## 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 P erson)

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) O F 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 Sha res, pursuant to the requirements of the Securities and

Exchange Commission 

# Page 1 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 R ule 405 of the Securities Act.

Yes No 

If this report is an annual or transition report, indicate by check mark if the re gistrant 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 S ection 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 r equired 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, a n accelerated filer, or a non-accelerated filer. See definition of

‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the E xchange Act. (Check one):

Indicate by check mark which basis of accounting the registrant has used to prepare the f inancial 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 mar k 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 she ll 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  

# Page 2 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Cross reference to Form 20-F

2 Page

Item 1. Identity of Directors, Senior Management a nd 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 fina ncial 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 securit ies n/a

Item 13. Defaults, Dividend Arrearages and Delinquencies None

Item 14. Material Modifications to the Rights of Security Ho lders 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 Com mittees n/a

Item 16E. Purchases of Equity Securities by the Issuer and Af filiated 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 

# Page 3 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Contents

5 Performance review

61 Board performance and biographies

73 Directors’ remuneration report

85 Additional information for

shareholders

99 Financial statements Page 4 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Certain definitions

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

Oil and natural gas reserves

Oil and gas reserves

Proved reserves are defined by the Securities and E xchange Commission (SEC) in Rule 410(a) of Regulati on S-X, paragraphs (2), (2i), (2ii) and (2iii). Pro ved oil

and gas reserves are the estimated quantities of cr ude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with r easonable

certainty to be recoverable in future years from kn own reservoirs under existing economic and operatin g conditions, i.e., prices and costs as of the date the

estimate is made. Prices include consideration of c hanges in existing prices provided only by contract ual arrangements, but not on escalations based upon future

conditions.

(i) Reservoirs are considered proved if economic pr oducibility is supported by either actual productio n or conclusive formation test. The area of a reser voir

considered proved includes: (A) that portion deline ated by drilling and defined by gas-oil and/or oil- water contacts, if any; and (B) the immediately adj oining portions

not yet drilled, but which can be reasonably judged as economically productive on the basis of availab le geological and engineering data. In the absence of

information on fluid contacts, the lowest known str uctural occurrence of hydrocarbons controls the low er proved limit of the reservoir.

(ii) Reserves which can be produced economically th rough application of improved recovery techniques ( such as fluid injection) are included in the ‘prove d’

classification when successful testing by a pilot p roject, or the operation of an installed programme in the reservoir, provides support for the engineer ing analysis on

which the project or programme was based.

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

Proved developed reserves

Proved reserves that can be expected to be recovere d through existing wells with existing equipment an d operating methods. Additional oil and natural gas

expected to be obtained through the application of fluid injection or other improved recovery techniqu es for supplementing the natural forces and mechani sms 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 c onfirmed

through production response that increased recovery will be achieved.

Proved undeveloped reserves

Proved reserves that are expected to be recovered f rom new wells on undrilled acreage, or from existin g wells where a relatively major expenditure is req uired for

recompletion. Reserves on undrilled acreage shall b e limited to those drilling units offsetting produc tive units that are reasonably certain of productio n when drilled.

Proved reserves for other undrilled units can be cl aimed only where it can be demonstrated with certai nty that there is continuity of production from the existing

productive formation. Under no circumstances are es timates for proved undeveloped reserves attributabl e to any acreage for which an application of fluid injection

or other improved recovery technique is contemplate d, unless such techniques have been proved effectiv e by actual tests in the area and in the same reser voir.

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, th e recovery of which is subject to reasonable doubt because of uncertainty as to

geology, reservoir characteristics, or economic fac tors;

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

(d) crude oil, natural gas, and natural gas liquids, th at may be recovered from oil shales, coal, gilsonit e and other such sources. 

# Page 5 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 Page 6 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 revenues a 365,700 288,951 270,602 243,948 194,919

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

Profit from continuing operations a 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 acquisitions b 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 B P shareholders a

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 data c

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

Average number outstanding of 25 cent ordinary shar es (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 equity d 21% 22% 20% 17% 22%

a Excludes Innovene, which was treated as a discontinued ope ration in accordance with IFRS 5 ‘ Non

- current Assets Held for Sale and Discontinued Operations ’ in 2004, 2005 and 2006.

b 2008 included capital expenditure of $2,822 million an d an asset exchange of $1,909 million, both in respect of our transaction with Husky, as well as capital expendit ure of $3,667 million in respect of our transactions

with Chesapeake (see page 47). 2007 included $1,132 mil lion for the acquisition of Chevron’s Netherlands manufa cturing 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 i n 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 th e exception of the shares issued to Alfa Group and Acces s 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 fina ncing.

c The number of ordinary shares shown has been used to calcu late per share amounts.

d Net debt and the ratio of net debt to net debt plus equity ratio are non-GAAP measures. We believe that th ese 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 si gnificant net debt is relative to equity from sharehold ers. Net debt has been redefined to include the

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

the balance sheet within the headings ‘Derivative financi al instruments’. Amounts for comparative periods are p resented 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, ha s been extracted or derived

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

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

preparation of these financial statements. The sele cted information should be

read in conjunction with the audited financial stat ements and related Notes

elsewhere herein. BP sold its Innovene operations in December 2005. I n the circumstances of

discontinued operations, IFRS require that the prof its earned by the

discontinued operations, in this case the Innovene operations, on sales to the

continuing operations be eliminated on consolidatio n from the discontinued

operations and attributed to the continuing operati ons and vice versa. 

# Page 7 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmProduction and net proved oil and natural gas reser ves

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

Production and net proved reserves a

During 2008, 1,085 million barrels of oil and natur al gas, on an oil equivalent* basis (mmboe), were a dded to BP’s proved reserves for subsidiaries (excl uding

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 loc ated in the US (44%), Rest of Americas (17%), Asia Pacific (10%), Africa (11%) and the UK (8%).

For equity-accounted entities, 646mmboe w ere added to proved reserves (excluding purchases a nd sales), production was 491mmboe and proved reser ves

were 5,585mmboe at 31 December 2008.

7 Performance review

2008 f 2007 2006 2005 2004

Crude oil production for subsidiaries (thousand bar rels 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 cu bic 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 subsidi aries (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 subsi diaries (billion cubic feet) d 40,005 41,130 42,168 44,448 45,650

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

a Crude oil includes natural gas liquids (NGLs) and conde nsate. Production and proved reserves exclude royalties due t o 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 ma ke lifting and sales arrangements independently, and in clude minority interests in consolidated operations.

b Includes 21 million barrels (20 million barrels at 31 D ecember 2007 and 23 million barrels at 31 December 20 06) in respect of the 30% minority interest in BP Trini dad 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 TN K-BP (6.51% at 31 December 2007 and 6.29% at 31

December 2006).

d Includes 3,108 billion cubic feet of natural gas (3,21 1 billion cubic feet at 31 December 2007 and 3,537 bil lion cubic feet at 31 December 2006) in respect of the 3 0% minority interest in BP Trinidad and Tobago LLC.

e Includes 131 billion cubic feet (68 billion cubic feet at 31 December 2007 and 99 billion cubic feet at 31 De cember 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).

f BP estimates proved reserves for reporting purposes in accord ance with SEC rules and relevant guidance. As currently r equired, these proved reserve estimates are based on price s and costs as of the date the

estimate is made. There was a rapid and substantial decli ne in oil prices in the fourth quarter of 2008 that w as not matched by a similar reduction in operating cos ts by the end of the year. BP does not expect that these

economic conditions will continue. However, our 2008 rese rves are calculated on the basis of operating activities tha t would be undertaken were year

- end prices and costs to persist.

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

# Page 8 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm8

Performance review



# Risk factors

We urge you to consider carefully the risks describ ed 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 s ecurities could decline, in

which case you could lose all or part of your inves tment.

In the current global financial crisis an d 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 imp act of this situation will

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

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

the risk of increased taxation. These factors may a lso 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 wh om we do, or may do,

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

condition and liquidity.

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

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

flows from our business operations may be under pre ssure, this may impact

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

effect on our growth rate, and may impact sharehold er returns, including

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

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

Our system of risk management provides th e 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 regul ations.

The risks are categorized against the fol lowing areas: strategic;

compliance and control; and operational.

Strategic risks

Access and renewal

Successful execution of our group plan depends crit ically on implementing

activities to renew and reposition our portfolio. T he challenges to renewal of

our upstream portfolio are growing due to increasin g 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 internat ional supply and demand.

Political developments and the outcome of meetings of OPEC can particularly

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

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

resources. As a result, increased oil prices may no t improve margin

performance. In addition to the adverse effect on r evenues, 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 re views for impairment of the

group’s oil and natural gas properties. Such review s 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 significa nt effect on the group’s

results of operations in the period in which it occ urs. 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 a bility 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 via bility of the markets in which

we operate.

Refining profitability can be volatile, w ith both periodic oversupply and

supply tightness in various regional markets. Secto rs of the chemicals industry

are also subject to fluctuations in supply and dema nd within the

petrochemicals market, with a consequent effect on prices and profitability.

Climate change and carbon pricing

Compliance with changes in laws, regulations and ob ligations 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, ec onomic and social

transition is taking place. Some countries have exp erienced political instability,

changes to the regulatory environment, expropriatio n or nationalization of

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

conditions occurring could disrupt or terminate our operations, causing our

development activities to be curtailed or terminate d in these areas or our

production to decline and could cause us to incur a dditional costs. In

particular, our investments in Russia could be adve rsely affected by

heightened political and economic environment risks

. We set ourselves high standards of corpor ate 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 respect ing 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 high ly competitive. There is

strong competition, both within the oil and gas ind ustry and with other

industries, in supplying the fuel needs of commerce , industry and the home.

Competition puts pressure on product prices, affect s oil products marketing

and requires continuous management focus on reducin g unit costs and

improving efficiency. The implementation of group s trategy requires continued

technological advances and innovation including adv ances in exploration,

production, refining, petrochemicals manufacturing technology and advances

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

competitors developed or acquired intellectual prop erty rights to technology

that we required or if our innovation lagged the in dustry.

Investment efficiency

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

investing in the best options. Ineffective investme nt 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 resourc es are not progressed to

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

long-term replacement of reserves. 

# Page 9 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm9

Performance review

Liquidity, financial capacity and financial exposur e The group has established a financial framework to ensure that it is able to

maintain an appropriate level of liquidity and fina ncial 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 distre ssed leading to a loss of

shareholder value. Commercial credit risk is measur ed and controlled to

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

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

other sectors of the economy could impact the abili ty 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. Fluctua tions 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 instrum ents 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 inter vention by governments

throughout the world in such matters as the award o f exploration and

production interests, the imposition of specific dr illing obligations,

environmental and health and safety protection cont rols, controls over the

development and decommissioning of a field (includi ng restrictions on

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

certain regulated commodity markets. The oil indust ry 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 rel ating to the interpretation of,

and changes to, tax law. As a result of new laws an d regulations or other

factors, we could be required to curtail or cease c ertain operations, or we

could incur additional costs.

For more information on environmental reg ulation, 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 mi sconduct or noncompliance with applicable laws and regulations cou ld be damaging to our

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

into question the integrity of our operations.

For certain legal proceedings involving t he group, see Legal

proceedings on page 88.

Liabilities and provisions

Changes in the external environment, such as new la ws and regulations,

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

for pensions, tax, environmental and legal liabilit ies.

Reporting

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

of systems and people. Failure to report data accur ately 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 fai lure and loss of containment of

hydrocarbons and other hazardous material at operat ing sites or pipelines.

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

environmental damage, or loss of production and cou ld result in regulatory

action, legal liability and damage to our reputatio n.

Personal safety

Inability to provide safe environments for our work force and the public could

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

and damage to our reputation.

Environmental

If we do not apply our resources to overcome the pe rceived trade-off between

global access to energy and the protection or impro vement of the natural

environment, we could fail to live up to our aspira tions of no or minimal

damage to the environment and contributing to human progress.

Security

Security threats require continuous oversight and c ontrol. Acts of terrorism

against our plants and offices, pipelines, transpor tation 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 ma rketplace. Failure to meet

product quality standards throughout the value chai n could lead to harm to

people and the environment and loss of customers.

Drilling and production

Exploration and production require high levels of i nvestment and are subject to

natural hazards and other uncertainties, including those relating to the

physical characteristics of an oil or natural gas f ield. The cost of drilling,

completing or operating wells is often uncertain. W e may be required to curtail,

delay or cancel drilling operations because of a va riety of factors, including

unexpected drilling conditions, pressure or irregul arities in geological

formations, equipment failures or accidents, advers e 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 mat erial 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 an d 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 pr ojects over the plan period.

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

major programme designed to enhance shareholder val ue could adversely

affect our financial performance.

Digital infrastructure

The reliability and security of our digital infrast ructure 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. 

# Page 10 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm10

Performance review

Business continuity and disaster recovery

Contingency plans are required to continue or recov er operations following a

disruption or incident. Inability to restore or rep lace critical capacity to an

agreed level within an agreed timeframe would prolo ng the impact of any

disruption and could severely affect business and o perations.

Crisis management

Crisis management plans and capability are essentia l 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 t o either an external or

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

People and capability

Employee training, development and successful recru itment 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 a ctivities is highly dependent

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

transactions across many markets and currencies. Sh ortcomings or failures in

our systems, risk management methodology, internal control processes or

people could lead to disruption of our business, fi nancial 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 pro viding the following

cautionary statement. This document contains certai n forward-looking

statements with respect to the financial condition, results of operations and

businesses of BP and certain of the plans and objec tives of BP with respect to

these items. These statements may generally, but no t always, be identified by

the use of words such as ‘will’, ‘expects’, ‘is exp ected to’, ‘aims’, ‘should’,

‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘bel ieves’, ‘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 o r 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 o ther projects

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

( pages 46-59

) with regard to the plans of the group, the cost o f and provision

for future remediation programmes, taxation, liquid ity and costs for providing

pension and other post-retirement benefits; and inc luding under ‘Liquidity and

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

products, refining volumes and margins and impact o n the petrochemicals

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

operations, and focus on cost efficiency, cost defl ation, capital expenditure,

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

working capital, guarantees, expected payments unde r contractual and

commercial commitments and purchase obligations; ar e all forward-looking in

nature. By their nature, forward

- looking statements involve risk and uncertainty

because they relate to events and depend on circums tances 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 t iming 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; cha nges in laws and

governmental regulations; exchange rate fluctuation s; development and use of

new technology; the success or otherwise of partner ing; the actions of

competitors; natural disasters and adverse weather conditions; changes in

public expectations and other changes to business c onditions; wars and acts

of terrorism or sabotage; and other factors discuss ed elsewhere in this report

including under ‘Risk factors’ on pages 8-10. In ad dition to factors set forth

elsewhere in this report, those set out above are i mportant factors, although

not exhaustive, that may cause actual results and d evelopments to differ

materially from those expressed or implied by these forward-looking

statements.



# Statements regarding competitive

position

Statements referring to BP’s competitive position a re based on the company’s

belief and, in some cases, rely on a range of sourc es, including investment

analysts’ reports, independent market studies and B P’s internal assessments

of market share based on publicly available informa tion about the financial

results and performance of market participants. 

# Page 11 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm11

Performance review



# Information on the company

General

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

assets and operations of the company and its subsid iaries that were

consolidated at the date or for the periods indicat ed, including minority

interests. Also, unless otherwise indicated, figure s 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 t he basis of market

capitalization and proved reserves. Our worldwide h eadquarters 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 Pa rk 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 o r associates established in,

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

interests and activities covered two business segme nts in 2008: Exploration

and Production and Refining and Marketing. With eff ect 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 a nd future growth options

outside oil and gas.

Exploration and Production’s activities include oil and natural gas exploration,

development and production (upstream activities), t ogether with related

pipeline, transportation and processing activities (midstream activities), as well

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

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

refining, manufacturing, supply and trading, market ing and transportation of

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

group provides high-quality technological support f or all its businesses through

its research and engineering activities.

All these activities are supported by a n umber of other organizational

elements comprising group functions and regions. Gr oup functions serve the

business segments, aiming to achieve coherence acro ss the group, manage

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

head provides the required integration and co-ordin ation 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 Commi ssion) in the US. The

system of internal control is the complete set of m anagement 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 addres ses 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 describ es strategic risks and

opportunities that arise from making such assumptio ns and the actions to be

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

executive responsibility for developing BP’s strate gy 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 prosp ectively affecting BP’s

performance

During 2008, we continued to pursue our t hree strategic priorities of

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

Through this, we have taken steps to rest ore revenues, reduce

complexity and manage costs and have made significa nt 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-q uality 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 b e 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 i nvestment is intended to be

focused on strengthening our position further by se curing new access and

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

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

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

increased emphasis on technology as a source of pro ductivity, access and

competitive advantage.

In Refining and Marketing, we expect to c ontinue building our business

around advantaged assets in material and significan t energy markets. We

intend to continue investing in improving the safet y and reliability of our

operations. Additionally, we intend to drive furthe r operational performance

and productivity by investing in the upgrade of man ufacturing capabilities

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

international businesses, including lubricants and petrochemicals, where we

believe there is the potential to deliver strong re turns.

In Alternative Energy, we are focusing ou r 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 w ind, solar, biofuels and

carbon capture and storage.

We are dependent on our people and techno logy to deliver on our

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

capability and experience to meet all of our object ives and the technology to

support the delivery of competitive business perfor mance and new business

development. BP is committed to delivering its stra tegy 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 Afric a. Currently, around 67% of

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

Development (OECD) countries, with around 41% of ou r 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 int erests in 29 countries.

Exploration and Production activities are managed t hrough operating units

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

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

areas of major development include the deepwater Gu lf of Mexico,

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

have competitive advantage and the foundation for v olume growth and

improved margins in the future. We also have signif icant midstream activities

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

power and NGLs marketing and trading activity and L NG activity, which are

focused on identifying and capturing worldwide oppo rtunities for our

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

in North America. 

# Page 12 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm12

Performance review

Through non-US subsidiaries or other non-US entitie s, during the period

covered by this report, BP conducted limited market ing, licensing and trading

activities in, or with persons from, certain countr ies 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 fi elds and a pipeline located

outside Iran in which the National Iranian Oil Comp any (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 Euro pe and a small portion is used

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

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

of lubricants for sale to domestic consumers throug h 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 a nd gas projects in Iran, is

not conducting any technical studies in Iran and do es not own or operate any

refineries or chemicals plants in Iran.

BP sells small quantities of lubricants in Cub a 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 c rude oil into Syria. These

sales and purchases are insignificant and BP does n ot 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-OE CD 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 t o 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 marke t. There is also a clear

need for greater energy diversity to address the co mpeting challenges of

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

energy industry also faces a shortage of profession als such as petroleum

engineers and scientists. • In Refining and Marketing, we have a strong presenc e 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 bra nd on the west coast,

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

supply and trading activity responsible for deliver ing value across the crude

and oil products supply chain. Our Aromatics & Acet yls business maintains a

manufacturing position globally, with emphasis on g rowth in Asia. We also

have, or are growing, businesses elsewhere in the w orld under the BP and

Castrol brands, including a strong global lubricant s portfolio and other

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

the mobility sectors. We continue to seek opportuni ties to broaden our

activities in growth markets such as China and Indi a. Acquisitions and disposals

There were no significant acquisitions in 2006, 200 7 or 2008.

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

asset purchases from Chesapeake Energy Corporation as described on page

47.

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

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

minority shareholding in Nerefco, its 31% sharehold ing 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 loc al pipelines linking the

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

included $1,903 million from the sale of the Coryto n 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 capi tal 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 s ale of our producing

properties on the Outer Continental Shelf of the Gu lf of Mexico to Apache

Corporation.

Resegmentation in 2008

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

structure by reducing the number of business segmen ts.

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

Production and Refining and Marketing. A separate b usiness, Alternative

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

outside oil and gas and reports under Other busines ses and corporate.

As a result, and with effect from 1 Janua ry 2008:

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

separately.

• The NGLs, LNG and gas and power marketing and tradi ng businesses were

transferred from the Gas, Power and Renewables segm ent to the

Exploration and Production segment.

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

Renewables segment to Other businesses and corporat e.

• The Emerging Consumers Marketing Unit was transferr ed 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 busi nesses and corporate).

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

businesses and corporate. 

# Page 13 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm13

Performance review



# Exploration and Production

Our Exploration and Production segment includes ups tream and midstream

activities in 29 countries, including Angola, Azerb aijan, Canada, Egypt,

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

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

marketing and trading activities, primarily in Cana da, Europe, the UK and the

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

development and production. Our exploration program me 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 2 1 countries. The principal

areas of production are Angola, Asia Pacific, Azerb aijan, Egypt, Latin America,

the Middle East, Russia, Trinidad, the UK and the U S.

Midstream activities involve the ownershi p and management of crude oil

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

processing facilities and transportation, and our N GL extraction businesses in

the US and UK. Our most significant midstream pipel ine 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 locate d in Trinidad, Indonesia

and Australia. BP is also investing in the LNG busi ness in Angola.

Additionally, our activities include the marketing and trading of natural

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

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

generate margins and fees associated with the provi sion 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-f ield 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 Russi a, 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 b illion, an increase of 37%

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

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

In 2008, nine major projects came onstrea m. Production commenced at

the Thunder Horse field, with four wells in operati on 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 o ur Deepwater Gunashli

platform in the Azerbaijan sector of the Caspian Se a. Other significant

successes included the start of oil and gas product ion at the Saqqara and

Taurt fields in Egypt. Production from our establis hed 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 apply ing new technology. In terms of the continued renewal of our oil and na tural gas resource base,

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

Total capital expenditure including acqui sitions in 2008 was $22.2 billion

(2007 $14.2 billion and 2006 $13.3 billion). In 200 8, there were no significant

acquisitions. Capital expenditure included $2.8 bil lion 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 Faye tteville Shale assets,

enabling further growth of our North American gas b usiness.

There were no significant acquisitions in 2006 and 2007. Capital

expenditure in 2006 included our investment of $1 b illion 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 operationa l 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 i n a range of external

conditions.

Comparative information presented in the table on the following page

has been restated, where appropriate, to reflect th e resegmentation, following

transfers of certain businesses between segments, t hat was effective from 1

January 2008. See page 12 for more details. 

# Page 14 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm14

Performance review

Key statistics

Total revenues are analysed in more detail below. $ million

2008 2007 2006

Total revenues a 89,902 69,376 71,868

Profit before interest and tax from continuing

operations b 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 realizations c 95.43 69.98 61.91

Average BP NGL realizations c 52.30 46.20 37.17

Average BP liquids realizations c 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 realizations c 6.00 4.53 4.72

Average BP US natural gas 6.77 5.43 5.74

realizations c

$ per million British thermal units

Average Henry Hub gas price e 9.04 6.86 7.24

pence per therm

Average UK National Balancing Point gas price 58.12 29.95 42.19

a Includes sales between businesses.

b Includes profit after interest and tax of equity

- accounted entities.

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

entities.

d Crude oil and natural gas liquids.

e Henry 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, excl uding lease acquisitions, in

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

$1,765 million in 2006. These costs include explora tion and appraisal drilling

expenditures, which are capitalized within intangib le 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 pa rticipated in 83 gross (34

net) exploration and appraisal wells in 11 countrie s. 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 $88 2 million (2007 $756 million

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

unsuccessful drilling activities in Azerbaijan ($10 5 million), Faeroes

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

others ($33 million).

In 2008, we obtained upstream rights in s everal new tracts, which

include the following:

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

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

commercial evaluations, including appraisal drillin g. 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 lett ers 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 mad e. 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 t he determination of

reserves for year-end 2008.

By their nature, there is always some ris k involved in the ultimate

development and production of reserves, including, but not limited to, final

regulatory approval, the installation of new or add itional infrastructure as well

as changes in oil and gas prices, changes in operat ing and development costs

and the continued availability of additional develo pment capital. • In the Gulf of Mexico, we were awarded 125 blocks t hrough 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 Se a.

• In India, BP acquired one block on the East Coast i n 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 Za ouatene

- 1 well in the

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

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

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

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

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

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

# Page 15 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm15

Performance review

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

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

volumes in 2008, 18% were based on estimates prepar ed 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 gr oup’s petroleum engineers

before making the assessment of volumes to be booke d by BP.

Our proved reserves are associated with b oth concessions (tax and

royalty arrangements) and agreements where the grou p is exposed to the

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

is not conferred, such as production-sharing agreem ents (PSAs). In a

concession, the consortium of which we are a part i s 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 pa rt of our entitlement is

driven by the monetary amount of costs to be recove red, price fluctuations will

have an impact on both production volumes and reser ves. Sixteen per cent of

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

we operate under PSAs are Algeria, Angola, Azerbaij an, Egypt, Indonesia and

Vietnam.

We separately disclose our share of reser ves held in equity-accounted

entities (jointly controlled entities and associate s), 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 in ventory to the non-proved

resource category. The resources move through vario us non-proved resource

sub-categories as their technical and commercial ma turity increases through

appraisal activity.

Resources in a field will only be categor ized as proved reserves when

all the criteria for attribution of proved status h ave been met, including an

internally imposed requirement for project sanction or for sanction typically

expected within six months and, for additional rese rves in existing fields, the

requirement that the reserves be included in the bu siness plan and scheduled

for development, typically within three years. Wher e, on occasion, the group

decides to book reserves where development is sched uled to commence after

three years, these reserves will be booked only whe re 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 rese rves will be categorized as

proved undeveloped (PUD). Volumes will subsequently be recategorized from

PUD to proved developed (PD) as a consequence of de velopment activity.

When part of a well’s reserves depends on a later p hase of activity, only that

portion of reserves associated with existing, avail able facilities and

infrastructure moves to PD. The first PD bookings w ill occur at the point of first

oil or gas production. Major development projects t ypically take one to four

years from the time of initial booking of PUD reser ves to the start of

production. Changes to reserves bookings may be mad e due to analysis of

new or existing data concerning production, reservo ir performance,

commercial factors, acquisition and divestment acti vity and additional reservoir

development activity.

Governance

BP’s centrally controlled process for proved reserv es estimation approval

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

the following elements:

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

and approval of proved reserves bookings independen t of the operating

business and that there are effective controls in t he 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 sev eral indicators by which the

performance of the Exploration and Production segme nt is assessed by the

remuneration committee for the purposes of determin ing compensation

bonuses for the executive directors. Other indicato rs 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 indi vidual performance

contracts. Individual performance contracts are bas ed on agreed items from

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

gas reserves.

Reserve replacement

Total hydrocarbon proved reserves, on an oil equiva lent basis and excluding

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

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

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

acquisitions and divestments of 169mmboe, largely c omprising a number of

assets in Venezuela and the US.

Total hydrocarbon proved reserves, on an oil equivalent basis for

equity-accounted entities alone, comprised 5,585mmb oe at 31

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

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

includes a net increase from acquisitions and dives tments of 199mmboe,

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

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

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

is expressed in oil equivalent terms and includes c hanges 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 replacem ent ratio including

acquisitions and divestments.

BP estimates proved reserves for reportin g purposes in accordance with

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

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

There was a rapid and substantial decline in oil pr ices 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 econ omic conditions will

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

activities that would be undertaken were year-end p rices and costs to persist. • Capital allocation processes, whereby delegated aut hority 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 en sure that both technical

and commercial criteria are met prior to the commit ment of capital to

projects.

• Internal Audit, whose role includes systematically examining the

effectiveness of the group’s financial controls des igned to assure the

reliability of reporting and safeguarding of assets and examining the group’s

compliance with laws, regulations and internal stan dards.

• Approval hierarchy, whereby proved reserves changes above certain

threshold volumes require central authorization and periodic reviews. The

frequency of review is determined according to fiel d size and ensures that

more than 80% of the BP reserves base undergoes cen tral review every two

years and more than 90% is reviewed every four year s. 

# Page 16 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm16

Performance review

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

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

1,085mmboe, principally through improved recovery f rom, and extensions to,

existing fields and discoveries of new fields. Of t he 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 remainde r are in existing

developments where they represent a mixture of prov ed 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 averag ed 2,517 thousand

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

equity-accounted entities, a decrease of 1.2% and a n 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 somewh at higher in 2009. The actual

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

spending, the efficiency of that spend (in turn dep ending 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 equity

accounted 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-place a 826 929 675

Additions to proved developed reserves, for

equity-accounted entities, including sales and

purchases of reserves-in-place a 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

a This includes some reserves that were previously classified as proved undeveloped. Estimated net proved reserves of liquids at 31 Dece mber 2008 a b c

Estimated net proved reserves of natural gas at 31 December 2008 a 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 2,990 d

Rest of Americas 58 56 114 e

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 4,688 f

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 11,877 g

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 5,203 h

mmboe

Developed Undeveloped Total

Group 6,249 6,313 12,562

Equity

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

a Proved reserves exclude royalties due to others, whether pay able in cash or in kind, where the royalty

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

sales arrangements independently, and include minority i nterests in consolidated operations. We

disclose our share of reserves held in joint ventures and a ssociates that are accounted for by the equity

method although we do not control these entities or th e assets held by such entities.

b In certain deepwater fields, such as fields in the Gulf of Mexico, BP has claimed proved reserves before

production flow tests are conducted, in part because of t he significant safety, cost and environmental

implications of conducting these tests. The industry has ma de substantial technological improvements

in understanding, measuring and delineating reservoir p roperties without the need for flow tests. The

general method of reserves assessment to determine reason able certainty of commercial recovery

which BP employs relies on the integration of three type s of data: (1) well data used to assess the local

characteristics and conditions of reservoirs and fluids; (2) f ield scale seismic data to allow the

interpolation and extrapolation of these characteristi cs outside the immediate area of the local well

control; and (3) data from relevant analogous fields. W ell 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, w ireline 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 volu me 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 expect ed to begin production in 2009. Six other fields

are in the early stages of appraisal and development.

c The 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).

d Proved 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 th e field under the terms of the BP Prudhoe Bay

Royalty Trust.

e Includes 21 million barrels of crude oil in respect of th e 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.

g Includes 3,108 billion cubic feet of natural gas in re spect of the 30% minority interest in BP Trinidad and

Tobago LLC.

h Includes 131 billion cubic feet of natural gas in respect of the 5.92% minority interest in TNK

- BP. 

# Page 17 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmThe 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 Bay b 26.4 72 74 71

Kuparuk Various 48 52 57

Northstar b 98.6 22 28 38

Milne Point b Various 27 28 31

Other Various 28 27 27

Total Alaska 197 209 224

Lower 48 onshore c Various Various 97 108 125

Gulf of Mexico deepwater c Na Kika b Various 29 32 41

Thunder Horse b 75.0 24

– – Horn Mountain b 100.0 18 18 23

King b 100.0 23 22 28

Mars 28.5 28 30 19

Mad Dog b 60.5 31 25 17

Atlantis b 56.0 42 2

– Other Various 49 67 70

Total Gulf of Mexico 244 196 198

Total US 538 513 547

UK offshore c ETAP d Various 27 32 49

Foinaven b Various 26 37 37

Magnus b 85.0 18 16 30

Schiehallion/Loyal b Various 18 20 26

Clair b 28.6 13 9 7

Harding b 70.0 11 14 17

Andrew b 62.8 7 8 7

Other Various 37 50 62

Total UK offshore 157 186 235

Onshore Wytch Farm b 67.8 16 15 18

Total UK 173 201 253

Netherlands c Various Various

– – 1

Norway Valhall b 28.1 14 17 21

Draugen 18.4 13 14 15

Ula b 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 Plutonio b 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-Gunashli b 34.1 97 200 145

Shah Deniz b 25.5 8 5

– Canada c Various b Various 9 8 8

Colombia Various b Various 24 28 34

Egypt Various Various 57 43 42

Trinidad & Tobago Various b 100.0 37 30 40

Venezuela c Various Various 4 16 26

Other c Various Various 42 35 28

Total Rest of World 509 539 490

Total group e 1,263 1,304 1,351

Equity-accounted entities (BP share)

Abu Dhabi f Various Various 210 192 163

Argentina – Pan American Energy Various Various 70 69 69

Russia

– TNK

- BP c Various Various 826 832 876

Other c Various Various 32 17 16

Total equity

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

a Production excludes royalties due to others whether pa yable in cash or in kind where the royalty owner has a dir ect interest in the underlying production and the opti on and ability to make lifting and sales arrangements

independently.

b BP

- operated.

c In 2008, BP concluded the migration of the Cerro Negr o operations to an incorporated joint venture with PDV SA while retaining its equity position and TNK-BP dispo sed of some non- core interests. In 2007, BP divested

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

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

Venezuela were reduced following a decision by the Venezu elan government. TNK-BP disposed of its non-core interest s in the Udmurtneft assets.

d Volumes relate to six BP

- operated fields within ETAP. BP has no interests in th e remaining three ETAP fields, which are operated by S hell.

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

f The BP group holds interests, through associates, in onsh ore and offshore concessions in Abu Dhabi, expiring in 201 4 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 re serves there gross of production taxes. 

# Page 18 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Page 19 of 199

20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmNatural gas

18 Performance review

% million cubic feet per day

BP net share of production a

Field or Area Interest 2008 2007 2006

Lower 48 onshore b San Juan c Various 682 694 765

Arkoma c Various 240 204 225

Hugoton c Various 91 123 137

Tuscaloosa c Various 65 78 86

Wamsutter c 66.6 136 120 113

Jonah c Various 221 173 133

Other Various 451 458 461

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

Gulf of Mexico deepwater b Na Kika c 51.9 62 50 97

Marlin c 78.2 46 13 16

Other Various 122 205 210

Gulf of Mexico Shelf b 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 offshore b Braes Various 75 69 101

Bruce c 37.0 65 72 107

West Sole c 100.0 51 55 56

Marnock c 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

Netherlands b 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

Canada b Various c Various 245 255 282

China Yacheng c 34.3 91 85 102

Egypt Ha'py c 50.0 94 108 99

Other Various 278 206 172

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

Other c 46.0 98 81 80

Sharjah Sajaa c 40.0 65 83 111

Other 40.0 8 9 9

Azerbaijan Shah Deniz c 25.5 143 73

– Trinidad & Tobago Kapok c 100.0 619 984 946

Mahogany c 100.0 323 454 321

Amherstia c 100.0 288 155 176

Parang c 100.0

– – 120

Immortelle c 100.0 136 153 219

Cassia c 100.0 5 25 30

Other c 100.0 1,075 663 453

Other b Various Various 421 466 441

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

Total group d 7,277 7,222 7,412

Equity-accounted entities (BP share)

Argentina – Pan American Energy Various Various 385 379 362

Russia – TNK-BP b Various Various 564 451 544

Other b Various Various 108 91 99

Total equity

- accounted entities d 1,057 921 1,005

a Production excludes royalties due to others whether pa yable in cash or in kind where the royalty owner has a dir ect interest in the underlying production and the opti on and ability to make lifting and sales arrangements

independently.

b In 2008, BP concluded the migration of the Cerro Negr o operations to an incorporated joint venture with PDV SA while retaining its equity position. In 2007, BP di vested its producing properties in the Netherlands and

some producing properties in the US Lower 48 and Canad a. TNK-BP disposed of its interests in several non-core p roperties. 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 fie ld in the UK. Our interests in the Boqueron, Desaroll o Zulia Occidental (DZO) and Jusepin projects in Venezuel a were reduced following a decision by the

Venezuelan government. TNK

- BP disposed of its non

- core interests in the Udmurtneft assets.

c BP-operated.

d Natural gas production volumes exclude gas consumed in ope rations within the lease boundaries of the producing fi eld, but the related reserves are included in the group ’ s reserves. 

# Page 20 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm19

Performance review

United States

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

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

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

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

natural reservoir decline and the impact of hurrica nes 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. Thes e facilities are located in

major production areas across North America, includ ing Alberta, Canada, the

US Rockies, the San Juan basin and the Gulf of Mexi co. 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 par tly offset by production

from shale acquisitions.

Development expenditure in the US (exclud ing 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 va rious development projects

in progress.

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

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

2008 within each of these are indicated below.

Deepwater Gulf of Mexico

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

deepwater Gulf of Mexico liquids production was 244 mb/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 sem i-submersible production

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

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

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

200,000boe/d (gross) at the year-end, signalling th e 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 Mississi ppi 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 result ed in most of the Gulf

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

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

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

production impact of both hurricanes was a reductio n 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 stradd les 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. Liqu ids production was

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

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

In 2008, we drilled approximately 540 wel ls 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 fie lds, partially offset by

continued strong reservoir and well performance.

BP operates 13 North Slope oil fields (in cluding 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 busi ness strategy in Alaska are

commercializing the large undeveloped natural gas r esource within our 26.4%

interest in Prudhoe Bay and unlocking the large und eveloped heavy oil

resources within existing North Slope fields throug h the application of

advanced technology.

Significant events in 2008 were: • In the western basins (Colorado, New Mexico and Wyo ming), our assets

produced 224mboe/d in 2008.

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

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

• In August 2008, BP acquired all Chesapeake Energy C orporation ’ 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 r etained 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 bil lion comprising

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

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

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

the end of 2009. The assets include approximately 1 35,000 net acres of

leasehold.

• In September 2008, in anticipation of Hurricane Gu stav, operations and

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

(Tuscaloosa field) and East Texas Exploration and P roduction operations.

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

South Louisiana, East Texas and the Permian Basin h aving production shut

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

down while other plants suffered production impacts due to widespread

outages and disruptions in the midstream infrastruc ture. 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 F ield Development plan

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

extensive field trials conducted during the past th ree years.

• In July 2008, BP announced the commencement of deve lopment activities

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

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

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

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

horizontal wells ever drilled in the world, extendi ng 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 p roject. Drilling is expected to

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

# Page 21 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm20

Performance review

United Kingdom

We are the largest producer of oil, the second larg est 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 i n the North Sea include a

focus on in-field drilling and selected new field d evelopments. Our

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

2008, compared with $804 million in 2007 and $794 m illion 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 sol e owner of the field.

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

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

production test programme during the period from Au gust 2008 until the end

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

surface, where it was processed using temporary fie ld facilities, combined

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

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

to determine the technical and commercial feasibili ty of a large scale heavy

oil development project on the North Slope using ex isting cold and thermal

technologies.

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

targeted for replacement in response to the oil spi lls in the Prudhoe Bay field

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

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

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

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

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

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

Production Storage and Offloading vessel (FPSO).

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

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

potential development options, including a subsea d evelopment tied back to

BP’s Andrew field, are being evaluated.

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

North West Hutton platform decommissioning programm e was completed.

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

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

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

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

recycled and/or reused.

• In December 2008, BP and BG Group agreed to exchang e 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 facilitat e development activity and

investment in the UK Continental Shelf. BP agreed t o 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% i nterest in the BPoperated Whittle and Wollaston fields. BG Group agr eed 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 reta in 18% equity in Erskine).

The deal is subject to government, regulatory and p artner approvals and

completion is expected in the second quarter of 200 9. Rest of Europe

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

February 2007, we also held exploration and product ion and gas infrastructure

interests in the Netherlands. Development expenditu re (excluding midstream)

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

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

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

by natural decline. In Norway, progress continued a s 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 millio n in 2007 and

$4,522 million in 2006.

Rest of Americas

Canada

Trinidad • In Canada, our natural gas and liquids production w as 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 busin ess by means of two

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

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

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

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

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

process issued by The Department of Indian and Nort hern Affairs of Canada.

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

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

the 15 significant discovery licences that BP curre ntly holds in the Beaufort

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

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

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

with acquiring these exploration licences.

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

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

operating efficiency on the Atlantic LNG Trains com bined 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 cr ude and condensate from

the two new fields and liquid optimization activiti es.

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

liquids from offshore fields to onshore delivery po ints. 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 frequen cy (per 200,000 work

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

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

has come about through the development and implemen tation of a

comprehensive multi-year safety plan, focused on co aching safety leaders,

workforce communication, standard implementation an d continuous learning. 

# Page 22 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm21

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 l iquids production

increased by 3mb/d compared with 2007.

• In the second quarter of 2008, BP concluded the mig ration of the Cerro

Negro operations to an IJV with PDVSA while retaini ng the same equity

interest.

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

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 Cusi ana, Cupiagua and

Cupiagua South fields, with increasing new producti on 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 ga ve its official

approval for equalization of RC4 and RC5 Caribbean offshore blocks with

partners Ecopetrol and Petrobras, with the main obj ective of simplifying

partner relations and agreements. New equity intere sts resulting from this

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

operations for these two blocks were completed succ essfully. Processing

and interpretation of the data to determine potenti al 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 conduc ted through Pan American

Energy (PAE), a joint venture company in which BP h olds 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 no w producing at its

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

assets producing gas and liquids in the Argentine p rovinces of Salta,

Neuguén and Tierra del Fuego, and in Bolivia, as we ll as interests in

exploration areas, pipelines, electricity generatio n plants and other

midstream infrastructure assets, primarily in Argen tina.

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

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

exchange for material long-term investment commitme nts in exploration and

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

development. The licence expiry dates have been ext ended 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 transfe r back a majority

shareholding to the Bolivian national oil company Y acimientos Petrolíferos

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

decree requiring this transfer to be made with imme diate 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. Fro m May 2008 and into

January 2009, PAE was in discussions with the gover nment 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 p reserve the value of its

shareholding. Africa

Algeria

Angola • On 26 November 2008, the Argentine government issue d a decree creating

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

production and reserves. The detailed rules of Petr óleo PLUS were issued

on 4 December 2008. On 15 December 2008, PAE made i ts 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 Sa lah due to planned

turnaround maintenance and the impact of lower enti tlement 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 w ith the Tin

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

On 24 September 2008, BP moved into the second pros pecting 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 an d Batuque (Kizomba C,

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

and operator), more than offsetting the impact of l ower 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 developm ent is located

approximately 140 kilometres off the coast of Angol a 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 t o comprise four fields

that lie in the north east sector of Block 31 (BP 2 6.67% and operator), in a

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

of Luanda. Contracts have been awarded and construc tion work started

during 2008.

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

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

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

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

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

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

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

approximately 2,000 metres, some 386 kilometres nor th-west of Luanda.

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

some 390 kilometres north-west of Luanda. 

# Page 23 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm22

Performance review

Egypt

Libya

Asia Pacific

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

97mboe/d in 2007. This increase was mainly due to t he 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% an d operator). The Satis1 well was drilled in approximately 90 metres of wa ter, 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 souther n 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 fa cilitated by modern, highquality, ocean-bottom cable (OBC) seismic data.

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

The Saqqara field, operated by the Gulf of Suez Pet roleum 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 co mmenced on 26

July 2008. The Saqqara development includes a jacke t 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, onsho re 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 C oncession (BP 50% and

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

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

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

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

- kilometre pipeline and

control umbilical back to upgraded facilities at th e existing West Harbor

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

the first of a planned programme of future subsea d evelopments. Local

contractors were used for onshore design/modificati ons and subsea

structure construction.

• In Libya, BP and its partner, the Libyan Investment Corporation

(LIC) commenced seismic operations on the acreage c overed under the

exploration and production-sharing agreement ratifi ed in December 2007. In

September 2008, the offshore seismic acquisition su rvey commenced in the

Mediterranean waters of Libya’s Gulf of Sirt. At th e end of 2008, the onshore

seismic operations commenced in the northern Ghadam es 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 ann um (mtpa). In May 2008,

gas was introduced from one of the two offshore pla tforms 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 Bontan g LNG plant in

Kalimantan.

• BP participates in one of the country’s largest fo reign 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 midnigh t 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 addition al 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 e ntitlements. 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 a ctive discussions with

PVN, the Vietnamese government and joint venture pa rtners to progress this

withdrawal.

• In 2008, natural gas production was 91mmcf/d BP ne t, 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 be yond.

• The Yacheng offshore gas field (BP 34.3%) supplies Castle Peak Power

Company with feedgas for up to 70% of Hong Kong’s g as-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% intere st in the infrastructure

and oil reserves and an equal 15.78% interest in th e gas and condensate

reserves, with a seventh partner owning the remaini ng 5.32% of gas and

condensate reserves. The NWS venture is currently t he 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 in crease of 1% from

2007 primarily due to increased domestic gas demand in Western Australia

and the startup of NWS Train 5 and the Angel platfo rm 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 exi sting North Rankin A

(NRA) platform. On completion, NRA and NR2 platform s are expected to be

operated as a single integrated facility and to rec over low pressure gas from

the North Rankin and Perseus gas fields.

• In September 2008, a fifth LNG train was successful ly completed and

commenced production at the Karratha gas plant. Tra in 5 increases NWS

total annual production capacity from 11.9 to 16.3 million tonnes.

• The Angel platform (BP 16.67%) was successfully com missioned and started

producing gas during October 2008. Angel has a gros s production capacity

of 800 million standard cubic feet of raw gas and u p to 50,000 barrels of

condensate per day. 

# Page 24 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm23

Performance review

Russia

TNK-BP

• TNK

- BP, a joint venture between BP (50%) and Alfa Group and Access

Renova (AAR) (50%), is an integrated oil company op erating in Russia and

the Ukraine. The TNK-BP group’s major assets are he ld 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 peo ple.

• 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 oi l equivalent (including

its 49.9% equity share of Slavneft), of which 5 bil lion 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 c ontributes about

1.2mmboe/d, together with Volga Urals (Orenburg) co ntributing some

0.4mmboe/d. About 40% of total oil production is cu rrently exported as crude

oil and 20% as refined product.

• Downstream, TNK

- BP has interests in six refineries in Russia and th e Ukraine (including Ryazan and Lisichansk and Slavne ft’s Yaroslavl refinery),

with throughput of approximately 34 million tonnes per year. During 2008,

TNK-BP purchased additional retail and other downst ream assets in Russia

and the Ukraine from a number of small companies. T NK-BP supplies

approximately 1,400 branded filling stations in Rus sia 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 a mendments to the

shareholder agreement with its Russian partners in TNK-BP. The revised

agreement is aimed at improving the balance of inte rests 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 ha s been replaced by one

with four representatives each from BP and AAR, plu s 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 change s to the TNK-BP group’ s financial framework and of related party transactio ns. A number of other

matters will be decided by approval of a majority o f the board, so that the

independent directors will have the ability to deci de in the event of

disagreement between the shareholder representative s on the board. BP will

continue to nominate the chief executive, subject t o 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 German y, James Leng, former

chairman of Corus Steel and Alexander Shokhin, pres ident of the Russian

Union of Industrialists and Entrepreneurs. In addit ion, significant TNK-BP

subsidiaries will have directors appointed by BP an d 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 pot ential future sale of up to

20% of a subsidiary of TNK-BP through an initial pu blic offering (IPO) at an

appropriate future point, subject to certain condit ions and the consent of the

Russian authorities.

• In 2007, BP and TNK-BP signed heads of terms to cr eate strategic business

alliances with OAO Gazprom. Under the terms of this agreement, TNK-BP

agreed to sell to Gazprom its stake in OAO Rusia Pe troleum, the company

that owns the licence for the Kovykta gas condensat e field in East Siberia

and its interest in East Siberia Gas Company. Discu ssions to conclude this

disposal continue. Sakhalin

Other

Azerbaijan

Middle East and South Asia • BP and its Russian partner Rosneft agreed two Share holder 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% eq uity interest in its third

joint venture company at Sakhalin, Elvary Neftegaz, with Rosneft holding the

remaining 51%. During the year, each of the three j oint ventures held

Geological and Geophysical Studies licences with th e Russian Ministry of

Natural Resources (MNR) to perform exploration seis mic and drilling

operations in these licence areas off the east coas t of Russia. To date, 3D

seismic data has been acquired in relation to all t hree licences. In the Elvary

Neftegaz licence additional commitment 2D seismic d ata was acquired

during 2008 in preparation for future drilling comm itments. Exploration wells

have been drilled in the Zapad-Shmidt Neftegaz and Elvary Neftegaz

licences. In 2008, it was agreed by both shareholde rs 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 decre ase of 40% from 2007. The primary elements of this were the effects of

significantly higher prices resulting in a change i n profit oil entitlement in line

with the terms of the PSA and reduced cost oil enti tlement, partially offset by

an increase following the start-up of the Deepwater Gunashli (DWG)

platform, the ramping up of three Azeri oil-produci ng platforms and the Shah

Deniz condensate gas platform commencing production in 2007.

• The DWG platform complex successfully started oil p roduction on schedule

on 20 April 2008. DWG completes the third phase of development of the

Azeri-Chirag-Gunashli (ACG) field (BP 34.1% and ope rator) in the

Azerbaijan sector of the Caspian Sea. The DWG compl ex is located in a

water depth of 175 metres on the east side of the G unashli field. The

complex comprises two platforms – a drilling and pr oduction platform linked

by a bridge to a water injection and gas compressio n platform.

• On 17 September 2008, a subsurface gas release occu rred below the

Central Azeri platform. As a precautionary measure, all personnel on the

platform were safely transferred onshore. The Centr al Azeri platform was

shut down until 19 December 2008, when following co mprehensive

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 nor mal operations on 9

October 2008. Operations of the Compressor and Wate r 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 ha ve 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 i mplemented in the fourth

quarter of 2008.

• In July 2008, BP Sharjah signed a farm-out agreeme nt with RAK Petroleum

for the East Sajaa concession. Drilling of the firs t exploration well is expected

in 2009.

• In Block 61 in Oman, the challenges posed by the wo rld ’ s largest onshore

azimuth 3D seismic survey led the BP Oman team to u se a ground-breaking

new technique known as Distance Separated Simultane ous Sweeping

(DS3). This technique allows the acquisition 

# Page 25 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm24

Performance review

Midstream activities

Oil and natural gas transportation

The group has direct or indirect interests in certa in crude oil transportation

systems, the principal ones being the Trans- Alaska Pipeline System (TAPS) in

the US, the Forties Pipelines System (FPS) in the U K 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 t he North Sea, the Western

Export Route Pipeline between Azerbaijan and the Bl ack Sea coast of Georgia

(as operator of AIOC), and, as technical operator, the South Caucasus

Pipeline (SCP) (BP 25.5%), which takes gas from Aze rbaijan through Georgia

to the Turkish border.

BP’s onshore US crude oil and product pip elines and related

transportation assets are included under Refining a nd Marketing ( see page

27).

Assets and activity during 2008 included:

Alaska in a single day of as much seismic data as previous ly obtained in a week.

The invention of DS3 along with some other innovati ons allowed an efficient

and cost effective survey of the Block to be comple ted within a six-month

period. The first appraisal well was spudded in Sep tember 2008.

• In Pakistan, BP ’ s net oil production in 2008 was 8.2mboe/d, an incr ease of

30% from 2007, and BP’s net gas production was 28.2 mboe/d, an increase

of 34% from 2007 as a result of the full-year impac t 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 re spect of the offshore Indus

PSA.

• On 30 December 2008, BP signed completion documents with Orient

Petroleum International Inc., to acquire a 51.3% wo rking interest, along with

operatorship, in two joint venture blocks, Mirpurkh as and Khipro, located in

the southern Sindh province of Pakistan.

• On 22 December 2008, BP signed a production-sharin g contract with the

Indian government for a deepwater exploration blockin the KrishnaGodavari Basin, offshore eastern India, which was a warded under the New

Exploration Licensing Policy Seventh round. BP is t he 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 Alas ka North Slope fields

averaged 700mb/d during 2008.

• Work on the strategic reconfiguration project to up grade and automate four

TAPS pump stations continued to progress in 2008. T his project is installing

electrically-driven pumps at four critical pump sta tions, 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 th e formation of a joint

venture company called Denali – The Alaska Gas Pipe line. The joint venture

has begun work on an Alaska gas pipeline project co nsisting of a gas

treatment plant on Alaska’s North Slope, a large-di ameter pipeline that is

intended to pass through Alaska into Canada, and sh ould it be required, a

large-diameter pipeline from Alberta to the Lower 4 8 United States. When

completed, the pipeline is expected to move approxi mately 4 billion cubic

feet of natural gas per day to market. The joint ve nture plans to spend up to

$600 million prior to reaching the first major proj ect 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, lon g

- term transportation

commitments to the project. Should the open season be successful, the joint

venture will seek certification from the Federal En ergy Regulatory

Commission (FERC) of the US and the National Energy Board (NEB) of

Canada to move forward with project construction. T he new joint venture

company will manage the project, and will own and o perate 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 offi ce of the Governor of

Alaska announced that it would be supporting an alt ernative gas pipeline

project proposed by TransCanada Alaska Company in r esponse to the State

of Alaska’s request for bids under the Alaska Gas I nducement Act (AGIA) in

2007. BP’s commitment to move forward with the Dena li project is

independent of any decisions made or inducement off ered by the State

under the AGIA process and BP believes that the Den ali project offers the

best opportunity for a successful Alaska gas pipeli ne project.

• Alaska state courts issued two noteworthy rulings i n 2008, related to

challenges filed by in-state refiners against BP an d the other TAPS carriers,

regarding intrastate tariffs charged for shipping o il through TAPS during the

period from 1997 through 2003. These rulings are re lated to long-standing

challenges that were originally filed with the Regu latory Commission of

Alaska (RCA). In 2002, the RCA issued Order 151, wh ich determined that

TAPS transportation rates charged from the beginnin g 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 Alas ka court system. In the

interim, the RCA issued Order 34, which imposed int rastate tariff rates

consistent with Order 151, effective from 1 July 20 03 forward. On 15

February 2008, the Alaska Supreme Court affirmed th e determination in

RCA's Order 151, and on 26 February 2008, the Alask a Superior Court

affirmed the RCA's Order 34, and imposed the applic ation of Order 151 to

intrastate tariff rates charged from 2001 forward. BP and the other TAPS

carriers decided not to appeal these matters any fu rther in the courts, and on

25 March 2008, BP Pipelines Alaska paid refunds to intrastate shippers

totalling $71 million covering the period 1997 thro ugh 2000. During the third

quarter of 2008, BP Pipelines Alaska paid out an ad ditional $75 million to

intrastate shippers covering the period from 2001 t hrough 30 June 2003. In

2008, intrastate transport made up approximately 13 .7% of total TAPS

throughput.

• Tariffs for interstate transportation of oil throu gh 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). Si nce then, Anadarko,

Tesoro, and the State of Alaska have challenged the interstate tariffs

charged by BP and the other TAPS carriers in the ye ars 2005, 2006 and

2007 with the FERC. Anadarko and the State of Alask a have also

challenged the 2008 tariffs. In 2006, the FERC cons olidated the proceedings

related to the years 2005-2006, and determined that the challenges

pertaining to 2007 tariff rates would be held in ab eyance until a decision was

issued in the proceedings on 2005 and 2006 tariff r ates. The FERC’s

hearings on the consolidated proceedings commenced in October 2006 and

concluded in January 2007. On 17 May 2007, a FERC A dministrative Law

Judge (ALJ) issued an initial decision on 2005 and 2006 tariff rates that was

adverse to BP and the other TAPS carriers, and esta blished 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 Nov ember 2008, the FERC

affirmed its 20 June 2008 ruling in response to app lications for rehearing

filed by BP and the other TAPS carriers. Accordingl y, in December 2008 BP

as 

# Page 26 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm25

Performance review

North Sea

Asia (including the former Soviet Union) a TAPS carrier paid third party shippers tariff ref unds of $52 million; and BP

as a TAPS shipper received tariff refunds from thir d party carriers of

$27 million. The FERC’s 20 November 2008 ruling als o concluded that a

unified tariff rate should be established for inter state transportation through

TAPS, and the TAPS carriers were ordered to impleme nt a revenue pooling

methodology in the TAPS Operating Agreement. Some T APS carriers other

than BP have filed legal challenges to this aspect of the FERC’s 20

November 2008 ruling, which are still pending. As o f 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, inte rstate transport made up

approximately 86% of total TAPS throughput.

• FPS (BP 100%) is an integrated oil and NGLs transpo rtation and processing

system that handles production from more than 50 fi elds in the Central North

Sea. The system has a capacity of more than one mil lion 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 Nor th 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 tran sportation and

processing services. In 2008, throughput was 836mmc f/d (gross),

247mmcf/d (net).

• BP operates the Dimlington/Easington gas processin g terminal (BP 100%)

on Humberside and the Sullom Voe oil and gas termin al 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 th e BP-operated ACG oil

field in the Caspian Sea to the eastern Mediterrane an port of Ceyhan. The

Turkish section of the pipeline is operated by Bota s.

• On 6 August 2008, the Baku-Tbilisi-Ceyhan (BTC) pi peline 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 pipeli ne restarted on 20

August 2008. The Azeri-Chirag-Gunashli (ACG) and Sh ah Deniz (SD) fields

reduced offshore production to manage stock levels at the Sangachal

Terminal. Some exports were maintained via the Nort hern Route Export

Pipeline (NREP) and by rail through Georgia.

• BP is technical operator of, and holds a 25.5% inte rest 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 do wn 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 ove r 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% inter est in Tengizchevroil

(TCO). CPC is a 1,510-kilometre pipeline from Kazak hstan to the Russian

port of Novorossiysk and carries crude oil from a n umber of Kazakh fields,

including Tengiz. In addition to our interest in Lu kArco, we hold a separate

0.87% interest in CPC through a 49% holding in Kaza khstan Pipeline

Ventures (KPV). In 2008, CPC total throughput reach ed 32.2 million tonnes.

During 2008, the majority of shareholders in CPC ag reed on the commercial

terms for expansion of CPC to 67 million tonnes. Th ese terms strongly

favour the upstream, and as BP has no additional vo lumes of Kazakh crude

to ship in an expanded CPC, BP has been unable to s upport these new

commercial terms. In order not to delay the expansi on of CPC, BP has

obtained the agreement of its KPV joint venture par tners and CPC

shareholders to dispose of its interest in KPV Liquefied natural gas

Our LNG activities are focused on building competit ively advantaged

liquefaction projects, establishing diversified mar ket positions to create

maximum value for our upstream natural gas resource s 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 p artners, CPC shareholders

and TCO partners to dispose of its interest in LukA rco.

• On 25 September 2008, Chevron announced that Tengiz chevroil had

completed a major expansion at the Tengiz field in Kazakhstan in which BP

holds a 2.3% interest through its joint venture wit h 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 yea r of LNG. All of the LNG

from Atlantic Train 1 and most of the LNG from Trai ns 2 and 3 is sold to third

parties in the US and Spain under long-term contrac ts. All of BP’s LNG

entitlement from Atlantic LNG Train 4 and some of i ts LNG entitlement from

Trains 2 and 3 is marketed via BP’s LNG marketing a nd trading business to

a variety of markets including the US, the Dominica n 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, wh ich is expected to

receive approximately one billion cubic feet of ass ociated gas per day from

offshore producing blocks and to produce 5.2 millio n tonnes gross per year

of LNG, as well as related gas liquids products. Wi th the completion of the

necessary agreements and the approval of the Angola n government, the

project investors have authorized Angola LNG Limite d to proceed with the

construction and implementation of the project.

• In Indonesia, BP is involved in two of the three L NG centres in the country.

BP participates in Indonesia’s LNG exports through its holdings in the

Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently del ivers 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 i n 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 T angguh LNG plant.

During 2008, construction continued on two LNG trai ns 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, K orea and North America.

• In Australia, we are one of seven partners in the N orth West Shelf

(NWS) venture. The joint venture operation covers o ffshore 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 pe r 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 Aus tralia’ s NWS project, the

terminal took delivery of an additional eight spot LNG cargoes during 2008,

to meet rapidly growing local demand for gas. 

# Page 27 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm26

Performance review

Gas marketing and trading activities

Gas and power marketing and trading activity is und ertaken primarily in the

US, Canada, the UK and Europe to market both BP pro duction 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 an d enhanced margins from

sources such as the management of price risk on beh alf of third-party

customers. These markets are large, liquid and vola tile.

In connection with the above activities, the group uses a range of

commodity derivative contracts and storage and tran sport contracts. These

include commodity derivatives such as futures, swap s and options to manage

price risk and forward contracts used to buy and se ll gas and power in the

marketplace. Using these contracts, in combination with rights to access

storage and transportation capacity, allows the gro up 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 f or both gas and power

transactions through bilateral and/or centrally cle ared arrangements. Futures

and options are primarily used to trade the key ind ex prices such as Henry

Hub, while swaps can be tailored to price with refe rence to specific delivery

locations where gas and power can be bought and sol d. OTC forward

contracts have evolved in both the US and UK market s, 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 i n future periods. Storage

and transportation contracts allow the group to sto re and transport gas, and

transmit power between these locations. The group h as developed a risk

governance framework to manage and oversee the fina ncial risks associated

with this trading activity, which is described in N ote 28 to the Financial

statements on pages 140-145.

The range of contracts that the group ent ers into is described below in

more detail:

Exchange-traded commodity derivatives

Exchange-traded commodity derivatives include gas a nd power futures

contracts. Though potentially settled physically, t hese contracts are typically

settled financially. Gains and losses, otherwise re ferred to as variation

margins, are settled on a daily basis with the rele vant exchange. Realized and

unrealized gains and losses on exchange-traded comm odity derivatives are

included in total revenues for accounting purposes.

OTC contracts

These contracts are typically in the form of forwar ds, swaps and options.

Some of these contracts are traded bilaterally betw een counterparties; others

may be cleared by a central clearing counterparty. These contracts can be

used for both trading and risk management activitie s. Realized and unrealized

gains and losses on OTC contracts are included in t otal revenues for

accounting purposes. Highly developed markets exist in North America and

the UK where gas and power can be bought and sold f or 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 155,000m 3 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, environmenta lly responsible marine

and shipping solutions in support of BP group activ ities.

• In both the Atlantic and Asian regions, BP is marke ting LNG using BP LNG

shipping and contractual rights to access import te rminal capacity in the

liquid markets of the US (via Cove Point and Elba I sland) 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. Certai n of these transactions are

not settled physically. This can be achieved by tra nsacting offsetting sale or

purchase contracts for the same location and delive ry period that are offset

during the scheduling of delivery or dispatch. The contracts contain standard

terms such as delivery point, pricing mechanism, se ttlement terms and

specification of the commodity. Typically, volume a nd price are the main

variable terms. Swaps can be contractual obligation s to exchange cash flows

between two parties. One usually references a float ing price and the other a

fixed price, with the net difference of the cash fl ows being settled. Options give

the holder the right, but not the obligation, to bu y or sell natural gas products

or power at a specified price on or before a specif ic future date. Amounts

under these derivative financial instruments are se ttled 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 d elivery date when title to the

inventory passes. Term contracts are contracts to p urchase or sell a

commodity at regular intervals over an agreed term. Though spot and term

contracts may have a standard form, there is no off setting mechanism in

place. These transactions result in physical delive ry with operational and price

risk. Spot and term contracts relate typically to p urchases of third-party gas

and sales of the group’s gas production to third pa rties. Spot and term sales

are included in total revenues, when title passes. Similarly, spot and term

purchases are included in purchases for accounting purposes. 

# Page 28 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm27

Performance review



# Refining and Marketing

Our Refining and Marketing business is responsible for the supply and trading,

refining, manufacturing, marketing and transportati on of crude oil, petroleum,

chemicals products and related services to wholesal e and retail customers.

BP markets its products in more than 100 countries. We operate primarily in

Europe and North America and also manufacture and m arket our products

across Australasia, in China and other parts of Asi a, Africa and Central and

South America.

In 2008 we restructured the Refining and Marketing organization into

two main business groupings: fuels value chains (FV Cs) 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 regiona lly. This shift to a more

geographic and integrated model represents a major simplification step and

the opportunity to create better value from our phy sical 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 eac h 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, physi cal asset quality,

operational efficiency, technology advantage and th e strength of our brands.

Each business has a clear strategy focused on inves ting in its key assets and

market positions in order to deliver value to its c ustomers 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 unit s 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-quali ty 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 produc t prices, which resulted in

substantial margin volatility as well as higher ene rgy 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 20 07 due to weaker gasoline

demand. Conversely, in Europe, where diesel account s 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 su bsequently 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 fo r our petrochemicals

products as a consequence of the economic slowdown. The year also saw

material swings in foreign exchange rates, particul arly in the second half, that

affected our results.

Our 2008 performance reflects the benefit s of the fundamental

improvements we are making across the business, inc luding the measures we

have taken to restore the availability of our refin ing 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 ta x of $6.1 billion in 2007.

The decrease was primarily driven by inventory-hold ing 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 Manag ement 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 U S and two of our refineries

in Europe were operating on OMS. Within our US refi neries, we continue to

implement the recommendations from the BP US Refine ries Independent

Safety Review Panel. We have worked closely with th e independent expert, L

Duane Wilson. The number of major incidents associa ted with integrity

management has decreased by 90% since 2005. We have also reduced the

number of oil spills by 60% and the recordable inju ry rate by more than 57%

since 1999. Regrettably, in 2008 there were four wo rkforce fatalities

associated with our operations, one of which was a process safety incident.

In 2008, we saw the first substantial ben efits of our operational

improvements. The Whiting refinery was restored to its full clean fuel capability

of 360mb/d in March 2008 following the compressor f ailure 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, w e commissioned new

upgrading units at the Rotterdam and Kwinana refine ries, enhanced

processing capability at the Gelsenkirchen refinery , reconfigured the Bayernoil

refinery for more efficient and competitive operati on, and completed

construction of a new coker at the Castellón refine ry. During the next five

years, we intend to continue the focus on process s afety, improve the

competitive performance of our refineries and compl ete the previously

announced investment in the Whiting refinery to inc rease its ability to process

Canadian heavy crude.

In total, our 17 refineries worldwide, in cluding 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 previ ous disposals and

acquisitions. The performance of Texas City was imp acted by Hurricane Ike in

September, which meant we had to shut down the refi nery in advance as a

precautionary measure, along with other refineries in the area. Operational

disruption was minimized as crude processing was re stored in seven days and

full operations restored within three weeks. This w as 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 refi ning, logistics, marketing, supply

and trading activities, establishing six refining-t o-marketing integrated FVCs

focused on refining and selling ground transportati on fuels in each region. This

has enabled us to simplify internal interfaces, opt imize margins, reduce

overhead costs and drive continuous improvement. Du ring the year, we

continued the implementation of our ampm convenienc e 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 l ower levels of capital

investment. In Europe, where we are one of the larg est 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 th e lubricants business we focused

on enhancing our customer relationships and brand d istinctiveness, together

with simplifying operations and improving efficienc y. 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. Dur ing 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 o rganization, improving the

efficiency of our back office and reducing our head count, including the number

of senior management positions. 

# Page 29 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm28

Performance review

Looking ahead, in 2009 the overall economic environ ment is expected to be

challenging with reduced demand for our products le ading to lower volumes

and pressure on margins. The impact is expected to be greatest in the

petrochemicals sector.

Against this background, we intend to con tinue 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 serv ices 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 investmen t to maintaining and improving

our core positions. To continue the progress we hav e made in recent years,

our top priority for spending will remain safety an d operational integrity. The

other area of focus will be delivering integrated v alue in our key markets

through investment in terminals and pipeline infras tructure. Our largest

investment is expected to be at the Whiting refiner y, where we have started a

major upgrading and modernization programme that wi ll 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 resegme ntation, 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 revenues a 320,458 250,897 232,833

Profit before interest and tax from continuing

operations b (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 Margin c 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 ave rage 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 characteris tic of the typical level of upgrading

complexity. The refining margins are industry-specific rat her than BP-specific measures, which we

believe are useful to investors in analyzing trends in th e 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 ind icator 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 maj or product group.

Marketing volumes were 3,711mb/d, slightly lower th an last year, reflecting the

impacts from the slowing of global economies and re duced 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 re gions of the US, the

Rhine region, Southern Africa, Australasia (ANZ) an d Iberia. Each of these is

a material business, optimizing activities across t he supply chain – from crude

delivery to the refineries; manufacture of high-qua lity fuels to meet market

demand; pipeline and terminal infrastructure and th e 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 in tegration with our marketing

and trading operations, as well as horizontal integ ration with other parts of the

group’s business. Refining’s focus is to maintain a nd improve its competitive

position through sustainable, safe, reliable and ef ficient operations of the

refining system and disciplined investment for inte grity management, to

achieve competitively advantaged configuration and growth.

For BP, the strategic advantage of a refi nery 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 w hile improving our competitive

position. In addition, we continue to invest to dev elop the capability to produce

the cleaner fuels that meet the requirements of our customers and their

communities. thousand barrels per day

Sales of refined products a 2008 2007 2006

Marketing sales

UK b 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 sales c 3,711 3,806 3,872

Trading/supply sales d 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 & Ace tyls products and Olefins &

Derivatives sales through equity-accounted entities.

b UK area includes the UK

- based international activities of Refining and Marketi ng.

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 an d small resellers).

d Trading/supply sales are sales to large unbranded reselle rs 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 

# Page 30 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmThe following table summarizes the BP group’s inter ests in refineries and crude distillation capacitie s at 31 December 2008.

The following table outlines by region the volume o f crude oil and feedstock processed by BP for its o wn account and for third parties. Corresponding BP refinery

capacity utilization data is summarized.

29 Performance review

thousand barrels per day

Crude distillation capacities a

Group interest b 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 Mombasa c 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.

a Crude distillation capacity is gross rated capacity, which is defined as the maximum achievable utilization of capacity (24

- hour assessment) based on standard feed.

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

c On 15 January 2008, it was announced that Essar Energy Ove rseas Ltd, a subsidiary of Essar Oil Limited, had entere d into an agreement to acquire 50% of Kenya Petroleum Refineries Ltd.

The transaction was initially expected to be finalized i n 2008, but has since been delayed in negotiations.

thousand barrels per day

Refinery throughputs a 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 December b 2,678 2,769 2,823

Crude distillation capacity utilization c 78% 72% 76%

US 72% 62% 70%

Europe 85% 84% 87%

Rest of World 83% 84% 78%

a Refinery throughputs reflect crude and other feedstock vol umes.

b Crude distillation capacity is gross rated capacity, which is defined as the maximum achievable utilization of capacity (24

- hour assessment) based on standard feed.

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

# Page 31 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm30

Performance review

Excluding portfolio impacts, underlying refining th roughputs in 2008 increased

by 5% relative to 2007, driven principally by impro ved 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 H usky joint venture (see

below). The improvement achieved in the US was lowe r 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 refiner y in September caused by

Hurricane Ike.

The increase in Rest of Europe throughput s in 2008 is primarily related

to the purchase of Chevron’s 31% interest in the Ro tterdam refinery in 2007.

The decrease in UK throughputs is due to the sale o f the Coryton refinery to

Petroplus.

Significant events in Refining were as fo llows:

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 v alue chain. Our priorities

are to operate an advantaged infrastructure and log istics network (which

includes pipelines, storage terminals and road or r ail tankers), drive excellence

in operating and transactional processes and delive r compelling customer

offers in the various markets where we operate. The fuels business markets a

comprehensive range of refined oil products primari ly focused on the ground

fuels sector.

On 29 August 2008, BP announced an agreem ent with Enbridge Inc. to

build and reconfigure a pipeline system to transpor t 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 init ial capacity of 250mb/d. The

joint investment of the phased capacity additions i s expected to be in the

range of $1-2 billion.

The ground fuels business supplies fuel a nd related convenience

services to retail consumers through company-owned and franchised retail

sites as well as other channels including wholesale rs and jobbers. It also

supplies commercial customers within the road and r ail transport sectors.

BP’ s value creation in ground fuels is obtained throug h the integration of

the value chain from the refinery gates or import h ubs across retail and

commercial channels to market. Convenience retail o ffers are focused on

delivering appealing convenience offers across the various markets in which

we operate, through the BP Connect, ampm and Aral b rands. • On 21 March 2008, the Whiting refinery in the US wa s restored to its full

clean fuel capability of 360mb/d.

• BP completed recommissioning the Texas City refiner y in the US. With the

successful return to service of Ultraformer No. 3 i n the fourth quarter, the

site’s full economic capability was restored.

• On 31 March 2008, we completed a deal with Husky En ergy Inc. to create an

integrated North American oil sands business by mea ns 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 exp anded to process

approximately 170mb/d of heavy oil and bitumen by 2 015.

• In July, a final investment decision was taken to p rogress the significant

upgrade of the Whiting refinery. This project repos itions Whiting

competitively by increasing its Canadian heavy crud e processing capability

by 260mb/d and modernizing it with equipment of sig nificant size and scale.

• On 17 March 2008, BP and Irving Oil entered into a memorandum of

understanding to work together on evaluating the fe asibility of the proposed

Eider Rock refinery in Saint John, New Brunswick, C anada. Our retail network is largely concentrated in Europ e 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 C hemical Corporation

(Sinopec).

At 31 December 2008, BP’s worldwide network consist ed of some 22,600

locations branded BP, Amoco, ARCO and Aral, around the same as in the

previous year. We continue to improve the efficienc y 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 und er the BP brand. We also

divested an additional 160 company-owned sites to t hird 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 agreemen t. In November 2007,

BP announced that it would sell all of its company- owned and companyoperated convenience sites in the US. Despite the c hallenges 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-bra nded fuels in the eastern

US and ARCO- branded fuels in the western US. The franchise agre ement has

a term of 20 years and requires sites to be supplie d with BP- or ARCObranded fuels for the term of the contract.

At the end of 2008, our European retail n etwork consisted of

approximately 8,600 sites and we had approximately 2,300 sites in the Rest of

World.

Our retail convenience operations offer c onsumers a range of food,

drink and other consumables and services on the fue l forecourt in a safe,

convenient and innovative manner. With operations i n 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-ou t 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 i n Germany and the Wild Bean

Café brand in other European locations has re-energ ized consumers’

convenience shopping choices. In the US, BP has emb arked on a roll-out of

its successful ampm brand across all targeted natio nal markets as its single

convenience flagship; this programme roll-out is in tended to be completed by

the end of 2009. Number of retail sites operated under a BP brand

Retail sites a 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

a Changes in the number of retail sites over time are aff ected by, among other things, dealer/jobber

owned sites that move to or from the BP brand as their fuel supply agreements expire and are

renegotiated in the normal course of business.

b Excludes our interest in equity

- accounted entities. Comparative information has been ame nded to this

basis. 

# Page 32 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm31

Performance review

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 ma intain a presence in the

regionally connected global markets.

The function seeks to identify the best m arkets and prices for our crude

oil, source optimal feedstocks for our refineries a nd provide competitive supply

for our marketing businesses. In addition, where re finery production is surplus

to marketing requirements or can be sourced more co mpetitively, 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 i ts own crude production into

the market and purchase alternative crude for its r efineries where this will

provide incremental margin.

In addition to the supply activity descri bed above, the function seeks to

create incremental trading opportunities. It enters into the full range of

exchange-traded commodity derivatives, over-the-cou nter (OTC) contracts

and spot and term contracts that are described in d etail below. In order to

facilitate the generation of trading margin from ar bitrage, 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 thi s 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 future s and options traded on a

recognized exchange, such as Nymex, SGX, ICE and Ch icago Board of

Trade. Such contracts are traded in standard specif ications for the main

marker crude oils, such as Brent and West Texas Int ermediate, 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 u nrealized gains and losses

on exchange-traded commodity derivatives are includ ed in total revenues for

accounting purposes.

OTC contracts

These contracts are typically in the form of forwar ds, swaps and options.

Some of these contracts are traded bilaterally betw een counterparties; others

may be cleared by a central clearing counterparty. These contracts can be

used both as part of trading and risk management ac tivities. Realized and

unrealized gains and losses on OTC contracts are in cluded in total revenues

for accounting purposes.

The main grades of crude oil bought and s old forward using standard

contracts are West Texas Intermediate and a standar d North Sea crude blend

(Brent, Forties and Osberg or BFO). Although the co ntracts specify physical

delivery terms for each crude blend, a significant volume are not settled

physically. The contracts typically contain standar d delivery, pricing and

settlement terms. Additionally, the BFO contract sp ecifies a standard volume

and tolerance given that the physically settled tra nsactions are delivered by

cargo. Swaps are often contractual obligations to exchange cash flows between two

parties: a typical swap transaction usually referen ces a floating price and a

fixed price with the net difference of the cash flo ws being settled. Options give

the holder the right, but not the obligation, to bu y 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 exp iry, typically through netting

agreements, to limit credit exposure and support li quidity.

Spot and term contracts

Spot contracts are contracts to purchase or sell cr ude 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 off setting mechanism in

place. These transactions result in physical delive ry with operational and price

risk. Spot and term contracts relate typically to p urchases of crude for a

refinery, purchases of products for marketing, sale s of the group’s oil

production and sales of the group’s oil products. F or 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 cust omers in more than 100

countries worldwide with a significant focus on Eur ope, North America and

Asia. Our products include aviation and marine fuel s, lubricants that meet the

needs of various industries and consumers, LPG, and a range of

petrochemicals that are sold for use in the manufac ture of other products such

as fabrics, fibres and various plastics.

Lubricants

We manufacture and market lubricants and related pr oducts and services to

the automotive, industrial, marine and energy marke ts across the world.

Following a decision to simplify and focus our chan nels of trade, we now sell

products direct to our customers in around 50 count ries and use approved

local distributors for the remaining locations. Cus tomer focus, distinctive

brands, superior technology and relationships remai n the cornerstones of our

long-term strategy.

BP markets primarily through its major br ands 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 be lieve it provides us with

a significant competitive advantage. In the automot ive lubricants sector, we

supply lubricants and other related products and se rvices to intermediate

customers such as retailers and workshops. These, i n turn, serve endconsumers such as car, truck and motorcycle owners in the mature markets of

Western Europe and North America as well as the mar kets of Russia, China,

India, the Middle East, South America and Africa, w hich we believe have the

potential for significant long-term growth.

BP’s marine lubricants business is a glob al market leader, supplying

many types of vessels from deep-sea fleets to marin e leisure-craft from

around 1,200 ports across the globe. BP’s industria l lubricants business is a

leading supplier to those sectors of the market inv olved in the manufacture of

automobiles, trucks, machinery components and steel . BP is also a leading

supplier of lubricants for the offshore oil and avi ation industries. 

# Page 33 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm32

Performance review

Petrochemicals

Our petrochemicals operations are comprised of the global Aromatics &

Acetyls businesses (A&A) and the Olefins & Derivati ves (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 m ain product lines: purified

terephthalic acid (PTA), paraxylene (PX) and acetic acid. Our A&A strategy is

to leverage our industry-leading technology in sele cted 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, texti les and film, and PET

bottles. Acetic acid is a versatile intermediate ch emical 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 s hare 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 propy lene from naphtha and also

produce a number of downstream derivative products.

Our O&D business has operations in both C hina and Malaysia. In

China, our SECCO joint venture between BP, Sinopec and its subsidiary,

Shanghai Petrochemical Company is the largest forei gn-invested olefins

cracker in China. SECCO is BP’s single largest inve stment in China. This

naphtha cracker produces ethylene and propylene plu s 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 Po lyethylene 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 Gelsenki rchen refinery in Germany.

The following table shows BP’s petrochemi cals 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 petrochem icals businesses operate

became more challenging as deterioration in the glo bal 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 follow s:

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 a s the general aviation and

military sectors. During 2008, which was a tough ye ar 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 re lationships with many of the

world ’s major commercial airlines. Air BP’s strategic ai m is to grow its position

in the core locations of Europe, the US, Australasi a and the Middle East, while

focusing its portfolio towards airports that offer long-term competitive

advantage. BP’s marine fuels business focuses on th e distribution and sale of

refined fuel oils to the shipping industry at locat ions in more than 100 ports

across the world. During 2008, this business perfor med well, supported by

strong growth in the shipping market.

LPG

The LPG business sells bulk, bottled, automotive an d wholesale LPG products

to a wide range of customers in 13 countries. Durin g the past few years, our

LPG business has consolidated its position in estab lished markets, pursued

opportunities in new and emerging markets such as C hina 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 Comp any Limited site in

Guangdong province (China) successfully completed c ommissioning in the

first quarter of 2008. This 900+ ktepa plant is the single largest PTA

manufacturing train in the world and employs BP’s l atest, proprietary

technology.

• Construction continued on the new 500ktepa acetic a cid plant in Jiangsu

province (China) by BP YPC Acetyls Company (Nanjing ) Limited (BYACO).

This is a BP joint venture with Yangzi Petrochemica l Co. Ltd (a subsidiary of

Sinopec). Construction is scheduled to be completed in June 2009 with

commercial sales expected to begin in the third qua rter of 2009.

• Commissioning of our expanded Geel (Belgium) PTA fa cility commenced at

the end of 2008. The 350ktepa expansion improves ov erall 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 Riv er Acetyls Co.

(YARACO) joint venture site in Chongqing (China). T his 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 wel l over one million

tonnes per annum, making this one of the largest ac etic acid production

locations in the world. 

# Page 34 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm33

Performance review



# Other businesses and corporate

Other businesses and corporate comprizes Treasury ( which includes interest

income on the group’s cash and cash equivalents) an d 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 resegme ntation, 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 a nd the Asia Pacific region, it

provides the link between BP and the international financial markets and

makes available a range of financial services to th e group, including

supporting the financing of BP’s projects around th e world.

Insurance

The group generally restricts its purchase of insur ance to situations where this

is required for legal or contractual reasons. This is because external insurance

is not considered an economic means of financing lo sses for the group.

Losses are therefore borne as they arise, rather th an being spread over time

through insurance premiums with attendant transacti on costs. This position is

reviewed periodically.

Aluminium

Our aluminium business is a non-integrated producer and marketer of rolled

aluminium products, headquartered in Louisville, Ke ntucky, US. Production

facilities are located in Logan County, Kentucky, a nd are jointly owned with

Novelis. The primary activity of our aluminium busi ness is the supply of

aluminium coil to the beverage can business, which it manufactures primarily

from recycled aluminium. $ million

2008 2007 2006

Total revenues a 5,040 3,972 3,703

Profit (loss) before interest and tax from

continuing operations b (1,258 ) (1,233 ) (779 )

Total assets 19,079 20,595 16,315

Capital expenditure and acquisitions 1,839 939 852

a Includes sales between businesses.

b Includes 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 commitm ent to invest a total of

$8 billion over 10 years. In 2008, we prioritized f our areas with significant longterm growth potential – wind, solar, biofuels and c arbon capture and storage

(CCS). We have also developed a fifth area – gas-fi red power – that offers

synergies with other BP operations. We have concent rated our 2008

investment in these areas.

Wind

Since the launch of Alternative Energy we have subs tantially grown our wind

portfolio, increasing from 32 megawatts (MW) in ope ration to 432MW (785MW

gross) at the end of 2008. In total, we have more t han 500MW (1,000MW

gross) of installed capacity. This increase in capa city was led by the US with

installations at Cedar Creek, Silver Star, Sherbino and Edom Hills.

To accelerate our growth in the US wind e nergy market, we acquired

two fully integrated wind power development compani es – Greenlight Energy

Inc. and Orion Energy LLC, during 2006. To secure t he 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 Netherl ands and in Maharashtra,

India.

Solar

We continued to implement BP Solar’s strategy to in vest in lower cost

manufacturing and technology to enable energy sourc ed from our products to

compete with conventional electricity. Our global b usiness 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 s olar panels that are then sold

and distributed as solar systems on the roofs of re sidential homes, large

commercial buildings and on vacant land.

Today, BP Solar’s main production facilit ies are located in Maryland

(US), Madrid (Spain), Xi’ an (China) and Bangalore (India). During 2008, due to

increasingly competitive market conditions, BP Sola r announced plans to

refocus operations at larger scale plants to achiev e lower-cost manufacturing.

This resulted in the start of an intensive programm e of operational efficiency

improvement in the remaining BP Solar plants and pl ans to close our

manufacturing plant in Australia. During 2008, BP S olar signed contracts with

a select set of third-party strategic partners in A sia who specialize in the

production of low-cost, high-quality wafers, cells and modules.

During 2008, BP Solar achieved sales of 1 62MW, an increase of 41%

from 115MW in 2007. The slight decrease in solar pr oduction capacity was

due to fire damage in a section of our manufacturin g 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

a Net wind capacity is the sum of the rated capacities of t he 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 equit y-accounted entities where BP has partial

ownership) were 785MW in 2008, 373MW in 2007 and 43M W in 2006.

b Solar capacity is the theoretical cell production capacity pe r annum of in-house manufacturing facilities. 

# Page 35 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm34

Performance review

More than 70% of our sales volume is through third

- party distributors in the

residential markets in Europe, the US and Australas ia. We have continued to

roll out our Certified Installer Programme (CIP), f irst established in Germany,

to ensure the safe, high-quality installation of pr oducts 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 suppl y large corporations with

sustainable energy solutions, completing a second s olar system for FedEx

Freight in California and a further six installatio ns for Wal-Mart. In Europe, we

expanded the relationship with Banco Santander to j ointly build and finance a

number of solar plants in Spain, with the construct ion of an 8 megawatts-peak

(MWp) solar farm in Toledo and a 6MWp project in Te nerife. In Asia, we

completed the installation of a solar power demonst ration 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 comm enced operation in

February 2008, representing the first commercial so lar power installation for

the Blacktown Solar City Project. The Solar Cities Programme is a

government initiative to implement distributed sola r and other energy efficient

technologies in seven Australian cities.

We are developing a new silicon growth pr ocess named Mono 2 TM

, which will increase cell efficiency over traditiona l multicrystalline -based solar

cells. We have moved from a prototype to low-volume production and have

converted our casting stations in Frederick, Maryla nd, delivering 1.2MW

Mono 2 TM . From the trials, we are seeing significant improv ement in power and

generated kWh when compared with multicrystalline-b ased solar cells

particularly when modules are used where sunlight i s low.

BP Solar has long-term relationships with world-class universities and

invests in research programmes with organizations i ncluding the University of

Delaware, California Institute of Technology (Cal T ech) and the Fraunhofer

Institute (Germany). BP Solar was selected for the Solar America Initiative

(SAI) award from the US Department of Energy – a $4 0-million research and

development programme aimed at decreasing the cost of solar cells and

increasing their efficiency. BP Solar is also a mem ber 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 chan ge. Our investments are

focused on sustainable feedstocks that minimize pre ssure on food supplies

and on research into advanced technologies and prac tices to make good

biofuels even better.

We have embarked on a focused programme o f biofuels development

based around the most efficient transformation of s ustainable and low-cost

sugars into a range of fuel molecules. These includ e bioethanol from Brazilian

sugar cane, more efficient fuel molecules like biob utanol and advanced

biofuels like lignocellulosic bioethanol produced f rom non- food energy grasses

and ‘for-purpose’ feedstocks such as miscanthus and energy cane. BP has announced it has plans to invest i n excess of $1 billion in

building our own biofuels business operations, incl uding partnerships with

other companies to develop the technologies, feedst ocks 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 pro duce bioethanol from

sugar cane; and a $90- million investment and strategic alliance with Vere nium

Corporation to accelerate the development and comme rcialization of biofuels

produced from lignocellulosic bioethanol. We have b een working with DuPont

since 2003 to explore new approaches to the develop ment of biofuels. The

first product from this collaboration will be an ad vanced fuel molecule called

biobutanol, which has a higher energy content than ethanol. We have

partnered with ABF (British Sugar) and DuPont to co nstruct 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 Bioscience s Institute (EBI), at which

biotechnologists are investigating applications of biotechnology to energy,

including advanced fuels. This amount is incrementa l to the $1 billion of

investments mentioned above. Our partners are the U niversity of California,

Berkeley and the University of Illinois at Urbana C hampaign and the Lawrence

Berkeley National Laboratory. The EBI is focusing o n the integrated

development of better crops, better processing tech nologies and better

biofuels, leading to cleaner energy.

Hydrogen power

In May 2007, BP and Rio Tinto announced the formati on of a new jointly

owned company, Hydrogen Energy International Limite d, 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 electr icity.

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 CO 2 will be transported to nearby

oil fields for use in enhanced oil recovery, with t he CO 2 stored deep

underground. General Electric and BP have formed a global alliance to jointly

develop and deploy technology for hydrogen power pl ants that could

significantly reduce emissions of the greenhouse ga s CO 2 from electricity

generation.

Through these initiatives, BP intends to continue to shape the

development of the CCS value chain and to seek to m inimize the carbon

footprint exposure of the BP group as carbon pricin g and policy develops

globally.

Gas-fired power

Our gas-fired power activities comprise modern comb ined cycle gas turbine

plants, which emit around 50% less CO 2 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 facilitie s. The Whiting Clean Energy

facility, acquired in July 2008, now provides a rel iable source of steam for our

Whiting refinery and we are adding a 250MW steam tu rbine to our existing

plant at our Texas City refinery. Our combined cycl e plants are providing

base-load demand for BP’s major upstream gas produc tion developments. 

# Page 36 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm35

Performance review

Shipping

We transport our products across oceans, around coa stlines and along

waterways, using a combination of BP -operated, time-chartered and spotchartered vessels. All vessels conducting BP activi ties are subject to our

health, safety, security and environmental requirem ents.

International fleet

At the end of 2008, we had an international fleet o f 54 vessels (37 mediumsize crude and product carriers, four very large cr ude carriers, one North Sea

shuttle tanker, eight LNG carriers and four LPG car riers). All these ships are

double-hulled. Of the eight LNG carriers, BP manage s one on behalf of a joint

venture in which it is a participant and operates s even LNG carriers.

Regional and specialist vessels

In Alaska, during 2008, we redelivered one of our t ime- 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 speci alist vessels (two doublehulled lubricants oil barges and 12 offshore suppor t 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 B P’s Time Charter

Assurance Programme.

Spot-charter vessels

BP spot-charters vessels, typically for single voya ges. 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 deadwe ight tonne barges to

carry hydrocarbons on inland waterways.

Maritime security issues

2008 has seen a significant escalation in piracy ac tivity, specifically off the

north coast of Somalia. At a strategic level, BP av oids 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 trad e 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 mil itary and government agency

advice. At present, we are following such advice an d are participating in

protective group transits through the Gulf of Aden Maritime Security Patrol

Area transit corridor. 

# Page 37 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm36

Performance review



# Research and technology

Research and technology (R&T) has a critical role t o play in addressing the

world ’s energy challenges, from fundamental research thr ough to wide-scale

deployment. The full breadth of these R&T activitie s 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 technol ogy activities are in service of

competitive business performance and new business d evelopment, through

the research, development or acquisition of new tec hnologies. The central

R&T group provides leadership for scientific and te chnological activities

throughout the group and, in particular, provides i nput to the group’s long- term

strategy. It ensures that the right capability is i n place in critical areas and

ensures the quality of BP’s major technology progra mmes. It also illuminates

the potential of emerging technologies and conducts research and

development (R&D) in support of BP’s long-term corp orate renewal. In

addition, a group of eminent industrialists and aca demics forms the

Technology Advisory Council, which advises the boar d and executive

management on the state of research and technology within the group and

helps to identify current trends and future develop ments in technology.

Research and development (R&D) is carried out using a balance of

internal and external resources. Involving third pa rties in the various steps of

technology development and application enables a wi der range of ideas and

technologies to be considered and implemented, impr oving 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 technologie s to get them to the point of

commercial readiness: this includes field trials, s upport for technology

deployment, specialist technical services and centr al 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 wit h the potential to add

more than 1 billion boe to reserves through their d evelopment and deployment

in our assets worldwide. These technologies contrib uted 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 i ndustry, pioneering new

wide -azimuth seismic acquisition and processing in deep water Angola, Egypt

and the Gulf of Mexico. In addition, BP has develop ed new technologies that

have significantly reduced the time needed for land seismic acquisition in

Oman, and these are now being deployed in Libya. Ou r enhanced oil recovery

technologies are pushing recovery factors to new li mits. For example,

recovery factors have already increased from 40% to 60% in Alaska, where

BP operates the world’s largest miscible gas enhanc ed oil recovery project.

BP also leads the industry in the application of ne w inter-well polymer

treatments aimed at improving waterflood recovery, with more than 25

treatments delivering an increase of around five mi llion 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 produ cing heavy oil at a

production rate of 100 barrels of oil per day. Unco nventional gas is another

area of focus; for example, using new technologies, BP has drilled in 17

unconventional coalbed methane basins around the wo rld, including some of

the largest reservoirs in North America. Another fl agship 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 pro duction. 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-chang e in onshore pipeline

monitoring, and which will now be deployed in Azerb aijan, Canada and

Scotland.

In our Refining and Marketing segment, te chnology advancements are

enabling our refineries to understand and process f eedstocks of varying

quality and optimize our assets in real time, enhan cing the flexibility and

reliability of our refineries and, in turn, improvi ng 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 th e industry’s most

technologically advanced coking operations. In Nape rville, US, we opened a

new refining R&D centre, installing more than 50 ne w 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 l osses from machinery

failure. BP’ s leading technologies in fuels and lubricants mean that it can keep

ahead of increasingly stringent regulations, balanc ing greater fuel efficiency

and performance and developing superior formulation s across its entire

product slate. For example, our BP Ultimate fuels d eliver 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 lubric ants. 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 exam ple, our new 900ktepa

purified terephthalic acid (PTA) plant in Zhuhai, C hina was officially opened in

2008, occupying a plot just half the size of its ol der, neighbouring plant, but

with double the production capacity. In the field o f conversion technology, our

Nikiski Fischer-Tropsch demonstration plant in Alas ka operated at levels to

prove that we have a working catalyst at industrial scale.

In Alternative Energy, our low-carbon res earch and technology activity

continues apace. In 2008, we filed patents covering biofuels, carbon capture

and storage (CCS), and hydrogen membranes. Our sola r business produced

the first prototype of a cut-cell high voltage modu le, giving a 5% increase in

power over conventional modules. Working as part of the UK’s Energy

Technologies Institute – a public/private partnersh ip to accelerate low-carbon

technology development – BP is proceeding with inve stments in projects to

develop new offshore wind and marine turbines. We a lso published results of

the satellite monitoring programme, verified by wel l and tracer detection, of the

CCS project at the In Salah gas field in Algeria wi th our partners Sonatrach.

Collaboration plays an important role acr oss the breadth of BP’s

research and development activities, but particular ly in those areas that

benefit from fundamental scientific research. BP ha s 11 significant long-term

research programmes with major universities and res earch institutions around

the world, exploring areas from energy bioscience a nd conversion technology

to carbon mitigation and nanotechnology in solar po wer. In 2008, our Energy

Biosciences Institute at Berkeley ( see page 34 ) became fully operational, with

49 research projects, all focused on lignocellulosi c biofuel production; we

announced the renewal of our Carbon Mitigation Init iative at Princeton; and

signed the joint venture agreement for the Clean En ergy Commercialisation

Centre with the Chinese Academy of Sciences. 

# Page 38 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm37

Performance review



# Regulation of the group’s business

BP’s activities, including its oil and gas explorat ion and production, pipelines

and transportation, refining and marketing, petroch emicals production, trading,

alternative energy and shipping activities, are con ducted in many different

countries and are therefore subject to a broad rang e of EU, US, international,

regional and local legislation and regulations, inc luding 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, l icences and contracts under

which our oil and gas interests are held vary from country to country. These

leases, licences and contracts are generally grante d by or entered into with a

government entity or state company and are sometime s entered into with

private property owners. These arrangements with go vernmental or state

entities usually take the form of licences or produ ction-sharing agreements.

Arrangements with private property owners are usual ly in the form of leases.

Licences (or concessions) give the holder the right to explore for and

exploit a commercial discovery. Under a licence, th e holder bears the risk of

exploration, development and production activities and provides the financing

for these operations. In principle, the licence hol der is entitled to all production,

minus any royalties that are payable in kind. A lic ence holder is generally

required to pay production taxes or royalties, whic h may be in cash or in kind.

Less typically, BP may explore for and exploit hydr ocarbons under a service

agreement with the host entity in exchange for reim bursement of costs and/or

a fee paid in cash rather than production.

PSAs entered into with a government entit y or state company generally

require BP to provide all the financing and bear th e risk of exploration and

production activities in exchange for a share of th e production remaining after

royalties, if any.

In certain countries, separate licences a re required for exploration and

production activities and, in certain cases, produc tion licences are limited to a

portion of the area covered by the exploration lice nce. Both exploration and

production licences are generally for a specified p eriod of time (except for

licences in the US, which typically remain in effec t until production ceases).

The term of BP’s licences and the extent to which t hese licences may be

renewed vary by area.

Frequently, BP conducts its exploration a nd production activities in joint

venture with other international oil companies, sta te companies or private

companies.

In general, BP is required to pay income tax on income generated from

production activities (whether under a licence or p roduction-sharing

agreement). In addition, depending on the area, BP’ s production activities may

be subject to a range of other taxes, levies and as sessments, including special

petroleum taxes and revenue taxes. The taxes impose d on oil and gas

production profits and activities may be substantia lly 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 cer tain health and safety

regulations and environmental proceedings, see Envi ronment on page 39.

See also Legal proceedings on page 88. 

# Safety

This section reviews BP’s safety performance in 200 8.

There were five workforce fatalities in 2 008, compared with seven in

2007. One resulted from fatal injuries sustained du ring operations at our

Texas City refinery; one was the result of a fall f rom 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 t hese incidents and

implementing appropriate improvement actions, we co ntinue to seek to secure

the safety of all members of our workforce. Our wor kforce reported recordable

injury frequency, which measures the number of inju ries per 200,000 hours

worked, was 0.43 in 2008. This was a good improveme nt 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 w hich safety was a focus, were

undertaken by the group chief executive (GCE) and m embers of the executive

team to reinforce the importance of their commitmen t to safe and reliable

operations.

Management systems

We continue to implement our new operating manageme nt 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 s ingle framework within which

we will operate, consolidating BP ’s requirements relating to process safety,

environmental performance, legal compliance in oper ations, and personal,

marine and driving safety. It embraces recommendati ons made by the BP US

Refineries Independent Safety Review Panel (the pan el), which reported in

January 2007 on safety management at our US refiner ies 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 relia bility. A number of

mandatory operating and engineering technical requi rements have been

defined within the OMS, to address process safety a nd related risks.

All operated businesses plan to transitio n 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, L ingen and Gelsenkirchen

and four Exploration and Production sites, North Am erica Gas, the Gulf of

Mexico, Colombia and the Endicott field in Alaska. Implementation is

continuing across the group and a number of other s ites, including all

refineries not already operating the OMS, are expec ted to complete the

transition in 2009.

For the sites already involved, implement ing OMS has involved detailed

planning, including gap assessments supported by ex ternal facilitators. A core

aspect of OMS implementation is that each site prod uces its own ‘local OMS’,

which takes account of relevant risks at the site a nd 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 r isk management. Each

site also develops a plan to close gaps that is rev iewed annually. The

transition to OMS, at local and group level, has be en handled in a formal and

systematic way, to ensure the change is managed saf ely and

comprehensively. 

# Page 39 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm38

Performance review

Experience so far has supported our expectation tha t having one integrated

and coherent system brings benefits of simplificati on and clarity, and that the

process of change is supporting our renewed commitm ent to safe operations.

We are on track to meet our target of imp lementing OMS across the

group by the end of 2010.

Capability development

In addition to ongoing training programmes we are u ndertaking a group wide

programme to enhance the capability of our staff fr om front line to executive

level to deliver operational excellence.

Almost 1,000, around a third, of our fron t-line supervisors have started

the Operating Essentials programme, which includes training on leadership,

process safety, operating culture, practices and co aching and effective

performance conversations.

More than 190, around half, of our operat ions leaders started the

Operations Academy programme in 2008. The academy, which has been

established in partnership with the Massachusetts I nstitute of Technology

(MIT), provides participants with a total of six we eks of operations training,

concentrating on the management of change and conti nuous improvement.

The Executive Operations programme, which seeks to increase insight

into manufacturing and operation activities among s enior business leaders,

has built on its successful launch with the first g roup, 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 e ngineering staff have

progressed through the Project and Engineering Acad emy at MIT and 13

process safety courses have been delivered for proj ect and project

engineering managers at the Project Management Coll ege. We have

continued to develop training on hazard evaluation and risk assessment

techniques for all engineers, operators and HSSE pr ofessionals.

Process safety management

We remain fully committed to becoming a recognized industry leader in

process safety management and are working to achiev e this. We have taken a

range of steps, including acting on the recommendat ions from both the panel

and those within the first annual report of the ind ependent expert.

Our actions can be summarized in three pr incipal areas:

• We have made progress in reducing process safety ri sk at our US refineries.

For example, we have completed and learned from saf ety and operations

audits, relocated workers to lower-risk accommodati on and implemented

fatigue reduction programmes.

• Executive management has taken a range of actions to demonstrate their

leadership and commitment to safety. The group chie f executive has

consistently emphasized that safety, people, and pe rformance are our top

priority, a belief made clear in his 2007 announcem ent of a forward agenda

for simplification and cultural change in BP. Safet y performance has been

scrutinized by the Group Operations Risk Committee (the GORC), chaired

by the group chief executive and tasked with assuri ng the group chief

executive that group operational risks are identifi ed and managed

appropriately. We continued to build our team of sa fety and operations

auditors. A team of 45 auditors is now in place, wi th 36 audits completed in

2008.

• Many of the process

- safety related improvements recommended by the

panel are being implemented across the group throug h the OMS. The group

essentials within the OMS (which cover diverse aspe cts of operating activity

including legal compliance, process and environment al safety and basic

operating practices) in some cases go beyond the pa nel’s process safety

recommendations, a point noted by the independent e xpert in his first report. In addition to action in these areas, we have conti nued to participate in

industry-wide forums on process safety and have mad e efforts to share our

learning with other organizations.

The independent expert has been tasked wi th reporting to the board on

BP’s progress in implementing the panel’s recommend ations. We welcome

the independent expert’s view expressed in his firs t report (May 2008) that BP

‘appears to be making substantial progress in chang ing culture and

addressing needed process safety improvements’. How ever, we also

acknowledge his observation that ‘a significant amo unt of work remains to be

done on the process safety journey’ and that ‘succe ssful completion of the

task will require the continued support and involve ment of the board, executive

management, and refinery leadership along with a su stained 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 launche d in 2006 to address

immediate priorities for improving process safety a nd minimizing risk at our

operations worldwide.

We have met our commitment to remove occu pied portable buildings

(OPBs) from high-risk zones within onshore process plant areas and to

remove all blow-down stacks in heavier-than-air, li ght hydrocarbon service. All

major sites and our fuels value chains have complet ed major accident risk

assessments, which identify major accident risks an d develop mitigation plans

to manage and respond to them.

We continue to implement the Control of W ork and Integrity

Management standards. We have made progress in ensu ring our operations

meet the requirements of a group framework designed to ensure we stay in

compliance with legal requirements on health and sa fety. We are continuing to

take steps to close out past audit actions. Leaders hip competency

assessments, which involve assessment of the experi ence of BP management

teams responsible for major production sites or man ufacturing plant, have

been completed in Exploration and Production and in all major Refining and

Marketing manufacturing sites.

Implementation of these actions is expect ed to be largely complete by

the end of 2009, with some aspects of implementatio n 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 dama ge or significant

environmental impact. We also track and analyze ‘hi gh 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 inciden t.

A total of 21 major incidents were report ed 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 o r more in 2008, similar to 2007

performance of 340 oil spills. The volume of oil sp illed 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-th irds of the total reported

volume of oil spilled, the great majority of which remained contained and the

oil recovered. 

# Page 40 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm39

Performance review

Performance indicators

We have well-developed systems, processes and metri cs for reporting

personal safety and environmental metrics that supp ort 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 incide nt index, as recommended

by the panel, which uses weighted severity scores t o 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, an d ‘leading’ indicators that

focus on the strength of our controls to prevent un desired events in future. A

suite of indicators is regularly reported to the GO RC within the quarterly ‘HSE

and Operations Integrity Report’ and several new me trics have also been

piloted. To further enhance the management of healt h risks across the group,

we began the systematic reporting of recordable ill ness rates within the HSE

and Operations Integrity Report. We continue to wor k with industry bodies

such as the Centre for Chemical Process Safety and the American Petroleum

Institute on the development of process safety metr ics, definitions and

guidance.

Continuing to focus on health

In addition to our efforts to improve process safet y performance, we strive to

protect the personal health and safety of our workf orce, recognizing that

healthy performance is delivered through healthy pe ople, healthy processes

and healthy plant.

In the course of 2008, we defined health ‘group essentials’, which

specify requirements designed to prevent harm to th e 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 occupationa l exposure and infectious

disease risks, maintaining robust regulatory compli ance in product health and

safety and addressing the issue of fatigue manageme nt 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 specification s, emission controls and

climate change programmes under a number of environ mental laws will have

a significant effect on the production, sale and pr ofitability of many of our

products. Environmental laws also require us to rem ediate 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, process ed, stored, distributed,

sold or disposed of, such as refineries, chemical p lants, natural gas

processing plants, oil and natural gas fields, serv ice stations, terminals and

waste disposal sites. Some of these obligations rel ate to prior asset sales or

closed facilities. Provisions for environmental res toration and remediation are

made when a clean-up is probable and the amount of the obligation can be

reliably estimated. Generally this coincides with c ommitment to a formal plan

of action or, if earlier, on divestment or on closu re of inactive sites. The

provisions made are considered by management to be sufficient to meet

known requirements.

The extent and cost of future environment al restoration, remediation

and abatement programmes are often inherently diffi cult to estimate. They

often depend on the extent of contamination, and th e associated impact and

timing of the corrective actions required, technolo gical feasibility and BP’s

share of liability. Though the costs of future prog rammes 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 pr ovided 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 re lease or exposure to

hazardous substances. A number of proceedings invol ving governmental

authorities are pending or known to be contemplated against BP and certain of

its subsidiaries under federal, state or local envi ronmental laws, each of which

could result in monetary sanctions of $100,000 or m ore. No individual

proceeding is, nor are the proceedings in aggregate , expected to be material

to the group’s results of operations or financial p osition.

We cannot accurately predict the effect o f future developments, such as

stricter environmental laws or enforcement policies on the group’s operations,

products or profitability. A risk of increased envi ronmental costs and

operational impacts is inherent in grouping our bus inesses and there can be

no assurance that material liabilities and costs wi ll 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 gro up has disclosed

such non-compliance and is working with the relevan t regulatory authorities to

ensure compliance. For a discussion of the group’ s environmental expenditure

see page 53.

BP operates in more than 90 countries wor ldwide. In each of these

areas, BP has, or is developing, processes designed to ensure compliance

with applicable regulations. In addition, each empl oyee is required to comply

with BP health, safety and environmental policies a s embedded in the BP

code of conduct. Our partners, suppliers and contra ctors are also encouraged

to adopt them.

This Environment section focuses primaril y on the US and the EU,

where around 61% of our fixed assets are located, a nd 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 mana gement systems to

seek improvements on a wide range of environmental issues. Except at two

locations, the operations at our major operating si tes are covered 

# Page 41 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm40

Performance review

by certification to the ISO 14001 international env ironmental management

system standard. The Texas City refinery, after com pleting planned work to

strengthen its environmental management systems, is planning to seek

recertification in 2009. Our Angola business is wor king towards an expansion

of its existing ISO 14001 certificate to include it s offshore production facilities

by the end of 2009. Progressive implementation of t he Operating Management

System (OMS), including ISO 14001, will also help u s strengthen our

management of environmental performance.

In support of ongoing risk management, on e element of the OMS

applies, at least annually, a formal systematic pro cess to identify and assess

risks; this process provides to identify emerging i ssues including those with an

environmental impact. To assist us in measuring the effectiveness of our risk

mitigation actions we have established environmenta l 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 En vironmental Requirements for

New Projects (ERNP) practice has been updated in li ne with the OMS. We

have simplified applicability, clarified the govern ance process and updated the

text to reflect organizational changes. This practi ce, now called the

Environmental Group Defined Practice (GDP) is a ful l life cycle environmental

assessment process. It requires all new major proje cts and projects in

sensitive areas, to undertake screening to determin e the potential

environmental sensitivities associated with the pro posed projects.

Requirements and project recommendations now extend to include

appropriate considerations for decommissioning of a ssets. A new project with

the highest level of environmental sensitivity requ ires more rigorous and

specific environmental management activities. The b oard-appointed Safety,

Environment and Ethics Assurance Committee reviewed the progress of

ERNP during summer 2008. This review included the 1 2 projects that have

been classified as requiring management at the high est level of sensitivity. We

are currently integrating social considerations int o 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 deci sion 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 a t the end of April 2009.

Our focus on asset decommissioning is dem onstrated by the North

West Hutton offshore platform project in the North Sea. 2008 saw the topsides

of the North West Hutton platform safely brought on shore for further

dismantling. This decommissioning is expected to re sult 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 emissi ons.

Climate change programmes

In response to rising concerns about climate change , governments continue to

identify fiscal and regulatory measures at local, n ational and international

levels.

In December 1997, at the Third Conference of the Parties to the United

Nations Framework Convention on Climate Change (UNF CCC) in Kyoto,

Japan, the participants agreed on a system of diffe rentiated international

legally-binding targets for the first commitment pe riod of 2008-2012. In 2005,

the Kyoto protocol came into force, committing the 176 participating countries

to emissions targets. However, Kyoto was only desig ned as a first step and

policymakers continue to discuss what new agreement might follow it after

2012, most recently at the UNFCCC conference in Poz nan, Poland in

December 2008.

Many of our larger EU stationary assets a re subject to the EU

Emissions Trading Scheme (EU ETS), which was extend ed to Norway by reciprocal agreement. After inclusion of our Norweg ian assets, around one

fifth of our reported 2008 global CO 2 emissions are now covered by this

scheme.

At the March 2007 European Council, the E uropean Heads of

Government decided to adopt their Climate Action an d 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 bein g 30% if an international

agreement is reached), as well as an improved energ y efficiency within the EU

Member States of 20% by 2020 and a 20% renewable en ergy target by 2020.

The Australian government has set a targe t 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 20 09. The Australian

government proposes to cover 70% of emissions sourc es and sectors via a

combination of direct obligations on facilities wit h large emissions, and

obligations on upstream fuel suppliers for the emis sions resulting from the

combustion of fuel. In December the government also announced 2020 GHG

emission targets that range from a 5 to 15% reducti on from 2000 levels. The

scheme builds on the existing National Greenhouse a nd Energy Reporting

System, the Australian mandatory reporting system f or 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 2 007, that includes stricter

corporate average fuel emissions standards for auto mobiles sold in the US

and biofuel mandates. Other bills currently under c onsideration propose

stricter emissions limits on large GHG sources and/ or the introduction of a

cap-and-trade programme on CO 2 and other GHG emissions.

An April 2007 US Supreme Court decision w ill require the US

Environmental Protection Agency (EPA) to reconsider its determination that it

is not required to regulate GHGs from motor vehicle s under the Clean Air Act

(CAA). The Supreme Court’s ruling is expected to re sult 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. re fineries and chemical

plants) under other provisions of the CAA.

In response to the US Supreme Court’s dec ision, the EPA issued an

Advanced Notice of Proposed Rulemaking (ANPR). The ANPR addresses

complexities involved in controlling greenhouse gas es under the CAA

including potential overlap between future legislat ion and regulation under the

existing CAA.

In its Fiscal Year 2008 Consolidated Appr opriations Act, US Congress

directed the EPA to publish a mandatory GHG reporti ng 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 dra ft language and the

proposed rule could be released early in the new US administration.

Congress will likely develop new legislat ion for GHG regulation, and

new regulation under the CAA will likely proceed as well. Additional GHG

regulation may also be issued under other laws, suc h as the National

Environmental Protection Act (NEPA) and Endangered Species Act (ESA).

In December 2008, the California Air Reso urces Board

(CARB) approved the final Proposed Scoping Plan for implementing Assembly

Bill 32, California’s law to reduce GHG emissions t o 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 Stand ard (LCFS). The

LCFS will require all refiners, producers, blenders and importers to reduce the

carbon intensity of transport fuel sold in Californ ia by 10% by 2020. CARB

released draft LCFS regulations in October 2008, wi th final regulations

expected to be taken up in March 2009. 

# Page 42 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm41

Performance review

In March 2008, the Canadian federal government upda ted its April 2007

Framework Report with an Action Plan to address cli mate change and reduce

emissions 20% below 2006 levels by 2020 and by grea ter than 60% by 2050,

through both a sector approach and domestic develop ment 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, m ore stringent requirements

are likely to emerge for upcoming projects that may include requirements for

significant reductions, including the implementatio n of large scale carbon

capture and sequestration. Since the conclusion of the recent Canadian and

US Federal elections there has been increased discu ssion 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 p rincipal kinds of GHG

emissions: operational emissions, which are generat ed 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 d eveloping sustainable lowcarbon technologies and businesses.

After seven years, we estimate that our o perations have delivered some

7.5 million tonnes (Mte) of GHG reductions. Our 200 8 operational GHG

emissions were 61.4Mte of CO2 equivalent on a direc t 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 pro tocol change for BP

Shipping (1.9Mte) to align us more closely with ind ustry practice.

In 2007, as part of our technology develo pment, two major BP-backed

research institutes came into full operation: the E nergy Biosciences Institute

(EBI) in the US, and the Energy Technologies Instit ute (ETI) in the UK. The

EBI is a strategic partnership between BP, the Univ ersity 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 recover y 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 ET I aims to accelerate the

development, demonstration and eventual commercial deployment of a

focused portfolio of energy technologies, which wil l increase energy efficiency,

reduce GHG emissions and help achieve energy securi ty and climate change

goals. The ETI has issued its first invitation for expressions of interest to

participate in programmes to develop new technologi es for offshore wind and

for marine, tidal and wave energy. BP established t he Carbon Mitigation

Initiative in 2000 at Princeton University in the U S to research the fundamental

scientific, environmental, and technological issues that will determine how

carbon is managed in the future and examine the pol icy 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 mor e than $2 million per year. In

October 2008, BP committed to a five-year renewal o f 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 9 0) imposes oil spill

prevention and planning requirements liability for tankers and barges

transporting oil and for offshore facilities such a s platforms and onshore

terminals. To ensure adequate funding for oil spill response and

compensation, OPA 90 created the Oil Spill Liabilit y 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 siz e of the fund from the

original amount of $1 billion to $2.7 billion. In l ate 2008, as part of the

Emergency Economic Stabilization Act, further amend ments were made to

increase the per-barrel contribution rate of tax an d to remove the provision for

cessation of the tax when the fund reached $2.7 bil lion. 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 Decemb er 2017. The 2006

legislation also increased the OPA limitation amoun t relating to the liability of

double-hulled tankers from $1,200 per gross tonne t o $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, includi ng Alaska, Washington,

Oregon and California, impose additional liability on the shippers or owners of

oil spilled from such vessels. The exposure of BP t o such liability is mitigated

by the vessels’ marine liability insurance, which h as a maximum limit of $1

billion for each accident or occurrence. OPA 90 als o provides that all new tank

vessels operating in US waters must have double hul ls 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 2 004 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 prepare dness regulations that are

typically promulgated through the International Mar itime Organization

(IMO) and implemented by the relevant flag state au thorities. The International

Convention for the Prevention of Pollution from Shi ps (Marpol 73/78) requires

vessels to have detailed shipboard emergency and sp ill prevention plans. The

International Convention on Oil Pollution, Prepared ness, Response and Cooperation requires vessels to have adequate spill r esponse 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 eng agement in the event of a

spill. All these requirements together are addresse d by the vessel owners in

Shipboard Oil Pollution Emergency Plans. BP Shippin g’s liabilities for oil

pollution damage under the OPA 90 and outside the U S under the 1969/1992

International Convention on Civil Liability for Oil Pollution Damage (CLC) are

covered by marine liability insurance, having a max imum limit of $1 billion for

each accident or occurrence. This insurance cover i s provided by three mutual

insurance associations (P&I Clubs): The United King dom Steam Ship

Assurance Association (Bermuda) Limited; The Britan nia Steam Ship

Insurance Association Limited; and The Standard Ste amship Owners’

Protection and Indemnity Association (Bermuda) Limi ted. 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 Polluti on 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 fir st scheme, the Small Tanker

Owners’ Pollution Indemnification Agreement (STOPIA ), provides for a

minimum liability of 20 million Special Drawing Rig hts (around $30 million) for

a ship at or below 29,548 gross tonnes, while the s econd 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 thei r 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 man aged and timechartered vessels participate in STOPIA and TOPIA.

For information regarding maritime securi ty issues, see Shipping on

page 35. 

# Page 43 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm42

Performance review

US

The following is a summary of significant US enviro nmental issues and

environment and health and safety legislation or re gulations affecting BP.

The CAA and its regulations, administered by the United States

Environmental Protection Agency (EPA) require, amon g other things: stringent

air emission limits and operating permits for chemi cals plants, refineries,

marine and distribution terminals and exploration a nd production facilities,

strict fuel specifications and sulphur reductions; enhanced monitoring of major

sources of specified pollutants; and risk managemen t plans for storage of

hazardous substances. This law affects BP facilitie s producing, storing,

refining, manufacturing and distributing oil and pr oducts as well as the fuels

themselves. Federal and state controls on ozone, pa rticulate matter, carbon

monoxide, benzene, sulphur, MTBE, nitrogen dioxide, oxygenates, lead and

Reid Vapor Pressure affect BP’s activities and prod ucts. Under the CAA all

gasoline produced by BP is subject to the EPA’s str ingent low-sulphur

standards. By June 2006, at least 80% of the highwa y 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 t he 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 Va por 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 C AA requirements related

largely to emissions of sulphur dioxide and nitroge n oxides at BP’s US

refineries. Implementation of the decree’s requirem ents continues.

In 2001, BP’s US refineries entered into a civil consent decree with the

EPA to resolve alleged violations of the CAA. The d ecree applies to all the US

refineries of BP Products North America Inc. (BP Pr oducts). 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 bo th the 2001 decree and the

CAA. The decree requires that BP Products pays a $1 2 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 co urt approval.

The Clean Water Act (CWA) and its regulat ions, administered by EPA

and the US Coast Guard, regulate the discharge of w astewater, 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 pr eventative measures.

Additionally, states have separate laws similar to the CWA.

The Resource Conservation and Recovery Ac t (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 remediatio n of locations at a facility

where such wastes have been managed. Many BP facili ties generate and

manage wastes regulated by RCRA and several include locations that are

subject to investigation and corrective action. Add itionally, states have

separate laws similar to RCRA.

Under the Comprehensive Environmental Res ponse, Compensation

and Liability Act (CERCLA or Superfund), persons wh o arranged to dispose of

hazardous substances at a site, persons who current ly own or operate a site

where such substances have been disposed and certain other parties are strictly lia ble for the cost of responding

to related hazardous substance contamination. EPA a dministers CERCLA.

Additionally, states have separate laws similar to CERCLA.

BP has been identified as a Potentially R esponsible Party (PRP) under

CERCLA or otherwise named under similar state statu tes 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 re mediation costs at these

sites to be small in comparison with the major site s. BP has estimated its

potential exposure at all sites where it has been i dentified as a PRP or is

otherwise named at a site is approximately $1.7 bil lion.

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 numb er of BP operations.

Many environmental clean-ups are driven by state an d federal groundwater

protection standards. Contamination or the threat o f contamination of current

or potential potable (and occasionally non-potable) water resources can result

in stringent clean-up requirements. BP has encourag ed risk-based

approaches to these issues and seeks to tailor reme dies at its facilities to

match the level of risk presented by the contaminat ion.

Other legislation that significantly affe ct BP operations includes: the

Toxic Substances Control Act, administered by EPA, which regulates the

development, testing, import, export and introducti on 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 p rocess safety

requirements to reduce the risks of physical and ch emical hazards and injury

to employees; the CAA, which created the US Chemica l Safety and Hazard

Investigation Board which investigates the causes o f chemical accidents and

makes non-binding recommendations to industry, gove rnment and nongovernmental organizations; and the Emergency Plann ing and Community

Right-to-Know Act, administered by the EPA, which r equires emergency

planning and hazardous substance release notificati on as well as public

disclosure of chemical usage and emissions. In addi tion, the US Department

of Transportation (DOT) regulates the transportatio n of the BP’s petroleum

products such as crude oil, gasoline and chemicals.

BP is subject to the Marine Transportatio n 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 secu rity mitigation plans that

require upgrades to security measures, the appointm ent and training of

security personnel and the submission of plans for approval and inspection by

government agencies.

The US government through the Department of Homelan d Security, in an

effort to further mitigate the threat of terrorism to critical US infrastructure, has

implemented two new security legislation initiative s, that began in 2007 and

has continued through 2008:

CFATS is intended to provide an enhanced security p osture for US facilities

that manufacture or store Chemicals of Interest, in cluding gasoline.

Additionally, in the future, it will cover faciliti es that have national economic

impact to the US, should these facilities be a targ et for terrorism. A number of

BP facilities may be required to conduct a detailed security vulnerability

assessment and a detailed security plan for each fa cility impacted.

TWIC requires all designated personnel wi th unescorted access to

restricted areas of MTSA designated facilities to s ubmit to a background

screening programme and to obtain a biometric ident ification card. All of • Chemical Facility Anti

- Terrorism Standard (CFATS).

• Transportation Workers Identification Credential (T WIC). 

# Page 44 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm43

Performance review

BP ’ s MTSA

- regulated facilities will be impacted and will be r equired 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 throug hout 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 challen ged 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 t he Whiting, Toledo, Carson and

Cherry Point refineries. Settlement negotiations co ntinue between BP

Products, the EPA and the DOJ in an effort to resol ve these matters. In

October 2008, the EPA issued an amended notice of v iolation alleging that BP

Products began construction on the Whiting upgrade in 2005 prior to receiving

the necessary permits. This allegation has been inc orporated into the permit

challenges filed by the environmental groups. The s ubject matter of the

notices of violation could be resolved as an amendm ent 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 E uropean 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 prepar ation of the ‘Climate Action

and Renewable Energy Package’, as part of our effor ts to actively contribute

to the formulation of energy security and climate c hange policy in the EU.

An EC directive for a system of integrate d pollution prevention and

control (IPPC) was adopted in 1996. This system req uires 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 comprehe nsive and integrated

fashion. The permit requires, among other things, t he application of Best

Available Techniques (BAT), taking into account the costs and benefits, unless

an applicable environmental quality standard requir es more stringent

restrictions, and an assessment of existing environ mental impacts and future

site closure obligations. All such plants had to ob tain such a permit by 30

October 2007 and permits included an environmental improvement

programme where necessary.

In December 2007, the EC issued a proposa l for the revision to the

IPPC Directive with the aims of streamlining legisl ation on industrial

emissions, improving the implementation of BATs acr oss 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 intern ational climate change

agreement; and

• a mandatory EU target of 20% renewable energy by 20 20 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 st ate; • 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 requ iring fuel suppliers to

reduce the life cycle emission of the fuels they pr ovide 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 mer ges 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 v alues 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 treatmen t (biofuels) and may open

the way for NOx and SOx trading by member states.

The EC proposal has triggered considerabl e debate and the timetable

for the completion of the legislative process and t he likely outcome are not

clear. However, the revision has already triggered a greater focus on the

information sharing process that is used to determi ne and document the BAT

for each industry sector, and will raise the profil e of the outputs from this

process – the BAT Reference Documents (BREFs).

In 2005, the EC published its Thematic St rategy on Air Pollution, which

outlines EU-wide targets for health and environment al 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 organ ic compounds and ammonia.

Associated with this is the revision to the Nationa l Emissions Ceiling Directive

(NECD), which would introduce new emissions ceiling s for each member state

for fine particles and tighten existing ceilings fo r sulphur dioxide, oxides of

nitrogen, volatile organic compounds and ammonia. T here is currently

uncertainty regarding the costs to industry of impl ementing possible outcomes

from the NECD and IPPC revisions.

The proposed revision of the current EU F uel Quality Directive is

referred to in the Climate Change Programmes sectio n above. In addition to

its provisions regarding life cycle GHG emission re ductions, it would also

facilitate the introduction of biofuels into gasoli ne and diesel.

Registration, Evaluation and Authorizatio n of Chemicals

(REACH) legislation became effective 1 June 2007 ac ross all member states

of the EU. All chemical substances manufactured wit hin, or imported into, the

EU in quantities above 1 tonne per annum must be re gistered fully by each

manufacturer/importer with the new European Chemica l Agency (ECHA).

Failure to comply with REACH in respect of such a s ubstance will immediately

remove a company’s legal right to manufacture or im port that substance.

Initially all existing manufactured and imported su bstances had to be preregistered by 1 December 2008, to qualify for a tim ed 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 chemic al 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 rest rictions in use may apply.

Crude oil and natural gas are exempt from registrat ion requirements, while

fuels are exempt from authorization but not registr ation. In BP, REACH affects

our refining, petrochemicals and other chemical man ufacturing operations,

with many other businesses, such as lubricants, als o being impacted in their

roles as major importers and downstream users of ch emicals. In 2008, BP

submitted around 700 pre-registrations, covering ap proximately 250 individual

chemical substances. For almost 60% of these, ‘full ’ registration dossiers must

be submitted to ECHA by 1 December 2010, the balanc e 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 mill ion during the period 2008-

2018 for pre-registration, registration and provisi on of additional testing

requirements.

In the UK, significant health and safety legislation affecting BP includes

the Health and Safety at Work Act and regulations m ade thereunder and the

Control of Major Accident Hazards Regulations. 

# Page 45 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Employees

44 Performance review

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 corporate a 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

a A minor amendment has been made to the comparative fi gure for Rest of the World to correct headcount data.

People and their capabilities are fundamental to ou r sustainability as a

business. To build an enduring business in an incre asingly complex and

competitive industry, we need people with world-cla ss capabilities, ranging

from deepwater drilling and operating refineries to negotiating with

governments and planning wind farms.

Our 2008 focus has been on reducing compl exity 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 stopp ed activity that was being

repeated at multiple layers, removed layers of mana gement and have

established the SPUs as the principal units of deli very. There is a greater focus on individual pe rformance management. We

have simplified the performance management process and can clearly identify

and reward top performing businesses and individual s. 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 2 007.

In managing our people, we seek to attrac t, develop and retain highly

talented individuals in order to maintain BP’s capa bility to deliver our strategy

and plans. Our three-year graduate development prog ramme currently has

1,200 participants from all over the world.

We are focusing on the need for deep spec ialist skills. Accordingly, we

have increased external hiring in infrastructure an d technical areas. The

energy industry faces a shortage of professionals s uch as petroleum

engineers. The number of experienced workers retiri ng is expected to exceed

that of new graduate hires. To help address this is sue we are developing more

robust resourcing plans supported by initiatives ai med at increasing the

numbers of recruits and diversifying the sources fr om which we recruit. The

external hiring initiatives are supported by plans for accelerated discipline

development, prioritized deployment and retention s chemes.

The continuous improvement we are making to performance

management and reward will help ensure that BP meet s the expectations of

these new recruits who are highly mobile and are mo re 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 b ecome disabled, our policy

is to provide continuing employment and training wh erever practicable. In 2008, a global diversity and inclusion (D&I) cou ncil was established. This

council, chaired by Tony Hayward, is supported by a North American regional

council and segment councils. The aim is to harmoni ze 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 200 7, continues to take overall

responsibility for policy decisions relating to emp loyees. In 2008, these ranged

from senior level talent review and succession plan ning, embedding of

diversity and inclusion plans in the businesses and the structure of long-term

incentive plans.

We continue to increase the number of loc al leaders and employees in

our operations so that they reflect the communities in which we operate. For

example, in Colombia, national employees now make u p 98% of BP’s team,

while in Azerbaijan, the equivalent proportion is 8 3%. By 2020, more than half

our operations are expected to be in non-OECD count ries and we see this as

an opportunity to develop a new generation of exper ts and skilled employees.

At the end of 2008, 14% of our top 583 le aders were female and 19%

came from countries other than the UK and the US. W hen we started tracking

the composition of our group leadership in 2000, th ese percentages were 9%

and 14% respectively. We continue to raise our seni or level leaders’

awareness of D&I, and further training is planned i n 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 peop le to positions in the

group leadership population. Of these, 39 were inte rnal candidates.

We provide development opportunities for our employees, including

training courses, international assignments, mentor ing, team development

days, workshops, seminars and online learning. We e ncourage all employees

to take five training days per year.

A leadership, development and learning st eering group was set up in

2008. This body of senior executives has responsibi lity for guiding and

advising on leadership and management development. As part of this, the

steering group oversees the Managing Essentials pro gramme, 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 employee s. 

# Page 46 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm45

Performance review

Communications with employees include magazines, in tranet sites, DVDs,

targeted emails and face-to-face communication. Tea m meetings are the core

of our employee consultation, complemented by forma l processes through

works councils in parts of Europe. These communicat ions, along with training

programmes, are designed to contribute to employee development and

motivation by raising awareness of financial, econo mic, social and

environmental factors affecting our performance.

The group seeks to maintain constructive relationships with labour

unions.

‘Pulse’ surveys conducted in 2008 among s amples of employees

indicated that BP’s safety culture is growing but t hat overall satisfaction levels

have fallen. The surveys also revealed that more wo rk needs to be done to

ensure all employees fully understand what they nee d to do to deliver

sustainable high performance.

We continue to make significant efforts t o communicate the intent and

progress of the forward agenda to reduce the potent ial negative impacts of

this change on the business. We have moved quickly, but our management of

change practices keep the focus on safety and ensur e that the changes are

sustainable. These improvements are expected to con tinue in 2009, but we

have already delivered material reductions in activ ity, cost and headcount.

The code of conduct

We have a code of conduct designed to ensure that a ll employees comply with

legal requirements and our own standards. The code defines what BP expects

of its people in key areas such as safety, workplac e behaviour, bribery and

corruption and financial integrity. Our employee co ncerns 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 o r the code of conduct,

including safety concerns.

We take steps to identify and correct are as 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 g roup will not participate directly

in party political activity or make any political c ontributions, 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 wher e we operate in a

manner that brings benefits to BP as well as the lo cal society. Investment in

education, for example, promotes sustainable develo pment as well as

providing skilled workers for BP and other companie s. Support for local

enterprise drives economic growth as well as helpin g local companies qualify

as our suppliers.

BP operates in a diverse range of locatio ns 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 nat ional and, in some cases,

the international level.

We support education because it creates o pportunities for communities,

while at the same time providing skills that are cr itical 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 u niversity research,

building skills and capability in communities as we ll advancing knowledge on

issues such as climate change and effective economi c management of natural

resource rich countries. In further and higher educ ation, a major driver for our

involvement is the need to encourage more people to develop the particular

skills needed for the energy industry. In supportin g school education, BP looks

to develop children’s awareness of links between en ergy and the environment

as well as stimulating interest in science and engi neering. In addition to its

investment in the formal learning system, BP suppor ts public education on

specific pressing social issues when there is a par ticular need within a local

community.

Through training and financing programmes , BP seeks to support the

development of local suppliers by building their sk ills, sharing internal

standards and practice and stimulating business dev elopment. This enables

greater participation in the supply chain by local business and greater

competitiveness overall.

We support several initiatives designed t o 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 pol icy options available to

emerging economies that are rich in natural resourc es such as oil and gas.

We remain a member of the Extractive Industries Tra nsparency Initiative

(EITI), which supports the creation of a standardiz ed process for transparent

reporting of company payments and government revenu es from oil, gas and

mining.

In the US, amongst various other initiati ves 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 th e Gulf of Mexico.

We make direct contributions to communiti es 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; busi ness leadership skills;

and basic education in developing countries where w e operate large projects.



# Essential contracts

BP has contractual and other arrangements with nume rous third parties in

support of its business activities. This report doe s not contain information

about any of these third parties as none of our arr angements with them are

considered to be essential to the business of BP.



# Property, plants and equipment

BP has freehold and leasehold interests in real est ate in numerous countries,

but no individual property is significant to the gr oup as a whole. See

Exploration and Production on page 13 for a descrip tion of the group’s

significant reserves and sources of crude oil and n atural 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 Dec ember 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 1 73. See Financial

statements – Notes 26 and 27 on pages 138 and 139 r espectively for

information on significant jointly controlled entit ies and associates of the

group. 

# Page 47 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Financial and operating performance

Group operating results

The following summarizes the group’s operating resu lts.

46 Performance review

$ million except per share amounts

2008 2007 2006

Total revenues a 365,700 288,951 270,602

Profit from continuing operations a 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 oper ation in accordance with IFRS 5 ‘Non-current Assets Held f or 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 2 007. Daily prices began

the year at $96.02 per barrel, peaked at $144.22 pe r barrel on 3 July 2008,

and fell to $36.55 per barrel at year-end. The shar p drop in prices was due to

falling demand in the second half of the year, caus ed by the OECD falling into

recession and the lagged effect on demand of high p rices in the first half of the

year. OPEC had increased production significantly t hrough the first three

quarters; and, as a result of falling consumption a nd rising OPEC production,

inventories rose. As prices continued to decline, O PEC responded with

successive announcements of production cuts in Sept ember, October, and

December.

Natural gas prices in the US and the UK i ncreased 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/mmB tu in July amid robust

demand and falling US gas imports, but fell to $6.9 0/mmBtu in December as

demand weakened and production remained strong. Ave rage UK gas prices

rose to 58.12 pence per therm at the National Balan cing 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 l ight products above fuel

oils remained high, reflecting a continuing shortag e of upgrading capacity and

the favouring of fully upgraded refineries over les s complex sites.

The retail environment continued to be ex tremely competitive in 2008

with market volatility, high absolute prices, as we ll as large price shifts in the

crude market.

In 2007, the average dated Brent price ro se 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, sustaine d consumption growth

and a resulting drop in commercial inventories afte r the summer.

Natural gas prices in the US and the UK d eclined in 2007. The Henry

Hub First of Month Index averaged $6.86/mmBtu, 5% l ower than the 2006

average of $7.24/mmBtu. Prices were pressured by st rong LNG imports in

summer, continued domestic production growth and hi gh 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 b arrel. The premium for

light products above fuel oils remained exceptional ly 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 averag ed 2,517mboe/d for

subsidiaries and 1,321mboe/d for equity accounted-e ntities, a decrease of

1.2% (a decrease of 3.1% for liquids and an increas e of 0.7% for gas) and an

increase of 4.0% (an increase of 2.5% for liquids a nd 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 majo r 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 a nd 1,269mboe/d for

equity-accounted entities, a decrease of 3% (3.5% f or liquids and 2.6% for

gas) and 2% (1.3% for liquids and 8.4% for gas) res pectively compared with

2006. In aggregate, the decrease primarily reflecte d 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 lo sses, net of tax, of

$4,436 million and a net charge for non-operating i tems, after tax, of

$796 million. In addition, fair value accounting ef fects 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-oper ating items and fair value

accounting effects can be found on page 51.

Profit attributable to BP shareholders fo r the year ended 31

December 2007 was $20,845 million, including invent ory holding gains, net of

tax, of $2,475 million and a net charge for non-ope rating items, after tax, of

$373 million ( see page 52 ). In addition, fair value accounting effects had a n unfavourable impact, net of tax, of $198 million ( see page 52 ) relative to

management’s measure of performance.

Profit attributable to BP shareholders fo r the year ended 31

December 2006 was $22,315 million, including invent ory holding losses, net of

tax, of $222 million and a net credit for non-opera ting 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 att ributable to BP

shareholders for the year ended 31 December 2006 in cluded a loss from

Innovene operations of $25 million. 

# Page 48 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm47

Performance review

The primary additional factors reflected in profit for 2008, compared with 2007,

were higher realizations, a higher contribution fro m the gas marketing and

trading business, improved oil supply and trading p erformance, improved

marketing performance and strong cost management; h owever, these positive

effects were partly offset by weaker refining margi ns, particularly in the US,

higher production taxes, higher depreciation, and a dverse foreign exchange

impacts.

The primary additional factors reflected in profit for 2007, compared with

2006, were higher liquids realizations, stronger re fining and marketing margins

and improved NGLs performance; however, these were more than offset by

lower gas realizations, lower reported production v olumes, higher production

taxes in Alaska, higher costs (primarily reflecting the impact of sector-specific

inflation and higher integrity spend), the impact o f outages and

recommissioning costs at the Texas City and Whiting refineries, reduced

supply optimization benefits and a lower contributi on 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 r esult of changes in such

factors as oil prices, natural gas prices and refin ing margins. Accordingly, the

results for the current and prior periods do not ne cessarily reflect trends, nor

do they provide indicators of results for future pe riods.

Employee numbers were approximately 92,00 0 at 31 December 2008,

98,100 at 31 December 2007 and 97,000 at 31 Decembe r 2006.

a Inventory holding gains and losses represent the differen ce between the cost of sales calculated using

the average cost to BP of supplies incurred during the yea r and the cost of sales calculated on the firstin first-out (FIFO) method including any changes in provi sions 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 e nergy markets, this can have a significant

distorting effect on reported income. The amounts disclo sed represent the difference between the

charge to the income statement on a FIFO basis (and any r elated 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 posi tion 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 a nd losses vary from period to period due

principally to changes in oil prices as well as changes to u nderlying 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 c omparisons of operating performance

between reporting periods, BP ’ s management believes it is helpful to disclose this inform ation. Capital expenditure and acquisitions

Capital expenditure and acquisitions in 2008, 2007 and 2006 amounted to

$30,700 million, $20,641 million and $17,231 millio n respectively. In 2008, this

included $4,731 million in respect of our transacti on with Husky Energy Inc.

and $3,667 million in respect of our purchase of al l Chesapeake Energy

Corporation’s interest in the Arkoma Basin Woodford Shale assets and the

purchase of a 25% interest in Chesapeake’s Fayettev ille Shale assets.

Acquisitions in 2007 included the remaining 31% of the Rotterdam (Nerefco)

refinery from Chevron’s Netherlands manufacturing c ompany. Excluding acquisitions and asset exchange s, capital expenditure for

2008 was $28,186 million compared with $19,194 mill ion 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 pe nsions and other

post-retirement benefits

Finance costs comprises group interest less amounts capitalized, and interest

accretion on provisions and long-term other payable s. Finance costs for

continuing operations in 2008 were $1,547 million c ompared with

$1,393 million in 2007 and $986 million in 2006. Th e increase in 2008, when

compared with 2007, is largely the outcome of reduc tions 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 a nd other post-retirement

benefits in 2008 was $591 million compared with $65 2 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 y ear increased, but this has

been offset in 2008 by higher interest costs reflec ting the increase in discount

rates applied to pension plan liabilities.

Taxation

The charge for corporate taxes for continuing opera tions in 2008 was

$12,617 million, compared with $10,442 million in 2 007 and $12,516 million in

2006. The effective rate was 37% in 2008, 33% in 20 07 and 36% in 2006. The

group earns income in many countries and, on averag e, 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 wi th 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 oth er 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 an d $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 

# Page 49 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmExploration and Production

48 Performance review

For the year ended 31 December $ million

2008 2007 2006

Total revenues a 89,902 69,376 71,868

Profit before interest and tax from continuing oper ations b 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 realizations c

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 realizations c

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 realizations c 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 realizations c

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 price e 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 subsidiaries d f 1,263 1,304 1,351

Total liquids production for equity

- accounted entities d f 1,138 1,110 1,124

million cubic feet per day

Natural gas production for subsidiaries f 7,277 7,222 7,412

Natural gas production for equity

- accounted entities f 1,057 921 1,005

thousand barrels of oil equivalent per day

Total production for subsidiaries f g 2,517 2,549 2,629

Total production for equity

- accounted entities f g 1,321 1,269 1,297

a Includes sales between businesses.

b Includes profit after interest and tax of equity-account ed entities.

c Realizations are based on sales of consolidated subsidiaries only, which excludes equity

- accounted entities.

d Crude oil and natural gas liquids.

e Henry Hub First of Month Index.

f Net of royalties.

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

# Page 50 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmTotal 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 inte rest 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 prima rily reflected higher oil and

gas realizations. Gas marketing sales also increase d primarily as a result of

higher prices. The decrease in 2007 compared with 2 006 primarily reflected

lower volumes of subsidiaries and lower gas marketi ng sales, partly offset by

higher realizations.

Profit before interest and tax for the ye ar ended 31 December 2008 was

$37,915 million. This included inventory holding lo sses 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 l osses on embedded

derivatives, partly offset by the reversal of certa in provisions. The impairment

charge includes a $517 million write-down of our in vestment 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 $2 82 million relative to

management’s measure of performance ( see page 52 ).

Profit before interest and tax for the ye ar ended 31 December 2007 was

$27,729 million. This included inventory holding ga ins 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 sal e of assets (primarily from

the disposal of our production and gas infrastructu re 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 ye ar ended 31 December 2006 was

$30,953 million. This included inventory holding lo sses 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 G ulf 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 e mbedded derivatives, partly

offset by a charge for legal provisions. In additio n, 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 3 7% increase in profit before

interest and tax for the year ended 31 December 200 8 compared with the year

ended 31 December 2007 was higher realizations. In addition, the result

reflected a higher contribution from the gas market ing and trading business

but was impacted by higher production taxes and hig her depreciation. The

impact of inflation within other costs was mitigate d 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 t he year ended 31

December 2006 were higher overall realizations (liq uids realizations were

higher and gas realizations were lower) and a favou rable effect from lagged

tax reference prices in TNK-BP; however, these fact ors were more than offset

by the impact of lower reported volumes, a lower co ntribution from the gas

marketing and trading business, higher production t axes in Alaska and higher

costs, reflecting the impacts of sector-specific in flation, 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 2,517mbo e/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, aft er adjusting for the effect

of lower entitlement in our PSAs, production was 5% higher than 2007. This

reflected strong performance from our existing asse ts, the continued ramp-up

of production following the startup of major projec ts in late-2007 and the startup of a further nine major projects in 2008.

Reported production for 2007 was 2,549mbo e/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 entitleme nt reductions in our PSAs. 

# Page 51 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmRefining and Marketing

Total revenues are explained in more detail below.

50 Performance review

$ million

2008 2007 2006

Total revenues a 320,458 250,897 232,833

Profit before interest and tax from continuing oper ations b (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 availability d 88.8 82.9 82.5

thousand barrels per day

Refinery throughputs 2,155 2,127 2,198

a Includes sales between businesses.

b Includes profit after interest and tax of equity

- accounted entities.

c The 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 investor s in analyzing trends in the industry and

their impact on our results. The margins are calculated b y BP based on published crude oil and product prices and take account of fuel utilization and catalyst costs. No accou nt is taken of BP’s other cash and noncash costs of refining, such as wages and salaries and plant d epreciation. The indicator margin may not be representa tive of the margins achieved by BP in any period because of BP’s particular refining configurations

and crude and product slate.

d Refining availability represents Solomon Associates’ oper ational availability, which is defined as the percentage of the year that a unit is available for processing afte r subtracting the annualized time lost due to

turnaround activity and all planned mechanical, process a nd 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), intere st, 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 comp ared with 2007 primarily

reflected an increase in marketing, spot and term s ales 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 wa s principally due to an

increase in marketing, spot and term sales of refin ed products. This was due

to higher prices and a positive foreign exchange im pact due to a weaker

dollar, partially offset by lower volumes. Addition ally, sales of crude oil, spot

and term contracts increased, primarily reflecting higher prices, and other

sales decreased due to lower volumes partially offs et 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 mi llion ( 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 favou rable impact of $511 million

relative to management’s measure of performance ( see page 52 ). Profit before interest and tax for the year ended 3 1 December 2007 was

$6,076 million. This included inventory holding gai ns 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 d isposal 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 impairme nt charges (primarily

related to the sale of the majority of our US Conve nience 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 T exas City refinery

incident. In addition, fair value accounting effect s had an unfavourable impact

of $357 million relative to management’s measure of performance ( see page

52 ).

Profit before interest and tax for the ye ar ended 31 December 2006 was

$5,419 million. This included inventory holding los ses 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 g ains (related primarily to

the sale of BP’s Czech Republic retail business, th e disposal of BP’s

shareholding in Zhenhai Refining and Chemicals Comp any, the sale of BP’s

shareholding in Eiffage, the French-based construct ion company, and

pipelines assets) and a charge related to the March 2005 Texas City refinery

incident. In addition, fair 

# Page 52 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm51

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 impr ovements 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 m arketing performance,

particularly from the International Businesses, and reduced costs. The cost

reductions have been driven by the simplification o f our business structure

through the establishment of Fuels Value Chains and a reduction in our

geographical footprint, as well as by strong cost m anagement. The most

significant environmental factor was the weaker ref ining environment,

particularly due to lower refining margins in the U S and the adverse impact in

the second half of 2008 of prior-month pricing of d omestic pipeline barrels for

our US refining system, but there were also adverse foreign exchange effects.

During 2007, the segment continued to foc us on the restoration of

operations at the Texas City refinery and on invest ments in integrity

management throughout our refining portfolio. We ha ve 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 reliabi lity and improved results

compared with 2006. However, for the full year, com pared with 2006, the

impact of the outages and recommissioning costs at the Texas City and

Whiting refineries, as well as investments in integ rity management and

scheduled turnarounds throughout our refining portf olio, cost inflation and

lower results from supply optimization decreased ou r result. These factors

more than offset increased margins in both refining and marketing.

The average refining Global Indicator Mar gin (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 percenta ge points higher than in

2007, the increase being driven primarily by improv ement at the Texas City

and Whiting refineries. Marketing volumes at 3,711m b/d were around 2.5%

lower than in 2007.

Other businesses and corporate

Other businesses and corporate comprises the Altern ative Energy business,

Shipping, the group’s aluminium asset, Treasury (wh ich includes all the

group’s cash, cash equivalents), and corporate acti vities worldwide.

The loss before interest and tax for the year ended 31 December 2008

was $1,258 million and included inventory holding l osses 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 l osses 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 gai ns 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 meaning ful and relevant to $ million

2008 2007 2006

Total revenues a 5,040 3,972 3,703

Profit (loss) before interest and tax from

continuing operations b (1,258 ) (1,233 ) (779 )

a Includes sales between businesses.

b Includes 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; rest ructuring, integration and

rationalization costs; and changes in the fair valu e of embedded derivatives.

These disclosures are provided in order to enable i nvestors better to

understand and evaluate the group’s financial perfo rmance. An analysis of

non-operating items is shown on page 52.

Non-GAAP information on fair value accounting effec ts

BP uses derivative instruments to manage the econom ic 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 con tracts are recorded at

historic cost and on an accruals basis respectively . The related derivative

instruments, however, are required to be recorded a t fair value with gains and

losses recognized in income because hedge accountin g is either not permitted

or not followed, principally due to the impractical ity of effectiveness testing

requirements. Therefore, measurement differences in relation to recognition of

gains and losses occur. Gains and losses on these i nventories 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 th e derivative commodity

contract is entered into on a fair value basis usin g forward prices consistent

with the contract maturity.

IFRS requires that inventory held for tra ding be recorded at its fair value

using period end spot prices whereas any related de rivative commodity

instruments are required to be recorded at values b ased on forward prices

consistent with the contract maturity. Depending on market conditions, these

forward prices can be either higher or lower than s pot prices resulting in

measurement differences.

BP enters into contracts for pipelines an d storage capacity that, under

IFRS, are recorded on an accruals basis. These cont racts are risk-managed

using a variety of derivative instruments that are fair valued under IFRS. This

results in measurement differences in relation to r ecognition of gains and

losses.

The way that BP manages the economic expo sures described above,

and measures performance internally, differs from t he way these activities are

measured under IFRS. BP calculates this difference by comparing the IFRS

result with management’s internal measure of perfor mance, under which the

inventory and the supply and capacity contracts in question are valued based

on fair value using relevant forward prices prevail ing 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 intern al measure of

performance, are shown in the table below and on th e 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 

# Page 53 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmNon-operating items

Fair value accounting effects

52 Performance review

$ million

2008 2007 2006

Exploration and Production

Impairment and gain (loss) on sale of businesses an d fixed assets (1,015 ) 857 2,410

Environmental and other provisions (12 ) (12) (17)

Restructuring, integration and rationalization cost s (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 an d fixed assets 801 (35 ) 726

Environmental and other provisions (64 ) (138 ) (33 )

Restructuring, integration and rationalization cost s (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 an d fixed assets (166 ) (14 ) 29

Environmental and other provisions (117 ) (35 ) 94

Restructuring, integration and rationalization cost s (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

Taxation a 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 pr evious period 107 155 123

Unrecognized (gains) losses carried forward (389 ) (107) (155)

Favourable (unfavourable) impact relative to manage ment ’ s measure of performance (282 ) 48 (32 )

Refining and Marketing

Unrecognized gains (losses) brought forward from pr evious period 429 72 283

Unrecognized (gains) losses carried forward 82 (429 ) (72 )

Favourable (unfavourable) impact relative to manage ment ’ s measure of performance 511 (357 ) 211

229 (309 ) 179

Taxation a (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

a The amounts shown for taxation are based upon the eff ective tax rate on group profit. 

# Page 54 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm53

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 wa ste pollution is

often not incurred as a separately identifiable tra nsaction.

Instead, it forms part of a larger transaction that includes, for

example, normal maintenance expenditure. The figure s for

environmental operating and capital expenditure in the table are

therefore estimates, based on the definitions and g uidelines of

the American Petroleum Institute.

Environmental operating expenditure of $7 55 million in

2008 was higher than in 2007 and reflects continuin g integrity

management activity. There were no individually sig nificant

factors driving the increase.

The increase in environmental operating e xpenditure in

2007 compared with 2006 is primarily due to increas ed integrity

management activity and activity associated with th e implementation of the Baker Panel recommendations. Similar

levels of operating and capital expenditures are ex pected in the

foreseeable future. In addition to operating and ca pital

expenditures, we also create provisions for future environmental

remediation. Expenditure against such provisions is normally in

subsequent periods and is not included in environme ntal

operating expenditure reported for such periods. Th e charge for

environmental remediation provisions in 2008 includ es $234 million resulting from a reassessment of exist ing site

obligations and $36 million in respect of provision s for new sites.

Provisions for environmental remediation are made when a

cleanup is probable and the amount of the obligatio n 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 inhe rently

difficult to estimate. They often depend on the ext ent of

contamination, and the associated impact and timing of the

corrective actions required, technological feasibil ity and BP’s

share of liability. Though the costs of future prog rammes could

be significant and may be material to the results o f 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 ev entual 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 underta ke periodic reviews of

existing provisions. These reviews take account of revised cost assumptions,

changes in decommissioning requirements and any tec hnological

developments. The level of increase in the decommis sioning 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 b y IAS 37 ‘Provisions,

Contingent Liabilities and Contingent Assets’.

Further details of decommissioning and en vironmental provisions

appear in Financial statements - Note 37 on page 15 6. See also Environment

on page 39.

Suppliers and contractors

Our processes are designed to enable us to choose s uppliers carefully on

merit, avoiding conflicts of interest and inappropr iate gifts and entertainment.

We expect suppliers to comply with legal requiremen ts and we seek to do

business with suppliers who act in line with BP’s c ommitments to compliance

and ethics, as outlined in the code of conduct. We engage with suppliers in a

variety of ways, including performance review meeti ngs 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 p ractice in respect of the

payment of trade creditors. In view of the internat ional nature of the group’s

operations there is no specific group-wide policy i n respect of payments to

suppliers. Relationships with suppliers are, howeve r, governed by the group’s

policy commitment to long-term relationships founde d on trust and mutual

advantage. Within this overall policy, individual o perating companies are

responsible for agreeing terms and conditions for t heir business transactions

and ensuring that suppliers are aware of the terms of payment. 

# Page 55 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Liquidity and capital resources

Cash flow

The following table summarizes the group’s cash flo ws.

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 a nd 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 y ear 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 pro fit before taxation of

$2,672 million and an increase in dividends from jo intly controlled entities and

associates of $1,255 million; these were partly off set 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 $2 8,172 million for the

equivalent period for 2006 reflecting an increase i n working capital

requirements of $6,282 million, a decrease in profi t before taxation from

continuing operations of $3,531 million, a decrease in dividends from jointly

controlled entities and associates of $2,022 millio n; these were partially offset

by a decrease in income taxes paid of $4,661 millio n, a lower net credit for

impairment and gains and losses on sale of business es and fixed assets of

$2,357 million and higher depreciation, depletion a nd 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 mi llion. The increase in 2007

reflected a reduction in disposal proceeds of $1,98 7 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 mi llion 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; th ese were partly offset by a

$4,546 million decrease in the net repurchase of sh ares. 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 lon g-term financing of

$4,278 million; these were partially offset by a ne t decrease in short-term debt

of $2,379 million.

The group has had significant levels of c apital 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 $1 5.7 billion in 2006. Sources

of funding are completely fungible, but the majorit y of the group’s funding

requirements for new investment come from cash gene rated 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 amounte d to $112 billion. The net

cash usage of $8 billion was financed by an increas e in finance debt of

$13 billion over the three-year period, offset by a n increase in our balance of

cash and cash equivalents of $5 billion. During thi s 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 s hares was $25 billion, which

includes $26 billion in respect of our share buybac k programme less net

proceeds from shares issued in connection with empl oyee 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 econ omy and oil demand on

the other. We expect continued volatility and our c urrent expectation is that oil

prices, relative to 2008, will continue to be low i n 2009, and that this could

extend into 2010.

In Exploration and Production, total prod uction is expected to be

somewhat higher in 2009. The actual growth rate wil l depend on a number of

factors, including our pace of capital spending, th e 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 expect ed to be a challenging

environment with reduced demand for our products, l eading to lower volumes

and pressure on margins. The impact is expected to be greatest in the

petrochemicals sector. In 2009, with our US refinin g system fully operational,

we expect our overall refining availability to be h igher 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 ) 

# Page 56 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm55

Performance review

During 2008, we established momentum in cost contro l, mitigating the cost

inflation that was primarily driven by rising oil p rices. In 2009, our highest

priority will continue to be achieving safe, compli ant and reliable operations

and we intend to continue our focus on cost efficie ncy. We expect cost

deflation to be increasingly visible as we move thr ough 2009.

We expect capital expenditure, excluding acquisitions and asset

exchanges, to be around $20-21 billion in 2009. Thi s reflects our intention in

Exploration and Production to maintain investment w hilst vigorously working to

drive down costs and to reduce spending in our Refi ning and Marketing and

Alternative Energy businesses in keeping with the c urrent weak economic

environment. We expect disposal proceeds to be betw een $2- 3 billion in 2009.

On the basis of our current plans, we exp ect cash inflows and outflows

in 2009 would balance at oil prices of around $60/b bl, taking account of

expected disposal proceeds. We would expect that br eak even point to lower

as we realize the benefits of our operational momen tum 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 st erling terms, the dividend

increased 40% due to the strengthening of the dolla r 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 rep urchased 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 repurch ased 4,929 million

shares at a cost of $51.1 billion.

Our aim is to strike the right balance fo r shareholders, between current

returns via the dividend, sustained investment for long-term growth, and

maintaining a prudent gearing level. At the beginni ng of 2008, we rebalanced

our distributions away from share buybacks in favou r of dividends.

BP intends to continue the operation of t he Dividend Reinvestment Plan

(DRIP) for shareholders who wish to receive their d ividend 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, d emand for refining products,

refining volumes and margins and impact on the petr ochemicals sector,

refining availability, continuing priority of safe, compliant and reliable

operations, and focus on cost efficiency, cost defl ation, capital expenditure,

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

working capital, guarantees, expected payments unde r contractual and

commercial commitments and purchase obligations. Th ese 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 s tatement under Forwardlooking statements on page 10 and Risk factors on p ages 8-10, which

describe the risks and uncertainties that may cause actual results and

developments to differ materially from those expres sed or implied by these

forward-looking statements. The company provides no commitment to update

the forward-looking statements or to publish financ ial projections for forwardlooking statements in the future. Financing the group ’ s activities

The group’s principal commodity, oil, is priced int ernationally in US dollars.

Group policy has been to minimize economic exposure to currency

movements by financing operations with US dollar de bt wherever possible,

otherwise by using currency swaps when funds have b een raised in

currencies other than US dollars.

The group’s finance debt is almost entire ly 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 te rm. Net debt was $25,041 million at the end o f 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 t o the lower end of our

target band. Net debt, which BP uses as a measure o f financial gearing,

includes the fair value of associated derivative fi nancial instruments that are

used to hedge foreign exchange and interest rate ri sks relating to finance

debt, for which hedge accounting is claimed.

The maturity profile and fixed/floating r ate characteristics of the group’s

debt are described in Financial statements – Note 2 8 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 m aturities 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 Eu rope are a primary source

of liquidity for the group. At 31 December 2008, th e outstanding commercial

paper amounted to $4,268 million (2007 $5,881 milli on).

The group also has access to significant sources of liquidity in the form

of committed facilities and other funding through t he capital markets. At 31

December 2008, the group had available undrawn comm itted borrowing

facilities of $4,950 million (2007 $4,950 million).

Despite current uncertainty in the financ ial 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 c ash and cash equivalents

held by the group to $8.2 billion at the end of 200 8, 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 h as sufficient working capital

for foreseeable requirements.

Off-balance sheet arrangements

At 31 December 2008, the group’s share of third-par ty 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 balanc e sheet.

The group has issued third-party guarante es under which amounts

outstanding at 31 December 2008 are summarized on t he following page.

Some guarantees outstanding are in respect of borro wings of jointly controlled

entities and associates noted above. The analysis b y time period indicates the

ultimate expiry of the guarantees. 

# Page 57 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmContractual 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 Financ ial statements – Note 16 on page 130.

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

The group expects its total capital expenditure, ex cluding acquisitions and asset exchanges to be arou nd $20- 21 billion in 2009. The following table summarizes the

group’s capital expenditure commitments for propert y, plant and equipment at 31 December 2008 and the proportion of that expenditure for which contracts have

been placed. Capital expenditure is considered to b e committed when the project has received the appro priate level of internal management approval. For j ointly

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 com mitted to capital expenditure relating to investmen ts in equity-accounted entities amounting to $1.2 b illion.

Contracts were in place for $0.8 billion of this to tal.

56 Performance review

$ million

Guarantees expiring by period

2014 and

Total 2009 2010 2011 2012 2013 thereafter

Guarantees issued in respect of a

Liabilities and borrowings of jointly controlled en tities and associates 223 70 32 25 6 6 84

Liabilities and borrowings of other third parties 613 94 19 30 35 34 401

a Of the amounts shown in the table, $215 million of th e jointly controlled entities and associates guarantees rel ate to guarantees of borrowings and for other third p arty 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

Borrowings a 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 leases b 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 benefits c 26,288 1,105 1,352 1,346 1,346 1,342 19,797

Purchase obligations d 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

a Expected payments include interest payments on borrowings to talling $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).

b The 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 wil l be reimbursed by joint venture partners. Where opera ting 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.

c Represents the expected future contributions to funded p ension plans and payments by the group for unfunded pensi on plans and the expected future payments for other post

- retirement benefits.

d Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies al l significant terms. The amounts shown include arrangemen ts 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 entere d 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 – No te 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 14,0 62 8,175 2,908 1,197 621 402 759 

# Page 58 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm57

Performance review



# Critical accounting policies

The significant accounting policies of the group ar e summarized in Financial

statements – Note 1 on page 106.

Inherent in the application of many of th e 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 accoun ting policies that could

have a significant impact on the results of the gro up and should be read in

conjunction with the Notes on financial statements.

The accounting policies and areas that re quire the most significant

judgements and estimates used in the preparation of the consolidated

financial statements are in relation to oil and nat ural gas accounting, including

the estimation of reserves, the recoverability of a sset carrying values, taxation,

derivative financial instruments, provisions and co ntingencies, 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 geophys ical seismic information, prior

to the discovery of proved reserves, is expensed as incurred.

Exploration licence and leasehold propert y acquisition costs are

capitalized within intangible assets and are review ed at each reporting date to

confirm that there is no indication that the carryi ng amount exceeds the

recoverable amount. This review includes confirming that exploration drilling is

still under way or firmly planned or that it has be en determined, or work is

under way to determine, that the discovery is econo mically viable based on a

range of technical and commercial considerations an d sufficient progress is

being made on establishing development plans and ti ming. If no future activity

is planned, the remaining balance of the licence an d 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-typ e 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 drilli ng effort. These costs

include employee remuneration, materials and fuel u sed, rig costs, delay

rentals and payments made to contractors. The deter mination 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. Exploratio n wells that discover

potentially economic quantities of oil and gas and are in areas where major

capital expenditure (e.g. offshore platform or a pi peline) would be required

before production could begin, and where the econom ic viability of that major

capital expenditure depends on the successful compl etion of further

exploration work in the area, remain capitalized on the balance sheet as long

as additional exploration appraisal work is under w ay or firmly planned.

It is not unusual to have exploration wel ls and exploratory-type

stratigraphic test wells remaining suspended on the balance sheet for several

years while additional appraisal drilling and seism ic work on the potential oil

and gas field is performed or while the optimum dev elopment plans and timing

are established. All such carried costs are subject to regular techn ical, commercial and

management review on at least an annual basis to co nfirm the continued

intent to develop, or otherwise extract value from, the discovery. Where this is

no longer the case, the costs are immediately expen sed.

Once a project is sanctioned for developm ent, the carrying values of

exploration licence and leasehold property acquisit ion costs and costs

associated with exploration wells and exploratory-t ype stratigraphic test wells,

are transferred to production assets within propert y, plant and equipment.

The capitalized exploration and developme nt costs for proved oil and

gas properties (which include the costs of drilling unsuccessful wells) are

amortized on the basis of oil-equivalent barrels th at are produced in a period

as a percentage of the estimated proved reserves. F ield development costs

subject to depreciation are expenditures incurred t o date, together with

approved future development expenditure required to develop reserves.

The estimated proved reserves used in the se unit-of-production

calculations vary with the nature of the capitalize d expenditure. The reserves

used in the calculation of the unit-of-production a mortization 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 esti mates are revised

downwards, earnings could be affected by higher dep reciation expense or an

immediate write-down of the property’s carrying val ue ( see discussion of

recoverability of asset carrying values on the foll owing page ).

At the end of 2006, BP adopted the SEC ru les for estimating reserves

instead of the UK accounting rules contained in the UK Statement of

Recommended Practice. These changes are explained i n Financial

statements – Note 10 on page 125.

The estimation of oil and natural gas res erves and BP’s process to

manage reserves bookings is described in Exploratio n and Production -

Reserves and production on page 14. As discussed on the following page, oil

and natural gas reserves have a direct impact on th e 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 n atural gas on pages 185

to 193. • Producing wells

– proved developed reserves.

• Licence and property acquisition, field development and future

decommissioning costs – total proved reserves. 

# Page 59 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm58

Performance review

Recoverability of asset carrying values

BP assesses its fixed assets, including goodwill, f or possible impairment if

there are events or changes in circumstances that i ndicate that carrying

values of the assets may not be recoverable and, as a result, charges for

impairment are recognized in the group’s results fr om time to time. Such

indicators include changes in the group’s business plans, changes in

commodity prices leading to unprofitable performanc e, low plant utilization,

evidence of physical damage and, for oil and gas pr operties, significant

downward revisions of estimated volumes or increase s in estimated future

development expenditure. If there are low oil price s, natural gas prices,

refining margins or marketing margins during an ext ended period, the group

may need to recognize significant impairment charge s. The assessment for impairment entails com paring the carrying value of

the cash-generating unit with its recoverable amoun t, 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 f lows.

Determination as to whether and how much an asset is impaired

involves management estimates on highly uncertain m atters such as future

commodity prices, the effects of inflation on opera ting expenses, discount

rates, production profiles and the outlook for glob al or regional market supplyand-demand conditions for crude oil, natural gas an d refined products.

For oil and natural gas properties, the e xpected future cash flows are

estimated based on the group’s plans to continue to develop and produce

proved reserves and associated risk-adjusted probab le and possible volumes.

Expected future cash flows from the sale or product ion 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 fut ure 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 B rent and $7.50/mmBtu for

Henry Hub (2007 $60 per barrel and $7.50/mmBtu). Th ese long- term planning

assumptions are subject to periodic review and modi fication. The estimated

future level of production is based on assumptions about future commodity

prices, lifting and development costs, field declin e rates, market demand and

supply, economic regulatory climates and other fact ors. The future cash flows are adjusted for ri sks 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 a ny specific risks relating to

the country where the cash-generating unit is locat ed. 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 informatio n. Irrespective of whether there is any indi cation of impairment, BP is

required to test annually for impairment of goodwil l acquired in a business

combination. The group carries goodwill of approxim ately $9.9 billion on its

balance sheet, principally relating to the Atlantic Richfield and Burmah Castrol

acquisitions. In testing goodwill for impairment, t he 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 im pairment charges. Taxation

The computation of the group’ s income tax expense involves the interpretation

of applicable tax laws and regulations in many juri sdictions 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 predi ct 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 exte nt that it is probable that

taxable profit will be available against which the unused tax losses can be

utilized. Management judgement is exercised in asse ssing whether this is the

case.

To the extent that actual outcomes differ from management’ s estimates,

taxation charges or credits may arise in future per iods. 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. I n addition, derivatives

embedded within other financial instruments or othe r host contracts are

treated as separate derivatives when their risks an d 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 der ivative 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 derivati ves are estimated using models

and other valuation methods due to the absence of q uoted prices or other

observable, market- corroborated data. In particular, this applies to t he majority

of the group’ s natural gas and LNG embedded derivatives. These a re primarily

long- term UK gas contracts that use pricing formulae not related to gas prices,

for example, oil product and power prices. These co ntracts are valued using

models with inputs that include price curves for ea ch of the different products

that are built up from active market pricing data a nd extrapolated to the expiry

of the contracts using the maximum available extern al 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 as sumptions could have a

material impact on the gains and losses on embedded derivatives recognized

in the income statement. For more information see F inancial 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 k ey assumptions is

provided in Financial statements - Note 28 on page 140. 

# Page 60 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm59

Performance review

Provisions and contingencies

The group holds provisions for the future decommiss ioning 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 arou nd the world. The estimated

discounted costs of dismantling and removing these facilities are accrued on

the installation of those facilities, reflecting ou r 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 pipelin e. 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 occu rs are uncertain. Asset

removal technologies and costs are constantly chang ing, as well as political,

environmental, safety and public expectations. Cons equently, the timing and

amounts of future cash flows are subject to signifi cant uncertainty. Changes in

the expected future costs are reflected in both the provision and the asset.

Decommissioning provisions associated wit h downstream and

petrochemicals facilities are generally not provide d for, as such potential

obligations cannot be measured, given their indeter minate settlement dates.

The group performs periodic reviews of its downstre am and petrochemicals

long-lived assets for any changes in facts and circ umstances that might

require the recognition of a decommissioning provis ion.

The timing and amount of future expenditu res 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 ra te represents the real

rate (i.e. adjusted for inflation) on long-dated go vernment bonds.

Other provisions and liabilities are reco gnized in the period when it

becomes probable that there will be a future outflo w of funds resulting from

past operations or events and the amount of cash ou tflow can be reliably

estimated. The timing of recognition requires the a pplication of judgement to

existing facts and circumstances, which can be subj ect to change. Since the

actual cash outflows can take place many years in t he 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 prov ision or liability would result in

a charge or credit to net income in the period in w hich 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, tec hnology, price levels and

expected plans for remediation. Actual costs and ca sh outflows can differ from

estimates because of changes in laws and regulation s, public expectations,

prices, discovery and analysis of site conditions a nd changes in clean-up

technology.

The provision for environmental liabiliti es is reviewed at least annually.

The interest rate used to determine the balance she et obligation at 31

December 2008 was 2%, the same rate as at the previ ous balance sheet date.

As further described in Financial stateme nts – Note 44 on page 172, the

group is subject to claims and actions. The facts a nd circumstances relating to

particular cases are evaluated regularly in determi ning whether it is ‘probable’

that there will be a future outflow of funds and, o nce established, whether a

provision relating to a specific litigation should be adjusted. Accordingly,

significant management judgement relating to contin gent liabilities is required,

since the outcome of litigation is difficult to pre dict. Pensions and other post-retirement benefits

Accounting for pensions and other post-retirement b enefits involves

judgement about uncertain events, including estimat ed 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 co untry. Determination of

the projected benefit obligations for the group’s d efined 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 fro m year to year, which

will affect future results of operations. Any diffe rences between these

assumptions and the actual outcome also affect futu re results of operations.

Pension and other post-retirement benefit assumptions are reviewed by

management at the end of each year. These assumptio ns are used to

determine the projected benefit obligation at the y ear-end and hence the

surpluses and deficits recorded on the group’s bala nce sheet, and pension

and other post-retirement benefit expense for the f ollowing year.

The pension and other post-retirement ben efit assumptions at 31

December 2008, 2007 and 2006 are provided in Financ ial statements – Note

38 on page 157.

The assumed rate of investment return, di scount rate and the US

healthcare cost trend rate have a significant effec t on the amounts reported. A

sensitivity analysis of the impact of changes in th ese assumptions on the

benefit expense and obligation is provided in Finan cial statements - Note 38

on page 157.

In addition to the financial assumptions, we regularly review the

demographic and mortality assumptions. Mortality as sumptions reflect best

practice in the countries in which we provide pensi ons and have been chosen

with regard to the latest available published table s adjusted where appropriate

to reflect the experience of the group and an extra polation of past longevity

improvements into the future. BP’s most substantial pension liabilities are in

the UK, US and Germany and the mortality assumption s for these countries

are detailed in Financial statements - Note 38 on p age 157. 

# Page 61 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### This page intentionally left blank.

60 

# Page 62 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Board performance

and biographies

62 Directors and senior management

65 BP board performance report Page 63 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Page 64 of 199

20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Directors and senior management

The following lists the company’s directors and sen ior management as at 18 February 2009.

Mr H L McKay, previously executive vice president ( special projects), was appointed chairman and presi dent 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 Apri l 2008. Mr G David was appointed a non-executive di rector

on 11 February 2008. At the company’s 2008 annual g eneral meeting (AGM), the following directors retir ed, offered themselves for election/re-election and were duly elected/re-elected: Mr A Burgmans; Mrs C B Car roll; 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 McKi llop; Sir Ian Prosser and Mr P D Sutherland.

Mr R Dudley has been appointed to the board with ef fect from 6 April 2009. All of the directors, inclu ding 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 Pensio n Trustees Limited and a member of the Listing Auth orities

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 M arketing) July 2004

Dr B E Grote Executive Director (Chief Financial Officer) August 2000

A G Inglis Executive Director (Chief Executive, Exploration an d 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 

# Page 65 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm63

Directors and senior management

Directors

P D Sutherland, SC, KCMG

Chairman of the chairman’s and the nomination commi ttees 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 appoi nted chairman in 1997.

He is non-executive chairman of Goldman Sachs Inter national and was a nonexecutive director of The Royal Bank of Scotland Gr oup PLC from 2001 to 6

February 2009.

Sir Ian Prosser

Member of the chairman’s, the nomination and the re muneration committees

and chairman of the audit committee

Sir Ian (65) joined BP’s board in 1997 and was appo inted non-executive

deputy chairman in 1999. He is the senior independe nt director. In 2003, he

retired as chairman of InterContinental Hotels Grou p PLC, a spin-off from the

former Bass PLC where he was chief executive.

He is a non-executive director and senior independe nt director of

GlaxoSmithKline plc, a non- executive director of the Sara Lee Corporation and

non-executive chairman of The Navy, Army and Air Fo rce Institutes (NAAFI).

He was previously on the boards of The Boots Compan y 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 chair man of Unilever NV and

vice chairman of Unilever PLC. In 2005, he became n on-executive chairman

of Unilever PLC and Unilever NV, retiring from thes e 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 env ironment 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 s he was appointed

president and chief executive officer of Alcan’s pr imary metals group and an

officer of Alcan, Inc. She was appointed as chief e xecutive 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 19 90 to 2004, he was chief

executive of Amersham plc and subsequently presiden t and chief executive

officer of GE Healthcare. He was appointed as a vic e chairman of the board of

GE in 2004, stepping down from this post in 2006 wh en he became chairman

of the Wellcome Trust. He remains a non-executive d irector 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 remuner ation committees

Erroll B Davis, Jr (64) joined BP’s board in 1998, having previously been a

director of Amoco. He was chairman and chief execut ive officer of Alliant

Energy, relinquishing this dual appointment in 2005 . He continued as

chairman of Alliant Energy until February 2006, lea ving 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 tr ained as a chartered

accountant and became a partner at KPMG in 1988. In 1995, he was

appointed group finance director of HSBC Holdings p lc. He was chairman of

the Financial Reporting Council’s review of the Tur nbull Guidance on Internal

Control. Between 2001 and 2004, he served on the Ac counting Standards

Board and the Standards Advisory Council of the Int ernational Accounting

Standards Board.

Dr D S Julius, CBE

Member of the chairman’s and the nomination committ ees and chairman of

the remuneration committee

DeAnne Julius (59) joined BP’s board in 2001. She b egan her career as a

project economist with the World Bank in Washington . From 1986 until 1997,

she held a succession of posts, including chief eco nomist 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 Eng land. 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 Zen eca Group PLC in

1999 until December 2005. He was a non-executive di rector 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 f rom 2006 to 3

February 2009.

Dr A B Hayward

Tony Hayward (51) joined BP in 1982. He held a seri es 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 p roduction 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 varie ty of roles in oil trading,

commercial refining, retail and commercial marketin g 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 exe cutive director in 2004. He

was appointed chief executive of refining and marke ting in June 2007. He is a

non-executive director and senior independent direc tor of Rolls-Royce Group

plc. 

# Page 66 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm64

Directors and senior management

Dr B E Grote

Byron Grote (60) joined BP in 1987 following the ac quisition of The Standard

Oil Company of Ohio, where he had worked since 1979 . He became group

treasurer in 1992 and in 1994 regional chief execut ive in Latin America. In

1999, he was appointed an executive vice president of exploration and

production, and chief executive of chemicals in 200 0. He was appointed an

executive director of BP in 2000 and chief financia l 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 vari ous North Sea projects.

Following a series of commercial roles in explorati on, in 1996 he became chief

of staff, exploration and production. From 1997 unt il 1999, he was responsible

for leading BP’s activities in the deepwater Gulf o f Mexico. In 1999, he was

appointed vice president of BP’s US western gas bus iness unit. In 2004, he

became executive vice president and deputy chief ex ecutive of exploration

and production. He was appointed chief executive of BP’s exploration and

production business and an executive director in Fe bruary 2007. He is a nonexecutive director of BAE Systems plc.

Senior management

R Bondy

Rupert Bondy (47) joined BP as group general counse l 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 fir m Lovells in London. In

1995, he joined SmithKline Beecham as senior counse l for mergers and

acquisitions and other corporate matters. He subseq uently held positions of

increasing responsibility and following the merger of SmithKline Beecham and

GlaxoWellcome he was appointed senior vice presiden t and general counsel

of GlaxoSmithKline in 2001.

S Bott

Sally Bott (59) joined BP in 2005 as an executive v ice president responsible

for global human resources. Sally joined Citibank i n 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 hu man resources director to

sectors of Citibank. In 1994, she joined Barclays D e 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 se ries 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 200 4, she was appointed an

executive vice president, responsible for gas, powe r and renewables in

addition to the supply and trading businesses. In l ate 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 preside nt of BP America, Inc.

from 1 February 2009. He joined Amoco Production Co mpany as a petroleum

engineer in 1980 and later served in a variety of o perating, commercial and

M&A roles. In 1993, he became general manager of Ar koma Basin and in

1997, the business unit leader for the Gulf of Mexi co Shelf. During 1998- 2000,

he worked on the BP-Amoco merger and served as gene ral manager for BP

p.l.c. worldwide exploration and production strateg y and planning. In 2000, he

became business unit leader for the Central North S ea in Aberdeen, and

subsequently chief of staff for worldwide explorati on 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 presiden t for Russia &

Kazakhstan, during which time he was appointed to t he 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 p resident 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 e arly 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 be fore being appointed as

group vice president for gas, power and renewables in 2002. In 2004, he

returned to exploration and production as group vic e president (technology

and functions). In 2005, he was appointed as senior group vice president of

safety and operations before becoming executive vic e president, safety and

operations in October 2007. He became chief operati ng 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 p ositions 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 a nd chief executive officer

of BP solar, and in 2004, group vice president of n atural gas liquids, power,

solar and renewables. In 2005, he was appointed gro up vice president of

alternative energy. He was appointed group chief of staff on 1 January 2008. 

# Page 67 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm65

BP board performance report



# BP board performance report

Letter from the chairman

I am once again pleased to introduce our board perf ormance report. The

report reviews the work of the board and its commit tees 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 sy stem of governance has

stood us in good stead. The strong set of principle s on which we base our

governance framework, which include clarity of role s, separation of powers,

independence and appropriate skills, remain valid t oday.

I have been encouraged from discussions w ith shareholders over time

that our approach to governance and the dialogue wh ich 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 cl imate have inevitably

triggered further debate about governance. This I w elcome. The framework of

governance does need to be kept under review and, w here necessary,

challenged by investors, regulators and companies t hemselves 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 beha lf of the company and

investors alike. I do not believe that our comply o r explain system is broken

and it is important for us that the principles-base d 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 withi n a clear framework.

The principles describe the role of the board, its processes, its relationship

with executive management and the main tasks and re quirements of the board

committees. The principles are available at

www.bp.com/corporategovernance

. In carrying out its work, the board focus es 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 oversigh t of risk.

The principles outline how the board dele gates its authority for

executive management of the company to the group ch ief executive, subject

to monitoring by the board and a clearly defined se t 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, ris k and the framework for

internal control.

Operating the principles

The group chief executive through the annual plan d escribes to the board how

the strategy is to be delivered, together with an a ssessment 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 r eview and discuss with the

board all strategic projects or developments and al l material matters currently

or prospectively affecting the company and its perf ormance. The principles are kept under review by t he board to ensure they remain

relevant and up to date.

Board activities in 2008

As outlined above, the board focuses on key areas i n carrying out its work.

Forward agendas are set to determine a high level w ork programme for the

board based on its core tasks (including dealing wi th 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 activi ties:

Strategy and Risk

The board undertook extensive discussions on strate gic options for the group,

including the future business and competitive envir onment, technology

developments, pricing and demand models and portfol io options. The

identification and management of group risks were r eviewed 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 r eview

While the audit committee reviewed project delivery performance, the board

undertook an annual review of the group’s project s anctioning process and

delegation of authority. The process and criteria f or each stage of a project

was discussed, together with examples of projects w ith different lead times

and complexities.

Business review

Business reviews were held with both segments (Expl oration and Production

and Refining and Marketing) and the finance and inf ormation technology and

services (IT&S) functions.

Global economic environment and energy markets

The board actively monitored developments in the gl obal energy markets and

economic environment. Issues considered included th e supply/demand

balance, the relationship between oil prices, energ y consumption and GDP

growth and turbulence in the financial markets.

Other areas

Other areas discussed by the board included interac tions with BP’ s partners in

TNK-BP, the results of a group-wide employee satisf action survey and the

findings of a report on BP’s reputation in the UK a nd US. The board also

received a presentation from the independent expert appointed to provide an

objective assessment of BP’s progress in implementi ng the recommendations

of the BP US Refineries Independent Safety Review P anel (the Panel).

The board is supported in its tasks by th e company secretary, who

reports to the chairman and has no executive functi ons. 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 

# Page 68 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm66

BP board performance report

The chairman and senior independent director

The principles require that neither the chairman no r deputy chairman be

employed as an executive of the group. During 2008, these posts were held

by Peter Sutherland and Sir Ian Prosser respectivel y. The chairman provides leadership of the b oard, acts as facilitator for

meetings and ensures that the governance framework of the board is

maintained and operated. The chairman also leads bo ard 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 boa rd’s senior independent

director and is available to shareholders where the re are issues that cannot be

addressed through normal channels.

The chairman and all the non-executive di rectors meet periodically

without the presence of executive management as the chairman ’s committee.

The performance of the chairman is evaluated each y ear, with the evaluation

discussion taking place when the chairman is not pr esent. 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, ex cluding the chairman,

comprise independent non-executive directors and th at the number of

directors to not normally exceed 16. The board is c omposed of the chairman,

nine non-executive and four executive directors.

The board considers that it is of an appr opriate size to govern BP, with

its directors possessing the relevant backgrounds a nd mix of experience,

knowledge and skills to maximize its effectiveness.

Board renewal and skills

The board remains actively engaged in orderly succe ssion planning for both

executive and non-executive directors and is assist ed in this task by the

nomination committee. The committee keeps under rev iew the composition,

skills and diversity of the board to ensure that it remains appropriate to the

tasks and work it undertakes. The nomination commit tee believes a breadth of

skills is required for the board to meet the demand s of a business with global

operations. These skills include deep operational, engineering, safety and

financial expertise, experience of leading industri al, 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 serv e on the basis of letters

of appointment. Executive directors of BP have serv ice contracts with the

company. Details of all payments to directors are d escribed in the directors’

remuneration report.

The service contracts of executive direct ors are expressed to expire at a

normal retirement age of 60 (subject to age discrim ination), while nonexecutive directors ordinarily retire at the AGM fo llowing their 70th birthday.

In accordance with BP’ s Articles of Association, directors are granted an

indemnity from the company in respect of liabilitie s 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 maint ained a directors’ and

officers’ liability insurance policy throughout 2008. During the year, a review of

the terms and nature of the policy was undertaken a nd has been renewed for

2009. Although their defence costs may be met, neit her the company’s

indemnity nor insurance provides cover in the event that the director is proved

to have acted fraudulently or dishonestly. Following recent chang es to company law, the

company is also permitted to advance costs to direc tors for their defence in

investigations or legal actions.

Director elections

New board directors are subject to election by shar eholders 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 b iography and a description

of the skills and experience that the company feels are relevant.

Voting levels at the 2008 AGM demonstrate d continued support for all

board directors.

Board independence

Non-executive directors are required by the princip les to be independent in

character and free from any business or other relat ionship that could

materially interfere with the exercise of their jud gement. The board has

determined that the non-executive directors who ser ved 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 te rm 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 l ong-term perspective on

BP’s business have provided and continue to provide a valuable contribution

to the board and the audit committee, which he chai rs. 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 aske d by the board to remain

in post until April 2010 in order that he may concl ude both the chairman’s

succession process and the identification and appoi ntment by the new

chairman of a senior independent director.

Mr Davis joined the board on the completi on of the Amoco merger in

December 1998. The board believes Mr Davis continue s to demonstrate his

independence. He is an active participant at the bo ard 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 appoi ntments in outside entities).

From 1 October 2008, there has been a req uirement that directors must

avoid a situation where they have, or can have, a d irect or indirect interest that

conflicts, or possibly may conflict, with the compa ny’s interests. Directors of

public companies may authorize conflicts and potent ial 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 a uthorization of these

conflicts by the board. These procedures allow for the imposition of limits or

conditions by the board when authorizing any confli ct, 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 sta nding item for

consideration by the board at its meetings. 

# Page 69 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm67

BP board performance report

Serving as a director

Induction

The induction of new board members is the responsib ility of the chairman,

who is assisted by the company secretary in this ta sk. All new directors

receive a full induction programme, including a ‘co re’ element covering the

principles and the legal and regulatory duties of d irectors. 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 strateg y 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 no n-executive directors taking

office, while the executive director programme is a rranged in the course of

their business activities.

Training and site visits

Directors and committee members receive briefings o n BP’s business, its

markets, operating environment and other key issues during their tenure as

directors to ensure they have the necessary skill a nd knowledge to perform

their duties effectively. Board members are also ke pt updated on legal and

regulatory developments that may impact their dutie s 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 h as enabled board members

to see a selection of BP’s businesses e.g. the Texa s 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 B P 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 invit ed to become nonexecutive directors of other companies and that suc h appointments can

broaden their knowledge and experience, to the bene fit of the individual and

the group. Executive directors are permitted to tak e up one external board

appointment, subject to the agreement of the chairm an and reported to the BP

board. Fees received for these external appointment s may be retained by the

executive director and are reported in the director s’ remuneration report.

Non-executive directors may serve on a nu mber of outside boards,

provided they continue to demonstrate the requisite commitment to discharge

their duties to BP effectively. The nomination comm ittee 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 i nconsistent with those

required by BP.

Board evaluation

The principles stipulate that the performance and e ffectiveness of the board,

including the work of its committees, should be eva luated annually. In 2008,

this evaluation was undertaken internally with the use of a questionnaire. The

questionnaire focused on areas including the conduc t of meetings, activities of

the board versus committees, monitoring and informa tion and board support

and built on the review of board operations and gov ernance that had taken

place in 2007. The main outcome of the evaluation w as a requirement for a

more systematic approach to ensure that the skills of the directors met the

changing demands of the business and the environmen t in which it operates. Engagement with shareholders

The board is accountable to shareholders for the pe rformance and activities of

the BP group and engages in regular dialogue to und erstand their views and

preferences. However, the board also recognizes tha t, 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 relati ng to the board, governance,

strategy and performance. The remuneration committe e chairman met with

larger shareholders to discuss executive director r emuneration.

The group chief executive, other executiv e directors and senior

management, company secretary’s office, investor re lations and other teams

within BP also engage with a range of shareholders on wider issues relating to

the group, including in particular its safety, oper ational and financial

performance. Presentations given by the group to th e investment community

are available to download from the ‘Investors’ sect ion of BP’s website, as are

speeches on topics of broad interest to shareholder s made by the group chief

executive and other senior members of the managemen t 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 procedura l issues) are taken by a

poll at the AGM, meaning that every vote cast -whet her by proxy or in person

at the meeting – is counted.

The chairman, board committee chairmen an d 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 l evels at the AGM increased

to 64%, compared with 61% in 2007. Last year was al so the first time that the

AGM was webcast. This will be repeated for the comp any’s forthcoming

meeting. The webcast, speeches and presentations gi ven 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 exe cutive 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 commit tees follow. In common with

the board, each committee has access to independent advice and counsel as

required and each is supported by the company secre tary’s office, which is

independent of the executive management of the grou p. 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 finan cial, international and

commercial expertise appropriate to fulfil the comm ittee’s duties.

During the year, Sir Ian Prosser (chairma n), 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 j oined in May 2008. The

secretary to the committee is David Pearl, deputy c ompany secretary of BP.

The board considers that Douglas Flint po ssesses the financial and

audit committee experience, as defined by the Combi ned Code guidance and

the SEC, and has nominated him as the audit committ ee’s financial expert. 

# Page 70 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm68

BP board performance report

Attendance

The audit committee met 13 times during 2008.

In addition to the above members, the committee inv ites the lead partner of

the external auditors (Ernst & Young), the group ch ief financial officer, the

general auditor (head of internal audit), the chief accounting officer and the

deputy chief financial officer to attend each meeti ng. Other senior

management attend on request to enable the committe e to discharge its

duties. The committee also holds private sessions d uring the year without the

presence of executive management.

Role and authority of the audit committee

The audit committee assists the board in carrying o ut its responsibilities in

relation to financial risk, internal controls, fina ncial and regulatory reporting

requirements and the broader observance of the ‘exe cutive limitations’ relating

to financial matters.

The main tasks and requirements for the a udit committee are set out in

the principles. The audit committee believes that t hese meet each of the tasks

and activities outlined by the Combined Code as fal ling 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 bus iness 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 ind ependent advice and counsel

when needed, on an unrestricted basis. Further supp ort is provided to the

committee by the company secretary’s office and dur ing 2008 external

specialist legal and regulatory advice was provided by Sullivan & Cromwell

LLP.

The wider board is kept informed of the a ctivities of the committee, and

any issues that have arisen, through the regular up date given by the audit

committee chair after each meeting.

Training and induction

BP provides an induction programme for new committe e members and

ongoing training to assist them in carrying out the ir duties. Elements of the

induction programme include familiarization with th e tasks and requirements of

the audit committee, an overview of the key financi al 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 a udit committee induction,

including private sessions with the lead external a udit partner and the general

auditor.

In 2008, the training programme for the a udit committee included

briefings on developments in financial reporting an d financial standards, a site

visit to BP’s UK trading operations and an external ly 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 financi al reports, including the

Annual Report and Accounts and Annual Report on For m 20-F, before

recommending their publication to the board.

Monitoring risk in the business

In 2008, the audit committee reviewed reports on ri sks, controls and

assurance for the BP business segments (Exploration and Production,

Refining and Marketing), together with alternative energy, information

technology and services, the proposed reorganizatio n of the group finance

function and BP’s trading function. The committee a lso reviewed BP’s longterm contractual commitments and the provisions mad e for environmental

remediation and decommissioning.

Internal controls

A joint meeting with the safety, ethics and environ ment assurance committee

was held to review the general auditor ’s report on internal controls and risk

management. A further joint meeting was held in ear ly 2009 to assist the

board in its assessment of the effectiveness of int ernal controls and risk

management in 2008.

The committee discussed key regulatory is sues during the year as part

of its standing agenda items, including the quarter ly 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 o f 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 a ll meetings of the audit

committee at the request of the committee chairman. Other external audit staff

are invited to attend meetings where their expertis e is relevant to the agenda

item, for example during business or technical revi ews. The committee held two private meetings d uring the year with the

external auditors without the presence of BP manage ment, in order to discuss

issues or concerns from either the committee or the auditors.

Performance of the external auditors is e valuated by the audit

committee each year, with particular scrutiny of th eir independence, objectivity

and viability. Independence is maintained through t he limiting of non-audit

services to tax and audit-related work that fall wi thin 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 th e 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 & You ng for both audit and

non-audit work have decreased in comparison to the previous year due to

improved audit efficiency, ongoing systems improvem ents 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 regu lation, a new lead audit

partner is appointed every five years and other sen ior 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 gro up.

The audit committee has considered both t he proposed fee structure

and the audit engagement terms for 2009 and has rec ommended to the board

that the reappointment of the external auditors be proposed to shareholders at

the 2009 AGM. 

# Page 71 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm69

BP board performance report

Internal audit

The general auditor attends each committee meeting at the invitation of the

audit committee chairman. With the retirement of th e general auditor in early

2008, a new general auditor was appointed following an externally facilitated

recruitment process.

During the year, the audit committee eval uated the performance of the

internal audit function and agreed to the proposed programme of work for the

year (being satisfied that it appropriately respond ed to the key risks facing the

company and that the function had adequate staff an d resources to complete

its work).

In 2008, the committee met once with the general auditor in a private

session without the presence of executive managemen t. In addition, the

general auditor met with the chairman of the commit tee from time to time

between meetings.

Fraud and employee concerns on financial matters

The audit committee received an annual certificatio n report from the group

compliance and ethics function, together with quart erly 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 p erformance through oneto-one interviews or questionnaires. The results ar e 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 add ition, the committee

considers performance during its private sessions t hroughout 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 re view, and consideration

was given to building on the training provided to m embers through site visits.

The audit committee plans to meet 13 time s during 2009.

Safety, ethics and environment assurance committee report

Membership

The committee consists solely of independent non-ex ecutive directors who

have been selected to provide a wide range of opera tional and international

expertise appropriate to fulfil the committee’s dut ies. Members of the safety, ethics and environment assur ance committee

(SEEAC) during 2008 were Antony Burgmans, Sir Willi am 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 se cretary).

Attendance

SEEAC met eight times during 2008.

In addition to the above members, each SEEAC meetin g is attended by the

lead partner of the external auditors (Ernst & Youn g) and the BP general

auditor (head of internal audit) on the invitation of the committee chairman.

The group chief executive also attends committee me etings as the executive

liaison with SEEAC: Dr Hayward attended all eight m eetings of the committee

in 2008. The committee holds private sessions witho ut 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 o ut 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 fro m Ernst & Young attend if

appropriate to a particular business or activity re view.

Like BP’s other board committees, SEEAC c an access independent

advice and counsel if it requires, on an unrestrict ed basis. The wider board is

kept informed of the activities of the committee an d any issues that have

arisen through the regular update given by the SEEA C chair after each

meeting.

Training and induction

Members of the committee receive ongoing training t o assist them in carrying

out their duties and an induction programme was pro vided 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 b riefings and several site

visits on becoming SEEAC chairman. These visits inc luded the Texas City

refinery, where progress in implementing the recomm endations of the Panel

was observed and to the North Sea ETAP platforms wh ere safety, operational

and environmental management on an offshore product ion facility were

reviewed.

Committee activities in 2008

The chart at the end of this section shows how SEEA C 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 executiv e.

• Reviewing material to be placed before shareholders that addresses

environmental, safety and ethical performance and m ake 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 re lates to non-financial

issues. 

# Page 72 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm70

BP board performance report

Safety and operations

The group operations risk committee (GORC) was form ed 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 mana gement 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 p rogress in implementing

the Panel recommendations, aimed at improving proce ss safety performance

at BP’ s five US refineries. Mr Wilson, who was a member o f the Panel, reports

to the chairman of SEEAC and is independently funde d through the company

secretary’s office.

Mr Wilson attended six meetings of the co mmittee during 2008 and a

private meeting with the committee during the year without the presence of

executive management. Topics discussed included a p resentation on his

detailed work plan and progress updates. In May 200 8, Mr Wilson published

his first annual report where he assessed BP’s prog ress against the 10 Panel

recommendations. The report noted that while signif icant 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 ref inery operations in

Rotterdam, and coal bed methane operations in Duran go, Colorado. In

addition, some members visited the BP solar manufac turing facilities in

Maryland and the group’s operations in Azerbaijan.

Other topics

Other topics reviewed by the committee during the y ear included business

continuity and crisis management, environmental req uirements for new

projects, results from a survey on safety culture i n 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 pe rformance and process.

In 2008, the review involved interviews with each c ommittee member, with the

results discussed at the committee’ s November meeting. Conclusions from the

evaluation included noting the helpful insight gain ed from site visits and the

value to the committee of the knowledge and experti se of the independent

expert in respect of safety in the US refineries. T he committee also reviewed

its forward agenda for 2009.

SEEAC plans to meet seven times during 20 09.

Remuneration committee report

Membership

The committee consists solely of non-executive dire ctors who are considered

by the board to be independent.

Members of the remuneration committee dur ing the year were Dr

DeAnne Julius (chairman), Erroll Davis, Jr, Sir Tom McKillop and Sir Ian

Prosser. The chairman of the board also attends mee tings 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, t he 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 

# Page 73 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm71

BP board performance report

Role and authority of the committee

The main tasks and requirements for the committee a re set out in the

principles and are:

Committee activities

The chairman’ s committee considered aspects of a number of strat egic issues

including the relationship with the company’s partn ers in TNK-BP. The

committee has reviewed with Dr Hayward the short- a nd long-term challenges

facing the group. Dr Hayward has kept the committee briefed on the

implementation of the forward agenda and its implic ations for the evolution of

the executive team and succession within the leader ship cadre. The

committee has also reviewed the steps taken by Dr H ayward to refine the

corporate culture and the values within BP. There h ave been active

discussions around the ‘tone from the top’.

The committee has reviewed the performanc e of the chairman and Dr

Hayward.

The chairman’s committee plans to meet fo ur 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 durin g the year were Peter

Sutherland (chairman), Dr DeAnne Julius, Sir Ian Pr osser and Dr Walter

Massey. Dr Massey remained a member of the nominati on committee during

the year after his retirement from the board to ass ist 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 a re set out in the

principles and are: • Evaluating the performance and effectiveness of the group chief executive;

• Reviewing the structure and effectiveness of the bu siness organization of

BP;

• Reviewing the systems for senior executive developm ent 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 chairma n 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 candidate s for appointment or

reappointment as directors.

• Identifying, evaluating and recommending candidates for appointment as

company secretary.

• Keeping under review the mix of knowledge, skills a nd experience of the

board to ensure the orderly succession of directors

.

• Reviewing the outside directorship/commitments of t he non

- executive

directors. Committee activities

During 2008 the primary work of the committee has b een 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 Indepe ndent Director, has chaired

the committee. The committee has been assisted in t his task by Dr Anna

Mann of MWM Consulting LLP. The committee has adopt ed a robust process.

Key strategic issues facing BP for the coming years were identified through

discussions with individual board members. From the se discussions a role

description was developed. This formed the basis of a worldwide search from

which in excess of 30 candidates emerged. This broa d group has been refined

and the process is continuing. The board has been r egularly briefed on the

work of the committee.

As part of the chairman selection process , potential candidates for nonexecutive directors roles have been revealed. The c ommittee will continue

actively to keep the skills of the board under revi ew and pursue its

refreshment. 

# Page 74 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmDirectors’ interests

The above figures indicate and include all the bene ficial and non-beneficial interests of each directo r of the company in shares of the company (or calcu lated

equivalents) that have been disclosed to the compan y under the Disclosure and Transparency Rules and C ompanies Acts 1985 or 2006 (as the case may be) as at

the applicable dates. The above figures do not incl ude share options granted or interests in performan ce shares that have yet to vest. Details of these a re set out in

full in the directors’ remuneration report on pages 79 and 80.

Executive directors are also deemed to ha ve an interest in such shares of the company held f rom 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 prefe rence 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 240,789 a 229,969 a 39,148

G David 9,000 b

– c

– E B Davis, Jr 73,185 b 70,602 b

– D J Flint 15,000 15,000

– Dr B E Grote 1,214,330 d 1,193,137 d 47,334

Dr A B Hayward 488,459 482,398 39,148

A G Inglis 226,175 e 224,006 e 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) 597,568 f 597,568 f

Dr W E Massey (retired 17 April 2008) 49,722 b 49,722 b

a Includes 44,158 shares held as ADSs at 31 December 2008 a nd 41,692 shares held as ADSs at 1 January 2008.

b Held as ADSs.

c On appointment at 11 February 2008.

d Held as ADSs, except for 94 shares held as ordinary shares.

e Includes 34,962 shares held as ADSs.

f Includes 25,368 shares held as ADSs. 

# Page 75 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Directors’ remuneration

report

74 Part 1 Summary

76 Part 2 Executive directors'

remuneration

82 Part 3 Non-executive directors'

remuneration Page 76 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Page 77 of 199

20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Directors’ remuneration report

74 

# Part 1 Summary

BP executives delivered a strong performance in a t urbulent environment

during 2008 and restored the group’s operations to a high standard after

several years of focused effort. We commend them fo r a job well done.

Key financial targets for the year were e xceeded, even after adjusting

for the effect of high oil prices during part of th e year. Safe and reliable

operations remained at the top of the agenda and ke y safety metrics and

milestones were achieved. The year’s results were e specially strong in

Exploration and Production, with the start-up of th e Thunder Horse platform

and excellent overall reserves replacement. Key tar gets 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 thi s 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 pl an (EDIP). This review

included financial measures such as earnings per sh are, returns on average

capital employed, free cash flow, operating measure s for both Exploration and

Production and Refining and Marketing, and non- financial measures for safety

and reputation. All measures were compared across c ompetitors and showed

BP firmly in the pack of the other European oil maj ors. The comparison of total

shareholder return (TSR) was less favourable to BP, partly due to exchange

rate movements and turbulence in the financial mark ets. After careful review,

the committee concluded that TSR alone was not a fa ir 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 opposit e.

Salaries were increased mid-2008 after ou r 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 n o 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 bas ed 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 perfor mance of their

respective businesses.

The EDIP share element will again provide the long-term component of

remuneration for the 2009-2011 period, with some sl ight modifications. First,

reflecting its recent growth, ConocoPhillips will b e 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 h alf on underlying

performance compared with this same peer group. BP’ s performance will be

compared on an interpolated basis relative to the p erformance of the other

five. As in previous years, shares will vest at 100 %, 70% and 35% for

performance equivalent to first, second and third r ank respectively and none

for fourth or fifth.

We remain committed to a remuneration pol icy and practice that aligns

with the long -term interests of shareholders and provides an app ropriate

reward for talented and committed executives. In th e current volatile climate,

executive leadership is more important than ever. T he committee will continue

to use careful and rigorous judgement in assessing performance, and to

communicate our assessment in a clear way to shareh olders.

Dr DeAnne S Julius

Chairman, Remuneration Committee

24 February 2009 

# Page 78 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmSummary of remuneration of executive directors in 2 008 a

Amounts shown are in the currency received by executive directo rs. Annual bonuses are shown in the year they were ea rned.

75 Directors ’ remuneration report

Annual remuneration Long

- term remuneration

Share element of EDIP b

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 Actual c maximum

(thousand) (thousand) (thousand) (thousand) shares Value shares Value d performance

2007 2008 2007 2008 2007 2008 2007 2008 vested (thousand) vested (thousand) shares e

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 80,231 f $603 581,748

A G Inglis £ 556 £ 670 £ 800 £ 1,173 £ 188 £ 212 g £ 1,544 £ 2,055 0 0 54,994 £ 279 578,376

Directors leaving the board in 2008

Dr D C Allen h £ 500 £ 128 £ 539 £ 163 £ 13 £ 3 £ 1,052 £ 294 0 0 34,518 £ 175 n/a

a This information has been subject to audit.

b Or equivalent plans in which the individual participate d prior to joining the board.

c Includes shares representing reinvested dividends received on the shares that vested at the end of the performance period.

d Based on market price on vesting date (£5.08 per share/$4 5.13 per ADS).

e Maximum potential shares that could vest at the end of th e three

- year period depending on performance.

f Dr Grote holds shares in the form of ADSs. The above num ber reflects calculated equivalent in ordinary shares.

g This amount includes costs of London accommodation provide d to Mr Inglis. In addition, under a tax equalization arrangement, BP also discharged a US tax liability ar ising on his participation in the UK pension scheme

amounting to $553,175.

h Dr 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 £56 1,000 for Dr Hayward,

£264,000 for Mr Conn, $868,000 for Dr Grote and £32 6,000 for Mr Inglis.

This graph shows the growth in value of a hypotheti cal £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 hy pothetical £100 holdings at

the end of the five-year period were £144.36 and £1 15.05 respectively. Remuneration of non-executive directors in 2008 a

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 recommendatio n from the

remuneration committee and, for the non-executive d irectors, it would be

based on a recommendation from the chairman.

This process was adopted in 2008 and reco mmendations were made.

However, the chairman and the non-executive directo rs informed the board

that, in the current economic circumstances, they d id not wish to receive any

increase in remuneration for 2009. The board accord ingly maintained the fees

at the 2008 level for 2009 save that no committee m embership fee would in

future be paid to members of the nomination committ ee. £ thousand

2007 2008

A Burgmans 86 90

Sir William Castell 87 108

C B Carroll 43 93

G David b 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 Massey c 133 90

a This information has been subject to audit.

b Appointed on 11 February 2008.

c Also received a superannuation gratuity of £ 23,000. 

# Page 79 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm76

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 per sonal performance. Dr

Hayward’s salary was increased 10% to £1,045,000, a nd 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 be ginning 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 (EBI TDA), cash costs, cash flow,

return on average capital employed (ROACE) and capi tal expenditure. The

remaining portion was weighted 25% on safety, 25% o n people and 20% on

individual performance, principally operating resul ts and leadership.

Overall performance for 2008 was very str ong and is more fully set out

in other parts of this report. Financial results ex ceeded targets for EBITDA,

free cash flow and returns on average capital emplo yed, even after adjusting

for the high oil prices for part of the year. Cash costs were managed below

target, and capital expenditure within expected lev els.

Operationally, the upstream business had an excellent year, replacing a

high proportion of proved reserves, exceeding its p roduction target and

successfully starting up the important Thunder Hors e 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 it s 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 pr ogress on OMS

implementation, was assessed as satisfactory by the safety, ethics and

environment assurance committee (SEEAC). On the peo ple front, significant

progress was made in reducing complexity and embedd ing a performance

culture throughout the group.

Annual bonus results for 2008 reflect thi s overall strong performance

and committed leadership and are set out in the tab le on page 75.

2006-2008 share element result

Performance for the share element is assessed relat ive to the TSR of the

company compared with the other oil majors – ExxonM obil, Shell, Total and

Chevron. Recognizing the inherent imperfections in a TSR ranking, the EDIP

rules give the committee power to adjust (upwards o r 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 comp rehensive review of

BP’s long-term performance, with the aims of temper ing anomalies created by

relying solely on a formula-based approach.

For the 2006-2008 plan, BP was fifth rela tive to the other majors in

terms of TSR when calculated on a common currency ( US dollar) basis as

originally anticipated. However, unusually large cu rrency 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 wer e 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 sha re growth, ROACE, free

cash flow, net income), operating measures (product ion, reserves

replacement and Refining and Marketing profitabilit y), and non-financial

measures (health, safety and environmental and repu tation). Again, the

performance of the European comparators was quite s imilar: BP led the group

on some measures (notably free cash flow and reserv es replacement) but

lagged on Refining and Marketing profitability. The committee concluded that the TSR result, by its elf, was not a fair

reflection of BP’s relative underlying performance over the period. After

thorough consideration, the committee determined th at 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 t o the clustering of results,

as anticipated in the EDIP rules approved by shareh olders in 2005.

In accordance with its powers under the E DIP rules, the committee also

determined that, as there was clear evidence of a p rogressive turnaround of

performance over the final 18 months of the perform ance 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 a ppointment as an executive

director under the MTPP (medium term performance pl an) that is the

comparable plan to the EDIP. Vesting conditions wer e the same as for the

EDIP for Mr Inglis but, unlike the EDIP, the MTPP d oes 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 foc used on sustaining BP’s

financial, strategic and organizational health. Per formance 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 aim s 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 achi eve 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 r emuneration committee

reviews this structure regularly to ensure it is ac hieving its aims. In 2008, over

three-quarters of executive directors’ total potent ial remuneration was

performance related. The same will be true for tota l potential remuneration in

2009. • The majority of executive remuneration will be link ed 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 overa ll amount of each

component of remuneration, taking into account the success of BP and the

competitive environment.

• There will be a quantitative and qualitative assess ment of performance, with

the remuneration committee making an informed judge ment within a

framework approved by shareholders.

• Remuneration policy and practice will be as transp arent as possible.

• Executives will develop a significant personal shar eholding in order to align

their interests with those of shareholders.

• Pay and employment conditions elsewhere in the grou p will be taken into

account, especially in setting annual salary increa ses.

• The remuneration policy for executive directors wi ll 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 un derstand shareholder

preferences. 

# Page 80 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm77

Directors ’ remuneration report

Salary

The remuneration committee normally reviews salarie s annually, taking into

account other large Europe- based global companies and companies in the US

oil and gas sector. These groups are each defined a nd analyzed by the

committee’ s independent remuneration advisers. For 2009, the committee has

agreed with the group chief executive’s view that s alaries should be frozen at

their current level.

Annual bonus

All executive directors are eligible to take part i n 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 substantiall y exceeding

performance targets will continue to be 150% of bas e salary.

The group chief executive’s and group chi ef financial officer’s bonus will

be determined on group results as follows:

For the chief executive of Exploration and Producti on, 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 respe ctive businesses as

measured by key metrics and milestones set out in t he annual plan. For

Exploration and Production, these include productio n costs and reserves

replacement as well as safety and new opportunities . For Refining and

Marketing, they include refining availability, earn ings and cash costs, as well

as safety and work simplification.

The remuneration committee will also revi ew carefully the underlying

performance of the group in light of company busine ss plans and will look at

competitors’ results, analysts’ reports and the vie ws of the chairmen of other

BP board committees when assessing results.

In exceptional circumstances, the remuner ation committee can decide

to award bonuses moderately above the maximum level . The committee can

also decide to reduce bonuses where this is warrant ed 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 a lso to be accountable

and transparent in our decisions. Any significant e xercise of discretion will be

explained in the subsequent directors’ remuneration report.

Long-term incentives

Each executive director participates in the EDIP. I t has three elements:

shares, share options and cash. The remuneration co mmittee 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 perfor mance shares under the

EDIP, barring unforeseen circumstances, until it ex pires 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 c ash flow.

• Production and reserves replacement.

• Refining availability and earnings/barrel.

• Installed wind capacity.

• 15% on safety performance, including satisfactory a nd improving key metrics

as well as progress on OMS implementation.

• 15% on people, including behaviour, culture and val ues. Policy for performance share awards

The remuneration committee can award shares to exec utive 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 committ ee 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. Tog ether with the performance

period, this gives executive directors a six-year i ncentive 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 rece ive additional shares

representing the value of the reinvested dividends.

The committee’s policy continues to be th at each executive director

build a significant personal shareholding, with a t arget 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 i s reflected in the terms of

the performance shares under the EDIP, as shares ve sted 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 elemen t will be somewhat

modified from previous years. First, the peer group of oil majors against which

we compare will be increased to include ConocoPhill ips as well as

ExxonMobil, Shell, Total and Chevron as previously. This change reflects

ConocoPhillips’ significant growth over the last fe w years, providing it with

similar scale and global reach to the other oil maj ors. Second, vesting of the shares will be bas ed 50% on total shareholder

return (TSR) versus the competitor group and 50% on a balanced scorecard

of underlying performance versus the same competito rs. The underlying

performance will be assessed on three measures refl ecting key priorities in

BP’s strategy – in Exploration and Production, hydrocarbon producti on 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 improvem ent are key strategic

objectives for the group and this inclusion aligns key measures with both

executive director priorities as well as key driver s of value for shareholders.

Group increase in underlying net income acts as a h olistic measure of success

reflecting revenues, costs and complexity as well a s safe and reliable

operations. 

# Page 81 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmPensions a

78 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 benefit c accrued benefit c contributions made by

31 Dec 2008 at 31 Dec 2008 31 Dec 2008 b 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

a This information has been subject to audit.

b Additional pension earned during the year includes an i nflation increase of 4.0% for UK directors and 5.8% for US directors.

c Transfer values have been calculated in accordance with vers ion 8.1 of guidance note GN11 issued by the actuarial p rofession.

d Dr D C Allen retired on 31 March 2008 and commuted pa rt of his pension for a lump sum. The figures above make no allowance for the payment of this lump sum. If allow ance is made (in line with the strict

requirements of the regulations), and the transfer valu e at the end of the year is based on the pension in p ayment at that time, then the transfer value at 31 D ecember 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 fi ve other oil majors to

determine the overall vesting result. The methodolo gy 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 p erformance of the other

five. For performance between second and third or f irst 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 equi valent to first, second

and third rank respectively and none for fourth or fifth place. The three

underlying measures will be averaged to form the ba lanced scorecard

component.

The committee considers that this combination of measures provides a

good balance of external as well as internal metric s reflecting both

shareholder value and operating priorities. As in p revious years, the

committee will exercise its discretion, in a reason able and informed manner to

adjust vesting levels upwards or downwards if it co ncludes the above

quantitative approach does not reflect the true und erlying health and

performance of BP’s business relative to its peers. It will explain any

adjustments in the next directors’ remuneration rep ort 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. Additiona l 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. Th ey 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 integra ted with state pension

benefits.

The rules of the BP Pension Scheme were a mended in 2006 such that

the normal retirement age is 65. Prior to 1 Decembe r 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 servi ce as

at 1 December 2006. Pension benefits in excess of the individual lifeti me allowance set by

legislation are paid via an unapproved, unfunded pe nsion arrangement

provided directly by the company.

Although Mr Inglis is, like other UK dire ctors, a member of the BP

Pension Scheme, he is currently based in Houston, U S. 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 lia bility under a tax

equalization arrangement in respect of the period s ince Mr Inglis became a

director in February 2007, amounting to $553,175.

US directors

Dr Grote participates in the US BP Retirement Accum ulation Plan (US plan),

which features a cash balance formula. Pension bene fits are provided through

a combination of tax-qualified and non-qualified be nefit restoration plans,

consistent with US tax regulations as applicable.

The Supplemental Executive Retirement Ben efit (supplemental plan) is

a non-qualified top-up arrangement that became effe ctive on 1 January 2002

for US employees above a specified salary level. Th e benefit formula is 1.3%

of final average earnings, which comprise base sala ry and bonus in

accordance with standard US practice (and as specif ied under the qualified

arrangement), multiplied by years of service. There is an offset for benefits

payable under all other BP qualified and non-qualif ied pension arrangements.

This benefit is unfunded and therefore paid from co rporate 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 saving s plans applying in their

home countries. Benefits in kind are not pensionabl e. Expatriates may receive

a resettlement allowance for a limited period.

As Mr Inglis is currently based in Housto n, US, BP provides

accommodation in London. 

# Page 82 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmShare element of EDIP a

79

Directors ’ remuneration report

Share element interests Interests vested in 2008 and 2009

Market price Potential maximum performance shares b

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 vested c 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

- 2011 d 13 Feb 2008 5.61

– 133,452 133,452

– – –

2008

- 2013 d 13 Feb 2008 5.61

– 133,452 133,452

– – –

Dr B E Grote e 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

- 2011 d 13 Feb 2008 5.61

– 133,452 133,452

– – – 2008

- 2013 d 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

a This information has been subject to audit. Includes equi valent plans in which the individual participated prior to joining the board.

b BP ’ 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 Chevr on. Each performance period

ends on 31 December of the third year.

c Represents awards of shares made at the end of the releva nt performance period based on performance achieved unde r rules of the plan and includes reinvested dividends on the shares awarded.

d Restricted award under share element of EDIP. As report ed 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 o f 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 com pany.

e Dr Grote receives awards in the form of ADSs. The above n umbers reflect calculated equivalents in ordinary shares. 

# Page 83 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmShare options a

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 a nd $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 exer cise 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 £4.72 b 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 Grote c 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 £ 3.50 d 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

– – 37,000 e £ 5.99 15 May 2003 15 May 2010

EXEC 87,950

– – 87,950 e £ 5.67 23 Feb 2004 23 Feb 2011

EXEC 175,000

– – 175,000 e £ 5.72 18 Feb 2005 18 Feb 2012

EDIP 220,000

– – 220,000 e £ 3.88 17 Feb 2004 17 Feb 2010

EDIP 275,000

– – 275,000 e £ 4.22 25 Feb 2005 25 Feb 2011

a This information has been subject to audit.

b Closing market price for information. Shares were reta ined when exercised.

c Numbers shown are ADSs under option. One ADS is equival ent to six ordinary shares.

d Options exercised on 21 January 2009 and the shares were retained by Mr Inglis. Closing market price for informat ion on that date was £ 4.86.

e On leaving the board on 31 March 2008. 

# Page 84 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm81

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 pa yment in lieu of notice

equivalent to one year’s salary or the amount of sa lary that would have been

paid if the contract had been terminated on the exp iry 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 Exploratio n (Alaska) Inc. He is seconded

to BP p.l.c. under a secondment agreement of 7 Augu st 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 compens ation 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 cau se (or under a specific

termination payment provision), the relevant direct or’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 appropria te. 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 accorda nce with his contractual

entitlement, as well as a pro rata bonus for 2008 a nd continued full

participation in the 2006-08 and 2007-09 share elem ents, 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 co mpany. Each executive

director is permitted to accept one non-executive a ppointment, from which

they may retain any fee. External appointments are subject to agreement by

the chairman and reported to the board. Any externa l appointment must not

conflict with a director’s duties and commitments t o 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 dir ectors for external

appointments were as follows:

Executive director

Remuneration committee

All the members of the committee are independent no n-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 w ho 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 e xecutive directors and to

report on these to the shareholders.

• To determine, on behalf of the board, matters of po licy over which the

company has authority regarding the establishment o r operation of the

company’s pension scheme of which the executive dir ectors 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 c hief executive in

remunerating senior executives other than executive directors to ensure

alignment and proportionality.

• To recommend to the board the quantum and structur e of remuneration for

the chairman. 

# Page 85 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm82

Directors ’ remuneration report

Constitution and operation

Each member of the remuneration committee is subjec t to annual re-election

as a director of the company. The board considers a ll 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 committe e meetings.

The committee is accountable to sharehold ers through its annual report

on executive directors’ remuneration. It will consi der the outcome of the vote

at the AGM on the directors’ remuneration report an d take into account the

views of shareholders in its future decisions. The committee values its

dialogue with major shareholders on remuneration ma tters.

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 th e committee’s secretary

and independent adviser. Advice was also received f rom Mr Jackson, the

company secretary.

The committee also appoints external advi sers to provide specialist

advice and services on particular remuneration matt ers. The independence of

the advice is subject to annual review.

In 2008, the committee continued to engag e Towers Perrin as its

principal external adviser. Towers Perrin also prov ided limited ad hoc

remuneration and benefits advice to parts of the gr oup, principally changes in

employee share plans and some market information on pay structures.

Freshfields Bruckhaus Deringer LLP provid ed legal advice on specific

matters to the committee, as well as providing some legal advice to the group.

Ernst & Young reviewed the calculations o n 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 descr ibed 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 de termines that

remuneration was reviewed during the year with the result that:

The above changes came into effect for the 2008 rev iew 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 remuner ation committee

would then make a recommendation to the board but t he chairman would not

vote on his own remuneration; and

• The quantum and structure of non-executive directo r remuneration would be

reviewed by the chairman, with support and analysis provided by the

company secretary. The chairman would then make a r ecommendation to

the board but non-executive directors would not vot e on their own

remuneration.

• Within the limits set by the shareholders from time to time, remuneration

should be sufficient to attract, motivate and retai n world-class non-executive

talent.

• Remuneration of non

- executive directors is set by the board and should be

proportional to their contribution towards the inte rests of the company.

• Remuneration practice should be consistent with rec ognized best

- practice

standards for non-executive directors’ remuneration

.

• Remuneration should be in the form of cash fees, p ayable monthly.

• Non

- executive directors should not receive share option s from the company.

• Non-executive directors should be encouraged to es tablish a holding in BP

shares broadly related to one year’s base fee, to b e held directly or indirectly

in a manner compatible with their personal investme nt activities, and any

applicable legal and regulatory requirements.

£ thousand

Fee level

Chairman a 600

Deputy chairman b 120

Board member 75

Audit committee and SEEAC chairmanship fees c 30

Remuneration committee chairmanship fee c 20

Transatlantic attendance allowance 5

Committee membership fee d 5

a The chairman remains ineligible for committee chairman ship and membership fees or transatlantic

attendance allowance, but has the use of a fully maintai ned office for company business, a chauffeured

car and security advice.

b The role of deputy chairman is combined with that of se nior independent director. The deputy chairman

is still eligible for committee chairmanship fees and tra nsatlantic attendance allowance plus any

committee membership fees.

c Committee chairmen do not receive an additional member ship fee for the committee they chair.

d For members of the audit, SEEAC and remuneration comm ittees. 

# Page 86 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm83

Directors ’ remuneration report

Remuneration of non-executive directors in 2008 a

No share or share option awards were made to any no n-executive director in

respect of service on the board during 2008.

Non-executive directors have letters of a ppointment, which recognize

that, subject to the Articles of Association, their service is at the discretion of

shareholders. All directors stand for re-election a t each AGM.

Review of chairman and non-executive director remun eration

The new process for the determination of non-execut ive remuneration, as

described earlier, was operated during the year and recommendations were

made. However, the chairman and the non-executive d irectors informed the

board that, in the current economic circumstances, they did not wish to receive

any increase in remuneration for the coming year 20 09.

The board, therefore, decided after revie w 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 o f 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 gra tuity. The board was, and

continues to be, authorized to make such payments u nder the company’s

Articles of Association and the amount of the payme nt 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 wit h 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 paym ent was in line with the

policy arrangements agreed in 2002 and outlined abo ve. £ thousand

2007 2008

A Burgmans 86 90

Sir William Castell 87 108

C B Carroll 43 93

G David b 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 Massey c 133 90

a This information has been subject to audit.

b Appointed on 11 February 2008.

c Also 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-execu tive directors of Amoco

Corporation have residual entitlements under the Am oco Non-Employee

Directors’ Restricted Stock Plan. Directors were al located restricted stock in

remuneration for their service on the board of Amoc o Corporation prior to its

merger with BP in 1998. On merger, interests in Amo co shares in the plan

were converted into interests in BP ADSs. The restr icted 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 furt her entitlements have

accrued to any director under the plan. The residua l interests, as interests in a

long-term incentive scheme, are set out in the tabl e below, in accordance with

the Directors’ Remuneration Report Regulations 2002

.

Past directors

Mr Miles (who was a non-executive director of BP un til 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-ex ecutive director of BP in

April 2008) remained a member of the nomination com mittee during the year

to assist in the search for a successor to BP’s cha irman. Dr Massey received

a total fee of £15,000 for this role in 2008. Dr Ma ssey was also appointed to

the BP America board in April 2008 for a term of tw o 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, o n 24 February 2009. Interest in BP ADSs Date on

at 1 Jan 2008 and which director

31 Dec 2008 a reaches age 70 b

E B Davis, Jr 4,490 5 Aug 2014

Director leaving the board in 2008

Dr W E Massey c 3,346 5 April 2008

a No awards were granted and no awards lapsed during the year. The awards were granted over Amoco

stock prior to the merger but their notional weighted average market value at the date of grant (applying

the subsequent merger ratio of 0.66167 of a BP ADS fo r every Amoco share) was $27.87 per BP ADS.

b For the purposes of the regulations, the date on whi ch the director retires from the board at or after the

age of 70 is the end of the qualifying period. If th e director retires prior to this date, the board may wa ive

the restrictions.

c Dr 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 t o the merger. These interests had been converted

into BP ADSs at the time of the merger. In accordance w ith the terms of the plan, the board exercised

its discretion over this award on 16 May 2008 and the sha res vested on that date (when the BP ADS

market price was $74.57) without payment by him. 

# Page 87 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### This page intentionally left blank.

84 

# Page 88 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 Page 89 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 2 5 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 opt ion schemes for ordinary shares or their calculated equivalent

as set out below:

There are no directors or members of senior managem ent who own more than 1% of the ordinary shares out standing. At 18 February 2009, all directors and se nior

management as a group held interests in 4,308,712 o rdinary shares or their calculated equivalent, 11,1 63,994 performance shares or their calculated equiv alent

and 3,281,964 options for ordinary shares or their calculated equivalent under the BP group share opti ons 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 gr anted.

86 I C Conn 279,937 1,815,940 a 266,904 c

Dr B E Grote 1,261,664 2,066,316 a

– Dr A B Hayward 527,607 2,734,170 a

– A G Inglis 255,424 1,759,435 a b 266,904 c

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 – –

a Performance shares awarded under the BP Executive Director s Incentive Plan. These figures represent the maximum possib le vesting levels. The actual number of shares/ADSs that vest will depend on the extent to

which performance conditions have been satisfied over a thr ee-year period.

b Also includes 325,750 performance shares awarded under th e BP Medium Term Performance Plan, which represents the maximum possible vesting level. The actual number of shar es that vest will depend on the

extent to which performance conditions have been satisfied over a three

- year period.

c Restricted share award under the BP Executive Directors Incentive Plan. These shares will vest in two equal tranche s after three and five years, subject to the directors’ con tinued 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 year a 8,063 6,004 53,977

a For the options outstanding at 31 December 2008, the e xercise price ranges and weighted average remaining cont ractual 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 pl ans ( see Financial

statements – Note 41 on page 166 ) and the granting of share options as

elements of remuneration for executive directors an d senior employees.

Shares acquired through the company’ s employee share plans rank pari

passu with shares in issue and have no special righ ts, save as described

below. For legal and practical reasons, the rules o f 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 ac celerated 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 a t the time of grant. The

option must be exercised within six months of matur ity 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 exercis e their options on a pro

rated basis. 

# Page 90 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm87

Additional information for shareholders

BP ShareMatch plans

These are matching share plans, under which BP matc hes 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 year s before they can be released

free of any income tax and national insurance liabi lity. In other countries, the

plan is run on an annual basis, with shares being h eld in trust for three years.

The plan is operated on a cash basis in those count ries where there are

regulatory restrictions preventing the holding of B P 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 emplo yee under the plan, the

employee may instruct the trustee how to vote their shares.

Local plans

In some countries, BP provides local scheme benefit s, the rules and

qualifications for which vary according to local ci rcumstances.

The above share plans are indicated as be ing equity-settled. In certain

countries, however, it is not possible to award sha res to employees owing to

local legislation. In these instances, the award wi ll be settled in cash,

calculated as the cash equivalent of the value to t he employee of an equitysettled plan.

Cash plans

Cash-settled share-based payments/Stock Appreciatio n Rights (SARs)

These are cash-settled share-based payments availab le to certain employees

that require the group to pay the intrinsic value o f 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 Perform ance Plan, the

Deferred Annual Bonus Plan and the BP ShareMatch pl ans. The ESOPs have

waived their rights to dividends on shares held for future awards and are

funded by the group. Pending vesting, the ESOPs hav e 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 dedu cted 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 29,05 1,082 shares (2007

6,448,838 shares and 2006 12,795,887 shares) for po tential future awards,

which had a market value of $220 million (2007 $79 million and 2006

$142 million).

Pursuant to the various BP group share op tion schemes, the following

options for ordinary shares of the company were out standing at 18

February 2009:

More details on share options appear in Financial s tatements – 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 a t 31

December 2008

Register of holders of American depositary shares ( ADSs) as at 31

December 2008 a

As at 31 December 2008, there were also 1,622 prefe rence shareholders.

Preference shareholders represented 0.44% and ordin ary shareholders

represented 99.56% of the total issued nominal shar e 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 s hares (ADSs) holds

interests through its nominee, Guaranty Nominees Li mited, in 5,184,252,501

ordinary shares (27.51% of the company’s ordinary s hare 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 ha s also been notified of the

following interests in preference shares: The Natio nal Farmers Union Mutual

Insurance Society Limited holds interests in 945,00 0 8% cumulative first

preference shares (13.07% of that class) and 987,00 0 9% cumulative second

preference shares (18.03% of that class). M & G Inv estment Management Ltd.

holds interests in 528,150 8% cumulative first pref erence shares (7.30% of

that class) and 644,450 9% cumulative second prefer ence shares (11.77% of

that class). Aviva Investors Global Services Limite d holds interests in 475,000

8% cumulative first preference shares (6.57% of tha t class). Lazard Asset

Management Ltd. (U.K.) holds interests in 463,000 8 % cumulative first

preference shares (6.40% of that class). Duncan Law rie 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 1,450,0 00 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 1,000,000 a 790 0.25 94.73

Totals 316,320 100.00 100.00

a Includes JP Morgan Chase Bank holding 27.48% of the tot al ordinary issued share capital (excluding

shares held in treasury) as the approved depositary for A DSs, 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 1,000,000 b 2 0.01 86.71

Totals 136,536 100.00 100.00

a One ADS represents six 25 cent ordinary shares.

b One of the holders of ADSs represents some 818,000 unde rlying shareholders. 

# Page 91 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmA dividend reinvestment plan is in place whereby ho lders of BP ordinary shares can elect to reinvest t he net cash dividend in shares purchased on the Lon don

Stock Exchange. This plan is not available to any p erson resident in the US or Canada or in any jurisd iction 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 fut ure earnings, the financial condition of the group, the Risk factors set out on pages 8-10 and other m atters that may

affect the business of the group set out in Financi al and operating performance on page 46 and in Liqu idity 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). Ru ffer LLP holds interests in

671,500 9% cumulative second preference shares (12. 27% of that class).

The total preference shares in issue comp rise only 0.44% of the

company’s total issued nominal share capital, the r est being ordinary shares.

Related-party transactions

Transactions between the group and its significant jointly controlled entities

and associates are summarized in Financial statemen ts – 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 of ficers 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 eac h year since 1917. In 2000

and thereafter, dividends were, and are expected to continue to be, paid quarterly in March, June, September and Decemb er. Former Amoco

Corporation and Atlantic Richfield Company sharehol ders will not be able to

receive dividends, or proxy material, until they se nd in their Amoco

Corporation or Atlantic Richfield Company common sh ares for exchange.

BP currently announces dividends for ordi nary shares in US dollars and

states an equivalent pounds sterling dividend. Divi dends on BP ordinary

shares will be paid in pounds sterling and on BP AD Ss in US dollars. The rate

of exchange used to determine the sterling amount e quivalent is the average

of the forward exchange rate in London over the fiv e business days prior to

the announcement date. The directors may choose to declare dividends in any

currency provided that a sterling equivalent is ann ounced, 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 annou nced 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 t he deemed credit allowed

to shareholders resident in the US under the former income tax convention

between the US and the UK and the associated withho lding tax in respect

thereof equal to the amount of such credit. (This d eemed credit and

associated withholding tax do not apply to dividend s paid after 30 April 2004 to

shareholders resident in the US.)

Save as disclosed in the following paragraphs, no m ember 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 invest igate and report alleged

violations of the US Commodity Exchange Act or US C ommodity Futures

Trading Commission (CFTC) regulations and to recomm end corrective action.

The appointment of the independent monitor was a co ndition of the deferred

prosecution agreement (DPA) entered into with the U S Department of Justice

(DOJ) on 25 October 2007 relating to allegations th at 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 comp anion consent order with

the CFTC, entered the same day, resolving all crimi nal and civil enforcement

matters pending at that time concerning propane trading by BP Products North

America Inc. (BP Products). The DPA requires BP Ame rica’s and certain of its

affiliates’ continued co-operation with the US gove rnment investigations of the

trades in question, as well as other trading matter s that may arise. The DPA

has a term of three years but can be extended by tw o additional one-year

periods, and contemplates dismissal of all charges at the end of the term

following the DOJ’s determination that BP America h as 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 actio ns, have also been filed against

BP Products alleging propane price manipulation. Th e 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 

# Page 92 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm89

Additional information for shareholders

complaints seek actual and punitive damages and inj unctive relief. Settlement

with one group of the class actions has received pr eliminary approval from the

court and final approval is expected in 2009.

On 23 March 2005, an explosion and fire o ccurred in the isomerization

unit of BP Products’ Texas City refinery as the uni t was coming out of planned

maintenance. Fifteen workers died in the incident a nd 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 t he board of the company.

In May 2007, BP responded to the CSB’s recommendati ons. BP and the CSB

continue to discuss BP’s responses with the objecti ve of the CSB agreeing to

close-out its recommendations.

On 25 October 2007, the DOJ announced tha t 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 F ebruary 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 victi ms’ 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 yea rs’ probation. Compliance

with a 2005 OSHA settlement agreement and an agreed order entered into by

BP Products with the Texas Commission on Environmen tal Quality

(TCEQ) are conditions of probation. The TCEQ and th e DOJ continue to

investigate certain matters arising from the March 2005 explosion and fire.

On 29 November 2007, BP Exploration (Alas ka) Inc. (BPXA) entered

into a criminal plea agreement with the DOJ relatin g to leaks of crude oil in

March and August 2006. BPXA’s guilty plea, to a mis demeanour violation of

the US Federal Water Pollution Control Act, include d a term of three years’

probation. BPXA is eligible to petition the court f or termination of the probation

term if it meets certain benchmarks relating to rep lacement of the transit lines,

upgrades to its leak detection system and improveme nts to its integrity

management programme. BPXA continues to co-operate with a parallel State

of Alaska civil investigation into the March and Au gust 2006 spills, including

three separate subpoenas issued to BPXA by the Alas ka Department of

Environmental Conservation. BPXA is also engaged in discussions with the

DOJ, the EPA and the US Department of Transportatio n 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 t he directors of the company

and others, nominally the company and certain US su bsidiaries, 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 ar ising out of the Exxon

Valdez oil spill in Prince William Sound in March 1 989. Most of those suits

named Exxon (now ExxonMobil), Alyeska Pipeline Serv ice Company

(Alyeska), which operates the oil terminal at Valde z, and the other oil

companies that own Alyeska. Alyeska initially respo nded to the spill until the

response was taken over by Exxon. BP owns a 46.9% i nterest (reduced

during 2001 from 50% by a sale of 3.1% to Phillips) in Alyeska through a

subsidiary of BP America Inc. and briefly indirectl y 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 co ntribution against Alyeska for

a portion of the costs and damages that it has incurred. If any claims are ass erted by Exxon that affect

Alyeska and its owners, BP will defend the claims v igorously.

Since 1987, Atlantic Richfield, a subsidi ary 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 pain t. The majority of the

lawsuits have been abandoned or dismissed against A tlantic Richfield. Atlantic

Richfield is named in these lawsuits as alleged suc cessor to International

Smelting and Refining and another company that manu factured lead pigment

during the period 1920-1946. Plaintiffs include ind ividuals and governmental

entities. Several of the lawsuits purport to be cla ss actions. The lawsuits seek

various remedies including compensation to lead-poi soned children, cost to

find and remove lead paint from buildings, medical monitoring and screening

programmes, public warning and education of lead ha zards, reimbursement of

government healthcare costs and special education f or lead-poisoned citizens

and punitive damages. No lawsuit against Atlantic R ichfield 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 th e outcome of these legal

actions, Atlantic Richfield believes that it has va lid defences and it intends to

defend such actions vigorously and that the incurre nce of liability is remote.

Consequently, BP believes that the impact of these lawsuits on the group’s

results of operations, financial position or liquid ity will not be material.

In January 2009, the TNK-BP shareholders resolved, or agreed a

process for resolving, all outstanding claims betwe en them, including those

relating to Russian back taxes. The suit filed in R ussia by a minority

shareholder in TNK-BP Holding, alleging that an agr eement 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 with drawn.

For certain information regarding environ mental 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 eleme nt 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 prim arily through the use of the

Stock Exchange Electronic Trading Service (SETS), i ntroduced 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 pr ices may be sent to the

exchange electronically by any firm that is a membe r of the LSE, on behalf of

a client or on behalf of itself acting as a princip al. 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 automat ically reported to the LSE.

Trading is continuous from 8.00 a.m. to 4.30 p.m. U K time but, in the event of

a 20% movement in the share price either way, the L SE may impose a

temporary halt in the trading of that company’s sha res in the order book to

allow the market to re-establish equilibrium. Deali ngs in ordinary shares may

also take place between an investor and a market-ma ker, via a member firm,

outside the electronic order book.

In the US, the company’s securities are t raded in the form of ADSs, for

which JPMorgan Chase Bank is the depositary (the De positary) and transfer

agent. The Depositary’s principal office is 4 New Y ork Plaza, Floor 13, New

York, NY 10004, US. Each ADS represents six ordinar y shares. ADSs are

listed on the New York Stock Exchange. ADSs are evi denced by American

depositary receipts (ADRs), which may be issued in either certificated or book

entry form.

The following table sets forth for the pe riods indicated the highest 

# Page 93 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm90

Additional information for shareholders

Pence Dollars

American

depositary

Ordinary shares shares a

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

a An 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 Li st 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 an d in after-hours trading off

the LSE, in each case while the NYSE is open, and t he market prices for

ADSs on the NYSE are closely related due to arbitra ge among the various

markets, although differences may exist from time t o time due to various

factors, including UK stamp duty reserve tax.

On 18 February 2009, 864,042,084 ADSs (eq uivalent 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 re presents some 818,000

underlying holders.

On 18 February 2009, there were approxima tely 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. 

# Page 94 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm91

Additional information for shareholders



# 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 Co mpanies Act and the

company’s Memorandum and Articles of Association. I nformation on where

investors can obtain copies of the Memorandum and A rticles 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 amendmen ts that had been

necessary to implement legislative changes since th e previous Articles of

Association were adopted in 1983.

At the AGM held on 15 April 2004, shareho lders approved an

amendment to the Articles of Association such that, at each AGM held after 31

December 2004, all directors shall retire from offi ce and may offer themselves

for re-election.

At the AGM held on 17 April 2008, shareho lders 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 am endments to the

Articles of Association are likely to be required a t 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 a cquisition of petroleumbearing lands; the carrying on of refining and deal ing businesses in the

petroleum, manufacturing, metallurgical or chemical s businesses; the

purchase and operation of ships and all other vehic les and other

conveyances; and the carrying on of any other busin esses calculated to

benefit BP. The memorandum grants BP a range of cor porate capabilities to

effect these objects.

Directors

The business and affairs of BP shall be managed by the directors.

The Articles of Association place a gener al 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 sh ares 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 f or the purpose of any vote

relating to a resolution concerning the following m atters:

• The giving of security or indemnity with respect t o 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 sh areholder 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 re tirement benefits

schemes under which he may benefit and that have be en approved by either

the UK Board of Inland Revenue or by the shareholde rs.

• 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 compa ny 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 director s 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 di rect or indirect interest that

conflicts, or possibly may conflict, with the compa ny’ s interests. The Act allows

directors of public companies to authorize such con flicts where appropriate, if

a company’s Articles of Association so permit. BP’s Articles of Association

permit the authorization of such conflicts. The dir ectors 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 pai d 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 bo ard may only be effected

by amending the Articles of Association.

Remuneration of non-executive directors s hall be determined in the

aggregate by resolution of the shareholders. Remune ration of executive

directors is determined by the remuneration committ ee. This committee is

made up of non-executive directors only. There is n o requirement of share

ownership for a director’s qualification.

Dividend rights; other rights to share in company p rofits; capital calls

If recommended by the directors of BP, BP sharehold ers may, by resolution,

declare dividends but no such dividend may be decla red in excess of the

amount recommended by the directors. The directors may also pay interim

dividends without obtaining shareholder approval. N o dividend may be paid

other than out of profits available for distributio n, as determined under IFRS

and the UK Companies Act. Dividends on ordinary sha res are payable only

after payment of dividends on BP preference shares. Any dividend unclaimed

after a period of 12 years from the date of declara tion of such dividend shall

be forfeited and reverts to BP.

The directors have the power to declare a nd pay dividends in any

currency provided that a sterling equivalent is ann ounced. 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 provi de that the directors may set

aside:

Any such sums so deposited may be distributed in ac cordance with the

manner of distribution of dividends as described ab ove. Holders of shares are not subject to call s on capital by the company,

provided that the amounts required to be paid on is sue have been paid off. All

shares are fully paid. • A special reserve fund out of the balance of profit s each year to make up any

deficit of cumulative dividend on the BP preference shares.

• A general reserve out of the balance of profits ea ch 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 ordina ry shares or in paying up

in full unissued ordinary shares for allotment and distribution as bonus

shares. 

# Page 95 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm92

Additional information for shareholders

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 resolu tions of a

procedural nature, which may be decided on a show o f 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 h ands, each shareholder who

is present at the meeting in person or whose duly a ppointed proxy is present

in person will have one vote, regardless of the num ber of shares held, unless

a poll is requested. Shareholders do not have cumul ative 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 entitl ed to attend, speak and vote

at any shareholders’ meeting of BP by the appointme nt by the approved

depositary, JPMorgan Chase Bank, of them as proxies in respect of the

ordinary shares represented by their ADSs. Each suc h proxy may also appoint

a proxy. Alternatively, holders of BP ADSs are enti tled to vote by supplying

their voting instructions to the depositary, who wi ll vote the ordinary shares

represented by their ADSs in accordance with their instructions.

Proxies may be delivered electronically.

Matters are transacted at shareholders’ m eetings by the proposing and

passing of resolutions, of which there are three ty pes: ordinary, special or

extraordinary. An annual general meeting must be he ld once in every year and

all other general meetings will be called extraordi nary general meetings.

An ordinary resolution requires the affir mative 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 affirmati ve 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 ye ar, reliance on this notice

period of 14 days will require annual shareholder a pproval, 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 entitl ed to the sum of (i) the

capital paid up on such shares plus, (ii) accrued a nd unpaid dividends and

(iii) a premium equal to the higher of (a) 10% of t he 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 p reviously conferred on the

holders of any class of shares, BP may issue any sh are with such preferred,

deferred or other special rights, or subject to suc h restrictions as the

shareholders by resolution determine (or, in the ab sence of any such

resolutions, by determination of the directors), an d may issue shares that are

to be or may be redeemed.

Variation of rights

The rights attached to any class of shares may be v aried with the consent in

writing of holders of 75% of the shares of that cla ss or on the adoption of an

extraordinary resolution passed at a separate meeti ng of the holders of the

shares of that class. At every such separate meetin g, 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 elect ronic address in the UK in

order to be entitled to receive notice of sharehold ers’ meetings. In certain

circumstances, BP may give notices to shareholders by advertisement in UK

newspapers. Holders of BP ADSs are entitled to rece ive notices under the

terms of the deposit agreement relating to BP ADSs. The substance and

timing of notices is described above under the head ing Voting Rights.

Under the Articles of Association, the AG M 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 shar es or ADSs, other than

limitations that would generally apply to all of th e shareholders.

Disclosure of interests in shares

The UK Companies Act permits a public company, on w ritten notice, to require

any person whom the company believes to be or, at a ny time during the

previous three years prior to the issue of the noti ce, to have been interested in

its voting shares, to disclose certain information with respect to those

interests. Failure to supply the information requir ed may lead to

disenfranchisement of the relevant shares and a pro hibition on their transfer

and receipt of dividends and other payments in resp ect of those shares. In this

context the term ‘interest’ is widely defined and w ill generally include an

interest of any kind whatsoever in voting shares, i ncluding 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 th e 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 prefe rence shares in the

company.



# Taxation

This section describes the material US federal inco me 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 t ax purposes. It does not

apply, however, to members of special classes of ho lders subject to special

rules and holders that, directly or indirectly, hol d 10% or more of the

company’s voting stock.

A US holder is any beneficial owner of or dinary 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 admin istration and one or more

US persons are authorized to control all substantia l decisions of the trust.

This section is based on the Internal Rev enue Code of 1986, as

amended, its legislative history, existing and prop osed regulations thereunder,

published rulings and court decisions, and the taxa tion laws of the UK, all as

currently in effect, as well as the income tax conv ention 

# Page 96 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm93

Additional information for shareholders

between the US and the UK that entered into force o n 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 repres entations of the Depositary

and assumes that each obligation in the Deposit Agr eement 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 shar es 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 ad viser 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 cir cumstances, and in

particular whether they are eligible for the benefi ts of the Treaty.

Taxation of dividends

UK taxation

Under current UK taxation law, no withholding tax w ill be deducted from

dividends paid by the company, including dividends paid to US holders. A

shareholder that is a company resident for tax purp oses 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 sh areholder who is an

individual resident for tax purposes in the UK is s ubject 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 taxatio n 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 ta x purposes). Dividends

paid to a non-corporate US holder in taxable years beginning before 1

January 2011 that constitute qualified dividend inc ome 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 divi dend income.

As noted above in UK taxation, a US holde r 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 actu ally received from the

company and the receipt of a dividend will not enti tle the US holder to a

foreign tax credit.

For US federal income tax purposes, a div idend 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 rec eives the dividend, and will

not be eligible for the dividends-received deductio n generally allowed to US

corporations in respect of dividends received from other US corporations.

Dividends will be income from sources outside the U S, and generally will be

‘passive category income’ or, in the case of certai n US holders, ‘general

category income,’ each of which is treated separate ly for purposes of

computing the allowable foreign tax credit.

The amount of the dividend distribution o n the ordinary shares or ADSs

that is paid in pounds sterling will be the US doll ar value of the pounds sterling

payments made, determined at the spot pounds sterli ng/US dollar rate on the

date the dividend distribution is includible in inc ome, regardless of whether the

payment is in fact converted into US dollars. Gener ally, any gain or loss

resulting from currency exchange fluctuations durin g 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 withi n 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 t he 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 holde r is (i) a citizen of the US

resident or ordinarily resident in the UK, (ii) a U S 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 corporatio n that carries on a trade or

profession or vocation in the UK through a branch o r agency or, in respect of

corporations for accounting periods beginning on or after 1 January 2003,

through a permanent establishment, and that have us ed, held, or acquired the

ordinary shares or ADSs for the purposes of such tr ade, profession or

vocation of such branch, agency or permanent establ ishment. However, such

persons may be entitled to a tax credit against the ir 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 dispos itions of ordinary shares or

ADSs generally will be subject to tax only in the j urisdiction of residence of the

relevant holder as determined under both the laws o f the UK and the US and

as required by the terms of the Treaty.

Under the Treaty, individuals who are res idents of either the UK or the

US and who have been residents of the other jurisdi ction (the US or the UK,

as the case may be) at any time during the six year s immediately preceding

the relevant disposal of ordinary shares or ADSs ma y 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 whic h the holder is resident at the

time of the disposition but also in the other juris diction.

US federal income taxation

A US holder that sells or otherwise disposes of ord inary shares or ADSs will

recognize a capital gain or loss for US federal inc ome tax purposes equal to

the difference between the US dollar value of the a mount realized and the

holder’s tax basis, determined in US dollars, in th e ordinary shares or ADSs.

Capital gain of a non-corporate US holder that is r ecognized 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 sh ares 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, f or US federal income tax

purposes, but this conclusion is a factual determin ation 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 c apital gain. Instead a US

holder would be treated as if he or she had realize d such gain and certain

‘excess distributions’ ratably over the holding per iod 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 whi ch an interest charge in

respect of the tax attributable to each such year w ould apply. 

# Page 97 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm94

Additional information for shareholders

Additional tax considerations

UK inheritance tax

The Estate Tax Convention applies to inheritance ta x. 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 Ta x 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, a mong other things, the ADSs

are part of the business property of a permanent es tablishment situated in the

UK used for the performance of independent personal services. In the

exceptional case where ADSs are subject both to inh eritance tax and to US

federal gift or estate tax, the Estate Tax Conventi on generally provides for tax

payable in the US to be credited against tax payabl e 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 t o be the current practice

of HM Revenue & Customs in the UK under existing la w. Provided that any instrument of transfer is not executed in the UK and

remains at all times outside the UK and the transfe r 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 a n agreement to transfer ADSs

in the form of ADRs give rise to a liability to sta mp 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 condit ional agreement, when the

condition is fulfilled). The stamp duty reserve tax will apply to agreements to

transfer ordinary shares even if the agreement is m ade outside the UK

between two non-residents. Purchases of ordinary sh ares outside the CREST

system are subject either to stamp duty at a rate o f £5 per £1,000 (or part,

unless the stamp duty is less than £5, when no stam p duty is charged), or

stamp duty reserve tax at 0.5%. Stamp duty and stam p 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 v alue of the ordinary shares

at the time of the transfer.

An ADR holder electing to receive ADSs in stead of a cash dividend will

be responsible for the stamp duty reserve tax due o n 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 & Cust oms 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 t o receive ADSs instead

of the cash dividend authorize the Depositary to se ll sufficient shares to cover

this liability.



# Documents on display

BP’s Annual Report and Accounts is also available o nline at

www.bp.com/annualreport . Shareholders may obtain a hard copy of BP’s

complete audited financial statements, free of char ge, by contacting BP

Distribution Services at +44 (0)870 241 3269 or thr ough 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 requireme nts, the company files its

Annual Report on Form 20-F and other related docume nts 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-S EC-0330 or log on to

www.sec.gov . In addition, BP’s SEC filings are available to th e 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 w hich 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 proc edures’ as such term is

defined in Exchange Act Rule 13a-15(e), that are de signed to ensure that

information required to be disclosed in reports the company files or submits

under the Exchange Act is recorded, processed, summ arized and reported

within the time periods specified in the Securities and Exchange Commission

rules and forms, and that such information is accum ulated 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 disclosur e controls and procedures, our

management, including the group chief executive and chief financial officer,

recognize that any controls and procedures, no matt er how well designed and

operated, can provide only reasonable, not absolute , assurance that the

objectives of the disclosure controls and procedure s are met. Because of the

inherent limitations in all control systems, no eva luation of controls can provide

absolute assurance that all control issues and inst ances of fraud, if any, within

the company have been detected. Further, in the des ign and evaluation of our

disclosure controls and procedures our management n ecessarily was required

to apply its judgment in evaluating the cost-benefi t 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 necess arily substantially more

limited than those we maintain with respect to our consolidated subsidiaries.

Because of the inherent limitations in a cost-effec tive control system, misstatements due to error or fraud may occur and not be detected. The

company’s disclosure controls and procedures have b een designed to meet,

and management believe that they meet, reasonable a ssurance standards.

The company’s management, with the partic ipation 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 pe riod 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 reporti ng 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 aff ect, our internal controls over

financial reporting.

During 2008, as part of an ongoing proces s, 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 

# Page 98 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm95

Additional information for shareholders

and the elimination of unrealised profit arising on transfers of inventory

between business segments. These improvements inclu ded clarifying roles

and accountabilities, implementing additional preve ntative and detective

controls and providing additional staff training.

Management’s report on internal control over financ ial reporting

Management of BP is responsible for establishing an d maintaining adequate

internal control over financial reporting. BP’s int ernal control over financial

reporting is a process designed under the supervisi on of the principal

executive and principal financial officers to provi de reasonable assurance

regarding the reliability of financial reporting an d the preparation of BP’s

financial statements for external reporting purpose s in accordance with IFRS.

As of the end of the 2008 fiscal year, ma nagement conducted an

assessment of the effectiveness of internal control over financial reporting in

accordance with the Internal Control Revised Guidan ce for Directors on the

Combined Code (Turnbull). Based on this assessment, management has

determined that BP’s internal control over financia l reporting as of 31

December 2008 was effective.

The company’s internal control over finan cial reporting includes policies

and procedures that pertain to the maintenance of r ecords 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 accor dance with IFRS and that

receipts and expenditures are being made only in ac cordance with

authorizations of management and the directors of B P; 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 repo rting as of 31 December 2008

has been audited by Ernst & Young LLP, an independe nt registered public

accounting firm, as stated in their report appearin g on page 100.



# Audit committee financial expert

The board determined that Douglas Flint is the audi t committee member with

recent and relevant financial experience as defined by the Combined Code

guidance.

The board also determined that Douglas Fl int meets the independence

criteria provisions of Rule 10A-3 of the Exchange A ct 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 HS BC Holdings plc and a

former member of the Accounting Standards Board and the Standards

Advisory Council of the International Accounting St andards Board.



# Code of ethics

The company has adopted a code of ethics for its gr oup chief executive, chief

financial officer, general auditor, group chief acc ounting officer and deputy

chief financial officer (previously titled group co ntroller) 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. T he 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 cond uct, which is applicable to all

employees.



# Principal accountants fees and services

The audit committee has established policies and pr ocedures for the

engagement of the independent registered public acc ounting firm, Ernst &

Young LLP, to render audit and certain assurance an d tax services. The

policies provide for pre-approval by the audit comm ittee of specifically defined audit, audit

- related, tax and other services that are not prohib ited by

regulatory or other professional requirements. Erns t & 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 assessme nt of the expertise of

Ernst & Young relative to that of other potential s ervice providers. These

services are for a fixed term.

Under the policy, pre-approval is given f or specific services within the

following categories: advice on accounting, auditin g and financial reporting

matters; internal accounting and risk management co ntrol reviews (excluding

any services relating to information systems design and implementation); nonstatutory audit; project assurance and advice on bu siness and accounting

process improvement (excluding any services relatin g to information systems

design and implementation relating to BP’s financia l statements or accounting

records); due diligence in connection with acquisit ions, disposals and joint

ventures (excluding valuation or involvement in pro spective financial

information); income tax and indirect tax complianc e and advisory services;

and employee tax services (excluding tax services t hat could impair

independence); provision of, or access to, Ernst & Young publications,

workshops, seminars and other training materials; p rovision of reports from

data gathered on non-financial policies and informa tion; 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 committe e authority to approve

permitted services provided that the chairman repor ts any decisions to the

committee at its next scheduled meeting.

The audit committee evaluates the perform ance of the auditors each

year. The audit fees payable to Ernst & Young are r eviewed by the committee

in the context of other global companies for cost e ffectiveness. The committee

keeps under review the scope and results of audit w ork and the independence

and objectivity of the auditors. External regulatio n and BP policy requires the

auditors to rotate their lead audit partner every f ive 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 gove rnance practices and

those required by NYSE listing standards for US com panies are listed as

follows:

Independence

BP has adopted a robust set of board governance pri nciples, which reflect the

UK’s prevailing principles-based approach to corpor ate governance. As such,

the way in which BP makes determinations of directo rs’ independence differs

from the NYSE rules. Rule 303A.02 under NYSE’s List ed Company Manual

sets out five bright line tests for director indepe ndence. In addition to these

five tests, the NYSE also requires that the board o f directors “affirmatively

determines that the director has no material relati onship with the company

(either directly or as a partner, shareholder or of ficer 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 “indepen dent in character and

judgement and free from any business or other relat ionship which could

materially interfere with the exercise of their jud gement”.

The BP board has determined that, in its judgement, all of the nonexecutive directors are independent. In doing so, h owever, the board did not

explicitly take into consideration the NYSE’s five bright line tests. 

# Page 99 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm96

Additional information for shareholders

Committees

BP has a number of board committees which are broad ly comparable in

purpose and composition to those required by NYSE r ules for domestic US

companies. For instance, BP has a chairman’s (rathe r than executive)

committee, nomination (rather than nominating/corpo rate governance)

committee and remuneration (rather than compensatio n) committee. BP also

has an audit committee, which NYSE rules require fo r both US companies and

foreign private issuers. These committees are compo sed solely of nonexecutive directors whom the board has determined t o be independent, in the

manner described above.

The BP board governance principles prescr ibe the composition, main

tasks and requirements of each of the committees (s ee The Board

Committees on page 67). BP has not, therefore, adop ted 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 commit tee is to have “accounting

or related financial management expertise”. For 200 8, the board determined

that Douglas Flint possessed such expertise and als o possesses the financial

and audit committee experiences set forth in both t he 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 shareh olders must be given

the opportunity to vote on all equity- compensation plans and material revisions

to those plans. BP complies with UK requirements wh ich are similar to the

NYSE rules. The board, however, does not explicitly take into consideration

the NYSE’s detailed definition of what are consider ed “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 emp loyees, and has board

governance principles which address the conduct of directors. In addition BP

has adopted a code of ethics for senior financial o fficers as required by the

SEC. BP considers that these codes and policies add ress the matters

specified in the NYSE rules for US companies. 

# Page 100 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Purchases of equity securities by the issuer and affiliated purchasers

The following table provides details of ordinary sh ares repurchased.

The following table provides details of share purch ases made by ESOP trusts.

97 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 purchased a b paid per share programmes the programme c

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)

– – –

a All share purchases were open market transactions.

b All shares were repurchased for cancellation.

c At the AGM on 17 April 2008, authorization was given t o repurchase up to 1.9 billion ordinary shares in the pe riod to the next AGM in 2009 or 16 July 2009, the lat est 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 programmes a the programme a

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

a No shares were repurchased pursuant to a publicly announced plan. Transactions represent the purchase of ordinary shar es by ESOP trusts to satisfy future requirements of empl oyee share schemes. 

# Page 101 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm98

Additional information for shareholders



# Called-up share capital

Details of the allotted, called up and fully paid s hare capital at 31

December 2008 are set out in Financial statements – Note 39 on page 163.

At the AGM on 17 April 2008, authorizatio n was given to the directors to

allot shares up to an aggregate nominal amount equa l 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 ri ghts issue, up to a

maximum of $238 million, without having to offer su ch shares to existing

shareholders. These authorities are given for the p eriod until the next AGM in

2009 or 16 July 2009, whichever is the earlier. The se 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, L ondon E16 1XL. A

separate notice convening the meeting is distribute d 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 wi llingness to continue in

office as auditors and a resolution for their reapp ointment 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 do es 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 a nnual 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 For m 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 Secur ities 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 pa yments, 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 BN 99 6DA

Freephone in UK 0800 701107; Tel +44 (0)121 415 700 5

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 pro viders’ 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 

# Page 102 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 discontin ued

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 natur al 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 factor s 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 a ssociates 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 charg es (unaudited) 179

51. Condensed consolidating information on certain US

subsidiaries 179



# 185 Supplementary information on oil

and natural gas (unaudited) Page 103 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 shee ts of BP p.l.c. as of 31 December 2008 and 2007, an d the related group statements of income, cash flow s, and recognized income and expense, for each of the three years in the period ended 31 December 2008. T hese financial statements are the responsibility of the

company’s management. Our responsibility is to expr ess an opinion on these financial statements based on our audits.

We conducted our audits in accordance wit h the standards of the Public Company Accounting Ov ersight Board (United States). Those standards requ ire that

we plan and perform the audit to obtain reasonable assurance about whether the financial statements ar e free of material misstatement. An audit includes

examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement s. An audit also includes assessing the accounting principles

used and significant estimates made by management, as well as evaluating the overall financial stateme nt 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 r espects, the group financial position of BP p.l.c. at 31 December 2008

and 2007, and the group results of operations and c ash flows for each of the three years in the period ended 31 December 2008, in accordance with Interna tional

Financial Reporting Standards as adopted by the Eur opean Union and International Financial Reporting S tandards as issued by the International Accounting

Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Over sight Board (United States), the effectiveness of B P 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 Februar y 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 f inancial reporting as of 31 December 2008, based on criteria established in Internal Control-Revised G uidance for

Directors on the Combined Code (Turnbull) as issued by the Institute of Chartered Accountants in Engla nd 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 co ntrol over

financial reporting included in the accompanying Ma nagement’s report on internal control over financia l reporting on page 95. Our responsibility is to ex press an opinion on the company’s internal control over fina ncial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Ove rsight Board (United States). Those standards requi re that

we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all mate rial

respects. Our audit included obtaining an understan ding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and

evaluating the design and operating effectiveness o f 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 financi al reporting is a process designed to provide reaso nable assurance regarding the reliability of financ ial reporting and

the preparation of financial statements for externa l purposes in accordance with generally accepted ac counting principles. A company’s internal control o ver financial reporting includes those policies and pro cedures that (1) pertain to the maintenance of reco rds that, in reasonable detail, accurately and fair ly reflect the

transactions and dispositions of the assets of the company; (2) provide reasonable assurance that tran sactions are recorded as necessary to permit prepar ation of

financial statements in accordance with generally a ccepted accounting principles, and that receipts an d expenditures of the company are being made only i n accordance with authorizations of management and di rectors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of

unauthorized acquisition, use, or disposition of th e company’s assets that could have a material effec t on the financial statements.

Because of its inherent limitations, inte rnal control over financial reporting may not preve nt or detect misstatements. Also, projections of an y 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 compl iance with

the policies or procedures may deteriorate.

In our opinion, BP p.l.c. maintained, in all material respects, effective internal control o ver financial reporting as of 31 December 2008, bas ed on the Turnbull

criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Over sight Board (United States), the group balance shee ts of BP

p.l.c. as of 31 December 2008 and 2007, and the rel ated group statements of income, cash flows and rec ognized income and expense, for each of the three y ears in the period ended 31 December 2008, and our repor t dated 24 February 2009 expressed an unqualified o pinion thereon.

/s/ERNST & YOUNG LLP

Ernst & Young LLP

London, England

24 February 2009

100 

# Page 104 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 re porting of BP p.l.c., included in this Annual Repor t (Form 20-F) for the year ended 31 December 2008 i n 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 Ca pital Markets p.l.c., BP Capital Markets America In c, 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, 33 3-

123483, 333-132619, 333-131584, 333-131583, 333-146 868, 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 

# Page 105 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 fix ed 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 p ost-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 B P shareholders

Basic 112.59 108.76 111.54

Diluted 111.56 107.84 110.68 

# Page 106 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 cla ssified 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 

# Page 107 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 an d fixed assets 8,11 380 (808 ) (3,165 )

Earnings from jointly controlled entities and assoc iates (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 p ost

- 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 pla ns (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 d isposed 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 a nd 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 

# Page 108 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 a nd

fixed assets

– (147) –

Actuarial (loss) gain relating to pensions and othe r 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 a nd 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



# Page 109 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 gro up for the year ended 31

December 2008 were authorized for issue by the boar d of directors on 24

February 2009 and the balance sheet was signed on t he board’s behalf by P

D Sutherland and Dr A B Hayward. BP p.l.c. is a pub lic limited company

incorporated and domiciled in England and Wales. Th e consolidated financial

statements have been prepared in accordance with In ternational Financial

Reporting Standards (IFRS) as issued by the Interna tional Accounting

Standards Board (IASB) and IFRS as adopted by the E uropean Union (EU).

IFRS as adopted by the EU differs in certain respec ts from IFRS as issued by

the IASB, however, the differences have no impact o n the group’s

consolidated financial statements for the years pre sented. The significant

accounting policies of the group are set out below.

Basis of preparation

The consolidated financial statements have been pre pared in accordance with

IFRS and International Financial Reporting Interpre tations Committee (IFRIC)

interpretations issued and effective for the year e nded 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 a nnouncement of the fourth

quarter 2008 results on 3 February 2009, an adjustm ent has been made to

correct for a $560 million overstatement of the def erred tax liability in the

balance sheet as at 31 December 2008 with a corresp onding 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 dolla rs ($ million), except where

otherwise indicated.

For further information regarding the key judgements and estimates

made by management in applying the group’s accounti ng policies, refer to

Critical accounting policies on pages 57 to 59, whi ch forms part of these

financial statements.

Basis of consolidation

The group financial statements consolidate the fina ncial statements of BP

p.l.c. and the entities it controls (its subsidiari es) drawn up to 31 December

each year. Control comprises the power to govern th e financial and operating

policies of the investee so as to obtain benefit fr om its activities and is

achieved through direct and indirect ownership of v oting rights; currently

exercisable or convertible potential voting rights; or by way of contractual

agreement. Subsidiaries are consolidated from the d ate of their acquisition,

being the date on which the group obtains control, and continue to be

consolidated until the date that such control cease s. 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 t he 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 whereb y two or more parties

(venturers) undertake an economic activity that is subject to joint control. Joint

control exists only when the strategic financial an d operating decisions relating

to the activity require the unanimous consent of th e venturers. A jointly

controlled entity is a joint venture that involves the establishment of a

company, partnership or other entity to engage in e conomic 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 th e equity method of

accounting. Under the equity method, the investment in a jointly controlled

entity is carried in the balance sheet at cost, plu s post-acquisition changes in

the group’ s share of net assets of the jointly controlled ent ity, less distributions

received and less any impairment in value of the in vestment. 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 controlle d 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 t he asset transferred.

The group assesses investments in jointly controlled entities for

impairment whenever events or changes in circumstan ces indicate that the

carrying value may not be recoverable. If any such indication of impairment

exists, the carrying amount of the investment is co mpared with its recoverable

amount, being the higher of its fair value less cos ts to sell and value in use.

Where the carrying amount exceeds the recoverable a mount, 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 signif icant influence over the joint

venture, or when the interest becomes held for sale

. Certain of the group’s activities, partic ularly in the Exploration and

Production segment, are conducted through joint ven tures where the

venturers have a direct ownership interest in and j ointly control the assets of

the venture. The income, expenses, assets and liabi lities 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 i n a position to exercise

significant influence through participation in the financial and operating policy

decisions of the investee, but that is not a subsid iary 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. 

# Page 110 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm107

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 curren cy 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 li abilities denominated in

foreign currencies are retranslated into the functi onal currency at the rate of

exchange ruling at the balance sheet date. Any resu lting 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 r ates of exchange as at the

dates of the initial transactions. Non-monetary ass ets 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 val ue was determined.

In the consolidated financial statements, the assets and liabilities of

non-US dollar functional currency subsidiaries, joi ntly controlled entities and

associates, including related goodwill, are transla ted into US dollars at the rate

of exchange ruling at the balance sheet date. The r esults and cash flows of

non-US dollar functional currency subsidiaries, joi ntly controlled entities and

associates are translated into US dollars using ave rage rates of exchange.

Exchange adjustments arising when the opening net a ssets and the profits for

the year retained by non-US dollar functional curre ncy subsidiaries, jointly

controlled entities and associates are translated i nto US dollars are taken to a

separate component of equity and reported in the st atement of recognized

income and expense. Exchange gains and losses arisi ng on long-term

intragroup foreign currency borrowings used to fina nce the group’s non-US

dollar investments are also taken to equity. On dis posal of a non-US dollar

functional currency subsidiary, jointly controlled entity or associate, the

deferred cumulative amount recognized in equity rel ating to that particular

non-US dollar operation is recognized in the income statement.

Business combinations and goodwill

Business combinations are accounted for using the p urchase method of

accounting. The cost of an acquisition is measured as the cash paid and the

fair value of other assets given, equity instrument s issued and liabilities

incurred or assumed at the date of exchange, plus c osts directly attributable to

the acquisition. The acquired identifiable assets, liabilities and contingent

liabilities are measured at their fair values at th e date of acquisition. Any

excess of the cost of acquisition over the net fair value of the identifiable

assets, liabilities and contingent liabilities acqu ired 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 g roup does not acquire

100% ownership of the acquired company, the interes t of minority

shareholders is stated at the minority’s proportion of the fair values of the

assets and liabilities recognized. Subsequently, an y losses applicable to the

minority shareholders in excess of the minority int erest on the group balance

sheet are allocated against the interests of the pa rent.

At the acquisition date, any goodwill acq uired 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 i s measured at cost less any

accumulated impairment losses. Goodwill is reviewed for impairment annually

or more frequently if events or changes in circumst ances indicate that the

carrying value may be impaired. Impairment is determined by assessing the recoverab le amount of the cash

generating unit to which the goodwill relates. Wher e the recoverable amount

of the cash-generating unit is less than the carryi ng 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 gen erally accepted

accounting practice.

Goodwill may also arise upon investments in jointly controlled entities

and associates, being the surplus of the cost of in vestment over the group’s

share of the net fair value of the identifiable ass ets. Such goodwill is recorded

within investments in jointly controlled entities a nd associates, and any

impairment of the goodwill is included within the e arnings from jointly

controlled entities and associates.

Non-current assets held for sale

Non-current assets and disposal groups classified a s held for sale are

measured at the lower of carrying amount and fair v alue less costs to sell.

Non-current assets and disposal groups ar e 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 c ommitted 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 intangi ble assets once classified as

held for sale are not depreciated.

Intangible assets

Intangible assets, other than goodwill, include exp enditure 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 accum ulated impairment

losses.

Intangible assets acquired separately fro m a business are carried

initially at cost. The initial cost is the aggregat e amount paid and the fair value

of any other consideration given to acquire the ass et. An intangible asset

acquired as part of a business combination is measu red at fair value at the

date of acquisition and is recognized separately fr om 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, lice nces 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 r eviewed on an annual basis

and, if necessary, changes in useful lives are acco unted for prospectively.

The carrying value of intangible assets i s reviewed for impairment

whenever events or changes in circumstances indicat e the carrying value may

not be recoverable. 

# Page 111 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm108

Notes on financial statements



### 1. Significant accounting policies continued

Oil and natural gas exploration and development exp enditure

Oil and natural gas exploration and development exp enditure is accounted for

using the successful efforts method of accounting.

Licence and property acquisition costs

Exploration licence and leasehold property acquisit ion costs are capitalized

within intangible assets and are reviewed at each r eporting date to confirm

that there is no indication that the carrying amoun t exceeds the recoverable

amount. This review includes confirming that explor ation drilling is still under

way or firmly planned or that it has been determine d, or work is under way to

determine, that the discovery is economically viabl e based on a range of

technical and commercial considerations and suffici ent progress is being

made on establishing development plans and timing. If no future activity is

planned, the remaining balance of the licence and p roperty acquisition costs is

written off. Lower value licences are pooled and am ortized on a straight -line

basis over the estimated period of exploration. Upo n 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 ch arged against income as

incurred. Costs directly associated with an explora tion well are initially

capitalized as an intangible asset until the drilli ng of the well is complete and

the results have been evaluated. These costs include employee remuneration,

materials and fuel used, rig costs, delay rentals a nd payments made to

contractors. If hydrocarbons are not found, the exp loration expenditure is

written off as a dry hole. If hydrocarbons are foun d and, subject to further

appraisal activity, which may include the drilling of further wells (exploration or

exploratory-type stratigraphic test wells), are lik ely to be capable of

commercial development, the costs continue to be ca rried as an asset. All

such carried costs are subject to technical, commer cial and management

review at least once a year to confirm the continue d intent to develop or

otherwise extract value from the discovery. When th is 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 relev ant expenditure is

transferred to property, plant and equipment.

Development expenditure

Expenditure on the construction, installation or co mpletion of infrastructure

facilities such as platforms, pipelines and the dri lling of development wells,

including unsuccessful development or delineation w ells, is capitalized within

property, plant and equipment and is depreciated fr om the commencement of

production as described below in the accounting pol icy for Property, plant and

equipment.

Property, plant and equipment

Property, plant and equipment is stated at cost, le ss accumulated depreciation

and accumulated impairment losses.

The initial cost of an asset comprises it s purchase price or construction

cost, any costs directly attributable to bringing t he asset into operation, the

initial estimate of any decommissioning obligation, if any, and, for qualifying

assets, borrowing costs. The purchase price or cons truction cost is the

aggregate amount paid and the fair value of any oth er consideration given to

acquire the asset. The capitalized value of a finan ce lease is also included

within property, plant and equipment. Exchanges of assets are measured at fair value unle ss the exchange

transaction lacks commercial substance or the fair value of neither the asset

received nor the asset given up is reliably measura ble. 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 ev ident. 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 o f the asset given up is

recognized in profit or loss.

Expenditure on major maintenance refits o r repairs comprises the cost

of replacement assets or parts of assets, inspectio n costs and overhaul costs.

Where an asset or part of an asset that was separat ely depreciated is

replaced and it is probable that future economic be nefits associated with the

item will flow to the group, the expenditure is cap italized and the carrying

amount of the replaced asset is derecognized. Inspe ction costs associated

with major maintenance programmes are capitalized a nd amortized over the

period to the next inspection. Overhaul costs for m ajor maintenance

programmes are expensed as incurred. All other main tenance 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 a cquisition, field

development and future decommissioning costs are am ortized over total

proved reserves. The unit-of-production rate for th e amortization of field

development costs takes into account expenditures i ncurred to date, together

with approved future development expenditure requir ed to develop reserves.

Other property, plant and equipment is de preciated on a straight-line

basis over its expected useful life.

The useful lives of the group’s other pro perty, plant and equipment are

as follows:

The expected useful lives of property, plant and eq uipment are reviewed on an

annual basis and, if necessary, changes in useful l ives are accounted for

prospectively.

The carrying value of property, plant and equipment is reviewed for

impairment whenever events or changes in circumstan ces 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 derec ognition of the asset

(calculated as the difference between the net dispo sal proceeds and the

carrying amount of the item) is included in the inc ome 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 

# Page 112 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm109

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 i mpairment whenever

events or changes in circumstances indicate that th e carrying value of an

asset may not be recoverable, for example, low pric es or margins for an

extended period or for oil and gas assets significa nt downward revisions of

estimated volumes or increases in estimated future development expenditure.

If any such indication of impairment exists, the gr oup makes an estimate of its

recoverable amount. Individual assets are grouped f or impairment assessment

purposes at the lowest level at which there are ide ntifiable cash flows that are

largely independent of the cash flows of other grou ps of assets. An asset

group’s recoverable amount is the higher of its fai r value less costs to sell and

its value in use. Where the carrying amount of an a sset group exceeds its

recoverable amount, the asset group is considered i mpaired and is written

down to its recoverable amount. In assessing value in use, the estimated

future cash flows are adjusted for the risks specif ic to the asset group and are

discounted to their present value using a pre-tax d iscount rate that reflects

current market assessments of the time value of mon ey. An assessment is made at each reporting d ate as to whether there is

any indication that previously recognized impairmen t losses may no longer

exist or may have decreased. If such indication exi sts, the recoverable amount

is estimated. A previously recognized impairment lo ss is reversed only if there

has been a change in the estimates used to determin e the asset’ s recoverable

amount since the last impairment loss was recognize d. If that is the case, the

carrying amount of the asset is increased to its re coverable 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 recogniz ed in profit or loss. After

such a reversal, the depreciation charge is adjuste d 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 receiv ables; available-for-sale

financial assets; financial assets at fair value th rough 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 invest ments, and derivative

financial instruments. The group determines the cla ssification of its financial

assets at initial recognition. Financial assets are recognized initially at fair

value, normally being the transaction price plus, i n the case of financial assets

not at fair value through profit or loss, directly attributable transaction costs.

The subsequent measurement of financial a ssets 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 act ive market. Such assets

are carried at amortized cost using the effective i nterest 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-d erivative financial assets

that are not classified as loans and receivables. A fter 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 d etermined by reference to bid

prices at the close of business on the balance shee t date. Where there is no

active market, fair value is determined using valua tion techniques. Where fair

value cannot be reliably measured, assets are carri ed at cost.

Financial assets at fair value through profit or lo ss Derivatives, other than those designated as effecti ve 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 a t fair value. The treatment

of gains and losses arising from revaluation is des cribed below in the

accounting policy for Derivative financial instrume nts and hedging activities.

Impairment of financial assets

The group assesses at each balance sheet date wheth er a financial asset or

group of financial assets is impaired.

Loans and receivables

If there is objective evidence that an impairment l oss on loans and receivables

carried at amortized cost has been incurred, the am ount of the loss is

measured as the difference between the asset’s carr ying amount and the

present value of estimated future cash flows discou nted at the financial asset’ s original effective interest rate. The carrying amou nt 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 impaire d, the cumulative gain or loss

previously recognized in equity is transferred to t he income statement.

If there is objective evidence that an im pairment 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 asse t’s carrying amount and

the present value of estimated future cash flows di scounted 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 det ermined by the first-in firstout method and comprises direct purchase costs, cos t of production,

transportation and manufacturing expenses. Net real izable value is

determined by reference to prices existing at the b alance 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 lo wer. 

# Page 113 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm110

Notes on financial statements



### 1. Significant accounting policies continued

Financial liabilities

Financial liabilities are classified as financial l iabilities at fair value through

profit or loss; derivatives designated as hedging i nstruments in an effective

hedge; or as financial liabilities measured at amor tized cost, as appropriate.

Financial liabilities include trade and other payab les, accruals, finance debt

and derivative financial instruments. The group det ermines the classification of

its financial liabilities at initial recognition. T he measurement of financial

liabilities depends on their classification, as fol lows:

Financial liabilities at fair value through profit or loss

Derivatives, other than those designated as effecti ve 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 a t fair value, the treatment

of gains and losses arising from revaluation are de scribed below in the

accounting policy for Derivative financial instrume nts and hedging activities.

Financial liabilities measured at amortized cost

All other financial liabilities are initially recog nized 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 financia l liabilities are subsequently

measured at amortized cost using the effective inte rest 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 recog nized respectively in interest

and other revenues and finance costs.

This category of financial liabilities in cludes trade and other payables

and finance debt.

Leases

Finance leases, which transfer to the group substan tially 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 pa yments. Finance charges

are allocated to each period so as to achieve a con stant 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 ter m. Operating lease payments are recognized a s an expense in the income

statement on a straight-line basis over the lease t erm. For both finance and operating leases, co ntingent rents are recognized

in the income statement in the period in which they are incurred.

Derivative financial instruments and hedging activi ties

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. S uch derivative financial

instruments are initially recognized at fair value on the date on which a

derivative contract is entered into and are subsequ ently remeasured at fair

value. Derivatives are carried as assets when the f air 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 fina ncial instruments, as if the

contracts were financial instruments, with the exce ption of contracts that were

entered into and continue to be held for the purpos e of the receipt or delivery

of a non-financial item in accordance with the grou p’ s expected purchase, sale

or usage requirements, are accounted for as financi al instruments.

Gains or losses arising from changes in t he fair value of derivatives that

are not designated as effective hedging instruments are recognized in the

income statement.

For the purpose of hedge accounting, hedg es are classified as:

At the inception of a hedge relationship the group formally designates and

documents the hedge relationship for which the grou p wishes to claim hedge

accounting, together with the risk management objec tive and strategy for

undertaking the hedge. The documentation includes i dentification of the

hedging instrument, the hedged item or transaction, the nature of the risk

being hedged, and how the entity will assess the he dging 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 of fsetting changes in fair value

or cash flows.

Hedges meeting the criteria for hedge acc ounting 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 att ributable 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 accoun ting 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 stat ement 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 carr ying amount of a hedged

item for which the effective interest rate method i s 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 equi ty are transferred to the

income statement when the hedged transaction affect s profit or loss. The gain

or loss relating to the effective portion of intere st rate swaps hedging variable

rate borrowings is recognized in the income stateme nt within finance costs.

Where the hedged item is the cost of a no n-financial asset or liability,

such as a forecast transaction for the purchase of property, plant and

equipment, the amounts taken to equity are transfer red to the initial carrying

amount of the non-financial asset or liability.

If the hedging instrument expires or is s old, terminated or exercised

without replacement or rollover, or if its designat ion as a hedge is revoked,

amounts previously recognized in equity remain in e quity until the forecast

transaction occurs and are transferred to the incom e statement or to the initial

carrying amount of a non-financial asset or liabili ty 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 variabili ty 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. 

# Page 114 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm111

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 operati on, the effective portion of

the gain or loss on the hedging instrument is recog nized directly in equity,

while the ineffective portion is recognized in prof it 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 risk s and characteristics are not

closely related to those of the host contract. Cont racts are assessed for

embedded derivatives when the group becomes a party to them, including at

the date of a business combination. Embedded deriva tives 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 pres ent obligation (legal or

constructive) as a result of a past event, it is pr obable that an outflow of

resources embodying economic benefits will be requi red to settle the

obligation and a reliable estimate can be made of t he amount of the obligation.

Where appropriate, the future cash flow estimates a re 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 val ue 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 th e amount of the obligation

cannot be measured reliably. Contingent assets are not recognized, but are

disclosed where an inflow of economic benefits is p robable.

Decommissioning

Liabilities for decommissioning costs are recognize d 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 reliabl e estimate of that liability can

be made. Where an obligation exists for a new facil ity, such as oil and natural

gas production or transportation facilities, this w ill 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 recogn ized is the present value

of the estimated future expenditure determined in a ccordance with local

conditions and requirements.

A corresponding item of property, plant a nd equipment of an amount

equivalent to the provision is also created. This i s 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 refle cted as an adjustment to the

provision and the corresponding item of property, p lant and equipment. Environmental expenditures and liabilities

Environmental expenditures that relate to current o r future revenues are

expensed or capitalized as appropriate. Expenditure s that relate to an existing

condition caused by past operations and do not cont ribute to current or future

earnings are expensed.

Liabilities for environmental costs are r ecognized when a clean-up is

probable and the associated costs can be reliably e stimated. 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 estimat e of the expenditure required.

Where the liability will not be settled for a numbe r of years, the amount

recognized is the present value of the estimated fu ture expenditure.

Employee benefits

Wages, salaries, bonuses, social security contribut ions, paid annual leave and

sick leave are accrued in the period in which the a ssociated 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 met hod and amortized on a

straight-line basis over the service period until t he award vests. The

accounting policy for pensions and other post-retir ement benefits is described

below.

Share-based payments

Equity-settled transactions

The cost of equity-settled transactions with employ ees is measured by

reference to the fair value at the date at which eq uity instruments are granted

and is recognized as an expense over the vesting pe riod, which ends on the

date on which the relevant employees become fully e ntitled to the award. Fair

value is determined by using an appropriate valuati on model. In valuing

equity-settled transactions, no account is taken of any vesting conditions,

other than conditions linked to the price of the sh ares 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 mark et condition, which are

treated as vesting irrespective of whether or not t he market condition is

satisfied, provided that all other performance cond itions are satisfied.

At each balance sheet date before vesting , the cumulative expense is

calculated, representing the extent to which the ve sting period has expired

and management’s best estimate of the achievement o r otherwise of nonmarket conditions and the number of equity instrume nts 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 cumu lative expense since

the previous balance sheet date is recognized in th e income statement, with a

corresponding entry in equity.

Where the terms of an equity-settled awar d are modified or a new

award is designated as replacing a cancelled or set tled award, the cost based

on the original award terms continues to be recogni zed over the original

vesting period. In addition, an expense is recogniz ed over the remainder of the

new vesting period for the incremental fair value o f any modification, based on

the difference between the fair value of the origin al 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 negat ive.

Where an equity-settled award is cancelle d, 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 immediat ely. Any compensation

paid up to the fair value of the award at the cance llation or settlement date is

deducted from equity, with any excess over fair val ue being treated as an

expense in the income statement. 

# Page 115 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm112

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 corre sponding liability

recognized on the balance sheet.

Pensions and other post-retirement benefits

The cost of providing benefits under the defined be nefit plans is determined

separately for each plan using the projected unit c redit method, which

attributes entitlement to benefits to the current p eriod (to determine current

service cost) and to the current and prior periods (to determine the present

value of the defined benefit obligation). Past serv ice costs are recognized

immediately when the company becomes committed to a change in pension

plan design. When a settlement (eliminating all obl igations for benefits already

accrued) or a curtailment (reducing future obligati ons as a result of a material

reduction in the scheme membership or a reduction i n future entitlement)

occurs, the obligation and related plan assets are remeasured using current

actuarial assumptions and the resultant gain or los s is recognized in the

income statement during the period in which the set tlement or curtailment

occurs.

The interest element of the defined benef it cost represents the change

in present value of scheme obligations resulting fr om 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 ch anges in the obligation during

the year. The expected return on plan assets is bas ed on an assessment

made at the beginning of the year of long-term mark et returns on scheme

assets, adjusted for the effect on the fair value o f plan assets of contributions

received and benefits paid during the year. The dif ference between the

expected return on plan assets and the interest cos t 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 w hich they occur.

The defined benefit pension plan surplus or deficit in the balance sheet

comprises the total for each plan of the present va lue of the defined benefit

obligation (using a discount rate based on high qua lity corporate bonds), less

the fair value of plan assets out of which the obli gations are to be settled

directly. Fair value is based on market price infor mation and, in the case of

quoted securities, is the published bid price.

Contributions to defined contribution sch emes 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 cu rrently payable and

deferred tax. Interest and penalties relating to ta x 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 b alance sheet date.

Deferred tax is provided, using the liabi lity method, on all temporary

differences at the balance sheet date between the t ax bases of assets and

liabilities and their carrying amounts for financia l reporting purposes. Deferred tax liabilities are recognized for all tax able temporary differences:

Deferred tax assets are recognized for all deductib le temporary differences,

carry-forward of unused tax assets and unused tax l osses, to the extent that it

is probable that taxable profit will be available a gainst which the deductible

temporary differences and the carry-forward of unus ed tax assets and unused

tax losses can be utilized:

The carrying amount of deferred tax assets is revie wed 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 pa rt of the deferred income tax

asset to be utilized.

Deferred tax assets and liabilities are m easured at the tax rates that are

expected to apply to the year when the asset is rea lized or the liability is

settled, based on tax rates (and tax laws) that hav e 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 pa yable to, the taxation

authority is included as part of receivables or pay ables 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, a nd are shown as

deductions from shareholders’ equity at cost. Consi deration received for the

sale of such shares is also recognized in equity, w ith 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 t he income statement on the

purchase, sale, issue or cancellation of equity sha res. • Except where the deferred tax liability arises on g oodwill that is not tax

deductible or the initial recognition of an asset o r liability in a transaction that

is not a business combination and, at the time of t he transaction, affects

neither the accounting profit nor taxable profit or loss.

• In respect of taxable temporary differences associa ted with investments in

subsidiaries, jointly controlled entities and assoc iates, except where the

group is able to control the timing of the reversal of the temporary

differences and it is probable that the temporary d ifferences will not reverse

in the foreseeable future.

• Except where the deferred income tax asset relating to the deductible

temporary difference arises from the initial recogn ition 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 asso ciated with investments

in subsidiaries, jointly controlled entities and as sociates, deferred tax assets

are only recognized to the extent that it is probab le that the temporary

differences will reverse in the foreseeable future and taxable profit will be

available against which the temporary differences c an be utilized.

• Where the customs duty or sales tax incurred on a purchase of goods and

services is not recoverable from the taxation autho rity, 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 applica ble.

• Receivables and payables are stated with the amount of customs duty or

sales tax included. 

# Page 116 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm113

Notes on financial statements



### 1. Significant accounting policies continued

Revenue

Revenue arising from the sale of goods is recognize d when the significant

risks and rewards of ownership have passed to the b uyer and it can be reliably

measured.

Revenue is measured at the fair value of the consideration received or

receivable and represents amounts receivable for go ods provided in the

normal course of business, net of discounts, custom s duties and sales taxes.

Revenues associated with the sale of oil, natural gas, natural gas

liquids, liquefied natural gas, petroleum and chemi cals products and all other

items are recognized when the title passes to the c ustomer. Physical

exchanges are reported net, as are sales and purcha ses made with a

common counterparty, as part of an arrangement simi lar to a physical

exchange. Similarly, where the group acts as agent on behalf of a third party

to procure or market energy commodities, any associ ated fee income is

recognized but no purchase or sale is recorded. Add itionally, where forward

sale and purchase contracts for oil, natural gas or power have been

determined to be for trading purposes, the associat ed sales and purchases

are reported net within sales and other operating r evenues whether or not

physical delivery has occurred.

Generally, revenues from the production o f 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 produc tion sold and the group’s

share of production are not significant.

Interest income is recognized as the inte rest accrues (using the

effective interest rate that is the rate that exact ly discounts estimated future

cash receipts through the expected life of the fina ncial instrument) to the net

carrying amount of the financial asset.

Dividend income from investments is recog nized when the

shareholders’ right to receive the payment is estab lished.

Research

Research costs are expensed as incurred.

Finance costs

Finance costs directly attributable to the acquisit ion, construction or production

of qualifying assets, which are assets that necessa rily 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 sub stantially 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 ma nagement 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 reve nues and expenses

during the reporting period. Actual outcomes could differ from those estimates.

Impact of new International Financial Reporting Sta ndards

Adopted for 2008

Standards and interpretations adopted in the year h ad no significant impact on

the financial statements. Not yet adopted

The following pronouncements from the IASB will bec ome effective for future

financial reporting periods and have not yet been a dopted 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 resource s and in assessing

performance. The new standard sets out the required disclosures for operating

segments and is effective for annual periods beginn ing on or after 1

January 2009. BP will adopt the new standard with e ffect from 1 January 2009

and expects no change to its segments that are sepa rately reported but

anticipates that its segmental analysis will be bas ed on non-GAAP measures

as used by the chief operating decision maker. Ther e will be no effect on the

group’s reported income or net assets. IFRS 8 has b een adopted by the EU.

In September 2007, the IASB issued Amendm ents to IAS 1

‘Presentation of Financial Statements’ – A Revised Presentation, which

requires separate presentation of owner and non-own er changes in equity by

introducing the statement of comprehensive income. The statement of

recognized income and expense will no longer be pre sented. 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 period s beginning on or after 1

January 2009 and BP will adopt it from that date. T here will be no effect on the

group’s reported income or net assets. IAS 1 Revise d has been adopted by

the EU.

In January 2008, the IASB issued a revise d version of IFRS 3 ‘ Business

Combinations’. The revised standard still requires the purchase method of

accounting to be applied to business combinations b ut will introduce some

changes to existing accounting treatment. For examp le, 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 paren t’s share of net assets or

it may include goodwill related to the minority int erest. All transaction costs are

expensed. The standard is applicable to business co mbinations occurring in

accounting periods beginning on or after 1 July 200 9 and BP plans to adopt it

with effect from 1 January 2010. Assets and liabili ties 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 gr oup’s reported income or net

assets on adoption. The revised standard has not ye t 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 t here is

no change in control. Such transactions will no lon ger result in goodwill or

gains or losses. When control is lost, any remainin g interest in the entity is

remeasured to fair value and a gain or loss recogni zed 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 h as not yet completed its

evaluation of the effect of adoption. The revised s tandard has not yet been

adopted by the EU.

In addition, IFRIC 18 ‘Transfers of Asset s 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 adopt ing this interpretation.

There are no other standards and interpre tations in issue but not yet

adopted that the directors anticipate will have a m aterial effect on the reported

income or net assets of the group. 

# Page 117 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 2. Resegmentation

With effect from 1 January 2008 the organizational structure of BP has been simplified into two busine ss segments – Exploration and Production and Refini ng and

Marketing. A separate business, Alternative Energy, handles BP’s low-carbon businesses and future grow th options outside oil and gas, including solar, wi nd, gasfired power, hydrogen, biofuels and coal conversion

. As a result, and with effect from 1 Janua ry 2008:

As a result of the transfers identified above, Othe r businesses and corporate has been redefined. It n ow consists of the Alternative Energy business, Shi pping, the

group’s aluminium asset, Treasury (which includes i nterest income on the group’s cash and cash equival ents) 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 rep ort separately.

• The natural gas liquids (NGLs), liquefied natural g as and gas and power marketing and trading business es were transferred from the Gas, Power and

Renewables segment to the Exploration and Productio n segment.

• The Alternative Energy business was transferred fr om the Gas, Power and Renewables segment to Other b usinesses and corporate.

• The Emerging Consumers Marketing Unit was transferr ed from Refining and Marketing to Alternative Energ y.

• The Biofuels business was transferred from Refinin g 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 grou p

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 

# Page 118 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 3. Acquisitions

Acquisitions in 2008

BP made a number of acquisitions in 2008 for a tota l consideration of $403 million. These business com binations were in the Exploration and Production se gment

and Other businesses and corporate and the most sig nificant was the acquisition of Whiting Clean Energ y, a cogeneration power plant. Fair value adjustmen ts

have been made on a provisional basis to the acquir ed assets and liabilities. Goodwill of $1 million h as been recognized on these acquisitions.

Acquisitions in 2007

BP made a number of acquisitions in 2007 for a tota l consideration of $1,200 million. These business c ombinations were predominantly in the Refining and

Marketing segment, the most significant of which wa s the acquisition of Chevron’s Netherlands manufact uring company, Texaco Raffiniderij Pernis B.V. The

acquisition included Chevron’s 31% minority shareho lding 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 T EAM terminal to the refinery. Fair value adjustment s were made to the acquired assets and liabilities. Goodwi ll of $270 million arose on these acquisitions.

Acquisitions in 2006

BP made a number of acquisitions in 2006 for a tota l consideration of $256 million. All these business combinations were in Other businesses and corporat e. Fair

value adjustments were made to the acquired assets and liabilities and goodwill of $64 million arose o n these acquisitions.



# 4. Non-current assets held for sale and discontinued oper ations

Non-current assets held for sale

In December 2007, BP signed a memorandum of underst anding with Husky Energy Inc. to form an integrated North American oil sands business. The transaction

was completed on 31 March 2008, with BP contributin g its Toledo refinery to a US jointly controlled en tity to which Husky contributed $250 million cash a nd a

payable of $2,588 million. The Toledo refinery asse ts and associated liabilities were classified as a disposal group held for sale at 31 December 2007. N o impairment loss was recognized at the time of recla ssification of the Toledo disposal group as held fo r sale nor at 31 December 2007. For further informa tion see

Notes 5 and 26.

The major classes of assets and liabiliti es of the Toledo disposal group, reported within th e Refining and Marketing segment, classified as hel d 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 Decem ber 2005. In 2006 a loss before taxation of $184 mi llion

was incurred which related to post -closing adjustments. These adjustments also reduce d disposal proceeds by $34 million.

Financial information for the Innovene op erations after group eliminations is presented belo w.

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 classif ied 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 val ue 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) 

# Page 119 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 5. Disposals

As part of the strategy to upgrade the quality of i ts asset portfolio, the group has an active program me to dispose of non-strategic assets. In the norma l course of

business in any particular year, the group may sell interests in exploration and production properties , service stations and pipeline interests as well a s non-core businesses. The group may also dispose of other ass ets, such as refineries, when this meets strategic objectives.

Cash received during the year from dispos als amounted to $929 million (2007 $4.3 billion and 2006 $6.3 billion).

The major transactions in 2008 were the d isposal of our Toledo refinery to an entity which w e jointly control in the US and our continued dispo sal of

company-owned and company-operated retail sites in the US.

The major transactions in 2007 were the d isposals of our Coryton refinery, our exploration a nd production and gas infrastructure business in th e Netherlands,

our interest in non-core Permian assets in the US a nd our interest in the Entrada field in the Gulf of Mexico.

The major transactions in 2006 were the d isposals of our interests in the Gulf of Mexico She lf and our interest in the Shenzi discovery in the Gulf of Mexico.

The principal transactions for each business segmen t are described below.

Exploration and Production

The group divested interests in a number of oil and natural gas properties in all three years. There w ere no significant disposals in 2008.

During 2007, the major transactions were the disposal of an exploration and production and g as infrastructure business in the Netherlands and t he

divestments of our interests in non-core Permian as sets 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 Sh elf, 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 numb er 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 Ena gas, 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 par ticular, in 2008, our continued disposal of sites i n the US. In

addition, in 2008 we contributed our Toledo refiner y to a US jointly controlled entity in an exchange transaction with Husky Energy and disposed of our i nterest 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 r efinery in the UK, our interest in the West Texas P ipeline in the US, our interest in the Samsung Petr ochemical

Company in South Korea and other interests in Franc e, 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 pipel ines.

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 

# Page 120 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 5. Disposals continued

Other businesses and corporate

In 2008, the group disposed of miscellaneous non-co re assets.

There were no significant disposals in 20 07. During 2006, the group disposed of miscellaneou s non-core businesses and assets.

Summarized financial information for the sale of bu sinesses 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 businesses a 1,721 1,384 167

Total consideration 2,838 2,508 399

Fair value of interest received in a jointly contro lled entity (2,838 )

– – Consideration received (receivable) b 11 10 (74 )

Closing adjustments associated with the sale of Inn ovene

– – ( 34 )

Proceeds from the sale of businesses c 11 2,518 291

a Of which $929 million gain has not been recognized in the income statement in 2008 as it represents an unreal ized gain on the transfer of the Toledo refinery into a jointly controlled entity.

b Consideration received from prior year disposals or not yet received from current year disposals.

c Net of cash and cash equivalents disposed of nil (2007 $115 million and 2006 $2 million). 

# Page 121 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 6. Segmental analysis

The group’s primary format for segment reporting is business segments and the secondary format is geog raphical segments. The risks and returns of the gro up’s

operations are primarily determined by the nature o f the different activities that the group engages i n, rather than the geographical location of these o perations. This

is reflected by the group’s organizational structur e and internal financial reporting systems.

In 2008, BP had two reportable operating segments: Exploration and Production and Refining a nd Marketing. Exploration and Production’s activiti es include

oil and natural gas exploration, development and pr oduction (upstream activities), together with relat ed pipeline, transportation and processing activiti es (midstream

activities), as well as the marketing and trading o f natural gas (including LNG), power and natural ga s liquids (NGLs). The activities of Refining and Ma rketing

include the supply and trading, refining, manufactu ring, marketing and transportation of crude oil, pe troleum 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 grou p’s aluminium asset, Treasury (which in the segment al

analysis includes all of the group’s cash, cash equ ivalents and associated interest income), and corpo rate activities worldwide.

The accounting policies of the operating segments are the same as the group’s accounting pol icies described in Note 1.

Sales between segments are made at prices that approximate market prices, taking into accoun t the volumes involved. Segment revenues and segmen t

results include transactions between business segme nts. 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 bas ed on the location of the group’s assets. The UK an d the US are significant countries of activity for the group; the

other geographical segments are groupings of countr ies determined by geographical location.

Sales to external customers are based on the location of the seller, which in most circumsta nces is not materially different from the location of the customer.

Crude oil and LNG are commodities for which there i s an international market and buyers and sellers ca n be widely separated geographically. The UK segmen t

includes the UK-based international activities of R efining 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 pe nsions 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 

# Page 122 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 pe nsions and other post

retirement 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 

# Page 123 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 pe nsions

and other post-retirement benefits – – – (5 16) (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 s ell 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 

# Page 124 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 pe nsions 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 

# Page 125 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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) – (83,38 3)

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 pe nsions 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 

# Page 126 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 pe nsions and other post

retirement 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 s ell 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 

# Page 127 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 7. Interest and other revenues

8. Gains on sale of businesses and fixed assets

The principal transactions giving rise to these gai ns 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 w ere no significant divestments during 2008.

The major divestments during 2007 that re sulted 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 Entra da field in the Gulf of Mexico.

The major divestments during 2006 that re sulted in gains were the sales of our interest in t he 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 c ontribution of Toledo refinery to a jointly control led entity with

Husky Energy and the disposal of our interest in th e Dixie Pipeline.

During 2007, the major transactions that resulted in gains were the divestment of Coryton re finery in the UK, the interest in the West Texas Pi peline in the US

and the interest in the Samsung Petrochemical Compa ny 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 in cluding the

shareholding in Zhenhai Refining and Chemicals Comp any in China, the shareholding in Eiffage, the Fren ch-based construction company, and pipeline assets.

Other businesses and corporate

There were no significant disposals in 2008 and 200 7.

During 2006, the group disposed of its et hylene oxide business.

Additional information on the sale of businesses an d 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 a ssets 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



# Page 128 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 Production a

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

UK b 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

UK b 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

a At the end of 2006, BP adopted the US Securities and Exchange Commission (SEC) rules for estimating oil and n atural gas reserves instead of the UK accounting rules cont ained in the Statement of Recommended

Practice ‘Accounting for Oil and Gas Exploration, Developm ent, 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 inco me statement in respect of oil and natural gas proper ties 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 per iods’ results. The group’s actual DD&A charge for 2006 w as $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 thr ee months of 2006. For 2007, it was estimated that t he 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 over all 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 in terpretations of SEC regulations relating to the use o f technology (mainly seismic) to estimate

reserves in the reservoir away from wellbores and the repo rting of fuel gas (i.e. gas used for fuel in operation s) 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 i s disclosed. In addition, the use of

SEC reserves for accounting purposes makes our results more co mparable with those of our major competitors.

b UK area includes the UK

- based international activities of Refining and Marketing

. 

# Page 129 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 11. Impairment and losses on sale of businesses and fixed assets

Impairment

In assessing whether a write-down is required in th e carrying value of a potentially impaired intangib le asset, item of property, plant and equipment or an equityaccounted investment, its carrying value is compare d with its recoverable amount. The recoverable amou nt is the higher of the asset’s fair value less cos ts to sell

and value in use. Given the nature of the group’s a ctivities, information on the fair value of an asse t is usually difficult to obtain unless negotiation s with potential

purchasers are taking place. Consequently, unless i ndicated otherwise, the recoverable amount used in assessing the impairment charges described below is value

in use. The group estimates value in use using a di scounted cash flow model. The future cash flows are adjusted for risks specific to the asset and are d iscounted

using a pre-tax discount rate. This discount rate i s derived from the group’s post-tax weighted averag e 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. Typicall y rates of 11% or 13% are used (2007 11% or 13%). T he 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. Th e main elements were the writing down of our invest ment

in Rosneft by $517 million to its fair value determ ined by reference to an active market, due to a sig nificant decline in the market value of the investm ent,

impairment of oil and gas properties in the Gulf of Mexico of $270 million triggered by downward revis ions of reserves, an impairment of exploration asse ts in

Vietnam of $210 million following BP’s decision to withdraw from activities in the area concerned, imp airment of oil and gas properties in Egypt of $85 m illion

triggered by cost increases and several other indiv idually insignificant impairment charges amounting to $104 million.

These charges were partly offset by rever sals of previously recognized impairment charges am ounting to $155 million. Of this total, $122 millio n resulted from

a reassessment of the economics of Rhourde El Bague l in Algeria.

During 2007, the Exploration and Producti on segment recognized impairment losses of $292 mil lion. The main elements were a charge of $112 milli on 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 Wes t Shmidt licence block in

Sakhalin and a $52 million write-off of the Whitney Canyon gas plant in US Lower 48 driven by manageme nt’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 reve rsals of previously recognized impairment charges a mounting to $237 million. Of this total, $208 milli on resulted

from a reassessment of the decommissioning liabilit y for damaged platforms in the Gulf of Mexico Shelf . The remaining $29 million related to other indivi dually

insignificant impairment reversals, resulting from favourable revisions to the estimates used in deter mining the assets’ recoverable amounts.

During 2006, Exploration and Production r ecognized a net gain on impairment. The main elemen t was a $340 million credit for reversals of previo usly booked

impairments relating to the UK North Sea, US Lower 48 and China. These reversals resulted from a posit ive change in the estimates used to determine the a ssets’

recoverable amount since the impairment losses were recognized. This was partially offset by impairmen t losses totalling $237 million. The major element was a charge of $109 million against intangible assets re lating to properties in Alaska. The trigger for the impairment test was the decision of the Alaska Dep artment of

Natural Resources to terminate the Point Thompson U nit Agreement. We are defending our right through t he appeal process. In addition, there was a charge of

$100 million relating to certain North American pip eline assets. The trigger for impairment testing wa s the reduction in future pipeline tariff revenues and increased

ongoing operational costs. The remaining $28 millio n relates to other individually insignificant impai rments, the impairment tests for which were trigger ed by

downward reserves revisions and increased tax burde n.

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 s ell and on disposal of Innovene operations

– – 184

1,733 1,679 733

Innovene operations

– – ( 184 )

Continuing operations 1,733 1,679 549 

# Page 130 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 11. Impairment and losses on sale of businesses and fixed assets continued

Refining and Marketing

During 2008, the Refining and Marketing segment rec ognized impairment losses on a number of assets whi ch in total amounted to $159 million.

The main component of the 2007 impairment charge of $1,186 million arose because of a decisi on to sell our company-owned and company-operated s ites

in the US resulting in a $610 million write-down of the carrying amount of the sites to fair value les s costs to sell. Following a decision to sell certa in assets at our

Acetyls plant in Hull, UK, we wrote down the carryi ng amount of these assets to fair value less costs to sell leading to an impairment charge of $186 mil lion.

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 bal ance relates principally to the write-downs of asse ts elsewhere in the segment portfolio.

During 2006, certain assets in our Retail and Aromatics & Acetyls businesses were written do wn to fair value less costs to sell.

Other businesses and corporate

During 2008, Other businesses and corporate recogni zed impairment losses totalling $227 million primar ily related to various assets in the Alternative En ergy

business.

There were no significant impairments in 2007.

The impairment charge for 2006 relates to remaining chemical assets after the sale of Innove ne.

Loss on sale of fixed assets

The principal transactions that give rise to the lo sses 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 200 6, the largest component of the loss is attributed to the sale of

properties in the Gulf of Mexico Shelf, which inclu ded increases in decommissioning liability estimate s associated with the hurricane-damaged fields that were divested during the year.

Refining and Marketing

For 2008, the principal transactions contributing t o the loss were disposals of retail sites in the US and Europe.

For 2007, the principal transactions cont ributing to the loss were related to the decision t o withdraw from the company-owned and company-opera ted

channel of trade in the US and retail churn. Retail churn is the overall process of acquiring and disp osing of retail sites by which the group aims to im prove the

quality and mix of its portfolio of service station s. For 2006, the principal transactions cont ributing 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 benefi t from

the synergies of the acquisition. For Exploration a nd Production, goodwill has been allocated to each geographic region, that is UK, Rest of Europe, US a nd 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 im paired, the carrying amount of the cash-generating unit (including goodwill) is compared with the reco verable

amount of the cash-generating unit. The recoverable amount is the higher of fair value less costs to s ell and value in use. In the absence of any informa tion about

the fair value of a cash-generating unit, the recov erable amount is deemed to be the value in use.

The group calculates the recoverable amou nt as the value in use using a discounted cash flow model. The future cash flows are adjusted for risk s specific to

the cash-generating unit and are discounted using a pre-tax discount rate. The discount rate is derive d from the group’s post-tax weighted average cost o f capital

and is adjusted where applicable to take into accou nt any specific risks relating to the country where the cash-generating unit is located. Typically rat es of 11% or

13% are used (2007 11% or 13%). The rate to be appl ied to each country is reassessed each year. A disc ount rate of 11% has been used for all goodwill

impairment calculations performed in 2008 (2007 11% ).

The three-year or four-year business segm ent plans, which are approved on an annual basis by senior management, are the primary source of infor mation

for the determination of value in use. They contain forecasts for oil and natural gas production, refi nery throughputs, sales volumes for various types o f refined

products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step i n the preparation of these plans, various environme ntal

assumptions, such as oil prices, natural gas prices , refining margins, refined product margins and cos t inflation rates, are set by senior management. Th ese environmental assumptions take account of existing prices, global supply-demand equilibrium for oil an d natural gas, other macroeconomic factors and hist orical

trends and variability.

For the purposes of impairment testing, t he group’s Brent oil price assumption is an average $49 per barrel in 2009, $59 per barrel in 2010, $6 5 per barrel in

2011, $68 per barrel in 2012, $70 per barrel in 201 3 and $75 per barrel in 2014 and beyond (2007 avera ge $90 per barrel in 2008, $86 per barrel in 2009, $84 per

barrel in 2010, $84 per barrel in 2011, $84 per bar rel 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 

# Page 131 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 bey ond (2007 average of $7.87/mmBtu in 2008, $8.33/mmB tu in 2009, $8.26/mmBtu in 2010, $8.12/mmBtu in

2011, $8.00/mmBtu in 2012 and $7.50/mmBtu in 2013 a nd 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 v iews of global supply and demand, building upon pas t experience of the industry and consistent with a

number of external economic forecasts. These prices are adjusted to arrive at appropriate consistent p rice assumptions for different qualities of oil and gas.

Exploration and Production

The value in use is based on the cash flows expecte d to be generated by the projected oil or natural g as production profiles up to the expected dates of cessation

of production of each producing field. Management b elieves that the cash flows generated over the esti mated life of field is the appropriate basis upon w hich to

assess goodwill and individual assets for impairmen t, as the production profile and related cash flows can be estimated from the company’s past experienc e. The

date of cessation of production depends on the inte raction of a number of variables, such as the recov erable quantities of hydrocarbons, the production p rofile of

the hydrocarbons, the cost of the development of th e infrastructure necessary to recover the hydrocarb ons, 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 com puted using appropriate individual economic models and key assumptions agreed by BP’s management for t he

purpose. Capital expenditure and operating costs fo r the first four years and expected hydrocarbon pro duction profiles up to 2020 are derived from the bu siness

segment plan. Estimated production quantities and c ash flows up to the date of cessation of production on a field-by-field basis are developed to be cons istent with

this. The production profiles used are consistent w ith the resource volumes approved as part of BP’s c entrally-controlled process for the estimation of p roved

reserves and total resources.

Consistent with prior years, the 2008 rev iew for impairment was carried out during the fourt h quarter. Detailed calculations were performed for the US and the

UK. As permitted by IAS 36, the detailed calculatio ns performed in 2005 were used for the 2008 impairm ent test on the goodwill for the Rest of World as t he criteria

of IAS 36 were considered to be satisfied: the exce ss of the recoverable amount over the carrying amou nt was substantial in 2005; there had been no signi ficant

change in the assets and liabilities; and the likel ihood that the recoverable amount would be less tha n the carrying amount at the time of the test was r emote.

The following table shows the carrying am ount of the goodwill allocated to each of the regio ns of the Exploration and Production segment and, f or the US and

the UK, the amount by which the recoverable amount (value in use) exceeds the carrying amount of the g oodwill and other non-current assets in the cashgenerating units to which the goodwill has been all ocated. No impairment charge is required.

The key assumptions required for the valu e-in-use estimation are the oil and natural gas pri ces, production volumes and the discount rate. To t est 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 produc tion

volumes and oil and natural gas prices, management has developed ‘rules of thumb’ for key assumptions. Applying these gives an indication of the impact o n 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 amoun t to be equal to the total carrying amount for each cash-generating

unit would be of the order of $38 per barrel for th e UK and $50 per barrel for the US. It was estimate d that the long-term price of gas that would cause the total

recoverable amount to be equal to the total carryin g amount of goodwill and related non-current assets for the US cash-generating unit would be of the or der of

$4/mmBtu (Henry Hub). As a significant amount of ga s from the North Sea is sold under fixed-price cont racts, or contracts priced using non-gas indices, i t is

estimated that no reasonably possible change in gas prices would cause the UK headroom to be reduced t o zero. It was estimated that no reasonably possibl e

change in oil and gas prices would cause the headro om 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 managem ent as part

of the long- term planning process. It is estimated that, if all our production were to be reduced by 10% for the w hole of the next 15 years, this would not be suffic ient

to reduce the excess of recoverable amount over the carrying amounts of each cash-generating unit to z ero. Consequently, management believes no reasonabl y possible change in the production assumption would cause the carrying amounts to exceed the recoverabl e amounts.

Management also believes that currently t here is no reasonably possible change in discount r ate 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 

# Page 132 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 i nto geographically-based Fuels Value Chain units (F VC) and consequently the cash-generating units to w hich

goodwill is allocated have been redefined. The good will previously allocated to the global Refining an d Retail units has been aggregated and reallocated to the FVC

units that are expected to benefit from the synergi es of the business combinations that gave rise to t he goodwill. As part of this reallocation a small a mount of

goodwill was also allocated to business units inclu ded in ‘Other’. Goodwill is now allocated to the fo llowing cash-generating units: Rhine FVC, US West C oast FVC,

Lubricants and Other.

For all cash-generating units, the cash f lows 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 f or a period of 10 years have been discounted and ag gregated with a terminal value. A key assumption fo r the

FVCs is the Global Indicator Margin (GIM). Each reg ional 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 extrapo lated using a 1.2% growth rate.

The key assumptions to which the calculat ion of value in use for the Rhine FVC unit is most sensitive are refinery gross margins, refinery prod uction volumes

and discount rate. The average value assigned to th e refinery gross margin during the plan period is b ased on a $5.50 per barrel GIM. The average value a ssigned

to the refinery production volume is 250mmbbl a yea r over the plan period. These key assumptions refle ct past experience and are consistent with external

sources.

The Rhine FVC’s recoverable amount exceed s its carrying amount by $3.6 billion. Based on sen sitivity 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 chang e in the GIM of $1.70 per barrel, the recoverable a mount 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 bill ion

and, if there is an adverse change in refinery volu mes of 36mmbbl a year, the recoverable amount of th e Rhine FVC would equal its carrying amount; and (i ii) a

change of 1% in the discount rate would change the Rhine FVC’s value in use by $0.8 billion and, if th e discount rate increases to 17% the value in use o f the

Rhine FVC would equal its carrying amount.

US West Coast FVC

Cash flows beyond the three-year period are extrapo lated using a 2% growth rate.

The key assumptions to which the calculat ion 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 assign ed to the refinery gross margin during the plan per iod is based on a $7.60 per barrel GIM. The average value

assigned to the refinery production volume is 170mm bbl a year over the plan period. These key assumpti ons reflect past experience and are consistent with

external sources.

The West Coast FVC’s recoverable amount e xceeds its carrying amount by $1.6 billion. Based o n sensitivity analysis, it is estimated that: (i) i f the GIM

changes by $1 per barrel, the West Coast FVC’s valu e in use changes by $1.5 billion and, if there was an adverse change in the GIM of $1.10 per barrel, t he

recoverable amount of the West Coast FVC would equa l its carrying amount; (ii) if the volume assumptio n changes by 8mmbbl a year, the West Coast FVC’s va lue

in use changes by $1.1 billion and, if there is an adverse change in refinery volumes of 12mmbbl a yea r, the recoverable amount of the West Coast FVC wou ld

equal its carrying amount; and (iii) a change of 1% in the discount rate would change the West Coast F VC’s value in use by $0.6 billion and, if the disco unt 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 extrapo lated using a 3% growth rate (2007 3%).

For the Lubricants unit, the key assumpti ons to which the calculation of value in use is mos t 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 cent s per litre (2007 65 cents per litre) and 3.4 billi on 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, th e Lubricants unit’s value in use changes by $1.4 bi llion and, if there is an adverse change in Lubrica nts sales

volumes of 700 million litres a year, the recoverab le amount of the Lubricants unit would equal its ca rrying amount; and (iii) a change of 1% in the disc ount rate

would change the Lubricants unit ’s value in use by $1.4 billion and, management bel ieves no reasonably possible change in the discount rate would lead to the

Lubricants unit’s value in use being equal to its c arrying amount.

Comparative narrative information is not generally shown because, due to the reorganization of the Ref ining and Marketing business in 2008, the informati on 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 

# Page 133 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 r espect of operating leases. Where an operating leas e is entered into solely by the group as the operat or of a

jointly controlled asset, the total cost is include d in this analysis, irrespective of any amounts tha t have been or will be reimbursed by joint venture partners. Where

BP is not the operator of a jointly controlled asse t, and has not co-signed the lease, operating lease costs and future minimum lease payments are exclud ed 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, b efore deducting related rental income from operatin g sub-leases of $557 million (2007 $618 million), a re

shown in the table below. This does not include fut ure 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 commitment s relating to drilling rigs are $7,730 million (200 7 $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 measure d at fair

value through profit or loss (496 ) 12 179

Other currency exchange (gains) losses (credited) c harged 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 

# Page 134 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 pay ments are

excluded from the information given below. However, where BP has co-signed the lease, BP’s share of th e lease costs and future minimum lease payments are

included.

Of which, future minimum operating lease commitment s relating to drilling rigs are $4,660 million (200 7 $3,736 million).

The group enters into operating leases of ships, plant and machinery, commercial vehicles an d land and buildings. Typical durations of the leas es are as

follows:

The group has entered into a number of structured o perating leases for ships and in most cases the lea se rental payments vary with market interest rates. The

variable portion of the lease payments above or bel ow the amount based on the market interest rate pre vailing at inception of the lease is treated as con tingent

rental expense. The group also routinely enters int o bareboat charters, time-charters and spot-charter s for ships on standard industry terms.

The most significant items of plant and m achinery 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 b y oil prices and may be significantly different fro m the rates at the

inception of the lease. Differences between the rat e paid and the rate at inception of the lease are t reated as contingent rental expense.

Commercial vehicles hired under operating leases are primarily railcars. Retail service stat ion sites and office accommodation are the main ite ms in the land

and buildings category.

The terms and conditions of these operati ng leases do not impose any significant financial r estrictions on the group. Some of the leases of shi ps and

buildings allow for renewals at BP’s option.



# 17. Exploration for and evaluation of oil and natura l gas resources

The following financial information represents the amounts included within the group totals relating t o activity associated with the exploration for and evaluation of

oil and natural gas resources. All such activity is recorded within the Exploration and Production seg ment.

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 year a 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

a In addition to these amounts, an impairment charge of $210 million was recognized in 2008 relating to explor ation assets in Vietnam following BP ’ s decision to withdraw from activities in the area concer ned. 

# Page 135 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 18. Auditor’s remuneration

Total fees for 2008 include $3 million of additiona l fees for 2007 (2007 includes $7 million of additi onal fees for 2006 and 2006 includes $5 million of additional fees

for 2005). Auditor’s remuneration is included in th e income statement within distribution and administ ration 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-a pproval policies and procedures for the engagement of Ernst & Young to render audit and certain assura nce and

tax services. The audit fees payable to Ernst & You ng are reviewed by the audit committee in the conte xt of other global companies for cost-effectiveness . Ernst &

Young performed further assurance and tax services that were not prohibited by regulatory or other pro fessional requirements and were pre-approved by the

committee. Ernst & Young is engaged for these servi ces when its expertise and experience of BP are imp ortant. Most of this work is of an audit nature. Ta x services were awarded either through a full competi tive tender process or following an assessment of t he expertise of Ernst & Young compared with that of other

potential service providers. These services are for a fixed term.



# 19. Finance costs

a Tax 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 t he discount on provisions and on other payables is now included within finance costs. Previously, it w as included

within other finance income or expense. This line i tem has now been renamed net finance income or expe nse relating to pensions and other post -retirement

benefits. This change does not affect profit before interest and taxation, profit before taxation or p rofit for the period in the group income statement. For 2007

$283 million was reclassified from other finance in come 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 audi t of the company’s accounts a 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

a Fees 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



# Page 136 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 th e UK statutory corporation tax rate to the effectiv e tax rate of the group on profit before taxation f rom 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 i n 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 othe r 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 u tilized) (1 ) (1 ) (1 )

Other

– – 1

Effective tax rate 37 33 36 

# Page 137 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 20. Taxation continued

Deferred tax

In 2008, there have been no changes in the statutor y tax rates that have materially impacted the group ’s tax charge. The enactment, in 2007, of a 2% redu ction in

the rate of UK corporation tax on profits arising f rom activities outside the North Sea reduced the de ferred tax charge by $189 million in that year.

Deferred tax assets are recognized to the extent that it is probable that taxable profit wil l be available against which the deductible tempora ry differences and

the carry-forward of unused tax assets and unused t ax 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 ta x asset has been recognized in respect of $4.2 bill ion of losses (2007 $3.2 billion). No deferred tax asset has been

recognized in respect of $2.1 billion of losses (20 07 $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 cre dits 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 liabi lity associated with unremitted profits from overse as 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 yea rs after generation, and substantially all expire i n the period

2014-2018.

The major components of temporary differe nces at the end of 2008 are tax depreciation, US in ventory holding gains (classified as other taxable temporary

differences), provisions, and pension plan and othe r 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-accou nted entities.



# 21. Dividends

The group does not account for dividends until they are paid. The accounts for the year ended 31 Decem ber 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 yea r ended 31 December 2009.

134 Notes on financial statements

$ million

Income statement Balance sheet

2008 2007 a 2006 a 2008 2007 a

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 t ax liability (766 ) 607 716 16,198 19,215

a A minor amendment has been made to the comparative am ounts 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 re cognized 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

– – 

# Page 138 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 22. Earnings per ordinary share

Basic earnings per ordinary share amounts are calcu lated by dividing the profit for the year attributa ble to ordinary shareholders by the weighted averag e number of

ordinary shares outstanding during the year. The av erage number of shares outstanding excludes treasur y 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 calcul ation, the weighted average number of shares outsta nding during the year is adjusted for the number of shares that

are potentially issuable in connection with employe e share-based payment plans using the treasury stoc k method. In addition, for 2006 the profit attribut able to

ordinary shareholders has been adjusted for the unw inding of the discount on the deferred consideratio n for the acquisition of our interest in TNK-BP and the

weighted average number of shares outstanding durin g the year has been adjusted for the number of shar es to be issued for the deferred consideration for the

acquisition of our interest in TNK-BP.

The number of ordinary shares outstanding at 31 Dec ember 2008, excluding treasury shares and the share s held by the ESOPs, and including certain shares t hat

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 nu mber of ordinary shares outstanding as a result of share

issues related to employee share plans. The number of potential ordinary shares issuable through the e xercise of options related to employee share plans was

191,340,183 at 31 December 2008. There has been a d ecrease of 42,722,753 in the number of potential or dinary shares between 31 December 2008 and 18

February 2009.

Loss per share for the discontinued opera tions in 2006 is derived from the net loss attribut able to ordinary shareholders from discontinued ope rations of

$25 million, divided by the weighted average number of ordinary shares for both basic and diluted amou nts 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 B P shareholders 21,157 20,845 22,340

Less dividend requirements on preference shares 2 2 2

Profit from continuing operations attributable to B P 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 ordi nary 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 issuab le under employee share schemes 172,690 163,486 109,813

Potential dilutive effect of ordinary shares issuab le as consideration for BP ’ s interest in

the TNK-BP joint venture

– – 58,118

18,962,517 19,326,875 20,195,458



# Page 139 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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

Transfers a

– – ( 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 )

Transfers b

– – ( 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) (2,9 75)

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 include d 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

a Includes $337 million transferred to equity

- accounted investments and $415 million transferred fro m intangible assets.

b Includes $75 million transferred to equity

- accounted investments. 

# Page 140 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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

Additions a 4,738 354 5,092 2,000 548 2,548

Transfers b (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

a Included in additions to exploration expenditure in 200 8 is $2,331 million in relation to BP ’ s purchase of interests in shale gas assets in the US.

b Included in transfers of exploration expenditure in 2007 is $84 million transferred to equity

- accounted investments. 

# Page 141 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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 ven ture.

Summarized financial information for the group’s sh are of jointly controlled entities is shown below.

In December 2007, BP signed a memorandum of underst anding with Husky Energy Inc. (Husky) to form an in tegrated North American oil sands business. The

transaction was completed on 31 March 2008, with BP contributing its Toledo refinery to a US jointly c ontrolled entity to which Husky contributed $250 mi llion cash

and a payable of $2,588 million. In Canada, Husky c ontributed its Sunrise field to a second jointly co ntrolled 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 ac counted for using the equity method. During the yea r, equityaccounted earnings from these jointly controlled en tities amounted to a loss of $70 million.

BP purchased refined products from the To ledo jointly controlled entity during the year amou nting to $3,440 million. In addition, BP purchased crude oil from

third parties which it sold to the Toledo jointly c ontrolled entity under an agency agreement. The fee s earned by BP for this service, and the total amou nts

receivable and payable at 31 December 2008 under th ese arrangements, were not significant. BP will als o purchase refinery feedstocks from the Sunrise joi ntly

controlled entity once production commences, which is expected in 2013. During 2008 the unwinding of d iscount on the payable to the Sunrise jointly contr olled

entity, included within finance costs in the group income statement, amounted to $103 million.

Our investment in TNK-BP will be reclassi fied from a jointly controlled entity to an associa te with effect from 9 January 2009, the date that B P finalized a

revised shareholder agreement with its Russian part ners in TNK-BP, Alfa Access-Renova (AAR). The forme rly evenly- balanced main board structure is replaced by

one with four representatives each from BP and AAR, plus three independent directors. The change in ac counting classification from a jointly controlled e ntity to an

associate reflects the ability of the independent d irectors of TNK-BP to decide on certain matters in the event of disagreement between the shareholder

representatives on the board. The group’s investmen t will continue to be accounted for using the equit y method.

Transactions between the group and its jo intly controlled entities are summarized below.

The terms of the outstanding balances receivable fr om 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 an d will be settled in cash. There are no significant provisions

for doubtful debts relating to these balances and n o significant expense recognized in the income stat ement 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 year a 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

a BP’s share of the profit of TNK-BP in 2006 includes a n et gain of $892 million on the disposal of certain asset s.

$ 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, emplo yee 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 December a Purchases 31 December Purchases 31 December

Crude oil and oil products, natural gas, refinery o perating costs, plant

processing fees 9,115 2,547 2,067 66 3,678 119

a Includes $110 million current payable and $2,255 milli on non

- current payable to the Sunrise Oil Sands jointly contro lled entity relating to BP ’ s contribution on the establishment of the joint ventur e. 

# Page 142 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 27. Investment in associates

The significant associates of the group are shown i n Note 46. Summarized financial information for the group’s share of associates is set out below.

Transactions between the group and its associates a re summarized below.

The terms of the outstanding balances receivable fr om associates are typically 30 to 45 days. The bala nces are unsecured and will be settled in cash. The re are no significant provisions for doubtful debts relating to these balances and no significant expense recogn ized in the income statement in respect of bad or d oubtful

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, emplo yee 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 

# Page 143 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 28. Financial instruments and financial risk factors

The accounting classification of each category of f inancial instruments, and their carrying amounts, a re 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 th e fair value.

Financial risk factors

The group is exposed to a number of different finan cial risks arising from natural business exposures as well as its use of financial instruments includi ng market

risks relating to commodity prices, foreign currenc y 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) wh o oversees the management of these risks. The GFRC is

chaired by the CFO and consists of a group of senio r managers including the group treasurer and the he ads of the finance, tax and the integrated supply a nd

trading functions. The purpose of the committee is to advise on financial risks and the appropriate fi nancial risk governance framework for the group. Th e committee

provides assurance to the CFO and the group chief e xecutive (GCE), and via the GCE to the board, that the group’s financial risk-taking activity is gover ned by

appropriate policies and procedures and that financ ial risks are identified, measured and managed in a ccordance with group policies and group risk appeti te.

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 li abilities 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 ) 

# Page 144 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 28. Financial instruments and financial risk factors continu ed

The group’ s trading activities in the oil, natural gas and po wer markets are managed within the integrated suppl y and trading function, while activities in the fin ancial

markets are managed by the treasury function. All d erivative activity is carried out by specialist tea ms that have the appropriate skills, experience and supervision.

These teams are subject to close financial and mana gement control.

The integrated supply and trading functio n maintains formal governance processes that provid e oversight of market risk associated with trading activity.

These processes meet generally accepted industry pr actice and reflect the principles of the Group of T hirty Global Derivatives Study recommendations. A p olicy

and risk committee monitors and validates limits an d risk exposures, reviews incidents and validates r isk-related policies, methodologies and procedures. A

commitments committee approves value-at-risk delega tions, the trading of new products, instruments and strategies and material commitments.

In addition, the integrated supply and tr ading function undertakes derivative activity for r isk management purposes under a separate control fr amework as

described more fully below.

(a) Market risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact o n 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 affec t the value of the group’s financial assets, liabil ities or expected future cash flows. The group ente rs into

derivatives in a well established entrepreneurial t rading operation. In addition, the group has develo ped a control framework aimed at managing the volat ility

inherent in certain of its natural business exposur es. In accordance with this control framework the g roup enters into various transactions using derivat ives for risk

management purposes.

During recent periods of increased volati lity in financial markets the group’s policies in r elation to managing market risk continue to be appr opriate and are

outlined in further detail below. The group measure s market risk exposure arising from its trading pos itions using value-at-risk techniques. These techni ques are

based on a variance/covariance model or a Monte Car lo simulation and make a statistical assessment of the market risk arising from possible future change s in

market prices over a 24-hour period. The calculatio n of the range of potential changes in fair value t akes into account a snapshot of the end-of-day expo sures and

the history of one-day price movements, together wi th the correlation of these price movements. The va lue-at-risk measure is supplemented by stress testi ng and

tail risk analysis.

The trading value-at-risk model is used f or derivative financial instrument types such as: i nterest rate forward and futures contracts, swap ag reements,

options and swaptions; foreign exchange forward and futures contracts, swap agreements and options; an d oil, natural gas and power price forwards, future s, swap agreements and options. Additionally, where physica l commodities or non-derivative forward contracts a re held as part of a trading position, they are als o reflected

in the value-at-risk model. For options, a linear a pproximation is included in the value-at-risk model s when full revaluation is not possible.

The value-at-risk table does not incorpor ate any of the group’s natural business exposures o r any derivatives entered into to risk manage those exposures. Market risk exposure in respect of embedded derivat ives is also not included in the value-at-risk tabl e. Instead separate sensitivity analyses are disclo sed below.

Value-at-risk limits are in place for eac h trading activity and for the group’s trading acti vity in total. The board has delegated an overall l imit of $100 million

value at risk in support of this trading activity. The high and low values at risk indicated in the ta ble 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. T his means that, in statistical terms, one would exp ect to see a decrease in fair values greater than t he trading

value at risk on one occasion per month if the port folio were left unchanged.

(i) Commodity price risk

The group’s integrated supply and trading function uses conventional financial and commodity instrumen ts and physical cargoes available in the related co mmodity

markets. Natural gas swaps, options and futures are used to mitigate price risk. Power trading is unde rtaken using a combination of over-the-counter forw ard

contracts and other derivative contracts, including options and futures. This activity is on both a st andalone basis and in conjunction with gas derivati ves in relation

to gas-generated power margin. In addition, NGLs ar e traded around certain US inventory locations usin g over-the-counter forward contracts in conjunction with

over-the-counter swaps, options and physical invent ories. Trading value-at-risk information in relatio n 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 

# Page 145 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 28. Financial instruments and financial risk factors continu ed

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 thre e years. In past periods commodity price risk relat ing to this activity has been managed using value-a t-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 n et fair

value to an immediate 10% increase or decrease in a ll reference prices would have been $90 million at 31 December 2008. This figure does not include any

corresponding economic benefit or disbenefit that w ould arise from the natural business exposure which would be expected to largely offset the gain or lo ss on the

derivatives.

In addition, the group has embedded deriv atives relating to certain natural gas and crude oi l contracts. The net fair value of these embedded d erivatives 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 t he net fair value to an immediate 10% favourable or unfavourable change in the key assumptions is as f ollows.

The sensitivities for risk management activity and embedded derivatives are hypothetical and should no t be considered to be predictive of future performa nce. In

addition, for the purposes of this analysis, in the above table, the effect of a variation in a partic ular assumption on the fair value of the embedded d erivatives is

calculated independently of any change in another a ssumption. In reality, changes in one factor may co ntribute to changes in another, which may magnify o r

counteract the sensitivities. Furthermore, the esti mated fair values as disclosed should not be consid ered indicative of future earnings on these contrac ts.

(ii) Foreign currency exchange risk

Where the group enters into foreign currency exchan ge contracts for entrepreneurial trading purposes t he activity is controlled using trading value-at- risk techniques

as explained above. This activity is described as c urrency trading in the value-at-risk table above.

Since BP has global operations, fluctuati ons in foreign currency exchange rates can have sig nificant effects on the group’s reported results. T he effects of

most exchange rate fluctuations are absorbed in bus iness operating results through changing cost compe titiveness, lags in market adjustment to movements in

rates and conversion differences accounted for on s pecific transactions. For this reason, the total ef fect of exchange rate fluctuations is not identifia ble separately in

the group’s reported results. The main underlying e conomic currency of the group’s cash flows is the U S dollar. This is because BP’s major product, oil, is priced

internationally in US dollars. BP’s foreign currenc y exchange management policy is to minimize economi c and material transactional exposures arising from

currency movements against the US dollar. The group co-ordinates the handling of foreign currency exch ange risks centrally, by netting off naturally-occu rring

opposite exposures wherever possible, and then deal ing with any material residual foreign currency exc hange risks.

The group manages these exposures by cons tantly reviewing the foreign currency economic valu e at risk and managing such risk to keep the 12-mon th

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 poin t over the

past three years did the value at risk exceed the m aximum risk limit. The most significant exposures r elate to capital expenditure commitments and other UK and

European operational requirements, for which a hedg ing programme is in place and hedge accounting is c laimed as outlined in Note 34.

For highly probable forecast capital expe nditures the group locks in the US-dollar cost of n on-US dollar supplies by using currency forwards an d 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 pla ce for

$949 million sterling, $553 million euro, $392 mill ion Norwegian krone, $303 million Australian dollar , $187 million Korean won and $712 million Canadian dollar

capital expenditures maturing within seven years, w ith over 65% of the deals maturing within two years (2007 $732 million sterling, $931 million euro, $4 79 million

Norwegian krone, $38 million Australian dollar, $24 3 million Korean won and $7 million Canadian dollar capital expenditures maturing within eight years w ith over

80% of the deals maturing within two years).

For other UK, European, Canadian and Aust ralian operational requirements the group uses cyli nders and currency forwards to hedge the estimated

exposures on a 12-month rolling basis. At 31 Decemb er 2008, the open positions relating to cylinders c onsisted of receive sterling, pay US dollar, purcha sed 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 m illion (2007 nil); and receive Australian dollar, p ay 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 mil lion (2007 nil); buy Canadian dollar, sell US dolla r, currency forwards for $50 million (2007 nil); an d buy Australian

dollar, sell US dollar, currency forwards for $90 m illion (2007 nil).

In addition, most of the group’s borrowin gs are in US dollars or are hedged with respect to the US dollar. At 31 December 2008, the total forei gn 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 t han the

functional currency of the individual operating uni t being entirely Canadian dollars (2007 $268 millio n, being $191 million in Canadian dollars and $77 m illion in

Trinidad & Tobago dollars). It is estimated that a 10% change in the corresponding exchange rates woul d 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 ) 

# Page 146 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 28. Financial instruments and financial risk factors continu ed

(iii) Interest rate risk

Where the group enters into money market contracts for entrepreneurial trading purposes the activity i s controlled using value-at-risk techniques as desc ribed

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 o f its financial

instruments, principally finance debt.

While the group issues debt in a variety of currencies based on market opportunities, it use s derivatives to swap the debt to a US dollar float ing rate exposure

but in certain defined circumstances maintains a fi xed rate exposure for a proportion of debt. The pro portion of floating rate debt net of interest rate swaps at 31

December 2008 was 72% of total finance debt outstan ding (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 deb t is three years (2007 two years).

The group’s earnings are sensitive to cha nges 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 gro up’s profit before taxation for 2009 would decrease by

approximately $239 million (2007 $168 million decre ase 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 effe ctive from the beginning of the year. Where the int erest rate

applicable to an instrument is reset during a quart er it is assumed that this occurs at the beginning of the quarter and remains unchanged for the rest o f the year. In

reality, the fixed/floating rate mix will fluctuate over the year and interest rates will change conti nually. Furthermore, the effect on earnings shown b y this analysis

does not consider the effect of any other changes i n 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 val ue 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 relati ng 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 r esult in an immediate credit to equity of $59 milli on (2007

$162 million credit to equity), whilst a decrease o f 10% in quoted equity prices would result in an im mediate 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 th e 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 change s in the share price of this equity in particular.

(b) Credit risk

Credit risk is the risk that a customer or counterp arty 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 f inancial instruments and deposits with financial in stitutions and principally from credit exposures to customers

relating to outstanding receivables.

The group has a credit policy, approved b y the CFO, that is designed to ensure that consiste nt processes are in place throughout the group to m easure and

control credit risk. Credit risk is considered as p art of the risk-reward balance of doing business. O n entering into any business contract the extent to which the

arrangement exposes the group to credit risk is con sidered. Key requirements of the policy are formal delegated authorities to the sales and marketing te ams to

incur credit risk and to a specialized credit funct ion to set counterparty limits; the establishment o f credit systems and processes to ensure that count erparties are

rated and limits set; and systems to monitor exposu re against limits and report regularly on those exp osures, and immediately on any excesses, and to tra ck and

report credit losses. The treasury function provide s a similar credit risk management activity with re spect to group-wide exposures to banks and other fi nancial

institutions.

In the current economic environment the g roup has placed increased emphasis on the managemen t 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 wh ere

appropriate.

Before trading with a new counterparty ca n start, its creditworthiness is assessed and a cre dit rating is allocated that indicates the probabil ity of default, along

with a credit exposure limit. The assessment proces s takes into account all available qualitative and quantitative information about the counterparty and the group,

if any, to which the counterparty belongs. The coun terparty’s business activities, financial resources and business risk management processes are taken i nto

account in the assessment, to the extent that this information is publicly available or otherwise disc losed to the group by the counterparty, together wi th external

credit ratings, if any, including ratings prepared by Moody’s Investor Service and Standard & Poor’s. Creditworthiness continues to be evaluated after tr ansactions

have been initiated and a watchlist of higher-risk counterparties is maintained. Once assigned a credi t rating, each counterparty is allocated a maximum exposure

limit.

The group does not aim to remove credit r isk but expects to experience a certain level of cr edit losses. The group attempts to mitigate credit risk by entering

into contracts that permit netting and allow for te rmination of the contract on the occurrence of cert ain events of default. Depending on the creditworth iness of the

counterparty, the group may require collateral or o ther credit enhancements such as cash deposits or l etters of credit and parent company guarantees. Tra de and

other derivative assets and liabilities are present ed on a net basis where unconditional netting arran gements are in place with counterparties and where there is an

intent to settle amounts due on a net basis. The ma ximum credit exposure associated with financial ass ets is equal to the carrying amount. At 31 December 2008,

the maximum credit exposure was $52,413 million (20 07 $53,498 million). Collateral received and recogn ized in the balance sheet at the year-end was

$1,121 million (2007 $39 million) and collateral he ld off balance sheet was $203 million (2007 $474 mi llion). Credit exposure exists in relation to guara ntees issued

by group companies under which amounts outstanding at 31 December 2008 were $223 million (2007 $443 mi llion) in respect of liabilities of jointly control led

entities and associates and $613 million (2007 $601 million) in respect of liabilities of other third parties.

143 Notes on financial statements 

# Page 147 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 28. Financial instruments and financial risk factors continu ed

Notwithstanding the processes described above, sign ificant unexpected credit losses can occasionally o ccur. Exposure to unexpected losses increases with

concentrations of credit risk that exist when a num ber of counterparties are involved in similar activ ities or operate in the same industry sector or geo graphical area,

which may result in their ability to meet contractu al obligations being impacted by changes in economi c, political or other conditions. The group ’s principal

customers, suppliers and financial institutions wit h which it conducts business are located throughout the world. In addition, these risks are managed by maintaining

a group watchlist and aggregating multi-segment exp osures to ensure that a material credit risk is not missed.

Reports are regularly prepared and presen ted to the GFRC that cover the group’s overall cred it exposure and expected loss trends, exposure by s egment,

and overall quality of the portfolio. The reports a lso include details of the largest counterparties b y 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 t he derivative financial instruments in an asset pos ition are of

investment grade credit quality.

Trade and other receivables of the group are analysed in the table below. By comparing the B P credit ratings to the equivalent external credit ratings, it is

estimated that approximately 60-65% (2007 65- 70%) of the trade receivables portfolio exposure ar e 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 obliga tions.

The group does not typically renegotiate the terms of trade receivables; however, if a reneg otiation does take place, the outstanding balance i s included in

the analysis based on the original payment terms. T here were no significant renegotiated balances outs tanding at 31 December 2008 or 31 December 2007.

The movement in the valuation allowance for trade r eceivables is set out below.

(c) Liquidity risk

Liquidity risk is the risk that suitable sources of funding for the group’s business activities may no t be available. The group’s liquidity is managed ce ntrally with

operating units forecasting their cash and currency requirements to the central treasury function. Unl ess restricted by local regulations, subsidiaries p ool their cash

surpluses to treasury, which will then arrange to f und 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 competiti ve rates through capital markets and banks. The gro up’s treasury

function centrally co-ordinates relationships with banks, borrowing requirements, foreign exchange req uirements and cash management. The group believes i t has

access to sufficient funding through the commercial paper markets and by using undrawn committed borro wing facilities to meet foreseeable borrowing

requirements. At 31 December 2008, the group had su bstantial amounts of undrawn borrowing facilities a vailable, including committed facilities of $4,950 million, of

which $4,550 million are in place until at least th e fourth quarter of 2011 (2007 $4,950 million, of w hich $4,550 million are in place until at least the fourth quarter of

2011). These facilities are with a number of intern ational banks and borrowings under them would be at pre-agreed rates.

The group has in place a European Debt Is suance Programme (DIP) under which the group may ra ise $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 m illion). In addition, the group has in place a US S helf

Registration under which it may raise $10 billion o f debt with maturities of one month or longer. At 3 1 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 A a1 (stable outlook) and AA (stable outlook), (2007 Aa1 (stable outlook) and AA+ (negative outlook)) as signed

respectively by Moody’s and Standard and Poor’s.

Despite current uncertainty in the financ ial market including a lack of liquidity for some b orrowers, we have been able to issue $5 billion of long-term debt in

the fourth quarter of 2008. In addition, we have be en able to issue short-term commercial paper at com petitive rates. In the context of unforeseen market volatility,

we have however, increased the cash and cash equiva lents held by the group to $8.2 billion at the end of 2008 compared with $3.6 billion at the end of 20 07.

The amounts shown for finance debt in the table below include expected interest payments on borrowings and the future minimum lease payments wi th

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 

# Page 148 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htmNotes on financial statements



### 28. Financial instruments and financial risk factors continu ed

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-ter m maturity profiles of the contracts as described i n Note 35. US Industrial Revenue/Municipal Bonds of

$3,166 million (2007 $2,880 million) with earliest contractual repayment dates within one year have ex pected repayment dates ranging from 1 to 40 years ( 2007 1

to 35 years). The bondholders typically have the op tion to tender these bonds for repayment on interes t reset dates; however, any bonds that are tendered are usually remarketed and BP has not experienced any s ignificant repurchases. BP considers these bonds to represent long-term funding when internally assess ing

the maturity profile of its finance debt. Similar t reatment 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 o utflows relating to trade and other payables and ac cruals.

The group manages liquidity risk associated with de rivative contracts on a portfolio basis, considerin g both physical commodity sale and purchase contrac ts

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 physic al commodities

under derivative contracts and the estimated cash o utflows of financially-settled derivative liabiliti es. The group also holds derivative contracts for t he sale of

physical commodities and financially- settled derivative assets that are expected to gene rate cash inflows that will be available to the gro up to meet cash outflows on

purchases and liabilities. These contracts are excl uded from the table below. The amounts disclosed fo r embedded derivatives represent the contractual ca sh

outflows of purchase contracts some of which have e mbedded 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 settl ed net, and the gross settlement amount where the p ay leg of a derivative will be settled separately t o the receive

leg, as in the case of cross-currency interest rate swaps hedging non-US dollar finance debt. The swap s are with high investment-grade counterparties and

therefore the settlement day risk exposure is consi dered 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

- for

Embedded 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 

# Page 149 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 29. Other investments

Other investments comprise equity investments that have no fixed maturity date or coupon rate. These i nvestments are classified as available-for-sale fin ancial

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 dis posal, or when the investment is impaired.

The fair value of listed investments has been determined by reference to quoted market bid p rices. Unlisted investments are stated at cost less accumulated

impairment losses.

The most significant investment is the gr oup’s stake in Rosneft which had a fair value of $4 83 million at 31 December 2008 (2007 $1,285 million ). During

2008, an impairment loss of $517 million was recogn ized relating to the Rosneft investment (see Note 1 1), $29 million relating to other listed investment s and

$17 million relating to unlisted investments (2007 $80 million relating to unlisted investments).



# 30. Inventories

The inventory valuation at 31 December 2008 is stat ed net of a provision of $1,412 million (2007 $117 million) to write inventories down to their net rea lizable value.

The net movement in the provision during the year w as a charge of $1,295 million (2007 $86 million cre dit).



# 31. Trade and other receivables

Trade and other receivables are predominantly non-i nterest 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 statemen t 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



# Page 150 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 32. Cash and cash equivalents

Cash and cash equivalents comprise cash in hand; cu rrent balances with banks and similar institutions; and short-term highly liquid investments that are readily

convertible to known amounts of cash, are subject t o 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 amo unts on

deposit to cover initial margins on trading exchang es.



# 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



# Page 151 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 34. Derivative financial instruments

An outline of the group’s financial risks and the o bjectives and policies pursued in relation to those risks is set out in Note 28.

IAS 39 prescribes strict criteria for hed ge 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 the se criteria should be classified as held for tradin g and fair valued, with gains and losses recognized in profit or

loss.

In the normal course of business the grou p enters into derivative financial instruments (der ivatives) to manage its normal business exposures i n relation to

commodity prices, foreign currency exchange rates a nd interest rates, including management of the bala nce between floating rate and fixed rate debt, cons istent

with risk management policies and objectives. Addit ionally, 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 i nstruments at 31 December are set out below.

Derivatives held for trading

The group maintains active trading positions in a v ariety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supp ly

requirements or for entrepreneurial trading. Certai n contracts are classified as held for trading, reg ardless of their original business objective, and a re recognized at

fair value with changes in fair value recognized in the income statement. Trading activities are under taken by using a range of contract types in combina tion to

create incremental gains by arbitraging prices betw een 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 informa tion on the fair value of derivatives and other fin ancial instruments held for trading purposes.

Changes during the year in the net fair v alue 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 duri ng 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 

# Page 152 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 34. Derivative financial instruments continued

If at inception of a contract the valuation cannot be supported by observable market data, any gain de termined by the valuation methodology is not recogn ized in

the income statement but is deferred on the balance sheet and is commonly known as ‘day-one profit’. T his deferred gain is recognized in the income state ment

over the life of the contract until substantially a ll of the remaining contract term can be valued usi ng observable market data at which point any remain ing deferred

gain is recognized in income. Changes in valuation from this initial valuation are recognized immediat ely 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 followi ng fair values and maturities.

Derivative liabilities held for trading have the fo llowing 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 duri ng 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 recogn ized in the income statement 66 49 – 1

Fair value recognized in the income statement (34 ) (2 )

– ( 1 )

Fair value of contracts not recognized through prof it 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 ) 

# Page 153 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 34. Derivative financial instruments continued

The following table shows the fair value of derivat ive assets held for trading, analysed by maturity p eriod and by methodology of fair value estimation.

The following table shows the fair value of derivat ive liabilities held for trading, analysed by matur ity period and by methodology of fair value estimat ion.

Prices actively quoted refers to the fair value of contracts valued solely using quoted prices in an a ctive market. Prices sourced from observable data o r market

corroboration refers to the fair value of contracts valued in part using active quotes and in part usi ng observable, market- corroborated data, for example, swaps and

physical forward contracts. Prices based on models and other valuation methods refers to the fair valu e of a contract valued in part using internal model s due to the

absence of quoted prices, including over-the-counte r options. The net change in fair value of contract s based on models and other valuation methods durin g the

year was a gain of $253 million (2007 $94 million l oss and 2006 $117 million loss).

Gains and losses relating to derivative c ontracts are included either within sales and other operating revenues or within purchases in the inco me 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 certa in forward

sales and forward purchases contracts. Gains or los ses arise on contracts entered into for risk manage ment purposes, optimization activity and entreprene urial

trading. They also arise on certain contracts that are for normal procurement or sales activity for th e group but that are required to be fair valued und er accounting

standards. Also included within sales and other ope rating revenues are gains and losses on inventory h eld 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) 

# Page 154 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 34. Derivative financial instruments continued

Embedded derivatives

Prior to the development of an active gas trading m arket, UK gas contracts were priced using a basket of available price indices, primarily relating to o il products,

power and inflation. After the development of an ac tive UK gas market, certain contracts were entered into or renegotiated using pricing formulae not dir ectly

related to gas prices, for example, oil product and power prices. In these circumstances, pricing form ulae have been determined to be derivatives, embedd ed within

the overall contractual arrangements that are not c learly and closely related to the underlying commod ity. The resulting fair value relating to these con tracts is

recognized on the balance sheet with gains or losse s recognized in the income statement.

All the embedded derivatives are valued u sing inputs that include price curves for each of t he different products that are built up from active market pricing

data. Where necessary, these are extrapolated to th e expiry of the contracts (the last of which is in 2018) using all available external pricing informat ion.

Additionally, where limited data exists for certain products, prices are interpolated using historic a nd long-term pricing relationships.

The following table shows the changes dur ing the year in the net fair value of embedded deri vatives.

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) 

# Page 155 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 34. Derivative financial instruments continued

Embedded derivative assets have the following fair values when analysed by maturity period and by meth odology 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 de rivatives is shown below.

The fair value gain (loss) in the above table inclu des $496 million of exchange gains (2007 $12 millio n of exchange losses and 2006 $179 million of excha nge losses) arising on contracts that are denominated i n 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 corro boration 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 corro boration 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 corro boration (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 corro boration

– – – – – – – 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 

# Page 156 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 34. Derivative financial instruments continued

Cash flow hedges

At 31 December 2008, the group held currency forwar ds and futures contracts and cylinders that were be ing used to hedge the foreign currency risk of high ly

probable forecast transactions, as well as cross-cu rrency interest rate swaps to fix the US dollar int erest rate and US dollar redemption value, with mat ching critical

terms on the currency leg of the swap with the unde rlying non-US dollar debt issuance. Note 28 outline s the management of risk aspects for currency and i nterest

rate risk. For cash flow hedges the group only clai ms for the intrinsic value on the currency with any fair value attributable to time value taken immedi ately to profit

or loss. There were no highly probable transactions for which hedge accounting has been claimed that h ave not occurred and no significant element of hedg e 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 gai n of $74 million and 2006 gain of $93 million). Of this, a loss of $1 million is included in productio n and

manufacturing expenses (2007 $143 million gain and 2006 $162 million gain) and a loss of $44 million i s included in finance costs (2007 $69 million loss and 2006

$69 million loss). The amount removed from equity d uring 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 Dece mber 2008 are expected to mature and affect the inc ome statement by a $826 million loss in 2009, a los s of

$92 million in 2010 and a loss of $182 million in 2 011 and beyond.

Fair value hedges

At 31 December 2008, the group held interest rate a nd cross-currency interest rate swap contracts as f air value hedges of the interest rate risk on fixed rate debt

issued by the group. The effectiveness of each hedg e relationship is quantitatively assessed and demon strated to continue to be highly effective. The gai n 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 inte rest rate swaps have an average maturity of three t o four years, (2007 one to two years) and are used to convert

sterling, euro, Swiss franc and Australian dollar d enominated borrowings into US dollar floating rate debt. Note 28 outlines the group’s approach to inte rest 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 expiri ng in 2009. At 31 December 2008, the hedge had a fa ir

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 millio n gain). US

dollars have been sold forward for sterling purchas ed and match the underlying liability with no signi ficant ineffectiveness reflected in the income stat ement.



# 35. Finance debt

153 Notes on financial statements

$ million

2008 2007

Within After Within After

1 year a 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

a Amounts due within one year include current maturities o f long-term debt and borrowings that are expected to b e 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 wit hin 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 bon ds for repayment on interest reset dates; however, any bo nds that are tendered are usually remarketed and BP has not experienced any significant

repurchases. BP considers these bonds to represent long-ter m 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 milli on) that mature within nine years. 

# Page 157 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 35. Finance debt continued

The following table shows, by major currency, the g roup’s finance debt at 31 December and the weighted average interest rates achieved at those dates thr ough a

combination of borrowings and derivative financial instruments entered into to manage interest rate an d currency exposures.

Finance leases

The group uses finance leases to acquire property, plant and equipment. These leases have terms of ren ewal but no purchase options and escalation clauses

. Renewals are at the option of the lessee. Future mi nimum lease payments under finance leases are set o ut below.

Fair values

The estimated fair value of finance debt is shown i n the table below together with the carrying amount as reflected in the balance sheet.

Long-term borrowings in the table below i nclude the portion of debt that matures in the year from 31 December 2008, whereas in the balance shee t 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 valu e of the group’s long-term borrowings and finance l ease obligations is estimated using quoted prices o r, where

these are not available, discounted cash flow analy ses based on the group’s current incremental borrow ing rates for similar types and maturities of borro wing.

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 

# Page 158 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 36. Capital disclosures and analysis of changes in net debt

The group defines capital as the total equity of th e 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 sub ject to any externally-imposed capital requirements

. The group’s approach to managing capital is set out in its financial framework. The group ai ms to balance returns to shareholders between long- term growth

and current returns via the dividend whilst maintai ning capital discipline in relation to investing ac tivities and taking action on costs to respond to t he current

environment. At the beginning of 2008, the group re balanced returns to shareholders by increasing the dividend component. As a result, the share buyback

programme was curtailed and then suspended in Septe mber in light of the uncertain environment.

The group monitors capital on the basis o f the net debt ratio, that is, the ratio of net deb t to net debt plus equity. Net debt is calculated a s 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 ra te risks

relating to finance debt, for which hedge accountin g is claimed, less cash and cash equivalents. Net d ebt and net debt ratio are non-GAAP measures. BP us es these measures to provide useful information to inv estors. Net debt enables investors to see the econo mic effect of gross debt, related hedges and cash a nd cash

equivalents in total. The net debt ratio enables in vestors to see how significant net debt is relative to equity from shareholders. The derivatives are r eported on the

balance sheet within the headings ‘Derivative finan cial instruments’. All components of equity are inc luded in the denominator of the calculation. We bel ieve that a

net debt ratio in the range 20-30% provides an effi cient capital structure and an appropriate level of financial flexibility.

At 31 December 2008 the net debt ratio wa s 21% (2007 22%).

An analysis of changes in net debt is provided belo w.

Revised definition of net debt

Net debt has been redefined to include the fair val ue of associated derivative financial instruments t hat are used to hedge foreign exchange and interest rate risks

relating to finance debt, for which hedge accountin g is claimed. The derivatives are reported on the b alance sheet within the headings ‘Derivative financ ial

instruments’. Amounts for comparative periods are p resented 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 relate d 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 debt a equivalents debt debt a 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 )

a Including fair value of associated derivative financial inst ruments.

$ 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% 

# Page 159 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 37. Provisions

The group makes full provision for the future cost of decommissioning oil and natural gas production f acilities and related pipelines on a discounted bas is on the

installation of those facilities. The provision for the costs of decommissioning these production faci lities and pipelines at the end of their economic l ives has been

estimated using existing technology, at current pri ces or long-term assumptions, depending on the expe cted 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 est imate of

future costs and the economic lives of the faciliti es and pipelines, there is uncertainty regarding bo th the amount and timing of incurring these costs. Where BP has

entered into a contract for the execution of decomm issioning activity, these amounts are generally rep orted 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. Gener ally, this

coincides with commitment to a formal plan of actio n or, if earlier, on divestment or on closure of in active sites. The provision for environmental liabi lities has been

estimated using existing technology, at current pri ces and discounted using a real discount rate of 2. 0% (2007 2.0%). The majority of these costs are exp ected to

be incurred over the next 10 years. The extent and cost of future remediation programmes are inherentl y difficult to estimate. They depend on the scale o f any

possible contamination, the timing and extent of co rrective actions, and also the group’s share of the liability.

Included within the litigation and other category at 31 December 2008 are provisions for lit igation of $1,446 million (2007 $1,737 million), fo r deferred

employee compensation of $792 million (2007 $761 mi llion) and for expected rental shortfalls on surplu s properties of $251 million (2007 $320 million). T o the

extent that these liabilities are not expected to b e settled within the next three years, the provisio ns are discounted using either a nominal discount r ate 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 inci dent (in

2007 the provision was increased by $500 million). Disbursements to claimants in 2008 were $410 millio n (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 

# Page 160 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 38. Pensions and other post-retirement benefits

Most group companies have pension plans, the forms and benefits of which vary with conditions and prac tices in the countries concerned. Pension benefits may be

provided through defined contribution plans (money purchase schemes) or defined benefit plans (final s alary and other types of schemes with committed pen sion

payments). For defined contribution plans, retireme nt benefits are determined by the value of funds ar ising from contributions paid in respect of each em ployee. For

defined benefit plans, retirement benefits are base d on such factors as the employees’ pensionable sal ary and length of service. Defined benefit plans ma y be

externally funded or unfunded. The assets of funded plans are generally held in separately administere d trusts.

In particular, the primary pension arrang ement in the UK is a funded final salary pension pl an that remains open to new employees. Retired empl oyees draw

the majority of their benefit as an annuity.

In the US, a range of retirement arrangem ents is provided. These include a funded final sala ry pension plan for certain heritage employees and a cash

balance arrangement for new hires. Retired US emplo yees typically take their pension benefit in the fo rm of a lump sum payment. US employees are also eli gible to

participate in a defined contribution (401k) plan i n which employee contributions are matched with com pany contributions.

The level of contributions to funded defi ned benefit plans is the amount needed to provide a dequate funds to meet pension obligations as they f all due.

During 2008, contributions of $6 million (2007 $524 million and 2006 $438 million) and $362 million (2 007 $97 million and 2006 $181 million) were made to the UK

plans and US plans respectively. In addition, contr ibutions of $130 million (2007 $127 million and 200 6 $136 million) were made to other funded defined b enefit

plans. The aggregate level of contributions in all countries in 2009 is expected to be approximately $ 500 million, and includes contributions that we exp ect to be

required to make by law or under contractual agreem ents as well as an allowance for discretionary fund ing.

Certain group companies, principally in t he US, provide post- retirement healthcare and life insurance benefits t o their retired employees and dependants. The

entitlement to these benefits is usually based on t he employee remaining in service until retirement a ge and completion of a minimum period of service. T he plans

are funded to a limited extent.

The obligation and cost of providing pens ions and other post-retirement benefits is assessed annually using the projected unit credit method. T he date of the

most recent actuarial review was 31 December 2008.

The material financial assumptions used f or estimating the benefit obligations of the variou s plans are set out below. The assumptions are revi ewed 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, t he assumptions at 31 December 2008 are used to dete rmine

the pension liabilities at that date and the pensio n expense for 2009.

Our discount rate assumptions are based on third-pa rty AA corporate bond indices and for our largest s chemes 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 sc hemes are based on the difference between the yield s on index-linked and fixed-interest long-term governmen t bonds. In other countries we use either this appr oach, or the central bank inflation target, or advi ce 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 th ere is such an increase.

Our assumptions for the rate of increase in salaries are based on our inflation assumption p lus an allowance for expected long- term real salary growth. These

include allowance for promotion-related salary grow th, of between 0.3% and 0.4% depending on country. In addition to the financial assumptions, we regula rly

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 

# Page 161 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 38. Pensions and other post-retirement benefits continu ed

Mortality assumptions reflect best practice in the countries in which we provide pensions, and have be en chosen with regard to the latest available publi shed tables

adjusted where appropriate to reflect the experienc e of the group and an extrapolation of past longevi ty improvements into the future. As part of the tri annual

valuation of our UK pensions funds, our UK mortalit y assumption was reviewed and updated at end-2008 r esulting 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 mortali ty assumptions are as follows:

Our assumptions for future US healthcare cost trend rate reflect the rate of actual cost increases see n in recent years for the initial trend rate, and t he ultimate trend

rate reflects our long-term expectations based on p ast medical inflation seen over a longer period of time. The assumed future US healthcare cost trend r ate is as

follows:

Pension plan assets are generally held in trusts. T he 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 m anner consistent with fiduciary obligations and pri nciples that reflect current practices in portfolio management.

A significant proportion of the assets ar e held in equities, owing to a higher expected leve l of return over the long term with an acceptable l evel of risk. In

order to provide reasonable assurance that no singl e security or type of security has an unwarranted i mpact on the total portfolio, the investment portfo lios 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 fi nancial instruments as part of their asset mix and to manage the level of risk. The group’s main pensi on plans

do not invest directly in either securities or prop erty/real estate of the company or of any subsidiar y. Return on asset assumptions reflect the g roup’s expectations built up by asset class and by plan. The group’s expectation is derived from a com bination of

historical returns over the long term and the forec asts of market professionals. Our assumption for re turn on equities is based on a long-term view, and the size of

the resulting equity risk premium over government b ond yields is reviewed each year for reasonableness . Our assumption for return on bonds reflects the p ortfolio

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 ag ed 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 ag ed 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 

# Page 162 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 38. Pensions and other post-retirement benefits continu ed

The expected long-term rates of return and market v alues of the various categories of asset held by th e defined benefit plans at 31 December are set out below.

The market values shown include the effects of deri vative financial instruments. The amounts classifie d as equities include investments in companies list ed on

stock exchanges as well as unlisted investments. Th e market value of unlisted investments at 31 Decemb er 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 200 7 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 rate s (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 rat e, inflation and the assumed US healthcare cost tre nd rate all have a significant effect on the amount s 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 ) 

# Page 163 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 38. Pensions and other post-retirement benefits continu ed

At 31 December 2008 reimbursement balances due from or to other companies in respect of pensions amoun ted to $455 million reimbursement assets (2007

$496 million) and $61 million reimbursement liabili ties (2007 $72 million). These balances are not inc luded as part of the pension liability, but are ref lected

elsewhere in the group balance sheet.

160 Notes on financial statements

$ million

2008

US other post

UK US retirement

pension pension benefit Other

plans plans plans plans Total

Analysis of the amount charged to profit before int erest and taxation

Current service cost a 448 235 40 128 851

Past service cost 7 74

– 1 82

Settlement, curtailment and special termination ben efits 30

– – 12 42

Payments to defined contribution plans

– 170

– 25 195

Total operating charge b 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 lia bilities (73 ) (194 ) 18 70 (179 )

Actuarial (loss) gain recognized in statement of re cognized 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 cost a 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 benefits c 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 December a 16,655 7,534 3,003 7,655 34,847

Movements in fair value of plan assets during the y ear

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 assets a 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 assets e (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 funde d 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 betw een 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 )

a The costs of managing the plan ’ s investments are treated as being part of the investmen t return, the costs of administering our pensions plan be nefits are generally included in current service cost and th e costs of

administering our other post

- retirement benefit plans are included in the benefit obligation.

b Included within production and manufacturing expenses and distribution and administration expenses.

c The charge for special termination benefits represents t he increased liability arising as a result of early retir ements occurring as part of restructuring programmes.

d The benefit payments amount shown above comprises $2,697 million benefits plus $57 million of plan expenses incurr ed in the administration of the benefit.

e The 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. 

# Page 164 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 38. Pensions and other post-retirement benefits continu ed

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 int erest and taxation

Current service cost a 492 227 43 132 894

Past service cost 5 10

– – 15

Settlement, curtailment and special termination ben efits 36

– – 2 38

Payments to defined contribution plans – 184 – 25 209

Total operating charge b 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 lia bilities (162) (27) 29 (40) (200)

Actuarial gain recognized in statement of recognize d 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 cost a 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 benefits c 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 December a 23,927 7,409 3,178 8,586 43,100

Movements in fair value of plan assets during the y ear

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 assets a 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 assets e 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 funde d 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 betw een 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 )

a The costs of managing the plan ’ s investments are treated as being part of the investmen t return, the costs of administering our pensions plan be nefits are generally included in current service cost and th e costs of

administering our other post

- retirement benefit plans are included in the benefit obligation.

b Included within production and manufacturing expenses and distribution and administration expenses.

c The charge for special termination benefits represents t he increased liability arising as a result of early retir ements occurring as part of a restructuring programme in the UK.

d The benefit payments amount shown above comprises $2,398 million benefits plus $57 million of plan expenses incurr ed in the administration of the benefit.

e The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gai n on plan assets as disclosed above. 

# Page 165 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 38. Pensions and other post-retirement benefits continu ed

Estimated future benefit payments

The expected benefit payments, which reflect expect ed future service, as appropriate, but exclude plan expenses, up until 2018 are as follows:

162 Notes on financial statements

$ million

2006

US other

post

UK US retirement

pension pension benefit Other

plans plans plans plans Total

Analysis of the amount charged to profit before int erest and taxation

Current service cost a 432 216 42 139 829

Past service cost (74 ) 38

– 39 3

Settlement, curtailment and special termination ben efits 4

– – 227 231

Payments to defined contribution plans – 161 – 16 177

Total operating charge b 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 lia bilities (24) 17 80 (197) (124)

Actuarial gain recognized in statement of recognize d income and expense 1,395 733 191 296 2, 615

a The costs of managing the plan’s investments are treated as being part of the investment return, the costs of adm inistering our pensions plan benefits are generally inclu ded in current service cost, and the costs of

administering our other post-retirement benefit plans are included in the benefit obligation.

b Included within production and manufacturing expenses and distribution and administration expenses.

$ million

2008 2007 2006 2005 2004

History of surplus (deficit) and of experience gain s 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 re cognized income and expense (8,430 ) 1,717 2,615 975 107

Cumulative amount recognized in statement of recogn ized income and expense (2,940 ) 5,490 3,773 1,158 183

$ million

US other

post

UK 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 

# Page 166 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 39. Called-up share capital

The allotted, called-up and fully paid share capita l at 31 December was as follows:

Voting on substantive resolutions tabled at a gener al meeting is on a poll. On a poll, shareholders pr esent in person or by proxy have two votes for ever y £5 in

nominal amount of the first and second preference s hares held and one vote for every ordinary share he ld. On a show-of-hands vote on other resolutions

(procedural matters) at a general meeting, sharehol ders present in person or by proxy have one vote ea ch.

In the event of the winding up of the com pany, preference shareholders would be entitled to a sum equal to the capital paid up on the preferenc e shares, plus

an amount in respect of accrued and unpaid dividend s and a premium equal to the higher of (i) 10% of t he capital paid up on the preference shares and (ii ) the

excess of the average market price of such shares o n 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 sh ares) for a total consideration of $2,914 million ( 2007

$7,497 million and 2006 $15,481 million), all of wh ich were for cancellation. At 31 December 2008, 150 ,444,408 (2007 150,966,096 and 2006 99,045,000) ord inary

shares bought back were awaiting cancellation. Thes e 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 1,940,6 38,808 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 ordi nary 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 capita l of the company. The nominal value of these shares was $13 million (2007 $2 million) and the total proceed s received from the re-issues in relation to employ ee share schemes were $75 million (2007 $35 million ).

Transaction costs of share repurchases am ounted to $16 million (2007 $40 million and 2006 $8 3 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 )

Other a

– – – – 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

a Reclassification in respect of share repurchases in 2005. 

# Page 167 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 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-r etirement 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 (ne t 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 (ne t 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

– Other b 246

– – Currency translation differences (net of tax)

– – –

At 31 December 2006 5,385 9,074 839

a At 31 December 2006, the foreign currency translation r eserve included $122 million relating to non

- current assets held for sale. During 2007, this was inclu ded in the $147 million recycled to the income statemen t

relating to disposals in 2007. For further details see N ote 5.

b Reclassification in respect of share repurchases in 2005. 

# Page 168 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm165

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 reserve a 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 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 a 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 

# Page 169 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 40. Capital and reserves continued

Share capital

The balance on the share capital account represents the aggregate nominal value of all ordinary and pr eference 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 valu e of the ordinary and preference shares.

Capital redemption reserve

The balance on the capital redemption reserve repre sents the aggregate nominal value of all the ordina ry shares repurchased and cancelled.

Merger reserve

The balance on the merger reserve represents the fa ir value of the consideration given in excess of th e 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 fai r 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 Sha re Ownership Plans (ESOPs) to meet the future requi rements 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 trans lation of the financial statements of foreign opera tions. Upon

disposal of foreign operations, the related accumul ated exchange differences are recycled to the incom e statement. This reserve is also used to record th e effect of

hedging net investments in foreign operations.

Available-for-sale investments

This reserve records the changes in fair value of a vailable-for- sale investments. On disposal, or impairment, the c umulative changes in fair value are recycled to the

income statement.

Cash flow hedges

This reserve records the portion of the gain or los s on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. When the h edged

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 transferr ed to profit or loss.

Share-based payment reserve

This reserve represents cumulative amounts charged to profit in respect of employee share-based paymen t plans where the scheme has not yet been settled b y

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 g roup’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 op tions over the company’s ADSs (one ADS is equivalen t to six ordinary shares). The share-based payment

plans that existed during the year are detailed bel ow. 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 

# Page 170 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 41. Share-based payments continued

Plans for executive directors

Executive Directors’ Incentive Plan (EDIP) – share element

An equity-settled incentive share plan for executiv e directors driven by one performance measure over a three-year performance period. The award of share s is

determined by comparing BP’s total shareholder retu rn (TSR) against the other oil majors. After the pe rformance period, the shares that vest (net of tax) are then

subject to a three-year retention period. In Februa ry 2008 it was considered appropriate to strengthen the retention element of remuneration for two exec utive

directors. The remuneration committee granted, on a one-off basis, a restricted share award to those t wo executive directors. The shares will vest subjec t to

continued service, in equal tranches, after three a nd 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 pe riod. The directors’ remuneration report on pages 7 3 to 83 includes full details of this plan.

Executive Directors’ Incentive Plan (EDIP) – share option element

An equity-settled share option plan for executive d irectors that permits options to be granted at an e xercise price no lower than the market price of a s hare on the

date that the option is granted. Options vest over three years (one-third each after one, two and thre e 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 po licy 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 se nior employees driven by two performance measures o ver 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 determi ned by comparing BP’s TSR against the other oil maj ors and, additionally, by comparing free cash flow (FCF ) against a threshold established for the period. F or a small group of particularly senior employees o nly 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, a ssuming that such dividends would have been reinves ted. With regard to leaver provisions the general r ule is

that leaving employment during the performance peri od will preclude the conversion of units into share s. However, special arrangements apply where the

participant leaves for a qualifying reason and empl oyment 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 tha t 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 se nior employees. In 2008 the grant value is equal to 50% (2007 and 2006 50%) of the annual cash bonus a warded

for the preceding performance year (the ‘performanc e period’). For 2009 this will increase to 100%. Th e units are restricted for a period of three years (the

‘restriction period’), during which they accrue net notional dividends which are treated as having bee n reinvested. At the end of the restriction period units are

converted into shares. With regard to leaver provis ions, if a participant ceases to be employed by BP prior to the end of the performance period the gene ral rule is

that this will preclude the grant of units. If a pa rticipant ceases to be employed by BP prior to the end of the restriction period the general rule is t hat this will

preclude the conversion of units into shares. Howev er, special arrangements apply where the participan t leaves for a qualifying reason.

Integrated Supply and Trading Deferred Annual Bonus Plan (IST DAB)

An equity-settled restricted share unit plan for tr aders in the IST function. The plan operates under the DAB but the rules differ in certain respects fr om that plan. If

eligible, a portion of a trader’s annual cash bonus (the ‘base grant’), awarded for the preceding perf ormance year (the ‘performance period’), plus an additional 25%

of that amount (the ‘additional grant’),will be def erred in restricted share units. The units are rest ricted over a period of three calendar years, durin g which they

accrue net notional dividends, which are treated as having been reinvested. At the end of the restrict ion period units are converted into shares. One thi rd of the

base grant vests after one and two calendar years r espectively, with the final third plus the addition al grant vesting after three calendar years. With r egard to leaver

provisions, if a participant ceases to be employed by BP prior to the end of the restriction period th e general rule is that this will preclude the conve rsion of units into

shares. Special arrangements apply where the partic ipant leaves for a qualifying reason.

Performance Share Plan (PSP)

An equity-settled restricted share unit plan for se nior professionals and team leaders. The grant take s into account the recipient’s performance in the p rior calendar

year (the ‘performance period’). The units are rest ricted for a period of three years (the ‘restrictio n period’), during which they accrue net notional d ividends, which

are treated as having been reinvested. At the end o f the restriction period additional units may be aw arded based on BP’s TSR performance against the oth er oil

majors. At the end of the restriction period units are converted into shares. With regard to leaver pr ovisions the general rule is that leaving during th e performance

period will preclude the grant of units. If a parti cipant 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 arrang ements apply where the participant leaves for a qua lifying reason.

Restricted Share Plan (RSP)

An equity-settled restricted share unit plan used p redominantly for senior employees in special circum stances (such as recruitment and retention). There are generally no performance conditions but the units a re subject to a three- year restriction period, during which they accrue n et notional dividends which are treated as

having been reinvested. At the end of the restricte d period the units are converted into shares. With regard to leaver provisions, if a participant cease s 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, speci al

arrangements apply where the participant leaves for a qualifying reason.

167 Notes on financial statements 

# Page 171 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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 low er than the

market price of a share immediately preceding the d ate of grant. There are no performance conditions a nd the options are exercisable between the third an d tenth

anniversaries of the grant date. The general rule i s that the options will lapse if the participant le aves employment before the end of the third calenda r year from the

date of grant (and that vested options are exercisa ble within 3 1 / 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 e lement of

our incentive plans.

Savings and matching plans

BP ShareSave Plan

This is a savings-related share option plan under w hich employees save on a monthly basis, over a thre e-year or five-year period, towards the purchase of shares

at a fixed price determined when the option is gran ted. 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 savi ngs 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 h ave six months in which to use their savings to exe rcise their options on a pro rated basis.

BP ShareMatch Plans

These are matching share plans under which BP match es employees’ own contributions of shares up to a p redetermined 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 fo r five years before they can be released free of an y income

tax and national insurance liability. In other coun tries the plan is run on an annual basis with share s being held in trust for three years. The plan is operated on a

cash basis in those countries where there are regul atory restrictions preventing the holding of BP sha res. When the employee leaves BP all shares must be

removed from trust and units under the plan operate d on a cash basis must be encashed.

Local plans

In some countries BP provides local scheme benefits , the rules and qualifications for which vary accor ding to local circumstances.

The above share plans are indicated as being equity -settled. In certain countries however, it is not p ossible to award shares to employees owing to local legislation.

In these instances the award will be settled in cas h, calculated as the cash equivalent of the value t o the employee of an equity-settled plan.

Cash plans

Cash-settled share-based payments/Stock Appreciatio n Rights (SARs)

These are cash-settled share-based payments availab le to certain employees that require the group to p ay the intrinsic value of the cash option/SAR/restr icted

shares to the employee at the date of exercise or o n maturity. The cash options/SARs have the same rul es 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 tim e as the company’s own shares held by the ESOP trus ts vest

unconditionally to employees, the amount paid for t hose 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 

# Page 172 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 41. Share-based payments continued

As share options are exercised continuously through out the year, the weighted average share price duri ng 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 outstandin g at 31 December 2008, the exercise price ranges an d

weighted average remaining contractual lives are sh own below.

Fair values and associated details for options and shares granted

The group uses an appropriate valuation model of ex pected volatility of US ADSs for the quarter within which the grant date of the relevant plan falls. M anagement

is responsible for all inputs and assumptions in re lation to that model, including the determination o f 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

- EDIP

Shares 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 

# Page 173 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 41. Share-based payments continued

The group used a Monte Carlo simulation to fair val ue the TSR element of the 2008, 2007 and 2006 PSP, MTPP and EDIP plans. In accordance with the rules o f

the plans the model simulates BP’s TSR and compares it against our principal strategic competitors ove r the three-year period of the plans. The model tak es into

account the historic dividends, share price volatil ities and covariances of BP and each comparator com pany to produce a predicted distribution of relativ e share

performance. This is applied to the reward criteria to give an expected value of the TSR element.

Accounting expense does not necessarily r epresent the actual value of share- based payments made to recipients, which are determ ined 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

- EDIP

Shares 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 salaries a 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 Marketing b c 61,500 67,200 68,000

Other businesses and corporate c 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 World b 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

a Includes termination payments of $669 million (2007 $4 22 million and 2006 $257 million). A restructuring w as announced in October 2007, the implementation of wh ich continues in 2009.

b Includes 21,200 (2007 24,500 and 2006 26,100) service st ation staff.

c A minor amendment has been made to the comparative fig ures to include some employee costs which had been previously incorrectly excluded and to correct headcount data. 

# Page 174 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 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-executi ve chairman and the non-executive directors and, fo r executive directors, salary and benefits earned d uring

the relevant financial year, plus bonuses awarded f or the year. This includes an ex gratia superannuat ion payment of nil (2007 $3 million and 2006 nil) a nd

compensation for loss of office of $1 million (2007 $1 million and 2006 nil).

Pension contributions

Four executive directors participated in a non-cont ributory pension scheme established for UK employee s by a separate trust fund to which contributions a re made

by BP based on actuarial advice. One US executive d irector participated in the US BP Retirement Accumu lation Plan during 2008.

Office facilities for former chairmen and deputy ch airmen

It is customary for the company to make available t o former chairmen and deputy chairmen, who were pre viously 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 manager s who are members of the executive management team.

Short-term employee benefits

In addition to fees paid to the non-executive chair man and non-executive directors, these amounts comp rise, for executive directors and senior managers, salary

and benefits earned during the year, plus bonuses a warded for the year. This includes an ex gratia sup erannuation payment of nil (2007 $3 million and 200 6 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 gro up of providing defined benefit pensions and other post-retirement benefits to senior management in re spect 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 me asured by the fair value of options and shares gran ted

accounted for in accordance with IFRS 2 ‘Share-base d Payments’. The main plans in which senior managem ent 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 

# Page 175 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 44. Contingent liabilities

There were contingent liabilities at 31 December 20 08 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 co ntingent liabilities. Further information is includ ed in Note 28.

Approximately 200 lawsuits were filed in State and Federal Courts in Alaska seeking compensa tory and punitive damages arising out of the Exxon Valdez oil

spill in Prince William Sound in March 1989. Most o f 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 t he spill until the response was taken over by Exxon . BP owns a

46.9% interest (reduced during 2001 from 50% by a s ale of 3.1% to Phillips) in Alyeska through a subsi diary of BP America Inc. and briefly indirectly own ed a

further 20% interest in Alyeska following BP’s comb ination with Atlantic Richfield Company (Atlantic R ichfield). Alyeska and its owners have settled all the claims

against them under these lawsuits. Exxon has indica ted that it may file a claim for contribution again st Alyeska for a portion of the costs and damages w hich it has

incurred. If any claims are asserted by Exxon that affect Alyeska and its owners, BP will defend the c laims vigorously. It is not possible to estimate an y 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 in jury to

persons and property caused by lead pigment in pain t. The majority of the lawsuits have been abandoned or dismissed as against Atlantic Richfield. Atlant ic

Richfield is named in these lawsuits as alleged suc cessor to International Smelting and Refining and a nother company that manufactured lead pigment durin g the

period 1920-1946. Plaintiffs include individuals an d governmental entities. Several of the lawsuits pu rport to be class actions. The lawsuits (depending on plaintiff)

seek various remedies, including: compensation to l ead-poisoned children; cost to find and remove lead paint from buildings; medical monitoring and scree ning

programmes; public warning and education on lead ha zards; reimbursement of government healthcare costs and special education for lead-poisoned citizens; and

punitive damages. No lawsuit against Atlantic Richf ield has been settled nor has Atlantic Richfield be en subject to a final adverse judgment in any proce eding. The

amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in t he various cases could be substantial. While it is not

possible to predict the outcome of these legal acti ons, Atlantic Richfield believes that it has valid defences and it intends to defend such actions vigo rously and thus

the incurrence of a liability by Atlantic Richfield is remote. Consequently, BP believes that the impa ct of these lawsuits on the group’s results of oper ations, financial

position or liquidity will not be material.

In addition, various group companies are parties to legal actions and claims that arise in t he ordinary course of the group’s business. While t he outcome of

such legal proceedings cannot be readily foreseen, BP believes that they will be resolved without mate rial effect on the group’s results of operations, f inancial

position or liquidity. The group files income tax r eturns 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 applica ble tax laws and regulations and the resolution of tax positions

through negotiations with relevant tax authorities, or through litigation, can take several years to c omplete. While it is difficult to predict the ultim ate outcome in

some cases, the group does not anticipate that ther e will be any material impact upon the group’s resu lts of operations, financial position or liquidity.

The group is subject to numerous national and local environmental laws and regulations conce rning its products, operations and other activities . These laws

and regulations may require the group to take futur e action to remediate the effects on the environmen t of prior disposal or release of chemicals or petr oleum

substances by the group or other parties. Such cont ingencies may exist for various sites including ref ineries, chemical plants, oil fields, service stati ons, terminals

and waste disposal sites. In addition, the group ma y have obligations relating to prior asset sales or closed facilities. The ultimate requirement for re mediation and

its cost are inherently difficult to estimate. Howe ver, the estimated cost of known environmental obli gations has been provided in these accounts in acco rdance with

the group’s accounting policies. While the amounts of future costs could be significant and could be m aterial to the group’s results of operations in the period in

which they are recognized, it is not practical to e stimate the amounts involved. BP does not expect th ese costs to have a material effect on the group ’s financial

position or liquidity.

The group generally restricts its purchas e 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 lo sses for the group. Losses will therefore be borne as they arise rather than being spread over time th rough

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 c ontracts had been placed at 31 December 2008 amount ed

to $14,062 million (2007 $8,263 million). In additi on, at 31 December 2008, the group had contracts in place for future capital expenditure relating to i nvestments in

jointly controlled entities of $644 million (2007 $ 1,039 million) and investments in associates of $16 0 million (2007 $74 million).

Capital commitments of jointly controlled entities amounted to $1,540 million (2007 $2,273 m illion).

172 Notes on financial statements 

# Page 176 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 46. Subsidiaries, jointly controlled entities and associa tes

The more important subsidiaries, jointly controlled entities and associates of the group at 31 Decembe r 2008 and the group percentage of ordinary share c apital or

joint venture interest (to nearest whole number) ar e 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 b y the parent company are marked with an asterisk (* ), the percentage owned being that of the group unl ess otherwise indicated. A complete list of investments in subsidiaries, jointly controlled entities and a ssociates 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 opera tions

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 

# Page 177 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 46. Subsidiaries, jointly controlled entities and associa tes 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 Energy a 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 ex traction

a Pan American Energy is not controlled by BP as certain ke y business decisions require joint approval of both BP and the minority partner. It is therefore classified as a jo intly controlled entity rather

than a subsidiary.

Associates % Country of incorporation Principal activities

Abu Dhabi

Abu Dhabi Marine Areas 37 England Crude oil pr oduction

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 

# Page 178 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 47. Oil and natural gas exploration and production act ivities a

The group’s share of jointly controlled entities’ a nd associates’ net capitalized costs at 31 December 2008 was $13,393 million.

The group’s share of jointly controlled entities’ a nd associates’ costs incurred in 2008 was $3,259 mi llion: 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’ a nd 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 mil lion, taxation of $1,217 million and minority inter est 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 costs b 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 Decembe r

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 taxation d 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 activities e 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

a This note contains information relating to oil and nat ural 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 transpor tation are excluded. In addition, our midstream activiti es of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are

excluded. The most significant midstream pipeline intere sts include the Trans-Alaska Pipeline System, the Forties P ipeline System, the Central Area Transmission System pip eline and the Baku-Tbilisi- Ceyhan pipeline.

Major LNG activities are located in Trinidad, Indonesi a and Australia and BP is also investing in the LNG b usiness in Angola. The group’s share of jointly controlle d entities’ and associates’ activities are excluded from

the tables and included in the footnotes with the except ion of the Abu Dhabi operations, which are included in the results of operations above.

b Includes exploration and appraisal drilling expenditure s, 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 fai r value loss on embedded derivatives of $102 million. The UK region includes a $499 million gain offset by corre sponding charges primarily in the US, relating

to the group self-insurance programme.

d Excludes the unwinding of the discount on provisions and pa yables amounting to $285 million which is included in fi nance costs in the group income statement.

e Includes a $517 million write

- down of our investment in Rosneft based on its quoted m arket price at the end of the year. 

# Page 179 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 47. Oil and natural gas exploration and production act ivities a 

### 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’ a nd 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 costs b 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’ a nd associates’ costs incurred in 2007 was $2,552 mi llion: 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 Decembe r

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 taxation d 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’ a nd 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 mil lion, taxation of $1,355 million and minority inter est of $215 million.

Exploration and Production segment profit before in terest

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

a This note contains information relating to oil and nat ural 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 transpor tation are excluded. In addition, our midstream activiti es of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are

excluded. The most significant midstream pipeline intere sts include the Trans-Alaska Pipeline System, the Forties P ipeline System, the Central Area Transmission System pip eline and the Baku-Tbilisi- Ceyhan pipeline.

Major LNG activities are located in Trinidad, Indonesi a and Australia. The group’s share of jointly control led entities’ and associates’ activities are excluded from the tables and included in the footnotes with the

exception of the Abu Dhabi operations, which are includ ed in the results of operations above.

b Includes exploration and appraisal drilling expenditure s, 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 fai r value gain on embedded derivatives of $47 million. Th e UK region includes a $409 million gain offset by corre sponding charges primarily in the US, relating to

the group self-insurance programme.

d Excludes the unwinding of the discount on provisions and pa yables amounting to $179 million which is included in fi nance costs in the group income statement. 

# Page 180 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 47. Oil and natural gas exploration and production act ivities a 

### continued

The group’s share of jointly controlled entities’ a nd associates’ net capitalized costs at 31 December 2006 was $10,870 million.

The group’s share of jointly controlled entities’ a nd associates’ costs incurred in 2006 was $1,688 mi llion: 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’ a nd 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 mil lion, taxation of $1,804 million and minority inter est 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 costs b 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 taxation d 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

a This note contains information relating to oil and nat ural 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 mar keting and trading of natural gas, power and NGLs in t he US, Canada, UK and Europe are excluded. The main m idstream activities are the Alaskan transportation

facilities, the Forties Pipeline system and the Central A rea Transmission System. The group’s share of jointly cont rolled entities’ and associates’ activities is excluded from the tables and included in the footnotes with

the exception of the Abu Dhabi operations, which are i ncluded in the income and expenditure items above.

b Includes exploration and appraisal drilling expenditure s, 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 othe rs where royalty is payable in cash, property taxes, other g overnment take and the fair value gain on embedded der ivatives $515 million.

d Excludes the unwinding of the discount on provisions and pa yables amounting to $153 million which is included in fi nance costs in the group income statement. 

# Page 181 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Additional information for US reporting

48. Auditor’s remuneration for US reporting

Audit fees for 2008 include $3 million of additiona l fees for 2007 (2007 $7 million of additional fees for 2006 and 2006 $5 million of additional fees fo r 2005). Audit

fees are included in the income statement within di stribution and administration expenses.

Other further assurance services include nil (2007 $1 million and 2006 nil) in respect of ad vice on accounting, auditing and financial reportin g matters;

$5 million (2007 $5 million and 2006 $5 million) in respect of non-statutory audits and nil (2007 $2 m illion and 2006 nil) in respect of project assuranc e 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-a pproval policies and procedures for the engagement of Ernst & Young to render audit and certain assura nce and

tax services. The audit fees payable to Ernst & You ng are reviewed by the audit committee in the conte xt of other global companies for cost-effectiveness . Ernst &

Young performed further assurance and tax services that were not prohibited by regulatory or other pro fessional requirements and were pre-approved by the

committee. Ernst & Young is engaged for these servi ces when its expertise and experience of BP are imp ortant. Most of this work is of an audit nature. Ta x services were awarded either through a full competi tive tender process or following an assessment of t he 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 

# Page 182 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# 49. Valuation and qualifying accounts

50. Computation of ratio of earnings to fixed charges ( unaudited)

51. Condensed consolidating information on certain US su bsidiaries

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 ba sis is

intended to provide investors with meaningful and c omparable financial information about BP p.l.c. and its subsidiary issuers of registered securities an d is provided

pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiar y issuer of public debt securities. Investments inc lude the

investments in subsidiaries recorded under the equi ty method for the purposes of the condensed consoli dating financial information. Equity income of subs idiaries

is the group’s share of profit related to such inve stments. The eliminations and reclassifications col umn includes the necessary amounts to eliminate the

intercompany balances and transactions between BP p .l.c., BP Exploration (Alaska) Inc. and other subsi diaries. BP p.l.c. also fully and unconditionally g uarantees

securities issued by BP Canada Finance Company, BP Capital Markets p.l.c. and BP Capital Markets Ameri ca 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 accounts a Deductions 31 December

2008

Fixed assets

– Investments b 146 647 143 (1 ) 935

Doubtful debts b 406 191 (32 ) (174 ) 391

2007

Fixed assets

– Investments b 151 158 2 (165 ) 146

Doubtful debts b 421 175 34 (224 ) 406

2006

Fixed assets

– Investments b 172 26 (3 ) (44 ) 151

Doubtful debts b 374 158 32 (143) 421

a Principally currency transactions.

b Deducted in the balance sheet from the assets to which th ey 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 equit y

- 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 fi xed 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 

# Page 183 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 51. Condensed consolidating information on certain US s ubsidiaries 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 fix ed 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 a nd 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 i nterest 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 revenues a 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 fix ed 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 costs a 49 381 2,230 (1,267 ) 1,393

Net finance (income) expense relating to pensions a nd other post-retirement

benefits

– ( 820 ) 168

– ( 652 )

Profit before taxation 3,530 20,924 28,944 (21,787 ) 31,611

Taxation a 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 

# Page 184 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 51. Condensed consolidating information on certain US s ubsidiaries 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 revenues a 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 fix ed 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 costs a 11 702 1,780 (1,507 ) 986

Net finance (income) expense relating to pensions a nd other post

- retirement

benefits – ( 675 ) 205 – ( 470 )

Profit before taxation from continuing operations 3,436 23,106 32,394 (23,794 ) 35,142

Taxation a 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

a Within the 2006 and 2007 income statements, the tax cha rge 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 m illion and $26 million respectively from the amounts pr eviously 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, th e profit for the year relating to BP Exploration (Ala ska) Inc has increased by $238 million in 2006 and

$26 million in 2007 and the profit for the year rela ting to Other subsidiaries has decreased by $238 million and $26 million respectively. There is no impact on the co nsolidated group profit for the year. In addition, fo r

Other subsidiaries the amount of interest and other re venues in 2007 has been increased by $789 million (2006, $628 million) and the amount of finance costs has incr eased by the same amounts. This change has

been made to properly reflect interest between group entities. Corresponding adjustments have been to the Eli minations and reclassifications amounts. The BP group amo unts are unchanged. This immaterial change

has no impact upon profit for the year for Other subsidi aries or BP group. 

# Page 185 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 51. Condensed consolidating information on certain US s ubsidiaries 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 

# Page 186 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 51. Condensed consolidating information on certain US s ubsidiaries 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 receivables a 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 payables a 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 classif ied 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-retirem ent 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

a Within Current liabilities

– Trade and other payables, the amount of other payables for BP Exploration (Alaska) Inc. has been reduced by $26 4 million from the amount previously reported and with in Current assets

– Trade and other receivables the amount of other receiva bles for other subsidiaries has been reduced by $264 milli on from the amounts previously reported, with a corresp onding change to intercompany eliminations

within the Eliminations and reclassifications column. As a result of this immaterial change, the net assets and BP sh areholders’ equity of BP Exploration (Alaska) Inc. have increased by $264 million and the net assets

and BP shareholders’ equity of Other subsidiaries have decr eased by $264 million. This change has been made to refl ect the allocation of tax liabilities between BP Explora tion (Alaska) Inc. and other Alaskan

subsidiaries in the BP group. There is no impact on the BP group total equity. 

# Page 187 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### 51. Condensed consolidating information on certain US s ubsidiaries 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 a nd 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 a nd 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 a nd 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 

# Page 188 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Supplementary information on oil and natural gas (u naudited)

Movements in estimated net proved reserves

For details of BP’s governance process for the book ing of oil and natural gas reserves, see page 15. B P 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 e stimate

is made. There was a rapid and substantial decline in oil prices in the fourth quarter of 2008 that wa s not matched by a similar reduction in operating c osts by the

end of the year. BP does not expect that these econ omic conditions will continue. However, our 2008 re serves are calculated on the basis of operating act ivities

that would be undertaken were year-end prices and c osts to persist.

185 Supplementary information on oil and natural gas (u naudited)

2008

Crude oil a 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

Production b (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 2008 c

Developed 410 81 1,717 58 77 464

– 174 2,981

Undeveloped 119 194 1,273 56 69 496

– 477 2,684

529 275 2,990 e 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 2008 d

Developed

– – – 399 1

– 2,227 498 3,125

Undeveloped

– – – 409

– 11 944 199 1,563

– – – 808 1 11 3,171 697 4,688

a Crude oil includes NGLs and condensate. Proved reserves excl ude 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 inde pendently.

b Excludes 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 mil lion barrels of crude oil in respect of the 30% minorit y interest in BP Trinidad and Tobago LLC.

d Includes 36 million barrels of NGLs. Also includes 216 mil lion barrels of crude oil in respect of the 6.80% min ority interest in TNK

- BP.

e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 54 million barrels upon which a net profi ts royalty will be payable over the life of the field un der the terms of the BP Prudhoe Bay Royalty Trust. 

# Page 189 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Movements in estimated net proved reserves continue d

186 Supplementary information on oil and natural gas (u naudited)

2008

Natural gas a 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

Production b (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 2008 c

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

Production b

– – – ( 188 ) (12 )

– ( 221 ) (10 ) (431 )

Sales of reserves-in-place

– – – – – – – – –

– – – 212 (3 ) 182 1,052 (10 ) 1,433

At 31 December 2008 d

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

a Proved reserves exclude royalties due to others, whether pay able in cash or in kind where the royalty owner has a di rect interest in the underlying production and the opt ion and ability to make lifting and sales

arrangements independently.

b Includes 193 billion cubic feet of natural gas consumed i n operations, 149 billion cubic feet in subsidiaries, 44 billion cubic feet in equity-accounted entities and exclud es 16.9 billion cubic feet of produced nonhydrocarbon components which meet regulatory requirements for sales.

c Includes 3,108 billion cubic feet of natural gas in respe ct of the 30% minority interest in BP Trinidad and To bago LLC.

d Includes 131 billion cubic feet of natural gas in respect of the 5.92% minority interest in TNK

- BP. 

# Page 190 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Movements in estimated net proved reserves continue d

187 Supplementary information on oil and natural gas (u naudited)

2007

Crude oil a million barrels

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Othe r 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

Production b (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 2007 c

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 f 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 2007 e

Developed

– – – 328 1

– 2,094 573 2,996

Undeveloped

– – – 243

– – 1,137 205 1,585

– – – 571 1 – 3,231 778 4,581

a Crude oil includes NGLs and condensate. Proved reserves excl ude 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 inde pendently.

b Excludes 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 mil lion barrels of crude oil in respect of the 30% minorit y interest in BP Trinidad and Tobago LLC.

d The BP group holds interests, through associates, in onshor e 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 reserve s 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.

e Includes 26 million barrels of NGLs. Also includes 210 mil lion barrels of crude oil in respect of the 6.51% min ority interest in TNK-BP.

f Proved reserves in the Prudhoe Bay field in Alaska include an estimated 98 million barrels upon which a net prof its royalty will be payable over the life of the field u nder the terms of the BP Prudhoe Bay Royalty Trust. 

# Page 191 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Movements in estimated net proved reserves continue d

188 Supplementary information on oil and natural gas (u naudited)

2007

Natural gas a billion cubic feet

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Othe r 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

Production b (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 2007 c

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

Production b – – – ( 176 ) (13) – (179) (9 ) (377)

Sales of reserves

- in

- place

– – – – – – – – –

– – – 114 1

– ( 110 ) 2 7

At 31 December 2007 d

Developed

– – – 1,478 39

– 808 148 2,473

Undeveloped

– – – 831 37

– 353 76 1,297

– – – 2,309 76

– 1,161 224 3,770

a Proved reserves exclude royalties due to others, whether pay able in cash or in kind where the royalty owner has a di rect interest in the underlying production and the opt ion and ability to make lifting and sales

arrangements independently.

b Includes 202 billion cubic feet of natural gas consumed i n operations, 161 billion cubic feet in subsidiaries, 41 billion cubic feet in equity-accounted entities and exclud es 10.9 billion cubic feet of produced nonhydrocarbon components which meet regulatory requirements for sales.

c Includes 3,211 billion cubic feet of natural gas in respe ct of the 30% minority interest in BP Trinidad and To bago LLC.

d Includes 68 billion cubic feet of natural gas in respect of the 5.88% minority interest in TNK

- BP. 

# Page 192 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Movements in estimated net proved reserves continue d

189 Supplementary information on oil and natural gas (u naudited)

2006

Crude oil a 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

Production b (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 2006 c

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 e 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 2006 d

Developed

– – – 221 1

– 2,200 520 2,942

Undeveloped

– – – 139

– – 644 163 946

– – – 360 1 – 2,844 683 3,888

a Crude oil includes NGLs and condensate. Proved reserves excl ude 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.

b Excludes 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 mil lion barrels of crude oil in respect of the 30% minorit y interest in BP Trinidad and Tobago LLC.

d Includes 28 million barrels of NGLs. Also includes 179 mil lion barrels of crude oil in respect of the 6.29% min ority interest in TNK-BP.

e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 81 million barrels upon which a net profi ts royalty will be payable over the life of the field un der the terms of the BP Prudhoe Bay Royalty Trust. 

# Page 193 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Movements in estimated net proved reserves continued

190 Supplementary information on oil and natural gas (u naudited)

2006

Natural gas a 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

Production b (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 2006 c

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

Production b

– – – ( 171 ) (15 )

– ( 204 ) (7 ) (397 )

Sales of reserves

- in

- place

– – – ( 77 )

– – – – ( 77 )

– – – ( 145 ) (1 )

– 13 40 (93 )

At 31 December 2006 d

Developed

– – – 1,460 52

– 1,087 170 2,769

Undeveloped

– – – 735 23

– 184 52 994

– – – 2,195 75

– 1,271 222 3,763

a Proved reserves exclude royalties due to others, whether pay able in cash or in kind where the royalty owner has a di rect interest in the underlying production and the opt ion to make lifting and sales arrangements

independently.

b Includes 178 billion cubic feet of natural gas consumed i n operations, 147 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities and exclud es 8.3 billion cubic feet of produced nonhydrocarbon components which meet regulatory requirements for sales.

c Includes 3,537 billion cubic feet of natural gas in respe ct of the 30% minority interest in BP Trinidad and To bago LLC.

d Includes 99 billion cubic feet of natural gas in respect of the 7.77% minority interest in TNK

- BP. 

# Page 194 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Standardized measure of discounted future net cash flows and changes therein relating to proved oil an d gas reserves

The following tables set out the standardized measu res of discounted future net cash flows, and change s therein, relating to crude oil and natural gas pr oduction

from the group’s estimated proved reserves. This in formation is prepared in compliance with the requir ements of FASB Statement of Financial Accounting

Standards No. 69 – ‘Disclosures about Oil and Gas P roducing Activities’.

Future net cash flows have been prepared on the basis of certain assumptions which may or ma y not be realized. These include the timing of futu re 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. Fur thermore,

both reserves estimates and production forecasts ar e subject to revision as further technical informat ion becomes available and economic conditions chang e. BP

cautions against relying on the information present ed because of the highly arbitrary nature of assump tions on which it is based and its lack of comparab ility with

the historical cost information presented in the fi nancial statements.

The following are the principal sources of change i n the standardized measure of discounted future net cash flows:

191 Supplementary information on oil and natural gas (u naudited)

$ million

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Other Total

At 31 December 2008

Future cash inflows a 36,400 13,800 165,800 32,700 28,400 40,400 27,200 344,700

Future production cost b 18,100 6,300 80,400 9,900 12,100 11,600 10,400 148,800

Future development cost b 3,300 2,900 25,600 8,500 3,800 10,900 6,900 61,900

Future taxation c 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 discount d 2,200 1,200 21,000 3,900 4,600 5,500 3,500 41,900

Standardized measure of discounted future

net cash flows e 5,500 1,100 21,300 4,400 4,700 5,800 4,400 47,200

At 31 December 2007

Future cash inflows a 72,100 29,500 350,100 67,700 47,600 63,300 49,400 679,700

Future production cost b 27,500 7,500 109,800 17,900 12,800 9,9 00 8,500 193,900

Future development cost b 4,000 3,300 21,900 6,500 4,100 8,300 3,500 51,600

Future taxation c 20,200 13,000 71,600 21,700 9,700 17,1 00 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 discount d 6,500 2,800 76,000 9,500 10,300 9,400 11,500 126,000

Standardized measure of discounted future

net cash flows e 13,900 2,900 70,800 12,100 10,700 18,6 00 17,200 146,200

At 31 December 2006

Future cash inflows a 45,300 18,200 218,900 46,800 36,800 47,700 36,200 449,900

Future production cost b 20,700 4,700 71,300 14,900 9,400 8,700 7,200 136,900

Future development cost b 3,300 1,500 18,600 4,900 3,800 6,600 3,900 42,600

Future taxation c 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 discount d 3,200 1,000 45,600 6,200 9,000 8,400 7,300 80,700

Standardized measure of discounted future

net cash flows e 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 dur ing 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 year f (99,000 ) 55,600 (37,600)

a The 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/mmB tu).

b Production costs, which include production taxes and deve lopment costs relating to future production of proved r eserves, are based on year-end cost levels and assume continua tion of existing economic conditions.

Future decommissioning costs are included.

c Taxation is computed using appropriate year

- end statutory corporate income tax rates.

d Future net cash flows from oil and natural gas producti on are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.

e Minority interest in BP Trinidad and Tobago LLC amoun ted to $900 million at 31 December 2008 ($2,300 mill ion at 31 December 2007 and $1,300 million at 31 Dece mber 2006).

f Total change in the standardized measure during the year includes the effect of exchange rate movements. 

# Page 195 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Equity-accounted entities

In addition, at 31 December 2008, the group’s share of the standardized measure of discounted future n et 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), excludin g minority interest.

Operational and statistical information

The following tables present operational and statis tical 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, 2 007 and 2006.

Production for the year a

Productive oil and gas wells and acreage

The following tables show the number of gross and n et productive oil and natural gas wells and total g ross and net developed and undeveloped oil and natu ral 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 frac tional

working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fra ctional working interests in gross wells or acres. Productive wells

are producing wells and wells capable of production . Developed acreage is the acreage within the bound ary of a field, on which development wells have bee n

drilled, which could produce the reserves; while un developed acres are those on which wells have not b een drilled or completed to a point that would perm it the

production of commercial quantities, whether or not such acres contain proved reserves.

192 Supplementary information on oil and natural gas (u naudited)

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Subsidiaries

Crude oil b 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 gas c 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 oil b 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 gas c 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

a Production excludes royalties due to others whether pa yable in cash or in kind where the royalty owner has a dir ect interest in the underlying production and the opti on and ability to make lifting and sales arrangements

independently.

b Crude oil includes natural gas liquids and condensate.

c Natural gas production excludes gas consumed in operati ons.

Rest of Rest of Asia

UK Europe US Americas Pacific Africa Russia Other Total

Number of productive wells at 31

December 2008

Oil wells a

– 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 wells b

– gross 310

– 20,913 2,326 466 99 44 134 24,292

– net 142

– 11,948 1,397 166 45 22 89 13,809

a Includes approximately 966 gross (255 net) multiple comp letion wells (more than one formation producing into the same well bore).

b Includes approximately 2,631 gross (1,737 net) multiple co mpletion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well. 

# Page 196 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

### Supplementary information on oil and natural gas (un audited) continued

Net oil and gas wells completed or abandoned

The following table shows the number of net product ive and dry exploratory and development oil and nat ural gas wells completed or abandoned in the years

indicated by the group and its equity-accounted ent ities. Productive wells include wells in which hydr ocarbons were encountered and the drilling or compl etion of

which, in the case of exploratory wells, has been s uspended pending further drilling or evaluation. A dry well is one found to be incapable of producing

hydrocarbons in sufficient quantities to justify co mpletion.

Drilling and production activities in progress

The following table shows the number of exploratory and development oil and natural gas wells in the p rocess of being drilled by the group and its equity

- accounted

entities as at 31 December 2008. Suspended developm ent wells and long-term suspended exploratory wells are also included in the table.

193 Supplementary information on oil and natural gas (u naudited)

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

Undeveloped a – 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

a Undeveloped 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 

# Page 197 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Miscellaneous terms

194 In this document, unless the context otherwise requ ires,

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 tho se 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.



# Page 198 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm

# Signatures

The registrant hereby certifies that it meets all o f 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 

# Page 199 of 199 20

- F

9/2/2009 http://www.sec.gov/Archives/edgar/data/313807/000115697309000125/u06412e20vf.htm