This information, insofar as it relates to 2007, has been extracted or derived from the audited financial statements of the BP group presented on pages 93-180. Note 1 to the Financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related Notes elsewhere herein.
     BP sold its Innovene operations in December 2005. In the circumstances of discontinued operations, IFRS require that the profits earned by the discontinued operations, in this case the Innovene

operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa. This adjustment has two offsetting elements: the net margin on crude refined by Innovene, as substantially all crude for its refineries was supplied by BP and most of the refined products manufactured by Innovene were taken by BP; and the margin on sales of feedstock from BP’s US refineries to Innovene’s manufacturing plants. The profits attributable to individual segments are not affected by this adjustment. This representation does not indicate the profits earned by continuing or Innovene operations, as if they were standalone entities, for past periods or those likely to be earned in future periods.

We urge you to consider carefully the risks described below. If any of these risks occur, our business, financial condition and results of operations could suffer and the trading price and liquidity of our securities could decline, in which case you could lose all or part of your investment.
     Our system of risk management provides the response to enduring 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 inability to capture opportunities, threats materializing, inefficiency and legal non-compliance.
     The risks are categorized against the following areas: Strategy; Compliance and ethics; Financial control; and Operations.

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 capture above-average market growth.

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 future fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to a review for impairment of the group’s oil and natural gas properties. This review would reflect management’s view of long-term oil and natural gas prices. Such a review 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.
     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 consequent effect on prices and profitability.

Climate change and carbon pricing
Compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, reduced profitability from changes in operating costs and revenue generation and strategic growth opportunities being impacted.

Socio-political
We have operations in countries where political, economic and social transition is taking place. Some countries have experienced political instability, changes to the regulatory environment, expropriation or nationalization of property, civil strife, strikes, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas or our production to decline and could cause us to incur additional costs.
     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, petrochemical 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.

Compliance and ethics 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 protection controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. We buy, sell and trade oil and gas products in certain regulated commodity markets. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, or we could incur additional costs.

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 non-compliance with applicable laws and regulation or ethical misconduct could be damaging to our reputation and shareholder value. Multiple events of non-compliance could call into question the integrity of our operations.

Financial control risks
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. 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.
     For further information on financial instruments and financial risk factors see Financial statements – Note 28 on page 136 and Note 34 on page 143.

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.

Operations risks
Operations – safety and operations
Process safety
Inherent in our operations are hazards that require continual 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 and/or loss of production.

Personal safety
Inability to provide safe environments for our workforce and the public could lead to injuries or loss of life.

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.

Product quality
Supplying customers with on-specification products is critical to maintaining our licence to operate and our reputation in the marketplace. Failure to meet product quality standards throughout the value chain could lead to harm to people and the environment and loss of customers.

Drilling and production
Exploration and production require high levels of investment and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of an oil or natural gas field. The cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements.

Transportation
All modes of transportation of hydrocarbons contain inherent risks. A loss of containment of hydrocarbons and other hazardous material could occur during transportation by road, rail, sea or pipeline. This is a significant risk due to the potential impact of a release on the environment and people and given the high volumes involved.

Operations – planning and performance management
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.

Major project delivery
Successful execution of our group plan (see page 11) depends critically on implementing the activities to deliver the major projects over the plan

period. Poor delivery of any major project that underpins production growth and/or a major programme designed to enhance shareholder value could adversely affect our financial performance.

Reserves replacement
Successful execution of our group plan depends critically on sustaining long-term reserves replacement. If upstream resources are not progressed to proved reserves in a timely and efficient manner, we will be unable to sustain long-term replacement of reserves.

Operations – enterprise systems, security and continuity
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.

Security
Security threats require continual oversight and control. Acts of terrorism that threaten our plants and offices, pipelines, transportation or computer systems would severely disrupt business and operations and could cause harm to people.

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.

Operations – people management
People and capability
Employee training, development and successful recruitment of new staff are key to implementing our plans. Inability to develop the human capacity and capability across the organization could jeopardize performance delivery.

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’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in Performance review (pages 6-55) with regard to management aims and objectives, future capital expenditure, future hydrocarbon production volume, date(s) or period(s) in which production is scheduled or expected to come onstream or a project or action is scheduled or expected to begin or be completed, capacity of planned plants or facilities and impact of health, safety and environmental regulations; (ii) the statements in Performance review (pages 6-44) with regard to planned expansion, investment or other projects and future regulatory actions; and (iii) the statements in Performance review (pages 45-55) with regard to the plans of the group, cash flows, opportunities for material acquisitions, the cost of and provision for future remediation programmes, liquidity and costs for providing pension and other post-retirement benefits; and including under ‘Liquidity and capital resources’ with regard to future production, future refining availability, future capital expenditure, sources of funding, future revenues and financial performance, potential for cost efficiencies, level of free cash flow allocated to share buybacks, shareholder distributions and share buybacks, gearing, working capital and expected payments under contractual and commercial commitments; are all forward-looking in nature.
     By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including the specific factors identified in the discussions accompanying such forward-looking statements; the timing of bringing new fields onstream; future levels of industry product supply, demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this report including under ‘Risk factors’ on pages 8-9. In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.

Statements referring to 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.

General
Unless otherwise indicated, information in this document reflects 100% of the assets and operations of the company and its subsidiaries that were consolidated at the date or for the periods indicated, including minority interests. Also, unless otherwise indicated, figures for business sales and other operating revenues include sales between BP businesses.
     The company, incorporated in 1909 in England and Wales, became known as BP Amoco p.l.c. following the merger with Amoco Corporation (incorporated in Indiana, US, in 1889). The company subsequently changed its name to BP p.l.c.
     BP is one of the world’s leading oil companies on the basis of market capitalization and proved reserves. Our worldwide headquarters is located at 1 St James’s Square, London SW1Y 4PD, UK, tel +44 (0)20 7496 4000. Our agent in the US is BP America Inc., 4101 Winfield Road, Warrenville, Illinois 60555, tel +1 630 821 2222.

Overview of the group
BP is a global group, with interests and activities held or operated through subsidiaries, jointly controlled entities or associates established in, and subject to the laws and regulations of, many different jurisdictions. These interests and activities covered three business segments in 2007, supported by a number of organizational elements comprising group functions and regions.
     In 2007, the three business segments were Exploration and Production, Refining and Marketing and Gas, Power and Renewables. With effect from 1 January 2008, the Gas, Power and Renewables segment ceased to report separately (see Resegmentation in 2008 on page 12). Exploration and Production’s activities include oil and natural gas exploration, development and production (upstream activities), together with related pipeline, transportation and processing activities (midstream activities). The activities of Refining and Marketing include the supply and trading, refining, marketing and transportation of crude oil, petroleum and chemicals products. Gas, Power and Renewables activities included marketing and trading of gas and power, marketing of liquefied natural gas (LNG), natural gas liquids (NGLs), and low-carbon power generation through our Alternative Energy business. The group provides high-quality technological support for all its businesses through its research and engineering activities.
     Group functions serve the business segments, aiming to achieve coherence across the group, manage risks effectively and achieve economies of scale. Each head of region ensures regional consistency of the activities of business segments and group functions and represents BP to external parties.
     The group’s system of internal control is described in the BP management framework. It is designed to meet the expectations of internal control of the Turnbull Guidance on the Combined Code in the UK and of COSO (committee of the sponsoring organization for the Treadway Commission in the US). The system of internal control is the complete set of management systems, organizational structures, processes, standards and behaviours that are employed to conduct the business of BP and deliver returns to shareholders. The design of the system of internal control addresses risks and how to respond to them. Each component of the system is in itself a device to respond to a particular type or collection of risks.
     The group strategy describes the group’s strategic objectives and the presumptions made by BP about the future. It describes strategic risks that arise from making such presumptions and the actions to be taken to manage or mitigate the risks. The board delegates to the group chief executive responsibility for developing BP’s strategy and its implementation through the group plan that determine the setting of priorities and allocation of resources. The group chief executive is obliged to discuss with the board, on the basis of the strategy and group plan, all material matters currently or prospectively affecting BP’s performance.
     As the group’s business segments are managed on a global, not regional, basis, geographical information for the group and segments is

     BP sells small quantities of lubricants in Cuba through a 50/50 joint venture there. In Syria, small quantities of lubricants are sold through a distributor and BP obtains small volumes of crude oil supplies for sale to third parties in Europe. These sales and purchases are insignificant and BP does not provide other goods, technologies or services in these countries.

Acquisitions and disposals
In 2007, BP acquired Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The acquisition included Chevron’s 31% minority shareholding in Nerefco, its 31% shareholding in the 22.5 MW wind farm co-located at the refinery as well as a 22.8% shareholding in the TEAM joint venture terminal and shareholdings in two local pipelines linking the TEAM terminal to the refinery. Disposal proceeds were $4,267 million, which included $1,903 million from the sale of the Coryton refinery and $605 million from the sale of our exploration and production gas infrastructure business in the Netherlands.
     In 2006, there were no significant acquisitions. BP purchased 9.6% of the shares issued under Rosneft’s IPO for a consideration of $1 billion (included in capital expenditure). This represented an interest of around 1.4% in Rosneft. Disposal proceeds were $6,254 million, which included $2.1 billion on the sale of our interest in the Shenzi discovery and around $1.3 billion from the sale of our producing properties on the Outer Continental Shelf of the Gulf of Mexico to Apache Corporation.
     In 2005, there were no significant acquisitions. Disposal proceeds were $11,200 million, which included net cash proceeds from the sale of Innovene to INEOS of $8,304 million after selling costs, closing

Our Exploration and Production segment includes upstream and midstream activities in 29 countries, including the US, the UK, Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad) and locations within Asia Pacific, Latin America, North Africa and the Middle East. Upstream activities involve oil and natural gas exploration and field development and production. Our exploration programme is currently focused around the deepwater Gulf of Mexico, Algeria, Angola, Azerbaijan, Egypt and Russia. Major development areas include the deepwater Gulf of Mexico, Azerbaijan, Algeria, Angola, Egypt and Asia Pacific. During 2007, production came from 22 countries. The principal areas of production are Russia, the US, Trinidad, the UK, Latin America, the Middle East, Asia Pacific, Azerbaijan, Angola and Egypt.
     Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation. Our most significant midstream pipeline interests include the Trans Alaska Pipeline System, the Forties Pipeline System and the Central Area Transmission System pipeline, both in the UK sector of the North Sea, and the Baku-Tbilisi-Ceyhan pipeline, running through Azerbaijan, Georgia and Turkey. Major LNG activities are located in Trinidad, Indonesia and Australia. Further LNG businesses with BP involvement are being built up in Egypt and Angola.
     Our oil and gas production assets are located onshore or 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.

Resegmentation in 2008
With effect from 1 January 2008, the NGLs, LNG and the gas and power marketing and trading businesses were transferred from the Gas, Power and Renewables segment to the Exploration and Production segment.

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 in 2007 were $1,892 million, compared with $1,765 million in 2006 and $1,266 million in 2005. 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 47% of 2007 exploration and appraisal costs were directed towards appraisal activity. In 2007, we participated in 86 gross (37 net) exploration and appraisal wells in 12 countries. The principal areas of activity were the deepwater Gulf of Mexico, Angola, Egypt, North Sea, Canada and Pakistan.
     Total exploration expense in 2007 of $756 million (2006 $1,045 million and 2005 $684 million) included the write-off of expenses related to

Reserves and production
Compliance
IFRS does not provide specific guidance on reserves disclosures. BP estimates proved reserves in accordance with SEC Rule 4-10 (a) and relevant guidance notes and letters issued by the SEC staff.
     By their nature, there is always some risk involved in the ultimate development and production of reserves, including, but not limited to, final regulatory approval, the installation of new or additional infrastructure as well as changes in oil and gas prices and the continued availability of additional development capital.
     All the group’s oil and gas reserves held in consolidated companies have been estimated by the group’s petroleum engineers. Of the equity-accounted volumes in 2007, 16% were based on estimates prepared by group petroleum engineers and 84% were based on estimates prepared by independent engineering consultants, although all of the group’s oil and gas reserves held in equity-accounted entities are reviewed by the group’s petroleum engineers before making the assessment of volumes to be booked by BP.
     Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where title to the hydrocarbons is not conferred, such as PSAs. In a concession, the consortium of which we are a part is entitled to the reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. Thirteen per cent of our proved reserves are associated with PSAs. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam.
     We separately disclose our share of reserves held in equity-accounted entities (jointly controlled entities and associates), although we do not control these entities or the assets held by such entities.

Resource progression
BP manages its hydrocarbon resources in three major categories: prospect inventory, non-proved resources and proved reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the non-proved resource category. The resources move through various non-proved resource sub-categories as their technical and commercial maturity increases through appraisal activity.
     Resources in a field will only be categorized as proved reserves when all the criteria for attribution of proved status have been met, including an internally imposed requirement for project sanction or for sanction expected within six months and, for additional reserves in existing fields, the requirement that the reserves be included in the business plan and scheduled for development, typically within three years. Where, on occasion, the group decides to book reserves where development is scheduled to commence beyond three years, these reserves will be booked only where they satisfy the SEC’s criteria for attribution of proved status. Internal approval and final investment decision are what we refer to as project sanction.
     At the point of sanction, all booked reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s reserves depends on a later phase of activity, only that portion of reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking of PUD reserves to the start of production. Changes to reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.

Reserve replacement
Total hydrocarbon proved reserves, on an oil equivalent basis and excluding equity-accounted entities, comprised 12,583mmboe at 31 December 2007, a decrease of 4.4% compared with 31 December 2006. Natural gas represents about 56% of these reserves. The reduction includes net sales of 58mmboe, largely comprising a number of assets in the Netherlands, Pakistan, Canada and the US.
     Total hydrocarbon proved reserves, on an oil equivalent basis for equity-accounted entities alone, comprised 5,231mmboe at 31 December 2007, an increase of 15.3% compared with 31 December 2006. Natural gas represents about 12% of these proved reserves. The increase includes net sales of 3mmboe, largely comprising a number of assets in Russia.
     The proved reserves replacement ratio (also known as the production replacement ratio) is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions and discoveries, and may be expressed as a replacement ratio excluding acquisitions and divestments or as a total replacement ratio including acquisitions and divestments.

In 2007, net additions to the group’s proved reserves (excluding sales and purchases of reserves-in-place and equity-accounted entities) amounted to 414mmboe, principally through improved recovery from, and extensions to, existing fields and discoveries of new fields. Of the reserves additions through improved recovery from, and extensions to, existing fields and discoveries of new fields, 64% are associated with new projects and are proved undeveloped reserves additions. The remainder are in existing developments where they represent a mixture of proved developed and proved undeveloped reserves. The principal reserves additions were in the Norway (Skarv), the US (Liberty, Prudhoe Bay, Great White, Nakika, Thunder Horse), Trinidad (Immortelle, Manakin), Angola (Pazflor) and Canada (Noel).

Production
Our total hydrocarbon production during 2007 averaged 2,549 thousand barrels of oil equivalent per day (mboe/d) for subsidiaries and 1,269mboe/d for equity-accounted entities, a decrease of 3% and 2% respectively compared with 2006. For subsidiaries, 35% of our production was in the US and 13% in the UK. For equity-accounted entities, 72% of production was from TNK-BP.
     Total production for 2008 is expected to be higher than in 2007. This is based on the group’s asset portfolio at 1 January 2008, expected startups in 2008 and Brent at $60/bbl, before any 2008 disposal effects and before any effects of prices above $60/bbl on volumes in PSAs.