20-F 1 u06412e20vf.htm 20-F 20-F
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 20-F
(Mark One)
     
o   REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g)
OF THE SECURITIES EXCHANGE ACT OF 1934
OR
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended 31 December 2008
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
     
o   SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-6262
 
BP p.l.c.
(Exact name of Registrant as specified in its charter)
England and Wales
(Jurisdiction of incorporation or organization)
1 St James’s Square,
London SW1Y 4PD
United Kingdom
(Address of principal executive offices)
Dr Byron E Grote
BP p.l.c. 1 St James’s Square,
London SW1Y 4PD
United Kingdom
Tel +44 (0) 20 7496 4000
Fax +44 (0) 20 7496 4630
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
     
Title of each class   Name of each exchange on which registered
Ordinary Shares of 25c each   New York Stock Exchange*
4 7/8% Guaranteed Notes due 2010   New York Stock Exchange
Floating Rate Guaranteed Extendible Notes   New York Stock Exchange
Floating Rate Guaranteed Notes due 2010   New York Stock Exchange
Substitute Floating Rate Guaranteed Notes due July 10 2009   New York Stock Exchange
Substitute Floating Rate Guaranteed Notes due October 9 2009   New York Stock Exchange
5.25% Guaranteed Notes due 2013   New York Stock Exchange
 
*Not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
 
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
         
Ordinary Shares of 25c each
    18,730,307,315  
Cumulative First Preference Shares of £1 each
    7,232,838  
Cumulative Second Preference Shares of £1 each
    5,473,414  
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ      No o
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes o      No þ
Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ      No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act. (Check one):
         
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: International Financial Reporting Standards as issued by the
U.S. GAAP o   International Accounting Standards Board þ   Other o
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
Item 17 o      Item 18 o
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o      No þ
 
 


 

Cross reference to Form 20-F
             
        Page  
Item 1.
  Identity of Directors, Senior Management and Advisors     n/a  
Item 2.
  Offer Statistics and Expected Timetable     n/a  
Item 3.
  Key Information        
 
  A. Selected financial data     6  
 
  B. Capitalization and indebtedness     n/a  
 
  C. Reasons for the offer and use of proceeds     n/a  
 
  D. Risk factors     8-10  
Item 4.
  Information on the Company        
 
  A. History and development of the company     11-12  
 
  B. Business overview     13-45  
 
  C. Organizational structure     45  
 
  Appendix A to Item 4D     7, 16-18, 185-190, 192  
 
  D. Property, plants and equipment     45  
Item 4A.
  Unresolved Staff Comments   None
Item 5.
  Operating and Financial Review and Prospects        
 
  A. Operating results     46-53  
 
  B. Liquidity and capital resources     54  
 
  C. Research and development, patent and licenses     36,130  
 
  D. Trend information     54-55  
 
  E. Off-balance sheet arrangements     55-56  
 
  F. Tabular disclosure of contractual commitments     56  
 
  G. Safe harbour     10  
Item 6.
  Directors, Senior Management and Employees        
 
  A. Directors and senior management     62-64  
 
  B. Compensation     73-83, 170-171  
 
  C. Board practices     61-71, 62, 81, 170-171  
 
  D. Employees     44-45  
 
  E. Share ownership     72, 79-80, 86-87, 166-170  
Item 7.
  Major Shareholders and Related Party Transactions        
 
  A. Major shareholders     87  
 
  B. Related party transactions     88, 138-139  
 
  C. Interests of experts and counsel     n/a  
Item 8.
  Financial Information        
 
  A. Consolidated financial statements and other financial information     88-89, 99-193  
 
  B. Significant changes   None
Item 9.
  The Offer and Listing        
 
  A. Offer and listing details     89-90  
 
  B. Plan of distribution     n/a  
 
  C. Markets     89-90  
 
  D. Selling shareholders     n/a  
 
  E. Dilution     n/a  
 
  F. Expenses of the issue     n/a  
Item 10.
  Additional Information        
 
  A. Share capital     n/a  
 
  B. Memorandum and articles of association     91-92  
 
  C. Material contracts   None
 
  D. Exchange controls     92  
 
  E. Taxation     92-94  
 
  F. Dividends and paying agents     n/a  
 
  G. Statements by experts     n/a  
 
  H. Documents on display     94  
 
  I. Subsidiary information     n/a  
Item 11.
  Quantitative and Qualitative Disclosures about Market Risk     140-145, 148-153  
Item 12.
  Description of securities other than equity securities     n/a  
Item 13.
  Defaults, Dividend Arrearages and Delinquencies   None
Item 14.
  Material Modifications to the Rights of Security Holders and Use of Proceeds     94  
Item 15.
  Controls and Procedures     94-95  
Item 16A.
  Audit Committee Financial Expert     95  
Item 16B.
  Code of Ethics     95  
Item 16C.
  Principal Accountant Fees and Services     95  
Item 16D.
  Exemptions from the Listing Standards for Audit Committees     n/a  
Item 16E.
  Purchases of Equity Securities by the Issuer and Affiliated Purchases     97  
Item 16G
  Corporate governance practices     95-96  
Item 17.
  Financial Statements     n/a  
Item 18.
  Financial Statements     16-18, 99-193  
Item 19.
  Exhibits     98  

2


 

Contents
 

     
 
5
  Performance review
 
 
61
  Board performance and biographies
 
 
73
  Directors’ remuneration report
 
 
85
  Additional information for shareholders
 
 
99
  Financial statements
 
 


 


 

Certain definitions
Unless the context indicates otherwise, the following terms have the meanings shown below:
Oil and natural gas reserves
Oil and gas reserves
Proved reserves are defined by the Securities and Exchange Commission (SEC) in Rule 410(a) of Regulation S-X, paragraphs (2), (2i), (2ii) and (2iii). Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the ‘proved’ classification when successful testing by a pilot project, or the operation of an installed programme in the reservoir, provides support for the engineering analysis on which the project or programme was based.
(iii) Estimates of proved reserves do not include the following:
(a)   oil that may become available from known reservoirs but is classified separately as ‘indicated additional reserves’;
 
(b)   crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;
 
(c)   crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and
 
(d)   crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved developed reserves
Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as ‘proved developed reserves’ only after testing by a pilot project or after the operation of an installed programme has confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves
Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances are estimates for proved undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

4


 

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


 


 

 
Performance review
 
Selected financial and operating information

This information, insofar as it relates to 2008, has been extracted or derived from the audited financial statements of the BP group presented on pages 99-184. Note 1 to the Financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related Notes elsewhere herein.
BP sold its Innovene operations in December 2005. In the circumstances of discontinued operations, IFRS require that the profits earned by the discontinued operations, in this case the Innovene operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa.
                                         
     
    $ million except per share amounts  
    2008     2007     2006     2005     2004  
     
Income statement data
                                       
     
Total revenuesa
    365,700       288,951       270,602       243,948       194,919  
Profit before interest and taxation from continuing operationsa
    35,239       32,352       35,658       32,182       25,746  
Profit from continuing operationsa
    21,666       21,169       22,626       22,133       17,884  
Profit for the year
    21,666       21,169       22,601       22,317       17,262  
Profit for the year attributable to BP shareholders
    21,157       20,845       22,315       22,026       17,075  
Capital expenditure and acquisitionsb
    30,700       20,641       17,231       14,149       16,651  
Per ordinary share – cents
                                       
Profit for the year attributable to BP shareholders
                                       
Basic
    112.59       108.76       111.41       104.25       78.24  
Diluted
    111.56       107.84       110.56       103.05       76.87  
Profit from continuing operations attributable to BP shareholdersa
                                       
Basic
    112.59       108.76       111.54       103.38       81.09  
Diluted
    111.56       107.84       110.68       102.19       79.66  
Dividends paid per share – cents
    55.05       42.30       38.40       34.85       27.70  
– pence
    29.387       20.995       21.104       19.152       15.251  
     
Ordinary share datac
                                       
     
Average number outstanding of 25 cent ordinary shares (shares million undiluted)
    18,790       19,163       20,028       21,126       21,821  
Average number outstanding of 25 cent ordinary shares (shares million diluted)
    18,963       19,327       20,195       21,411       22,293  
     
Balance sheet data
                                       
     
Total assets
    228,238       236,076       217,601       206,914       194,630  
Net assets
    92,109       94,652       85,465       80,450       78,235  
Share capital
    5,176       5,237       5,385       5,185       5,403  
BP shareholders’ equity
    91,303       93,690       84,624       79,661       76,892  
Finance debt due after more than one year
    17,464       15,651       11,086       10,230       12,907  
Net debt to net debt plus equityd
    21%       22%       20%       17%       22%  
     
 
aExcludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2004, 2005 and 2006.
 
b2008 included capital expenditure of $2,822 million and an asset exchange of $1,909 million, both in respect of our transaction with Husky, as well as capital expenditure of $3,667 million in respect of our transactions with Chesapeake (see page 47). 2007 included $1,132 million for the acquisition of Chevron’s Netherlands manufacturing company. Capital expenditure in 2006 included $1 billion in respect of our investment in Rosneft. Capital expenditure and acquisitions for 2004 included $1,354 million for including TNK’s interest in Slavneft within TNK-BP and $1,355 million for the acquisition of Solvay’s interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America. With the exception of the shares issued to Alfa Group and Access Renova (AAR) in connection with TNK-BP (2004-2006), all capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing.
 
cThe number of ordinary shares shown has been used to calculate per share amounts.
 
dNet debt and the ratio of net debt to net debt plus equity ratio are non-GAAP measures. We believe that these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. Net debt has been redefined to include the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. Amounts for comparative periods are presented on a consistent basis.
Revised definition of net debt
                                 
     
                            $ 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%  
     

6


 

Performance review
 
Production and net proved oil and natural gas reserves
The following table shows our production for the past five years and the estimated net proved oil and natural gas reserves at the end of each of those years.
Production and net proved reservesa
     
    2008f     2007     2006     2005     2004  
     
Crude oil production for subsidiaries (thousand barrels per day)
    1,263       1,304       1,351       1,423       1,480  
Crude oil production for equity-accounted entities (thousand barrels per day)
    1,138       1,110       1,124       1,139       1,051  
Natural gas production for subsidiaries (million cubic feet per day)
    7,277       7,222       7,412       7,512       7,624  
Natural gas production for equity-accounted entities (million cubic feet per day)
    1,057       921       1,005       912       879  
Estimated net proved crude oil reserves for subsidiaries (million barrels)b
    5,665       5,492       5,893       6,360       6,755  
Estimated net proved crude oil reserves for equity-accounted entities (million barrels)c
    4,688       4,581       3,888       3,205       3,179  
Estimated net proved natural gas reserves for subsidiaries (billion cubic feet)d
    40,005       41,130       42,168       44,448       45,650  
Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet)e
    5,203       3,770       3,763       3,856       2,857  
     
 
aCrude oil includes natural gas liquids (NGLs) and condensate. Production and proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations.
 
bIncludes 21 million barrels (20 million barrels at 31 December 2007 and 23 million barrels at 31 December 2006) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
cIncludes 216 million barrels (210 million barrels at 31 December 2007 and 179 million barrels at 31 December 2006) in respect of the 6.80% minority interest in TNK-BP (6.51% at 31 December 2007 and 6.29% at 31 December 2006).
 
dIncludes 3,108 billion cubic feet of natural gas (3,211 billion cubic feet at 31 December 2007 and 3,537 billion cubic feet at 31 December 2006) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
eIncludes 131 billion cubic feet (68 billion cubic feet at 31 December 2007 and 99 billion cubic feet at 31 December 2006) in respect of the 5.92% minority interest in TNK-BP (5.88% at 31 December 2007 and 7.77% at 31 December 2006).
 
fBP estimates proved reserves for reporting purposes in accordance with SEC rules and relevant guidance. As currently required, these proved reserve estimates are based on prices and costs as of the date the estimate is made. There was a rapid and substantial decline in oil prices in the fourth quarter of 2008 that was not matched by a similar reduction in operating costs by the end of the year. BP does not expect that these economic conditions will continue. However, our 2008 reserves are calculated on the basis of operating activities that would be undertaken were year-end prices and costs to persist.
During 2008, 1,085 million barrels of oil and natural gas, on an oil equivalent* basis (mmboe), were added to BP’s proved reserves for subsidiaries (excluding purchases and sales). After allowing for production, which amounted to 937mmboe, BP’s proved reserves for subsidiaries were 12,562mmboe at 31 December 2008. These proved reserves are mainly located in the US (44%), Rest of Americas (17%), Asia Pacific (10%), Africa (11%) and the UK (8%).
          For equity-accounted entities, 646mmboe were added to proved reserves (excluding purchases and sales), production was 491mmboe and proved reserves were 5,585mmboe at 31 December 2008.
 
*Natural gas is converted to oil equivalent at 5.8 billion cubic feet (bcf) = 1 million barrels.

7


 

Performance review
 

Risk factors
We urge you to consider carefully the risks described below. If any of these risks occur, our business, financial condition and results of operations could suffer and the trading price and liquidity of our securities could decline, in which case you could lose all or part of your investment.
          In the current global financial crisis and uncertain economic environment, certain risks may gain more prominence either individually or when taken together. Oil and gas prices and margins are likely to remain lower than in recent times due to reduced demand; the impact of this situation will also depend on the degree to which producers reduce production. At the same time, governments will be facing greater pressure on public finances leading to the risk of increased taxation. These factors may also lead to intensified competition for market share and available margin, with consequential potential adverse effects on volumes. The financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. Any of these factors may affect our results of operations, financial condition and liquidity.
          If there is an extended period of constraint in the capital markets, with debt markets in particular experiencing lack of liquidity, at a time when cash flows from our business operations may be under pressure, this may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements.
          Our system of risk management provides the response to risks of group significance through the establishment of standards and other controls. Inability to identify, assess and respond to risks through this and other controls could lead to an inability to capture opportunities, threats materializing, inefficiency and non-compliance with laws and regulations.
          The risks are categorized against the following areas: strategic; compliance and control; and operational.
Strategic risks
Access and renewal
Successful execution of our group plan depends critically on implementing activities to renew and reposition our portfolio. The challenges to renewal of our upstream portfolio are growing due to increasing competition for access to opportunities globally. Lack of material positions in new markets and/or inability to complete disposals could result in an inability to grow or even maintain our production.
Prices and markets
Oil, gas and product prices are subject to international supply and demand. Political developments and the outcome of meetings of OPEC can particularly affect world supply and oil prices. Previous oil price increases have resulted in increased fiscal take, cost inflation and more onerous terms for access to resources. As a result, increased oil prices may not improve margin performance. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to further reviews for impairment of the group’s oil and natural gas properties. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the group’s results of operations in the period in which it occurs. Rapid material and/or sustained change in oil, gas and product prices can impact the validity of the assumptions on which strategic decisions are based and, as a result, the ensuing actions derived from those decisions may no longer be appropriate. A prolonged period of low oil prices may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate and may impact shareholder returns, including dividends and share buybacks, or share price.
Periods of global recession could impact the demand for our products, the prices at which they can be sold and affect the viability of the markets in which we operate.
          Refining profitability can be volatile, with both periodic oversupply and supply tightness in various regional markets. Sectors of the chemicals industry are also subject to fluctuations in supply and demand within the petrochemicals market, with a consequent effect on prices and profitability.
Climate change and carbon pricing
Compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted.
Socio-political
We have operations in countries where political, economic and social transition is taking place. Some countries have experienced political instability, changes to the regulatory environment, expropriation or nationalization of property, civil strife, strikes, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas or our production to decline and could cause us to incur additional costs. In particular, our investments in Russia could be adversely affected by heightened political and economic environment risks.
          We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged.
Competition
The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency. The implementation of group strategy requires continued technological advances and innovation including advances in exploration, production, refining, petrochemicals manufacturing technology and advances in technology related to energy usage. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged the industry.
Investment efficiency
Our organic growth is dependent on creating a portfolio of quality options and investing in the best options. Ineffective investment selection could lead to loss of value and higher capital expenditure.
Reserves replacement
Successful execution of our group strategy depends critically on sustaining long-term reserves replacement. If upstream resources are not progressed to proved reserves in a timely and efficient manner, we will be unable to sustain long-term replacement of reserves.


8


 

Performance review
 

Liquidity, financial capacity and financial exposure
The group has established a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity and to constrain the level of assessed capital at risk for the purposes of positions taken in financial instruments. Failure to operate within our financial framework could lead to the group becoming financially distressed leading to a loss of shareholder value. Commercial credit risk is measured and controlled to determine the group’s total credit risk. Inability to determine adequately our credit exposure could lead to financial loss. A credit crisis affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth.
          Crude oil prices are generally set in US dollars, while sales of refined products may be in a variety of currencies. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues.
          For more information on financial instruments and financial risk factors see Financial statements – Note 28 on page 140 and Note 34 on page 148.
Compliance and control risks
Regulatory
The oil industry is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental and health and safety protection controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. We buy, sell and trade oil and gas products in certain regulated commodity markets. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, or we could incur additional costs.
          For more information on environmental regulation, see Environment on page 39.
Ethical misconduct and non-compliance
Our code of conduct, which applies to all employees, defines our commitment to integrity, compliance with all applicable legal requirements, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. Incidents of ethical misconduct or non-compliance with applicable laws and regulations could be damaging to our reputation and shareholder value. Multiple events of non-compliance could call into question the integrity of our operations.
          For certain legal proceedings involving the group, see Legal proceedings on page 88.
Liabilities and provisions
Changes in the external environment, such as new laws and regulations, market volatility or other factors, could affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities.
Reporting
External reporting of financial and non-financial data is reliant on the integrity of systems and people. Failure to report data accurately and in compliance with external standards could result in regulatory action, legal liability and damage to our reputation.
Operational risks
Process safety
Inherent in our operations are hazards that require continuous oversight and control. There are risks of technical integrity failure and loss of containment of hydrocarbons and other hazardous material at operating sites or pipelines. Failure to manage these risks could result in injury or loss of life, environmental damage, or loss of production and could result in regulatory action, legal liability and damage to our reputation.
Personal safety
Inability to provide safe environments for our workforce and the public could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation.
Environmental
If we do not apply our resources to overcome the perceived trade-off between global access to energy and the protection or improvement of the natural environment, we could fail to live up to our aspirations of no or minimal damage to the environment and contributing to human progress.
Security
Security threats require continuous oversight and control. Acts of terrorism against our plants and offices, pipelines, transportation or computer systems could severely disrupt business and operations and could cause harm to people.
Product quality
Supplying customers with on-specification products is critical to maintaining our licence to operate and our reputation in the marketplace. Failure to meet product quality standards throughout the value chain could lead to harm to people and the environment and loss of customers.
Drilling and production
Exploration and production require high levels of investment and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of an oil or natural gas field. The cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements.
Transportation
All modes of transportation of hydrocarbons contain inherent risks. A loss of containment of hydrocarbons and other hazardous material could occur during transportation by road, rail, sea or pipeline. This is a significant risk due to the potential impact of a release on the environment and people and given the high volumes involved.
Major project delivery
Successful execution of our group plan (see page 11) depends critically on implementing the activities to deliver the major projects over the plan period. Poor delivery of any major project that underpins production growth and/or a major programme designed to enhance shareholder value could adversely affect our financial performance.
Digital infrastructure
The reliability and security of our digital infrastructure are critical to maintaining our business applications availability. A breach of our digital security could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment and breaches of regulations.


9


 

Performance review
 

Business continuity and disaster recovery
Contingency plans are required to continue or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed timeframe would prolong the impact of any disruption and could severely affect business and operations.
Crisis management
Crisis management plans and capability are essential to deal with emergencies at every level of our operations. If we do not respond or are perceived not to respond in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.
People and capability
Employee training, development and successful recruitment of new staff, in particular petroleum engineers and scientists, are key to implementing our plans. Inability to develop the human capacity and capability across the organization could jeopardize performance delivery.
Treasury and trading activities
In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation.
Forward-looking statements
In order to utilize the ‘Safe Harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995, BP is providing the following cautionary statement. This document contains certain forward-looking statements with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in Performance review (pages 6-56) with regard to strategy, management aims and objectives, future capital expenditure, future hydrocarbon production volume, date(s) or period(s) in which production is scheduled or expected to come onstream or a project or action is scheduled or expected to begin or be completed, capacity of planned plants or facilities and impact of health, safety and environmental regulations; (ii) the statements in Performance review (pages 6-45) with regard to planned expansion, investment or other projects and future regulatory actions; and (iii) the statements in Performance review (pages 46-59) with regard to the plans of the group, the cost of and provision for future remediation programmes, taxation, liquidity and costs for providing pension and other post-retirement benefits; and including under ‘Liquidity and capital resources’ with regard to oil prices, production, demand for refining products, refining volumes and margins and impact on the petrochemicals sector, refining availability, continuing priority of safe, compliant and reliable operations, and focus on cost efficiency, cost deflation, capital expenditure, expected disposal proceeds, cash flows, shareholder distributions, gearing, working capital, guarantees, expected payments under contractual and commercial commitments and purchase obligations; are all forward-looking in nature.
By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including the specific factors identified in the discussions accompanying such forward-looking statements; the timing of bringing new fields onstream; future levels of industry product supply, demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this report including under ‘Risk factors’ on pages 8-10. In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.
Statements regarding competitive position
Statements referring to BP’s competitive position are based on the company’s belief and, in some cases, rely on a range of sources, including investment analysts’ reports, independent market studies and BP’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.


10


 

Performance review
 

Information on the company
General
Unless otherwise indicated, information in this document reflects 100% of the assets and operations of the company and its subsidiaries that were consolidated at the date or for the periods indicated, including minority interests. Also, unless otherwise indicated, figures for total revenues include sales between BP businesses.
          The company was incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001.
          BP is one of the world’s leading oil companies on the basis of market capitalization and proved reserves. Our worldwide headquarters is located at 1 St James’s Square, London SW1Y 4PD, UK, tel +44 (0)20 7496 4000. Our agent in the US is BP America Inc., 501 Westlake Park Boulevard, Houston, Texas 77079, tel +1281 366 2000.
Overview of the group
          BP is a global group, with interests and activities held or operated through subsidiaries, jointly controlled entities or associates established in, and subject to the laws and regulations of, many different jurisdictions. These interests and activities covered two business segments in 2008: Exploration and Production and Refining and Marketing. With effect from 1 January 2008, the former Gas, Power and Renewables segment ceased to report separately (see Resegmentation in 2008 on page 12).
          A separate business, Alternative Energy, reported in Other businesses and corporate, handles BP’s low-carbon businesses and future growth options outside oil and gas.
Exploration and Production’s activities include oil and natural gas exploration, development and production (upstream activities), together with related pipeline, transportation and processing activities (midstream activities), as well as the marketing and trading of natural gas (including LNG), power and natural gas liquids (NGLs). The activities of Refining and Marketing include the refining, manufacturing, supply and trading, marketing and transportation of crude oil, petroleum and petrochemicals products and related services. The group provides high-quality technological support for all its businesses through its research and engineering activities.
          All these activities are supported by a number of other organizational elements comprising group functions and regions. Group functions serve the business segments, aiming to achieve coherence across the group, manage risks effectively and achieve economies of scale. In addition, each regional head provides the required integration and co-ordination of group activities and represents BP to external parties.
Internal control
The group’s system of internal control is designed to meet the expectations of internal control of the Combined Code in the UK and of COSO (committee of the sponsoring organizations for the Treadway Commission) in the US. The system of internal control is the complete set of management systems, organizational structures, processes, standards and behaviours that are employed to conduct the business of BP and deliver returns to shareholders. The design of the system of internal control addresses risks and how to respond to them. Each component of the system is in itself a device to respond to a particular type or collection of risks.
Strategy
The group strategy describes the group’s strategic objectives and the assumptions made by BP about the future. It describes strategic risks and opportunities that arise from making such assumptions and the actions to be taken to manage or mitigate the risks. The board delegates to the group chief executive responsibility for developing BP’s strategy and its implementation through the group plan that determines the setting of priorities and allocation of resources. The group chief
executive is obliged to discuss with the board, on the basis of the strategy and group plan, all material matters currently or prospectively affecting BP’s performance
          During 2008, we continued to pursue our three strategic priorities of ‘Safety’, ‘People’ and ‘Performance’, which underpin BP’s ‘forward agenda’.
          Through this, we have taken steps to restore revenues, reduce complexity and manage costs and have made significant progress towards closing the competitive performance gap to our peer group. Looking forward, our strategy is to create value for shareholders by investing to deliver growth in Exploration and Production, together with high-quality earnings and returns throughout our operations. Our first priority will always be to ensure the safety and integrity of our operations.
          We expect Exploration and Production to be our core source of growth. We intend to re-invest competitively in Exploration and Production to secure and grow high-quality oil and gas resources. This investment is intended to be focused on strengthening our position further by securing new access and achieving exploration success. It is also intended to be targeted on a renewed focus on increasing recovery from fields in which we already operate. We expect to make investment across the full life cycle of our assets with an increased emphasis on technology as a source of productivity, access and competitive advantage.
          In Refining and Marketing, we expect to continue building our business around advantaged assets in material and significant energy markets. We intend to continue investing in improving the safety and reliability of our operations. Additionally, we intend to drive further operational performance and productivity by investing in the upgrade of manufacturing capabilities within our integrated fuels value chains. We also intend to invest selectively in international businesses, including lubricants and petrochemicals, where we believe there is the potential to deliver strong returns.
          In Alternative Energy, we are focusing our investment activity in new energy technology and low-carbon energy businesses that we believe will provide long-term options to meet energy demand and provide BP with significant long-term growth potential. These are wind, solar, biofuels and carbon capture and storage.
          We are dependent on our people and technology to deliver on our strategy. We intend to invest in ensuring that we have people with the right capability and experience to meet all of our objectives and the technology to support the delivery of competitive business performance and new business development. BP is committed to delivering its strategy by operating safely, reliably, in compliance with the law and within the discipline of a clear financial framework.
Geographical presence
We have well-established operations in Europe, the US, Canada, Russia, South America, Australasia, Asia and parts of Africa. Currently, around 67% of the group’s capital is invested in Organisation for Economic Cooperation and Development (OECD) countries, with around 41% of our fixed assets located in the US and around 20% located in Europe.
          We believe that BP has a strong portfolio of assets:
  In Exploration and Production, we have upstream interests in 29 countries. Exploration and Production activities are managed through operating units that are accountable for the day-to-day management of the segment’s activities. An operating unit is accountable for one or more fields. Our current areas of major development include the deepwater Gulf of Mexico, Azerbaijan, Algeria, Angola, Egypt and Asia Pacific where we believe we have competitive advantage and the foundation for volume growth and improved margins in the future. We also have significant midstream activities to support our upstream interests. Additionally, we undertake natural gas, power and NGLs marketing and trading activity and LNG activity, which are focused on identifying and capturing worldwide opportunities for our upstream natural gas reserves, and we have an NGLs processing business in North America.


11


 

Performance review
 

  In Refining and Marketing, we have a strong presence in the US and Europe. In the US, we market under the Amoco and BP brands in the midwest, east and south-east and under the ARCO brand on the west coast, and in Europe, under the BP and Aral brands. We have a long-established supply and trading activity responsible for delivering value across the crude and oil products supply chain. Our Aromatics & Acetyls business maintains a manufacturing position globally, with emphasis on growth in Asia. We also have, or are growing, businesses elsewhere in the world under the BP and Castrol brands, including a strong global lubricants portfolio and other business-to-business marketing businesses (aviation and marine) covering the mobility sectors. We continue to seek opportunities to broaden our activities in growth markets such as China and India.
Through non-US subsidiaries or other non-US entities, during the period covered by this report, BP conducted limited marketing, licensing and trading activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism. BP believes that these activities are immaterial to the group.
BP has interests in, and is the operator of, two fields and a pipeline located outside Iran in which the National Iranian Oil Company (NIOC) and an affiliated entity have interests. In Iran, BP buys small quantities of crude oil. This is primarily for sale to third parties in Europe and a small portion is used by BP in its own refineries in South Africa and Europe. In addition, BP sells small quantities of crude oil into Iran and blends and markets small quantities of lubricants for sale to domestic consumers through a joint venture there, which has a blending facility. However, BP does not seek to obtain from the government of Iran licences or agreements for oil and gas projects in Iran, is not conducting any technical studies in Iran and does not own or operate any refineries or chemicals plants in Iran.
     BP sells small quantities of lubricants in Cuba through a 50/50 joint venture there. In Syria, small quantities of lubricants are sold through a distributor and BP obtains small volumes of crude oil supplies for sale to third parties in Europe. In addition, BP sells small quantities of crude oil into Syria. These sales and purchases are insignificant and BP does not provide other goods, technologies or services in these countries.
Market context
Our market is a complex and fast-moving environment. In 2008, volatile energy price movements mirrored unsettled financial markets and wider economic uncertainty (see Risk factors on page 8). World oil consumption fell in 2008, with growing demand in fast growing non-OECD countries more than offset by falling consumption in the OECD countries. Gas consumption grew in the major markets. Anxieties around energy security continued, with individual consumer countries facing specific issues related to cost, geography and political relationships with producers. In terms of supply, substantial global reserves of oil and gas are in place but government, energy companies and industry must work together to bring these to market. There is also a clear need for greater energy diversity to address the competing challenges of growing demand and climate change. In terms of human resources, the energy industry also faces a shortage of professionals such as petroleum engineers and scientists.
Acquisitions and disposals
There were no significant acquisitions in 2006, 2007 or 2008.
          In 2008, we completed an asset exchange with Husky Energy Inc., and asset purchases from Chesapeake Energy Corporation as described on page 47.
          In 2007, BP acquired Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The acquisition included Chevron’s 31% minority shareholding in Nerefco, its 31% shareholding in the 22.5MW wind farm co-located at the refinery as well as a 22.8% shareholding in the TEAM joint venture terminal and shareholdings in two local pipelines linking the TEAM terminal to the refinery. Disposal proceeds were $4,267 million, which included $1,903 million from the sale of the Coryton refinery and $605 million from the sale of our exploration and production gas infrastructure business in the Netherlands.
          In 2006, BP purchased 9.6% of the shares issued under Rosneft’s IPO for a consideration of $1 billion (included in capital expenditure). This represented an interest of around 1.4% in Rosneft. Disposal proceeds were $6,254 million, which included $2.1 billion on the sale of our interest in the Shenzi discovery and around $1.3 billion from the sale of our producing properties on the Outer Continental Shelf of the Gulf of Mexico to Apache Corporation.
Resegmentation in 2008
On 11 October 2007, BP announced that it was to simplify its organizational structure by reducing the number of business segments.
          From 1 January 2008, BP has two business segments: Exploration and Production and Refining and Marketing. A separate business, Alternative Energy, handles BP’s low-carbon businesses and future growth options outside oil and gas and reports under Other businesses and corporate.
          As a result, and with effect from 1 January 2008:
  The former Gas, Power and Renewables segment ceased to report separately.
 
  The NGLs, LNG and gas and power marketing and trading businesses were transferred from the Gas, Power and Renewables segment to the Exploration and Production segment.
 
  The Alternative Energy business was transferred from the Gas, Power and Renewables segment to Other businesses and corporate.
 
  The Emerging Consumers Marketing Unit was transferred from Refining and Marketing to Alternative Energy (which is reported in Other businesses and corporate).
 
  The Biofuels business was transferred from Refining and Marketing to Alternative Energy (which is reported in Other businesses and corporate).
 
  The Shipping business was transferred from Refining and Marketing to Other businesses and corporate.


12


 

Performance review
 

Exploration and Production
Our Exploration and Production segment includes upstream and midstream activities in 29 countries, including Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), the UK, the US and locations within Asia Pacific, Latin America, North Africa and the Middle East, as well as gas marketing and trading activities, primarily in Canada, Europe, the UK and the US. Upstream activities involve oil and natural gas exploration and field development and production. Our exploration programme is currently focused around Algeria, Angola, Azerbaijan, Canada, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea and onshore US. Major development areas include Algeria, Angola, Asia Pacific, Azerbaijan, Egypt and the deepwater Gulf of Mexico. During 2008, production came from 21 countries. The principal areas of production are Angola, Asia Pacific, Azerbaijan, Egypt, Latin America, the Middle East, Russia, Trinidad, the UK and the US.
          Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing facilities and transportation, and our NGL extraction businesses in the US and UK. Our most significant midstream pipeline interests are the Trans-Alaska Pipeline System in the US, the Forties Pipeline System and the Central Area Transmission System pipeline, both in the UK sector of the North Sea, and the Baku-Tbilisi-Ceyhan pipeline, running through Azerbaijan, Georgia and Turkey. Major LNG activities are located in Trinidad, Indonesia and Australia. BP is also investing in the LNG business in Angola.
          Additionally, our activities include the marketing and trading of natural gas, power and natural gas liquids in the US, Canada, UK and Europe. These activities provide routes into liquid markets for BP’s gas and power, and generate margins and fees associated with the provision of physical and financial products to third parties and additional income from asset optimization and trading.
          Our oil and natural gas production assets are located onshore and offshore and include wells, gathering centres, in-field flow lines, processing facilities, storage facilities, offshore platforms, export systems (e.g. transit lines), pipelines and LNG plant facilities.
          Upstream operations in Argentina, Bolivia, Abu Dhabi, Kazakhstan and TNK-BP and some of the Sakhalin operations in Russia, as well as some of our operations in Canada, Indonesia and Venezuela, are conducted through equity-accounted entities.
Our performance in 2008
Profit before interest and tax for 2008 was $37.9 billion, an increase of 37% compared with 2007. The increase was primarily driven by higher oil and gas realizations. Our financial results are discussed in more detail on pages 48-49.
          In 2008, nine major projects came onstream. Production commenced at the Thunder Horse field, with four wells in operation by the end of the year, producing around 200,000boe/d (gross) making us the largest producer in the Gulf of Mexico. We also started oil production on our Deepwater Gunashli platform in the Azerbaijan sector of the Caspian Sea. Other significant successes included the start of oil and gas production at the Saqqara and Taurt fields in Egypt. Production from our established centres including the North Sea, Alaska, North America Gas and Trinidad & Tobago, was on plan. We are also increasing our ability to get more from fields by improving our overall recovery rates through developing and applying new technology.
In terms of the continued renewal of our oil and natural gas resource base, 2008 was one of our best years this decade for new discoveries.
          Total capital expenditure including acquisitions in 2008 was $22.2 billion (2007 $14.2 billion and 2006 $13.3 billion). In 2008, there were no significant acquisitions. Capital expenditure included $2.8 billion relating to the formation of an integrated North American oil sands business with Husky Energy Inc. It also included $3.7 billion relating to the purchase of all Chesapeake Energy Corporation’s interest in the Woodford Shale assets in the Arkoma basin, and the purchase of a 25% interest in Chesapeake’s Fayetteville Shale assets, enabling further growth of our North American gas business.
          There were no significant acquisitions in 2006 and 2007. Capital expenditure in 2006 included our investment of $1 billion in Rosneft.
          Development expenditure incurred in 2008, excluding midstream activities, was $11,767 million, compared with $10,153 million in 2007 and $9,109 million in 2006.
          Looking ahead, our priorities remain the same: safety, people and performance. We will continue to strive to deliver safe, reliable and efficient operations while maintaining our flexibility so we can respond to oil price volatility.
          In 2009, oil and gas prices are expected to be significantly lower than 2008. In response we will aim to use the operational momentum generated in 2008 to continue to increase the efficiency of our cost base and to build capability for the future. We intend to retain our rigour around capital investment, in particular pacing our development to take advantage of any cost reductions in a deflationary environment, and supporting our strategy of growing the upstream business. We believe that our portfolio of assets is strong and is well positioned to compete and grow in a range of external conditions.
          Comparative information presented in the table on the following page has been restated, where appropriate, to reflect the resegmentation, following transfers of certain businesses between segments, that was effective from 1 January 2008. See page 12 for more details.


13


 

Performance review
 

Key statistics
                         
 
                    $ million  
 
    2008     2007     2006  
 
Total revenuesa
    89,902       69,376       71,868  
Profit before interest and tax from continuing operationsb
    37,915       27,729       30,953  
Total assets
    136,665       125,736       124,803  
Capital expenditure and acquisitions
    22,227       14,207       13,252  
 
 
                       
million barrels of oil equivalent
 
Net proved reserves – group
    12,562       12,583       13,163  
Net proved reserves – equity-accounted entities
    5,585       5,231       4,537  
 
 
                       
thousand barrels per day
 
Liquids production – group
    1,263       1,304       1,351  
Liquids production – equity-accounted
    1,138       1,110       1,124  
  entities
                       
 
 
                       
million cubic feet per day
 
Natural gas production – group
    7,277       7,222       7,412  
Natural gas production – equity-accounted entities
    1,057       921       1,005  
 
 
                       
$  per barrel
 
Average BP crude oil realizationsc
    95.43       69.98       61.91  
Average BP NGL realizationsc
    52.30       46.20       37.17  
Average BP liquids realizationsc d
    90.20       67.45       59.23  
Average West Texas Intermediate oil price
    100.06       72.20       66.02  
Average Brent oil price
    97.26       72.39       65.14  
 
 
                       
$  per thousand cubic feet
 
Average BP natural gas realizationsc
    6.00       4.53       4.72  
Average BP US natural gas
    6.77       5.43       5.74  
realizationsc
                       
 
 
                       
$  per million British thermal units
 
Average Henry Hub gas pricee
    9.04       6.86       7.24  
 
 
                       
pence per therm
 
Average UK National Balancing Point gas price
    58.12       29.95       42.19  
 
 
aIncludes sales between businesses.
 
bIncludes profit after interest and tax of equity-accounted entities.
 
cRealizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.
 
dCrude oil and natural gas liquids.
eHenry Hub First of Month Index.
Total revenues are analysed in more detail below.
                         
 
                    $ million  
 
    2008     2007     2006  
 
Sales and other operating revenues
    86,170       65,740       67,950  
Earnings from equity-accounted entities (after interest and tax), interest and other revenues
    3,732       3,636       3,918  
 
 
    89,902       69,376       71,868  
 
Upstream activities
Exploration
The group explores for oil and natural gas under a wide range of licensing, joint venture and other contractual agreements. We may do this alone or, more frequently, with partners. BP acts as operator for many of these ventures.
          Our exploration and appraisal costs, excluding lease acquisitions, in 2008 were $2,290 million, compared with $1,892 million in 2007 and $1,765 million in 2006. These costs include exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs, which are charged to income as incurred. Approximately 51% of 2008 exploration and appraisal costs were directed towards appraisal activity. In 2008, we participated in 83 gross (34 net) exploration and appraisal wells in 11 countries. The principal areas of activity were Algeria, Angola, Azerbaijan, Canada, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea and onshore US.
           Total exploration expense in 2008 of $882 million (2007 $756 million and 2006 $1,045 million) included the write-off of expenses related to unsuccessful drilling activities in Azerbaijan ($105 million), Faeroes ($83 million), Egypt ($64 million), deepwater Gulf of Mexico ($38 million), and others ($33 million).
          In 2008, we obtained upstream rights in several new tracts, which include the following:
  In the Gulf of Mexico, we were awarded 125 blocks through the Outer Continental Shelf Lease Sales 205, 206 and 207.
 
  In the US Lower 48 states, we acquired 225,000 net acres of shale gas assets from Chesapeake Energy Corporation.
 
  In Canada, BP acquired three licences, covering a total of approximately 6,000 square kilometres in the Canadian Beaufort Sea.
 
  In India, BP acquired one block on the East Coast in the New Exploration Licensing Policy seventh round.
In 2008, we were involved in a number of discoveries. In most cases, reserves bookings from these fields will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling. Our most significant discoveries in 2008 included the following:
  In Angola, we made further discoveries in the ultra deepwater (greater than 1,500 metres) Block 31 (BP 26.7% and operator) with the Portia and Dione wells, bringing the total number of discoveries in Block 31 to 16.
 
  In Algeria, we discovered natural gas in the Tin Zaouatene-1 well in the Bourarhet Sud Blocks 230 and 231 (BP 49% and operator).
 
  In Egypt, we made a discovery with the Satis (BP 50% and operator) well.
 
  In the UK, we made two discoveries with the South West Foinaven (BP 72% and operator) and the Kinnoull (BP 77% and operator) wells.
 
  In the deepwater Gulf of Mexico, we made two discoveries with the Kodiak (BP 63.75% and operator) and Freedom (BP 25% and operator) wells.
Reserves and production
Compliance
IFRS does not provide specific guidance on reserves disclosures.
BP estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant guidance notes and letters issued by the SEC staff. As currently required, these proved reserve estimates are based on prices and costs as of the date the estimate is made.
          On 31 December 2008, the SEC published a revised set of rules for the estimation of reserves. These revised rules will be used for the 2009 year-end estimation of reserves, and have not been used in the determination of reserves for year-end 2008.
          By their nature, there is always some risk involved in the ultimate development and production of reserves, including, but not limited to, final regulatory approval, the installation of new or additional infrastructure as well as changes in oil and gas prices, changes in operating and development costs and the continued availability of additional development capital.


14


 

Performance review
 

All the group’s oil and gas reserves held in consolidated companies have been estimated by the group’s petroleum engineers. Of the equity-accounted volumes in 2008, 18% were based on estimates prepared by group petroleum engineers and 82% were based on estimates prepared by independent engineering consultants, although all of the group’s oil and gas reserves held in equity-accounted entities are reviewed by the group’s petroleum engineers before making the assessment of volumes to be booked by BP.
          Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where title to the hydrocarbons is not conferred, such as production-sharing agreements (PSAs). In a concession, the consortium of which we are a part is entitled to the reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. Sixteen per cent of our proved reserves are associated with PSAs. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam.
          We separately disclose our share of reserves held in equity-accounted entities (jointly controlled entities and associates), although we do not control these entities or the assets held by such entities.
Resource progression
BP manages its hydrocarbon resources in three major categories: prospect inventory, non-proved resources and proved reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the non-proved resource category. The resources move through various non-proved resource sub-categories as their technical and commercial maturity increases through appraisal activity.
          Resources in a field will only be categorized as proved reserves when all the criteria for attribution of proved status have been met, including an internally imposed requirement for project sanction or for sanction typically expected within six months and, for additional reserves in existing fields, the requirement that the reserves be included in the business plan and scheduled for development, typically within three years. Where, on occasion, the group decides to book reserves where development is scheduled to commence after three years, these reserves will be booked only where they satisfy the SEC’s criteria for attribution of proved status. Internal approval and final investment decision are what we refer to as project sanction.
          At the point of sanction, all booked reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s reserves depends on a later phase of activity, only that portion of reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking of PUD reserves to the start of production. Changes to reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.
Governance
BP’s centrally controlled process for proved reserves estimation approval forms part of a holistic and integrated system of internal control. It consists of the following elements:
  Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner.
  Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects.
 
  Internal Audit, whose role includes systematically examining the effectiveness of the group’s financial controls designed to assure the reliability of reporting and safeguarding of assets and examining the group’s compliance with laws, regulations and internal standards.
 
  Approval hierarchy, whereby proved reserves changes above certain threshold volumes require central authorization and periodic reviews. The frequency of review is determined according to field size and ensures that more than 80% of the BP reserves base undergoes central review every two years and more than 90% is reviewed every four years.
For the executive directors and senior management, no specific portion of compensation bonuses is directly related to oil and natural gas reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Exploration and Production segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures.
          BP’s variable pay programme for the other senior managers in the Exploration and Production segment is based on individual performance contracts. Individual performance contracts are based on agreed items from the business performance plan, one of which, if chosen, could relate to oil and gas reserves.
Reserve replacement
Total hydrocarbon proved reserves, on an oil equivalent basis and excluding equity-accounted entities, comprised 12,562mmboe at 31 December 2008, a decrease of 0.2% compared with 31 December 2007. Natural gas represents about 55% of these reserves. The decrease includes a net decrease from acquisitions and divestments of 169mmboe, largely comprising a number of assets in Venezuela and the US.
          Total hydrocarbon proved reserves, on an oil equivalent basis for equity-accounted entities alone, comprised 5,585mmboe at 31 December 2008, an increase of 6.8% compared with 31 December 2007. Natural gas represents about 16% of these proved reserves. The increase includes a net increase from acquisitions and divestments of 199mmboe, largely comprising a number of assets in Venezuela. The proved reserves replacement ratio (also known as the production replacement ratio) is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions and discoveries, and may be expressed as a replacement ratio excluding acquisitions and divestments or as a total replacement ratio including acquisitions and divestments.
          BP estimates proved reserves for reporting purposes in accordance with SEC rules and relevant guidance. As currently required, these proved reserve estimates are based on prices and costs as of the date the estimate is made. There was a rapid and substantial decline in oil prices in the fourth quarter of 2008 that was not matched by a similar reduction in operating costs by the end of the year. BP does not expect that these economic conditions will continue. However, our 2008 reserves are calculated on the basis of operating activities that would be undertaken were year-end prices and costs to persist.


15


 

Performance review
 

                         
 
                    %  
 
    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 equity- accounted 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-placea
    826       929       675  
Additions to proved developed reserves, for equity-accounted entities, including sales and purchases of reserves-in-placea
    751       473       936  
 
                       
%  
 
Proved developed reserves replacement ratio, excluding equity-accounted entities, including sales and purchases of reserves-in-place
    88       99       70  
Proved developed reserves replacement ratio, for equity-accounted entities, including sales and purchases of reserves-in-place
    153       101       195  
   
 
aThis includes some reserves that were previously classified as proved undeveloped.
In 2008, net additions to the group’s proved reserves (excluding sales and purchases of reserves-in-place and equity-accounted entities) amounted to 1,085mmboe, principally through improved recovery from, and extensions to, existing fields and discoveries of new fields. Of the reserves additions through improved recovery from, and extensions to, existing fields and discoveries of new fields, approximately half are associated with new projects and are proved undeveloped reserves additions. The remainder are in existing developments where they represent a mixture of proved developed and proved undeveloped reserves. The principal reserves additions were in the US (Arkoma, Thunder Horse, Wamsutter), Trinidad (Mango), Asia-Pacific (Tangguh), Angola (Plutão, Saturno, Vênus and Marte, and Angola LNG) and Azerbaijan (ACG).
Production
Our total hydrocarbon production during 2008 averaged 2,517 thousand barrels of oil equivalent per day (mboe/d) for subsidiaries and 1,321mboe/d for equity-accounted entities, a decrease of 1.2% and an increase of 4.0% respectively compared with 2007. For subsidiaries, 36% of our production was in the US and 12% in the UK. For equity-accounted entities, 70% of production was from TNK-BP.
          Total production is expected to be somewhat higher in 2009. The actual growth rate will depend on a number of factors, including our pace of capital spending, the efficiency of that spend (in turn depending on industry cost deflation), the oil price and its impact on PSAs as well as OPEC quota restrictions.
          The following tables show BP’s estimated net proved reserves as at 31 December 2008.
Estimated net proved reserves of liquids at 31 December 2008a b c
                         
 
                    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
   
Estimated net proved reserves of natural gas at 31 December 2008a b c
                         
 
                    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
   
Net proved reserves on an oil equivalent basis
                         
 
mmboe  
 
    Developed     Undeveloped     Total  
 
Group
    6,249       6,313       12,562  
Equity-accounted entities
    3,683       1,902       5,585  
   
 
aProved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations. We disclose our share of reserves held in joint ventures and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities.
 
bIn certain deepwater fields, such as fields in the Gulf of Mexico, BP has claimed proved reserves before production flow tests are conducted, in part because of the significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring and delineating reservoir properties without the need for flow tests. The general method of reserves assessment to determine reasonable certainty of commercial recovery which BP employs relies on the integration of three types of data: (1) well data used to assess the local characteristics and conditions of reservoirs and fluids; (2) field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control; and (3) data from relevant analogous fields. Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. BP considers the integration of this data in certain cases to be superior to a flow test in providing a better understanding of the overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be determined over a greater volume than the localized volume of investigation associated with a short-term flow test. Historically, proved reserves recorded using these methods have been validated by actual production levels. As at the end of 2008, BP had proved reserves in 20 fields in the deepwater Gulf of Mexico that had been initially booked prior to production flow testing. Of these fields, 18 are in production and two, Dorado and Great White, are expected to begin production in 2009. Six other fields are in the early stages of appraisal and development.
 
cThe 2008 year-end marker prices used were Brent $36.55/bbl (2007 $96.02/bbl and 2006 $58.93/bbl) and Henry Hub $5.63/mmBtu (2007 $7.10/mmBtu and 2006 $5.52/mmBtu).
 
dProved reserves in the Prudhoe Bay field in Alaska include an estimated 54 million barrels on which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust.
 
eIncludes 21 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
fIncludes 216 million barrels of crude oil in respect of the 6.80% minority interest in TNK-BP.
 
gIncludes 3,108 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
hIncludes 131 billion cubic feet of natural gas in respect of the 5.92% minority interest in TNK-BP.


16


 

Performance review
 
The following tables show BP’s production by major field for 2008, 2007 and 2006.
Liquids
                                     
     
        %     thousand barrels per day  
     
                BP net share of production a  
     
    Field or Area   Interest     2008     2007     2006  
     
Alaska
  Prudhoe Bayb     26.4       72       74       71  
 
  Kuparuk   Various       48       52       57  
 
  Northstarb     98.6       22       28       38  
 
  Milne Pointb   Various       27       28       31  
 
  Other   Various       28       27       27  
     
Total Alaska
                197       209       224  
     
Lower 48 onshorec
  Various   Various       97       108       125  
     
Gulf of Mexico deepwaterc
  Na Kikab   Various       29       32       41  
 
  Thunder Horseb     75.0       24              
 
  Horn Mountainb     100.0       18       18       23  
 
  Kingb     100.0       23       22       28  
 
  Mars     28.5       28       30       19  
 
  Mad Dogb     60.5       31       25       17  
 
  Atlantisb     56.0       42       2        
 
  Other   Various       49       67       70  
     
Total Gulf of Mexico
                244       196       198  
     
Total US
                538       513       547  
     
UK offshorec
  ETAPd   Various       27       32       49  
 
  Foinavenb   Various       26       37       37  
 
  Magnusb     85.0       18       16       30  
 
  Schiehallion/Loyalb   Various       18       20       26  
 
  Clairb     28.6       13       9       7  
 
  Hardingb     70.0       11       14       17  
 
  Andrewb     62.8       7       8       7  
 
  Other   Various       37       50       62  
     
Total UK offshore
                157       186       235  
     
Onshore
  Wytch Farmb     67.8       16       15       18  
     
Total UK
                173       201       253  
     
Netherlandsc
  Various   Various                   1  
Norway
  Valhallb     28.1       14       17       21  
 
  Draugen     18.4       13       14       15  
 
  Ulab     80.0       8       12       14  
 
  Other   Various       8       8       10  
     
Total Rest of Europe
                43       51       61  
     
Angola
  Dalia     16.7       34       31        
 
  Girassol     16.7       6       14       17  
 
  Greater Plutoniob     50.0       69       12        
 
  Kizomba A     26.7       15       36       54  
 
  Kizomba B     26.7       16       35       58  
 
  Other   Various       62       12       4  
Australia
  Various     15.8       29       34       34  
Azerbaijan
  Azeri-Chirag-Gunashlib     34.1       97       200       145  
 
  Shah Denizb     25.5       8       5        
Canadac
  Variousb   Various       9       8       8  
Colombia
  Variousb   Various       24       28       34  
Egypt
  Various   Various       57       43       42  
Trinidad & Tobago
  Variousb     100.0       37       30       40  
Venezuelac
  Various   Various       4       16       26  
Otherc
  Various   Various       42       35       28  
     
Total Rest of World
                509       539       490  
     
Total groupe
                1,263       1,304       1,351  
     
Equity-accounted entities (BP share)
                                   
Abu Dhabif
  Various   Various       210       192       163  
Argentina – Pan American Energy
  Various   Various       70       69       69  
Russia – TNK-BPc
  Various   Various       826       832       876  
Otherc
  Various   Various       32       17       16  
     
Total equity-accounted entities
                1,138       1,110       1,124  
     
 
aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
 
bBP-operated.
 
cIn 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position and TNK-BP disposed of some non-core interests. In 2007, BP divested its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. In 2006, BP divested its producing properties on the Outer Continental Shelf of the Gulf of Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in the Boqueron, Desarollo Zulia Occidental (DZO) and Jusepin projects in Venezuela were reduced following a decision by the Venezuelan government. TNK-BP disposed of its non-core interests in the Udmurtneft assets.
 
dVolumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell.
 
eIncludes 19 net mboe/d of NGLs from processing plants in which BP has an interest (2007 54mboe/d and 2006 55mboe/d).
 
fThe BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. During the second quarter of 2007, we updated our reporting policy in Abu Dhabi to be consistent with general industry practice and as a result have started reporting production and reserves there gross of production taxes.

17


 

Performance review
 
Natural gas
                                     
     
        %     million cubic feet per day  
     
                BP net share of productiona  
     
    Field or Area   Interest     2008     2007     2006  
     
Lower 48 onshoreb
  San Juanc   Various       682       694       765  
 
  Arkomac   Various       240       204       225  
 
  Hugotonc   Various       91       123       137  
 
  Tuscaloosac   Various       65       78       86  
 
  Wamsutterc     66.6       136       120       113  
 
  Jonahc   Various       221       173       133  
 
  Other   Various       451       458       461  
     
Total Lower 48 onshore
                1,886       1,850       1,920  
     
Gulf of Mexico deepwaterb
  Na Kikac     51.9       62       50       97  
 
  Marlinc     78.2       46       13       16  
 
  Other   Various       122       205       210  
Gulf of Mexico Shelfb
  Other   Various             1       66  
     
Total Gulf of Mexico
                230       269       389  
     
Alaska
  Various   Various       41       55       67  
     
Total US
                2,157       2,174       2,376  
     
UK offshoreb
  Braes   Various       75       69       101  
 
  Brucec     37.0       65       72       107  
 
  West Solec     100.0       51       55       56  
 
  Marnockc     62.1       24       25       42  
 
  Britannia     9.0       30       37       42  
 
  Shearwater     27.5       17       19       31  
 
  Armada     18.2       16       16       28  
 
  Other   Various       481       475       529  
     
Total UK
                759       768       936  
     
Netherlandsb
  P/18-2     48.7                   23  
 
  Other   Various             3       33  
Norway
  Various   Various       23       26       35  
     
Total Rest of Europe
                23       29       91  
     
Australia
  Various     15.8       380       376       364  
Canadab
  Variousc   Various       245       255       282  
China
  Yachengc     34.3       91       85       102  
Egypt
  Ha'pyc     50.0       94       108       99  
 
  Other   Various       278       206       172  
Indonesia
  Sanga-Sanga (direct)c     26.3       69       75       84  
 
  Otherc     46.0       98       81       80  
Sharjah
  Sajaac     40.0       65       83       111  
 
  Other     40.0       8       9       9  
Azerbaijan
  Shah Denizc     25.5       143       73        
Trinidad & Tobago
  Kapokc     100.0       619       984       946  
 
  Mahoganyc     100.0       323       454       321  
 
  Amherstiac     100.0       288       155       176  
 
  Parangc     100.0                   120  
 
  Immortellec     100.0       136       153       219  
 
  Cassiac     100.0       5       25       30  
 
  Otherc     100.0       1,075       663       453  
Otherb
  Various   Various       421       466       441  
     
Total Rest of World
                4,338       4,251       4,009  
     
Total groupd
                7,277       7,222       7,412  
     
Equity-accounted entities (BP share)
Argentina – Pan American Energy
  Various   Various       385       379       362  
Russia – TNK-BPb
  Various   Various       564       451       544  
Otherb
  Various   Various       108       91       99  
     
Total equity-accounted entitiesd
                1,057       921       1,005  
     
 
aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently.
 
bIn 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position. In 2007, BP divested its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. In 2006, BP divested its producing properties on the Outer Continental Shelf of the Gulf of Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in the Boqueron, Desarollo Zulia Occidental (DZO) and Jusepin projects in Venezuela were reduced following a decision by the Venezuelan government. TNK-BP disposed of its non-core interests in the Udmurtneft assets.
 
cBP-operated.
 
dNatural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.

18


 

Performance review
 

United States
2008 liquids production at 538mb/d increased 4.9% from 2007, while natural gas production at 2,157mmcf/d decreased 0.8% compared with 2007.
          Crude oil production increased by 32mb/d, an increase of 8% from 2007, primarily driven by major projects in the Gulf of Mexico, partly offset by natural reservoir decline and the impact of hurricanes in the third quarter.
          The NGLs component of liquids production decreased by 7mb/d, driven mainly by plant turnarounds and operational issues resulting from the hurricanes in the third quarter. BP operates or has interests in NGL extraction plants with a processing capacity of 6.4bcf/d. These facilities are located in major production areas across North America, including Alberta, Canada, the US Rockies, the San Juan basin and the Gulf of Mexico. We also own or have an interest in fractionation plants (that separate the NGL into its component products) in Canada and the US.
          Gas production was 17mmcf/d lower because of natural reservoir decline and the impact of hurricanes, which was partly offset by production from shale acquisitions.
          Development expenditure in the US (excluding midstream) during 2008 was $4,914 million, compared with $3,861 million in 2007 and $3,579 million in 2006. The year-on-year increase is the result of various development projects in progress.
          Our activities within the US take place in three main areas: deepwater Gulf of Mexico, the Lower 48 states and Alaska. Significant events during 2008 within each of these are indicated below.
Deepwater Gulf of Mexico
Deepwater Gulf of Mexico is our largest area of growth in the US. In 2008, our deepwater Gulf of Mexico liquids production was 244mb/d and gas production was 40mboe/d
          Significant events were:
  On 14 June 2008, first oil was achieved at Thunder Horse (BP 75% and operator). Thunder Horse is the world’s largest semi-submersible production facility, and is located 150 miles south-east of New Orleans. It is designed to process 250,000 barrels of oil per day and 200 million cubic feet per day of natural gas. In 2008 four wells started up with production of around 200,000boe/d (gross) at the year-end, signalling the completion of commissioning. Production started up in the Thunder Horse North field in February 2009.
 
  On 3 April 2008, BP announced an oil discovery at its Kodiak prospect (BP 63.75% and operator). The well, located in Mississippi Canyon block 771, approximately 60 miles south-east of the Louisiana Coast, is in about 1,500 metres of water.
 
  In September 2008, Hurricanes Gustav and Ike resulted in most of the Gulf of Mexico’s oil production being shut down. There was minimal damage to most of BP’s platforms other than to the drilling derrick on the Mad Dog platform, located approximately 190 miles south of New Orleans. The production impact of both hurricanes was a reduction equivalent to approximately 24mboe/d for the year.
 
  In October 2008, BP announced an oil discovery with its Freedom well (BP 25% and operator). The well, located in Mississippi Canyon Block 948, approximately 70 miles south-east of the Louisiana Coast, is in about 1,860 metres of water. It is believed that Freedom straddles Mississippi Canyon Block 948 and Mississippi Canyon Block 992. BP owns a 67.75% interest in Block 992.
Lower 48 states
In the Lower 48 states (onshore), our 2008 natural gas production was 325mboe/d, which was up 2% compared with 2007. Liquids production was 97mb/d, down 10% compared with 2007. Total 2008 production, excluding the impacts from the 2008 hurricanes, was broadly flat compared with 2007.
          In 2008, we drilled approximately 540 wells as operator and continued to maintain a stable programme of drilling activity throughout the year.
          Production is derived from two main areas:
  In the western basins (Colorado, New Mexico and Wyoming), our assets produced 224mboe/d in 2008.
 
  In the Gulf Coast and mid-continental basins (Kansas, Louisiana, Oklahoma and Texas), our assets produced 198mboe/d in 2008.
          Significant events were:
  In August 2008, BP acquired all Chesapeake Energy Corporation’s interest in approximately 90,000 net acres of leasehold and producing natural gas properties in the Arkoma basin Woodford Shale area for $1.75 billion. BP took over production operations on 1 November and retained three drilling rigs as part of the deal.
 
  In September 2008, BP acquired a 25% non-operated interest in Chesapeake’s Fayetteville Shale assets for $1.9 billion comprising $1.1 billion in cash at closing and an $800 million commitment to fund Chesapeake’s 75% share of drilling and completion costs. $183 million of this commitment was met in 2008, with the balance expected to be paid by the end of 2009. The assets include approximately 135,000 net acres of leasehold.
 
  In September 2008, in anticipation of Hurricane Gustav, operations and activity were shut down in the Pascagoula NGL plant, South Louisiana (Tuscaloosa field) and East Texas Exploration and Production operations. Also in September, Hurricane Ike resulted in every field location across South Louisiana, East Texas and the Permian Basin having production shut in. Four NGL plants, Pascagoula, Block 31, Crane and Midland, were shut down while other plants suffered production impacts due to widespread outages and disruptions in the midstream infrastructure. The impact of both hurricanes on production was a reduction equivalent to approximately 2mboe/d for the year.
 
  In October 2008, BP sanctioned the Wamsutter Full Field Development plan (Phase ll). This builds on the operational and technological results of extensive field trials conducted during the past three years.
Alaska
In Alaska, BP net oil production in 2008 was 197mb/d, a decrease of 6% from 2007, due to normal decline in the large mature fields, partially offset by continued strong reservoir and well performance.
          BP operates 13 North Slope oil fields (including Prudhoe Bay, Northstar and Milne Point) and four North Slope pipelines and owns a significant interest in six other producing fields
          In addition, two key aspects of BP’s business strategy in Alaska are commercializing the large undeveloped natural gas resource within our 26.4% interest in Prudhoe Bay and unlocking the large undeveloped heavy oil resources within existing North Slope fields through the application of advanced technology.
          Significant events in 2008 were:
  In July 2008, BP announced the commencement of development activities for the Liberty oilfield, which is located on federal leases about six miles offshore in the Beaufort Sea, and east of the Prudhoe Bay oilfield. The planned development includes up to six ultra-extended reach wells, including four producers and two injectors. These wells are expected to be the longest horizontal wells ever drilled in the world, extending two miles deep and as far as eight miles horizontally, guided by 3-D seismic imagery. A specialized rig for drilling in the Arctic is being built for the project. Drilling is expected to start in 2010, from an existing satellite pad that is being expanded for


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    the project at the BP-operated Endicott oilfield. BP drilled the Liberty discovery well in 1997, and is the operator and sole owner of the field.
 
  In August 2008, BP successfully tested Cold Heavy Oil Production with Sand (CHOPS) technology for the first time in Alaska, initiating a four-well production test programme during the period from August 2008 until the end of 2009. This first test at Milne Point S Pad brought oil and sand to the surface, where it was processed using temporary field facilities, combined with other light oil production, and shipped down the Trans-Alaska Pipeline System (TAPS). The CHOPS well tests are part of a multi-year programme to determine the technical and commercial feasibility of a large scale heavy oil development project on the North Slope using existing cold and thermal technologies.
 
  During 2008, all four of the Prudhoe Bay Oil Transit Line segments that were targeted for replacement in response to the oil spills in the Prudhoe Bay field in March and August 2006 were completed and placed in service.
United Kingdom
We are the largest producer of oil, the second largest producer of gas and the largest overall producer of hydrocarbons in the UK. In 2008, total liquids production was 173mb/d, a 14% decrease on 2007, and gas production was 759mmcf/d, a 1% decrease on 2007. This decrease in production was driven by natural decline. Key aspects of our activities in the North Sea include a focus on in-field drilling and selected new field developments. Our development expenditure (excluding midstream) in the UK was $907 million in 2008, compared with $804 million in 2007 and $794 million in 2006. BP operates one NGL plant in the UK.
          Significant events in 2008 were:
  In February 2008, BP and its partner, Marathon Petroleum West of Shetlands Ltd, announced a new oil discovery in UK Continental Shelf Block 204/23 (BP 72%), following drilling on the South West Foinaven prospect. BP, together with its partner, is evaluating the discovery and the potential for a two-well subsea development, tied back to the Foinaven Floating Production Storage and Offloading vessel (FPSO).
 
  In May 2008, BP and its co-venturers made an oil discovery in North Sea Block 16/23s (BP 77.07%), named Kinnoull. The Kinnoull discovery and potential development options, including a subsea development tied back to BP’s Andrew field, are being evaluated.
 
  During the third quarter, the first phase of offshore removal activity for the North West Hutton platform decommissioning programme was completed. This is BP’s biggest decommissioning project so far in the North Sea and has seen the removal of 22 separate topsides modules, which were then taken away by barges to the Able UK yard on Teesside for recycling and disposal. It is estimated that around 97% of the material recovered will be recycled and/or reused.
 
  In December 2008, BP and BG Group agreed to exchange a package of North Sea assets. This is expected to strengthen BP’s position as a major operator in the Southern North Sea and to facilitate development activity and investment in the UK Continental Shelf. BP agreed to acquire BG’s 24.2% interest in the BP-operated Amethyst field and all its interests in the Easington Catchment Area (ECA) fields, including a 73.3% interest in the Mercury field, a 79% interest in the Neptune field, a 65% interest in the Minerva, Apollo and Artemis fields and BG’s 30.8% interest in the BP-operated Whittle and Wollaston fields. BG Group agreed to acquire BP’s interest and operatorship in the Everest (BP 21.1%) and Lomond (BP 22.2%) fields, BP’s 18.2% interest in the BG-operated Armada field and 32% of the Chevron-operated Erskine field (BP will retain 18% equity in Erskine). The deal is subject to government, regulatory and partner approvals and completion is expected in the second quarter of 2009.
Rest of Europe
Our activities in the Rest of Europe are now centred on Norway. Until February 2007, we also held exploration and production and gas infrastructure interests in the Netherlands. Development expenditure (excluding midstream) in the Rest of Europe was $695 million, compared with $443 million in 2007 and $214 million in 2006. In 2008, our total production in Norway was 47mboe/d, a 16% decrease on 2007. This decrease in production was driven by natural decline. In Norway, progress continued as planned on the Skarv and Valhall Redevelopment projects.
Rest of World
Development expenditure in Rest of World (excluding midstream) was $5,251 million in 2008, compared with $5,045 million in 2007 and $4,522 million in 2006.
Rest of Americas
Canada
  In Canada, our natural gas and liquids production was 51mboe/d in 2008, a decrease of 1% compared with 2007. The year-on-year decrease in production is mainly due to natural field decline.
 
  On 31 March 2008, BP and Husky Energy Inc. (Husky) completed a deal to create an integrated North American oil sands business by means of two separate 50:50 joint ventures, BP-Husky Refinery LLC, operated by BP, and the Sunrise Oil Sands Partnership (SOSP), operated by Husky. BP’s capital expenditure in respect of the creation of SOSP amounted to $2.8 billion.
 
  In June 2008, BP successfully acquired three of five exploration licences on offer in the Canadian section of the Beaufort Sea through a Call for Bids process issued by The Department of Indian and Northern Affairs of Canada. The leases awarded to BP cover about 611,000 hectares of the Beaufort seabed, north of Tuktoyaktuk, Northwest Territories. These are in addition to the 15 significant discovery licences that BP currently holds in the Beaufort Sea, and two exploration licences currently in moratorium. The term for exploration licences issued from this Call for Bids is nine years consisting of two consecutive periods. There is a $300 million work obligation associated with acquiring these exploration licences.
Trinidad
  In Trinidad, natural gas production volumes increased from 420mboe/d in 2007 to 422mboe/d in 2008. The increase was a result of improved operating efficiency on the Atlantic LNG Trains combined with increased demand from the domestic market and full ramp-up of two new fields, Mango and Cashima. Liquids production increased by 7mb/d (23%) to 37mb/d in 2008 from 30mb/d in 2007 as a result of an increase in NGLs associated with higher throughput for the Trains, increased crude and condensate from the two new fields and liquid optimization activities.
 
  In December 2008, a new oil export pipeline was commissioned to transport liquids from offshore fields to onshore delivery points. BP owns 100% of the capacity of the pipeline.
 
  Progress on Savonette, BP’s next field development in Trinidad, continued throughout the year and first gas is expected to be delivered in 2009.
 
  In 2008, the Day Away from Work Case injury frequency (per 200,000 work hours) has been reduced from 0.12 in 2003 to zero in 2008 and the recordable injury frequency has more than halved in the same period. This has come about through the development and implementation of a comprehensive multi-year safety plan, focused on coaching safety leaders, workforce communication, standard implementation and continuous learning.


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Performance review
 

Venezuela
  In Venezuela, despite the transition since 2006 of BP’s interests to incorporated joint venture (IJV) entities with the state oil company Petróleos de Venezuela, S.A. (PDVSA), and OPEC quotas, 2008 liquids production increased by 3mb/d compared with 2007.
 
  In the second quarter of 2008, BP concluded the migration of the Cerro Negro operations to an IJV with PDVSA while retaining the same equity interest.
Colombia
  In Colombia, BP’s net production averaged 38mboe/d. The reduction of 8mboe/d compared with 2007 is mainly due to natural field decline and lower gas transfers from Recetor (BP 50%) to Santiago de las Atalayas (BP 31%). The main part of the production comes from the Cusiana, Cupiagua and Cupiagua South fields, with increasing new production from the Cupiagua extension into the Recetor Association Contract and the Floreña and Pauto fields in the Piedemonte Association Contract.
 
  On 20 June 2008, the National Hydrocarbon Agency gave its official approval for equalization of RC4 and RC5 Caribbean offshore blocks with partners Ecopetrol and Petrobras, with the main objective of simplifying partner relations and agreements. New equity interests resulting from this approval are BP 40.6%, Ecopetrol 32% and Petrobras 27.4%. Seismic operations for these two blocks were completed successfully. Processing and interpretation of the data to determine potential prospects for offshore field developments and drilling operations is under way and is expected to be completed in 2009.
Argentina, Bolivia and Chile
  In Argentina, Bolivia and Chile, activity is conducted through Pan American Energy (PAE), a joint venture company in which BP holds a 60% interest, and which is accounted for by the equity method. In 2008, total PAE gross production of 250mboe/d represented an increase of 3% compared with 2007. Most of this production comes from the Cerro Dragón field in the provinces of Chubut and Santa Cruz. The field is now producing at its highest level since inception of the licence area in 1958. PAE also has other assets producing gas and liquids in the Argentine provinces of Salta, Neuguén and Tierra del Fuego, and in Bolivia, as well as interests in exploration areas, pipelines, electricity generation plants and other midstream infrastructure assets, primarily in Argentina.
 
  In 2007 and early 2008, PAE was granted extensions of the two principal Cerro Dragón licence areas by the provinces of Chubut and Santa Cruz in exchange for material long-term investment commitments in exploration and production, and for long-term commitments to local community and supplier development. The licence expiry dates have been extended from 2017 to 2027, with further extension potential to 2047.
 
  In May 2008, following its decree of 2006 requiring all private owners of shares in Bolivian oil and gas companies to transfer back a majority shareholding to the Bolivian national oil company Yacimientos Petrolíferos Fiscales Bolivianos (YPFB), the Bolivian government issued a second decree requiring this transfer to be made with immediate effect. PAE, as the majority shareholder of Empresa Petrolera Chaco S.A. (Chaco), a company created in the 1990s, was affected by these decrees. PAE was required to sell approximately 1% of the share capital of Chaco to YPFB, such that YPFB would own 50% plus one share of the total. From May 2008 and into January 2009, PAE was in discussions with the government regarding the decrees and options for implementation. However, on 23 January 2009, the president of Bolivia issued a decree nationalizing PAE’s shareholding in Chaco. PAE is currently evaluating all options to preserve the value of its shareholding.
  On 26 November 2008, the Argentine government issued a decree creating a new regime called Petróleo PLUS. This regime is aimed at increasing oil production and reserves. The detailed rules of Petróleo PLUS were issued on 4 December 2008. On 15 December 2008, PAE made its first applications under Petróleo PLUS for fiscal credit certificates with the Secretary of Energy.
Africa
Algeria
  BP, through its joint operatorships of the In Salah Gas (33.15%) and In Amenas (12.5%) projects, supplied 33mboe/d (BP net) to markets in Algeria and southern Europe during 2008. This is a decrease of 15% from 39mboe/d in 2007 as a result of lower gross volumes at In Salah due to planned turnaround maintenance and the impact of lower entitlement in our PSAs driven by higher prices, partly offset by improved operating efficiency at In Amenas. Further, BP, through its joint operatorship of the Rhourde El Baguel field, received 4.4mboe/d (BP net) of oil in 2008.
 
  Sonatrach and BP announced an exploration success with the Tin Zaouatene-1 (TZN-1) discovery in the Bourarhet Sud Blocks 230 and 231. On 24 September 2008, BP moved into the second prospecting period, which lasts for a further two years.
Angola
  In Angola, BP net production in 2008 was 202mboe/d, an increase of 45% from 2007 due to the start-up of the Mondo, Saxi and Batuque (Kizomba C, BP 26.67%) fields, and the ramp-up of the Greater Plutonio field (BP 50% and operator), more than offsetting the impact of lower entitlement in our PSAs driven by higher prices in existing fields. We expect to have invested over $15 billion in our Angolan business by 2010.
 
  In January 2008, the Kizomba C project (BP 26.67%) came onstream with the start-up of the Mondo field, followed by first production from the Saxi and Batuque fields in July 2008. The Kizomba C development is located approximately 140 kilometres off the coast of Angola in water depths of nearly 800 metres.
 
  In June 2008, the Plutão, Saturno, Vênus and Marte (PSVM) project was authorized by Sonangol. The programme is expected to comprise four fields that lie in the north east sector of Block 31 (BP 26.67% and operator), in a water depth of approximately 2,000 metres, some 400 kilometres north west of Luanda. Contracts have been awarded and construction work started during 2008.
 
  During the third quarter of 2008, production was shut down at the Greater Plutonio FPSO located in deepwater Block 18 (BP 50% and operator), offshore Angola, due to operational issues. Production was restarted on 12 October 2008. The adverse impact on full-year production was 14mb/d.
 
  In the ultra deepwater Block 31 (BP 26.67% and operator), there was further exploration success with the Portia and Dione wells, bringing the total successes for Block 31 to 16. The Portia well is located in a water depth of approximately 2,000 metres, some 386 kilometres north-west of Luanda. The Dione well is located in a water depth of approximately 1,700 metres, some 390 kilometres north-west of Luanda.


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Performance review
 

Egypt
  In Egypt, BP net production was 121mboe/d, an increase of 25% from 97mboe/d in 2007. This increase was mainly due to the start-up of two new fields, Saqqara and Taurt, and the full-year impact from Denise, which started up at the end of 2007.
 
  In January 2008, BP completed drilling a successful exploration well, Satis-1, in the North El Burg offshore concession (BP 50% and operator). The Satis-1 well was drilled in approximately 90 metres of water, some 50 kilometres offshore, and is in the Oligocene formation.
 
  In January 2008, an oil discovery was announced in the North Shadwan (BP 50% and operator) concession located in the southern part of the Gulf of Suez. The NS394-1A exploration well was drilled in shallow water seven kilometres from the Hilal field. This discovery is the first new oil discovery in the south-eastern area of the Gulf of Suez in more than 10 years and is also the first discovery drilled by BP which has been facilitated by modern, high-quality, ocean-bottom cable (OBC) seismic data.
 
  On 15 May 2008, oil production from the Saqqara field (BP 100%) started. The Saqqara field, operated by the Gulf of Suez Petroleum Company (GUPCO), a joint venture operating company between BP and the Eygptian General Petroleum Corporation (EGPC), is located 13 kilometres offshore in the central Gulf of Suez. Natural gas production commenced on 26 July 2008. The Saqqara development includes a jacket and unmanned topsides, three wells, and a 13-kilometre pipeline to a new dedicated onshore separation and gas processing plant at Ras Shukeir on the Gulf of Suez. Local contractors were used for design, onshore construction and offshore fabrication work.
 
  In July 2008, natural gas production began from the Taurt field (BP 50%). The Taurt field is located between the Ras El Bar Concession (BP 50% and operator) and the Temsah Concession (BP 50%), 70 kilometres offshore to the north-east of Port Said, East Nile Delta. Gross Taurt production ramped up to 230mmcf/d in August. The Taurt development includes a Subsea Production System (SPS), two subsea wells, and a 70-kilometre pipeline and control umbilical back to upgraded facilities at the existing West Harbor processing plant. Taurt is BP’s first subsea development in Egypt and also the first of a planned programme of future subsea developments. Local contractors were used for onshore design/modifications and subsea structure construction.
Libya
  In Libya, BP and its partner, the Libyan Investment Corporation (LIC) commenced seismic operations on the acreage covered under the exploration and production-sharing agreement ratified in December 2007. In September 2008, the offshore seismic acquisition survey commenced in the Mediterranean waters of Libya’s Gulf of Sirt. At the end of 2008, the onshore seismic operations commenced in the northern Ghadames block.
Asia Pacific
Indonesia
  BP produces crude oil in, and supplies natural gas to, the island of Java through its holding in the Offshore Northwest Java PSA (BP 46%). In 2008, BP net production was 22mboe/d, an increase of 18% from 18.6mboe/d in 2007 as a result of improved operating efficiencies and increased gas demand in Java.
 
  BP is operator of the Tangguh LNG project (BP 37.2%), which includes offshore platforms, pipelines and an LNG plant with two production trains with a total capacity of 7.6 million tonnes per annum (mtpa). In May 2008, gas was introduced from one of the two offshore platforms into the Onshore Receiving Facility (ORF). First commercial delivery of LNG is expected in the second quarter of 2009.
  BP has a 50% interest in Virginia Indonesia Company LLC (Vico), the operator of the Sanga-Sanga PSA (BP 38%) supplying feedgas to Indonesia’s largest LNG export facility, the Bontang LNG plant in Kalimantan.
Vietnam
  BP participates in one of the country’s largest foreign investment projects, the Nam Con Son gas project. This is an integrated resource and infrastructure project, which includes offshore gas production, a pipeline transportation system and a power plant. At midnight on 31 December 2007, the operation of the Nam Con Son Pipeline (BP 32.67%) transferred from BP to PetroVietnam (PVN). In September 2008, capacity of the Nam Con Son Pipeline was increased by 30% to allow for additional current and future expected volumes.
 
  In 2008, BP net natural gas production was 61mmcf/d, a decrease of 26% from 82mmcf/d in 2007, primarily due to lower PSA entitlements. Gas sales from Block 6.1 (BP 35% and operator) are made under a long-term agreement for electricity generation at the Phu My 3 power plant (BP 33.3%).
 
  BP has determined that its licences in Blocks 5.2 (BP 55.9% and operator) and 5.3 (BP 75% and operator) do not fit within its current portfolio and has decided to withdraw from them. BP is currently in active discussions with PVN, the Vietnamese government and joint venture partners to progress this withdrawal.
China
  In 2008, natural gas production was 91mmcf/d BP net, an increase of 7% compared with 2007. This increase was mainly due to increased gas demand. A new development project was sanctioned in late 2008 to help meet the expected increase in demand in 2010 and beyond.
 
  The Yacheng offshore gas field (BP 34.3%) supplies Castle Peak Power Company with feedgas for up to 70% of Hong Kong’s gas-fired electricity generation. Additional gas is also sold to the Fuel & Chemical Company of Hainan.
 
  In March 2007, the National People’s Congress reduced the rate of corporation tax from 33% to 25% with effect from 1 January 2008.
Australia
  BP is one of seven partners in the North West Shelf (NWS) venture. Six partners (including BP) hold an equal 16.67% interest in the infrastructure and oil reserves and an equal 15.78% interest in the gas and condensate reserves, with a seventh partner owning the remaining 5.32% of gas and condensate reserves. The NWS venture is currently the principal supplier to the domestic market in Western Australia and one of the largest LNG export projects in Asia with five LNG Trains in operation.
 
  In 2008, BP net gas production was 380mmcf/d, an increase of 1% from 2007 primarily due to increased domestic gas demand in Western Australia and the startup of NWS Train 5 and the Angel platform in the third quarter. BP net liquids production was 29mb/d, a decrease of 15% from 2007 due to natural field decline.
 
  In March 2008, the North Rankin 2 (NR2) project was sanctioned. This links a second platform via a 100-metre bridge to the existing North Rankin A (NRA) platform. On completion, NRA and NR2 platforms are expected to be operated as a single integrated facility and to recover low pressure gas from the North Rankin and Perseus gas fields.
 
  In September 2008, a fifth LNG train was successfully completed and commenced production at the Karratha gas plant. Train 5 increases NWS total annual production capacity from 11.9 to 16.3 million tonnes.
 
  The Angel platform (BP 16.67%) was successfully commissioned and started producing gas during October 2008. Angel has a gross production capacity of 800 million standard cubic feet of raw gas and up to 50,000 barrels of condensate per day.


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Performance review
 

Russia
TNK-BP
  TNK-BP, a joint venture between BP (50%) and Alfa Group and Access-Renova (AAR) (50%), is an integrated oil company operating in Russia and the Ukraine. The TNK-BP group’s major assets are held in OAO TNK-BP Holding. Other assets include the BP-branded retail sites in Moscow and the Moscow region and interests in OAO Rusia Petroleum and the OAO Slavneft group. The workforce comprises more than 60,000 people.
 
  BP’s investment in TNK-BP is held by the Exploration and Production segment and the results of TNK-BP are accounted for under the equity method in this segment.
 
  TNK-BP has proved reserves of 7.1 billion barrels of oil equivalent (including its 49.9% equity share of Slavneft), of which 5 billion are developed. In 2008, TNK-BP’s average liquids production was 1.65mmb/d, a decrease of just under 1% compared with 2007. The production base is largely centred in West Siberia (Samotlor, Nyagan and Megion), which contributes about 1.2mmboe/d, together with Volga Urals (Orenburg) contributing some 0.4mmboe/d. About 40% of total oil production is currently exported as crude oil and 20% as refined product.
 
  Downstream, TNK-BP has interests in six refineries in Russia and the Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl refinery), with throughput of approximately 34 million tonnes per year. During 2008, TNK-BP purchased additional retail and other downstream assets in Russia and the Ukraine from a number of small companies. TNK-BP supplies approximately 1,400 branded filling stations in Russia and the Ukraine and, with the additional sites, is expected to have more than 20% market share of the Moscow retail market.
 
  On 9 January 2009, BP reached final agreement on amendments to the shareholder agreement with its Russian partners in TNK-BP. The revised agreement is aimed at improving the balance of interests between the company’s 50:50 owners, BP and Alfa Access-Renova (AAR), and focusing the business more explicitly on value growth.
 
  The former evenly-balanced main board structure has been replaced by one with four representatives each from BP and AAR, plus three independent directors. Unanimous board support is required for certain matters including substantial acquisitions, divestments and contracts, and projects outside the business plan, together with approval of key changes to the TNK-BP group’s financial framework and of related party transactions. A number of other matters will be decided by approval of a majority of the board, so that the independent directors will have the ability to decide in the event of disagreement between the shareholder representatives on the board. BP will continue to nominate the chief executive, subject to main board approval, and AAR will continue to appoint the chairman. The three independent directors appointed to the restructured main board are Gerhard Schroeder, former chancellor of the Federal Republic of Germany, James Leng, former chairman of Corus Steel and Alexander Shokhin, president of the Russian Union of Industrialists and Entrepreneurs. In addition, significant TNK-BP subsidiaries will have directors appointed by BP and AAR on their boards. Our investment in TNK-BP will be reclassified from a jointly controlled entity to an associate with effect from 9 January 2009.
 
  The parties have confirmed their agreement to a potential future sale of up to 20% of a subsidiary of TNK-BP through an initial public offering (IPO) at an appropriate future point, subject to certain conditions and the consent of the Russian authorities.
 
  In 2007, BP and TNK-BP signed heads of terms to create strategic business alliances with OAO Gazprom. Under the terms of this agreement, TNK-BP agreed to sell to Gazprom its stake in OAO Rusia Petroleum, the company that owns the licence for the Kovykta gas condensate field in East Siberia and its interest in East Siberia Gas Company. Discussions to conclude this disposal continue.
Sakhalin
  BP and its Russian partner Rosneft agreed two Shareholder and Operating Agreements (SOAs) on 28 April 2008, recognizing BP as a 49% equity interest holder with Rosneft holding the remaining 51% interest in the two newly formed joint venture companies, Vostok Shmidt Neftegaz and Zapad Shmidt Neftegaz. BP also continues to hold a 49% equity interest in its third joint venture company at Sakhalin, Elvary Neftegaz, with Rosneft holding the remaining 51%. During the year, each of the three joint ventures held Geological and Geophysical Studies licences with the Russian Ministry of Natural Resources (MNR) to perform exploration seismic and drilling operations in these licence areas off the east coast of Russia. To date, 3D seismic data has been acquired in relation to all three licences. In the Elvary Neftegaz licence additional commitment 2D seismic data was acquired during 2008 in preparation for future drilling commitments. Exploration wells have been drilled in the Zapad-Shmidt Neftegaz and Elvary Neftegaz licences. In 2008, it was agreed by both shareholders to allow the Zapad-Shmidt Neftegaz licence to lapse at the end of its normal term.
Other
Azerbaijan
  In Azerbaijan, BP’s net production in 2008 was 130mboe/d, a net decrease of 40% from 2007. The primary elements of this were the effects of significantly higher prices resulting in a change in profit oil entitlement in line with the terms of the PSA and reduced cost oil entitlement, partially offset by an increase following the start-up of the Deepwater Gunashli (DWG) platform, the ramping up of three Azeri oil-producing platforms and the Shah Deniz condensate gas platform commencing production in 2007.
 
  The DWG platform complex successfully started oil production on schedule on 20 April 2008. DWG completes the third phase of development of the Azeri-Chirag-Gunashli (ACG) field (BP 34.1% and operator) in the Azerbaijan sector of the Caspian Sea. The DWG complex is located in a water depth of 175 metres on the east side of the Gunashli field. The complex comprises two platforms – a drilling and production platform linked by a bridge to a water injection and gas compression platform.
 
  On 17 September 2008, a subsurface gas release occurred below the Central Azeri platform. As a precautionary measure, all personnel on the platform were safely transferred onshore. The Central Azeri platform was shut down until 19 December 2008, when following comprehensive investigation and recovery work, BP began to resume oil and gas production. Central Azeri processes oil and gas from West Azeri, and West Azeri was also temporarily shut down and then restored to normal operations on 9 October 2008. Operations of the Compressor and Water Injection Platform (CWP), which is linked by a bridge to Central Azeri, and the provision of power and injection water across three Azeri field platforms were re-established on 12 October 2008.
Middle East and South Asia
  Production in the Middle East consists principally of the production entitlement of associates in Abu Dhabi, where we have equity interests of 9.5% and 14.7% in onshore and offshore concessions respectively. In 2008, BP’s share of production in Abu Dhabi was 210mb/d, up 9% from 2007 as a result of higher overall OPEC demand despite cuts implemented in the fourth quarter of 2008.
 
  In July 2008, BP Sharjah signed a farm-out agreement with RAK Petroleum for the East Sajaa concession. Drilling of the first exploration well is expected in 2009.
 
  In Block 61 in Oman, the challenges posed by the world’s largest onshore azimuth 3D seismic survey led the BP Oman team to use a ground-breaking new technique known as Distance Separated Simultaneous Sweeping (DS3). This technique allows the acquisition


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Performance review
 

    in a single day of as much seismic data as previously obtained in a week. The invention of DS3 along with some other innovations allowed an efficient and cost effective survey of the Block to be completed within a six-month period. The first appraisal well was spudded in September 2008.
 
  In Pakistan, BP’s net oil production in 2008 was 8.2mboe/d, an increase of 30% from 2007, and BP’s net gas production was 28.2mboe/d, an increase of 34% from 2007 as a result of the full-year impact of BP increasing its equity in the onshore Badin asset in 2007 to 84%.
 
  In Pakistan, BP received an 18-month extension until January 2010 in Phase 1 of the initial term of Exploration Licences in respect of the offshore Indus PSA.
 
  On 30 December 2008, BP signed completion documents with Orient Petroleum International Inc., to acquire a 51.3% working interest, along with operatorship, in two joint venture blocks, Mirpurkhas and Khipro, located in the southern Sindh province of Pakistan.
 
  On 22 December 2008, BP signed a production-sharing contract with the Indian government for a deepwater exploration block in the Krishna-Godavari Basin, offshore eastern India, which was awarded under the New Exploration Licensing Policy Seventh round. BP is the designated operator with a 30% working interest in the block. Reliance Industries Limited holds the remaining 70% working interest.
Midstream activities
Oil and natural gas transportation
The group has direct or indirect interests in certain crude oil transportation systems, the principal ones being the Trans-Alaska Pipeline System (TAPS) in the US, the Forties Pipelines System (FPS) in the UK sector of the North Sea and the Baku-Tbilisi-Ceyhan (BTC) oil pipeline.
          In addition to these, we also operate the Central Area Transmission System (CATS) for natural gas in the UK sector of the North Sea, the Western Export Route Pipeline between Azerbaijan and the Black Sea coast of Georgia (as operator of AIOC), and, as technical operator, the South Caucasus Pipeline (SCP) (BP 25.5%), which takes gas from Azerbaijan through Georgia to the Turkish border.
          BP’s onshore US crude oil and product pipelines and related transportation assets are included under Refining and Marketing (see page 27).
          Assets and activity during 2008 included:
Alaska
  BP owns a 46.9% interest in TAPS, with the balance owned by four other companies. Production transported by TAPS from Alaska North Slope fields averaged 700mb/d during 2008.
 
  Work on the strategic reconfiguration project to upgrade and automate four TAPS pump stations continued to progress in 2008. This project is installing electrically-driven pumps at four critical pump stations, along with increased automation and upgraded control systems. Two of the reconfigured pump stations came online during 2007. The remaining two reconfigured pump stations are expected to come online sequentially, one in 2009 and one in 2010.
 
  On 8 April 2008, BP and ConocoPhillips announced the formation of a joint venture company called Denali – The Alaska Gas Pipeline. The joint venture has begun work on an Alaska gas pipeline project consisting of a gas treatment plant on Alaska’s North Slope, a large-diameter pipeline that is intended to pass through Alaska into Canada, and should it be required, a large-diameter pipeline from Alberta to the Lower 48 United States. When completed, the pipeline is expected to move approximately 4 billion cubic feet of natural gas per day to market. The joint venture plans to spend up to $600 million prior to reaching the first major project milestone, an ‘open season’, before the end of 2010. An open season is a process during which
    the joint venture seeks customers to make firm, long-term transportation commitments to the project. Should the open season be successful, the joint venture will seek certification from the Federal Energy Regulatory Commission (FERC) of the US and the National Energy Board (NEB) of Canada to move forward with project construction. The new joint venture company will manage the project, and will own and operate the pipeline when completed. BP and ConocoPhillips may consider other equity partners, including pipeline companies, who can add value to the project and help manage the risks involved. On 22 May 2008, the office of the Governor of Alaska announced that it would be supporting an alternative gas pipeline project proposed by TransCanada Alaska Company in response to the State of Alaska’s request for bids under the Alaska Gas Inducement Act (AGIA) in 2007. BP’s commitment to move forward with the Denali project is independent of any decisions made or inducement offered by the State under the AGIA process and BP believes that the Denali project offers the best opportunity for a successful Alaska gas pipeline project.
 
  Alaska state courts issued two noteworthy rulings in 2008, related to challenges filed by in-state refiners against BP and the other TAPS carriers, regarding intrastate tariffs charged for shipping oil through TAPS during the period from 1997 through 2003. These rulings are related to long-standing challenges that were originally filed with the Regulatory Commission of Alaska (RCA). In 2002, the RCA issued Order 151, which determined that TAPS transportation rates charged from the beginning of 1997 were excessive, and that refunds should be paid. BP and the other TAPS carriers appealed the RCA's 2002 ruling in the State of Alaska court system. In the interim, the RCA issued Order 34, which imposed intrastate tariff rates consistent with Order 151, effective from 1 July 2003 forward. On 15 February 2008, the Alaska Supreme Court affirmed the determination in RCA's Order 151, and on 26 February 2008, the Alaska Superior Court affirmed the RCA's Order 34, and imposed the application of Order 151 to intrastate tariff rates charged from 2001 forward. BP and the other TAPS carriers decided not to appeal these matters any further in the courts, and on 25 March 2008, BP Pipelines Alaska paid refunds to intrastate shippers totalling $71 million covering the period 1997 through 2000. During the third quarter of 2008, BP Pipelines Alaska paid out an additional $75 million to intrastate shippers covering the period from 2001 through 30 June 2003. In 2008, intrastate transport made up approximately 13.7% of total TAPS throughput.
 
  Tariffs for interstate transportation of oil through TAPS are calculated using the TAPS Tariff Settlement Methodology (TSM), which is defined in an agreement entered into with the State of Alaska in 1985. The TSM was also accepted at that time by the Regulatory Commission of Alaska (RCA) and the Federal Energy Regulatory Commission (FERC). Since then, Anadarko, Tesoro, and the State of Alaska have challenged the interstate tariffs charged by BP and the other TAPS carriers in the years 2005, 2006 and 2007 with the FERC. Anadarko and the State of Alaska have also challenged the 2008 tariffs. In 2006, the FERC consolidated the proceedings related to the years 2005-2006, and determined that the challenges pertaining to 2007 tariff rates would be held in abeyance until a decision was issued in the proceedings on 2005 and 2006 tariff rates. The FERC’s hearings on the consolidated proceedings commenced in October 2006 and concluded in January 2007. On 17 May 2007, a FERC Administrative Law Judge (ALJ) issued an initial decision on 2005 and 2006 tariff rates that was adverse to BP and the other TAPS carriers, and established a floor of $3.01/bbl for the 2005-2006 period, as this was the last uncontested tariff rate. On 20 June 2008, the FERC issued a ruling on the 2005-2006 period, which substantially affirmed the initial ruling by the ALJ, and ordered the TAPS carriers to pay refunds to shippers. On 20 November 2008, the FERC affirmed its 20 June 2008 ruling in response to applications for rehearing filed by BP and the other TAPS carriers. Accordingly, in December 2008 BP as


24


 

Performance review
 

    a TAPS carrier paid third party shippers tariff refunds of $52 million; and BP as a TAPS shipper received tariff refunds from third party carriers of $27 million. The FERC’s 20 November 2008 ruling also concluded that a unified tariff rate should be established for interstate transportation through TAPS, and the TAPS carriers were ordered to implement a revenue pooling methodology in the TAPS Operating Agreement. Some TAPS carriers other than BP have filed legal challenges to this aspect of the FERC’s 20 November 2008 ruling, which are still pending. As of the end of 2008, there have been no proceedings in the challenges to BP’s and the other TAPS carriers’ 2007 and 2008 tariff rates. In 2008, interstate transport made up approximately 86% of total TAPS throughput.
North Sea
  FPS (BP 100%) is an integrated oil and NGLs transportation and processing system that handles production from more than 50 fields in the Central North Sea. The system has a capacity of more than one million barrels per day, with average throughput in 2008 of 662mb/d.
 
  BP operates and has a 29.5% interest in CATS, a 400-kilometre natural gas pipeline system in the central UK sector of the North Sea. The pipeline has a transportation capacity of 1,700mmcf/d to a natural gas terminal at Teesside in north-east England. CATS offers natural gas transportation and processing services. In 2008, throughput was 836mmcf/d (gross), 247mmcf/d (net).
 
  BP operates the Dimlington/Easington gas processing terminal (BP 100%) on Humberside and the Sullom Voe oil and gas terminal in Shetland.
Asia (including the former Soviet Union)
  BP as operator, manages and holds a 30.1% interest in the BTC oil pipeline. The 1,768-kilometre pipeline transports oil from the BP-operated ACG oil field in the Caspian Sea to the eastern Mediterranean port of Ceyhan. The Turkish section of the pipeline is operated by Botas.
 
  On 6 August 2008, the Baku-Tbilisi-Ceyhan (BTC) pipeline was shut down for 14 days as a result of a fire that occurred at Block Valve 30, located in the Erzincan province in Eastern Turkey. The pipeline restarted on 20 August 2008. The Azeri-Chirag-Gunashli (ACG) and Shah Deniz (SD) fields reduced offshore production to manage stock levels at the Sangachal Terminal. Some exports were maintained via the Northern Route Export Pipeline (NREP) and by rail through Georgia.
 
  BP is technical operator of, and holds a 25.5% interest in, the 693-kilometre South Caucasus Pipeline (SCP), which takes gas from Azerbaijan through Georgia to the Turkish border. During August 2008, the South Caucasus gas and Western Route oil export pipelines were shut down for a short period as a precautionary measure during a period of military activity in the region.
 
  In February 2008, BP, on behalf of AIOC, handed over operatorship of the Azerbaijani section of the NREP between Azerbaijan and Russia to the State Oil Company of Azerbaijan Republic (SOCAR).
 
  Through the LukArco joint venture, BP holds a 5.75% interest in the Caspian Pipeline Consortium (CPC) pipeline and a 2.3% interest in Tengizchevroil (TCO). CPC is a 1,510-kilometre pipeline from Kazakhstan to the Russian port of Novorossiysk and carries crude oil from a number of Kazakh fields, including Tengiz. In addition to our interest in LukArco, we hold a separate 0.87% interest in CPC through a 49% holding in Kazakhstan Pipeline Ventures (KPV). In 2008, CPC total throughput reached 32.2 million tonnes. During 2008, the majority of shareholders in CPC agreed on the commercial terms for expansion of CPC to 67 million tonnes. These terms strongly favour the upstream, and as BP has no additional volumes of Kazakh crude to ship in an expanded CPC, BP has been unable to support these new commercial terms. In order not to delay the expansion of CPC, BP has obtained the agreement of its KPV joint venture partners and CPC shareholders to dispose of its interest in KPV
    and is seeking the agreement of its joint venture partners, CPC shareholders and TCO partners to dispose of its interest in LukArco.
 
  On 25 September 2008, Chevron announced that Tengizchevroil had completed a major expansion at the Tengiz field in Kazakhstan in which BP holds a 2.3% interest through its joint venture with LukArco. The completion of the expansion brings daily crude capacity of the field to 540mb/d.
Liquefied natural gas
Our LNG activities are focused on building competitively advantaged liquefaction projects, establishing diversified market positions to create maximum value for our upstream natural gas resources and capturing third party LNG supply to complement our equity flows.
          Assets and activity during 2008 included:
  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 re-gasified), with the Atlantic LNG Train 4 (BP 37.8%) designed to produce 5.2 million tonnes (253 billion cubic feet) per year of LNG. All of the LNG from Atlantic Train 1 and most of the LNG from Trains 2 and 3 is sold to third parties in the US and Spain under long-term contracts. All of BP’s LNG entitlement from Atlantic LNG Train 4 and some of its LNG entitlement from Trains 2 and 3 is marketed via BP’s LNG marketing and trading business to a variety of markets including the US, the Dominican Republic, Spain, the UK and the Far East.
 
  We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction Company, which in 2008 supplied 5.8 million tonnes (298.746mmcf) of LNG, up 3% from 2007.
 
  BP has a 13.6% share in the Angola LNG project, which is expected to receive approximately one billion cubic feet of associated gas per day from offshore producing blocks and to produce 5.2 million tonnes gross per year of LNG, as well as related gas liquids products. With the completion of the necessary agreements and the approval of the Angolan government, the project investors have authorized Angola LNG Limited to proceed with the construction and implementation of the project.
 
  In Indonesia, BP is involved in two of the three LNG centres in the country. BP participates in Indonesia’s LNG exports through its holdings in the Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently delivers around 13% of the total gas feed to Bontang, one of the world’s largest LNG plants. The Bontang plant produced 18.4 million tonnes of LNG in 2008.
 
  Also in Indonesia, BP has interests in the Tangguh LNG joint venture (BP 37.2% and operator) and in each of the Wiriagar (BP 38% and operator), Berau (BP 48% and operator) and Muturi (BP 1%) PSAs in north-west Papua that are expected to supply feed gas to the Tangguh LNG plant. During 2008, construction continued on two LNG trains and the offshore facilities, with commercial delivery planned in the second quarter of 2009. Tangguh will be the third LNG centre in Indonesia, with an expected initial capacity of 7.6 million tonnes of LNG (388,000mmcf) per year. Tangguh has signed LNG sales contracts for delivery to China, Korea and North America.
 
  In Australia, we are one of seven partners in the North West Shelf (NWS) venture. The joint venture operation covers offshore production platforms, an FPSO, trunklines, onshore gas and LNG processing plants and LNG carriers. BP’s net share of the capacity of NWS LNG Trains 1-5 is 2.7 million tonnes of LNG per year.
 
  BP has a 30% equity stake in the 7 million tonne per annum capacity Guangdong LNG re-gasification and pipeline project in south-east China, making it the only foreign partner in China’s LNG import business. In addition to LNG supplied under a long-term contract with Australia’s NWS project, the terminal took delivery of an additional eight spot LNG cargoes during 2008, to meet rapidly growing local demand for gas.


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Performance review
 

  BP Shipping took delivery of four LNG ships during 2007 and 2008. The ‘Gem’ class ships can carry 155,000m3 of LNG and are among the first ships in the industry to be powered by low-emission, fuel-efficient, diesel-electric propulsion. BP Shipping provides safe, environmentally responsible marine and shipping solutions in support of BP group activities.
 
  In both the Atlantic and Asian regions, BP is marketing LNG using BP LNG shipping and contractual rights to access import terminal capacity in the liquid markets of the US (via Cove Point and Elba Island) and the UK (via the Isle of Grain), and is supplying Asian customers in Japan, South Korea and Taiwan.
Gas marketing and trading activities
Gas and power marketing and trading activity is undertaken primarily in the US, Canada, the UK and Europe to market both BP production and third-party natural gas and manage market price risk as well as to create incremental trading opportunities through the use of commodity derivative contracts. Additionally, this activity generates fee income and enhanced margins from sources such as the management of price risk on behalf of third-party customers. These markets are large, liquid and volatile.
          In connection with the above activities, the group uses a range of commodity derivative contracts and storage and transport contracts. These include commodity derivatives such as futures, swaps and options to manage price risk and forward contracts used to buy and sell gas and power in the marketplace. Using these contracts, in combination with rights to access storage and transportation capacity, allows the group to access advantageous pricing differences between locations, time periods and arbitrage between markets. Natural gas futures and options are traded through exchanges, while over-the-counter (OTC) options and swaps are used for both gas and power transactions through bilateral and/or centrally cleared arrangements. Futures and options are primarily used to trade the key index prices such as Henry Hub, while swaps can be tailored to price with reference to specific delivery locations where gas and power can be bought and sold. OTC forward contracts have evolved in both the US and UK markets, enabling gas and power to be sold forward in a variety of locations and future periods. These contracts are used both to sell production into the wholesale markets and as trading instruments to buy and sell gas and power in future periods. Storage and transportation contracts allow the group to store and transport gas, and transmit power between these locations. The group has developed a risk governance framework to manage and oversee the financial risks associated with this trading activity, which is described in Note 28 to the Financial statements on pages 140-145.
          The range of contracts that the group enters into is described below in more detail:
Exchange-traded commodity derivatives
Exchange-traded commodity derivatives include gas and power futures contracts. Though potentially settled physically, these contracts are typically settled financially. Gains and losses, otherwise referred to as variation margins, are settled on a daily basis with the relevant exchange. Realized and unrealized gains and losses on exchange-traded commodity derivatives are included in total revenues for accounting purposes.
OTC contracts
These contracts are typically in the form of forwards, swaps and options. Some of these contracts are traded bilaterally between counterparties; others may be cleared by a central clearing counterparty. These contracts can be used for both trading and risk management activities. Realized and unrealized gains and losses on OTC contracts are included in total revenues for accounting purposes. Highly developed markets exist in North America and the UK where gas and power can be bought and sold for delivery in future periods. These contracts are negotiated between two parties to purchase and sell gas and power at a specified price, with
delivery and settlement at a future date. Typically, these contracts specify delivery terms for the underlying commodity. Certain of these transactions are not settled physically. This can be achieved by transacting offsetting sale or purchase contracts for the same location and delivery period that are offset during the scheduling of delivery or dispatch. The contracts contain standard terms such as delivery point, pricing mechanism, settlement terms and specification of the commodity. Typically, volume and price are the main variable terms. Swaps can be contractual obligations to exchange cash flows between two parties. One usually references a floating price and the other a fixed price, with the net difference of the cash flows being settled. Options give the holder the right, but not the obligation, to buy or sell natural gas products or power at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry, typically through netting agreements to limit credit exposure and support liquidity.
Spot and term contracts
Spot contracts are contracts to purchase or sell a commodity at the market price, typically an index price prevailing on the delivery date when title to the inventory passes. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. These transactions result in physical delivery with operational and price risk. Spot and term contracts relate typically to purchases of third-party gas and sales of the group’s gas production to third parties. Spot and term sales are included in total revenues, when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes.


26


 

Performance review
 

Refining and Marketing
Our Refining and Marketing business is responsible for the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum, chemicals products and related services to wholesale and retail customers. BP markets its products in more than 100 countries. We operate primarily in Europe and North America and also manufacture and market our products across Australasia, in China and other parts of Asia, Africa and Central and South America.
          In 2008 we restructured the Refining and Marketing organization into two main business groupings: fuels value chains (FVCs) and international businesses (IBs). The FVCs integrate the activities of refining, logistics, marketing, supply and trading, on a regional basis, recognizing that the markets for our main fuels products operate regionally. This shift to a more geographic and integrated model represents a major simplification step and the opportunity to create better value from our physical assets (refineries, terminals, pipelines and retail stations). The IBs include the manufacturing, supply and marketing of lubricants, petrochemicals, liquefied petroleum gas (LPG) and aviation and marine fuels. We believe each of these IBs is competitively advantaged in the markets in which we have chosen to participate. Such advantage is derived from several factors, including location, proximity of manufacturing assets to markets, physical asset quality, operational efficiency, technology advantage and the strength of our brands. Each business has a clear strategy focused on investing in its key assets and market positions in order to deliver value to its customers and outperform its competitors.
          During the past five years, our focus has been on process safety, upgrading organizational capability and significant integrity management investment. The construction of new production units at many of our refineries as well as upgrades of existing conversion units at a number of our facilities has positioned our assets to produce the high-quality fuels needed to meet today’s heightened product specifications.
Our performance in 2008
The 2008 environment in which the segment operated was very challenging, characterized by high and volatile crude and product prices, which resulted in substantial margin volatility as well as higher energy costs in manufacturing. Crude prices fell significantly in the second half of the year and at the end of the year, prices were around $50/bbl lower than the start of the year. Refining margins in the US were significantly weaker than 2007 due to weaker gasoline demand. Conversely, in Europe, where diesel accounts for a larger share of regional demand, margins were stronger than a year ago. Demand for fuels has fallen, initially due to high oil prices and subsequently due to the slowing of global economies and the impact of the financial crisis. During the fourth quarter, we saw a dramatic decline in the demand for our petrochemicals products as a consequence of the economic slowdown. The year also saw material swings in foreign exchange rates, particularly in the second half, that affected our results.
          Our 2008 performance reflects the benefits of the fundamental improvements we are making across the business, including the measures we have taken to restore the availability of our refining system, reduce costs and simplify the organization. The loss before interest and tax was $1.9 billion for 2008, compared with a profit before interest and tax of $6.1 billion in 2007. The decrease was primarily driven by inventory-holding losses. Our financial results are discussed in more detail on pages 50-51.
Safety, both process and personal, remains our top priority. During 2008, we started the migration to the new BP Operating Management System (OMS) with an increased focus on process safety and continuous improvement. The OMS is described in further detail on page 40. At the end of the year, two of our petrochemicals plants in the US and two of our refineries in Europe were operating on OMS. Within our US refineries, we continue to implement the recommendations from the BP US Refineries Independent Safety Review Panel. We have worked closely with the independent expert, L Duane Wilson. The number of major incidents associated with integrity management has decreased by 90% since 2005. We have also reduced the number of oil spills by 60% and the recordable injury rate by more than 57% since 1999. Regrettably, in 2008 there were four workforce fatalities associated with our operations, one of which was a process safety incident.
          In 2008, we saw the first substantial benefits of our operational improvements. The Whiting refinery was restored to its full clean fuel capability of 360mb/d in March 2008 following the compressor failure and fire that took place during 2007. Texas City was also restored to full economic capability by the end of the year. In Europe and Rest of World, we commissioned new upgrading units at the Rotterdam and Kwinana refineries, enhanced processing capability at the Gelsenkirchen refinery, reconfigured the Bayernoil refinery for more efficient and competitive operation, and completed construction of a new coker at the Castellón refinery. During the next five years, we intend to continue the focus on process safety, improve the competitive performance of our refineries and complete the previously announced investment in the Whiting refinery to increase its ability to process Canadian heavy crude.
          In total, our 17 refineries worldwide, including those partially owned, achieved throughputs of 2,155mb/d on average, a 5% increase on 2007 after adjusting for the net loss of throughput from previous disposals and acquisitions. The performance of Texas City was impacted by Hurricane Ike in September, which meant we had to shut down the refinery in advance as a precautionary measure, along with other refineries in the area. Operational disruption was minimized as crude processing was restored in seven days and full operations restored within three weeks. This was due to a terrific response from employees and also reflected the improvements we have made to our assets at Texas City over the last few years.
          During 2008, we fully integrated our refining, logistics, marketing, supply and trading activities, establishing six refining-to-marketing integrated FVCs focused on refining and selling ground transportation fuels in each region. This has enabled us to simplify internal interfaces, optimize margins, reduce overhead costs and drive continuous improvement. During the year, we continued the implementation of our ampm convenience retail franchise model in the US, which we expect to provide reliable long-term sales growth for our refinery systems, together with reduced costs and lower levels of capital investment. In Europe, where we are one of the largest forecourt convenience retailers, with about 2,500 shops in 10 countries, we are growing our food-on-the-go and fresh grocery services through BP-owned brands and partnerships with leading retailers such as Marks & Spencer.
          In relation to our IBs during 2008, in the lubricants business we focused on enhancing our customer relationships and brand distinctiveness, together with simplifying operations and improving efficiency. Although 2008 was a difficult year for the aviation industry, in Air BP, we simplified our footprint by exiting non-core countries resulting in a reduction in working capital and improved returns on operating capital employed. During the year, the environment in which our petrochemicals businesses operate became more challenging as deterioration in the global economic market led to reduced demand for our products.
          We are simplifying the structure of our organization, improving the efficiency of our back office and reducing our headcount, including the number of senior management positions.


27


 

Performance review
 

Looking ahead, in 2009 the overall economic environment is expected to be challenging with reduced demand for our products leading to lower volumes and pressure on margins. The impact is expected to be greatest in the petrochemicals sector.
          Against this background, we intend to continue actively managing our cost base, simplifying our marketing footprint and developing the market positions where we have competitive advantage based on brand and technology strengths. We also intend to improve the efficiency of our back office, including customer service, accounting services and procurement systems, by centralizing these activities in a few global centres to remove duplication and reduce cost. We intend to focus on cash generation through active management of our working capital and credit exposure.
           We intend to limit our capital investment to maintaining and improving our core positions. To continue the progress we have made in recent years, our top priority for spending will remain safety and operational integrity. The other area of focus will be delivering integrated value in our key markets through investment in terminals and pipeline infrastructure. Our largest investment is expected to be at the Whiting refinery, where we have started a major upgrading and modernization programme that will enable the refinery to operate on Canadian heavy crude oil. We also intend to complete the planned projects in petrochemicals (see page 32).
          Comparative information presented in the table below has been restated, where appropriate, to reflect the resegmentation, following transfers of businesses between segments, that was effective from 1 January 2008. See page 12 for further details.
Key statistics
                         
 
                    $ million  
 
    2008     2007     2006  
 
Total revenuesa
    320,458       250,897       232,833  
Profit before interest and tax from continuing operationsb
    (1,884 )     6,076       5,419  
Total assets
    75,329       95,311       80,738  
Capital expenditure and acquisitions
    6,634       5,495       3,127  
 
$  per barrel
 
Global Indicator Refining Marginc
    6.50       9.94       8.39  
 
 
a   Includes sales between businesses.
 
b   Includes profit after interest and tax of equity-accounted entities.
 
c   The Global Indicator Refining Margin (GIM) is the average of regional industry indicator margins, which we weight for BP’s crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with product yields characteristic of the typical level of upgrading complexity. The refining margins are industry-specific rather than BP-specific measures, which we believe are useful to investors in analyzing trends in the industry and their impact on our results. The margins are calculated by BP based on published crude oil and product prices and take account of fuel utilization and catalyst costs. No account is taken of BP’s other cash and non-cash costs of refining, such as wages and salaries and plant depreciation. The indicator margin may not be representative of the margins achieved by BP in any period because of BP’s particular refining configurations and crude and product slate.
Total revenues are analysed in more detail below.
                         
 
                    $ 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  
 
                         
thousand barrels per day  
Sales of refined productsa   2008     2007     2006  
 
Marketing sales
                       
UKb
    310       339       356  
Rest of Europe
    1,256       1,294       1,340  
US
    1,460       1,533       1,595  
Rest of World
    685       640       581  
 
Total marketing salesc
    3,711       3,806       3,872  
Trading/supply salesd
    1,987       1,818       1,929  
 
Total refined products
    5,698       5,624       5,801  
 
                         
                    $ million  
 
Proceeds from sale of refined products
    248,561       194,979       177,995  
 
 
a   Excludes sales to other BP businesses, sales of Aromatics & Acetyls products and Olefins & Derivatives sales through equity-accounted entities.
 
b   UK area includes the UK-based international activities of Refining and Marketing.
 
c   Marketing sales are sales to service stations, end-consumers, bulk buyers and jobbers (i.e. third parties who own networks of a number of service stations and small resellers).
 
d   Trading/supply sales are sales to large unbranded resellers and other oil companies.
The following table sets out marketing sales by major product group.
                         
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  
 
Marketing volumes were 3,711mb/d, slightly lower than last year, reflecting the impacts from the slowing of global economies and reduced industry demand in the US and Europe.
Fuels value chains
Following our reorganization we have six integrated FVCs. They are organized regionally, covering the West Coast and Mid-West regions of the US, the Rhine region, Southern Africa, Australasia (ANZ) and Iberia. Each of these is a material business, optimizing activities across the supply chain – from crude delivery to the refineries; manufacture of high-quality fuels to meet market demand; pipeline and terminal infrastructure and the marketing and sales to our customers. The Texas City refinery is operated as a standalone predominantly merchant refining business that also supports our marketing operations on the east and gulf coasts.
Refining
The group’s global refining strategy is to own and operate strategically advantaged refineries that benefit from vertical integration with our marketing and trading operations, as well as horizontal integration with other parts of the group’s business. Refining’s focus is to maintain and improve its competitive position through sustainable, safe, reliable and efficient operations of the refining system and disciplined investment for integrity management, to achieve competitively advantaged configuration and growth.
          For BP, the strategic advantage of a refinery relates to its location, scale and configuration to produce fuels from lower-cost feedstocks in line with the demand of the region. Strategic investments in our refineries are focused on securing the safety and reliability of our assets while improving our competitive position. In addition, we continue to invest to develop the capability to produce the cleaner fuels that meet the requirements of our customers and their communities.


28


 

Performance review
 
The following table summarizes the BP group’s interests in refineries and crude distillation capacities at 31 December 2008.
                                     
     
    thousand barrels per day  
    Crude distillation capacitiesa  
                Group interestb             BP  
    Refinery   Fuels value chain     %     Total     share  
     
Rest of Europe
                                   
Germany
  Bayernoil   Rhine     22.5%       215       48  
 
  Gelsenkirchen*   Rhine     50.0%       266       133  
 
  Karlsruhe   Rhine     12.0%       323       39  
 
  Lingen*   Rhine     100.0%       93       93  
 
  Schwedt   Rhine     18.8%       226       42  
Netherlands
  Rotterdam*   Rhine     100.0%       386       386  
Spain
  Castellón*   Iberia     100.0%       110       110  
     
Total Rest of Europe
                        1,619       851  
     
US
                                   
California
  Carson*   US West Coast     100.0%       266       266  
Washington
  Cherry Point*   US West Coast     100.0%       234       234  
Indiana
  Whiting*   US Mid-West     100.0%       405       405  
Ohio
  Toledo*   US Mid-West     50.0%       155       78  
Texas
  Texas City*         100.0%       475       475  
     
Total US
                        1,535       1,458  
     
Rest of World
                                   
Australia
  Bulwer*   ANZ     100.0%       102       102  
 
  Kwinana*   ANZ     100.0%       137       137  
New Zealand
  Whangerei   ANZ     23.7%       102       24  
Kenya
  Mombasac   Southern Africa     17.1%       94       16  
South Africa
  Durban   Southern Africa     50.0%       180       90  
     
Total Rest of World
                        615       369  
     
Total
                        3,769       2,678  
     
 
*Indicates refineries operated by BP.
 
aCrude distillation capacity is gross rated capacity, which is defined as the maximum achievable utilization of capacity (24-hour assessment) based on standard feed.
 
bBP share of equity, which is not necessarily the same as BP share of processing entitlements.
 
cOn 15 January 2008, it was announced that Essar Energy Overseas Ltd, a subsidiary of Essar Oil Limited, had entered into an agreement to acquire 50% of Kenya Petroleum Refineries Ltd.
  The transaction was initially expected to be finalized in 2008, but has since been delayed in negotiations.
The following table outlines by region the volume of crude oil and feedstock processed by BP for its own account and for third parties. Corresponding BP refinery capacity utilization data is summarized.
                         
     
    thousand barrels per day  
Refinery throughputsa   2008     2007     2006  
     
UK
          67       165  
Rest of Europe
    739       691       648  
US
    1,121       1,064       1,110  
Rest of World
    295       305       275  
     
Total
    2,155       2,127       2,198  
     
Refinery capacity utilization
                       
Crude distillation capacity at 31 Decemberb
    2,678       2,769       2,823  
Crude distillation capacity utilizationc
    78%       72%       76%  
US
    72%       62%       70%  
Europe
    85%       84%       87%  
Rest of World
    83%       84%       78%  
     
 
aRefinery throughputs reflect crude and other feedstock volumes.
 
bCrude distillation capacity is gross rated capacity, which is defined as the maximum achievable utilization of capacity (24-hour assessment) based on standard feed.
 
cCrude distillation capacity utilization is defined as the percentage utilization of capacity per calendar day during the year after making allowances for average annual shutdowns at BP refineries (i.e. net rated capacity).

29


 

Performance review
 

Excluding portfolio impacts, underlying refining throughputs in 2008 increased by 5% relative to 2007, driven principally by improved operational performance in the US. Higher US throughputs were attributable to the recoveries at the Texas City and Whiting refineries, partially offset by the reduced equity interest in the Toledo refinery stemming from the Husky joint venture (see below). The improvement achieved in the US was lower than it would have been as crude runs were reduced as a result of the low-margin environment as well as the disruption at the Texas City refinery in September caused by Hurricane Ike.
          The increase in Rest of Europe throughputs in 2008 is primarily related to the purchase of Chevron’s 31% interest in the Rotterdam refinery in 2007. The decrease in UK throughputs is due to the sale of the Coryton refinery to Petroplus.
          Significant events in Refining were as follows:
  On 21 March 2008, the Whiting refinery in the US was restored to its full clean fuel capability of 360mb/d.
 
  BP completed recommissioning the Texas City refinery in the US. With the successful return to service of Ultraformer No. 3 in the fourth quarter, the site’s full economic capability was restored.
 
  On 31 March 2008, we completed a deal with Husky Energy Inc. to create an integrated North American oil sands business by means of two separate joint ventures, one of which entailed Husky taking a 50% interest in BP’s Toledo refinery. The Toledo refinery is intended to be expanded to process approximately 170mb/d of heavy oil and bitumen by 2015.
 
  In July, a final investment decision was taken to progress the significant upgrade of the Whiting refinery. This project repositions Whiting competitively by increasing its Canadian heavy crude processing capability by 260mb/d and modernizing it with equipment of significant size and scale.
 
  On 17 March 2008, BP and Irving Oil entered into a memorandum of understanding to work together on evaluating the feasibility of the proposed Eider Rock refinery in Saint John, New Brunswick, Canada.
Fuels marketing, supply and logistics
Our fuels marketing strategy focuses on optimizing the integrated value of each fuels value chain that is responsible for the delivery of ground fuels to the market. We do this by co-ordinating our marketing, refining and trading activities to maximize synergies across the whole value chain. Our priorities are to operate an advantaged infrastructure and logistics network (which includes pipelines, storage terminals and road or rail tankers), drive excellence in operating and transactional processes and deliver compelling customer offers in the various markets where we operate. The fuels business markets a comprehensive range of refined oil products primarily focused on the ground fuels sector.
          On 29 August 2008, BP announced an agreement with Enbridge Inc. to build and reconfigure a pipeline system to transport Canadian heavy crude oil from Flanagan, Illinois, to Houston and Texas City, Texas. The system is expected to be in service by late 2012 with an initial capacity of 250mb/d. The joint investment of the phased capacity additions is expected to be in the range of $1-2 billion.
          The ground fuels business supplies fuel and related convenience services to retail consumers through company-owned and franchised retail sites as well as other channels including wholesalers and jobbers. It also supplies commercial customers within the road and rail transport sectors.
          BP’s value creation in ground fuels is obtained through the integration of the value chain from the refinery gates or import hubs across retail and commercial channels to market. Convenience retail offers are focused on delivering appealing convenience offers across the various markets in which we operate, through the BP Connect, ampm and Aral brands.
Our retail network is largely concentrated in Europe and the US, and also has established operations in Australasia and southern and eastern Africa. We are developing networks in China in two separate joint ventures, one with Petrochina and the other with China Petroleum and Chemical Corporation (Sinopec).
                         
 
Number of retail sites operated under a BP brand  
Retail sitesa b   2008     2007     2006  
 
UK
    1,200       1,200       1,300  
Rest of Europe
    7,400       7,400       7,700  
US (excluding jobbers)
    2,500       2,500       2,700  
US jobbers
    9,200       9,700       9,600  
Rest of World
    2,300       2,500       2,600  
 
Total
    22,600       23,300       23,900  
   
 
a Changes in the number of retail sites over time are affected 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 amended to this basis.
At 31 December 2008, BP’s worldwide network consisted of some 22,600 locations branded BP, Amoco, ARCO and Aral, around the same as in the previous year. We continue to improve the efficiency of our retail network and increase the consistency of our site offer through a process of regular review. In 2008, we sold 470 company-owned sites to dealers, jobbers and franchisees who continue to operate these sites under the BP brand. We also divested an additional 160 company-owned sites to third parties.
          At 31 December 2008, BP’s retail network in the US comprised approximately 11,700 sites, of which approximately 9,200 were owned by jobbers and 900 operated under a franchise agreement. In November 2007, BP announced that it would sell all of its company-owned and company-operated convenience sites in the US. Despite the challenges in the global credit market, we expect the sale of these sites to be completed by the end of 2009. At the end of 2008, sales of 293 of sites had been successfully completed. The sites will continue to market BP-branded fuels in the eastern US and ARCO-branded fuels in the western US. The franchise agreement has a term of 20 years and requires sites to be supplied with BP- or ARCO-branded fuels for the term of the contract.
          At the end of 2008, our European retail network consisted of approximately 8,600 sites and we had approximately 2,300 sites in the Rest of World.
          Our retail convenience operations offer consumers a range of food, drink and other consumables and services on the fuel forecourt in a safe, convenient and innovative manner. With operations in both Europe and the US, using recognized and distinctive brands, BP is working to maximize the efficiency and effectiveness of its retail network in each of its chosen market areas. By the end of 2008, we completed the roll-out of more than 100 Marks & Spencer Simply Food sites as an integral part of the convenience network in the UK, while a refresh of the Petit Bistro brand in Germany and the Wild Bean Café brand in other European locations has re-energized consumers’ convenience shopping choices. In the US, BP has embarked on a roll-out of its successful ampm brand across all targeted national markets as its single convenience flagship; this programme roll-out is intended to be completed by the end of 2009.


30


 

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 maintain a presence in the regionally connected global markets.
          The function seeks to identify the best markets and prices for our crude oil, source optimal feedstocks for our refineries and provide competitive supply for our marketing businesses. In addition, where refinery production is surplus to marketing requirements or can be sourced more competitively, it is sold into the market. Wherever possible, the group will look to optimize value across the supply chain. For example, BP will often sell its own crude production into the market and purchase alternative crude for its refineries where this will provide incremental margin.
          In addition to the supply activity described above, the function seeks to create incremental trading opportunities. It enters into the full range of exchange-traded commodity derivatives, over-the-counter (OTC) contracts and spot and term contracts that are described in detail below. In order to facilitate the generation of trading margin from arbitrage, blending and storage opportunities, it also both owns and contracts for storage and transport capacity. The group has developed a risk governance framework to manage and oversee the financial risks associated with this trading activity, which is described in the Financial statements – Note 28 on pages 140-145.
          The range of transactions that the group enters into is described below:
Exchange-traded commodity derivatives
These contracts are typically in the form of futures and options traded on a recognized exchange, such as Nymex, SGX, ICE and Chicago Board of Trade. Such contracts are traded in standard specifications for the main marker crude oils, such as Brent and West Texas Intermediate, and the main product grades, such as gasoline and gasoil. Gains and losses, otherwise referred to as variation margins, are settled on a daily basis with the relevant exchange. These contracts are used for the trading and risk management of both crude oil and refined products. Realized and unrealized gains and losses on exchange-traded commodity derivatives are included in total revenues for accounting purposes.
OTC contracts
These contracts are typically in the form of forwards, swaps and options. Some of these contracts are traded bilaterally between counterparties; others may be cleared by a central clearing counterparty. These contracts can be used both as part of trading and risk management activities. Realized and unrealized gains and losses on OTC contracts are included in total revenues for accounting purposes.
          The main grades of crude oil bought and sold forward using standard contracts are West Texas Intermediate and a standard North Sea crude blend (Brent, Forties and Osberg or BFO). Although the contracts specify physical delivery terms for each crude blend, a significant volume are not settled physically. The contracts typically contain standard delivery, pricing and settlement terms. Additionally, the BFO contract specifies a standard volume and tolerance given that the physically settled transactions are delivered by cargo.
Swaps are often contractual obligations to exchange cash flows between two parties: a typical swap transaction usually references a floating price and a fixed price with the net difference of the cash flows being settled. Options give the holder the right, but not the obligation, to buy or sell crude or oil products at a specified price on or before a specific future date. Amounts under these derivative financial instruments are settled at expiry, typically through netting agreements, to limit credit exposure and support liquidity.
Spot and term contracts
Spot contracts are contracts to purchase or sell crude and oil products at the market price prevailing on and around the delivery date when title to the inventory is taken. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. These transactions result in physical delivery with operational and price risk. Spot and term contracts relate typically to purchases of crude for a refinery, purchases of products for marketing, sales of the group’s oil production and sales of the group’s oil products. For accounting purposes, spot and term sales are included in total revenues, when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes.
International businesses
Our IBs provide quality products and offers to customers in more than 100 countries worldwide with a significant focus on Europe, North America and Asia. Our products include aviation and marine fuels, lubricants that meet the needs of various industries and consumers, LPG, and a range of petrochemicals that are sold for use in the manufacture of other products such as fabrics, fibres and various plastics.
Lubricants
We manufacture and market lubricants and related products and services to the automotive, industrial, marine and energy markets across the world. Following a decision to simplify and focus our channels of trade, we now sell products direct to our customers in around 50 countries and use approved local distributors for the remaining locations. Customer focus, distinctive brands, superior technology and relationships remain the cornerstones of our long-term strategy.
          BP markets primarily through its major brands of Castrol and BP, plus the Aral brand in some specific markets. Castrol is recognized as one of the most powerful lubricants brands worldwide and we believe it provides us with a significant competitive advantage. In the automotive lubricants sector, we supply lubricants and other related products and services to intermediate customers such as retailers and workshops. These, in turn, serve end-consumers such as car, truck and motorcycle owners in the mature markets of Western Europe and North America as well as the markets of Russia, China, India, the Middle East, South America and Africa, which we believe have the potential for significant long-term growth.
          BP’s marine lubricants business is a global market leader, supplying many types of vessels from deep-sea fleets to marine leisure-craft from around 1,200 ports across the globe. BP’s industrial lubricants business is a leading supplier to those sectors of the market involved in the manufacture of automobiles, trucks, machinery components and steel. BP is also a leading supplier of lubricants for the offshore oil and aviation industries.


31


 

Performance review
 

Petrochemicals
Our petrochemicals operations are comprised of the global Aromatics & Acetyls businesses (A&A) and the Olefins & Derivatives (O&D) businesses, predominantly in Asia. New investments are targeted principally in the higher growth Asian markets.
          In A&A, we manufacture and market three main product lines: purified terephthalic acid (PTA), paraxylene (PX) and acetic acid. Our A&A strategy is to leverage our industry-leading technology in selected markets, to grow the business and to deliver industry-leading returns. PTA is a raw material used in the manufacture of polyesters used in fibres, textiles and film, and PET bottles. Acetic acid is a versatile intermediate chemical used in a variety of products such as paints, adhesives and solvents, as well as its use in the production of PTA. We have a strong global market share in the PTA and acetic markets with a major manufacturing presence in Asia, particularly China. PX is a feedstock for PTA production.
          In O&D, we manufacture ethylene and propylene from naphtha and also produce a number of downstream derivative products.
          Our O&D business has operations in both China and Malaysia. In China, our SECCO joint venture between BP, Sinopec and its subsidiary, Shanghai Petrochemical Company is the largest foreign-invested olefins cracker in China. SECCO is BP’s single largest investment in China. This naphtha cracker produces ethylene and propylene plus derivatives acrylonitrile, polyethylene, polypropylene, styrene, polystyrene, and other products. In Malaysia, BP participates in two joint-ventures: Ethylene Malaysia Sdn. Bhd. (EMSB), which produces ethylene from gas feedstock in a joint venture between BP, Petronas and Idemitsu; while Polyethylene Malaysia Sdn. Bhd. (PEMSB) produces polyethylene in a joint venture between BP and Petronas. Each of these ventures has demonstrated a strong track record of project delivery and performance. BP also owns one other naphtha cracker outside Asia, which is integrated with our Gelsenkirchen refinery in Germany.
          The following table shows BP’s petrochemicals production capacity at 31 December 2008. This production capacity is based on the original design capacity of the plants plus expansions.
BP share of capacity
                                                 
 
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  
   
During 2008, the environment in which our petrochemicals businesses operate became more challenging as deterioration in the global economic environment has led to a reduced demand for our products.
Significant events in petrochemicals were as follows:
  The second PTA plant at the BP Zhuhai Chemical Company Limited site in Guangdong province (China) successfully completed commissioning in the first quarter of 2008. This 900+ ktepa plant is the single largest PTA manufacturing train in the world and employs BP’s latest, proprietary technology.
 
  Construction continued on the new 500ktepa acetic acid plant in Jiangsu province (China) by BP YPC Acetyls Company (Nanjing) Limited (BYACO). This is a BP joint venture with Yangzi Petrochemical Co. Ltd (a subsidiary of Sinopec). Construction is scheduled to be completed in June 2009 with commercial sales expected to begin in the third quarter of 2009.
 
  Commissioning of our expanded Geel (Belgium) PTA facility commenced at the end of 2008. The 350ktepa expansion improves overall operating costs and increases the site’s PTA capacity to 1,425ktepa.
 
  In January 2008, BP and Sinopec signed a memorandum of understanding to add a new acetic acid plant at their Yangtze River Acetyls Co. (YARACO) joint venture site in Chongqing (China). This world-scale (650ktepa) acetic acid plant will use BP’s leading Cativa™ technology. The expected plant start-up date, which was originally anticipated to be during 2011, is under review due to the market conditions. When complete, total production at the YARACO site is expected to be well over one million tonnes per annum, making this one of the largest acetic acid production locations in the world.
Aviation and marine fuels
Air BP is one of the world’s largest and best known aviation fuels suppliers, serving all the major commercial airlines as well as the general aviation and military sectors. During 2008, which was a tough year for the aviation industry, we simplified our geographical footprint by exiting non-core countries and now supply customers in approximately 70 countries. We have annual marketing sales in excess of 27 billion litres and we have relationships with many of the world’s major commercial airlines. Air BP’s strategic aim is to grow its position in the core locations of Europe, the US, Australasia and the Middle East, while focusing its portfolio towards airports that offer long-term competitive advantage. BP’s marine fuels business focuses on the distribution and sale of refined fuel oils to the shipping industry at locations in more than 100 ports across the world. During 2008, this business performed well, supported by strong growth in the shipping market.
LPG
The LPG business sells bulk, bottled, automotive and wholesale LPG products to a wide range of customers in 13 countries. During the past few years, our LPG business has consolidated its position in established markets, pursued opportunities in new and emerging markets such as China and announced the exit from the Vietnam market in December 2008. LPG product sales in 2008 were approximately 68mbpd.


32


 

Performance review
 

Other businesses and corporate
Other businesses and corporate comprizes Treasury (which includes interest income on the group’s cash and cash equivalents) and corporate activities worldwide, the group’s aluminium asset, the Alternative Energy business and Shipping.
          Comparative information presented in the table below has been restated, where appropriate, to reflect the resegmentation, following transfers of businesses between segments, that was effective from 1 January 2008. See page 12 for more details.
Key statistics
                         
 
                    $ million  
   
    2008     2007     2006  
 
Total revenuesa
    5,040       3,972       3,703  
Profit (loss) before interest and tax from continuing operationsb
    (1,258 )     (1,233 )     (779 )
Total assets
    19,079       20,595       16,315  
Capital expenditure and acquisitions
    1,839       939       852  
   
 
aIncludes sales between businesses.
 
bIncludes profit after interest and tax of equity-accounted entities.
Treasury
Treasury co-ordinates the management of the group’s major financial assets and liabilities. From locations in the UK, the US and the Asia Pacific region, it provides the link between BP and the international financial markets and makes available a range of financial services to the group, including supporting the financing of BP’s projects around the world.
Insurance
The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the group. Losses are therefore borne as they arise, rather than being spread over time through insurance premiums with attendant transaction costs. This position is reviewed periodically.
Aluminium
Our aluminium business is a non-integrated producer and marketer of rolled aluminium products, headquartered in Louisville, Kentucky, US. Production facilities are located in Logan County, Kentucky, and are jointly owned with Novelis. The primary activity of our aluminium business is the supply of aluminium coil to the beverage can business, which it manufactures primarily from recycled aluminium.
Alternative Energy
BP invested $1.4 billion in our Alternative Energy business during 2008, bringing the total investment in this business to $2.9 billion since its launch in 2005. We expect to fulfil our original 2005 commitment to invest a total of $8 billion over 10 years. In 2008, we prioritized four areas with significant long-term growth potential – wind, solar, biofuels and carbon capture and storage (CCS). We have also developed a fifth area – gas-fired power – that offers synergies with other BP operations. We have concentrated our 2008 investment in these areas.
                         
 
    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 the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities. The equivalent capacities on a gross-JV basis (which includes 100% of the capacity of equity-accounted entities where BP has partial ownership) were 785MW in 2008, 373MW in 2007 and 43MW in 2006.
 
b Solar capacity is the theoretical cell production capacity per annum of in-house manufacturing facilities.
Wind
Since the launch of Alternative Energy we have substantially grown our wind portfolio, increasing from 32 megawatts (MW) in operation to 432MW (785MW gross) at the end of 2008. In total, we have more than 500MW (1,000MW gross) of installed capacity. This increase in capacity was led by the US with installations at Cedar Creek, Silver Star, Sherbino and Edom Hills.
          To accelerate our growth in the US wind energy market, we acquired two fully integrated wind power development companies – Greenlight Energy Inc. and Orion Energy LLC, during 2006. To secure the continuing availability of turbines we have signed agreements with Nordex (Germany) and GE (the US) for a combined 900MW to be delivered during the next two years. This is in addition to a five-year wind turbine contract we previously signed with Clipper Windpower Inc. in 2006.
          We also operate wind farms in the Netherlands and in Maharashtra, India.
Solar
We continued to implement BP Solar’s strategy to invest in lower cost manufacturing and technology to enable energy sourced from our products to compete with conventional electricity. Our global business model spans the entire solar ‘value chain’ – from the acquisition of silicon as a raw material, the production of wafers and cells to the creation of solar panels that are then sold and distributed as solar systems on the roofs of residential homes, large commercial buildings and on vacant land.
          Today, BP Solar’s main production facilities are located in Maryland (US), Madrid (Spain), Xi’an (China) and Bangalore (India). During 2008, due to increasingly competitive market conditions, BP Solar announced plans to refocus operations at larger scale plants to achieve lower-cost manufacturing. This resulted in the start of an intensive programme of operational efficiency improvement in the remaining BP Solar plants and plans to close our manufacturing plant in Australia. During 2008, BP Solar signed contracts with a select set of third-party strategic partners in Asia who specialize in the production of low-cost, high-quality wafers, cells and modules.
          During 2008, BP Solar achieved sales of 162MW, an increase of 41% from 115MW in 2007. The slight decrease in solar production capacity was due to fire damage in a section of our manufacturing plant in India.


33


 

Performance review
 

More than 70% of our sales volume is through third-party distributors in the residential markets in Europe, the US and Australasia. We have continued to roll out our Certified Installer Programme (CIP), first established in Germany, to ensure the safe, high-quality installation of products by third parties. The CIP has grown rapidly in Germany and this year has been rolled out in Spain and Australia.
          In the US, in 2008, we continued to supply large corporations with sustainable energy solutions, completing a second solar system for FedEx Freight in California and a further six installations for Wal-Mart. In Europe, we expanded the relationship with Banco Santander to jointly build and finance a number of solar plants in Spain, with the construction of an 8 megawatts-peak (MWp) solar farm in Toledo and a 6MWp project in Tenerife. In Asia, we completed the installation of a solar power demonstration project (SolarSail) at the Guangdong Science Center; the SolarSail absorbs sunlight to produce power, while providing cool shade for visitors. In Australia, the largest roof-top solar system (100 kilowatt) in New South Wales commenced operation in February 2008, representing the first commercial solar power installation for the Blacktown Solar City Project. The Solar Cities Programme is a government initiative to implement distributed solar and other energy efficient technologies in seven Australian cities.
          We are developing a new silicon growth process named Mono2 TM, which will increase cell efficiency over traditional multicrystalline-based solar cells. We have moved from a prototype to low-volume production and have converted our casting stations in Frederick, Maryland, delivering 1.2MW Mono2 TM. From the trials, we are seeing significant improvement in power and generated kWh when compared with multicrystalline-based solar cells particularly when modules are used where sunlight is low.
          BP Solar has long-term relationships with world-class universities and invests in research programmes with organizations including the University of Delaware, California Institute of Technology (Cal Tech) and the Fraunhofer Institute (Germany). BP Solar was selected for the Solar America Initiative (SAI) award from the US Department of Energy – a $40-million research and development programme aimed at decreasing the cost of solar cells and increasing their efficiency. BP Solar is also a member of the broad consortium led by DuPont in conjunction with the University of Delaware, funded by the Defense Advanced Research Projects Agency (DARPA), to develop high-efficiency solar cells.
Biofuels
BP has a key role to play in enabling the transport sector to respond to the dual challenges of energy security and climate change. Our investments are focused on sustainable feedstocks that minimize pressure on food supplies and on research into advanced technologies and practices to make good biofuels even better.
          We have embarked on a focused programme of biofuels development based around the most efficient transformation of sustainable and low-cost sugars into a range of fuel molecules. These include bioethanol from Brazilian sugar cane, more efficient fuel molecules like biobutanol and advanced biofuels like lignocellulosic bioethanol produced from non-food energy grasses and ‘for-purpose’ feedstocks such as miscanthus and energy cane.
          BP has announced it has plans to invest in excess of $1 billion in building our own biofuels business operations, including partnerships with other companies to develop the technologies, feedstocks and processes required to produce advanced biofuels.
These investments include: a 50% stake in Tropical BioEnergia, a joint venture with Santelisa Vale and Maeda Group, to produce bioethanol from sugar cane; and a $90-million investment and strategic alliance with Verenium Corporation to accelerate the development and commercialization of biofuels produced from lignocellulosic bioethanol. We have been working with DuPont since 2003 to explore new approaches to the development of biofuels. The first product from this collaboration will be an advanced fuel molecule called biobutanol, which has a higher energy content than ethanol. We have partnered with ABF (British Sugar) and DuPont to construct a world-scale biofuels plant in Hull.
          Innovation begins with research. In 2006, we announced plans to invest $500 million over 10 years in the Energy Biosciences Institute (EBI), at which biotechnologists are investigating applications of biotechnology to energy, including advanced fuels. This amount is incremental to the $1 billion of investments mentioned above. Our partners are the University of California, Berkeley and the University of Illinois at Urbana Champaign and the Lawrence Berkeley National Laboratory. The EBI is focusing on the integrated development of better crops, better processing technologies and better biofuels, leading to cleaner energy.
Hydrogen power
In May 2007, BP and Rio Tinto announced the formation of a new jointly owned company, Hydrogen Energy International Limited, which will develop decarbonized energy projects around the world. The venture will initially focus on hydrogen-fuelled power generation, using fossil fuels and CCS technology to produce new large-scale supplies of clean electricity.
          Hydrogen Energy is working on developing low-carbon power plants with projects in Abu Dhabi and California – manufacturing hydrogen for power generation. In both instances, the captured CO2 will be transported to nearby oil fields for use in enhanced oil recovery, with the CO2 stored deep underground. General Electric and BP have formed a global alliance to jointly develop and deploy technology for hydrogen power plants that could significantly reduce emissions of the greenhouse gas CO2 from electricity generation.
          Through these initiatives, BP intends to continue to shape the development of the CCS value chain and to seek to minimize the carbon footprint exposure of the BP group as carbon pricing and policy develops globally.
Gas-fired power
Our gas-fired power activities comprise modern combined cycle gas turbine plants, which emit around 50% less CO2 than a conventional coal plant of the same capacity, and several low-carbon co-generation gas power facilities. We have stakes in eight plants worldwide and this year increased the total power they are capable of producing from 5GW to 6GW and, where possible, we integrate plants with other BP production facilities. The Whiting Clean Energy facility, acquired in July 2008, now provides a reliable source of steam for our Whiting refinery and we are adding a 250MW steam turbine to our existing plant at our Texas City refinery. Our combined cycle plants are providing base-load demand for BP’s major upstream gas production developments.


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Shipping
We transport our products across oceans, around coastlines and along waterways, using a combination of BP-operated, time-chartered and spot-chartered vessels. All vessels conducting BP activities are subject to our health, safety, security and environmental requirements.
International fleet
At the end of 2008, we had an international fleet of 54 vessels (37 medium-size crude and product carriers, four very large crude carriers, one North Sea shuttle tanker, eight LNG carriers and four LPG carriers). All these ships are double-hulled. Of the eight LNG carriers, BP manages one on behalf of a joint venture in which it is a participant and operates seven LNG carriers.
Regional and specialist vessels
In Alaska, during 2008, we redelivered one of our time-chartered vessels back to the owner, leaving a fleet of four double-hulled vessels. In the Lower 48, the two remaining heritage Amoco barges were phased out of BP’s service. Outside the US, at the end of 2008, we had 14 specialist vessels (two double-hulled lubricants oil barges and 12 offshore support vessels).
Time-charter vessels
At the end of 2008, BP had 115 hydrocarbon-carrying vessels above 600 deadweight tonnes on time-charter, of which 107 are double-hulled and one is double-bottomed. All these vessels participate in BP’s Time Charter Assurance Programme.
Spot-charter vessels
BP spot-charters vessels, typically for single voyages. These vessels are always vetted for safety assurance prior to use.
Other vessels
BP uses various craft such as tugs, crew boats and seismic vessels in support of the group’s business. We also use sub-600 deadweight tonne barges to carry hydrocarbons on inland waterways.
Maritime security issues
2008 has seen a significant escalation in piracy activity, specifically off the north coast of Somalia. At a strategic level, BP avoids known areas of pirate attack or armed robbery; where this is not possible for trading reasons and we consider it safe to do so, we will continue to trade vessels through areas of known piracy, subject to the adoption of heightened security measures. BP will continue to route vessels through the Gulf of Aden for as long as it considers it to be safe to do so, having regard to available military and government agency advice. At present, we are following such advice and are participating in protective group transits through the Gulf of Aden Maritime Security Patrol Area transit corridor.


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Performance review
 

Research and technology
Research and technology (R&T) has a critical role to play in addressing the world’s energy challenges, from fundamental research through to wide-scale deployment. The full breadth of these R&T activities is carried out by each of the business segments. We also conduct long-term research within the central R&T group.
          Inside the segments, research and technology activities are in service of competitive business performance and new business development, through the research, development or acquisition of new technologies. The central R&T group provides leadership for scientific and technological activities throughout the group and, in particular, provides input to the group’s long-term strategy. It ensures that the right capability is in place in critical areas and ensures the quality of BP’s major technology programmes. It also illuminates the potential of emerging technologies and conducts research and development (R&D) in support of BP’s long-term corporate renewal. In addition, a group of eminent industrialists and academics forms the Technology Advisory Council, which advises the board and executive management on the state of research and technology within the group and helps to identify current trends and future developments in technology.
          Research and development (R&D) is carried out using a balance of internal and external resources. Involving third parties in the various steps of technology development and application enables a wider range of ideas and technologies to be considered and implemented, improving the impact of research and development activities.
          Across the group, expenditure on R&D for 2008 was $595 million, compared with $566 million in 2007 and $395 million in 2006. See Financial statements note 15 on page 130. The 5% increase in 2008 compared with 2007 reflects increased investment in biosciences, conversion and carbon capture and storage technologies.
          Beyond R&D, we also invest in technologies to get them to the point of commercial readiness: this includes field trials, support for technology deployment, specialist technical services and central investment in functional excellence and capability development have deepened our current areas of technology leadership.
          In our Exploration and Production segment, we have organized leading technologies under 10 flagship programmes, each with the potential to add more than 1 billion boe to reserves through their development and deployment in our assets worldwide. These technologies contributed to exploration and production success in Algeria, Angola, Azerbaijan, Egypt, the North Sea and the Gulf of Mexico deepwater. Our advanced seismic imaging expertise, which is one of these programmes, continues to lead the industry, pioneering new wide-azimuth seismic acquisition and processing in deepwater Angola, Egypt and the Gulf of Mexico. In addition, BP has developed new technologies that have significantly reduced the time needed for land seismic acquisition in Oman, and these are now being deployed in Libya. Our enhanced oil recovery technologies are pushing recovery factors to new limits. For example, recovery factors have already increased from 40% to 60% in Alaska, where BP operates the world’s largest miscible gas enhanced oil recovery project. BP also leads the industry in the application of new inter-well polymer treatments aimed at improving waterflood recovery, with more than 25 treatments delivering an increase of around five million barrels. Also in Alaska, BP’s first hexalateral well came online in 2008 in the Orion field, which is capable of producing 9,500 barrels of oil per day – the largest producer in BP’s operations on the North Slope; while our first well using cold heavy oil production with sand (CHOPS) technology began producing heavy oil at a production rate of 100 barrels of oil per day. Unconventional gas is another area of focus; for example, using new technologies, BP has drilled in 17 unconventional coalbed methane basins around the world, including some of the largest reservoirs in North America. Another flagship programme is our use of digital technologies to optimize production and improve recovery, where BP has established an industry-leading position. In 2008, BP’s oil and gas
operations, enabled by real-time data and Field-of-the-Future® technologies delivered an extra 30,000 to 50,000 boepd gross production. Also in 2008, as part of its Inherently Reliable Facilities flagship, BP completed a field trial of a new fibre-optic system that represents a step-change in onshore pipeline monitoring, and which will now be deployed in Azerbaijan, Canada and Scotland.
          In our Refining and Marketing segment, technology advancements are enabling our refineries to understand and process feedstocks of varying quality and optimize our assets in real time, enhancing the flexibility and reliability of our refineries and, in turn, improving the margins of our existing asset base. In 2008, BP began upgrading its Whiting refinery in Indiana to process heavy crude oil from Canada using one of the industry’s most technologically advanced coking operations. In Naperville, US, we opened a new refining R&D centre, installing more than 50 new pilot units at the forefront of experimental technology and modelling. We have installed predictive analytics technology for fault detection and prediction on critical machinery across seven of our refineries reducing losses from machinery failure. BP’s leading technologies in fuels and lubricants mean that it can keep ahead of increasingly stringent regulations, balancing greater fuel efficiency and performance and developing superior formulations across its entire product slate. For example, our BP Ultimate fuels deliver performance benefits such as improved fuel economy, lower emissions and a cleaner engine; and we have launched Greendeck and Greenfield, a suite of high-performance and environmentally friendly marine and offshore lubricants. Our proprietary processing technologies and operational experience continue to reduce the manufacturing costs and environmental impact of our petrochemicals plants, helping to maintain competitive advantage. For example, our new 900ktepa purified terephthalic acid (PTA) plant in Zhuhai, China was officially opened in 2008, occupying a plot just half the size of its older, neighbouring plant, but with double the production capacity. In the field of conversion technology, our Nikiski Fischer-Tropsch demonstration plant in Alaska operated at levels to prove that we have a working catalyst at industrial scale.
          In Alternative Energy, our low-carbon research and technology activity continues apace. In 2008, we filed patents covering biofuels, carbon capture and storage (CCS), and hydrogen membranes. Our solar business produced the first prototype of a cut-cell high voltage module, giving a 5% increase in power over conventional modules. Working as part of the UK’s Energy Technologies Institute – a public/private partnership to accelerate low-carbon technology development – BP is proceeding with investments in projects to develop new offshore wind and marine turbines. We also published results of the satellite monitoring programme, verified by well and tracer detection, of the CCS project at the In Salah gas field in Algeria with our partners Sonatrach.
          Collaboration plays an important role across the breadth of BP’s research and development activities, but particularly in those areas that benefit from fundamental scientific research. BP has 11 significant long-term research programmes with major universities and research institutions around the world, exploring areas from energy bioscience and conversion technology to carbon mitigation and nanotechnology in solar power. In 2008, our Energy Biosciences Institute at Berkeley (see page 34) became fully operational, with 49 research projects, all focused on lignocellulosic biofuel production; we announced the renewal of our Carbon Mitigation Initiative at Princeton; and signed the joint venture agreement for the Clean Energy Commercialisation Centre with the Chinese Academy of Sciences.


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Regulation of the group’s business
BP’s activities, including its oil and gas exploration and production, pipelines and transportation, refining and marketing, petrochemicals production, trading, alternative energy and shipping activities, are conducted in many different countries and are therefore subject to a broad range of EU, US, international, regional and local legislation and regulations, including legislation that implements international conventions and protocols. These cover virtually all aspects of our activities and include matters such as licence acquisition, production rates, royalties, environmental, health and safety protection, fuel specifications and transportation, trading, pricing, anti-trust, export, taxes and foreign exchange.
          The terms and conditions of the leases, licences and contracts under which our oil and gas interests are held vary from country to country. These leases, licences and contracts are generally granted by or entered into with a government entity or state company and are sometimes entered into with private property owners. These arrangements with governmental or state entities usually take the form of licences or production-sharing agreements. Arrangements with private property owners are usually in the form of leases.
          Licences (or concessions) give the holder the right to explore for and exploit a commercial discovery. Under a licence, the holder bears the risk of exploration, development and production activities and provides the financing for these operations. In principle, the licence holder is entitled to all production, minus any royalties that are payable in kind. A licence holder is generally required to pay production taxes or royalties, which may be in cash or in kind. Less typically, BP may explore for and exploit hydrocarbons under a service agreement with the host entity in exchange for reimbursement of costs and/or a fee paid in cash rather than production.
          PSAs entered into with a government entity or state company generally require BP to provide all the financing and bear the risk of exploration and production activities in exchange for a share of the production remaining after royalties, if any.
          In certain countries, separate licences are required for exploration and production activities and, in certain cases, production licences are limited to a portion of the area covered by the exploration licence. Both exploration and production licences are generally for a specified period of time (except for licences in the US, which typically remain in effect until production ceases). The term of BP’s licences and the extent to which these licences may be renewed vary by area.
          Frequently, BP conducts its exploration and production activities in joint venture with other international oil companies, state companies or private companies.
          In general, BP is required to pay income tax on income generated from production activities (whether under a licence or production-sharing agreement). In addition, depending on the area, BP’s production activities may be subject to a range of other taxes, levies and assessments, including special petroleum taxes and revenue taxes. The taxes imposed on oil and gas production profits and activities may be substantially higher than those imposed on other activities, particularly in Angola, Norway, the UK, Russia, South America and Trinidad & Tobago.
          For a discussion of environmental and certain health and safety regulations and environmental proceedings, see Environment on page 39. See also Legal proceedings on page 88.
Safety
This section reviews BP’s safety performance in 2008.
          There were five workforce fatalities in 2008, compared with seven in 2007. One resulted from fatal injuries sustained during operations at our Texas City refinery; one was the result of a fall from height at the Tangguh operations in Indonesia; one fatality was on a land farm near Texas City, and two were driving fatalities incidents in Mozambique and South Africa. We deeply regret this loss of life. By learning from these incidents and implementing appropriate improvement actions, we continue to seek to secure the safety of all members of our workforce. Our workforce reported recordable injury frequency, which measures the number of injuries per 200,000 hours worked, was 0.43 in 2008. This was a good improvement on the rate of 0.48 recorded in both 2007 and 2006.
          Throughout 2008, senior leadership across the group continued to hold safety as their highest priority. Site visits, in which safety was a focus, were undertaken by the group chief executive (GCE) and members of the executive team to reinforce the importance of their commitment to safe and reliable operations.
Management systems
We continue to implement our new operating management system (OMS), a framework for operations across BP that is integral to improving safety and operating performance in every site.
          When fully implemented, OMS will be the single framework within which we will operate, consolidating BP’s requirements relating to process safety, environmental performance, legal compliance in operations, and personal, marine and driving safety. It embraces recommendations made by the BP US Refineries Independent Safety Review Panel (the panel), which reported in January 2007 on safety management at our US refineries and our safety management culture.
          The OMS establishes a set of requirements, and provides sites with a systematic way to improve operating performance on a continuous basis. BP businesses implementing OMS must work to integrate group requirements within their local system to meet legal obligations, address local stakeholder needs, reduce risk and improve efficiency and reliability. A number of mandatory operating and engineering technical requirements have been defined within the OMS, to address process safety and related risks.
          All operated businesses plan to transition to OMS by the end of 2010. Eight sites completed the transition to OMS in 2008; two petrochemicals plants, Cooper River and Decatur, two refineries, Lingen and Gelsenkirchen and four Exploration and Production sites, North America Gas, the Gulf of Mexico, Colombia and the Endicott field in Alaska. Implementation is continuing across the group and a number of other sites, including all refineries not already operating the OMS, are expected to complete the transition in 2009.
          For the sites already involved, implementing OMS has involved detailed planning, including gap assessments supported by external facilitators. A core aspect of OMS implementation is that each site produces its own ‘local OMS’, which takes account of relevant risks at the site and details the site’s approach to managing those risks. As part of its transition to OMS, a site issues its local OMS handbook, and this summarizes its approach to risk management. Each site also develops a plan to close gaps that is reviewed annually. The transition to OMS, at local and group level, has been handled in a formal and systematic way, to ensure the change is managed safely and comprehensively.


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Experience so far has supported our expectation that having one integrated and coherent system brings benefits of simplification and clarity, and that the process of change is supporting our renewed commitment to safe operations.
          We are on track to meet our target of implementing OMS across the group by the end of 2010.
Capability development
In addition to ongoing training programmes we are undertaking a group wide programme to enhance the capability of our staff from front line to executive level to deliver operational excellence.
          Almost 1,000, around a third, of our front-line supervisors have started the Operating Essentials programme, which includes training on leadership, process safety, operating culture, practices and coaching and effective performance conversations.
          More than 190, around half, of our operations leaders started the Operations Academy programme in 2008. The academy, which has been established in partnership with the Massachusetts Institute of Technology (MIT), provides participants with a total of six weeks of operations training, concentrating on the management of change and continuous improvement.
          The Executive Operations programme, which seeks to increase insight into manufacturing and operation activities among senior business leaders, has built on its successful launch with the first group, which included the group chief executive and his executive team. By the end of 2008, 99 executives had attended the three-day programme.
          In addition, new cadres of projects and engineering staff have progressed through the Project and Engineering Academy at MIT and 13 process safety courses have been delivered for project and project engineering managers at the Project Management College. We have continued to develop training on hazard evaluation and risk assessment techniques for all engineers, operators and HSSE professionals.
Process safety management
We remain fully committed to becoming a recognized industry leader in process safety management and are working to achieve this. We have taken a range of steps, including acting on the recommendations from both the panel and those within the first annual report of the independent expert.
          Our actions can be summarized in three principal areas:
  We have made progress in reducing process safety risk at our US refineries. For example, we have completed and learned from safety and operations audits, relocated workers to lower-risk accommodation and implemented fatigue reduction programmes.
 
  Executive management has taken a range of actions to demonstrate their leadership and commitment to safety. The group chief executive has consistently emphasized that safety, people, and performance are our top priority, a belief made clear in his 2007 announcement of a forward agenda for simplification and cultural change in BP. Safety performance has been scrutinized by the Group Operations Risk Committee (the GORC), chaired by the group chief executive and tasked with assuring the group chief executive that group operational risks are identified and managed appropriately. We continued to build our team of safety and operations auditors. A team of 45 auditors is now in place, with 36 audits completed in 2008.
 
  Many of the process-safety related improvements recommended by the panel are being implemented across the group through the OMS. The group essentials within the OMS (which cover diverse aspects of operating activity including legal compliance, process and environmental safety and basic operating practices) in some cases go beyond the panel’s process safety recommendations, a point noted by the independent expert in his first report.
In addition to action in these areas, we have continued to participate in industry-wide forums on process safety and have made efforts to share our learning with other organizations.
          The independent expert has been tasked with reporting to the board on BP’s progress in implementing the panel’s recommendations. We welcome the independent expert’s view expressed in his first report (May 2008) that BP ‘appears to be making substantial progress in changing culture and addressing needed process safety improvements’. However, we also acknowledge his observation that ‘a significant amount of work remains to be done on the process safety journey’ and that ‘successful completion of the task will require the continued support and involvement of the board, executive management, and refinery leadership along with a sustained effort over an extended period of time’. The independent expert’s second report is expected in the first half of 2009.
Operational integrity
We continue to implement the six-point plan launched in 2006 to address immediate priorities for improving process safety and minimizing risk at our operations worldwide.
          We have met our commitment to remove occupied portable buildings (OPBs) from high-risk zones within onshore process plant areas and to remove all blow-down stacks in heavier-than-air, light hydrocarbon service. All major sites and our fuels value chains have completed major accident risk assessments, which identify major accident risks and develop mitigation plans to manage and respond to them.
          We continue to implement the Control of Work and Integrity Management standards. We have made progress in ensuring our operations meet the requirements of a group framework designed to ensure we stay in compliance with legal requirements on health and safety. We are continuing to take steps to close out past audit actions. Leadership competency assessments, which involve assessment of the experience of BP management teams responsible for major production sites or manufacturing plant, have been completed in Exploration and Production and in all major Refining and Marketing manufacturing sites.
          Implementation of these actions is expected to be largely complete by the end of 2009, with some aspects of implementation being incorporated into the transition to the OMS, expected to be completed by the end of 2010. The GORC regularly monitors progress against the plan.
          We monitor and report separately on major incidents such as those covering fatal accidents, significant property damage or significant environmental impact. We also track and analyze ‘high potential’ incidents – those that could have resulted in a major incident. All major incidents and many high-potential incidents are discussed by the GORC and we continue to seek to learn as much as possible from each incident.
          A total of 21 major incidents were reported in 2008. Two of the major incidents were related to hurricanes and eight were related to driving incidents.
          There were 335 oil spills of one barrel or more in 2008, similar to 2007 performance of 340 oil spills. The volume of oil spilled in 2008 was approximately 3.5 million litres, an increase of 2.5 million litres, compared with 2007. This was largely the result of two incidents, one at Texas City and one at the Whiting refinery, which accounted for two-thirds of the total reported volume of oil spilled, the great majority of which remained contained and the oil recovered.


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Performance indicators
We have well-developed systems, processes and metrics for reporting personal safety and environmental metrics that support internal performance management as well as public reporting.
          We introduced several new metrics in 2008 that aim to enhance our monitoring of process safety performance within BP’s operating entities. These include, for example, a process safety incident index, as recommended by the panel, which uses weighted severity scores to record and assess process safety events, and a measure to record any loss of hydrocarbon from primary containment.
          Our indicators include industry-aligned ‘lagging’ process safety metrics that register events that have already occurred, and ‘leading’ indicators that focus on the strength of our controls to prevent undesired events in future. A suite of indicators is regularly reported to the GORC within the quarterly ‘HSE and Operations Integrity Report’ and several new metrics have also been piloted. To further enhance the management of health risks across the group, we began the systematic reporting of recordable illness rates within the HSE and Operations Integrity Report. We continue to work with industry bodies such as the Centre for Chemical Process Safety and the American Petroleum Institute on the development of process safety metrics, definitions and guidance.
Continuing to focus on health
In addition to our efforts to improve process safety performance, we strive to protect the personal health and safety of our workforce, recognizing that healthy performance is delivered through healthy people, healthy processes and healthy plant.
          In the course of 2008, we defined health ‘group essentials’, which specify requirements designed to prevent harm to the health of employees, contractors, visitors and local communities. These were incorporated within the OMS framework. Our health strategy and plan was also refreshed in 2008. Priorities include reducing significant occupational exposure and infectious disease risks, maintaining robust regulatory compliance in product health and safety and addressing the issue of fatigue management raised by the panel by providing training and awareness-raising.
Environment
Regulation and claims
We are subject to extensive international, national, state and local environmental regulations concerning our products, operations and activities. Current and proposed fuel and product specifications, emission controls and climate change programmes under a number of environmental laws will have a significant effect on the production, sale and profitability of many of our products. Environmental laws also require us to remediate the environmental impacts of prior disposal or releases of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various locations where products are, or have been, produced, processed, stored, distributed, sold or disposed of, such as refineries, chemical plants, natural gas processing plants, oil and natural gas fields, service stations, terminals and waste disposal sites. Some of these obligations relate to prior asset sales or closed facilities. Provisions for environmental restoration and remediation are made when a clean-up is probable and the amount of the obligation can be reliably estimated. Generally this coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provisions made are considered by management to be sufficient to meet known requirements.
          The extent and cost of future environmental restoration, remediation and abatement programmes are often inherently difficult to estimate. They often depend on the extent of contamination, and the associated impact and timing of the corrective actions required, technological feasibility and BP’s share of liability. Though the costs of future programmes could be significant and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will be material to the group’s overall results of operations or financial position or liquidity. See Financial statements – Note 37 on page 156 for the amounts provided in respect of environmental remediation and decommissioning.
          We are also subject to environmental and common law claims for personal injury and property damage alleging the release or exposure to hazardous substances. A number of proceedings involving governmental authorities are pending or known to be contemplated against BP and certain of its subsidiaries under federal, state or local environmental laws, each of which could result in monetary sanctions of $100,000 or more. No individual proceeding is, nor are the proceedings in aggregate, expected to be material to the group’s results of operations or financial position.
          We cannot accurately predict the effect of future developments, such as stricter environmental laws or enforcement policies on the group’s operations, products or profitability. A risk of increased environmental costs and operational impacts is inherent in grouping our businesses and there can be no assurance that material liabilities and costs will not be incurred in the future. We believe that the group’s activities are in material compliance with applicable environmental laws and regulations, or that the group has disclosed such non-compliance and is working with the relevant regulatory authorities to ensure compliance. For a discussion of the group’s environmental expenditure see page 53.
          BP operates in more than 90 countries worldwide. In each of these areas, BP has, or is developing, processes designed to ensure compliance with applicable regulations. In addition, each employee is required to comply with BP health, safety and environmental policies as embedded in the BP code of conduct. Our partners, suppliers and contractors are also encouraged to adopt them.
          This Environment section focuses primarily on the US and the EU, where around 61% of our fixed assets are located, and on issues of a global nature such as our operations and the environment, climate change programmes and maritime oil spills regulations.
Our operations and the environment
During 2008, we continued to use environmental management systems to seek improvements on a wide range of environmental issues. Except at two locations, the operations at our major operating sites are covered


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Performance review
 

by certification to the ISO 14001 international environmental management system standard. The Texas City refinery, after completing planned work to strengthen its environmental management systems, is planning to seek recertification in 2009. Our Angola business is working towards an expansion of its existing ISO 14001 certificate to include its offshore production facilities by the end of 2009. Progressive implementation of the Operating Management System (OMS), including ISO 14001, will also help us strengthen our management of environmental performance.
          In support of ongoing risk management, one element of the OMS applies, at least annually, a formal systematic process to identify and assess risks; this process provides to identify emerging issues including those with an environmental impact. To assist us in measuring the effectiveness of our risk mitigation actions we have established environmental metrics, which are available within BP Sustainability Report 2008, at www.bp.com/sustainability. The 2008 information is planned to be available in conjunction with the publication of our 2008 Sustainability Report.
          After two years of implementation, our Environmental Requirements for New Projects (ERNP) practice has been updated in line with the OMS. We have simplified applicability, clarified the governance process and updated the text to reflect organizational changes. This practice, now called the Environmental Group Defined Practice (GDP) is a full life cycle environmental assessment process. It requires all new major projects and projects in sensitive areas, to undertake screening to determine the potential environmental sensitivities associated with the proposed projects. Requirements and project recommendations now extend to include appropriate considerations for decommissioning of assets. A new project with the highest level of environmental sensitivity requires more rigorous and specific environmental management activities. The board-appointed Safety, Environment and Ethics Assurance Committee reviewed the progress of ERNP during summer 2008. This review included the 12 projects that have been classified as requiring management at the highest level of sensitivity. We are currently integrating social considerations into the Environmental GDP and plan to issue this in 2009 as an integrated set of requirements addressing social and environmental issues.
          In 2008, BP used the ERNP to review risks and establish mitigation measures prior to entry in connection with the decision to develop adjacent to a Protected Area at Hamble Oil Terminal in the UK. We intend to make a summary of the risk assessment publicly available at the end of April 2009.
          Our focus on asset decommissioning is demonstrated by the North West Hutton offshore platform project in the North Sea. 2008 saw the topsides of the North West Hutton platform safely brought onshore for further dismantling. This decommissioning is expected to result in 20,000 tonnes of recycled steel, in line with our aim to have 97% of the decommissioned materials recycled and/or reused.
          We seek to limit the environmental impact of our operations by using resources responsibly and reducing waste and emissions.
Climate change programmes
In response to rising concerns about climate change, governments continue to identify fiscal and regulatory measures at local, national and international levels.
          In December 1997, at the Third Conference of the Parties to the United Nations Framework Convention on Climate Change (UNFCCC) in Kyoto, Japan, the participants agreed on a system of differentiated international legally-binding targets for the first commitment period of 2008-2012. In 2005, the Kyoto protocol came into force, committing the 176 participating countries to emissions targets. However, Kyoto was only designed as a first step and policymakers continue to discuss what new agreement might follow it after 2012, most recently at the UNFCCC conference in Poznan, Poland in December 2008.
          Many of our larger EU stationary assets are subject to the EU Emissions Trading Scheme (EU ETS), which was extended to Norway by
reciprocal agreement. After inclusion of our Norwegian assets, around one-fifth of our reported 2008 global CO2 emissions are now covered by this scheme.
          At the March 2007 European Council, the European Heads of Government decided to adopt their Climate Action and Renewable Energy Package. This legislation was voted through by the European Parliament in December 2008. The package includes a commitment to reduce greenhouse gas (GHG) emissions by 20% by 2020 (the target being 30% if an international agreement is reached), as well as an improved energy efficiency within the EU Member States of 20% by 2020 and a 20% renewable energy target by 2020.
          The Australian government has set a target to reduce GHG emissions by 60% below 2000 levels by 2050. In December 2008, the Australian government released its Carbon Pollution Reduction Scheme White Paper, outlining the design of an emissions trading scheme that will go into effect in mid-2010; draft legislation is expected in early 2009. The Australian government proposes to cover 70% of emissions sources and sectors via a combination of direct obligations on facilities with large emissions, and obligations on upstream fuel suppliers for the emissions resulting from the combustion of fuel. In December the government also announced 2020 GHG emission targets that range from a 5 to 15% reduction from 2000 levels. The scheme builds on the existing National Greenhouse and Energy Reporting System, the Australian mandatory reporting system for corporate greenhouse gas emissions and energy production and consumption. The first reporting period commenced on 1 July 2008.
          The US congress continues to propose new climate change legislation and regulation. A new bill became law in December 2007, that includes stricter corporate average fuel emissions standards for automobiles sold in the US and biofuel mandates. Other bills currently under consideration propose stricter emissions limits on large GHG sources and/or the introduction of a cap-and-trade programme on CO2 and other GHG emissions.
          An April 2007 US Supreme Court decision will require the US Environmental Protection Agency (EPA) to reconsider its determination that it is not required to regulate GHGs from motor vehicles under the Clean Air Act (CAA). The Supreme Court’s ruling is expected to result in the EPA regulating motor vehicle GHG emissions. It is also expected to increase pressure on the EPA to regulate stationary sources of GHGs (e.g. refineries and chemical plants) under other provisions of the CAA.
          In response to the US Supreme Court’s decision, the EPA issued an Advanced Notice of Proposed Rulemaking (ANPR). The ANPR addresses complexities involved in controlling greenhouse gases under the CAA including potential overlap between future legislation and regulation under the existing CAA.
          In its Fiscal Year 2008 Consolidated Appropriations Act, US Congress directed the EPA to publish a mandatory GHG reporting rule, issuing a proposed rule within nine months (by September 2008), and a final rule within 18 months (by June 2009). The EPA has developed draft language and the proposed rule could be released early in the new US administration.
          Congress will likely develop new legislation for GHG regulation, and new regulation under the CAA will likely proceed as well. Additional GHG regulation may also be issued under other laws, such as the National Environmental Protection Act (NEPA) and Endangered Species Act (ESA).
          In December 2008, the California Air Resources Board (CARB) approved the final Proposed Scoping Plan for implementing Assembly Bill 32, California’s law to reduce GHG emissions to 1990 levels by 2020. Implementation measures are due to be developed by 2012. In advance of the Scoping Plan, CARB has taken early actions with the development of mandatory GHG reporting and a Low Carbon Fuel Standard (LCFS). The LCFS will require all refiners, producers, blenders and importers to reduce the carbon intensity of transport fuel sold in California by 10% by 2020. CARB released draft LCFS regulations in October 2008, with final regulations expected to be taken up in March 2009.


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In March 2008, the Canadian federal government updated its April 2007 Framework Report with an Action Plan to address climate change and reduce emissions 20% below 2006 levels by 2020 and by greater than 60% by 2050, through both a sector approach and domestic development and deployment of new technologies and projects. For the conventional oil and gas industry, the intensity based targets as included in the plan of the April 2007 Framework Report remain likely. For the oil sands industry, more stringent requirements are likely to emerge for upcoming projects that may include requirements for significant reductions, including the implementation of large scale carbon capture and sequestration. Since the conclusion of the recent Canadian and US Federal elections there has been increased discussion on the possibility of aligning regulations, including possible inclusion of a North America wide cap-and-trade system.
          Since 1997, BP has been actively involved in the policy debate. We also ran a global programme that reduced our operational GHG emissions by 10% between 1998 and 2001. We continue to look at two principal kinds of GHG emissions: operational emissions, which are generated from our operations such as refineries, chemicals plants and production facilities; and product emissions, generated by our customers when they use the fuels and products that we sell. Since 2001, we have been focusing on measuring and improving the carbon intensity of our operations as well as developing sustainable low-carbon technologies and businesses.
          After seven years, we estimate that our operations have delivered some 7.5 million tonnes (Mte) of GHG reductions. Our 2008 operational GHG emissions were 61.4Mte of CO2 equivalent on a direct equity basis, nearly 2.1Mte lower than the reported figure of 63.5Mte in 2007. The primary reason for the lower reported emissions is a reporting protocol change for BP Shipping (1.9Mte) to align us more closely with industry practice.
          In 2007, as part of our technology development, two major BP-backed research institutes came into full operation: the Energy Biosciences Institute (EBI) in the US, and the Energy Technologies Institute (ETI) in the UK. The EBI is a strategic partnership between BP, the University of California, Berkeley, the Lawrence Berkeley National Laboratory and the University of Illinois, Urbana-Champaign to conduct research into the production of new and cleaner energy, initially focusing on advanced biofuels for road transport. The EBI will also pursue bioscience-based research into the conversion of heavy hydrocarbons to clean fuels, improved recovery from existing oil and gas reservoirs and carbon sequestration. In the UK, the ETI has been established as a 50:50 public private partnership, funded equally by member companies, including BP, and the government. The ETI aims to accelerate the development, demonstration and eventual commercial deployment of a focused portfolio of energy technologies, which will increase energy efficiency, reduce GHG emissions and help achieve energy security and climate change goals. The ETI has issued its first invitation for expressions of interest to participate in programmes to develop new technologies for offshore wind and for marine, tidal and wave energy. BP established the Carbon Mitigation Initiative in 2000 at Princeton University in the US to research the fundamental scientific, environmental, and technological issues that will determine how carbon is managed in the future and examine the policy impact of different options. BP’s original 10-year commitment initially funded the programme at $1.5 million per year and later increased it to more than $2 million per year. In October 2008, BP committed to a five-year renewal of the partnership and to support Princeton to at least its current level of funding for the years 2011 to 2015.
Maritime oil spill regulations
Within the US, the Oil Pollution Act of 1990 (OPA 90) imposes oil spill prevention and planning requirements liability for tankers and barges transporting oil and for offshore facilities such as platforms and onshore terminals. To ensure adequate funding for oil spill response and compensation, OPA 90 created the Oil Spill Liability Trust Fund that is
financed by a tax on imported and domestic oil. In 2006, the Coast Guard and Maritime Transportation Act 2006, increased the size of the fund from the original amount of $1 billion to $2.7 billion. In late 2008, as part of the Emergency Economic Stabilization Act, further amendments were made to increase the per-barrel contribution rate of tax and to remove the provision for cessation of the tax when the fund reached $2.7 billion. There is now no limit on the size of the fund. The same 2008 legislation amended the termination date of this tax from 31 December 2014 to 31 December 2017. The 2006 legislation also increased the OPA limitation amount relating to the liability of double-hulled tankers from $1,200 per gross tonne to $1,900 per gross tonne. In addition to the spill liabilities imposed by OPA 90 on the owners and operators of carrying vessels, some states, including Alaska, Washington, Oregon and California, impose additional liability on the shippers or owners of oil spilled from such vessels. The exposure of BP to such liability is mitigated by the vessels’ marine liability insurance, which has a maximum limit of $1 billion for each accident or occurrence. OPA 90 also provides that all new tank vessels operating in US waters must have double hulls and existing tank vessels without double hulls must be phased out by 2015. At the end of 2008, BP owned four double-hulled tankers built between 2004 and 2006, demise-chartered to and operated by Alaska Tanker Company, L.L.C. (ATC), which transports BP Alaskan crude oil from Valdez.
          Outside of US territorial waters, the BP-operated fleet of tankers is subject to international spill response and preparedness regulations that are typically promulgated through the International Maritime Organization (IMO) and implemented by the relevant flag state authorities. The International Convention for the Prevention of Pollution from Ships (Marpol 73/78) requires vessels to have detailed shipboard emergency and spill prevention plans. The International Convention on Oil Pollution, Preparedness, Response and Co-operation requires vessels to have adequate spill response plans and resources for response anywhere the vessel travels. These conventions and separate Marine Environmental Protection Circulars also stipulate the relevant state authorities around the globe that require engagement in the event of a spill. All these requirements together are addressed by the vessel owners in Shipboard Oil Pollution Emergency Plans. BP Shipping’s liabilities for oil pollution damage under the OPA 90 and outside the US under the 1969/1992 International Convention on Civil Liability for Oil Pollution Damage (CLC) are covered by marine liability insurance, having a maximum limit of $1 billion for each accident or occurrence. This insurance cover is provided by three mutual insurance associations (P&I Clubs): The United Kingdom Steam Ship Assurance Association (Bermuda) Limited; The Britannia Steam Ship Insurance Association Limited; and The Standard Steamship Owners’ Protection and Indemnity Association (Bermuda) Limited. With effect from 20 February 2006, two new complementary voluntary oil pollution compensation schemes were introduced by tanker owners, supported by their P&I Clubs, with the agreement of the International Oil Pollution Compensation Fund at the IMO. Pursuant to both these schemes, tanker owners will voluntarily assume a greater liability for oil pollution compensation in the event of a spill of persistent oil than is provided for in CLC. The first scheme, the Small Tanker Owners’ Pollution Indemnification Agreement (STOPIA), provides for a minimum liability of 20 million Special Drawing Rights (around $30 million) for a ship at or below 29,548 gross tonnes, while the second scheme, the Tanker Owners’ Pollution Indemnification Agreement (TOPIA), provides for the tanker owner to take a 50% stake in the 2003 Supplementary Fund, that is, an additional liability of up to 273.5 million Special Drawing Rights (around $405 million). Both STOPIA and TOPIA will only apply to tankers whose owners are party to these agreements and who have entered their ships with P&I Clubs in the International Group of P&I Clubs, so benefiting from those clubs’ pooling and reinsurance arrangements. All BP Shipping’s managed and time-chartered vessels participate in STOPIA and TOPIA.
          For information regarding maritime security issues, see Shipping on page 35.


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US
The following is a summary of significant US environmental issues and environment and health and safety legislation or regulations affecting BP.
          The CAA and its regulations, administered by the United States Environmental Protection Agency (EPA) require, among other things: stringent air emission limits and operating permits for chemicals plants, refineries, marine and distribution terminals and exploration and production facilities, strict fuel specifications and sulphur reductions; enhanced monitoring of major sources of specified pollutants; and risk management plans for storage of hazardous substances. This law affects BP facilities producing, storing, refining, manufacturing and distributing oil and products as well as the fuels themselves. Federal and state controls on ozone, particulate matter, carbon monoxide, benzene, sulphur, MTBE, nitrogen dioxide, oxygenates, lead and Reid Vapor Pressure affect BP’s activities and products. Under the CAA all gasoline produced by BP is subject to the EPA’s stringent low-sulphur standards. By June 2006, at least 80% of the highway diesel fuel produced each year by BP was required to meet a sulphur cap of 15 parts per million (ppm). By June 2007, all non-road locomotive and marine diesel fuel produced each year by BP was required to meet a sulphur cap of 500ppm. Additionally, states have separate laws similar to the CAA.
          The Energy Policy Act of 2005 affects the US fuels market by: eliminating the Federal Reformulated Gasoline (RFG) oxygen requirement in May 2006; establishing a renewable fuels mandate (4 billion gallons in 2006, increasing to 7.5 billion in 2012); consolidating the summertime RFG volatile organic compound (VOC) standards for EPA Regions 1 and 2; allowing the Ozone Transport Commission states on the east coast to opt any area into RFG; and allowing states to repeal the 1psi Reid Vapor Pressure waiver for 10% ethanol blends.
          The Energy Independence and Security Act of 2007 increased the renewable fuel mandate to 9 billion gallons in 2008 and further each year to a maximum of 36 billion gallons in 2022.
          In 2001, BP entered into a consent decree with the EPA and several states that settled alleged violations of various CAA requirements related largely to emissions of sulphur dioxide and nitrogen oxides at BP’s US refineries. Implementation of the decree’s requirements continues.
          In 2001, BP’s US refineries entered into a civil consent decree with the EPA to resolve alleged violations of the CAA. The decree applies to all the US refineries of BP Products North America Inc. (BP Products). On 19 February 2009, the EPA and US Department of Justice (DOJ) lodged an amendment to the 2001 decree. The amendment applies only to the Texas City refinery and resolves alleged violations of both the 2001 decree and the CAA. The decree requires that BP Products pays a $12 million civil fine, funds a $6 million supplemental environmental project and takes steps at the Texas City refinery to enhance compliance with CAA rules.
The estimated cost of these compliance measures is approximately $150 million. The decree amendment is subject to court approval.
          The Clean Water Act (CWA) and its regulations, administered by EPA and the US Coast Guard, regulate the discharge of wastewater, stormwater and toxic discharges from BP’s onshore and offshore operations to navigable waters. Facilities are required to obtain discharge permits, install control equipment and implement operational controls and preventative measures. Additionally, states have separate laws similar to the CWA.
          The Resource Conservation and Recovery Act (RCRA) and its regulations, administered by the EPA, regulate the storage, handling, treatment, transportation and disposal of hazardous and non-hazardous wastes and require the investigation and remediation of locations at a facility where such wastes have been managed. Many BP facilities generate and manage wastes regulated by RCRA and several include locations that are subject to investigation and corrective action. Additionally, states have separate laws similar to RCRA.
          Under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund), persons who arranged to dispose of hazardous substances at a site, persons who currently own or operate a site where such substances have been
disposed and certain other parties are strictly liable for the cost of responding to related hazardous substance contamination. EPA administers CERCLA. Additionally, states have separate laws similar to CERCLA.
          BP has been identified as a Potentially Responsible Party (PRP) under CERCLA or otherwise named under similar state statutes at approximately 809 sites. A PRP or named party can incur joint and several liability for site remediation costs under some of these statutes and so BP may be required to assume, among other costs, the share attributed to insolvent, unidentified or other parties. BP has the most significant exposure for remediation costs at 50 of these sites. For the remaining sites, BP is one of many potentially responsible parties, and BP expects its share of remediation costs at these sites to be small in comparison with the major sites. BP has estimated its potential exposure at all sites where it has been identified as a PRP or is otherwise named at a site is approximately $1.7 billion.
          BP is also subject to claims for natural resource damages (NRD) under CERCLA, the OPA 90 and other federal and state laws. NRD claims have been asserted by government trustees against a number of BP operations. Many environmental clean-ups are driven by state and federal groundwater protection standards. Contamination or the threat of contamination of current or potential potable (and occasionally non-potable) water resources can result in stringent clean-up requirements. BP has encouraged risk-based approaches to these issues and seeks to tailor remedies at its facilities to match the level of risk presented by the contamination.
          Other legislation that significantly affect BP operations includes: the Toxic Substances Control Act, administered by EPA, which regulates the development, testing, import, export and introduction of new chemical products into commerce; the Occupational Safety and Health Act, administered by the Occupational Safety and Health Administration, which imposes workplace safety and health, training and process safety requirements to reduce the risks of physical and chemical hazards and injury to employees; the CAA, which created the US Chemical Safety and Hazard Investigation Board which investigates the causes of chemical accidents and makes non-binding recommendations to industry, government and non-governmental organizations; and the Emergency Planning and Community Right-to-Know Act, administered by the EPA, which requires emergency planning and hazardous substance release notification as well as public disclosure of chemical usage and emissions. In addition, the US Department of Transportation (DOT) regulates the transportation of the BP’s petroleum products such as crude oil, gasoline and chemicals.
          BP is subject to the Marine Transportation Security Act (MTSA) and regulations and the DOT Hazardous Materials (HAZMAT) security compliance regulations. These regulations require many of BP’s businesses to conduct security vulnerability assessments and prepare security mitigation plans that require upgrades to security measures, the appointment and training of security personnel and the submission of plans for approval and inspection by government agencies.
The US government through the Department of Homeland Security, in an effort to further mitigate the threat of terrorism to critical US infrastructure, has implemented two new security legislation initiatives, that began in 2007 and has continued through 2008:
  Chemical Facility Anti-Terrorism Standard (CFATS).
 
  Transportation Workers Identification Credential (TWIC).
CFATS is intended to provide an enhanced security posture for US facilities that manufacture or store Chemicals of Interest, including gasoline. Additionally, in the future, it will cover facilities that have national economic impact to the US, should these facilities be a target for terrorism. A number of BP facilities may be required to conduct a detailed security vulnerability assessment and a detailed security plan for each facility impacted.
          TWIC requires all designated personnel with unescorted access to restricted areas of MTSA designated facilities to submit to a background screening programme and to obtain a biometric identification card. All of


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BP’s MTSA-regulated facilities will be impacted and will be required to comply by the end of 2008 or beginning of 2009 in a phased approach.
          The BP Americas Response Team consists of approximately 210 trained emergency responders at BP locations throughout North America. In addition, there are five Regional Response Incident Management Teams, a number of HAZMAT Teams and emergency response teams at BP’s major facilities. Collectively, these teams are ready to assist in a response to a major incident.
          In 2008, BP Products obtained and renewed environmental permits that enabled it to commence construction on the project to upgrade the Whiting refinery. Various environmental groups have challenged these permits in state and federal proceedings.
          In November 2007, the EPA began issuing a series of notices of violations, alleging clean air act violations, to the Whiting, Toledo, Carson and Cherry Point refineries. Settlement negotiations continue between BP Products, the EPA and the DOJ in an effort to resolve these matters. In October 2008, the EPA issued an amended notice of violation alleging that BP Products began construction on the Whiting upgrade in 2005 prior to receiving the necessary permits. This allegation has been incorporated into the permit challenges filed by the environmental groups. The subject matter of the notices of violation could be resolved as an amendment to the 2001 EPA consent decree or as a separate matter.
          See also Legal proceedings on page 88.
European Union
The following is a summary of significant EU level environmental legislation and UK health and safety legislation affecting BP.
          At the March 2007 European Council, the European Heads of Government decided to adopt:
  a commitment to reduce GHG emissions by at least 20% by 2020 as compared with 1990 levels and the objective of a 30% reduction by 2020, subject to the conclusion of a comprehensive international climate change agreement; and
 
  a mandatory EU target of 20% renewable energy by 2020 including a 10% biofuels target.
          In December 2008, the European Parliament approved the ‘Climate Action and Renewable Energy Package’, which:
  revises the EU’s Emissions Trading System to establish auctioning of emission allowances from 2013;
 
  sets binding national targets for each EU member state; equips power plants to capture and store CO2 underground;
 
  sets mandatory national targets for each EU member state with the goal of delivering 20% renewable energy target by 2020; and
 
  provides for a revised Fuel Quality Directive requiring fuel suppliers to reduce the life cycle emission of the fuels they provide by up to 10% by 2020.
BP was involved at the highest levels in the preparation of the ‘Climate Action and Renewable Energy Package’, as part of our efforts to actively contribute to the formulation of energy security and climate change policy in the EU.
          An EC directive for a system of integrated pollution prevention and control (IPPC) was adopted in 1996. This system requires certain listed industrial installations, including most activities and processes undertaken by the oil and petrochemicals industry within the EU, to obtain an IPPC permit, which is designed to address an installation’s environmental impacts, air emissions, water discharges and waste in a comprehensive and integrated fashion. The permit requires, among other things, the application of Best Available Techniques (BAT), taking into account the costs and benefits, unless an applicable environmental quality standard requires more stringent restrictions, and an assessment of existing environmental impacts and future site closure obligations. All such plants had to obtain such a permit by 30 October 2007 and permits included an environmental improvement programme where necessary.
          In December 2007, the EC issued a proposal for the revision to the IPPC Directive with the aims of streamlining legislation on industrial emissions, improving the implementation of BATs across Europe, and
contributing to the achievement of the targets set in the EC’s Thematic Strategies on Air, Soil and Waste. The proposal merges and revises several separate directives related to industrial emissions (including the Large Combustion Plant Directive) into one Directive. It proposes tighter minimum standards for emissions from large combustion plant (>50MW), and introduces a mandatory requirement to achieve emission limit values indicated by use of ‘Best Available Techniques’ (with derogations from this requirement allowed where justified).
          The proposal would also extend the scope of IPPC to specifically cover organic chemical manufacture by biological treatment (biofuels) and may open the way for NOx and SOx trading by member states.
          The EC proposal has triggered considerable debate and the timetable for the completion of the legislative process and the likely outcome are not clear. However, the revision has already triggered a greater focus on the information sharing process that is used to determine and document the BAT for each industry sector, and will raise the profile of the outputs from this process – the BAT Reference Documents (BREFs).
          In 2005, the EC published its Thematic Strategy on Air Pollution, which outlines EU-wide targets for health and environmental benefits from improved air quality to be achieved through further controls on emissions of fine particulates (PM 2.5 – particulate matter less than 2.5 microns diameter), sulphur dioxide, oxides of nitrogen, volatile organic compounds and ammonia. Associated with this is the revision to the National Emissions Ceiling Directive (NECD), which would introduce new emissions ceilings for each member state for fine particles and tighten existing ceilings for sulphur dioxide, oxides of nitrogen, volatile organic compounds and ammonia. There is currently uncertainty regarding the costs to industry of implementing possible outcomes from the NECD and IPPC revisions.
          The proposed revision of the current EU Fuel Quality Directive is referred to in the Climate Change Programmes section above. In addition to its provisions regarding life cycle GHG emission reductions, it would also facilitate the introduction of biofuels into gasoline and diesel.
          Registration, Evaluation and Authorization of Chemicals (REACH) legislation became effective 1 June 2007 across all member states of the EU. All chemical substances manufactured within, or imported into, the EU in quantities above 1 tonne per annum must be registered fully by each manufacturer/importer with the new European Chemical Agency (ECHA). Failure to comply with REACH in respect of such a substance will immediately remove a company’s legal right to manufacture or import that substance. Initially all existing manufactured and imported substances had to be pre-registered by 1 December 2008, to qualify for a timed phase-in for full registration during the period 2010-2018, with the exact timing being determined by the volumes of chemicals manufactured/imported, and by the health, safety and environmental hazards the chemical may possess. Failure to pre-register an existing chemical will result in an immediate requirement to register fully the chemical with the ECHA prior to continued manufacture within, or import into, the EU. Time-limited authorizations may be granted for substances of ‘high concern’ and in some cases restrictions in use may apply. Crude oil and natural gas are exempt from registration requirements, while fuels are exempt from authorization but not registration. In BP, REACH affects our refining, petrochemicals and other chemical manufacturing operations, with many other businesses, such as lubricants, also being impacted in their roles as major importers and downstream users of chemicals. In 2008, BP submitted around 700 pre-registrations, covering approximately 250 individual chemical substances. For almost 60% of these, ‘full’ registration dossiers must be submitted to ECHA by 1 December 2010, the balance being required in the period 2013-2018. Total REACH registration fees to be incurred by BP’s businesses are estimated to be in the region of $15 million and these contribute to an estimated overall cost of $60 million during the period 2008-2018 for pre-registration, registration and provision of additional testing requirements.
          In the UK, significant health and safety legislation affecting BP includes the Health and Safety at Work Act and regulations made thereunder and the Control of Major Accident Hazards Regulations.


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Employees
                                         
     
            Rest of             Rest of        
Number of employees at 31 December   UK     Europe     US     World     Total  
     
2008
                                       
Exploration and Production
    3,600       700       7,700       9,400       21,400  
Refining and Marketing
    9,000       18,000       19,000       15,500       61,500  
Other businesses and corporate
    3,300       700       2,600       2,500       9,100  
     
 
    15,900       19,400       29,300       27,400       92,000  
     
2007
                                       
Exploration and Production
    3,800       700       7,800       9,500       21,800  
Refining and Marketing
    9,700       18,400       22,700       16,400       67,200  
Other businesses and corporatea
    3,500       800       2,500       2,300       9,100  
     
 
    17,000       19,900       33,000       28,200       98,100  
     
2006
                                       
Exploration and Production
    3,600       1,000       7,600       9,200       21,400  
Refining and Marketing
    10,200       18,600       23,800       15,400       68,000  
Other businesses and corporate
    3,100       600       2,300       1,600       7,600  
     
 
    16,900       20,200       33,700       26,200       97,000  
     
 
aA minor amendment has been made to the comparative figure for Rest of the World to correct headcount data.

People and their capabilities are fundamental to our sustainability as a business. To build an enduring business in an increasingly complex and competitive industry, we need people with world-class capabilities, ranging from deepwater drilling and operating refineries to negotiating with governments and planning wind farms.
          Our 2008 focus has been on reducing complexity and embedding the performance culture throughout the company. We have implemented structured transformational programmes in a number of strategic performance units (SPUs) and the major functions. We have stopped activity that was being repeated at multiple layers, removed layers of management and have established the SPUs as the principal units of delivery.
          There is a greater focus on individual performance management. We have simplified the performance management process and can clearly identify and reward top performing businesses and individuals. Our incentive plans provide a direct link between SPU performance, the individual’s contribution, and the bonus outcome.
          We had approximately 92,000 employees at 31 December 2008, compared with approximately 98,100 at 31 December 2007.
          In managing our people, we seek to attract, develop and retain highly talented individuals in order to maintain BP’s capability to deliver our strategy and plans. Our three-year graduate development programme currently has 1,200 participants from all over the world.
          We are focusing on the need for deep specialist skills. Accordingly, we have increased external hiring in infrastructure and technical areas. The energy industry faces a shortage of professionals such as petroleum engineers. The number of experienced workers retiring is expected to exceed that of new graduate hires. To help address this issue we are developing more robust resourcing plans supported by initiatives aimed at increasing the numbers of recruits and diversifying the sources from which we recruit. The external hiring initiatives are supported by plans for accelerated discipline development, prioritized deployment and retention schemes.
          The continuous improvement we are making to performance management and reward will help ensure that BP meets the expectations of these new recruits who are highly mobile and are more conscious that they have a choice about where to work.
          Our policy is to ensure equal opportunity in recruitment, career development, promotion, training and reward for all employees, including those with disabilities. Where existing employees become disabled, our policy is to provide continuing employment and training wherever practicable.
In 2008, a global diversity and inclusion (D&I) council was established. This council, chaired by Tony Hayward, is supported by a North American regional council and segment councils. The aim is to harmonize processes and tools for managing D&I across all Segments and Functions. Responsibility for delivering D&I plans sits at the business/SPU level.
          The group people committee, formed in 2007, continues to take overall responsibility for policy decisions relating to employees. In 2008, these ranged from senior level talent review and succession planning, embedding of diversity and inclusion plans in the businesses and the structure of long-term incentive plans.
          We continue to increase the number of local leaders and employees in our operations so that they reflect the communities in which we operate. For example, in Colombia, national employees now make up 98% of BP’s team, while in Azerbaijan, the equivalent proportion is 83%. By 2020, more than half our operations are expected to be in non-OECD countries and we see this as an opportunity to develop a new generation of experts and skilled employees.
          At the end of 2008, 14% of our top 583 leaders were female and 19% came from countries other than the UK and the US. When we started tracking the composition of our group leadership in 2000, these percentages were 9% and 14% respectively. We continue to raise our senior level leaders’ awareness of D&I, and further training is planned in 2009.
          We aim to develop our leaders internally, although we recruit outside the group when we do not have specialist skills in-house or when exceptional people are available. In 2008, we appointed 73 people to positions in the group leadership population. Of these, 39 were internal candidates.
          We provide development opportunities for our employees, including training courses, international assignments, mentoring, team development days, workshops, seminars and online learning. We encourage all employees to take five training days per year.
          A leadership, development and learning steering group was set up in 2008. This body of senior executives has responsibility for guiding and advising on leadership and management development. As part of this, the steering group oversees the Managing Essentials programme, which was successfully rolled out in 2007.
          Through our award-winning ShareMatch plan, run in more than 70 countries, we match BP shares purchased by employees.


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Communications with employees include magazines, intranet sites, DVDs, targeted emails and face-to-face communication. Team meetings are the core of our employee consultation, complemented by formal processes through works councils in parts of Europe. These communications, along with training programmes, are designed to contribute to employee development and motivation by raising awareness of financial, economic, social and environmental factors affecting our performance.
          The group seeks to maintain constructive relationships with labour unions.
          ‘Pulse’ surveys conducted in 2008 among samples of employees indicated that BP’s safety culture is growing but that overall satisfaction levels have fallen. The surveys also revealed that more work needs to be done to ensure all employees fully understand what they need to do to deliver sustainable high performance.
          We continue to make significant efforts to communicate the intent and progress of the forward agenda to reduce the potential negative impacts of this change on the business. We have moved quickly, but our management of change practices keep the focus on safety and ensure that the changes are sustainable. These improvements are expected to continue in 2009, but we have already delivered material reductions in activity, cost and headcount.
The code of conduct
We have a code of conduct designed to ensure that all employees comply with legal requirements and our own standards. The code defines what BP expects of its people in key areas such as safety, workplace behaviour, bribery and corruption and financial integrity. Our employee concerns programme, OpenTalk, enables employees to seek guidance on the code of conduct as well as to report suspected breaches of compliance or other concerns. The number of cases raised through OpenTalk in 2008 was 925, compared with 973 in 2007.
          In the US, former US district court judge Stanley Sporkin acts as an ombudsperson. Employees and contractors can contact him confidentially to report any suspected breach of compliance, ethics or the code of conduct, including safety concerns.
          We take steps to identify and correct areas of non-compliance and take disciplinary action where appropriate. In 2008, 765 dismissals were reported by BP’s businesses for non-compliance or unethical behaviour. This number excludes dismissals of staff employed at our retail service station sites, for incidents such as thefts of small amounts of money.
          BP continues to apply a policy that the group will not participate directly in party political activity or make any political contributions, whether in cash or in kind. BP specifically made no donations to UK or other EU political parties or organizations in 2008.
Social and community issues
Contributing to communities
We aim to make a difference in the communities where we operate in a manner that brings benefits to BP as well as the local society. Investment in education, for example, promotes sustainable development as well as providing skilled workers for BP and other companies. Support for local enterprise drives economic growth as well as helping local companies qualify as our suppliers.
          BP operates in a diverse range of locations with varying levels of economic and national development. We contribute to communities in ways that are relevant to local circumstances, and which offer opportunities for mutual benefit to our business. Given the scale of our business, our impact often reaches beyond the local community to the national and, in some cases, the international level.
          We support education because it creates opportunities for communities, while at the same time providing skills that are critical to BP business and the wider industry. Our interventions in education
are diverse and wide-ranging. We help fund a range of educational programmes, from early years learning to advanced university research, building skills and capability in communities as well advancing knowledge on issues such as climate change and effective economic management of natural resource rich countries. In further and higher education, a major driver for our involvement is the need to encourage more people to develop the particular skills needed for the energy industry. In supporting school education, BP looks to develop children’s awareness of links between energy and the environment as well as stimulating interest in science and engineering. In addition to its investment in the formal learning system, BP supports public education on specific pressing social issues when there is a particular need within a local community.
          Through training and financing programmes, BP seeks to support the development of local suppliers by building their skills, sharing internal standards and practice and stimulating business development. This enables greater participation in the supply chain by local business and greater competitiveness overall.
          We support several initiatives designed to promote the effectiveness of natural resource led national development. Through the support of the Oxford Centre for the Analysis of Resource Rich Economies, we seek to improve the understanding of the development challenges and policy options available to emerging economies that are rich in natural resources such as oil and gas. We remain a member of the Extractive Industries Transparency Initiative (EITI), which supports the creation of a standardized process for transparent reporting of company payments and government revenues from oil, gas and mining.
          In the US, amongst various other initiatives in 2008, we provided more than $17 million to assist with relief and recovery efforts for the wider community following Hurricanes Ike and Gustav in the Gulf of Mexico.
          We make direct contributions to communities through community programmes. Our total contribution in 2008 was $125.6 million. This included $0.2 million contributed by BP to UK charities. The growing focus of this is on education, the development of local enterprise and providing access to energy in remote locations.
          In 2008, we spent $59.5 million promoting education, with investment in three broad areas: energy and the environment; business leadership skills; and basic education in developing countries where we operate large projects.
Essential contracts
BP has contractual and other arrangements with numerous third parties in support of its business activities. This report does not contain information about any of these third parties as none of our arrangements with them are considered to be essential to the business of BP.
Property, plants and equipment
BP has freehold and leasehold interests in real estate in numerous countries, but no individual property is significant to the group as a whole. See Exploration and Production on page 13 for a description of the group’s significant reserves and sources of crude oil and natural gas. Significant plans to construct, expand or improve specific facilities are described under each of the business headings within this section.
Organizational structure
The significant subsidiaries of the group at 31 December 2008 and to the group percentage of ordinary share capital (to the nearest whole number) are set out in Financial statements – Note 46 on page 173. See Financial statements – Notes 26 and 27 on pages 138 and 139 respectively for information on significant jointly controlled entities and associates of the group.


45


 

Performance review
 
Financial and operating performance
Group operating results
The following summarizes the group’s operating results.
                         
     
    $ million except per share amounts  
     
    2008     2007     2006  
     
Total revenuesa
    365,700       288,951       270,602  
Profit from continuing operationsa
    21,666       21,169       22,626  
Profit for the year
    21,666       21,169       22,601  
Profit for the year attributable to BP shareholders
    21,157       20,845       22,315  
Profit attributable to BP shareholders per ordinary share – cents
    112.59       108.76       111.41  
Dividends paid per ordinary share – cents
    55.05       42.30       38.40  
     
 
a Excludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2004, 2005 and 2006.

Business environment
Crude oil prices reached new record highs in 2008, in nominal terms. The average dated Brent price for the year rose to $97.26 per barrel, an increase of 34% over the $72.39 per barrel average seen in 2007. Daily prices began the year at $96.02 per barrel, peaked at $144.22 per barrel on 3 July 2008, and fell to $36.55 per barrel at year-end. The sharp drop in prices was due to falling demand in the second half of the year, caused by the OECD falling into recession and the lagged effect on demand of high prices in the first half of the year. OPEC had increased production significantly through the first three quarters; and, as a result of falling consumption and rising OPEC production, inventories rose. As prices continued to decline, OPEC responded with successive announcements of production cuts in September, October, and December.
          Natural gas prices in the US and the UK increased in 2008. The Henry Hub First of Month Index averaged $9.04/mmBtu, 32% higher than the 2007 average of $6.86/mmBtu. Prices peaked at $13.11/mmBtu in July amid robust demand and falling US gas imports, but fell to $6.90/mmBtu in December as demand weakened and production remained strong. Average UK gas prices rose to 58.12 pence per therm at the National Balancing Point in 2008, 94% above the 2007 average of 29.95 pence per therm.
          Refining margins fell back in 2008, with the BP Global Indicator Margin (GIM) averaging $6.50 per barrel. The premium for light products above fuel oils remained high, reflecting a continuing shortage of upgrading capacity and the favouring of fully upgraded refineries over less complex sites.
          The retail environment continued to be extremely competitive in 2008 with market volatility, high absolute prices, as well as large price shifts in the crude market.
          In 2007, the average dated Brent price rose to $72.39 per barrel, an increase of 11% over the $65.14 per barrel average seen in 2006. Daily prices began the year at $58.62 per barrel and rose to $96.02 per barrel at year-end due to OPEC production cuts in early 2007, sustained consumption growth and a resulting drop in commercial inventories after the summer.
          Natural gas prices in the US and the UK declined in 2007. The Henry Hub First of Month Index averaged $6.86/mmBtu, 5% lower than the 2006 average of $7.24/mmBtu. Prices were pressured by strong LNG imports in summer, continued domestic production growth and high inventories. Average UK gas prices fell to 29.95 pence per therm at the National Balancing Point in 2007, 29% below the 2006 average of 42.19 pence per therm.
          Refining margins had reached a new record high in 2007, with the BP Global Indicator Margin (GIM) averaging $9.94 per barrel. The premium for light products above fuel oils remained exceptionally high, reflecting a shortage of upgrading capacity and the favouring of fully upgraded refineries over less complex sites.
Hydrocarbon production
Our total hydrocarbon production during 2008 averaged 2,517mboe/d for subsidiaries and 1,321mboe/d for equity accounted-entities, a decrease of 1.2% (a decrease of 3.1% for liquids and an increase of 0.7% for gas) and an increase of 4.0% (an increase of 2.5% for liquids and an increase of 14.8% for gas) respectively compared with 2007. In aggregate, after adjusting for the effect of lower entitlement in our PSAs, production was 5% higher than 2007. This reflected strong performance from our existing assets, the continued ramp-up of production following the startup of major projects in late-2007 and a further nine major project startups in 2008. Our total hydrocarbon production during 2007 averaged 2,549mboe/d for subsidiaries and 1,269mboe/d for equity-accounted entities, a decrease of 3% (3.5% for liquids and 2.6% for gas) and 2% (1.3% for liquids and 8.4% for gas) respectively compared with 2006. In aggregate, the decrease primarily reflected the effect of disposals and net entitlement reductions in our PSAs.
Profit attributable to BP shareholders
Profit attributable to BP shareholders for the year ended 31 December 2008 was $21,157 million, including inventory holding losses, net of tax, of $4,436 million and a net charge for non-operating items, after tax, of $796 million. In addition, fair value accounting effects had a favourable impact, net of tax, of $146 million relative to management’s measure of performance. Inventory holdings gains or losses, net of tax, are described in footnote (a) on the following page. Further information on non-operating items and fair value accounting effects can be found on page 51.
          Profit attributable to BP shareholders for the year ended 31 December 2007 was $20,845 million, including inventory holding gains, net of tax, of $2,475 million and a net charge for non-operating items, after tax, of $373 million (see page 52). In addition, fair value accounting effects had an unfavourable impact, net of tax, of $198 million (see page 52) relative to management’s measure of performance.
          Profit attributable to BP shareholders for the year ended 31 December 2006 was $22,315 million, including inventory holding losses, net of tax, of $222 million and a net credit for non-operating items, after tax, of $1,531 million (see page 52). In addition, fair value accounting effects had a favourable impact, net of tax, of $72 million (see page 52) relative to management’s measure of performance. The profit attributable to BP shareholders for the year ended 31 December 2006 included a loss from Innovene operations of $25 million.


46


 

Performance review
 

The primary additional factors reflected in profit for 2008, compared with 2007, were higher realizations, a higher contribution from the gas marketing and trading business, improved oil supply and trading performance, improved marketing performance and strong cost management; however, these positive effects were partly offset by weaker refining margins, particularly in the US, higher production taxes, higher depreciation, and adverse foreign exchange impacts.
          The primary additional factors reflected in profit for 2007, compared with 2006, were higher liquids realizations, stronger refining and marketing margins and improved NGLs performance; however, these were more than offset by lower gas realizations, lower reported production volumes, higher production taxes in Alaska, higher costs (primarily reflecting the impact of sector-specific inflation and higher integrity spend), the impact of outages and recommissioning costs at the Texas City and Whiting refineries, reduced supply optimization benefits and a lower contribution from the marketing and trading business.
          Profits and margins for the group and for individual business segments can vary significantly from period to period as a result of changes in such factors as oil prices, natural gas prices and refining margins. Accordingly, the results for the current and prior periods do not necessarily reflect trends, nor do they provide indicators of results for future periods.
          Employee numbers were approximately 92,000 at 31 December 2008, 98,100 at 31 December 2007 and 97,000 at 31 December 2006.
 
a Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies incurred during the year and the cost of sales calculated on the first-in first-out (FIFO) method including any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on the historic cost of acquisition or manufacture rather than the current replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge to the income statement on a FIFO basis (and any related movements in net realizable value provisions) and the charge that would arise using average cost of supplies incurred during the period. For this purpose, average cost of supplies incurred during the period is calculated by dividing the total cost of inventory purchased in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.
 
       Management believes this information is useful to illustrate to investors the fact that crude oil and product prices can vary significantly from period to period and that the impact on our reported result under IFRS can be significant. Inventory holding gains and losses vary from period to period due principally to changes in oil prices as well as changes to underlying inventory levels. In order for investors to understand the operating performance of the group excluding the impact of oil price changes on the replacement of inventories, and to make comparisons of operating performance between reporting periods, BP’s management believes it is helpful to disclose this information.
Capital expenditure and acquisitions
                         
 
                    $ 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  
   
Capital expenditure and acquisitions in 2008, 2007 and 2006 amounted to $30,700 million, $20,641 million and $17,231 million respectively. In 2008, this included $4,731 million in respect of our transaction with Husky Energy Inc. and $3,667 million in respect of our purchase of all Chesapeake Energy Corporation’s interest in the Arkoma Basin Woodford Shale assets and the purchase of a 25% interest in Chesapeake’s Fayetteville Shale assets. Acquisitions in 2007 included the remaining 31% of the Rotterdam (Nerefco) refinery from Chevron’s Netherlands manufacturing company.
          Excluding acquisitions and asset exchanges, capital expenditure for 2008 was $28,186 million compared with $19,194 million in 2007 and $16,910 million in 2006. In 2006, this included $1 billion in respect of our investment in Rosneft.
Finance costs and net finance income relating to pensions and other post-retirement benefits
Finance costs comprises group interest less amounts capitalized, and interest accretion on provisions and long-term other payables. Finance costs for continuing operations in 2008 were $1,547 million compared with $1,393 million in 2007 and $986 million in 2006. The increase in 2008, when compared with 2007, is largely the outcome of reductions in capitalized interest as capital construction projects concluded. The increase in 2007, when compared with 2006, reflected a higher average gross debt balance and lower capitalized interest as capital construction projects concluded.
          Net finance income relating to pensions and other post-retirement benefits in 2008 was $591 million compared with $652 million in 2007 and $470 million in 2006. The expected return on assets has increased year on year as the pension asset base applicable to each year increased, but this has been offset in 2008 by higher interest costs reflecting the increase in discount rates applied to pension plan liabilities.
Taxation
The charge for corporate taxes for continuing operations in 2008 was $12,617 million, compared with $10,442 million in 2007 and $12,516 million in 2006. The effective rate was 37% in 2008, 33% in 2007 and 36% in 2006. The group earns income in many countries and, on average, pays taxes at rates higher than the UK statutory rate of 28% for 2008. The increase in the effective rate in 2008 compared with 2007 primarily reflects the change in the country mix of the group’s income, resulting in a higher overall tax burden. The reduction in the effective rate in 2007 compared with 2006 primarily reflects the reduction in the UK tax rate and the fact that a higher proportion of income arose in countries bearing a lower tax rate and other factors.
Business results
Profit before interest and taxation from continuing operations, which is before finance costs, other finance expense, taxation and minority interests, was $35,239 million in 2008, $32,352 million in 2007 and $35,658 million in 2006.


47


 

Performance review
 
Exploration and Production
                         
 
For the year ended 31 December                     $ million  
     
    2008     2007     2006  
     
Total revenuesa
    89,902       69,376       71,868  
Profit before interest and tax from continuing operationsb
    37,915       27,729       30,953  
Results include:
                       
Exploration expense
    882       756       1,045  
Of which: Exploration expenditure written off
    385       347       624  
     
 
                       
$ per barrel  
     
Key statistics
                       
Average BP crude oil realizationsc
                       
UK
    92.09       70.36       62.45  
US
    97.37       68.51       62.03  
Rest of World
    94.74       70.86       61.11  
BP average
    95.43       69.98       61.91  
Average BP NGL realizationsc
                       
UK
    57.24       52.71       47.21  
US
    52.14       44.59       36.13  
Rest of World
    50.84       48.14       36.03  
BP average
    52.30       46.20       37.17  
Average BP liquids realizationsc d
                       
UK
    89.82       69.17       61.67  
US
    89.22       64.18       57.25  
Rest of World
    91.05       69.56       59.54  
BP average
    90.20       67.45       59.23  
     
 
                       
$  per thousand cubic feet  
     
Average BP natural gas realizationsc
                       
UK
    8.41       6.40       6.33  
US
    6.77       5.43       5.74  
Rest of World
    5.19       3.71       3.70  
BP average
    6.00       4.53       4.72  
     
 
                       
$  per barrel  
     
Average West Texas Intermediate oil price
    100.06       72.20       66.02  
Alaska North Slope US West Coast
    98.86       71.68       63.57  
Average Brent oil price
    97.26       72.39       65.14  
     
 
                       
$  per million British thermal units  
     
Average Henry Hub gas pricee
    9.04       6.86       7.24  
     
 
                       
pence per therm  
     
Average UK National Balancing Point gas price
    58.12       29.95       42.19  
     
 
                       
thousand barrels per day  
     
Total liquids production for subsidiariesd f
    1,263       1,304       1,351  
Total liquids production for equity-accounted entitiesd f
    1,138       1,110       1,124  
     
 
                       
million cubic feet per day  
     
Natural gas production for subsidiariesf
    7,277       7,222       7,412  
Natural gas production for equity-accounted entitiesf
    1,057       921       1,005  
     
 
                       
thousand barrels of oil equivalent per day  
     
Total production for subsidiariesf g
    2,517       2,549       2,629  
Total production for equity-accounted entitiesf g
    1,321       1,269       1,297  
     
 
aIncludes sales between businesses.
 
bIncludes profit after interest and tax of equity-accounted entities.
 
cRealizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.
 
dCrude oil and natural gas liquids.
 
eHenry Hub First of Month Index.
 
fNet of royalties.
 
gExpressed in thousands of barrels of oil equivalent per day (mboe/d). Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

48


 

Performance review
 
Total revenues are analysed in more detail below.
                         
     
                    $ million  
     
    2008     2007     2006  
     
Sales and other operating revenues
    86,170       65,740       67,950  
Earnings from equity-accounted entities (after interest and tax), interest and other revenues
    3,732       3,636       3,918  
     
 
    89,902       69,376       71,868  
     

Total revenues for 2008 were $90 billion, compared with $69 billion in 2007 and $72 billion in 2006. The increase in 2008 primarily reflected higher oil and gas realizations. Gas marketing sales also increased primarily as a result of higher prices. The decrease in 2007 compared with 2006 primarily reflected lower volumes of subsidiaries and lower gas marketing sales, partly offset by higher realizations.
          Profit before interest and tax for the year ended 31 December 2008 was $37,915 million. This included inventory holding losses of $393 million and a net charge for non-operating items of $990 million (see page 52), with the most significant items being net impairment charges (primarily driven by the current low price environment) and net fair value losses on embedded derivatives, partly offset by the reversal of certain provisions. The impairment charge includes a $517 million write-down of our investment in Rosneft based on its quoted market price at the end of the year. In addition, fair value accounting effects had an unfavourable impact of $282 million relative to management’s measure of performance (see page 52).
          Profit before interest and tax for the year ended 31 December 2007 was $27,729 million. This included inventory holding gains of $127 million and a net credit from non-operating items of $491 million (see page 52), with the most significant items being net gains from the sale of assets (primarily from the disposal of our production and gas infrastructure in the Netherlands, our interests in non-core Permian assets in the US and our interests in the Entrada field in the Gulf of Mexico), partly offset by a restructuring charge and a charge in respect of the reassessment of certain provisions. In addition, fair value accounting effects had a favourable impact of $48 million relative to management’s measure of performance (see page 52).
          Profit before interest and tax for the year ended 31 December 2006 was $30,953 million. This included inventory holding losses of $73 million and a net credit from non-operating items of $2,563 million (see page 52), with the most significant items being net gains from the sale of assets (primarily from the sales of interests in the Shenzi discovery in the Gulf of Mexico in the US and interests in the North Sea partly offset by a loss on the sale of properties in the Gulf of Mexico Shelf) and net fair value gains on embedded derivatives, partly offset by a charge for legal provisions. In addition, fair value accounting effects had an unfavourable impact of $32 million relative to management’s measure of performance (see page 52).
The primary additional factor contributing to the 37% increase in profit before interest and tax for the year ended 31 December 2008 compared with the year ended 31 December 2007 was higher realizations. In addition, the result reflected a higher contribution from the gas marketing and trading business but was impacted by higher production taxes and higher depreciation. The impact of inflation within other costs was mitigated by rigorous cost control and a focus on simplification and efficiency.
          The primary additional factors reflected in profit before interest and tax for the year ended 31 December 2007 compared with the year ended 31 December 2006 were higher overall realizations (liquids realizations were higher and gas realizations were lower) and a favourable effect from lagged tax reference prices in TNK-BP; however, these factors were more than offset by the impact of lower reported volumes, a lower contribution from the gas marketing and trading business, higher production taxes in Alaska and higher costs, reflecting the impacts of sector-specific inflation, increased integrity spend and higher depreciation charges. Additionally, the result was lower due to the absence of disposal gains in 2006 in equity-accounted entities.
          Reported production for 2008 was 2,517mboe/d for subsidiaries and 1,321mboe/d for equity-accounted entities, compared with 2,549mboe/d and 1,269mboe/d respectively in 2007. In aggregate, after adjusting for the effect of lower entitlement in our PSAs, production was 5% higher than 2007. This reflected strong performance from our existing assets, the continued ramp-up of production following the startup of major projects in late-2007 and the start-up of a further nine major projects in 2008.
          Reported production for 2007 was 2,549mboe/d for subsidiaries and 1,269mboe/d for equity-accounted entities, compared with 2,629mboe/d and 1,297mboe/d respectively in 2006. In aggregate, the decrease primarily reflected the effect of disposals and net entitlement reductions in our PSAs.


49


 

Performance review
 
Refining and Marketing
                         
     
                    $ million  
     
    2008     2007     2006  
     
Total revenuesa
    320,458       250,897       232,833  
Profit before interest and tax from continuing operationsb
    (1,884 )     6,076       5,419  
     
 
                       
 
                  $ per barrel  
     
Global Indicator Refining Margin (GIM)c
                       
Northwest Europe
    6.72       4.99       3.92  
US Gulf Coast
    6.78       13.48       12.00  
Midwest
    5.17       12.81       9.14  
US West Coast
    7.42       15.05       14.84  
Singapore
    6.30       5.29       4.22  
BP average
    6.50       9.94       8.39  
     
 
                       
 
                    %  
     
Refining availabilityd
    88.8       82.9       82.5  
     
 
                       
 
              thousand barrels per day  
     
Refinery throughputs
    2,155       2,127       2,198  
     
 
aIncludes sales between businesses.
 
bIncludes profit after interest and tax of equity-accounted entities.
 
cThe GIM is the average of regional industry indicator margins that we weight for BP’s crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with product yields characteristic of the typical level of upgrading complexity. The refining margins are industry-specific rather than BP-specific measures, which we believe are useful to investors in analyzing trends in the industry and their impact on our results. The margins are calculated by BP based on published crude oil and product prices and take account of fuel utilization and catalyst costs. No account is taken of BP’s other cash and non-cash costs of refining, such as wages and salaries and plant depreciation. The indicator margin may not be representative of the margins achieved by BP in any period because of BP’s particular refining configurations and crude and product slate.
 
dRefining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime.
Total revenues are explained in more detail below.
                         
     
                    $ million    
     
    2008     2007     2006  
     
Sale of crude oil through spot and term contracts
    54,901       43,004       38,577  
Marketing, spot and term sales of refined products
    248,561       194,979       177,995  
Other sales and operating revenues
    16,577       12,238       15,814  
Earnings from equity-accounted entities (after interest and tax), interest, and other revenues
    419       676       447  
     
 
    320,458       250,897       232,833  
     
 
                       
 
              thousand barrels per day  
     
Sale of crude oil through spot and term contracts
    1,689       1,885       2,110  
Marketing, spot and term sales of refined products
    5,698       5,624       5,801  
     

Total revenues for 2008 were $320 billion, compared with $251 billion in 2007 and $233 billion in 2006. The increase in 2008 compared with 2007 primarily reflected an increase in marketing, spot and term sales of refined products, mainly driven by higher prices. Additionally, sales of crude oil, spot and term contracts increased, as a result of higher prices, partly offset by lower volumes. The increase in 2007 compared with 2006 was principally due to an increase in marketing, spot and term sales of refined products. This was due to higher prices and a positive foreign exchange impact due to a weaker dollar, partially offset by lower volumes. Additionally, sales of crude oil, spot and term contracts increased, primarily reflecting higher prices, and other sales decreased due to lower volumes partially offset by a positive foreign exchange impact.
          The loss before interest and tax for the year ended 31 December 2008 was $1,884 million. This included inventory holding losses of $6,060 million and a net credit for non-operating items of $347 million (see page 52). The most significant non-operating items were net gains on disposal (primarily in respect of the gain recognized on the contribution of the Toledo refinery into a joint venture with Husky Energy Inc.) partly offset by restructuring charges. In addition, fair value accounting effects had a favourable impact of $511 million relative to management’s measure of performance (see page 52).
Profit before interest and tax for the year ended 31 December 2007 was $6,076 million. This included inventory holding gains of $3,455 million and a net charge for non-operating items of $952 million (see page 52).
The most significant non-operating items were net disposal gains (primarily related to the sale of BP’s Coryton refinery in the UK, its interest in the West Texas pipeline system in the US and its interest in the Samsung Petrochemical Company in South Korea), net impairment charges (primarily related to the sale of the majority of our US Convenience Retail business, a write-down of certain assets at our Hull site and write-down of our retail assets in Mexico) and a charge related to the March 2005 Texas City refinery incident. In addition, fair value accounting effects had an unfavourable impact of $357 million relative to management’s measure of performance (see page 52).
          Profit before interest and tax for the year ended 31 December 2006 was $5,419 million. This included inventory holding losses of $242 million and a net credit for non-operating items of $113 million (see page 52). The most significant non-operating items were net disposal gains (related primarily to the sale of BP’s Czech Republic retail business, the disposal of BP’s shareholding in Zhenhai Refining and Chemicals Company, the sale of BP’s shareholding in Eiffage, the French-based construction company, and pipelines assets) and a charge related to the March 2005 Texas City refinery incident. In addition, fair


50


 

Performance review
 

value accounting effects had a favourable impact of $211 million relative to management’s measure of performance (see page 52).
          During 2008, significant performance improvements in both our Fuels Value Chains and International Businesses mitigated cost inflation and, to a large extent, the much weaker environment. The main sources of improvement were from restoring the revenues of our refining operations; improved supply and trading performance; improved marketing performance, particularly from the International Businesses, and reduced costs. The cost reductions have been driven by the simplification of our business structure through the establishment of Fuels Value Chains and a reduction in our geographical footprint, as well as by strong cost management. The most significant environmental factor was the weaker refining environment, particularly due to lower refining margins in the US and the adverse impact in the second half of 2008 of prior-month pricing of domestic pipeline barrels for our US refining system, but there were also adverse foreign exchange effects.
          During 2007, the segment continued to focus on the restoration of operations at the Texas City refinery and on investments in integrity management throughout our refining portfolio. We have also focused on the repair and recommissioning of the Whiting refinery following the operational issues in March 2007. In many parts of the refining portfolio and the other market-facing businesses, we delivered high reliability and improved results compared with 2006. However, for the full year, compared with 2006, the impact of the outages and recommissioning costs at the Texas City and Whiting refineries, as well as investments in integrity management and scheduled turnarounds throughout our refining portfolio, cost inflation and lower results from supply optimization decreased our result. These factors more than offset increased margins in both refining and marketing.
          The average refining Global Indicator Margin (GIM) in 2008 was lower than in 2007.
          Refining throughputs in 2008 were 2,155mb/d, 28mb/d higher than in 2007. Refining availability was 88.8%, six percentage points higher than in 2007, the increase being driven primarily by improvement at the Texas City and Whiting refineries. Marketing volumes at 3,711mb/d were around 2.5% lower than in 2007.
Other businesses and corporate
                         
 
                    $ million  
   
    2008     2007     2006  
 
Total revenuesa
    5,040       3,972       3,703  
Profit (loss) before interest and tax from continuing operationsb
    (1,258 )     (1,233 )     (779 )
   
 
a Includes sales between businesses.
 
b Includes profit after interest and tax of equity-accounted entities.
Other businesses and corporate comprises the Alternative Energy business, Shipping, the group’s aluminium asset, Treasury (which includes all the group’s cash, cash equivalents), and corporate activities worldwide.
          The loss before interest and tax for the year ended 31 December 2008 was $1,258 million and included inventory holding losses of $35 million and a net charge for non-operating items of $633 million (see page 52).
          The loss before interest and tax for the year ended 31 December 2007 was $1,233 million and included inventory holding losses of $24 million and a net charge for non-operating items of $262 million (see page 52).
          The loss before interest and tax for the year ended 31 December 2006 was $779 million and included inventory holding gains of $62 million and a net charge for non-operating items of $72 million (see page 52).
Non-operating items
Non-operating items are charges and credits that BP discloses separately because it considers such disclosures to be meaningful and relevant to
investors. The main categories of non-operating items in the periods presented are: impairments; gains or losses on sale of fixed assets and the sale of businesses; environmental remediation; restructuring, integration and rationalization costs; and changes in the fair value of embedded derivatives. These disclosures are provided in order to enable investors better to understand and evaluate the group’s financial performance. An analysis of non-operating items is shown on page 52.
Non-GAAP information on fair value accounting effects
BP uses derivative instruments to manage the economic exposure relating to inventories above normal operating requirements of crude oil, natural gas and petroleum products as well as certain contracts to supply physical volumes at future dates. Under IFRS, these inventories and contracts are recorded at historic cost and on an accruals basis respectively. The related derivative instruments, however, are required to be recorded at fair value with gains and losses recognized in income because hedge accounting is either not permitted or not followed, principally due to the impracticality of effectiveness testing requirements. Therefore, measurement differences in relation to recognition of gains and losses occur. Gains and losses on these inventories and contracts are not recognized until the commodity is sold in a subsequent accounting period. Gains and losses on the related derivative commodity contracts are recognized in the income statement from the time the derivative commodity contract is entered into on a fair value basis using forward prices consistent with the contract maturity.
          IFRS requires that inventory held for trading be recorded at its fair value using period end spot prices whereas any related derivative commodity instruments are required to be recorded at values based on forward prices consistent with the contract maturity. Depending on market conditions, these forward prices can be either higher or lower than spot prices resulting in measurement differences.
          BP enters into contracts for pipelines and storage capacity that, under IFRS, are recorded on an accruals basis. These contracts are risk-managed using a variety of derivative instruments that are fair valued under IFRS. This results in measurement differences in relation to recognition of gains and losses.
          The way that BP manages the economic exposures described above, and measures performance internally, differs from the way these activities are measured under IFRS. BP calculates this difference by comparing the IFRS result with management’s internal measure of performance, under which the inventory and the supply and capacity contracts in question are valued based on fair value using relevant forward prices prevailing at the end of the period. We believe that disclosing management’s estimate of this difference provides useful information for investors because it enables investors to see the economic effect of these activities as a whole. The impacts of fair value accounting effects, relative to management’s internal measure of performance, are shown in the table below and on the following page.
Reconciliation of non-GAAP information
Exploration and Production
                         
 
                    $ million  
   
    2008     2007     2006  
 
Profit before interest and tax adjusted for fair value accounting effects
    38,197       27,681       39,985  
Impact of fair value accounting effects
    (282 )     48       (32 )
 
Profit before interest and tax
    37,915       27,729       39,953  
 
 
                       
Refining and Marketing
                       
Profit before interest and tax adjusted for fair value accounting effects
    (2,395 )     6,433       5,208  
Impact of fair value accounting effects
    511       (357 )     211  
 
Profit before interest and tax
    (1,884 )     6,076       5,419  
   


51


 

Performance review
 
Non-operating items
                         
     
                    $ million  
     
    2008     2007     2006  
     
Exploration and Production
                       
Impairment and gain (loss) on sale of businesses and fixed assets
    (1,015 )     857       2,410  
Environmental and other provisions
    (12 )     (12 )     (17 )
Restructuring, integration and rationalization costs
    (57 )     (186 )      
Fair value gain (loss) on embedded derivatives
    (163 )           603  
Other
    257       (168 )     (433 )
     
 
    (990 )     491       2,563  
     
 
                       
Refining and Marketing
                       
Impairment and gain (loss) on sale of businesses and fixed assets
    801       (35 )     726  
Environmental and other provisions
    (64 )     (138 )     (33 )
Restructuring, integration and rationalization costs
    (447 )     (118 )      
Fair value gain (loss) on embedded derivatives
    57              
Other
          (661 )     (580 )
     
 
    347       (952 )     113  
     
 
                       
Other businesses and corporate
                       
Impairment and gain (loss) on sale of businesses and fixed assets
    (166 )     (14 )     29  
Environmental and other provisions
    (117 )     (35 )     94  
Restructuring, integration and rationalization costs
    (254 )     (34 )      
Fair value gain (loss) on embedded derivatives
    (5 )     (7 )     5  
Other
    (91 )     (172 )     (200 )
     
 
    (633 )     (262 )     (72 )
     
Total before taxation for continuing operations
    (1,276 )     (723 )     2,604  
Taxationa
    480       350       (1,073 )
     
Total after taxation for continuing operations
    (796 )     (373 )     1,531  
     
Fair value accounting effects
                         
     
                    $ million  
     
    2008     2007     2006  
     
Exploration and Production
                       
Unrecognized gains (losses) brought forward from previous period
    107       155       123  
Unrecognized (gains) losses carried forward
    (389 )     (107 )     (155 )
     
Favourable (unfavourable) impact relative to management’s measure of performance
    (282 )     48       (32 )
     
 
                       
Refining and Marketing
                       
Unrecognized gains (losses) brought forward from previous period
    429       72       283  
Unrecognized (gains) losses carried forward
    82       (429 )     (72 )
     
Favourable (unfavourable) impact relative to management’s measure of performance
    511       (357 )     211  
     
 
    229       (309 )     179  
Taxationa
    (83 )     111       (107 )
     
 
    146       (198 )     72  
     
 
                       
By region
                       
Exploration and Production
                       
     
UK
    45       1       63  
Rest of Europe
                 
US
    (231 )     (77 )     (59 )
Rest of World
    (96 )     124       (36 )
     
 
    (282 )     48       (32 )
     
 
                       
Refining and Marketing
                       
     
UK
    186       (52 )     109  
Rest of Europe
    54       (110 )     101  
US
    231       (165 )     13  
Rest of World
    40       (30 )     (12 )
     
 
    511       (357 )     211  
     
 
aThe amounts shown for taxation are based upon the effective tax rate on group profit.

52


 

Performance review
 
                         
     
                    $ million  
     
    2008     2007     2006  
     
Environmental expenditure
                       
Operating expenditure
    755       662       596  
Clean-ups
    64       62       59  
Capital expenditure
    1,104       1,033       806  
Additions to environmental remediation provision
    270       373       423  
Additions to decommissioning provision
    326       1,163       2,142  
     

Operating and capital expenditure on the prevention, control, abatement or elimination of air, water and solid waste pollution is often not incurred as a separately identifiable transaction. Instead, it forms part of a larger transaction that includes, for example, normal maintenance expenditure. The figures for environmental operating and capital expenditure in the table are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute.
          Environmental operating expenditure of $755 million in 2008 was higher than in 2007 and reflects continuing integrity management activity. There were no individually significant factors driving the increase.
          The increase in environmental operating expenditure in 2007 compared with 2006 is primarily due to increased integrity management activity and activity associated with the implementation of the Baker Panel recommendations. Similar levels of operating and capital expenditures are expected in the foreseeable future. In addition to operating and capital expenditures, we also create provisions for future environmental remediation. Expenditure against such provisions is normally in subsequent periods and is not included in environmental operating expenditure reported for such periods. The charge for environmental remediation provisions in 2008 includes $234 million resulting from a reassessment of existing site obligations and $36 million in respect of provisions for new sites.
          Provisions for environmental remediation are made when a cleanup is probable and the amount of the obligation can be reliably estimated. Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.
          The extent and cost of future environment restoration, remediation and abatement programmes are often inherently difficult to estimate. They often depend on the extent of contamination, and the associated impact and timing of the corrective actions required, technological feasibility and BP’s share of liability. Though the costs of future programmes could be significant and may be material to the results of operations in the period in which they are recognized, it is not expected that such costs will be material to the group’s overall results of operations or financial position.
In addition, we make provisions on installation of our oil- and gas-producing assets and related pipelines to meet the cost of eventual decommissioning. On installation of an oil or natural gas production facility a provision is established that represents the discounted value of the expected future cost of decommissioning the asset. Additionally, we undertake periodic reviews of existing provisions. These reviews take account of revised cost assumptions, changes in decommissioning requirements and any technological developments. The level of increase in the decommissioning provision varies with the number of new fields coming onstream in a particular year and the outcome of the periodic reviews.
          Provisions for environmental remediation and decommissioning are usually set up on a discounted basis, as required by IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’.
          Further details of decommissioning and environmental provisions appear in Financial statements - Note 37 on page 156. See also Environment on page 39.
Suppliers and contractors
Our processes are designed to enable us to choose suppliers carefully on merit, avoiding conflicts of interest and inappropriate gifts and entertainment. We expect suppliers to comply with legal requirements and we seek to do business with suppliers who act in line with BP’s commitments to compliance and ethics, as outlined in the code of conduct. We engage with suppliers in a variety of ways, including performance review meetings to identify mutually advantageous ways to improve performance.
Creditor payment policy and practice
Statutory regulations issued under the UK Companies Act 1985 require companies to make a statement of their policy and practice in respect of the payment of trade creditors. In view of the international nature of the group’s operations there is no specific group-wide policy in respect of payments to suppliers. Relationships with suppliers are, however, governed by the group’s policy commitment to long-term relationships founded on trust and mutual advantage. Within this overall policy, individual operating companies are responsible for agreeing terms and conditions for their business transactions and ensuring that suppliers are aware of the terms of payment.


53


 

Performance review
 
Liquidity and capital resources
Cash flow
The following table summarizes the group’s cash flows.
                         
     
                    $ million  
     
    2008     2007     2006  
     
Net cash provided by operating activities
    38,095       24,709       28,172  
Net cash used in investing activities
    (22,767 )     (14,837 )     (9,518 )
Net cash used in financing activities
    (10,509 )     (9,035 )     (19,071 )
Currency translation differences relating to cash and cash equivalents
    (184 )     135       47  
     
Increase (decrease) in cash and cash equivalents
    4,635       972       (370 )
Cash and cash equivalents at beginning of year
    3,562       2,590       2,960  
     
Cash and cash equivalents at end of year
    8,197       3,562       2,590  
     

Net cash provided by operating activities for the year ended 31 December 2008 was $38,095 million compared with $24,709 million for the equivalent period of 2007 reflecting a decrease in working capital requirements of $11,250 million, an increase in profit before taxation of $2,672 million and an increase in dividends from jointly controlled entities and associates of $1,255 million; these were partly offset by an increase in income taxes paid of $3,752 million.
          Net cash provided by operating activities for the year ended 31 December 2007 was $24,709 million, compared with $28,172 million for the equivalent period for 2006 reflecting an increase in working capital requirements of $6,282 million, a decrease in profit before taxation from continuing operations of $3,531 million, a decrease in dividends from jointly controlled entities and associates of $2,022 million; these were partially offset by a decrease in income taxes paid of $4,661 million, a lower net credit for impairment and gains and losses on sale of businesses and fixed assets of $2,357 million and higher depreciation, depletion and amortization of $1,451 million.
          Net cash used in investing activities was $22,767 million in 2008, compared with $14,837 million and $9,518 million in 2007 and 2006. The increase in 2008 reflected a reduction in disposal proceeds of $3,338 million and an increase in capital expenditure of $5,303 million. The increase in 2007 reflected a reduction in disposal proceeds of $1,987 million and an increase in capital expenditure of $2,713 million.
          Net cash used in financing activities was $10,509 million in 2008 compared with $9,035 million in 2007 and $19,071 million in 2006. The increase in 2008 reflects a decrease in short-term debt of $2,809 million and an increase in dividends paid of $2,434 million; these were partly offset by a $4,546 million decrease in the net repurchase of shares. The reduction in 2007 compared with 2006 reflects a reduction in net repurchases of shares of $8,038 million and an increase in proceeds from long-term financing of $4,278 million; these were partially offset by a net decrease in short-term debt of $2,379 million.
          The group has had significant levels of capital investment for many years. Cash flow in respect of capital investment, excluding acquisitions, was $23.7 billion in 2008, $18.4 billion in 2007 and $15.7 billion in 2006. Sources of funding are completely fungible, but the majority of the group’s funding requirements for new investment come from cash generated by existing operations. The group’s level of net debt, that is debt less cash and cash equivalents, was $25.0 billion at the end of 2008, $26.8 billion at the end of 2007 and was $21.1 billion at the end of 2006.
          During the period 2006 to 2008, our total sources of cash amounted to $104 billion, whilst our total uses of cash amounted to $112 billion. The net cash usage of $8 billion was financed by an increase in finance debt of $13 billion over the three-year period, offset by an increase in our balance of cash and cash equivalents of $5 billion. During this period, the price of Brent has averaged $78.26 per barrel. The following table summarizes the three-year sources and uses of cash.
         
 
    $ 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 )
   
Acquisitions made for cash were more than offset by divestments. Net investment during the same period has averaged $16 billion per year. Dividends to BP shareholders, which grew on average by 16.8% per year in dollar terms, used $26 billion. Net repurchase of shares was $25 billion, which includes $26 billion in respect of our share buyback programme less net proceeds from shares issued in connection with employee share schemes. Finally, cash was used to strengthen the financial condition of certain of our pension plans. In the past three years, $2 billion has been contributed to funded pension plans. This is reflected in net cash provided by operating activities in the table above.
Trend information
We expect the short-term outlook for oil prices to be impacted by OPEC cuts on the one hand, and the outlook for the world economy and oil demand on the other. We expect continued volatility and our current expectation is that oil prices, relative to 2008, will continue to be low in 2009, and that this could extend into 2010.
          In Exploration and Production, total production is expected to be somewhat higher in 2009. The actual growth rate will depend on a number of factors, including our pace of capital spending, the efficiency of that spend (in turn depending on industry cost deflation), the oil price and its impact on PSAs as well as OPEC quota restrictions.
          In Refining and Marketing, 2009 is expected to be a challenging environment with reduced demand for our products, leading to lower volumes and pressure on margins. The impact is expected to be greatest in the petrochemicals sector. In 2009, with our US refining system fully operational, we expect our overall refining availability to be higher than in 2008.


54


 

Performance review
 

During 2008, we established momentum in cost control, mitigating the cost inflation that was primarily driven by rising oil prices. In 2009, our highest priority will continue to be achieving safe, compliant and reliable operations and we intend to continue our focus on cost efficiency. We expect cost deflation to be increasingly visible as we move through 2009.
          We expect capital expenditure, excluding acquisitions and asset exchanges, to be around $20-21 billion in 2009. This reflects our intention in Exploration and Production to maintain investment whilst vigorously working to drive down costs and to reduce spending in our Refining and Marketing and Alternative Energy businesses in keeping with the current weak economic environment. We expect disposal proceeds to be between $2-3 billion in 2009.
          On the basis of our current plans, we expect cash inflows and outflows in 2009 would balance at oil prices of around $60/bbl, taking account of expected disposal proceeds. We would expect that break even point to lower as we realize the benefits of our operational momentum and our action on costs.
Dividends and other distributions to shareholders
The total dividend paid to BP shareholders in 2008 was $10,342 million, compared with $8,106 million for 2007. The dividend paid per share was 55.05 cents, an increase of 30% compared with 2007. In sterling terms, the dividend increased 40% due to the strengthening of the dollar relative to sterling. We determine the dividend in US dollars, the economic currency of BP.
          During 2008, the company repurchased 269.8 million of its own shares for cancellation at a cost of $2.9 billion. The repurchased shares had a nominal value of $67.5 million and represented 1.4% of ordinary shares in issue, net of treasury shares, at the end of 2007. Since the inception of the share repurchase programme in 2000, we have repurchased 4,929 million shares at a cost of $51.1 billion.
          Our aim is to strike the right balance for shareholders, between current returns via the dividend, sustained investment for long-term growth, and maintaining a prudent gearing level. At the beginning of 2008, we rebalanced our distributions away from share buybacks in favour of dividends.
          BP intends to continue the operation of the Dividend Reinvestment Plan (DRIP) for shareholders who wish to receive their dividend in the form of shares rather than cash. The BP Direct Access Plan for US and Canadian shareholders also includes a dividend reinvestment feature.
          The discussion above and following contains forward-looking statements with regard to oil prices, production, demand for refining products, refining volumes and margins and impact on the petrochemicals sector, refining availability, continuing priority of safe, compliant and reliable operations, and focus on cost efficiency, cost deflation, capital expenditure, expected disposal proceeds, cash flows, shareholder distributions, gearing, working capital, guarantees, expected payments under contractual and commercial commitments and purchase obligations. These forward-looking statements are based on assumptions that management believes to be reasonable in the light of the group’s operational and financial experience. However, no assurance can be given that the forward-looking statements will be realized. You are urged to read the cautionary statement under Forward-looking statements on page 10 and Risk factors on pages 8-10, which describe the risks and uncertainties that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements. The company provides no commitment to update the forward-looking statements or to publish financial projections for forward-looking statements in the future.
Financing the group’s activities
The group’s principal commodity, oil, is priced internationally in US dollars. Group policy has been to minimize economic exposure to currency movements by financing operations with US dollar debt wherever possible, otherwise by using currency swaps when funds have been raised in currencies other than US dollars.
          The group’s finance debt is almost entirely in US dollars and at 31 December 2008 amounted to $33,204 million (2007 $31,045 million) of which $15,740 million (2007 $15,394 million) was short term.
          Net debt was $25,041 million at the end of 2008, a decrease of $1,776 million compared with 2007. We believe that a net debt ratio, that is net debt to net debt plus equity, of 20-30% provides an efficient capital structure and the appropriate level of financial flexibility. The net debt ratio was 21% at the end of 2008 and 22% at the end of 2007, close to the lower end of our target band. Net debt, which BP uses as a measure of financial gearing, includes the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge accounting is claimed.
          The maturity profile and fixed/floating rate characteristics of the group’s debt are described in Financial statements – Note 28 on page 140 and Note 35 on page 153.
          We have in place a European Debt Issuance Programme (DIP) under which the group may raise $20 billion of debt for maturities of one month or longer. At 31 December 2008, the amount drawn down against the DIP was $10,334 million (2007 $10,438 million).
          In addition, the group has in place a US Shelf Registration under which it may raise $10 billion of debt with maturities of one month or longer. At 31 December 2008, the amount raised under the US Shelf Registration was $6,500 million (2007 $2,500 million).
          Commercial paper markets in the US and Europe are a primary source of liquidity for the group. At 31 December 2008, the outstanding commercial paper amounted to $4,268 million (2007 $5,881 million).
          The group also has access to significant sources of liquidity in the form of committed facilities and other funding through the capital markets. At 31 December 2008, the group had available undrawn committed borrowing facilities of $4,950 million (2007 $4,950 million).
          Despite current uncertainty in the financial markets, including a lack of liquidity for some borrowers, we have been able to issue $5 billion of long-term debt in the fourth quarter of 2008. In addition, we have been able to issue short-term commercial paper at competitive rates. In the context of unforeseen market volatility, we have however, increased the cash and cash equivalents held by the group to $8.2 billion at the end of 2008, compared with $3.6 billion at the end of 2007.
          BP believes that, taking into account the substantial amounts of undrawn borrowing facilities available, the group has sufficient working capital for foreseeable requirements.
Off-balance sheet arrangements
At 31 December 2008, the group’s share of third-party finance debt of equity-accounted entities was $6,675 million (2007 $6,764 million). These amounts are not reflected in the group’s debt on the balance sheet.
          The group has issued third-party guarantees under which amounts outstanding at 31 December 2008 are summarized on the following page. Some guarantees outstanding are in respect of borrowings of jointly controlled entities and associates noted above. The analysis by time period indicates the ultimate expiry of the guarantees.


55


 

Performance review
 
                                                         
     
                                                    $ million  
     
                                            Guarantees expiring by period  
     
                                                    2014 and  
    Total     2009     2010     2011     2012     2013     thereafter  
     
Guarantees issued in respect ofa
                                                       
Liabilities and borrowings of jointly controlled entities and associates
    223       70       32       25       6       6       84  
Liabilities and borrowings of other third parties
    613       94       19       30       35       34       401  
     
 
aOf the amounts shown in the table, $215 million of the jointly controlled entities and associates guarantees relate to guarantees of borrowings and for other third party guarantees, $582 million relates to guarantees of borrowings.
Contractual commitments
The following table summarizes the group’s principal contractual obligations at 31 December 2008. Further information on borrowings and finance leases is given in Financial statements – Note 35 on page 153 and more information on operating leases is given in Financial statements – Note 16 on page 130.
                                                         
     
                                                    $ million  
     
                                            Payments due by period  
     
Expected payments by period under contractual                                                   2014 and  
obligations and commercial commitments   Total     2009     2010     2011     2012     2013     thereafter  
     
Borrowingsa
    35,192       16,554       5,817       3,303       2,577       5,014       1,927  
Finance lease future minimum lease payments
    916       116       117       116       70       58       439  
Operating leasesb
    18,795       4,135       3,215       2,340       1,897       1,688       5,520  
Decommissioning liabilities
    12,347       348       361       211       157       197       11,073  
Environmental liabilities
    1,797       422       380       204       177       129       485  
Pensions and other post-retirement benefitsc
    26,288       1,105       1,352       1,346       1,346       1,342       19,797  
Purchase obligationsd
    115,642       64,479       13,317       6,559       5,100       4,531       21,656  
     
Total
    210,977       87,159       24,559       14,079       11,324       12,959       60,897  
     
 
aExpected payments include interest payments on borrowings totalling $2,607 million ($907 million in 2009, $608 million in 2010, $421 million in 2011, $318 million in 2012, $236 million in 2013 and $117 million thereafter).
 
bThe future minimum lease payments are before deducting related rental income from operating sub-leases. Where an operating lease is entered into solely by the group as the operator of a jointly controlled asset, the total cost is included irrespective of any amounts that will be reimbursed by joint venture partners. Where operating lease costs are incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project.
 
cRepresents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post- retirement benefits.
 
dRepresents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2009 include purchase commitments existing at 31 December 2008 entered into principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements – Note 28 on page 140.
The following table summarizes the nature of the group’s unconditional purchase obligations.
                                                         
     
                                                    $ 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  
     
The group expects its total capital expenditure, excluding acquisitions and asset exchanges to be around $20-21 billion in 2009. The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2008 and the proportion of that expenditure for which contracts have been placed. Capital expenditure is considered to be committed when the project has received the appropriate level of internal management approval. For jointly controlled assets, the net BP share is included in the amounts shown. Where operating lease costs are incurred in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. Such costs are included in the amounts shown.
                                                         
     
                                                    $ million  
     
                                                    2014 and  
Capital expenditure commitments   Total     2009     2010     2011     2012     2013     thereafter  
     
Committed on major projects
    35,845       14,936       8,154       5,175       3,136       1,580       2,864  
Amounts for which contracts have been placed
    14,062       8,175       2,908       1,197       621       402       759  
     
In addition, at 31 December 2008, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $1.2 billion. Contracts were in place for $0.8 billion of this total.

56


 

Performance review
 

Critical accounting policies
The significant accounting policies of the group are summarized in Financial statements – Note 1 on page 106.
          Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for BP management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual outcomes could differ from the estimates and assumptions used. The following summary provides more information about the critical accounting policies that could have a significant impact on the results of the group and should be read in conjunction with the Notes on financial statements.
          The accounting policies and areas that require the most significant judgements and estimates used in the preparation of the consolidated financial statements are in relation to oil and natural gas accounting, including the estimation of reserves, the recoverability of asset carrying values, taxation, derivative financial instruments, provisions and contingencies, and pensions and other post-retirement benefits.
Oil and natural gas accounting
The group follows the successful efforts method of accounting for its oil and natural gas exploration and production activities.
          The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred.
          Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still under way or firmly planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a range of technical and commercial considerations and sufficient progress is being made on establishing development plans and timing. If no future activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on a straight-line basis over the estimated period of exploration.
          For exploration wells and exploratory-type stratigraphic test wells, costs directly associated with the drilling of wells are initially capitalized within intangible assets, pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. The determination is usually made within one year after well completion, but can take longer, depending on the complexity of the geological structure. If the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploration wells that discover potentially economic quantities of oil and gas and are in areas where major capital expenditure (e.g. offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration appraisal work is under way or firmly planned.
          It is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and gas field is performed or while the optimum development plans and timing are established.
All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately expensed.
          Once a project is sanctioned for development, the carrying values of exploration licence and leasehold property acquisition costs and costs associated with exploration wells and exploratory-type stratigraphic test wells, are transferred to production assets within property, plant and equipment.
          The capitalized exploration and development costs for proved oil and gas properties (which include the costs of drilling unsuccessful wells) are amortized on the basis of oil-equivalent barrels that are produced in a period as a percentage of the estimated proved reserves. Field development costs subject to depreciation are expenditures incurred to date, together with approved future development expenditure required to develop reserves.
          The estimated proved reserves used in these unit-of-production calculations vary with the nature of the capitalized expenditure. The reserves used in the calculation of the unit-of-production amortization are as follows:
  Producing wells – proved developed reserves.
  Licence and property acquisition, field development and future decommissioning costs – total proved reserves.
The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the expected future production. If proved reserves estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the property’s carrying value (see discussion of recoverability of asset carrying values on the following page).
          At the end of 2006, BP adopted the SEC rules for estimating reserves instead of the UK accounting rules contained in the UK Statement of Recommended Practice. These changes are explained in Financial statements – Note 10 on page 125.
          The estimation of oil and natural gas reserves and BP’s process to manage reserves bookings is described in Exploration and Production - Reserves and production on page 14. As discussed on the following page, oil and natural gas reserves have a direct impact on the assessment of the recoverability of asset carrying values reported in the financial statements.
          The 2008 movements in proved reserves are reflected in the tables showing movements in oil and gas reserves by region in Financial statements – Supplementary information on oil and natural gas on pages 185 to 193.


57


 

Performance review
 

Recoverability of asset carrying values
BP assesses its fixed assets, including goodwill, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable and, as a result, charges for impairment are recognized in the group’s results from time to time. Such indicators include changes in the group’s business plans, changes in commodity prices leading to unprofitable performance, low plant utilization, evidence of physical damage and, for oil and gas properties, significant downward revisions of estimated volumes or increases in estimated future development expenditure. If there are low oil prices, natural gas prices, refining margins or marketing margins during an extended period, the group may need to recognize significant impairment charges.
          The assessment for impairment entails comparing the carrying value of the cash-generating unit with its recoverable amount, that is, the higher of fair value less costs to sell and value in use. Value in use is usually determined on the basis of discounted estimated future net cash flows.
          Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas and refined products.
          For oil and natural gas properties, the expected future cash flows are estimated based on the group’s plans to continue to develop and produce proved reserves and associated risk-adjusted probable and possible volumes. Expected future cash flows from the sale or production of these volumes are calculated based on the management’s best estimate of future oil and gas prices. Prices for oil and natural gas used for future cash flow calculations are based on market prices for the first five years and the group’s long-term planning assumptions thereafter. As at 31 December 2008, the group’s long-term planning assumptions were $75 per barrel for Brent and $7.50/mmBtu for Henry Hub (2007 $60 per barrel and $7.50/mmBtu). These long-term planning assumptions are subject to periodic review and modification. The estimated future level of production is based on assumptions about future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors.
          The future cash flows are adjusted for risks specific to the cash-generating unit and are discounted using a pre-tax discount rate. The discount rate is derived from the group’s post-tax weighted average cost of capital and is adjusted where applicable to take into account any specific risks relating to the country where the cash-generating unit is located. Typically rates of 11% or 13% are used (2007 11% or 13%). The rate applied in each country is re-assessed each year by analyzing relevant information.
          Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in a business combination. The group carries goodwill of approximately $9.9 billion on its balance sheet, principally relating to the Atlantic Richfield and Burmah Castrol acquisitions. In testing goodwill for impairment, the group uses a similar approach to that described above. If there are low oil prices or natural gas prices or refining margins or marketing margins for an extended period, the group may need to recognize significant goodwill impairment charges.
Taxation
The computation of the group’s income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome.
          In addition, the group has carry-forward tax losses in certain taxing jurisdictions that are available to offset against future taxable profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgement is exercised in assessing whether this is the case.
          To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods. For more information see Financial statements – Note 20 on page 133 and Note 44 on page 172.
Derivative financial instruments
The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices as well as for trading purposes. In addition, derivatives embedded within other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of the host contract. All such derivatives are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Gains and losses arising from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.
          In some cases the fair values of derivatives are estimated using models and other valuation methods due to the absence of quoted prices or other observable, market-corroborated data. In particular, this applies to the majority of the group’s natural gas and LNG embedded derivatives. These are primarily long-term UK gas contracts that use pricing formulae not related to gas prices, for example, oil product and power prices. These contracts are valued using models with inputs that include price curves for each of the different products that are built up from active market pricing data and extrapolated to the expiry of the contracts using the maximum available external pricing information. Additionally, where limited data exists for certain products, prices are interpolated using historic and long-term pricing relationships. Price volatility is also an input for the models. Changes in the key assumptions could have a material impact on the gains and losses on embedded derivatives recognized in the income statement. For more information see Financial statements - Note 34 on page 148. An analysis of the sensitivity of the fair value of the natural gas and LNG derivatives to changes in the key assumptions is provided in Financial statements - Note 28 on page 140.


58


 

Performance review
 

Provisions and contingencies
The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest asset removal obligations facing BP relate to the removal and disposal of oil and natural gas platforms and pipelines around the world. The estimated discounted costs of dismantling and removing these facilities are accrued on the installation of those facilities, reflecting our legal obligations at that time. A corresponding asset of an amount equivalent to the provision is also created within property, plant and equipment. This asset is depreciated over the expected life of the production facility or pipeline. Most of these removal events are many years in the future and the precise requirements that will have to be met when the removal event actually occurs are uncertain. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public expectations. Consequently, the timing and amounts of future cash flows are subject to significant uncertainty. Changes in the expected future costs are reflected in both the provision and the asset.
          Decommissioning provisions associated with downstream and petrochemicals facilities are generally not provided for, as such potential obligations cannot be measured, given their indeterminate settlement dates. The group performs periodic reviews of its downstream and petrochemicals long-lived assets for any changes in facts and circumstances that might require the recognition of a decommissioning provision.
          The timing and amount of future expenditures are reviewed annually, together with the interest rate used in discounting the cash flows. The interest rate used to determine the balance sheet obligation at the end of 2008 was 2%, unchanged from the end of 2007. The interest rate represents the real rate (i.e. adjusted for inflation) on long-dated government bonds.
          Other provisions and liabilities are recognized in the period when it becomes probable that there will be a future outflow of funds resulting from past operations or events and the amount of cash outflow can be reliably estimated. The timing of recognition requires the application of judgement to existing facts and circumstances, which can be subject to change. Since the actual cash outflows can take place many years in the future, the carrying amounts of provisions and liabilities are reviewed regularly and adjusted to take account of changing facts and circumstances.
          A change in estimate of a recognized provision or liability would result in a charge or credit to net income in the period in which the change occurs (with the exception of decommissioning costs as described above).
          Provisions for environmental clean-up and remediation costs are based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.
          The provision for environmental liabilities is reviewed at least annually. The interest rate used to determine the balance sheet obligation at 31 December 2008 was 2%, the same rate as at the previous balance sheet date.
          As further described in Financial statements – Note 44 on page 172, the group is subject to claims and actions. The facts and circumstances relating to particular cases are evaluated regularly in determining whether it is ‘probable’ that there will be a future outflow of funds and, once established, whether a provision relating to a specific litigation should be adjusted. Accordingly, significant management judgement relating to contingent liabilities is required, since the outcome of litigation is difficult to predict.
Pensions and other post-retirement benefits
Accounting for pensions and other post-retirement benefits involves judgement about uncertain events, including estimated retirement dates, salary levels at retirement, mortality rates, rates of return on plan assets, determination of discount rates for measuring plan obligations, healthcare cost trend rates and rates of utilization of healthcare services by retirees. These assumptions are based on the environment in each country. Determination of the projected benefit obligations for the group’s defined benefit pension and post-retirement plans is important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The assumptions used may vary from year to year, which will affect future results of operations. Any differences between these assumptions and the actual outcome also affect future results of operations.
          Pension and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to determine the projected benefit obligation at the year-end and hence the surpluses and deficits recorded on the group’s balance sheet, and pension and other post-retirement benefit expense for the following year.
          The pension and other post-retirement benefit assumptions at 31 December 2008, 2007 and 2006 are provided in Financial statements – Note 38 on page 157.
          The assumed rate of investment return, discount rate and the US healthcare cost trend rate have a significant effect on the amounts reported. A sensitivity analysis of the impact of changes in these assumptions on the benefit expense and obligation is provided in Financial statements - Note 38 on page 157.
          In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice in the countries in which we provide pensions and have been chosen with regard to the latest available published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension liabilities are in the UK, US and Germany and the mortality assumptions for these countries are detailed in Financial statements - Note 38 on page 157.


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60


 

Board performance
and biographies
 

     
 
62
  Directors and senior management
 
 
65
  BP board performance report


 

 


 

Directors and senior management
 
Directors and senior management
The following lists the company’s directors and senior management as at 18 February 2009.
         
 
Name       Initially elected or appointed
 
P D Sutherland
  Chairman   Chairman since May 1997
 
      Director since July 1995
Sir Ian Prosser
  Non-Executive Deputy Chairman   Deputy chairman since February 1999
 
      Director since May 1997
A Burgmans
  Non-Executive Director   February 2004
C B Carroll
  Non-Executive Director   June 2007
Sir William Castell
  Non-Executive Director   July 2006
G David
  Non-Executive Director   February 2008
E B Davis, Jr
  Non-Executive Director   December 1998
D J Flint
  Non-Executive Director   January 2005
Dr D S Julius
  Non-Executive Director   November 2001
Sir Tom McKillop
  Non-Executive Director   July 2004
Dr A B Hayward
  Executive Director (Group Chief Executive)   Group Chief Executive since May 2007
 
      Director since February 2003
I C Conn
  Executive Director (Chief Executive, Refining and Marketing)   July 2004
Dr B E Grote
  Executive Director (Chief Financial Officer)   August 2000
A G Inglis
  Executive Director (Chief Executive, Exploration and Production)   February 2007
R Bondy
  Group General Counsel   May 2008
S Bott
  Executive Vice President, Human Resources   March 2005
V Cox
  Executive Vice President, Alternative Energy   July 2004
H L McKay
  Executive Vice President (Chairman and President of BP America Inc.)   June 2008
J Mogford
  Executive Vice President (Chief Operating Officer, Refining and US Fuels Value Chains)   October 2007
S Westwell
  Executive Vice President (Group Chief of Staff)   January 2008
 
Mr H L McKay, previously executive vice president (special projects), was appointed chairman and president of BP America Inc. on the retirement of Mr R A Malone on 1 February 2009.
Dr D C Allen retired as a director on 31 March 2008 and Dr W E Massey retired as a director on 17 April 2008. Mr G David was appointed a non-executive director on 11 February 2008. At the company’s 2008 annual general meeting (AGM), the following directors retired, offered themselves for election/re-election and were duly elected/re-elected: Mr A Burgmans; Mrs C B Carroll; Sir William Castell; Mr I C Conn; Mr G David, Mr E B Davis, Jr; Mr D J Flint; Dr B E Grote; Dr A B Hayward; Mr A G Inglis; Dr D S Julius; Sir Tom McKillop; Sir Ian Prosser and Mr P D Sutherland.
Mr R Dudley has been appointed to the board with effect from 6 April 2009. All of the directors, including Mr Dudley, will offer themselves for election/ re-election at the company’s 2009 AGM.
David Jackson (56) was appointed company secretary in 2003. A solicitor, he is a director of BP Pension Trustees Limited and a member of the Listing Authorities Advisory Committee.

62


 

Directors and senior management
 

Directors
P D Sutherland, SC, KCMG
Chairman of the chairman’s and the nomination committees and attends meetings of the remuneration committee
Peter Sutherland (62) rejoined BP’s board in 1995, having been a non-executive director from 1990 to 1993, and was appointed chairman in 1997. He is non-executive chairman of Goldman Sachs International and was a non-executive director of The Royal Bank of Scotland Group PLC from 2001 to 6 February 2009.
Sir Ian Prosser
Member of the chairman’s, the nomination and the remuneration committees and chairman of the audit committee
Sir Ian (65) joined BP’s board in 1997 and was appointed non-executive deputy chairman in 1999. He is the senior independent director. In 2003, he retired as chairman of InterContinental Hotels Group PLC, a spin-off from the former Bass PLC where he was chief executive.
He is a non-executive director and senior independent director of GlaxoSmithKline plc, a non-executive director of the Sara Lee Corporation and non-executive chairman of The Navy, Army and Air Force Institutes (NAAFI). He was previously on the boards of The Boots Company PLC and Lloyds TSB PLC.
A Burgmans, KBE
Member of the chairman’s and the safety, ethics and environment assurance committees
Antony Burgmans (62) joined BP’s board in 2004. He was appointed to the board of Unilever in 1991. In 1999, he became chairman of Unilever NV and vice chairman of Unilever PLC. In 2005, he became non-executive chairman of Unilever PLC and Unilever NV, retiring from these appointments in May 2007. He is also a member of the supervisory boards of Akzo Nobel NV and Aegon NV.
C B Carroll
Member of the chairman’s and safety, ethics and environment assurance committees
Cynthia Carroll (52) joined BP’s board in June 2007. She started her career at Amoco and in 1989 she joined Alcan, where in 2002 she was appointed president and chief executive officer of Alcan’s primary metals group and an officer of Alcan, Inc. She was appointed as chief executive of Anglo American plc, the global mining group, in March 2007. She is also a director of De Beers s.a. and Anglo Platinum Ltd.
Sir William Castell, LVO
Member of the chairman’s committee and chairman of the safety, ethics and environment assurance committee
Sir William (61) joined BP’s board in 2006. From 1990 to 2004, he was chief executive of Amersham plc and subsequently president and chief executive officer of GE Healthcare. He was appointed as a vice chairman of the board of GE in 2004, stepping down from this post in 2006 when he became chairman of the Wellcome Trust. He remains a non-executive director of GE.
G David
Member of the chairman’s and the audit committees
George David (66) joined BP’s board on 11 February 2008. He has spent his career with United Technologies Corporation (UTC), as its chief executive officer from 1994 to 2008 and chairman since 1997. He joined UTC’s Otis elevator subsidiary in 1975.
E B Davis, Jr
Member of the chairman’s, the audit and the remuneration committees
Erroll B Davis, Jr (64) joined BP’s board in 1998, having previously been a director of Amoco. He was chairman and chief executive officer of Alliant Energy, relinquishing this dual appointment in 2005. He continued as chairman of Alliant Energy until February 2006, leaving to become chancellor of the University System of Georgia. He is a member of the board of General Motors Corporation and Union Pacific Corporation.
D J Flint, CBE
Member of the chairman’s and the audit committees
Douglas Flint (53) joined BP’s board in 2005. He trained as a chartered accountant and became a partner at KPMG in 1988. In 1995, he was appointed group finance director of HSBC Holdings plc. He was chairman of the Financial Reporting Council’s review of the Turnbull Guidance on Internal Control. Between 2001 and 2004, he served on the Accounting Standards Board and the Standards Advisory Council of the International Accounting Standards Board.
Dr D S Julius, CBE
Member of the chairman’s and the nomination committees and chairman of the remuneration committee
DeAnne Julius (59) joined BP’s board in 2001. She began her career as a project economist with the World Bank in Washington. From 1986 until 1997, she held a succession of posts, including chief economist at British Airways and Royal Dutch Shell Group. From 1997 to 2001, she was a full time member of the Monetary Policy Committee of the Bank of England. She is chairman of the Royal Institute of International Affairs and a non-executive director of Roche Holdings SA and Jones Lang LaSalle, Inc.
Sir Tom McKillop
Member of the chairman’s, the remuneration and the safety, ethics and environment assurance committees
Sir Tom (65) joined BP’s board in 2004. Sir Tom was chief executive of AstraZeneca PLC from the merger of Astra AB and Zeneca Group PLC in 1999 until December 2005. He was a non-executive director of Lloyds TSB Group PLC until 2004 and was appointed to the board of The Royal Bank of Scotland Group PLC in 2005, where he was chairman from 2006 to 3 February 2009.
Dr A B Hayward
Tony Hayward (51) joined BP in 1982. He held a series of roles in exploration and production, becoming a director of exploration and production in 1997. In 2000, he was made group treasurer, and an executive vice president in 2002. He was chief executive officer of exploration and production between 2002 and February 2007. He became an executive director of BP in 2003 and was appointed as group chief executive in May 2007. Dr Hayward is a non-executive director and senior independent director of Tata Steel.
I C Conn
Iain Conn (46) joined BP in 1986. Following a variety of roles in oil trading, commercial refining, retail and commercial marketing operations, and exploration and production, in 2000 he became group vice president of BP’s refining and marketing business. From 2002 to 2004, he was chief executive of petrochemicals. He was appointed group executive officer with a range of regional and functional responsibilities and an executive director in 2004. He was appointed chief executive of refining and marketing in June 2007. He is a non-executive director and senior independent director of Rolls-Royce Group plc.


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Directors and senior management
 

Dr B E Grote
Byron Grote (60) joined BP in 1987 following the acquisition of The Standard Oil Company of Ohio, where he had worked since 1979. He became group treasurer in 1992 and in 1994 regional chief executive in Latin America. In 1999, he was appointed an executive vice president of exploration and production, and chief executive of chemicals in 2000. He was appointed an executive director of BP in 2000 and chief financial officer in 2002. He is a non-executive director of Unilever NV and Unilever PLC.
A G Inglis
Andy Inglis (49) joined BP in 1980, working on various North Sea projects. Following a series of commercial roles in exploration, in 1996 he became chief of staff, exploration and production. From 1997 until 1999, he was responsible for leading BP’s activities in the deepwater Gulf of Mexico. In 1999, he was appointed vice president of BP’s US western gas business unit. In 2004, he became executive vice president and deputy chief executive of exploration and production. He was appointed chief executive of BP’s exploration and production business and an executive director in February 2007. He is a non-executive director of BAE Systems plc.
Senior management
R Bondy
Rupert Bondy (47) joined BP as group general counsel in May 2008. In 1989 he joined US law firm Morrison & Foerster, working in San Francisco and London. From 1994 to 1995, he worked for UK law firm Lovells in London. In 1995, he joined SmithKline Beecham as senior counsel for mergers and acquisitions and other corporate matters. He subsequently held positions of increasing responsibility and following the merger of SmithKline Beecham and GlaxoWellcome he was appointed senior vice president and general counsel of GlaxoSmithKline in 2001.
S Bott
Sally Bott (59) joined BP in 2005 as an executive vice president responsible for global human resources. Sally joined Citibank in 1970 and, following a variety of roles, was appointed a vice president in human resources in 1979 and subsequently held a series of positions as a human resources director to sectors of Citibank. In 1994, she joined Barclays De Zoete Wedd, an investment bank, as head of human resources and in 1997 became group human resources director of Barclays plc. From 2000 to early 2005, she was managing director of Marsh and McLennan and head of global human resources at Marsh Inc. In 2008, Sally was elected as a non-executive director of UBS AG.
V Cox
Vivienne Cox (49) joined BP in 1981. Following a series of commercial roles, she was appointed chief executive of Air BP in 1998. From 1999 until 2001, she was group vice president of BP Oil, responsible for business-to-business marketing and oil supply and trading. From 2001 to 2004, she was group vice president for integrated supply and trading. In 2004, she was appointed an executive vice president, responsible for gas, power and renewables in addition to the supply and trading businesses. In late 2005, she became responsible for Alternative Energy. She is a non-executive director of Rio Tinto plc and Climate Change Capital Limited.
H L McKay
Lamar McKay (50) was appointed chairman and president of BP America, Inc. from 1 February 2009. He joined Amoco Production Company as a petroleum engineer in 1980 and later served in a variety of operating, commercial and M&A roles. In 1993, he became general manager of Arkoma Basin and in 1997, the business unit leader for the Gulf of Mexico Shelf. During 1998-2000, he worked on the BP-Amoco merger and served as general manager for BP p.l.c. worldwide exploration and production strategy and planning. In 2000, he became business unit leader for the Central North Sea in Aberdeen, and subsequently chief of staff for worldwide exploration and production in London, following which he served as chief of staff for the BP deputy group chief executive. Lamar then worked as group vice president for Russia & Kazakhstan, during which time he was appointed to the board of TNK-BP. He was named executive vice-president of BP America and COO in the USA in May 2007. In early 2008, he became executive vice president of BP p.l.c. special projects, focusing on Russia, subsequently joining the group executive management team in June 2008.
J Mogford
John Mogford (55) joined BP in 1977, spending the early part of his career in a variety of drilling and production roles. In 1999, he became group vice president for health, safety and the environment before being appointed as group vice president for gas, power and renewables in 2002. In 2004, he returned to exploration and production as group vice president (technology and functions). In 2005, he was appointed as senior group vice president of safety and operations before becoming executive vice president, safety and operations in October 2007. He became chief operating officer of refining from 1 March 2008. On 15 January 2009, he moved to chief operating officer for US fuels value chains and head of refining.
S Westwell
Steve Westwell (50) joined BP in the manufacturing and supply division of BP Southern Africa in 1988. Following various retail positions in the UK and the US he was appointed head of retail and a member of the board of BP Southern Africa Pty. In 2003, he became president and chief executive officer of BP solar, and in 2004, group vice president of natural gas liquids, power, solar and renewables. In 2005, he was appointed group vice president of alternative energy. He was appointed group chief of staff on 1 January 2008.


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BP board performance report
 

BP board performance report
Letter from the chairman
I am once again pleased to introduce our board performance report. The report reviews the work of the board and its committees as my tenure as chairman moves to a close. Over the past 12 years, both the calibre of individuals who have served on the board and our system of governance has stood us in good stead. The strong set of principles on which we base our governance framework, which include clarity of roles, separation of powers, independence and appropriate skills, remain valid today.
          I have been encouraged from discussions with shareholders over time that our approach to governance and the dialogue which we continue to have with them is welcomed. This is important to us and no more so than during the testing times in which we operate.
          Recent events and the current economic climate have inevitably triggered further debate about governance. This I welcome. The framework of governance does need to be kept under review and, where necessary, challenged by investors, regulators and companies themselves to ensure that the system is delivering.
          Under such a review I believe that BP’s governance approach can show its strength. It requires active engagement on behalf of the company and investors alike. I do not believe that our comply or explain system is broken and it is important for us that the principles-based system continues.
Peter Sutherland
Chairman
24 February 2009
Board governance principles
The board governance principles (‘principles’) are designed to enable the board and the executive management to operate within a clear framework. The principles describe the role of the board, its processes, its relationship with executive management and the main tasks and requirements of the board committees. The principles are available at www.bp.com/corporategovernance.
          In carrying out its work, the board focuses on key tasks, which include the active review of the long-term strategy and the annual plan, monitoring the decisions and actions of the group chief executive, the performance of BP, the succession of executive management and the oversight of risk.
          The principles outline how the board delegates its authority for executive management of the company to the group chief executive, subject to monitoring by the board and a clearly defined set of limitations. These ‘executive limitations’ require that any executive action taken in the course of business takes specific issues into consideration, including health, safety and the environment, any reputational impact on BP, risk and the framework for internal control.
Operating the principles
The group chief executive through the annual plan describes to the board how the strategy is to be delivered, together with an assessment of the group’s risks. During the year, the board monitors progress and keeps the strategy under review.
          The group chief executive is obliged to review and discuss with the board all strategic projects or developments and all material matters currently or prospectively affecting the company and its performance.
          The principles are kept under review by the board to ensure they remain relevant and up to date.
Board activities in 2008
As outlined above, the board focuses on key areas in carrying out its work. Forward agendas are set to determine a high level work programme for the board based on its core tasks (including dealing with strategy and monitoring) but additional items are added throughout the
year depending on the exigencies of the business as they arise. During the year the board was involved in the following activities:
Strategy and Risk
The board undertook extensive discussions on strategic options for the group, including the future business and competitive environment, technology developments, pricing and demand models and portfolio options. The identification and management of group risks were reviewed by the board, together with how these risks and their mitigation were embedded in the group’s annual plan.
Review of capital expenditure and post investment review
While the audit committee reviewed project delivery performance, the board undertook an annual review of the group’s project sanctioning process and delegation of authority. The process and criteria for each stage of a project was discussed, together with examples of projects with different lead times and complexities.
Business review
Business reviews were held with both segments (Exploration and Production and Refining and Marketing) and the finance and information technology and services (IT&S) functions.
Global economic environment and energy markets
The board actively monitored developments in the global energy markets and economic environment. Issues considered included the supply/demand balance, the relationship between oil prices, energy consumption and GDP growth and turbulence in the financial markets.
Other areas
Other areas discussed by the board included interactions with BP’s partners in TNK-BP, the results of a group-wide employee satisfaction survey and the findings of a report on BP’s reputation in the UK and US. The board also received a presentation from the independent expert appointed to provide an objective assessment of BP’s progress in implementing the recommendations of the BP US Refineries Independent Safety Review Panel (the Panel).
          The board is supported in its tasks by the company secretary, who reports to the chairman and has no executive functions. His remuneration is determined by the remuneration committee.
Board meetings and attendance
The board met nine times during 2008, of which one meeting was a two-day strategy session and another meeting was a one-day strategy session.
                 
 
    Board meetings     Board meetings  
    eligible to attend     attended  
 
P D Sutherland
    9       9  
Sir Ian Prosser
    9       9  
A Burgmans
    9       9  
C B Carroll
    9       9  
Sir William Castell
    9       9  
G David
    7       7  
E B Davis, Jr
    9       8  
D J Flint
    9       7  
Dr D S Julius
    9       9  
Sir Tom McKillop
    9       9  
Dr W E Massey
    4       4  
Dr D C Allen
    3       3  
I C Conn
    9       9  
Dr B E Grote
    9       9  
Dr A B Hayward
    9       9  
A G Inglis
    9       9  
 


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The chairman and senior independent director
The principles require that neither the chairman nor deputy chairman be employed as an executive of the group. During 2008, these posts were held by Peter Sutherland and Sir Ian Prosser respectively.
          The chairman provides leadership of the board, acts as facilitator for meetings and ensures that the governance framework of the board is maintained and operated. The chairman also leads board performance appraisals. He represents the views of the board to shareholders on key issues, in particular those relating to governance and succession planning and informs the board of shareholder views.
          Between board meetings, the chairman has responsibility for ensuring the integrity and effectiveness of the relationship with executive management. This requires his interaction with the group chief executive, as well as his contact with other board members, senior management and stakeholders.
          The deputy chairman acts for the chairman in his absence or at his request. The deputy chairman also serves as the board’s senior independent director and is available to shareholders where there are issues that cannot be addressed through normal channels.
          The chairman and all the non-executive directors meet periodically without the presence of executive management as the chairman’s committee. The performance of the chairman is evaluated each year, with the evaluation discussion taking place when the chairman is not present. The principles require that the board develop and maintain a plan for the succession of both the chairman and deputy chairman.
Board composition
The principles require that over half the board, excluding the chairman, comprise independent non-executive directors and that the number of directors to not normally exceed 16. The board is composed of the chairman, nine non-executive and four executive directors.
          The board considers that it is of an appropriate size to govern BP, with its directors possessing the relevant backgrounds and mix of experience, knowledge and skills to maximize its effectiveness.
Board renewal and skills
The board remains actively engaged in orderly succession planning for both executive and non-executive directors and is assisted in this task by the nomination committee. The committee keeps under review the composition, skills and diversity of the board to ensure that it remains appropriate to the tasks and work it undertakes. The nomination committee believes a breadth of skills is required for the board to meet the demands of a business with global operations. These skills include deep operational, engineering, safety and financial expertise, experience of leading industrial, capital intensive or ‘long lead time’ businesses and insight into key emerging markets and technology development.
The board: terms of appointment
The chairman and non-executive directors of BP serve on the basis of letters of appointment. Executive directors of BP have service contracts with the company. Details of all payments to directors are described in the directors’ remuneration report.
          The service contracts of executive directors are expressed to expire at a normal retirement age of 60 (subject to age discrimination), while non-executive directors ordinarily retire at the AGM following their 70th birthday.
          In accordance with BP’s Articles of Association, directors are granted an indemnity from the company in respect of liabilities incurred as a result of their office, to the extent permitted by law. In respect of those liabilities for which directors may not be indemnified, the company maintained a directors’ and officers’ liability insurance policy throughout 2008. During the year, a review of the terms and nature of the policy was undertaken and has been renewed for 2009. Although their defence costs may be met, neither the company’s indemnity nor insurance provides cover in the event that the director is proved to have acted
fraudulently or dishonestly. Following recent changes to company law, the company is also permitted to advance costs to directors for their defence in investigations or legal actions.
Director elections
New board directors are subject to election by shareholders at the first AGM following their appointment. All existing directors stand for re-election each year – a practice the company has followed since 2004. All directors proposed to shareholders for election are accompanied by a biography and a description of the skills and experience that the company feels are relevant.
          Voting levels at the 2008 AGM demonstrated continued support for all board directors.
Board independence
Non-executive directors are required by the principles to be independent in character and free from any business or other relationship that could materially interfere with the exercise of their judgement. The board has determined that the non-executive directors who served during 2008 fulfilled this requirement and were independent.
          BP believes that tenure of board members should be determined on the basis of contribution and continued evidence of the exercise of independent judgement. As all directors are proposed for annual re-election by shareholders, the board considers that arbitrary term limits on a director’s service are not appropriate.
          Sir Ian Prosser joined the board in 1997. It is the view of the board that he remains firmly independent. His experience and long-term perspective on BP’s business have provided and continue to provide a valuable contribution to the board and the audit committee, which he chairs. As deputy chairman and senior independent director, Sir Ian is leading the board’s search for the successor to the current chairman. He has been asked by the board to remain in post until April 2010 in order that he may conclude both the chairman’s succession process and the identification and appointment by the new chairman of a senior independent director.
          Mr Davis joined the board on the completion of the Amoco merger in December 1998. The board believes Mr Davis continues to demonstrate his independence. He is an active participant at the board and sits on the audit and remuneration committees, and the high level of his independence is demonstrated by his engagement in these forums.
          The board has satisfied itself that there is no compromise to the independence of those directors who serve together as directors on the boards of outside entities (or who have other appointments in outside entities).
          From 1 October 2008, there has been a requirement that directors must avoid a situation where they have, or can have, a direct or indirect interest that conflicts, or possibly may conflict, with the company’s interests. Directors of public companies may authorize conflicts and potential conflicts, where appropriate, if a company’s articles of association permit and shareholders have approved appropriate amendments.
          Procedures have been put in place for the disclosure by directors of any such conflicts and also for the consideration and authorization of these conflicts by the board. These procedures allow for the imposition of limits or conditions by the board when authorizing any conflict, if they think this is appropriate. These procedures were duly followed to approve appropriate conflicts immediately prior to the enactment of the conflict provisions in October 2008, and are now included as a regular standing item for consideration by the board at its meetings.


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Serving as a director
Induction
The induction of new board members is the responsibility of the chairman, who is assisted by the company secretary in this task. All new directors receive a full induction programme, including a ‘core’ element covering the principles and the legal and regulatory duties of directors. Non-executive directors receive further induction content devised according to their own interests and needs, together with the requirements of the committees on which they will serve. This would include meetings and briefings on the operations and activities of the group, the strategy and the annual plan and the company’s financial performance. The induction programme is targeted for completion within the first nine to 12 months of non-executive directors taking office, while the executive director programme is arranged in the course of their business activities.
Training and site visits
Directors and committee members receive briefings on BP’s business, its markets, operating environment and other key issues during their tenure as directors to ensure they have the necessary skill and knowledge to perform their duties effectively. Board members are also kept updated on legal and regulatory developments that may impact their duties and obligations as directors of a listed company.
          In the past two years, the board and its committees have sought greater opportunity to meet at BP’s operating sites. This has enabled board members to see a selection of BP’s businesses e.g. the Texas City refinery, gas production in Colorado, exploration and production activities in Azerbaijan and the alternative energy solar facility in Maryland. These site visits have given directors the opportunity to meet both operational staff and government and community leaders in the parts of the world where BP operates. All non-executive directors are required to participate in at least one site visit per year.
Outside appointments
BP recognizes that executive directors may be invited to become non-executive directors of other companies and that such appointments can broaden their knowledge and experience, to the benefit of the individual and the group. Executive directors are permitted to take up one external board appointment, subject to the agreement of the chairman and reported to the BP board. Fees received for these external appointments may be retained by the executive director and are reported in the directors’ remuneration report.
          Non-executive directors may serve on a number of outside boards, provided they continue to demonstrate the requisite commitment to discharge their duties to BP effectively. The nomination committee keeps under review the nature of directors’ other interests to ensure that the efficacy of the board is not compromised and may make recommendations to the board if it concludes that a director’s other commitments are inconsistent with those required by BP.
Board evaluation
The principles stipulate that the performance and effectiveness of the board, including the work of its committees, should be evaluated annually. In 2008, this evaluation was undertaken internally with the use of a questionnaire. The questionnaire focused on areas including the conduct of meetings, activities of the board versus committees, monitoring and information and board support and built on the review of board operations and governance that had taken place in 2007. The main outcome of the evaluation was a requirement for a more systematic approach to ensure that the skills of the directors met the changing demands of the business and the environment in which it operates.
Engagement with shareholders
The board is accountable to shareholders for the performance and activities of the BP group and engages in regular dialogue to understand their views and preferences. However, the board also recognizes that, in conducting its business, BP should be responsive to other relevant constituencies.
          During the year, the chairman and deputy chairman met with institutional shareholders to discuss issues relating to the board, governance, strategy and performance. The remuneration committee chairman met with larger shareholders to discuss executive director remuneration.
          The group chief executive, other executive directors and senior management, company secretary’s office, investor relations and other teams within BP also engage with a range of shareholders on wider issues relating to the group, including in particular its safety, operational and financial performance. Presentations given by the group to the investment community are available to download from the ‘Investors’ section of BP’s website, as are speeches on topics of broad interest to shareholders made by the group chief executive and other senior members of the management team.
AGM
BP’s AGM enables shareholders to ask questions and hear the resulting discussion about the company’s performance and the directors’ stewardship of the company. Votes on all matters (except procedural issues) are taken by a poll at the AGM, meaning that every vote cast -whether by proxy or in person at the meeting – is counted.
          The chairman, board committee chairmen and other directors were present during the 2008 AGM and met shareholders on an informal basis after the main business of the meeting. In 2008, voting levels at the AGM increased to 64%, compared with 61% in 2007. Last year was also the first time that the AGM was webcast. This will be repeated for the company’s forthcoming meeting. The webcast, speeches and presentations given at the AGM are available to download from the BP website after the event, together with the outcome of voting on the resolutions.
Board committees
The principles allocate the tasks of monitoring executive actions and assessing performance to certain board committees. These tasks prescribe the authority and role of the board committees.
          Reports for each of the main board committees follow. In common with the board, each committee has access to independent advice and counsel as required and each is supported by the company secretary’s office, which is independent of the executive management of the group. The main tasks and requirements of each of the board’s committees are set out in the principles, available at www.bp.com/corporategovernance.
Audit committee report
Membership
The audit committee comprises four independent non-executive directors who have been selected to provide a wide range of financial, international and commercial expertise appropriate to fulfil the committee’s duties.
          During the year, Sir Ian Prosser (chairman), Douglas Flint and Erroll Davis, Jr were members of the audit committee. Sir William Castell retired from the committee in April 2008 and George David joined in May 2008. The secretary to the committee is David Pearl, deputy company secretary of BP.
          The board considers that Douglas Flint possesses the financial and audit committee experience, as defined by the Combined Code guidance and the SEC, and has nominated him as the audit committee’s financial expert.


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Attendance
The audit committee met 13 times during 2008.
                 
 
    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  
   
In addition to the above members, the committee invites the lead partner of the external auditors (Ernst & Young), the group chief financial officer, the general auditor (head of internal audit), the chief accounting officer and the deputy chief financial officer to attend each meeting. Other senior management attend on request to enable the committee to discharge its duties. The committee also holds private sessions during the year without the presence of executive management.
Role and authority of the audit committee
The audit committee assists the board in carrying out its responsibilities in relation to financial risk, internal controls, financial and regulatory reporting requirements and the broader observance of the ‘executive limitations’ relating to financial matters.
          The main tasks and requirements for the audit committee are set out in the principles. The audit committee believes that these meet each of the tasks and activities outlined by the Combined Code as falling within the remit of an audit committee.
Information
The committee receives information and reports from internal and external sources, including a wide cross-section of BP’s business and financial control management, with the attendance of additional Ernst & Young staff if appropriate to a particular business or functional review.
          The audit committee is able to access independent advice and counsel when needed, on an unrestricted basis. Further support is provided to the committee by the company secretary’s office and during 2008 external specialist legal and regulatory advice was provided by Sullivan & Cromwell LLP.
          The wider board is kept informed of the activities of the committee, and any issues that have arisen, through the regular update given by the audit committee chair after each meeting.
Training and induction
BP provides an induction programme for new committee members and ongoing training to assist them in carrying out their duties. Elements of the induction programme include familiarization with the tasks and requirements of the audit committee, an overview of the key financial and operational aspects of the businesses and an introduction to the group’s system of internal control. During the year, George David participated in the audit committee induction, including private sessions with the lead external audit partner and the general auditor.
          In 2008, the training programme for the audit committee included briefings on developments in financial reporting and financial standards, a site visit to BP’s UK trading operations and an externally facilitated session on tax risk management.
Committee activities in 2008
The chart at the end of this section shows how the audit committee allocated its agenda time in 2008.
Financial reporting
During the year, the committee reviewed all financial reports, including the Annual Report and Accounts and Annual Report on Form 20-F, before recommending their publication to the board.
Monitoring risk in the business
In 2008, the audit committee reviewed reports on risks, controls and assurance for the BP business segments (Exploration and Production, Refining and Marketing), together with alternative energy, information technology and services, the proposed reorganization of the group finance function and BP’s trading function. The committee also reviewed BP’s long-term contractual commitments and the provisions made for environmental remediation and decommissioning.
Internal controls
A joint meeting with the safety, ethics and environment assurance committee was held to review the general auditor’s report on internal controls and risk management. A further joint meeting was held in early 2009 to assist the board in its assessment of the effectiveness of internal controls and risk management in 2008.
          The committee discussed key regulatory issues during the year as part of its standing agenda items, including the quarterly internal audit findings report and a review of the company’s evaluation of its internal controls systems as part of the requirement of Section 404 of the Sarbanes-Oxley Act. The effectiveness of BP’s enterprise level controls was examined through the annual assessment undertaken by the internal audit function.
External auditors
The lead audit partner from Ernst & Young attends all meetings of the audit committee at the request of the committee chairman. Other external audit staff are invited to attend meetings where their expertise is relevant to the agenda item, for example during business or technical reviews.
          The committee held two private meetings during the year with the external auditors without the presence of BP management, in order to discuss issues or concerns from either the committee or the auditors.
          Performance of the external auditors is evaluated by the audit committee each year, with particular scrutiny of their independence, objectivity and viability. Independence is maintained through the limiting of non-audit services to tax and audit-related work that fall within defined categories. This work is pre-approved by the audit committee and all non-audit services are monitored quarterly.
          Fees paid to the external auditors for the year (see Financial statements – Note 18 on page 132) were $67 million, of which 14% was for non-audit work. The fees and services provided by Ernst & Young for both audit and non-audit work have decreased in comparison to the previous year due to improved audit efficiency, ongoing systems improvements and BP’s new business structure.
          During the year, a new lead partner from Ernst & Young replaced the existing partner who had completed five years’ service on the BP audit in early 2008. Under BP policy and pursuant to external regulation, a new lead audit partner is appointed every five years and other senior audit staff are rotated every seven years. No partners or senior staff from Ernst & Young who are connected with the BP audit may transfer to the group.
          The audit committee has considered both the proposed fee structure and the audit engagement terms for 2009 and has recommended to the board that the reappointment of the external auditors be proposed to shareholders at the 2009 AGM.


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Internal audit
The general auditor attends each committee meeting at the invitation of the audit committee chairman. With the retirement of the general auditor in early 2008, a new general auditor was appointed following an externally facilitated recruitment process.
          During the year, the audit committee evaluated the performance of the internal audit function and agreed to the proposed programme of work for the year (being satisfied that it appropriately responded to the key risks facing the company and that the function had adequate staff and resources to complete its work).
          In 2008, the committee met once with the general auditor in a private session without the presence of executive management. In addition, the general auditor met with the chairman of the committee from time to time between meetings.
Fraud and employee concerns on financial matters
The audit committee received an annual certification report from the group compliance and ethics function, together with quarterly reports that highlighted financial issues raised through OpenTalk, the group-wide employee concerns programme.
          The committee further received quarterly updates from internal audit on instances of actual or potential fraud.
Audit committee activities
Approximate allocation of agenda time in 2008*
(PIECHART LOGO)
Committee performance evaluation
The committee conducts a yearly evaluation of its performance through one-to-one interviews or questionnaires. The results are collated and reported by the committee secretary. Actions taken in 2008 as a result of the end 2007 evaluation included participation in an externally facilitated training session and improved tracking of outstanding issues. In addition, the committee considers performance during its private sessions throughout the year.
          The 2008 evaluation was conducted through individual interviews and the outcomes discussed by the committee in January 2009. The forward agenda for the year ahead was set following this review, and consideration was given to building on the training provided to members through site visits.
          The audit committee plans to meet 13 times during 2009.
Safety, ethics and environment assurance committee report
Membership
The committee consists solely of independent non-executive directors who have been selected to provide a wide range of operational and international expertise appropriate to fulfil the committee’s duties.
Members of the safety, ethics and environment assurance committee (SEEAC) during 2008 were Antony Burgmans, Sir William Castell and Sir Tom McKillop. Dr Massey retired as chairman of SEEAC in April 2008 and Sir William Castell became the committee chairman from that date. Cynthia Carroll joined the committee in June 2008. Support was provided by the committee secretary, David Pearl (deputy company secretary).
Attendance
SEEAC met eight times during 2008.
                 
 
    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  
 
In addition to the above members, each SEEAC meeting is attended by the lead partner of the external auditors (Ernst & Young) and the BP general auditor (head of internal audit) on the invitation of the committee chairman. The group chief executive also attends committee meetings as the executive liaison with SEEAC: Dr Hayward attended all eight meetings of the committee in 2008. The committee holds private sessions without executive management in attendance at the end of each meeting.
Role and authority of the committee
The main tasks and requirements for SEEAC are set out in the principles and include among others:
  Monitoring and obtaining assurance on behalf of the board that the management or mitigation of significant BP risks of a non-financial nature is appropriately addressed by the group chief executive.
 
  Reviewing material to be placed before shareholders that addresses environmental, safety and ethical performance and make recommendations to the board about their adoption and publication.
 
  Reviewing reports on the group’s compliance with its code of conduct and on the employee concerns programme (OpenTalk) as it relates to non-financial issues.
Information
The committee receives information and reports from the safety and operations function, internal and external sources, including internal audit and the group compliance and ethics function. Staff from Ernst & Young attend if appropriate to a particular business or activity review.
          Like BP’s other board committees, SEEAC can access independent advice and counsel if it requires, on an unrestricted basis. The wider board is kept informed of the activities of the committee and any issues that have arisen through the regular update given by the SEEAC chair after each meeting.
Training and induction
Members of the committee receive ongoing training to assist them in carrying out their duties and an induction programme was provided for Mrs Carroll on joining the committee.
          To develop a deeper understanding of BP’s business and operations, Sir William Castell undertook a number of private briefings and several site visits on becoming SEEAC chairman. These visits included the Texas City refinery, where progress in implementing the recommendations of the Panel was observed and to the North Sea ETAP platforms where safety, operational and environmental management on an offshore production facility were reviewed.
Committee activities in 2008
The chart at the end of this section shows how SEEAC allocated its agenda time in 2008.


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Safety and operations
The group operations risk committee (GORC) was formed at the end of 2006 and is an executive level committee, chaired by the group chief executive. The GORC made regular reports to SEEAC during the year, including progress on the group-wide implementation of the operating management system (OMS) and BP’s six-point plan, the development and utilization of the process safety index and statistics relating to the group’s safety and operational performance.
          L Duane Wilson was appointed by the board in 2007 as an independent expert to provide an objective assessment of BP’s progress in implementing the Panel recommendations, aimed at improving process safety performance at BP’s five US refineries. Mr Wilson, who was a member of the Panel, reports to the chairman of SEEAC and is independently funded through the company secretary’s office.
          Mr Wilson attended six meetings of the committee during 2008 and a private meeting with the committee during the year without the presence of executive management. Topics discussed included a presentation on his detailed work plan and progress updates. In May 2008, Mr Wilson published his first annual report where he assessed BP’s progress against the 10 Panel recommendations. The report noted that while significant progress had been made, areas for improvement still remained. Further information on the report is available on BP’s website.
Regional reviews and site visits
During the year, the committee reviewed reports on Alaska, the BTC pipeline, shipping and TNK-BP. The committee visited BP’s refinery operations in Rotterdam, and coal bed methane operations in Durango, Colorado. In addition, some members visited the BP solar manufacturing facilities in Maryland and the group’s operations in Azerbaijan.
Other topics
Other topics reviewed by the committee during the year included business continuity and crisis management, environmental requirements for new projects, results from a survey on safety culture in BP’s US refineries and a report from the US ombudsman on concerns raised by employees in Alaska. The committee also received and discussed quarterly reports from the general auditor and the group compliance and ethics officer.
SEEAC 2008 Activities
Approximate allocation of agenda time*
()
Performance evaluation and forward agenda
The committee undertakes an annual review of its performance and process. In 2008, the review involved interviews with each committee member, with the results discussed at the committee’s November meeting. Conclusions from the evaluation included noting the helpful insight gained from site visits and the value to the committee of the knowledge and expertise of the independent expert in respect of safety in the US refineries. The committee also reviewed its forward agenda for 2009.
          SEEAC plans to meet seven times during 2009.
Remuneration committee report
Membership
The committee consists solely of non-executive directors who are considered by the board to be independent.
          Members of the remuneration committee during the year were Dr DeAnne Julius (chairman), Erroll Davis, Jr, Sir Tom McKillop and Sir Ian Prosser. The chairman of the board also attends meetings of the committee.
Attendance
The committee met six times during 2008.
                 
 
    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  
 
Role and authority of the committee
The committee determines, on behalf of the board, the terms of engagement and remuneration of the group chief executive, the chairman and executive directors and reports on those to shareholders. The committee is independently advised.
          Further details on the committee’s role, authority and activities during the year are set out in the directors’ remuneration report, which is the subject of a vote by shareholders at the 2009 AGM.
          The remuneration committee plans to meet five times in 2009.
Chairman’s committee report
Membership
The committee consists of the chairman and all non-executive directors.
Attendance
The committee met four times during 2008.
                 
 
Chairman’s committee meetings     Chairman’s committee  
    eligible to attend     meetings attended  
 
P D Sutherland
    4       4  
Sir Ian Prosser
    4       4  
A Burgmans
    4       4  
C B Carroll
    4       3  
Sir William Castell
    4       4  
G David
    2       2  
E B Davis, Jr
    4       4  
D J Flint
    4       4  
Dr D S Julius
    4       4  
Sir Tom McKillop
    4       4  
Dr W E Massey (former member)
    2       2  
 


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Role and authority of the committee
The main tasks and requirements for the committee are set out in the principles and are:
  Evaluating the performance and effectiveness of the group chief executive;
 
  Reviewing the structure and effectiveness of the business organization of BP;
 
  Reviewing the systems for senior executive development and determining the succession plan for the group chief executive, executive directors and other senior members of executive management;
 
  Determining any other matter that is appropriate to be considered by all of the non-executive directors;
 
  Opining on any matter referred to it by the chairman of any committee comprised solely of non-executive directors.
Committee activities
The chairman’s committee considered aspects of a number of strategic issues including the relationship with the company’s partners in TNK-BP. The committee has reviewed with Dr Hayward the short- and long-term challenges facing the group. Dr Hayward has kept the committee briefed on the implementation of the forward agenda and its implications for the evolution of the executive team and succession within the leadership cadre. The committee has also reviewed the steps taken by Dr Hayward to refine the corporate culture and the values within BP. There have been active discussions around the ‘tone from the top’.
          The committee has reviewed the performance of the chairman and Dr Hayward.
          The chairman’s committee plans to meet four times in 2009.
Nomination committee report
Membership
The committee’s members nominally consist of the chairman and the chairs of SEEAC, audit and remuneration committees.
          Members of the nomination committee during the year were Peter Sutherland (chairman), Dr DeAnne Julius, Sir Ian Prosser and Dr Walter Massey. Dr Massey remained a member of the nomination committee during the year after his retirement from the board to assist in the search for a successor to BP’s chairman. Sir William Castell has now joined the committee.
Attendance
The committee met six times during 2008.
                 
 
    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  
 
Role and authority of the committee
The main tasks and requirements for the committee are set out in the principles and are:
  Identifying, evaluating and recommending candidates for appointment or reappointment as directors.
 
  Identifying, evaluating and recommending candidates for appointment as company secretary.
 
  Keeping under review the mix of knowledge, skills and experience of the board to ensure the orderly succession of directors.
 
  Reviewing the outside directorship/commitments of the non-executive directors.
Committee activities
During 2008 the primary work of the committee has been the continuation of the process to select a successor to Mr Sutherland who is to stand down as chairman.
For this purpose, Sir Ian Prosser, as Senior Independent Director, has chaired the committee. The committee has been assisted in this task by Dr Anna Mann of MWM Consulting LLP. The committee has adopted a robust process. Key strategic issues facing BP for the coming years were identified through discussions with individual board members. From these discussions a role description was developed. This formed the basis of a worldwide search from which in excess of 30 candidates emerged. This broad group has been refined and the process is continuing. The board has been regularly briefed on the work of the committee.
          As part of the chairman selection process, potential candidates for non-executive directors roles have been revealed. The committee will continue actively to keep the skills of the board under review and pursue its refreshment.


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Directors’ interests
                         
     
                    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        
     
 
aIncludes 44,158 shares held as ADSs at 31 December 2008 and 41,692 shares held as ADSs at 1 January 2008.
 
bHeld as ADSs.
 
cOn appointment at 11 February 2008.
 
dHeld as ADSs, except for 94 shares held as ordinary shares.
 
eIncludes 34,962 shares held as ADSs.
 
fIncludes 25,368 shares held as ADSs.
The above figures indicate and include all the beneficial and non-beneficial interests of each director of the company in shares of the company (or calculated equivalents) that have been disclosed to the company under the Disclosure and Transparency Rules and Companies Acts 1985 or 2006 (as the case may be) as at the applicable dates. The above figures do not include share options granted or interests in performance shares that have yet to vest. Details of these are set out in full in the directors’ remuneration report on pages 79 and 80.
          Executive directors are also deemed to have an interest in such shares of the company held from time to time by the BP Employee Share Ownership Plan (No. 2) to facilitate the operation of the company’s option schemes.
          No director has any interest in the preference shares or debentures of the company or in the shares or loan stock of any subsidiary company.

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74
  Part 1 Summary
 
 
76
  Part 2 Executive directors' remuneration
 
 
82
  Part 3 Non-executive directors' remuneration


 

 


 

 
Directors’ remuneration report
 

Part 1 Summary
BP executives delivered a strong performance in a turbulent environment during 2008 and restored the group’s operations to a high standard after several years of focused effort. We commend them for a job well done.
          Key financial targets for the year were exceeded, even after adjusting for the effect of high oil prices during part of the year. Safe and reliable operations remained at the t