

demand and falling US gas imports, but fell to $6.90/mmBtu in December as 

demand weakened and production remained strong. Average UK gas prices 

rose to 58.12 pence per therm at the National Balancing Point in 2008, 94% 

above the 2007 average of 29.95 pence per therm. 

 Refining margins fell back in 2008, with the BP Global Indicator Margin 

(GIM) averaging $6.50 per barrel. The premium for light products above fuel 

oils remained high, reflecting a continuing shortage of upgrading capacity and 

the favouring of fully upgraded refineries over less complex sites. 

 The retail environment continued to be extremely competitive in 2008 

with market volatility, high absolute prices, as well as large price shifts in the 

crude market. 

 In 2007, the average dated Brent price rose to $72.39 per barrel, an 

increase of 11% over the $65.14 per barrel average seen in 2006. Daily prices 

began the year at $58.62 per barrel and rose to $96.02 per barrel at year-end 

due to OPEC production cuts in early 2007, sustained consumption growth 

and a resulting drop in commercial inventories after the summer. 

 Natural gas prices in the US and the UK declined in 2007. The Henry 

Hub First of Month Index averaged $6.86/mmBtu, 5% lower than the 2006 

average of $7.24/mmBtu. Prices were pressured by strong LNG imports in 

summer, continued domestic production growth and high inventories. Average 

UK gas prices fell to 29.95 pence per therm at the National Balancing Point in 

2007, 29% below the 2006 average of 42.19 pence per therm. 

 Refining margins had reached a new record high in 2007, with the BP 

Global Indicator Margin (GIM) averaging $9.94 per barrel. The premium for 

light products above fuel oils remained exceptionally high, reflecting a 

shortage of upgrading capacity and the favouring of fully upgraded refineries 

over less complex sites. 

Hydrocarbon production 

Our total hydrocarbon production during 2008 averaged 2,517mboe/d for 

subsidiaries and 1,321mboe/d for equity accounted-entities, a decrease of 

1.2% (a decrease of 3.1% for liquids and an increase of 0.7% for gas) and an 

increase of 4.0% (an increase of 2.5% for liquids and an increase of 14.8% for 

gas) respectively compared with 2007. In aggregate, after adjusting for the 

effect of lower entitlement in our PSAs, production was 5% higher than 2007. 

This reflected strong performance from our existing assets, the continued 

ramp-up of production following the startup of major projects in late-2007 and 

a further nine major project startups in 2008. Our total hydrocarbon production 

during 2007 averaged 2,549mboe/d for subsidiaries and 1,269mboe/d for 

equity-accounted entities, a decrease of 3% (3.5% for liquids and 2.6% for 

gas) and 2% (1.3% for liquids and 8.4% for gas) respectively compared with 

2006. In aggregate, the decrease primarily reflected the effect of disposals 

and net entitlement reductions in our PSAs. 

Profit attributable to BP shareholders 

Profit attributable to BP shareholders for the year ended 31 December 2008 

was $21,157 million, including inventory holding losses, net of tax, of 

$4,436 million and a net charge for non-operating items, after tax, of 

$796 million. In addition, fair value accounting effects had a favourable impact, 

net of tax, of $146 million relative to management’s measure of performance. 

Inventory holdings gains or losses, net of tax, are described in footnote (a) on 

the following page. Further information on non-operating items and fair value 

accounting effects can be found on page 51. 

 Profit attributable to BP shareholders for the year ended 31 

December 2007 was $20,845 million, including inventory holding gains, net of 

tax, of $2,475 million and a net charge for non-operating items, after tax, of 

$373 million (see page 52). In addition, fair value accounting effects had an 

unfavourable impact, net of tax, of $198 million (see page 52) relative to 

management’s measure of performance. 

 Profit attributable to BP shareholders for the year ended 31 

December 2006 was $22,315 million, including inventory holding losses, net of 

tax, of $222 million and a net credit for non-operating items, after tax, of 

$1,531 million (see page 52). In addition, fair value accounting effects had a

favourable impact, net of tax, of $72 million (see page 52) relative to 

management’s measure of performance. The profit attributable to BP 

shareholders for the year ended 31 December 2006 included a loss from 

Innovene operations of $25 million. 

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47

Performance review

The primary additional factors reflected in profit for 2008, compared with 2007, 

were higher realizations, a higher contribution from the gas marketing and 

trading business, improved oil supply and trading performance, improved 

marketing performance and strong cost management; however, these positive 

effects were partly offset by weaker refining margins, particularly in the US, 

higher production taxes, higher depreciation, and adverse foreign exchange 

impacts. 

 The primary additional factors reflected in profit for 2007, compared with 

2006, were higher liquids realizations, stronger refining and marketing margins 

and improved NGLs performance; however, these were more than offset by 

lower gas realizations, lower reported production volumes, higher production 

taxes in Alaska, higher costs (primarily reflecting the impact of sector-specific 

inflation and higher integrity spend), the impact of outages and 

recommissioning costs at the Texas City and Whiting refineries, reduced 

supply optimization benefits and a lower contribution from the marketing and 

trading business. 

 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. 

 Employee numbers were approximately 92,000 at 31 December 2008, 

98,100 at 31 December 2007 and 97,000 at 31 December 2006. 

aInventory holding gains and losses represent the difference between the cost of sales calculated using 

the average cost to BP of supplies incurred during the year and the cost of sales calculated on the firstin first-out (FIFO) method including any changes in provisions where the net realizable value of the 

inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of 

inventory charged to the income statement is based on the historic cost of acquisition or manufacture 

rather than the current replacement cost. In volatile energy markets, this can have a significant 

distorting effect on reported income. The amounts disclosed represent the difference between the 

charge to the income statement on a FIFO basis (and any related movements in net realizable value 

provisions) and the charge that would arise using average cost of supplies incurred during the period. 

For this purpose, average cost of supplies incurred during the period is calculated by dividing the total 

cost of inventory purchased in the period by the number of barrels acquired. The amounts disclosed are 

not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect 

of the cost of inventories held as part of a trading position and certain other temporary inventory 

positions.

 Management believes this information is useful to illustrate to investors the fact that crude oil and 

product prices can vary significantly from period to period and that the impact on our reported result 

under IFRS can be significant. Inventory holding gains and losses vary from period to period due 

principally to changes in oil prices as well as changes to underlying inventory levels. In order for 

investors to understand the operating performance of the group excluding the impact of oil price 

changes on the replacement of inventories, and to make comparisons of operating performance 

between reporting periods, BP’s management believes it is helpful to disclose this information.

Capital expenditure and acquisitions

Capital expenditure and acquisitions in 2008, 2007 and 2006 amounted to 

$30,700 million, $20,641 million and $17,231 million respectively. In 2008, this 

included $4,731 million in respect of our transaction with Husky Energy Inc. 

and $3,667 million in respect of our purchase of all Chesapeake Energy 

Corporation’s interest in the Arkoma Basin Woodford Shale assets and the 

purchase of a 25% interest in Chesapeake’s Fayetteville Shale assets. 

Acquisitions in 2007 included the remaining 31% of the Rotterdam (Nerefco) 

refinery from Chevron’s Netherlands manufacturing company. 

 Excluding acquisitions and asset exchanges, capital expenditure for 

2008 was $28,186 million compared with $19,194 million in 2007 and 

$16,910 million in 2006. In 2006, this included $1 billion in respect of our 

investment in Rosneft. 

Finance costs and net finance income relating to pensions and other 

post-retirement benefits 

Finance costs comprises group interest less amounts capitalized, and interest 

accretion on provisions and long-term other payables. Finance costs for 

continuing operations in 2008 were $1,547 million compared with 

$1,393 million in 2007 and $986 million in 2006. The increase in 2008, when 

compared with 2007, is largely the outcome of reductions in capitalized 

interest as capital construction projects concluded. The increase in 2007, 

when compared with 2006, reflected a higher average gross debt balance and 

lower capitalized interest as capital construction projects concluded. 

 Net finance income relating to pensions and other post-retirement 

benefits in 2008 was $591 million compared with $652 million in 2007 and 

$470 million in 2006. The expected return on assets has increased year on 

year as the pension asset base applicable to each year increased, but this has 

been offset in 2008 by higher interest costs reflecting the increase in discount 

rates applied to pension plan liabilities. 

Taxation 

The charge for corporate taxes for continuing operations in 2008 was 

$12,617 million, compared with $10,442 million in 2007 and $12,516 million in 

2006. The effective rate was 37% in 2008, 33% in 2007 and 36% in 2006. The 

group earns income in many countries and, on average, pays taxes at rates 

higher than the UK statutory rate of 28% for 2008. The increase in the 

effective rate in 2008 compared with 2007 primarily reflects the change in the 

country mix of the group’s income, resulting in a higher overall tax burden. The 

reduction in the effective rate in 2007 compared with 2006 primarily reflects 

the reduction in the UK tax rate and the fact that a higher proportion of income 

arose in countries bearing a lower tax rate and other factors. 

Business results 

Profit before interest and taxation from continuing operations, which is before 

finance costs, other finance expense, taxation and minority interests, was 

$35,239 million in 2008, $32,352 million in 2007 and $35,658 million in 2006. 

 $ million 

2008 2007 2006

Exploration and Production 22,026 13,904 13,209 

Refining and Marketing 4,710 4,356 3,105

Other businesses and corporate 1,450 934 596

Capital expenditure 28,186 19,194 16,910

Acquisitions and asset exchanges 2,514 1,447 321

30,700 20,641 17,231

Disposals (929) (4,267) (6,254)

Net investment 29,771 16,374 10,977

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Exploration and Production

48 

Performance review

For the year ended 31 December $ million

2008 2007 2006

Total revenuesa 89,902 69,376 71,868

Profit before interest and tax from continuing operationsb 37,915 27,729 30,953

Results include:

Exploration expense 882 756 1,045

Of which: Exploration expenditure written off 385 347 624 

$ per barrel

Key statistics

Average BP crude oil realizationsc 

UK 92.09 70.36 62.45

US 97.37 68.51 62.03

Rest of World 94.74 70.86 61.11

BP average 95.43 69.98 61.91

Average BP NGL realizationsc 

UK 57.24 52.71 47.21

US 52.14 44.59 36.13

Rest of World 50.84 48.14 36.03

BP average 52.30 46.20 37.17

Average BP liquids realizationsc d 

UK 89.82 69.17 61.67

US 89.22 64.18 57.25 

Rest of World 91.05 69.56 59.54

BP average 90.20 67.45 59.23

$ per thousand cubic feet

Average BP natural gas realizationsc

UK 8.41 6.40 6.33

US 6.77 5.43 5.74

Rest of World 5.19 3.71 3.70

BP average 6.00 4.53 4.72 

 

$ per barrel

Average West Texas Intermediate oil price 100.06 72.20 66.02

Alaska North Slope US West Coast 98.86 71.68 63.57 

Average Brent oil price 97.26 72.39 65.14

$ per million British thermal units

Average Henry Hub gas pricee 9.04 6.86 7.24 

pence per therm

Average UK National Balancing Point gas price 58.12 29.95 42.19

thousand barrels per day

Total liquids production for subsidiariesd f 1,263 1,304 1,351

Total liquids production for equity-accounted entitiesd f 1,138 1,110 1,124

million cubic feet per day

Natural gas production for subsidiariesf 7,277 7,222 7,412

Natural gas production for equity-accounted entitiesf 1,057 921 1,005

 

thousand barrels of oil equivalent per day

Total production for subsidiariesf g 2,517 2,549 2,629

Total production for equity-accounted entitiesf g 1,321 1,269 1,297

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

cRealizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.

dCrude oil and natural gas liquids.

eHenry Hub First of Month Index.

fNet of royalties.

gExpressed 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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Total revenues are analysed in more detail below. 

49

Performance review

$ million

2008 2007 2006

Sales and other operating revenues 86,170 65,740 67,950

Earnings from equity-accounted entities (after interest and tax), interest and other revenues 3,732 3,636 3,918 

 89,902 69,376 71,868 

Total revenues for 2008 were $90 billion, compared with $69 billion in 2007 

and $72 billion in 2006. The increase in 2008 primarily reflected higher oil and 

gas realizations. Gas marketing sales also increased primarily as a result of 

higher prices. The decrease in 2007 compared with 2006 primarily reflected 

lower volumes of subsidiaries and lower gas marketing sales, partly offset by 

higher realizations. 

 Profit before interest and tax for the year ended 31 December 2008 was 

$37,915 million. This included inventory holding losses of $393 million and a 

net charge for non-operating items of $990 million (see page 52), with the 

most significant items being net impairment charges (primarily driven by the 

current low price environment) and net fair value losses on embedded 

derivatives, partly offset by the reversal of certain provisions. The impairment 

charge includes a $517 million write-down of our investment in Rosneft based 

on its quoted market price at the end of the year. In addition, fair value 

accounting effects had an unfavourable impact of $282 million relative to 

management’s measure of performance (see page 52). 

 Profit before interest and tax for the year ended 31 December 2007 was 

$27,729 million. This included inventory holding gains of $127 million and a 

net credit from non-operating items of $491 million (see page 52), with the 

most significant items being net gains from the sale of assets (primarily from 

the disposal of our production and gas infrastructure in the Netherlands, our 

interests in non-core Permian assets in the US and our interests in the 

Entrada field in the Gulf of Mexico), partly offset by a restructuring charge and 

a charge in respect of the reassessment of certain provisions. In addition, fair 

value accounting effects had a favourable impact of $48 million relative to 

management’s measure of performance (see page 52). 

 Profit before interest and tax for the year ended 31 December 2006 was 

$30,953 million. This included inventory holding losses of $73 million and a net 

credit from non-operating items of $2,563 million (see page 52), with the most 

significant items being net gains from the sale of assets (primarily from the 

sales of interests in the Shenzi discovery in the Gulf of Mexico in the US and 

interests in the North Sea partly offset by a loss on the sale of properties in the 

Gulf of Mexico Shelf) and net fair value gains on embedded derivatives, partly 

offset by a charge for legal provisions. In addition, fair value accounting effects 

had an unfavourable impact of $32 million relative to management’s measure 

of performance (see page 52). 

The primary additional factor contributing to the 37% increase in profit before 

interest and tax for the year ended 31 December 2008 compared with the year 

ended 31 December 2007 was higher realizations. In addition, the result 

reflected a higher contribution from the gas marketing and trading business 

but was impacted by higher production taxes and higher depreciation. The 

impact of inflation within other costs was mitigated by rigorous cost control and 

a focus on simplification and efficiency. 

 The primary additional factors reflected in profit before interest and tax 

for the year ended 31 December 2007 compared with the year ended 31 

December 2006 were higher overall realizations (liquids realizations were 

higher and gas realizations were lower) and a favourable effect from lagged 

tax reference prices in TNK-BP; however, these factors were more than offset 

by the impact of lower reported volumes, a lower contribution from the gas 

marketing and trading business, higher production taxes in Alaska and higher 

costs, reflecting the impacts of sector-specific inflation, increased integrity 

spend and higher depreciation charges. Additionally, the result was lower due 

to the absence of disposal gains in 2006 in equity-accounted entities. 

 Reported production for 2008 was 2,517mboe/d for subsidiaries and 

1,321mboe/d for equity-accounted entities, compared with 2,549mboe/d and 

1,269mboe/d respectively in 2007. In aggregate, after adjusting for the effect 

of lower entitlement in our PSAs, production was 5% higher than 2007. This 

reflected strong performance from our existing assets, the continued ramp-up 

of production following the startup of major projects in late-2007 and the startup of a further nine major projects in 2008. 

 Reported production for 2007 was 2,549mboe/d for subsidiaries and 

1,269mboe/d for equity-accounted entities, compared with 2,629mboe/d and 

1,297mboe/d respectively in 2006. In aggregate, the decrease primarily 

reflected the effect of disposals and net entitlement reductions in our PSAs. 

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Refining and Marketing 

Total revenues are explained in more detail below. 

50 

Performance review

$ million

2008 2007 2006

Total revenuesa 320,458 250,897 232,833

Profit before interest and tax from continuing operationsb (1,884) 6,076 5,419

 

$ per barrel

Global Indicator Refining Margin (GIM)c

Northwest Europe 6.72 4.99 3.92

US Gulf Coast 6.78 13.48 12.00

Midwest 5.17 12.81 9.14

US West Coast 7.42 15.05 14.84 

Singapore 6.30 5.29 4.22

BP average 6.50 9.94 8.39 

 

%

Refining availabilityd 88.8 82.9 82.5

 thousand barrels per day

Refinery throughputs 2,155 2,127 2,198

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

cThe GIM is the average of regional industry indicator margins that 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 analyzing 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 noncash 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.

dRefining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to 

turnaround activity and all planned mechanical, process and regulatory maintenance downtime. 

$ million 

2008 2007 2006

Sale of crude oil through spot and term contracts 54,901 43,004 38,577

Marketing, spot and term sales of refined products 248,561 194,979 177,995

Other sales and operating revenues 16,577 12,238 15,814

Earnings from equity-accounted entities (after interest and tax), interest, and other revenues 419 676 447

 320,458 250,897 232,833

thousand barrels per day

Sale of crude oil through spot and term contracts 1,689 1,885 2,110

Marketing, spot and term sales of refined products 5,698 5,624 5,801

Total revenues for 2008 were $320 billion, compared with $251 billion in 2007 

and $233 billion in 2006. The increase in 2008 compared with 2007 primarily 

reflected an increase in marketing, spot and term sales of refined products, 

mainly driven by higher prices. Additionally, sales of crude oil, spot and term 

contracts increased, as a result of higher prices, partly offset by lower 

volumes. The increase in 2007 compared with 2006 was principally due to an 

increase in marketing, spot and term sales of refined products. This was due 

to higher prices and a positive foreign exchange impact due to a weaker 

dollar, partially offset by lower volumes. Additionally, sales of crude oil, spot 

and term contracts increased, primarily reflecting higher prices, and other 

sales decreased due to lower volumes partially offset by a positive foreign 

exchange impact. 

 The loss before interest and tax for the year ended 31 December 2008 

was $1,884 million. This included inventory holding losses of $6,060 million 

and a net credit for non-operating items of $347 million (see page 52). The 

most significant non-operating items were net gains on disposal (primarily in 

respect of the gain recognized on the contribution of the Toledo refinery into a 

joint venture with Husky Energy Inc.) partly offset by restructuring charges. In 

addition, fair value accounting effects had a favourable impact of $511 million 

relative to management’s measure of performance (see page 52). 

Profit before interest and tax for the year ended 31 December 2007 was 

$6,076 million. This included inventory holding gains of $3,455 million and a 

net charge for non-operating items of $952 million (see page 52). 

The most significant non-operating items were net disposal gains (primarily 

related to the sale of BP’s Coryton refinery in the UK, its interest in the West 

Texas pipeline system in the US and its interest in the Samsung 

Petrochemical Company in South Korea), net impairment charges (primarily 

related to the sale of the majority of our US Convenience Retail business, a 

write-down of certain assets at our Hull site and write-down of our retail assets 

in Mexico) and a charge related to the March 2005 Texas City refinery 

incident. In addition, fair value accounting effects had an unfavourable impact 

of $357 million relative to management’s measure of performance (see page 

52). 

 Profit before interest and tax for the year ended 31 December 2006 was 

$5,419 million. This included inventory holding losses of $242 million and a net 

credit for non-operating items of $113 million (see page 52). The most 

significant non-operating items were net disposal gains (related primarily to 

the sale of BP’s Czech Republic retail business, the disposal of BP’s 

shareholding in Zhenhai Refining and Chemicals Company, the sale of BP’s 

shareholding in Eiffage, the French-based construction company, and 

pipelines assets) and a charge related to the March 2005 Texas City refinery 

incident. In addition, fair 

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51

Performance review

value accounting effects had a favourable impact of $211 million relative to 

management’s measure of performance (see page 52). 

 During 2008, significant performance improvements in both our Fuels 

Value Chains and International Businesses mitigated cost inflation and, to a 

large extent, the much weaker environment. The main sources of 

improvement were from restoring the revenues of our refining operations; 

improved supply and trading performance; improved marketing performance, 

particularly from the International Businesses, and reduced costs. The cost 

reductions have been driven by the simplification of our business structure 

through the establishment of Fuels Value Chains and a reduction in our 

geographical footprint, as well as by strong cost management. The most 

significant environmental factor was the weaker refining environment, 

particularly due to lower refining margins in the US and the adverse impact in 

the second half of 2008 of prior-month pricing of domestic pipeline barrels for 

our US refining system, but there were also adverse foreign exchange effects. 

 During 2007, the segment continued to focus on the restoration of 

operations at the Texas City refinery and on investments in integrity 

management throughout our refining portfolio. We have also focused on the 

repair and recommissioning of the Whiting refinery following the operational 

issues in March 2007. In many parts of the refining portfolio and the other 

market-facing businesses, we delivered high reliability and improved results 

compared with 2006. However, for the full year, compared with 2006, the 

impact of the outages and recommissioning costs at the Texas City and 

Whiting refineries, as well as investments in integrity management and 

scheduled turnarounds throughout our refining portfolio, cost inflation and 

lower results from supply optimization decreased our result. These factors 

more than offset increased margins in both refining and marketing. 

 The average refining Global Indicator Margin (GIM) in 2008 was lower 

than in 2007. 

 Refining throughputs in 2008 were 2,155mb/d, 28mb/d higher than in 

2007. Refining availability was 88.8%, six percentage points higher than in 

2007, the increase being driven primarily by improvement at the Texas City 

and Whiting refineries. Marketing volumes at 3,711mb/d were around 2.5% 

lower than in 2007. 

Other businesses and corporate

Other businesses and corporate comprises the Alternative Energy business, 

Shipping, the group’s aluminium asset, Treasury (which includes all the 

group’s cash, cash equivalents), and corporate activities worldwide. 

 The loss before interest and tax for the year ended 31 December 2008 

was $1,258 million and included inventory holding losses of $35 million and a 

net charge for non-operating items of $633 million (see page 52). 

 The loss before interest and tax for the year ended 31 December 2007 

was $1,233 million and included inventory holding losses of $24 million and a 

net charge for non-operating items of $262 million (see page 52). 

 The loss before interest and tax for the year ended 31 December 2006 

was $779 million and included inventory holding gains of $62 million and a net 

charge for non-operating items of $72 million (see page 52). 

Non-operating items 

Non-operating items are charges and credits that BP discloses separately 

because it considers such disclosures to be meaningful and relevant to 

$ million

2008 2007 2006

Total revenuesa 5,040 3,972 3,703

Profit (loss) before interest and tax from 

continuing operationsb (1,258) (1,233) (779)

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

investors. The main categories of non-operating items in the periods 

presented are: impairments; gains or losses on sale of fixed assets and the 

sale of businesses; environmental remediation; restructuring, integration and 

rationalization costs; and changes in the fair value of embedded derivatives. 

These disclosures are provided in order to enable investors better to 

understand and evaluate the group’s financial performance. An analysis of 

non-operating items is shown on page 52. 

Non-GAAP information on fair value accounting effects 

BP uses derivative instruments to manage the economic exposure relating to 

inventories above normal operating requirements of crude oil, natural gas and 

petroleum products as well as certain contracts to supply physical volumes at 

future dates. Under IFRS, these inventories and contracts are recorded at 

historic cost and on an accruals basis respectively. The related derivative 

instruments, however, are required to be recorded at fair value with gains and 

losses recognized in income because hedge accounting is either not permitted 

or not followed, principally due to the impracticality of effectiveness testing 

requirements. Therefore, measurement differences in relation to recognition of 

gains and losses occur. Gains and losses on these inventories and contracts 

are not recognized until the commodity is sold in a subsequent accounting 

period. Gains and losses on the related derivative commodity contracts are 

recognized in the income statement from the time the derivative commodity 

contract is entered into on a fair value basis using forward prices consistent 

with the contract maturity.

 IFRS requires that inventory held for trading be recorded at its fair value 

using period end spot prices whereas any related derivative commodity 

instruments are required to be recorded at values based on forward prices 

consistent with the contract maturity. Depending on market conditions, these 

forward prices can be either higher or lower than spot prices resulting in 

measurement differences. 

 BP enters into contracts for pipelines and storage capacity that, under 

IFRS, are recorded on an accruals basis. These contracts are risk-managed 

using a variety of derivative instruments that are fair valued under IFRS. This 

results in measurement differences in relation to recognition of gains and 

losses. 

 The way that BP manages the economic exposures described above, 

and measures performance internally, differs from the way these activities are 

measured under IFRS. BP calculates this difference by comparing the IFRS 

result with management’s internal measure of performance, under which the 

inventory and the supply and capacity contracts in question are valued based 

on fair value using relevant forward prices prevailing at the end of the period. 

We believe that disclosing management’s estimate of this difference provides 

useful information for investors because it enables investors to see the 

economic effect of these activities as a whole. The impacts of fair value 

accounting effects, relative to management’s internal measure of 

performance, are shown in the table below and on the following page. 

Reconciliation of non-GAAP information 

Exploration and Production 

 $ million 

2008 2007 2006

Profit before interest and tax adjusted for fair 

value accounting effects 38,197 27,681 39,985

Impact of fair value accounting effects (282) 48 (32)

Profit before interest and tax 37,915 27,729 39,953

 

Refining and Marketing

Profit before interest and tax adjusted for fair 

value accounting effects (2,395) 6,433 5,208

Impact of fair value accounting effects 511 (357) 211

Profit before interest and tax (1,884) 6,076 5,419

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Non-operating items

Fair value accounting effects

52 

Performance review

$ million

2008 2007 2006

Exploration and Production

Impairment and gain (loss) on sale of businesses and fixed assets (1,015) 857 2,410

Environmental and other provisions (12) (12) (17)

Restructuring, integration and rationalization costs (57) (186) –

Fair value gain (loss) on embedded derivatives (163) – 603

Other 257 (168) (433)

(990) 491 2,563

Refining and Marketing

Impairment and gain (loss) on sale of businesses and fixed assets 801 (35) 726

Environmental and other provisions (64) (138) (33)

Restructuring, integration and rationalization costs (447) (118) – 

Fair value gain (loss) on embedded derivatives 57 – –

Other – (661) (580)

 347 (952) 113 

 

Other businesses and corporate

Impairment and gain (loss) on sale of businesses and fixed assets (166) (14) 29

Environmental and other provisions (117) (35) 94

Restructuring, integration and rationalization costs (254) (34) –

Fair value gain (loss) on embedded derivatives (5) (7) 5 

Other (91) (172) (200)

(633) (262) (72)

Total before taxation for continuing operations (1,276) (723) 2,604

Taxationa 480 350 (1,073)

Total after taxation for continuing operations (796) (373) 1,531

$ million

2008 2007 2006

Exploration and Production

Unrecognized gains (losses) brought forward from previous period 107 155 123

Unrecognized (gains) losses carried forward (389) (107) (155)

Favourable (unfavourable) impact relative to management’s measure of performance (282) 48 (32)

Refining and Marketing

Unrecognized gains (losses) brought forward from previous period 429 72 283 

Unrecognized (gains) losses carried forward 82 (429) (72)

Favourable (unfavourable) impact relative to management’s measure of performance 511 (357) 211

229 (309) 179

Taxationa (83) 111 (107)

 146 (198) 72

By region

Exploration and Production

UK 45 1 63

Rest of Europe – – –

US (231) (77) (59)

Rest of World (96) 124 (36)

 (282) 48 (32)

Refining and Marketing

UK 186 (52) 109

Rest of Europe 54 (110) 101

US 231 (165) 13 

Rest of World 40 (30) (12)

 511 (357) 211

aThe amounts shown for taxation are based upon the effective tax rate on group profit.

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53

Performance review

 

 $ million 

2008 2007 2006

Environmental expenditure

Operating expenditure 755 662 596

Clean-ups 64 62 59 

Capital expenditure 1,104 1,033 806

Additions to environmental remediation provision 270 373 423

Additions to decommissioning provision 326 1,163 2,142

Operating and capital expenditure on the prevention, control, 

abatement or elimination of air, water and solid waste pollution is 

often not incurred as a separately identifiable transaction. 

Instead, it forms part of a larger transaction that includes, for 

example, normal maintenance expenditure. The figures for 

environmental operating and capital expenditure in the table are 

therefore estimates, based on the definitions and guidelines of 

the American Petroleum Institute. 

 Environmental operating expenditure of $755 million in 

2008 was higher than in 2007 and reflects continuing integrity 

management activity. There were no individually significant 

factors driving the increase. 

 The increase in environmental operating expenditure in 

2007 compared with 2006 is primarily due to increased integrity 

management activity and activity associated with the 

implementation of the Baker Panel recommendations. 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 2008 includes 

$234 million resulting from a reassessment of existing site 

obligations and $36 million in respect of provisions for new sites. 

 Provisions for environmental remediation are made when a 

cleanup is probable and the amount of the obligation can be 

reliably estimated. Generally, this 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 environment restoration, 

remediation and abatement programmes are often inherently 

difficult to estimate. They often depend on the extent of 

contamination, and the associated impact and timing of the 

corrective actions required, technological feasibility and BP’s 

share of liability. Though the costs of future programmes 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. 

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 an oil or natural gas production facility a provision is 

established that 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 onstream 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 Financial statements - Note 37 on page 156. See also Environment 

on page 39. 

Suppliers and contractors

Our processes are designed to enable us to choose suppliers carefully on 

merit, avoiding conflicts of interest and inappropriate gifts and entertainment. 

We expect suppliers to comply with legal requirements and we seek to do 

business with suppliers who act in line with BP’s commitments to compliance 

and ethics, as outlined in the code of conduct. We engage with suppliers in a 

variety of ways, including performance review meetings to identify mutually 

advantageous ways to improve performance. 

Creditor payment policy and practice

Statutory regulations issued under the UK Companies Act 1985 require 

companies to make a statement of their policy and practice in respect of the 

payment of trade creditors. In view of the international nature of the group’s 

operations there is no specific group-wide policy in respect of payments to 

suppliers. Relationships with suppliers are, however, governed by the group’s 

policy commitment to long-term relationships founded on trust and mutual 

advantage. Within this overall policy, individual operating companies are 

responsible for agreeing terms and conditions for their business transactions 

and ensuring that suppliers are aware of the terms of payment. 

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Liquidity and capital resources 

Cash flow 

The following table summarizes the group’s cash flows. 

54 

Performance review

 

$ million

2008 2007 2006

Net cash provided by operating activities 38,095 24,709 28,172

Net cash used in investing activities (22,767) (14,837) (9,518)

Net cash used in financing activities (10,509) (9,035) (19,071)

Currency translation differences relating to cash and cash equivalents (184) 135 47

Increase (decrease) in cash and cash equivalents 4,635 972 (370)

Cash and cash equivalents at beginning of year 3,562 2,590 2,960 

Cash and cash equivalents at end of year 8,197 3,562 2,590 

Net cash provided by operating activities for the year ended 31 

December 2008 was $38,095 million compared with $24,709 million for the 

equivalent period of 2007 reflecting a decrease in working capital 

requirements of $11,250 million, an increase in profit before taxation of 

$2,672 million and an increase in dividends from jointly controlled entities and 

associates of $1,255 million; these were partly offset by an increase in income 

taxes paid of $3,752 million. 

 Net cash provided by operating activities for the year ended 31 

December 2007 was $24,709 million, compared with $28,172 million for the 

equivalent period for 2006 reflecting an increase in working capital 

requirements of $6,282 million, a decrease in profit before taxation from 

continuing operations of $3,531 million, a decrease in dividends from jointly 

controlled entities and associates of $2,022 million; these were partially offset 

by a decrease in income taxes paid of $4,661 million, a lower net credit for 

impairment and gains and losses on sale of businesses and fixed assets of 

$2,357 million and higher depreciation, depletion and amortization of 

$1,451 million. 

 Net cash used in investing activities was $22,767 million in 2008, 

compared with $14,837 million and $9,518 million in 2007 and 2006. The 

increase in 2008 reflected a reduction in disposal proceeds of $3,338 million 

and an increase in capital expenditure of $5,303 million. The increase in 2007 

reflected a reduction in disposal proceeds of $1,987 million and an increase in 

capital expenditure of $2,713 million. 

 Net cash used in financing activities was $10,509 million in 2008 

compared with $9,035 million in 2007 and $19,071 million in 2006. The 

increase in 2008 reflects a decrease in short-term debt of $2,809 million and 

an increase in dividends paid of $2,434 million; these were partly offset by a 

$4,546 million decrease in the net repurchase of shares. The reduction in 

2007 compared with 2006 reflects a reduction in net repurchases of shares of 

$8,038 million and an increase in proceeds from long-term financing of 

$4,278 million; these were partially offset by a net decrease in short-term debt 

of $2,379 million. 

 The group has had significant levels of capital investment for many 

years. Cash flow in respect of capital investment, excluding acquisitions, was 

$23.7 billion in 2008, $18.4 billion in 2007 and $15.7 billion in 2006. 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 $25.0 billion at the end of 2008, $26.8 billion at the end of 

2007 and was $21.1 billion at the end of 2006. 

 During the period 2006 to 2008, our total sources of cash amounted to 

$104 billion, whilst our total uses of cash amounted to $112 billion. The net 

cash usage of $8 billion was financed by an increase in finance debt of 

$13 billion over the three-year period, offset by an increase in our balance of 

cash and cash equivalents of $5 billion. During this period, the price of Brent 

has averaged $78.26 per barrel. The following table summarizes the threeyear sources and uses of cash. 

Acquisitions made for cash were more than offset by divestments. Net 

investment during the same period has averaged $16 billion per year. 

Dividends to BP shareholders, which grew on average by 16.8% per year in 

dollar terms, used $26 billion. Net repurchase of shares was $25 billion, which 

includes $26 billion in respect of our share buyback programme less net 

proceeds from shares issued in connection with employee share schemes. 

Finally, cash was used to strengthen the financial condition of certain of our 

pension plans. In the past three years, $2 billion has been contributed to 

funded pension plans. This is reflected in net cash provided by operating 

activities in the table above. 

Trend information 

We expect the short-term outlook for oil prices to be impacted by OPEC cuts 

on the one hand, and the outlook for the world economy and oil demand on 

the other. We expect continued volatility and our current expectation is that oil 

prices, relative to 2008, will continue to be low in 2009, and that this could 

extend into 2010. 

 In Exploration and Production, total production is expected to be 

somewhat higher in 2009. The actual growth rate will depend on a number of 

factors, including our pace of capital spending, the efficiency of that spend (in 

turn depending on industry cost deflation), the oil price and its impact on PSAs 

as well as OPEC quota restrictions. 

 In Refining and Marketing, 2009 is expected to be a challenging 

environment with reduced demand for our products, leading to lower volumes 

and pressure on margins. The impact is expected to be greatest in the 

petrochemicals sector. In 2009, with our US refining system fully operational, 

we expect our overall refining availability to be higher than in 2008. 

 

 $ billion 

Sources of cash 

Net cash provided by operating activities 91

Divestments 13

104

Uses of cash

Capital expenditure 58 

Acquisitions 2

Net repurchase of shares 25

Dividends to BP shareholders 26 

Dividends to minority interests 1

112

Net use of cash (8)

Financed by

Increase in finance debt (13)

Increase in cash and cash equivalents 5

(8)

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55

Performance review

During 2008, we established momentum in cost control, mitigating the cost 

inflation that was primarily driven by rising oil prices. In 2009, our highest 

priority will continue to be achieving safe, compliant and reliable operations 

and we intend to continue our focus on cost efficiency. We expect cost 

deflation to be increasingly visible as we move through 2009. 

 We expect capital expenditure, excluding acquisitions and asset 

exchanges, to be around $20-21 billion in 2009. This reflects our intention in 

Exploration and Production to maintain investment whilst vigorously working to 

drive down costs and to reduce spending in our Refining and Marketing and 

Alternative Energy businesses in keeping with the current weak economic 

environment. We expect disposal proceeds to be between $2-3 billion in 2009. 

 On the basis of our current plans, we expect cash inflows and outflows 

in 2009 would balance at oil prices of around $60/bbl, taking account of 

expected disposal proceeds. We would expect that break even point to lower 

as we realize the benefits of our operational momentum and our action on 

costs. 

Dividends and other distributions to shareholders 

The total dividend paid to BP shareholders in 2008 was $10,342 million, 

compared with $8,106 million for 2007. The dividend paid per share was 55.05 

cents, an increase of 30% compared with 2007. In sterling terms, the dividend 

increased 40% due to the strengthening of the dollar relative to sterling. We 

determine the dividend in US dollars, the economic currency of BP. 

 During 2008, the company repurchased 269.8 million of its own shares 

for cancellation at a cost of $2.9 billion. The repurchased shares had a 

nominal value of $67.5 million and represented 1.4% of ordinary shares in 

issue, net of treasury shares, at the end of 2007. Since the inception of the 

share repurchase programme in 2000, we have repurchased 4,929 million 

shares at a cost of $51.1 billion. 

 Our aim is to strike the right balance for shareholders, between current 

returns via the dividend, sustained investment for long-term growth, and 

maintaining a prudent gearing level. At the beginning of 2008, we rebalanced 

our distributions away from share buybacks in favour of dividends. 

 BP intends to continue the operation of the Dividend Reinvestment Plan 

(DRIP) for shareholders who wish to receive their dividend in the form of 

shares rather than cash. The BP Direct Access Plan for US and Canadian 

shareholders also includes a dividend reinvestment feature. 

 The discussion above and following contains forward-looking 

statements with regard to oil prices, production, demand for refining products, 

refining volumes and margins and impact on the petrochemicals sector, 

refining availability, continuing priority of safe, compliant and reliable 

operations, and focus on cost efficiency, cost deflation, capital expenditure, 

expected disposal proceeds, cash flows, shareholder distributions, gearing, 

working capital, guarantees, expected payments under contractual and 

commercial commitments and purchase obligations. These forward-looking 

statements are based on assumptions that management believes to be 

reasonable in the light of the group’s operational and financial experience. 

However, no assurance can be given that the forward-looking statements will 

be realized. You are urged to read the cautionary statement under Forwardlooking statements on page 10 and Risk factors on pages 8-10, 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 forwardlooking 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 31 

December 2008 amounted to $33,204 million (2007 $31,045 million) of which 

$15,740 million (2007 $15,394 million) was short term. 

 Net debt was $25,041 million at the end of 2008, a decrease of 

$1,776 million compared with 2007. We believe that a net debt ratio, that is net 

debt to net debt plus equity, of 20-30% provides an efficient capital structure 

and the appropriate level of financial flexibility. The net debt ratio was 21% at 

the end of 2008 and 22% at the end of 2007, close to the lower end of our 

target band. Net debt, which BP uses as a measure of financial gearing, 

includes the fair value of associated derivative financial instruments that are 

used to hedge foreign exchange and interest rate risks relating to finance 

debt, for which hedge accounting is claimed. 

 The maturity profile and fixed/floating rate characteristics of the group’s 

debt are described in Financial statements – Note 28 on page 140 and Note 

35 on page 153. 

 We have in place a European Debt Issuance Programme (DIP) under 

which the group may raise $20 billion of debt for maturities of one month or 

longer. At 31 December 2008, the amount drawn down against the DIP was 

$10,334 million (2007 $10,438 million). 

 In addition, the group has in place a US Shelf Registration under which 

it may raise $10 billion of debt with maturities of one month or longer. At 31 

December 2008, the amount raised under the US Shelf Registration was 

$6,500 million (2007 $2,500 million). 

 Commercial paper markets in the US and Europe are a primary source 

of liquidity for the group. At 31 December 2008, the outstanding commercial 

paper amounted to $4,268 million (2007 $5,881 million). 

 The group also has access to significant sources of liquidity in the form 

of committed facilities and other funding through the capital markets. At 31 

December 2008, the group had available undrawn committed borrowing 

facilities of $4,950 million (2007 $4,950 million). 

 Despite current uncertainty in the financial markets, including a lack of 

liquidity for some borrowers, we have been able to issue $5 billion of long-term 

debt in the fourth quarter of 2008. In addition, we have been able to issue 

short-term commercial paper at competitive rates. In the context of unforeseen 

market volatility, we have however, increased the cash and cash equivalents 

held by the group to $8.2 billion at the end of 2008, compared with $3.6 billion 

at the end of 2007. 

 BP believes that, taking into account the substantial amounts of 

undrawn borrowing facilities available, the group has sufficient working capital 

for foreseeable requirements. 

Off-balance sheet arrangements 

At 31 December 2008, the group’s share of third-party finance debt of equityaccounted entities was $6,675 million (2007 $6,764 million). 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 31 December 2008 are summarized on the following page. 

Some guarantees outstanding are in respect of borrowings of jointly controlled 

entities and associates noted above. The analysis by time period indicates the 

ultimate expiry of the guarantees. 

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Contractual commitments 

The following table summarizes the group’s principal contractual obligations at 31 December 2008. Further information on borrowings and finance leases is given in 

Financial statements – Note 35 on page 153 and more information on operating leases is given in Financial statements – Note 16 on page 130. 

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

The group expects its total capital expenditure, excluding acquisitions and asset exchanges to be around $20-21 billion in 2009. The following table summarizes the 

group’s capital expenditure commitments for property, plant and equipment at 31 December 2008 and the proportion of that expenditure for which contracts have 

been placed. Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. For jointly 

controlled assets, the net BP share is included in the amounts shown. Where operating lease costs are incurred in connection with a capital project, some or all of 

the cost may be capitalized as part of the capital cost of the project. Such costs are included in the amounts shown. 

In addition, at 31 December 2008, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $1.2 billion. 

Contracts were in place for $0.8 billion of this total. 

56 

Performance review

 

 $ million 

Guarantees expiring by period

2014 and

Total 2009 2010 2011 2012 2013 thereafter

Guarantees issued in respect ofa

Liabilities and borrowings of jointly controlled entities and associates 223 70 32 25 6 6 84

Liabilities and borrowings of other third parties 613 94 19 30 35 34 401

aOf the amounts shown in the table, $215 million of the jointly controlled entities and associates guarantees relate to guarantees of borrowings and for other third party guarantees, $582 million relates to guarantees of 

borrowings.

 

 $ million 

Payments due by period

Expected payments by period under contractual 2014 and

obligations and commercial commitments Total 2009 2010 2011 2012 2013 thereafter

Borrowingsa 35,192 16,554 5,817 3,303 2,577 5,014 1,927

Finance lease future minimum lease payments 916 116 117 116 70 58 439

Operating leasesb 18,795 4,135 3,215 2,340 1,897 1,688 5,520

Decommissioning liabilities 12,347 348 361 211 157 197 11,073

Environmental liabilities 1,797 422 380 204 177 129 485 

Pensions and other post-retirement benefitsc 26,288 1,105 1,352 1,346 1,346 1,342 19,797

Purchase obligationsd 115,642 64,479 13,317 6,559 5,100 4,531 21,656

Total 210,977 87,159 24,559 14,079 11,324 12,959 60,897 

aExpected payments include interest payments on borrowings totalling $2,607 million ($907 million in 2009, $608 million in 2010, $421 million in 2011, $318 million in 2012, $236 million in 2013 and $117 million 

thereafter). 

bThe future minimum lease payments are before deducting related rental income from operating sub-leases. Where an operating lease is entered into solely by the group as the operator of a jointly controlled asset, the 

total cost is included irrespective of any amounts that will be reimbursed by joint venture partners. Where operating lease costs are incurred in relation to the hire of equipment used in connection with a capital project, 

some or all of the cost may be capitalized as part of the capital cost of the project. 

cRepresents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post- retirement benefits.

dRepresents 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 2009 include purchase commitments existing at 31 December 2008 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 Financial statements – Note 28 on page 140. 

 

$ million

Payments due by period

2014 and

Purchase obligations Total 2009 2010 2011 2012 2013 thereafter

Crude oil and oil products 42,261 31,308 2,972 970 1,203 953 4,855

Natural gas 43,242 22,949 5,982 2,844 1,837 1,619 8,011 

Chemicals and other refinery feedstocks 12,223 3,010 1,724 1,295 837 847 4,510

Power 6,156 4,910 1,168 60 16 2 –

Utilities 690 111 101 86 83 57 252

Transportation 3,820 759 464 416 341 314 1,526

Use of facilities and services 7,250 1,432 906 888 783 739 2,502 

Total 115,642 64,479 13,317 6,559 5,100 4,531 21,656 

 

$ million

2014 and

Capital expenditure commitments Total 2009 2010 2011 2012 2013 thereafter

Committed on major projects 35,845 14,936 8,154 5,175 3,136 1,580 2,864

Amounts for which contracts have been placed 14,062 8,175 2,908 1,197 621 402 759 

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57

Performance review

Critical accounting policies 

The significant accounting policies of the group are summarized in Financial 

statements – Note 1 on page 106. 

 Inherent in the application of many of the accounting policies used in 

preparing 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 financial statements 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 more 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 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, taxation, 

derivative financial instruments, provisions and contingencies, and pensions 

and other post-retirement benefits. 

Oil and natural gas accounting 

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. 

 Exploration licence and leasehold property acquisition costs are 

capitalized within intangible assets and are reviewed at each reporting date to 

confirm that there is no indication that the carrying amount exceeds the 

recoverable amount. This review includes confirming that exploration drilling is 

still under way or firmly planned or that it has been determined, or work is 

under way 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. If no future activity 

is planned, the remaining balance of the licence and property acquisition costs 

is written off. Lower value licences are pooled and amortized on a straight-line 

basis over the estimated period of exploration. 

 For exploration wells and exploratory-type stratigraphic test wells, costs 

directly associated with the drilling of wells are initially capitalized within 

intangible 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 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. 

 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. Where this is 

no longer the case, the costs are immediately expensed. 

 Once a project is sanctioned for development, the carrying values of 

exploration licence and leasehold property acquisition costs and costs 

associated with exploration wells and exploratory-type stratigraphic test wells, 

are transferred to production assets within property, plant and equipment. 

 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. Field development costs 

subject to depreciation are expenditures incurred to date, together with 

approved future development expenditure required to develop 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: 

The impact of changes in estimated proved reserves is dealt with 

prospectively by amortizing the remaining carrying value of the asset over the 

expected future production. If proved reserves estimates are revised 

downwards, earnings could be affected by higher depreciation expense or an 

immediate write-down of the property’s carrying value (see discussion of 

recoverability of asset carrying values on the following page). 

 At the end of 2006, BP adopted the SEC rules for estimating reserves 

instead of the UK accounting rules contained in the UK Statement of 

Recommended Practice. These changes are explained in Financial 

statements – Note 10 on page 125. 

 The estimation of oil and natural gas reserves and BP’s process to 

manage reserves bookings is described in Exploration and Production - 

Reserves and production on page 14. As discussed on the following page, oil 

and natural gas reserves have a direct impact on the assessment of the 

recoverability of asset carrying values reported in the financial statements. 

 The 2008 movements in proved reserves are reflected in the tables 

showing movements in oil and gas reserves by region in Financial 

statements – Supplementary information on oil and natural gas on pages 185 

to 193. 

• Producing wells – proved developed reserves.

• Licence and property acquisition, field development and future 

decommissioning costs – total proved reserves.

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58 

Performance review

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 and, as a result, charges for 

impairment are recognized in the group’s results from time to time. Such 

indicators include changes in the group’s business plans, changes in 

commodity prices leading to unprofitable performance, low plant utilization, 

evidence of physical damage and, for oil and gas properties, significant 

downward revisions of estimated volumes or increases in estimated future 

development expenditure. If there are low oil prices, natural gas prices, 

refining margins or marketing margins during an extended period, the group 

may need to recognize significant impairment charges. 

 The assessment for impairment entails comparing the carrying value of 

the cash-generating unit with its recoverable amount, that is, the higher of fair 

value less costs to sell 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 on operating expenses, discount 

rates, production profiles and the outlook for global or regional market supplyand-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 develop and produce 

proved reserves and associated risk-adjusted probable and possible volumes. 

Expected future cash flows from the sale or production of these volumes are 

calculated based on the management’s best estimate of future oil and gas 

prices. Prices for oil and natural gas used for future cash flow calculations are 

based on market prices for the first five years and the group’s long-term 

planning assumptions thereafter. As at 31 December 2008, the group’s longterm planning assumptions were $75 per barrel for Brent and $7.50/mmBtu for 

Henry Hub (2007 $60 per barrel and $7.50/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. 

 The future cash flows are adjusted for risks specific to the cashgenerating unit and are discounted using a pre-tax discount rate. The discount 

rate is derived from the group’s post-tax weighted average cost of capital and 

is adjusted where applicable to take into account any specific risks relating to 

the country where the cash-generating unit is located. Typically rates of 11% 

or 13% are used (2007 11% or 13%). The rate applied in each country is reassessed each year by analyzing relevant information. 

 Irrespective of whether there is any indication of impairment, BP is 

required to test annually for impairment of goodwill acquired in a business 

combination. The group carries goodwill of approximately $9.9 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. 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. 

Taxation 

The computation of the group’s income tax expense involves the interpretation 

of applicable tax laws and regulations in many jurisdictions throughout the 

world. The resolution of tax positions taken by the group, through negotiations 

with relevant tax authorities or through litigation, can take several years to 

complete and in some cases it is difficult to predict the ultimate outcome. 

 In addition, the group has carry-forward tax losses in certain taxing 

jurisdictions that are available to offset against future taxable profit. However, 

deferred tax assets are recognized only to the extent that it is probable that 

taxable profit will be available against which the unused tax losses can be 

utilized. Management judgement is exercised in assessing whether this is the 

case. 

 To the extent that actual outcomes differ from management’s estimates, 

taxation charges or credits may arise in future periods. For more information 

see Financial statements – Note 20 on page 133 and Note 44 on page 172. 

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 as well as for trading purposes. In addition, derivatives 

embedded within other financial instruments or other host contracts are 

treated as separate derivatives when their risks and characteristics are not 

closely related to those of the host contract. All such derivatives are initially 

recognized at fair value on the date on which a derivative contract is entered 

into and are subsequently remeasured at fair value. Gains and losses arising 

from changes in the fair value of derivatives that are not designated as 

effective hedging instruments are recognized in the income statement. 

 In some cases the fair values of derivatives are estimated using models 

and other valuation methods due to the absence of quoted prices or other 

observable, market-corroborated data. In particular, this applies to the majority 

of the group’s natural gas and LNG embedded derivatives. These are primarily 

long-term UK gas contracts that use pricing formulae not related to gas prices, 

for example, oil product and power prices. These contracts are valued using 

models with inputs that include price curves for each of the different products 

that are built up from active market pricing data and extrapolated to the expiry 

of the contracts 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. Price volatility is 

also an input for the models. Changes in the key assumptions could have a 

material impact on the gains and losses on embedded derivatives recognized 

in the income statement. For more information see Financial statements - 

Note 34 on page 148. An analysis of the sensitivity of the fair value of the 

natural gas and LNG derivatives to changes in the key assumptions is 

provided in Financial statements - Note 28 on page 140. 

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Performance review

Provisions and contingencies 

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 of future cash flows are subject to significant uncertainty. Changes in 

the expected future costs are reflected in both the provision and the 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 used in discounting the cash flows. The interest 

rate used to determine the balance sheet obligation at the end of 2008 was 

2%, unchanged from the end of 2007. 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 and the amount of cash outflow can be reliably 

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). 

 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 31 

December 2008 was 2%, the same rate as at the previous balance sheet date. 

 As further described in Financial statements – Note 44 on page 172, 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 post-retirement benefits 

Accounting for pensions and other post-retirement 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 

post-retirement 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 post-retirement benefit assumptions are reviewed by 

management at the end of each year. These assumptions are used to 

determine the projected benefit obligation at the year-end and hence the 

surpluses and deficits recorded on the group’s balance sheet, and pension 

and other post-retirement benefit expense for the following year. 

 The pension and other post-retirement benefit assumptions at 31 

December 2008, 2007 and 2006 are provided in Financial statements – Note 

38 on page 157. 

 The assumed rate of investment return, discount rate and the US 

healthcare cost trend rate have a significant effect on the amounts reported. A 

sensitivity analysis of the impact of changes in these assumptions on the 

benefit expense and obligation is provided in Financial statements - Note 38 

on page 157. 

 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 published tables adjusted where appropriate 

to reflect the experience of the group and an extrapolation of past longevity 

improvements into the future. BP’s most substantial pension liabilities are in 

the UK, US and Germany and the mortality assumptions for these countries 

are detailed in Financial statements - Note 38 on page 157. 

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Board performance 

and biographies

 

 

62 Directors and senior management

65 BP board performance report

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Directors and senior management 

The following lists the company’s directors and senior management as at 18 February 2009. 

Mr H L McKay, previously executive vice president (special projects), was appointed chairman and president of BP America Inc. on the retirement of Mr R A Malone 

on 1 February 2009. 

Dr D C Allen retired as a director on 31 March 2008 and Dr W E Massey retired as a director on 17 April 2008. Mr G David was appointed a non-executive director 

on 11 February 2008. At the company’s 2008 annual general meeting (AGM), the following directors retired, offered themselves for election/re-election and were 

duly elected/re-elected: Mr A Burgmans; Mrs C B Carroll; Sir William Castell; Mr I C Conn; Mr G David, Mr E B Davis, Jr; Mr D J Flint; Dr B E Grote; Dr A B 

Hayward; Mr A G Inglis; Dr D S Julius; Sir Tom McKillop; Sir Ian Prosser and Mr P D Sutherland. 

Mr R Dudley has been appointed to the board with effect from 6 April 2009. All of the directors, including Mr Dudley, will offer themselves for election/ re-election at 

the company’s 2009 AGM. 

David Jackson (56) was appointed company secretary in 2003. A solicitor, he is a director of BP Pension Trustees Limited and a member of the Listing Authorities 

Advisory Committee. 

62 

Directors and senior management

Name Initially elected or appointed

P D Sutherland Chairman Chairman since May 1997

 Director since July 1995

Sir Ian Prosser Non-Executive Deputy Chairman Deputy chairman since February 1999

 Director since May 1997

A Burgmans Non-Executive Director February 2004

C B Carroll Non-Executive Director June 2007

Sir William Castell Non-Executive Director July 2006

G David Non-Executive Director February 2008

E B Davis, Jr Non-Executive Director December 1998

D J Flint Non-Executive Director January 2005

Dr D S Julius Non-Executive Director November 2001

Sir Tom McKillop Non-Executive Director July 2004

Dr A B Hayward Executive Director (Group Chief Executive) Group Chief Executive since May 2007

 Director since February 2003

I C Conn Executive Director (Chief Executive, Refining and Marketing) July 2004

Dr B E Grote Executive Director (Chief Financial Officer) August 2000

A G Inglis Executive Director (Chief Executive, Exploration and Production) February 2007

R Bondy Group General Counsel May 2008

S Bott Executive Vice President, Human Resources March 2005

V Cox Executive Vice President, Alternative Energy July 2004

H L McKay Executive Vice President (Chairman and President of BP America Inc.) June 2008

J Mogford Executive Vice President (Chief Operating Officer, Refining and US Fuels Value Chains) October 2007

S Westwell Executive Vice President (Group Chief of Staff) January 2008

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63

Directors and senior management

Directors 

P D Sutherland, SC, KCMG 

Chairman of the chairman’s and the nomination committees and attends 

meetings of the remuneration committee 

Peter Sutherland (62) rejoined BP’s board in 1995, having been a nonexecutive director from 1990 to 1993, and was appointed chairman in 1997. 

He is non-executive chairman of Goldman Sachs International and was a nonexecutive director of The Royal Bank of Scotland Group PLC from 2001 to 6 

February 2009. 

Sir Ian Prosser 

Member of the chairman’s, the nomination and the remuneration committees 

and chairman of the audit committee 

Sir Ian (65) joined BP’s board in 1997 and was appointed non-executive 

deputy chairman in 1999. He is the senior independent director. In 2003, he 

retired as chairman of InterContinental Hotels Group PLC, a spin-off from the 

former Bass PLC where he was chief executive. 

He is a non-executive director and senior independent director of 

GlaxoSmithKline plc, a non-executive director of the Sara Lee Corporation and 

non-executive chairman of The Navy, Army and Air Force Institutes (NAAFI). 

He was previously on the boards of The Boots Company PLC and Lloyds TSB 

PLC. 

A Burgmans, KBE 

Member of the chairman’s and the safety, ethics and environment assurance 

committees 

Antony Burgmans (62) 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. In 2005, he became non-executive chairman 

of Unilever PLC and Unilever NV, retiring from these appointments in May 

2007. He is also a member of the supervisory boards of Akzo Nobel NV and 

Aegon NV. 

C B Carroll 

Member of the chairman’s and safety, ethics and environment assurance 

committees 

Cynthia Carroll (52) joined BP’s board in June 2007. She started her career at 

Amoco and in 1989 she joined Alcan, where in 2002 she was appointed 

president and chief executive officer of Alcan’s primary metals group and an 

officer of Alcan, Inc. She was appointed as chief executive of Anglo American 

plc, the global mining group, in March 2007. She is also a director of De Beers 

s.a. and Anglo Platinum Ltd. 

Sir William Castell, LVO 

Member of the chairman’s committee and chairman of the safety, ethics and 

environment assurance committee 

Sir William (61) joined BP’s board in 2006. From 1990 to 2004, he was chief 

executive of Amersham plc and subsequently president and chief executive 

officer of GE Healthcare. He was appointed as a vice chairman of the board of 

GE in 2004, stepping down from this post in 2006 when he became chairman 

of the Wellcome Trust. He remains a non-executive director of GE. 

G David 

Member of the chairman’s and the audit committees 

George David (66) joined BP’s board on 11 February 2008. He has spent his 

career with United Technologies Corporation (UTC), as its chief executive 

officer from 1994 to 2008 and chairman since 1997. He joined UTC’s Otis 

elevator subsidiary in 1975. 

E B Davis, Jr 

Member of the chairman’s, the audit and the remuneration committees 

Erroll B Davis, Jr (64) 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 2005. He continued as 

chairman of Alliant Energy until February 2006, leaving to become chancellor 

of the University System of Georgia. He is a member of the board of General 

Motors Corporation and Union Pacific Corporation. 

D J Flint, CBE 

Member of the chairman’s and the audit committees 

Douglas Flint (53) joined BP’s board in 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 Standards Advisory Council of the International Accounting 

Standards Board. 

Dr D S Julius, CBE 

Member of the chairman’s and the nomination committees and chairman of 

the remuneration committee 

DeAnne Julius (59) 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 

Roche Holdings SA and Jones Lang LaSalle, Inc. 

Sir Tom McKillop 

Member of the chairman’s, the remuneration and the safety, ethics and 

environment assurance committees 

Sir Tom (65) joined BP’s board in 2004. Sir Tom was chief executive of 

AstraZeneca PLC from the merger of Astra AB and Zeneca Group PLC in 

1999 until December 2005. He was a non-executive director of Lloyds TSB 

Group PLC until 2004 and was appointed to the board of The Royal Bank of 

Scotland Group PLC in 2005, where he was chairman from 2006 to 3 

February 2009. 

Dr A B Hayward 

Tony Hayward (51) joined BP in 1982. He held a series of roles in exploration 

and production, becoming a director of exploration and production in 1997. In 

2000, he was made group treasurer, and an executive vice president in 2002. 

He was chief executive officer of exploration and production between 2002 

and February 2007. He became an executive director of BP in 2003 and was 

appointed as group chief executive in May 2007. Dr Hayward is a nonexecutive director and senior independent director of Tata Steel. 

I C Conn 

Iain Conn (46) joined BP in 1986. Following a variety of roles in oil trading, 

commercial refining, retail and commercial marketing operations, and 

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 2004. He 

was appointed chief executive of refining and marketing in June 2007. He is a 

non-executive director and senior independent director of Rolls-Royce Group 

plc. 

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64 

Directors and senior management

Dr B E Grote 

Byron Grote (60) 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 is a 

non-executive director of Unilever NV and Unilever PLC. 

A G Inglis 

Andy Inglis (49) joined BP in 1980, working on various North Sea projects. 

Following a series of commercial roles in 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. In 2004, he 

became executive vice president and deputy chief executive of exploration 

and production. He was appointed chief executive of BP’s exploration and 

production business and an executive director in February 2007. He is a nonexecutive director of BAE Systems plc. 

Senior management 

R Bondy 

Rupert Bondy (47) joined BP as group general counsel in May 2008. In 1989 

he joined US law firm Morrison & Foerster, working in San Francisco and 

London. From 1994 to 1995, he worked for UK law firm Lovells in London. In 

1995, he joined SmithKline Beecham as senior counsel for mergers and 

acquisitions and other corporate matters. He subsequently held positions of 

increasing responsibility and following the merger of SmithKline Beecham and 

GlaxoWellcome he was appointed senior vice president and general counsel 

of GlaxoSmithKline in 2001. 

S Bott 

Sally Bott (59) joined BP in 2005 as an executive vice president responsible 

for global human resources. Sally joined Citibank in 1970 and, following a 

variety of roles, was appointed a vice president in human resources in 1979 

and subsequently held a series of positions as a human resources director to 

sectors of Citibank. In 1994, she joined Barclays De Zoete Wedd, an 

investment bank, as head of human resources and in 1997 became group 

human resources director of Barclays plc. From 2000 to early 2005, she was 

managing director of Marsh and McLennan and head of global human 

resources at Marsh Inc. In 2008, Sally was elected as a non-executive director 

of UBS AG. 

V Cox 

Vivienne Cox (49) 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 of BP Oil, responsible for business-to-business 

marketing and oil supply and trading. From 2001 to 2004, she was group vice 

president for integrated supply and trading. In 2004, she was appointed an 

executive vice president, responsible for gas, power and renewables in 

addition to the supply and trading businesses. In late 2005, she became 

responsible for Alternative Energy. She is a non-executive director of Rio Tinto 

plc and Climate Change Capital Limited. 

H L McKay 

Lamar McKay (50) was appointed chairman and president of BP America, Inc. 

from 1 February 2009. He joined Amoco Production Company as a petroleum 

engineer in 1980 and later served in a variety of operating, commercial and 

M&A roles. In 1993, he became general manager of Arkoma Basin and in 

1997, the business unit leader for the Gulf of Mexico Shelf. During 1998-2000, 

he worked on the BP-Amoco merger and served as general manager for BP 

p.l.c. worldwide exploration and production strategy and planning. In 2000, he 

became business unit leader for the Central North Sea in Aberdeen, and 

subsequently chief of staff for worldwide exploration and production in London, 

following which he served as chief of staff for the BP deputy group chief 

executive. Lamar then worked as group vice president for Russia & 

Kazakhstan, during which time he was appointed to the board of TNK-BP. He 

was named executive vice-president of BP America and COO in the USA in 

May 2007. In early 2008, he became executive vice president of BP p.l.c. 

special projects, focusing on Russia, subsequently joining the group executive 

management team in June 2008. 

J Mogford 

John Mogford (55) joined BP in 1977, spending the early part of his career in a 

variety of drilling and production roles. In 1999, he became group vice 

president for health, safety and the environment before being appointed as 

group vice president for gas, power and renewables in 2002. In 2004, he 

returned to exploration and production as group vice president (technology 

and functions). In 2005, he was appointed as senior group vice president of 

safety and operations before becoming executive vice president, safety and 

operations in October 2007. He became chief operating officer of refining from 

1 March 2008. On 15 January 2009, he moved to chief operating officer for US 

fuels value chains and head of refining. 

S Westwell 

Steve Westwell (50) joined BP in the manufacturing and supply division of BP 

Southern Africa in 1988. Following various retail positions in the UK and the 

US he was appointed head of retail and a member of the board of BP 

Southern Africa Pty. In 2003, he became president and chief executive officer 

of BP solar, and in 2004, group vice president of natural gas liquids, power, 

solar and renewables. In 2005, he was appointed group vice president of 

alternative energy. He was appointed group chief of staff on 1 January 2008. 

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BP board performance report 

Letter from the chairman 

I am once again pleased to introduce our board performance report. The 

report reviews the work of the board and its committees as my tenure as 

chairman moves to a close. Over the past 12 years, both the calibre of 

individuals who have served on the board and our system of governance has 

stood us in good stead. The strong set of principles on which we base our 

governance framework, which include clarity of roles, separation of powers, 

independence and appropriate skills, remain valid today. 

 I have been encouraged from discussions with shareholders over time 

that our approach to governance and the dialogue which we continue to have 

with them is welcomed. This is important to us and no more so than during the 

testing times in which we operate. 

 Recent events and the current economic climate have inevitably 

triggered further debate about governance. This I welcome. The framework of 

governance does need to be kept under review and, where necessary, 

challenged by investors, regulators and companies themselves to ensure that 

the system is delivering. 

 Under such a review I believe that BP’s governance approach can show 

its strength. It requires active engagement on behalf of the company and 

investors alike. I do not believe that our comply or explain system is broken 

and it is important for us that the principles-based system continues. 

Peter Sutherland 

Chairman 

24 February 2009 

Board governance principles 

The board governance principles (‘principles’) are designed to enable the 

board and the executive management to operate within a clear framework. 

The principles describe the role of the board, its processes, its relationship 

with executive management and the main tasks and requirements of the board 

committees. The principles are available at 

www.bp.com/corporategovernance. 

 In carrying out its work, the board focuses on key tasks, which include 

the active review of the long-term strategy and the annual plan, monitoring the 

decisions and actions of the group chief executive, the performance of BP, the 

succession of executive management and the oversight of risk. 

 The principles outline how the board delegates its authority for 

executive management of the company to the group chief executive, subject 

to monitoring by the board and a clearly defined set of limitations. These 

‘executive limitations’ require that any executive action taken in the course of 

business takes specific issues into consideration, including health, safety and 

the environment, any reputational impact on BP, risk and the framework for 

internal control. 

Operating the principles 

The group chief executive through the annual plan describes to the board how 

the strategy is to be delivered, together with an assessment of the group’s 

risks. During the year, the board monitors progress and keeps the strategy 

under review. 

 The group chief executive is obliged to review and discuss with the 

board all strategic projects or developments and all material matters currently 

or prospectively affecting the company and its performance. 

 The principles are kept under review by the board to ensure they remain 

relevant and up to date. 

Board activities in 2008 

As outlined above, the board focuses on key areas in carrying out its work. 

Forward agendas are set to determine a high level work programme for the 

board based on its core tasks (including dealing with strategy and monitoring) 

but additional items are added throughout the 

year depending on the exigencies of the business as they arise. During the 

year the board was involved in the following activities: 

Strategy and Risk 

The board undertook extensive discussions on strategic options for the group, 

including the future business and competitive environment, technology 

developments, pricing and demand models and portfolio options. The 

identification and management of group risks were reviewed by the board, 

together with how these risks and their mitigation were embedded in the 

group’s annual plan. 

Review of capital expenditure and post investment review 

While the audit committee reviewed project delivery performance, the board 

undertook an annual review of the group’s project sanctioning process and 

delegation of authority. The process and criteria for each stage of a project 

was discussed, together with examples of projects with different lead times 

and complexities. 

Business review 

Business reviews were held with both segments (Exploration and Production 

and Refining and Marketing) and the finance and information technology and 

services (IT&S) functions. 

Global economic environment and energy markets 

The board actively monitored developments in the global energy markets and 

economic environment. Issues considered included the supply/demand 

balance, the relationship between oil prices, energy consumption and GDP 

growth and turbulence in the financial markets. 

Other areas 

Other areas discussed by the board included interactions with BP’s partners in 

TNK-BP, the results of a group-wide employee satisfaction survey and the 

findings of a report on BP’s reputation in the UK and US. The board also 

received a presentation from the independent expert appointed to provide an 

objective assessment of BP’s progress in implementing the recommendations 

of the BP US Refineries Independent Safety Review Panel (the Panel). 

 The board is supported in its tasks by the company secretary, who 

reports to the chairman and has no executive functions. His remuneration is 

determined by the remuneration committee. 

Board meetings and attendance 

The board met nine times during 2008, of which one meeting was a two-day 

strategy session and another meeting was a one-day strategy session. 

 

Board meetings Board meetings

eligible to attend attended

P D Sutherland 9 9

Sir Ian Prosser 9 9 

A Burgmans 9 9

C B Carroll 9 9

Sir William Castell 9 9 

G David 7 7

E B Davis, Jr 9 8 

D J Flint 9 7

Dr D S Julius 9 9

Sir Tom McKillop 9 9 

Dr W E Massey 4 4

Dr D C Allen 3 3 

I C Conn 9 9

Dr B E Grote 9 9

Dr A B Hayward 9 9 

A G Inglis 9 9

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The chairman and senior independent director

The principles require that neither the chairman nor deputy chairman be 

employed as an executive of the group. During 2008, these posts were held 

by Peter Sutherland and Sir Ian Prosser respectively. 

 The chairman provides leadership of the board, acts as facilitator for 

meetings and ensures that the governance framework of the board is 

maintained and operated. The chairman also leads board performance 

appraisals. He represents the views of the board to shareholders on key 

issues, in particular those relating to governance and succession planning and 

informs the board of shareholder views. 

 Between board meetings, the chairman has responsibility for ensuring 

the integrity and effectiveness of the relationship with executive management. 

This requires his interaction with the group chief executive, as well as his 

contact with other board members, senior management and stakeholders. 

 The deputy chairman acts for the chairman in his absence or at his 

request. The deputy chairman also serves as the board’s senior independent 

director and is available to shareholders where there are issues that cannot be 

addressed through normal channels. 

 The chairman and all the non-executive directors meet periodically 

without the presence of executive management as the chairman’s committee. 

The performance of the chairman is evaluated each year, with the evaluation 

discussion taking place when the chairman is not present. The principles 

require that the board develop and maintain a plan for the succession of both 

the chairman and deputy chairman. 

Board composition 

The principles require that over half the board, excluding the chairman, 

comprise independent non-executive directors and that the number of 

directors to not normally exceed 16. The board is composed of the chairman, 

nine non-executive and four executive directors. 

 The board considers that it is of an appropriate size to govern BP, with 

its directors possessing the relevant backgrounds and mix of experience, 

knowledge and skills to maximize its effectiveness. 

Board renewal and skills 

The board remains actively engaged in orderly succession planning for both 

executive and non-executive directors and is assisted in this task by the 

nomination committee. The committee keeps under review the composition, 

skills and diversity of the board to ensure that it remains appropriate to the 

tasks and work it undertakes. The nomination committee believes a breadth of 

skills is required for the board to meet the demands of a business with global 

operations. These skills include deep operational, engineering, safety and 

financial expertise, experience of leading industrial, capital intensive or ‘long 

lead time’ businesses and insight into key emerging markets and technology 

development. 

The board: terms of appointment 

The chairman and non-executive directors of BP 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 described in the directors’ 

remuneration report. 

 The service contracts of executive directors are expressed to expire at a 

normal retirement age of 60 (subject to age discrimination), while nonexecutive directors ordinarily retire at the AGM following their 70th birthday. 

 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 maintained a directors’ and 

officers’ liability insurance policy throughout 2008. During the year, a review of 

the terms and nature of the policy was undertaken and has been renewed for 

2009. 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. Following recent changes to company law, the 

company is also permitted to advance costs to directors for their defence in 

investigations or legal actions. 

Director elections 

New board directors are subject to election by shareholders at the first AGM 

following their appointment. All existing directors stand for re-election each 

year – a practice the company has followed since 2004. All directors proposed 

to shareholders for election are accompanied by a biography and a description 

of the skills and experience that the company feels are relevant. 

 Voting levels at the 2008 AGM demonstrated continued support for all 

board directors. 

Board independence 

Non-executive directors are required by the principles to be independent in 

character and free from any business or other relationship that could 

materially interfere with the exercise of their judgement. The board has 

determined that the non-executive directors who served during 2008 fulfilled 

this requirement and were independent. 

 BP believes that tenure of board members should be determined on the 

basis of contribution and continued evidence of the exercise of independent 

judgement. As all directors are proposed for annual re-election by 

shareholders, the board considers that arbitrary term limits on a director’s 

service are not appropriate. 

 Sir Ian Prosser joined the board in 1997. It is the view of the board that 

he remains firmly independent. His experience and long-term perspective on 

BP’s business have provided and continue to provide a valuable contribution 

to the board and the audit committee, which he chairs. As deputy chairman 

and senior independent director, Sir Ian is leading the board’s search for the 

successor to the current chairman. He has been asked by the board to remain 

in post until April 2010 in order that he may conclude both the chairman’s 

succession process and the identification and appointment by the new 

chairman of a senior independent director. 

 Mr Davis joined the board on the completion of the Amoco merger in 

December 1998. The board believes Mr Davis continues to demonstrate his 

independence. He is an active participant at the board and sits on the audit 

and remuneration committees, and the high level of his independence is 

demonstrated by his engagement in these forums. 

 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). 

 From 1 October 2008, there has been a requirement that directors must 

avoid a situation where they have, or can have, a direct or indirect interest that 

conflicts, or possibly may conflict, with the company’s interests. Directors of 

public companies may authorize conflicts and potential conflicts, where 

appropriate, if a company’s articles of association permit and shareholders 

have approved appropriate amendments. 

 Procedures have been put in place for the disclosure by directors of any 

such conflicts and also for the consideration and authorization of these 

conflicts by the board. These procedures allow for the imposition of limits or 

conditions by the board when authorizing any conflict, if they think this is 

appropriate. These procedures were duly followed to approve appropriate 

conflicts immediately prior to the enactment of the conflict provisions in 

October 2008, and are now included as a regular standing item for 

consideration by the board at its meetings. 

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Serving as a director 

Induction 

The induction of new board members is the responsibility of the chairman, 

who is assisted by the company secretary in this task. All new directors 

receive a full induction programme, including a ‘core’ element covering the 

principles and the legal and regulatory duties of directors. Non-executive 

directors receive further induction content devised according to their own 

interests and needs, together with the requirements of the committees on 

which they will serve. This would include meetings and briefings on the 

operations and activities of the group, the strategy and the annual plan and 

the company’s financial performance. The induction programme is targeted for 

completion within the first nine to 12 months of non-executive directors taking 

office, while the executive director programme is arranged in the course of 

their business activities. 

Training and site visits 

Directors and committee members receive briefings on BP’s business, its 

markets, operating environment and other key issues during their tenure as 

directors to ensure they have the necessary skill and knowledge to perform 

their duties effectively. Board members are also kept updated on legal and 

regulatory developments that may impact their duties and obligations as 

directors of a listed company. 

 In the past two years, the board and its committees have sought greater 

opportunity to meet at BP’s operating sites. This has enabled board members 

to see a selection of BP’s businesses e.g. the Texas City refinery, gas 

production in Colorado, exploration and production activities in Azerbaijan and 

the alternative energy solar facility in Maryland. These site visits have given 

directors the opportunity to meet both operational staff and government and 

community leaders in the parts of the world where BP operates. All nonexecutive directors are required to participate in at least one site visit per year. 

Outside appointments 

BP recognizes that executive directors may be invited to become nonexecutive directors of other companies and that such appointments can 

broaden their knowledge and experience, to the benefit of the individual and 

the group. Executive directors are permitted to take up one external board 

appointment, subject to the agreement of the chairman and reported to the BP 

board. Fees received for these external appointments may be retained by the 

executive director and are reported in the directors’ remuneration report. 

 Non-executive directors may serve on a number of outside boards, 

provided they continue to demonstrate the requisite commitment to discharge 

their duties to BP effectively. The nomination committee keeps under review 

the nature of directors’ other interests to ensure that the efficacy of the board 

is not compromised and may make recommendations to the board if it 

concludes that a director’s other commitments are inconsistent with those 

required by BP. 

Board evaluation 

The principles stipulate that the performance and effectiveness of the board, 

including the work of its committees, should be evaluated annually. In 2008, 

this evaluation was undertaken internally with the use of a questionnaire. The 

questionnaire focused on areas including the conduct of meetings, activities of 

the board versus committees, monitoring and information and board support 

and built on the review of board operations and governance that had taken 

place in 2007. The main outcome of the evaluation was a requirement for a 

more systematic approach to ensure that the skills of the directors met the 

changing demands of the business and the environment in which it operates. 

Engagement with shareholders 

The board is accountable to shareholders for the performance and activities of 

the BP group and engages in regular dialogue to understand their views and 

preferences. However, the board also recognizes that, in conducting its 

business, BP should be responsive to other relevant constituencies. 

 During the year, the chairman and deputy chairman met with 

institutional shareholders to discuss issues relating to the board, governance, 

strategy and performance. The remuneration committee chairman met with 

larger shareholders to discuss executive director remuneration. 

 The group chief executive, other executive directors and senior 

management, company secretary’s office, investor relations and other teams 

within BP also engage with a range of shareholders on wider issues relating to 

the group, including in particular its safety, operational and financial 

performance. Presentations given by the group to the investment community 

are available to download from the ‘Investors’ section of BP’s website, as are 

speeches on topics of broad interest to shareholders made by the group chief 

executive and other senior members of the management team. 

AGM 

BP’s AGM enables shareholders to ask questions and hear the resulting 

discussion about the company’s performance and the directors’ stewardship of 

the company. Votes on all matters (except procedural issues) are taken by a 

poll at the AGM, meaning that every vote cast -whether by proxy or in person 

at the meeting – is counted. 

 The chairman, board committee chairmen and other directors were 

present during the 2008 AGM and met shareholders on an informal basis after 

the main business of the meeting. In 2008, voting levels at the AGM increased 

to 64%, compared with 61% in 2007. Last year was also the first time that the 

AGM was webcast. This will be repeated for the company’s forthcoming 

meeting. The webcast, speeches and presentations given at the AGM are 

available to download from the BP website after the event, together with the 

outcome of voting on the resolutions. 

Board committees 

The principles allocate the tasks of monitoring executive actions and 

assessing performance to certain board committees. These tasks prescribe 

the authority and role of the board committees. 

 Reports for each of the main board committees follow. 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 

independent of the executive management of the group. The main tasks and 

requirements of each of the board’s committees are set out in the principles, 

available at www.bp.com/corporategovernance. 

Audit committee report 

Membership 

The audit committee comprises four independent non-executive directors who 

have been selected to provide a wide range of financial, international and 

commercial expertise appropriate to fulfil the committee’s duties. 

 During the year, Sir Ian Prosser (chairman), Douglas Flint and Erroll 

Davis, Jr were members of the audit committee. Sir William Castell retired 

from the committee in April 2008 and George David joined in May 2008. The 

secretary to the committee is David Pearl, deputy company secretary of BP. 

 The board considers that Douglas Flint possesses the financial and 

audit committee experience, as defined by the Combined Code guidance and 

the SEC, and has nominated him as the audit committee’s financial expert. 

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Attendance 

The audit committee met 13 times during 2008. 

In addition to the above members, the committee invites the lead partner of 

the external auditors (Ernst & Young), the group chief financial officer, the 

general auditor (head of internal audit), the chief accounting officer and the 

deputy chief financial officer to attend each meeting. Other senior 

management attend on request to enable the committee to discharge its 

duties. The committee also holds private sessions during the year without the 

presence of executive management. 

Role and authority of the audit committee 

The audit committee assists the board in carrying out its responsibilities in 

relation to financial risk, internal controls, financial and regulatory reporting 

requirements and the broader observance of the ‘executive limitations’ relating 

to financial matters. 

 The main tasks and requirements for the audit committee are set out in 

the principles. The audit committee believes that these meet each of the tasks 

and activities outlined by the Combined Code as falling within the remit of an 

audit committee. 

Information 

The committee receives information and reports from internal and external 

sources, including a wide cross-section of BP’s business and financial control 

management, with the attendance of additional Ernst & Young staff if 

appropriate to a particular business or functional review. 

 The audit committee is able to access independent advice and counsel 

when needed, on an unrestricted basis. Further support is provided to the 

committee by the company secretary’s office and during 2008 external 

specialist legal and regulatory advice was provided by Sullivan & Cromwell 

LLP. 

 The wider board is kept informed of the activities of the committee, and 

any issues that have arisen, through the regular update given by the audit 

committee chair after each meeting. 

Training and induction 

BP provides an induction programme for new committee members and 

ongoing training to assist them in carrying out their duties. Elements of the 

induction programme include familiarization with the tasks and requirements of 

the audit committee, an overview of the key financial and operational aspects 

of the businesses and an introduction to the group’s system of internal control. 

During the year, George David participated in the audit committee induction, 

including private sessions with the lead external audit partner and the general 

auditor. 

 In 2008, the training programme for the audit committee included 

briefings on developments in financial reporting and financial standards, a site 

visit to BP’s UK trading operations and an externally facilitated session on tax 

risk management. 

Committee activities in 2008 

The chart at the end of this section shows how the audit committee allocated 

its agenda time in 2008. 

Audit Audit 

committee committee

meetings eligible meetings

to attend attended

Sir Ian Prosser (chairman) 13 13

E B Davis, Jr 13 10

D J Flint 13 13

G David 6 6

Sir William Castell (former member) 7 7

Financial reporting 

During the year, the committee reviewed all financial reports, including the 

Annual Report and Accounts and Annual Report on Form 20-F, before 

recommending their publication to the board. 

Monitoring risk in the business 

In 2008, the audit committee reviewed reports on risks, controls and 

assurance for the BP business segments (Exploration and Production, 

Refining and Marketing), together with alternative energy, information 

technology and services, the proposed reorganization of the group finance 

function and BP’s trading function. The committee also reviewed BP’s longterm contractual commitments and the provisions made for environmental 

remediation and decommissioning. 

Internal controls 

A joint meeting with the safety, ethics and environment assurance committee 

was held to review the general auditor’s report on internal controls and risk 

management. A further joint meeting was held in early 2009 to assist the 

board in its assessment of the effectiveness of internal controls and risk 

management in 2008. 

 The committee discussed key regulatory issues during the year as part 

of its standing agenda items, including the quarterly internal audit findings 

report and a review of the company’s evaluation of its internal controls 

systems as part of the requirement of Section 404 of the Sarbanes-Oxley Act. 

The effectiveness of BP’s enterprise level controls was examined through the 

annual assessment undertaken by the internal audit function. 

External auditors 

The lead audit partner from Ernst & Young attends all meetings of the audit 

committee at the request of the committee chairman. Other external audit staff 

are invited to attend meetings where their expertise is relevant to the agenda 

item, for example during business or technical reviews. 

 The committee held two private meetings during the year with the 

external auditors without the presence of BP management, in order to discuss 

issues or concerns from either the committee or the auditors. 

 Performance of the external auditors is evaluated by the audit 

committee each year, with particular scrutiny of their independence, objectivity 

and viability. Independence is maintained through the limiting of non-audit 

services to tax and audit-related work that fall within defined categories. This 

work is pre-approved by the audit committee and all non-audit services are 

monitored quarterly. 

 Fees paid to the external auditors for the year (see Financial statements 

– Note 18 on page 132) were $67 million, of which 14% was for non-audit 

work. The fees and services provided by Ernst & Young for both audit and 

non-audit work have decreased in comparison to the previous year due to 

improved audit efficiency, ongoing systems improvements and BP’s new 

business structure. 

 During the year, a new lead partner from Ernst & Young replaced the 

existing partner who had completed five years’ service on the BP audit in early 

2008. Under BP policy and pursuant to external regulation, a new lead audit 

partner is appointed every five years and other senior audit staff are rotated 

every seven years. No partners or senior staff from Ernst & Young who are 

connected with the BP audit may transfer to the group. 

 The audit committee has considered both the proposed fee structure 

and the audit engagement terms for 2009 and has recommended to the board 

that the reappointment of the external auditors be proposed to shareholders at 

the 2009 AGM. 

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Internal audit

The general auditor attends each committee meeting at the invitation of the 

audit committee chairman. With the retirement of the general auditor in early 

2008, a new general auditor was appointed following an externally facilitated 

recruitment process. 

 During the year, the audit committee evaluated the performance of the 

internal audit function and agreed to the proposed programme of work for the 

year (being satisfied that it appropriately responded to the key risks facing the 

company and that the function had adequate staff and resources to complete 

its work). 

 In 2008, the committee met once with the general auditor in a private 

session without the presence of executive management. In addition, the 

general auditor met with the chairman of the committee from time to time 

between meetings. 

Fraud and employee concerns on financial matters 

The audit committee received an annual certification report from the group 

compliance and ethics function, together with quarterly reports that highlighted 

financial issues raised through OpenTalk, the group-wide employee concerns 

programme. 

 The committee further received quarterly updates from internal audit on 

instances of actual or potential fraud. 

Audit committee activities 

Approximate allocation of agenda time in 2008* 

Committee performance evaluation 

The committee conducts a yearly evaluation of its performance through oneto-one interviews or questionnaires. The results are collated and reported by 

the committee secretary. Actions taken in 2008 as a result of the end 2007 

evaluation included participation in an externally facilitated training session 

and improved tracking of outstanding issues. In addition, the committee 

considers performance during its private sessions throughout the year. 

 The 2008 evaluation was conducted through individual interviews and 

the outcomes discussed by the committee in January 2009. The forward 

agenda for the year ahead was set following this review, and consideration 

was given to building on the training provided to members through site visits. 

 The audit committee plans to meet 13 times during 2009. 

Safety, ethics and environment assurance committee report 

Membership 

The committee consists solely of independent non-executive directors who 

have been selected to provide a wide range of operational and international 

expertise appropriate to fulfil the committee’s duties. 

Members of the safety, ethics and environment assurance committee 

(SEEAC) during 2008 were Antony Burgmans, Sir William Castell and Sir Tom 

McKillop. Dr Massey retired as chairman of SEEAC in April 2008 and Sir 

William Castell became the committee chairman from that date. Cynthia 

Carroll joined the committee in June 2008. Support was provided by the 

committee secretary, David Pearl (deputy company secretary). 

Attendance 

SEEAC met eight times during 2008. 

In addition to the above members, each SEEAC meeting is attended by the 

lead partner of the external auditors (Ernst & Young) and the BP general 

auditor (head of internal audit) on the invitation of the committee chairman. 

The group chief executive also attends committee meetings as the executive 

liaison with SEEAC: Dr Hayward attended all eight meetings of the committee 

in 2008. The committee holds private sessions without executive management 

in attendance at the end of each meeting. 

Role and authority of the committee 

The main tasks and requirements for SEEAC are set out in the principles and 

include among others: 

Information 

The committee receives information and reports from the safety and 

operations function, internal and external sources, including internal audit and 

the group compliance and ethics function. Staff from Ernst & Young attend if 

appropriate to a particular business or activity review. 

 Like BP’s other board committees, SEEAC can access independent 

advice and counsel if it requires, on an unrestricted basis. The wider board is 

kept informed of the activities of the committee and any issues that have 

arisen through the regular update given by the SEEAC chair after each 

meeting. 

Training and induction 

Members of the committee receive ongoing training to assist them in carrying 

out their duties and an induction programme was provided for Mrs Carroll on 

joining the committee.

 To develop a deeper understanding of BP’s business and operations, 

Sir William Castell undertook a number of private briefings and several site 

visits on becoming SEEAC chairman. These visits included the Texas City 

refinery, where progress in implementing the recommendations of the Panel 

was observed and to the North Sea ETAP platforms where safety, operational 

and environmental management on an offshore production facility were 

reviewed. 

Committee activities in 2008 

The chart at the end of this section shows how SEEAC allocated its agenda 

time in 2008. 

SEEAC meetings SEEAC meetings

eligible to attend attended

Sir William Castell (chairman) 8 8

A Burgmans 8 8 

C B Carroll 3 2

Sir Tom McKillop 8 8

Dr W E Massey (former member) 4 4

• Monitoring and obtaining assurance on behalf of the board that the 

management or mitigation of significant BP risks of a non-financial nature is 

appropriately addressed by the group chief executive.

• Reviewing material to be placed before shareholders that addresses 

environmental, safety and ethical performance and make recommendations 

to the board about their adoption and publication.

• Reviewing reports on the group’s compliance with its code of conduct and on 

the employee concerns programme (OpenTalk) as it relates to non-financial 

issues.

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Safety and operations 

The group operations risk committee (GORC) was formed at the end of 2006 

and is an executive level committee, chaired by the group chief executive. The 

GORC made regular reports to SEEAC during the year, including progress on 

the group-wide implementation of the operating management system 

(OMS) and BP’s six-point plan, the development and utilization of the process 

safety index and statistics relating to the group’s safety and operational 

performance. 

 L Duane Wilson was appointed by the board in 2007 as an independent 

expert to provide an objective assessment of BP’s progress in implementing 

the Panel recommendations, aimed at improving process safety performance 

at BP’s five US refineries. Mr Wilson, who was a member of the Panel, reports 

to the chairman of SEEAC and is independently funded through the company 

secretary’s office. 

 Mr Wilson attended six meetings of the committee during 2008 and a 

private meeting with the committee during the year without the presence of 

executive management. Topics discussed included a presentation on his 

detailed work plan and progress updates. In May 2008, Mr Wilson published 

his first annual report where he assessed BP’s progress against the 10 Panel 

recommendations. The report noted that while significant progress had been 

made, areas for improvement still remained. Further information on the report 

is available on BP’s website. 

Regional reviews and site visits 

During the year, the committee reviewed reports on Alaska, the BTC pipeline, 

shipping and TNK-BP. The committee visited BP’s refinery operations in 

Rotterdam, and coal bed methane operations in Durango, Colorado. In 

addition, some members visited the BP solar manufacturing facilities in 

Maryland and the group’s operations in Azerbaijan. 

Other topics 

Other topics reviewed by the committee during the year included business 

continuity and crisis management, environmental requirements for new 

projects, results from a survey on safety culture in BP’s US refineries and a 

report from the US ombudsman on concerns raised by employees in Alaska. 

The committee also received and discussed quarterly reports from the general 

auditor and the group compliance and ethics officer. 

SEEAC 2008 Activities 

Approximate allocation of agenda time* 

 

Performance evaluation and forward agenda 

The committee undertakes an annual review of its performance and process. 

In 2008, the review involved interviews with each committee member, with the 

results discussed at the committee’s November meeting. Conclusions from the 

evaluation included noting the helpful insight gained from site visits and the 

value to the committee of the knowledge and expertise of the independent 

expert in respect of safety in the US refineries. The committee also reviewed 

its forward agenda for 2009. 

 SEEAC plans to meet seven times during 2009. 

Remuneration committee report 

Membership 

The committee consists solely of non-executive directors who are considered 

by the board to be independent. 

 Members of the remuneration committee during the year were Dr 

DeAnne Julius (chairman), Erroll Davis, Jr, Sir Tom McKillop and Sir Ian 

Prosser. The chairman of the board also attends meetings of the committee. 

Attendance 

The committee met six times during 2008. 

Role and authority of the committee 

The committee determines, on behalf of the board, the terms of engagement 

and remuneration of the group chief executive, the chairman and executive 

directors and reports on those to shareholders. The committee is 

independently advised. 

 Further details on the committee’s role, authority and activities during 

the year are set out in the directors’ remuneration report, which is the subject 

of a vote by shareholders at the 2009 AGM. 

 The remuneration committee plans to meet five times in 2009. 

Chairman’s committee report 

Membership 

The committee consists of the chairman and all non-executive directors. 

Attendance 

The committee met four times during 2008. 

Remuneration committee Remuneration committee

 meetings eligible to attend meetings attended 

Dr D S Julius (Chair) 6 6 

E B Davis, Jr 6 5

Sir Tom McKillop 6 6 

Sir Ian Prosser 6 6

P D Sutherland 6 6

Chairman’s committee meetings Chairman’s committee

eligible to attend meetings attended

P D Sutherland 4 4

Sir Ian Prosser 4 4

A Burgmans 4 4

C B Carroll 4 3 

Sir William Castell 4 4

G David 2 2

E B Davis, Jr 4 4

D J Flint 4 4

Dr D S Julius 4 4 

Sir Tom McKillop 4 4

Dr W E Massey (former member) 2 2

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BP board performance report

Role and authority of the committee 

The main tasks and requirements for the committee are set out in the 

principles and are: 

Committee activities 

The chairman’s committee considered aspects of a number of strategic issues 

including the relationship with the company’s partners in TNK-BP. The 

committee has reviewed with Dr Hayward the short- and long-term challenges 

facing the group. Dr Hayward has kept the committee briefed on the 

implementation of the forward agenda and its implications for the evolution of 

the executive team and succession within the leadership cadre. The 

committee has also reviewed the steps taken by Dr Hayward to refine the 

corporate culture and the values within BP. There have been active 

discussions around the ‘tone from the top’. 

 The committee has reviewed the performance of the chairman and Dr 

Hayward. 

 The chairman’s committee plans to meet four times in 2009. 

Nomination committee report 

Membership 

The committee’s members nominally consist of the chairman and the chairs of 

SEEAC, audit and remuneration committees. 

 Members of the nomination committee during the year were Peter 

Sutherland (chairman), Dr DeAnne Julius, Sir Ian Prosser and Dr Walter 

Massey. Dr Massey remained a member of the nomination committee during 

the year after his retirement from the board to assist in the search for a 

successor to BP’s chairman. Sir William Castell has now joined the committee. 

Attendance 

The committee met six times during 2008. 

Role and authority of the committee 

The main tasks and requirements for the committee are set out in the 

principles and are: 

• Evaluating the performance and effectiveness of the group chief executive;

• Reviewing the structure and effectiveness of the business organization of 

BP;

• Reviewing the systems for senior executive development and determining 

the succession plan for the group chief executive, executive directors and 

other senior members of executive management;

• Determining any other matter that is appropriate to be considered by all of 

the non-executive directors;

• Opining on any matter referred to it by the chairman of any committee 

comprised solely of non-executive directors.

Nomination committee meetings Nomination committee

eligible to attend meetings attended 

P D Sutherland (chairman) 6 6

Dr D S Julius 6 6

Dr W E Massey 6 6 

Sir Ian Prosser 6 6

• Identifying, evaluating and recommending candidates for appointment or 

reappointment as directors.

• Identifying, evaluating and recommending candidates for appointment as 

company secretary.

• Keeping under review the mix of knowledge, skills and experience of the 

board to ensure the orderly succession of directors.

• Reviewing the outside directorship/commitments of the non-executive 

directors.

Committee activities 

During 2008 the primary work of the committee has been the continuation of 

the process to select a successor to Mr Sutherland who is to stand down as 

chairman. 

For this purpose, Sir Ian Prosser, as Senior Independent Director, has chaired 

the committee. The committee has been assisted in this task by Dr Anna 

Mann of MWM Consulting LLP. The committee has adopted a robust process. 

Key strategic issues facing BP for the coming years were identified through 

discussions with individual board members. From these discussions a role 

description was developed. This formed the basis of a worldwide search from 

which in excess of 30 candidates emerged. This broad group has been refined 

and the process is continuing. The board has been regularly briefed on the 

work of the committee.

 As part of the chairman selection process, potential candidates for nonexecutive directors roles have been revealed. The committee will continue 

actively to keep the skills of the board under review and pursue its 

refreshment. 

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Directors’ interests 

The above figures indicate and include all the beneficial and non-beneficial interests of each director of the company in shares of the company (or calculated 

equivalents) that have been disclosed to the company under the Disclosure and Transparency Rules and Companies Acts 1985 or 2006 (as the case may be) as at 

the applicable dates. The above figures do not include share options granted or interests in performance shares that have yet to vest. Details of these are set out in 

full in the directors’ remuneration report on pages 79 and 80. 

 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. 

72 

BP board performance report

Change from

 31 Dec 2008 

Current directors At 31 Dec 2008 At 1 Jan 2008 to 18 Feb 2009

A Burgmans 10,000 10,000 –

C B Carroll – – –

Sir William Castell 82,500 50,000 –

I C Conn 240,789a 229,969a 39,148

G David 9,000b –c – 

E B Davis, Jr 73,185b 70,602b –

D J Flint 15,000 15,000 –

Dr B E Grote 1,214,330d 1,193,137d 47,334

Dr A B Hayward 488,459 482,398 39,148

A G Inglis 226,175e 224,006e 29,249 

Dr D S Julius 15,000 15,000 –

Sir Tom McKillop 20,000 20,000 –

Sir Ian Prosser 16,301 16,301 –

P D Sutherland 30,906 30,906 –

Directors leaving the board in 2008 At resignation/retirement At 1 Jan 2008

Dr D C Allen (retired 31 March 2008) 597,568f 597,568f

Dr W E Massey (retired 17 April 2008) 49,722b 49,722b 

aIncludes 44,158 shares held as ADSs at 31 December 2008 and 41,692 shares held as ADSs at 1 January 2008.

bHeld as ADSs.

cOn appointment at 11 February 2008.

dHeld as ADSs, except for 94 shares held as ordinary shares.

eIncludes 34,962 shares held as ADSs.

f

Includes 25,368 shares held as ADSs.

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Directors’ remuneration 

report

74 Part 1 Summary

76 Part 2 Executive directors' 

remuneration

82 Part 3 Non-executive directors' 

remuneration

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Directors’ remuneration report

 

74 

Part 1 Summary 

BP executives delivered a strong performance in a turbulent environment 

during 2008 and restored the group’s operations to a high standard after 

several years of focused effort. We commend them for a job well done. 

 Key financial targets for the year were exceeded, even after adjusting 

for the effect of high oil prices during part of the year. Safe and reliable 

operations remained at the top of the agenda and key safety metrics and 

milestones were achieved. The year’s results were especially strong in 

Exploration and Production, with the start-up of the Thunder Horse platform 

and excellent overall reserves replacement. Key targets were also met in 

Refining and Marketing and both the Texas City and Whiting refineries were 

safely restored to full capacity by the end of the year. The annual bonus 

results, set out in the table opposite, reflect this strong performance and 

determined leadership. 

 The committee undertook a detailed review of BP’s underlying 

performance against competitors in determining the 2006-2008 share element 

vesting under the executive directors’ incentive plan (EDIP). This review 

included financial measures such as earnings per share, returns on average 

capital employed, free cash flow, operating measures for both Exploration and 

Production and Refining and Marketing, and non-financial measures for safety 

and reputation. All measures were compared across competitors and showed 

BP firmly in the pack of the other European oil majors. The comparison of total 

shareholder return (TSR) was less favourable to BP, partly due to exchange 

rate movements and turbulence in the financial markets. After careful review, 

the committee concluded that TSR alone was not a fair reflection of underlying 

performance over the 2006-2008 period. We concluded that it was appropriate 

to approve the vesting of 15% of the shares in the plan for the current 

directors. This too is set out in the table opposite. 

 Salaries were increased mid-2008 after our normal review. For 2009, 

we have agreed with the group chief executive’s view that salaries should be 

frozen at their current level. There also will be no change in the target and 

normal maximum levels of bonus for 2009. The group chief executive’s and 

group chief financial officer’s bonuses will be based 70% on group 

performance against key metrics in the annual plan, 15% on safety 

performance and 15% on people. The chief executives of Exploration and 

Production and Refining and Marketing will have 50% of their bonuses 

determined on the above basis and 50% on the performance of their 

respective businesses. 

 The EDIP share element will again provide the long-term component of 

remuneration for the 2009-2011 period, with some slight modifications. First, 

reflecting its recent growth, ConocoPhillips will be added to the peer group of 

comparators (currently ExxonMobil, Shell, Total and Chevron). Second, to 

provide a more balanced assessment, vesting will be based half on BP’s total 

shareholder return relative to the peer group and half on underlying 

performance compared with this same peer group. BP’s performance will be 

compared on an interpolated basis relative to the performance of the other 

five. As in previous years, shares will vest at 100%, 70% and 35% for 

performance equivalent to first, second and third rank respectively and none 

for fourth or fifth. 

 We remain committed to a remuneration policy and practice that aligns 

with the long-term interests of shareholders and provides an appropriate 

reward for talented and committed executives. In the current volatile climate, 

executive leadership is more important than ever. The committee will continue 

to use careful and rigorous judgement in assessing performance, and to 

communicate our assessment in a clear way to shareholders. 

 

Dr DeAnne S Julius 

Chairman, Remuneration Committee 

24 February 2009 

 

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Summary of remuneration of executive directors in 2008a

Amounts shown are in the currency received by executive directors. Annual bonuses are shown in the year they were earned. 

75

Directors’ remuneration report

Annual remuneration Long-term remuneration

Share element of EDIPb

2005-2007 plan 2006-2008 plan 2008-2010

 (vested in Feb 2008) (vested in Feb 2009) plan 

 Annual Non-cash benefits and Potential 

Salary performance bonus other emoluments Total Actual Actualc maximum

(thousand) (thousand) (thousand) (thousand) shares Value shares Valued performance

 2007 2008 2007 2008 2007 2008 2007 2008 vested (thousand) vested (thousand) sharese

Dr A B Hayward £877 £998 £1,262 £1,496 £14 £15 £2,153 £2,509 0 0 66,136 £336 845,319 

I C Conn £581 £670 £698 £871 £45 £45 £1,324 £1,586 0 0 66,136 £336 578,376

Dr B E Grote $1,175 $1,340 $1,551 $1,742 $10 $8 $2,736 $3,090 0 0 80,231f $603 581,748

A G Inglis £556 £670 £800 £1,173 £188 £ 212g £1,544 £2,055 0 0 54,994 £279 578,376

Directors leaving the board in 2008

Dr D C Allenh £500 £128 £539 £163 £13 £3 £1,052 £294 0 0 34,518 £175 n/a

aThis information has been subject to audit.

bOr equivalent plans in which the individual participated prior to joining the board. 

c

Includes shares representing reinvested dividends received on the shares that vested at the end of the performance period.

dBased on market price on vesting date (£5.08 per share/$45.13 per ADS). 

eMaximum potential shares that could vest at the end of the three-year period depending on performance.

fDr Grote holds shares in the form of ADSs. The above number reflects calculated equivalent in ordinary shares.

gThis amount includes costs of London accommodation provided to Mr Inglis. In addition, under a tax equalization arrangement, BP also discharged a US tax liability arising on his participation in the UK pension scheme 

amounting to $553,175. 

hDr Allen resigned from the board on 31 March 2008. In addition to the above, he was awarded compensation for loss of office equal to one year’s salary (£510,000). He also received £30,000 in respect of statutory 

rights and retained his company car. 

Pensions 

All executive directors are part of a final salary pension scheme. Accrued 

annual pension earned as at 31 December 2008 is £561,000 for Dr Hayward, 

£264,000 for Mr Conn, $868,000 for Dr Grote and £326,000 for Mr Inglis. 

 

This graph shows the growth in value of a hypothetical £100 holding in BP 

p.l.c. ordinary shares over five years, relative to the FTSE 100 Index (of which 

the company is a constituent). The values of the hypothetical £100 holdings at 

the end of the five-year period were £144.36 and £115.05 respectively. 

Remuneration of non-executive directors in 2008a

In 2008 the board, after a review, determined that in future it would continue to 

set the remuneration of the non-executive directors. However, in the case of 

the chairman this would be based on a recommendation from the 

remuneration committee and, for the non-executive directors, it would be 

based on a recommendation from the chairman. 

 This process was adopted in 2008 and recommendations were made. 

However, the chairman and the non-executive directors informed the board 

that, in the current economic circumstances, they did not wish to receive any 

increase in remuneration for 2009. The board accordingly maintained the fees 

at the 2008 level for 2009 save that no committee membership fee would in 

future be paid to members of the nomination committee. 

£ thousand

2007 2008

A Burgmans 86 90

Sir William Castell 87 108

C B Carroll 43 93

G Davidb n/a 100

E B Davis, Jr 107 105

D J Flint 86 90

Dr D S Julius 106 110

Sir Tom McKillop 87 95

Sir Ian Prosser 137 170

P D Sutherland 517 600

Directors leaving the board in 2008

Dr W E Masseyc 133 90

aThis information has been subject to audit.

bAppointed on 11 February 2008.

cAlso received a superannuation gratuity of £23,000.

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Directors’ remuneration report

Part 2 Executive directors’ remuneration 

2008 remuneration

Salary increases 

As part of our normal cycle, salaries were reviewed mid-year and were 

increased to reflect market competitiveness and personal performance. Dr 

Hayward’s salary was increased 10% to £1,045,000, and the other executive 

directors by 6% to the following: Mr Conn £690,000, Dr Grote $1,380,000 and 

Mr Inglis £690,000. 

Annual bonus result 

Performance measures and targets were set at the beginning of the year 

based on the annual plan. The target level bonus of 120% of base salary 

placed 50% on group financial and operating results including earnings before 

interest, taxes, depreciation and amortization (EBITDA), cash costs, cash flow, 

return on average capital employed (ROACE) and capital expenditure. The 

remaining portion was weighted 25% on safety, 25% on people and 20% on 

individual performance, principally operating results and leadership. 

 Overall performance for 2008 was very strong and is more fully set out 

in other parts of this report. Financial results exceeded targets for EBITDA, 

free cash flow and returns on average capital employed, even after adjusting 

for the high oil prices for part of the year. Cash costs were managed below 

target, and capital expenditure within expected levels. 

 Operationally, the upstream business had an excellent year, replacing a 

high proportion of proved reserves, exceeding its production target and 

successfully starting up the important Thunder Horse development in the Gulf 

of Mexico. The downstream business successfully and safely completed the 

full re-commissioning of the Texas City and Whiting refineries and improved 

overall performance. Alternative Energy exceeded its targets for wind and met 

its solar sales target. 

 Safe and reliable operations remained at the top of the agenda and 

performance, both in terms of safety metrics and progress on OMS 

implementation, was assessed as satisfactory by the safety, ethics and 

environment assurance committee (SEEAC). On the people front, significant 

progress was made in reducing complexity and embedding a performance 

culture throughout the group. 

 Annual bonus results for 2008 reflect this overall strong performance 

and committed leadership and are set out in the table on page 75. 

2006-2008 share element result 

Performance for the share element is assessed relative to the TSR of the 

company compared with the other oil majors – ExxonMobil, Shell, Total and 

Chevron. Recognizing the inherent imperfections in a TSR ranking, the EDIP 

rules give the committee power to adjust (upwards or downwards) the vesting 

level derived from the TSR ranking if it considers that the ranking does not 

fairly reflect BP’s underlying business performance relative to the 

comparators. This is designed to enable a more comprehensive review of 

BP’s long-term performance, with the aims of tempering anomalies created by 

relying solely on a formula-based approach. 

 For the 2006-2008 plan, BP was fifth relative to the other majors in 

terms of TSR when calculated on a common currency (US dollar) basis as 

originally anticipated. However, unusually large currency movements at the 

end of this period were an extraneous influence on this result. On a local 

currency basis, the TSRs of BP, Shell and Total were tightly bunched 

together. The committee also reviewed BP’s underlying business performance 

relative to the comparator companies over the full three-year period. This 

review included financial measures (earning per share growth, ROACE, free 

cash flow, net income), operating measures (production, reserves 

replacement and Refining and Marketing profitability), and non-financial 

measures (health, safety and environmental and reputation). Again, the 

performance of the European comparators was quite similar: BP led the group 

on some measures (notably free cash flow and reserves replacement) but 

lagged on Refining and Marketing profitability. 

The committee concluded that the TSR result, by itself, was not a fair 

reflection of BP’s relative underlying performance over the period. After 

thorough consideration, the committee determined that 15% of the shares 

under the 2006-08 award should vest – this being a fair reflection of the overall 

results achieved and consistent with its approach to the clustering of results, 

as anticipated in the EDIP rules approved by shareholders in 2005. 

 In accordance with its powers under the EDIP rules, the committee also 

determined that, as there was clear evidence of a progressive turnaround of 

performance over the final 18 months of the performance period, individual 

vesting levels should only occur to the extent that eligible individuals 

contributed to the turnaround. The resulting final vesting for all eligible 

participants is shown in the table on page 79. 

 Mr Inglis’s award was made prior to his appointment as an executive 

director under the MTPP (medium term performance plan) that is the 

comparable plan to the EDIP. Vesting conditions were the same as for the 

EDIP for Mr Inglis but, unlike the EDIP, the MTPP does not have a three-year 

retention period. 

 Lord Browne also held an award under the 2006-08 share element 

related to long-term leadership measures. These focused on sustaining BP’s 

financial, strategic and organizational health. Performance relative to the 

award was assessed by the chairman’s committee and, based on this 

assessment, no shares were vested. 

Remuneration policy 

Our remuneration policy for executive directors aims to ensure there is a clear 

link between the company’s purpose, its business plans and executive reward,

with pay varying with performance. In order to achieve this, the policy is based 

on these key principles: 

Executive directors’ total remuneration consists of salary, annual bonus, longterm incentives, pensions and other benefits. The remuneration committee 

reviews this structure regularly to ensure it is achieving its aims. In 2008, over 

three-quarters of executive directors’ total potential remuneration was 

performance related. The same will be true for total potential remuneration in 

2009. 

• The majority of executive remuneration will be linked to the achievement of 

demanding performance targets, independently set to support the creation of 

long-term shareholder value.

• The structure will reflect a fair system of reward for all the participants.

• The remuneration committee will determine the overall amount of each 

component of remuneration, taking into account the success of BP and the 

competitive environment.

• There will be a quantitative and qualitative assessment of performance, with 

the remuneration committee making an informed judgement within a 

framework approved by shareholders.

• Remuneration policy and practice will be as transparent as possible.

• Executives will develop a significant personal shareholding in order to align 

their interests with those of shareholders.

• Pay and employment conditions elsewhere in the group will be taken into 

account, especially in setting annual salary increases.

• The remuneration policy for executive directors will be reviewed regularly, 

independently of executive management, and will set the tone for the 

remuneration of other senior executives.

• The remuneration committee will actively seek to understand shareholder 

preferences.

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Salary 

The remuneration committee normally reviews salaries annually, taking into 

account other large Europe-based global companies and companies in the US 

oil and gas sector. These groups are each defined and analyzed by the 

committee’s independent remuneration advisers. For 2009, the committee has 

agreed with the group chief executive’s view that salaries should be frozen at 

their current level. 

Annual bonus 

All executive directors are eligible to take part in an annual performancebased bonus scheme. The remuneration committee sets bonus targets and 

levels of eligibility each year. 

 The target level for 2009 is 120% of base salary. In normal 

circumstances, the maximum payment for substantially exceeding 

performance targets will continue to be 150% of base salary. 

 The group chief executive’s and group chief financial officer’s bonus will 

be determined on group results as follows: 

For the chief executive of Exploration and Production, and the chief executive 

of Refining and Marketing, 50% of their bonus will be based on the above 

group results and 50% on the results of their respective businesses as 

measured by key metrics and milestones set out in the annual plan. For 

Exploration and Production, these include production costs and reserves 

replacement as well as safety and new opportunities. For Refining and 

Marketing, they include refining availability, earnings and cash costs, as well 

as safety and work simplification. 

 The remuneration committee will also review carefully the underlying 

performance of the group in light of company business plans and will look at 

competitors’ results, analysts’ reports and the views of the chairmen of other 

BP board committees when assessing results. 

 In exceptional circumstances, the remuneration committee can decide 

to award bonuses moderately above the maximum level. The committee can 

also decide to reduce bonuses where this is warranted and, in exceptional 

circumstances, bonuses could be reduced to zero. We have a duty to 

shareholders to use our discretion in a reasonable and informed manner, 

acting to promote the success of the company, and also to be accountable 

and transparent in our decisions. Any significant exercise of discretion will be 

explained in the subsequent directors’ remuneration report. 

Long-term incentives 

Each executive director participates in the EDIP. It has three elements: 

shares, share options and cash. The remuneration committee does not intend 

to use either the share option or cash elements in 2009, nor to grant any 

retention awards which are also permitted under the EDIP. We intend that 

executive directors will continue to receive performance shares under the 

EDIP, barring unforeseen circumstances, until it expires or is renewed in 2010.

• 70% on group performance compared with key metrics and milestones from 

the annual plan including:

• Cash costs and organic capex.

• Underlying replacement cost profit and operating cash flow.

• Production and reserves replacement.

• Refining availability and earnings/barrel.

• Installed wind capacity.

• 15% on safety performance, including satisfactory and improving key metrics 

as well as progress on OMS implementation.

• 15% on people, including behaviour, culture and values.

Policy for performance share awards 

The remuneration committee can award shares to executive directors that will 

only vest to the extent that demanding performance conditions are satisfied at 

the end of a three-year period. The maximum number of these performance 

shares that can be awarded to an executive director in any year is at the 

discretion of the remuneration committee, but will not normally exceed 5.5 

times base salary. 

 In exceptional circumstances, the committee also has an overriding 

discretion to reduce the number of shares that vest or to decide that no shares 

vest. 

 The compulsory retention period will also be decided by the committee 

and will not normally be less than three years. Together with the performance 

period, this gives executive directors a six-year incentive structure, as shown 

in the timeline below, which is designed to ensure their interests are aligned 

with those of shareholders. 

 

Where shares vest, the executive director will receive additional shares 

representing the value of the reinvested dividends.

 The committee’s policy continues to be that each executive director 

build a significant personal shareholding, with a target of shares equivalent in 

value to five times his or her base salary within a reasonable timeframe from 

appointment as an executive director. This policy is reflected in the terms of 

the performance shares under the EDIP, as shares vested will normally only 

be released at the end of the three-year retention period, described above, if 

these minimum shareholding guidelines are met. 

Performance conditions 

Performance conditions for the 2009-11 share element will be somewhat 

modified from previous years. First, the peer group of oil majors against which 

we compare will be increased to include ConocoPhillips as well as 

ExxonMobil, Shell, Total and Chevron as previously. This change reflects 

ConocoPhillips’ significant growth over the last few years, providing it with 

similar scale and global reach to the other oil majors. 

 Second, vesting of the shares will be based 50% on total shareholder 

return (TSR) versus the competitor group and 50% on a balanced scorecard 

of underlying performance versus the same competitors. The underlying 

performance will be assessed on three measures reflecting key priorities in 

BP’s strategy – in Exploration and Production, hydrocarbon production growth, 

in Refining and Marketing, improvement in earnings per barrel, and group 

increase in underlying net income. Both Exploration and Production production 

growth and Refining and Marketing earnings improvement are key strategic 

objectives for the group and this inclusion aligns key measures with both 

executive director priorities as well as key drivers of value for shareholders. 

Group increase in underlying net income acts as a holistic measure of success 

reflecting revenues, costs and complexity as well as safe and reliable 

operations. 

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Pensionsa 

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Directors’ remuneration report

thousand

Additional pension

Accrued pension earned during the Transfer value of Transfer value of Amount of B-A less

Service at entitlement year ended accrued benefitc accrued benefitc contributions made by

 31 Dec 2008 at 31 Dec 2008 31 Dec 2008b at 31 Dec 2007 (A) at 31 Dec 2008 (B) the director in 2008 

Dr A B Hayward (UK) 27 years £561 £72 £7,986 £8,045 £9 

I C Conn (UK) 23 years £264 £26 £3,375 £3,161 (£214)

Dr B E Grote (US) 29 years $868 $45 $7,901 $11,220 $2,860

A G Inglis (UK) 28 years £326 £30 £4,613 £4,399 (£214)

Directors leaving the board in 2008

Dr D C Allen (UK)d n/a £260 £12 £4,256 £5,580 £1,324

aThis information has been subject to audit.

bAdditional pension earned during the year includes an inflation increase of 4.0% for UK directors and 5.8% for US directors.

cTransfer values have been calculated in accordance with version 8.1 of guidance note GN11 issued by the actuarial profession. 

dDr D C Allen retired on 31 March 2008 and commuted part of his pension for a lump sum. The figures above make no allowance for the payment of this lump sum. If allowance is made (in line with the strict 

requirements of the regulations), and the transfer value at the end of the year is based on the pension in payment at that time, then the transfer value at 31 December 2008 would be £4.55 million and the change in

value over the year would be £0.29 million.

All the above measures will be compared with the five other oil majors to 

determine the overall vesting result. The methodology used will rank each of 

the five other majors on each of the measures. BP’s performance will then be 

compared on an interpolated basis relative to the performance of the other 

five. For performance between second and third or first and second, the result 

will be interpolated based on BP’s performance relative to the company 

ranked directly above and below it. As in previous years, performance shares 

will vest at 100%, 70% and 35% for performance equivalent to first, second 

and third rank respectively and none for fourth or fifth place. The three 

underlying measures will be averaged to form the balanced scorecard 

component. 

 The committee considers that this combination of measures provides a 

good balance of external as well as internal metrics reflecting both 

shareholder value and operating priorities. As in previous years, the 

committee will exercise its discretion, in a reasonable and informed manner to 

adjust vesting levels upwards or downwards if it concludes the above 

quantitative approach does not reflect the true underlying health and 

performance of BP’s business relative to its peers. It will explain any 

adjustments in the next directors’ remuneration report following the vesting, in 

line with its commitment to transparency. 

Pensions 

Executive directors are eligible to participate in the appropriate pension 

schemes applying in their home countries. Additional details are given in the 

table below. 

UK directors 

UK directors are members of the regular BP Pension Scheme. The core 

benefits under this scheme are non-contributory. They include a pension 

accrual of 1/60th of basic salary for each year of service, up to a maximum of 

two-thirds of final basic salary and a dependant’s benefit of two-thirds of the 

member’s pension. The scheme pension is not integrated with state pension 

benefits. 

 The rules of the BP Pension Scheme were amended in 2006 such that 

the normal retirement age is 65. Prior to 1 December 2006, scheme members 

could retire on or after age 60 without reduction. Special early retirement 

terms apply to pre-1 December 2006 service for members with long service as 

at 1 December 2006. 

Pension benefits in excess of the individual lifetime allowance set by 

legislation are paid via an unapproved, unfunded pension arrangement 

provided directly by the company. 

 Although Mr Inglis is, like other UK directors, a member of the BP 

Pension Scheme, he is currently based in Houston, US. His participation in the 

BP Pension Scheme gives rise to a US tax liability. During 2008, the 

committee approved the discharge of this US tax liability under a tax 

equalization arrangement in respect of the period since Mr Inglis became a 

director in February 2007, amounting to $553,175. 

US directors 

Dr Grote participates in the US BP Retirement Accumulation Plan (US plan), 

which features a cash balance formula. Pension benefits are provided through 

a combination of tax-qualified and non-qualified benefit restoration plans, 

consistent with US tax regulations as applicable. 

 The Supplemental Executive Retirement Benefit (supplemental plan) is 

a non-qualified top-up arrangement that became effective on 1 January 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 (and as specified under the qualified 

arrangement), multiplied by years of service. There is 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 eligible to participate under the supplemental plan. His 

pension accrual for 2008, shown in the table below, includes the total amount 

that could become payable under all plans. 

Other benefits 

Executive directors are eligible to participate in regular employee benefit plans 

and in all-employee share saving schemes and savings plans applying in their 

home countries. Benefits in kind are not pensionable. Expatriates may receive 

a resettlement allowance for a limited period. 

 As Mr Inglis is currently based in Houston, US, BP provides 

accommodation in London. 

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Share element of EDIPa

79

Directors’ remuneration report

Share element interests Interests vested in 2008 and 2009

Market price Potential maximum performance sharesb

of each share

 Date of at date of award Number of Market price 

award of of performance ordinary of each share

Performance performance shares At 1 Jan Awarded At 31 Dec shares Vesting at vesting

 period shares £ 2008 2008 2008 vestedc date £ 

Dr A B Hayward 2005-2007 28 Apr 2005 5.33 436,623 – – 0 n/a n/a 

2006-2008 16 Feb 2006 6.54 383,200 – 383,200 66,136 6 Feb 2009 5.08

2007-2009 06 Mar 2007 5.12 706,311 – 706,311 – – –

 2008-2010 13 Feb 2008 5.61 – 845,319 845,319 – – – 

I C Conn 2005-2007 28 Apr 2005 5.33 415,832 – – 0 n/a n/a

2006-2008 16 Feb 2006 6.54 383,200 – 383,200 66,136 6 Feb 2009 5.08

 2007-2009 06 Mar 2007 5.12 456,748 – 456,748 – – – 

2008-2010 13 Feb 2008 5.61 – 578,376 578,376 – – –

2008-2011d 13 Feb 2008 5.61 – 133,452 133,452 – – –

2008-2013d 13 Feb 2008 5.61 – 133,452 133,452 – – –

Dr B E Grotee 2005-2007 28 Apr 2005 5.33 501,782 – – 0 n/a n/a

2006-2008 16 Feb 2006 6.54 470,432 – 470,432 80,231 6 Feb 2009 5.08

2007-2009 06 Mar 2007 5.12 491,640 – 491,640 – – –

2008-2010 13 Feb 2008 5.61 – 581,748 581,748 – – –

A G Inglis 2005-2007 8 Mar 2005 5.70 209,000 – – 0 n/a n/a

 2006-2008 27 Mar 2006 6.59 325,750 – 325,750 54,994 6 Feb 2009 5.08

2007-2009 06 Mar 2007 5.12 400,243 – 400,243 – – –

 2008-2010 13 Feb 2008 5.61 – 578,376 578,376 – – – 

2008-2011d 13 Feb 2008 5.61 – 133,452 133,452 – – –

2008-2013d 13 Feb 2008 5.61 – 133,452 133,452 – – –

Directors leaving the board in 

2008 

Dr D C Allen 2005-2007 28 Apr 2005 5.33 436,623 – – 0 n/a n/a

2006-2008 16 Feb 2006 6.54 383,200 – 383,200 34,518 6 Feb 2009 5.08

2007-2009 06 Mar 2007 5.12 456,748 – 456,748 – – –

Former directors

Lord Browne 2005-2007 28 Apr 2005 5.33 2,006,767 – – 90,232 6 Feb 2008 5.45

2006-2008 16 Feb 2006 6.54 1,761,249 – 1,761,249 0 n/a n/a

J A Manzoni 2005-2007 28 Apr 2005 5.33 436,623 – – 0 n/a n/a 

2006-2008 16 Feb 2006 6.54 383,200 – 383,200 0 n/a n/a

aThis information has been subject to audit. Includes equivalent plans in which the individual participated prior to joining the board. 

bBP’s performance is measured against the oil sector. For the 2005-2007 and subsequent awards, the performance condition is TSR measured against ExxonMobil, Shell, Total and Chevron. Each performance period 

ends on 31 December of the third year.

cRepresents awards of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares awarded. 

dRestricted award under share element of EDIP. As reported in the 2007 directors’ remuneration report in February 2008, the committee awarded both Mr Inglis and Mr Conn restricted shares, as set out above.

These one-off awards will vest on the third and fifth anniversary of the award, dependent on the remuneration committee being satisfied as to their personal performance at the date of vesting. Any unvested tranche will 

lapse in the event of cessation of employment with the company.

eDr Grote receives awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. 

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Share optionsa

The closing market prices of an ordinary share and of an ADS on 31 December 2008 were £5.26 and $46.74 respectively. 

During 2008, the highest market prices were £6.50 and $76.12 respectively and the lowest market prices were £3.76 and $39.56 respectively. 

BPA = BP Amoco share option plan, which applied to US executive directors prior to the adoption of the EDIP. 

EDIP = Executive Directors’ Incentive Plan adopted by shareholders in April 2005 as described on page 76. 

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. 

SAYE = Save As You Earn employee share scheme. 

80 

Directors’ remuneration report

Market price Date from

Option At 31 Dec Option at date of which first

 type At 1 Jan 2008 Granted Exercised 2008 price exercise exercisable Expiry date

Dr A B Hayward SAYE 3,220 – – 3,220 £5.00 01 Sep 2011 29 Feb 2012

EXEC 34,000 – – 34,000 £5.99 15 May 2003 15 May 2010

EXEC 77,400 – – 77,400 £5.67 23 Feb 2004 23 Feb 2011

EXEC 160,000 – – 160,000 £5.72 18 Feb 2005 18 Feb 2012

EDIP 220,000 – – 220,000 £3.88 17 Feb 2004 17 Feb 2010

 EDIP 275,000 – – 275,000 £4.22 25 Feb 2005 25 Feb 2011

I C Conn SAYE 1,456 – 1,456 – £3.50 £4.72b 01 Sep 2008 28 Feb 2009

SAYE 1,186 – – 1,186 £3.86 01 Sep 2009 28 Feb 2010

 SAYE 1,498 – – 1,498 £4.41 01 Sep 2010 28 Feb 2011

SAYE – 617 – 617 £4.87 01 Sep 2011 01 Feb 2012

EXEC 72,250 – – 72,250 £5.67 23 Feb 2004 23 Feb 2011

 EXEC 130,000 – – 130,000 £5.72 18 Feb 2005 18 Feb 2012

Dr B E Grotec BPA 10,404 – – 10,404 $53.90 15 Mar 2000 14 Mar 2009

BPA 12,600 – – 12,600 $48.94 28 Mar 2001 27 Mar 2010

 EDIP 40,182 – 40,182 – $49.65 $65.58-$66.50 19 Feb 2002 19 Feb 2008

EDIP 58,173 – – 58,173 $48.82 18 Feb 2003 18 Feb 2009

EDIP 58,173 – – 58,173 $37.76 17 Feb 2004 17 Feb 2010

EDIP 58,333 – – 58,333 $48.53 25 Feb 2005 25 Feb 2011

A G Inglis SAYE 4,550 – – 4,550 £3.50d 01 Sep 2008 28 Feb 2009

EXEC 72,250 – – 72,250 £5.67 23 Feb 2004 22 Feb 2011

EXEC 119,000 – – 119,000 £5.72 18 Feb 2005 17 Feb 2012

EXEC 119,000 – – 119,000 £3.88 17 Feb 2006 16 Feb 2013

 EXEC 100,500 – – 100,500 £4.22 25 Feb 2007 24 Feb 2014

Directors leaving the board in 

2008 

Dr D C Allen EXEC 37,000 – – 37,000e £5.99 15 May 2003 15 May 2010

 EXEC 87,950 – – 87,950e £5.67 23 Feb 2004 23 Feb 2011

EXEC 175,000 – – 175,000e £5.72 18 Feb 2005 18 Feb 2012

EDIP 220,000 – – 220,000e £3.88 17 Feb 2004 17 Feb 2010

EDIP 275,000 – – 275,000e £4.22 25 Feb 2005 25 Feb 2011

aThis information has been subject to audit.

bClosing market price for information. Shares were retained when exercised. 

cNumbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.

dOptions exercised on 21 January 2009 and the shares were retained by Mr Inglis. Closing market price for information on that date was £4.86.

eOn leaving the board on 31 March 2008. 

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Directors’ remuneration report

Service contracts 

Director 

Service contracts have a notice period of one year and 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 been terminated on the expiry of the remainder of the 

notice period. The service contracts are expressed to expire at a normal 

retirement age of 60 (subject to age discrimination). 

 Dr Grote’s contract is with BP Exploration (Alaska) Inc. He is seconded 

to BP p.l.c. under a secondment agreement of 7 August 2000, which expires 

on 31 March 2010. The secondment can 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 the early termination of any 

of the contracts by the company, other than for cause (or under a specific 

termination payment 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, new service contracts include a provision to allow 

for severance payments to be phased, when appropriate. The committee will 

also consider mitigation to reduce compensation to a departing director, when 

appropriate to do so. 

Director leaving the board in 2008 

Dr Allen left the company at the end of March 2008. He was entitled to one 

year’s salary (£510,000) as compensation in accordance with his contractual 

entitlement, as well as a pro rata bonus for 2008 and continued full 

participation in the 2006-08 and 2007-09 share elements, according to the 

normal rules of the plan. 

Executive directors – external appointments 

The board encourages executive directors to broaden their knowledge and 

experience by taking up appointments outside the company. Each executive 

director is permitted to accept one non-executive appointment, from which 

they may retain any fee. External appointments are subject to agreement by 

the chairman and reported to the board. Any external appointment must not 

conflict with a director’s duties and commitments to BP. 

Contract Salary as at

 date 31 Dec 2008 

Dr A B Hayward 29 Jan 2003 £1,045,000 

I C Conn 22 Jul 2004 £690,000

Dr B E Grote 7 Aug 2000 $1,380,000

A G Inglis 1 Feb 2007 £690,000 

During the year, the fees received by executive directors for external 

appointments were as follows: 

Executive director 

Remuneration committee 

All the members of the committee are independent non-executive directors. 

Throughout the year, Dr Julius (chairman), Mr Davis, Sir Tom McKillop and Sir 

Ian Prosser were members. The 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; neither he nor the 

chairman were present when matters affecting their own remuneration were 

discussed. 

Tasks 

The remuneration committee’s tasks are: 

 Additional postion 

Appointee held at appointee Total

company company fees

Dr A B Hayward Tata Steel Senior £83,000

 Independent 

Director

I C Conn Rolls-Royce Senior £65,000

Independent

Director

Dr B E Grote Unilever Audit committee Unilever PLC

member £33,500

Unilever NV

€48,625

A G Inglis BAE Chair of £86,754

 Systems Corporate 

Responsibility

 Committee 

• 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 these to the shareholders.

• To determine, on behalf of the board, matters of policy over which the 

company has authority regarding 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 the scheme.

• To review the policies being applied by the group chief executive in 

remunerating senior executives other than executive directors to ensure 

alignment and proportionality.

• To recommend to the board the quantum and structure of remuneration for 

the chairman. 

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Directors’ remuneration report

Constitution and operation 

Each member of the remuneration committee is subject to annual re-election 

as a director of the company. The board considers all committee members to 

be independent (see page 66). 

 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. Mr Sutherland, 

as chairman of the board, attended all the 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. 

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 independent adviser. Advice was also received from Mr Jackson, the 

company secretary. 

 The committee also appoints external advisers to provide specialist 

advice and services on particular remuneration matters. The independence of 

the advice is subject to annual review. 

 In 2008, the committee continued to engage Towers Perrin as its 

principal external adviser. Towers Perrin also provided limited ad hoc 

remuneration and benefits advice to parts of the group, principally changes in 

employee share plans and some market information on pay structures. 

 Freshfields Bruckhaus Deringer LLP provided legal advice on specific 

matters to the committee, as well as providing some legal advice to the group. 

 Ernst & Young reviewed the calculations on the financial-based targets 

that form the basis of the performance-related pay for executive directors, that 

is, the annual bonus and share element awards described on page 75, to 

ensure they met an independent, objective standard. They also provided audit, 

audit-related and taxation services for the group. 

Part 3 Non-executive directors’ 

remuneration 

Policy 

Remuneration of the chairman and the non-executive directors continues to be 

set by the board. The process by which the board determines that 

remuneration was reviewed during the year with the result that: 

The above changes came into effect for the 2008 review of remuneration. 

 The other elements of BP’s non-executive director remuneration policy 

remain unchanged: 

Fee structure 

The table below shows the current fee structure for non-executive directors: 

• The quantum and structure of the chairman’s remuneration would be 

reviewed by the remuneration committee. The remuneration committee 

would then make a recommendation to the board but the chairman would not 

vote on his own remuneration; and

• The quantum and structure of non-executive director remuneration would be 

reviewed by the chairman, with support and analysis provided by the 

company secretary. The chairman would then make a recommendation to 

the board but non-executive directors would not vote on their own 

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.

• 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.

£ thousand

Fee level

Chairmana 600

Deputy chairmanb 120

Board member 75

Audit committee and SEEAC chairmanship feesc 30 

Remuneration committee chairmanship feec 20

Transatlantic attendance allowance 5

Committee membership feed 5

aThe chairman remains ineligible for committee chairmanship and membership fees or transatlantic 

attendance allowance, but has the use of a fully maintained office for company business, a chauffeured 

car and security advice.

bThe role of deputy chairman is combined with that of senior independent director. The deputy chairman 

is still eligible for committee chairmanship fees and transatlantic attendance allowance plus any 

committee membership fees.

cCommittee chairmen do not receive an additional membership fee for the committee they chair.

dFor members of the audit, SEEAC and remuneration committees.

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Directors’ remuneration report

Remuneration of non-executive directors in 2008a

No share or share option awards were made to any non-executive director in 

respect of service on the board during 2008. 

 Non-executive directors have letters of appointment, which recognize 

that, subject to the Articles of Association, their service is at the discretion of 

shareholders. All directors stand for re-election at each AGM. 

Review of chairman and non-executive director remuneration 

The new process for the determination of non-executive remuneration, as 

described earlier, was operated during the year and recommendations were 

made. However, the chairman and the non-executive directors informed the 

board that, in the current economic circumstances, they did not wish to receive 

any increase in remuneration for the coming year 2009. 

 The board, therefore, decided after review to maintain fees for 2009 at 

the 2008 level set out in the fee structure table, save that the committee 

membership fee would no longer be paid to members of the nomination 

committee. 

Superannuation gratuities 

Until 2002, BP maintained a long-standing practice whereby non-executive 

directors who retired from the board after at least six years’ service were 

eligible for consideration for a superannuation gratuity. The board was, and 

continues to be, authorized to make such payments under the company’s 

Articles of Association and 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. 

 In 2002, the board revised its policy with respect to superannuation 

gratuities so that: 

The board made a superannuation gratuity of £23,000 during the year to Dr 

Walter Massey, who retired in April 2008. This payment was in line with the 

policy arrangements agreed in 2002 and outlined above. 

 £ thousand 

 2007 2008

A Burgmans 86 90

Sir William Castell 87 108

C B Carroll 43 93

G Davidb n/a 100

E B Davis, Jr 107 105

D J Flint 86 90

Dr D S Julius 106 110

Sir Tom McKillop 87 95

Sir Ian Prosser 137 170

P D Sutherland 517 600

Director leaving the board in 2008 

Dr W E Masseyc 133 90

aThis information has been subject to audit.

bAppointed on 11 February 2008.

cAlso received a superannuation gratuity of £23,000.

• Non-executive directors appointed to the board after 1 July 2002 would not 

be eligible for consideration for such a payment.

• While non-executive directors in service at 1 July 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.

Non-executive directors of Amoco Corporation 

Non-executive directors who were formerly non-executive directors of Amoco 

Corporation have residual entitlements under the Amoco Non-Employee 

Directors’ Restricted Stock Plan. Directors were allocated restricted stock in 

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. The restricted stock will vest on the 

retirement of the non-executive director at the age of 70 (or earlier at the 

discretion of the board). Since the merger, no further entitlements have 

accrued to any director under the plan. The residual interests, as interests in a 

long-term incentive scheme, are set out in the table below, in accordance with 

the Directors’ Remuneration Report Regulations 2002. 

Past directors 

Mr Miles (who was a non-executive director of BP until April 2006) was 

appointed as a director and non-executive chairman of BP Pension Trustees 

Limited in October 2006 for a term of three years. During 2008, he received 

£150,000 for this role. 

 Dr Walter Massey (who retired as a non-executive director of BP in 

April 2008) remained a member of the nomination committee during the year 

to assist in the search for a successor to BP’s chairman. Dr Massey received 

a total fee of £15,000 for this role in 2008. Dr Massey was also appointed to 

the BP America board in April 2008 for a term of two years. During 2008, he 

received US$93,500 for this role. 

 

This directors’ remuneration report was approved by the board and signed on 

its behalf by David J Jackson, company secretary, on 24 February 2009. 

 Interest in BP ADSs Date on 

at 1 Jan 2008 and which director

31 Dec 2008a reaches age 70b

E B Davis, Jr 4,490 5 Aug 2014

Director leaving the board in 2008

Dr W E Masseyc 3,346 5 April 2008

aNo 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.

bFor 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.

cDr Massey retired from the board on 17 April 2008. He had received awards of Amoco shares under the 

plan between 22 June 1993 and 28 April 1998 prior to the merger. These interests had been converted 

into BP ADSs at the time of the merger. In accordance with the terms of the plan, the board exercised 

its discretion over this award on 16 May 2008 and the shares vested on that date (when the BP ADS 

market price was $74.57) without payment by him.

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Additional information

for shareholders

86 Share ownership

87 Major shareholders and related party 

transactions

88 Dividends

88 Legal proceedings

89 The offer and listing

91 Memorandum and Articles of 

Association

92 Exchange controls

92 Taxation

94 Documents on display

94 Material modifications to the rights of 

security holders and use of proceeds

94 Controls and procedures

95 Audit committee financial expert

95 Code of ethics

95 Principal accountants fees and 

services

95 Corporate governance practices

97 Purchases of equity securities by the 

issuer and affiliated purchasers

98 Called-up share capital

98 Annual general meeting

98 Exhibits

98 Administration

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Additional information for shareholders

 

Share ownership 

Directors and senior management 

As at 18 February 2009, 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: 

As at 18 February 2009, 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: 

There are no directors or members of senior management who own more than 1% of the ordinary shares outstanding. At 18 February 2009, all directors and senior 

management as a group held interests in 4,308,712 ordinary shares or their calculated equivalent, 11,163,994 performance shares or their calculated equivalent 

and 3,281,964 options for ordinary shares or their calculated equivalent under the BP group share options schemes. 

 Additional details regarding the options granted and performance shares awarded can be found in the directors’ remuneration report on pages 79 and 80. 

Employee share plans 

The following table shows employee share options granted. 

86 

I C Conn 279,937 1,815,940a 266,904c

Dr B E Grote 1,261,664 2,066,316a –

Dr A B Hayward 527,607 2,734,170a –

A G Inglis 255,424 1,759,435a b 266,904c

A Burgmans 10,000 – –

C B Carroll – – –

Sir William Castell 82,500 – –

G David 9,000 – –

E B Davis, Jr 73,185 – – 

D J Flint 15,000 – –

Dr D S Julius 15,000 – –

Sir Tom McKillop 20,000 – –

Sir Ian Prosser 16,301 – –

P D Sutherland 30,906 – – 

aPerformance shares awarded under the BP Executive Directors Incentive Plan. These figures represent the maximum possible vesting levels. The actual number of shares/ADSs that vest will depend on the extent to 

which performance conditions have been satisfied over a three-year period. 

bAlso includes 325,750 performance shares awarded under the BP Medium Term Performance Plan, which represents the maximum possible vesting level. The actual number of shares that vest will depend on the 

extent to which performance conditions have been satisfied over a three-year period.

cRestricted share award under the BP Executive Directors Incentive Plan. These shares will vest in two equal tranches after three and five years, subject to the directors’ continued service and satisfactory performance. 

I C Conn 205,551

Dr B E Grote 1,186,098

Dr A B Hayward 769,620

A G Inglis 410,750

options thousands

2008 2007 2006

Employee share options granted during the yeara 8,063 6,004 53,977

aFor the options outstanding at 31 December 2008, the exercise price ranges and weighted average remaining contractual lives are shown in Financial statements – Note 41 on page 166.

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 Financial 

statements – Note 41 on page 166) and the granting of share options as 

elements of remuneration for executive directors and senior employees. 

 Shares acquired through the company’s employee share plans rank pari 

passu with shares in issue and have no special rights, save as described 

below. For legal and practical reasons, the rules of these plans set out the 

consequences of a change of control of the company, and generally provide 

for options and conditional awards to vest on an accelerated basis. 

Savings and matching plans

BP ShareSave Plan 

This is a savings-related share option plan, under which employees save on a 

monthly basis over a three-year 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. 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. 

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87

Additional information for shareholders

BP ShareMatch plans 

These are 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 more than 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.

 Once shares have been awarded to an employee under the plan, the 

employee may instruct the trustee how to vote their shares. 

Local plans 

In some countries, BP provides local scheme benefits, the rules and 

qualifications for which vary according to local circumstances. 

 The above share plans are indicated as being equity-settled. In certain 

countries, however, it is not possible to award shares to employees owing to 

local legislation. In these instances, the award will be settled in cash, 

calculated as the cash equivalent of the value to the employee of an equitysettled plan. 

Cash plans 

Cash-settled share-based payments/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/restricted shares to the employee at the date of exercise/maturity. 

Employee share ownership plans (ESOPs) 

ESOPs have been established to acquire BP shares to satisfy any awards 

made to participants under the Executive Directors’ Incentive Plan, the 

Medium-Term Performance Plan, the Long-Term Performance Plan, the 

Deferred Annual Bonus Plan 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. Pending vesting, the ESOPs have independent trustees 

that have the discretion in relation to the voting of such shares. 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 Financial statements – Note 40 on page 164). 

Assets and liabilities of the ESOPs are recognized as assets and liabilities of 

the group. 

 At 31 December 2008, the ESOPs held 29,051,082 shares (2007 

6,448,838 shares and 2006 12,795,887 shares) for potential future awards, 

which had a market value of $220 million (2007 $79 million and 2006 

$142 million). 

 Pursuant to the various BP group share option schemes, the following 

options for ordinary shares of the company were outstanding at 18 

February 2009: 

More details on share options appear in Financial statements – Note 41 on 

page 166. 

Expiry dates Exercise price

Options outstanding (shares) of options per share

323,378,846 2009-2016 5.7050-11.9210

Major shareholders and related party 

transactions 

Register of members holding BP ordinary shares as at 31 

December 2008 

Register of holders of American depositary shares (ADSs) as at 31 

December 2008a 

As at 31 December 2008, there were also 1,622 preference shareholders. 

Preference shareholders represented 0.44% and ordinary shareholders 

represented 99.56% of the total issued nominal share capital of the company 

as at that date. 

Substantial shareholdings 

As at the date of this report, the company had been notified that JPMorgan 

Chase Bank, as depositary for American depositary shares (ADSs) holds 

interests through its nominee, Guaranty Nominees Limited, in 5,184,252,501 

ordinary shares (27.51% of the company’s ordinary share capital excluding 

shares held in Treasury). Legal & General Group plc hold interests in 

813,276,072 ordinary shares (4.32% of the company’s ordinary share capital 

excluding shares held in treasury). 

 At the date of this report the company has also been notified of the 

following interests in preference shares: The National Farmers Union Mutual 

Insurance Society Limited holds interests in 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). M & G Investment Management Ltd. 

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). Aviva Investors Global Services Limited holds interests in 475,000 

8% cumulative first preference shares (6.57% of that class). Lazard Asset 

Management Ltd. (U.K.) holds interests in 463,000 8% cumulative first 

preference shares (6.40% of that class). Duncan Lawrie Ltd. holds interests in 

451,376 8% cumulative first preference shares (6.24% of that class). Cooperative Insurance Society Ltd. holds interests in 444,538 8% cumulative first 

preference shares (6.15% of that class) and 1,450,000 9% cumulative 

Number of Percentage of Percentage of

 ordinary total ordinary total ordinary 

Range of holdings shareholders shareholders share capital

1-200 57,617 18.22 0.01

201-1,000 120,017 37.94 0.31

1,001-10,000 124,970 39.51 1.83 

10,001-100,000 11,837 3.74 1.17

100,001-1,000,000 1,089 0.34 1.95

Over 1,000,000a 790 0.25 94.73

Totals 316,320 100.00 100.00

aIncludes JP Morgan Chase Bank holding 27.48% of the total ordinary issued share capital (excluding 

shares held in treasury) as the approved depositary for ADSs, a breakdown of which is shown in the 

table below.

 

 Percentage of 

Number of total ADS Percentage of

Range of holdings ADS holders holders total ADSs

1-200 73,569 53.88 0.50

201-1,000 38,781 28.40 2.16 

1,001-10,000 22,656 16.59 7.12

10,001-100,000 1,505 1.10 3.04 

100,001-1,000,000 23 0.02 0.47

Over 1,000,000b 2 0.01 86.71

Totals 136,536 100.00 100.00

aOne ADS represents six 25 cent ordinary shares.

bOne of the holders of ADSs represents some 818,000 underlying shareholders.

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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 US 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 on future earnings, the financial condition of the group, the Risk factors set out on pages 8-10 and other matters that may 

affect the business of the group set out in Financial and operating performance on page 46 and in Liquidity and capital resources on page 54. 

Legal proceedings 

88 

Additional information for shareholders

 March June September December Total 

Dividends per American depositary share 

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

 Canadian 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

 Canadian cents 64.0 63.2 65.3 63.7 256.2 

2006 UK pence 31.7 31.5 31.9 31.4 126.5

US cents 56.25 56.25 58.95 58.95 230.40

 Canadian cents 64.5 64.1 67.4 66.5 262.5 

2007 UK pence 31.5 30.9 31.7 31.8 125.9 

US cents 61.95 61.95 64.95 64.95 253.8

 Canadian cents 73.3 69.5 67.8 63.6 274.2 

2008 UK pence 40.9 41.0 42.2 52.2 176.3

US cents 81.15 81.15 84.00 84.00 330.3

Canadian cents 80.8 82.5 85.8 108.6 357.7

second preference shares (26.49% of that class). Ruffer LLP holds interests in 

671,500 9% cumulative second preference shares (12.27% of that class). 

 The total preference shares in issue comprise only 0.44% of the 

company’s total issued nominal share capital, the rest being ordinary shares. 

Related-party transactions 

Transactions between the group and its significant jointly controlled entities 

and associates are summarized in Financial statements – Note 26 on page 

138 and Financial statements – Note 27 on page 139. In the ordinary course 

of its business, the group enters into transactions with various organizations 

with which certain of its directors or executive officers are associated. Except 

as described in this report, the group did not have material transactions or 

transactions of an unusual nature with, and did not make loans to, related 

parties in the period commencing 1 January 2008 to 18 February 2009. 

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. Former Amoco 

Corporation and Atlantic Richfield Company shareholders will not be able to 

receive dividends, or proxy material, until they send in their Amoco 

Corporation or Atlantic Richfield Company common shares for exchange. 

 BP currently announces dividends for ordinary shares in US dollars and 

states an equivalent pounds sterling dividend. Dividends on BP ordinary 

shares will be paid in pounds sterling and on BP ADSs in US dollars. The rate 

of exchange used to determine the sterling amount equivalent is the average 

of the forward exchange rate in London over the five business days prior to 

the announcement date. The directors may choose to declare dividends in any 

currency provided that a sterling equivalent is announced, but it is not the 

company’s intention to change its current policy of announcing dividends on 

ordinary shares in US dollars. 

 The following table shows dividends announced and paid by the 

company per ADS for each of the past five years. In the case of dividends paid 

before 1 May 2004, the dividends shown are before the deemed credit allowed 

to shareholders resident in the US under the former income tax convention 

between the US and the UK and the associated withholding tax in respect 

thereof equal to the amount of such credit. (This deemed credit and 

associated withholding tax do not apply to dividends paid after 30 April 2004 to 

shareholders resident in the US.) 

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 that are significant to the group. 

 BP America Inc. (BP America) continues to be subject to oversight by 

an independent monitor, who has authority to investigate and report alleged 

violations of the US Commodity Exchange Act or US Commodity Futures 

Trading Commission (CFTC) regulations and to recommend corrective action. 

The appointment of the independent monitor was a condition of the deferred 

prosecution agreement (DPA) entered into with the US Department of Justice 

(DOJ) on 25 October 2007 relating to allegations that BP America manipulated 

the price of February 2004 TET physical propane and attempted to manipulate 

the price of TET propane in April 2003 and the companion consent order with 

the CFTC, entered the same day, resolving all criminal and civil enforcement 

matters 

pending at that time concerning propane trading by BP Products North 

America Inc. (BP Products). The DPA requires BP America’s and certain of its 

affiliates’ continued co-operation with the US government investigations of the 

trades in question, as well as other trading matters that may arise. The DPA 

has a term of three years but can be extended by two additional one-year 

periods, and contemplates dismissal of all charges at the end of the term 

following the DOJ’s determination that BP America has complied with the 

terms of the DPA. Investigations into BP’s trading activities continue to be 

conducted from time to time. 

 Private complaints, including class actions, have also been filed against 

BP Products alleging propane price manipulation. The complaints contain 

allegations similar to those in the CFTC action as well as of violations of 

federal and state antitrust and unfair competition laws and state consumer 

protection statutes and unjust enrichment. The 

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complaints seek actual and punitive damages and injunctive relief. Settlement 

with one group of the class actions has received preliminary approval from the 

court and final approval is expected in 2009. 

 On 23 March 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 workers died in the incident and many others were 

injured. BP Products has resolved all civil claims arising from the incident, 

except for a small number of claims that remain on appeal following dismissal 

in the trial court. 

 In March 2007, the US Chemical Safety and Hazard Investigation Board 

(CSB) issued its final report on the incident. The report contained 

recommendations to the Texas City refinery and to the board of the company. 

In May 2007, BP responded to the CSB’s recommendations. BP and the CSB 

continue to discuss BP’s responses with the objective of the CSB agreeing to 

close-out its recommendations. 

 On 25 October 2007, the DOJ announced that it had entered into a 

criminal plea agreement with BP Products related to the March 2005 explosion 

and fire. Following BP Products’ guilty plea on 4 February 2008, pursuant to 

the plea agreement, to one felony violation of the risk management planning 

regulations promulgated under the US federal Clean Air Act, a series of 

appeals were taken by victims of the incident, who alleged that the plea 

agreement did not fully take into account the victims’ injuries. On 7 

October 2008, after resolution of those appeals, BP Products returned to court 

to argue for acceptance of the guilty plea. At the plea hearing, the court 

advised that it would take the matter under review and decide whether to 

accept or reject the plea. If the court accepts the agreement, BP Products will 

pay a $50 million criminal fine and serve three years’ probation. Compliance 

with a 2005 OSHA settlement agreement and an agreed order entered into by 

BP Products with the Texas Commission on Environmental Quality 

(TCEQ) are conditions of probation. The TCEQ and the DOJ continue to 

investigate certain matters arising from the March 2005 explosion and fire. 

 On 29 November 2007, BP Exploration (Alaska) Inc. (BPXA) entered 

into a criminal plea agreement with the DOJ relating to leaks of crude oil in 

March and August 2006. BPXA’s guilty plea, to a misdemeanour violation of 

the US Federal Water Pollution Control Act, included a term of three years’ 

probation. BPXA is eligible to petition the court for termination of the probation 

term if it meets certain benchmarks relating to replacement of the transit lines, 

upgrades to its leak detection system and improvements to its integrity 

management programme. BPXA continues to co-operate with a parallel State 

of Alaska civil investigation into the March and August 2006 spills, including 

three separate subpoenas issued to BPXA by the Alaska Department of 

Environmental Conservation. BPXA is also engaged in discussions with the 

DOJ, the EPA and the US Department of Transportation concerning a civil 

enforcement action relating to the 2006 Prudhoe Bay oil transit line incidents. 

 Shareholder derivative lawsuits alleging breach of fiduciary duty that 

were filed in US federal and state courts against the directors of the company 

and others, nominally the company and certain US subsidiaries, following the 

events relating to, inter alia, Prudhoe Bay, Texas City and the trading cases, 

have been settled (following court approval of the settlement terms) and the 

claims have been dismissed. 

 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 46.9% interest (reduced 

during 2001 from 50% by a sale of 3.1% 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 that 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 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 against Atlantic Richfield. Atlantic 

Richfield is named in these lawsuits as alleged successor to International 

Smelting and Refining and another company that 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 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 judgment 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 that the incurrence of liability 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 January 2009, the TNK-BP shareholders resolved, or agreed a 

process for resolving, all outstanding claims between them, including those 

relating to Russian back taxes. The suit filed in Russia by a minority 

shareholder in TNK-BP Holding, alleging that an agreement by BP specialists 

to provide services to the TNK-BP group is invalid and demanding repayment 

of sums paid to BP for such services, has been withdrawn. 

 For certain information regarding environmental proceedings, see 

Environment – US regional review on page 42. 

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 and Germany. 

 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 that 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 US, 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 principal office is 4 New York Plaza, Floor 13, New 

York, NY 10004, US. Each ADS represents six ordinary shares. ADSs are 

listed on the New York Stock Exchange. ADSs are evidenced by American 

depositary receipts (ADRs), which may be issued in either certificated or book 

entry form. 

 The following table sets forth for the periods indicated the highest 

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Pence Dollars

American

depositary

 Ordinary shares sharesa

 High Low High Low 

Year ended 31 December

2004 561.00 407.75 62.10 46.65

2005 686.00 499.00 72.75 56.60

2006 723.00 558.50 76.85 63.52 

2007 640.00 504.50 79.77 58.62

2008 657.25 370.00 77.69 37.57 

Year ended 31 December 

2007: First quarter 574.50 504.50 67.27 58.62

Second quarter 606.50 542.50 72.49 64.42

Third quarter 617.00 516.00 75.25 61.10

Fourth quarter 640.00 548.00 79.77 67.24

2008: First quarter 648.00 495.00 75.87 57.87

Second quarter 657.25 501.34 77.69 60.25

Third quarter 583.00 446.00 69.10 48.35

Fourth quarter 541.25 370.00 51.49 37.57

2009: First quarter (to 18 February) 566.50 461.50 49.83 39.45

Month of

September 2008 536.00 446.00 58.13 48.35

October 2008 518.75 370.00 50.96 37.57

November 2008 540.00 450.25 51.49 39.45

December 2008 541.25 476.00 50.10 41.55

January 2009 566.50 470.50 49.83 39.45

February 2009 (to 18 February) 518.00 461.50 46.07 39.91

aAn ADS is equivalent to six 25 cent ordinary shares.

and lowest middle market quotations for BP’s ordinary shares 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 (NYSE) composite tape. 

Market prices for the ordinary shares on the LSE and in after-hours trading off 

the LSE, in each case while the NYSE is open, and the market prices for 

ADSs on the NYSE 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. 

 On 18 February 2009, 864,042,084 ADSs (equivalent to 5,184,252,501 

ordinary shares or some 27.51% of the total issued share capital, excluding 

treasury shares) were outstanding and were held by approximately 136,213 

ADS holders. Of these, about 134,710 had registered addresses in the US at 

that date. One of the registered holders of ADSs represents some 818,000 

underlying holders. 

 On 18 February 2009, there were approximately 317,409 holders of 

record of ordinary shares. Of these holders, around 1,504 had registered 

addresses in the US and held a total of some 4,236,569 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 US may not be 

representative of the number of beneficial holders or of their country of 

residence. 

 

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Memorandum and Articles of Association 

The following summarizes certain provisions of the company’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 the 

company’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’ on page 94. 

 On 24 April 2003, the shareholders of BP voted at the AGM to adopt 

new Articles of Association to consolidate amendments that had been 

necessary to implement legislative changes since the previous Articles of 

Association were adopted in 1983. 

 At the AGM held on 15 April 2004, shareholders approved an 

amendment to the Articles of Association such that, at each AGM held after 31 

December 2004, all directors shall retire from office and may offer themselves 

for re-election. 

 At the AGM held on 17 April 2008, shareholders voted to adopt new 

Articles of Association, largely to take account of changes in UK company law 

brought about by the Companies Act 2006. Further amendments to the 

Articles of Association are likely to be required at our AGM in 2010, to reflect 

the full implementation of the Companies Act 2006. 

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 petroleumbearing 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 that have been approved by either 

the UK Board of Inland Revenue or by the shareholders.

• 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’ includes the interests of spouses, children, companies 

and trusts. The UK Companies Act also requires that a director must avoid a 

situation where a director has, or could have, a direct or indirect interest that 

conflicts, or possibly may conflict, with the company’s interests. The Act allows 

directors of public companies to authorize such conflicts where appropriate, if 

a company’s Articles of Association so permit. BP’s Articles of Association 

permit the authorization of such conflicts. 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. 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 12 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: 

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. 

• 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.

• 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.

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Voting rights 

The Articles of Association of the company 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 are also 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 respect of the 

ordinary shares represented by their ADSs. Each such proxy may also appoint 

a proxy. Alternatively, holders of BP 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 annual general meeting must be held once in every year and 

all other general meetings will be called extraordinary general meetings. 

 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 requires 21 days’ notice. The notice period for an extraordinary 

general meeting is 14 days. With the implementation of the EU Shareholder 

Rights Directive into UK law expected later this year, reliance on this notice 

period of 14 days will require annual shareholder approval, failing which, a 21-

day notice period will apply. 

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 LSE 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 that 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 on 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 onethird 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 the six-month period from the first day of BP’s accounting period. All 

general meetings shall be held at a time and place determined by the directors 

within the UK. 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 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 the company’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. 

Exchange controls 

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 

company’s Articles of Association, restricting the right of non-resident or 

foreign owners to hold or vote BP ordinary or preference shares in the 

company. 

Taxation 

This section describes the material US federal income tax and UK taxation 

consequences of owning ordinary shares or ADSs to a US holder who 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 US federal income tax purposes (i) a citizen or resident of the US, (ii) a US 

domestic corporation, (iii) an estate whose income is subject to US federal 

income taxation regardless of its source, or (iv) a trust if a US court can 

exercise primary supervision over the trust’s administration and one or more 

US 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 UK, all as 

currently in effect, as well as the income tax convention 

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between the US and the UK that entered into force on 31 March 2003 (the 

Treaty). These laws are subject to change, possibly on a retroactive basis. 

This section is further based in part on 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. 

 For purposes of the Treaty and the estate and gift tax Convention (the 

‘Estate Tax Convention’), and for US 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 US federal income tax or to UK taxation other than stamp duty or 

stamp duty reserve tax, as described below. 

 Investors should consult their own tax adviser regarding the US 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 

UK 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 UK or trading in 

the UK through a permanent establishment generally will not be taxable in the 

UK on a dividend it receives from the company. A shareholder who is an 

individual resident for tax purposes in the UK is subject to UK tax but 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. 

US federal income taxation 

A US holder is subject to US 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 US federal income tax purposes). Dividends 

paid to a non-corporate US holder in taxable years beginning before 1 

January 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. 

 As noted above in UK taxation, a US holder will not be subject to UK 

withholding tax. A US holder will include in gross income for US 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 US 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 US 

corporations in respect of dividends received from other US corporations. 

Dividends will be income from sources outside the US, and generally will be 

‘passive category income’ or, in the case of certain US holders, ‘general 

category income,’ each of which is treated separately 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 and will not be 

eligible for the 15% tax rate on qualified dividend income. The gain or loss 

generally will be income or loss from sources within the US for foreign tax 

credit limitation purposes. 

 Distributions in excess of the company’s earnings and profits, as 

determined for US 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 Taxation of 

capital gains – US federal income taxation. 

Taxation of capital gains 

UK taxation 

A US holder may be liable for both UK and US tax in respect of a gain on the 

disposal of ordinary shares or ADSs if the US holder is (i) a citizen of the US 

resident or ordinarily resident in the UK, (ii) a US domestic corporation 

resident in the UK by reason of its business being managed or controlled in 

the UK or (iii) a citizen of the US or a corporation that carries on a trade or 

profession or vocation in the UK through a branch or agency or, in respect of 

corporations for accounting periods beginning on or after 1 January 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 US federal income tax 

liability for the amount of UK capital gains tax or UK corporation tax on 

chargeable gains (as the case may be) that 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 UK and the US and 

as required by the terms of the Treaty. 

 Under the Treaty, individuals who are residents of either the UK or the 

US and who have been residents of the other jurisdiction (the US or the UK, 

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. 

US federal income taxation 

A US holder that sells or otherwise disposes of ordinary shares or ADSs will 

recognize a capital gain or loss for US 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 1 January 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 

US for foreign tax credit limitation purposes. The deductibility of capital losses 

is subject to limitations. 

 We do not believe that ordinary shares or ADSs will be treated as stock 

of a passive foreign investment company, or PFIC, for US federal income tax 

purposes, but this conclusion is a factual determination that is made annually 

and thus is subject to change. If we are treated as a PFIC, unless a US holder 

elects to be taxed annually on a mark-to-mark basis with respect to ordinary 

shares or ADSs, gain realized on the sale or other disposition of ordinary 

shares or ADSs would in general not be treated as capital gain. Instead a US 

holder would be treated as if he or she had realized such gain and certain 

‘excess distributions’ ratably over the holding period for ordinary shares or 

ADSs and would be taxed at the highest tax rate in effect for each such year 

to which the gain was allocated, in addition to which an interest charge in 

respect of the tax attributable to each such year would apply. 

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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 HM Revenue & Customs in the UK under existing law. 

 Provided that any 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 £5 per £1,000 (or part, 

unless the stamp duty is less than £5, when no stamp duty is charged), 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. 

 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. It is understood that HM Revenue & Customs practice is to 

calculate the issue price by reference to the total cash receipt 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. 

Documents on display 

BP’s Annual Report and Accounts is also available online at 

www.bp.com/annualreport. Shareholders may obtain a hard copy of BP’s 

complete audited financial statements, free of charge, by contacting BP 

Distribution Services at +44 (0)870 241 3269 or through an email request 

addressed to bpdistributionservices@bp.com, or BP’s US Shareholder 

Services office in Warrenville, Illinois at +1 800 638 5672 or through an email 

request addressed to shareholderus@bp.com. 

 The company is subject to the information requirements of the US 

Securities Exchange Act of 1934 (the “Exchange Act”) applicable to foreign 

private issuers. In accordance with these requirements, the company files its 

Annual Report on Form 20-F and other related documents with the SEC. It is 

possible to read and copy documents that have been filed with the SEC 

at the SEC’s public reference room located at 100 F Street NE, Washington, 

DC 20549, US. You may also call the SEC at +1 800-SEC-0330 or log on to 

www.sec.gov. In addition, BP’s SEC filings are available to the public at the 

SEC’s website www.sec.gov. BP discloses on its website at 

www.bp.com/NYSEcorporategovernancerules, and in its Annual Report on 

Form 20-F (Item 16G) significant ways (if any) in which its corporate 

governance practices differ from those mandated for US companies under 

NYSE listing standards. 

Material modifications to the rights of 

security holders and use of proceeds 

During 2008, the Depositary and transfer agent for BP’s ADSs changed its 

contact address to PO Box 64504, St. Paul, MN 55164-0504. 

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, misstatements 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. 

 The company’s management, with the participation of the company’s 

group chief executive and 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. Based on that evaluation, the group chief executive and chief 

financial officer have concluded that the company’s disclosure controls and 

procedures were effective at a reasonable assurance level. 

Changes in internal controls over financial reporting 

There were no changes in the Group’s internal controls over financial reporting 

that occurred during the period covered by the Form 20-F that have materially 

affected or are reasonably likely to materially affect, our internal controls over 

financial reporting. 

 During 2008, as part of an ongoing process, improvements were made 

in the design and operation of the Group’s internal control over financial 

reporting including those relating to the valuation of inventory 

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and the elimination of unrealised profit arising on transfers of inventory 

between business segments. These improvements included clarifying roles 

and accountabilities, implementing additional preventative and detective 

controls and providing additional staff training. 

Management’s report on internal control over financial reporting 

Management of BP is responsible for establishing and maintaining adequate 

internal control over financial reporting. BP’s internal control over financial 

reporting is a process designed under the supervision of the principal 

executive and principal financial officers to provide reasonable assurance 

regarding the reliability of financial reporting and the preparation of BP’s 

financial statements for external reporting purposes in accordance with IFRS. 

 As of the end of the 2008 fiscal year, management conducted an 

assessment of the effectiveness of internal control over financial reporting in 

accordance with the Internal Control Revised Guidance for Directors on the 

Combined Code (Turnbull). Based on this assessment, management has 

determined that BP’s internal control over financial reporting as of 31 

December 2008 was effective. 

 The company’s internal control over financial reporting includes policies 

and procedures that pertain to the maintenance of records that, in reasonable 

detail, accurately and fairly reflect transactions and dispositions of assets; 

provide reasonable assurances that transactions are recorded as necessary to 

permit preparation of financial statements in accordance with IFRS and that 

receipts and expenditures are being made only in accordance with 

authorizations of management and the directors of BP; and provide 

reasonable assurance regarding prevention or timely detection of 

unauthorized acquisition, use or disposition of BP’s assets that could have a 

material effect on our financial statements. 

 BP’s internal control over financial reporting as of 31 December 2008 

has been audited by Ernst & Young LLP, an independent registered public 

accounting firm, as stated in their report appearing on page 100. 

Audit committee financial expert 

The board determined that Douglas Flint is the audit committee member with 

recent and relevant financial experience as defined by the Combined Code 

guidance. 

 The board also determined that Douglas Flint meets the independence 

criteria provisions of Rule 10A-3 of the Exchange Act and that Mr Flint may be 

regarded as an audit committee financial expert as defined in Item 16A of 

Form 20-F. Mr Flint 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. 

Code of ethics 

The company has adopted a code of ethics for its group chief executive, chief 

financial officer, general auditor, group chief accounting officer and deputy 

chief financial officer (previously titled 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 our Annual Report on Form 20-F. 

 In June 2005, BP published a code of conduct, which is applicable to all 

employees. 

Principal accountants 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 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); nonstatutory 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 (excluding valuation or involvement in prospective financial 

information); income tax and indirect tax compliance and advisory services; 

and employee tax services (excluding tax services that could impair 

independence); provision of, or access to, Ernst & Young publications, 

workshops, seminars and other training materials; provision of reports from 

data gathered on non-financial policies and information; and assistance with 

understanding non-financial regulatory requirements. 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 chairman of the audit committee authority to approve 

permitted services provided that the chairman reports any decisions to the 

committee at its next scheduled meeting. 

 The audit committee evaluates the performance of the auditors each 

year. The audit fees payable to Ernst & Young are reviewed by the committee 

in the context of other global companies for cost effectiveness. The committee 

keeps under review the scope and results of audit work and the independence 

and objectivity of the auditors. External regulation and BP policy requires the 

auditors to rotate their lead audit partner every five years. 

 (See Financial statements – Notes 18 and 48 on pages 132 and 178 for 

details of audit fees.) 

Corporate governance practices 

In the US, BP ADSs are listed on the New York Stock Exchange (NYSE). The 

significant differences between BP’s corporate governance practices and 

those required by NYSE listing standards for US companies are listed as 

follows: 

Independence 

BP has adopted a robust set of board governance principles, which reflect the 

UK’s prevailing principles-based approach to corporate governance. As such, 

the way in which BP makes determinations of directors’ independence differs 

from the NYSE rules. Rule 303A.02 under NYSE’s Listed Company Manual 

sets out five bright line tests for director independence. In addition to these 

five tests, the NYSE also requires that the board of directors “affirmatively 

determines that the director has no material relationship with the company 

(either directly or as a partner, shareholder or officer of an organization that 

has a relationship with the company)”. 

 BP’s board governance principles require that all non-executive 

directors be determined by the board to be “independent in character and 

judgement and free from any business or other relationship which could 

materially interfere with the exercise of their judgement”. 

 The BP board has determined that, in its judgement, all of the nonexecutive directors are independent. In doing so, however, the board did not 

explicitly take into consideration the NYSE’s five bright line tests. 

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Committees 

BP has a number of board committees which are broadly comparable in 

purpose and composition to those required by NYSE rules for domestic US 

companies. For instance, BP has a chairman’s (rather than executive) 

committee, nomination (rather than nominating/corporate governance) 

committee and remuneration (rather than compensation) committee. BP also 

has an audit committee, which NYSE rules require for both US companies and 

foreign private issuers. These committees are composed solely of nonexecutive directors whom the board has determined to be independent, in the 

manner described above. 

 The BP board governance principles prescribe the composition, main 

tasks and requirements of each of the committees (see The Board 

Committees on page 67). BP has not, therefore, adopted separate charters for 

each committee. 

 One of the NYSE’s additional requirements for the audit committee 

states that at least one member of the audit committee is to have “accounting 

or related financial management expertise”. For 2008, the board determined 

that Douglas Flint possessed such expertise and also possesses the financial 

and audit committee experiences set forth in both the Combined Code and 

SEC rules (See Audit Committee Financial Expert on page 95). 

Shareholder approval of equity compensation plans 

The NYSE rules for US companies require that shareholders must be given 

the opportunity to vote on all equity-compensation plans and material revisions 

to those plans. BP complies with UK requirements which are similar to the 

NYSE rules. The board, however, does not explicitly take into consideration 

the NYSE’s detailed definition of what are considered “material revisions”. 

Code of ethics 

The NYSE rules require that US companies adopt and disclose a code of 

business conduct and ethics for directors, officers and employees. BP has 

adopted a code of conduct, which applies to all employees, and has board 

governance principles which address the conduct of directors. In addition BP 

has adopted a code of ethics for senior financial officers as required by the 

SEC. BP considers that these codes and policies address the matters 

specified in the NYSE rules for US companies. 

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Purchases of equity securities by the issuer and affiliated purchasers 

The following table provides details of ordinary shares repurchased. 

The following table provides details of share purchases made by ESOP trusts. 

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Additional information for shareholders

Total number of shares Maximum number of

 $ purchased as part of shares that may yet 

Total number of Average price publicly announced be purchased under

shares purchaseda b paid per share programmes the programmec

2008

January 41,187,000 11.26 41,187,000 

February 24,314,706 10.90 24,314,706

March 25,494,193 10.60 25,494,193

April 28,537,196 11.02 28,537,196

May 27,570,000 12.34 27,570,000

June 29,793,000 11.58 29,793,000 

July 32,285,000 10.67 32,285,000

August 33,006,764 9.86 33,006,764

September 27,569,329 8.92 27,569,329

October – – –

November – – – 

December – – –

2009 

January – – –

February (to 18 February) – – –

aAll share purchases were open market transactions.

bAll shares were repurchased for cancellation.

cAt the AGM on 17 April 2008, authorization was given to repurchase up to 1.9 billion ordinary shares in the period to the next AGM in 2009 or 16 July 2009, the latest date by which an AGM must be held. This 

authorization is renewed annually at the AGM. 

Total number of shares Maximum number of

$ purchased as part of shares that may yet

Total number of Average price publicly announced be purchased under 

shares purchased paid per share programmesa the programmea

2008

January – –

February – – 

March 30,000,000 11.41

April 680 11.53 

May – –

June – –

July 63 11.08 

August 1,500,000 9.49

September 81,694 8.73 

October 1,000,772 7.39

November 166 10.09

December 59,049 8.09 

2009

January – – 

February (to 18 February) 126 7.65

aNo 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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Called-up share capital 

Details of the allotted, called up and fully paid share capital at 31 

December 2008 are set out in Financial statements – Note 39 on page 163. 

 At the AGM on 17 April 2008, authorization was given to the directors to 

allot shares up to an aggregate nominal amount equal to $1,586 million. 

Authority was also given to the directors to allot shares for cash and to 

dispose of treasury shares, other than by way of rights issue, up to a 

maximum of $238 million, without having to offer such shares to existing 

shareholders. These authorities are given for the period until the next AGM in 

2009 or 16 July 2009, whichever is the earlier. These authorities are renewed 

annually at the AGM. 

Annual general meeting 

The 2009 AGM will be held on Thursday 16 April 2009 at 11.30 a.m. at ExCeL 

London, One Western Gateway, Royal Victoria Dock, London E16 1XL. A 

separate notice convening the meeting is distributed to shareholders, which 

includes an explanation of the items of business to be considered at the 

meeting. 

 All resolutions of which notice has been given will be decided on a poll. 

 Ernst & Young LLP have expressed their willingness to continue in 

office as auditors and a resolution for their reappointment is included in Notice 

of BP Annual General Meeting 2009. 

By order of the board 

David J Jackson 

Secretary 

24 February 2009 

Exhibits 

 The total amount of long-term 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. 

 

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 Medium Term Performance Plan†

Exhibit 4.3 Deferred Annual Bonus Plan†

Exhibit 4.4 Performance Share 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 Report on Form 6-K filed on 22 May 2008.

**Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 

31 December 2004.

***Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 

31 December 2003.

#Furnished only.

†Included only in the annual report filed in the Securities and Exchange Commission EDGAR system.

Administration 

If you have any queries about the administration of shareholdings, such as 

change of address, change of ownership, dividend payments, the dividend 

reinvestment plan or the ADS direct access plan, or to change the way you 

receive your company documents (such as the Annual Report and Accounts, 

Annual Review and Notice of Meeting) please contact the BP Registrar or 

ADS Depositary. 

UK – Registrar’s Office 

The BP Registrar, Equiniti 

Aspect House, Spencer Road, Lancing, West Sussex BN99 6DA 

Freephone in UK 0800 701107; Tel +44 (0)121 415 7005 

Textphone 0871 384 2255; Fax +44 (0)871 384 2100 

Please note that any numbers quoted with the prefix 0871 will be charged at 

8p per minute from a BT landline. Other network providers’ costs may vary. 

US – ADS Depositary 

JPMorgan Chase Bank, N.A. 

PO Box 64504, St. Paul, MN 55164-0504 

Toll-free in US and Canada +1 877 638 5672; Tel +1 651 306 4383 

For the hearing impaired +1 651 453 2133 

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Financial statements 

 

 

100 Consolidated financial 

statements of the BP group 

 

Report of independent registered public accounting firm 100

Consent of independent registered public accounting firm 101

Group income statement 102

Group balance sheet 103

Group cash flow statement 104

Group statement of recognized income and expense 105

106 Notes on financial statements

1. Significant accounting policies 106

2. Resegmentation 114

3. Acquisitions 115

4. Non-current assets held for sale and discontinued 

operations 115

5. Disposals 116

6. Segmental analysis 118

7. Interest and other revenues 124

8. Gains on sale of businesses and fixed assets 124

9. Production and similar taxes 125

10. Depreciation, depletion and amortization 125

11. Impairment and losses on sale of businesses and fixed 

assets 126

12. Impairment review of goodwill 127

13. Distribution and administration expenses 130

14. Currency exchange gains and losses 130

15. Research and development 130

16. Operating leases 130

17. Exploration for and evaluation of oil and natural gas 

resources 131

18. Auditor’s remuneration 132

19. Finance costs 132

20. Taxation 133

21. Dividends 134

22. Earnings per ordinary share 135

23. Property, plant and equipment 136

24. Goodwill 137

 

25. Intangible assets 137

26. Investments in jointly controlled entities 138

27. Investments in associates 139

28. Financial instruments and financial risk factors 140

29. Other investments 146

30. Inventories 146

31. Trade and other receivables 146

32. Cash and cash equivalents 147

33. Trade and other payables 147

34. Derivative financial instruments 148

35. Finance debt 153

36. Capital disclosures and analysis of changes in net debt 155

37. Provisions 156

38. Pensions and other post-retirement benefits 157

39. Called-up share capital 163

40. Capital and reserves 164

41. Share-based payments 166

42. Employee costs and numbers 170

43. Remuneration of directors and senior management 171

44. Contingent liabilities 172

45. Capital commitments 172

46. Subsidiaries, jointly controlled entities and associates 173

47. Oil and natural gas exploration and production activities 175

178 Additional information for US 

reporting 

48. Auditor’s remuneration for US reporting 178

49. Valuation and qualifying accounts 179

50. Computation of ratio of earnings to fixed charges 

(unaudited) 

 179

51. Condensed consolidating information on certain US 

subsidiaries 179

185 Supplementary information on oil 

and natural gas (unaudited)

 

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Consolidated financial statements of the BP group

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of BP p.l.c. 

We have audited the accompanying group balance sheets of BP p.l.c. as of 31 December 2008 and 2007, and the related group statements of income, cash flows, 

and recognized income and expense, for each of the three years in the period ended 31 December 2008. These financial statements are the responsibility of the 

company’s management. Our responsibility is to express an opinion on these financial statements 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. An audit includes 

examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles 

used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a 

reasonable basis for our opinion. 

 In our opinion, the financial statements referred to above present fairly, in all material respects, the group financial position of BP p.l.c. at 31 December 2008 

and 2007, and the group results of operations and cash flows for each of the three years in the period ended 31 December 2008, in accordance with International 

Financial Reporting Standards as adopted by the European Union and International Financial Reporting Standards as issued by the International Accounting 

Standards Board. 

 We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of BP p.l.c.’s 

internal control over financial reporting as of 31 December 2008, based on criteria established in the Internal Control Revised Guidance for Directors on the 

Combined Code (Turnbull) as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull criteria) and our report dated 24 February 2009 

expressed an unqualified opinion thereon. 

/s/ERNST & YOUNG LLP 

Ernst & Young LLP 

London, England 

24 February 2009 

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of BP p.l.c. 

We have audited BP p.l.c.’s internal control over financial reporting as of 31 December 2008, based on criteria established in Internal Control-Revised Guidance for 

Directors on the Combined Code (Turnbull) as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull criteria). BP p.l.c.’s 

management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over 

financial reporting included in the accompanying Management’s report on internal control over financial reporting on page 95. Our responsibility is to express an 

opinion on the company’s internal control over financial reporting based on our audit. 

 We conducted our audit 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 effective internal control over financial reporting was maintained in all material 

respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and 

evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered 

necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 

 A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and 

the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over 

financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the 

transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of 

financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in 

accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of 

unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 

 Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of 

effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with 

the policies or procedures may deteriorate. 

 In our opinion, BP p.l.c. maintained, in all material respects, effective internal control over financial reporting as of 31 December 2008, based on the Turnbull 

criteria. 

 We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the group balance sheets of BP 

p.l.c. as of 31 December 2008 and 2007, and the related group statements of income, cash flows and recognized income and expense, for each of the three years 

in the period ended 31 December 2008, and our report dated 24 February 2009 expressed an unqualified opinion thereon. 

/s/ERNST & YOUNG LLP 

Ernst & Young LLP 

London, England 

24 February 2009 

100 

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Consent of independent registered public accounting firm

We consent to the incorporation by reference of our reports dated 24 February 2009 with respect to the group financial statements of BP p.l.c., and the 

effectiveness of internal control over financial reporting of BP p.l.c., included in this Annual Report (Form 20-F) for the year ended 31 December 2008 in the 

following registration statements: 

 Registration Statement on Form F-3 (File No. 333-155798) of BP p.l.c.; 

 Registration Statement on Form F-3 (File No. 333-110203) of 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. 333-149778, 333-79399, 333-67206, 333-102583, 333-103923, 333-103924, 333-119934, 333-123482, 333-

123483, 333-132619, 333-131584, 333-131583, 333-146868, 333-146870 and 333-146873) of BP p.l.c. 

/s/ERNST & YOUNG LLP 

Ernst & Young LLP 

London, England 

4 March 2009 

101

Consolidated financial statements of the BP group

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Group income statement 

102 

Consolidated financial statements of the BP group

 

 $ million 

For the year ended 31 December Note 2008 2007 2006 

Sales and other operating revenues 361,143 284,365 265,906

Earnings from jointly controlled entities – after interest and tax 3,023 3,135 3,553

Earnings from associates – after interest and tax 798 697 442 

Interest and other revenues 7 736 754 701

Total revenues 6 365,700 288,951 270,602

Gains on sale of businesses and fixed assets 8 1,353 2,487 3,714

Total revenues and other income 367,053 291,438 274,316 

Purchases 266,982 200,766 187,183

Production and manufacturing expenses 29,183 25,915 23,293

Production and similar taxes 9 6,526 4,013 3,621

Depreciation, depletion and amortization 10 10,985 10,579 9,128

Impairment and losses on sale of businesses and fixed assets 11 1,733 1,679 549 

Exploration expense 17 882 756 1,045

Distribution and administration expenses 13 15,412 15,371 14,447

Fair value (gain) loss on embedded derivatives 34 111 7 (608)

Profit before interest and taxation from continuing operations 35,239 32,352 35,658

Finance costs 19 1,547 1,393 986

Net finance income relating to pensions and other post-retirement benefits 38 (591) (652) (470)

Profit before taxation from continuing operations 34,283 31,611 35,142

Taxation 20 12,617 10,442 12,516

Profit from continuing operations 21,666 21,169 22,626

Loss from Innovene operations 4 – – (25)

Profit for the year 21,666 21,169 22,601

Attributable to

BP shareholders 21,157 20,845 22,315

Minority interest 509 324 286

 21,666 21,169 22,601

Earnings per share – cents

Profit for the year attributable to BP shareholders

Basic 22 112.59 108.76 111.41

Diluted 22 111.56 107.84 110.56

Profit from continuing operations attributable to BP shareholders

Basic 112.59 108.76 111.54

Diluted 111.56 107.84 110.68

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Group balance sheet 

P D Sutherland Chairman 

Dr A B Hayward Group Chief Executive 

103

Consolidated financial statements of the BP group

 

At 31 December $ million 

 Note 2008 2007 

Non-current assets

Property, plant and equipment 23 103,200 97,989

Goodwill 24 9,878 11,006 

Intangible assets 25 10,260 6,652

Investments in jointly controlled entities 26 23,826 18,113

Investments in associates 27 4,000 4,579

Other investments 29 855 1,830

Fixed assets 152,019 140,169

Loans 995 999 

Other receivables 31 710 968

Derivative financial instruments 34 5,054 3,741

Prepayments 1,338 1,083

Defined benefit pension plan surpluses 38 1,738 8,914

161,854 155,874

Current assets 

Loans 168 165

Inventories 30 16,821 26,554

Trade and other receivables 31 29,261 38,020 

Derivative financial instruments 34 8,510 6,321

Prepayments 3,050 3,589 

Current tax receivable 377 705

Cash and cash equivalents 32 8,197 3,562

66,384 78,916

Assets classified as held for sale 4 – 1,286

66,384 80,202

Total assets 228,238 236,076

Current liabilities

Trade and other payables 33 33,644 43,152 

Derivative financial instruments 34 8,977 6,405

Accruals 6,743 6,640

Finance debt 35 15,740 15,394

Current tax payable 3,144 3,282

Provisions 37 1,545 2,195 

69,793 77,068

Liabilities directly associated with the assets classified as held for sale 4 – 163

69,793 77,231

Non-current liabilities

Other payables 33 3,080 1,251

Derivative financial instruments 34 6,271 5,002

Accruals 784 959 

Finance debt 35 17,464 15,651

Deferred tax liabilities 20 16,198 19,215

Provisions 37 12,108 12,900

Defined benefit pension plan and other post-retirement benefit plan deficits 38 10,431 9,215

66,336 64,193

Total liabilities 136,129 141,424

Net assets 92,109 94,652 

Equity 

Share capital 39 5,176 5,237

Reserves 86,127 88,453 

BP shareholders’ equity 40 91,303 93,690 

Minority interest 40 806 962

Total equity 40 92,109 94,652

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Group cash flow statement 

104 

Consolidated financial statements of the BP group

 

For the year ended 31 December $ million 

 Note 2008 2007 2006 

Operating activities

Profit before taxation 34,283 31,611 35,142

Adjustments to reconcile profit before taxation to net cash provided by 

operating activities 

Exploration expenditure written off 17 385 347 624

Depreciation, depletion and amortization 10 10,985 10,579 9,128

Impairment and (gain) loss on sale of businesses and fixed assets 8,11 380 (808) (3,165)

Earnings from jointly controlled entities and associates (3,821) (3,832) (3,995)

Dividends received from jointly controlled entities and associates 3,728 2,473 4,495

Interest receivable (407) (489) (473)

Interest received 385 500 500

Finance costs 19 1,547 1,393 986

Interest paid (1,291) (1,363) (1,242)

Net finance income relating to pensions and other post-retirement benefits 38 (591) (652) (470)

Share-based payments 459 420 416

Net operating charge for pensions and other post-retirement benefits, less 

contributions and benefit payments for unfunded plans (173) (404) (261)

Net charge for provisions, less payments (298) (92) (160)

(Increase) decrease in inventories 9,010 (7,255) 995

(Increase) decrease in other current and non-current assets 2,439 5,210 3,596

Increase (decrease) in other current and non-current liabilities (6,101) (3,857) (4,211)

Income taxes paid (12,824) (9,072) (13,733)

Net cash provided by operating activities 38,095 24,709 28,172

Investing activities

Capital expenditure (22,658) (17,830) (15,125)

Acquisitions, net of cash acquired (395) (1,225) (229)

Investment in jointly controlled entities (1,009) (428) (37)

Investment in associates (81) (187) (570)

Proceeds from disposal of fixed assets 5 918 1,749 5,963

Proceeds from disposal of businesses, net of cash disposed 5 11 2,518 291

Proceeds from loan repayments 647 192 189

Other (200) 374 – 

Net cash used in investing activities (22,767) (14,837) (9,518)

Financing activities

Net repurchase of shares (2,567) (7,113) (15,151)

Proceeds from long-term financing 7,961 8,109 3,831 

Repayments of long-term financing (3,821) (3,192) (3,655)

Net increase (decrease) in short-term debt (1,315) 1,494 3,873 

Dividends paid

BP shareholders 21 (10,342) (8,106) (7,686)

Minority interest (425) (227) (283)

Net cash used in financing activities (10,509) (9,035) (19,071)

Currency translation differences relating to cash and cash equivalents (184) 135 47

Increase (decrease) in cash and cash equivalents 4,635 972 (370)

Cash and cash equivalents at beginning of year 3,562 2,590 2,960

Cash and cash equivalents at end of year 8,197 3,562 2,590 

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Group statement of recognized income and expense 

105

Consolidated financial statements of the BP group

 

For the year ended 31 December $ million 

2008 2007 2006 

Currency translation differences (4,362) 1,887 2,025

Exchange gain on translation of foreign operations transferred to gain or loss on sale of businesses and 

fixed assets – (147) – 

Actuarial (loss) gain relating to pensions and other post-retirement benefits (8,430) 1,717 2,615

Available-for-sale investments marked to market (994) 200 561

Available-for-sale investments – recycled to the income statement 526 (91) (695)

Cash flow hedges marked to market (1,173) 155 413

Cash flow hedges – recycled to the income statement 45 (74) (93)

Cash flow hedges – recycled to the balance sheet (38) (40) (6)

Tax on currency translation differences 100 139 (201)

Tax on actuarial (loss) gain relating to pensions and other post-retirement benefits 2,602 (427) (820)

Tax on available-for-sale investments 50 (14) 108

Tax on cash flow hedges 194 26 (47)

Tax on share-based payments (190) 213 26

Net (expense) income recognized directly in equity (11,670) 3,544 3,886

Profit for the year 21,666 21,169 22,601 

Total recognized income and expense for the year 9,996 24,713 26,487 

Attributable to 

BP shareholders 9,562 24,365 26,152

Minority interest 434 348 335 

 9,996 24,713 26,487 

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Notes on financial statements

 

106 

1. Significant accounting policies 

Authorization of financial statements and statement of compliance with 

International Financial Reporting Standards 

The consolidated financial statements of the BP group for the year ended 31 

December 2008 were authorized for issue by the board of directors on 24 

February 2009 and the balance sheet was signed on the board’s behalf by P 

D Sutherland and Dr A B Hayward. 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 (IFRS) as issued by the International Accounting 

Standards Board (IASB) and IFRS as adopted by the European Union (EU). 

IFRS as adopted by the EU differs in certain respects from IFRS as issued by 

the IASB, however, the differences have no impact on the group’s 

consolidated financial statements for the years presented. The significant 

accounting policies of the group are set out below.

Basis of preparation 

The consolidated financial statements have been prepared in accordance with 

IFRS and International Financial Reporting Interpretations Committee (IFRIC) 

interpretations issued and effective for the year ended 31 December 2008, or 

issued and early adopted. 

 Standards and interpretations adopted in the year had no significant 

impact on the financial statements. 

 Subsequent to releasing our preliminary announcement of the fourth 

quarter 2008 results on 3 February 2009, an adjustment has been made to 

correct for a $560 million overstatement of the deferred tax liability in the 

balance sheet as at 31 December 2008 with a corresponding adjustment to 

the foreign currency translation reserve in equity. There was no impact on 

profit for the year. 

 The accounting policies that follow have been consistently applied to all 

years presented. 

 The consolidated financial statements are presented in US dollars and 

all values are rounded to the nearest million dollars ($ million), except where 

otherwise indicated. 

 For further information regarding the key judgements and estimates 

made by management in applying the group’s accounting policies, refer to 

Critical accounting policies on pages 57 to 59, which forms part of these 

financial statements. 

Basis of consolidation 

The group financial statements consolidate the financial statements of BP 

p.l.c. and the entities it controls (its subsidiaries) drawn up to 31 December 

each year. Control comprises the power to govern the financial and operating 

policies of the investee so as to obtain benefit from its activities and is 

achieved through direct and indirect ownership of voting rights; currently 

exercisable or convertible potential voting rights; or by way of contractual 

agreement. Subsidiaries are consolidated from the date of their acquisition, 

being the date on which the group obtains control, and continue to be 

consolidated until the date that such control ceases. The financial statements 

of subsidiaries are prepared for the same reporting year as the parent 

company, using consistent accounting policies. All 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. 

Interests in joint ventures 

A joint venture is a contractual arrangement whereby two or more parties 

(venturers) undertake an economic activity that is subject to joint control. Joint 

control exists only when the strategic financial and operating decisions relating 

to the activity require the unanimous consent of the venturers. A jointly 

controlled entity is a joint venture that involves the establishment of a 

company, partnership or other entity to engage in economic activity that the 

group jointly controls with its fellow venturers. 

 The results, assets and liabilities of a jointly controlled entity are 

incorporated in these financial statements using the equity method of 

accounting. Under the equity method, the investment in a jointly controlled 

entity is carried in the balance sheet at cost, plus post-acquisition changes in 

the group’s share of net assets of the jointly controlled entity, less distributions 

received and less any impairment in value of the investment. Loans advanced 

to jointly controlled entities are also included in the investment on the group 

balance sheet. 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 assesses investments in jointly controlled entities for 

impairment whenever events or changes in circumstances indicate that the 

carrying value may not be recoverable. If any such indication of impairment 

exists, the carrying amount of the investment is compared with its recoverable 

amount, being the higher of its fair value less costs to sell and value in use. 

Where the carrying amount exceeds the recoverable amount, the investment 

is written down to its recoverable amount. 

 The group ceases to use the equity method of accounting on the date 

from which it no longer has joint control or significant influence over 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 that 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 as described 

above for jointly controlled entities. 

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107

Notes on financial statements

1. Significant accounting policies continued 

Foreign currency translation 

Functional currency is the currency of the primary economic environment in 

which an entity operates and is normally the currency in which the entity 

primarily generates and expends cash. 

 In individual companies, transactions in foreign currencies are initially 

recorded in the functional currency by applying the rate of exchange ruling at 

the date of the transaction. Monetary assets and liabilities denominated in 

foreign currencies are retranslated into the functional currency at the rate of 

exchange ruling at the balance sheet date. Any resulting exchange differences 

are included in the income statement. Non-monetary assets and liabilities that 

are measured at historical cost and denominated in a foreign currency are 

translated into the functional currency using the rates of exchange as at the 

dates of the initial transactions. Non-monetary assets and liabilities measured 

at fair value in a foreign currency are translated into the functional currency 

using the rate of exchange at the date the fair value was determined. 

 In the consolidated financial statements, the assets and liabilities of 

non-US dollar functional currency subsidiaries, jointly controlled entities and 

associates, including related goodwill, are translated into US dollars at the rate 

of exchange ruling at the balance sheet date. The results and cash flows of 

non-US dollar functional currency subsidiaries, jointly controlled entities and 

associates are translated into US dollars using average rates of exchange. 

Exchange adjustments arising when the opening net assets and the profits for 

the year retained by non-US dollar functional currency subsidiaries, jointly 

controlled entities and associates are translated into US dollars are taken to a 

separate component of equity and reported in the statement of recognized 

income and expense. Exchange gains and losses arising on long-term 

intragroup 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 purchase 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, liabilities and contingent liabilities 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 on the group balance 

sheet are allocated against the interests of the parent. 

 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. 

 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. 

Impairment is determined by assessing the recoverable amount of the cashgenerating unit to which the goodwill relates. Where the recoverable amount 

of the cash-generating unit is less than the carrying amount, an impairment 

loss is recognized. 

 Goodwill arising on business combinations prior to 1 January 2003 is 

stated at the previous carrying amount under UK generally accepted 

accounting practice. 

 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 earnings from jointly 

controlled entities and associates. 

Non-current assets held for sale 

Non-current assets and disposal groups classified as held for sale are 

measured at the lower of carrying amount and fair value less costs to sell. 

 Non-current assets and disposal groups are classified as held for sale if 

their carrying amounts will be recovered through a sale transaction rather than 

through continuing use. This condition is regarded as met only when the sale 

is highly probable and the asset or disposal group is available for immediate 

sale in its present condition. Management must be committed to the sale, 

which should be expected to qualify for recognition as a completed sale within 

one year from the date of classification. 

 Property, plant and equipment and intangible assets once classified as 

held for sale are not depreciated. 

Intangible assets 

Intangible assets, other than goodwill, include expenditure on the exploration 

for and evaluation of oil and natural gas resources, computer software, 

patents, licences and trademarks and are stated at the amount initially 

recognized, less accumulated amortization and accumulated impairment 

losses. 

 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 measured at fair value at the 

date of acquisition and 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. 

 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 shorter 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 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. 

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Notes on financial statements

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 licence and leasehold property acquisition costs are capitalized 

within intangible assets and are reviewed at each reporting date to confirm 

that there is no indication that the carrying amount exceeds the recoverable 

amount. This review includes confirming that exploration drilling is still under 

way or firmly planned or that it has been determined, or work is under way 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. If no future activity is 

planned, the remaining balance of the licence and property acquisition costs is 

written off. Lower value licences are pooled and amortized on a straight-line 

basis over the estimated period of exploration. Upon recognition of proved 

reserves and internal approval for development, 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 initially 

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 and is depreciated from the commencement of 

production as described below in the accounting policy for 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 fair value unless the exchange 

transaction lacks commercial substance or the fair value of neither the asset 

received nor the asset given up is reliably measurable. The cost of the 

acquired asset is measured at the fair value of the asset given up, unless the 

fair value of the asset received is more clearly evident. Where fair value is not 

used, the cost of the acquired asset is measured at the carrying amount of the 

asset given up. The gain or loss on derecognition of the asset given up is 

recognized in profit or loss. 

 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 is 

replaced and it is probable that future economic benefits associated with the 

item will flow to the group, the expenditure is capitalized and the carrying 

amount of the replaced asset is derecognized. 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, including related pipelines, are 

depreciated using a unit-of-production method. The cost of producing wells is 

amortized over proved developed reserves. Licence acquisition, field 

development and future decommissioning 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 approved future development expenditure required to develop reserves. 

 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: 

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. 

Land improvements 15 to 25 years

Buildings 20 to 50 years 

Refineries 20 to 30 years

Petrochemicals plants 20 to 30 years

Pipelines 10 to 50 years 

Service stations 15 years

Office equipment 3 to 7 years 

Fixtures and fittings 5 to 15 years

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Notes on financial statements

1. Significant accounting policies continued 

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, for example, low prices or margins for an 

extended period or for oil and gas assets significant downward revisions of 

estimated volumes or increases in estimated future development expenditure. 

If any such indication of impairment exists, the group makes an estimate of its 

recoverable amount. 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. An asset 

group’s recoverable amount is the higher of its fair value less costs to sell and 

its value in use. Where the carrying amount of an asset group exceeds its 

recoverable amount, the asset group is considered impaired and is written 

down to its recoverable amount. In assessing value in use, the estimated 

future cash flows are adjusted for the risks specific to the asset group and are 

discounted to their present value using a pre-tax discount rate that reflects 

current market assessments of the time value of money. 

 An assessment is made at each reporting date as to whether there is 

any indication that previously recognized impairment losses may no longer 

exist or may have decreased. If such indication exists, the recoverable amount 

is estimated. A previously recognized impairment loss is reversed only if there 

has been a change in the estimates used to determine the asset’s recoverable 

amount since the last impairment loss was recognized. If that is the case, the 

carrying amount of the asset is increased to its recoverable amount. That 

increased amount cannot exceed the carrying amount that would have been 

determined, net of depreciation, had no impairment loss been recognized for 

the asset in prior years. Such reversal is recognized in profit or loss. After 

such a reversal, the depreciation charge is adjusted in future periods to 

allocate the asset’s revised carrying amount, less any residual value, on a 

systematic basis over its remaining useful life. 

Financial assets 

Financial assets are classified as loans and receivables; available-for-sale 

financial assets; financial assets at fair value through profit or loss; or as 

derivatives designated as hedging instruments in an effective hedge, 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. Financial assets are recognized initially at fair 

value, normally being the transaction price plus, in the case of financial assets 

not at fair value through profit or loss, directly attributable transaction costs. 

 The subsequent measurement of financial assets depends on their 

classification, as follows: 

Loans and receivables 

Loans and receivables are non-derivative financial assets with fixed or 

determinable payments that are not quoted in an active market. 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. This category of financial assets includes 

trade and other receivables. 

Available-for-sale financial assets 

Available-for-sale financial assets are those non-derivative financial assets 

that are not classified as loans and receivables. After initial recognition, 

available-for-sale financial assets are measured at fair value, with gains or 

losses recognized as a separate component of equity until the investment is 

derecognized or impaired. 

 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. Where fair 

value cannot be reliably measured, assets are carried at cost. 

Financial assets at fair value through profit or loss 

Derivatives, other than those designated as effective hedging instruments, are 

classified as held for trading and are included in this category. These assets 

are carried on the balance sheet at fair value with gains or losses recognized 

in the income statement. 

Derivatives designated as hedging instruments in an effective hedge 

Such derivatives are carried on the balance sheet at fair value. The treatment 

of gains and losses arising from revaluation is described below in the 

accounting policy for Derivative financial instruments and hedging activities. 

Impairment of financial assets 

The group assesses at each balance sheet date whether a financial asset or 

group of financial assets is impaired. 

Loans and receivables 

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 profit or loss.

Available-for-sale financial assets 

If an available-for-sale financial asset is impaired, the cumulative gain or loss 

previously recognized in equity is transferred to the income statement. 

 If there is objective evidence that an impairment loss on an unquoted 

equity instrument that is carried at 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 current 

market rate of return for a similar financial asset. 

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 firstout method and comprises direct purchase costs, cost of production, 

transportation and manufacturing expenses. Net realizable value is 

determined by reference to prices existing at the balance sheet date. 

 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. 

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Notes on financial statements

1. Significant accounting policies continued 

Financial liabilities 

Financial liabilities are classified as financial liabilities at fair value through 

profit or loss; derivatives designated as hedging instruments in an effective 

hedge; or as financial liabilities measured at amortized cost, as appropriate. 

Financial liabilities include trade and other payables, accruals, finance debt 

and derivative financial instruments. The group determines the classification of 

its financial liabilities at initial recognition. The measurement of financial 

liabilities depends on their classification, as follows: 

Financial liabilities at fair value through profit or loss 

Derivatives, other than those designated as effective hedging instruments, are 

classified as held for trading and are included in this category. These liabilities 

are carried on the balance sheet at fair value with gains or losses recognized 

in the income statement. 

Derivatives designated as hedging instruments in an effective hedge 

Such derivatives are carried on the balance sheet at fair value, the treatment 

of gains and losses arising from revaluation are described below in the 

accounting policy for Derivative financial instruments and hedging activities. 

Financial liabilities measured at amortized cost 

All other financial liabilities are initially recognized at fair value. For interestbearing loans and borrowings this is the fair value of the proceeds received 

net of issue costs associated with the borrowing. 

 After initial recognition, other financial liabilities 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 finance costs. 

 This category of financial liabilities includes trade and other payables 

and finance debt. 

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 

commencement of the lease term at the fair value of the leased property or, if 

lower, at the present value of the minimum lease payments. Finance charges 

are allocated to each period so as to achieve a constant rate of interest on the 

remaining balance of the liability and 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. 

 For both finance and operating leases, contingent rents are recognized 

in the income statement in the period in which they are incurred. 

Derivative financial instruments and hedging activities 

The group uses derivative financial instruments to manage certain exposures 

to fluctuations in foreign currency exchange rates, interest rates and 

commodity prices as well as for trading purposes. Such derivative financial 

instruments are initially recognized at fair value on the date on which a 

derivative contract is entered into and are subsequently remeasured at fair 

value. Derivatives are carried as assets when the fair value is positive and as 

liabilities when the fair value is negative. 

Contracts to buy or sell a non-financial item that can be settled net in cash or 

another financial instrument, or by exchanging financial instruments, as if the 

contracts were financial instruments, with the exception of contracts that were 

entered into and continue to be held for the purpose of the receipt or delivery 

of a non-financial item in accordance with the group’s expected purchase, sale 

or usage requirements, are accounted for as financial instruments. 

 Gains or losses arising from changes in the fair value of derivatives that 

are not designated as effective hedging instruments are recognized in the 

income statement. 

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

At the inception of a hedge relationship the group formally designates and 

documents the hedge relationship for which the group wishes to claim hedge 

accounting, together with the risk management objective and strategy for 

undertaking the hedge. The documentation includes identification of the 

hedging instrument, the hedged item or transaction, the nature of the risk 

being hedged, and how the entity will assess the hedging instrument 

effectiveness in offsetting the exposure to changes in the hedged item’s fair 

value or cash flows attributable to the hedged item. Such hedges are expected 

at inception to be highly effective in achieving offsetting changes in fair value 

or cash flows. 

 Hedges meeting the criteria for hedge accounting are accounted for as 

follows: 

Fair value hedges 

The change in fair value of a hedging derivative is recognized in profit or loss. 

The change in the fair value of the hedged item attributable to the risk being 

hedged is recorded as part of the carrying value of the hedged item and is 

also recognized in profit or loss. 

 The group applies fair value hedge accounting for hedging fixed interest 

rate risk on borrowings. The gain or loss relating to the effective portion of the 

interest rate swap is recognized in the income statement within finance costs, 

offsetting the amortization of the interest on the underlying borrowings. 

 If the criteria for hedge accounting are no longer met, or if the group 

revokes the designation, the adjustment to the carrying amount of a hedged 

item for which the effective interest rate method is used is amortized to profit 

or loss over the period to maturity. 

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. The gain 

or loss relating to the effective portion of interest rate swaps hedging variable 

rate borrowings is recognized in the income statement within finance costs. 

 Where the hedged item is the cost of a non-financial asset or liability, 

such as a forecast transaction for the purchase of property, plant and 

equipment, the amounts taken to equity are transferred to the initial carrying 

amount of the non-financial asset or liability. 

 If the hedging instrument expires or is sold, terminated or exercised 

without replacement or rollover, or if its designation as a hedge is revoked, 

amounts previously recognized in equity remain in equity until the forecast 

transaction occurs and are transferred to the income statement or to the initial 

carrying amount of a non-financial asset or liability as above. If a forecast 

transaction is no longer expected to occur, amounts previously recognized in 

equity are transferred to profit or loss. 

• Fair value hedges when hedging 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.

• Hedges of a net investment in a foreign operation.

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Notes on financial statements

1. Significant accounting policies continued 

Hedges of a net investment in a foreign operation 

For hedges of a net investment in a foreign operation, 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 operation is 

sold or partially disposed. 

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 the host contract. Contracts are assessed for 

embedded derivatives when the group becomes a party to them, including at 

the date of a business combination. Embedded derivatives are measured at 

fair value at each balance sheet date. Any gains or losses arising from 

changes in fair value are taken directly to profit or loss. 

Provisions and contingencies 

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 appropriate, the future cash flow estimates are adjusted to reflect risks 

specific to the liability. 

 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. Where 

discounting is used, the increase in the provision due to the passage of time is 

recognized within finance costs. 

 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 reliably. Contingent assets are not recognized, but are 

disclosed where an inflow of economic benefits is probable. 

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 reliable 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 asset. 

 Other than the unwinding discount on the provision, any change in the 

present value of the estimated expenditure is reflected as an adjustment to the 

provision and the corresponding item of property, plant and equipment. 

Environmental expenditures and 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 a clean-up is 

probable and the associated costs can be reliably estimated. Generally, the 

timing of recognition of these provisions coincides with the commitment to a 

formal plan of action or, if earlier, on divestment or on closure of inactive sites. 

 The amount recognized is the best estimate of the expenditure required. 

Where the liability will not be settled for a number of years, the amount 

recognized is the present value of the estimated future expenditure. 

Employee benefits 

Wages, salaries, bonuses, social security contributions, paid annual leave and 

sick leave are accrued in the period in which the associated services are 

rendered by employees of the group. Deferred bonus arrangements that have 

a vesting date more than 12 months after the period end are valued on an 

actuarial basis using the projected unit credit method and amortized on a 

straight-line basis over the service period until the award vests. The 

accounting policy for pensions and other post-retirement benefits is described 

below. 

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 equity instruments 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 nonmarket conditions and the number of equity instruments that will ultimately 

vest or, in the case of an instrument subject to a market condition, be treated 

as vesting as described above. The movement in cumulative expense since 

the previous balance sheet date is recognized in the income statement, with a 

corresponding entry in equity. 

 Where the terms of an equity-settled award are modified or a new 

award is designated as replacing a cancelled or settled award, the cost based 

on the original award terms continues to be recognized over the original 

vesting period. In addition, an expense is recognized over the remainder of the 

new vesting period for the incremental fair value of any modification, based on 

the difference between the fair value of the original award and the fair value of 

the modified award, both as measured on the date of the modification. No 

reduction is recognized if this difference is negative. 

 Where an equity-settled award is cancelled, it is treated as if it had 

vested on the date of cancellation and any cost not yet recognized in the 

income statement for the award is expensed immediately. Any compensation 

paid up to the fair value of the award at the cancellation or settlement date is 

deducted from equity, with any excess over fair value being treated as an 

expense in the income statement. 

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Notes on financial statements

1. Significant accounting policies continued 

Cash-settled transactions

The cost of cash-settled transactions is measured at fair value and recognized 

as an expense over the vesting period, with a corresponding liability 

recognized on the balance sheet. 

Pensions and other post-retirement benefits 

The cost of providing benefits under the defined benefit plans is determined 

separately for each plan using the projected unit credit 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 the defined benefit obligation). Past service costs are recognized 

immediately when the company becomes committed to a change in pension 

plan design. 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 is 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 plan surplus or deficit 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 

the fair value of plan assets out of which the obligations are to be settled 

directly. Fair value is based on market price information and, in the case of 

quoted securities, is the published bid price. 

 Contributions to defined contribution schemes are recognized in the 

income statement in the period in which they become payable. 

Corporate taxes 

Income tax expense represents the sum of the tax currently payable and 

deferred tax. Interest and penalties relating to tax are also included in income 

tax expense. 

 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:

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: 

The carrying amount of deferred tax assets is reviewed at each balance sheet 

date and reduced to the extent that it is no longer probable that sufficient 

taxable profit will be available to allow all or part of the deferred income tax 

asset to be utilized. 

 Deferred tax assets and liabilities are measured at the tax rates that are 

expected to apply to the year when the asset is realized or the liability is 

settled, based on tax rates (and tax laws) that have been enacted or 

substantively enacted at the balance sheet date. 

 Tax relating to items recognized directly in equity is recognized in equity 

and not in the income statement. 

Customs duties and sales taxes 

Revenues, expenses and assets are recognized net of the amount of customs 

duties or sales tax except: 

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 holdings in its own equity instruments, including ordinary shares 

held by Employee Share Ownership Plans (ESOPs), are classified as 

‘treasury shares’, or ‘own shares’ for the ESOPs, and are 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 the profit and loss 

account reserve. No gain or loss is recognized in the income statement on the 

purchase, sale, issue or cancellation of equity shares. 

• 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.

• In respect of taxable temporary differences associated with investments in 

subsidiaries, jointly controlled entities and associates, except where the 

group is able to control the timing of the reversal of the temporary 

differences and it is probable that the temporary differences will not reverse 

in the foreseeable future.

• 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.

• 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.

• 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.

• Receivables and payables are stated with the amount of customs duty or 

sales tax included.

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113

Notes on financial statements

1. Significant accounting policies continued 

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, natural gas 

liquids, liquefied natural gas, petroleum and chemicals products and all other 

items are recognized when the title passes to the customer. Physical 

exchanges are reported net, as are sales and purchases made with a 

common counterparty, as part of an arrangement similar to a physical 

exchange. Similarly, where the group acts as agent on behalf of a third party 

to procure or market energy commodities, any associated fee income is 

recognized but no purchase or sale is recorded. Additionally, where forward 

sale and purchase contracts for oil, natural gas or power have been 

determined to be for trading purposes, the associated sales and purchases 

are reported net within sales and other operating revenues whether or not 

physical delivery has occurred. 

 Generally, revenues from the production of oil and natural gas 

properties in which the group has an interest with joint venture partners 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 that is the rate that exactly discounts estimated future 

cash receipts through the expected life of the financial instrument) to the net 

carrying amount of the financial asset. 

 Dividend income from investments is recognized when the 

shareholders’ right to receive the payment is established. 

Research 

Research costs are expensed as incurred. 

Finance costs 

Finance costs directly attributable to the acquisition, construction or production 

of qualifying assets, which are assets that necessarily take a substantial 

period of time to get ready for their intended use, are added to the cost of 

those assets, until such time as the assets are substantially ready for their 

intended use. 

 All other finance costs are recognized in the income statement in the 

period in which they are incurred. 

Use of estimates 

The preparation of financial statements requires management to make 

estimates and assumptions that affect the reported amounts of assets and 

liabilities as well as the disclosure of contingent assets and liabilities at the 

balance sheet date and the reported amounts of revenues and expenses 

during the reporting period. Actual outcomes could differ from those estimates.

Impact of new International Financial Reporting Standards 

Adopted for 2008 

Standards and interpretations adopted in the year had no significant impact on 

the financial statements. 

Not yet adopted 

The following pronouncements from the IASB will become effective for future 

financial reporting periods and have not yet been adopted by the group. 

 IFRS 8 ‘Operating Segments’ was issued in October 2006 and defines 

operating segments as components of an entity about which separate financial 

information is available and is evaluated regularly by the chief operating 

decision maker in deciding how to allocate resources and in assessing 

performance. The new standard sets out the required disclosures for operating 

segments and is effective for annual periods beginning on or after 1 

January 2009. BP will adopt the new standard with effect from 1 January 2009 

and expects no change to its segments that are separately reported but 

anticipates that its segmental analysis will be based on non-GAAP measures 

as used by the chief operating decision maker. There will be no effect on the 

group’s reported income or net assets. IFRS 8 has been adopted by the EU. 

 In September 2007, the IASB issued Amendments to IAS 1 

‘Presentation of Financial Statements’ – A Revised Presentation, which 

requires separate presentation of owner and non-owner changes in equity by 

introducing the statement of comprehensive income. The statement of 

recognized income and expense will no longer be presented. Whenever there 

is a restatement or reclassification, an additional balance sheet, as at the 

beginning of the earliest period presented, will be required to be published. 

The revised standard is effective for annual periods beginning on or after 1 

January 2009 and BP will adopt it from that date. There will be no effect on the 

group’s reported income or net assets. IAS 1 Revised has been adopted by 

the EU. 

 In January 2008, the IASB issued a revised version of IFRS 3 ‘Business 

Combinations’. The revised standard still requires the purchase method of 

accounting to be applied to business combinations but will introduce some 

changes to existing accounting treatment. For example, contingent 

consideration is measured at fair value at the date of acquisition and 

subsequently remeasured to fair value with changes recognized in profit or 

loss. Goodwill may be calculated based on the parent’s share of net assets or 

it may include goodwill related to the minority interest. All transaction costs are 

expensed. The standard is applicable to business combinations occurring in 

accounting periods beginning on or after 1 July 2009 and BP plans to adopt it 

with effect from 1 January 2010. Assets and liabilities arising from business 

combinations occurring before the date of adoption by the group will not be 

restated and thus there will be no effect on the group’s reported income or net 

assets on adoption. The revised standard has not yet been adopted by the 

EU. 

 Also in January 2008, the IASB issued an amended version of IAS 27 

‘Consolidated and Separate Financial Statements’. This requires the effects of 

all transactions with non-controlling interests to be recorded in equity if there is 

no change in control. Such transactions will no longer result in goodwill or 

gains or losses. When control is lost, any remaining interest in the entity is 

remeasured to fair value and a gain or loss recognized in profit or loss. The 

amendment is effective for annual periods beginning on or after 1 July 2009 

and is to be applied retrospectively, with certain exceptions. BP plans to adopt 

the amendment with effect from 1 January 2010 and has not yet completed its 

evaluation of the effect of adoption. The revised standard has not yet been 

adopted by the EU. 

 In addition, IFRIC 18 ‘Transfers of Assets from Customers’ was issued 

in January 2009 and is effective prospectively from 1 July 2009. BP has not 

yet completed its evaluation of the effect of adopting this interpretation. 

 There are no other standards and interpretations in issue but not yet 

adopted that the directors anticipate will have a material effect on the reported 

income or net assets of the group. 

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2. Resegmentation 

With effect from 1 January 2008 the organizational structure of BP has been simplified into two business segments – Exploration and Production and Refining and 

Marketing. A separate business, Alternative Energy, handles BP’s low-carbon businesses and future growth options outside oil and gas, including solar, wind, gasfired power, hydrogen, biofuels and coal conversion. 

 As a result, and with effect from 1 January 2008: 

As a result of the transfers identified above, Other businesses and corporate has been redefined. It now consists of the Alternative Energy business, Shipping, the 

group’s aluminium asset, Treasury (which includes interest income on the group’s cash and cash equivalents) and corporate activities worldwide. 

 Comparative amounts have been restated to reflect the resegmentation, as shown below. 

114 

Notes on financial statements

• The Gas, Power and Renewables segment ceased to report separately.

• The natural gas liquids (NGLs), liquefied natural gas and gas and power marketing and trading businesses were transferred from the Gas, Power and 

Renewables segment to the Exploration and Production segment.

• The Alternative Energy business was transferred from the Gas, Power and Renewables segment to Other businesses and corporate.

• The Emerging Consumers Marketing Unit was transferred from Refining and Marketing to Alternative Energy.

• The Biofuels business was transferred from Refining and Marketing to Alternative Energy.

• The Shipping business was transferred from Refining and Marketing to Other businesses and corporate.

 

$ million

2007

Gas, Other Consolidation

Exploration Refining Power businesses adjustment

and and and and and Total

By business - as reported Production Marketing Renewables corporate eliminations group 

Revenues 

Total revenues 57,941 251,538 21,725 1,010 (43,263) 288,951

Less: sales between businesses (38,803) (2,024) (2,436) – 43,263 –

Total third party revenues 19,138 249,514 19,289 1,010 – 288,951

Segment results

Profit (loss) before interest and tax 26,938 6,072 674 (1,128) (204) 32,352 

Segment assets and liabilities 

Segment assets 108,874 95,691 19,889 17,188 (6,271) 235,371

Segment liabilities (23,792) (41,053) (13,439) (14,940) 5,342 (87,882)

By business – as restated

Revenues

Total revenues 69,376 250,897 – 3,972 (35,294) 288,951

Less: sales between businesses (32,083) (1,914) – (1,297) 35,294 –

Total third party revenues 37,293 248,983 – 2,675 – 288,951

Segment results

Profit (loss) before interest and tax 27,729 6,076 – (1,233) (220) 32,352

Segment assets and liabilities

Segment assets 125,736 95,311 – 20,595 (6,271) 235,371

Segment liabilities (37,741) (41,409) – (14,074) 5,342 (87,882)

$ million

2006

Gas, Other Consolidation

Exploration Refining Power businesses adjustment Total

and and and and and Total Innovene continuing 

By business - as reported Production Marketing Renewables corporate eliminations group operations operations

Revenues

Total revenues 56,400 233,302 23,923 1,243 (44,266) 270,602 – 270,602

Less: sales between businesses (36,171) (4,076) (4,019) – 44,266 – – – 

Total third party revenues 20,229 229,226 19,904 1,243 – 270,602 – 270,602 

Segment results

Profit (loss) before interest and 

tax 29,629 5,541 1,321 (1,069) 52 35,474 184 35,658

By business – as restated

Revenues

Total revenues 71,868 232,833 – 3,703 (37,802) 270,602 – 270,602 

Less: sales between businesses (32,608) (3,935) – (1,259) 37,802 – – –

Total third party revenues 39,260 228,898 – 2,444 – 270,602 – 270,602

Segment results

Profit (loss) before interest and 

tax 30,953 5,419 – (963) 65 35,474 184 35,658 

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3. Acquisitions 

Acquisitions in 2008 

BP made a number of acquisitions in 2008 for a total consideration of $403 million. These business combinations were in the Exploration and Production segment 

and Other businesses and corporate and the most significant was the acquisition of Whiting Clean Energy, a cogeneration power plant. Fair value adjustments 

have been made on a provisional basis to the acquired assets and liabilities. Goodwill of $1 million has been recognized on these acquisitions. 

Acquisitions in 2007 

BP made a number of acquisitions in 2007 for a total consideration of $1,200 million. These business combinations were predominantly in the Refining and 

Marketing segment, the most significant of which was the acquisition of Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The 

acquisition included Chevron’s 31% minority shareholding in Nerefco, its 31% shareholding in the 22.5 MW wind farm co-located at the refinery as well as a 22.8% 

shareholding in the TEAM joint venture terminal and shareholdings in two local pipelines linking the TEAM terminal to the refinery. Fair value adjustments were 

made to the acquired assets and liabilities. Goodwill of $270 million arose on these acquisitions. 

Acquisitions in 2006 

BP made a number of acquisitions in 2006 for a total consideration of $256 million. All these business combinations were in Other businesses and corporate. Fair 

value adjustments were made to the acquired assets and liabilities and goodwill of $64 million arose on these acquisitions. 

4. Non-current assets held for sale and discontinued operations 

Non-current assets held for sale 

In December 2007, BP signed a memorandum of understanding with Husky Energy Inc. to form an integrated North American oil sands business. The transaction

was completed on 31 March 2008, with BP contributing its Toledo refinery to a US jointly controlled entity to which Husky contributed $250 million cash and a 

payable of $2,588 million. The Toledo refinery assets and associated liabilities were classified as a disposal group held for sale at 31 December 2007. No 

impairment loss was recognized at the time of reclassification of the Toledo disposal group as held for sale nor at 31 December 2007. For further information see 

Notes 5 and 26. 

 The major classes of assets and liabilities of the Toledo disposal group, reported within the Refining and Marketing segment, classified as held for sale at 31 

December 2007, are set out below. 

Discontinued operations 

The sale of Innovene, BP’s olefins, derivatives and refining group, to INEOS was completed on 16 December 2005. In 2006 a loss before taxation of $184 million 

was incurred which related to post-closing adjustments. These adjustments also reduced disposal proceeds by $34 million. 

 Financial information for the Innovene operations after group eliminations is presented below. 

Further information is contained in Note 5. 

115

Notes on financial statements

$ million

2007

Assets

Property, plant and equipment 635 

Goodwill 90

Inventories 561

Assets classified as held for sale 1,286

Liabilities 

Current liabilities 163

Liabilities directly associated with assets classified as held for sale 163

$ million

2006

Loss recognized on the remeasurement to fair value less costs to sell and on disposal (184)

Loss before taxation from Innovene operations (184)

Tax (charge) credit 

on loss before loss recognized on remeasurement to fair value less costs to sell and on disposal 166

on loss recognized on the remeasurement to fair value less costs to sell and on disposal (7)

Loss from Innovene operations (25)

Loss per share from Innovene operations – cents

Basic (0.13)

Diluted (0.12)

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5. Disposals 

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. The group may also dispose of other assets, such as refineries, when this meets strategic objectives. 

 Cash received during the year from disposals amounted to $929 million (2007 $4.3 billion and 2006 $6.3 billion). 

 The major transactions in 2008 were the disposal of our Toledo refinery to an entity which we jointly control in the US and our continued disposal of 

company-owned and company-operated retail sites in the US. 

 The major transactions in 2007 were the disposals of our Coryton refinery, our exploration and production and gas infrastructure business in the Netherlands, 

our interest in non-core Permian assets in the US and our interest in the Entrada field in the Gulf of Mexico. 

 The major transactions in 2006 were the disposals of our interests in the Gulf of Mexico Shelf and our interest in the Shenzi discovery in the Gulf of Mexico. 

The principal transactions for each business segment are described below. 

Exploration and Production 

The group divested interests in a number of oil and natural gas properties in all three years. There were no significant disposals in 2008. 

 During 2007, the major transactions were the disposal of an exploration and production and gas infrastructure business in the Netherlands and the 

divestments of our interests in non-core Permian assets in the US and in the Entrada field in the Gulf of Mexico. We also sold our interests in a number of fields in 

Egypt, Canada and the US. 

 During 2006, the major transactions were disposals of our interests in the Gulf of Mexico Shelf, in the Shenzi discovery in the Gulf of Mexico, in the Statfjord 

oil and gas field and in the Luva gas field in the North Sea. We also divested our interests in a number of onshore fields in South Louisiana, interests in fields in the 

North Sea, the Gulf of Suez and Venezuela, part of an interest in Colombia and our shareholding in Enagas, the Spanish gas transport grid operator. 

Refining and Marketing 

The churn of retail assets represents a significant element of the total in all three years and in particular, in 2008, our continued disposal of sites in the US. In 

addition, in 2008 we contributed our Toledo refinery to a US jointly controlled entity in an exchange transaction with Husky Energy and disposed of our interest in 

the Dixie Pipeline in the US, certain assets at our Acetyls plant in Hull, UK, and other interests in the UK and Europe. 

 During 2007, we disposed of the Coryton refinery in the UK, our interest in the West Texas Pipeline in the US, our interest in the Samsung Petrochemical 

Company in South Korea and other interests in France, Brazil and Africa. 

 During 2006, we disposed of our interests in Zhenhai Refining and Chemicals Company in China and in Eiffage, the French-based construction company. We 

also exited the retail market in the Czech Republic and disposed of our interests in a number of pipelines. 

116 

Notes on financial statements

 

 $ million 

2008 2007 2006 

Proceeds from the sale of Innovene operations – – (34)

Proceeds from the sale of other businesses 11 2,518 325

Proceeds from the sale of businesses 11 2,518 291

Proceeds from disposal of fixed assets 918 1,749 5,963 

 929 4,267 6,254

By business

Exploration and Production 19 1,280 4,302

Refining and Marketing 813 2,953 1,784 

Other businesses and corporate 97 34 168

 929 4,267 6,254

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5. Disposals continued 

Other businesses and corporate 

In 2008, the group disposed of miscellaneous non-core assets. 

 There were no significant disposals in 2007. During 2006, the group disposed of miscellaneous non-core businesses and assets. 

Summarized financial information for the sale of businesses is shown below. 

117

Notes on financial statements

$ million

2008 2007 2006

The disposals comprise the following

Non-current assets 759 753 143

Current assets 485 587 169

Non-current liabilities – (64) (10)

Current liabilities (134) (27) (70)

Total carrying amount of net assets disposed 1,110 1,249 232

Recycling of foreign exchange on disposal – (147) –

Costs on disposal 7 22 – 

 1,117 1,124 232 

Profit (loss) on sale of businessesa 1,721 1,384 167

Total consideration 2,838 2,508 399

Fair value of interest received in a jointly controlled entity (2,838) – – 

Consideration received (receivable)b 11 10 (74)

Closing adjustments associated with the sale of Innovene – – (34)

Proceeds from the sale of businessesc 11 2,518 291 

aOf which $929 million gain has not been recognized in the income statement in 2008 as it represents an unrealized gain on the transfer of the Toledo refinery into a jointly controlled entity.

bConsideration received from prior year disposals or not yet received from current year disposals.

cNet of cash and cash equivalents disposed of nil (2007 $115 million and 2006 $2 million).

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6. 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 internal financial reporting systems. 

 In 2008, BP had two reportable operating segments: Exploration and Production and Refining and Marketing. 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), as well as the marketing and trading of natural gas (including LNG), power and natural gas liquids (NGLs). The activities of Refining and Marketing 

include the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum and chemicals products and related services. The 

group is managed on an integrated basis. 

 Other businesses and corporate comprises the Alternative Energy business, Shipping, the group’s aluminium asset, Treasury (which in the segmental 

analysis includes all of the group’s cash, cash equivalents and associated interest income), and corporate activities worldwide. 

 The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. 

 Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and segment 

results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on consolidation, unless 

unrealized losses provide evidence of an impairment of the asset transferred. 

 The group’s geographical segments are based on the location of the group’s assets. The UK and the US are significant countries of activity for the group; the 

other geographical segments are groupings of countries 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. 

118 

Notes on financial statements

 $ million

 2008

 Other Consolidation 

Exploration Refining businesses adjustment

and and and and Total

By business Production Marketing corporate eliminations group

Sales and other operating revenues 

Segment sales and other operating revenues 86,170 320,039 4,634 (49,700) 361,143

Less: sales between businesses (45,931) (1,918) (1,851) 49,700 –

Third party sales 40,239 318,121 2,783 – 361,143

Equity-accounted earnings 3,565 131 125 – 3,821

Interest and other revenues 167 288 281 – 736

Total revenues 43,971 318,540 3,189 – 365,700

Segment results

Profit (loss) before interest and taxation 37,915 (1,884) (1,258) 466 35,239

Finance costs and net finance income relating to pensions and other post-retirement 

benefits – – – (956) (956)

Profit (loss) before taxation 37,915 (1,884) (1,258) (490) 34,283

Taxation – – – (12,617) (12,617)

Profit (loss) for the year 37,915 (1,884) (1,258) (13,107) 21,666

Assets and liabilities

Segment assets 136,665 75,329 19,079 (3,212) 227,861

Current tax receivable – – – 377 377

Total assets 136,665 75,329 19,079 (2,835) 228,238

Includes 

Equity-accounted investments 20,131 6,622 1,073 – 27,826

Segment liabilities (39,611) (28,668) (18,218) 2,914 (83,583)

Current tax payable – – – (3,144) (3,144)

Finance debt – – – (33,204) (33,204)

Deferred tax liabilities – – – (16,198) (16,198)

Total liabilities (39,611) (28,668) (18,218) (49,632) (136,129)

Other segment information

Capital expenditure and acquisitions 

Goodwill and other intangible assets 4,940 145 89 – 5,174

Property, plant and equipment 14,117 4,417 959 – 19,493

Other 3,170 2,072 791 – 6,033

Total 22,227 6,634 1,839 – 30,700

Depreciation, depletion and amortization 8,440 2,208 337 – 10,985

Impairment losses 1,186 159 227 – 1,572

Impairment reversals 155 – – – 155

Losses on sale of businesses and fixed assets 18 297 1 – 316

Gains on sale of businesses and fixed assets 34 1,258 61 – 1,353

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6. Segmental analysis continued 

119

Notes on financial statements

$ million

2007

Other Consolidation

Exploration Refining businesses adjustment

 and and and and Total 

By business Production Marketing corporate eliminations group

Sales and other operating revenues

Segment sales and other operating revenues 65,740 250,221 3,698 (35,294) 284,365

Less: sales between businesses (32,083) (1,914) (1,297) 35,294 – 

Third party sales 33,657 248,307 2,401 – 284,365 

Equity-accounted earnings 3,199 542 91 – 3,832

Interest and other revenues 437 134 183 – 754

Total revenues 37,293 248,983 2,675 – 288,951 

Segment results 

Profit (loss) before interest and taxation 27,729 6,076 (1,233) (220) 32,352

Finance costs and net finance income relating to pensions and other postretirement benefits – – – (741) (741)

Profit (loss) before taxation 27,729 6,076 (1,233) (961) 31,611 

Taxation – – – (10,442) (10,442)

Profit (loss) for the year 27,729 6,076 (1,233) (11,403) 21,169

Assets and liabilities

Segment assets 125,736 95,311 20,595 (6,271) 235,371

Current tax receivable – – – 705 705

Total assets 125,736 95,311 20,595 (5,566) 236,076

Includes

Equity-accounted investments 16,770 5,268 654 – 22,692 

Segment liabilities (37,741) (41,409) (14,074) 5,342 (87,882)

Current tax payable – – – (3,282) (3,282)

Finance debt – – – (31,045) (31,045)

Deferred tax liabilities – – – (19,215) (19,215)

Total liabilities (37,741) (41,409) (14,074) (48,200) (141,424)

Other segment information

Capital expenditure and acquisitions

Goodwill and other intangible assets 2,245 581 27 – 2,853

Property, plant and equipment 11,539 4,474 874 – 16,887

Other 423 440 38 – 901

Total 14,207 5,495 939 – 20,641

Depreciation, depletion and amortization 7,856 2,421 302 – 10,579

Impairment losses 292 1,186 83 – 1,561

Impairment reversals 237 – – – 237

Losses on sale of businesses and fixed assets 42 313 – – 355 

Gains on sale of businesses and fixed assets 954 1,464 69 – 2,487

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6. Segmental analysis continued 

120 

Notes on financial statements

$ million

2006

Other Consolidation

Exploration Refining businesses adjustment Total

and and and and Total Innovene continuing

By business Production Marketing corporate eliminations group operations operations

Sales and other operating revenues

Segment sales and other operating revenues 67,950 232,386 3,372 (37,802) 265,906 – 265,906

Less: sales between businesses (32,608) (3,935) (1,259) 37,802 – – – 

Third party sales 35,342 228,451 2,113 – 265,906 – 265,906 

Equity-accounted earnings 3,568 341 86 – 3,995 – 3,995

Interest and other revenues 350 106 245 – 701 – 701

Total revenues 39,260 228,898 2,444 – 270,602 – 270,602 

Segment results 

Profit (loss) before interest and taxation 30,953 5,419 (963) 65 35,474 184 35,658

Finance costs and net finance income relating to pensions 

and other post-retirement benefits – – – (516) (516) – (516)

Profit (loss) before taxation 30,953 5,419 (963) (451) 34,958 184 35,142 

Taxation – – – (12,357) (12,357) (159) (12,516)

Profit (loss) for the year 30,953 5,419 (963) (12,808) 22,601 25 22,626

Other segment information

Depreciation, depletion and amortization 6,689 2,239 200 – 9,128 – 9,128

Impairment losses 237 155 69 – 461 – 461

Impairment reversals 340 – – – 340 – 340

Loss on remeasurement to fair value less costs to sell and 

on disposal of Innovene operations – – 184 – 184 (184) –

Losses on sale of businesses and fixed assets 195 228 5 – 428 – 428

Gains on sale of businesses and fixed assets 2,502 1,109 103 – 3,714 – 3,714

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6. Segmental analysis continued 

121

Notes on financial statements

$ million

2008

Consolidation

adjustment

 Rest of Rest of and 

By geographical area UK Europe US World eliminations Total

Sales and other operating revenues

Segment sales and other operating revenues 150,133 93,303 130,142 105,911 – 479,489

Less: sales between areas (68,360) (11,272) (6,778) (31,936) – (118,346)

Third party sales 81,773 82,031 123,364 73,975 – 361,143

Equity-accounted earnings (4) 74 (14) 3,765 – 3,821

Interest and other revenues 55 226 193 262 – 736

Total revenues 81,824 82,331 123,543 78,002 – 365,700

Segment results 

Profit before interest and taxation 5,808 1,541 7,831 20,059 – 35,239

Finance costs and net finance income relating to pensions and 

other post-retirement benefits (22) (316) (411) (207) – (956)

Profit before taxation 5,786 1,225 7,420 19,852 – 34,283

Taxation (2,867) (576) (2,336) (6,838) – (12,617)

Profit for the year 2,919 649 5,084 13,014 – 21,666

Assets and liabilities

Segment assets 40,693 27,999 87,364 80,090 (8,285) 227,861

Current tax receivable 1 187 125 64 – 377

Total assets 40,694 28,186 87,489 80,154 (8,285) 228,238

Includes

Equity-accounted investments 92 1,873 3,790 22,071 – 27,826

Segment liabilities (23,767) (14,319) (33,099) (20,683) 8,285 (83,583)

Current tax payable (438) (399) (881) (1,426) – (3,144)

Finance debt (22,621) (201) (7,659) (2,723) – (33,204)

Deferred tax liabilities (2,031) (862) (8,916) (4,389) – (16,198)

Total liabilities (48,857) (15,781) (50,555) (29,221) 8,285 (136,129)

Other segment information

Capital expenditure and acquisitions

Goodwill and other intangible assets 277 19 3,794 1,084 – 5,174

Property, plant and equipment 1,279 2,043 9,655 6,516 – 19,493

Other 52 125 2,597 3,259 – 6,033

Total 1,608 2,187 16,046 10,859 – 30,700

Depreciation, depletion and amortization 1,610 997 3,969 4,409 – 10,985

Exploration expense 121 1 306 454 – 882

Impairment losses 97 104 392 979 – 1,572

Impairment reversals – – 9 146 – 155

Losses on sale of businesses and fixed assets 1 23 259 33 – 316

Gains on sale of businesses and fixed assets 74 49 1,209 21 – 1,353

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6. Segmental analysis continued 

122 

Notes on financial statements

$ million

2007

Consolidation

adjustment

 Rest of Rest of and 

By geographical area UK Europe US World eliminations Total

Sales and other operating revenues

Segment sales and other operating revenues 109,800 78,366 105,120 74,462 – 367,748

Less: sales between areas (48,651) (12,024) (2,801) (19,907) – (83,383)

Third party sales 61,149 66,342 102,319 54,555 – 284,365 

Equity-accounted earnings 1 55 144 3,632 – 3,832

Interest and other revenues 222 78 142 312 – 754

Total revenues 61,372 66,475 102,605 58,499 – 288,951 

Segment results 

Profit before interest and taxation 4,613 4,164 7,439 16,136 – 32,352

Finance costs and net finance income relating to pensions and 

other post-retirement benefits (17) (287) (524) 87 – (741)

Profit before taxation 4,596 3,877 6,915 16,223 – 31,611 

Taxation (2,027) (949) (2,593) (4,873) – (10,442)

Profit for the year 2,569 2,928 4,322 11,350 – 21,169

Assets and liabilities

Segment assets 53,065 34,658 81,911 76,504 (10,767) 235,371

Current tax receivable 3 27 468 207 – 705

Total assets 53,068 34,685 82,379 76,711 (10,767) 236,076

Includes

Equity-accounted investments 142 1,970 1,659 18,921 – 22,692 

Segment liabilities (30,043) (18,985) (31,314) (18,307) 10,767 (87,882)

Current tax payable (963) (658) (104) (1,557) – (3,282)

Finance debt (20,085) (200) (8,238) (2,522) – (31,045)

Deferred tax liabilities (3,397) (1,124) (10,656) (4,038) – (19,215)

Total liabilities (54,488) (20,967) (50,312) (26,424) 10,767 (141,424)

Other segment information

Capital expenditure and acquisitions

Goodwill and other intangible assets 453 298 817 1,285 – 2,853

Property, plant and equipment 1,141 2,489 6,516 6,741 – 16,887

Other 78 253 154 416 – 901

Total 1,672 3,040 7,487 8,442 – 20,641

Depreciation, depletion and amortization 2,133 959 3,558 3,929 – 10,579

Exploration expense 46 – 252 458 – 756

Impairment losses 315 136 723 387 – 1,561

Impairment reversals – – 237 – – 237 

Losses on sale of businesses and fixed assets 2 77 233 43 – 355

Gains on sale of businesses and fixed assets 893 655 770 169 – 2,487

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6. Segmental analysis continued 

123

Notes on financial statements

$ million

2006

Rest of Rest of

By geographical area UK Europe US World Total 

Sales and other operating revenues 

Segment sales and other operating revenues 105,518 76,768 99,935 71,547 353,768

Less: sales between areas (50,942) (14,821) (5,032) (17,067) (87,862)

Third party sales 54,576 61,947 94,903 54,480 265,906

Equity-accounted earnings 5 13 127 3,850 3,995 

Interest and other revenues 258 7 107 329 701

Total revenues 54,839 61,967 95,137 58,659 270,602

Segment results

Profit before interest and taxation from continuing operations 5,897 3,282 11,664 14,815 35,658 

Finance costs and net finance income relating to pensions and other postretirement benefits 43 (262) (331) 34 (516)

Profit before taxation from continuing operations 5,940 3,020 11,333 14,849 35,142

Taxation (3,158) (1,176) (3,738) (4,444) (12,516)

Profit for the year from continuing operations 2,782 1,844 7,595 10,405 22,626

Profit (loss) from Innovene operations 31 (76) (2) 22 (25)

Profit for the year 2,813 1,768 7,593 10,427 22,601

Other segment information 

Depreciation, depletion and amortization 2,139 840 3,459 2,690 9,128 

Exploration expense 20 – 633 392 1,045

Impairment losses – 171 114 176 461 

Impairment reversals 176 – 90 74 340

Loss on remeasurement to fair value less costs to sell and on disposal of 

Innovene operations 185 36 (16) (21) 184 

Losses on sale of businesses and fixed assets 12 96 217 103 428

Gains on sale of businesses and fixed assets 337 577 2,530 270 3,714 

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7. Interest and other revenues 

8. Gains on sale of businesses and fixed assets 

The principal transactions giving rise to these gains for each business segment are described below. 

Exploration and Production 

The group divested interests in a number of oil and natural gas properties in all three years. There were no significant divestments during 2008. 

 The major divestments during 2007 that resulted in gains were the disposal of an exploration and production and gas infrastructure business in the 

Netherlands and the divestments of our interests in non-core Permian assets in the US and in the Entrada field in the Gulf of Mexico. 

 The major divestments during 2006 that resulted in gains were the sales of our interest in the Shenzi discovery in the Gulf of Mexico in the US, interests in 

the North Sea and our shareholding in Enagas. 

Refining and Marketing 

During 2008, the major divestments that resulted in gains were the disposal of US retail assets, the contribution of Toledo refinery to a jointly controlled entity with 

Husky Energy and the disposal of our interest in the Dixie Pipeline. 

 During 2007, the major transactions that resulted in gains were the divestment of Coryton refinery in the UK, the interest in the West Texas Pipeline in the US 

and the interest in the Samsung Petrochemical Company in South Korea. 

 During 2006, the major transactions that resulted in gains were the divestment of the retail business in the Czech Republic and fixed assets including the 

shareholding in Zhenhai Refining and Chemicals Company in China, the shareholding in Eiffage, the French-based construction company, and pipeline assets. 

Other businesses and corporate 

There were no significant disposals in 2008 and 2007. 

 During 2006, the group disposed of its ethylene oxide business. 

Additional information on the sale of businesses and fixed assets is given in Note 5. 

124 

Notes on financial statements

 

 $ million 

2008 2007 2006 

Related to financial instruments

Interest income from available-for-sale financial assets 32 5 13

Dividend income from available-for-sale financial assets 37 29 32 

Interest income from loans and receivables 163 175 186

232 209 231

Not related to financial instruments

Interest from loans to equity-accounted entities 115 172 176 

Other interest 59 97 62

Other income 330 276 232

 504 545 470 

 736 754 701 

$ million

2008 2007 2006

Gains on sale of businesses

Exploration and Production – 527 –

Refining and Marketing 792 850 101

Other businesses and corporate – 7 66

792 1,384 167

Gains on sale of fixed assets

Exploration and Production 34 427 2,502

Refining and Marketing 466 614 1,008

Other businesses and corporate 61 62 37 

561 1,103 3,547

 1,353 2,487 3,714

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9. Production and similar taxes 

10. Depreciation, depletion and amortization 

125

Notes on financial statements

 

 $ million 

2008 2007 2006 

UK 370 197 260 

Overseas 6,156 3,816 3,361

6,526 4,013 3,621

$ million

By business 2008 2007 2006

Exploration and Productiona

UK 1,168 1,698 1,735 

Rest of Europe 203 213 225

US 3,012 2,365 2,336 

Rest of World 4,057 3,580 2,393

8,440 7,856 6,689

Refining and Marketing

UKb 288 278 299 

Rest of Europe 761 729 603

US 825 1,076 1,047

Rest of World 334 338 290

2,208 2,421 2,239

Other businesses and corporate

UK 154 157 105

Rest of Europe 33 17 12

US 132 117 76

Rest of World 18 11 7 

 337 302 200 

By geographical area

UKb 1,610 2,133 2,139

Rest of Europe 997 959 840

US 3,969 3,558 3,459

Rest of World 4,409 3,929 2,690 

 10,985 10,579 9,128 

aAt the end of 2006, BP adopted the US Securities and Exchange Commission (SEC) rules for estimating oil and natural gas reserves instead of the UK accounting rules contained in the Statement of Recommended 

Practice ‘Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities’ (UK SORP). This change in accounting estimate had a direct impact on the amount of depreciation, 

depletion and amortization (DD&A) charged in the income statement in respect of oil and natural gas properties which are depreciated on a unit-of-production basis as described in Note 1. The change in estimate was 

applied prospectively, with no restatement of prior periods’ results. The group’s actual DD&A charge for 2006 was $9,128 million, whereas the charge based on UK SORP reserves would have been $9,057 million, i.e. 

an increase of $71 million due to the change in reserves estimates that was used to calculate DD&A for the last three months of 2006. For 2007, it was estimated that the DD&A charge would have increased by 

approximately $400 million to $500 million as a result of the change. No estimate has been made in respect of 2008. Over the life of a field, this change has no overall effect on DD&A. The main differences between the 

UK SORP and SEC rules relate to the SEC requirement to use year-end prices and costs, the application of 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) within proved reserves. Consequently, reserves quantities under SEC rules differ from those that would be 

reported under application of the UK SORP. The change to SEC reserves in 2006 represented a simplification of the group’s reserves reporting, as only one set of reserves estimates is disclosed. In addition, the use of 

SEC reserves for accounting purposes makes our results more comparable with those of our major competitors. 

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

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11. Impairment and losses on sale of businesses and fixed assets 

Impairment 

In assessing whether a write-down is required in the carrying value of a potentially impaired intangible asset, item of property, plant and equipment or an equityaccounted investment, 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 estimates value in use using a discounted cash flow model. The future cash flows are adjusted for risks specific to the asset and are discounted 

using a pre-tax discount rate. This discount rate is derived from the group’s post-tax weighted average cost of capital and is adjusted where applicable to take into 

account any specific risks relating to the country where the cash-generating unit is located. Typically rates of 11% or 13% are used (2007 11% or 13%). The rate to 

be applied for each country is reassessed each year. For impairments of available-for-sale financial assets that are quoted investments, the fair value is determined 

by reference to bid prices at the close of business at the balance sheet date. Any cumulative gain or loss previously recognized in equity is transferred to the 

income statement. 

Exploration and Production 

During 2008, the Exploration and Production segment recognized impairment losses of $1,186 million. The main elements were the writing down of our investment 

in Rosneft by $517 million to its fair value determined by reference to an active market, due to a significant decline in the market value of the investment, 

impairment of oil and gas properties in the Gulf of Mexico of $270 million triggered by downward revisions of reserves, an impairment of exploration assets in 

Vietnam of $210 million following BP’s decision to withdraw from activities in the area concerned, impairment of oil and gas properties in Egypt of $85 million 

triggered by cost increases and several other individually insignificant impairment charges amounting to $104 million. 

 These charges were partly offset by reversals of previously recognized impairment charges amounting to $155 million. Of this total, $122 million resulted from 

a reassessment of the economics of Rhourde El Baguel in Algeria. 

 During 2007, the Exploration and Production segment recognized impairment losses of $292 million. The main elements were a charge of $112 million 

relating to the cancellation of the DF1 project in Scotland, a $103 million partner loan write-off as a result of unsuccessful drilling in the West Shmidt licence block in 

Sakhalin and a $52 million write-off of the Whitney Canyon gas plant in US Lower 48 driven by management’s decision to abandon this facility. In addition, there 

were several individually insignificant impairment charges, triggered by downward reserves revisions, amounting to $25 million in total. 

 These charges were largely offset by reversals of previously recognized impairment charges amounting to $237 million. Of this total, $208 million resulted 

from a reassessment of the decommissioning liability for damaged platforms in the Gulf of Mexico Shelf. The remaining $29 million related to other individually 

insignificant impairment reversals, resulting from favourable revisions to the estimates used in determining the assets’ recoverable amounts. 

 During 2006, Exploration and Production recognized a net gain on impairment. The main element was a $340 million credit for reversals of previously booked 

impairments relating to the UK North Sea, US Lower 48 and China. These reversals resulted from a positive change in the estimates used to determine the assets’ 

recoverable amount since the impairment losses were recognized. This was partially offset by impairment losses totalling $237 million. The major element was a 

charge of $109 million against intangible assets relating to properties in Alaska. The trigger for the impairment test was the decision of the Alaska Department of 

Natural Resources to terminate the Point Thompson Unit Agreement. We are defending our right through the appeal process. In addition, there was a charge of 

$100 million relating to certain North American pipeline assets. The trigger for impairment testing was the reduction in future pipeline tariff revenues and increased 

ongoing operational costs. The remaining $28 million relates to other individually insignificant impairments, the impairment tests for which were triggered by 

downward reserves revisions and increased tax burden. 

126 

Notes on financial statements

 

 $ million 

2008 2007 2006 

Impairment losses 

Exploration and Production 1,186 292 237

Refining and Marketing 159 1,186 155

Other businesses and corporate 227 83 69

1,572 1,561 461

Impairment reversals

Exploration and Production (155) (237) (340)

 (155) (237) (340)

Loss on sale of fixed assets 

Exploration and Production 18 42 195

Refining and Marketing 297 313 228 

Other businesses and corporate 1 – 5

316 355 428

Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations – – 184

 1,733 1,679 733 

Innovene operations – – (184)

Continuing operations 1,733 1,679 549

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11. Impairment and losses on sale of businesses and fixed assets continued 

Refining and Marketing 

During 2008, the Refining and Marketing segment recognized impairment losses on a number of assets which in total amounted to $159 million. 

 The main component of the 2007 impairment charge of $1,186 million arose because of a decision to sell our company-owned and company-operated sites 

in the US resulting in a $610 million write-down of the carrying amount of the sites to fair value less costs to sell. Following a decision to sell certain assets at our 

Acetyls plant in Hull, UK, we wrote down the carrying amount of these assets to fair value less costs to sell leading to an impairment charge of $186 million. 

Changing marketing conditions led to impairments in Samsung Petrochemical Company, to fair value less costs to sell, and in China American Petrochemical 

Company amounting in total to $165 million. The balance relates principally to the write-downs of assets elsewhere in the segment portfolio. 

 During 2006, certain assets in our Retail and Aromatics & Acetyls businesses were written down to fair value less costs to sell. 

Other businesses and corporate 

During 2008, Other businesses and corporate recognized impairment losses totalling $227 million primarily related to various assets in the Alternative Energy 

business. 

 There were no significant impairments in 2007. 

 The impairment charge for 2006 relates to remaining chemical assets after the sale of Innovene. 

Loss on sale of fixed assets

The principal transactions that give rise to the losses for each business 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 2006, the largest component of the loss is attributed to the sale of 

properties in the Gulf of Mexico Shelf, which included increases in decommissioning liability estimates associated with the hurricane-damaged fields that were 

divested during the year. 

Refining and Marketing 

For 2008, the principal transactions contributing to the loss were disposals of retail sites in the US and Europe. 

 For 2007, the principal transactions contributing to the loss were related to the decision to withdraw from the company-owned and company-operated 

channel of trade in the US and retail churn. Retail churn is the overall process of acquiring and disposing of retail sites by which the group aims to improve the 

quality and mix of its portfolio of service stations. 

 For 2006, the principal transactions contributing to the loss were retail churn. 

12. Impairment review of goodwill 

Goodwill acquired through business combinations has been allocated to groups of cash-generating units (cash-generating units) that are 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 the Rhine Fuels Value Chain (FVC), US West Coast FVC, Lubricants and Other. 

 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 calculates the recoverable amount as the value in use using a discounted cash flow model. The future cash flows are adjusted for risks specific to 

the cash-generating unit and are discounted using a pre-tax discount rate. The discount rate is derived from the group’s post-tax weighted average cost of capital 

and is adjusted where applicable to take into account any specific risks relating to the country where the cash-generating unit is located. Typically rates of 11% or 

13% are used (2007 11% or 13%). The rate to be applied to each country is reassessed each year. A discount rate of 11% has been used for all goodwill 

impairment calculations performed in 2008 (2007 11%). 

 The three-year or four-year business segment plans, which are approved on an annual basis by senior management, are the primary source of information 

for the determination of value in use. They contain 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 in the preparation of these plans, 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 

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 Brent oil price assumption is an average $49 per barrel in 2009, $59 per barrel in 2010, $65 per barrel in 

2011, $68 per barrel in 2012, $70 per barrel in 2013 and $75 per barrel in 2014 and beyond (2007 average $90 per barrel in 2008, $86 per barrel in 2009, $84 per 

barrel in 2010, $84 per barrel in 2011, $84 per barrel in 2012 and $60 per barrel in 2013 and beyond). Similarly, the 

127

Notes on financial statements

$ million

Goodwill at 31 December 2008 2007

Exploration and Production 4,297 4,296

Refining and Marketing 5,462 6,626

Other businesses and corporate 119 84

 9,878 11,006

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12. Impairment review of goodwill continued 

group’s assumption for Henry Hub natural gas prices is an average of $6.16/mmBtu in 2009, $7.15/mmBtu in 2010, $7.34/mmBtu in 2011, $7.62/mmBtu in 2012, 

$7.60/mmBtu in 2013 and $7.50/mmBtu in 2014 and beyond (2007 average of $7.87/mmBtu in 2008, $8.33/mmBtu in 2009, $8.26/mmBtu in 2010, $8.12/mmBtu in 

2011, $8.00/mmBtu in 2012 and $7.50/mmBtu in 2013 and beyond). The prices for the first five years are derived from forward price curves at the year-end. Prices 

in 2014 and beyond are determined using long-term views of global supply and demand, building upon past experience of the industry and consistent with a 

number of external economic forecasts. 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. Management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to 

assess goodwill and individual assets for impairment, as the production profile and related cash flows can be estimated from the company’s past experience. 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. Capital expenditure and operating costs for the first four years and expected hydrocarbon production profiles up to 2020 are derived from the business 

segment plan. Estimated production quantities and cash flows up to the date of cessation of production on a field-by-field basis are developed to be consistent with 

this. The production profiles used are consistent with the resource volumes approved as part of BP’s centrally-controlled process for the estimation of proved 

reserves and total resources. 

 Consistent with prior years, the 2008 review for impairment was carried out during the fourth quarter. Detailed calculations were performed for the US and the 

UK. As permitted by IAS 36, the detailed calculations performed in 2005 were used for the 2008 impairment test on the goodwill for the Rest of World as the criteria 

of IAS 36 were considered to be satisfied: the excess of the recoverable amount over the carrying amount was substantial in 2005; there had been no significant 

change in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount at the time of the test was remote. 

 The following table shows the carrying amount of the goodwill allocated to each of the regions of the Exploration and Production segment and, for the US and 

the UK, the amount by which the recoverable amount (value in use) exceeds the carrying amount of the goodwill and other non-current assets in the cashgenerating units to which the goodwill has been allocated. No impairment charge is required. 

 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 non-current assets (the headroom) to changes in production 

volumes and oil and natural gas prices, management has developed ‘rules of thumb’ for key assumptions. Applying these gives an indication of the impact on the 

headroom of possible changes in the key assumptions. 

 It is estimated that the long-term price of oil that would cause the total recoverable amount to be equal to the total carrying amount for each cash-generating 

unit would be of the order of $38 per barrel for the UK and $50 per barrel for the US. It was estimated that the long-term price of gas that would cause the total 

recoverable amount to be equal to the total carrying amount of goodwill and related non-current assets for the US cash-generating unit would be of the order of 

$4/mmBtu (Henry Hub). As a significant amount of gas from the North Sea is sold under fixed-price contracts, or contracts priced using non-gas indices, it is 

estimated that no reasonably possible change in gas prices would cause the UK headroom to be reduced to zero. It was estimated that no reasonably possible 

change in oil and 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 each cash-generating unit to zero. Consequently, management believes no reasonably 

possible change in the production assumption would cause the carrying amounts to exceed the recoverable amounts. 

 Management also believes that currently there is no reasonably possible change in discount rate that would cause the carrying amounts in the UK, US or 

Rest of World to exceed the recoverable amounts. 

128 

Notes on financial statements

 

$ million

2008

Rest of

UK US World Total

Goodwill 341 3,441 515 4,297

Excess of recoverable amount over carrying amount 7,972 16,692 n/a n/a

 

$ million

2007

Rest of

UK US World Total

Goodwill 341 3,440 515 4,296

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12. Impairment review of goodwill continued 

Refining and Marketing 

In previous years, Refining and Marketing goodwill has been allocated to the following cash-generating units: Refining, Retail, Lubricants, and Other. In 2008, the 

Refining and Retail units were largely integrated into geographically-based Fuels Value Chain units (FVC) and consequently the cash-generating units to which 

goodwill is allocated have been redefined. The goodwill previously allocated to the global Refining and Retail units has been aggregated and reallocated to the FVC 

units that are expected to benefit from the synergies of the business combinations that gave rise to the goodwill. As part of this reallocation a small amount of 

goodwill was also allocated to business units included in ‘Other’. Goodwill is now allocated to the following cash-generating units: Rhine FVC, US West Coast FVC, 

Lubricants and Other. 

 For all cash-generating units, the cash flows for the first three years are derived from the three-year business segment plan. For determining the value in use 

for each of the cash-generating units, cash flows for a period of 10 years have been discounted and aggregated with a terminal value. A key assumption for the 

FVCs is the Global Indicator Margin (GIM). Each regional GIM is based on a single representative crude with product yields characteristic of the typical level of 

upgrading complexity. 

Rhine FVC 

Cash flows beyond the three-year period are extrapolated using a 1.2% growth rate. 

 The key assumptions to which the calculation of value in use for the Rhine FVC unit is most sensitive are refinery gross margins, refinery production volumes 

and discount rate. The average value assigned to the refinery gross margin during the plan period is based on a $5.50 per barrel GIM. The average value assigned 

to the refinery production volume is 250mmbbl a year over the plan period. These key assumptions reflect past experience and are consistent with external

sources. 

 The Rhine FVC’s recoverable amount exceeds its carrying amount by $3.6 billion. Based on sensitivity analysis, it is estimated that: (i) if the GIM changes by 

$1 per barrel, the Rhine FVC’s value in use changes by $2.1 billion and, if there was an adverse change in the GIM of $1.70 per barrel, the recoverable amount of 

the Rhine FVC would equal its carrying amount; (ii) if the volume assumption changes by 13mmbbl a year, the Rhine FVC’s value in use changes by $1.2 billion 

and, if there is an adverse change in refinery volumes of 36mmbbl a year, the recoverable amount of the Rhine FVC would equal its carrying amount; and (iii) a 

change of 1% in the discount rate would change the Rhine FVC’s value in use by $0.8 billion and, if the discount rate increases to 17% the value in use of the 

Rhine FVC would equal its carrying amount. 

US West Coast FVC 

Cash flows beyond the three-year period are extrapolated using a 2% growth rate. 

 The key assumptions to which the calculation of value in use for the West Coast FVC unit is most sensitive are refinery gross margins, refinery production 

volumes and discount rate. The average value assigned to the refinery gross margin during the plan period is based on a $7.60 per barrel GIM. The average value 

assigned to the refinery production volume is 170mmbbl a year over the plan period. These key assumptions reflect past experience and are consistent with

external sources. 

 The West Coast FVC’s recoverable amount exceeds its carrying amount by $1.6 billion. Based on sensitivity analysis, it is estimated that: (i) if the GIM 

changes by $1 per barrel, the West Coast FVC’s value in use changes by $1.5 billion and, if there was an adverse change in the GIM of $1.10 per barrel, the 

recoverable amount of the West Coast FVC would equal its carrying amount; (ii) if the volume assumption changes by 8mmbbl a year, the West Coast FVC’s value 

in use changes by $1.1 billion and, if there is an adverse change in refinery volumes of 12mmbbl a year, the recoverable amount of the West Coast FVC would 

equal its carrying amount; and (iii) a change of 1% in the discount rate would change the West Coast FVC’s value in use by $0.6 billion and, if the discount rate 

increases to 14% the value in use of the West Coast FVC would equal its carrying amount. 

Lubricants 

Cash flows beyond the three-year period are extrapolated using a 3% growth rate (2007 3%). 

 For the Lubricants unit, the key assumptions to which the calculation of value in use is most sensitive are operating margin, sales volumes and discount rate. 

The average values assigned to the operating margin and sales volumes over the plan period are 70 cents per litre (2007 65 cents per litre) and 3.4 billion litres a 

year (2007 3.3 billion litres a year) respectively. These key assumptions reflect past experience. 

 The Lubricants unit’s recoverable amount exceeds its carrying amount by $5.4 billion. Based on sensitivity analysis, it is estimated that: (i) if there is an 

adverse change in the operating margin of 14 cents per litre, the recoverable amount of the Lubricants unit would equal its carrying amount; (ii) if the sales volume 

assumption changes by 200 million litres a year, the Lubricants unit’s value in use changes by $1.4 billion and, if there is an adverse change in Lubricants sales 

volumes of 700 million litres a year, the recoverable amount of the Lubricants unit would equal its carrying amount; and (iii) a change of 1% in the discount rate 

would change the Lubricants unit’s value in use by $1.4 billion and, management believes no reasonably possible change in the discount rate would lead to the 

Lubricants unit’s value in use being equal to its carrying amount. 

Comparative narrative information is not generally shown because, due to the reorganization of the Refining and Marketing business in 2008, the information is not 

relevant to an understanding of the current year’s financial statements. 

129

Notes on financial statements

$ million

2008

US West

Rhine FVC Coast FVC Lubricants Other Total

Goodwill 637 1,579 3,043 203 5,462

Excess of recoverable amount over carrying amount 3,603 1,629 5,445 n/a n/a

$ million

2007

Refining Retail Lubricants Other Total

Goodwill 1,515 827 4,175 109 6,626

Excess of recoverable amount over carrying amount 11,443 4,062 5,028 n/a n/a 

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13. Distribution and administration expenses 

14. Currency exchange gains and losses 

15. Research and development 

16. Operating leases 

The table below shows the expense for the year in respect of operating leases. Where an operating lease is entered into solely by the group as the operator of a 

jointly controlled asset, the total cost is included in this analysis, irrespective of any amounts that have been or will be reimbursed by joint venture partners. Where 

BP is not the operator of a jointly controlled asset, and has not co-signed the lease, operating lease costs and future minimum lease payments are excluded from 

the information given below. However, where BP has co-signed the lease, BP’s share of the lease costs and future minimum lease payments are included. 

The future minimum lease payments at 31 December, before deducting related rental income from operating sub-leases of $557 million (2007 $618 million), are 

shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor, the future minimum lease 

payments are based on the factor as at inception of the lease. 

Of which, future minimum operating lease commitments relating to drilling rigs are $7,730 million (2007 $5,688 million). 

130 

Notes on financial statements

 

 $ million 

2008 2007 2006 

Distribution 14,075 14,028 13,174 

Administration 1,337 1,343 1,273

 15,412 15,371 14,447

$ million

2008 2007 2006

Currency exchange (gains) losses (credited) charged to income relating to embedded derivatives measured at fair 

value through profit or loss (496) 12 179 

Other currency exchange (gains) losses (credited) charged to income 156 (201) 43

 (340) (189) 222

$ million

2008 2007 2006

Expenditure on research and development 595 566 395

$ million

2008 2007 2006

Minimum lease payments 4,870 4,152 3,647

Contingent rentals 134 105 13

Sub-lease rentals (201) (191) (131)

 4,803 4,066 3,529

 $ million 

Future minimum lease payments 2008 2007 

Payable within 

1 year 4,135 3,780

2 to 5 years 9,140 7,660

Thereafter 5,520 5,498

 18,795 16,938

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16. Operating leases continued 

The following additional disclosures represent the net operating lease expense and net future minimum lease payments, after deducting amounts reimbursed, or to 

be reimbursed, by joint venture partners. 

 Where BP is not the operator of a jointly controlled asset, and has not co-signed the lease, operating lease costs and future minimum lease payments are 

excluded from the information given below. However, where BP has co-signed the lease, BP’s share of the lease costs and future minimum lease payments are

included. 

Of which, future minimum operating lease commitments relating to drilling rigs are $4,660 million (2007 $3,736 million). 

 The group enters into operating leases of ships, plant and machinery, commercial vehicles and land and buildings. Typical durations of the leases are as 

follows: 

The group has entered into a number of structured operating leases for ships and in most cases the lease rental payments vary with market interest rates. The 

variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is treated as contingent 

rental expense. The group also routinely enters into bareboat charters, time-charters and spot-charters for ships on standard industry terms. 

 The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Exploration and Production segment. In some 

cases, drilling rig lease rental rates are adjusted periodically to market rates that are influenced by oil prices and may be significantly different from the rates at the 

inception of the lease. Differences between the rate paid and the rate at inception of the lease are treated as contingent rental expense. 

 Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in the land 

and buildings category. 

 The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of ships and 

buildings allow for renewals at BP’s option. 

17. Exploration for and evaluation of oil and natural gas resources 

The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and evaluation of 

oil and natural gas resources. All such activity is recorded within the Exploration and Production segment. 

131

Notes on financial statements

$ million

2008 2007 2006

Minimum lease payments 3,693 3,100 2,924

Contingent rentals 97 80 13 

Sub-lease rentals (197) (183) (131)

 3,593 2,997 2,806

$ million

Future minimum lease payments 2008 2007

Payable within

1 year 3,165 2,826

2 to 5 years 7,135 6,519

Thereafter 4,820 5,050 

 15,120 14,395

Years

Ships up to 15

Plant and machinery up to 10

Commercial vehicles up to 15 

Land and buildings up to 40

 $ million 

2008 2007 2006 

Exploration and evaluation costs 

Exploration expenditure written off 385 347 624

Other exploration costs 497 409 421

Exploration expense for the yeara 882 756 1,045 

Intangible assets – exploration expenditure 9,031 5,252 4,110 

Net assets 9,031 5,252 4,110

Capital expenditure and acquisitions 4,780 2,000 1,537

Net cash used in operating activities 497 409 421

Net cash used in investing activities 4,163 2,000 1,498

aIn addition to these amounts, an impairment charge of $210 million was recognized in 2008 relating to exploration assets in Vietnam following BP’s decision to withdraw from activities in the area concerned.

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18. Auditor’s remuneration 

Total fees for 2008 include $3 million of additional fees for 2007 (2007 includes $7 million of additional fees for 2006 and 2006 includes $5 million of additional fees 

for 2005). Auditor’s remuneration is included in the income statement within distribution and administration expenses. 

 The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services. 

 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 compared with that of other 

potential service providers. These services are for a fixed term. 

19. Finance costs 

aTax relief on capitalized interest is $42 million (2007 $81 million and 2006 $182 million). 

Revised income statement presentation 

With effect from 1 January 2008, the unwinding of the discount on provisions and on other payables is now included within finance costs. Previously, it was included 

within other finance income or expense. This line item has now been renamed net finance income or expense relating to pensions and other post-retirement 

benefits. This change does not affect profit before interest and taxation, profit before taxation or profit for the period in the group income statement. For 2007 

$283 million was reclassified from other finance income to finance costs (2006 $268 million). 

132 

Notes on financial statements

 

 $ million 

Fees - Ernst & Young 2008 2007 2006 

Fees payable to the company’s auditors for the audit of the company’s accountsa 16 18 15 

Fees payable to the company’s auditors and its associates for other services

Audit of the company’s subsidiaries pursuant to legislation 28 31 31

Other services pursuant to legislation 13 14 15

57 63 61

Tax services 2 2 1

Services relating to corporate finance transactions 2 1 2

All other services 5 8 9

Audit fees in respect of the BP pension plans 1 1 – 

 67 75 73 

aFees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.

 

 $ million 

2008 2007 2006 

Interest payable 1,319 1,433 1,196 

Capitalized at 4.00% (2007 5.70% and 2006 5.25%)a (162) (323) (478)

Unwinding of discount on provisions 287 283 245

Unwinding of discount on other payables 103 – 23

 1,547 1,393 986

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20. Taxation 

Tax on profit 

Tax included in the statement of recognized income and expense 

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. 

133

Notes on financial statements

$ million

2008 2007 2006

Current tax

Charge for the year 13,468 10,006 11,199

Adjustment in respect of prior years (85) (171) 442

13,383 9,835 11,641

Innovene operations – – 159

Continuing operations 13,383 9,835 11,800

Deferred tax 

Origination and reversal of temporary differences in the current year (324) 671 1,956

Adjustment in respect of prior years (442) (64) (1,240)

 (766) 607 716 

Tax on profit from continuing operations 12,617 10,442 12,516 

$ million

2008 2007 2006

Current tax (264) (178) (51)

Deferred tax (2,492) 241 985 

 (2,756) 63 934 

This comprises:

Currency translation differences (100) (139) 201

Actuarial gain (loss) relating to pensions and other post-retirement benefits (2,602) 427 820

Share-based payments 190 (213) (26)

Cash flow hedges (194) (26) 47

Available-for-sale investments (50) 14 (108)

 (2,756) 63 934 

 $ million 

2008 2007 2006 

Profit before taxation from continuing operations 34,283 31,611 35,142 

Tax on profit from continuing operations 12,617 10,442 12,516 

Effective tax rate 37% 33% 36%

% of profit before taxation

from continuing operations

UK statutory corporation tax rate 28 30 30

Increase (decrease) resulting from

UK supplementary and overseas taxes at higher rates 14 7 11

Tax reported in equity-accounted entities (2) (2) (3)

Adjustments in respect of prior years (2) (1) (2)

Current year losses unrelieved (prior year losses utilized) (1) (1) (1)

Other – – 1

Effective tax rate 37 33 36

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20. Taxation continued 

Deferred tax 

In 2008, there have been no changes in the statutory tax rates that have materially impacted the group’s tax charge. The enactment, in 2007, of a 2% reduction in 

the rate of UK corporation tax on profits arising from activities outside the North Sea reduced the deferred tax charge by $189 million in that year. 

 Deferred tax assets are recognized 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. 

 At 31 December 2008, the group had around $6.3 billion (2007 $5.0 billion) of carry-forward tax losses, predominantly in Europe, that would be available to 

offset against future taxable profit. A deferred tax asset has been recognized in respect of $4.2 billion of losses (2007 $3.2 billion). No deferred tax asset has been 

recognized in respect of $2.1 billion of losses (2007 $1.8 billion). Substantially all the tax losses have no fixed expiry date. 

 At 31 December 2008, the group had around $3.4 billion (2007 $4.1 billion) of unused tax credits in the UK and US. A deferred tax asset of $0.5 billion has 

been recognized in 2008 for these credits (2007 $0.8 billion), which is offset by a deferred tax liability associated with unremitted profits from overseas entities in 

jurisdictions with a lower tax rate than the UK. No deferred tax asset has been recognized in respect of $2.9 billion of tax credits (2007 $3.2 billion). The UK tax 

credits do not have a fixed expiry date. The US tax credits, amounting to $1.8 billion, expire ten years after generation, and substantially all expire in the period 

2014-2018. 

 The major components of temporary differences at the end of 2008 are tax depreciation, US inventory holding gains (classified as other taxable temporary 

differences), provisions, and pension plan and other post-retirement benefit plan deficits. 

 The group profit and loss account reserve includes $18,347 million (2007 $16,335 million) of earnings retained by subsidiaries and equity-accounted entities. 

21. Dividends 

The group does not account for dividends until they are paid. The accounts for the year ended 31 December 2008 do not reflect the dividend announced on 3

February 2009 and payable in March 2009; this will be treated as an appropriation of profit in the year ended 31 December 2009. 

134 

Notes on financial statements

 

 $ million 

 Income statement Balance sheet 

2008 2007a 2006a 2008 2007a

Deferred tax liability 

Depreciation 1,248 125 1,423 23,342 22,338

Pension plan surpluses 108 127 173 412 2,136

Other taxable temporary differences (2,471) 1,371 417 3,626 5,998

(1,115) 1,623 2,013 27,380 30,472

Deferred tax asset

Petroleum revenue tax 121 139 4 (192) (325)

Pension plan and other post-retirement benefit plan deficits 104 (72) 71 (2,414) (1,545)

Decommissioning, environmental and other provisions (333) (1,069) (569) (4,860) (5,107)

Derivative financial instruments 228 450 (115) (331) (541)

Tax credit and loss carry forward 118 (466) 220 (1,821) (1,822)

Other deductible temporary differences 111 2 (908) (1,564) (1,917)

349 (1,016) (1,297) (11,182) (11,257)

Net deferred tax (credit) charge and net deferred tax liability (766) 607 716 16,198 19,215

aA minor amendment has been made to the comparative amounts shown in the analysis of deferred tax by category of temporary difference.

 

$ million

Analysis of movements during the year 2008 2007

At 1 January 19,215 18,116

Exchange adjustments (67) 42

Charge (credit) for the year on ordinary activities (766) 607 

Charge (credit) for the year in the statement of recognized income and expense (2,492) 241

Acquisitions – 199

Other movements 308 10

At 31 December 16,198 19,215

pence per share cents per share $ million

2008 2007 2006 2008 2007 2006 2008 2007 2006

Dividends announced and paid

Preference shares 2 2 2

Ordinary shares

March 6.813 5.258 5.288 13.525 10.325 9.375 2,553 2,000 1,922 

June 6.830 5.151 5.251 13.525 10.325 9.375 2,545 1,983 1,893

September 7.039 5.278 5.324 14.000 10.825 9.825 2,623 2,065 1,943

December 8.705 5.308 5.241 14.000 10.825 9.825 2,619 2,056 1,926

 29.387 20.995 21.104 55.050 42.300 38.400 10,342 8,106 7,686

Dividend announced per ordinary share, 

payable in March 2009 9.818 – – 14.000 – – 2,626 – –

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22. Earnings per ordinary share 

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 (ESOPs) and includes certain shares that will be issuable in the future under employee share plans. 

 For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the number of shares that 

are potentially issuable in connection with employee share-based payment plans using the treasury stock method. In addition, for 2006 the profit attributable to 

ordinary shareholders has been adjusted for the unwinding of the discount on the deferred consideration for the acquisition of our interest in TNK-BP and the 

weighted average number of shares outstanding during the year has been adjusted for the number of shares to be issued for the deferred consideration for the 

acquisition of our interest in TNK-BP. 

The number of ordinary shares outstanding at 31 December 2008, excluding treasury shares and the shares held by the ESOPs, and including certain shares that 

will be issuable in the future under employee share plans was 18,716,098,258. Between 31 December 2008 and 18 February 2009, the latest practicable date 

before the completion of these financial statements, there has been an increase of 4,867,626 in the number of ordinary shares outstanding as a result of share 

issues related to employee share plans. The number of potential ordinary shares issuable through the exercise of options related to employee share plans was 

191,340,183 at 31 December 2008. There has been a decrease of 42,722,753 in the number of potential ordinary shares between 31 December 2008 and 18 

February 2009. 

 Loss per share for the discontinued operations in 2006 is derived from the net loss attributable to ordinary shareholders from discontinued operations of 

$25 million, divided by the weighted average number of ordinary shares for both basic and diluted amounts as shown above. 

135

Notes on financial statements

 

 cents per share 

2008 2007 2006 

Basic earnings per share 112.59 108.76 111.41

Diluted earnings per share 111.56 107.84 110.56

$ million

2008 2007 2006

Profit from continuing operations attributable to BP shareholders 21,157 20,845 22,340

Less dividend requirements on preference shares 2 2 2

Profit from continuing operations attributable to BP ordinary shareholders 21,155 20,843 22,338 

Loss from discontinued operations – – (25)

21,155 20,843 22,313

Unwinding of discount on deferred consideration for acquisition of 

investment in TNK-BP (net of tax) – – 16

Diluted profit for the year attributable to BP ordinary shareholders 21,155 20,843 22,329

shares thousand

2008 2007 2006

Basic weighted average number of ordinary shares 18,789,827 19,163,389 20,027,527

Potential dilutive effect of ordinary shares issuable under employee share schemes 172,690 163,486 109,813 

Potential dilutive effect of ordinary shares issuable as consideration for BP’s interest in

the TNK-BP joint venture – – 58,118 

 18,962,517 19,326,875 20,195,458 

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23. Property, plant and equipment 

136 

Notes on financial statements

 

 $ million 

 Oil depots, 

Land Plant, Fixtures, storage

and land Oil and machinery fittings and tanks and

improve- gas and office Transport- service 

ments Buildings properties equipment equipment ation stations Total

Cost

At 1 January 2008 4,516 3,150 134,615 36,365 3,169 11,866 11,410 205,091

Exchange adjustments (320) (287) (1) (1,655) (237) (98) (1,047) (3,645)

Acquisitions – – 136 212 – – – 348

Additions 64 161 12,571 4,118 530 243 842 18,529

Transfersa – – (454) 79 (1) 454 – 78

Deletions (296) (282) (54) (1,214) (416) (170) (860) (3,292)

At 31 December 2008 3,964 2,742 146,813 37,905 3,045 12,295 10,345 217,109

Depreciation 

At 1 January 2008 718 1,533 72,486 17,417 1,820 7,126 6,002 107,102

Exchange adjustments (30) (118) – (917) (147) (41) (502) (1,755)

Charge for the year 32 79 7,490 1,697 313 296 709 10,616

Impairment losses 21 33 469 131 1 – 19 674

Impairment reversals – – (122) – – – – (122)

Transfersb – – (352) 4 (1) 274 – (75)

Deletions (143) (214) (16) (1,034) (290) (113) (721) (2,531)

At 31 December 2008 598 1,313 79,955 17,298 1,696 7,542 5,507 113,909

Net book amount at 31 December 2008 3,366 1,429 66,858 20,607 1,349 4,753 4,838 103,200

Cost

At 1 January 2007 4,442 3,129 123,493 32,203 3,006 11,930 11,076 189,279

Exchange adjustments 271 148 22 1,182 73 32 733 2,461

Acquisitions – – – 910 – – – 910

Additions 78 171 12,107 3,662 466 181 643 17,308

Transfers – – 422 – – – – 422

Reclassified as assets held for sale (16) – – (1,114) – – – (1,130)

Deletions (259) (298) (1,429) (478) (376) (277) (1,042) (4,159)

At 31 December 2007 4,516 3,150 134,615 36,365 3,169 11,866 11,410 205,091 

Depreciation

At 1 January 2007 675 1,470 66,189 16,189 1,762 6,876 5,119 98,280

Exchange adjustments 25 89 19 556 45 16 299 1,049

Charge for the year 52 98 7,370 1,266 341 373 741 10,241

Impairment losses 86 62 189 236 9 14 643 1,239

Impairment reversals – – (237) – – – – (237)

Reclassified as assets held for sale (9) – – (486) – – – (495)

Deletions (111) (186) (1,044) (344) (337) (153) (800) (2,975)

At 31 December 2007 718 1,533 72,486 17,417 1,820 7,126 6,002 107,102 

Net book amount at 31 December 2007 3,798 1,617 62,129 18,948 1,349 4,740 5,408 97,989

Net book amount at 1 January 2007 3,767 1,659 57,304 16,014 1,244 5,054 5,957 90,999

Assets held under finance leases at net book amount included above

At 31 December 2008 – 12 237 107 – 8 18 382

At 31 December 2007 – 17 155 185 – 11 24 392

Decommissioning asset at net book amount included above Cost Depreciation Net

At 31 December 2008 7,140 3,659 3,481

At 31 December 2007 7,851 3,328 4,523

 

Assets under construction included above

At 31 December 2008 17,213

At 31 December 2007 18,658

aIncludes $337 million transferred to equity-accounted investments and $415 million transferred from intangible assets.

bIncludes $75 million transferred to equity-accounted investments.

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24. Goodwill 

25. Intangible assets 

137

Notes on financial statements

$ million

2008 2007

Cost and net book amount

At 1 January 11,006 10,780 

Exchange adjustments (1,112) 126

Acquisitions 1 270

Additions 39 –

Reclassified as assets held for sale – (90)

Deletions (56) (80)

At 31 December 9,878 11,006

$ million

2008 2007

Exploration Other Exploration Other

expenditure intangibles Total expenditure intangibles Total

Cost

At 1 January 5,637 2,898 8,535 4,590 2,396 6,986

Exchange adjustments (1) (175) (176) 3 49 52

Acquisitions 42 – 42 – 35 35 

Additionsa 4,738 354 5,092 2,000 548 2,548

Transfersb (415) – (415) (506) – (506)

Deletions (576) (150) (726) (450) (130) (580)

At 31 December 9,425 2,927 12,352 5,637 2,898 8,535

Amortization 

At 1 January 385 1,498 1,883 480 1,260 1,740

Exchange adjustments – (60) (60) – 25 25

Charge for the year 385 369 754 347 338 685

Impairment losses 200 – 200 – – – 

Deletions (576) (109) (685) (442) (125) (567)

At 31 December 394 1,698 2,092 385 1,498 1,883

Net book amount at 31 December 9,031 1,229 10,260 5,252 1,400 6,652

Net book amount at 1 January 5,252 1,400 6,652 4,110 1,136 5,246

aIncluded in additions to exploration expenditure in 2008 is $2,331 million in relation to BP’s purchase of interests in shale gas assets in the US. 

bIncluded in transfers of exploration expenditure in 2007 is $84 million transferred to equity-accounted investments.

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26. Investments in jointly controlled entities 

The significant jointly controlled entities of the BP group at 31 December 2008 are shown in Note 46. 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. 

In December 2007, BP signed a memorandum of understanding with Husky Energy Inc. (Husky) to form an integrated North American oil sands business. The 

transaction was completed on 31 March 2008, with BP contributing its Toledo refinery to a US jointly controlled entity to which Husky contributed $250 million cash 

and a payable of $2,588 million. In Canada, Husky contributed its Sunrise field to a second jointly controlled entity, with BP contributing $250 million in cash and a 

payable of $2,264 million. Both jointly controlled entities are owned 50:50 by BP and Husky and are accounted for using the equity method. During the year, equityaccounted earnings from these jointly controlled entities amounted to a loss of $70 million. 

 BP purchased refined products from the Toledo jointly controlled entity during the year amounting to $3,440 million. In addition, BP purchased crude oil from 

third parties which it sold to the Toledo jointly controlled entity under an agency agreement. The fees earned by BP for this service, and the total amounts 

receivable and payable at 31 December 2008 under these arrangements, were not significant. BP will also purchase refinery feedstocks from the Sunrise jointly 

controlled entity once production commences, which is expected in 2013. During 2008 the unwinding of discount on the payable to the Sunrise jointly controlled 

entity, included within finance costs in the group income statement, amounted to $103 million. 

 Our investment in TNK-BP will be reclassified from a jointly controlled entity to an associate with effect from 9 January 2009, the date that BP finalized a 

revised shareholder agreement with its Russian partners in TNK-BP, Alfa Access-Renova (AAR). The formerly evenly-balanced main board structure is replaced by 

one with four representatives each from BP and AAR, plus three independent directors. The change in accounting classification from a jointly controlled entity to an 

associate reflects the ability of the independent directors of TNK-BP to decide on certain matters in the event of disagreement between the shareholder 

representatives on the board. The group’s investment will continue to be accounted for using the equity method. 

 Transactions between the group and its jointly controlled entities are summarized below. 

The terms of the outstanding balances receivable from jointly controlled entities are typically 30 to 45 days, except for a receivable from Ruhr Oel of $386 million, 

which will be paid over several years as it relates to pension payments. The balances are unsecured and will be settled in cash. There are no significant provisions 

for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. 

138 

Notes on financial statements

 

$ million

2008 2007 2006

TNK-BP Other Total TNK-BP Other Total TNK-BP Other Total

Sales and other operating revenues 25,936 10,796 36,732 19,463 7,245 26,708 17,863 6,119 23,982

Profit before interest and taxation 3,588 1,343 4,931 3,743 1,299 5,042 4,616 1,218 5,834

Finance costs 275 185 460 264 176 440 192 169 361

Profit before taxation 3,313 1,158 4,471 3,479 1,123 4,602 4,424 1,049 5,473

Taxation 882 397 1,279 993 259 1,252 1,467 260 1,727

Minority interest 169 – 169 215 – 215 193 – 193

Profit for the yeara 2,262 761 3,023 2,271 864 3,135 2,764 789 3,553

Non-current assets 13,874 15,584 29,458 12,433 9,841 22,274 

Current assets 3,760 3,687 7,447 6,073 2,642 8,715

Total assets 17,634 19,271 36,905 18,506 12,483 30,989

Current liabilities 3,287 1,998 5,285 3,547 1,552 5,099

Non-current liabilities 4,820 3,973 8,793 5,562 3,620 9,182 

Total liabilities 8,107 5,971 14,078 9,109 5,172 14,281 

Minority interest 588 – 588 580 – 580

 8,939 13,300 22,239 8,817 7,311 16,128

Group investment in jointly controlled entities 

Group share of net assets (as above) 8,939 13,300 22,239 8,817 7,311 16,128 

Loans made by group companies to jointly controlled

entities – 1,587 1,587 – 1,985 1,985 

 8,939 14,887 23,826 8,817 9,296 18,113 

aBP’s share of the profit of TNK-BP in 2006 includes a net gain of $892 million on the disposal of certain assets.

 $ million 

Sales to jointly controlled entities 2008 2007 2006 

 Amount Amount Amount 

receivable at receivable at receivable at

Product Sales 31 December Sales 31 December Sales 31 December

LNG, crude oil and oil products, natural gas, employee services 2,971 1,036 2,336 888 2,258 830

$ million

Purchases from jointly controlled entities 2008 2007 2006

Amount Amount Amount

payable at payable at payable at

Product Purchases 31 Decembera Purchases 31 December Purchases 31 December

Crude oil and oil products, natural gas, refinery operating costs, plant 

processing fees 9,115 2,547 2,067 66 3,678 119

aIncludes $110 million current payable and $2,255 million non-current payable to the Sunrise Oil Sands jointly controlled entity relating to BP’s contribution on the establishment of the joint venture.

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27. Investment in associates 

The significant associates of the group are shown in Note 46. Summarized financial information for the group’s share of associates is set out below. 

Transactions between the group and its associates are summarized below. 

The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash. There are no 

significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful 

debts. 

139

Notes on financial statements

$ million

2008 2007 2006

Sales and other operating revenues 11,709 9,855 8,792

Profit before interest and taxation 1,065 947 669 

Finance costs 33 57 63

Profit before taxation 1,032 890 606

Taxation 234 193 164

Profit for the year 798 697 442 

Non-current assets 4,292 5,012 

Current assets 1,912 2,308

Total assets 6,204 7,320

Current liabilities 1,669 1,801

Non-current liabilities 1,852 2,423 

Total liabilities 3,521 4,224

 2,683 3,096

Group investment in associates 

Group share of net assets (as above) 2,683 3,096

Loans made by group companies to associates 1,317 1,483

4,000 4,579

 

$ million

Sales to associates 2008 2007 2006

Amount Amount Amount

receivable at receivable at receivable at

Product Sales 31 December Sales 31 December Sales 31 December

LNG, crude oil and oil products, natural gas, employee services 3,248 219 697 60 747 66

 

 $ million 

Purchases from associates 2008 2007 2006

 Amount Amount Amount 

payable at payable at payable at

Product Purchases 31 December Purchases 31 December Purchases 31 December

Crude oil, natural gas, transportation tariff 4,635 295 2,905 574 2,568 236

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28. Financial instruments and financial risk factors 

The accounting classification of each category of financial instruments, and their carrying amounts, are set out below. 

The fair value of finance debt is shown in Note 35. For all other financial instruments, the carrying amount is either the fair value, or approximates the fair value. 

Financial risk factors 

The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including market 

risks relating to commodity prices, foreign currency exchange rates, interest rates and equity prices, credit risk and liquidity risk. 

 The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is 

chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the finance, tax and the integrated supply and 

trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the group. The committee 

provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is governed by 

appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with group policies and group risk appetite. 

140 

Notes on financial statements

$ million

At 31 December 2008

Financial

 Available-for- At fair value Derivative liabilities Total

Loans and sale financial through profit hedging measured at carrying

Note receivables assets and loss instruments amortized cost amount

Financial assets

Other investments – listed 29 – 592 – – – 592

Other investments – unlisted 29 – 263 – – – 263

Loans 1,163 – – – – 1,163

Trade and other receivables 31 29,489 – – – – 29,489

Derivative financial instruments 34 – – 12,501 1,063 – 13,564

Cash at bank and in hand 32 4,001 – – – – 4,001

Cash equivalents – listed 32 – 4,060 – – – 4,060

Cash equivalents – unlisted 32 – 136 – – – 136

Financial liabilities

Trade and other payables 33 – – – – (33,140) (33,140)

Derivative financial instruments 34 – – (13,173) (2,075) – (15,248)

Accruals – – – – (7,527) (7,527)

Finance debt 35 – – – – (33,204) (33,204)

 34,653 5,051 (672) (1,012) (73,871) (35,851)

$ million

At 31 December 2007

Financial

 Available-for- At fair value Derivative liabilities Total 

Loans and sale financial through profit hedging measured at carrying

Note receivables assets and loss instruments amortized cost amount

Financial assets

Other investments – listed 29 – 1,617 – – – 1,617

Other investments – unlisted 29 – 213 – – – 213

Loans 1,164 – – – – 1,164

Trade and other receivables 31 38,710 – – – – 38,710 

Derivative financial instruments 34 – – 9,155 907 – 10,062

Cash at bank and in hand 32 2,996 – – – – 2,996 

Cash equivalents – listed 32 – 3 – – – 3

Cash equivalents – unlisted 32 – 563 – – – 563

 

Financial liabilities

Trade and other payables 33 – – – – (40,062) (40,062)

Derivative financial instruments 34 – – (11,284) (123) – (11,407)

Accruals – – – – (7,599) (7,599)

Finance debt 35 – – – – (31,045) (31,045)

42,870 2,396 (2,129) 784 (78,706) (34,785)

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28. Financial instruments and financial risk factors continued 

The group’s trading activities in the oil, natural gas and power markets are managed within the integrated supply and trading function, while activities in the financial 

markets are managed by the treasury function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. 

These teams are subject to close financial and management control. 

 The integrated supply and trading function maintains formal governance processes that provide oversight of market risk associated with trading activity. 

These processes meet generally accepted industry practice and reflect the principles of the Group of Thirty Global Derivatives Study recommendations. A policy 

and risk committee monitors and validates limits and risk exposures, reviews incidents and validates risk-related policies, methodologies and procedures. A 

commitments committee approves value-at-risk delegations, the trading of new products, instruments and strategies and material commitments. 

 In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a separate control framework as 

described more fully below. 

(a) Market risk 

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The market price 

movements that the group is exposed to include oil, natural gas and power prices (commodity price risk), foreign currency exchange rates, interest rates, equity 

prices and other indices that could adversely affect the value of the group’s financial assets, liabilities or expected future cash flows. The group enters into 

derivatives in a well established entrepreneurial trading operation. In addition, the group has developed a control framework aimed at managing the volatility 

inherent in certain of its natural business exposures. In accordance with this control framework the group enters into various transactions using derivatives for risk 

management purposes. 

 During recent periods of increased volatility in financial markets the group’s policies in relation to managing market risk continue to be appropriate and are 

outlined in further detail below. The group measures market risk exposure arising from its trading positions 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 prices 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 value-at-risk measure is supplemented by stress testing and 

tail risk analysis. 

 The trading value-at-risk model is used for 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 forwards, futures, swap 

agreements and options. Additionally, where physical commodities or non-derivative forward contracts are held as part of a trading position, they are also reflected 

in the value-at-risk model. For options, a linear approximation is included in the value-at-risk models when full revaluation is not possible. 

 The value-at-risk table does not incorporate any of the group’s natural business exposures or any derivatives entered into to risk manage those exposures. 

Market risk exposure in respect of embedded derivatives is also not included in the value-at-risk table. Instead separate sensitivity analyses are disclosed below. 

 Value-at-risk limits are in place for each trading activity and for the group’s trading activity in total. The board has delegated an overall limit of $100 million 

value at risk in support of this trading activity. The high and low values at risk indicated in the table below for each type of activity are independent of each other. 

Through the portfolio effect the high value at risk for the group as a whole is lower than the sum of the highs for the constituent parts. The potential movement in fair 

values is expressed to a 95% confidence interval. This means that, in statistical terms, one would expect to see a decrease in fair values greater than the trading 

value at risk on one occasion per month if the portfolio were left unchanged. 

(i) Commodity price risk 

The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes available in the related commodity 

markets. Natural gas swaps, options and futures are used to mitigate price risk. 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, NGLs are traded around certain US inventory locations using over-the-counter forward contracts in conjunction with 

over-the-counter swaps, options and physical inventories. Trading value-at-risk information in relation to these activities is shown in the table above. 

141

Notes on financial statements

$ million

Value at risk for 1 day at 95% confidence interval 2008 2007

High Low Average Year end High Low Average Year end

Group trading 76 20 37 69 50 24 35 38

Oil price trading 69 12 25 63 46 16 26 34 

Natural gas price trading 50 12 24 23 32 9 16 15

Power price trading 14 3 7 4 6 1 3 5

Currency trading 4 – 2 – 6 1 3 2 

Interest rate trading 7 – 2 1 11 – 5 2

Other trading 5 1 2 2 7 – 2 1 

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28. Financial instruments and financial risk factors continued 

As described above, the group also carries out risk management of certain short-term natural business exposures using over-the-counter swaps and exchange

futures contracts with a duration of less than three years. In past periods commodity price risk relating to this activity has been managed using value-at-risk 

measures. For 2008 a separate control framework is now used as described under market risk above. For these derivative contracts the sensitivity of the net fair 

value to an immediate 10% increase or decrease in all reference prices would have been $90 million at 31 December 2008. This figure does not include any 

corresponding economic benefit or disbenefit that would arise from the natural business exposure which would be expected to largely offset the gain or loss on the 

derivatives. 

 In addition, the group has embedded derivatives relating to certain natural gas and crude oil contracts. The net fair value of these embedded derivatives was 

a liability of $1,867 million at 31 December 2008 (2007 liability of $2,085 million). Key information on the natural gas contracts is given below. 

For these embedded derivatives the sensitivity of the net fair value to an immediate 10% favourable or unfavourable change in the key assumptions is as follows. 

The sensitivities for risk management activity and embedded derivatives are hypothetical and should not be considered to be predictive of future performance. In 

addition, for the purposes of this analysis, in the above 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. 

(ii) Foreign currency exchange risk 

Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk techniques 

as explained above. This activity is described as currency trading in the value-at-risk table above. 

 Since BP has global operations, fluctuations in foreign currency 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 currency 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 currency exchange risks centrally, by netting off naturally-occurring 

opposite exposures wherever possible, and then dealing with any material residual foreign currency exchange risks. 

 The group manages these exposures by constantly reviewing the foreign currency economic value at risk and managing such risk to keep the 12-month 

foreign currency value at risk below $200 million. At 31 December 2008, the foreign currency value at risk was $70 million (2007 $60 million). At no point over the 

past three years did the value at risk exceed the maximum risk limit. The most significant exposures relate to capital expenditure commitments and other UK and 

European operational requirements, for which a hedging programme is in place and hedge accounting is claimed as outlined in Note 34. 

 For highly probable forecast capital expenditures the group locks in the US-dollar cost of non-US dollar supplies by using currency forwards and futures. The 

main exposures are sterling, euro, Norwegian krone, Australian dollar, Korean won and Canadian dollar, and at 31 December 2008 open contracts were in place for 

$949 million sterling, $553 million euro, $392 million Norwegian krone, $303 million Australian dollar, $187 million Korean won and $712 million Canadian dollar 

capital expenditures maturing within seven years, with over 65% of the deals maturing within two years (2007 $732 million sterling, $931 million euro, $479 million 

Norwegian krone, $38 million Australian dollar, $243 million Korean won and $7 million Canadian dollar capital expenditures maturing within eight years with over 

80% of the deals maturing within two years). 

 For other UK, European, Canadian and Australian operational requirements the group uses cylinders and currency forwards to hedge the estimated 

exposures on a 12-month rolling basis. At 31 December 2008, the open positions relating to cylinders consisted of receive sterling, pay US dollar, purchased call 

and sold put options (cylinders) for $1,660 million (2007 $2,800 million); receive euro, pay US dollar cylinders for $1,612 million (2007 $1,400 million); receive 

Canadian dollar, pay US dollar cylinders for $250 million (2007 nil); and receive Australian dollar, pay US dollar cylinders for $455 million (2007 $382 million). 

At 31 December 2008, the open positions relating to currency forwards consisted of buy sterling, sell US dollar, currency forwards for $816 million (2007 nil); buy 

euro, sell US dollar currency forwards for $141 million (2007 nil); buy Canadian dollar, sell US dollar, currency forwards for $50 million (2007 nil); and buy Australian 

dollar, sell US dollar, currency forwards for $90 million (2007 nil). 

 In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2008, the total foreign currency net 

borrowings not swapped into US dollars amounted to $1,037 million (2007 $1,045 million). Of this total, $92 million was denominated in currencies other than the 

functional currency of the individual operating unit being entirely Canadian dollars (2007 $268 million, being $191 million in Canadian dollars and $77 million in 

Trinidad & Tobago dollars). It is estimated that a 10% change in the corresponding exchange rates would result in an exchange gain or loss in the income 

statement of $9 million (2007 $27 million). 

142 

Notes on financial statements

 

At 31 December 2008 2007 

Remaining contract terms 1 year 9 months to 9 years 9 months 9 months to 11 years 

Contractual/notional amount 3,585 million therms 3,889 million therms

Discount rate – nominal risk free 2.5% 4.5%

$ million

At 31 December 2008 2007

Discount Discount

Gas price Oil price Power price rate Gas price Oil price Power price rate 

Favourable 10% change 291 81 27 16 317 72 37 31 

Unfavourable 10% change (289) (81) (27) (16) (368) (84) (34) (32)

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28. Financial instruments and financial risk factors continued 

(iii) Interest rate risk 

Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques as described 

above. This activity is described as interest rate trading in the value-at-risk table above. 

 BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial 

instruments, principally finance debt. 

 While the group issues debt in a variety of currencies based on market opportunities, it uses derivatives to swap the debt to a US dollar floating rate exposure 

but in certain defined circumstances maintains a fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 

December 2008 was 72% of total finance debt outstanding (2007 68%). The weighted average interest rate on finance debt at 31 December 2008 is 3% (2007 5%) 

and the weighted average maturity of fixed rate debt is three years (2007 two years). 

 The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates applicable to 

floating rate instruments were to have increased by 1% on 1 January 2009, it is estimated that the group’s profit before taxation for 2009 would decrease by 

approximately $239 million (2007 $168 million decrease in 2008). This assumes that the amount and mix of fixed and floating rate debt, including finance leases, 

remains unchanged from that in place at 31 December 2008 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 any other changes in general economic activity that may accompany such an increase in interest rates. 

(iv) Equity price risk 

The group holds equity investments, typically made for strategic purposes, that are classified as non-current available-for-sale financial assets and are measured 

initially at fair value with changes in fair value recognized directly in equity. Accumulated fair value changes are recycled to the income statement on disposal, or 

when the investment is impaired. Impairment losses of $546 million have been recognized in 2008 relating to listed non-current available-for-sale investments. For 

further information see Note 29. 

 At 31 December 2008, it is estimated that an increase of 10% in quoted equity prices would result in an immediate credit to equity of $59 million (2007 

$162 million credit to equity), whilst a decrease of 10% in quoted equity prices would result in an immediate charge to profit or loss of $48 million and a charge to 

equity of $11 million (2007 $162 million charge to equity). 

 At 31 December 2008, 56% (2007 70%) of the carrying amount of non-current available-for-sale financial assets represented the group’s stake in Rosneft, 

thus the group’s exposure is concentrated on changes in the share price of this equity in particular. 

(b) Credit risk 

Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the group and 

arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit exposures to customers 

relating to outstanding receivables. 

 The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to measure and 

control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent to which the 

arrangement exposes the group to credit risk is considered. Key requirements of the policy are formal delegated authorities to the sales and marketing teams to 

incur credit risk and to a specialized credit function to set counterparty limits; the establishment of credit systems and processes to ensure that counterparties are 

rated and limits set; and systems to monitor exposure against limits and report regularly on those exposures, and immediately on any excesses, and to track and 

report credit losses. The treasury function provides a similar credit risk management activity with respect to group-wide exposures to banks and other financial 

institutions. 

 In the current economic environment the group has placed increased emphasis on the management of credit risk. Policies and processes have been 

reviewed during the year and credit exposures with banks and others have been reduced through netting and collateral arrangements, or reduced activity where 

appropriate. 

 Before trading with a new counterparty can start, its creditworthiness is assessed and a credit rating is allocated that indicates the probability of default, along 

with a credit exposure limit. The assessment process takes into account all available qualitative and quantitative information about the counterparty and the group, 

if any, to which the counterparty belongs. The counterparty’s business activities, financial resources and business risk management processes are taken into 

account in the assessment, to the extent that this information is publicly available or otherwise disclosed to the group by the counterparty, together with external 

credit ratings, if any, including ratings prepared by Moody’s Investor Service and Standard & Poor’s. Creditworthiness continues to be evaluated after transactions 

have been initiated and a watchlist of higher-risk counterparties is maintained. Once assigned a credit rating, each counterparty is allocated a maximum exposure 

limit. 

 The group does not aim to remove credit risk but expects to experience a certain level of credit losses. The group attempts to mitigate credit risk by entering 

into contracts that permit netting and allow for termination of the contract on the occurrence of certain events of default. Depending on the creditworthiness of the 

counterparty, the group may require collateral or other credit enhancements such as cash deposits or letters of credit and parent company guarantees. Trade and 

other derivative assets and liabilities are presented on a net basis where unconditional netting arrangements are in place with counterparties and where there is an 

intent to settle amounts due on a net basis. The maximum credit exposure associated with financial assets is equal to the carrying amount. At 31 December 2008, 

the maximum credit exposure was $52,413 million (2007 $53,498 million). Collateral received and recognized in the balance sheet at the year-end was 

$1,121 million (2007 $39 million) and collateral held off balance sheet was $203 million (2007 $474 million). Credit exposure exists in relation to guarantees issued 

by group companies under which amounts outstanding at 31 December 2008 were $223 million (2007 $443 million) in respect of liabilities of jointly controlled 

entities and associates and $613 million (2007 $601 million) in respect of liabilities of other third parties. 

143

Notes on financial statements

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28. Financial instruments and financial risk factors continued 

Notwithstanding the processes described above, significant unexpected credit losses can occasionally occur. Exposure to unexpected losses increases with 

concentrations of credit risk that exist when a number of counterparties are involved in similar activities or operate in the same industry sector or geographical area, 

which may result in their ability to meet contractual obligations being impacted by changes in economic, political or other conditions. The group’s principal 

customers, suppliers and financial institutions with which it conducts business are located throughout the world. In addition, these risks are managed by maintaining 

a group watchlist and aggregating multi-segment exposures to ensure that a material credit risk is not missed. 

 Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by segment, 

and overall quality of the portfolio. The reports also include details of the largest counterparties by exposure level and expected loss, and details of counterparties 

on the group watchlist. 

 It is estimated that over 80% (2007 80%) of the counterparties to the contracts comprising the derivative financial instruments in an asset position are of 

investment grade credit quality. 

 Trade and other receivables of the group are analysed in the table below. By comparing the BP credit ratings to the equivalent external credit ratings, it is 

estimated that approximately 60-65% (2007 65-70%) of the trade receivables portfolio exposure are of investment grade quality. With respect to the trade and other 

receivables that are neither impaired nor past due, there are no indications as of the reporting date that the debtors will not meet their payment obligations. 

 The group does not typically renegotiate the terms of trade receivables; however, if a renegotiation does take place, the outstanding balance is included in 

the analysis based on the original payment terms. There were no significant renegotiated balances outstanding at 31 December 2008 or 31 December 2007. 

The movement in the valuation allowance for trade receivables is set out below. 

(c) Liquidity risk 

Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally with 

operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, subsidiaries pool their cash 

surpluses to treasury, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the market or arrange for necessary external 

borrowings, while managing the group’s overall net currency positions. 

 In managing its liquidity risk, the group has access to a wide range of funding at competitive rates through capital markets and banks. The group’s treasury 

function centrally co-ordinates relationships with banks, borrowing requirements, foreign exchange requirements and cash management. The group believes it has 

access to sufficient funding through the commercial paper markets and by using undrawn committed borrowing facilities to meet foreseeable borrowing 

requirements. At 31 December 2008, the group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,950 million, of 

which $4,550 million are in place until at least the fourth quarter of 2011 (2007 $4,950 million, of which $4,550 million are in place until at least the fourth quarter of 

2011). These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. 

 The group has in place a European Debt Issuance Programme (DIP) under which the group may raise $20 billion of debt for maturities of one month or 

longer. At 31 December 2008, the amount drawn down against the DIP was $10,334 million (2007 $10,438 million). In addition, the group has in place a US Shelf 

Registration under which it may raise $10 billion of debt with maturities of one month or longer. At 31 December 2008, the amount drawn down under the US Shelf 

was $6,500 million (2007 $2,500 million). 

 The group has long-term debt ratings of Aa1 (stable outlook) and AA (stable outlook), (2007 Aa1 (stable outlook) and AA+ (negative outlook)) assigned 

respectively by Moody’s and Standard and Poor’s. 

 Despite current uncertainty in the financial market including a lack of liquidity for some borrowers, we have been able to issue $5 billion of long-term debt in 

the fourth quarter of 2008. In addition, we have been able to issue short-term commercial paper at competitive rates. In the context of unforeseen market volatility, 

we have however, increased the cash and cash equivalents held by the group to $8.2 billion at the end of 2008 compared with $3.6 billion at the end of 2007. 

 The amounts shown for finance debt in the table below include expected interest payments on borrowings and the future minimum lease payments with 

respect to finance leases. 

144 

Notes on financial statements

$ million

Trade and other receivables at 31 December 2008 2007

Neither impaired nor past due 25,838 35,167

Impaired (net of valuation allowance) 73 145

Not impaired and past due in the following periods

within 30 days 1,323 2,350

31 to 60 days 489 273 

61 to 90 days 596 311

over 90 days 1,170 464

 29,489 38,710 

$ million

2008 2007

At 1 January 406 421

Exchange adjustments (32) 34

Charge for the year 191 175

Utilization (174) (224)

At 31 December 391 406

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Notes on financial statements 

 

28. Financial instruments and financial risk factors continued 

There are amounts included within finance debt that we show in the table below as due within one year to reflect the earliest contractual repayment dates but that 

are expected to be repaid over the maximum long-term maturity profiles of the contracts as described in Note 35. US Industrial Revenue/Municipal Bonds of

$3,166 million (2007 $2,880 million) with earliest contractual repayment dates within one year have expected repayment dates ranging from 1 to 40 years (2007 1 

to 35 years). The bondholders typically have the option to tender these bonds for repayment on interest reset dates; however, 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 internally assessing 

the maturity profile of its finance debt. Similar treatment is applied for loans associated with long-term gas supply contracts totalling $1,806 million (2007 

$1,899 million) that mature within nine years. 

 The table also shows the timing of cash outflows relating to trade and other payables and accruals. 

The group manages liquidity risk associated with derivative contracts on a portfolio basis, considering both physical commodity sale and purchase contracts 

together with financially-settled derivative assets and liabilities. 

 The held-for-trading derivatives amounts in the table below represent the total contractual cash outflows by period for the purchases of physical commodities 

under derivative contracts and the estimated cash outflows of financially-settled derivative liabilities. The group also holds derivative contracts for the sale of 

physical commodities and financially-settled derivative assets that are expected to generate cash inflows that will be available to the group to meet cash outflows on 

purchases and liabilities. These contracts are excluded from the table below. The amounts disclosed for embedded derivatives represent the contractual cash 

outflows of purchase contracts some of which have embedded derivatives associated with them which are financial assets. 

The table below shows cash outflows for derivative hedging instruments based upon contractual payment dates. The amounts reflect the maturity profile of the fair 

value liability where the instruments will be settled net, and the gross settlement amount where the pay leg of a derivative will be settled separately to the receive 

leg, as in the case of cross-currency interest rate swaps hedging non-US dollar finance debt. The swaps are with high investment-grade counterparties and

therefore the settlement day risk exposure is considered to be negligible. 

145

$ million

At 31 December 2008 2007

Trade and Trade and

other Finance other Finance

payables Accruals debt payables Accruals debt 

Within one year 30,598 6,743 16,670 39,576 6,640 16,561 

1 to 2 years 402 359 5,934 147 351 8,011

2 to 3 years 898 77 3,419 62 245 3,515

3 to 4 years 902 72 2,647 26 78 1,447

4 to 5 years 223 67 5,072 30 49 2,352

5 to 10 years 53 164 1,316 197 200 1,100 

Over 10 years 64 45 1,050 24 36 1,447

 33,140 7,527 36,108 40,062 7,599 34,433

$ million

At 31 December 2008 2007

Held-for- Held-forEmbedded trading Embedded trading

derivatives derivatives derivatives derivatives 

Within one year 562 60,270 699 82,465 

1 to 2 years 403 8,189 659 8,541

2 to 3 years 470 2,437 641 2,906

3 to 4 years 509 1,111 627 707

4 to 5 years 535 841 624 338

5 to 10 years 1,538 2,087 2,342 592 

Over 10 years – 553 – 447

 4,017 75,488 5,592 95,996

$ million

At 31 December 2008 2007

Within one year 3,426 1,708

1 to 2 years 3,024 1,220 

2 to 3 years 1,037 3,759

3 to 4 years 1,731 365

4 to 5 years 1,389 1,650

5 to 10 years 129 105

 10,736 8,807

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29. Other investments 

Other investments comprise equity investments that have no fixed maturity date or coupon rate. 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 changes in fair value recorded directly in equity. Accumulated fair value 

changes are recycled to the income statement on disposal, or when the investment is impaired. 

 The fair value of listed investments has been determined by reference to quoted market bid prices. Unlisted investments are stated at cost less accumulated 

impairment losses. 

 The most significant investment is the group’s stake in Rosneft which had a fair value of $483 million at 31 December 2008 (2007 $1,285 million). During 

2008, an impairment loss of $517 million was recognized relating to the Rosneft investment (see Note 11), $29 million relating to other listed investments and 

$17 million relating to unlisted investments (2007 $80 million relating to unlisted investments). 

30. Inventories 

The inventory valuation at 31 December 2008 is stated net of a provision of $1,412 million (2007 $117 million) to write inventories down to their net realizable value. 

The net movement in the provision during the year was a charge of $1,295 million (2007 $86 million credit). 

31. Trade and other receivables 

Trade and other receivables are predominantly non-interest bearing. 

146 

Notes on financial statements

 

 $ million 

2008 2007 

Listed 592 1,617

Unlisted 263 213

 855 1,830

$ million

2008 2007

Crude oil 4,396 8,157

Natural gas 107 160

Refined petroleum and petrochemical products 9,318 14,723

13,821 23,040

Supplies 1,588 1,517

15,409 24,557

Trading inventories 1,412 1,997

 16,821 26,554

Cost of inventories expensed in the income statement 266,982 200,766

$ million

2008 2007

Current Non-current Current Non-current

Financial assets

Trade receivables 22,869 – 33,012 –

Amounts receivable from jointly controlled entities 1,035 – 888 –

Amounts receivable from associates 219 – 380 – 

Other receivables 4,656 710 3,462 968

28,779 710 37,742 968

Non-financial assets

Other receivables 482 – 278 – 

 29,261 710 38,020 968 

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32. 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. 

 Cash and cash equivalents at 31 December 2008 includes $2,133 million (2007 $1,294 million) that is restricted. This relates principally to amounts on 

deposit to cover initial margins on trading exchanges. 

33. Trade and other payables 

Trade and other payables are predominantly interest free. 

147

Notes on financial statements

 

 $ million 

2008 2007 

Cash at bank and in hand 4,001 2,996

Cash equivalents 

Listed 4,060 3 

Unlisted 136 563

 8,197 3,562

$ million

2008 2007

Current Non-current Current Non-current

Financial liabilities

Trade payables 20,129 – 30,735 – 

Amounts payable to jointly controlled entities 292 2,255 66 –

Amounts payable to associates 295 – 650 –

Other payables 9,882 287 8,125 486

30,598 2,542 39,576 486

Non-financial liabilities 

Production and similar taxes 445 538 803 765

Other payables 2,601 – 2,773 –

3,046 538 3,576 765

33,644 3,080 43,152 1,251

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34. Derivative financial instruments 

An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 28. 

 IAS 39 prescribes strict criteria for hedge accounting, whether as a cash flow or fair value hedge or a hedge of a net investment in a foreign operation, and 

requires that any derivative that does not meet these criteria should be classified as held for trading and fair valued, with gains and losses recognized in profit or 

loss. 

 In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation to 

commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt, consistent 

with risk management policies and objectives. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in conjunction with 

these activities using a similar range of contracts. 

 The fair values of derivative financial instruments at 31 December are set out below. 

Derivatives held for trading 

The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply 

requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are recognized at 

fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types in combination to 

create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored using market value-at-risk 

techniques as described in Note 28. 

 The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes. 

 Changes during the year in the net fair value of derivatives held for trading purposes were as follows. 

148 

Notes on financial statements

 $ million 

2008 2007

Fair Fair Fair Fair 

value value value value

asset liability asset liability

Derivatives held for trading

Currency derivatives 278 (273) 147 (317)

Oil price derivatives 3,813 (3,523) 3,214 (3,432)

Natural gas price derivatives 6,945 (6,113) 4,388 (4,022)

Power price derivatives 978 (904) 1,121 (1,140)

Other derivatives 90 (96) 30 –

12,104 (10,909) 8,900 (8,911)

Embedded derivatives

Commodity contracts 397 (2,264) 255 (2,340)

Interest rate contracts – – – (33)

397 (2,264) 255 (2,373)

Cash flow hedges

Currency forwards, futures and cylinders 120 (1,175) 226 (45)

Cross-currency interest rate swaps 109 (558) 122 (52)

229 (1,733) 348 (97)

Fair value hedges 

Cross-currency interest rate swaps 465 (342) 430 (9)

Interest rate swaps 367 – 89 (17)

832 (342) 519 (26)

Hedges of net investments in foreign operations 2 – 40 – 

 13,564 (15,248) 10,062 (11,407)

Of which – current 8,510 (8,977) 6,321 (6,405)

– non-current 5,054 (6,271) 3,741 (5,002)

$ million

Oil Natural gas Power

Currency price price price Other Total

Fair value of contracts at 1 January 2008 (170) (218) 366 (19) 30 (11)

Contracts realized or settled in the year 24 190 (216) 3 (15) (14)

Fair value of options at inception – (216) (201) 34 – (383)

Fair value of other new contracts entered into during the year – 66 49 – – 115

Changes in fair values relating to price 151 468 881 60 (21) 1,539

Exchange adjustments – – (47) (4) – (51)

Fair value of contracts at 31 December 2008 5 290 832 74 (6) 1,195

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34. Derivative financial instruments continued 

If at inception of a contract the valuation cannot be supported by observable market data, any gain determined by the valuation methodology is not recognized in 

the income statement but is deferred on the balance sheet and is commonly known as ‘day-one profit’. This deferred gain is recognized in the income statement 

over the life of the contract until substantially all of the remaining contract term can be valued using observable market data at which point any remaining deferred 

gain is recognized in income. Changes in valuation from this initial valuation are recognized immediately through income. 

 The following table shows the changes in the day-one profits deferred on the balance sheet. 

Derivative assets held for trading have the following fair values and maturities. 

Derivative liabilities held for trading have the following fair values and maturities. 

149

Notes on financial statements

$ million

Oil Natural gas Power

Currency price price price Other Total

Fair value of contracts at 1 January 2007 105 296 855 42 113 1,411

Contracts realized or settled in the year (109) (289) (602) (68) (83) (1,151)

Fair value of options at inception – 28 168 36 – 232

Fair value of other new contracts entered into during the year – – 1 – – 1 

Changes in fair values relating to price (167) (253) (58) (20) – (498)

Exchange adjustments 1 – 2 (9) – (6)

Fair value of contracts at 31 December 2007 (170) (218) 366 (19) 30 (11)

$ million

2008 2007

Natural Natural

Oil price gas price Oil price gas price

Fair value of contracts not recognized through the income statement at 1 January – 36 – 36

Fair value of new contracts at inception not recognized in the income statement 66 49 – 1 

Fair value recognized in the income statement (34) (2) – (1)

Fair value of contracts not recognized through profit at 31 December 32 83 – 36

 

 $ million 

 2008

Less than Over 

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Currency derivatives 53 90 67 37 20 11 278

Oil price derivatives 3,368 353 61 11 11 9 3,813

Natural gas price derivatives 3,940 1,090 545 436 271 663 6,945

Power price derivatives 688 256 31 1 2 – 978

Other derivatives 90 – – – – – 90

 8,139 1,789 704 485 304 683 12,104

$ million

2007

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Currency derivatives 123 10 6 5 1 2 147

Oil price derivatives 2,545 471 113 39 26 20 3,214 

Natural gas price derivatives 2,170 677 333 283 216 709 4,388

Power price derivatives 819 250 52 – – – 1,121

Other derivatives 12 18 – – – – 30

5,669 1,426 504 327 243 731 8,900

$ million

2008

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Currency derivatives (257) – (2) (1) (13) – (273)

Oil price derivatives (3,001) (458) (36) (18) (9) (1) (3,523)

Natural gas price derivatives (3,484) (987) (438) (310) (283) (611) (6,113)

Power price derivatives (722) (159) (18) (4) (1) – (904)

Other derivatives (95) (1) – – – – (96)

 (7,559) (1,605) (494) (333) (306) (612) (10,909)

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34. Derivative financial instruments continued 

The following table shows the fair value of derivative assets held for trading, analysed by maturity period and by methodology of fair value estimation. 

The following table shows the fair value of derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation. 

Prices actively quoted refers to the fair value of contracts valued solely using quoted prices in an active market. Prices sourced from observable data or market 

corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data, 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 was a gain of $253 million (2007 $94 million loss and 2006 $117 million loss). 

 Gains and losses relating to derivative contracts are included either within sales and other operating revenues or within purchases in the income statement 

depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures, options, swaps and certain forward 

sales and forward purchases contracts. Gains or losses arise on contracts entered into for risk management purposes, optimization activity and entrepreneurial 

trading. They also arise on certain contracts that are for normal procurement or sales activity for the group but that are required to be fair valued under accounting 

standards. Also included within sales and other operating revenues are gains and losses on inventory held for trading purposes. The total amount relating to all of 

these items was a gain of $6,721 million (2007 $376 million gain and 2006 $2,842 million gain). 

150 

Notes on financial statements

$ million

2007

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Currency derivatives (145) (99) (32) (16) (15) (10) (317)

Oil price derivatives (2,735) (512) (135) (25) (22) (3) (3,432)

Natural gas price derivatives (2,089) (527) (298) (219) (185) (704) (4,022)

Power price derivatives (832) (246) (61) (1) – – (1,140)

 (5,801) (1,384) (526) (261) (222) (717) (8,911)

 $ million 

 2008

Less than Over 

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Prices actively quoted 40 43 30 7 6 2 128

Prices sourced from observable data or market 

corroboration 7,628 1,614 553 361 190 56 10,402

Prices based on models and other valuation methods 471 132 121 117 108 625 1,574

8,139 1,789 704 485 304 683 12,104

 $ million 

 2007 

 Less than Over 

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Prices actively quoted 169 53 49 3 – 2 276

Prices sourced from observable data or market 

corroboration 5,417 1,174 363 225 140 – 7,319 

Prices based on models and other valuation methods 83 199 92 99 103 729 1,305

5,669 1,426 504 327 243 731 8,900

$ million

2008

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Prices actively quoted (227) – (2) – (13) – (242)

Prices sourced from observable data or market 

corroboration (6,997) (1,482) (365) (209) (182) (27) (9,262)

Prices based on models and other valuation methods (335) (123) (127) (124) (111) (585) (1,405)

 (7,559) (1,605) (494) (333) (306) (612) (10,909)

$ million

2007

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Prices actively quoted (50) (50) – (1) (9) (1) (111)

Prices sourced from observable data or market 

corroboration (5,629) (1,116) (420) (143) (103) – (7,411)

Prices based on models and other valuation methods (122) (218) (106) (117) (110) (716) (1,389)

 (5,801) (1,384) (526) (261) (222) (717) (8,911)

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34. Derivative financial instruments continued 

Embedded derivatives 

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, 

power and inflation. After 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. 

 All the embedded derivatives are valued using inputs that include price curves for each of the different products that are built up from active market pricing 

data. Where necessary, these are extrapolated to the expiry of the contracts (the last of which is in 2018) using all available external pricing information. 

Additionally, where limited data exists for certain products, prices are interpolated using historic and long-term pricing relationships. 

 The following table shows the changes during the year in the net fair value of embedded derivatives. 

Embedded derivative assets have the following fair values and maturities. 

Embedded derivative liabilities have the following fair values and maturities. 

151

Notes on financial statements

 $ million 

 2008 2007 

Commodity Interest Commodity Interest 

price rate Total price rate Total

Fair value of contracts at 1 January (2,085) (33) (2,118) (2,064) (26) (2,090)

Contracts realized or settled in the year 294 38 332 449 – 449

Changes in valuation techniques or key assumptions – – – 130 – 130 

Changes in fair values relating to price (928) (5) (933) (567) (7) (574)

Exchange adjustments 852 – 852 (33) – (33)

Fair value of contracts at 31 December (1,867) – (1,867) (2,085) (33) (2,118)

$ million

2008

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Commodity price embedded derivatives 50 116 75 45 36 75 397

$ million

2007

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Commodity price embedded derivatives 193 18 15 7 10 12 255

$ million

2008

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Commodity price embedded derivatives (404) (322) (365) (303) (271) (599) (2,264)

 

$ million

2007

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Commodity price embedded derivatives (554) (437) (299) (244) (219) (587) (2,340)

Interest rate embedded derivatives (33) – – – – – (33)

 (587) (437) (299) (244) (219) (587) (2,373)

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34. Derivative financial instruments continued 

Embedded derivative assets have the following fair values when analysed by maturity period and by methodology of fair value estimation. 

Embedded derivative liabilities have the following fair values when analysed by maturity period and by methodology of fair value estimation. 

The net change in fair value of contracts based on models and other valuation methods during the year is a gain of $287 million (2007 gain of $18 million and 2006 

gain of $423 million). 

 The fair value gain (loss) on embedded derivatives is shown below. 

The fair value gain (loss) in the above table includes $496 million of exchange gains (2007 $12 million of exchange losses and 2006 $179 million of exchange 

losses) arising on contracts that are denominated in a currency other than the functional currency of the individual operating unit. 

152 

Notes on financial statements

$ million

2008

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Prices actively quoted – – – – – – –

Prices sourced from observable data or market corroboration 35 – – – – – 35

Prices based on models and other valuation methods 15 116 75 45 36 75 362

50 116 75 45 36 75 397

 $ million 

 2007 

 Less than Over 

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Prices actively quoted – – – – – – –

Prices sourced from observable data or market corroboration 61 – – – – – 61

Prices based on models and other valuation methods 132 18 15 7 10 12 194

193 18 15 7 10 12 255

 

 $ million

2008

Less than Over

1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total

Prices actively quoted – – – – – – –

Prices sourced from observable data or market corroboration (10) – – – – – (10)

Prices based on models and other valuation methods (394) (322) (365) (303) (271) (599) (2,254)

(404) (322) (365) (303) (271) (599) (2,264)

$ million

2007

Less than Over

 1 year 1-2 years 2-3 years 3-4 years 4-5 years 5 years Total 

Prices actively quoted – – – – – – – 

Prices sourced from observable data or market corroboration – – – – – – –

Prices based on models and other valuation methods (587) (437) (299) (244) (219) (587) (2,373)

 (587) (437) (299) (244) (219) (587) (2,373)

 

 $ million 

2008 2007 2006 

Commodity price embedded derivatives (106) – 604 

Interest rate embedded derivatives (5) (7) 4

Fair value (loss) gain (111) (7) 608

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34. Derivative financial instruments continued 

Cash flow hedges 

At 31 December 2008, the group held currency forwards and futures contracts and cylinders that were being used to hedge the foreign currency risk of highly 

probable forecast transactions, as well as cross-currency interest rate swaps to fix the US dollar interest rate and US dollar redemption value, with matching critical 

terms on the currency leg of the swap with the underlying non-US dollar debt issuance. Note 28 outlines the management of risk aspects for currency and interest 

rate risk. For cash flow hedges the group only claims for the intrinsic value on the currency with any fair value attributable to time value taken immediately to profit 

or loss. There were no highly probable transactions for which hedge accounting has been claimed that have not occurred and no significant element of hedge 

ineffectiveness requiring recognition in the income statement. For cash flow hedges the pre-tax amount removed from equity during the period and included in the 

income statement is a loss of $45 million (2007 gain of $74 million and 2006 gain of $93 million). Of this, a loss of $1 million is included in production and 

manufacturing expenses (2007 $143 million gain and 2006 $162 million gain) and a loss of $44 million is included in finance costs (2007 $69 million loss and 2006 

$69 million loss). The amount removed from equity during the year and included in the carrying amount of non-financial assets was a gain of $38 million (2007 $40 

million gain and 2006 $6 million gain). 

 The amounts retained in equity at 31 December 2008 are expected to mature and affect the income statement by a $826 million loss in 2009, a loss of 

$92 million in 2010 and a loss of $182 million in 2011 and beyond. 

Fair value hedges 

At 31 December 2008, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk on fixed rate debt 

issued by the group. The effectiveness of each hedge relationship is quantitatively assessed and demonstrated to continue to be highly effective. The gain on the 

hedging derivative instruments taken to the income statement in 2008 was $2 million (2007 $334 million gain and 2006 $257 million gain) offset by a loss on the fair 

value of the finance debt of $20 million (2007 $327 million loss and 2006 $257 million loss). 

 The interest rate and cross-currency interest rate swaps have an average maturity of three to four years, (2007 one to two years) and are used to convert 

sterling, euro, Swiss franc and Australian dollar denominated borrowings into US dollar floating rate debt. Note 28 outlines the group’s approach to interest rate risk 

management. 

Hedges of net investments in foreign operations 

The group holds currency swap contracts as a hedge of a long-term investment in a UK subsidiary expiring in 2009. At 31 December 2008, the hedge had a fair 

value of $2 million (2007 $40 million) and the loss on the hedge recognized in equity in 2008 was $38 million (2007 $67 million loss and 2006 $105 million gain). US 

dollars have been sold forward for sterling purchased and match the underlying liability with no significant ineffectiveness reflected in the income statement. 

35. Finance debt 

153

Notes on financial statements

$ million

2008 2007

Within After Within After

1 yeara 1 year Total 1 year a 1 year Total

Borrowings 15,647 16,937 32,584 15,149 15,004 30,153

Net obligations under finance leases 93 527 620 245 647 892 

 15,740 17,464 33,204 15,394 15,651 31,045

aAmounts due within one year include current maturities of long-term debt and borrowings that are expected to be repaid later than the earliest contractual repayment dates of within one year. US Industrial 

Revenue/Municipal Bonds of $3,166 million (2007 $2,880 million) with earliest contractual repayment dates within one year have expected repayment dates ranging from 1 to 40 years (2007 1 to 35 years). The 

bondholders typically have the option to tender these bonds for repayment on interest reset dates; however, 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 internally assessing the maturity profile of its finance debt. Similar treatment is applied for loans associated with long-term gas supply 

contracts totalling $1,806 million (2007 $1,899 million) that mature within nine years. 

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35. Finance debt continued 

The following table shows, by major currency, the group’s finance debt at 31 December and the weighted average interest rates achieved at those dates through a 

combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures. 

Finance leases 

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. Future minimum lease payments under finance leases are set out below. 

Fair values 

The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet. 

 Long-term borrowings in the table below include the portion of debt that matures in the year from 31 December 2008, whereas in the balance sheet the 

amount would be reported within current liabilities. 

 The carrying amount of the group’s short-term borrowings, comprising mainly commercial paper, bank loans, overdrafts and US Industrial Revenue/Municipal 

Bonds, 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. 

154 

Notes on financial statements

Fixed rate debt Floating rate debt

Weighted

Weighted average Weighted 

average time for average

interest which rate interest

rate is fixed Amount rate Amount Total

% Years $ million % $ million $ million

2008

US dollar 5 3 9,005 2 22,116 31,121

Sterling – – – 6 21 21

Euro 4 3 74 4 1,330 1,404

Other currencies 7 10 216 7 442 658

 9,295 23,909 33,204

2007

US dollar 5 2 9,541 5 20,460 30,001

Sterling – – – 6 35 35 

Euro 4 4 81 5 107 188

Other currencies 7 13 268 7 553 821

 9,890 21,155 31,045 

$ million

2008 2007

Future minimum lease payments payable within

1 year 116 268 

2 to 5 years 361 393

Thereafter 439 630

 916 1,291 

Less finance charges 296 399

Net obligations 620 892

Of which – payable within 1 year 93 245

– payable within 2 to 5 years 234 217 

– payable thereafter 293 430

$ million

2008 2007

Carrying Carrying

Fair value amount Fair value amount 

Short-term borrowings 9,913 9,913 11,212 11,212 

Long-term borrowings 23,239 22,671 19,094 18,941

Net obligations under finance leases 638 620 908 892

Total finance debt 33,790 33,204 31,214 31,045 

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36. Capital disclosures and analysis of changes in net debt

The group defines capital as the total equity of the group. The group’s objective for managing capital is to deliver competitive, secure and sustainable returns to 

maximize long-term shareholder value. BP is not subject to any externally-imposed capital requirements. 

 The group’s approach to managing capital is set out in its financial framework. The group aims to balance returns to shareholders between long-term growth 

and current returns via the dividend whilst maintaining capital discipline in relation to investing activities and taking action on costs to respond to the current 

environment. At the beginning of 2008, the group rebalanced returns to shareholders by increasing the dividend component. As a result, the share buyback 

programme was curtailed and then suspended in September in light of the uncertain environment. 

 The group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross finance debt, 

as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks 

relating to finance debt, for which hedge accounting is claimed, less cash and cash equivalents. Net debt and net debt ratio are non-GAAP measures. BP uses 

these measures to provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash 

equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. The derivatives are reported on the 

balance sheet within the headings ‘Derivative financial instruments’. All components of equity are included in the denominator of the calculation. We believe that a 

net debt ratio in the range 20-30% provides an efficient capital structure and an appropriate level of financial flexibility. 

 At 31 December 2008 the net debt ratio was 21% (2007 22%). 

An analysis of changes in net debt is provided below. 

Revised definition of net debt 

Net debt has been redefined to include the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks 

relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on the balance sheet within the headings ‘Derivative financial 

instruments’. Amounts for comparative periods are presented on a consistent basis. 

155

Notes on financial statements

 $ million 

At 31 December 2008 2007 

Gross debt 33,204 31,045 

Less: Cash and cash equivalents 8,197 3,562

Less: Fair value (liability) asset of hedges related to finance debt (34) 666

Net debt 25,041 26,817 

Equity 92,109 94,652 

Net debt ratio 21% 22%

 $ million 

 2008 2007 

 Cash and Cash and 

Finance cash Net Finance cash Net

Movement in net debt debta equivalents debt debta equivalents debt

At 1 January (30,379) 3,562 (26,817) (23,712) 2,590 (21,122)

Exchange adjustments 102 (184) (82) (122) 135 13

Net cash flow (2,825) 4,819 1,994 (6,411) 837 (5,574)

Other movements (136) – (136) (134) – (134)

At 31 December (33,238) 8,197 (25,041) (30,379) 3,562 (26,817)

aIncluding fair value of associated derivative financial instruments.

$ million

2007

As amended As reported

Net debt 26,817 27,483

Equity 94,652 94,652

Ratio of net debt to net debt plus equity 22% 23%

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37. Provisions 

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. The provision for the costs of decommissioning these production facilities and pipelines at the end of their economic lives has been 

estimated using existing technology, at current prices or long-term assumptions, depending on the expected timing of the activity, and discounted using a real 

discount rate of 2.0% (2007 2.0%). These costs are generally 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. Where BP has 

entered into a contract for the execution of decommissioning activity, these amounts are generally reported within accruals or other payables. 

 Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be reliably estimated. Generally, this 

coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provision for environmental liabilities has been 

estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2007 2.0%). 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 the liability. 

 Included within the litigation and other category at 31 December 2008 are provisions for litigation of $1,446 million (2007 $1,737 million), for deferred 

employee compensation of $792 million (2007 $761 million) and for expected rental shortfalls on surplus properties of $251 million (2007 $320 million). 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 2.5% 

(2007 4.5%) or a real discount rate of 2.0% (2007 2.0%), as appropriate. No additional provisions were made during 2008 in respect of the Texas City incident (in 

2007 the provision was increased by $500 million). Disbursements to claimants in 2008 were $410 million (2007 $314 million) and the provision at 31 

December 2008 was $46 million (2007 $456 million). 

156 

Notes on financial statements

 

 $ million

 Litigation 

Decommissioning Environmental and other Total

At 1 January 2008 9,501 2,107 3,487 15,095

Exchange adjustments (1,208) (45) (107) (1,360)

New or increased provisions 327 270 2,059 2,656

Write-back of unused provisions – (107) (513) (620)

Unwinding of discount 202 43 42 287

Utilization (402) (512) (1,424) (2,338)

Deletions (2) (65) – (67)

At 31 December 2008 8,418 1,691 3,544 13,653

Of which – expected to be incurred within 1 year 322 418 805 1,545

– expected to be incurred in more than 1 year 8,096 1,273 2,739 12,108

$ million

Litigation

 Decommissioning Environmental and other Total

At 1 January 2007 8,365 2,127 3,152 13,644 

Exchange adjustments 168 19 11 198

New or increased provisions 1,163 373 1,376 2,912

Write-back of unused provisions – (151) (196) (347)

Unwinding of discount 195 44 44 283

Utilization (297) (305) (899) (1,501)

Deletions (93) – (1) (94)

At 31 December 2007 9,501 2,107 3,487 15,095

Of which – expected to be incurred within 1 year 447 431 1,317 2,195

– expected to be incurred in more than 1 year 9,054 1,676 2,170 12,900 

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38. Pensions and other post-retirement 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. 

 In particular, the primary pension arrangement in the UK is a funded final salary pension plan that remains open to new employees. Retired employees draw 

the majority of their benefit as an annuity. 

 In the US, a range of retirement arrangements is provided. These include a funded final salary pension plan for certain heritage employees and a cash 

balance arrangement for new hires. Retired US employees typically take their pension benefit in the form of a lump sum payment. US employees are also eligible to 

participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions. 

 The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due. 

During 2008, contributions of $6 million (2007 $524 million and 2006 $438 million) and $362 million (2007 $97 million and 2006 $181 million) were made to the UK 

plans and US plans respectively. In addition, contributions of $130 million (2007 $127 million and 2006 $136 million) were made to other funded defined benefit 

plans. The aggregate level of contributions in all countries in 2009 is expected to be approximately $500 million, and includes contributions that we expect to be 

required to make by law or under contractual agreements as well as an allowance for discretionary funding. 

 Certain group companies, principally in the US, provide post-retirement 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 obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date of the 

most recent actuarial review was 31 December 2008. 

 The material financial assumptions used for estimating the benefit obligations of the various plans are set out below. The assumptions are reviewed by 

management at the end of each year, and are used to evaluate accrued pension and other post-retirement benefits at 31 December. The same assumptions are 

used to determine pension and other post-retirement benefit expense for the following year, that is, the assumptions at 31 December 2008 are used to determine 

the pension liabilities at that date and the pension expense for 2009. 

Our discount rate assumptions are based on third-party AA corporate bond indices and for our largest schemes in the UK and US we use yields which reflect the 

maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US schemes are based on the difference between the yields on 

index-linked and fixed-interest long-term government bonds. In other countries we use either this approach, or the central bank inflation target, or advice from the 

local actuary depending on the information that is available to us. The inflation assumptions are used to determine the rate of increase for pensions in payment and 

the rate of increase for deferred pensions where there is such an increase. 

 Our assumptions for the rate of increase in salaries are based on our inflation assumption plus an allowance for expected long-term real salary growth. These 

include allowance for promotion-related salary growth, of between 0.3% and 0.4% depending on country. In addition to the financial assumptions, we regularly 

review the demographic and mortality assumptions. 

157

Notes on financial statements

 % 

Financial assumptions UK US Other 

2008 2007 2006 2008 2007 2006 2008 2007 2006

Discount rate for pension plan liabilities 6.3 5.7 5.1 6.3 6.1 5.7 5.7 5.6 4.8

Discount rate for post-retirement benefit plans n/a n/a n/a 6.2 6.4 5.9 n/a n/a n/a

Rate of increase in salaries 4.9 5.1 4.7 2.2 4.2 4.2 3.5 3.7 3.6 

Rate of increase for pensions in payment 3.0 3.2 2.8 – – – 1.7 1.8 1.8

Rate of increase in deferred pensions 3.0 3.2 2.8 – – – 1.0 1.2 1.1 

Inflation 3.0 3.2 2.8 0.4 2.4 2.4 2.0 2.2 2.2

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38. Pensions and other post-retirement benefits continued 

Mortality assumptions reflect best practice in the countries in which we provide pensions, and have been chosen with regard to the latest available published tables 

adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. As part of the triannual 

valuation of our UK pensions funds, our UK mortality assumption was reviewed and updated at end-2008 resulting in an increase in the liability of around $900 

million. BP’s most substantial pension liabilities are in the UK, the US and Germany where our mortality assumptions are as follows: 

Our assumptions for future US healthcare cost trend rate reflect the rate of actual cost increases seen in recent years for the initial trend rate, and the ultimate trend 

rate reflects our long-term expectations based on past medical inflation seen over a longer period of time. The assumed future US healthcare cost trend rate is as 

follows: 

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: 

Some of the group’s pension plans use derivative financial instruments as part of their asset mix and to manage the level of risk. The group’s main pension plans 

do not invest directly in either securities or property/real estate of the company or of any subsidiary. 

 Return on asset assumptions reflect the group’s expectations built up by asset class and by plan. The group’s expectation is derived from a combination of 

historical returns over the long term and the forecasts of market professionals. Our assumption for return on equities is based on a long-term view, and the size of 

the resulting equity risk premium over government bond yields is reviewed each year for reasonableness. Our assumption for return on bonds reflects the portfolio 

mix of government fixed-interest, index-linked and corporate bonds. 

158 

Notes on financial statements

Years

Mortality assumptions UK US Germany

2008 2007 2006 2008 2007 2006 2008 2007 2006

Life expectancy at age 60 for a male currently aged 60 25.9 24.0 23.9 24.4 24.3 24.2 23.0 22.4 22.2

Life expectancy at age 60 for a male currently aged 40 28.9 25.1 25.0 25.9 25.8 25.8 25.9 25.3 25.2

Life expectancy at age 60 for a female currently aged 60 28.5 26.9 26.8 26.1 26.1 26.0 27.6 27.0 26.9

Life expectancy at age 60 for a female currently aged 40 31.4 27.9 27.8 27.0 27.0 26.9 30.3 29.7 29.6 

%

2008 2007 2006

Initial US healthcare cost trend rate 8.6 9.0 9.3

Ultimate US healthcare cost trend rate 5.0 5.0 5.0 

Year in which ultimate trend rate is reached 2015 2013 2013

 Policy range 

Asset category %

Total equity 45-75

Bonds/cash 17.5-50

Property/real estate 0-10 

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38. Pensions and other post-retirement benefits continued 

The expected long-term rates of return and market values of the various categories of asset held by the defined benefit plans at 31 December are set out below. 

The market values shown include the effects of derivative financial instruments. The amounts classified as equities include investments in companies listed on 

stock exchanges as well as unlisted investments. The market value of unlisted investments at 31 December 2008 was $2,819 million (2007 $2,491 million and 2006 

$1,506 million). The market value of pension assets at the end of 2008 is lower than at the end of 2007 due to a fall in the market value of investments when 

expressed in their local currencies and a reduction in value that arises from changes in exchange rates (reducing the reported value of investments when 

expressed in US dollars). Movements in the value of plan assets during the year are shown in detail in the table on page 160. 

The assumed rate of investment return, discount rate, inflation and the assumed US healthcare cost trend rate all 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: 

159

Notes on financial statements

2008 2007 2006

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 8.0 13,704 8.0 24,106 7.5 23,631

Bonds 6.1 3,258 4.4 5,279 4.7 3,881 

Property 6.5 978 6.5 1,259 6.5 1,370

Cash 2.9 299 5.6 977 3.8 379

 7.4 18,239 7.3 31,621 7.0 29,261 

US pension plans 

Equities 8.5 3,991 8.5 6,610 8.5 6,528

Bonds 3.7 1,247 5.0 1,347 5.0 1,371

Property 8.0 8 8.0 16 8.0 15

Cash 1.9 131 3.6 72 3.2 41

 8.0 5,377 8.0 8,045 8.0 7,955

US other post-retirement benefit plans

Equities 8.5 9 8.5 17 8.5 19

Bonds 3.7 4 5.0 6 5.0 7

 7.3 13 7.6 23 7.5 26

Other plans 

Equities 8.4 799 8.1 1,260 7.6 1,158

Bonds 4.2 1,481 5.0 1,491 4.6 1,199

Property 6.3 127 5.7 145 4.7 120 

Cash 3.1 118 4.2 214 3.0 191

 5.8 2,525 6.4 3,110 5.8 2,668

 $ million 

One-percentage point

Increase Decrease

Investment return 

Effect on pension and other post-retirement benefit expense in 2009 (256) 258

Discount rate

Effect on pension and other post-retirement benefit expense in 2009 (88) 129

Effect on pension and other post-retirement benefit obligation at 31 December 2008 (3,783) 4,818

Inflation rate 

Effect on pension and other post-retirement benefit expense in 2009 375 (286)

Effect on pension and other post-retirement benefit obligation at 31 December 2008 3,407 (2,783)

US healthcare cost trend rate

Effect on US other post-retirement benefit expense in 2009 29 (23)

Effect on US other post-retirement obligation at 31 December 2008 335 (277)

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38. Pensions and other post-retirement benefits continued 

At 31 December 2008 reimbursement balances due from or to other companies in respect of pensions amounted to $455 million reimbursement assets (2007 

$496 million) and $61 million reimbursement liabilities (2007 $72 million). These balances are not included as part of the pension liability, but are reflected 

elsewhere in the group balance sheet. 

160 

Notes on financial statements

$ million

2008

US other postUK US retirement

pension pension benefit Other 

plans plans plans plans Total

Analysis of the amount charged to profit before interest and taxation

Current service costa 448 235 40 128 851

Past service cost 7 74 – 1 82

Settlement, curtailment and special termination benefits 30 – – 12 42

Payments to defined contribution plans – 170 – 25 195

Total operating chargeb 485 479 40 166 1,170

Analysis of the amount credited (charged) to other finance expense 

Expected return on plan assets 2,094 632 2 194 2,922

Interest on plan liabilities (1,239) (444) (198) (450) (2,331)

Other finance income (expense) 855 188 (196) (256) 591

Analysis of the amount recognized in the statement of recognized income and expense

Actual return less expected return on pension plan assets (6,946) (2,895) (8) (404) (10,253)

Change in assumptions underlying the present value of the plan liabilities 1,570 3 215 214 2,002

Experience gains and losses arising on the plan liabilities (73) (194) 18 70 (179)

Actuarial (loss) gain recognized in statement of recognized income and expense (5,449) (3,086) 225 (120) (8,430)

Movements in benefit obligation during the year

Benefit obligation at 1 January 23,927 7,409 3,178 8,586 43,100

Exchange adjustments (6,408) – – (628) (7,036)

Current service costa 448 235 40 128 851

Past service cost 7 74 – 1 82

Interest cost 1,239 444 198 450 2,331

Curtailment – – – (3) (3)

Settlement (3) – – (3) (6)

Special termination benefitsc 33 – – 18 51

Contributions by plan participants 42 – – 12 54

Benefit payments (funded plans)d (1,131) (767) (4) (203) (2,105)

Benefit payments (unfunded plans)d (2) (52) (176) (419) (649)

Actuarial (gain) loss on obligation (1,497) 191 (233) (284) (1,823)

Benefit obligation at 31 Decembera 16,655 7,534 3,003 7,655 34,847

Movements in fair value of plan assets during the year

Fair value of plan assets at 1 January 31,621 8,045 23 3,110 42,799

Exchange adjustments (7,447) – – (314) (7,761)

Expected return on plan assetsa e 2,094 632 2 194 2,922

Contributions by plan participants 42 – – 12 54

Contributions by employers (funded plans) 6 362 – 130 498

Benefit payments (funded plans)d (1,131) (767) (4) (203) (2,105)

Actuarial loss on plan assetse (6,946) (2,895) (8) (404) (10,253)

Fair value of plan assets at 31 December 18,239 5,377 13 2,525 26,154

Surplus (deficit) at 31 December 1,584 (2,157) (2,990) (5,130) (8,693)

Represented by

Asset recognized 1,682 – – 56 1,738

Liability recognized (98) (2,157) (2,990) (5,186) (10,431)

1,584 (2,157) (2,990) (5,130) (8,693)

The surplus (deficit) may be analysed between funded and unfunded plans as follows

Funded 1,682 (1,734) (31) (354) (437)

Unfunded (98) (423) (2,959) (4,776) (8,256)

 1,584 (2,157) (2,990) (5,130) (8,693)

The defined benefit obligation may be analysed between funded and unfunded plans as follows

Funded (16,557) (7,111) (44) (2,879) (26,591)

Unfunded (98) (423) (2,959) (4,776) (8,256)

(16,655) (7,534) (3,003) (7,655) (34,847)

aThe costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are generally included in current service cost and the costs of 

administering our other post-retirement benefit plans are included in the benefit obligation.

bIncluded within production and manufacturing expenses and distribution and administration expenses.

cThe charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.

dThe benefit payments amount shown above comprises $2,697 million benefits plus $57 million of plan expenses incurred in the administration of the benefit.

eThe actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial loss on plan assets as disclosed above.

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38. Pensions and other post-retirement benefits continued 

161

Notes on financial statements

 $ million 

 2007 

 US other postUK US retirement

pension pension benefit Other

plans plans plans plans Total

Analysis of the amount charged to profit before interest and taxation

Current service costa 492 227 43 132 894 

Past service cost 5 10 – – 15

Settlement, curtailment and special termination benefits 36 – – 2 38

Payments to defined contribution plans – 184 – 25 209 

Total operating chargeb 533 421 43 159 1,156

Analysis of the amount credited (charged) to other finance expense

Expected return on plan assets 2,075 613 2 165 2,855

Interest on plan liabilities (1,198) (425) (190) (390) (2,203)

Other finance income (expense) 877 188 (188) (225) 652 

Analysis of the amount recognized in the statement of recognized income and expense 

Actual return less expected return on pension plan assets 406 (28) – (76) 302

Change in assumptions underlying the present value of the plan liabilities 513 358 137 607 1,615

Experience gains and losses arising on the plan liabilities (162) (27) 29 (40) (200)

Actuarial gain recognized in statement of recognized income and expense 757 303 166 491 1,717

Movements in benefit obligation during the year

Benefit obligation at 1 January 23,289 7,695 3,300 8,149 42,433

Exchange adjustments 394 – – 917 1,311

Current service costa 492 227 43 132 894

Past service cost 5 10 – – 15

Interest cost 1,198 425 190 390 2,203 

Curtailment (7) – – – (7)

Settlement (3) – – – (3)

Special termination benefitsc 46 – – 2 48

Contributions by plan participants 43 – – 12 55

Benefit payments (funded plans)d (1,085) (580) (5) (182) (1,852)

Benefit payments (unfunded plans)d (3) (37) (184) (379) (603)

Acquisitions – – – 141 141

Disposals (91) – – (29) (120)

Actuarial gain on obligation (351) (331) (166) (567) (1,415)

Benefit obligation at 31 Decembera 23,927 7,409 3,178 8,586 43,100

Movements in fair value of plan assets during the year

Fair value of plan assets at 1 January 29,261 7,955 26 2,668 39,910 

Exchange adjustments 488 – – 316 804

Expected return on plan assetsa e 2,075 613 2 165 2,855

Contributions by plan participants 43 – – 12 55

Contributions by employers (funded plans) 524 97 – 127 748

Benefit payments (funded plans)d (1,085) (580) (5) (182) (1,852)

Acquisitions – – – 101 101

Disposals (91) (12) – (21) (124)

Actuarial gain (loss) on plan assetse 406 (28) – (76) 302

Fair value of plan assets at 31 December 31,621 8,045 23 3,110 42,799

Surplus (deficit) at 31 December 7,694 636 (3,155) (5,476) (301)

Represented by

Asset recognized 7,818 989 – 107 8,914 

Liability recognized (124) (353) (3,155) (5,583) (9,215)

7,694 636 (3,155) (5,476) (301)

The surplus (deficit) may be analysed between funded and unfunded plans as follows

Funded 7,818 978 (29) (263) 8,504 

Unfunded (124) (342) (3,126) (5,213) (8,805)

7,694 636 (3,155) (5,476) (301)

The defined benefit obligation may be analysed between funded and unfunded plans as follows

Funded (23,803) (7,067) (52) (3,373) (34,295)

Unfunded (124) (342) (3,126) (5,213) (8,805)

(23,927) (7,409) (3,178) (8,586) (43,100)

aThe costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are generally included in current service cost and the costs of 

administering our other post-retirement benefit plans are included in the benefit obligation.

bIncluded within production and manufacturing expenses and distribution and administration expenses.

cThe charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of a restructuring programme in the UK.

dThe benefit payments amount shown above comprises $2,398 million benefits plus $57 million of plan expenses incurred in the administration of the benefit.

eThe actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain on plan assets as disclosed above.

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38. Pensions and other post-retirement benefits continued 

Estimated future benefit payments 

The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2018 are as follows: 

162 

Notes on financial statements

$ million

2006

US other

postUK US retirement 

pension pension benefit Other

plans plans plans plans Total

Analysis of the amount charged to profit before interest and taxation

Current service costa 432 216 42 139 829

Past service cost (74) 38 – 39 3

Settlement, curtailment and special termination benefits 4 – – 227 231

Payments to defined contribution plans – 161 – 16 177 

Total operating chargeb 362 415 42 421 1,240 

Analysis of the amount credited (charged) to other finance expense

Expected return on plan assets 1,711 564 2 133 2,410

Interest on plan liabilities (1,006) (423) (186) (325) (1,940)

Other finance income (expense) 705 141 (184) (192) 470

Analysis of the amount recognized in the statement of recognized income and expense 

Actual return less expected return on pension plan assets 1,305 521 – 141 1,967 

Change in assumptions underlying the present value of the plan liabilities 114 195 111 352 772

Experience gains and losses arising on the plan liabilities (24) 17 80 (197) (124)

Actuarial gain recognized in statement of recognized income and expense 1,395 733 191 296 2,615 

aThe costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are generally included in current service cost, and the costs of 

administering our other post-retirement benefit plans are included in the benefit obligation. 

bIncluded within production and manufacturing expenses and distribution and administration expenses.

$ million

2008 2007 2006 2005 2004

History of surplus (deficit) and of experience gains and losses

Benefit obligation at 31 December 34,847 43,100 42,433 38,855 39,945 

Fair value of plan assets at 31 December 26,154 42,799 39,910 32,907 31,712

Deficit (8,693) (301) (2,523) (5,948) (8,233)

Experience losses on plan liabilities (178) (200) (124) (212) (468)

Actual return less expected return on pension plan assets (10,253) 302 1,967 3,364 1,349 

Actual return on plan assets (7,331) 3,157 4,377 5,502 3,332

Actuarial (loss) gain recognized in statement of recognized income and expense (8,430) 1,717 2,615 975 107

Cumulative amount recognized in statement of recognized income and expense (2,940) 5,490 3,773 1,158 183

$ million

US other

postUK US retirement 

pension pension benefit Other

plans plans plans plans Total

2009 941 795 194 525 2,455

2010 969 798 200 512 2,479

2011 942 771 207 506 2,426

2012 941 787 211 506 2,445

2013 941 754 214 496 2,405

2014-2018 4,704 3,645 1,111 2,501 11,961

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39. Called-up share capital 

The allotted, called-up and fully paid share capital at 31 December was as follows: 

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. 

Repurchase of ordinary share capital 

The company purchased 269,757,188 ordinary shares (2007 663,149,528 and 2006 1,334,362,750 ordinary shares) for a total consideration of $2,914 million (2007 

$7,497 million and 2006 $15,481 million), all of which were for cancellation. At 31 December 2008, 150,444,408 (2007 150,966,096 and 2006 99,045,000) ordinary 

shares bought back were awaiting cancellation. These shares have been excluded from ordinary shares in issue shown above. At 31 December 2008, 

1,888,151,157 shares of nominal value $472 million were held in treasury (2007 1,940,638,808 shares of nominal value $485 million). The maximum number of

shares held in treasury during the year was 1,940,638,808 shares of nominal value $485 million (2007 1,946,804,533 shares of nominal value $487 million),

representing 9.3% (2007 9.1%) of the called-up ordinary share capital of the company. 

 During 2008, 10,000,000 treasury shares (2007 1,700,000 treasury shares) were gifted to the Employee Share Ownership Plans (ESOPs), 20,000,000 

treasury shares were transferred at market price to the ESOPs, and 22,487,651 treasury shares (2007 4,465,725 treasury shares) were reissued in relation to 

employee share schemes, in total representing 0.25% (2007 less than 0.1%) of the ordinary share capital of the company. The nominal value of these shares was 

$13 million (2007 $2 million) and the total proceeds received from the re-issues in relation to employee share schemes were $75 million (2007 $35 million). 

 Transaction costs of share repurchases amounted to $16 million (2007 $40 million and 2006 $83 million). 

163

Notes on financial statements

2008 2007 2006

Shares Shares Shares

Issued (thousand) $ million (thousand) $ million (thousand) $ 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

At 1 January 20,863,424 5,216 21,457,301 5,364 20,657,045 5,164

Issue of new shares for employee share schemes 24,791 6 69,273 18 64,854 16

Issue of ordinary share capital for TNK-BP – – – – 111,151 28

Repurchase of ordinary share capital (269,757) (67) (663,150) (166) (358,374) (90)

Othera – – – – 982,625 246

At 31 December 20,618,458 5,155 20,863,424 5,216 21,457,301 5,364

 5,176 5,237 5,385

Authorized 

8% cumulative first preference shares of £1 each 7,250 12 7,250 12 7,250 12

9% cumulative second preference shares of £1 each 5,500 9 5,500 9 5,500 9 

Ordinary shares of 25 cents each 36,000,000 9,000 36,000,000 9,000 36,000,000 9,000

aReclassification in respect of share repurchases in 2005.

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40. Capital and reserves 

164 

Notes on financial statements

 

 

 

Share Capital

Share premium redemption

capital account reserve

At 1 January 2008 5,237 9,581 1,005

Recognized income and expense

Currency translation differences (net of tax) – – –

Actuarial loss relating to pension and other post-retirement benefits (net of tax) – – –

Available-for-sale investments marked to market (net of tax) – – –

Available-for-sale investments recycling (net of tax) – – –

Cash flow hedges marked to market (net of tax) – – –

Cash flow hedges recycling (net of tax) – – –

Tax on share-based payments – – –

Profit for the year – – –

Total recognized income and expense for the year – – –

Dividends – – –

Repurchase of ordinary share capital (67) – 67

Share-based payments 6 182 –

Minority interest buyout – – –

At 31 December 2008 5,176 9,763 1,072

Share Capital

 Share premium redemption 

capital account reserve

At 1 January 2007 5,385 9,074 839

Recognized income and expense

Currency translation differences (net of tax) – – –

Exchange gain on translation of foreign operations transferred to (profit) or loss on sale (net of tax) – – –

Actuarial gain relating to pension and other post-retirement benefits (net of tax) – – –

Available-for-sale investments marked to market (net of tax) – – –

Available-for-sale investments recycling (net of tax) – – –

Cash flow hedges marked to market (net of tax) – – –

Cash flow hedges recycling (net of tax) – – –

Tax on share-based payments – – –

Profit for the year – – –

Total recognized income and expense for the year – – –

Dividends – – –

Repurchase of ordinary share capital (166) – 166

Share-based payments 18 507 –

At 31 December 2007 5,237 9,581 1,005

 Share Capital

Share premium redemption

capital account reserve

At 1 January 2006 5,185 7,371 749

Recognized income and expense

Currency translation differences (net of tax) – – –

Actuarial gain relating to pension and other post-retirement benefits (net of tax) – – –

Available-for-sale investments marked to market (net of tax) – – –

Available-for-sale investments recycling (net of tax) – – –

Cash flow hedges marked to market (net of tax) – – –

Cash flow hedges recycling (net of tax) – – –

Tax on share-based payments – – –

Profit for the year – – –

Total recognized income and expense for the year – – –

Dividends – – –

Repurchase of ordinary share capital (90) – 90

Issue of ordinary share capital for TNK-BP 28 1,222 –

Share-based payments 16 481 –

Otherb 246 – –

Currency translation differences (net of tax) – – –

At 31 December 2006 5,385 9,074 839

aAt 31 December 2006, the foreign currency translation reserve included $122 million relating to non-current assets held for sale. During 2007, this was included in the $147 million recycled to the income statement 

relating to disposals in 2007. For further details see Note 5.

bReclassification in respect of share repurchases in 2005. 

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165

Notes on financial statements

 

$ million

Foreign Share-

 currency Available- based Profit BP 

Merger Other Own Treasury translation for-sale Cash flow payment and loss shareholders' Minority Total

reserve reserve shares shares reserve investments hedges reserve account equity interest equity

27,206 – (60) (22,112) 6,540 481 106 1,196 64,510 93,690 962 94,652

– – – – (4,187) – – – – (4,187) (75) (4,262)

– – – – – – – – (5,828) (5,828) – (5,828)

– – – – – (944) – – – (944) – (944)

– – – – – 526 – – – 526 – 526

– – – – – – (984) – – (984) – (984)

– – – – – – 12 – – 12 – 12

– – – – – – – (190) – (190) – (190)

– – – – – – – – 21,157 21,157 509 21,666

– – – – (4,187) (418) (972) (190) 15,329 9,562 434 9,996

– – – – – – – – (10,342) (10,342) (425) (10,767)

– – – – – – – – (2,414) (2,414) – (2,414)

– – (266) 599 – – – 289 (3) 807 – 807

– – – – – – – – – – (165) (165)

27,206 – (326) (21,513) 2,353 63 (866) 1,295 67,080 91,303 806 92,109

 

 Foreign Sharecurrency Available- based Profit BP

Merger Other Own Treasury translation for-sale Cash flow payment and loss shareholders' Minority Total

reserve reserve shares shares reservea investments hedges reserve account equity interest equity 

27,201 5 (154) (22,182) 4,685 386 39 859 58,487 84,624 841 85,465 

 

– – – – 2,002 – – – – 2,002 24 2,026

– – – – (147) – – – – (147) – (147)

– – – – – – – – 1,290 1,290 – 1,290

– – – – – 152 – – – 152 – 152

– – – – – (57) – – – (57) – (57)

– – – – – – 138 – – 138 – 138

– – – – – – (71) – – (71) – (71)

– – – – – – – 213 – 213 – 213

– – – – – – – – 20,845 20,845 324 21,169

– – – – 1,855 95 67 213 22,135 24,365 348 24,713

– – – – – – – – (8,106) (8,106) (227) (8,333)

– – – – – – – – (7,997) (7,997) – (7,997)

5 (5) 94 70 – – – 124 (9) 804 – 804 

27,206 – (60) (22,112) 6,540 481 106 1,196 64,510 93,690 962 94,652

 

Foreign Sharecurrency Available- based Profit BP

Merger Other Own Treasury translation for-sale Cash flow payment and loss shareholders' Minority Total

reserve reserve shares shares reservea investments hedges reserve account equity interest equity

27,190 16 (140) (10,598) 2,943 385 (234) 643 46,151 79,661 789 80,450

– – – – 1,742 27 6 – – 1,775 49 1,824

– – – – – – – – 1,795 1,795 – 1,795

– – – – – 478 – – – 478 – 478

– – – – – (504) – – – (504) – (504)

– – – – – – 313 – – 313 – 313

– – – – – – (46) – – (46) – (46)

– – – – – – – 26 – 26 – 26

– – – – – – – – 22,315 22,315 286 22,601

– – – – 1,742 1 273 26 24,110 26,152 335 26,487

– – – – – – – – (7,686) (7,686) (283) (7,969)

– – – (11,472) – – – – (4,009) (15,481) – (15,481)

– – – – – – – – – 1,250 – 1,250 

11 (11) 5 134 – – – 190 (79) 747 – 747

– – – (246) – – – – – – – –

– – (19) – – – – – – (19) – (19)

27,201 5 (154) (22,182) 4,685 386 39 859 58,487 84,624 841 85,465

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40. Capital and reserves continued 

Share capital 

The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury shares. 

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 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 plans.

Treasury shares 

Treasury shares represent BP shares repurchased and available for re-issue. 

Foreign currency translation reserve 

The foreign currency translation reserve is used to record exchange differences arising from the translation of the financial statements of foreign operations. Upon 

disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement. This reserve 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 of available-for-sale investments. On disposal, or impairment, 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. When the hedged 

transaction occurs, the gain or loss on the hedging instrument is transferred out of equity to either profit or loss or the carrying value of assets, as appropriate. If the 

forecast transaction is no longer expected to occur the gain or loss recognized in equity is transferred to profit or loss. 

Share-based payment reserve 

This reserve represents cumulative amounts charged to profit in respect of employee share-based payment plans where the scheme has not yet been settled by 

means of an award of shares to an individual. 

Profit and loss account 

The balance held on this reserve is the accumulated retained profits of the group. 

41. Share-based payments 

Effect of share-based payment transactions on the group’s result and financial position 

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. 

166 

Notes on financial statements

$ million

2008 2007 2006

Total expense recognized for equity-settled share-based payment transactions 524 412 405

Total (credit) expense recognized for cash-settled share-based payment transactions (16) 16 14 

Total expense recognized for share-based payment transactions 508 428 419

Closing balance of liability for cash-settled share-based payment transactions 21 40 38

Total intrinsic value for vested cash-settled share-based payments 2 22 23

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41. Share-based payments continued 

Plans for executive directors 

Executive Directors’ Incentive Plan (EDIP) – share element 

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. After the performance period, the shares that vest (net of tax) are then 

subject to a three-year retention period. In February 2008 it was considered appropriate to strengthen the retention element of remuneration for two executive 

directors. The remuneration committee granted, on a one-off basis, a restricted share award to those two executive directors. The shares will vest subject to 

continued service, in equal tranches, after three and five years. Vesting of each tranche is dependent on the committee being satisfied, at each vesting date, with 

the performance of the individuals. These retention awards have been granted under EDIP which permits awards to be made, on an exceptional basis, subject to a 

requirement of continued service over a specific period. The directors’ remuneration report on pages 73 to 83 includes full details of this plan. 

Executive Directors’ Incentive Plan (EDIP) – share option element 

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. From 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) 

An equity-settled restricted share unit plan for senior employees driven by two performance measures over a three-year performance period. At the end of the 

performance period units are converted into shares. The amount of units converted to 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 units converted into shares is increased to take account of the net notional dividends that would 

have been received during the performance period, assuming that such dividends would have been reinvested. With regard to leaver provisions the general rule is 

that leaving employment during the performance period will preclude the conversion of units into 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. The current policy of the company, 

which is reflected in the terms of the MTPP, is that senior employees subject to the plan should meet a minimum shareholding requirement. Grants will not be made 

under this plan after 2008. 

Senior Employees Deferred Annual Bonus Plan (DAB) 

An equity-settled restricted share unit plan for senior employees. In 2008 the grant value is equal to 50% (2007 and 2006 50%) of the annual cash bonus awarded 

for the preceding performance year (the ‘performance period’). For 2009 this will increase to 100%. The units are restricted for a period of three years (the 

‘restriction period’), during which they accrue net notional dividends which are treated as having been reinvested. At the end of the restriction period units are 

converted into shares. With regard to leaver provisions, if a participant ceases to be employed by BP prior to the end of the performance period the general rule is 

that this will preclude the grant of units. If a participant ceases to be employed by BP prior to the end of the restriction period the general rule is that this will 

preclude the conversion of units into shares. However, special arrangements apply where the participant leaves for a qualifying reason. 

Integrated Supply and Trading Deferred Annual Bonus Plan (IST DAB) 

An equity-settled restricted share unit plan for traders in the IST function. The plan operates under the DAB but the rules differ in certain respects from that plan. If 

eligible, a portion of a trader’s annual cash bonus (the ‘base grant’), awarded for the preceding performance year (the ‘performance period’), plus an additional 25% 

of that amount (the ‘additional grant’),will be deferred in restricted share units. The units are restricted over a period of three calendar years, during which they 

accrue net notional dividends, which are treated as having been reinvested. At the end of the restriction period units are converted into shares. One third of the 

base grant vests after one and two calendar years respectively, with the final third plus the additional grant vesting after three calendar years. With regard to leaver 

provisions, if a participant ceases to be employed by BP prior to the end of the restriction period the general rule is that this will preclude the conversion of units into 

shares. Special arrangements apply where the participant leaves for a qualifying reason. 

Performance Share Plan (PSP) 

An equity-settled restricted share unit plan for senior professionals and team leaders. The grant takes into account the recipient’s performance in the prior calendar 

year (the ‘performance period’). The units are restricted for a period of three years (the ‘restriction period’), during which they accrue net notional dividends, which 

are treated as having been reinvested. At the end of the restriction period additional units may be awarded based on BP’s TSR performance against the other oil 

majors. At the end of the restriction period units are converted into shares. With regard to leaver provisions the general rule is that leaving during the performance 

period will preclude the grant of units. If a participant ceases to be employed by BP prior to the end of the restriction period the general rule is that this will preclude 

the conversion of units into shares. Special arrangements apply where the participant leaves for a qualifying reason. 

Restricted Share Plan (RSP) 

An equity-settled restricted share unit plan used predominantly for senior employees in special circumstances (such as recruitment and retention). There are 

generally no performance conditions but the units are subject to a three-year restriction period, during which they accrue net notional dividends which are treated as 

having been reinvested. At the end of the restricted period the units are converted into shares. With regard to leaver provisions, if a participant ceases to be 

employed by BP prior to the end of the restriction period the general rule is that this will preclude the conversion of units into shares. However, special 

arrangements apply where the participant leaves for a qualifying reason. 

167

Notes on financial statements

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41. Share-based payments continued 

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 the 

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 tenth 

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. From 2007 share options no longer form a regular element of 

our incentive plans. 

Savings and matching plans 

BP ShareSave Plan 

This is a savings-related share option plan under which employees save on a monthly basis, over a three-year 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. 

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 

These are 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 

more than 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. 

Local plans 

In some countries BP provides local scheme benefits, the rules and qualifications for which vary according to local circumstances. 

The above share plans are indicated as being equity-settled. In certain countries however, it is not possible to award shares to employees owing to local legislation. 

In these instances the award will be settled in cash, calculated as the cash equivalent of the value to the employee of an equity-settled plan. 

Cash plans 

Cash-settled share-based payments/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/restricted 

shares to the employee at the date of exercise or on maturity. The cash options/SARs have the same rules as the BPSOP plan and the cash restricted share plans 

(MTPP, DAB, PSP, RSP) have the same rules as their equity-settled counterparts. 

Employee Share Ownership Plans (ESOPs) 

ESOPs have been established to acquire BP shares to satisfy any awards made to participants under the BP share plans as required. 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 to employees, the amount paid for those shares is deducted in arriving at shareholders’ equity (see Note 40). Assets and liabilities of the ESOPs are 

recognized as assets and liabilities of the group. 

 At 31 December 2008 the ESOPs held 29,051,082 shares (2007 6,448,838 shares and 2006 12,795,887 shares) for potential future awards, which had a 

market value of $220 million (2007 $79 million and 2006 $142 million). 

168 

Notes on financial statements

Share option transactions 2008 2007 2006

Weighted Weighted Weighted

Number average Number average Number average

of exercise price of exercise price of exercise price 

options $ options $ options $

Outstanding at 1 January 358,094,243 8.51 426,471,462 8.25 450,453,502 7.64

Granted 8,062,899 8.96 6,004,025 9.11 53,977,639 11.18

Forfeited (2,502,784) 8.50 (3,924,714) 9.10 (7,169,710) 8.69

Exercised (37,277,895) 6.97 (69,715,558) 6.94 (70,658,480) 6.52

Expired (121,864) 7.00 (740,972) 8.68 (131,489) 7.99

Outstanding at 31 December 326,254,599 8.70 358,094,243 8.51 426,471,462 8.25

Exercisable at 31 December 260,178,938 8.22 238,707,055 7.70 236,726,966 7.41

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41. Share-based payments continued 

As share options are exercised continuously throughout the year, the weighted average share price during the year of $10.87 (2007 $11.72 and 2006 $11.85) is 

representative of the weighted average share price at the date of exercise. For the options outstanding at 31 December 2008, the exercise price ranges and 

weighted average remaining contractual lives are shown below.

Fair values and associated details for options and shares granted 

The group uses an appropriate valuation model of expected volatility of US ADSs for the quarter within which the grant date of the relevant plan falls. Management 

is responsible for all inputs and assumptions in relation to that model, including the determination of expected volatility. 

169

Notes on financial statements

Options outstanding Options exercisable

Weighted Weighted Weighted

Number average average Number average

of remaining life exercise price of exercise price

Range of exercise prices shares Years $ shares $

$5.71 – $7.25 51,430,951 3.81 6.39 48,919,680 6.35

$7.26 – $8.80 159,708,260 3.12 8.11 157,933,135 8.11

$8.81 – $10.36 42,960,673 4.53 9.53 26,083,268 9.83

$10.37 – $11.92 72,154,715 6.81 11.14 27,242,855 10.67

 326,254,599 4.23 8.70 260,178,938 8.22

Options granted in 2008 ShareSave 3 year ShareSave 5 year

Option pricing model used Binomial Binomial

Weighted average fair value $1.82 $1.74

Weighted average share price $11.26 $11.26

Weighted average exercise price $9.70 $9.70

Expected volatility 23% 23%

Option life 3.5 years 5.5 years

Expected dividends 4.60% 4.60%

Risk free interest rate 5.00% 5.00%

Expected exercise behaviour 100% year 4 100% year 6

 

Options granted in 2007 ShareSave 3 year ShareSave 5 year

Option pricing model used Binomial Binomial

Weighted average fair value $3.57 $3.79

Weighted average share price $12.10 $12.10 

Weighted average exercise price $9.13 $9.13

Expected volatility 21% 21%

Option life 3.5 years 5.5 years

Expected dividends 3.48% 3.48%

Risk free interest rate 5.75% 5.75% 

Expected exercise behaviour 100% year 4 100% year 6

Options granted in 2006 BPSOP ShareSave 3 year ShareSave 5 year

Option pricing model used Binomial Binomial Binomial

Weighted average fair value $2.46 $2.88 $3.08 

Weighted average share price $11.07 $11.08 $11.08

Weighted average exercise price $11.17 $9.10 $9.10 

Expected volatility 22% 24% 24%

Option life 10 years 3.5 years 5.5 years

Expected dividends 3.23% 3.40% 3.40%

Risk free interest rate 4.50% 5.00% 4.75%

Expected exercise behaviour 5% years 4-9, 100% year 4 100% year 6 

70% year 10

MTPP- MTPP- EDIP- EDIPShares granted in 2008 TSR FCF TSR RET RSP DAB PSP

Number of equity instruments granted (million) 9.1 9.1 2.6 0.5 7.7 5.8 16.7

Weighted average fair value $5.07 $10.34 $4.55 $11.13 $8.83 $10.34 $12.89

Fair value measurement basis Monte Market Monte Market Market Market Monte

Carlo value Carlo value value value Carlo

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41. Share-based payments continued 

The group used a Monte Carlo simulation to fair value the TSR element of the 2008, 2007 and 2006 PSP, 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. 

 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. 

42. Employee costs and numbers 

170 

Notes on financial statements

 MTPP- MTPP- EDIP- EDIPShares granted in 2007 TSR FCF TSR LTL RSP DAB PSP

Number of equity instruments granted (million) 9.4 8.5 4.5 0.5 7.7 4.4 14.8

Weighted average fair value $4.73 $10.02 $2.81 $9.92 $11.93 $10.02 $12.37

Fair value measurement basis Monte Market Monte Market Market Market Monte 

Carlo value Carlo value value value Carlo

MTPP- MTPP- EDIP- EDIPShares granted in 2006 TSR FCF TSR LTL RSP DAB 

Number of equity instruments granted (million) 8.7 7.8 3.3 0.5 0.5 3.5 

Weighted average fair value $7.28 $11.23 $4.87 $11.23 $11.07 $11.06

Fair value measurement basis Monte Market Monte Market Market Market

 Carlo value Carlo value value value

 $ million 

Employee costs 2008 2007 2006 

Wages and salariesa c 10,388 9,808 8,703 

Social security costs 805 771 751

Share-based payments 508 428 419

Pension and other post-retirement benefit costs 579 504 770 

 12,280 11,511 10,643 

Number of employees at 31 December 2008 2007 2006

Exploration and Production 21,400 21,800 21,400

Refining and Marketingb c 61,500 67,200 68,000

Other businesses and corporatec 9,100 9,100 7,600 

 92,000 98,100 97,000

By geographical area

UK 15,900 17,000 16,900

Rest of Europe 19,400 19,900 20,200 

US 29,300 33,000 33,700

Rest of Worldb 27,400 28,200 26,200

 92,000 98,100 97,000 

 

2008 2007

Rest of Rest of Rest of Rest of

Average number of employees UK Europe US World Total UK Europe US World Total

Exploration and Production 3,700 700 7,800 9,400 21,600 3,800 700 7,700 9,300 21,500

Refining and Marketing 9,300 18,300 21,600 15,800 65,000 10,300 18,600 23,400 15,000 67,300 

Other businesses and corporate 3,400 800 2,600 2,300 9,100 2,600 900 2,500 2,400 8,400

16,400 19,800 32,000 27,500 95,700 16,700 20,200 33,600 26,700 97,200

aIncludes termination payments of $669 million (2007 $422 million and 2006 $257 million). A restructuring was announced in October 2007, the implementation of which continues in 2009. 

b Includes 21,200 (2007 24,500 and 2006 26,100) service station staff.

cA minor amendment has been made to the comparative figures to include some employee costs which had been previously incorrectly excluded and to correct headcount data.

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42. Employee costs and numbers continued 

43. Remuneration of directors and senior management 

Remuneration of directors 

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. This includes an ex gratia superannuation payment of nil (2007 $3 million and 2006 nil) and 

compensation for loss of office of $1 million (2007 $1 million and 2006 nil). 

Pension contributions 

Four executive directors participated in a non-contributory pension scheme established for UK employees 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 2008. 

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. 

Further information 

Full details of individual directors’ remuneration are given in the directors’ remuneration report on pages 73 to 83. 

Remuneration of senior management 

Senior management, in addition to executive and non-executive directors, includes other senior managers who are members of the executive management team.

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. This includes an ex gratia superannuation payment of nil (2007 $3 million and 2006 nil) 

and compensation for loss of office of $3 million (2007 $1 million and 2006 $5 million). 

Post-retirement benefits 

The amounts represent the estimated cost to the group of providing defined benefit pensions and other post-retirement benefits to senior 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 senior 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 senior management have participated are the EDIP, MTPP and LTPP. 

For details of these plans refer to Note 41. 

171

Notes on financial statements

 2006 

 Rest of Rest of 

Average number of employees UK Europe US World Total

Exploration and Production 3,500 800 7,100 9,000 20,400

Refining and Marketing 11,100 19,300 24,800 14,100 69,300

Other businesses and corporate 2,200 800 2,600 1,800 7,400 

16,800 20,900 34,500 24,900 97,100

$ million

2008 2007 2006

Total for all directors

Emoluments 19 26 14 

Gains made on the exercise of share options 1 2 12

Amounts awarded under incentive schemes – 10 14 

$ million

2008 2007 2006

Total for all senior management

Short-term employee benefits 40 37 30

Post-retirement benefits 4 7 4 

Share-based payments 20 22 26

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44. Contingent liabilities 

There were contingent liabilities at 31 December 2008 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. Further information is included in Note 28. 

 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 

46.9% interest (reduced during 2001 from 50% by a sale of 3.1% 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 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. It is not possible to estimate any financial 

effect. 

 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 and Refining and another company that 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 judgment 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 files income tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group’s income 

tax returns. Tax returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the resolution of tax positions 

through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is difficult to predict the ultimate outcome in 

some cases, the group does not anticipate that there will be any material impact upon 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, it is not practical to estimate the amounts involved. 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. 

45. Capital commitments 

Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been placed at 31 December 2008 amounted 

to $14,062 million (2007 $8,263 million). In addition, at 31 December 2008, the group had contracts in place for future capital expenditure relating to investments in 

jointly controlled entities of $644 million (2007 $1,039 million) and investments in associates of $160 million (2007 $74 million).

 Capital commitments of jointly controlled entities amounted to $1,540 million (2007 $2,273 million). 

172 

Notes on financial statements

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46. Subsidiaries, jointly controlled entities and associates 

The more important subsidiaries, jointly controlled entities and associates of the group at 31 December 2008 and the group percentage of ordinary share capital or 

joint venture interest (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 parent company are marked with an asterisk (*), the percentage owned being that of the group unless 

otherwise indicated. A complete list of investments in subsidiaries, jointly controlled entities and associates will be attached to the parent company’s annual return 

made to the Registrar of Companies. 

173

Notes on financial statements

 

 Country of 

Subsidiaries % incorporation Principal activities

International

*BP Corporate Holdings 100 England Investment holding

BP Exploration Op. 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

Germany

Deutsche BP 100 Germany Refining and marketing 

and petrochemicals

Indonesia

BP Berau 100 US Exploration and production

BP West Java 100 US Exploration and production

 

 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 & Tobago

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 Oil UK 100 England Marketing

Britoil 100 Scotland Exploration and 

production

Jupiter Insurance 100 Guernsey Insurance

US

*BP Holdings North America 100 England Investment holding

Atlantic Richfield Co. 























































 

















 

BP America Exploration and

BP America Production Company production, refining 

and marketing, pipelines

BP Amoco Chemical Company 100 US and petrochemicals

BP Company North America 

BP Corporation North America

BP Exploration (Alaska) Inc.

BP Products North America

BP West Coast Products

Standard Oil Co.

BP Capital Markets America Finance

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46. Subsidiaries, jointly controlled entities and associates continued 

174 

Notes on financial statements

 Country of incorporation 

Jointly controlled entities % or registration Principal activities

Angola LNG Supply Services 14 US LNG processing and transportation

Atlantic 4 Holdings 38 US LNG manufacture

Atlantic LNG 2/3 Company of Trinidad and Tobago 43 Trinidad & Tobago LNG manufacture

BP-Husky Refining 50 US Refining

Elvary Neftegaz Holdings BV 49 Netherlands Exploration and appraisal

Fowler 1 Holdings 50 US Wind farm development

LukArco 46 Netherlands Exploration and production, pipelines

Pan American Energya 60 US Exploration and production

Petromonagas 17 Venezuela Exploration and production

Ruhr Oel 50 Germany Refining and marketing and petrochemicals

Shanghai SECCO Petrochemical Co. 50 China Petrochemicals

Sunrise Oil Sands 50 Canada Exploration and production

TNK-BP 50 British Virgin Islands Integrated oil operations

United Gas Derivatives Company 33 Egypt NGL extraction

a Pan American Energy is not controlled by BP as certain key business decisions require joint approval of both BP and the minority partner. It is therefore classified as a jointly controlled entity rather 

than a subsidiary.

Associates % Country of 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

South Caucasus Pipeline Co. 26 Cayman Islands Pipelines

Trinidad & Tobago 

Atlantic LNG Company of Trinidad and Tobago 34 Trinidad & Tobago LNG manufacture

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47. Oil and natural gas exploration and production activitiesa

The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2008 was $13,393 million. 

The group’s share of jointly controlled entities’ and associates’ costs incurred in 2008 was $3,259 million: in Russia $1,921 million, Rest of Americas $1,039 million, 

Asia Pacific $24 million and other $275 million. 

The group’s share of jointly controlled entities’ and associates’ results of operations (including the group’s share of total TNK-BP results) in 2008 was a profit of 

$2,793 million after deducting interest of $355 million, taxation of $1,217 million and minority interest of $169 million. 

175

Notes on financial statements

 

 $ million 

 2008

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Capitalized costs at 31 December

Gross capitalized costs

Proved properties 34,614 5,507 59,918 11,451 4,720 21,563 – 8,550 146,323

Unproved properties 626 – 5,006 299 1,019 2,011 – 464 9,425

35,240 5,507 64,924 11,750 5,739 23,574 – 9,014 155,748

Accumulated depreciation 26,564 3,125 28,511 6,358 2,181 10,451 – 3,159 80,349

Net capitalized costs 8,676 2,382 36,413 5,392 3,558 13,123 – 5,855 75,399

Costs incurred for the year ended 31 December 

Acquisition of properties 

Proved – – 1,374 2 – – – 136 1,512

Unproved 4 – 2,942 – – – – 41 2,987

 4 – 4,316 2 – – – 177 4,499

Exploration and appraisal costsb 137 – 862 123 79 838 12 239 2,290

Development 907 695 4,914 1,077 465 2,966 – 743 11,767

Total costs 1,048 695 10,092 1,202 544 3,804 12 1,159 18,556

 

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties 3,865 105 8,010 3,573 1,410 3,745 – 549 21,257

Sales between businesses 4,374 1,416 15,610 3,755 1,420 6,022 – 11,087 43,684

8,239 1,521 23,620 7,328 2,830 9,767 – 11,636 64,941

Exploration expenditure 121 1 305 62 41 213 14 125 882

Production costs 1,357 150 3,002 718 213 875 18 334 6,667

Production taxes 503 – 2,603 360 110 – – 3,083 6,659

Other costs (income)c(28) (43) 3,440 541 309 245 196 4,041 8,701

Depreciation, depletion and amortization 1,049 199 2,729 911 251 2,120 – 624 7,883

Impairments and (gains) losses on sale of 

businesses and fixed assets – – 308 6 219 8 – – 541

3,002 307 12,387 2,598 1,143 3,461 228 8,207 31,333

Profit before taxationd 5,237 1,214 11,233 4,730 1,687 6,306 (228) 3,429 33,608

Allocable taxes 2,280 883 3,857 2,423 618 2,672 (36) 879 13,576

Results of operations 2,957 331 7,376 2,307 1,069 3,634 (192) 2,550 20,032

Exploration and Production segment profit 

before interest and tax 

Exploration and production activities 

Group (as above) 5,237 1,214 11,233 4,730 1,687 6,306 (228) 3,429 33,608

Jointly controlled entities and associates (1) – 1 344 48 (1) 2,259 143 2,793

Midstream activitiese 743 16 425 619 (228) 112 – (173) 1,514

Total profit before interest and tax 5,979 1,230 11,659 5,693 1,507 6,417 2,031 3,399 37,915

aThis note contains information relating to oil and natural gas exploration and production activities. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and 

export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are 

excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline and the Baku-Tbilisi-Ceyhan pipeline. 

Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola. The group’s share of jointly controlled entities’ and associates’ activities are excluded from 

the tables and included in the footnotes with the exception of the Abu Dhabi operations, which are included in the results of operations above. 

bIncludes 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

Includes property taxes, other government take and the fair value loss on embedded derivatives of $102 million. The UK region includes a $499 million gain offset by corresponding charges primarily in the US, relating 

to the group self-insurance programme. 

dExcludes the unwinding of the discount on provisions and payables amounting to $285 million which is included in finance costs in the group income statement.

eIncludes a $517 million write-down of our investment in Rosneft based on its quoted market price at the end of the year.

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47. Oil and natural gas exploration and production activitiesa continued

176 

Notes on financial statements

$ million

2007

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Capitalized costs at 31 December

Gross capitalized costs 

Proved properties 34,774 4,925 53,079 10,627 3,528 18,333 – 7,596 132,862

Unproved properties 606 – 1,660 297 1,188 1,533 4 349 5,637

35,380 4,925 54,739 10,924 4,716 19,866 4 7,945 138,499

Accumulated depreciation 25,515 2,925 25,500 5,528 1,508 8,315 – 2,553 71,844

Net capitalized costs 9,865 2,000 29,239 5,396 3,208 11,551 4 5,392 66,655

The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2007 was $11,787 million. 

Costs incurred for the year ended 31 December 

Acquisition of properties

Proved – – 245 – – – – 232 477

Unproved – – 54 16 – 321 – 126 517 

– – 299 16 – 321 – 358 994

Exploration and appraisal costsb 209 16 646 72 51 677 119 102 1,892

Development costs 804 443 3,861 1,057 333 2,634 – 1,021 10,153 

Total costs 1,013 459 4,806 1,145 384 3,632 119 1,481 13,039 

The group’s share of jointly controlled entities’ and associates’ costs incurred in 2007 was $2,552 million: in Russia $1,787 million, Rest of Americas $569 million, 

Asia Pacific $17 million and other $179 million. 

Results of operations for the year ended 31 December

Sales and other operating revenues

Third parties 4,503 434 1,436 2,142 1,148 2,219 – 921 12,803

Sales between businesses 2,260 902 14,353 3,142 970 3,223 – 9,983 34,833

6,763 1,336 15,789 5,284 2,118 5,442 – 10,904 47,636

Exploration expenditure 46 – 252 134 11 183 116 14 756

Production costs 1,658 147 2,782 770 190 637 2 344 6,530

Production taxes 227 3 1,260 273 56 – – 2,224 4,043

Other costs (income)c (419) 123 2,505 395 378 200 169 3,018 6,369

Depreciation, depletion and amortization 1,569 207 2,118 822 205 1,372 – 995 7,288 

Impairments and (gains) losses on sale

of businesses and fixed assets 112 (534) (413) (43) – (76) – – (954)

 3,193 (54) 8,504 2,351 840 2,316 287 6,595 24,032 

Profit before taxationd 3,570 1,390 7,285 2,933 1,278 3,126 (287) 4,309 23,604 

Allocable taxes 1,664 611 2,560 1,202 321 1,462 3 1,079 8,902

Results of operations 1,906 779 4,725 1,731 957 1,664 (290) 3,230 14,702

The group’s share of jointly controlled entities’ and associates’ results of operations (including the group’s share of total TNK-BP results) in 2007 was a profit of 

$2,704 million after deducting interest of $401 million, taxation of $1,355 million and minority interest of $215 million. 

Exploration and Production segment profit before interest 

and tax 

Exploration and production activities

Group (as above) 3,570 1,390 7,285 2,933 1,278 3,126 (287) 4,309 23,604

Jointly controlled entities and associates – – 1 381 21 – 2,292 9 2,704

Midstream activities 15 13 709 699 (108) 96 (112) 109 1,421 

Total profit before interest and tax 3,585 1,403 7,995 4,013 1,191 3,222 1,893 4,427 27,729

aThis note contains information relating to oil and natural gas exploration and production activities. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and 

export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are 

excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline and the Baku-Tbilisi-Ceyhan pipeline. 

Major LNG activities are located in Trinidad, Indonesia and Australia. The group’s share of jointly controlled entities’ and associates’ activities are excluded from the tables and included in the footnotes with the 

exception of the Abu Dhabi operations, which are included in the results of operations above. 

bIncludes 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

Includes property taxes, other government take and the fair value gain on embedded derivatives of $47 million. The UK region includes a $409 million gain offset by corresponding charges primarily in the US, relating to 

the group self-insurance programme. 

dExcludes the unwinding of the discount on provisions and payables amounting to $179 million which is included in finance costs in the group income statement.

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47. Oil and natural gas exploration and production activitiesa continued

The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2006 was $10,870 million. 

The group’s share of jointly controlled entities’ and associates’ costs incurred in 2006 was $1,688 million: in Russia $1,109 million, Rest of Americas $424 million, 

Asia Pacific $16 million and other $139 million. 

The group’s share of jointly controlled entities’ and associates’ results of operations (including the group’s share of total TNK-BP results) in 2006 was a profit of 

$3,302 million after deducting interest of $324 million, taxation of $1,804 million and minority interest of $193 million. 

177

Notes on financial statements

$ million

2006

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Capitalized costs at 31 December

Gross capitalized costs 

Proved properties 32,528 4,951 44,856 9,404 3,569 15,516 – 6,278 117,102

Unproved properties 423 116 1,443 379 1,155 936 1 137 4,590

32,951 5,067 46,299 9,783 4,724 16,452 1 6,415 121,692

Accumulated depreciation 22,908 3,175 19,724 4,618 1,709 6,944 – 1,708 60,786

Net capitalized costs 10,043 1,892 26,575 5,165 3,015 9,508 1 4,707 60,906

 

Costs incurred for the year ended 31 

December 

Acquisition of properties

Proved – – – – – – – – –

Unproved – – 74 8 2 70 – – 154

– – 74 8 2 70 – – 154

Exploration and appraisal costsb 132 26 838 135 45 434 73 82 1,765 

Development costs 794 214 3,579 820 238 2,356 – 1,108 9,109

Total costs 926 240 4,491 963 285 2,860 73 1,190 11,028

Results of operations for the year ended 31 

December 

Sales and other operating revenues

Third parties 5,378 628 1,381 2,196 1,159 1,647 – 768 13,157

Sales between businesses 2,329 1,024 14,572 3,229 807 2,875 – 7,640 32,476

7,707 1,652 15,953 5,425 1,966 4,522 – 8,408 45,633

Exploration expenditure 20 (1) 634 132 11 132 17 100 1,045

Production costs 1,312 145 2,311 638 155 509 – 238 5,308

Production taxes 492 38 887 295 63 – – 2,079 3,854

Other costs (income)c (867) 90 2,561 478 154 104 32 3,121 5,673

Depreciation, depletion and amortization 1,612 213 2,083 685 175 865 – 510 6,143 

Impairments and (gains) losses on sale of 

businesses and fixed assets (450) (57) (1,880) 42 (99) (31) – – (2,475)

 2,119 428 6,596 2,270 459 1,579 49 6,048 19,548 

Profit before taxationd 5,588 1,224 9,357 3,155 1,507 2,943 (49) 2,360 26,085 

Allocable taxes 2,567 793 3,136 1,443 472 1,328 3 737 10,479

Results of operations 3,021 431 6,221 1,712 1,035 1,615 (52) 1,623 15,606

Exploration and Production segment profit 

before interest and tax 

Exploration and production activities

Group (as above) 5,588 1,224 9,357 3,155 1,507 2,943 (49) 2,360 26,085

Jointly controlled entities and associates – – 1 535 33 1 2,730 2 3,302

Midstream activities 519 154 617 445 (196) 37 (24) 14 1,566

Total profit before interest and tax 6,107 1,378 9,975 4,135 1,344 2,981 2,657 2,376 30,953

aThis note contains information relating to oil and natural gas exploration and production activities. Midstream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are 

excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe 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. 

bIncludes 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

Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes, other government take and the fair value gain on embedded derivatives $515 million. 

dExcludes the unwinding of the discount on provisions and payables amounting to $153 million which is included in finance costs in the group income statement.

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Additional information for US reporting 

48. Auditor’s remuneration for US reporting 

Audit fees for 2008 include $3 million of additional fees for 2007 (2007 $7 million of additional fees for 2006 and 2006 $5 million of additional fees for 2005). Audit 

fees are included in the income statement within distribution and administration expenses. 

 Other further assurance services include nil (2007 $1 million and 2006 nil) in respect of advice on accounting, auditing and financial reporting matters; 

$5 million (2007 $5 million and 2006 $5 million) in respect of non-statutory audits and nil (2007 $2 million and 2006 nil) in respect of project assurance and advice 

on business and accounting process improvement. 

 The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services. 

 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 compared with that of other 

potential service providers. These services are for a fixed term. 

178 

Additional information for US reporting

$ million

2008 2007 2006

Audit fees – Ernst & Young

Group audit 34 37 36

Audit-related regulatory reporting 6 7 9 

Statutory audit of subsidiaries 17 19 19

57 63 64

Fees for other services – Ernst & Young

Further assurance services

Acquisition and disposal due diligence 2 1 3 

Pension plan audits 1 1 –

Other further assurance services 5 8 5

Tax services

Compliance services – – 1

Advisory services 2 2 – 

 10 12 9

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49. Valuation and qualifying accounts 

50. Computation of ratio of earnings to fixed charges (unaudited) 

51. 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., 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 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 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. 

179

Additional information for US reporting

 

 $ million 

 Additions 

Charged to Charged to

Balance at costs and other Balance at

1 January expenses accountsa Deductions 31 December

2008

Fixed assets – Investmentsb 146 647 143 (1) 935

Doubtful debtsb 406 191 (32) (174) 391

2007 

Fixed assets – Investmentsb 151 158 2 (165) 146

Doubtful debtsb 421 175 34 (224) 406

2006

Fixed assets – Investmentsb 172 26 (3) (44) 151

Doubtful debtsb 374 158 32 (143) 421

aPrincipally currency transactions.

bDeducted in the balance sheet from the assets to which they apply. 

$ million, except ratios

For the year ended 31 December 2008 2007 2006 2005 2004

Profit before taxation 34,283 31,611 35,142 31,421 24,966

Group’s share of income in excess of dividends from equity-accounted entities (93) (1,359) – (710) (81)

Capitalized interest, net of amortization 56 (183) (341) (193) (133)

34,246 30,069 34,801 30,518 24,752

Fixed charges

Interest expense 1,157 1,110 718 559 440

Rental expense representative of interest 1,231 1,033 946 605 619

Capitalized interest 162 323 478 351 204

2,550 2,466 2,142 1,515 1,263

Total adjusted earnings available for payment of fixed charges 36,796 32,535 36,943 32,033 26,015 

Ratio of earnings to fixed charges 14.4 13.2 17.2 21.1 20.6 

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51. Condensed consolidating information on certain US subsidiaries continued 

Income statement 

180 

Additional information for US reporting

$ million

For the year ended 31 December 2008

Issuer Guarantor

BP Eliminations

Exploration Other and 

(Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Sales and other operating revenues 6,782 – 361,143 (6,782) 361,143

Earnings from jointly controlled entities – after interest and tax – – 3,023 – 3,023

Earnings from associates – after interest and tax – – 798 – 798

Equity-accounted income of subsidiaries – after interest and tax 469 20,295 – (20,764) –

Interest and other revenues 514 173 1,025 (976) 736

Total revenues 7,765 20,468 365,989 (28,522) 365,700

Gains on sale of businesses and fixed assets – – 1,353 – 1,353

Total revenues and other income 7,765 20,468 367,342 (28,522) 367,053

Purchases 895 – 272,869 (6,782) 266,982

Production and manufacturing expenses 1,083 – 28,100 – 29,183

Production and similar taxes 2,343 – 4,183 – 6,526

Depreciation, depletion and amortization 365 – 10,620 – 10,985

Impairment and losses on sale of businesses and fixed assets – – 1,733 – 1,733

Exploration expense – – 882 – 882

Distribution and administration expenses 22 28 15,469 (107) 15,412

Fair value (gain) loss on embedded derivatives – – 111 – 111

Profit before interest and taxation 3,057 20,440 33,375 (21,633) 35,239

Finance costs 158 169 2,089 (869) 1,547

Net finance (income) expense relating to pensions and other post-retirement 

benefits – (822) 231 – (591)

Profit before taxation 2,899 21,093 31,055 (20,764) 34,283

Taxation 944 (64) 11,737 – 12,617

Profit for the year 1,955 21,157 19,318 (20,764) 21,666

Attributable to

BP shareholders 1,955 21,157 18,809 (20,764) 21,157

Minority interest – – 509 – 509

1,955 21,157 19,318 (20,764) 21,666

 $ million 

For the year ended 31 December 2007 

Issuer Guarantor

 BP Eliminations 

Exploration Other and

(Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Sales and other operating revenues 5,243 – 284,365 (5,243) 284,365

Earnings from jointly controlled entities – after interest and tax – – 3,135 – 3,135

Earnings from associates – after interest and tax – – 697 – 697

Equity-accounted income of subsidiaries – after interest and tax 586 21,201 – (21,787) –

Interest and other revenuesa 758 205 1,166 (1,375) 754

Total revenues 6,587 21,406 289,363 (28,405) 288,951

Gains on sale of businesses and fixed assets 1 – 2,486 – 2,487

Total revenues and other income 6,588 21,406 291,849 (28,405) 291,438

Purchases 650 – 205,359 (5,243) 200,766

Production and manufacturing expenses 897 – 25,018 – 25,915

Production and similar taxes 1,052 – 2,961 – 4,013

Depreciation, depletion and amortization 388 – 10,191 – 10,579

Impairment and losses on sale of businesses and fixed assets – – 1,679 – 1,679

Exploration expense – – 756 – 756

Distribution and administration expenses 22 921 14,536 (108) 15,371

Fair value (gain) loss on embedded derivatives – – 7 – 7 

Profit before interest and taxation 3,579 20,485 31,342 (23,054) 32,352

Finance costsa 49 381 2,230 (1,267) 1,393

Net finance (income) expense relating to pensions and other post-retirement 

benefits – (820) 168 – (652)

Profit before taxation 3,530 20,924 28,944 (21,787) 31,611

Taxationa 1,055 79 9,308 – 10,442

Profit for the year 2,475 20,845 19,636 (21,787) 21,169

Attributable to

BP shareholders 2,475 20,845 19,312 (21,787) 20,845

Minority interest – – 324 – 324

 2,475 20,845 19,636 (21,787) 21,169

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51. Condensed consolidating information on certain US subsidiaries continued 

Income statement continued 

181

Additional information for US reporting

$ million

For the year ended 31 December 2006

Issuer Guarantor

BP Eliminations

 Exploration Other and 

(Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Sales and other operating revenues 4,812 – 265,906 (4,812) 265,906

Earnings from jointly controlled entities – after interest and tax – – 3,553 – 3,553

Earnings from associates – after interest and tax – – 442 – 442

Equity-accounted income of subsidiaries – after interest and tax 570 23,119 – (23,689) –

Interest and other revenuesa 627 187 1,509 (1,622) 701

Total revenues 6,009 23,306 271,410 (30,123) 270,602

Gains on sale of businesses and fixed assets – 105 3,714 (105) 3,714

Total revenues and other income 6,009 23,411 275,124 (30,228) 274,316

Purchases 566 – 191,429 (4,812) 187,183

Production and manufacturing expenses 814 – 22,479 – 23,293

Production and similar taxes 665 – 2,956 – 3,621

Depreciation, depletion and amortization 374 – 8,754 – 9,128

Impairment and losses on sale of businesses and fixed assets 109 – 440 – 549

Exploration expense 14 – 1,031 – 1,045

Distribution and administration expenses 20 278 14,264 (115) 14,447

Fair value (gain) loss on embedded derivatives – – (608) – (608)

Profit before interest and taxation from continuing operations 3,447 23,133 34,379 (25,301) 35,658

Finance costsa 11 702 1,780 (1,507) 986

Net finance (income) expense relating to pensions and other post-retirement 

benefits – (675) 205 – (470)

Profit before taxation from continuing operations 3,436 23,106 32,394 (23,794) 35,142

Taxationa 1,005 686 10,825 – 12,516

Profit from continuing operations 2,431 22,420 21,569 (23,794) 22,626

Profit (loss) from Innovene operations – – (25) – (25)

Profit for the year 2,431 22,420 21,544 (23,794) 22,601

Attributable to

BP shareholders 2,431 22,420 21,258 (23,794) 22,315

Minority interest – – 286 – 286

2,431 22,420 21,544 (23,794) 22,601

aWithin the 2006 and 2007 income statements, the tax charge for BP Exploration (Alaska) Inc has been reduced by $238 million for 2006 and $26 million for 2007 from the amounts previously disclosed, and the tax 

charge for Other subsidiaries has been increased by $238 million and $26 million respectively from the amounts previously disclosed. This change has been made to reflect the allocation of tax charges between BP 

Exploration (Alaska) Inc and other Alaskan subsidiaries in the BP group. As a result of this immaterial change, the profit for the year relating to BP Exploration (Alaska) Inc has increased by $238 million in 2006 and 

$26 million in 2007 and the profit for the year relating to Other subsidiaries has decreased by $238 million and $26 million respectively. There is no impact on the consolidated group profit for the year. In addition, for 

Other subsidiaries the amount of interest and other revenues in 2007 has been increased by $789 million (2006, $628 million) and the amount of finance costs has increased by the same amounts. This change has 

been made to properly reflect interest between group entities. Corresponding adjustments have been to the Eliminations and reclassifications amounts. The BP group amounts are unchanged. This immaterial change 

has no impact upon profit for the year for Other subsidiaries or BP group.

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51. Condensed consolidating information on certain US subsidiaries continued 

Balance sheet 

182 

Additional information for US reporting

 $ million 

At 31 December 2008

Issuer Guarantor 

BP Eliminations

Exploration Other and

(Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Non-current assets 

Property, plant and equipment 6,959 – 96,241 – 103,200

Goodwill – – 9,878 – 9,878

Intangible assets 243 – 10,017 – 10,260

Investments in jointly controlled entities – – 23,826 – 23,826

Investments in associates – 2 3,998 – 4,000

Other investments – – 855 – 855

Subsidiaries – equity-accounted basis 3,585 111,730 – (115,315) –

Fixed assets 10,787 111,732 144,815 (115,315) 152,019

Loans 209 1,174 1,393 (1,781) 995

Other receivables – – 710 – 710

Derivative financial instruments – – 5,054 – 5,054

Prepayments – – 1,338 – 1,338

Defined benefit pension plan surpluses – 1,516 222 – 1,738

 10,996 114,422 153,532 (117,096) 161,854

Current assets 

Loans – – 168 – 168

Inventories 198 – 16,623 – 16,821

Trade and other receivables 18,302 6,129 35,745 (30,915) 29,261

Derivative financial instruments – – 8,510 – 8,510

Prepayments 37 – 3,013 – 3,050

Current tax receivable – – 377 – 377

Cash and cash equivalents (10) 11 8,196 – 8,197

 18,527 6,140 72,632 (30,915) 66,384

Total assets 29,523 120,562 226,164 (148,011) 228,238

Current liabilities

Trade and other payables 4,925 2,602 57,032 (30,915) 33,644

Derivative financial instruments – – 8,977 – 8,977

Accruals – 7 6,736 – 6,743

Finance debt 55 – 15,685 – 15,740

Current tax payable 162 – 2,982 – 3,144

Provisions – – 1,545 – 1,545

 5,142 2,609 92,957 (30,915) 69,793

Non-current liabilities 

Other payables 398 33 4,430 (1,781) 3,080

Derivative financial instruments – – 6,271 – 6,271

Accruals – 47 737 – 784

Finance debt – – 17,464 – 17,464

Deferred tax liabilities 1,630 322 14,246 – 16,198

Provisions 1,074 – 11,034 – 12,108

Defined benefit pension plan and other post-retirement benefit plan deficits – – 10,431 – 10,431

3,102 402 64,613 (1,781) 66,336

Total liabilities 8,244 3,011 157,570 (32,696) 136,129

Net assets 21,279 117,551 68,594 (115,315) 92,109

Equity

BP shareholders’ equity 21,279 117,551 67,788 (115,315) 91,303

Minority interest – – 806 – 806

Total equity 21,279 117,551 68,594 (115,315) 92,109

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51. Condensed consolidating information on certain US subsidiaries continued 

Balance sheet continued 

183

Additional information for US reporting

$ million

At 31 December 2007

Issuer Guarantor

BP Eliminations

 Exploration Other and 

(Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Non-current assets

Property, plant and equipment 6,310 – 91,679 – 97,989

Goodwill – – 11,006 – 11,006

Intangible assets 349 – 6,303 – 6,652

Investments in jointly controlled entities – – 18,113 – 18,113

Investments in associates – 2 4,577 – 4,579

Other investments – – 1,830 – 1,830

Subsidiaries – equity-accounted basis 3,117 115,476 – (118,593) – 

Fixed assets 9,776 115,478 133,508 (118,593) 140,169

Loans 2,151 1,192 1,541 (3,885) 999

Other receivables – – 968 – 968

Derivative financial instruments – – 3,741 – 3,741

Prepayments – – 1,083 – 1,083

Defined benefit pension plan surpluses – 7,265 1,649 – 8,914

11,927 123,935 142,490 (122,478) 155,874

Current assets

Loans – – 165 – 165

Inventories 202 – 26,352 – 26,554

Trade and other receivablesa 15,986 840 44,422 (23,228) 38,020

Derivative financial instruments – – 6,321 – 6,321

Prepayments 24 – 3,565 – 3,589

Current tax receivable – – 705 – 705

Cash and cash equivalents (10) 244 3,328 – 3,562

16,202 1,084 84,858 (23,228) 78,916

Assets classified as held for sale – – 1,286 – 1,286

16,202 1,084 86,144 (23,228) 80,202

Total assets 28,129 125,019 228,634 (145,706) 236,076

Current liabilities 

Trade and other payablesa 4,969 3,115 58,296 (23,228) 43,152

Derivative financial instruments – – 6,405 – 6,405

Accruals – 10 6,630 – 6,640

Finance debt 55 – 15,339 – 15,394

Current tax payable 306 – 2,976 – 3,282

Provisions – – 2,195 – 2,195

5,330 3,125 91,841 (23,228) 77,068

Liabilities directly associated with assets classified as held for sale – – 163 – 163

5,330 3,125 92,004 (23,228) 77,231

Non-current liabilities

Other payables 559 27 4,550 (3,885) 1,251

Derivative financial instruments – – 5,002 – 5,002

Accruals – 44 915 – 959

Finance debt – – 15,651 – 15,651

Deferred tax liabilities 1,765 1,885 15,565 – 19,215

Provisions 946 – 11,954 – 12,900

Defined benefit pension plan and other post-retirement benefit plan deficits – – 9,215 – 9,215

3,270 1,956 62,852 (3,885) 64,193

Total liabilities 8,600 5,081 154,856 (27,113) 141,424

Net assets 19,529 119,938 73,778 (118,593) 94,652

Equity

BP shareholders’ equity 19,529 119,938 72,816 (118,593) 93,690

Minority interest – – 962 – 962

Total equity 19,529 119,938 73,778 (118,593) 94,652

aWithin Current liabilities – Trade and other payables, the amount of other payables for BP Exploration (Alaska) Inc. has been reduced by $264 million from the amount previously reported and within Current assets –

Trade and other receivables the amount of other receivables for other subsidiaries has been reduced by $264 million from the amounts previously reported, with a corresponding change to intercompany eliminations 

within the Eliminations and reclassifications column. As a result of this immaterial change, the net assets and BP shareholders’ equity of BP Exploration (Alaska) Inc. have increased by $264 million and the net assets 

and BP shareholders’ equity of Other subsidiaries have decreased by $264 million. This change has been made to reflect the allocation of tax liabilities between BP Exploration (Alaska) Inc. and other Alaskan 

subsidiaries in the BP group. There is no impact on the BP group total equity. 

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51. Condensed consolidating information on certain US subsidiaries continued 

Cash flow statement 

184 

Additional information for US

$ million

2008

Issuer Guarantor

BP Eliminations

Exploration Other and 

(Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Net cash provided by operating activities 6,793 12,665 35,703 (17,066) 38,095

Net cash used in investing activities (896) – (21,871) – (22,767)

Net cash used in financing activities (5,897) (12,898) (8,780) 17,066 (10,509)

Currency translation differences relating to cash and cash equivalents – – (184) – (184)

(Decrease) increase in cash and cash equivalents – (233) 4,868 – 4,635

Cash and cash equivalents at beginning of year (10) 244 3,328 – 3,562

Cash and cash equivalents at end of year (10) 11 8,196 – 8,197

$ million

2007

Issuer Guarantor 

BP Eliminations

Exploration Other and

 (Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Net cash provided by operating activities 3,072 15,403 22,839 (16,605) 24,709

Net cash used in investing activities (532) 1 (14,306) – (14,837)

Net cash used in financing activities (2,545) (15,139) (7,956) 16,605 (9,035)

Currency translation differences relating to cash and cash equivalents – – 135 – 135

(Decrease) increase in cash and cash equivalents (5) 265 712 – 972

Cash and cash equivalents at beginning of year (5) (21) 2,616 – 2,590

Cash and cash equivalents at end of year (10) 244 3,328 – 3,562

 

 $ million 

 2006 

Issuer Guarantor

 BP Eliminations 

Exploration Other and

(Alaska) Inc. BP p.l.c. subsidiaries reclassifications BP group

Net cash provided by operating activities 3,522 20,628 29,030 (25,008) 28,172

Net cash used in investing activities (379) 843 (9,982) – (9,518)

Net cash used in financing activities (3,141) (21,495) (19,443) 25,008 (19,071)

Currency translation differences relating to cash and cash equivalents – – 47 – 47

(Decrease) increase in cash and cash equivalents 2 (24) (348) – (370)

Cash and cash equivalents at beginning of year (7) 3 2,964 – 2,960

Cash and cash equivalents at end of year (5) (21) 2,616 – 2,590

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Supplementary information on oil and natural gas (unaudited) 

Movements in estimated net proved reserves 

For details of BP’s governance process for the booking of oil and natural gas reserves, see page 15. BP estimates proved reserves for reporting purposes in 

accordance with SEC rules and relevant guidance. As currently required, these proved reserve estimates are based on prices and costs as of the date the estimate 

is made. There was a rapid and substantial decline in oil prices in the fourth quarter of 2008 that was not matched by a similar reduction in operating costs by the 

end of the year. BP does not expect that these economic conditions will continue. However, our 2008 reserves are calculated on the basis of operating activities 

that would be undertaken were year-end prices and costs to persist. 

185

Supplementary information on oil and natural gas (unaudited)

2008

Crude oila million barrels

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Subsidiaries 

At 1 January 2008

Developed 414 105 1,882 115 61 256 – 104 2,937

Undeveloped 123 169 1,265 203 77 350 – 368 2,555

537 274 3,147 318 138 606 – 472 5,492

Changes attributable to

Revisions of previous estimates 16 (11) (212) 8 16 264 – 183 264

Purchases of reserves-in-place – – – – – – – – –

Discoveries and extensions – – 64 5 – 173 – – 242

Improved recovery 39 28 182 8 6 18 – 40 321

Productionb (63) (16) (191) (26) (14) (101) – (44) (455)

Sales of reserves-in-place – – – (199) – – – – (199)

(8) 1 (157) (204) 8 354 – 179 173

At 31 December 2008c 

Developed 410 81 1,717 58 77 464 – 174 2,981

Undeveloped 119 194 1,273 56 69 496 – 477 2,684

 529 275 2,990e 114 146 960 – 651 5,665

Equity-accounted entities (BP share) 

At 1 January 2008 

Developed – – – 328 1 – 2,094 573 2,996

Undeveloped – – – 243 – – 1,137 205 1,585

 – – – 571 1 – 3,231 778 4,581

Changes attributable to 

Revisions of previous estimates – – – (3) – 11 217 (1) 224

Purchases of reserves-in-place – – – 199 – – – – 199

Discoveries and extensions – – – 13 – – 26 – 39

Improved recovery – – – 62 – – – – 62

Production – – – (34) – – (302) (80) (416)

Sales of reserves-in-place – – – – – – (1) – (1)

– – – 237 – 11 (60) (81) 107

At 31 December 2008d

Developed – – – 399 1 – 2,227 498 3,125

Undeveloped – – – 409 – 11 944 199 1,563

 – – – 808 1 11 3,171 697 4,688

aCrude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option 

and ability to make lifting and sales arrangements independently. 

bExcludes NGLs from processing plants in which an interest is held of 19 thousand barrels per day.

c

Includes 807 million barrels of NGLs. Also includes 21 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. 

dIncludes 36 million barrels of NGLs. Also includes 216 million barrels of crude oil in respect of the 6.80% minority interest in TNK-BP.

eProved reserves in the Prudhoe Bay field in Alaska include an estimated 54 million barrels 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.

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Supplementary information on oil and natural gas (unaudited) continued 

Movements in estimated net proved reserves continued 

186 

Supplementary information on oil and natural gas (unaudited)

2008

Natural gasa billion cubic feet

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Subsidiaries 

At 1 January 2008 

Developed 2,049 63 10,670 3,683 1,822 990 – 583 19,860

Undeveloped 553 410 4,705 8,394 4,817 1,410 – 981 21,270

 2,602 473 15,375 12,077 6,639 2,400 – 1,564 41,130

Changes attributable to 

Revisions of previous estimates 23 (8) (2,063) (405) 326 142 – 35 (1,950)

Purchases of reserves-in-place – – 183 – – – – – 183

Discoveries and extensions – – 549 1,073 – 82 – 37 1,741

Improved recovery 77 9 1,322 175 56 6 – 54 1,699

Productionb (298) (11) (834) (1,040) (264) (198) – (150) (2,795)

Sales of reserves-in-place – – – (3) – – – – (3)

(198) (10) (843) (200) 118 32 – (24) (1,125)

At 31 December 2008c

Developed 1,822 61 9,059 3,975 2,482 1,050 – 507 18,956

Undeveloped 582 402 5,473 7,902 4,275 1,382 – 1,033 21,049

 2,404 463 14,532 11,877 6,757 2,432 – 1,540 40,005

Equity-accounted entities (BP share)

At 1 January 2008

Developed – – – 1,478 39 – 808 148 2,473

Undeveloped – – – 831 37 – 353 76 1,297

– – – 2,309 76 – 1,161 224 3,770

Changes attributable to

Revisions of previous estimates – – – (96) (2) 182 1,273 – 1,357

Purchases of reserves-in-place – – – 3 – – – – 3

Discoveries and extensions – – – 192 – – – – 192

Improved recovery – – – 301 11 – – – 312

Productionb – – – (188) (12) – (221) (10) (431)

Sales of reserves-in-place – – – – – – – – –

– – – 212 (3) 182 1,052 (10) 1,433

At 31 December 2008d

Developed – – – 1,498 37 – 1,560 139 3,234

Undeveloped – – – 1,023 36 182 653 75 1,969

 – – – 2,521 73 182 2,213 214 5,203

aProved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales 

arrangements independently. 

bIncludes 193 billion cubic feet of natural gas consumed in operations, 149 billion cubic feet in subsidiaries, 44 billion cubic feet in equity-accounted entities and excludes 16.9 billion cubic feet of produced nonhydrocarbon components which meet regulatory requirements for sales. 

cIncludes 3,108 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 131 billion cubic feet of natural gas in respect of the 5.92% minority interest in TNK-BP.

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187

Supplementary information on oil and natural gas (unaudited)

2007

Crude oila million barrels

Rest of Rest of Asia

 UK Europe US Americas Pacific Africa Russia Other Total 

Subsidiaries 

At 1 January 2007 

Developed 458 189 1,916 130 67 193 – 88 3,041

Undeveloped 146 97 1,292 237 86 512 – 482 2,852

 604 286 3,208 367 153 705 – 570 5,893 

Changes attributable to 

Revisions of previous estimates (1) (25) 18 (29) (7) (133) – (27) (204)

Purchases of reserves-in-place – – 25 – – – – 8 33 

Discoveries and extensions – 31 60 1 2 93 – – 187

Improved recovery 7 1 99 6 5 12 – 1 131

Productionb (73) (19) (169) (27) (15) (71) – (80) (454)

Sales of reserves-in-place – – (94) – – – – – (94)

(67) (12) (61) (49) (15) (99) – (98) (401)

At 31 December 2007c

Developed 414 105 1,882 115 61 256 – 104 2,937

Undeveloped 123 169 1,265 203 77 350 – 368 2,555

 537 274 3,147f 318 138 606 – 472 5,492

Equity-accounted entities (BP share)d

At 1 January 2007

Developed – – – 221 1 – 2,200 520 2,942 

Undeveloped – – – 139 – – 644 163 946

– – – 360 1 – 2,844 683 3,888

Changes attributable to

Revisions of previous estimates – – – 178 – – 413 167 758 

Purchases of reserves-in-place – – – – – – 16 – 16

Discoveries and extensions – – – 2 – – 283 – 285 

Improved recovery – – – 59 – – – 1 60

Production – – – (28) – – (304) (73) (405)

Sales of reserves-in-place – – – – – – (21) – (21)

– – – 211 – – 387 95 693

At 31 December 2007e

Developed – – – 328 1 – 2,094 573 2,996

Undeveloped – – – 243 – – 1,137 205 1,585

 – – – 571 1 – 3,231 778 4,581 

aCrude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option 

and ability to make lifting and sales arrangements independently. 

bExcludes NGLs from processing plants in which an interest is held of 54 thousand barrels per day.

c

Includes 739 million barrels of NGLs. Also includes 20 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dThe BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. During the second quarter of 2007, we updated our reporting policy in Abu 

Dhabi to be consistent with general industry practice and as a result have started reporting production and reserves there gross of production taxes. This change resulted in an increase in our reserves of 153 million 

barrels and in our production of 33mb/d.

eIncludes 26 million barrels of NGLs. Also includes 210 million barrels of crude oil in respect of the 6.51% minority interest in TNK-BP. 

fProved reserves in the Prudhoe Bay field in Alaska include an estimated 98 million barrels 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.

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Movements in estimated net proved reserves continued 

188 

Supplementary information on oil and natural gas (unaudited)

2007

Natural gasa billion cubic feet

Rest of Rest of Asia

 UK Europe US Americas Pacific Africa Russia Other Total 

Subsidiaries 

At 1 January 2007 

Developed 1,968 242 10,438 3,932 1,359 1,032 – 331 19,302

Undeveloped 825 56 4,660 9,194 5,202 1,675 – 1,254 22,866

 2,793 298 15,098 13,126 6,561 2,707 – 1,585 42,168 

Changes attributable to 

Revisions of previous estimates 93 (37) 744 (276) 140 (146) – (21) 497

Purchases of reserves-in-place – – 23 – – – – 109 132 

Discoveries and extensions – 293 95 249 88 17 – – 742

Improved recovery 15 1 326 32 111 9 – 5 499

Productionb (299) (14) (879) (1,047) (261) (187) – (114) (2,801)

Sales of reserves-in-place – (68) (32) (7) – – – – (107)

(191) 175 277 (1,049) 78 (307) – (21) (1,038)

At 31 December 2007c

Developed 2,049 63 10,670 3,683 1,822 990 – 583 19,860

Undeveloped 553 410 4,705 8,394 4,817 1,410 – 981 21,270

2,602 473 15,375 12,077 6,639 2,400 – 1,564 41,130

Equity-accounted entities (BP share)

At 1 January 2007 

Developed – – – 1,460 52 – 1,087 170 2,769

Undeveloped – – – 735 23 – 184 52 994

– – – 2,195 75 – 1,271 222 3,763

Changes attributable to 

Revisions of previous estimates – – – 73 (2) – 61 11 143

Purchases of reserves-in-place – – – – – – 8 – 8

Discoveries and extensions – – – 22 – – – – 22

Improved recovery – – – 195 16 – – – 211

Productionb – – – (176) (13) – (179) (9) (377)

Sales of reserves-in-place – – – – – – – – –

– – – 114 1 – (110) 2 7

At 31 December 2007d

Developed – – – 1,478 39 – 808 148 2,473

Undeveloped – – – 831 37 – 353 76 1,297

 – – – 2,309 76 – 1,161 224 3,770

aProved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales 

arrangements independently. 

bIncludes 202 billion cubic feet of natural gas consumed in operations, 161 billion cubic feet in subsidiaries, 41 billion cubic feet in equity-accounted entities and excludes 10.9 billion cubic feet of produced nonhydrocarbon components which meet regulatory requirements for sales. 

cIncludes 3,211 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 68 billion cubic feet of natural gas in respect of the 5.88% minority interest in TNK-BP.

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Movements in estimated net proved reserves continued 

189

Supplementary information on oil and natural gas (unaudited)

2006

Crude oila million barrels

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total 

Subsidiaries 

At 1 January 2006 

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 

Changes attributable to 

Revisions of previous estimates (3) (11) (108) (9) – 2 – 16 (113)

Purchases of reserves-in-place – – – – – – – – – 

Discoveries and extensions 3 – 48 – 1 67 – – 119

Improved recovery 26 9 95 13 4 22 – – 169

Productionb (92) (23) (178) (39) (17) (64) – (58) (471)

Sales of reserves-in-place (10) – (62) (99) – – – – (171)

(76) (25) (205) (134) (12) 27 – (42) (467)

At 31 December 2006c

Developed 458 189 1,916 130 67 193 – 88 3,041

Undeveloped 146 97 1,292 237 86 512 – 482 2,852

 604 286 3,208e 367 153 705 – 570 5,893

Equity-accounted entities (BP share)

At 1 January 2006 

Developed – – – 207 1 – 1,688 590 2,486 

Undeveloped – – – 124 – – 431 164 719

– – – 331 1 – 2,119 754 3,205

Changes attributable to

Revisions of previous estimates – – – (2) – – 1,215 (8) 1,205 

Purchases of reserves-in-place – – – 28 – – – – 28

Discoveries and extensions – – – 1 – – – – 1 

Improved recovery – – – 34 – – – – 34

Production – – – (28) – – (320) (63) (411)

Sales of reserves-in-place – – – (4) – – (170) – (174)

– – – 29 – – 725 (71) 683

At 31 December 2006d

Developed – – – 221 1 – 2,200 520 2,942

Undeveloped – – – 139 – – 644 163 946

 – – – 360 1 – 2,844 683 3,888 

aCrude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option to 

make lifting and sales arrangements independently. 

bExcludes NGLs from processing plants in which an interest is held of 55 thousand barrels per day.

c

Includes 779 million barrels of NGLs. Also includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 28 million barrels of NGLs. Also includes 179 million barrels of crude oil in respect of the 6.29% minority interest in TNK-BP.

eProved reserves in the Prudhoe Bay field in Alaska include an estimated 81 million barrels 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.

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Movements in estimated net proved reserves continued 

190 

Supplementary information on oil and natural gas (unaudited)

2006

Natural gasa billion cubic feet

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total 

Subsidiaries 

At 1 January 2006 

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 

Changes attributable to

Revisions of previous estimates (343) 11 (922) (291) (92) (69) – 33 (1,673)

Purchases of reserves-in-place – – – – – – – – – 

Discoveries and extensions 101 – 116 – 21 5 – 2 245

Improved recovery 144 – 1,755 344 71 6 – 9 2,329

Productionb (370) (38) (941) (982) (273) (169) – (82) (2,855)

Sales of reserves-in-place (25) – (292) (9) – – – – (326)

 (493) (27) (284) (938) (273) (227) – (38) (2,280)

At 31 December 2006c

Developed 1,968 242 10,438 3,932 1,359 1,032 – 331 19,302 

Undeveloped 825 56 4,660 9,194 5,202 1,675 – 1,254 22,866

2,793 298 15,098 13,126 6,561 2,707 – 1,585 42,168

Equity-accounted entities (BP share)

At 1 January 2006

Developed – – – 1,492 50 – 1,089 130 2,761 

Undeveloped – – – 848 26 – 169 52 1,095

– – – 2,340 76 – 1,258 182 3,856

Changes attributable to

Revisions of previous estimates – – – 7 13 – 217 47 284

Purchases of reserves-in-place – – – – – – – – –

Discoveries and extensions – – – 23 – – – – 23 

Improved recovery – – – 73 1 – – – 74

Productionb – – – (171) (15) – (204) (7) (397)

Sales of reserves-in-place – – – (77) – – – – (77)

– – – (145) (1) – 13 40 (93)

At 31 December 2006d

Developed – – – 1,460 52 – 1,087 170 2,769

Undeveloped – – – 735 23 – 184 52 994

 – – – 2,195 75 – 1,271 222 3,763

aProved reserves exclude royalties due to others, whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option to make lifting and sales arrangements 

independently. 

bIncludes 178 billion cubic feet of natural gas consumed in operations, 147 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities and excludes 8.3 billion cubic feet of produced nonhydrocarbon components which meet regulatory requirements for sales. 

cIncludes 3,537 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 99 billion cubic feet of natural gas in respect of the 7.77% minority interest in TNK-BP.

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Supplementary information on oil and natural gas (unaudited) continued 

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 FASB Statement of Financial Accounting 

Standards 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 reserves 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. 

The following are the principal sources of change in the standardized measure of discounted future net cash flows: 

191

Supplementary information on oil and natural gas (unaudited)

 

$ million

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Other Total

At 31 December 2008

Future cash inflowsa 36,400 13,800 165,800 32,700 28,400 40,400 27,200 344,700

Future production costb 18,100 6,300 80,400 9,900 12,100 11,600 10,400 148,800

Future development costb 3,300 2,900 25,600 8,500 3,800 10,900 6,900 61,900

Future taxationc 7,300 2,300 17,500 6,000 3,200 6,600 2,000 44,900

Future net cash flows 7,700 2,300 42,300 8,300 9,300 11,300 7,900 89,100

10% annual discountd 2,200 1,200 21,000 3,900 4,600 5,500 3,500 41,900

Standardized measure of discounted future 

net cash flowse 5,500 1,100 21,300 4,400 4,700 5,800 4,400 47,200

At 31 December 2007

Future cash inflowsa 72,100 29,500 350,100 67,700 47,600 63,300 49,400 679,700

Future production costb 27,500 7,500 109,800 17,900 12,800 9,900 8,500 193,900 

Future development costb 4,000 3,300 21,900 6,500 4,100 8,300 3,500 51,600

Future taxationc 20,200 13,000 71,600 21,700 9,700 17,100 8,700 162,000 

Future net cash flows 20,400 5,700 146,800 21,600 21,000 28,000 28,700 272,200 

10% annual discountd 6,500 2,800 76,000 9,500 10,300 9,400 11,500 126,000

Standardized measure of discounted future 

net cash flowse 13,900 2,900 70,800 12,100 10,700 18,600 17,200 146,200 

At 31 December 2006 

Future cash inflowsa 45,300 18,200 218,900 46,800 36,800 47,700 36,200 449,900

Future production costb 20,700 4,700 71,300 14,900 9,400 8,700 7,200 136,900 

Future development costb 3,300 1,500 18,600 4,900 3,800 6,600 3,900 42,600

Future taxationc 10,300 9,400 43,100 12,900 7,000 10,600 5,800 99,100

Future net cash flows 11,000 2,600 85,900 14,100 16,600 21,800 19,300 171,300

10% annual discountd 3,200 1,000 45,600 6,200 9,000 8,400 7,300 80,700

Standardized measure of discounted future 

net cash flowse 7,800 1,600 40,300 7,900 7,600 13,400 12,000 90,600

$ million

2008 2007 2006

Sales and transfers of oil and gas produced, net of production costs (43,600) (28,300) (35,800)

Previously estimated development costs incurred during the year 9,400 9,400 8,200 

Extensions, discoveries and improved recovery, less related costs 4,400 12,300 7,900

Net changes in prices and production cost (146,800) 102,100 (43,900)

Revisions of previous reserves estimates 1,200 (12,200) (9,500)

Net change in taxation 69,400 (28,300) 32,200

Future development costs (7,400) (7,800) (7,000)

Net change in purchase and sales of reserves-in-place (200) (700) (2,500)

Addition of 10% annual discount 14,600 9,100 12,800

Total change in the standardized measure during the yearf (99,000) 55,600 (37,600)

aThe year-end marker prices used were Brent $36.55/bbl, Henry Hub $5.63/mmBtu (2007 Brent $96.02/bbl, Henry Hub $7.10/mmBtu and 2006 Brent $58.93/bbl, Henry Hub $5.52/mmBtu).

bProduction costs, which include production taxes 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. 

cTaxation is computed using appropriate year-end statutory corporate income tax rates.

dFuture 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. 

eMinority interest in BP Trinidad and Tobago LLC amounted to $900 million at 31 December 2008 ($2,300 million at 31 December 2007 and $1,300 million at 31 December 2006).

fTotal change in the standardized measure during the year includes the effect of exchange rate movements.

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Supplementary information on oil and natural gas (unaudited) continued 

Equity-accounted entities 

In addition, at 31 December 2008, the group’s share of the standardized measure of discounted future net cash flows of equity-accounted entities amounted to 

$9,000 million ($28,300 million at 31 December 2007 and $14,700 million at 31 December 2006), excluding minority interest. 

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 31 December 2008, 2007 and 2006. 

Production for the yeara

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 at 31 December 2008. 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. 

192 

Supplementary information on oil and natural gas (unaudited)

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Subsidiaries

Crude oilb

thousand barrels per day

2008 173 43 538 75 37 277 – 120 1,263

2007 201 51 513 82 41 195 – 221 1,304

2006 253 61 547 108 44 177 – 161 1,351

Natural gasc million cubic feet per day

2008 759 23 2,157 2,777 699 484 – 378 7,277

2007 768 29 2,174 2,798 699 468 – 286 7,222

2006 936 91 2,376 2,645 727 430 – 207 7,412

Equity-accounted entities (BP share)

Crude oilb

thousand barrels per day

2008 – – – 92 1 – 826 219 1,138

2007 – – – 77 1 – 832 200 1,110

2006 – – – 77 1 – 876 170 1,124

Natural gasc million cubic feet per day

2008 – – – 454 31 – 564 8 1,057

2007 – – – 429 33 – 451 8 921

2006 – – – 416 37 – 544 8 1,005

aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements 

independently.

bCrude oil includes natural gas liquids and condensate.

cNatural gas production excludes gas consumed in operations.

 Rest of Rest of Asia 

UK Europe US Americas Pacific Africa Russia Other Total

Number of productive wells at 31 

December 2008 

Oil wellsa – gross 273 81 5,960 3,695 250 669 19,991 1,622 32,541

– net 147 25 2,120 2,023 108 544 8,503 268 13,738

Gas wellsb – gross 310 – 20,913 2,326 466 99 44 134 24,292

– net 142 – 11,948 1,397 166 45 22 89 13,809

aIncludes approximately 966 gross (255 net) multiple completion wells (more than one formation producing into the same well bore).

bIncludes approximately 2,631 gross (1,737 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.

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Supplementary information on oil and natural gas (unaudited) 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. 

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 at 31 December 2008. Suspended development wells and long-term suspended exploratory wells are also included in the table. 

193

Supplementary information on oil and natural gas (unaudited)

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Oil and natural gas acreage at 31 

December 2008 Thousands of acres

Developed – gross 390 64 7,657 3,151 1,251 500 4,072 1,876 18,961

– net 193 18 4,783 1,414 327 212 1,768 692 9,407

Undevelopeda – gross 1,615 519 7,733 15,586 7,433 21,524 10,079 14,832 79,321

 – net 916 234 5,332 9,081 2,782 16,009 4,544 6,098 44,996

aUndeveloped acreage includes leases and concessions.

 

 Rest of Rest of Asia 

UK Europe US Americas Pacific Africa Russia Other Total

2008

Exploratory

Productive 0.8 – 2.4 4.4 1.1 4.3 12.5 – 25.5

Dry – 0.5 0.9 0.5 0.4 2.6 23.0 0.5 28.4

Development 

Productive 6.6 0.5 379.8 140.8 23.3 18.6 10.0 26.6 606.2

Dry 0.2 – 1.1 3.8 0.8 1.5 19.5 1.3 28.2

2007 

Exploratory

Productive 1.6 – 4.1 0.5 1.1 6.1 16.0 1.7 31.1 

Dry – – 0.7 0.5 0.4 1.6 9.0 1.0 13.2

Development

Productive 0.4 0.8 401.2 46.0 13.8 15.3 246.0 15.8 739.3

Dry 0.6 – 4.2 8.8 – – 9.5 – 23.1

2006 

Exploratory

Productive 0.1 0.1 2.9 0.5 1.0 3.2 15.6 1.4 24.8

Dry – – 7.4 1.0 1.5 0.5 5.7 0.3 16.4

Development

Productive 4.9 1.6 418.8 154.0 12.4 23.8 227.2 14.5 857.2 

Dry – – 4.5 5.0 0.2 – 20.8 1.0 31.5

 

 Rest of Rest of Asia 

UK Europe US Americas Pacific Africa Russia Other Total

At 31 December 2008

Exploratory

Gross 2.0 – 27.0 5.0 1.0 4.0 7.0 3.0 49.0

Net 0.2 – 12.8 2.8 0.2 2.6 3.0 2.3 23.9

Development 

Gross 8.0 2.0 480.0 27.0 8.0 15.0 20.0 20.0 580.0

Net 4.8 0.5 291.5 16.1 3.2 6.1 7.5 5.6 335.3

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Miscellaneous terms

 

194 

In this document, unless the context otherwise requires, 

the following terms shall have the meaning set out 

below. 

ADR 

American depositary receipt. 

ADS 

American depositary share. 

AGM 

Annual general meeting. 

Amoco 

The former Amoco Corporation and its 

subsidiaries. 

Atlantic Richfield 

Atlantic Richfield Company and its subsidiaries. 

Associate 

An entity, including an unincorporated entity 

such as a partnership, over which the group has 

significant influence and that is neither a 

subsidiary nor a joint venture. Significant 

influence is the power to participate in the 

financial and operating policy decisions of an 

entity but is not control or joint control over those 

policies. 

Barrel 

42 US gallons. 

b/d 

barrels per day. 

boe 

barrels of oil equivalent. 

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. 

Joint control 

Joint control is the contractually agreed sharing 

of control over an economic activity, and exists 

only when the strategic financial and operating 

decisions relating to the activity require the 

unanimous consent of the parties sharing control 

(the venturers). 

Joint venture 

A contractual arrangementwhereby two or more 

parties undertake an economic activity that is 

subject to joint control. 

Jointly controlled asset 

A joint venture where the venturers jointly 

control, and often have a direct ownership 

interest in the assets of the venture. The assets 

are used to obtain benefits for the venturers. 

Each venturer may take a share of the output 

from the assets and each bears an agreed share 

of the expenses incurred. 

Jointly controlled entity 

A joint venture that involves the establishment of 

acorporation, partnership or other entity in which 

each venturer has an interest. A contractual 

arrangement between the venturers establishes 

joint control over the economic activity of the 

entity. 

Liquids 

Crude oil, condensate and natural gas liquids. 

LNG 

Liquefied natural gas. 

London Stock Exchange or LSE 

London Stock Exchange plc. 

LPG 

Liquefied petroleum gas. 

mb/d 

thousand barrels per day. 

mboe/d 

thousand barrels of oil equivalent per day. 

mmBtu 

million British thermal units. 

mmboe 

million barrels of oil equivalent. 

mmcf 

million cubic feet. 

mmcf/d 

million cubic feet per day. 

MTBE 

Methyl tertiary butyl ether. 

MW 

Megawatt. 

NGLs 

Natural gas liquids. 

OPEC 

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. 

PSA 

Production-sharing agreement. 

SEC 

The United States Securities and Exchange 

Commission. 

Subsidiary 

An entity that is controlled by the BP group. 

Control is the power to govern the financial and 

operating policies of an entity so as to obtain the

benefits from its activities. 

Tonne 

2,204.6 pounds. 

UK 

United Kingdom of Great Britain and Northern 

Ireland. 

US 

United States of America. 

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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: 4 March 2009 

195

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