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Annual Report and Accounts 2009
bp.com/annualreport

What’s inside?
3 Business review
4 6 8 10 22 36 42 44 46 52 52 52 53 61 Chairman’s letter Group chief executive’s review Our performance Group overview Exploration and Production Re?ning and Marketing Other businesses and corporate Research and technology Corporate responsibility Relationships with suppliers and contractors Regulation of the group’s business Organizational structure Financial performance Liquidity and capital resources

93 Additional information for shareholders
94 96 96 98 98 99 100 101 103 103 105 105 106 106 106 107 107 108 108 108 108 Critical accounting policies Property, plants and equipment Share ownership Major shareholders and related party transactions Dividends Legal proceedings Share prices and listings Memorandum and Articles of Association Exchange controls Taxation Documents on display Controls and procedures Code of ethics Principal accountants’ fees and services Corporate governance practices Purchases of equity securities by the issuer and af?liated purchasers Fees and charges payable by a holder of ADSs Fees and payments made by the Depositary to the issuer Called-up share capital Administration Annual general meeting

65 Board performance and biographies
66 69 Directors and senior management Board performance report

81 Directors’ remuneration report
82 84 91 Part 1 Summary Part 2 Executive directors’ remuneration Part 3 Non-executive directors’ remuneration

109 Financial statements
110 Consolidated ?nancial statements of the BP group 116 Notes on ?nancial statements 179 Supplementary information on oil and natural gas (unaudited) 193 Parent company ?nancial statements of BP p.l.c.

BP Annual Report and Accounts 2009

Information about this report
This document constitutes the Annual Report and Accounts of BP p.l.c. for the year ended 31 December 2009 in accordance with UK requirements and is dated 26 February 2010. This document also contains information that will be included in the company’s Annual Report on Form 20-F 2009 in accordance with the requirements of the US Securities and Exchange Commission (SEC). Such information will be supplemented and may be updated at the time of filing that document with the SEC, or later amended, if necessary. The Annual Report and Accounts for the year ended 31 December 2009 contains the Directors’ Report, including the Business Review and Management Report, on pages 3-80 and 93-108, 110 and 193. The Directors’ Remuneration Report is on pages 81-92. The consolidated financial statements are on pages 109-192. The report of the auditor is on page 111 for the group and page 194 for the company. BP Annual Report and Accounts 2009 and BP Annual Review 2009 may be downloaded from www.bp.com/annualreport. No material on the BP website, other than the items identified as BP Annual Report and Accounts 2009 and BP Annual Review 2009, forms any part of those documents. Reconciliation of profit for the year to replacement cost profit
For the year ended 31 December 2009 2008 $ million 2007

Profit before interest and taxation Finance costs and net finance expense/income relating to pensions and other post-retirement benefits Taxation Minority interest Profit for the year attributable to BP shareholders Inventory holding (gains) losses, net of tax Replacement cost profita Exploration and Production Refining and Marketing Other businesses and corporate Consolidation adjustment – unrealized profit in inventory Replacement cost profit before interest and taxation Finance costs and net finance expense/income relating to pensions and other post-retirement benefits Taxation on a replacement cost basis Minority interest Replacement cost profit attributable to BP shareholders Per ordinary share – cents Profit for the year attributable to BP shareholders Replacement cost profit Dividends paid per ordinary share – cents – pence Dividends paid per American depositary share (ADS) – dollars
a Replacement

26,426 (1,302) (8,365) (181) 16,578 (2,623) 13,955 24,800 743 (2,322) (717) 22,504 (1,302) (7,066) (181) 13,955 88.49 74.49 56.00 36.417 3.360

35,239 (956) (12,617) (509) 21,157 4,436 25,593 38,308 4,176 (1,223) 466 41,727 (956) (14,669) (509) 25,593 112.59 136.20 55.05 29.387 3.303

32,352 (741) (10,442) (324) 20,845 (2,475) 18,370 27,602 2,621 (1,209) (220) 28,794 (741) (9,359) (324) 18,370 108.76 95.85 42.30 20.995 2.538

cost profit reflects the replacement cost of supplies. The replacement cost profit for the year is arrived at by excluding from profit inventory holding gains and losses and their associated tax effect. Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies incurred during the year and the cost of sales calculated on the first-in first-out method, including any changes in provisions where the net realizable value of the inventory is lower than its cost. Inventory holding gains and losses, for this purpose, are calculated for all inventories except for those that are held as part of a trading position and certain other temporary inventory positions. BP uses this measure to assist investors in assessing BP’s performance from period to period. Replacement cost profit for the group is a non-GAAP measure.

On pages 4-9, references within BP Annual Report and Accounts 2009 to ‘profits’, ‘results’ and ‘return on average capital employed’ are to those measures on a replacement cost basis unless otherwise indicated. BP p.l.c. is the parent company of the BP group of companies. Unless otherwise stated, the text does not distinguish between the activities and operations of the parent company and those of its subsidiaries. The term ‘shareholder’ in this Annual Report and Accounts means, unless the context otherwise requires, investors in the equity capital of BP p.l.c., both direct and/or indirect. As BP shares, in the form of ADSs, are listed on the New York Stock Exchange (NYSE), an Annual Report on Form 20-F will be filed with the SEC in accordance with the US Securities Exchange Act of 1934. When filed, copies may be obtained free of charge (see page 108). Cautionary statement BP Annual Report and Accounts 2009 contains certain forward-looking statements within the meaning of the US Private Securities Litigation Reform Act of 1995 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. For more details, please see Forward-looking statements on page 21. The registered office of BP p.l.c. is 1 St James’s Square, London SW1Y 4PD, UK. Tel +44 (0)20 7496 4000. Registered in England and Wales No. 102498. Stock exchange symbol ‘BP’.

1

BP Annual Report and Accounts 2009

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

2

Business review

Business review

4 6 8

Chairman’s letter Group chief executive’s review

52 Relationships with suppliers and contractors 52 Regulation of the group’s business

Our performance
Business review

52 Organizational structure 10 Group overview 53 Financial performance 22 Exploration and Production 61 Liquidity and capital resources 36 Refining and Marketing 42 Other businesses and corporate 44 Research and technology 46 Corporate responsibility

BP Annual Report and Accounts 2009 Business review

Chairman’s letter
I have joined BP at an exciting and testing time for the energy industry and the wider world. Crisis in the global economy has asked tough questions of everyone. Meanwhile, two long-term issues require our continued attention – the high growth in energy demand expected over coming years, and the complex challenges created by climate change. Naturally, more and more people want to improve their quality of life, and a reliable supply of affordable energy is central to meeting their needs and aspirations. Sharing the bene?ts of energy with communities around the world represents important human progress, but this must be achieved with care. Such pressing matters place BP at the heart of what is important to society. While many of the group’s operations are conducted far from our towns and cities, what we produce is essential to everyday life. I have been here only a short time, but I have already seen in action the remarkable skills and technology that ?nd and extract raw materials and turn them into muchneeded energy products. I am particularly impressed by the professionalism and sheer tenacity of the BP people I have met. There is a powerful spirit here. This spirit can be seen clearly within the executive team, under the leadership of Tony Hayward. Their focus on safety, operational performance and culture has produced great results across the group, despite tough market conditions. There is still more to do, and I look forward to working with them as BP moves forward. Our employees have also shown considerable determination over the past 12 months. They have helped to drive a notable and continuing business transformation and I thank them for their commitment.

A revitalized BP
Carl-Henric Svanberg Chairman 26 February 2010
Highlights ? BP playing key role in addressing the energy challenge. ? Strong board enhanced by new appointments. ? Powerful spirit among BP people.

4

The success of BP today is, in many ways, testament to Peter Sutherland’s unique style in leading the board. As chairman for 12 years and non-executive board director for 14 years, Peter steered the group through many challenges. He leaves a strong BP that is well positioned for further success. As a board, we thank him for his exceptional contribution. We also thank those nonexecutives who are to leave after the annual general meeting. Sir Ian Prosser departs after 12 years of outstanding service, including 10 years as deputy chairman. Erroll Davis, Jr joined in 1998 and played an important role in key non-executive committees. Sir Tom McKillop joined in 2004 and chose to retire this year, having made a strong impression. I know my fellow board members greatly appreciate their contributions. We are now in the process of appointing experienced and talented newcomers to the board. I have worked closely with colleagues on the nominations committee to select individuals whose skills match the needs of the business while ensuring appropriate independence. As part of our continuing refreshment of the board, I am delighted that Paul Anderson has recently joined the board and that Ian Davis will join in April 2010. Our clear objective as a board is to sustain the success of the group and I can tell you that we will not lack ambition. BP has driven itself back to competitive ?tness; we must ensure we build on the hard work of the past three years and continue to grow a successful and enduring company. We now have the opportunity to plot the group’s future position within a changing energy landscape.

The ?nancial crisis has highlighted concerns about the way in which companies operate. In some cases, levels of trust between boards of directors and shareholders have been impacted. From my early contact with BP shareholders, I understand that the BP board has long been actively engaged in dialogue. I strongly endorse and encourage this and intend to build on such good practice. BP is respected for its leadership on governance and we will keep looking for ways to enhance how we govern and report on the group. Risk remains a key issue for every business, but at BP it is fundamental to what we do. We operate at the frontiers of the energy industry, in an environment where attitude to risk is key. The countries we work in, the technical and physical challenges we take on and the investments we make – these all demand a sharp focus on how we manage risk. We must never shrink from taking on dif?cult challenges, but the board will strive to set high expectations of how risk is managed and remain vigilant on oversight. As is well known, BP responded early to the issue of climate change. The group has made substantial investments in alternative energies and in lower-carbon fossil fuels such as natural gas. We support the low-carbon evolution, but must also continue to produce the high-quality hydrocarbons required by a world with a growing population, growing economies and greater mobility.

We will continue to contribute to debate around public policy, and intend to help shape and lead the energy industry of tomorrow. People need BP to keep doing what it does best. I recognize that many institutions and individuals rely on BP for a consistent return on their investment and the board takes seriously its responsibilities in this regard. Our task is to achieve the best balance of our sources and uses of cash, making investments to generate long-term business momentum while managing debt and realizing steady rewards for shareholders. Over the past year we have demonstrated our ability to achieve this despite a very volatile business environment. While we cannot control the price of oil we can control the ef?ciency of our own operations, and the improving performance within the group will help us to balance ?nancial priorities. The quarterly dividend, to be paid in March, is 14 cents per share ($0.84 per ADS), the same as a year ago. In sterling terms, the quarterly dividend is 8.679 pence per share, compared with 9.818 pence a year ago. We are now proposing to introduce a scrip dividend programme. For those shareholders who choose to take their dividend in shares, rather than cash, the issuing of scrip shares is an attractive alternative. So, I thank shareholders for their continued support. The group has recently celebrated its centenary and I relish the opportunity to lead the board as we move into a second century. We operate in a fast-moving world full of profound challenges and opportunities, but I see no reason why a ?t and determined BP cannot thrive in this environment and remain at the heart of society for many years to come.

Business review

BP has driven itself back to competitive ?tness; we must ensure we build on the hard work of the past three years and continue to grow a successful and enduring company.

Our market Read about key issues affecting the energy market on pages 11-13.

5

BP Annual Report and Accounts 2009 Business review

Group chief executive’s review
Performance has been restored and the group is competitive with the industry once again, so what priorities have you now set for BP? Our priorities have remained absolutely consistent – safety, people and performance – and you can see the results of this focus with improvements on all three fronts. This year we have increased emphasis on operational ef?ciency, with a particular focus on compliance and continuous improvement. Achieving safe, reliable and compliant operations is our number one priority and the foundation stone for good business. This year we achieved a reported recordable injury frequency of 0.34, an improvement of 20% over 2008. In Re?ning and Marketing reported major incidents have been reduced by 90% since 2005. All our operated re?neries and petrochemicals plants now operate on the BP operating management system (OMS), which governs how BP’s operations, sites, projects and facilities are managed. In Exploration and Production 47 of our 54 sites completed the transition to OMS by the end of 2009, and I expect all BP operations to be on OMS by the end of 2010. This represents good progress and we must remain absolutely vigilant. Why are you putting such strong emphasis on operational ef?ciency? In 2009 we invested $20 billion in our businesses and realized more than $4 billion in cash costb savings, of which approximately 40% related to foreign exchange bene?ts and lower fuel costs. Within an organization of our scale, putting a long-term commitment to ef?ciency at the heart of the group is essential to improving earnings, year after year. Our challenge is to maintain a relentless focus on continuous improvement, making today better than yesterday, so that we continue to drive the business forward whatever the market conditions. What does the focus on ef?ciency and continuous improvement mean for your people? Better performance starts and ends with the actions of individuals and I want to thank our employees for the commitment they showed in 2009. Our performance speaks volumes
b

Ef?ciency, momentum and growth
Tony Hayward Group Chief Executive 26 February 2010
Highlights ? Progress on safe and reliable operations. ? Real momentum in growing our businesses. ? Continued focus on ef?ciency and improvement.

about their motivation and skills. The results from our 2009 employee survey con?rm that employee morale is improving as our operational performance improves. We have placed greater emphasis on organizational quality, which is about driving continuous improvement in our leadership and culture, skills and capability, and systems and processes. We have redesigned the way we manage and reward people to incentivize performance. We are simplifying the organization and freeing people to do their jobs. We are placing particular value on deep specialist skills and technical expertise, and are developing and recruiting the excellent professionals we need to ensure a sustainable future for the group. How is this focus translating into performance in Exploration and Production? 2009 was an outstanding year. Reported production grew by 4% and unit production costs were down by 12%. We are now the largest producer in deepwater ?elds globally. In the Gulf of Mexico we ramped up production at Thunder Horse to more than 300,000 barrels of oil equivalent per day. Production started from Atlantis Phase 2, Dorado and King South. And in September we announced the Tiber discovery, the deepest oil and gas discovery well ever drilled. These successes make us the largest producer and leading resource holder in the deepwater Gulf of Mexico. During the year we also shipped the ?rst cargo of lique?ed natural gas (LNG) from the Tangguh project in Indonesia, and we brought ?rst gas onstream at Savonette, Trinidad & Tobago, in record time. We also gained access to new resource opportunities in Iraq, Egypt, the Gulf of Mexico, Indonesia, Jordan and onshore US. We entered Iraq through a contract to expand production from the Rumaila ?eld near Basra, one of the largest oil ?elds in the world. Working with partners China National Petroleum Company (CNPC) and the Iraqi State Oil Marketing Organization (SOMO), we intend to grow production in Rumaila from approximately 1 million barrels per day to 2.85 million barrels per day. Overall, 2009 was the 17th consecutive year of delivering reported reserves replacement of more than 100%. Our success in adding reserves and resources gives us con?dence in our ability to grow oil and gas production.

2009 saw the continuation of dif?cult economic conditions and a volatile energy market, with rising demand for oil in non-OECD countries failing to offset lower levels of consumption in OECD countries. Oil prices began the year at $36.55 per barrel and recovered to $77.67 per barrel in December. Re?ning margins and gas prices fell sharply. Despite these dif?cult conditions, a revitalized BP kept up its momentum and delivered strong operating and ?nancial results while continuing to focus on safe and reliable operations. Replacement cost pro?t for the year was $14 billion, with a return on average capital employeda of 11%.
a

The return on average capital employed on a replacement basis is the ratio of replacement cost pro?t before interest expense and minority interest but after tax, to the average of opening and closing capital employed. Capital employed is BP shareholders’ interest, plus ?nance debt and minority interest.

Cash costs are a subset of production and manufacturing expenses plus distribution and administration expenses. They represent the substantial majority of the expenses in these line items but exclude associated non-operating items and certain costs that are variable, primarily with volumes (such as freight costs). They are the principal operating and overhead costs that management considers to be most directly under their control although they include certain foreign exchange and commodity price effects.

6

Revitalizing BP Tony Hayward discusses priorities, results and continuous improvement with employees at BP’s International Centre for Business and Technology, Sunbury, UK.

greenhouse gases of 80% or more relative to conventional transport fuels. We have focused our wind business on the US, where we now have more than one gigawatta of spinning power generation capacity. In solar, we are repositioning our manufacturing footprint to lower-cost locations, principally India and China. And in carbon capture and storage, we are investing in two major projects – one in California, the other in Abu Dhabi. In 2009 we saw further challenges for international oil companies in terms of generating growth and achieving access, together with the continued strong emergence of national oil companies. How is BP responding? BP has always operated at the frontiers of the energy industry and our core strengths are more relevant and valuable than ever. BP’s experience, skills, capability, technology and access to markets enable resource holders to maximize returns over the long term. We continue to show our ability to take on and manage risk, doing the dif?cult things that others either can’t do or choose not to do. This is why we are able to form such strong relationships with governments and national oil companies and why we continue to have a critical role to play in supplying the world with its future energy needs. In a world of increasing energy demand and growing technical challenges, I believe BP will continue to set itself apart by operating and succeeding at the frontiers of the energy industry.
a

Business review

What progress are you making in Re?ning and Marketing? The transition to full OMS status across all our operated re?neries and petrochemicals plants is a major milestone, and oil spills and recordable injuries are at the lowest levels for 10 years. So, I’m pleased with the progress made on safety and we have made very strong progress on operational performance in a year when re?ning margins were hit hard by recession. Re?ning availability is up around 5% on 2008 and we have restored our performance so that it is once again competitive with our supermajor peers. We saw a really competitive performance from our international businesses in 2009. We are building strong positions in the petrochemicals market in China and we are continuing to enhance our six integrated fuels value chains around the world to maximize ef?ciency and pro?tability. It is critical that we keep driving ef?ciencies through the businesses while growing our positions in the most valuable and attractive markets.

The world must meet growing demand for energy in a sustainable way; what role will BP play in this energy evolution? We are looking to build a future energy industry that provides energy that is available, sustainable, secure and affordable. For BP, supporting the transition to a lowcarbon economy has several dimensions. First, we are improving energy ef?ciency in BP’s own operations through close performance monitoring. We are also developing more ef?cient products such as BP Ultimate fuels and Castrol lubricants. Second, we are promoting a greater role for natural gas as a key part of the energy future. Gas is easily the cleanest burning fossil fuel and is ef?cient, versatile and abundantly available. We are also including a cost of carbon in investment appraisals for all new major projects to allow informed investment in fossil fuels and to encourage development of the technology needed to reduce their carbon footprint. And ?nally, we are investing in our low-carbon businesses. Since 2005 we have invested more than $4 billion in Alternative Energy, with our activity focused on four key areas. We are investing in advanced biofuels, which are low cost, scalable and sustainable, and can provide reductions in

On a gross joint-venture basis (which includes 100% of the capacity of equity-accounted entities where BP has partial ownership). Including BP’s share of joint ventures on a net basis, the capacity was 711 megawatts.

Speeches by Tony Hayward bp.com/speeches

7

BP Annual Report and Accounts 2009 Business review

Our performance

Progress in 2009

Safety
Personal safety – reported recordable injury frequency
Reported recordable injury frequency (RIF) measures the number of reported work-related incidents that result in a fatality or injury (apart from minor ?rst aid cases) per 200,000 hours worked. Safety is BP’s number one priority and we constantly seek to improve our performance through our procedures, processes and training programmes. Our workforce RIF, which includes employees and contractors combined, was 0.34 in 2009 – signi?cantly lower than 0.43 in 2008 and 0.48 in 2007.
Employees Contractors 0.75 0.60 0.45 0.30
0.35 2007 0.59 2007 0.35 2008 0.50 2008 0.23 2009 0.43 2009

People
Employee satisfactiona (%)
The overall Employee Satisfaction Index comprises 10 key questions that provide insight into levels of employee satisfaction across a range of topics such as pay. The improved performance in 2009 was underpinned by increases in the categories of ‘trust in management’ and ‘perceptions that BP is being effectively managed and well run’. This re?ects our clear, simple and consistent communication to employees of BP’s business performance and progress against corporate goals.
100 80 60 40
66 2006
a

0.15

59 2008

65 2009

20

The People Assurance Survey conducted in 2006 used a census methodology and targeted the entire BP employee population. Based on the same set of questions, the Pulse Plus Survey, in 2008 and 2009, adopted a sample-based approach, which achieved a representative view of BP.

Process safety – oil spills
We report all spills of hydrocarbons greater than or equal to one barrel (159 litres, 42 US gallons). The reduction in the number of oil spills in 2009 follows several years of focus across BP on procedures such as ‘integrity management’ and ‘control of work’, which are core elements of BP’s operating management system.
500 400 300 200
340 2007 335 2008 234 2009

Number of employeesa
Employees include all individuals who have a contract of employment with a BP group entity. In 2009 BP total headcount fell by 11,700, re?ecting the transfer of our US convenience retail sites to a franchise model and the progress we have made in making BP a simpler, more ef?cient organization.
a

125 100 75 50
98,100 2007 92,000 2008 80,300 2009

100

25

As at 31 December.

Environment – greenhouse gas emissionsa (million tonnes of carbon dioxide equivalent)
We report greenhouse gas (GHG) emissions, and emission reductions, on a CO2-equivalent basis including CO2 and methane. This represents all consolidated entities and BP’s share of equity-accounted entities except TNK-BP. The increase in GHG emissions in 2009 was driven primarily by increases in operational activity, in particular higher throughput from our US re?neries, the start-up of our Tangguh LNG project in Indonesia and increased production from deepwater platforms in the Gulf of Mexico.
8 100 80 60 40
63.5 2007
a

Diversity and inclusion (%)
Each year we record the percentage of women and individuals from countries other than the UK and US among BP’s top 492 leaders (2008 583, 2007 624). BP has maintained the percentage of female and ‘most-of-world’ leaders in 2009 and remains focused on building a more sustainable pipeline of diverse talent for the future.
Women Non-UK/US 25 20 15 10
16 2007 19 2007 14 2008 19 2008 14 2009 21 2009

61.4 2008

65.0 2009

20

5

See BP Sustainability Review 2009 for more information on how we derive our sustainable GHG reductions.

Operating cash ?ow ($ billion)
Operating cash ?ow is net cash ?ow provided by operating activities, from the group cash ?ow statement. Operating activities are the principal revenue-generating activities of the group and other activities that are not investing or ?nancing activities. Lower operating cash ?ow in 2009 primarily re?ected lower group pro?ts, movements in working capital and a decrease in dividends from jointly controlled entities and associates. These effects were partly offset by decreases in income taxes paid.
50 40 30 20
24.7 2007 38.1 2008 27.7 2009

10

Performance
Business review

Production (thousand barrels of oil equivalent per day)
We report crude oil, natural gas liquids (NGLs) and natural gas produced from subsidiaries and equity-accounted entities. These are converted to barrels of oil equivalent (boe) at 1 barrel of NGL = 1boe and 5,800 standard cubic feet of natural gas = 1boe. Reported production increased by 4% compared with 2008. This re?ected strong performance from our existing assets, the continued ramp-up of production following the start-up of major projects in 2008 and the start-up of a further seven major projects in 2009.
4,250 4,000 3,750 3,500
3,818 2007 3,838 2008 3,998 2009

Replacement cost pro?t per ordinary share (cents)
Replacement cost pro?t re?ects the replacement cost of supplies. It is arrived at by excluding from pro?t inventory holding gains and losses and their associated tax effect. (See footnote a on page 1.) Our 2009 results were impacted by lower oil and gas realizations and lower re?ning margins, partly offset by higher production, stronger operational performance and lower costs.
200 160 120 80
95.85 2007 136.20 2008 74.49 2009

3,250

40

Reserves replacement ratioa b (%)
Proved reserves replacement ratio (also known as the production replacement ratio) is the extent to which production is replaced by proved reserves additions. The ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions, and discoveries. In 2009 we extended our track record for reported reserves replacement of more than 100% to 17 consecutive years. We continue to drive renewal through new access, exploration, targeted acquisitions and a strategic focus on increasing resources from ?elds we currently operate.
150 120 90 60
112 2007
a

Dividends paid per ordinary share
This measure shows the total dividend per share paid to ordinary shareholders in the year. The total dividend paid per share in 2009 increased by 2% compared with 2008. We determine the dividend in US dollars as it is the economic currency of BP. In sterling terms, our 2009 dividend was 24% higher than in 2008 due to the strengthening of the dollar relative to sterling.
Cents Pence 75 60 45 30
42.30 2007 20.995 55.05 2007 2008 29.387 56.00 2008 2009 36.417 2009

121 2008

129 2009

30

15

Combined basis of subsidiaries and equity-accounted entities, excluding acquisitions and disposals. b See footnote f on page 27.

Re?ning availability (%)
Re?ning availability represents Solomon Associates’ operational availability, which is de?ned as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime. Re?ning availability has increased signi?cantly each year from 2007 to 2009 and is now at the highest level since 2005. This has been a key element in our drive to restore missing revenues in our operations, with the biggest contributor being the restoration of our Texas City re?nery.
100 80 60 40
82.9 2007 88.8 2008 93.6 2009

Total shareholder returna (%)
Total shareholder return represents the change in value of a shareholding over a calendar year, assuming that dividends are re-invested to purchase additional shares at the closing price applicable on the ex-dividend date. Total shareholder return scores in 2009 re?ect BP’s improving competitive performance as well as a general recovery of global stock markets compared with the low levels seen at the end of 2008.
ADS basis Ordinary share basis 60 40
14.1 2007 6.8 2007 2008 -34.6 2008 -15.1 33.0 2009 27.6 2009

20 0 -20

20

a

There is a small change in comparative data due to the exclusion of non-trading days from the average TSR calculation.

9

BP Annual Report and Accounts 2009 Business review

Group overview

Our group functions and regions support the work of our segments and businesses. Their key objectives are to establish and monitor fit-forpurpose functional standards across the group; to act as centres of deep functional expertise; to access significant leverage with third-party suppliers; and to establish and maintain capabilities among the functional staff employed within our operating businesses. In addition, the head of each region provides the required integration and co-ordination of group activities in a particular geographic area and represents BP to external parties. Where we operate BP’s worldwide headquarters is in London. The UK is a centre for trading, legal, finance and other business functions as well as three of BP’s major global research and technology groups. We have well-established operations in Europe, the US, Canada, Russia, South America, Australasia, Asia and parts of Africa. Currently, around 67% of the group’s capital is invested in Organisation for Economic Co-operation and Development (OECD) countries, with around 40% of our fixed assets located in the US and around 20% in Europe.

Our organization
BP is one of the world’s leading international oil and gas companiesa. We operate in more than 80 countries, providing our customers with fuel for transportation, energy for heat and light, retail services and petrochemicals products for everyday items.
As a global group, our interests and activities are held or operated through subsidiaries, jointly controlled entities or associates established in – and subject to the laws and regulations of – many different jurisdictions. These interests and activities covered two business segments in 2009: Exploration and Production and Refining and Marketing. BP’s activities in low-carbon energy are managed through our Alternative Energy business, which is reported within Other businesses and corporate. Exploration and Production’s activities cover three key areas. Upstream activities include oil and natural gas exploration, field development and production. Midstream activities include pipeline, transportation and processing activities related to our upstream activities. Marketing and trading activities include the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs). Refining and Marketing’s activities include the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum and petrochemicals products and related services. The two business segments each comprise a number of strategic performance units (SPUs), which are organized along either geographic or activity-related lines. The role of the SPU includes the development of local capability and the fostering of external stakeholder relationships. Each SPU is of a scale that allows for a close focus on performance delivery by its respective segment, which includes the appropriate management of costs.
a

Exploration and Production BP’s major areas of production in 2009

On the basis of market capitalization, proved reserves and production.

Unless otherwise indicated, information in this document reflects 100% of the assets and operations of the company and its subsidiaries that were consolidated at the date or for the periods indicated, including minority interests. The company was incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001. BP’s primary share listing is the London Stock Exchange. Ordinary shares are also traded on the Frankfurt Stock Exchange in Germany and, in the US, the company’s securities are traded in the form of ADSs. (See pages 100 to 101 for more details.) Our worldwide headquarters is located at: 1 St James’s Square, London SW1Y 4PD, UK. Tel +44 (0)20 7496 4000. Our agent in the US is BP America Inc., 501 Westlake Park Boulevard, Houston, Texas 77079. Tel +1 281 366 2000.

? BP subsidiary ? Equity-accounted entity

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BP Annual Report and Accounts 2009 Business review

Our Exploration and Production segment conducts upstream and midstream activities in 30 countries and we are the largest producer of oil and gas in North America. The segment’s geographical coverage in these activities currently includes Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), Norway, the UK, the US and locations within Asia Pacific, Latin America, North Africa and the Middle East. Our Exploration and Production segment also includes gas marketing and trading activities, primarily in Canada, Europe and the US. In Russia, we have an important associate through our 50% shareholding in TNK-BP a major oil company with exploration assets, , refineries and other downstream infrastructure. In Refining and Marketing, we market our products in more than 80 countries, with a particularly strong presence in the US and Europe, as well as major activities in Australia, Southern Africa, India and China. In the US, we own or have a share in five refineries and market primarily under the Amoco, ARCO, BP and Castrol brands. We are one of the largest gasoline retailers in that country. In Europe, we own or have a share in seven refineries and we market extensively across the region, primarily under the Aral, BP and Castrol brands. Our long-established supply and trading activity is responsible for delivering value across the crude and oil products supply chain. Our petrochemicals business maintains a manufacturing position globally, with an emphasis on growth in Asia. We continue to seek opportunities to broaden our activities in growth markets such as China and India. Refining and Marketing BP’s global presencea

Our market
Energy markets remained volatile in 2009, reflecting the dramatic drop in world economic activity early in the year and indications of economic recovery in the second half. Looking ahead, the long-term outlook is one of growing demand for energya, particularly in Asia, alongside challenges for the industry in meeting this demand. Rising incomes and expanding urban populations are expected to drive demand, while the evolution towards a lowercarbon economy will require technology, innovation and investment.
World oil consumption declined for a second successive year during 2009, with growing demand in non-OECD countries once again more than offset by falling consumption in OECD countries. Average crude oil prices for 2009 were lower than in the previous year, breaking an unprecedented string of seven consecutive annual increases. Natural gas prices also weakened in 2009 and were highly volatile. Refining margins fell sharply as oil demand contracted and substantial amounts of new refining capacity came onstream. Economic context The world economy began to show signs of recovery in the latter part of 2009 and this is expected to continue through 2010, but economic growth in 2010 is likely to be muted in the OECD countries. Growth in global oil consumption is expected to resume as the world economy recovers from recession. In 2009, concerns about the volatility of commodity and financial markets, combined with renewed focus on climate change and the early experiences with efforts to reduce CO2 emissions in the EU and elsewhere, led to an increased focus on the appropriate role for markets, government oversight and other policy measures relating to the supply and consumption of energy. The concept of peak oil – the time after which less oil is available to the world – continues to hold the interest of some commentators, although global proved reserves have tended to rise over time and remain sufficient to support higher levels of production. Meanwhile, the consumer response to higher prices and an increased focus on energy efficiency have served to constrain demand. We expect regulation and taxation of the energy industry and energy users to increase in many areas over the short to medium term.
a

World Energy Outlook 2009. ?OECD/IEA 2009, pages 622-623: ‘Reference Scenario, World’.

? BP refinery (wholly or partly owned) ? Petrochemicals site(s)
a

The green shaded circles indicate the approximate coverage of BP’s integrated fuels value chains.

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BP Annual Report and Accounts 2009 Business review

Crude oil and gas prices, and refining margins ($ per barrel of oil equivalent)
Dated Brent oil price Henry Hub gas price (First of Month Index) Global indicator refining margin (GIM)a 150

120

90

60

30

2004

2005

2006

2007

2008

2009

Source: Platts/BP.

Crude oil prices Dated Brent for the year averaged $61.67 per barrel, about 37% below 2008’s record average of $97.26 per barrel. Prices began the year at their lowest point as the world economy grappled with the sharpest downturn in modern economic history. Global oil consumption reflected the economic slowdown, falling by roughly 1.3 million b/d for the year (1.5%)b, the largest annual decline since 1982. The biggest reductions were early in the year, with OECD countries accounting for the entire global decline. Crude oil prices rose sharply in the second quarter in response to sustained OPEC production cuts and emerging signs of stabilization in the world economy, despite very high commercial oil inventories in the OECD. OPEC members sustained roughly 2.5 million b/d of production cutsb implemented in late 2008 and throughout 2009. Additional price increases later in the year were sustained by further positive economic news and signs that the inventory overhang was beginning to correct. In 2008, the average dated Brent price of $97.26 per barrel was 34% higher than the $72.39 per barrel average seen in 2007. Daily prices began 2008 at $96.02 per barrel, peaked at $144.22 per barrel on 3 July 2008, and fell to $36.55 per barrel at the end of the year. The sharp drop in prices was due to falling demand in the second half of the year, caused by the OECD falling into recession and the lagged effect on demand of high prices in the first half of the year. OPEC had increased production significantly through the first three quarters and, as a result of falling consumption and rising OPEC production, inventories rose. As prices continued to decline, OPEC responded with successive announcements of production cuts in September, October and December. Looking ahead, in 2010 we expect oil price movements to continue to be driven by the extent of global economic growth and its resulting implications for oil consumption, and by OPEC production decisions.
a See b

Natural gas prices Natural gas prices weakened in 2009 and were volatile. The average US Henry Hub First of Month Index fell to $3.99/mmBtu in 2009, a 56% decrease from the record $9.04/mmBtu average seen in 2008. Recession-induced demand declines and strong production caused prices to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in September. However, over the course of the year, the impact was partly offset as US regional gas price differentials narrowed, driven partly by the Rockies Express Pipeline extension allowing the transportation of larger quantities of gas out of the Rockies area. Reduced imports from Canada, slowing US production growth and cooler temperatures allowed prices to recover to $4.49/mmBtu by the end of the year. Prices at the UK National Balancing Point similarly fell to an average of 30.85 pence per therm, 47% below the 2008 average price of 58.12 pence per therm. In 2009, there was a switch of uncontracted LNG cargoes from Asia to Europe, reflecting a shift in relative spot prices. LNG imports to Europe have competed with pipeline imports, where the gas price is often indexed to oil prices, as well as with marginal European gas production. Gas prices were often at or below parity with coal, when translated into the cost of generating power, which led to gas displacing coal in power generation in Europe and the US. In 2008, average natural gas prices in the US and the UK were higher than in 2007. The Henry Hub First of Month Index, at $9.04/mmBtu, was 32% higher than the 2007 average of $6.86/mmBtu. 2008’s prices peaked at $13.11/mmBtu in July amid robust demand and falling US gas imports, but fell to $6.90/mmBtu in December as demand weakened and production remained strong. In the UK, 2008 average prices of 58.12 pence per therm at the National Balancing Point, were 94% above the 2007 average of 29.95 pence per therm. Looking ahead, gas markets in 2010 are expected to follow developments in the global economy, but any price movements are likely to be impacted by significant new LNG capacity as it becomes available. Refining margins Refining margins fell sharply in 2009 as demand for oil products reduced in the wake of the global economic recession and new refining capacity came onstream, mostly in Asia Pacific. The BP global indicator refining margin (GIM)a averaged $4 per barrel last year, down $2.50 per barrel compared with 2008. Margins in the Far East were particularly badly hit – averaging close to zero in Singapore – because new refining capacity has been added in the region. Margins in Europe were about half the 2008 level as the reduction in economic activity meant weaker demand for commercial transport and therefore lower middle distillate consumption. In the US, where refining is more highly upgraded and the transport market more gasoline-orientated, margins were stronger than in Europe. Refining margins in 2008 were lower than in 2007, with the BP GIM decreasing to an average of $6.50 per barrel from $9.94 per barrel in 2007. The premium for light products above fuel oils remained high, reflecting a continuing shortage of upgrading capacity and the favouring of fully upgraded refineries over less complex sites. Looking ahead, refining margins are likely to remain under pressure through 2010, with capacity already exceeding demand and additional new capacity expected to come onstream during the year.

footnote d on page 37. Adapted from Oil Market Report (February 2009). ?OECD/IEA 2009.

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BP Annual Report and Accounts 2009 Business review

Global energy demand by type (million tonnes of oil equivalent)
Other renewables Biomass and waste Coal Hydroelectricity Nuclear energy Natural gas Oil 20

16

12

8

4

1990

2007

2015

2030

Source: World Energy Outlook 2009. ?OECD/IEA 2009, page 622: ‘Reference Scenario, World’.

Long-term outlook Recent economic conditions have weakened global demand for primary energy, but a number of forecasts predict a return to growth in the medium term. This is underpinned by continuing population growth and by generally rising living standards in the developing world, including the expansion of urban populations. Under the International Energy Agency’s (IEA) reference scenario, global energy demand is projected to increase by around 40% between 2007 and 2030a. That scenario also projects that fossil fuels will still be satisfying as much as 80% of the world’s energy needs in 2030. At current rates of consumption, the world has enough proved reserves of fossil fuels to meet these requirementsb if investment is permitted to turn those reserves into production capacity. However, to meet the potential growth in demand, continued investment in new technology will be required in order to boost recovery from declining fields and commercialize currently inaccessible resources. For example, in oil alone, where we believe there are reserves in place to satisfy approximately 40 years’ demand at current rates of consumptionb, we estimate that our industry will need to bring nearly 50 million barrels per day of new capacity onstream by 2030 if it is to meet the increased demand. To play their part in achieving this, energy companies such as BP will need secure and reliable access to as-yet undeveloped resources. We estimate that more than 80% of the world’s oil resources are held by Russia, Mexico and members of OPEC – areas where international oil companies are frequently limited or prohibited from applying their technology and expertise to produce additional supply. New partnerships will be required to transform latent resources into much-needed proved reserves. A more diverse mix of energy will also be required to meet this increased demand. Such a mix is likely to include both unconventional fossil fuel resources – such as oil sands, coalbed methane and natural gas produced from shale formations – and renewable energy sources such as wind, biofuels and solar power. Beyond simply meeting growth in overall demand, a diverse mix would also help to provide enhanced national and global energy security while supporting the transition to a lower-carbon economy. Improving the efficiency of energy use will also play a key role in maintaining energy market balance in the future.

Along with increasing supply, we believe the energy industry will be required to make hydrocarbons cleaner and more efficient to use – particularly in the critical area of power generation, for which the key hydrocarbons are currently coal and gas. The world has reserves of coal for around 120 years at current consumption ratesb, but coal produces more carbon than any other fossil fuel. Carbon capture and storage (CCS) may help to provide a path to cleaner coal, and BP is investing in this area, but CCS technologies still face significant technical and economic issues and are unlikely to be in operation at scale for at least a decade. In contrast, we believe that in many countries natural gas has the potential to provide the most significant reductions in carbon emissions from power generation in the shortest time and at the lowest cost. These reductions can be achieved using technology available today. Combinedcycle turbines, fuelled by natural gas, produce around half the CO2 emissions of coal-fired power, and are cheaper and quicker to build. It is estimated that there are reserves of natural gas in place equivalent to 60 years’ consumption at current ratesb and they are rising as new skills and technology unlock new unconventional gas resources. For these reasons, gas is looking to be an increasingly attractive resource in meeting the growing demand for energy, playing a greater role as a key part of the energy future. At the same time, alternative energies also have the potential to make a substantial contribution to the transition to a lower-carbon economy, but this will require investment, innovation and time. Currently, wind, solar, wave, tide and geothermal energy account for only around 1% of total global consumptionc. Even in the most aggressive scenario put forward by the IEA, these forms of energy are estimated to meet no more than 5% of total demand in 2030d. If industry and the market are to meet the world’s growing demand for energy in a sustainable way, governments will be required to set a stable and enduring framework. As part of this, governments will need to provide secure access for exploration and development of fossil fuel resources, define mutual benefits for resource owners and development partners, and establish and maintain an appropriate legal and regulatory environment, including a mechanism for recognizing and incorporating the cost of reducing carbon emissions.
a

World Energy Outlook 2009. ?OECD/IEA 2009, pages 622-623: ‘Reference Scenario, World’. The IEA’s reference scenario describes what would happen if, among other things, governments were to take no new initiatives bearing on the energy sector, beyond those already adopted by mid-2009. b BP Statistical Review of World Energy June 2009. This estimate is not based on proved reserves as defined by SEC rules. c Adapted from World Energy Outlook 2009. ?OECD/IEA 2009, page 74. The IEA’s 450 policy scenario assumes governments adopt commitments to limit the long-term concentration of greenhouse gases in the atmosphere to 450 parts per million of CO2 equivalent. d World Energy Outlook 2009. ?OECD/IEA 2009, page 212: ‘World primary energy demand by fuel in the 450 Scenario (Mtoe)’.

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Business review – Group overview

BP Annual Report and Accounts 2009 Business review

Our strategy
The priorities that drove our success in 2009 – safety, people and performance – remain the foundation of our agenda as we build on our momentum and work to further enhance our competitive position.
Our strategy is to invest competitively to grow oil and gas production while working to drive performance across the group through enhanced operating efficiency, capital efficiency and cost efficiency. To meet growing world demand, BP is committed to exploring, developing and producing more fossil fuel resources; manufacturing, processing and delivering better and more advanced products; and enabling the transition to a lower-carbon future. We aim to do this while operating safely, reliably and in compliance with the law. We strive to run our business within the discipline of a clear financial framework. In 2009, we improved our overall competitive performance by enhancing operating performance and reducing complexity and costs. We believe we can continue to compete successfully through our ability to access resources and deliver high-quality products and service to our customers. We intend to remain focused on the application of technology and developing relationships based on a commitment to long-term partnerships and mutual advantage. Our intention is to generate and sustain business momentum and growth through a rigorous process of continuous improvement and an ongoing focus on safety, people and performance. Safety, reliability, compliance and continuous improvement Safe, reliable and compliant operations remain the group’s first priority. A key enabler for this is the BP operating management system (OMS), which provides a common framework for all BP operations, designed to achieve consistency and continuous improvement in safety and efficiency. OMS includes mandatory practices, such as integrity management and incident investigation, which are designed to address particular risks. In addition, it enables each site to focus on the most important risks in its own operations and sets out procedures on how to manage them in accordance with the group-wide framework. Further information on our safety priorities and performance can be found on page 46. The right people, skills and capability It is vital that we develop and deploy people with the skills, capability and behaviours required to meet our objectives. Despite a tight global recruitment market for some of our core technical disciplines, we have been successful in building capacity and getting the right people with the right skills in the right place. We are now going further, strengthening the culture within BP through a commitment to continuous improvement in operations and enhancing the capabilities, technical expertise and organizational quality needed to drive performance. Our people strategy has already resulted in refreshed group leadership and senior management teams, recruitment focused on individuals with strong operational and technical expertise, and appropriate reward for performance at all levels.

Enhanced performance and efficiency Our strategy aims to create value for shareholders by investing to deliver growth in our Exploration and Production business together with enhanced efficiency and high-quality earnings and returns throughout our operations. In Exploration and Production, our strategy is to invest to grow production safely, reliably and efficiently. We intend to achieve this by strengthening our portfolio of leadership positions in the world’s most prolific hydrocarbon basins, enabled by the development and application of technology and the building of strong relationships based on mutual advantage. We also intend to sustainably drive cost and capital efficiency in accessing, finding, developing and producing resources, enabled by deep technical capability and a culture of continuous improvement. In Refining and Marketing, our strategic focus is on enhancing portfolio quality, integrating activities across value chains and performance efficiency. We expect to continue building our business around advantaged assets in material and significant energy markets while improving the safety and reliability of our operations. Our objective is to achieve sector-leading levels of performance on a sustainable basis. To achieve this, we need to continue upgrading the manufacturing capabilities within our integrated fuels value chains to achieve the best capacity utilization and margin capture. We continue to explore appropriate opportunities to deploy downstream capital into fastergrowing 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 and Accounts (see pages 11 to 13), we expect that the world will require a more diverse energy mix as the basis for a secure supply of energy over time. We intend to play a central role in meeting the world’s continued need for hydrocarbons, with our Exploration and Production and Refining and Marketing activities remaining at the core of our strategy. We are also creating long-term options for the future in new energy technology and low-carbon energy businesses. Current investment is focused on wind, solar and biofuels as potential sources of resource diversification for the world, and we are investing in carbon capture and storage as an enabling technology. We believe that this focused portfolio has the potential to be a material source of value creation for BP in the longer term (see pages 42 to 43). We are also enhancing our capabilities in natural gas, which is likely to play a greater role as a key part of the energy future. We intend to lead and shape this transition, including through the application of advanced technology to unlock sources of unconventional gas, while working to achieve sector-leading levels of return for our shareholders.

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BP Annual Report and Accounts 2009 Business review

Our performance
2009 has been a successful year for BP, with positive financial and operational momentum despite an extremely turbulent global financial environment.
Safety Good progress has been made on underpinning improved safety performance in 2009. Throughout the year, we continued to focus on training and enhancing procedures across the organization. Significantly, 2009 was an important year in the development of OMS. By the end of 2009, around 80% of our operating sites were using the system, including all our operated refineries and petrochemicals plants. (See Safety on page 46 for more information on OMS.) In 2009, a third-party-operated helicopter carrying contractors from BP’s Miller platform crashed in the North Sea, resulting in the tragic loss of 16 lives. In addition, BP sustained two fatalities within our own operations. We deeply regret the loss of these lives. Recordable injury frequency (RIF a measure of the number of , reported injuries per 200,000 hours worked) was 0.34, significantly below 2008 and 2007 levels of 0.43 and 0.48, respectively. Reported oil spills greater than one barrel were 234 in 2009 compared with 335 in 2008 and 340 in 2007. Our environmental measure that tracks greenhouse gas (GHG) emissionsa increased in 2009 to 65.0 million tonnes of carbon dioxide equivalent, compared with 61.4 million tonnes in 2008. The primary reason for this increase is the growth of our business, including the significant increase in our US refining throughputs, the start-up of our Tangguh LNG project in Indonesia and the continued success of our Gulf of Mexico deepwater operations, including Thunder Horse. People During 2009 we made further significant progress in generating a stronger performance focus and in fostering a culture that attributes more value to deep specialist skills and expertise. At the same time, we continued to improve operational efficiency and reduce overheads. Non-retail headcount was reduced by 4,400 (6%) in 2009. Overall, the number of employees (including retail staff) was reduced by 11,700 in 2009.

Performance Against the backdrop of the global recession, we delivered a strong performance in 2009. Profit and cash flow were lower than in 2008, due primarily to a much weaker price environment, although the impact was partially offset by better operational performance and lower costs across the group as we implemented our efficiency programmes. Notable achievements include: Exploration and Production ? Replacing 129% of our proved reserves, on a combined basis of subsidiaries and equity-accounted entities. ? Delivering a 5% underlying growth in productionb. ? Reducing unit production costs by 12%. ? Achieving a strong gas marketing and trading performance. ? Accessing new resources in Egypt, the Gulf of Mexico, Indonesia, Iraq and Jordan. ? Making the Tiber discovery in the Gulf of Mexico at a depth of over 35,000 feet, the deepest oil and gas discovery well ever drilled. ? Making three further discoveries in Block 31, Angola. ? Starting up Tangguh in Indonesia and six other major projects in the Gulf of Mexico, Trinidad and Russia. Refining and Marketing ? Restoring our overall performance so that it is once again competitive with our supermajor peers. ? Achieving a Solomon refining availabilityc of 93.6%, which is an increase of almost five percentage points compared with 2008. ? Reducing costs across the segment by more than 15%d. ? Delivering a strong supply and trading performance. ? Performing strongly in our international businesses, despite the weak environment. ? Delivering simplification and lower costs through integration in the fuels value chains. ? Simplifying the segment’s footprint in aviation and lubricants and completing the transfer of our US convenience retail business to a franchise operation. ? Successfully exiting from our ground fuels marketing business in Greece.
footnote a in Environment on page 47. Underlying production growth excludes the effect of entitlement changes in our production-sharing agreements (driven by changes in oil and gas prices) and the effect of OPEC quota restrictions. c Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime. d Based on Refining and Marketing’s share of production and manufacturing expenses plus distribution and administration expenses.
a See b

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Business review – Group overview

BP Annual Report and Accounts 2009 Business review

Selected financial and operating information
This information, insofar as it relates to 2009, has been extracted or derived from the audited consolidated financial statements of the BP group presented on pages 109 to 178. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes elsewhere herein.
$ million except per share amounts 2009 2008 2007 2006 2005

Income statement data Sales and other operating revenues from continuing operationsa Profit before interest and taxation from continuing operationsa Profit from continuing operationsa Profit for the year Profit for the year attributable to BP shareholders Capital expenditure and acquisitionsb Per ordinary share – cents Profit for the year attributable to BP shareholders Basic Diluted Profit from continuing operations attributable to BP shareholdersa Basic Diluted Dividends paid per share – cents – pence Ordinary share datac Average number outstanding of 25 cent ordinary shares (shares million undiluted) Average number outstanding of 25 cent ordinary shares (shares million diluted) Balance sheet data Total assets Net assets Share capital BP shareholders’ equity Finance debt due after more than one year Net debt to net debt plus equityd
a Excludes b

239,272 26,426 16,759 16,759 16,578 20,309

361,143 35,239 21,666 21,666 21,157 30,700

284,365 32,352 21,169 21,169 20,845 20,641

265,906 35,158 22,311 22,286 22,000 17,231

239,792 32,682 22,448 22,632 22,341 14,149

88.49 87.54 88.49 87.54 56.00 36.417 18,732 18,936 235,968 102,113 5,179 101,613 25,518 20%

112.59 111.56 112.59 111.56 55.05 29.387 18,790 18,963 228,238 92,109 5,176 91,303 17,464 21%

108.76 107.84 108.76 107.84 42.30 20.995 19,163 19,327 236,076 94,652 5,237 93,690 15,651 22%

109.84 109.00 109.97 109.12 38.40 21.104 20,028 20,195 217,601 85,465 5,385 84,624 11,086 20%

105.74 104.52 104.87 103.66 34.85 19.152 21,126 21,411 206,914 80,765 5,185 79,976 10,230 17%

Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2005 and 2006. 2008 included capital expenditure of $2,822 million and an asset exchange of $1,909 million, both in respect of our transaction with Husky, as well as capital expenditure of $3,667 million in respect of our transactions with Chesapeake (see page 53). 2007 included $1,132 million for the acquisition of Chevron’s Netherlands manufacturing company. Capital expenditure in 2006 included $1 billion in respect of our investment in Rosneft. All capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing. c The number of ordinary shares shown has been used to calculate per share amounts. d Net debt and the ratio of net debt to net debt plus equity ratio are non-GAAP measures. We believe that these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders.

Profits Profit attributable to BP shareholders for the year ended 31 December 2009 was $16,578 million, including inventory holding gains, net of tax, of $2,623 million and a net charge for non-operating items, after tax, of $1,067 million. In addition, fair value accounting effects had a favourable impact, net of tax, of $445 million relative to management’s measure of performance. Inventory holding gains and losses, net of tax, are described in footnote (a) on page 53. More information on non-operating items and fair value accounting effects can be found on pages 58-59. Profit attributable to BP shareholders for the year ended 31 December 2008 was $21,157 million, including inventory holding losses, net of tax, of $4,436 million and a net charge for non-operating items, after tax, of $796 million. In addition, fair value accounting effects had a favourable impact, net of tax, of $146 million relative to management’s measure of performance.

Profit attributable to BP shareholders for the year ended 31 December 2007 was $20,845 million, including inventory holding gains, net of tax, of $2,475 million and a net charge for non-operating items, after tax, of $373 million. In addition, fair value accounting effects had an unfavourable impact, net of tax, of $198 million relative to management’s measure of performance. The primary additional factors affecting profit for 2009, compared with 2008, were lower realizations and refining margins, partly offset by higher production, stronger operational performance and lower costs. The primary additional factors reflected in profit for 2008, compared with 2007, were higher realizations, a higher contribution from the gas marketing and trading business, improved oil supply and trading performance, improved marketing performance and strong cost management; however, these positive effects were partly offset by weaker refining margins, particularly in the US, higher production taxes, higher depreciation, and adverse foreign exchange impacts.

16

BP Annual Report and Accounts 2009 Business review

Production and net proved oil and natural gas reserves The following table shows our production for the past five years and the estimated net proved oil and natural gas reserves at the end of each of those years. Production and net proved reservesa
2009f 2008 2007 2006 2005

Crude oil production for subsidiaries (thousand barrels per day) Crude oil production for equity-accounted entities (thousand barrels per day) Natural gas production for subsidiaries (million cubic feet per day) Natural gas production for equity-accounted entities (million cubic feet per day) Estimated net proved crude oil reserves for subsidiaries (million barrels)b Estimated net proved crude oil reserves for equity-accounted entities (million barrels)c Estimated net proved natural gas reserves for subsidiaries (billion cubic feet)d Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet)e
a

1,400 1,135 7,450 1,035 5,658 4,853 40,388 4,742

1,263 1,138 7,277 1,057 5,665 4,688 40,005 5,203

1,304 1,110 7,222 921 5,492 4,581 41,130 3,770

1,351 1,124 7,412 1,005 5,893 3,888 42,168 3,763

1,423 1,139 7,512 912 6,360 3,205 44,448 Business review – Group overview 3,856

Crude oil includes natural gas liquids (NGLs) and condensate. Production and proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations. 23 million barrels (21 million barrels at 31 December 2008 and 20 million barrels at 31 December 2007) in respect of the 30% minority interest in BP Trinidad and Tobago LLC. Includes 243 million barrels (216 million barrels at 31 December 2008 and 210 million barrels at 31 December 2007) in respect of the 6.86% minority interest in TNK-BP (6.80% at 31 December 2008 and 6.51% at 31 December 2007). d Includes 3,068 billion cubic feet of natural gas (3,108 billion cubic feet at 31 December 2008 and 3,211 billion cubic feet at 31 December 2007) in respect of the 30% minority interest in BP Trinidad and Tobago LLC. e Includes 131 billion cubic feet (131 billion cubic feet at 31 December 2008 and 68 billion cubic feet at 31 December 2007) in respect of the 5.79% minority interest in TNK-BP (5.92% at 31 December 2008 and 5.88% at 31 December 2007). f On 31 December 2008, the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than one per cent to BP’s total proved reserves.
b Includes c

Total net proved reserves 2009 (million barrels of oil equivalent)

ab

10,511

Liquidsc Natural gas 2009 was our 17th consecutive year of delivering reported reserves replacement of more than 100%.

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 productionsharing 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 124. In 2008, we completed an asset exchange with Husky Energy Inc., and asset purchases from Chesapeake Energy Corporation as described on page 53. In 2007, BP acquired Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The acquisition included Chevron’s 31% minority shareholding in Nerefco and certain associated assets. Disposal proceeds were $4,267 million, which included $1,903 million from the sale of the Coryton refinery and $605 million from the sale of our exploration and production gas infrastructure business in the Netherlands.

7,781

a b

Combined basis of subsidiaries and equity-accounted entities, on a basis consistent with general industry practice. On 31 December 2008 the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than 1% to BP‘s total proved reserves. c Crude oil, condensate and natural gas liquids.

During 2009, 1,908 million barrels of oil and natural gas, on an oil equivalenta basis (mmboe), were added, excluding purchases and sales, to BP’s proved reserves (1,113mmboe for subsidiaries and 795mmboe for equity-accounted entities). At 31 December 2009, BP’s proved reserves were 18,292mmboe (12,621mmboe for subsidiaries and 5,671mmboe for equity-accounted entities). Our proved reserves in subsidiaries are located in the US (45%), South America (15%), Australasia (10%), Africa (10%) and the UK (9%). Our proved reserves in equity-accounted entities are located in Russia (69%), South America (21%), and Rest of Asia (9%).
a

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

17

Business review

BP Annual Report and Accounts 2009 Business review

Risk factors
We urge you to consider carefully the risks described below. If any of these risks occur, we might fail to deliver on our strategic priorities, which are expressed in terms of safety, people and performance (see page 14). Our business, financial condition and results of operations could suffer and the trading price and liquidity of our securities could decline. In the current uncertain financial and economic environment, certain risks may gain more prominence either individually or when taken together. Oil and gas prices are likely to remain volatile with average prices and margins influenced by changes in supply and demand. This is likely to exacerbate competition in all businesses, which may impact costs and margins. At the same time, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal and regulatory frameworks for the oil and gas industry, including the risk of increased taxation. The financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. Any of these factors may affect our results of operations, financial condition and liquidity. Capital markets have regained some confidence after the recent crisis but if there are extended periods of constraints in these markets, at a time when cash flows from our business operations may be under pressure, our ability to maintain our long-term investment programme may be impacted with a consequent effect on our growth rate, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements. Our system of risk management identifies and provides the response to risks of group significance through the establishment of standards and other controls. Inability to identify, assess and respond to risks through this and other controls could lead to an inability to capture opportunities, threats materializing, inefficiency and non-compliance with laws and regulations. The risks are categorized against the following areas: strategic; compliance and control; and operational. Strategic risks Access and renewal Successful execution of our group plan depends critically on implementing activities to renew and reposition our portfolio. The challenges to renewal of our upstream portfolio are growing due to increasing competition for access to opportunities globally. Lack of material positions in new markets and/or inability to complete disposals could result in an inability to grow or even maintain our production. Prices and markets Oil, gas and product prices are subject to international supply and demand. Political developments and the outcome of meetings of OPEC can particularly affect world supply and oil prices. Previous oil price increases have resulted in increased fiscal take, cost inflation and more onerous terms for access to resources. As a result, increased oil prices may not improve margin performance. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to

further reviews for impairment of the group’s oil and natural gas properties. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the group’s results of operations in the period in which it occurs. Rapid material and/or sustained change in oil, gas and product prices can impact the validity of the assumptions on which strategic decisions are based and, as a result, the ensuing actions derived from those decisions may no longer be appropriate. A prolonged period of low oil prices may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate and may impact shareholder returns, including dividends and share buybacks, or share price. Periods of global recession could impact the demand for our products, the prices at which they can be sold and affect the viability of the markets in which we operate. Refining profitability can be volatile, with both periodic oversupply and supply tightness in various regional markets. Sectors of the chemicals industry are also subject to fluctuations in supply and demand within the petrochemicals market, with a consequent effect on prices and profitability. Climate change and carbon pricing Compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, taxes, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted. Our commitment to the transition to a lower-carbon economy may create expectations for our activities, and the level of participation in alternative energies carries reputational, economic and technology risks. Socio-political We have operations in countries where political, economic and social transition is taking place. Some countries have experienced political instability, changes to the regulatory environment, expropriation or nationalization of property, civil strife, strikes, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas or our production to decline and could cause us to incur additional costs. In particular, our investments in Russia could be adversely affected by heightened political and economic environment risks. We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged. Competition The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency. The implementation of group strategy requires continued technological advances and innovation including advances in exploration, production, refining, petrochemicals manufacturing technology and advances in technology related to energy usage. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged the industry.

18

BP Annual Report and Accounts 2009 Business review

Investment efficiency Our organic growth is dependent on creating a portfolio of quality options and investing in the best options. Ineffective investment selection could lead to loss of value and higher capital expenditure. Reserves replacement Successful execution of our group strategy depends critically on sustaining long-term reserves replacement. If upstream resources are not progressed in a timely and efficient manner, we will be unable to sustain long-term replacement of reserves. Liquidity, financial capacity and financial exposure The group has established a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity and to constrain the level of assessed capital at risk for the purposes of positions taken in financial instruments. Failure to operate within our financial framework could lead to the group becoming financially distressed leading to a loss of shareholder value. Commercial credit risk is measured and controlled to determine the group’s total credit risk. Inability to determine adequately our credit exposure could lead to financial loss. A credit crisis affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth. Crude oil prices are generally set in US dollars, while sales of refined products may be in a variety of currencies. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues. For more information on financial instruments and financial risk factors see Financial statements – Note 24 on page 144. Compliance and control risks Regulatory The oil industry is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental and health and safety protection controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. We buy, sell and trade oil and gas products in certain regulated commodity markets. Failure to respond to changes in trading regulations could result in regulatory action and damage to our reputation. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, or we could incur additional costs. For more information on environmental regulation, see Environment on pages 47-49. 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 99-100.

Liabilities and provisions Changes in the external environment, such as new laws and regulations, market volatility or other factors, could affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities. Reporting External reporting of financial and non-financial data is reliant on the integrity of systems and people. Failure to report data accurately and in compliance with external standards could result in regulatory action, legal liability and damage to our reputation. Operational risks Process safety Inherent in our operations are hazards that require continuous oversight and control. There are risks of technical integrity failure and loss of containment of hydrocarbons and other hazardous material at operating sites or pipelines. Failure to manage these risks could result in injury or loss of life, environmental damage, or loss of production and could result in regulatory action, legal liability and damage to our reputation. Personal safety Inability to provide safe environments for our workforce and the public could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation. Environmental If we do not apply our resources to overcome the perceived trade-off between global access to energy and the protection or improvement of the natural environment, we could fail to live up to our aspirations of no or minimal damage to the environment and contributing to human progress. Failure to comply with environmental laws, regulations and permits could lead to damage to the environment and could result in regulatory action, legal liability and damage to our reputation. Security Security threats require continuous oversight and control. Acts of terrorism against our plants and offices, pipelines, transportation or computer systems could severely disrupt business and operations and could cause harm to people. Product quality Supplying customers with on-specification products is critical to maintaining our licence to operate and our reputation in the marketplace. Failure to meet product quality standards throughout the value chain could lead to harm to people and the environment and loss of customers. Drilling and production Exploration and production require high levels of investment and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of an oil or natural gas field. The cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements. Transportation All modes of transportation of hydrocarbons involve inherent risks. A loss of containment of hydrocarbons and other hazardous material could occur during transportation by road, rail, sea or pipeline. This is a significant risk due to the potential impact of a release on the environment and people and given the high volumes involved.

19

Business review

Business review – Group overview

BP Annual Report and Accounts 2009 Business review

Major project delivery Successful execution of our group plan depends critically on implementing the activities to deliver the major projects over the plan period. Poor delivery of any major project that underpins production growth and/or a major programme designed to enhance shareholder value could adversely affect our financial performance. Digital infrastructure The reliability and security of our digital infrastructure are critical to maintaining our business applications availability. A breach of our digital security could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment and breaches of regulations. Business continuity and disaster recovery Contingency plans are required to continue or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed timeframe would prolong the impact of any disruption and could severely affect business and operations. Crisis management Crisis management plans and capability are essential to deal with emergencies at every level of our operations. If we do not respond or are perceived not to respond in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted. People and capability Successful recruitment of new staff, employee training, development and long-term renewal of skills, in particular technical capabilities such as petroleum engineers and scientists, are key to implementing our plans. Inability to develop the human capacity and capability across the organization could jeopardize performance delivery. Treasury and trading activities In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation.

Our systems of control
The board is responsible for the direction and oversight of BP. The board has set an overall goal for BP which is to maximize long-term shareholder , value through the allocation of its resources to activities in the oil, natural gas, petrochemicals and energy businesses. The board delegates authority for achieving this goal to the group chief executive (GCE). The board maintains five permanent committees that are composed entirely of non-executives. The board and its committees monitor, among other things, the identification and management of the group’s risks – both financial and non-financial. During the year, the board’s committees engaged with executive management, the general auditor and other monitoring and assurance providers (such as the group compliance and ethics officer and the external auditor) on a regular basis as part of their oversight of the group’s risks. Significant incidents that occurred and management’s response to them were considered by the appropriate committee and reported to the board. (See Board performance report on pages 69 to 80.) 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 18 to 20). Key elements of our system of internal control are: the control environment; the management of risk and operational performance (including in relation to financial reporting); and the management of people and individual performance. Controls include the BP code of conduct, our leadership framework and our principles for delegation of authority, which are designed to make sure employees understand what is expected of them. As part of the control system, the GCE’s senior team – known as the executive team – is supported by sub-committees that are responsible for and monitor specific group risks. These include the group operations risk committee (GORC), the group financial risk committee (GFRC), the group people committee (GPC), and the group disclosures committee (GDC), which reviews the disclosures, controls and procedures over reporting. Operations and investments are conducted and reported in accordance with, and associated risks are thereby managed through, relevant standards and processes. These range from group standards, which set out processes for major areas such as safety and integrity, through to detailed administrative instructions on issues such as fraud reporting. The GCE conducts regular performance reviews with the segments and key functions to monitor performance and the management of risk and to intervene if necessary. People management is based on performance objectives, through which individuals are accountable for delivering specific elements of the group plan within agreed boundaries.

20

BP Annual Report and Accounts 2009 Business review

Forward-looking statements
In order to utilize the ‘Safe Harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995, BP is providing the following cautionary statement. This document contains certain forward-looking statements with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in Business review (pages 10-63), including under the headings ‘Outlook’, with regard to strategy, management aims and objectives, future capital expenditure, the future scrip dividend programme, future hydrocarbon production volume and the group’s ability to satisfy its long-term sales commitments from future supplies available to the group, date(s) or period(s) in which production is scheduled or expected to come onstream or a project or action is scheduled or expected to begin or be completed, capacity of planned plants or facilities and impact of health, safety and environmental regulations; (ii) the statements in Business review (pages 10-52) 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 5363) 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 18-20. In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.

Statements regarding competitive position
Statements referring to BP’s competitive position are based on the company’s belief and, in some cases, rely on a range of sources, including investment analysts’ reports, independent market studies and BP’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.

Further note on certain activities
During the period covered by this report, non-US subsidiaries or other non-US entities of BP, conducted limited activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism (‘Sanctioned Countries’). These activities continue to be insignificant to the group’s financial condition and results of operations. BP has interests in, and is the operator of, two fields and a pipeline located outside Iran in which the National Iranian Oil Company (NIOC) and an affiliated entity have interests. BP buys crude oil, refinery and petrochemicals feedstocks, blending components and LPG of Iranian origin or from Iranian counterparties primarily for sale to third parties in Europe and a small portion is used by BP in its own facilities in South Africa and Europe. Until recently BP held an equity interest in an Iranian joint venture that has a blending facility and markets lubricants for sale to domestic consumers. In January 2010, BP restructured its interest in the joint venture and currently maintains its involvement through certain contractual arrangements, which it keeps under review in light of pending legislative developments in the US. BP does not seek to obtain from the government of Iran licences or agreements for oil and gas projects in Iran, is not conducting any technical studies in Iran and does not own or operate any refineries or petrochemicals plants in Iran. BP sells lubricants in Cuba through a 50:50 joint venture there and in 2009 purchased a cargo of naphtha from a non-Cuban counterparty that was loaded in Cuba. In Syria, lubricants are sold through a distributor and BP obtains crude oil and refinery feedstocks for sale to third parties in Europe. In addition, BP sells crude oil and refined products into Syria. BP supplies fuels and lubricants to airlines and shipping companies from Sanctioned Countries at airports and ports located outside these countries. BP monitors its activities with Sanctioned Countries and keeps them under review to ensure compliance with applicable laws and regulations of the US and other countries where BP operates. Business review – Group overview

21

Business review

BP Annual Report and Accounts 2009 Business review

Exploration and Production
Our Exploration and Production segment includes upstream and midstream activities in 30 countries, including Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), Norway, the UK, the US and locations within Asia Pacific, Latin America, North Africa and the Middle East, as well as gas marketing and trading activities, primarily in Canada, Europe and the US. Upstream activities involve oil and natural gas exploration and field development and production. Our exploration programme is currently focused around Angola, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea, Oman and onshore US. Major development areas include Algeria, Angola, Asia Pacific, Azerbaijan, Egypt and the deepwater Gulf of Mexico. During 2009, production came from 21 countries. The principal areas of production are Angola, Asia Pacific, Azerbaijan, Egypt, Latin America, the Middle East, Russia, Trinidad, the UK and the US. Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing facilities and transportation, and our NGL extraction businesses in the US, the UK, Canada and Indonesia. Our most significant midstream pipeline interests are the Trans-Alaska Pipeline System in the US, the Forties Pipeline System and the Central Area Transmission System pipeline, both in the UK sector of the North Sea, the South Caucasus Pipeline (SCP), which takes gas from Azerbaijan through Georgia to the Turkish border and the Baku-Tbilisi-Ceyhan pipeline, running through Azerbaijan, Georgia and Turkey. Major LNG activities are located in Trinidad, Indonesia and Australia. BP is also investing in the LNG business in Angola. Additionally, our activities include the marketing and trading of natural gas, power and natural gas liquids. These activities provide routes into liquid markets for BP’s gas and power, and generate margins and fees associated with the provision of physical and financial products to third parties and additional income from asset optimization and trading. Our oil and natural gas production assets are located onshore and offshore and include wells, gathering centres, in-field flow lines, processing facilities, storage facilities, offshore platforms, export systems (e.g. transit lines), pipelines and LNG plant facilities. Upstream operations in Argentina, Bolivia, Chile, Abu Dhabi, Kazakhstan, Venezuela and Russia, as well as some of our operations in Angola, Canada and Indonesia, are conducted through equity-accounted entities. Our market The market environment in which we operate was particularly challenging during 2009, with crude oil and natural gas prices at lower levels than we have experienced in recent history. The annual average crude oil price declined in 2009 for the first time since 2001, breaking an unprecedented string of seven consecutive annual increases. Dated Brent for the year averaged $61.67 per barrel, about 37% below 2008’s record average of $97.26 per barrel. Prices were lowest at the beginning of the year as the world economy grappled with the sharpest downturn in modern economic history. In 2010, we expect oil market movements to continue to be driven by developments in the world economy, by their resulting implications for oil consumption, and by OPEC production decisions. Natural gas prices weakened in 2009 and were volatile. The average US Henry Hub First of Month Index fell to $3.99/mmBtu in 2009, a 56% decrease from the record $9.04/mmBtu average seen in 2008.

Recession-induced demand declines and strong production caused prices to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in September. However, over the course of the year, the impact was partly offset as US regional gas price differentials narrowed, driven partly by the Rockies Express Pipeline extension allowing the transportation of larger quantities of gas out of the Rockies area. Reduced imports from Canada, slowing US production growth and cooler temperatures allowed prices to recover to $4.49/mmBtu by the end of the year. Prices at the UK National Balancing Point similarly fell to an average of 30.85 pence per therm, 47% below the 2008 average price of 58.12 pence per therm. In 2009, there was a switch of uncontracted LNG cargoes from Asia to Europe, reflecting a shift in relative spot prices. LNG imports to Europe have competed with pipeline imports, where the gas price is often indexed to oil prices, as well as with marginal European gas production. On an energy equivalent basis, gas prices were often at or below parity with coal, which led to gas displacing coal in power generation in Europe and the US. In the event of any recovery in the economy in 2010, both the US and UK gas markets are expected to benefit although the price upside is likely to be constrained as a result of a record amount of LNG expected to become available globally. Our strategy Our strategy is to invest to grow production safely, reliably and efficiently by: ? Strengthening our portfolio of leadership positions in the world’s most prolific hydrocarbon basins, enabled by the development and application of technology and strong relationships based on mutual advantage. ? Sustainably driving cost and capital efficiency in accessing, finding, developing and producing resources, enabled by deep technical capability and a culture of continuous improvement. Our performance In Exploration and Production, safety, both personal and process, remains our highest priority. 2009 brought further improvements in personal safety with our reported recordable injury frequency improving from 0.43 in 2008 to 0.39 in 2009. We also achieved improvements in the number of reported process safety-related incidents and a significant reduction in the number of reported spills. BP’s operating management system (OMS) provides us with a systematic framework for safe, reliable and efficient operations. Throughout 2009, OMS helped us to deliver continuous improvement in the way we manage our people, processes, plant and performance. From onshore production facilities to offshore platforms, a total of 47 exploration and production sites had completed their transition to OMS by the end of 2009. The remaining seven sites are on track to transition to OMS in 2010.

22

BP Annual Report and Accounts 2009 Business review

We continually seek to access resources and in 2009 this included Iraq, where, together with China National Petroleum Corporation (CNPC), we entered into a contract with the state-owned South Oil Company (SOC) to expand production from the Rumaila field; Jordan, where on 3 January 2010, we received approval from the Government of Jordan to join the state-owned National Petroleum Company (NPC) to exploit the onshore Risha concession in the north east of the country; further access in Egypt, where we were awarded two blocks in an offshore area of the Nile Delta; Indonesia, where we signed a production-sharing agreement (PSA) for the exploration and development of coalbed methane in the Sanga-Sanga block, supplying gas to Indonesia’s largest LNG export facility and, subject to Government of Indonesia approval, farmed into Chevron’s West Papua I & III blocks; and the Gulf of Mexico, where we were awarded 61 blocks through the Outer Continental Shelf Lease Sales 208 and 210. In 2009, we were involved in a number of discoveries. The most significant of these were in the deepwater Gulf of Mexico with the Tiber well; Angola, where we made three further discoveries in the ultra deepwater Block 31; and Canada, where we discovered natural gas with the Ellice J27 well. Seven major projects came onstream. We continue to grow our position and leverage our experience as the largest producer in the Gulf of Mexico, starting up three projects ahead of schedule, including the second phase of Atlantis. In addition, production commenced at our Savonette field in Trinidad, at our Tangguh LNG project in Indonesia and, through TNK-BP we saw the start-up of a further two projects, in the , northern hub of Kamennoye, and the Urna and Ust-Tegus fields in the Uvat area. Production from our established centres – including the North Sea, Alaska, North America Gas and Trinidad – was on plan, with improved operating efficiency for the segment as a whole, and we had strong production growth in the Gulf of Mexico, including excellent performance from Thunder Horse. Production from Egypt and TNK-BP also made a strong contribution to our growth. Production for the year was up more than 4% from last year. After adjusting for the effect of entitlement changes in our PSAs and the effect of OPEC quota restrictions, underlying production growtha was 5% higher than 2008.
a

We also reduced unit production costs through a combination of highgrading 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 55-56. Total capital expenditure including acquisitions and asset exchanges in 2009 was $14.9 billion (2008 $22.2 billion and 2007 $14.2 billion). In 2009, capital expenditure included $306 million relating to the award of the contract to redevelop the Rumaila field in Iraq. Development expenditure of subsidiaries incurred in 2009, excluding midstream activities, was $10,396 million, compared with $11,767 million in 2008 and $10,153 million in 2007. Key statistics
$ million 2009 2008 2007

Sales and other operating revenuesa Replacement cost profit before interest and taxb Total assets Capital expenditure and acquisitions

57,626 24,800 140,149 14,896

86,170 38,308 136,665 22,227

65,740 27,602 125,736 14,207
$ per barrel

Average BP liquids realizationsc d

56.26

90.20

67.45

$ per thousand cubic feet

Average BP natural gas realizationsc
a Includes sales between businesses. b Includes profit after interest and tax of c

3.25

6.00

4.53

Underlying production growth excludes the effect of entitlement changes in our PSAs (driven by changes in oil and gas prices) and the effect of OPEC quota restrictions.

equity-accounted entities. Realizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities. d Crude oil and natural gas liquids.

The table below presents our average sales price per unit of production.
$ per unit of productiona Europe North America Rest of Europe Rest of North America South America Africa Asia Australasia Total group average

UK

US

Russia

Rest of Asia

Average sales priceb 2009 Liquidsc Gas 2008 Liquidsc Gas 2007 Liquidsc Gas 62.19 4.68 89.82 8.41 69.17 6.40 60.73 7.62 93.77 6.96 70.41 5.84 53.68 3.07 89.22 6.77 64.18 5.43 30.77 3.53 64.42 7.87 48.24 6.24 52.48 2.50 91.61 4.90 65.54 3.25 57.40 3.61 89.44 4.46 67.81 3.93 – – – – – – 61.27 3.30 97.20 3.63 73.00 3.05 57.22 5.25 86.33 9.22 70.56 5.96 56.26 3.25 90.20 6.00 67.45 4.53

a Units of production are barrels for liquids and thousands of cubic feet for gas. b Realizations are based on sales of consolidated subsidiaries only (including transfers c

between businesses), which excludes equity-accounted entities.

Crude oil and natural gas liquids.

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Business review

Business review

BP Annual Report and Accounts 2009 Business review

The table below presents our average production cost per unit of production.
$ per unit of productiona Europe North America Rest of Europe Rest of North America South America Africa Asia Australasia Total group average

UK

US

Russia

Rest of Asia

The average production cost per unit of productiona 2009 2008 2007
a Units

12.38 12.19 14.00

10.72 8.74 7.17

7.26 9.02 9.03

14.45 15.35 14.04

2.20 2.34 2.69

6.05 6.72 6.43

– – –

4.35 5.24 3.81

1.60 1.74 1.75

6.39 7.24 7.14

of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes; and are based on production cost of consolidated subsidiaries only, which excludes equity-accounted entities.

Outlook Our priorities remain the same – safety, people and performance, focusing on the delivery of safe, reliable and efficient operations. In 2010, we aim to use the momentum generated in 2009 to continue to improve operational, cost and capital efficiency, while ensuring we maintain our priorities of safe, reliable and efficient operations. We intend to continue to focus on building personnel and technological capability for the future. We believe our portfolio of assets is strong and well positioned to compete and grow in a range of external conditions. Also in 2010, we intend to create a centralized developments organization to deliver our major projects. By bringing our project expertise into one team, we expect to continue our drive for improved capital efficiency by fully optimizing our project designs and improving project execution. Upstream activities Exploration The group explores for oil and natural gas under a wide range of licensing, joint venture and other contractual agreements. We may do this alone or, more frequently, with partners. BP acts as operator for many of these ventures. Our exploration and appraisal costs, excluding lease acquisitions, in 2009 were $2,805 million, compared with $2,290 million in 2008 and $1,892 million in 2007. These costs include exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs, which are charged to income as incurred. Approximately 68% of 2009 exploration and appraisal costs were directed towards appraisal activity. In 2009, we participated in 503 gross (107 net) exploration and appraisal wells in 12 countries. The principal areas of exploration and appraisal activity were Angola, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea, Oman and onshore US. Total exploration expense in 2009 of $1,116 million (2008 $882 million and 2007 $756 million) included the write-off of expenses related to unsuccessful drilling activities in the deepwater Gulf of Mexico ($391 million), India ($31 million), Angola ($28 million), Egypt ($27 million), and others ($31 million). In most cases, reserves booking from new discoveries will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling.

Reserves and production Resource progression BP manages its hydrocarbon resources in three major categories: prospect inventory, contingent resources and proved reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the contingent resources category. The contingent resources move through various sub-categories as their technical and commercial maturity increases through appraisal activity. At the point of final investment decision, most proved reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s proved reserves depends on a later phase of activity, only that portion of proved reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will typically occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking of proved reserves to the start of production. Changes to proved reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity. Contingent resources in a field will only be recategorized as proved reserves when all the criteria for attribution of proved status have been met and the proved reserves are included in the business plan and scheduled for development, typically within five years. Where, on occasion, the group decides to book proved reserves where development is scheduled to commence after five years, these proved reserves will be booked only where they satisfy the SEC’s criteria for attribution of proved status. There are material volumes of proved undeveloped reserves in Angola, Trinidad, the US, and Canada which are part of ongoing development activities for which BP has a historical track record of completing comparable projects. In all cases, the volumes are being progressed as part of an adopted development plan which calls for drilling of wells over an extended period of time given the magnitude of the development. In 2009, we converted approximately 2,061mmboe proved undeveloped reserves to proved developed reserves through ongoing investment in our upstream development activities. Total development expenditure in Exploration and Production, excluding midstream activities, was $12,392 million in 2009 ($10,396 million for subsidiaries and $1,996 million for equity-accounted entities). The major areas converted in 2009 were Azerbaijan, Indonesia, Russia, Trinidad and the US.

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BP Annual Report and Accounts 2009 Business review

Governance BP’s centrally controlled process for proved reserves estimation approval forms part of a holistic and integrated system of internal control. It consists of the following elements: ? Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner. ? Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects. ? Internal Audit, whose role includes systematically examining the effectiveness of the group’s financial controls designed to assure the reliability of reporting and safeguarding of assets and examining the group’s compliance with laws, regulations and internal standards. ? Approval hierarchy, whereby proved reserves changes above certain threshold volumes require central authorization and periodic reviews. The frequency of review is determined according to field size and ensures that more than 80% of the BP proved reserves base undergoes central review every two years and more than 90% is reviewed centrally every four years. BP’s segment resources authority is the petroleum engineer primarily responsible for overseeing the preparation of the reserves estimate. He has over 35 years of diversified industry experience with the past 10 spent as the head of the reservoir management function within BP. He is a member of the Society of Petroleum Engineers (SPE) and the Institute of Materials, Minerals and Mining. On the retirement of the current

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BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice. BP only applies technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. BP applies high resolution seismic data for the identification of reservoir extent and fluid contacts only where there is an overwhelming track record of success in its local application. In certain deepwater fields, such as fields in the Gulf of Mexico, BP has booked proved reserves before production flow tests are conducted, in part because of the significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring and delineating reservoir properties without the need for flow tests. To determine reasonable certainty of commercial recovery, BP employs a general method of reserves assessment that relies on the integration of three types of data: (1) well data used to assess the local characteristics and conditions of reservoirs and fluids; (2) field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control; and (3) data from relevant analogous fields. Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. BP considers the integration of this data in certain cases to be superior to a flow test in providing understanding of overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be determined over a greater volume than the localized volume of investigation associated with a short-term flow test. There is a strong track record of proved reserves recorded using these methods, validated by actual production levels.

segment resources authority in 2010, his responsibilities for reserves estimation, governance and compliance will be taken by the current vice president of segment reserves. The current vice president of segment reserves has over 25 years of diversified industry experience with the past seven spent managing the governance and compliance of BP’s reserves estimation. He is a sitting member of the SPE Oil and Gas Reserves Committee and the United Nations Economic Commission for Europe Expert Group on Resource Classification. For the executive directors and senior management, no specific portion of compensation bonuses is directly related to proved reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Exploration and Production segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures. BP’s variable pay programme for the other senior managers in the Exploration and Production segment is based on individual performance contracts. Individual performance contracts are based on agreed items from the business performance plan, one of which, if chosen, could relate to proved reserves. Proved reserves replacement Total hydrocarbon proved reserves, on an oil equivalent basis including equity-accounted entities, comprised 18,292mmboe (12,621mmboe for subsidiaries and 5,671mmboe for equity-accounted entities) at 31 December 2009, an increase of 0.8% (increase of 0.5% for subsidiaries and increase of 1.5% for equity-accounted entities) compared with 31 December 2008. Natural gas represents about 43% (55% for subsidiaries and 14% for equity-accounted entities) of these reserves. The increase includes a net decrease from acquisitions and divestments of 282mmboe, (59mmboe net decrease for subsidiaries and 223mmboe net decrease for equity-accounted entities) largely comprising a number of assets in Bolivia, Indonesia, Kazakhstan, Pakistan and the UK. The proved reserves replacement ratio is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions and discoveries, and may be expressed as a replacement ratio excluding acquisitions and divestments or as a total replacement ratio including acquisitions and divestments. For 2009 the proved reserves replacement ratio excluding acquisitions and divestments was 129% (121% in 2008 and 112% in 2007) for subsidiaries and equity-accounted entities, 112% for subsidiaries alone and 164% for equity-accounted entities alone. In 2009, net additions to the group’s proved reserves (excluding production, sales and purchases of reserves-in-place and equityaccounted entities) amounted to 1,113mmboe (795mmboe for equityaccounted 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 equityaccounted entities were in Argentina (Cerro Dragon, Cuenca Marina Austral) and in Russia (Kamennoye, Samatlor).

Business review

BP Annual Report and Accounts 2009 Business review

Compliance International Financial Reporting Standards (IFRSs) do not provide specific guidance on reserves disclosures. BP estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins as issued by the SEC staff. On 31 December 2008, the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than 1% to BP’s total proved reserves. The reasons for the increase are primarily due to the application of reliable technologies and inclusion of proved reserves more than one spacing away from existing penetrations as discussed below. By their nature, there is always some risk involved in the ultimate development and production of proved reserves, including, but not limited to, final regulatory approval, the installation of new or additional infrastructure as well as changes in oil and gas prices, changes in operating and development costs and the continued availability of additional development capital. All the group’s proved reserves held in subsidiaries and equity-accounted entities are estimated by the group’s petroleum engineers. Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where title to the hydrocarbons is not conferred, such as PSAs. In a concession, the consortium of which we are a part is entitled to the proved reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the proved reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. Fourteen percent of our proved reserves are associated with PSAs. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam. We disclose our share of proved reserves held in equityaccounted entities (jointly controlled entities and associates), although we do not control these entities or the assets held by such entities. Production Our total hydrocarbon production during 2009 averaged 3,998 thousand barrels of oil equivalent per day (mboe/d). This comprised 2,684mboe/d for subsidiaries and 1,314mboe/d for equity-accounted entities, an increase of 6.6% and a decrease of 0.5% respectively compared with 2008. For subsidiaries, 40% of our production was in the US, 17% in Trinidad and 10% in the UK. For equity-accounted entities, 71% of production was from Russia, 14% in the United Arab Emirates and 11% in Argentina. The strong growth in production in 2009 benefited by about 40mboe/d on an annual basis from a combination of the absence of a significant hurricane season and from the make-up of a prior period underlift. As a result, we expect production in 2010 to be slightly lower than in 2009. The actual growth rate will depend on a number of factors, including our pace of capital spending, the efficiency of that spend, the oil price and its impact on PSAs, as well as OPEC quota restrictions. The group and its equity-accounted entities have numerous longterm sales commitments in their various business activities, all of which are expected to be sourced from supplies available to the group which are not subject to priorities, curtailments or other restrictions. No single contract or group of related contracts is material to the group.

The following tables show BP’s estimated net proved reserves as at 31 December 2009. Estimated net proved reserves of liquids at 31 December 2009a b
million barrels Developed Undeveloped Total

UK Rest of Europe US Rest of North America South America Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total

403 83 1,862 11 49 422 182 58 3,070 3,121 6,191

291 184 1,211 1 56 454 334 57 2,588 1,732 4,320

694 267 3,073c 12 105d 876 516 115 5,658 4,853e 10,511

Estimated net proved reserves of natural gas at 31 December 2009a b
billion cubic feet Developed Undeveloped Total

UK Rest of Europe US Rest of North America South America Africa Rest of Asia Australasia Subsidiaries Equity-accounted entities Total

1,602 49 9,583 716 3,177 1,107 1,579 3,219 21,032 3,035 24,067

670 397 5,633 453 7,393 1,454 249 3,107 19,356 1,707 21,063

2,272 446 15,216 1,169 10,570f 2,561 1,828 6,326 40,388 4,742g 45,130

Net proved reserves on an oil equivalent basis
million barrels of oil equivalent Developed Undeveloped Total

Subsidiaries Equity-accounted entities Total
a

6,696 3,644 10,340

5,925 2,027 7,952

12,621 5,671 18,292

Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations. We disclose our share of reserves held in jointly controlled entities and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities. b The 2009 marker prices used were Brent $59.91/bbl (2008 $36.55/bbl and 2007 $96.02/bbl) and Henry Hub $3.82/mmBtu (2008 $5.63/mmBtu and 2007 $7.10/mmBtu). c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 68 million barrels on which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. d Includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. e Includes 243 million barrels of crude oil in respect of the 6.86% minority interest in TNK-BP. f Includes 3,068 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. g Includes 131 billion cubic feet of natural gas in respect of the 5.79% minority interest in TNK-BP.

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BP Annual Report and Accounts 2009 Business review

The following tables show BP’s net production by major field for 2009, 2008 and 2007. Liquids
thousand barrels per day BP net share of productiona Field or area 2009 2008 2007

UKb

ETAPc Foinavend Other Various

Total UK Norway Total Rest of Europe Total Europe Alaska

Prudhoe Bayd Kuparuk Milne Pointd Other Various Thunder Horsed Atlantisd Mad Dogd Mars Na Kikad Horn Mountaind Kingd Other

Total Alaska Lower 48 onshoreb Gulf of Mexico deepwater

Variousd Variousd Various Greater Plutoniod Kizomba C Dev Dalia Girassol FPSO Other Gupco Other Various Azeri-Chirag-Gunashlid Other Various Various

Total Angola Egypt Total Egypt Algeria Total Africa Azerbaijan Total Azerbaijan Western Indonesiab Other Total Rest of Asiab Total Asia Australia Total Australasia Total subsidiariese Equity-accounted entities (BP share) Russia – TNK-BPb Total Russia Abu Dhabif Other Total Rest of Asiab Total Asia Argentina Venezuelab Boliviab Total South America Total equity-accounted entities Total subsidiaries and equity-accounted entities
a

Various

Various Various Various

Various Various Various

840 840 182 12 194 1,034 75 25 1 101 1,135 2,535

826 826 210 10 220 1,046 70 19 3 92 1,138 2,401

832 832 192 9 201 1,033 69 6 2 77 1,110 2,414

Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. In 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in Pakistan, swapped a number of assets with BG Group plc in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest Java to Pertamina, divested its interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation payable, Pan American Energy’s shares of Chaco. In 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position and TNK-BP disposed of some non-core interests. In 2007, BP divested its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. c Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell. d BP-operated. e Includes 26 net mboe/d of NGLs from processing plants in which BP has an interest (2008 19mboe/d and 2007 54mboe/d). f The BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. During the second quarter of 2007, we updated our reporting policy in Abu Dhabi to be consistent with general industry practice and as a result we report production and reserves there gross of production taxes.
b

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Total Gulf of Mexico deepwater Total US Canadab Total Rest of North America Total North America Colombia Trinidad & Tobago Venezuelab Total South America Angola

Variousd

34 29 105 168 40 40 208 69 45 24 43 181 97 133 54 35 29 27 25 22 62 387 665 8 8 673 23 38 – 61 70 43 32 22 44 211 55 16 71 22 304 94 7 101 5 17 123 123 31 31 1,400

27 26 120 173 43 43 216 72 48 27 50 197 97 24 42 31 28 29 18 23 49 244 538 9 9 547 24 38 4 66 69 30 34 22 46 201 41 16 57 19 277 97 8 105 7 16 128 128 29 29 1,263

32 37 132 201 51 51 252 74 52 28 55 209 108 – 2 25 30 32 18 22 67 196 513 8 8 521 28 30 16 74 12 – 31 20 77 140 36 7 43 12 195 200 5 205 7 16 228 228 34 34 1,304

Business review

BP Annual Report and Accounts 2009 Business review

Natural gas
million cubic feet per day BP net share of productiona Field or area 2009 2008 2007

UKb Total UK Netherlandsb Norway Total Rest of Europe Total Europe Lower 48 onshoreb

Bruce/Rhumc Brae East Other Various Various San Juanc Jonahc Arkomac Wamsutterc Hugotonc Tuscaloosac Other Thunder Horsec Other Various West Central Otherc

Total Lower 48 onshore Gulf of Mexico deepwater Total Gulf of Mexico deepwater Alaska Total US Canadab Total Canada Total Rest of North America Total North America Trinidad & Tobago

Mangoc Cashima/NEQBc Kapokc Cannonballc Amherstiac Otherc Various Various Temsah Ha’pyc Taurtc Other Various Variousc Variousc Sanga-Sanga Other Yacheng Variousc Variousc Perseus/Athena Goodwyn Angel Other Tangguhc

Total Trinidad Colombia Venezuelab Total South America Egypt

Total Egypt Algeria Total Africa Pakistanb Azerbaijan Western Indonesiab Total Western Indonesia China Vietnam Sharjah Total Rest of Asia Total Asia Australia

Total Australia Eastern Indonesia Total Australasia Total subsidiariesd Equity-accounted entities (BP share) Russia – TNK-BPb Total Russia Western Indonesia Kazakhstanb Total Rest of Asia Total Asia Argentina Boliviab Venezuelab Total South America Total equity-accounted entitiesd Total subsidiaries and equity-accounted entities
a Production b In

110 62 446 618 – 16 16 634 659 227 194 146 102 65 562 1,955 83 220 303 58 2,316 69 194 263 263 2,579 664 571 540 225 197 233 2,430 62 – 2,492 118 94 73 177 462 159 621 173 126 71 35 106 83 63 59 610 610 142 139 120 39 440 74 514 7,450 601 601 31 11 42 643 378 11 3 392 1,035 8,485

165 71 523 759 – 23 23 782 682 221 240 136 91 65 451 1,886 11 219 230 41 2,157 63 182 245 245 2,402 471 375 619 336 288 357 2,446 84 2 2,532 109 94 24 145 372 112 484 162 143 69 97 166 91 61 73 696 696 229 74 6 71 380 1 381 7,277 564 564 31 8 39 603 385 63 6 454 1,057 8,334

161 60 547 768 3 26 29 797 694 173 204 120 123 78 458 1,850 – 269 269 55 2,174 63 192 255 255 2,429 22 6 984 628 155 638 2,433 104 6 2,543 118 108 – 89 315 153 468 121 73 75 81 156 85 82 92 609 609 193 107 – 76 376 – 376 7,222 451 451 33 8 41 492 369 60 – 429 921 8,143

Various Various Various Various Various Various

excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in Pakistan, swapped a number of assets with BG Group plc in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest Java to Pertamina, divested it’s interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation, Pan American Energy’s shares of Chaco. In 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position and TNK-BP disposed of some non-core interests. In 2007, BP divested its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. c BP-operated. d Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves. 28

BP Annual Report and Accounts 2009 Business review

The following narrative reviews operations in our Exploration and Production business by continent and country, and lists associated significant events that occurred in 2009. Where relevant, BP’s percentage working interest in oil and gas assets is shown in brackets. Working interest is the cost-bearing ownership share of an oil or gas lease. The percentages disclosed for certain agreements do not necessarily reflect the percentage interests in reserves and production. North America United States Our activities within the US take place in three main areas: deepwater Gulf of Mexico, Lower 48 states and Alaska. Deepwater Gulf of Mexico: Deepwater Gulf of Mexico is our largest area of growth in the US. In addition, we are the largest producer and acreage holder in the region. Significant events were: ? In May 2009, BP announced it had begun production from the Dorado (BP 75% and operator) and King South (BP 100%) projects. Both projects are subsea tiebacks to the existing BP Marlin Tension Leg Platform (TLP) infrastructure. Dorado comprises three new subsea wells located about two miles from the Marlin TLP. King South comprises a single subsea well located 18 miles from the Marlin TLP. Both projects leverage existing subsea and topsides infrastructure and the latest subsea and drilling technology to enable the efficient development of the fields. Dorado utilizes dual completion technology enabling production from five Miocene zones and King South is produced through the existing King subsea pump. ? In June 2009, the Atlantis Phase 2 (BP 56%) project achieved first oil ahead of schedule, signalling the official start-up. ? In July 2009, BP announced the drilling of a successful appraisal well in a previously untested southern segment of the Mad Dog field (BP 60.5% and operator). The 826-5 well is located in the Green Canyon block 826, approximately 100 miles south of Grand Isle, Louisiana, in about 5,100 feet of water. The results from this well continue the successful phased development of the Mad Dog field and build upon the success from 2008. ? In September 2009, BP announced the Tiber discovery in the deepwater Gulf of Mexico (BP 62% and operator). The discovery well, located in Keathley Canyon block 102, approximately 250 miles southeast of Houston, is in 4,132 feet of water. It was drilled to a total depth of approximately 35,055 feet making it the deepest oil and gas discovery well ever drilled. The well found oil in multiple Lower Tertiary reservoirs. Appraisal will be required to determine the size and commerciality of the discovery. Lower 48 states: Our North America Gas business operates onshore in the Lower 48 states producing natural gas, natural gas liquids and coalbed methane across 14 states. In 2009, we drilled almost 300 wells as operator and continued to maintain a stable programme of drilling activity throughout the year. Shale gas assets are becoming an increasingly important part of our North America Gas business: Significant events were: ? In the fourth quarter of 2009, BP further expanded its shale gas portfolio by securing new access in the Eagle Ford Shale in South Texas. Combined with our 2008 acquisitions of interests in Chesapeake Energy Corporation’s Woodford and Fayetteville Shale assets in the Arkoma Basin and our incumbent position in the Haynesville Shale in East Texas, BP now has a material shale gas position in the Lower 48 states. ? Since taking over operations of the Woodford shale properties, BP gross operated production has increased from 60mmcf/d in November 2008 to over 100mmcf/d by the end of 2009, a 67% increase. BP delivered 23 wells by the end of the year with an

?

?

?

average 30-day rate of 4.6mmcf/d per well, approximately 50% higher than initial expectations. In 2009, BP net production from the Fayetteville shale properties has grown from approximately 55mmcf/d to 87mmcf/d at the end of the year, an increase of approximately 60%. Individual well performance continues to exceed expectations by approximately 25%. In 2009, BP drilled four wells appraising the Haynesville Shale asset and plans to increase horizontal well drilling in 2010. BP’s position in the Haynesville Shale in North Louisiana and East Texas covers an area of approximately 150,000 net acres. The business has made good progress in restructuring its activity and driving down costs to a level that is consistent with the economic environment. Business review

Alaska: BP operates 15 North Slope oil fields (including Prudhoe Bay, Endicott, Northstar, and Milne Point) and four North Slope pipelines, and owns a significant interest in six other producing fields. Two key aspects of BP’s business strategy in Alaska are commercializing the large undeveloped natural gas resource within our 26.4% interest in Prudhoe Bay and unlocking the large undeveloped heavy oil resources within existing North Slope fields through the application of advanced technology. Significant events were: ? In 2009, we progressed the previously announced development activities for the Liberty oilfield, which is located on federal leases about six miles offshore in the Beaufort Sea, and east of the Prudhoe Bay oilfield. The planned development includes up to six ultraextended reach wells, including four producers and two injectors, to be drilled from existing infrastructure in the BP-operated Endicott field to minimize the onshore and offshore environmental footprint. These wells are expected to be the longest horizontal wells ever drilled and completed in the industry, extending two miles deep and as far as eight miles horizontally. A specialized rig for drilling in the Arctic has been built for the project, and it is the world’s largest and most powerful onshore drilling rig. Key project milestones achieved during 2009 include expansion of the BP-operated Endicott field satellite drilling island (SDI) in April; and sealift delivery of the ultra-extended reach drilling rig to the Endicott SDI in August. Drilling is expected to start in 2010, with first oil expected in 2011. BP drilled the Liberty discovery well in 1997, and is the operator and sole owner of the field. ? On 27 January 2009, the Commissioner of the State of Alaska Department of Natural Resources (DNR) issued a ‘Conditional Interim Decision’ in connection with the appeal of the Point Thomson area lease terminations. The Point Thomson Unit (PTU) was terminated by administrative decision of the DNR in November 2006 (BP 32%). In February 2007, the DNR notified the PTU owners of its decision to terminate the Point Thomson area leases as well. ExxonMobil, operator, and the other unit owners including BP, are pursuing an appeal of the unit termination in the Alaska Superior Court; and the lease terminations are under administrative appeal with the DNR. The 27 January 2009 Conditional Interim Decision permitted ExxonMobil to conduct drilling operations on two of the 31 terminated leases comprising the former PTU. The DNR’s interim decision provided that the two leases would be reinstated if certain conditions were met. On 11 January 2010, the Alaska Superior Court reversed the DNR Commissioner’s administrative decision to terminate the PTU. The parties have been ordered to provide the Court further briefing regarding whether the Court should again remand the matter for an administrative proceeding with DNR, or retain jurisdiction with the Alaska Superior Court and conduct a de novo proceeding.

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Business review

BP Annual Report and Accounts 2009 Business review

Canada In Canada, BP operates in five provinces and two territories, exploring for, developing, producing and processing natural gas and heavy crude oil. We also hold an interest in an oil sands joint venture with Husky Energy Inc., we market natural gas and we are the largest marketer of natural gas liquids. ? In 2009, BP conducted a successful 3D seismic programme over the primary area of interest on the exploration licences acquired in 2008 in the Canadian Beaufort Sea. The programme was the most northerly 3D seismic programme ever conducted, with approximately 1,600 square kilometres of 3D data acquired. The project also had the largest array of towed marine streamers deployed in the high Arctic. BP has 2,392,101 acres (968,049 hectares) of significant discovery licences and exploration licences in the Beaufort Sea. South America Venezuela BP has been in Venezuela since 1994 and currently participates in three equity-accounted entities. ? In 2009, production cuts due to OPEC quota restrictions were assigned to the Petromonagas and Petroperija entities. Petromonagas’s OPEC quota restrictions resulted in a complete production shutdown until 12 July 2009. There is uncertainty regarding the duration of the quota restrictions in Petroperija. Colombia Our main activity in Colombia is concentrated on operating a producing field complex in the Casanare region. In addition, we operate four principal processing plants and own pipeline interests. BP also holds exploration rights over two blocks off Colombia’s northern coast in the Caribbean Sea. ? During 2009, seismic data processing and interpretation was carried out at the RC4 and RC5 Caribbean offshore blocks (BP 40.6%) in order to determine potential prospects. A decision whether to drill a well is expected to be taken in 2010. ? During 2009, the strategy and detailed plan for the termination of the Santiago de las Atalayas field contract by June 2010, and its subsequent operation by Ecopetrol, was designed and implemented. Argentina, Bolivia and Chile BP conducts activity in the Southern Cone region of South America (Argentina, Bolivia and Chile) through Pan American Energy (PAE), a joint venture company in which BP holds a 60% interest. As the venture is jointly controlled with Bridas Corporation, it is accounted for using the equity method of accounting. Most of the PAE production comes from the Cerro Dragon field in the provinces of Chubut and Santa Cruz. ? The Cerro Dragon field is now producing at its highest level since the licence was granted in 1958, and further expansion programmes are planned. PAE also has other gas and liquids producing assets in the Argentine provinces of Salta, Neuquen and Tierra del Fuego, and in Bolivia. PAE also has interests in exploration areas, pipelines, and other midstream infrastructure assets, primarily in Argentina. ? On 26 November 2008, the Argentine government issued a decree by which a new regime on oil and by-products exports, called Petróleo Plus was put in place. This programme provides fiscal relief in the form of fiscal credit certificates, which can be used to offset export tariffs on oil, LPG and by-products. The goal is to incentivize investment to increase oil production and reserves. As PAE achieved the targets for both reserves replacement and production growth stipulated in the programme, it has obtained and applied fiscal credit certificates since January 2009.

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On 23 January 2009, the president of Bolivia issued a decree nationalizing PAE’s investment in 8,049,660 shares of Chaco. The decree establishes a compensation value per share, which represents a total amount of $233 million (BP share $140 million), subject to eventual adjustments. The partners assert that this is not an adequate compensation for the nationalized shares. PAE will pursue an adequate compensation for the nationalized assets. ? On 28 January and 22 May 2009, PAE entered into two agreements with the Neuquen province in Argentina that provide for the extension of concession terms related to the exploration and development of the Aguada Pichana and San Roque blocks and of the Lindero Atravesado block, respectively.

Trinidad & Tobago BP holds exploration and production licences covering 904,000 acres offshore of the east coast. Facilities include 12 offshore platforms and one onshore processing facility. Production is comprised of oil, gas and NGLs. ? On 27 October 2009, the Savonette offshore field development began production on a normally unmanned installation platform (NUI). Savonette is located in 290 feet (88 metres) of water approximately 50 miles off Trinidad’s south-east coast. Production from the platform is tied in to BP Trinidad and Tobago’s Mahogany B platform and will supply the Trinidad domestic market as well as Atlantic LNG’s liquefaction plant for export as LNG to international markets. The Savonette platform, installed in February 2009, is the fourth in a series of NUIs designed and constructed locally in Trinidad using a standardized ‘clone’ concept. The first three NUIs were Cannonball, Mango and Cashima. Europe United Kingdom We are the largest producer of oil, the second largest producer of gas and the largest overall producer of hydrocarbons in the UK. Key aspects of our activities in the North Sea include a focus on in-field drilling and selected new field developments. Our development expenditure (excluding midstream) in the UK was $751 million in 2009, compared with $907 million in 2008 and $804 million in 2007. BP operates one NGL plant in the UK. Significant events were: ? On 31 August 2009, the exchange of assets between BP and BG Group was formally completed. The exchange is expected to strengthen BP’s position as a major operator in the southern North Sea and to facilitate development activity and investment in the UK Continental Shelf. BP acquired BG’s 24.2% interest in the BPoperated Amethyst field and all its interests in the Easington Catchment Area fields, including a 73.3% interest in the Mercury field, a 79% interest in the Neptune field, a 65% interest in the Minerva, Apollo and Artemis fields and BG’s 30.8% interest in the BP-operated Whittle and Wollaston fields. In return, BG Group acquired BP’s interest and operatorship in the Everest (BP 21.1%) and Lomond (BP 22.2%) fields, BP’s 18.2% interest in the BGoperated Armada field and 32% of the Chevron-operated Erskine field (BP retained 18% equity in Erskine). ? Drilling performance moved from fourth quartile in 2007 to first quartile in 2008a, and generated additional drilling capital efficiencies in 2009.
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BP Drilling and Completions Global Benchmarking.

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BP Annual Report and Accounts 2009 Business review

Rest of Europe Our activities in the Rest of Europe are in Norway. ? Development expenditure (excluding midstream) in the Rest of Europe was $1,054 million, compared with $695 million in 2008 and $443 million in 2007. Progress continued on the Skarv and Valhall redevelopment projects. Africa Angola BP is present in four major deepwater licences offshore Angola (Blocks 15, 17, 18 and 31) and is operator in Blocks 18 and 31. In addition, BP holds a 13.6% equity share in the first Angolan LNG project. Technical skills developed in similar deepwater basins around the world have been applied extensively in BP’s operations in Angola. ? On 29 December 2008, BP began a comprehensive seismic survey on Block 31 (BP 26.67% and operator) using a wide azimuth towed streamer (WATS) to gain improved imaging quality of sub-salt strata. WATS seismic is an acquisition configuration developed by BP to image areas of complex geology below salt. The WATS survey will significantly improve the imaging and understanding of the fields, and more significantly, the data acquired will also support the definition of hubs which will form part of BP’s development programme. This is the first such survey to be conducted by BP outside the Gulf of Mexico, and is the first WATS survey conducted in Angola. ? In 2009, BP announced its seventeenth through nineteenth discoveries in the ultra deepwater Block 31. On 3 March 2009, BP announced the discovery of the Leda field. Leda was drilled in a water depth of 2,070 metres and reached a total depth of nearly 6 kilometres below sea level. It is located in the central northern portion of Block 31, some 415 kilometres north-west of Luanda. This is the fifth discovery in Block 31 in which the exploration well has been drilled through salt to access the oil-bearing sandstone reservoir beneath. On 27 May 2009, BP announced the Oberon oil discovery. Oberon-1 was drilled in a water depth of 1,624 metres and reached a total depth of 3,622 metres below sea level. On 1 October 2009, BP announced the Tebe oil discovery. The Tebe well was drilled in a water depth of 1,752 metres and a total depth of 3,325 metres below sea level. Algeria BP is a partner with Sonatrach and Statoil in the In Salah (BP 33.15%) and In Amenas (BP 45.89%) projects, which supply gas to the domestic and European markets. BP is also in partnership with Sonatrach in the Rhourde El Baguel (REB) oilfield (BP 60%), an enhanced oil recovery project 75 kilometres east of the Hassi Messaoud oilfield. In addition, BP is in partnership with Sonatrach in the Bourarhet Sud block, located to the south-west of In Amenas. ? In 2008, Sonatrach and BP announced a discovery with the Tin Zaouatene-1 (TZN-1) exploration well. BP is currently in the second prospecting period, which runs until September 2010. Seismic operations started in February 2009 and were completed in October 2009. Drilling activities commenced in December 2009. Libya In Libya, BP is in partnership with the Libyan Investment Corporation (LIC) to explore the onshore Ghadames and offshore Sirt basins. ? In 2009, BP continued the onshore and offshore seismic operations started in 2008 on the acreage covered under the exploration and production sharing agreement ratified in December 2007 (BP 85%). ? In October 2009, BP completed a large offshore 3D survey in the deepwaters of the Libyan Gulf of Sirt. The programme, started in September 2008, was conducted by the seismic vessel Geowave Endeavour (operated by CGGV-Wavefield Inseis), and covered 17,000 square kilometres, 60% of BP’s Sirt exploration acreage.

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BP is also progressing its onshore seismic operations in the deserts of Libya’s Ghadames basin. This is the first full application of a new, cutting-edge seismic technique developed by BP, known as Independent Simultaneous Sweeping (ISS): the technology allows greater acquisition (in excess of 10,000 vibration points per day compared with conventional technology of 1,500 per day) and cost efficiency. Exploration drilling is scheduled to commence during 2010 in both onshore and offshore blocks.

Egypt BP is the single largest foreign investor in Egypt, with investments close to $15 billion to date. With its partners, BP has produced almost 40% of Egypt’s entire oil production and close to 30% of its gas production. The Gulf of Suez Petroleum Company (GUPCO), BP’s joint venture with the Egyptian General Petroleum Corporation, has been an industry leader in Egypt and the entire region and covers operations in the Gulf of Suez and the Western Desert. ? During the second quarter of 2009, BP was awarded two blocks in the Egyptian Offshore Nile Delta. BP has a 100% working interest and is the operator of Block 2, North Tineh, which is in a deepwater area of the Eastern Nile Delta. BP will also be the operator of Block 3, North Damietta Offshore, which is adjacent to Block 2, with Shell and Petronas as partners with a one-third working interest each. These awards build on the existing portfolio in Egypt, providing an additional platform for growth. BP’s expertise in exploring deepwater, highpressure and high-temperature deep targets maximizes the chances of unlocking the potential in this area. ? During the third quarter of 2009, the Egyptian parliament approved the amendments to two Gulf of Suez (GOS) concessions: South Belayim (BP 100%) and South Ghara (BP 75%). The amendments provide BP with enhanced commercial structure and extend the term of both concessions by 20 years in return for increased investment levels. This marks a significant step in the development of the Southern GOS assets. Asia Western Indonesia BP has a joint interest in Virginia Indonesia Company LLC (VICO), the operator of the Sanga-Sanga PSA (BP 38%) supplying gas to Indonesia’s largest LNG export facility, the Bontang LNG plant in Kalimantan. ? During 2009, VICO successfully completed a joint evaluation of the coalbed methane (CBM) opportunities in the Sanga-Sanga area. In November, VICO signed a PSA with the Government of Indonesia, for the exploration and development of these CBM resources. ? On 1 July 2009, BP divested its entire 46% holding in the Offshore Northwest Java (ONWJ) PSA to Indonesia’s national oil company, Pertamina. Vietnam Our upstream business in Vietnam is concentrated on the Block 6.1 offshore gas field. BP participates in one of the country’s largest foreign investment projects, the Nam Con Son gas project. This is an integrated resource and infrastructure project, which includes offshore gas production, a pipeline transportation system and a power plant. ? BP Block 6.1 Lan Do development project was sanctioned in December 2009, with first gas scheduled in 2012. ? BP’s withdrawal from Blocks 5.2 (BP 55.9% and operator) and 5.3 (BP 75% and operator) was completed in December 2009. China BP’s upstream asset in the country is the Yacheng offshore gas field (BP 34.3%) in the South China Sea, one of the biggest offshore gas fields in China. Yacheng supplies the Castle Peak Power Company gas for up to 70% of Hong Kong’s gas-fired electricity generation. Additional gas is also sold to the Hainan Holdings Fuel & Chemical Corporation Limited.
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Business review

BP Annual Report and Accounts 2009 Business review

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The Platform A development project approved at the end of 2008 is on track to deliver first gas in 2010.

Azerbaijan BP is the largest foreign investor in the country. BP operates two PSAs, Azeri-Chirag-Gunashli (ACG) and Shah Deniz, and also holds other exploration leases. ? A comprehensive review of the subsurface gas release that occurred beneath the Central Azeri platform in September 2008, and subsequent remedial works, have resulted in bringing the level of production from the platform to over 220mboe/d from 12 wells. Further minor remedial work is planned during 2010. ? On 13 July 2009, BP and the State Oil Company of the Republic of Azerbaijan (SOCAR) signed a memorandum of understanding (MOU) to jointly explore and develop the Shafag and Asiman structures in the Azerbaijan sector of the Caspian Sea. The MOU gives BP the exclusive right to negotiate the PSA. The block covers an area of some 1,100 square kilometres and has never been explored before. It is located in a deepwater section of about 650-800 metres with reservoir depth of about 7,000 metres. Russia TNK-BP TNK-BP, an associate owned by BP (50%) and Alfa Group and AccessRenova (AAR) (50%), is an integrated oil company operating in Russia and the Ukraine. BP’s investment in TNK-BP is reported in the Exploration and Production segment. The TNK-BP group’s major assets are held in OAO TNK-BP Holding. Other assets include the BP-branded retail sites in the Moscow region and interests in OAO Rusia Petroleum and the OAO Slavneft group. The workforce comprises more than 52,000 people. ? Downstream, TNK-BP has interests in six refineries in Russia and the Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl refinery), with throughput of approximately 683 thousand barrels per day. TNK-BP supplies approximately 1,400 branded filling stations in Russia and the Ukraine and has more than 20% market share of the Moscow retail market. ? On 9 January 2009, BP reached final agreement on amendments to the shareholder agreement with its Russian partners in TNK-BP. The revised agreement is aimed at improving the balance of interests between the company’s owners, and focusing the business more explicitly on value growth. The former evenly balanced main board structure has been replaced by one with four representatives each from BP and AAR, plus three independent directors. Unanimous board support is required for certain matters including substantial acquisitions, divestments and contracts, and projects outside the business plan, together with approval of key changes to the TNK-BP group’s financial framework and related-party transactions. A number of other matters will be decided by approval of a majority of the board, so that the independent directors will have the ability to decide in the event of disagreement between the shareholder representatives on the board. BP will continue to nominate the chief executive officer (CEO), subject to main board approval, and AAR will continue to appoint the chairman. The three independent directors appointed to the restructured main board are Gerhard Schroeder, former chancellor of the Federal Republic of Germany, James Leng, former chairman of Corus Steel and Alexander Shokhin, president of the Russian Union of Industrialists and Entrepreneurs. In addition, significant TNK-BP subsidiaries will have directors appointed by BP and AAR on their boards. Our investment was reclassified from a jointly controlled entity to an associate with effect from 9 January 2009; however, the results of TNK-BP continue to be accounted for under the equity method. On 6 August 2009, TNK-BP announced that William Schrader was appointed chief operating officer. Mr. Schrader took office during the fourth quarter of 2009, replacing Tim Summers. In November, the TNK-BP board of directors unanimously agreed to
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appoint Maxim Barsky, TNK-BP executive vice president for strategy and business development, as the TNK-BP group’s future CEO, effective 1 January 2011. Until that time, Mikhail Fridman has agreed to continue to act as interim CEO, in addition to his role as executive chairman of the board of directors of TNK-BP Limited. On 16 February 2009, TNK-BP announced that the company had launched commercial production from the Urna and Ust-Tegus fields in the Uvat area of the Tyumen region, Russia. Urna and Ust-Tegus are located in the eastern part of Uvat. TNK-BP completed construction of a 264-kilometre pipeline and a central crude oil gathering facility, which facilitate transportation of oil from the fields westwards to enter the Transneft pipeline system. Investment in field development and construction of the infrastructure is expected to amount to over $1.5 billion. On 2 June 2009, TNK-BP announced that the company had launched commercial production in the Northern Hub of the Kamennoye field, one month earlier than planned. The Kamennoye field, in the KhantyMansiisk region of West Siberia, is one of the largest greenfield projects developed by TNK-BP. Aitor and Poima form the Northern Hub of the producing Kamennoye field. Thirty-five wells were drilled and completed in Aitor and, going forward, the primary focus is on drilling 194 wells in Poima. Infrastructure construction includes upgrading of the gathering and treatment facilities, construction and upgrade of the pipeline and water flood systems as well as the power supply system. This strategy and development plan is aimed at maximizing the use of existing facilities and minimizing the impact on the ecologically sensitive territory. Between 2004 and 2009, investment in the Kamennoye project amounted to over $800 million. On 29 July 2009, TNK-BP and Weatherford International Ltd (Weatherford) announced that TNK-BP completed the sale of its Oil Field Services (OFS) enterprises to Weatherford pursuant to the sales and purchase agreement signed on 29 May 2009. Via this transaction, Weatherford acquired 10 OFS companies providing drilling, well workover and cementing services operating in West Siberia, East Siberia and the Volga-Urals region. In 2007, BP and TNK-BP signed heads of agreement to create strategic business alliances with OAO Gazprom. Under the terms of this agreement, TNK-BP agreed to sell to Gazprom its stake in OAO Rusia Petroleum, the company that owns the licence for the Kovykta gas condensate field in East Siberia and its interest in East Siberia Gas Company. Discussions to conclude this disposal continue.

Sakhalin ? BP has material interests in Sakhalin through two joint venture companies, Elvary Neftegaz and Vostok Shmidt Neftegaz. BP has a 49% equity interest in each joint venture, and its partner, Rosneft, holds the remaining 51% interest. During the year, both joint ventures, via their Russian affiliates, held Geological and Geophysical Studies licences with the Russian Ministry of Natural Resources (MNR) to perform exploration seismic and drilling operations in these licence areas off the east coast of Russia. To date, 3D seismic data has been acquired in relation to both licences. In the Elvary Neftegaz licence additional 2D and 3D seismic data was acquired during 2009 in preparation for future drilling commitments.

BP Annual Report and Accounts 2009 Business review

Kazakhstan ? On 11 December 2009, BP announced that it has divested its interest in Kazakhstan’s Tengiz oil field and the Caspian Pipeline Consortium (CPC) pipeline, carrying oil between Kazakhstan and Russia, by selling its 46% stake in LukArco to Russia’s Lukoil. Lukoil, which already owns 54% of LukArco, will pay $1.6 billion in cash in three instalments over two years from December 2009. Middle East and Pakistan Production in the Middle East consists principally of the production entitlement of associates in Abu Dhabi, where we have equity interests of 9.5% and 14.67% in onshore and offshore concessions respectively. ? In Sharjah, the joint agreement between BP, the Government of Sharjah, Itochu and Tokyo Beki, for the operation and maintenance of LPG facilities and the production and marketing of LPG products, expired on 22 March 2009 after a period of 25 years. BP relinquished its 25% ownership, in accordance with the joint venture agreement, and negotiated terms that retain BP as the operator of the facilities through an operating fee structure. ? In Block 61 in Oman, the challenges posed by the world’s largest onshore wide-azimuth 3D seismic survey led the BP Oman team to use a ground-breaking new technique known as distance separated simultaneous sweeping (DS3). BP’s appraisal programme continues to make good progress evaluating the resources in place in the Khazzan/Makarem gas fields. Five appraisal wells have been drilled in 2009. Fracture stimulation and testing of these wells continues. Infrastructure to facilitate long-term wells tests is under construction and expected to be ready for service in the second half of 2010. ? On 3 January 2010, we received approval from the Government of Jordan to join the state-owned National Petroleum Company to exploit the onshore Risha concession in the north-east of the country. ? With effect from 1 January 2009 BP assumed operatorship of the Mirpurkhas and Khipro onshore blocks in the southern Sindh province of Pakistan. ? In the third quarter of 2009, BP won bids for two new exploration blocks, Digri and Sanghar South, in Pakistan. These blocks are adjacent to BP’s Mirpurkhas and Khipro concession areas and add another 5,000 square kilometres to the group’s existing portfolio of 5,300 square kilometres. BP has committed to invest approximately $30 million in these blocks for seismic and wells over the next three years. Iraq ? In November 2009, BP and China National Petroleum Company (CNPC) entered into a contract with the state-owned Southern Oil Company of Iraq to expand production from the Rumaila oilfield near Basra in southern Iraq. This followed a successful bid for the contract in Baghdad in June 2009. The Rumaila field currently produces approximately one million barrels of oil per day. BP and CNPC plan to invest approximately $15 billion over the next 20 years to enhance the Rumaila production to a plateau rate of 2.85mmb/d, around 3% of global oil production. BP will hold a 38% working interest, CNPC will hold 37% and the remaining 25% will be held by the State Oil Marketing Organisation (SOMO) representing the Iraqi government. Australasia Australia BP is one of seven partners in the North West Shelf (NWS) venture. Six partners (including BP) hold an equal 16.67% interest in the infrastructure and oil reserves and an equal 15.78% interest in the gas and condensate reserves, with a seventh partner owning the remaining 5.32% of gas and condensate reserves. The NWS venture is currently the principal supplier to the domestic market in Western Australia and one of the largest LNG export projects in Asia with five LNG trains in operation.

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The North Rankin 2 project linking a second platform to the existing North Rankin A platform sanctioned in 2008, is on schedule. On completion, the North Rankin A and North Rankin B platforms will operate as a single integrated facility and recover low pressure gas from the North Rankin and Perseus gas fields. The joint venture partners (Chevron, ExxonMobil and Shell) approved the Greater Gorgon project on 14 September 2009 with the Australian Government also awarding production licences for the Jansz-Io field (BP 5.375%). The Jansz-Io field will be developed as part of the Greater Gorgon project, which will comprise three LNG trains, each with a capacity of 5 million tonnes per annum (mtpa), on Barrow Island with first gas expected in 2014. As part of this, a unitization and unit operating agreement has been executed with the joint venture partners and sales and purchase agreements for the wellhead sale of raw gas and repurchase of LNG ex-Barrow Island have been executed between BP and Shell.

Business review

Alaska BP owns a 46.9% interest in the Trans-Alaska Pipeline System (TAPS), with the balance owned by four other companies. BP also owns a 50% interest in a joint venture company called ‘Denali – The Alaska Gas Pipeline’ (Denali). Denali has begun work on an Alaska gas pipeline project, consisting of a gas treatment plant on Alaska’s North Slope, a large diameter pipeline that is intended to pass through Alaska into Canada, and should it be required, a large-diameter pipeline from Alberta to the Lower 48 states. When completed, the pipeline is expected to transport approximately 4 billion cubic feet of natural gas per day to market. Following a successful open season, Denali will seek certification from the Federal Energy Regulatory Commission (FERC) of the US and the National Energy Board (NEB) of Canada to move forward with project construction. Denali will manage the project, and will own and operate the pipeline when completed. BP may consider other equity partners, including pipeline companies, who can add value to the project and help manage the risks involved. Significant events were: ? Work on the strategic reconfiguration project to upgrade and automate four TAPS pump stations continued to progress in 2009. This project involves installing electrically driven pumps at four critical pump stations, along with increased automation and upgraded control systems. Two of the reconfigured pump stations came online during 2007 and a third reconfigured pump station came online in May 2009. Reconfiguration of the remaining pump station in the programme plan will commence in 2010, with installation currently planned for 2012.

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Business review

Midstream activities Oil and natural gas transportation The group has direct or indirect interests in certain crude oil and natural gas transportation systems. The following narrative details the significant events that occurred during 2009 by country. BP’s onshore US crude oil and product pipelines and related transportation assets are included under Refining and Marketing (see page 36).

BP Annual Report and Accounts 2009 Business review

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On 16 April 2009, the US FERC issued an initial ruling on shipper challenges of TAPS interstate tariff rates for the years 2007 and 2008, ordering interim refunds to be paid to shippers based on the January 2009 tariff rate filings. As a result of this order, BP, as a TAPS carrier, paid refunds of $7.3 million to third-party shippers covering the period from 1 January 2007 to 30 June 2009, based on its January 2009 tariff rate filing of $3.45/bbl. Shippers had also filed challenges of the TAPS carriers’ 2009 interstate tariff rates, based on the FERC rulings issued related to 2005 through 2008 tariff rates. On 12 January 2010, an agreement to settle all remaining challenges to TAPS carrier interstate tariff rate filings for the years 2008 and the first half of 2009 was signed by all the TAPS carriers and shippers. Under the terms of the settlement, BP will pay additional refunds to third-party shippers for the period from January 2007 through June 2009 of $0.12/bbl, representing the difference between the $3.45/bbl tariff rate on which the interim refunds for this period were based, and the $3.33/bbl tariff rate in the settlement agreement. The signed settlement agreement has been submitted to the FERC for final regulatory approval. In 2009, interstate transport represented approximately 90% of total TAPS throughput.

North Sea In the UK sector of the North Sea, BP operates the Forties Pipeline System (FPS) (BP 100%), an integrated oil and NGLs transportation and processing system that handles production from more than 50 fields in the Central North Sea. The system has a capacity of more than one million barrels per day, with average throughput in 2009 of 671mb/d. BP also operates and has a 29.5% interest in the Central Area Transmission System (CATS), a 400-kilometre natural gas pipeline system in the central UK sector of the North Sea. The pipeline has a transportation capacity of 1,700mmcf/d to a natural gas terminal at Teesside in north-east England. CATS offers natural gas transportation and processing services. In addition, BP operates the Dimlington/Easington gas processing terminal (BP 100%) on Humberside and the Sullom Voe oil and gas terminal in Shetland. Asia BP, as operator, manages and holds a 30.1% interest in the Baku-Tbilisi-Ceyhan (BTC) oil pipeline. The 1,768-kilometre pipeline transports oil from the BP-operated ACG oil field in the Caspian Sea to the eastern Mediterranean port of Ceyhan. BP is technical operator of, and holds a 25.5% interest in, the 693-kilometre South Caucasus Pipeline (SCP), which takes gas from Azerbaijan through Georgia to the Turkish border. In addition, BP operates the Azerbaijan section of the Western Export Route Pipeline between Azerbaijan and the Black Sea coast of Georgia (as operator of Azerbaijan International Operating Company). Significant events were: ? On 23 April 2009, BP completed the sale of its 49.9% interest in Kazakhstan Pipeline Ventures (KPV) to Kazakhstan state oil and gas company KazMunayGas (KMG) for $250 million. KPV holds a 1.75% interest in the Caspian Pipeline Consortium (CPC) that carries crude oil from Kazakhstan’s largest producing oil field, Tengiz, to the Russian port of Novorossiysk on the Black Sea. ? On 11 December 2009, BP also divested its interest in the CPC pipeline (held through LukArco) by selling its 46% stake in LukArco to Lukoil.

Liquefied natural gas Our LNG activities are focused on building competitively advantaged liquefaction projects, establishing diversified market positions to create maximum value for our upstream natural gas resources and capturing third-party LNG supply to complement our equity flows. Assets and significant events included: ? In Trinidad, BP’s net share of the capacity of Atlantic LNG Trains 1, 2, 3 and 4 is 6 million tonnes of LNG per year (369 billion cubic feet equivalent regasified), with the Atlantic LNG Train 4 (BP 37.8%) designed to produce 5.2mtpa (294 billion cubic feet per annum) of LNG. All of the LNG from Atlantic Train 1 and most of the LNG from Trains 2 and 3 is sold to third parties in the US and Spain under longterm contracts. All of BP’s LNG entitlement from Atlantic LNG Train 4 and some of its LNG entitlement from Trains 2 and 3 is marketed via BP’s LNG marketing and trading business to a variety of markets including the US, the Dominican Republic, Spain, the UK and the Far East. ? We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction Company, which in 2009 supplied 5.4 million tonnes (279,000mmcf) of LNG. ? BP has a 13.6% share in the Angola LNG project, which is expected to receive approximately one billion cubic feet of associated gas per day from offshore producing blocks and to produce 5.2 million tonnes per year of LNG (gross), as well as related gas liquids products. Construction and implementation of the project is proceeding and is expected to start up in 2012. ? In Indonesia, BP is involved in two of the three LNG centres in the country. BP participates in Indonesia’s LNG exports through its holdings in the Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently delivers around 13% of the total gas feed to Bontang, one of the world’s largest LNG plants. The Bontang plant produced more than 17 million tonnes of LNG in 2009. ? Also in Indonesia, the Tangguh project (BP 37.16% and operator) in Papua Barat, Indonesia, started LNG production in June 2009, delivering its first commercial LNG delivery in July. Tangguh is BP’s first operated LNG plant. The first phase of Tangguh comprises two offshore platforms, two pipelines and an LNG plant with two production trains with a total capacity of 7.6mtpa. Tangguh adopted a fully integrated approach to development and its impact on local communities. The Tangguh project has five long-term contracts in place to supply LNG to purchasers in China, South Korea, Mexico and Japan. ? In Australia, we are one of seven partners in the North West Shelf (NWS) venture. The joint venture operation covers offshore production platforms, trunklines, onshore gas and LNG processing plants and LNG carriers. BP’s net share of the capacity of NWS LNG Trains 1-5 is 2.7mtpa of LNG. ? BP has a 30% equity stake in the 7mtpa capacity Guangdong LNG regasification and pipeline project in south-east China, making it the only foreign partner in China’s LNG import business. The terminal is also supplied under a long-term contract with Australia’s NWS project. ? In both the Atlantic and Asian regions, BP is marketing LNG using BP LNG shipping and contractual rights to access import terminal capacity in the liquid markets of the US (via Cove Point and Elba Island), the UK (via the Isle of Grain) and Italy (Rovigo), and is supplying Asian customers in Japan, South Korea and Taiwan.

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BP Annual Report and Accounts 2009 Business review

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 144-149. 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.

Spot and term contracts Spot contracts are contracts to purchase or sell a commodity at the market price, typically an index price prevailing on the delivery date when title to the inventory passes. Term contracts are contracts to purchase or sell a commodity at regular intervals over an agreed term. Though spot and term contracts may have a standard form, there is no offsetting mechanism in place. These transactions result in physical delivery with operational and price risk. Spot and term contracts relate typically to purchases of third-party gas and sales of the group’s gas production to third parties. For accounting purposes, spot and term sales are included in sales and other operating revenues, when title passes. Similarly, spot and term purchases are included in purchases for accounting purposes.

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Business review

OTC contracts These contracts are typically in the form of forwards,

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