BP 20-F 2010
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Commission file number: 1-6262
(Exact name of Registrant as specified in its charter)
England and Wales
(Jurisdiction of incorporation or organization)
1 St Jamess Square, London SW1Y 4PD
(Address of principal executive offices)
Dr Byron E Grote
1 St Jamess Square, London SW1Y 4PD
Tel +44 (0) 20 7496 4000
Fax +44 (0) 20 7496 4630
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(g) of the Act.
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
Indicate the number of outstanding shares of each of the issuers classes of capital or common stock as of the close of the period covered by the annual report.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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.
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.
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).*
*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):
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
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.
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).
Cross reference to Form 20-F
In this document, unless the context otherwise requires, the following terms shall have the meaning set out below.
American depositary receipt.
American depositary share.
Annual general meeting.
The former Amoco Corporation and its subsidiaries.
Atlantic Richfield Company and its subsidiaries.
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.
42 US gallons.
barrels per day.
barrels of oil equivalent.
BP p.l.c. and its subsidiaries.
Burmah Castrol PLC and its subsidiaries.
One-hundredth of the US dollar.
The US dollar.
Crude oil and natural gas.
International Financial Reporting
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).
A contractual arrangement whereby two or more parties undertake an economic activity that is subject to joint control.
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.
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.
Crude oil, condensate and natural gas liquids.
Liquefied natural gas.
London Stock Exchange plc.
Liquefied petroleum gas.
thousand barrels per day.
thousand barrels of oil equivalent per day.
million British thermal units.
million barrels of oil equivalent.
million cubic feet.
million cubic feet per day.
Methyl tertiary butyl ether.
Natural gas liquids.
Organization of Petroleum Exporting Countries.
Ordinary fully paid shares in BP p.l.c. of 25c each.
One-hundredth of a pound sterling.
The pound sterling.
Cumulative First Preference Shares and Cumulative Second Preference Shares in BP p.l.c. of £1 each.
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.
The United States Securities and Exchange Commission.
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.
United Kingdom of Great Britain and Northern Ireland.
United States of America.
BP is one of the worlds 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. BPs activities in low-carbon energy are managed through our Alternative Energy business, which is reported within Other businesses and corporate.
Exploration and Productions 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 Marketings 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.
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. BPs 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 companys securities are traded in the form of ADSs. (See pages 96 to 97 for more details.)
Our worldwide headquarters is located at:
1 St Jamess 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
BPs worldwide headquarters is in London. The UK is a centre for trading, legal, finance and other business functions as well as three of BPs 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 groups 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.
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 segments 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.
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.
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.
Crude oil prices
Dated Brent for the year averaged $61.67 per barrel, about 37% below 2008s 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.
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. 2008s 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 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.
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 Agencys (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 worlds 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 worlds 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 worlds 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.
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 groups 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 worlds 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 worlds 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.
2009 has been a successful year for BP, with positive financial and operational momentum despite an extremely turbulent global financial environment.
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 BPs 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.
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.
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
Refining and Marketing
Selected financial and operating
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.
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 managements 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 managements 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 managements 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.
Production and net proved oil and natural gas reserves
The following table shows our production for the past five years and the estimated net proved oil and natural gas reserves at the end of each of those years.
Production and net proved reservesa
During 2009, 1,908 million barrels of oil and natural gas, on an oil equivalenta basis (mmboe), were added, excluding purchases and sales, to BPs proved reserves (1,113mmboe for subsidiaries and 795mmboe for equity-accounted entities). At 31 December 2009, BPs 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%).
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 Chevrons Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The acquisition included Chevrons 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.
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.
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 groups oil and natural gas properties. Such reviews would reflect managements 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 groups 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.
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.
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.
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.
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 groups 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
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.
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.
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.
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.
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 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.
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.
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.
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.
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 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 groups risks both financial and non-financial. During the year, the boards 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 groups risks. Significant incidents that occurred and managements 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 GCEs 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.
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 groups 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 referring to BPs competitive position are based on the companys belief and, in some cases, rely on a range of sources, including investment analysts reports, independent market studies and BPs 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 groups 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.
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 BPs 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.
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 2008s 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 is to invest to grow production safely, reliably and efficiently by:
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.
BPs 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.
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 Indonesias largest LNG export facility and, subject to Government of Indonesia approval, farmed into Chevrons 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.
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.
The table below presents our average sales price per unit of production.
The table below presents our average production cost per unit of production.
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.
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
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 wells 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 SECs 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.
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.
BPs 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:
BPs 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 BPs 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.
BPs 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 groups 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).
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 BPs 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 groups proved reserves held in subsidiaries and equity-accounted entities are estimated by the groups 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.
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 BPs estimated net proved reserves as at 31 December 2009.
Estimated net proved reserves of liquids at 31 December 2009a b
Estimated net proved reserves of natural gas at 31 December 2009a b
Net proved reserves on an oil equivalent basis
The following tables show BPs net production by major field for 2009, 2008 and 2007.
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, BPs 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.
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.
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:
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 BPs 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.
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.
BP has been in Venezuela since 1994 and currently participates in three equity-accounted entities.
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 Colombias northern coast in the Caribbean Sea.
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.
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.
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:
Rest of Europe
Our activities in the Rest of Europe are in Norway.
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 BPs operations in Angola.
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 Libya, BP is in partnership with the Libyan Investment Corporation (LIC) to explore the onshore Ghadames and offshore Sirt basins.
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 Egypts entire oil production and close to 30% of its gas production. The Gulf of Suez Petroleum Company (GUPCO), BPs 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.
BP has a joint interest in Virginia Indonesia Company LLC (VICO), the operator of the Sanga-Sanga PSA (BP 38%) supplying gas to Indonesias largest LNG export facility, the Bontang LNG plant in Kalimantan.
Our upstream business in Vietnam is concentrated on the Block 6.1 offshore gas field. BP participates in one of the countrys 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.
BPs 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 Kongs gas-fired electricity generation. Additional gas is also sold to the Hainan Holdings Fuel & Chemical Corporation Limited.
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.
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. BPs investment in TNK-BP is reported in the Exploration and Production segment. The TNK-BP groups 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.
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.
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.
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.
BPs onshore US crude oil and product pipelines and related transportation assets are included under Refining and Marketing (see page 32).
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 Alaskas 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:
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.
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:
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:
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.
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 groups 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.
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).
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 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 segments 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 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 segments 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.
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 sites 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).
Sales and other operating revenues are analysed in more detail below.
Oil sales volumes
The following table sets out marketing sales by major product group.
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.
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.
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 segments goodwill in the West Coast fuels value chain.
Significant events in the FVCs in 2009 were as follows:
BPs 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 groups 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.
The following table summarizes the BP groups 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.
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.
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 BPs 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.
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 groups oil production and sales of the groups 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).
At 31 December 2009, BPs 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.
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 segments 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:
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. BPs 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.
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.
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 BPs 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 BPs 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
The supply of aviation fuels and LPG is run globally in the global fuels SPU.
Air BP is one of the worlds 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 BPs 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 groups aluminium asset, Treasury (which includes interest income on the groups cash and cash equivalents), and corporate activities worldwide.
The financial results of Other businesses and corporate are discussed on page 53.
Alternative Energy comprises BPs 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 BPs core capabilities. These are biofuels, wind, solar, and hydrogen power and carbon capture and storage (CCS).
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.
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.
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.
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.
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 Solars 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 Xian, 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.
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 DoEs Clean Coal Power Initiative.
Separately, the 400MW Hydrogen Power Abu Dhabi project with CCS reached an important milestone, with the Abu Dhabi environmental regulators approval of the environment and social impact assessment. The project is a joint venture between BP (40%) and Masdar (60%).
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.
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).
BP has 104 hydrocarbon-carrying vessels above 600 deadweight tonnes on time-charter, of which 102 are double-hulled. All these vessels participate in BPs Time Charter Assurance Programme.
BP spot-charters vessels, typically for single voyages. These vessels are always vetted for safety assurance prior to use.
BP uses various craft such as tugs, crew boats and seismic vessels in support of the groups business. We also use sub-600 deadweight tonne barges to carry hydrocarbons on inland waterways.
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.
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 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 BPs 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.
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.
Research and technology
Research and technology (R&T) has a critical role to play in addressing the worlds energy challenges, from fundamental research through to wide-scale deployment. BPs 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 BPs 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:
In our Refining and Marketing segment, technology is delivering performance improvements across all businesses. For example:
BPs Alternative Energy portfolio covers a wide range of renewable and low-carbon energy technologies.
Collaboration plays an important role across the breadth of BPs research and development activities, but particularly in those areas that benefit from fundamental scientific research:
Safety, people and performance are BPs 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 BPs 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, BPs 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. BPs 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 groups 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.
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 Experts second annual report, published in 2009, he acknowledged BPs 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 BPs 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.
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.
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 years 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 todays world but in a future where carbon has a more robust price.
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.
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:
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 BPs 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 BPs 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 groups 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 groups environmental expenditure see page 56.
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:
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 BPs 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:
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 decrees 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.
BPs operations in the EU are subject to a number of current and proposed regulatory requirements that affect our operations and profitability. These include:
BP Shippings operations are subject to extensive national and international regulations governing liability, operations, training, spill prevention and insurance. These include:
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.
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 BPs 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 BPs 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.
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 BPs 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 BPs 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 projects 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 BPs 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.
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
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 BPs 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 groups operations there is no specific group-wide policy in respect of payments to suppliers. Relationships with suppliers are, however, governed by the groups 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 groups business
BPs 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 BPs 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, BPs 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.
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.
The following summarizes the groups results.
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 managements 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 managements 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 managements 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.
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, BPs management believes it is helpful to disclose this information.
Capital expenditure and acquisitions
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 Corporations interest in the Arkoma Basin Woodford Shale assets and the purchase of a 25% interest in Chesapeakes Fayetteville Shale assets. Acquisitions in 2007 included the remaining 31% of the Rotterdam (Nerefco) refinery from Chevrons 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.
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.
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 groups income. The increase in the effective rate in 2008 compared with 2007 primarily reflects the change in the country mix of the groups income, resulting in a higher overall tax burden.
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
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.
Exploration and Production
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 managements 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 managements 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 managements 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
Sales and other operating revenues are explained in more detail below.
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 segments 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 managements 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 favou