Annual Reports

  • 20-F (Mar 6, 2014)
  • 20-F (Mar 6, 2013)
  • 20-F (Mar 6, 2012)
  • 20-F (Mar 2, 2011)
  • 20-F (Mar 5, 2010)
  • 20-F (Mar 4, 2009)

 
Other

BP 20-F 2010
e20vf
Table of Contents

 
 
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
 
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
þ
  OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
  For the fiscal year ended 31 December 2009
 
  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
5.25% Guaranteed Notes due 2013   New York Stock Exchange
Floating Rate Guaranteed Notes due 2011   New York Stock Exchange
1.55% Guaranteed Notes due 2011   New York Stock Exchange
3.125% Guaranteed Notes due 2012   New York Stock Exchange
3.625% Guaranteed Notes due 2014   New York Stock Exchange
3.875% Guaranteed Notes due 2015   New York Stock Exchange
4.75% Guaranteed Notes due 2019   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
    18,759,888,123  
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 has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).*
     
Yes þ
  No o
*This requirement does not apply to the registrant until its fiscal year ending December 31, 2011.
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
 
 

 


Table of Contents

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     12  
 
  B.   Capitalization and indebtedness     n/a  
 
  C.   Reasons for the offer and use of proceeds     n/a  
 
  D.   Risk factors     14-16  
Item 4.   Information on the Company        
 
  A.   History and development of the company     6-7  
 
  B.   Business overview     18-48  
 
  C.   Organizational structure     48  
 
  D.   Property, plants and equipment     92  
Item 4A.
  Unresolved Staff Comments   None  
Item 5.   Operating and Financial Review and Prospects        
 
  A.   Operating results     49-56  
 
  B.   Liquidity and capital resources     57-59  
 
  C.   Research and development, patent and licenses     40-41, 132  
 
  D.   Trend information     58  
 
  E.   Off-balance sheet arrangements     58  
 
  F.   Tabular disclosure of contractual commitments     59  
 
  G.   Safe harbour     17  
Item 6.   Directors, Senior Management and Employees        
 
  A.   Directors and senior management     62-64  
 
  B.   Compensation     78-88, 172-173  
 
  C.   Board practices     62-76, 80-81, 172-173  
 
  D.   Employees     46-47  
 
  E.   Share ownership     76, 84-85, 92-94, 170-172  
Item 7.   Major Shareholders and Related Party Transactions        
 
  A.   Major shareholders     94  
 
  B.   Related party transactions     94, 140-141  
 
  C.   Interests of experts and counsel     n/a  
Item 8.   Financial Information        
 
  A.   Consolidated statements and other financial information     94-96, 107-197  
 
  B.   Significant changes   None  
Item 9.   The Offer and Listing        
 
  A.   Offer and listing details     96-97  
 
  B.   Plan of distribution     n/a  
 
  C.   Markets     96-97  
 
  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     97-99  
 
  C.   Material contracts   None  
 
  D.   Exchange controls     99  
 
  E.   Taxation     99-101  
 
  F.   Dividends and paying agents     n/a  
 
  G.   Statements by experts     n/a  
 
  H.   Documents on display     101  
 
  I.   Subsidiary information     n/a  
Item 11.   Quantitative and Qualitative Disclosures about Market Risk     142-147, 150-155  
Item 12.   Description of securities other than equity securities        
 
  A.   Debt Securities     n/a  
 
  B.   Warrants and Rights     n/a  
 
  C.   Other Securities     n/a  
 
  D.   American Depositary Shares     103-104  
Item 13.
  Defaults, Dividend Arrearages and Delinquencies   None  
Item 14.
  Material Modifications to the Rights of Security Holders and Use of Proceeds   None  
Item 15.   Controls and Procedures     101-102  
Item 16A.   Audit Committee Financial Expert     71  
Item 16B.   Code of Ethics     102  
Item 16C.   Principal Accountant Fees and Services     102  
Item 16D.   Exemptions from the Listing Standards for Audit Committees     n/a  
Item 16E.   Purchases of Equity Securities by the Issuer and Affiliated Purchases     103  
Item 16F.
  Change in Registrant’s Certifying Accountant   None  
Item 16G.   Corporate governance     102  
Item 17.   Financial Statements     n/a  
Item 18.   Financial Statements     22-24, 107-197  
Item 19.   Exhibits     105  

2


Table of Contents

 
Miscellaneous terms
 
In this document, unless the context otherwise requires, the following terms shall have the meaning set out below.
ADR
American depositary receipt.
ADS
American depositary share.
AGM
Annual general meeting.
Amoco
The former Amoco Corporation and its subsidiaries.
Atlantic Richfield
Atlantic Richfield Company and its subsidiaries.
Associate
An entity, including an unincorporated entity such as a partnership, over which the group has significant influence and that is neither a subsidiary nor a joint venture. Significant influence is the power to participate in the financial and operating policy decisions of an entity but is not control or joint control over those policies.
Barrel
42 US gallons.
b/d
barrels per day.
boe
barrels of oil equivalent.
BP, BP group or the group
BP p.l.c. and its subsidiaries.
Burmah Castrol
Burmah Castrol PLC and its subsidiaries.
Cent or c
One-hundredth of the US dollar.
The company
BP p.l.c.
Dollar or $
The US dollar.
EU
European Union.
Gas
Natural gas.
Hydrocarbons
Crude oil and natural gas.
IFRS
International Financial Reporting
Standards.
Joint control
Joint control is the contractually agreed sharing of control over an economic activity, and exists only when the strategic financial and operating decisions relating to the activity require the unanimous consent of the parties sharing control (the venturers).
Joint venture
A contractual arrangement whereby two or more parties undertake an economic activity that is subject to joint control.
Jointly controlled asset
A joint venture where the venturers jointly control, and often have a direct ownership interest in the assets of the venture. The assets are used to obtain benefits for the venturers. Each venturer may take a share of the output from the assets and each bears an agreed share of the expenses incurred.
Jointly controlled entity
A joint venture that involves the establishment of a corporation, partnership or other entity in which each venturer has an interest. A contractual arrangement between the venturers establishes joint control over the economic activity of the entity.
Liquids
Crude oil, condensate and natural gas liquids.
LNG
Liquefied natural gas.
London Stock Exchange or LSE
London Stock Exchange plc.
LPG
Liquefied petroleum gas.
mb/d
thousand barrels per day.
mboe/d
thousand barrels of oil equivalent per day.
mmBtu
million British thermal units.
mmboe
million barrels of oil equivalent.
mmcf
million cubic feet.
mmcf/d
million cubic feet per day.
MTBE
Methyl tertiary butyl ether.
MW
Megawatt.
NGLs
Natural gas liquids.
OPEC
Organization of Petroleum Exporting Countries.
Ordinary shares
Ordinary fully paid shares in BP p.l.c. of 25c each.
Pence or p
One-hundredth of a pound sterling.
Pound, sterling or £
The pound sterling.
Preference shares
Cumulative First Preference Shares and Cumulative Second Preference Shares in BP p.l.c. of £1 each.
PSA
A production-sharing agreement (PSA) is an arrangement through which an oil company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.
SEC
The United States Securities and Exchange Commission.
Subsidiary
An entity that is controlled by the BP group. Control is the power to govern the financial and operating policies of an entity so as to obtain the benefits from its activities.
Tonne
2,204.6 pounds.
UK
United Kingdom of Great Britain and Northern Ireland.
US
United States of America.
 


3


 

 
Contents
 
 
 
 
             
     
5          
   
 
       
         
61          
         
   
 
       
         
77          
         
   
 
       
         
89          
         
   
 
       
         
107          
         
   
 
       
         
   
 
       
 
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Business review
 
 
 
 
             
     
6     48   Relationships with suppliers and contractors
         
18          
         
   
 
  48   Regulation of the group’s business
         
32          
         
   
 
  48   Organizational structure
         
38          
         
   
 
  49   Financial performance
         
40          
         
   
 
  57   Liquidity and capital resources
         
42          
 
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Table of Contents

 
Business review

 
Group overview

 
Our organization
BP is one of the world’s leading international oil and gas companiesa. We operate in more than 80 countries, providing our customers with fuel for transportation, energy for heat and light, retail services and petrochemicals products for everyday items.
As a global group, our interests and activities are 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 2009: Exploration and Production and Refining and Marketing. BP’s activities in low-carbon energy are managed through our Alternative Energy business, which is reported within Other businesses and corporate.
          Exploration and Production’s activities cover three key areas. Upstream activities include oil and natural gas exploration, field development and production. Midstream activities include pipeline, transportation and processing activities related to our upstream activities. Marketing and trading activities include the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs).
          Refining and Marketing’s activities include the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum and petrochemicals products and related services.
          The two business segments each comprise a number of strategic performance units (SPUs), which are organized along either geographic or activity-related lines. The role of the SPU includes the development of local capability and the fostering of external stakeholder relationships. Each SPU is of a scale that allows for a close focus on performance delivery by its respective segment, which includes the appropriate management of costs.
 
a On the basis of market capitalization, proved reserves and production.
 
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. The company was incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001. BP’s primary share listing is the London Stock Exchange. Ordinary shares are also traded on the Frankfurt Stock Exchange in Germany and, in the US, the company’s securities are traded in the form of ADSs. (See pages 96 to 97 for more details.)
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 +1 281 366 2000.
 
Our group functions and regions support the work of our segments and businesses. Their key objectives are to establish and monitor fit-for-purpose functional standards across the group; to act as centres of deep functional expertise; to access significant leverage with third-party suppliers; and to establish and maintain capabilities among the functional staff employed within our operating businesses. In addition, the head of each region provides the required integration and co-ordination of group activities in a particular geographic area and represents BP to external parties.
Where we operate
BP’s worldwide headquarters is in London. The UK is a centre for trading, legal, finance and other business functions as well as three of BP’s major global research and technology groups.
          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 Co-operation and Development (OECD) countries, with around 40% of our fixed assets located in the US and around 20% in Europe.
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Table of Contents

Business review

Our Exploration and Production segment conducts upstream and midstream activities in 30 countries and we are the largest producer of oil and gas in North America. The segment’s geographical coverage in these activities currently includes Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), Norway, the UK, the US and locations within Asia Pacific, Latin America, North Africa and the Middle East. Our Exploration and Production segment also includes gas marketing and trading activities, primarily in Canada, Europe and the US. In Russia, we have an important associate through our 50% shareholding in TNK-BP, a major oil company with exploration assets, refineries and other downstream infrastructure.
          In Refining and Marketing, we market our products in more than 80 countries, with a particularly strong presence in the US and Europe, as well as major activities in Australia, Southern Africa, India and China. In the US, we own or have a share in five refineries and market primarily under the Amoco, ARCO, BP and Castrol brands. We are one of the largest gasoline retailers in that country. In Europe, we own or have a share in seven refineries and we market extensively across the region, primarily under the Aral, BP and Castrol brands. Our long-established supply and trading activity is responsible for delivering value across the crude and oil products supply chain. Our petrochemicals business maintains a manufacturing position globally, with an emphasis on growth in Asia. We continue to seek opportunities to broaden our activities in growth markets such as China and India.
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Our market
Energy markets remained volatile in 2009, reflecting the dramatic drop in world economic activity early in the year and indications of economic recovery in the second half. Looking ahead, the long-term outlook is one of growing demand for energya, particularly in Asia, alongside challenges for the industry in meeting this demand. Rising incomes and expanding urban populations are expected to drive demand, while the evolution towards a lower-carbon economy will require technology, innovation and investment.
World oil consumption declined for a second successive year during 2009, with growing demand in non-OECD countries once again more than offset by falling consumption in OECD countries. Average crude oil prices for 2009 were lower than in the previous year, breaking an unprecedented string of seven consecutive annual increases. Natural gas prices also weakened in 2009 and were highly volatile. Refining margins fell sharply as oil demand contracted and substantial amounts of new refining capacity came onstream.
Economic context
The world economy began to show signs of recovery in the latter part of 2009 and this is expected to continue through 2010, but economic growth in 2010 is likely to be muted in the OECD countries. Growth in global oil consumption is expected to resume as the world economy recovers from recession.
          In 2009, concerns about the volatility of commodity and financial markets, combined with renewed focus on climate change and the early experiences with efforts to reduce CO2 emissions in the EU and elsewhere, led to an increased focus on the appropriate role for markets, government oversight and other policy measures relating to the supply and consumption of energy.
          The concept of peak oil – the time after which less oil is available to the world – continues to hold the interest of some commentators, although global proved reserves have tended to rise over time and remain sufficient to support higher levels of production. Meanwhile, the consumer response to higher prices and an increased focus on energy efficiency have served to constrain demand. We expect regulation and taxation of the energy industry and energy users to increase in many areas over the short to medium term.
 
a World Energy Outlook 2009. ©OECD/IEA 2009, pages 622-623: ‘Reference Scenario, World’.
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Table of Contents

Business review

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Crude oil prices
Dated Brent for the year averaged $61.67 per barrel, about 37% below 2008’s record average of $97.26 per barrel. Prices began the year at their lowest point as the world economy grappled with the sharpest downturn in modern economic history.
          Global oil consumption reflected the economic slowdown, falling by roughly 1.3 million b/d for the year (1.5%)b, the largest annual decline since 1982. The biggest reductions were early in the year, with OECD countries accounting for the entire global decline. Crude oil prices rose sharply in the second quarter in response to sustained OPEC production cuts and emerging signs of stabilization in the world economy, despite very high commercial oil inventories in the OECD. OPEC members sustained roughly 2.5 million b/d of production cutsb implemented in late 2008 and throughout 2009. Additional price increases later in the year were sustained by further positive economic news and signs that the inventory overhang was beginning to correct.
          In 2008, the average dated Brent price of $97.26 per barrel was 34% higher than the $72.39 per barrel average seen in 2007. Daily prices began 2008 at $96.02 per barrel, peaked at $144.22 per barrel on 3 July 2008, and fell to $36.55 per barrel at the end of the year. 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.
          Looking ahead, in 2010 we expect oil price movements to continue to be driven by the extent of global economic growth and its resulting implications for oil consumption, and by OPEC production decisions.
 
a See footnote d on page 33.
 
b Adapted from Oil Market Report (February 2009). ©OECD/IEA 2009.
Natural gas prices
Natural gas prices weakened in 2009 and were volatile. The average US Henry Hub First of Month Index fell to $3.99/mmBtu in 2009, a 56% decrease from the record $9.04/mmBtu average seen in 2008.
Recession-induced demand declines and strong production caused prices to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in September. However, over the course of the year, the impact was partly offset as US regional gas price differentials narrowed, driven partly by the Rockies Express Pipeline extension allowing the transportation of larger quantities of gas out of the Rockies area. Reduced imports from Canada, slowing US production growth and cooler temperatures allowed prices to recover to $4.49/mmBtu by the end of the year. Prices at the UK National Balancing Point similarly fell to an average of 30.85 pence per therm, 47% below the 2008 average price of 58.12 pence per therm. In 2009, there was a switch of uncontracted LNG cargoes from Asia to Europe, reflecting a shift in relative spot prices. LNG imports to Europe have competed with pipeline imports, where the gas price is often indexed to oil prices, as well as with marginal European gas production. Gas prices were often at or below parity with coal, when translated into the cost of generating power, which led to gas displacing coal in power generation in Europe and the US.
          In 2008, average natural gas prices in the US and the UK were higher than in 2007. The Henry Hub First of Month Index, at $9.04/mmBtu, was 32% higher than the 2007 average of $6.86/mmBtu. 2008’s 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. In the UK, 2008 average prices of 58.12 pence per therm at the National Balancing Point, were 94% above the 2007 average of 29.95 pence per therm.
          Looking ahead, gas markets in 2010 are expected to follow developments in the global economy, but any price movements are likely to be impacted by significant new LNG capacity as it becomes available.
Refining margins
Refining margins fell sharply in 2009 as demand for oil products reduced in the wake of the global economic recession and new refining capacity came onstream, mostly in Asia Pacific. The BP global indicator refining margin (GIM)a averaged $4 per barrel last year, down $2.50 per barrel compared with 2008. Margins in the Far East were particularly badly hit –averaging close to zero in Singapore – because new refining capacity has been added in the region.
          Margins in Europe were about half the 2008 level as the reduction in economic activity meant weaker demand for commercial transport and therefore lower middle distillate consumption. In the US, where refining is more highly upgraded and the transport market more gasoline-orientated, margins were stronger than in Europe.
          Refining margins in 2008 were lower than in 2007, with the BP GIM decreasing to an average of $6.50 per barrel from $9.94 per barrel in 2007. 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.
          Looking ahead, refining margins are likely to remain under pressure through 2010, with capacity already exceeding demand and additional new capacity expected to come onstream during the year.
 


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Table of Contents

Business review

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Long-term outlook
Recent economic conditions have weakened global demand for primary energy, but a number of forecasts predict a return to growth in the medium term. This is underpinned by continuing population growth and by generally rising living standards in the developing world, including the expansion of urban populations.
          Under the International Energy Agency’s (IEA) reference scenario, global energy demand is projected to increase by around 40% between 2007 and 2030a. That scenario also projects that fossil fuels will still be satisfying as much as 80% of the world’s energy needs in 2030. At current rates of consumption, the world has enough proved reserves of fossil fuels to meet these requirementsb if investment is permitted to turn those reserves into production capacity. However, to meet the potential growth in demand, continued investment in new technology will be required in order to boost recovery from declining fields and commercialize currently inaccessible resources. For example, in oil alone, where we believe there are reserves in place to satisfy approximately 40 years’ demand at current rates of consumptionb, we estimate that our industry will need to bring nearly 50 million barrels per day of new capacity onstream by 2030 if it is to meet the increased demand. To play their part in achieving this, energy companies such as BP will need secure and reliable access to as-yet undeveloped resources. We estimate that more than 80% of the world’s oil resources are held by Russia, Mexico and members of OPEC – areas where international oil companies are frequently limited or prohibited from applying their technology and expertise to produce additional supply. New partnerships will be required to transform latent resources into much-needed proved reserves.
          A more diverse mix of energy will also be required to meet this increased demand. Such a mix is likely to include both unconventional fossil fuel resources – such as oil sands, coalbed methane and natural gas produced from shale formations – and renewable energy sources such as wind, biofuels and solar power. Beyond simply meeting growth in overall demand, a diverse mix would also help to provide enhanced national and global energy security while supporting the transition to a lower-carbon economy. Improving the efficiency of energy use will also play a key role in maintaining energy market balance in the future.
Along with increasing supply, we believe the energy industry will be required to make hydrocarbons cleaner and more efficient to use –particularly in the critical area of power generation, for which the key hydrocarbons are currently coal and gas. The world has reserves of coal for around 120 years at current consumption ratesb, but coal produces more carbon than any other fossil fuel. Carbon capture and storage (CCS) may help to provide a path to cleaner coal, and BP is investing in this area, but CCS technologies still face significant technical and economic issues and are unlikely to be in operation at scale for at least a decade.
          In contrast, we believe that in many countries natural gas has the potential to provide the most significant reductions in carbon emissions from power generation in the shortest time and at the lowest cost. These reductions can be achieved using technology available today. Combined- cycle turbines, fuelled by natural gas, produce around half the CO2 emissions of coal-fired power, and are cheaper and quicker to build. It is estimated that there are reserves of natural gas in place equivalent to 60 years’ consumption at current ratesb and they are rising as new skills and technology unlock new unconventional gas resources. For these reasons, gas is looking to be an increasingly attractive resource in meeting the growing demand for energy, playing a greater role as a key part of the energy future.
          At the same time, alternative energies also have the potential to make a substantial contribution to the transition to a lower-carbon economy, but this will require investment, innovation and time. Currently, wind, solar, wave, tide and geothermal energy account for only around 1% of total global consumptionc. Even in the most aggressive scenario put forward by the IEA, these forms of energy are estimated to meet no more than 5% of total demand in 2030d.
          If industry and the market are to meet the world’s growing demand for energy in a sustainable way, governments will be required to set a stable and enduring framework. As part of this, governments will need to provide secure access for exploration and development of fossil fuel resources, define mutual benefits for resource owners and development partners, and establish and maintain an appropriate legal and regulatory environment, including a mechanism for recognizing and incorporating the cost of reducing carbon emissions.
 
a World Energy Outlook 2009. ©OECD/IEA 2009, pages 622-623: ‘Reference Scenario, World’. The IEA’s reference scenario describes what would happen if, among other things, governments were to take no new initiatives bearing on the energy sector, beyond those already adopted by mid-2009.
 
b BP Statistical Review of World Energy June 2009. This estimate is not based on proved reserves as defined by SEC rules.
 
c Adapted from World Energy Outlook 2009. ©OECD/IEA 2009, page 74. The IEA’s 450 policy scenario assumes governments adopt commitments to limit the long-term concentration of greenhouse gases in the atmosphere to 450 parts per million of CO2 equivalent.
 
d World Energy Outlook 2009. ©OECD/IEA 2009, page 212: ‘World primary energy demand by fuel in the 450 Scenario (Mtoe)’.
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Table of Contents

Business review

Our strategy
The priorities that drove our success in 2009 –safety, people and performance – remain the foundation of our agenda as we build on our momentum and work to further enhance our competitive position.
Our strategy is to invest competitively to grow oil and gas production while working to drive performance across the group through enhanced operating efficiency, capital efficiency and cost efficiency.
          To meet growing world demand, BP is committed to exploring, developing and producing more fossil fuel resources; manufacturing, processing and delivering better and more advanced products; and enabling the transition to a lower-carbon future. We aim to do this while operating safely, reliably and in compliance with the law. We strive to run our business within the discipline of a clear financial framework.
          In 2009, we improved our overall competitive performance by enhancing operating performance and reducing complexity and costs. We believe we can continue to compete successfully through our ability to access resources and deliver high-quality products and service to our customers. We intend to remain focused on the application of technology and developing relationships based on a commitment to long-term partnerships and mutual advantage. Our intention is to generate and sustain business momentum and growth through a rigorous process of continuous improvement and an ongoing focus on safety, people and performance.
Safety, reliability, compliance and continuous improvement
Safe, reliable and compliant operations remain the group’s first priority. A key enabler for this is the BP operating management system (OMS), which provides a common framework for all BP operations, designed to achieve consistency and continuous improvement in safety and efficiency. OMS includes mandatory practices, such as integrity management and incident investigation, which are designed to address particular risks. In addition, it enables each site to focus on the most important risks in its own operations and sets out procedures on how to manage them in accordance with the group-wide framework. Further information on our safety priorities and performance can be found on page 42.
The right people, skills and capability
It is vital that we develop and deploy people with the skills, capability and behaviours required to meet our objectives. Despite a tight global recruitment market for some of our core technical disciplines, we have been successful in building capacity and getting the right people with the right skills in the right place. We are now going further, strengthening the culture within BP through a commitment to continuous improvement in operations and enhancing the capabilities, technical expertise and organizational quality needed to drive performance.
          Our people strategy has already resulted in refreshed group leadership and senior management teams, recruitment focused on individuals with strong operational and technical expertise, and appropriate reward for performance at all levels.
Enhanced performance and efficiency
Our strategy aims to create value for shareholders by investing to deliver growth in our Exploration and Production business together with enhanced efficiency and high-quality earnings and returns throughout our operations.
          In Exploration and Production, our strategy is to invest to grow production safely, reliably and efficiently. We intend to achieve this by strengthening our portfolio of leadership positions in the world’s most prolific hydrocarbon basins, enabled by the development and application of technology and the building of strong relationships based on mutual advantage. We also intend to sustainably drive cost and capital efficiency in accessing, finding, developing and producing resources, enabled by deep technical capability and a culture of continuous improvement.
          In Refining and Marketing, our strategic focus is on enhancing portfolio quality, integrating activities across value chains and performance efficiency. We expect to continue building our business around advantaged assets in material and significant energy markets while improving the safety and reliability of our operations. Our objective is to achieve sector-leading levels of performance on a sustainable basis. To achieve this, we need to continue upgrading the manufacturing capabilities within our integrated fuels value chains to achieve the best capacity utilization and margin capture. We continue to explore appropriate opportunities to deploy downstream capital into faster-growing non-OECD markets. We also intend to continue our selective investment in our international businesses, which include petrochemicals and lubricants, where we see potential to deliver strong and sustainable returns.
          In Alternative Energy, we have focused our investments in the areas where we believe we can create the greatest competitive advantage. We have substantial businesses in wind and solar power and are developing advanced biofuels and low-carbon energy technologies such as hydrogen power and carbon capture and storage.
          Our determination to drive efficiency through our businesses has proved vital to our performance during a period of recession and we believe that it will remain critical to our future prospects as the global economy recovers and evolves.
Looking further ahead
As discussed in the ‘Our market’ section of this Annual Report on Form 20-F (see pages 7 to 9), we expect that the world will require a more diverse energy mix as the basis for a secure supply of energy over time. We intend to play a central role in meeting the world’s continued need for hydrocarbons, with our Exploration and Production and Refining and Marketing activities remaining at the core of our strategy. We are also creating long-term options for the future in new energy technology and low-carbon energy businesses. Current investment is focused on wind, solar and biofuels as potential sources of resource diversification for the world, and we are investing in carbon capture and storage as an enabling technology. We believe that this focused portfolio has the potential to be a material source of value creation for BP in the longer term (see pages 38 to 39). We are also enhancing our capabilities in natural gas, which is likely to play a greater role as a key part of the energy future. We intend to lead and shape this transition, including through the application of advanced technology to unlock sources of unconventional gas, while working to achieve sector-leading levels of return for our shareholders.
 


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Business review

Our performance
2009 has been a successful year for BP, with positive financial and operational momentum despite an extremely turbulent global financial environment.
Safety
Good progress has been made on underpinning improved safety performance in 2009. Throughout the year, we continued to focus on training and enhancing procedures across the organization. Significantly, 2009 was an important year in the development of OMS. By the end of 2009, around 80% of our operating sites were using the system, including all our operated refineries and petrochemicals plants. (See Safety on page 42 for more information on OMS.)
           In 2009, a third-party-operated helicopter carrying contractors from BP’s Miller platform crashed in the North Sea, resulting in the tragic loss of 16 lives. In addition, BP sustained two fatalities within our own operations. We deeply regret the loss of these lives.
          Recordable injury frequency (RIF, a measure of the number of reported injuries per 200,000 hours worked) was 0.34, significantly below 2008 and 2007 levels of 0.43 and 0.48, respectively. Reported oil spills greater than one barrel were 234 in 2009 compared with 335 in 2008 and 340 in 2007. Our environmental measure that tracks greenhouse gas (GHG) emissionsa increased in 2009 to 65.0 million tonnes of carbon dioxide equivalent, compared with 61.4 million tonnes in 2008. The primary reason for this increase is the growth of our business, including the significant increase in our US refining throughputs, the start-up of our Tangguh LNG project in Indonesia and the continued success of our Gulf of Mexico deepwater operations, including Thunder Horse.
People
During 2009 we made further significant progress in generating a stronger performance focus and in fostering a culture that attributes more value to deep specialist skills and expertise. At the same time, we continued to improve operational efficiency and reduce overheads.
          Non-retail headcount was reduced by 4,400 (6%) in 2009. Overall, the number of employees (including retail staff) was reduced by 11,700 in 2009.
Performance
Against the backdrop of the global recession, we delivered a strong performance in 2009. Profit and cash flow were lower than in 2008, due primarily to a much weaker price environment, although the impact was partially offset by better operational performance and lower costs across the group as we implemented our efficiency programmes. Notable achievements include:
Exploration and Production
  Replacing 129% of our proved reserves, on a combined basis of subsidiaries and equity-accounted entities.
 
  Delivering a 5% underlying growth in productionb.
 
  Reducing unit production costs by 12%.
 
  Achieving a strong gas marketing and trading performance.
 
  Accessing new resources in Egypt, the Gulf of Mexico, Indonesia, Iraq and Jordan.
 
  Making the Tiber discovery in the Gulf of Mexico at a depth of over 35,000 feet, the deepest oil and gas discovery well ever drilled.
 
  Making three further discoveries in Block 31, Angola.
 
  Starting up Tangguh in Indonesia and six other major projects in the Gulf of Mexico, Trinidad and Russia.
Refining and Marketing
  Restoring our overall performance so that it is once again competitive with our supermajor peers.
 
  Achieving a Solomon refining availabilityc of 93.6%, which is an increase of almost five percentage points compared with 2008.
 
  Reducing costs across the segment by more than 15%d.
 
  Delivering a strong supply and trading performance.
 
  Performing strongly in our international businesses, despite the weak environment.
 
  Delivering simplification and lower costs through integration in the fuels value chains.
 
  Simplifying the segment’s footprint in aviation and lubricants and completing the transfer of our US convenience retail business to a franchise operation.
 
  Successfully exiting from our ground fuels marketing business in Greece.
 
a See footnote a in Environment on page 43.
 
b Underlying production growth excludes the effect of entitlement changes in our production-sharing agreements (driven by changes in oil and gas prices) and the effect of OPEC quota restrictions.
 
c Refining 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.
 
d Based on Refining and Marketing’s share of production and manufacturing expenses plus distribution and administration expenses.
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Business review
Selected financial and operating
information

This information, insofar as it relates to 2009, has been extracted or derived from the audited consolidated financial statements of the BP group presented on pages 107 to 182. 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.
 


                                         
     
$ million except per share amounts  
     
    2009     2008     2007     2006     2005  
     
Income statement data
                                       
     
Sales and other operating revenues from continuing operationsa
    239,272       361,143       284,365       265,906       239,792  
Profit before interest and taxation from continuing operationsa
    26,426       35,239       32,352       35,658       32,182  
Profit from continuing operationsa
    16,759       21,666       21,169       22,626       22,133  
Profit for the year
    16,759       21,666       21,169       22,601       22,317  
Profit for the year attributable to BP shareholders
    16,578       21,157       20,845       22,315       22,026  
Capital expenditure and acquisitionsb
    20,309       30,700       20,641       17,231       14,149  
Per ordinary share – cents
                                       
Profit for the year attributable to BP shareholders
                                       
Basic
    88.49       112.59       108.76       111.41       104.25  
Diluted
    87.54       111.56       107.84       110.56       103.05  
Profit from continuing operations attributable to BP shareholdersa
                                       
Basic
    88.49       112.59       108.76       111.54       103.38  
Diluted
    87.54       111.56       107.84       110.68       102.19  
Dividends paid per share – cents
    56.00       55.05       42.30       38.40       34.85  
– pence
    36.417       29.387       20.995       21.104       19.152  
     
Ordinary share datac
                                       
     
Average number outstanding of 25 cent ordinary shares (shares million undiluted)
    18,732       18,790       19,163       20,028       21,126  
Average number outstanding of 25 cent ordinary shares (shares million diluted)
    18,936       18,963       19,327       20,195       21,411  
     
Balance sheet data
                                       
     
Total assets
    235,968       228,238       236,076       217,601       206,914  
Net assets
    102,113       92,109       94,652       85,465       80,450  
Share capital
    5,179       5,176       5,237       5,385       5,185  
BP shareholders’ equity
    101,613       91,303       93,690       84,624       79,661  
Finance debt due after more than one year
    25,518       17,464       15,651       11,086       10,230  
Net debt to net debt plus equityd
    20%       21%       22%       20%       17%  
     
 
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 2005 and 2006.
 
b 2008 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 49). 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. All capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing.
 
c The number of ordinary shares shown has been used to calculate per share amounts.
 
d Net debt and the ratio of net debt to net debt plus equity ratio are non-GAAP measures. We believe that 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.
 


Profits
Profit attributable to BP shareholders for the year ended 31 December 2009 was $16,578 million, including inventory holding gains, net of tax, of $2,623 million and a net charge for non-operating items, after tax, of $1,067 million. In addition, fair value accounting effects had a favourable impact, net of tax, of $445 million relative to management’s measure of performance. Inventory holding gains and losses, net of tax, are described in footnote (a) on page 49. More information on non-operating items and fair value accounting effects can be found on pages 54-55.
          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.
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. In addition, fair value accounting effects had an unfavourable impact, net of tax, of $198 million relative to management’s measure of performance.
          The primary additional factors affecting profit for 2009, compared with 2008, were lower realizations and refining margins, partly offset by higher production, stronger operational performance and lower costs.
          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.
 


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Business 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
                                         
     
    2009f     2008     2007     2006     2005  
     
Crude oil production for subsidiaries (thousand barrels per day)
    1,400       1,263       1,304       1,351       1,423  
Crude oil production for equity-accounted entities (thousand barrels per day)
    1,135       1,138       1,110       1,124       1,139  
Natural gas production for subsidiaries (million cubic feet per day)
    7,450       7,277       7,222       7,412       7,512  
Natural gas production for equity-accounted entities (million cubic feet per day)
    1,035       1,057       921       1,005       912  
Estimated net proved crude oil reserves for subsidiaries (million barrels)b
    5,658       5,665       5,492       5,893       6,360  
Estimated net proved crude oil reserves for equity-accounted entities (million barrels)c
    4,853       4,688       4,581       3,888       3,205  
Estimated net proved natural gas reserves for subsidiaries (billion cubic feet)d
    40,388       40,005       41,130       42,168       44,448  
Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet)e
    4,742       5,203       3,770       3,763       3,856  
     
 
a Crude 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.
 
b Includes 23 million barrels (21 million barrels at 31 December 2008 and 20 million barrels at 31 December 2007) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
c Includes 243 million barrels (216 million barrels at 31 December 2008 and 210 million barrels at 31 December 2007) in respect of the 6.86% minority interest in TNK-BP (6.80% at 31 December 2008 and 6.51% at 31 December 2007).
 
d Includes 3,068 billion cubic feet of natural gas (3,108 billion cubic feet at 31 December 2008 and 3,211 billion cubic feet at 31 December 2007) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
e Includes 131 billion cubic feet (131 billion cubic feet at 31 December 2008 and 68 billion cubic feet at 31 December 2007) in respect of the 5.79% minority interest in TNK-BP (5.92% at 31 December 2008 and 5.88% at 31 December 2007).
 
f On 31 December 2008, the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than one per cent to BP’s total proved reserves.

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a Combined basis of subsidiaries and equity-accounted entities, on a basis consistent with general industry practice.
 
b On 31 December 2008 the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than 1% to BP‘s total proved reserves.
 
c Crude oil, condensate and natural gas liquids.
During 2009, 1,908 million barrels of oil and natural gas, on an oil equivalenta basis (mmboe), were added, excluding purchases and sales, to BP’s proved reserves (1,113mmboe for subsidiaries and 795mmboe for equity-accounted entities). At 31 December 2009, BP’s proved reserves were 18,292mmboe (12,621mmboe for subsidiaries and 5,671mmboe for equity-accounted entities). Our proved reserves in subsidiaries are located in the US (45%), South America (15%), Australasia (10%), Africa (10%) and the UK (9%). Our proved reserves in equity-accounted entities are located in Russia (69%), South America (21%), and Rest of Asia (9%).
 
a Natural gas is converted to oil equivalent at 5.8 billion cubic feet (bcf) = 1 million barrels.
Our total hydrocarbon production during 2009 averaged 3,998mboe/d (2,684mboe/d for subsidiaries and 1,314mboe/d for equity-accounted entities). This represents an increase of 4% (an increase of 6% for liquids and an increase of 2% for gas) when compared with 2008. In aggregate, after adjusting for entitlement impacts in our production-sharing agreements (PSAs) and the effect of OPEC quota restrictions, production was 5% higher than 2008. Our total hydrocarbon production during 2008 averaged 3,838mboe/d (2,517mboe/d for subsidiaries and 1,321mboe/d for equity accounted-entities). This represented an increase of 0.5% (a decrease of 0.5% for liquids and an increase of 2% for gas) when compared with 2007. In aggregate, after adjusting for entitlement impacts in our PSAs, 2008 production was 5% higher than 2007.
Acquisitions and disposals
There were no significant acquisitions in 2009. Disposal proceeds in 2009 were $2,681 million, principally from the sale of our interests in BP West Java Limited, Kazakhstan Pipeline Ventures LLC and LukArco, and the sale of our ground fuels marketing business in Greece and retail churn in the US, Europe and Australasia. Further proceeds from the sale of LukArco are receivable in the next two years. See Financial statements – Note 3 on page 122.
          In 2008, we completed an asset exchange with Husky Energy Inc., and asset purchases from Chesapeake Energy Corporation as described on page 49.
          In 2007, BP acquired Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The acquisition included Chevron’s 31% minority shareholding in Nerefco and certain associated assets. 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.


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Business review


Risk factors
We urge you to consider carefully the risks described below. If any of these risks occur, we might fail to deliver on our strategic priorities, which are expressed in terms of safety, people and performance (see page 10). Our business, financial condition and results of operations could suffer and the trading price and liquidity of our securities could decline.
In the current uncertain financial and economic environment, certain risks may gain more prominence either individually or when taken together. Oil and gas prices are likely to remain volatile with average prices and margins influenced by changes in supply and demand. This is likely to exacerbate competition in all businesses, which may impact costs and margins. At the same time, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal and regulatory frameworks for the oil and gas industry, including the risk of increased taxation. 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.
          Capital markets have regained some confidence after the recent crisis but if there are extended periods of constraints in these markets, at a time when cash flows from our business operations may be under pressure, our ability to maintain our long-term investment programme may be impacted 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 identifies and 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, taxes, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted. Our commitment to the transition to a lower-carbon economy may create expectations for our activities, and the level of participation in alternative energies carries reputational, economic and technology risks.
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.
 


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Business review


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 in a timely and efficient manner, we will be unable to sustain long-term replacement of reserves.
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 24 on page 142.
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. Failure to respond to changes in trading regulations could result in regulatory action and damage to our reputation. 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 pages 43-45.
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 pages 95-96.
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. Failure to comply with environmental laws, regulations and permits could lead to damage to the environment and could result in regulatory action, legal liability and damage to our reputation.
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 involve 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.
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Major project delivery
Successful execution of our group plan 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.
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
Successful recruitment of new staff, employee training, development and long-term renewal of skills, in particular technical capabilities such as 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.
Our systems of control
The board is responsible for the direction and oversight of BP. The board has set an overall goal for BP, which is to maximize long-term shareholder value through the allocation of its resources to activities in the oil, natural gas, petrochemicals and energy businesses. The board delegates authority for achieving this goal to the group chief executive (GCE).
          The board maintains five permanent committees that are composed entirely of non-executives. The board and its committees monitor, among other things, the identification and management of the group’s risks — both financial and non-financial. During the year, the board’s committees engaged with executive management, the general auditor and other monitoring and assurance providers (such as the group compliance and ethics officer and the external auditor) on a regular basis as part of their oversight of the group’s risks. Significant incidents that occurred and management’s response to them were considered by the appropriate committee and reported to the board. (See Board performance report on pages 65 to 76.)
          The GCE maintains a comprehensive system of internal control. This comprises the holistic set of management systems, organizational structures, processes, standards and behaviours that are employed to conduct our business and deliver returns for shareholders. The system 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. It addresses risks and how we should respond to them as well as the overall control environment. Each component of the system has been designed to respond to a particular type or collection of risks. Material risks are described within the Risk factors section (see pages 14 to 16).
          Key elements of our system of internal control are: the control environment; the management of risk and operational performance (including in relation to financial reporting); and the management of people and individual performance. Controls include the BP code of conduct, our leadership framework and our principles for delegation of authority, which are designed to make sure employees understand what is expected of them.
          As part of the control system, the GCE’s senior team — known as the executive team — is supported by sub-committees that are responsible for and monitor specific group risks. These include the group operations risk committee (GORC), the group financial risk committee (GFRC), the group people committee (GPC), and the group disclosures committee (GDC), which reviews the disclosures, controls and procedures over reporting.
          Operations and investments are conducted and reported in accordance with, and associated risks are thereby managed through, relevant standards and processes. These range from group standards, which set out processes for major areas such as safety and integrity, through to detailed administrative instructions on issues such as fraud reporting. The GCE conducts regular performance reviews with the segments and key functions to monitor performance and the management of risk and to intervene if necessary. People management is based on performance objectives, through which individuals are accountable for delivering specific elements of the group plan within agreed boundaries.
      


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Forward-looking statements
In order to utilize the ‘Safe Harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995, BP is providing the following cautionary statement. This document contains certain forward-looking statements with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in Business review (pages 6-59), including under the headings ‘Outlook’, with regard to strategy, management aims and objectives, future capital expenditure, the future scrip dividend programme, future hydrocarbon production volume and the group’s ability to satisfy its long-term sales commitments from future supplies available to the group, 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 Business review (pages 6-48) with regard to anticipated energy demand and consumption, global economic recovery, oil and gas prices, global reserves, expected future energy mix and the potential for cleaner and more efficient sources of energy, management aims and objectives, strategy, production, petrochemical and refining margins, anticipated investment in Alternative Energy, anticipated future project developments, growth of the international businesses, Refining and Marketing investments, reserves increases through technological developments, with regard to planned investment or other projects, timing and ability to complete announced transactions and future regulatory actions; and (iii) the statements in Business review (pages 49-59) with regard to the plans of the group, the cost of and provision for future remediation programmes and environmental operating and capital expenditures, taxation, liquidity and costs for providing pension and other post-retirement benefits; and including under ‘Liquidity and capital resources’ — Trend Information, with regard to global economic recovery, oil and gas prices, petrochemical and refining margins, production, demand for petrochemicals, production and production growth, depreciation, underlying average quarterly charge from Other businesses and corporate, costs, foreign exchange and energy costs, capital expenditure, timing and proceeds of divestments, balance of cash inflows and outflows, dividend and optional scrip dividend, 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; actions by regulators; 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 14-16. 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.
Further note on certain activities
During the period covered by this report, non-US subsidiaries or other non-US entities of BP, conducted limited activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism (‘Sanctioned Countries’). These activities continue to be insignificant to the group’s financial condition and results of operations.
          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. BP buys crude oil, refinery and petrochemicals feedstocks, blending components and LPG of Iranian origin or from Iranian counterparties primarily for sale to third parties in Europe and a small portion is used by BP in its own facilities in South Africa and Europe. Until recently BP held an equity interest in an Iranian joint venture that has a blending facility and markets lubricants for sale to domestic consumers. In January 2010, BP restructured its interest in the joint venture and currently maintains its involvement through certain contractual arrangements, which it keeps under review in light of pending legislative developments in the US. 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 petrochemicals plants in Iran.
          BP sells lubricants in Cuba through a 50:50 joint venture there and in 2009 purchased a cargo of naphtha from a non-Cuban counterparty that was loaded in Cuba. In Syria, lubricants are sold through a distributor and BP obtains crude oil and refinery feedstocks for sale to third parties in Europe. In addition, BP sells crude oil and refined products into Syria.
          BP supplies fuels and lubricants to airlines and shipping companies from Sanctioned Countries at airports and ports located outside these countries.
          BP monitors its activities with Sanctioned Countries and keeps them under review to ensure compliance with applicable laws and regulations of the US and other countries where BP operates.
 
 
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Exploration and Production
Our Exploration and Production segment includes upstream and midstream activities in 30 countries, including Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), Norway, 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 and the US. Upstream activities involve oil and natural gas exploration and field development and production. Our exploration programme is currently focused around Angola, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea, Oman and onshore US. Major development areas include Algeria, Angola, Asia Pacific, Azerbaijan, Egypt and the deepwater Gulf of Mexico. During 2009, 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, the UK, Canada and Indonesia. 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, the South Caucasus Pipeline (SCP), which takes gas from Azerbaijan through Georgia to the Turkish border 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. 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, Chile, Abu Dhabi, Kazakhstan, Venezuela and Russia, as well as some of our operations in Angola, Canada and Indonesia, are conducted through equity-accounted entities.
Our market
The market environment in which we operate was particularly challenging during 2009, with crude oil and natural gas prices at lower levels than we have experienced in recent history.
          The annual average crude oil price declined in 2009 for the first time since 2001, breaking an unprecedented string of seven consecutive annual increases. Dated Brent for the year averaged $61.67 per barrel, about 37% below 2008’s record average of $97.26 per barrel. Prices were lowest at the beginning of the year as the world economy grappled with the sharpest downturn in modern economic history.
          In 2010, we expect oil market movements to continue to be driven by developments in the world economy, by their resulting implications for oil consumption, and by OPEC production decisions.
          Natural gas prices weakened in 2009 and were volatile. The average US Henry Hub First of Month Index fell to $3.99/mmBtu in 2009, a 56% decrease from the record $9.04/mmBtu average seen in 2008.
Recession-induced demand declines and strong production caused prices to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in September. However, over the course of the year, the impact was partly offset as US regional gas price differentials narrowed, driven partly by the Rockies Express Pipeline extension allowing the transportation of larger quantities of gas out of the Rockies area. Reduced imports from Canada, slowing US production growth and cooler temperatures allowed prices to recover to $4.49/mmBtu by the end of the year. Prices at the UK National Balancing Point similarly fell to an average of 30.85 pence per therm, 47% below the 2008 average price of 58.12 pence per therm.
          In 2009, there was a switch of uncontracted LNG cargoes from Asia to Europe, reflecting a shift in relative spot prices. LNG imports to Europe have competed with pipeline imports, where the gas price is often indexed to oil prices, as well as with marginal European gas production. On an energy equivalent basis, gas prices were often at or below parity with coal, which led to gas displacing coal in power generation in Europe and the US.
          In the event of any recovery in the economy in 2010, both the US and UK gas markets are expected to benefit although the price upside is likely to be constrained as a result of a record amount of LNG expected to become available globally.
Our strategy
Our strategy is to invest to grow production safely, reliably and efficiently by:
  Strengthening our portfolio of leadership positions in the world’s most prolific hydrocarbon basins, enabled by the development and application of technology and strong relationships based on mutual advantage.
 
  Sustainably driving cost and capital efficiency in accessing, finding, developing and producing resources, enabled by deep technical capability and a culture of continuous improvement.
Our performance
In Exploration and Production, safety, both personal and process, remains our highest priority. 2009 brought further improvements in personal safety with our reported recordable injury frequency improving from 0.43 in 2008 to 0.39 in 2009. We also achieved improvements in the number of reported process safety-related incidents and a significant reduction in the number of reported spills.
          BP’s operating management system (OMS) provides us with a systematic framework for safe, reliable and efficient operations. Throughout 2009, OMS helped us to deliver continuous improvement in the way we manage our people, processes, plant and performance.
          From onshore production facilities to offshore platforms, a total of 47 exploration and production sites had completed their transition to OMS by the end of 2009. The remaining seven sites are on track to transition to OMS in 2010.
      


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We continually seek to access resources and in 2009 this included Iraq, where, together with China National Petroleum Corporation (CNPC), we entered into a contract with the state-owned South Oil Company (SOC) to expand production from the Rumaila field; Jordan, where on 3 January 2010, we received approval from the Government of Jordan to join the state-owned National Petroleum Company (NPC) to exploit the onshore Risha concession in the north east of the country; further access in Egypt, where we were awarded two blocks in an offshore area of the Nile Delta; Indonesia, where we signed a production-sharing agreement (PSA) for the exploration and development of coalbed methane in the Sanga-Sanga block, supplying gas to Indonesia’s largest LNG export facility and, subject to Government of Indonesia approval, farmed into Chevron’s West Papua I & III blocks; and the Gulf of Mexico, where we were awarded 61 blocks through the Outer Continental Shelf Lease Sales 208 and 210.
          In 2009, we were involved in a number of discoveries. The most significant of these were in the deepwater Gulf of Mexico with the Tiber well; Angola, where we made three further discoveries in the ultra deepwater Block 31; and Canada, where we discovered natural gas with the Ellice J27 well.
          Seven major projects came onstream. We continue to grow our position and leverage our experience as the largest producer in the Gulf of Mexico, starting up three projects ahead of schedule, including the second phase of Atlantis. In addition, production commenced at our Savonette field in Trinidad, at our Tangguh LNG project in Indonesia and, through TNK-BP, we saw the start-up of a further two projects, in the northern hub of Kamennoye, and the Urna and Ust-Tegus fields in the Uvat area.
          Production from our established centres — including the North Sea, Alaska, North America Gas and Trinidad — was on plan, with improved operating efficiency for the segment as a whole, and we had strong production growth in the Gulf of Mexico, including excellent performance from Thunder Horse. Production from Egypt and TNK-BP also made a strong contribution to our growth.
          Production for the year was up more than 4% from last year. After adjusting for the effect of entitlement changes in our PSAs and the effect of OPEC quota restrictions, underlying production growtha was 5% higher than 2008.
 
a Underlying production growth excludes the effect of entitlement changes in our PSAs (driven by changes in oil and gas prices) and the effect of OPEC quota restrictions.
We also reduced unit production costs through a combination of high-grading activity, improving execution efficiency, capturing the benefits of the deflationary cost environment at the beginning of the year and favourable foreign exchange effects. During 2009 we improved the quality of our procurement and supply chain management organization, systems and processes, which we expect will help deliver sustained cost efficiency in the future.
          The replacement cost profit before interest and tax was $24.8 billion, a 35% decrease compared with the record level in 2008. This result was primarily driven by lower oil and gas realizations, lower income from equity-accounted entities and higher depreciation, partly offset by strong underlying production growth and improved cost management, which contributed to a 12% reduction in unit production costs. Our financial results are discussed in more detail on pages 51-52.
          Total capital expenditure including acquisitions and asset exchanges in 2009 was $14.9 billion (2008 $22.2 billion and 2007 $14.2 billion). In 2009, capital expenditure included $306 million relating to the award of the contract to redevelop the Rumaila field in Iraq.
          Development expenditure of subsidiaries incurred in 2009, excluding midstream activities, was $10,396 million, compared with $11,767 million in 2008 and $10,153 million in 2007.
Key statistics
                         
   
 
$ million  
    2009     2008     2007  
 
Sales and other operating revenuesa
    57,626       86,170       65,740  
Replacement cost profit before interest and taxb
    24,800       38,308       27,602  
Total assets
    140,149       136,665       125,736  
Capital expenditure and acquisitions
    14,896       22,227       14,207  
 
 
                       
$  per barrel
 
 
Average BP liquids realizationsc d
    56.26       90.20       67.45  
 
 
                       
$  per thousand cubic feet
 
 
Average BP natural gas realizationsc
    3.25       6.00       4.53  
 
 
a Includes sales between businesses.
 
b Includes profit after interest and tax of equity-accounted entities.
 
c Realizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.
 
d Crude oil and natural gas liquids.
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The table below presents our average sales price per unit of production.
                                                                                 
     
    $ per unit of productiona
    ┌───────Europe───────┐     ┌───────North───────┐     ┌─South─┐     ┌─Africa─┐     ┌───────Asia───────┐     Australasia     Total group  
                    America     America                                     average  
     
                            Rest of                                                
            Rest of             North                             Rest of                  
    UK     Europe     US     America                     Russia     Asia                  
     
Average sales priceb
                                                                               
     
2009
                                                                               
     
Liquidsc
    62.19       60.73       53.68       30.77       52.48       57.40             61.27       57.22       56.26  
Gas
    4.68       7.62       3.07       3.53       2.50       3.61             3.30       5.25       3.25  
     
2008
                                                                               
     
Liquidsc
    89.82       93.77       89.22       64.42       91.61       89.44             97.20       86.33       90.20  
Gas
    8.41       6.96       6.77       7.87       4.90       4.46             3.63       9.22       6.00  
     
2007
                                                                               
     
Liquidsc
    69.17       70.41       64.18       48.24       65.54       67.81             73.00       70.56       67.45  
Gas
    6.40       5.84       5.43       6.24       3.25       3.93             3.05       5.96       4.53  
     
 
aUnits of production are barrels for liquids and thousands of cubic feet for gas.
 
bRealizations are based on sales of consolidated subsidiaries only (including transfers between businesses), which excludes equity-accounted entities.
 
cCrude oil and natural gas liquids.
      


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The table below presents our average production cost per unit of production.
                                                                                 
     
    $ per unit of productiona  
     
    ┌───────Europe───────┐     ┌───────North───────┐     ┌─South─┐     ┌─Africa─┐     ┌───────Asia───────┐     Australasia     Total group  
                    America     America                                     average  
     
                                                                             
                            Rest of                                                
            Rest of             North                             Rest of                  
    UK     Europe     US     America                     Russia     Asia                  
     
The average production cost per unit of productiona
                                                                               
2009
    12.38       10.72       7.26       14.45       2.20       6.05             4.35       1.60       6.39  
2008
    12.19       8.74       9.02       15.35       2.34       6.72             5.24       1.74       7.24  
2007
    14.00       7.17       9.03       14.04       2.69       6.43             3.81       1.75       7.14  
     
 
aUnits of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes; and are based on production cost of consolidated subsidiaries only, which excludes equity-accounted entities.

Outlook
Our priorities remain the same — safety, people and performance, focusing on the delivery of safe, reliable and efficient operations.
          In 2010, we aim to use the momentum generated in 2009 to continue to improve operational, cost and capital efficiency, while ensuring we maintain our priorities of safe, reliable and efficient operations. We intend to continue to focus on building personnel and technological capability for the future. We believe our portfolio of assets is strong and well positioned to compete and grow in a range of external conditions. Also in 2010, we intend to create a centralized developments organization to deliver our major projects. By bringing our project expertise into one team, we expect to continue our drive for improved capital efficiency by fully optimizing our project designs and improving project execution.
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 2009 were $2,805 million, compared with $2,290 million in 2008 and $1,892 million in 2007. 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 68% of 2009 exploration and appraisal costs were directed towards appraisal activity. In 2009, we participated in 503 gross (107 net) exploration and appraisal wells in 12 countries. The principal areas of exploration and appraisal activity were Angola, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea, Oman and onshore US.
          Total exploration expense in 2009 of $1,116 million (2008 $882 million and 2007 $756 million) included the write-off of expenses related to unsuccessful drilling activities in the deepwater Gulf of Mexico ($391 million), India ($31 million), Angola ($28 million), Egypt ($27 million), and others ($31 million).
          In most cases, reserves booking from new discoveries will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling.
Reserves and production
Resource progression
BP manages its hydrocarbon resources in three major categories: prospect inventory, contingent resources and proved reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the contingent resources category. The contingent resources move through various sub-categories as their technical and commercial maturity increases through appraisal activity.
          At the point of final investment decision, most proved 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 proved reserves depends on a later phase of activity, only that portion of proved reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will typically 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 proved reserves to the start of production. Changes to proved 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.
          Contingent resources in a field will only be recategorized as proved reserves when all the criteria for attribution of proved status have been met and the proved reserves are included in the business plan and scheduled for development, typically within five years. Where, on occasion, the group decides to book proved reserves where development is scheduled to commence after five years, these proved reserves will be booked only where they satisfy the SEC’s criteria for attribution of proved status. There are material volumes of proved undeveloped reserves in Angola, Trinidad, the US, and Canada which are part of ongoing development activities for which BP has a historical track record of completing comparable projects. In all cases, the volumes are being progressed as part of an adopted development plan which calls for drilling of wells over an extended period of time given the magnitude of the development.
          In 2009, we converted approximately 2,061mmboe proved undeveloped reserves to proved developed reserves through ongoing investment in our upstream development activities. Total development expenditure in Exploration and Production, excluding midstream activities, was $12,392 million in 2009 ($10,396 million for subsidiaries and $1,996 million for equity-accounted entities). The major areas converted in 2009 were Azerbaijan, Indonesia, Russia, Trinidad and the US.


      


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BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice. BP only applies technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. BP applies high resolution seismic data for the identification of reservoir extent and fluid contacts only where there is an overwhelming track record of success in its local application. In certain deepwater fields, such as fields in the Gulf of Mexico, BP has booked 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. To determine reasonable certainty of commercial recovery, BP employs a general method of reserves assessment that 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 understanding of 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. There is a strong track record of proved reserves recorded using these methods, validated by actual production levels.
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 proved reserves base undergoes central review every two years and more than 90% is reviewed centrally every four years.
BP’s segment resources authority is the petroleum engineer primarily responsible for overseeing the preparation of the reserves estimate. He has over 35 years of diversified industry experience with the past 10 spent as the head of the reservoir management function within BP. He is a member of the Society of Petroleum Engineers (SPE) and the Institute of Materials, Minerals and Mining. On the retirement of the current
segment resources authority in 2010, his responsibilities for reserves estimation, governance and compliance will be taken by the current vice president of segment reserves. The current vice president of segment reserves has over 25 years of diversified industry experience with the past seven spent managing the governance and compliance of BP’s reserves estimation. He is a sitting member of the SPE Oil and Gas Reserves Committee and the United Nations Economic Commission for Europe Expert Group on Resource Classification.
          For the executive directors and senior management, no specific portion of compensation bonuses is directly related to proved 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 proved reserves.
Proved reserves replacement
Total hydrocarbon proved reserves, on an oil equivalent basis including equity-accounted entities, comprised 18,292mmboe (12,621mmboe for subsidiaries and 5,671mmboe for equity-accounted entities) at 31 December 2009, an increase of 0.8% (increase of 0.5% for subsidiaries and increase of 1.5% for equity-accounted entities) compared with 31 December 2008. Natural gas represents about 43% (55% for subsidiaries and 14% for equity-accounted entities) of these reserves. The increase includes a net decrease from acquisitions and divestments of 282mmboe, (59mmboe net decrease for subsidiaries and 223mmboe net decrease for equity-accounted entities) largely comprising a number of assets in Bolivia, Indonesia, Kazakhstan, Pakistan and the UK.
          The proved reserves 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. For 2009 the proved reserves replacement ratio excluding acquisitions and divestments was 129% (121% in 2008 and 112% in 2007) for subsidiaries and equity-accounted entities, 112% for subsidiaries alone and 164% for equity-accounted entities alone.
          In 2009, net additions to the group’s proved reserves (excluding production, sales and purchases of reserves-in-place and equity-accounted entities) amounted to 1,113mmboe (795mmboe for equity-accounted entities), principally through improved recovery from, and extensions to, existing fields and discoveries of new fields. Of our subsidiary reserves additions through improved recovery from, and extensions to, existing fields and discoveries of new fields, approximately 55% are associated with new projects and are proved undeveloped reserves additions. Volumes added in 2009 principally relied on the application of conventional technologies. The remaining additions are in existing developments where they represent a mixture of proved developed and proved undeveloped reserves. The principal reserves additions in our subsidiaries were in the US (Arkoma, Mad Dog, Prudhoe Bay, Thunder Horse), the UK (Clair), Trinidad (Kapok), Angola (Pazflor) and Australia (Jansz-Io). The principal reserves additions in our equity-accounted entities were in Argentina (Cerro Dragon, Cuenca Marina Austral) and in Russia (Kamennoye, Samatlor).
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Compliance
International Financial Reporting Standards (IFRSs) do 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 Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins as issued by the SEC staff. On 31 December 2008, the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than 1% to BP’s total proved reserves. The reasons for the increase are primarily due to the application of reliable technologies and inclusion of proved reserves more than one spacing away from existing penetrations as discussed below.
          By their nature, there is always some risk involved in the ultimate development and production of proved 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. All the group’s proved reserves held in subsidiaries and equity-accounted entities are estimated by the group’s petroleum engineers.
          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 PSAs. In a concession, the consortium of which we are a part is entitled to the proved 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 proved 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. Fourteen percent 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 disclose our share of proved 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.
Production
Our total hydrocarbon production during 2009 averaged 3,998 thousand barrels of oil equivalent per day (mboe/d). This comprised 2,684mboe/d for subsidiaries and 1,314mboe/d for equity-accounted entities, an increase of 6.6% and a decrease of 0.5% respectively compared with 2008. For subsidiaries, 40% of our production was in the US, 17% in Trinidad and 10% in the UK. For equity-accounted entities, 71% of production was from Russia, 14% in the United Arab Emirates and 11% in Argentina.
          The strong growth in production in 2009 benefited by about 40mboe/d on an annual basis from a combination of the absence of a significant hurricane season and from the make-up of a prior period underlift. As a result, we expect production in 2010 to be slightly lower than in 2009. The actual growth rate will depend on a number of factors, including our pace of capital spending, the efficiency of that spend, the oil price and its impact on PSAs, as well as OPEC quota restrictions.
          The group and its equity-accounted entities have numerous long-term sales commitments in their various business activities, all of which are expected to be sourced from supplies available to the group which are not subject to priorities, curtailments or other restrictions. No single contract or group of related contracts is material to the group.
The following tables show BP’s estimated net proved reserves as at 31 December 2009.
Estimated net proved reserves of liquids at 31 December 2009a b
                         
 
million barrels  
    Developed     Undeveloped     Total  
 
UK
    403       291       694  
Rest of Europe
    83       184       267  
US
    1,862       1,211       3,073 c
Rest of North America
    11       1       12  
South America
    49       56       105 d
Africa
    422       454       876  
Rest of Asia
    182       334       516  
Australasia
    58       57       115  
 
Subsidiaries
    3,070       2,588       5,658  
 
Equity-accounted entities
    3,121       1,732       4,853 e
 
Total
    6,191       4,320       10,511  
 
Estimated net proved reserves of natural gas at 31 December 2009a b
                         
 
billion cubic feet  
    Developed     Undeveloped     Total  
 
UK
    1,602       670       2,272  
Rest of Europe
    49       397       446  
US
    9,583       5,633       15,216  
Rest of North America
    716       453       1,169  
South America
    3,177       7,393       10,570 f
Africa
    1,107       1,454       2,561  
Rest of Asia
    1,579       249       1,828  
Australasia
    3,219       3,107       6,326  
 
Subsidiaries
    21,032       19,356       40,388  
 
Equity-accounted entities
    3,035       1,707       4,742 g
 
Total
    24,067       21,063       45,130  
 
Net proved reserves on an oil equivalent basis
                         
 
million barrels of oil equivalent  
    Developed     Undeveloped     Total  
 
Subsidiaries
    6,696       5,925       12,621  
Equity-accounted entities
    3,644       2,027       5,671  
 
Total
    10,340       7,952       18,292  
 
 
a 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. We disclose our share of reserves held in jointly controlled entities and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities.
 
b The 2009 marker prices used were Brent $59.91/bbl (2008 $36.55/bbl and 2007 $96.02/bbl) and Henry Hub $3.82/mmBtu (2008 $5.63/mmBtu and 2007 $7.10/mmBtu).
 
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 68 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.
 
d Includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
e Includes 243 million barrels of crude oil in respect of the 6.86% minority interest in TNK-BP.
 
f Includes 3,068 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
 
g Includes 131 billion cubic feet of natural gas in respect of the 5.79% minority interest in TNK-BP.
      


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The following tables show BP’s net production by major field for 2009, 2008 and 2007.
Liquids
                             
         
thousand barrels per day  
         
    BP net share of production a
    Field or area   2009     2008     2007  
         
UKb
  ETAPc     34       27       32  
 
  Foinavend     29       26       37  
 
  Other     105       120       132  
         
Total UK
        168       173       201  
         
Norway
  Various     40       43       51  
         
Total Rest of Europe
        40       43       51  
         
Total Europe
        208       216       252  
         
Alaska
  Prudhoe Bayd     69       72       74  
 
  Kuparuk     45       48       52  
 
  Milne Pointd     24       27       28  
 
  Other     43       50       55  
         
Total Alaska
        181       197       209  
         
Lower 48 onshoreb
  Various     97       97       108  
         
Gulf of Mexico deepwater
  Thunder Horsed     133       24        
 
  Atlantisd     54       42       2  
 
  Mad Dogd     35       31       25  
 
  Mars     29       28       30  
 
  Na Kikad     27       29       32  
 
  Horn Mountaind     25       18       18  
 
  Kingd     22       23       22  
 
  Other     62       49       67  
         
Total Gulf of Mexico deepwater
        387       244       196  
         
Total US
        665       538       513  
         
Canadab
  Variousd     8       9       8  
         
Total Rest of North America
        8       9       8  
         
Total North America
        673       547       521  
         
Colombia
  Variousd     23       24       28  
Trinidad & Tobago
  Variousd     38       38       30  
Venezuelab
  Various           4       16  
         
Total South America
        61       66       74  
         
Angola
  Greater Plutoniod     70       69       12  
 
  Kizomba C Dev     43       30        
 
  Dalia     32       34       31  
 
  Girassol FPSO     22       22       20  
 
  Other     44       46       77  
         
Total Angola
        211       201       140  
         
Egypt
  Gupco     55       41       36  
 
  Other     16       16       7  
         
Total Egypt
        71       57       43  
         
Algeria
  Various     22       19       12  
         
Total Africa
        304       277       195  
         
Azerbaijan
  Azeri-Chirag-Gunashlid     94       97       200  
 
  Other     7       8       5  
         
Total Azerbaijan
        101       105       205  
         
Western Indonesiab
  Various     5       7       7  
Other
  Various     17       16       16  
         
Total Rest of Asiab
        123       128       228  
         
Total Asia
        123       128       228  
         
Australia
  Various     31       29       34  
         
Total Australasia
        31       29       34  
         
Total subsidiariese
        1,400       1,263       1,304  
         
Equity-accounted entities (BP share)
                           
Russia — TNK-BPb
  Various     840       826       832  
         
Total Russia
        840       826       832  
         
Abu Dhabif
  Various     182       210       192  
Other
  Various     12       10       9  
         
Total Rest of Asiab
        194       220       201  
         
Total Asia
        1,034       1,046       1,033  
         
Argentina
  Various     75       70       69  
Venezuelab
  Various     25       19       6  
Boliviab
  Various     1       3       2  
         
Total South America
        101       92       77  
         
Total equity-accounted entities
        1,135       1,138       1,110  
         
Total subsidiaries and equity-accounted entities
        2,535       2,401       2,414  
         
 
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 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in Pakistan, swapped a number of assets with BG Group plc in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest Java to Pertamina, divested its interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation payable, Pan American Energy’s shares of Chaco. In 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position and TNK-BP disposed of some non-core interests. In 2007, BP divested its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties.
 
cVolumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell.
 
dBP-operated.
 
eIncludes 26 net mboe/d of NGLs from processing plants in which BP has an interest (2008 19mboe/d and 2007 54mboe/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 we report production and reserves there gross of production taxes.
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Natural gas
                             
         
                million cubic feet per day  
         
        BP net share of production a
         
    Field or area   2009     2008     2007  
         
UKb
  Bruce/Rhumc     110       165       161  
 
  Brae East     62       71       60  
 
  Other     446       523       547  
         
Total UK
        618       759       768  
         
Netherlandsb
  Various                 3  
Norway
  Various     16       23       26  
         
Total Rest of Europe
        16       23       29  
         
Total Europe
        634       782       797  
         
Lower 48 onshoreb
  San Juanc     659       682       694  
 
  Jonahc     227       221       173  
 
  Arkomac     194       240       204  
 
  Wamsutterc     146       136       120  
 
  Hugotonc     102       91       123  
 
  Tuscaloosac     65       65       78  
 
  Other     562       451       458  
         
Total Lower 48 onshore
        1,955       1,886       1,850  
         
Gulf of Mexico deepwater
  Thunder Horsec     83       11        
 
  Other     220       219       269  
         
Total Gulf of Mexico deepwater
        303       230       269  
         
Alaska
  Various     58       41       55  
         
Total US
        2,316       2,157       2,174  
         
Canadab
  West Central     69       63       63  
 
  Otherc     194       182       192  
         
Total Canada
        263       245       255  
         
Total Rest of North America
        263       245       255  
         
Total North America
        2,579       2,402       2,429  
         
Trinidad & Tobago
  Mangoc     664       471       22  
 
  Cashima/NEQBc     571       375       6  
 
  Kapokc     540       619       984  
 
  Cannonballc     225       336       628  
 
  Amherstiac     197       288       155  
 
  Otherc     233       357       638  
         
Total Trinidad
        2,430       2,446       2,433  
         
Colombia
  Various     62       84       104  
Venezuelab
  Various           2       6  
         
Total South America
        2,492       2,532       2,543  
         
Egypt
  Temsah     118       109       118  
 
  Ha’pyc     94       94       108  
 
  Taurtc     73       24        
 
  Other     177       145       89  
         
Total Egypt
        462       372       315  
         
Algeria
  Various     159       112       153  
         
Total Africa
        621       484       468  
         
Pakistanb
  Variousc     173       162       121  
         
Azerbaijan
  Variousc     126       143       73  
         
Western Indonesiab
  Sanga-Sanga     71       69       75  
 
  Other     35       97       81  
         
Total Western Indonesia
        106       166       156  
         
China
  Yacheng     83       91       85  
Vietnam
  Variousc     63       61       82  
Sharjah
  Variousc     59       73       92  
         
Total Rest of Asia
        610       696       609  
         
Total Asia
        610       696       609  
         
Australia
  Perseus/Athena     142       229       193  
 
  Goodwyn     139       74       107  
 
  Angel     120       6        
 
  Other     39       71       76  
         
Total Australia
        440       380       376  
         
Eastern Indonesia
  Tangguhc     74       1        
         
Total Australasia
        514       381       376  
         
Total subsidiariesd
        7,450       7,277       7,222  
         
Equity-accounted entities (BP share)
                           
Russia — TNK-BPb
  Various     601       564       451  
         
Total Russia
        601       564       451  
         
Western Indonesia
  Various     31       31       33  
Kazakhstanb
  Various     11       8       8  
         
Total Rest of Asia
        42       39       41  
         
Total Asia
        643       603       492  
         
Argentina
  Various     378       385       369  
Boliviab
  Various     11       63       60  
Venezuelab
  Various     3       6        
         
Total South America
        392       454       429  
         
Total equity-accounted entitiesd
        1,035       1,057       921  
         
Total subsidiaries and equity-accounted entities
        8,485       8,334       8,143  
         
 
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 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in Pakistan, swapped a number of assets with BG Group plc in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest Java to Pertamina, divested its interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation payable, Pan American Energy’s shares of Chaco. In 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position and TNK-BP disposed of some non-core interests. In 2007, BP divested its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties.
 
cBP-operated.
 
dNatural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.
      


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The following narrative reviews operations in our Exploration and Production business by continent and country, and lists associated significant events that occurred in 2009. Where relevant, BP’s percentage working interest in oil and gas assets is shown in brackets. Working interest is the cost-bearing ownership share of an oil or gas lease. The percentages disclosed for certain agreements do not necessarily reflect the percentage interests in reserves and production.
North America
United States
Our activities within the US take place in three main areas: deepwater Gulf of Mexico, Lower 48 states and Alaska.
Deepwater Gulf of Mexico:
Deepwater Gulf of Mexico is our largest area of growth in the US. In addition, we are the largest producer and acreage holder in the region.
         Significant events were:
 
  In May 2009, BP announced it had begun production from the Dorado (BP 75% and operator) and King South (BP 100%) projects. Both projects are subsea tiebacks to the existing BP Marlin Tension Leg Platform (TLP) infrastructure. Dorado comprises three new subsea wells located about two miles from the Marlin TLP. King South comprises a single subsea well located 18 miles from the Marlin TLP. Both projects leverage existing subsea and topsides infrastructure and the latest subsea and drilling technology to enable the efficient development of the fields. Dorado utilizes dual completion technology enabling production from five Miocene zones and King South is produced through the existing King subsea pump.
 
  In June 2009, the Atlantis Phase 2 (BP 56%) project achieved first oil ahead of schedule, signalling the official start-up.
 
  In July 2009, BP announced the drilling of a successful appraisal well in a previously untested southern segment of the Mad Dog field (BP 60.5% and operator). The 826-5 well is located in the Green Canyon block 826, approximately 100 miles south of Grand Isle, Louisiana, in about 5,100 feet of water. The results from this well continue the successful phased development of the Mad Dog field and build upon the success from 2008.
 
  In September 2009, BP announced the Tiber discovery in the deepwater Gulf of Mexico (BP 62% and operator). The discovery well, located in Keathley Canyon block 102, approximately 250 miles south-east of Houston, is in 4,132 feet of water. It was drilled to a total depth of approximately 35,055 feet making it the deepest oil and gas discovery well ever drilled. The well found oil in multiple Lower Tertiary reservoirs. Appraisal will be required to determine the size and commerciality of the discovery.
Lower 48 states:
Our North America Gas business operates onshore in the Lower 48 states producing natural gas, natural gas liquids and coalbed methane across 14 states. In 2009, we drilled almost 300 wells as operator and continued to maintain a stable programme of drilling activity throughout the year. Shale gas assets are becoming an increasingly important part of our North America Gas business:
         Significant events were:
  In the fourth quarter of 2009, BP further expanded its shale gas portfolio by securing new access in the Eagle Ford Shale in South Texas. Combined with our 2008 acquisitions of interests in Chesapeake Energy Corporation’s Woodford and Fayetteville Shale assets in the Arkoma Basin and our incumbent position in the Haynesville Shale in East Texas, BP now has a material shale gas position in the Lower 48 states.
 
  Since taking over operations of the Woodford shale properties, BP gross operated production has increased from 60mmcf/d in November 2008 to over 100mmcf/d by the end of 2009, a 67% increase. BP delivered 23 wells by the end of the year with an
    average 30-day rate of 4.6mmcf/d per well, approximately 50% higher than initial expectations.
 
  In 2009, BP net production from the Fayetteville shale properties has grown from approximately 55mmcf/d to 87mmcf/d at the end of the year, an increase of approximately 60%. Individual well performance continues to exceed expectations by approximately 25%.
 
  In 2009, BP drilled four wells appraising the Haynesville Shale asset and plans to increase horizontal well drilling in 2010. BP’s position in the Haynesville Shale in North Louisiana and East Texas covers an area of approximately 150,000 net acres.
 
  The business has made good progress in restructuring its activity and driving down costs to a level that is consistent with the economic environment.
Alaska:
BP operates 15 North Slope oil fields (including Prudhoe Bay, Endicott, Northstar, and Milne Point) and four North Slope pipelines, and owns a significant interest in six other producing fields.
          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 were:
 
  In 2009, we progressed the previously announced 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, to be drilled from existing infrastructure in the BP-operated Endicott field to minimize the onshore and offshore environmental footprint. These wells are expected to be the longest horizontal wells ever drilled and completed in the industry, extending two miles deep and as far as eight miles horizontally. A specialized rig for drilling in the Arctic has been built for the project, and it is the world’s largest and most powerful onshore drilling rig. Key project milestones achieved during 2009 include expansion of the BP-operated Endicott field satellite drilling island (SDI) in April; and sealift delivery of the ultra-extended reach drilling rig to the Endicott SDI in August. Drilling is expected to start in 2010, with first oil expected in 2011. BP drilled the Liberty discovery well in 1997, and is the operator and sole owner of the field.
 
  On 27 January 2009, the Commissioner of the State of Alaska Department of Natural Resources (DNR) issued a ‘Conditional Interim Decision’ in connection with the appeal of the Point Thomson area lease terminations. The Point Thomson Unit (PTU) was terminated by administrative decision of the DNR in November 2006 (BP 32%). In February 2007, the DNR notified the PTU owners of its decision to terminate the Point Thomson area leases as well. ExxonMobil, operator, and the other unit owners including BP, are pursuing an appeal of the unit termination in the Alaska Superior Court; and the lease terminations are under administrative appeal with the DNR. The 27 January 2009 Conditional Interim Decision permitted ExxonMobil to conduct drilling operations on two of the 31 terminated leases comprising the former PTU. The DNR’s interim decision provided that the two leases would be reinstated if certain conditions were met. On 11 January 2010, the Alaska Superior Court reversed the DNR Commissioner’s administrative decision to terminate the PTU. The parties have been ordered to provide the Court further briefing regarding whether the Court should again remand the matter for an administrative proceeding with DNR, or retain jurisdiction with the Alaska Superior Court and conduct a de novo proceeding.
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Canada
In Canada, BP operates in five provinces and two territories, exploring for, developing, producing and processing natural gas and heavy crude oil. We also hold an interest in an oil sands joint venture with Husky Energy Inc., we market natural gas and we are the largest marketer of natural gas liquids.
  In 2009, BP conducted a successful 3D seismic programme over the primary area of interest on the exploration licences acquired in 2008 in the Canadian Beaufort Sea. The programme was the most northerly 3D seismic programme ever conducted, with approximately 1,600 square kilometres of 3D data acquired. The project also had the largest array of towed marine streamers deployed in the high Arctic. BP has 2,392,101 acres (968,049 hectares) of significant discovery licences and exploration licences in the Beaufort Sea.
South America
Venezuela
BP has been in Venezuela since 1994 and currently participates in three equity-accounted entities.
  In 2009, production cuts due to OPEC quota restrictions were assigned to the Petromonagas and Petroperija entities. Petromonagas’s OPEC quota restrictions resulted in a complete production shutdown until 12 July 2009. There is uncertainty regarding the duration of the quota restrictions in Petroperija.
Colombia
Our main activity in Colombia is concentrated on operating a producing field complex in the Casanare region. In addition, we operate four principal processing plants and own pipeline interests. BP also holds exploration rights over two blocks off Colombia’s northern coast in the Caribbean Sea.
  During 2009, seismic data processing and interpretation was carried out at the RC4 and RC5 Caribbean offshore blocks (BP 40.6%) in order to determine potential prospects. A decision whether to drill a well is expected to be taken in 2010.
 
  During 2009, the strategy and detailed plan for the termination of the Santiago de las Atalayas field contract by June 2010, and its subsequent operation by Ecopetrol, was designed and implemented.
Argentina, Bolivia and Chile
BP conducts activity in the Southern Cone region of South America (Argentina, Bolivia and Chile) through Pan American Energy (PAE), a joint venture company in which BP holds a 60% interest. As the venture is jointly controlled with Bridas Corporation, it is accounted for using the equity method of accounting. Most of the PAE production comes from the Cerro Dragon field in the provinces of Chubut and Santa Cruz.
  The Cerro Dragon field is now producing at its highest level since the licence was granted in 1958, and further expansion programmes are planned. PAE also has other gas and liquids producing assets in the Argentine provinces of Salta, Neuquen and Tierra del Fuego, and in Bolivia. PAE also has interests in exploration areas, pipelines, and other midstream infrastructure assets, primarily in Argentina.
 
  On 26 November 2008, the Argentine government issued a decree by which a new regime on oil and by-products exports, called Petróleo Plus was put in place. This programme provides fiscal relief in the form of fiscal credit certificates, which can be used to offset export tariffs on oil, LPG and by-products. The goal is to incentivize investment to increase oil production and reserves. As PAE achieved the targets for both reserves replacement and production growth stipulated in the programme, it has obtained and applied fiscal credit certificates since January 2009.
  On 23 January 2009, the president of Bolivia issued a decree nationalizing PAE’s investment in 8,049,660 shares of Chaco. The decree establishes a compensation value per share, which represents a total amount of $233 million (BP share $140 million), subject to eventual adjustments. The partners assert that this is not an adequate compensation for the nationalized shares. PAE will pursue an adequate compensation for the nationalized assets.
 
  On 28 January and 22 May 2009, PAE entered into two agreements with the Neuquen province in Argentina that provide for the extension of concession terms related to the exploration and development of the Aguada Pichana and San Roque blocks and of the Lindero Atravesado block, respectively.
Trinidad & Tobago
BP holds exploration and production licences covering 904,000 acres offshore of the east coast. Facilities include 12 offshore platforms and one onshore processing facility. Production is comprised of oil, gas and NGLs.
  On 27 October 2009, the Savonette offshore field development began production on a normally unmanned installation platform (NUI). Savonette is located in 290 feet (88 metres) of water approximately 50 miles off Trinidad’s south-east coast. Production from the platform is tied in to BP Trinidad and Tobago’s Mahogany B platform and will supply the Trinidad domestic market as well as Atlantic LNG’s liquefaction plant for export as LNG to international markets. The Savonette platform, installed in February 2009, is the fourth in a series of NUIs designed and constructed locally in Trinidad using a standardized ‘clone’ concept. The first three NUIs were Cannonball, Mango and Cashima.
Europe
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. 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 $751 million in 2009, compared with $907 million in 2008 and $804 million in 2007. BP operates one NGL plant in the UK.
          Significant events were:
  On 31 August 2009, the exchange of assets between BP and BG Group was formally completed. The exchange 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 acquired BG’s 24.2% interest in the BP-operated Amethyst field and all its interests in the Easington Catchment Area 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. In return, BG Group acquired 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 retained 18% equity in Erskine).
 
  Drilling performance moved from fourth quartile in 2007 to first quartile in 2008a, and generated additional drilling capital efficiencies in 2009.
 
a Source: BP Drilling and Completions Global Benchmarking.
 


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Rest of Europe
Our activities in the Rest of Europe are in Norway.
  Development expenditure (excluding midstream) in the Rest of Europe was $1,054 million, compared with $695 million in 2008 and $443 million in 2007. Progress continued on the Skarv and Valhall redevelopment projects.
Africa
Angola
BP is present in four major deepwater licences offshore Angola (Blocks 15, 17, 18 and 31) and is operator in Blocks 18 and 31. In addition, BP holds a 13.6% equity share in the first Angolan LNG project. Technical skills developed in similar deepwater basins around the world have been applied extensively in BP’s operations in Angola.
  On 29 December 2008, BP began a comprehensive seismic survey on Block 31 (BP 26.67% and operator) using a wide azimuth towed streamer (WATS) to gain improved imaging quality of sub-salt strata. WATS seismic is an acquisition configuration developed by BP to image areas of complex geology below salt. The WATS survey will significantly improve the imaging and understanding of the fields, and more significantly, the data acquired will also support the definition of hubs which will form part of BP’s development programme. This is the first such survey to be conducted by BP outside the Gulf of Mexico, and is the first WATS survey conducted in Angola.
  In 2009, BP announced its seventeenth through nineteenth discoveries in the ultra deepwater Block 31. On 3 March 2009, BP announced the discovery of the Leda field. Leda was drilled in a water depth of 2,070 metres and reached a total depth of nearly 6 kilometres below sea level. It is located in the central northern portion of Block 31, some 415 kilometres north-west of Luanda. This is the fifth discovery in Block 31 in which the exploration well has been drilled through salt to access the oil-bearing sandstone reservoir beneath. On 27 May 2009, BP announced the Oberon oil discovery. Oberon-1 was drilled in a water depth of 1,624 metres and reached a total depth of 3,622 metres below sea level. On 1 October 2009, BP announced the Tebe oil discovery. The Tebe well was drilled in a water depth of 1,752 metres and a total depth of 3,325 metres below sea level.
Algeria
BP is a partner with Sonatrach and Statoil in the In Salah (BP 33.15%) and In Amenas (BP 45.89%) projects, which supply gas to the domestic and European markets. BP is also in partnership with Sonatrach in the Rhourde El Baguel (REB) oilfield (BP 60%), an enhanced oil recovery project 75 kilometres east of the Hassi Messaoud oilfield. In addition, BP is in partnership with Sonatrach in the Bourarhet Sud block, located to the south-west of In Amenas.
  In 2008, Sonatrach and BP announced a discovery with the Tin Zaouatene-1 (TZN-1) exploration well. BP is currently in the second prospecting period, which runs until September 2010. Seismic operations started in February 2009 and were completed in October 2009. Drilling activities commenced in December 2009.
Libya
In Libya, BP is in partnership with the Libyan Investment Corporation (LIC) to explore the onshore Ghadames and offshore Sirt basins.
  In 2009, BP continued the onshore and offshore seismic operations started in 2008 on the acreage covered under the exploration and production sharing agreement ratified in December 2007 (BP 85%).
 
  In October 2009, BP completed a large offshore 3D survey in the deepwaters of the Libyan Gulf of Sirt. The programme, started in September 2008, was conducted by the seismic vessel Geowave Endeavour (operated by CGGV-Wavefield Inseis), and covered 17,000 square kilometres, 60% of BP’s Sirt exploration acreage.
  BP is also progressing its onshore seismic operations in the deserts of Libya’s Ghadames basin. This is the first full application of a new, cutting-edge seismic technique developed by BP, known as Independent Simultaneous Sweeping (ISS): the technology allows greater acquisition (in excess of 10,000 vibration points per day compared with conventional technology of 1,500 per day) and cost efficiency. Exploration drilling is scheduled to commence during 2010 in both onshore and offshore blocks.
Egypt
BP is the single largest foreign investor in Egypt, with investments close to $15 billion to date. With its partners, BP has produced almost 40% of Egypt’s entire oil production and close to 30% of its gas production. The Gulf of Suez Petroleum Company (GUPCO), BP’s joint venture with the Egyptian General Petroleum Corporation, has been an industry leader in Egypt and the entire region and covers operations in the Gulf of Suez and the Western Desert.
  During the second quarter of 2009, BP was awarded two blocks in the Egyptian Offshore Nile Delta. BP has a 100% working interest and is the operator of Block 2, North Tineh, which is in a deepwater area of the Eastern Nile Delta. BP will also be the operator of Block 3, North Damietta Offshore, which is adjacent to Block 2, with Shell and Petronas as partners with a one-third working interest each. These awards build on the existing portfolio in Egypt, providing an additional platform for growth. BP’s expertise in exploring deepwater, high-pressure and high-temperature deep targets maximizes the chances of unlocking the potential in this area.
 
  During the third quarter of 2009, the Egyptian parliament approved the amendments to two Gulf of Suez (GOS) concessions: South Belayim (BP 100%) and South Ghara (BP 75%). The amendments provide BP with enhanced commercial structure and extend the term of both concessions by 20 years in return for increased investment levels. This marks a significant step in the development of the Southern GOS assets.
Asia
Western Indonesia
BP has a joint interest in Virginia Indonesia Company LLC (VICO), the operator of the Sanga-Sanga PSA (BP 38%) supplying gas to Indonesia’s largest LNG export facility, the Bontang LNG plant in Kalimantan.
  During 2009, VICO successfully completed a joint evaluation of the coalbed methane (CBM) opportunities in the Sanga-Sanga area. In November, VICO signed a PSA with the Government of Indonesia, for the exploration and development of these CBM resources.
  On 1 July 2009, BP divested its entire 46% holding in the Offshore Northwest Java (ONWJ) PSA to Indonesia’s national oil company, Pertamina.
Vietnam
Our upstream business in Vietnam is concentrated on the Block 6.1 offshore gas field. 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.
  BP Block 6.1 Lan Do development project was sanctioned in December 2009, with first gas scheduled in 2012.
 
  BP’s withdrawal from Blocks 5.2 (BP 55.9% and operator) and 5.3 (BP 75% and operator) was completed in December 2009.
China
BP’s upstream asset in the country is the Yacheng offshore gas field (BP 34.3%) in the South China Sea, one of the biggest offshore gas fields in China. Yacheng supplies the Castle Peak Power Company gas for up to 70% of Hong Kong’s gas-fired electricity generation. Additional gas is also sold to the Hainan Holdings Fuel & Chemical Corporation Limited.
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  The Platform A development project approved at the end of 2008 is on track to deliver first gas in 2010.
Azerbaijan
BP is the largest foreign investor in the country. BP operates two PSAs, Azeri-Chirag-Gunashli (ACG) and Shah Deniz, and also holds other exploration leases.
  A comprehensive review of the subsurface gas release that occurred beneath the Central Azeri platform in September 2008, and subsequent remedial works, have resulted in bringing the level of production from the platform to over 220mboe/d from 12 wells. Further minor remedial work is planned during 2010.
 
  On 13 July 2009, BP and the State Oil Company of the Republic of Azerbaijan (SOCAR) signed a memorandum of understanding (MOU) to jointly explore and develop the Shafag and Asiman structures in the Azerbaijan sector of the Caspian Sea. The MOU gives BP the exclusive right to negotiate the PSA. The block covers an area of some 1,100 square kilometres and has never been explored before. It is located in a deepwater section of about 650-800 metres with reservoir depth of about 7,000 metres.
Russia
TNK-BP
TNK-BP, an associate owned by BP (50%) and Alfa Group and Access-Renova (AAR) (50%), is an integrated oil company operating in Russia and the Ukraine. BP’s investment in TNK-BP is reported in the Exploration and Production segment. The TNK-BP group’s major assets are held in OAO TNK-BP Holding. Other assets include the BP-branded retail sites in the Moscow region and interests in OAO Rusia Petroleum and the OAO Slavneft group. The workforce comprises more than 52,000 people.
  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 683 thousand barrels per day. TNK-BP supplies approximately 1,400 branded filling stations in Russia and the Ukraine and has 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 owners, 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 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 officer (CEO), 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 was reclassified from a jointly controlled entity to an associate with effect from 9 January 2009; however, the results of TNK-BP continue to be accounted for under the equity method. On 6 August 2009, TNK-BP announced that William Schrader was appointed chief operating officer. Mr. Schrader took office during the fourth quarter of 2009, replacing Tim Summers. In November, the TNK-BP board of directors unanimously agreed to
    appoint Maxim Barsky, TNK-BP executive vice president for strategy and business development, as the TNK-BP group’s future CEO, effective 1 January 2011. Until that time, Mikhail Fridman has agreed to continue to act as interim CEO, in addition to his role as executive chairman of the board of directors of TNK-BP Limited.
 
  On 16 February 2009, TNK-BP announced that the company had launched commercial production from the Urna and Ust-Tegus fields in the Uvat area of the Tyumen region, Russia. Urna and Ust-Tegus are located in the eastern part of Uvat. TNK-BP completed construction of a 264-kilometre pipeline and a central crude oil gathering facility, which facilitate transportation of oil from the fields westwards to enter the Transneft pipeline system. Investment in field development and construction of the infrastructure is expected to amount to over $1.5 billion.
 
  On 2 June 2009, TNK-BP announced that the company had launched commercial production in the Northern Hub of the Kamennoye field, one month earlier than planned. The Kamennoye field, in the Khanty-Mansiisk region of West Siberia, is one of the largest greenfield projects developed by TNK-BP. Aitor and Poima form the Northern Hub of the producing Kamennoye field. Thirty-five wells were drilled and completed in Aitor and, going forward, the primary focus is on drilling 194 wells in Poima. Infrastructure construction includes upgrading of the gathering and treatment facilities, construction and upgrade of the pipeline and water flood systems as well as the power supply system. This strategy and development plan is aimed at maximizing the use of existing facilities and minimizing the impact on the ecologically sensitive territory. Between 2004 and 2009, investment in the Kamennoye project amounted to over $800 million.
 
  On 29 July 2009, TNK-BP and Weatherford International Ltd (Weatherford) announced that TNK-BP completed the sale of its Oil Field Services (OFS) enterprises to Weatherford pursuant to the sales and purchase agreement signed on 29 May 2009. Via this transaction, Weatherford acquired 10 OFS companies providing drilling, well work-over and cementing services operating in West Siberia, East Siberia and the Volga-Urals region.
 
  In 2007, BP and TNK-BP signed heads of agreement 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 has material interests in Sakhalin through two joint venture companies, Elvary Neftegaz and Vostok Shmidt Neftegaz. BP has a 49% equity interest in each joint venture, and its partner, Rosneft, holds the remaining 51% interest. During the year, both joint ventures, via their Russian affiliates, 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 both licences. In the Elvary Neftegaz licence additional 2D and 3D seismic data was acquired during 2009 in preparation for future drilling commitments.


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Kazakhstan
  On 11 December 2009, BP announced that it has divested its interest in Kazakhstan’s Tengiz oil field and the Caspian Pipeline Consortium (CPC) pipeline, carrying oil between Kazakhstan and Russia, by selling its 46% stake in LukArco to Russia’s Lukoil. Lukoil, which already owns 54% of LukArco, will pay $1.6 billion in cash in three instalments over two years from December 2009.
Middle East and Pakistan
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 14.67% in onshore and offshore concessions respectively.
  In Sharjah, the joint agreement between BP, the Government of Sharjah, Itochu and Tokyo Beki, for the operation and maintenance of LPG facilities and the production and marketing of LPG products, expired on 22 March 2009 after a period of 25 years. BP relinquished its 25% ownership, in accordance with the joint venture agreement, and negotiated terms that retain BP as the operator of the facilities through an operating fee structure.
 
  In Block 61 in Oman, the challenges posed by the world’s largest onshore wide-azimuth 3D seismic survey led the BP Oman team to use a ground-breaking new technique known as distance separated simultaneous sweeping (DS3). BP’s appraisal programme continues to make good progress evaluating the resources in place in the Khazzan/Makarem gas fields. Five appraisal wells have been drilled in 2009. Fracture stimulation and testing of these wells continues. Infrastructure to facilitate long-term wells tests is under construction and expected to be ready for service in the second half of 2010.
 
  On 3 January 2010, we received approval from the Government of Jordan to join the state-owned National Petroleum Company to exploit the onshore Risha concession in the north-east of the country.
 
  With effect from 1 January 2009 BP assumed operatorship of the Mirpurkhas and Khipro onshore blocks in the southern Sindh province of Pakistan.
 
  In the third quarter of 2009, BP won bids for two new exploration blocks, Digri and Sanghar South, in Pakistan. These blocks are adjacent to BP’s Mirpurkhas and Khipro concession areas and add another 5,000 square kilometres to the group’s existing portfolio of 5,300 square kilometres. BP has committed to invest approximately $30 million in these blocks for seismic and wells over the next three years.
Iraq
  In November 2009, BP and China National Petroleum Company (CNPC) entered into a contract with the state-owned Southern Oil Company of Iraq to expand production from the Rumaila oilfield near Basra in southern Iraq. This followed a successful bid for the contract in Baghdad in June 2009. The Rumaila field currently produces approximately one million barrels of oil per day. BP and CNPC plan to invest approximately $15 billion over the next 20 years to enhance the Rumaila production to a plateau rate of 2.85mmb/d, around 3% of global oil production. BP will hold a 38% working interest, CNPC will hold 37% and the remaining 25% will be held by the State Oil Marketing Organisation (SOMO) representing the Iraqi government.
Australasia
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.
  The North Rankin 2 project linking a second platform to the existing North Rankin A platform sanctioned in 2008, is on schedule. On completion, the North Rankin A and North Rankin B platforms will operate as a single integrated facility and recover low pressure gas from the North Rankin and Perseus gas fields.
 
  The joint venture partners (Chevron, ExxonMobil and Shell) approved the Greater Gorgon project on 14 September 2009 with the Australian Government also awarding production licences for the Jansz-Io field (BP 5.375%). The Jansz-Io field will be developed as part of the Greater Gorgon project, which will comprise three LNG trains, each with a capacity of 5 million tonnes per annum (mtpa), on Barrow Island with first gas expected in 2014. As part of this, a unitization and unit operating agreement has been executed with the joint venture partners and sales and purchase agreements for the wellhead sale of raw gas and repurchase of LNG ex-Barrow Island have been executed between BP and Shell.
Midstream activities
Oil and natural gas transportation
The group has direct or indirect interests in certain crude oil and natural gas transportation systems. The following narrative details the significant events that occurred during 2009 by country.
          BP’s onshore US crude oil and product pipelines and related transportation assets are included under Refining and Marketing (see page 32).
Alaska
BP owns a 46.9% interest in the Trans-Alaska Pipeline System (TAPS), with the balance owned by four other companies. BP also owns a 50% interest in a joint venture company called ‘Denali — The Alaska Gas Pipeline’ (Denali). Denali 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 states. When completed, the pipeline is expected to transport approximately 4 billion cubic feet of natural gas per day to market. Following a successful open season, Denali 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. Denali will manage the project, and will own and operate the pipeline when completed. BP may consider other equity partners, including pipeline companies, who can add value to the project and help manage the risks involved.
          Significant events were:
  Work on the strategic reconfiguration project to upgrade and automate four TAPS pump stations continued to progress in 2009. This project involves 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 and a third reconfigured pump station came online in May 2009. Reconfiguration of the remaining pump station in the programme plan will commence in 2010, with installation currently planned for 2012.
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  On 16 April 2009, the US FERC issued an initial ruling on shipper challenges of TAPS interstate tariff rates for the years 2007 and 2008, ordering interim refunds to be paid to shippers based on the January 2009 tariff rate filings. As a result of this order, BP, as a TAPS carrier, paid refunds of $7.3 million to third-party shippers covering the period from 1 January 2007 to 30 June 2009, based on its January 2009 tariff rate filing of $3.45/bbl. Shippers had also filed challenges of the TAPS carriers’ 2009 interstate tariff rates, based on the FERC rulings issued related to 2005 through 2008 tariff rates. On 12 January 2010, an agreement to settle all remaining challenges to TAPS carrier interstate tariff rate filings for the years 2008 and the first half of 2009 was signed by all the TAPS carriers and shippers. Under the terms of the settlement, BP will pay additional refunds to third-party shippers for the period from January 2007 through June 2009 of $0.12/bbl, representing the difference between the $3.45/bbl tariff rate on which the interim refunds for this period were based, and the $3.33/bbl tariff rate in the settlement agreement. The signed settlement agreement has been submitted to the FERC for final regulatory approval. In 2009, interstate transport represented approximately 90% of total TAPS throughput.
North Sea
In the UK sector of the North Sea, BP operates the Forties Pipeline System (FPS) (BP 100%), 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 2009 of 671mb/d. BP also operates and has a 29.5% interest in the Central Area Transmission System (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 addition, BP operates the Dimlington/Easington gas processing terminal (BP 100%) on Humberside and the Sullom Voe oil and gas terminal in Shetland.
Asia
BP, as operator, manages and holds a 30.1% interest in the Baku-Tbilisi-Ceyhan (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. 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. In addition, BP operates the Azerbaijan section of the Western Export Route Pipeline between Azerbaijan and the Black Sea coast of Georgia (as operator of Azerbaijan International Operating Company).
          Significant events were:
  On 23 April 2009, BP completed the sale of its 49.9% interest in Kazakhstan Pipeline Ventures (KPV) to Kazakhstan state oil and gas company KazMunayGas (KMG) for $250 million. KPV holds a 1.75% interest in the Caspian Pipeline Consortium (CPC) that carries crude oil from Kazakhstan’s largest producing oil field, Tengiz, to the Russian port of Novorossiysk on the Black Sea.
 
  On 11 December 2009, BP also divested its interest in the CPC pipeline (held through LukArco) by selling its 46% stake in LukArco to Lukoil.
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 significant events 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 (369 billion cubic feet equivalent regasified), with the Atlantic LNG Train 4 (BP 37.8%) designed to produce 5.2mtpa (294 billion cubic feet per annum) 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 2009 supplied 5.4 million tonnes (279,000mmcf) of LNG.
 
  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 per year of LNG (gross), as well as related gas liquids products. Construction and implementation of the project is proceeding and is expected to start up in 2012.
 
  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 more than 17 million tonnes of LNG in 2009.
 
  Also in Indonesia, the Tangguh project (BP 37.16% and operator) in Papua Barat, Indonesia, started LNG production in June 2009, delivering its first commercial LNG delivery in July. Tangguh is BP’s first operated LNG plant. The first phase of Tangguh comprises two offshore platforms, two pipelines and an LNG plant with two production trains with a total capacity of 7.6mtpa. Tangguh adopted a fully integrated approach to development and its impact on local communities. The Tangguh project has five long-term contracts in place to supply LNG to purchasers in China, South Korea, Mexico and Japan.
 
  In Australia, we are one of seven partners in the North West Shelf (NWS) venture. The joint venture operation covers offshore production platforms, trunklines, onshore gas and LNG processing plants and LNG carriers. BP’s net share of the capacity of NWS LNG Trains 1-5 is 2.7mtpa of LNG.
 
  BP has a 30% equity stake in the 7mtpa capacity Guangdong LNG regasification and pipeline project in south-east China, making it the only foreign partner in China’s LNG import business. The terminal is also supplied under a long-term contract with Australia’s NWS project.
 
  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), the UK (via the Isle of Grain) and Italy (Rovigo), and is supplying Asian customers in Japan, South Korea and Taiwan.


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Gas marketing and trading activities
Gas and power marketing and trading activity is undertaken primarily in the US, Canada and Europe to market both BP production and third-party natural gas, support LNG activities 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 24 to the Financial statements on pages 142-147.
          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 sales and other operating 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 sales and other operating 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. For accounting purposes, spot and term sales are included in sales and other operating revenues, when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes.
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Refining and Marketing
Our Refining and Marketing business is responsible for the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum, petrochemicals products and related services to wholesale and retail customers. BP markets its products in more than 80 countries. We have significant operations 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.
          Our organization is managed through 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 the geographic nature of the markets in which we compete. This provides the opportunity to optimize our activities from crude oil purchases to end-consumer sales through our physical assets (refineries, terminals, pipelines and retail stations). The IBs include the manufacturing, supply and marketing of lubricants, petrochemicals, aviation fuels and liquefied petroleum gas (LPG).
Our market
The 2009 operating environment was again challenging. Global oil demand contracted by approximately 1.3 million barrels per day with demand in the OECD falling for the fourth consecutive year. Crude oil prices more than doubled during the course of the year, from a dated Brent price of $36.55 per barrel on 1 January 2009 to $77.67 per barrel at the end of 2009, contributing to margin volatility.
          Refining margins fell sharply in 2009 as demand for oil products reduced in the wake of the global economic recession and new refining capacity came onstream, mostly in Asia. During 2009, distillate inventories were consistently above the top of the range of the past five years. Gasoline inventories grew steadily and were generally at or slightly above the average level of the past five years. As a result, the BP global indicator refining margin (GIM) averaged $4 per barrel in 2009, down $2.50 per barrel compared with 2008, with the average for the fourth-quarter of 2009 at only $1.49 per barrel, the lowest for almost 15 years. This margin decline had a significant adverse impact on the financial performance of the segment.
          In Europe, where diesel accounts for a large proportion of regional demand, refining margins were hit by reduced demand from commercial transport because of the economic recession. In the US, where refining is more highly upgraded and the transport market is more gasoline oriented, margins deteriorated less. Refining margins in Asia Pacific were the hardest hit due to substantial additions to refining capacity in the region.
          During 2009, upgrading margins were particularly poor due to stronger relative fuel oil prices and narrow light-heavy crude spreads. This adversely impacted our highly upgraded refineries and had an adverse impact on our financial performance in 2009 compared with 2008.
          The end of 2008 and the first quarter of 2009 saw unprecedented levels of market volatility, driven by turmoil in the financial sector and disruptions in the supply chain resulting from the economic downturn. This high level of volatility, combined with our proprietary asset base and trading skills, enabled us to deliver a particularly strong supply and trading result in the first quarter of 2009. Subsequent to the first quarter, volatility returned to more normal levels.
          In our IBs, we saw a decline in demand for lubricants due to the financial crisis. During the year we saw a partial recovery in the demand for our petrochemicals products.
Our strategy
Our purpose is to be the product- and service-led arm of BP, focused on fuels, lubricants, petrochemicals products and related services. We aim to be excellent in the markets we choose to be in – those that allow BP to serve the major energy markets of the world. We are in pursuit of competitive returns and enduring growth, as we serve customers and promote BP and our brands through quality products.
          We believe that key to our continued success in Refining and Marketing is holding a portfolio of quality, integrated, efficient positions and accessing available market growth in emerging markets. We intend to do this through holding positions in advantaged integrated FVCs where we will invest to strengthen our established positions. We also intend to retain and grow our IBs.
          In 2007, we identified that the segment’s financial performance lagged that of our competitors, based on our analysis of our position compared with our supermajor peers, and we launched a programme to restore our financial performance. Our objective was to restore our performance over a period of three to four years by focusing on achieving safe, reliable and compliant operations, restoring missing revenues and delivering sustainable competitive returns and cash flows.
          We believe our overall performance has now returned to being competitive with our supermajor peers, but that there is significant potential for further performance improvements. In the future, we intend to build on this by focusing on further improvements in operations, asset quality and overall efficiency, in order to be a leading player in each of the markets in which we choose to participate.
Our performance
Our 2009 performance has benefited from the fundamental improvements we have been 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 replacement cost profit before interest and tax was $0.7 billion for 2009, compared with $4.2 billion in 2008. The result was heavily impacted by non-operating items, which included a significant level of restructuring charges and a $1.6 billion one-off charge to write off all the segment’s goodwill in the US West Coast FVC relating to our 2000 ARCO acquisition. This resulted from our annual review of goodwill as required under IFRS and reflects the prevailing weak refining environment that, together with a review of future margin expectations in the FVC, has led to a reduction in the expected future cash flows. The decrease in profit was also driven by the very significantly weaker environment, where refining margins fell by almost 40%. This was partly offset by significantly stronger operational performance in the fuels value chains, with 93.6% Solomon refining availability, lower costs and improved performance in the international businesses. Our financial results are discussed in more detail on pages 52-53.
          Safety, both process and personal, remains our top priority. During 2009, we continued the migration to the BP operating management system (OMS) with a continuing focus on process safety. The OMS is described in further detail in Safety (see page 42). At the end of 2009, all our operated refineries and petrochemicals plants were using the OMS. Within our US refineries, we continued to implement the recommendations of the BP US Refineries Independent Safety Review Panel and regulatory bodies (further information can be found in Safety on page 42 and in Legal proceedings on page 95). The focus on operational integrity continues to yield positive results across the segment. Since 2005, when we started identifying incidents by type, we have reduced the overall number of major incidents by 90%. None of the major incidents reported in 2009 was integrity-management related. We have also reduced the number of reported oil spills and the recordable injury frequency in our workforce to the lowest level for 10 years. In 2009, there were no reported workforce fatalities associated with our refining and marketing operations.


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In 2009, despite the impact on our overall results of the weak refining environment, our focus on operations delivered significant performance improvements, both financial and operational. Solomon availability for the year was around five percentage points higher than in 2008. Average throughputs were up by over 130,000b/d compared with 2008, an increase of more than 6%. In addition, 2009 has seen further improvements at our Texas City refinery. Production has ramped up steadily during the year and availability has increased each quarter. During April 2009, the site’s Solomon availability exceeded 90% for the first time in four years.
          Our financial performance also benefited from lower non-feedstock costs. In 2009, our total costs were over 15%a lower than in 2008. In addition we reduced our headcount, excluding retail store staff, by over 2,600 (see Financial statements – Note 39 on page 172).
 
a Based on Refining and Marketing’s share of production and manufacturing expenses plus distribution and administration expenses.
Key statistics
                         
$ million  
 
    2009     2008     2007  
 
Sales and other operating revenuesa
    213,050       320,039       250,221  
Replacement cost profit before interest and taxb
    743       4,176       2,621  
Total assets
    82,224       75,329       95,311  
Capital expenditure and acquisitions
    4,114       6,634       5,495  
 
thousand barrels per day
 
Total refinery throughputs
    2,287       2,155       2,127  
 
thousand tonnes
 
Total chemicals productionc
    12,391       12,518       14,028  
 
$ per barrel
 
Global indicator refining margind
    4.00       6.50       9.94  
 
Refining availabilitye
    93.6%       88.8%       82.9%  
 
 
a Includes sales between businesses.
 
b Includes profit after interest and tax of equity-accounted entities.
 
c A minor amendment has been made to comparative periods.
 
d The global indicator refining margin (GIM) is the average of regional industry indicator margins weighted 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 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.
 
e Refining 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.
Sales and other operating revenues are analysed in more detail below.
                         
$ million  
 
    2009     2008     2007  
 
Sale of crude oil through spot and term contracts
    35,625       54,901       43,004  
Marketing, spot and term sales of refined products
    166,088       248,561       194,979  
Other sales and operating revenues
    11,337       16,577       12,238  
 
 
    213,050       320,039       250,221  
 
Oil sales volumes
                         
thousand barrels per day  
 
Refined products   2009     2008     2007  
 
US
    1,426       1,460       1,533  
Europe
    1,504       1,566       1,633  
Rest of World
    630       685       640  
 
Total marketing salesa
    3,560       3,711       3,806  
Trading/supply salesb
    2,327       1,987       1,818  
 
Total refined product sales
    5,887       5,698       5,624  
 
Crude oil
    1,824       1,689       1,885  
 
Total oil sales
    7,711       7,387       7,509  
 
 
a 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).
 
b 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   2009     2008     2007  
 
Aviation fuel
    495       501       490  
Gasolines
    1,444       1,500       1,572  
Middle distillates
    1,012       1,055       1,119  
Fuel oil
    418       460       429  
Other products
    191       195       196  
 
Total marketing sales
    3,560       3,711       3,806  
 
Marketing volumes were 3,560mb/d, slightly lower than last year, reflecting the impact of slowing global economies on demand for fuel and the volume effects of our business simplification.
Outlook
For 2010, although demand has stabilized, the overall economic environment is expected to continue to be very challenging with continuing pressure on the demand for our products and on margins.
          In response, our priorities in 2010 remain consistent with those in 2009 and we intend to build on the momentum we have established around improving financial performance and operations. We will continue to focus on delivering safe, reliable and compliant operations, improving the performance of our integrated FVCs, in particular in the US, and driving further cost efficiencies across all our businesses. We intend to maintain investment at 2009 levels, focused on key safety and operational integrity priorities, maintaining our quality manufacturing and marketing portfolio, strengthening our US Mid-West FVC business through the Whiting refinery modernization project and continuing to grow our advantaged petrochemicals business in China.
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Fuels value chains
We have six regionally organized integrated FVCs, 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 marketing and sales to our customers. The Texas City refinery is not part of an integrated FVC but is operated as a standalone, predominantly merchant, refining business that also supports our marketing operations on the east and Gulf coasts of the US.
          We also have a number of regionally focused fuels marketing businesses that are not integrated into a refinery, covering the UK, France and Turkey.
          In 2009, the FVCs accounted for roughly three-quarters of the operating capital employeda in Refining and Marketing and generated just under half of the profit, after adjusting for non-operating items and fair value accounting effects. Without these adjustments, the result for the FVCs was a significant loss in 2009, with the most significant factor being the impairment charge to write off all the segment’s goodwill in the West Coast fuels value chain.
          Significant events in the FVCs in 2009 were as follows:
  In February 2009, a new 20,000b/d coker was commissioned at our Castellón refinery in Spain. This was the culmination of a four-year project to convert the Castellón refinery to one capable of upgrading all fuel oil to higher value products. This will allow the refinery to produce about 50% more diesel than it did before, for sale to the local Spanish market and will also improve the ability of the refinery to process higher-margin heavy crude oils.
 
  The Whiting refinery modernization project is more than one year into construction. The engineering design is now almost complete and many of the large foundations are in place. For further details on permit issues relating to our planned upgrades see Environment on page 45.
 
  In July 2009, BP announced that it would not be progressing with the project with Irving Oil to build a refinery at Eider Rock in Saint John, New Brunswick, Canada as a result of global economic and industry conditions.
 
  In December 2009, BP completed the sale of our ground fuels marketing business in Greece, to Hellenic Petroleum for $0.5 billion. The sale included a BP brand licence agreement for at least three years.
 
  In November 2007, BP announced that it would sell all of its company-owned and company-operated convenience sites in the US. The sites will be supplied with BP or ARCO branded fuels under a 20-year contract and will continue to market BP-branded fuels in the eastern US and ARCO-branded fuels in the western US. By the end of 2009, we were no longer operating any of these sites and had completed the sale of all but around 30.
 
  In the fourth quarter of 2009, we announced that we would explore options to divest a number of non-strategic pipelines and terminals in the US Mid-West, Gulf Coast and West Coast during 2010 and 2011.
 
  In February 2010, we announced that we had received an offer from Delek Europe B.V. for the retail fuels and convenience business and selected fuels terminals in France. As a result, BP has agreed a period of exclusivity with Delek Europe B.V. to negotiate the terms for the sale and to allow consultation with the relevant works councils. Any transaction will be subject to regulatory approval. Any transaction is expected to include a BP brand licence agreement.
 
a Operating capital employed is total assets (excluding goodwill) less total liabilities, excluding finance debt and current and deferred taxation.
Refineries
BP’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 synergies with other parts of the group’s business. Our refining focus is to maintain and improve our competitive position through sustainable, safe, reliable, compliant 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.


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The following table summarizes the BP group’s interests in refineries and average daily crude distillation capacities at 31 December 2009. In July 2009, BP disposed of its 17.1% interest in Kenya Petroleum Refineries Ltd to Essar Energy Overseas Ltd.
                                 
            thousand barrels per day  
     
    Crude distillation capacitiesa  
    Group interestb             BP  
    Refinery   Fuels value chain   %     Total     share  
     
Europe
                               
Germany
  Bayernoil   Rhine     22.5%       215       48  
 
  Gelsenkirchenc   Rhine     50.0%       266       133  
 
  Karlsruhe   Rhine     12.0%       323       39  
 
  Lingenc   Rhine     100.0%       93       93  
 
  Schwedt   Rhine     18.8%       226       42  
Netherlands
  Rotterdamc   Rhine     100.0%       386       386  
Spain
  Castellónc   Iberia     100.0%       110       110  
     
Total Europe
                    1,619       851  
     
US
                               
California
  Carsonc   US West Coast     100.0%       265       265  
Washington
  Cherry Pointc   US West Coast     100.0%       234       234  
Indiana
  Whitingc   US Mid-West     100.0%       405       405  
Ohio
  Toledoc   US Mid-West     50.0%       160       80  
Texas
  Texas Cityc       100.0%       475       475  
     
Total US
                    1,539       1,459  
     
Rest of World
                               
Australia
  Bulwerc   ANZ     100.0%       102       102  
 
  Kwinanac   ANZ     100.0%       137       137  
New Zealand
  Whangerei   ANZ     23.7%       112       27  
South Africa
  Durban   Southern Africa     50.0%       180       90  
     
Total Rest of World
                    531       356  
     
Total
                    3,689       2,666  
     
 
aCrude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
 
bBP share of equity, which is not necessarily the same as BP share of processing entitlements.
 
cIndicates refineries operated by BP.
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   2009     2008     2007  
     
US
    1,238       1,121       1,064  
Europe
    755       739       758  
Rest of World
    294       295       305  
     
Total
    2,287       2,155       2,127  
     
Refinery capacity utilization
                       
Crude distillation capacity at 31 Decemberb
    2,666       2,678       2,769  
Refinery utilizationc
    86%       81%       77%  
US
    85%       77%       69%  
Europe
    89%       87%       88%  
Rest of World
    83%       80%       83%  
     
 
aRefinery throughputs reflect crude oil and other feedstock volumes.
 
bCrude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
 
cRefinery utilization is annual throughput divided by crude distillation capacity, expressed as a percentage. The measure has been redefined in 2009 to be more consistent with industry standards. Prior periods have been restated.
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Refining throughputs in 2009 increased by 6% relative to 2008, driven principally by improved operational performance in the US. Higher US throughputs were largely attributable to the recovery at the Texas City refinery, partially offset by the reduced equity interest in the Toledo refinery stemming from the Husky joint venture.
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 the optimization of BP’s FVCs to maintain a single interface with the oil trading markets and to operate with a single set of trading compliance processes, systems and controls. The business is organized along global commodity lines and with trading offices in Europe, the US and Asia, the function is able to maintain a presence in the regionally connected global markets. The supply and trading function has supported the Refining and Marketing segment through a period of higher volatility of crude and oil product prices and increased credit risk following the global financial crisis.
          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.
          Along with 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 24 on pages 142-147.
          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 sales and other operating 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 sales and other operating 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 or 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 sales and other operating revenues, when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes.
Fuels marketing and logistics
Our fuels strategy focuses on optimizing the integrated value of each FVC 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.
          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 transport and industrial sectors.
          Our retail network is largely concentrated in Europe and the US but also has established operations in Australasia, 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   2009     2008     2007  
 
US
    11,500       11,700       12,200  
Europe
    8,600       8,600       8,600  
Rest of World
    2,300       2,300       2,500  
 
Total
    22,400       22,600       23,300  
 
 
a The number of retail sites includes sites not operated by BP but instead operated by dealers, jobbers, franchisees or brand licensees that operate under a BP brand. These may move to or from the BP brand as their fuel supply or brand licence agreements expire and are renegotiated in the normal course of business.
 
b Excludes our interest in equity-accounted entities which are dual-branded.


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At 31 December 2009, BP’s worldwide network consisted of some 22,400 sites 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 2009, we sold over 600 company-owned sites to dealers, jobbers and franchisees who continue to operate these sites under the BP brand. In addition we sold around 1,200 sites in Greece to Hellenic Petroleum, which will continue to be operated under the BP brand through a brand licensing agreement. We also divested around 100 company-owned sites to third parties.
          Our retail convenience operations offer consumers a range of food, drink and other consumables and services on the fuel forecourt in a convenient and innovative manner. The convenience offer includes brands such as ampm, Wild Bean Café and Petit Bistro.
          During 2009, we continued the implementation of our ampm convenience retail franchise model in the US. We expect this model to provide a reliable, long-term sales outlet for transport fuels from our refinery systems, together with reduced costs and lower levels of capital investment. Overall in the US, by the end of 2009 there were 11,500 branded retail sites of which 1,200 were branded ampm, compared with 11,700 and 1,100 respectively at the beginning of 2009.
          In Europe, we are one of the largest forecourt convenience retailers, with about 2,500 convenience retail sites 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 addition, at the end of 2009, we had approximately 500 sites outside Europe and the US in countries such as Australia, New Zealand and South Africa.
International businesses
Our IBs provide quality products and offers to customers in more than 80 countries worldwide with a significant focus on Europe, North America and Asia. Our products include aviation 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. 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.
          In 2009, the IBs accounted for just under a quarter of the segment’s operating capital employeda and just over half the profit, after adjusting for non-operating items and fair value accounting effects. Without these adjustments, the profit for the IBs more than offset the loss for the FVCs.
          Significant events in the international businesses in 2009 were:
  Our expanded purified terephthalic acid (PTA) facility in Geel, Belgium was successfully commissioned in the first quarter of 2009. The expansion, which has a design capacity of 350 thousand tonnes per annum (ktepa), has improved operating costs and by the end of 2009 had already increased the site’s PTA capacity by 255ktepa.
 
  SECCO completed its first major turnaround in the third quarter of 2009 and at the same time expanded production capacity, creating China’s largest ethylene cracker capable of producing 1.3mtpa of ethylene per year, an increase of 25%.
 
a Operating capital employed is total assets (excluding goodwill) less total liabilities, excluding finance debt and current and deferred taxation.
  Construction of the new 500ktepa acetic acid plant in Jiangsu province, China by BP YPC Acetyls Company (Nanjing) Limited (BYACO) was completed. This is a BP joint venture with Yangzi Petrochemical Co. Ltd (a subsidiary of Sinopec). Commercial production is expected to begin in the second quarter of 2010.
 
  BP and Sinopec continued to progress the project 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 is under review due to current market conditions. When complete, total production at the YARACO site is expected to be in excess of one million tonnes per annum, making this one of the largest acetic acid production locations in the world.
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 46 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, and also 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. In 2009, more than 30% of pre-tax operating income was generated from emerging markets.
          BP marine lubricants is one of the largest global suppliers of lubricants to the marine industry. We supply many types of vessels from bulkers to container ships to dredgers and cruise ships, with global presence in over 850 ports. 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.
Petrochemicals
Our petrochemicals operations comprise 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 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 polyethylene terephthalate (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 acid markets with a major manufacturing presence in Asia, particularly China. PX is a feedstock for PTA production. In addition to these three main products, we produce a number of other speciality petrochemicals products. We have a total of 14 manufacturing sites operating in the UK, the US, Belgium, China, Indonesia, Korea, Malaysia and Taiwan, including our joint ventures.
          In O&D, we crack naptha and ethane as feedstocks to produce ethylene and other products and derivatives, within equity-accounted entities.
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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 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, butadiene 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. BP also owns one other naphtha cracker site outside of Asia, which is integrated with our Gelsenkirchen refinery in Germany.
          The following table shows BP’s petrochemicals production capacity at 31 December 2009. This production capacity is based on the original design capacity of the plants plus expansions.
BP share of petrochemicals production capacitya b
                                                 
thousand tonnes per year  
                    Acetic                    
Geographic area   PTA     PX     acid     Other     O&D     Total  
 
US
    2,385       2,373       583       151             5,492  
Europe
    1,330       624       532       158       1,629       4,273  
Rest of World
    3,704             1,035       108       3,217       8,064  
 
 
    7,419       2,997       2,150       417       4,846       17,829  
 
 
a Petrochemicals capacity is the maximum proven sustainable daily rate (msdr) multiplied by the number of days in the respective period, where msdr is the highest average daily rate ever achieved over a sustained period.
 
b Includes BP share of equity-accounted entities.
Global fuels
The supply of aviation fuels and LPG is run globally in the global fuels SPU.
          Air BP is one of the world’s largest and best known aviation fuels suppliers, serving many of the major commercial airlines as well as the general aviation and military sectors. During 2009, which was another tough year for the aviation industry, we continued to simplify our geographical footprint by exiting non-core countries and we now supply customers in 64 countries. This has allowed us to reduce working capital and improve returns on operating capital employed.
          We have annual marketing sales in excess of 25 billion litres. 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.
          The LPG business sells bulk, bottled, automotive and wholesale LPG products to a wide range of customers in 12 countries. During the past few years, our LPG business has consolidated its position and introduced new consumer offers in established markets, developed opportunities in growth markets and pursued new demand such as the German Autogas market. In 2009, we have divested non-core operations and focused our asset base around sustainable marketing operations. Annual sales are in excess of 2 million tonnes per annum.
Other businesses and corporate
Other businesses and corporate comprises the Alternative Energy business, Shipping, the group’s aluminium asset, Treasury (which includes interest income on the group’s cash and cash equivalents), and corporate activities worldwide.
          The financial results of Other businesses and corporate are discussed on page 53.
Key statistics
                         
$ million  
 
    2009     2008     2007  
 
Sales and other operating revenuesa
    2,843       4,634       3,698  
Replacement cost profit (loss) before interest and taxb
    (2,322 )     (1,223 )     (1,209 )
Total assets
    17,954       19,079       20,595  
Capital expenditure and acquisitions
    1,299       1,839       939  
 
 
a Includes sales between businesses.
 
b Includes profit after interest and tax of equity-accounted entities.
Alternative Energy
Alternative Energy comprises BP’s low-carbon businesses and future growth options outside oil and gas. Alternative Energy is focused on four key businesses, which we believe have the potential to be a material source of low-carbon energy and are aligned with BP’s core capabilities. These are biofuels, wind, solar, and hydrogen power and carbon capture and storage (CCS).
Our market
It is now well accepted that a more diverse mix of energy will be required to meet future demand. The International Energy Association (IEA)a estimates that world energy demand could be 40% higher than at present by 2030, driven largely by China and India. The IEA also projects that higher fossil-fuel prices, as well as increasing concerns over energy security and climate change, could boost the share of wind and solar electricity generation from 1% in 2007 to 6% in 2030, and the biofuels share of transport fuels from 1% in 2007 to 4% in 2030b.
Our performance
Alternative Energy made good progress in 2009. Our wind business has added 279MW of capacity including the construction of two wind farms in the US — Fowler Ridge II in Indiana and Titan I in South Dakota — taking the total capacity in commercial operation to 711MW (1,237MW gross) at the end of 2009. In our solar business, we completed the restructuring of our manufacturing facilities and increased unit sales 25% over 2008. Our biofuels business is investing in advanced technologies. We have our first joint-venture ethanol refinery in Brazil and another joint-venture facility is under construction in the UK.
          Since 2005, we have invested more than $4 billionc in Alternative Energy, in line with our commitment to invest $8 billion by 2015.
 
a Adapted from World Energy Outlook 2009. ©OECD/IEA 2009, page 73.
 
b World Energy Outlook 2009. ©OECD/IEA 2009, pages 622-623: ‘Reference Scenario, World’.
 
c The majority of costs have been capitalized, some were expensed under IFRS.
                         
    2009     2008     2007  
 
Wind – net rated capacity at year-end (megawatts)a
    711       432       172  
Solar – module sales (megawatts)b
    203       162       115  
 
 
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 1,237MW in 2009, 785MW in 2008 and 373MW in 2007. This includes 32MW of capacity in the Netherlands that is managed by our Refining and Marketing segment.
 
b Solar sales are the total sales of solar modules to third-party customers, expressed in MW. Previously we reported the theoretical cell production capacity of our in-house solar manufacturing facilities. Reporting sales volumes operating data brings us into line with the broader solar industry.


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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. 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. BP continues to invest throughout the entire biofuels value chain from sustainable feedstocks that minimize pressure on food supplies through to the development of the advantaged fuel molecule biobutanol. BP has production facilities operating, or in the planning and construction phases, in the US, Brazil and the UK.
          In 2009, we announced a $45-million investment in a joint venture with Verenium which plans to construct a facility to produce lignocellulosic bioethanol in Florida, US. This investment builds on the $90-million investment made by BP in 2008 to further develop existing Verenium technical work and develop a demonstration plant at commercial scale. In August, BP also announced a $10-million multi-year agreement with Martek Biosciences Corporation to establish proof of concept for large-scale microbial biodiesel production through the fermentation of sugars.
          The blending and distribution of biofuels continues to be carried out by our Refining and Marketing segment, in line with regulation. BP is one of the largest blenders and marketers of biofuels in the world.
Wind
In wind power, BP has focused its portfolio in the US, where we believe the most attractive opportunities exist and where we have developed one of the leading wind portfolios.
          During 2009, we announced the completion of phase I of the 100MW Flat Ridge Wind Farm in Barber County, Kansas. BP and Westar Energy, Inc. each own 50% of phase 1 of the wind farm. BP sells its share of the output to Westar. In addition, commercial operations commenced at the Fowler Ridge Wind Farm in Benton County, Indiana, the largest wind farm in the US Midwest at 600MW, where BP and Dominion are equal partners in 300MW. BP and Sempra Generation are equal partners in 200MW, and 100MW is wholly-owned by BP. Full commercial operation also began at our wholly-owned 25MW Titan I Wind Farm in South Dakota.
          As a result, BP has increased its net wind generation capacity to 711MW during 2009, an increase of 65% over the prior year. This net increase in capacity includes the disposal of 78MW of our wind interests in India as part of our focus on US wind.
Solar
2009 was quite challenging in the solar market due to weak demand in the first half year and a significant decrease in module sales prices of about 40%. However, BP Solar was successful in increasing unit sales by 41MW to 203MW, an increase of 25% over 2008.
          BP Solar’s organization, with over 1,700 employees worldwide, is headquartered in San Francisco, California, in the US. BP Solar is structured to serve the residential, commercial, and utility markets with sales and marketing offices in major markets around the world. Our manufacturing facilities are located in Frederick, Maryland, US; and joint venture manufacturing is located in Xi’an, China and Bangalore, Indiaa.
          During 2009, BP Solar continued to restructure manufacturing to reduce costs and, as part of this programme, module assembly was phased out in Maryland and our cell manufacture and module assembly facilities in Madrid, Spain, were closed. Wafer and cell manufacturing facilities in Maryland and joint venture manufacturing sites in China and India continue to supply BP Solar.
 
  aOur Indian manufacturing operations are accounted for as a consolidated subsidiary.
Hydrogen power and CCS
BP has played a leading role in the CCS industry for more than 10 years, and today focuses on both full-scale projects and a continuing programme of research and technology development. The Hydrogen Energy International Limited joint venture, which was formed to develop hydrogen power projects in 2007, is now wholly owned by BP following an agreement with Rio Tinto to sell its 50% share.
          The two companies are continuing to develop the Hydrogen Energy California 250MW power project with CCS through the Hydrogen Energy International LLC joint venture, which secured $308 million of Department of Energy (DoE) funding during 2009. The funding award was made to California as part of the American Recovery Reinvestment Act of 2009 and is part of the third round of the DoE’s Clean Coal Power Initiative.
          Separately, the 400MW Hydrogen Power Abu Dhabi project with CCS reached an important milestone, with the Abu Dhabi environmental regulator’s approval of the environment and social impact assessment. The project is a joint venture between BP (40%) and Masdar (60%).
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. The primary purpose of our shipping and chartering activities is the transportation of our hydrocarbon products. In addition, we may use surplus capacity to transport third-party products.
International fleet
The size of our managed international fleet has not changed since 2008. At the end of 2009, we had 54 international 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, we retain a fleet of four double-hulled vessels. Outside the US, we had 14 specialist vessels (two double-hulled lubricants oil barges and 12 offshore support vessels).
Time-charter vessels
BP has 104 hydrocarbon-carrying vessels above 600 deadweight tonnes on time-charter, of which 102 are double-hulled. 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.
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Maritime security issues
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 these areas, subject to the adoption of heightened security measures.
          2009 has seen continuing pirate activity in the Gulf of Aden, extending into the Indian Ocean (from the east coast of Somalia to beyond the Seychelles) and a significant increase in the number of international shipping incidents. The number of vessels actually hijacked has remained roughly the same as 2008, as a result of heightened awareness to the threat, and protective measures adopted by transiting ships.
          At present, we follow available military and government agency advice and are participating in protective group transits through the Gulf of Aden Maritime Security Patrol Area transit corridor. BP supports the protective measures recommended in the international shipping industry guide Best Management Practices to Deter Piracy in the Gulf of Adena.
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.
Treasury
Treasury manages the financing of the group centrally, ensuring liquidity sufficient to meet group requirements and manages key financial risks including interest rate, foreign exchange, pension and financial institution credit risk. From locations in the UK, the US and the Asia Pacific region, Treasury provides the interface between BP and the international financial markets and supports the financing of BP’s projects around the world. Treasury trades foreign exchange and interest rate products in the financial markets, hedging group exposures and generating incremental value through optimizing and managing flows. Trading activities are underpinned by the compliance, control, and risk management infrastructure common to all BP trading activities.
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.
 
  aJointly published and supported by Industry bodies, including OCIMF.
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. BP’s model is one of selective technology leadership, where we have chosen 20 major technology programmes – 10 in Exploration and Production, seven in Refining and Marketing and three focused on lower-carbon value chains.
          Inside the business segments, the full breadth of these activities is carried out in service of competitive business performance and new business development, through research and development (R&D) or acquisition of new technologies. The central R&T group provides leadership and assurance for scientific and technological activities across BP with a focus on having the right capability in critical areas, overseeing the quality of BP’s major technology programmes, and illuminating the potential of emerging science. External assurance is achieved through the Technology Advisory Council, which advises the board and executive management on the state of research and technology within BP. The Council comprises typically eight to 10 world-leading and eminent industrialists and academics.
          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 and the leverage of our spend.
          Across the group, expenditure on R&D for 2009 was $587 million, compared with $595 million in 2008 and $566 million in 2007. See Financial statements – Note 11 on page 132. Despite the economic downturn of 2009, R&D spending remained roughly flat. In addition we increased our focus on value realization from the application of technology (including field trials), and capability development, which are not included in the headline R&D expenditure.
          In our Exploration and Production segment, we selectively focus on 10 ‘flagship’ technology programmes which have the greatest business impact. We consider that each has the potential to add more than one billion boe to reserves through their development and deployment in our assets worldwide. These technologies continue to contribute to exploration and production success in Alaska, Angola, Azerbaijan, Egypt, North Africa, the North Sea, Trinidad and the deepwater Gulf of Mexico. 2009 highlights from four of these flagships include:
  Advanced seismic imaging – BP’s expertise leads the industry, with cutting-edge ‘simultaneous sweeping’ techniques being successfully applied in onshore seismic surveys in Libya and Oman. Offshore, BP completed its largest ever 3D surveys in Libya’s deepwater, carried out the most northerly 3D seismic programme ever conducted (in the Canadian Beaufort Sea), and deployed a wide azimuth towed streamer in Angola – an acquisition configuration developed by BP to image areas of complex geology below salt. These imaging techniques significantly reduce time and costs needed to acquire seismic data over vast areas.
 
  Enhanced oil recovery (EOR) technologies are pushing recovery factors to new limits. By increasing the overall recovery factor from our fields by 1%, we believe we can add 2 billion boe to our reserves. At the Endicott field in Alaska, BP completed a field trial of its LoSalTM EOR technology, which uses injection water with a much lower than usual salt content to flush out or displace extra oil from the reservoir. Following the success of this trial, the technology is now being actively considered for application in several new projects. BP has now performed 38 Bright Water™ treatments in Alaska, Argentina and Pakistan, which have delivered an increase of more than 9 million barrels to our recoverable volumes at a development cost of less than $6 per barrel.


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  Field-of-the-FutureTM (FotF) exploits digital technologies to improve performance and optimize production. For example, ISIS, a proprietary system designed by BP engineers, gathers subsurface information from wells in real time using field sensors that measure parameters such as pressures and temperatures. ISIS has now been deployed as a virtual flow meter and has improved production rates at Thunder Horse and other fields. BP has deployed FotF to 35 operations using a common platform, leading the industry in this area.
 
  Inherently reliable facilities – BP conducted a high reliability chemical injection skid field trial at Wytch Farm in the UK, as part of this flagship’s objectives of improving corrosion inhibition, extending the life of BP’s assets and ensuring safe, reliable and efficient operations.
In our Refining and Marketing segment, technology is delivering performance improvements across all businesses. For example:
  Refining technology advances are enabling better understanding and processing of feedstocks of varying quality and optimization of our assets in real time, enhancing the flexibility and reliability of our refineries and improving margins. The reconfiguration at Whiting refinery to process heavier crudes is on track, incorporating technologically advanced coking operations. BP’s Refinery-of-the-Future programme develops and deploys state-of-the-art measurement, monitoring and predictive technologies to improve refinery safety, integrity, availability and utilization, and to optimize feedstock selection and blending. For example, BP has completed large-scale field trials of wireless, online, sensors for remote corrosion monitoring, and deployment across our refineries is now under way.
 
  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. In 2009, BP completed the launch of Castrol EDGE Sport, a range of highly advanced synthetic engine oils that outperform conventional, high mileage, part synthetic and benchmark synthetic motor oils. BP’s strong relationship with Ford has contributed to important technological advances in fuel and lubricants products, including a joint UK Government-backed project to improve fuel efficiency, which has achieved reductions in friction and a significant overall reduction in fuel usage for next generation engines.
 
  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 in purified terephthalic acid (PTA) and acetic acid. Learning from successful project implementations in Asia, continuous improvement of our CATIVA® technology for manufacture of acetic acid maintains BP’s world-class capital and conversion cost position.
 
  In the field of conversion technology, our Fischer-Tropsch demonstration plant programme in Nikiski, Alaska, has been completed, proving the performance of BP’s fixed-bed process. This technology is now ready for commercial deployment and available for third-party licensing. The process is particularly well suited for the chemical conversion of biomass-derived feedstocks to liquids.
BP’s Alternative Energy portfolio covers a wide range of renewable and low-carbon energy technologies.
  In 2009, our biofuels business extended its reach and capability through joint ventures with Dupont (to develop, produce and market next-generation biofuels from biobutanol), Verenium (two 50:50 JVs accelerating the development and commercialization of biofuels from lignocellulosic feedstocks), and Martek Biosciences (developing technology to convert sugars into diesel).
  In our solar business, BP has joined forces with Interuniversity Microelectronics Centre (IMEC) and other partners to demonstrate high-efficiency, low-cost silicon Mono2TM solar cells. This new technology is producing cells ranging up to 18% efficiency, compared with multicrystalline cells that are typically around 15%-15.8% efficiency. Mono2 cells are fabricated using BP Solar’s proprietary casting technique to produce monocrystalline wafers. BP Solar has also developed and is in the process of commercializing a full portfolio of module technology. This uses advanced heat management and internal microcircuits to optimize energy production, safety, and ease of operation and maintenance.
  Our carbon capture and storage projects in Abu Dhabi and California are making progress, with environmental regulator approval for the former and Department of Energy funding for the latter.
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 2009, we established an EOR exploratory research programme with three European universities to improve our understanding, foster innovation and provide a ‘springboard’ for new technologies.
 
  At our Energy Biosciences Institute at Berkeley, we have located BP researchers at the institute to collaborate with the academic researchers. Several foundational research platforms have been established (including second-generation biofuel technologies and microbially-enhanced oil and gas recovery) and the first patents and inventions have started to emerge.
 
  BP is an industry member of the UK’s EnergyTechnologies Institute (ETI) – a public/private partnership to accelerate low-carbon technology development. In 2009, the ETI commissioned over £50 million ($80 million) of work covering 10 projects across a wide range of technologies. The ETI has also developed a model of the UK energy system which projects out to 2050.
 
  In 2009, BP launched the Energy Sustainability Challenge, a three-year study into how changes in availability of and demand for natural resources and ecosystem services will affect future energy supply and demand, the technologies that could enable more efficient use of natural resources, and the policies that will be necessary to bring these into effect.
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Corporate responsibility
Safety
Safety, people and performance are BP’s top priorities. We constantly seek to improve our safety performance through the procedures, processes and training programmes that we implement in pursuit of our goal of ‘no accidents, no harm to people and no damage to the environment’.
          In 2009, a third-party-operated helicopter carrying contractors from BP’s Miller platform crashed in the North Sea resulting in the tragic loss of 16 lives. In addition, BP sustained two fatalities within our own operations, one, when a rig worker was lost overboard during drilling operations in Azerbaijan and a second, in a crush injury on a well pad in Alaska.
          We deeply regret the loss of these lives.
Safety and operational performance
In 2009, BP’s safety record continued to improve, as indicated by measures of personal safety including reported recordable injury frequency (RIF) and days away from work case frequency (DAFWC).
          Our overall RIF of 0.34 was significantly lower than the rate of 0.43 in 2008 and 0.48 in 2007. Our DAFWCF was 0.069, an improvement on the level of 0.080 in 2008.
          In 2009, eight work-related major incidents were reported, compared with 21 in 2008. Major incidents include incidents resulting in fatalities, significant property damage or significant environmental impacts. All fatalities and other major incidents and many that have the potential to become major incidents, are discussed by the group operations risk committee (GORC), chaired by the group chief executive. Our mandatory internal requirement to undertake incident investigations seeks to ensure that we learn as much as possible from each incident and take action to prevent re-occurrence.
          There were 234 oil spills of one barrel or more reported in 2009, a significant reduction on the 335 spills that occurred in 2008. The reported volume of oil spilled in 2009 was approximately 1,191 million litres, a reduction of 65% compared with 2008.
          This performance follows several years of intense focus on training and procedures across BP. BP’s operating management system (OMS), which provides a single operating framework for all BP operations, is a key part of continuing to drive a rigorous approach to safe operations. 2009 marked an important year in the continuing implementation of OMS.
Safe, reliable and responsible operations
Having been introduced at eight operating sites in 2008, implementation of the OMS gathered pace in 2009. The system was up and running at 70 operations across the business by the end of the year, including all our operated refineries and petrochemicals plants. This represents around 80% of the operations for which OMS implementation is planned, with the remainder scheduled to be live by the end of 2010.
          Taking a systematic approach is integral to improving safety and operating performance in every BP site. Our OMS covers all areas from process safety, to personal health, to environmental performance. By applying consistent principles and processes across the BP group’s operations, the system provides for an integrated and consistent way of working. These principles and processes are designed to simplify the organization, improve productivity, enable consistent execution and focus BP on performance.
Capability development
Having built a safety and operations learning framework to enhance the capability of our staff to deliver safe, reliable, responsible and efficient operations, we defined target populations for these programmes more accurately in 2009.
          More than 2,700 front-line operational leaders across our global operations have started one or more of the modules within the Operating Essentials programme which seeks to embed the BP way of operating as defined by OMS. Our Operations Academy (OA), a partnership with the Massachusetts Institute of Technology (MIT), is also now well established. Seven cadres of senior operations staff have already attended this academy and three of these have graduated: all are applying their learning and having a deep influence in the operations community. We also have an Executive Operations Programme which has continued to support the executive team and senior business leaders in the development of their unique operations capability requirements.
Process safety management
We continued to implement the 2007 recommendations made by the BP US Refineries Independent Safety Review Panel (Panel), which following the incident at Texas City in 2005, reviewed process safety management at our US refineries and our safety management culture.
          In accordance with those recommendations, we appointed an Independent Expert for a five-year term to monitor their implementation. We again co-operated closely with the Independent Expert in 2009, providing him access to our sites, personnel and documentation and routinely supplying him with progress reports. In the Independent Expert’s second annual report, published in 2009, he acknowledged BP’s sustained focus on its safety and operations agenda and the priority given by executive management and the board to safe, reliable and responsible operations. The report identified areas for continued focus and highlighted the progress made in several areas, including the development of capability programmes, OMS implementation, safety and operations auditing, and the improvement of metrics to monitor process safety performance. During the course of 2009, we also provided regular progress updates to the Safety, Ethics and Environment Assurance Committee of the board.
          See Legal proceedings on pages 95-96 in respect of ongoing Texas City refinery matters.
          By the end of 2009 our safety and operations audit team had audited a total of 94 BP businesses, including all major operating sites, within a three-year period. The audits, which in 2009 included pilot audits for analysis against the requirements of the OMS, have provided a rigorous process for assessing our businesses against BP’s relevant standards and requirements.
          We also participated in industry-wide forums on process safety. We chaired the API/ANSI multi-stakeholder group developing a standard for public reporting of leading and lagging process safety indicators. Through this and other bodies, we shared our learning with other organizations within and outside the oil and gas industry.
‘Six-point plan’
Our efforts on process safety included taking action to close out our six-point plan for process safety, which was launched in 2006 to address immediate priorities for improving process safety and minimizing risk at our operations worldwide. We have either completed the required actions or integrated the few continuing requirements within the OMS, for tracking to completion. We established a clear approach for future monitoring of these within the internal HSE & Operations Integrity Report. This report, which is the key source of management information relating to safety and operations in BP, is prepared quarterly for the GORC.


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Environment
Climate change
BP recognizes that climate change is a global concern representing a significant challenge for society, the energy industry, and BP.
          We monitor and report on greenhouse gas (GHG) emissionsa, and we manage our GHG emissions through a focus on operational energy efficiency. Each year since 2002, we have estimated the reduction in our reported annual emissions due to efficiency projects and the running total of these estimated reductions is now 7.9 million tonnes (Mte), including 0.3Mte estimated for the last year.
          However, last year’s sustainable reductions have been more than offset by additional emissions from increased operational activity. As such, we are reporting 65.0Mte of GHG emissions for the year 2009, 3.6Mte higher than the 61.4Mte reported for 2008. Increased throughput from US refineries, the start-up of our Tangguh LNG project in Indonesia and deepwater production platforms in the Gulf of Mexico account for much of this increase.
          We expect that additional regulation of GHG emissions in the future and international accords aimed at addressing climate change will have an increasing impact on our businesses, operating costs and strategic planning, but may also offer opportunities in the development of low-carbon technologies and businesses. See Regulation – Greenhouse gas regulation on page 44.
          To address this expectation, we factor a carbon cost into our investment appraisals and the engineering design of new projects. We do this by requiring projects to make realistic assumptions about the likely carbon price during the lifetime of the project. This is used as a basis for assessing the economic value of the investment, and for assessing options to optimize the way the project is engineered. This is our way of evaluating investments to ensure they are competitive not only in today’s world but in a future where carbon has a more robust price.
Environmental management
During 2009, we began integrating our environmental management systems into our operating management system (OMS) and piloted an integrated approach to identify potential environmental and social impacts in new projects. These are intended to improve our consistency and effectiveness in identifying and mitigating the environmental and social impacts of our operations. Our major operating sites are all certified under the international environmental management system standard ISO 14001, with the exception of the Texas City petrochemicals plant which is seeking certification in 2010.
          None of our new projects entered a protected area in 2009. Our protected areas classification includes the International Union for the Conservation of Nature (IUCN) I-IV, Ramsar and World Heritage designations.
          We continue to strengthen our processes for managing compliance with environmental regulations in each of the countries in which we operate. In addition, each employee is required to comply with the health, safety and environmental requirements of the BP code of conduct. We expect our partners, suppliers and contractors to comply with legal requirements and operate consistently with the principles of our code of conduct.
          Information on the environmental impact of our operations and our efforts to manage resources responsibly are discussed in our annual BP Sustainability Report which is available on our website at www.bp.com/sustainability.
 
a We report greenhouse gas (GHG) emissions, and emission reductions, on a CO2-equivalent basis including CO2 and methane. This represents all consolidated entities and BP’s share of equity-accounted entities except TNK-BP.
Technology development
BP invests in, or jointly funds, research and development seeking opportunities to reduce our potential environmental impacts, for example, sound and marine life research, a range of water management projects and advanced drill cuttings treatment. BP also participates in public and private partnerships to develop new technologies. These include:
  the Energy Biosciences Institute (EBI) in the US, which conducts research into biofuel technologies, improved oil and gas recovery and carbon sequestration;
 
  the Energy Technologies Institute (ETI) in the UK, which seeks to accelerate the development of energy technologies to reduce GHG emissions including offshore wind and for marine, tidal and wave energy; and
 
  the Carbon Mitigation Initiative at Princeton University, to research the fundamental environmental, and technological issues in carbon management.
Regulation
BP operates in more than 80 countries and is subject to a wide variety of 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 may have a significant effect on the production, sale and profitability of many of our products.
          There also are environmental laws that require us to remediate and restore areas damaged by the accidental or unauthorized release of hazardous materials or petroleum associated with our operations. These laws may apply to sites that BP currently owns or operates, sites that it previously owned or operated, or sites used for the disposal of its and other parties’ waste. Provisions for environmental restoration and remediation are made when a clean-up is probable and the amount of BP’s legal obligation can be reliably estimated. The cost of future environmental remediation obligations is often inherently difficult to estimate. Uncertainties can include the extent of contamination, the appropriate corrective actions, technological feasibility and BP’s share of liability. See Financial statements – Note 34 on page 158 for the amounts provided in respect of environmental remediation and decommissioning.
          A number of pending or anticipated governmental proceedings against BP and certain subsidiaries under environmental laws could result in monetary sanctions of $100,000 or more. We are also subject to environmental claims for personal injury and property damage alleging the release or exposure to hazardous substances. The costs associated with such future environmental remediation obligations, governmental proceedings and claims could be significant and may be material to the results of operations in the period in which they are recognized, but it is not expected that such costs will be material to the group’s overall results of operations, our financial position or liquidity. However, we cannot accurately predict the effects of future developments on the group, such as stricter environmental laws or enforcement policies or future events at our facilities, and there can be no assurance that material liabilities and costs will not be incurred in the future. For a discussion of the group’s environmental expenditure see page 56.
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Greenhouse gas regulation
Increasing concerns about climate change have led to a number of international, national and regional measures to limit greenhouse gas emissions; additional stricter measures can be expected in the future. Current measures and developments affecting our businesses include the following:
  The Kyoto Protocol currently commits 38 ratified parties to meet emissions targets in the commitment period 2008 to 2012.
 
  The UN summit in Copenhagen in December 2009 where Parties to the UN Framework Convention on Climate Change (UNFCCC) took note of the Copenhagen Accord. The Accord recognizes the scientific view that the increase in global temperature should be below 2°C. Signatories to the Accord are to append to it their emissions targets for 2020 or their proposed GHG mitigation measures. By the end of January 2010 the UNFCCC had received submissions of national pledges to cut and limit greenhouse gases by 2020 from 55 countries. According to the UNFCCC, these countries together account for 78% of global emissions from energy use.
 
  The European Union (EU) Climate Action and Renewable Energy Package which requires increased greenhouse gas reductions, improvements in energy efficiency and increased renewable energy use by 2020 as well as including the Revision of the EU Emissions Trading Scheme (EU ETS) directive. This regulates approximately one-fifth of our reported 2009 global CO2 emissions and can be expected to require additional expenditure from 2013 when the revision of the scheme (EU ETS Phase 3) comes into effect.
 
  Australia has committed to reduce its GHG emissions by between
5-25% below 2000 levels by 2020, depending on the extent of international action. Australia has also developed an emissions trading scheme. If passed in law, it will cover around 70% of the nation’s GHG emissions including stationary energy and transport emissions.
 
  New Zealand has agreed to cut GHG emissions by 10-20% from 1990 levels by 2020, subject to certain conditions. New Zealand is extending the scope of its Emission Trading Scheme in July 2010.
 
  In the US, recent national legislation has imposed stricter automobile fuel emissions standards and biofuel mandates and legislative proposals would impose GHG emission limits through cap-and-trade programmes as well as mandates for alternative energy and increases in energy efficiency.
    The US Environmental Protection Agency (EPA) released a GHG endangerment finding in late 2009 giving it authority to regulate GHG emissions under the Clean Air Act; it has also issued a GHG reporting rule covering major stationary emission sources and upstream fuel suppliers.
 
    A number of additional state and regional initiatives in the US will affect our operations including regulation in California seeking to reduce GHG emissions to 1990 levels by 2020, including reductions in the carbon intensity of transport fuel sold in the state.
 
    Canada has adopted an action plan to reduce emissions to 20% below 2006 levels by 2020 and the national government seeks a coordinated approach with the US on environmental and energy objectives, such as a North America-wide cap-and-trade system.
Each of these measures can increase our production costs for certain products, increase demand for competing energy alternatives or products with lower-carbon intensity and affect the sales of many of our products.
US and EU regulations
Approximately 60% of our fixed assets are located in the US and the EU. US and EU environment and health and safety regulations significantly affect BP’s exploration and production, refining, marketing, transportation and shipping operations. Significant legislation in the US and the EU affecting our businesses and profitability includes the following:
United States
  The Clean Air Act (CAA) regulates air emissions, permitting, fuel specifications and other aspects of our production, distribution and marketing activities. Stricter limits on sulphur and benzene in fuels will affect us going forward. Additionally, many states have separate laws similar to the CAA.
 
  The Energy Policy Act of 2005 and The Energy Independence and Security Act of 2007 affect our US fuel markets by, among other things, imposing renewable fuel mandate and imposing GHG emission thresholds for certain renewable fuels. States such as California also impose additional carbon fuel standards.
 
  The Clean Water Act (CWA) regulates wastewater and other effluent discharges from BP’s facilities, and BP is required to obtain discharge permits, install control equipment and implement operational controls and preventative measures.
 
  The Resource Conservation and Recovery Act (RCRA) regulates the generation, handling, and disposal of wastes associated with our operations and can require corrective action at locations where such wastes have released.
 
  The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), can, in certain circumstances, impose the entire cost of investigation and remediation on a party who owned or operated a contaminated site or arranged for waste disposal at the site. BP has incurred, or expects to incur, liability under CERCLA or similar state laws, including costs attributed to insolvent or unidentified parties. BP is also subject to claims for remediation costs under other federal and state laws, and to claims for natural resource damages (NRD) under CERCLA, the OPA 90 and other federal and state laws.
 
  The Toxic Substances Control Act regulates BP’s import, export and sale of new chemical products.
 
  The Occupational Safety and Health Act (OSHA), imposes workplace safety and health requirements on our operations along with significant process safety management obligations.
 
  The Emergency Planning and Community Right-to-Know Act, requires emergency planning and hazardous substance release notification as well as public disclosure of our chemical usage and emissions.
 
  The US Department of Transportation (DOT) regulates the transport of BP’s petroleum products such as crude oil, gasoline and petrochemicals.
 
  The Marine Transportation Security Act and the DOT Hazardous Materials (HAZMAT) and the Chemical Facility Anti-Terrorism Standard (CFATS) regulations impose security compliance regulations on BP and require security vulnerability assessments, security mitigation plans and require security upgrades that increase our cost of operations.


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The US refineries of BP Products North America Inc (BP Products) are subject to a consent decree with the EPA to resolve alleged violations of the CAA and implementation of the decree’s requirements continues. A 2009 amendment to the decree resolves remaining alleged air violations at the Texas City refinery through the payment of a $12 million civil fine, a $6 million supplemental environmental project and enhanced CAA compliance measures estimated to cost approximately $150 million. The fine has been paid and BP Products is implementing the other provisions. For further disclosures relating to Texas City refinery, please see Legal proceedings on pages 95-96.
          Various environmental groups and the EPA have challenged certain aspects of the operating permit issued by the Indiana Department of Environmental Management (IDEM) for our upgrades to the Whiting refinery. In response to these challenges, IDEM has reviewed the permits and responded formally to the EPA. The EPA either through IDEM or directly can cause the permit to be modified, reissued or in extremis terminated or revoked. BP is in discussions with the EPA and IDEM over these issues and clean air act violations at the Whiting, Toledo, Carson and Cherry Point refineries. Settlement negotiations continue in an effort to resolve these matters.
European Union
BP’s operations in the EU are subject to a number of current and proposed regulatory requirements that affect our operations and profitability. These include:
  The EU Climate Action and Renewable Energy Package and the Emissions Trading Scheme (ETS) Directive (see Greenhouse gas regulation above).
 
  The EU European Integrated Pollution Prevention and Control (IPPC) Directive imposes a unified environmental permit requirement on our major European sites including refineries and chemical facilities and requires assessments and some upgrades to our facilities. A proposed Industrial Emission Directive would replace the IPPC Directive. It would merge several existing industrial emission directives, impose tighter emission standards for large combustion plants and be more prescriptive as to the Best Available Techniques (BAT) to be used to achieve emission limits. This may result in requirements for further emission reductions at our EU sites.
 
  The EC Thematic Strategy on Air Pollution and the related work on revisions to the Gothenburg Protocol and National Emissions Ceiling Directive (NECD). This will establish national ceilings for emissions of a variety of air pollutants in order to achieve EU-wide health and environmental improvement targets. The EC is also considering the use of a NOX and SO2 trading scheme as a tool to achieve emission reductions. This may result in requirements for further emission reductions at our EU sites.
 
  The EU Regulation on ozone depleting substances (ODS), which implements the Montreal Protocol on ODS was most recently revised in 2009 requires BP to reduce the use of ozone depleting substances (ODS) and phase out certain ODS substances. BP continues to replace ODS in refrigerants and/or equipment, in the EU and elsewhere, in accordance with the Protocol and related legislation. Methyl bromide (an ODS) is a minor byproduct in the production by our petrochemicals operations of purified terephthalic acid and the progressive phase out of methyl bromide uses may result in future pressure to reduce our emissions of methyl bromide.
 
  The EU Fuel Quality Directive affects our production and marketing of fuels. Proposed changes to this directive would require BP to achieve life cycle GHG emission reductions in fuels we sell and would also facilitate the introduction of biofuels into gasoline and diesel.
  The EU Registration, Evaluation and Authorization of Chemicals (REACH) legislation requires that we register chemical substances we manufacture or import into the EU with a complete set of hazard and risk data. Existing manufactured and imported substances were all preregistered by 1 December 2008 and qualified for a timed phase-in for full registration during the period 2010-2018. Crude oil and natural gas are exempt from registration requirements, while fuels are exempt from authorization but not registration. REACH affects our refining, petrochemicals and other manufacturing operations.
 
  International marine fuel regulations under International Maritime Organisation (IMO) and International Convention for the Prevention of Pollution from Ships (Marpol) regimes impose stricter sulphur emission restrictions on ships in EU ports and inland waterways and the North and Baltic seas beginning in 2010 and with a stricter global cap on marine sulphur emissions beginning in 2012. Further reductions are to be phased in thereafter. These restrictions require the use of compliant heavy fuel oil (HFO) or distillate, or the installation of abatement technologies on ships. These regulations will place additional costs on refineries producing marine fuel, including costs to dispose of sulphur, as well as increased CO2 emissions and energy costs for additional refining.
 
  In the UK, significant health and safety legislation affecting BP includes the Health and Safety at Work Act and regulations and the Control of Major Accident Hazards Regulations.
Maritime regulations
BP Shipping’s operations are subject to extensive national and international regulations governing liability, operations, training, spill prevention and insurance. These include:
  In US waters, the Oil Pollution Act of 1990 (OPA 90) imposes liability and spill prevention and planning requirements governing, amongst others, tankers, barges and offshore facilities and mandates a levy on oil imported and produced domestically to fund oil spill response. Some states, including Alaska, Washington, Oregon and California, impose additional liability for oil spills.
 
  Outside US territorial waters, BP Shipping tankers are subject to international liability, spill response and preparedness regulations under the UN’s International Maritime Organization, including the International Convention on Civil Liability for Oil Pollution, the International Convention for the Prevention of Pollution from Ships, the International Convention on Oil Pollution, Preparedness, Response and Co-operation and the International Convention on Civil Liability for Bunker Oil Pollution Damage.
To meet its financial responsibility requirements, BP Shipping maintains marine liability pollution insurance to a maximum limit of $1 billion for each occurrence through mutual insurance associations (P&I Clubs) but there can be no assurance that a spill will necessarily be adequately covered by insurance or that liabilities will not exceed insurance recoveries.
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Employees
                         
     
Number of employees at 31 December   US     Non-US     Total  
     
2009
                       
Exploration and Production
    8,000       13,500       21,500  
Refining and Marketinga
    12,700       38,900       51,600  
Other businesses and corporate
    2,100       5,100       7,200  
     
 
    22,800       57,500       80,300  
     
2008
                       
Exploration and Production
    7,700       13,700       21,400  
Refining and Marketinga
    19,000       42,500       61,500  
Other businesses and corporate
    2,600       6,500       9,100  
     
 
    29,300       62,700       92,000  
     
2007
                       
Exploration and Production
    7,800       14,000       21,800  
Refining and Marketinga
    22,700       44,500       67,200  
Other businesses and corporate
    2,500       6,600       9,100  
     
 
    33,000       65,100       98,100  
     
 
aIncludes 13,900 (2008 21,200 and 2007 24,500) service station staff.

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.
          We had approximately 80,300 employees at 31 December 2009, compared with approximately 92,000 at 31 December 2008. This reduction principally reflects the transfer of our convenience retail sites to a franchise model and the progress we have made in making BP a simpler, more efficient organization.
          Our focus in 2009 has been on ensuring we have the right people in the right roles including renewal of the group leader population. We are seeking to promote continuous improvement by embedding the BP leadership framework throughout the organization. This framework sets out how BP leaders are expected to behave in delivering our strategy and achieving sustained high performance. We are striving for deeper skills development and continuing to align reward frameworks to promote our desired behaviours and outcomes. Diversity and inclusion (D&I) is an important part of all our people processes in BP and involves acknowledging, valuing and leveraging our similarities and differences for business success.
          We have made significant progress in changing the culture of the group to one with a stronger performance focus and which places more value on deep specialist skills and expertise. Creating this culture has required us to enhance our approach to performance management at the business, team and individual level and to align performance and reward outcomes.
          We have completed the second cycle of our redesigned performance management and reward process to ensure that there is a direct link between performance and incentive reward. Throughout the organization we have also achieved greater differentiation of performance ratings and, as a result, in incentive compensation spend. We believe this will continue to improve the performance focus of businesses and individuals.
          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 1,400 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 whose skills are in high demand.
          We aim 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.
          We have revitalized our approach to D&I. In 2009, the focus has been to re-establish D&I as a corporate priority. There is now clear ownership by the business of D&I plans which are the direct responsibility of the relevant SPU or function. Each SPU and function has a D&I plan against which progress is measured. In addition the group chief executive chairs the global D&I council. This council is supported by a North American regional council and segment councils. We are creating momentum which we expect will lead to sustainable progress on D&I.
          The group people committee, formed in 2007, continues to take overall responsibility for policy decisions relating to employees. In 2009, this included senior level talent review and succession planning, embedding of D&I 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 proportion is around 85%. 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 2009, 14% of our top 492 group leaders were female and 21% 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 leaders’ awareness of D&I, and further training is planned in 2010.
          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 2009, we appointed 40 people to positions in the group leadership population. Of these, 20 were internal candidates.




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The Leadership Framework is being embedded through access to management development programmes and progress will be measured by a new 360° feedback tool. The group-wide management development programme, Managing Essentials – Effective Performance Conversations, has now run in 41 countries. A further five programmes have been developed in 2009 which address particular leadership challenges faced by the group leader, senior level leader and first level leader populations.
          We provide development opportunities for all our employees, including external and on-the-job training, international assignments, mentoring, team development days, workshops, seminars and online learning. We encourage all employees to take five training days per year.
          Through our ShareMatch plan, run in around 65 countries, we match BP shares purchased by employees.
          Communications with employees include magazines, intranet sites, DVDs, targeted emails and face-to-face communication. Team meetings are the core of our employee engagement, 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.
          In 2008, we received feedback through our employee engagement surveys that, while there was still very high loyalty to BP as a company, employee engagement was declining as we worked through the difficult actions needed to turn around our performance. In response, we have made it a priority to ensure that BP’s group leaders are better equipped to tell our story and engage their staff in supporting our strategy.
          The progress we have made in employee engagement is evident from the results from our 2009 employee survey. The response rate for the survey improved year on year with 57% of people completing the survey, up from 42% in 2008. The Employee Satisfaction Index and our Pulse survey scores for Performance culture and Safety and Compliance culture all improved year on year.
          We continue to make significant efforts to communicate the intent and progress of our ongoing cost-efficiency programmes, to minimize any potential negative perceptions within the business. We have moved quickly to manage these people and performance changes while keeping the focus on safety, continuous improvement and sustainable change. These improvements are expected to continue in 2010, but we have already delivered material reductions in complexity, 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 2009 was 874, compared with 925 in 2008.
          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 2009, 524 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. Specifically, BP made no donations to UK or other EU political parties or organizations in 2009.
Social and community issues
Contributing to communities
We seek to make a positive difference wherever we operate. To do this, we take action that is relevant to local circumstances, mutually beneficial and designed to create enduring, as opposed to short-term, solutions. Our investments in education and local enterprise development aim to build local capability as part of our business agenda, either through our local employees or through the provision of goods and services.
          As a global energy company, BP operates in a diverse range of countries and in a variety of environmental and social conditions. A common feature of these operations is the lifespan of our projects — some BP projects might last as long as 30-40 years. This longevity requires that BP seeks to cultivate and maintain enduring relationships with the communities and governments in these areas. To do this, BP is committed to finding solutions that create mutual benefit: work with local communities, agencies and organizations on finding solutions to issues that can bring benefit to both the local operations as well as help to meet community development needs over a project’s lifespan.
          We always seek solutions that are aligned to the strategy of our local businesses. For example, in education we support projects that contribute to the wider sustainable development agenda of the particular country but also develop skills and capabilities that are relevant to BP. In doing this, we involve ourselves, as appropriate, in supporting the enhancement of the availability, quality and relevance of education offerings, particularly technical education. This can range from the development of new geo-science and petro-technical offerings at universities, to the support for English language-based technical training, to the support for a broader understanding of the legal aspects of oil and gas management for policy makers, to the basics of the oil industry for journalists.
          In some instances we get involved in supporting elements of macro-economic planning to ensure that issues such as good revenue management practices can enable wider national development. In doing this we usually facilitate access to world class policy thinkers on a range of issues through BP’s global relationships with leading education institutions.
          We also seek to support the development of the local supply chain as a way of deepening the involvement of local enterprise in BP business activities. The way we do this depends on local conditions but can include training, business advisory services or financing programmes that aim to help develop existing business products and services, improve internal standards and practices, or create new small enterprises.
          We support various voluntary, multi-stakeholder initiatives aimed at sharing best practice and improving industry-wide management of key social and economic challenges. We are 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. We are also members of the Voluntary Principles on Security and Human Rights through which we have developed a robust internal process designed to ensure that the security of our operations around the world is maintained in a manner consistent with our group stance on human rights.
          We make direct contributions to communities through community programmes. Our total contribution in 2009 was $106.8 million, which included $1.3 million to UK charities. The majority of our community expenditure was directed towards education and technical training projects.
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In 2009, we spent $55 million promoting education, with investment in three broad areas: tertiary and post secondary level support for engineering; energy industry-related areas such as geo-science and business leadership skills; and supporting the improvement of science and technology teaching within basic education.
Relationships with suppliers
and contractors
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.
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 our 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 2006 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.
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 (PSAs). 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 ventures 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 PSAs). 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 Abu Dhabi, Angola, Egypt, Norway, the UK, the US, Russia, South America and Trinidad & Tobago.
          For a discussion of environmental and certain health and safety regulations and environmental proceedings, see Environment on pages 43-45. See also Legal proceedings on pages 95-96.
Organizational structure
The significant subsidiaries of the group at 31 December 2009 and the group percentage of ordinary share capital (to the nearest whole number) are set out in Financial statements – Note 43 on pages 175-176. See Financial statements – Notes 22 and 23 on pages 140 and 141 respectively for information on significant jointly controlled entities and associates of the group.


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Financial performance
Group results
The following summarizes the group’s results.
                         
     
$ million except per share amounts  
     
    2009     2008     2007  
     
Sales and other operating revenues
    239,272       361,143       284,365  
Profit for the year
    16,759       21,666       21,169  
Profit for the year attributable to BP shareholders
    16,578       21,157       20,845  
Profit attributable to BP shareholders per ordinary share – cents
    88.49       112.59       108.76  
Dividends paid per ordinary share – cents
    56.00       55.05       42.30  
     
For a discussion of the business environment in 2007-2009, see Group overview on page 8.

Profit attributable to BP shareholders
Profit attributable to BP shareholders for the year ended 31 December 2009 was $16,578 million, including inventory holding gains, net of tax, of $2,623 million and a net charge for non-operating items, after tax, of $1,067 million. In addition, fair value accounting effects had a favourable impact, net of tax, of $445 million relative to management’s measure of performance. Inventory holding gains and losses, net of tax, are described in footnote (a) below. Further information on non-operating items and fair value accounting effects can be found on pages 54-55.
          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) below.
          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. In addition, fair value accounting effects had an unfavourable impact, net of tax, of $198 million relative to management’s measure of performance. Further information on non-operating items and fair value accounting effects can be found on pages 54-55.
          The primary additional factors reflected in profit for 2009, compared with 2008, were lower realizations and refining margins and higher depreciation, partly offset by higher production, stronger operational performance and lower costs.
          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.
          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 80,300 at 31 December 2009, 92,000 at 31 December 2008 and 98,100 at 31 December 2007.
 
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  
    2009     2008     2007  
 
Exploration and Production
    14,696       22,026       13,904  
Refining and Marketing
    4,114       4,710       4,356  
Other businesses and corporate
    1,191       1,450       934  
 
Capital expenditure
    20,001       28,186       19,194  
Acquisitions and asset exchanges
    308       2,514       1,447  
 
 
    20,309       30,700       20,641  
Disposals
    (2,681 )     (929 )     (4,267 )
 
Net investment
    17,628       29,771       16,374  
 
Capital expenditure and acquisitions in 2009, 2008 and 2007 amounted to $20,309 million, $30,700 million and $20,641 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 of 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 2009 was $20,001 million compared with $28,186 million in 2008 and $19,194 million in 2007.


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Finance costs and net finance expense relating to pensions and other post-retirement benefits
Finance costs comprise interest payable less amounts capitalized, and interest accretion on provisions and long-term other payables. Finance costs in 2009 were $1,110 million compared with $1,547 million in 2008 and $1,393 million in 2007. The decrease in 2009, when compared with 2008, is largely attributable to the reduction in interest rates. The increase in 2008, when compared with 2007, is largely the outcome of reductions in capitalized interest as capital construction projects concluded.
          Net finance expense relating to pensions and other post-retirement benefits in 2009 was $192 million compared with net finance income of $591 million and $652 million in 2008 and 2007 respectively. The expected return on assets decreased significantly in 2009 as the pension asset base reduced, consistent with falls in equity markets during 2008.
Taxation
The charge for corporate taxes in 2009 was $8,365 million, compared with $12,617 million in 2008 and $10,442 million in 2007. The effective tax rate was 33% in 2009, 37% in 2008 and 33% in 2007. The group earns income in many countries and, on average, pays taxes at rates higher than the UK statutory rate of 28%. The decrease in the effective tax rate in 2009 compared with 2008 primarily reflects a higher proportion of income from associates and jointly controlled entities where tax is included in the pre-tax operating result, foreign exchange effects and changes to the geographical mix of the group’s income. 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.
Segment results
Profit before interest and taxation, which is before finance costs, net finance income or expense, taxation and minority interests, was $26,426 million in 2009, $35,239 million in 2008 and $32,352 million in 2007.


Analysis of replacement cost profit before interest and tax and reconciliation to profit before taxationa
                         
     
$ million  
     
    2009     2008     2007  
     
By business
                       
Exploration and Production
                       
US
    6,685       11,724       7,929  
Non-US
    18,115       26,584       19,673  
     
 
    24,800       38,308       27,602  
     
Refining and Marketing
                       
US
    (2,578 )     (644 )     (1,232 )
Non-US
    3,321       4,820       3,853  
     
 
    743       4,176       2,621  
     
Other businesses and corporate
                       
US
    (728 )     (902 )     (960 )
Non-US
    (1,594 )     (321 )     (249 )
     
 
    (2,322 )     (1,223 )     (1,209 )
     
 
    23,221       41,261       29,014  
Consolidation adjustment
    (717 )     466       (220 )
     
Replacement cost profit before interest and taxb
    22,504       41,727       28,794  
     
Inventory holding gains (losses)
                       
Exploration and Production
    142       (393 )     127  
Refining and Marketing
    3,774       (6,060 )     3,455  
Other businesses and corporate
    6       (35 )     (24 )
     
Profit before interest and tax
    26,426       35,239       32,352  
     
Finance costs
    1,110       1,547       1,393  
Net finance expense (income) relating to
pensions and other post-retirement benefits
    192       (591 )     (652 )
     
Profit before taxation
    25,124       34,283       31,611  
     
Replacement cost profit before interest and tax
                       
By geographical area
                       
US
    2,806       10,678       5,581  
Non-US
    19,698       31,049       23,213  
     
 
    22,504       41,727       28,794  
     
 
aIFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit before interest and tax. In addition, a reconciliation is required between the total of the operating segments’ measures of profit or loss and the group profit or loss before taxation.
bReplacement cost profit reflects the replacement cost of supplies. The replacement cost profit for the period is arrived at by excluding from profit inventory holding gains and losses and their associated tax effect. Replacement cost profit for the group is not a recognized GAAP measure. Further information on inventory holding gains and losses is provided on page 49.


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Exploration and Production
                         
For the year ended 31 December                   $ million  
    2009     2008     2007  
     
Sales and other operating revenuesa
    57,626       86,170       65,740  
Replacement cost profit before interest and taxb
    24,800       38,308       27,602  
     
 
                       
million barrels of oil equivalent
 
     
Net proved reserves for subsidiaries
    12,621       12,562       12,583  
Net proved reserves for equity-accounted entities
    5,671       5,585       5,231  
     
Total of subsidiaries and equity-accounted entities
    18,292       18,147       17,814  
     
 
                       
$  per barrel
 
     
Average BP crude oil realizationsc
    59.86       95.43       69.98  
Average BP NGL realizationsc
    29.60       52.30       46.20  
Average BP liquids realizationsc d
    56.26       90.20       67.45  
Average West Texas Intermediate oil price
    61.92       100.06       72.20  
Average Brent oil price
    61.67       97.26       72.39  
     
 
                       
$  per thousand cubic feet
 
     
Average BP natural gas realizationsc
    3.25       6.00       4.53  
Average BP US natural gas realizationsc
    3.07       6.77       5.43  
     
 
                       
$  per million British thermal units  
     
Average Henry Hub gas pricee
    3.99       9.04       6.86  
     
 
                       
pence per therm
 
     
Average UK National Balancing Point gas price
    30.85       58.12       29.95  
     
 
                       
thousand barrels per day
 
     
Total liquids production for subsidiariesd f
    1,400       1,263       1,304  
Total liquids production for equity-accounted entitiesd f
    1,135       1,138       1,110  
     
Total of subsidiaries and equity-accounted entitiesd f
    2,535       2,401       2,414  
     
 
                       
million cubic feet per day
 
     
Natural gas production for subsidiariesf
    7,450       7,277       7,222  
Natural gas production for equity-accounted entitiesf
    1,035       1,057       921  
     
Total of subsidiaries and equity-accounted entitiesf
    8,485       8,334       8,143  
     
 
                       
thousand barrels of oil equivalent per day
 
     
Total production for subsidiariesf g
    2,684       2,517       2,549  
Total production for equity-accounted entitiesf g
    1,314       1,321       1,269  
     
Total of subsidiaries and equity-accounted entitiesf g
    3,998       3,838       3,818  
     
 
aIncludes sales between businesses.
 
bIncludes profit after interest and tax of equity-accounted entities.
 
cRealizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.
 
dCrude oil and natural gas liquids.
 
eHenry Hub First of Month Index.
 
fNet of royalties.
 
gExpressed in thousands of barrels of oil equivalent per day (mboe/d). Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
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Sales and other operating revenues for 2009 were $58 billion, compared with $86 billion in 2008 and $66 billion in 2007. The decrease in 2009 primarily reflected lower oil and gas realizations. The increase in 2008 compared with 2007 primarily reflected higher oil and gas realizations; gas marketing sales also increased primarily as a result of higher prices.
          The replacement cost profit before interest and tax for the year ended 31 December 2009 was $24,800 million. This included a net credit for non-operating items of $2,265 million (see page 54), with the most significant items being gains on the sale of operations (primarily from the disposal of our 46% stake in LukArco, the sale of our 49.9% interest in Kazakhstan Pipeline Ventures LLC and the sale of BP West Java Limited in Indonesia) and fair value gains on embedded derivatives. In addition, fair value accounting effects had a favourable impact of $919 million relative to management’s measure of performance (see page 55).
          The replacement cost profit before interest and tax for the year ended 31 December 2008 was $38,308 million. This included a net charge for non-operating items of $990 million (see page 54), with the most significant items being net impairment charges and net fair value losses on embedded derivatives, partly offset by the reversal of certain provisions. The impairment charge included 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 55).
          The replacement cost profit before interest and tax for the year ended 31 December 2007 was $27,602 million. This included a net credit from non-operating items of $491 million (see page 54), 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 55).
The primary additional factor contributing to the 35% decrease in the replacement cost profit before interest and tax for the year ended 31 December 2009 compared with the year ended 31 December 2008 was lower realizations. In addition, the result was impacted by lower income from equity-accounted entities and higher depreciation but the result benefited from higher production and lower costs, as a result of our continued focus on cost management.
          The primary additional factor contributing to the 39% increase in the replacement cost 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.
          Reported production for 2009 was 3,998mboe/d (2,684mboe/d for subsidiaries and 1,314mboe/d for equity-accounted entities) compared with 3,838mboe/d in 2008 (2,517mboe/d for subsidiaries and 1,321mboe/d for equity-accounted entities), an increase of 4%. After adjusting for entitlement impacts in our PSAs and the effect of OPEC quota restrictions, the increase was 5%. This reflected continued strong operational performance and the start-up of seven major projects in 2009.
          Reported production for 2008 was 3,838mboe/d (2,517mboe/d for subsidiaries and 1,321mboe/d for equity-accounted entities), compared with 3,818mboe/d in 2007 (2,549mboe/d for subsidiaries and 1,269mboe/d for equity-accounted entities). In aggregate, after adjusting for the effect of lower entitlement in our PSAs, 2008 production was 5% higher than 2007. This reflected strong performance from our existing assets, the continued ramp-up of production following the start-up of major projects in late 2007 and the start-up of nine major projects in 2008.


Refining and Marketing
                         
$ million  
     
    2009     2008     2007  
     
Sales and other operating revenuesa
    213,050       320,039       250,221  
Replacement cost profit before interest and taxb
    743       4,176       2,621  
     
 
                       
$  per barrel
 
     
Global indicator refining margin (GIM)c
                       
Northwest Europe
    3.26       6.72       4.99  
US Gulf Coast
    4.63       6.78       13.48  
Midwest
    5.43       5.17       12.81  
US West Coast
    5.88       7.42       15.05  
Singapore
    0.21       6.30       5.29  
BP average
    4.00       6.50       9.94  
     
 
                       
%
 
     
Refining availabilityd
    93.6       88.8       82.9  
     
 
                       
thousand barrels per day
 
     
Refinery throughputs
    2,287       2,155       2,127  
     
 
aIncludes sales between businesses.
 
bIncludes profit after interest and tax of equity-accounted entities.
 
cThe global indicator refining margin (GIM) is the average of regional indicator margins weighted 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 regional indicator margins may not be representative of the margins achieved by BP in any period because of BP’s particular refinery 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.


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Table of Contents

Business review


Sales and other operating revenues are explained in more detail below.
                         
     
$ million  
     
    2009     2008     2007  
     
Sale of crude oil through spot and term contracts
    35,625       54,901       43,004  
Marketing, spot and term sales of refined products
    166,088       248,561       194,979  
Other sales and operating revenues
    11,337       16,577       12,238  
     
 
    213,050       320,039       250,221  
     
 
                       
thousand barrels per day
 
     
Sale of crude oil through spot and term contracts
    1,824       1,689       1,885  
Marketing, spot and term sales of refined products
    5,887       5,698       5,624  
     

Sales and other operating revenues for 2009 were $213 billion, compared with $320 billion in 2008 and $250 billion in 2007. The decrease in 2009 compared with 2008 primarily reflected a decrease in prices. The increase in 2008 compared with 2007 primarily reflected an increase in revenues from marketing, spot and term sales of refined products, mainly driven by higher prices. Additionally, revenues from sales of crude oil through spot and term contracts increased as a result of higher prices, partly offset by lower volumes.
          The replacement cost profit before interest and tax for the year ended 31 December 2009 was $743 million. This included a net charge for non-operating items of $2,603 million (see page 54). The most significant non-operating items were restructuring charges and a $1.6 billion one-off, non-cash, loss to impair all the segment’s goodwill in the US West Coast fuels value chain relating to our 2000 ARCO acquisition. In addition, fair value accounting effects had an unfavourable impact of $261 million relative to management’s measure of performance (see page 55).
          The replacement cost profit before interest and tax for the year ended 31 December 2008 was $4,176 million. This included a net credit for non-operating items of $347 million (see page 54). 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 to 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 55).
          The replacement cost profit before interest and tax for the year ended 31 December 2007 was $2,621 million. This included a net charge for non-operating items of $952 million (see page 54). 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 in the UK and a 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 55).
          During 2009, our performance was also driven by the significantly weaker environment, where refining margins fell by almost 40%. This was partly offset by significantly stronger operational performance in the fuels value chains, with 93.6% refining availability; lower costs and improved performance in the international businesses.
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 were 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 compared with 2007, 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.
          Refining throughputs in 2009 were 2,287mb/d, 132mb/d higher than in 2008. Refining availability was 93.6%, 4.8 percentage points higher than in 2008, the increase being driven primarily by the restoration of availability at our Texas City refinery. Marketing volumes at 3,560mb/d were around 4.1% lower than in 2008.
Other businesses and corporate
                         
$ million  
 
    2009     2008     2007  
 
Sales and other operating revenuesa
    2,843       4,634       3,698  
Replacement cost profit (loss) before interest and taxb
    (2,322 )     (1,223 )     (1,209 )
 
 
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 interest income on the group’s cash, cash equivalents), and corporate activities worldwide.
          The replacement cost loss before interest and tax for the year ended 31 December 2009 was $2,322 million and included a net charge for non-operating items of $489 million (see page 54).
          The primary additional factors affecting 2009’s result compared with that of 2008 were a weaker margin environment for Shipping and our BP Solar business and adverse foreign exchange effects.
          The replacement cost loss before interest and tax for the year ended 31 December 2008 was $1,223 million and included a net charge for non-operating items of $633 million (see page 54).
          The replacement cost loss before interest and tax for the year ended 31 December 2007 was $1,209 million and included a net charge for n