This information, insofar as it relates to 2008, has been extracted or derived from the audited financial statements of the BP group presented on pages 99-184. Note 1 to the Financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related Notes elsewhere herein.

BP sold its Innovene operations in December 2005. In the circumstances of discontinued operations, IFRS require that the profits earned by the discontinued operations, in this case the Innovene operations, on sales to the continuing operations be eliminated on consolidation from the discontinued operations and attributed to the continuing operations and vice versa.

 

 

 

Risk factors

We urge you to consider carefully the risks described below. If any of these risks occur, our business, financial condition and results of operations could suffer and the trading price and liquidity of our securities could decline, in which case you could lose all or part of your investment.

          In the current global financial crisis and uncertain economic environment, certain risks may gain more prominence either individually or when taken together. Oil and gas prices and margins are likely to remain lower than in recent times due to reduced demand; the impact of this situation will also depend on the degree to which producers reduce production. At the same time, governments will be facing greater pressure on public finances leading to the risk of increased taxation. These factors may also lead to intensified competition for market share and available margin, with consequential potential adverse effects on volumes. The financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. Any of these factors may affect our results of operations, financial condition and liquidity.

          If there is an extended period of constraint in the capital markets, with debt markets in particular experiencing lack of liquidity, at a time when cash flows from our business operations may be under pressure, this may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements.

          Our system of risk management provides the response to risks of group significance through the establishment of standards and other controls. Inability to identify, assess and respond to risks through this and other controls could lead to an inability to capture opportunities, threats materializing, inefficiency and non-compliance with laws and regulations.

          The risks are categorized against the following areas: strategic; compliance and control; and operational.

Strategic risks

Access and renewal

Successful execution of our group plan depends critically on implementing activities to renew and reposition our portfolio. The challenges to renewal of our upstream portfolio are growing due to increasing competition for access to opportunities globally. Lack of material positions in new markets and/or inability to complete disposals could result in an inability to grow or even maintain our production.

Prices and markets

Oil, gas and product prices are subject to international supply and demand. Political developments and the outcome of meetings of OPEC can particularly affect world supply and oil prices. Previous oil price increases have resulted in increased fiscal take, cost inflation and more onerous terms for access to resources. As a result, increased oil prices may not improve margin performance. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to further reviews for impairment of the group’s oil and natural gas properties. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the group’s results of operations in the period in which it occurs. Rapid material and/or sustained change in oil, gas and product prices can impact the validity of the assumptions on which strategic decisions are based and, as a result, the ensuing actions derived from those decisions may no longer be appropriate. A prolonged period of low oil prices may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate and may impact shareholder returns, including dividends and share buybacks, or share price.

Periods of global recession could impact the demand for our products, the prices at which they can be sold and affect the viability of the markets in which we operate.

          Refining profitability can be volatile, with both periodic oversupply and supply tightness in various regional markets. Sectors of the chemicals industry are also subject to fluctuations in supply and demand within the petrochemicals market, with a consequent effect on prices and profitability.

Climate change and carbon pricing

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

Socio-political

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

          We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged.

Competition

The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency. The implementation of group strategy requires continued technological advances and innovation including advances in exploration, production, refining, petrochemicals manufacturing technology and advances in technology related to energy usage. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged the industry.

Investment efficiency

Our organic growth is dependent on creating a portfolio of quality options and investing in the best options. Ineffective investment selection could lead to loss of value and higher capital expenditure.

Reserves replacement

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

Liquidity, financial capacity and financial exposure

The group has established a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity and to constrain the level of assessed capital at risk for the purposes of positions taken in financial instruments. Failure to operate within our financial framework could lead to the group becoming financially distressed leading to a loss of shareholder value. Commercial credit risk is measured and controlled to determine the group’s total credit risk. Inability to determine adequately our credit exposure could lead to financial loss. A credit crisis affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth.

          Crude oil prices are generally set in US dollars, while sales of refined products may be in a variety of currencies. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues.

          For more information on financial instruments and financial risk factors see Financial statements – Note 28 on page 140 and Note 34 on page 148.

Compliance and control risks

Regulatory

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

          For more information on environmental regulation, see Environment on page 39.

Ethical misconduct and non-compliance

Our code of conduct, which applies to all employees, defines our commitment to integrity, compliance with all applicable legal requirements, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. Incidents of ethical misconduct or non-compliance with applicable laws and regulations could be damaging to our reputation and shareholder value. Multiple events of non-compliance could call into question the integrity of our operations.

          For certain legal proceedings involving the group, see Legal proceedings on page 88.

Liabilities and provisions

Changes in the external environment, such as new laws and regulations, market volatility or other factors, could affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities.

Reporting

External reporting of financial and non-financial data is reliant on the integrity of systems and people. Failure to report data accurately and in compliance with external standards could result in regulatory action, legal liability and damage to our reputation.

Operational risks

Process safety

Inherent in our operations are hazards that require continuous oversight and control. There are risks of technical integrity failure and loss of containment of hydrocarbons and other hazardous material at operating sites or pipelines. Failure to manage these risks could result in injury or loss of life, environmental damage, or loss of production and could result in regulatory action, legal liability and damage to our reputation.

Personal safety

Inability to provide safe environments for our workforce and the public could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation.

Environmental

If we do not apply our resources to overcome the perceived trade-off between global access to energy and the protection or improvement of the natural environment, we could fail to live up to our aspirations of no or minimal damage to the environment and contributing to human progress.

Security

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

Product quality

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

Drilling and production

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

Transportation

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

Major project delivery

Successful execution of our group plan (see page 11) depends critically on implementing the activities to deliver the major projects over the plan period. Poor delivery of any major project that underpins production growth and/or a major programme designed to enhance shareholder value could adversely affect our financial performance.

Digital infrastructure

The reliability and security of our digital infrastructure are critical to maintaining our business applications availability. A breach of our digital security could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment and breaches of regulations.

Business continuity and disaster recovery

Contingency plans are required to continue or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed timeframe would prolong the impact of any disruption and could severely affect business and operations.

Crisis management

Crisis management plans and capability are essential to deal with emergencies at every level of our operations. If we do not respond or are perceived not to respond in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.

People and capability

Employee training, development and successful recruitment of new staff, in particular petroleum engineers and scientists, are key to implementing our plans. Inability to develop the human capacity and capability across the organization could jeopardize performance delivery.

Treasury and trading activities

In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation.

Forward-looking statements

In order to utilize the ‘Safe Harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995, BP is providing the following cautionary statement. This document contains certain forward-looking statements with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in Performance review (pages 6-56) with regard to strategy, management aims and objectives, future capital expenditure, future hydrocarbon production volume, date(s) or period(s) in which production is scheduled or expected to come onstream or a project or action is scheduled or expected to begin or be completed, capacity of planned plants or facilities and impact of health, safety and environmental regulations; (ii) the statements in Performance review (pages 6-45) with regard to planned expansion, investment or other projects and future regulatory actions; and (iii) the statements in Performance review (pages 46-59) with regard to the plans of the group, the cost of and provision for future remediation programmes, taxation, liquidity and costs for providing pension and other post-retirement benefits; and including under ‘Liquidity and capital resources’ with regard to oil prices, production, demand for refining products, refining volumes and margins and impact on the petrochemicals sector, refining availability, continuing priority of safe, compliant and reliable operations, and focus on cost efficiency, cost deflation, capital expenditure, expected disposal proceeds, cash flows, shareholder distributions, gearing, working capital, guarantees, expected payments under contractual and commercial commitments and purchase obligations; are all forward-looking in nature.

By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including the specific factors identified in the discussions accompanying such forward-looking statements; the timing of bringing new fields onstream; future levels of industry product supply, demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this report including under ‘Risk factors’ on pages 8-10. In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.

Statements regarding competitive position

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

Information on the company

General

          The company was incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001.

          BP is one of the world’s leading oil companies on the basis of market capitalization and proved reserves. Our worldwide headquarters is located at 1 St James’s Square, London SW1Y 4PD, UK, tel +44 (0)20 7496 4000. Our agent in the US is BP America Inc., 501 Westlake Park Boulevard, Houston, Texas 77079, tel +1281 366 2000.

Overview of the group

          BP is a global group, with interests and activities held or operated through subsidiaries, jointly controlled entities or associates established in, and subject to the laws and regulations of, many different jurisdictions. These interests and activities covered two business segments in 2008: Exploration and Production and Refining and Marketing. With effect from 1 January 2008, the former Gas, Power and Renewables segment ceased to report separately (see Resegmentation in 2008 on page 12).

          A separate business, Alternative Energy, reported in Other businesses and corporate, handles BP’s low-carbon businesses and future growth options outside oil and gas.

Exploration and Production’s activities include oil and natural gas exploration, development and production (upstream activities), together with related pipeline, transportation and processing activities (midstream activities), as well as the marketing and trading of natural gas (including LNG), power and natural gas liquids (NGLs). The activities of Refining and Marketing include the refining, manufacturing, supply and trading, marketing and transportation of crude oil, petroleum and petrochemicals products and related services. The group provides high-quality technological support for all its businesses through its research and engineering activities.

          All these activities are supported by a number of other organizational elements comprising group functions and regions. Group functions serve the business segments, aiming to achieve coherence across the group, manage risks effectively and achieve economies of scale. In addition, each regional head provides the required integration and co-ordination of group activities and represents BP to external parties.

Internal control

The group’s system of internal control is designed to meet the expectations of internal control of the Combined Code in the UK and of COSO (committee of the sponsoring organizations for the Treadway Commission) in the US. The system of internal control is the complete set of management systems, organizational structures, processes, standards and behaviours that are employed to conduct the business of BP and deliver returns to shareholders. The design of the system of internal control addresses risks and how to respond to them. Each component of the system is in itself a device to respond to a particular type or collection of risks.

Strategy

The group strategy describes the group’s strategic objectives and the assumptions made by BP about the future. It describes strategic risks and opportunities that arise from making such assumptions and the actions to be taken to manage or mitigate the risks. The board delegates to the group chief executive responsibility for developing BP’s strategy and its implementation through the group plan that determines the setting of priorities and allocation of resources. The group chief

executive is obliged to discuss with the board, on the basis of the strategy and group plan, all material matters currently or prospectively affecting BP’s performance

          During 2008, we continued to pursue our three strategic priorities of ‘Safety’, ‘People’ and ‘Performance’, which underpin BP’s ‘forward agenda’.

          Through this, we have taken steps to restore revenues, reduce complexity and manage costs and have made significant progress towards closing the competitive performance gap to our peer group. Looking forward, our strategy is to create value for shareholders by investing to deliver growth in Exploration and Production, together with high-quality earnings and returns throughout our operations. Our first priority will always be to ensure the safety and integrity of our operations.

          We expect Exploration and Production to be our core source of growth. We intend to re-invest competitively in Exploration and Production to secure and grow high-quality oil and gas resources. This investment is intended to be focused on strengthening our position further by securing new access and achieving exploration success. It is also intended to be targeted on a renewed focus on increasing recovery from fields in which we already operate. We expect to make investment across the full life cycle of our assets with an increased emphasis on technology as a source of productivity, access and competitive advantage.

          In Refining and Marketing, we expect to continue building our business around advantaged assets in material and significant energy markets. We intend to continue investing in improving the safety and reliability of our operations. Additionally, we intend to drive further operational performance and productivity by investing in the upgrade of manufacturing capabilities within our integrated fuels value chains. We also intend to invest selectively in international businesses, including lubricants and petrochemicals, where we believe there is the potential to deliver strong returns.

          In Alternative Energy, we are focusing our investment activity in new energy technology and low-carbon energy businesses that we believe will provide long-term options to meet energy demand and provide BP with significant long-term growth potential. These are wind, solar, biofuels and carbon capture and storage.

          We are dependent on our people and technology to deliver on our strategy. We intend to invest in ensuring that we have people with the right capability and experience to meet all of our objectives and the technology to support the delivery of competitive business performance and new business development. BP is committed to delivering its strategy by operating safely, reliably, in compliance with the law and within the discipline of a clear financial framework.

Geographical presence

We have well-established operations in Europe, the US, Canada, Russia, South America, Australasia, Asia and parts of Africa. Currently, around 67% of the group’s capital is invested in Organisation for Economic Cooperation and Development (OECD) countries, with around 41% of our fixed assets located in the US and around 20% located in Europe.

          We believe that BP has a strong portfolio of assets:

•

In Exploration and Production, we have upstream interests in 29 countries. Exploration and Production activities are managed through operating units that are accountable for the day-to-day management of the segment’s activities. An operating unit is accountable for one or more fields. Our current areas of major development include the deepwater Gulf of Mexico, Azerbaijan, Algeria, Angola, Egypt and Asia Pacific where we believe we have competitive advantage and the foundation for volume growth and improved margins in the future. We also have significant midstream activities to support our upstream interests. Additionally, we undertake natural gas, power and NGLs marketing and trading activity and LNG activity, which are focused on identifying and capturing worldwide opportunities for our upstream natural gas reserves, and we have an NGLs processing business in North America.

•

In Refining and Marketing, we have a strong presence in the US and Europe. In the US, we market under the Amoco and BP brands in the midwest, east and south-east and under the ARCO brand on the west coast, and in Europe, under the BP and Aral brands. We have a long-established supply and trading activity responsible for delivering value across the crude and oil products supply chain. Our Aromatics & Acetyls business maintains a manufacturing position globally, with emphasis on growth in Asia. We also have, or are growing, businesses elsewhere in the world under the BP and Castrol brands, including a strong global lubricants portfolio and other business-to-business marketing businesses (aviation and marine) covering the mobility sectors. We continue to seek opportunities to broaden our activities in growth markets such as China and India.

Through non-US subsidiaries or other non-US entities, during the period covered by this report, BP conducted limited marketing, licensing and trading activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism. BP believes that these activities are immaterial to the group.
BP has interests in, and is the operator of, two fields and a pipeline located outside Iran in which the National Iranian Oil Company (NIOC) and an affiliated entity have interests. In Iran, BP buys small quantities of crude oil. This is primarily for sale to third parties in Europe and a small portion is used by BP in its own refineries in South Africa and Europe. In addition, BP sells small quantities of crude oil into Iran and blends and markets small quantities of lubricants for sale to domestic consumers through a joint venture there, which has a blending facility. However, BP does not seek to obtain from the government of Iran licences or agreements for oil and gas projects in Iran, is not conducting any technical studies in Iran and does not own or operate any refineries or chemicals plants in Iran.

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

Market context

Our market is a complex and fast-moving environment. In 2008, volatile energy price movements mirrored unsettled financial markets and wider economic uncertainty (see Risk factors on page 8). World oil consumption fell in 2008, with growing demand in fast growing non-OECD countries more than offset by falling consumption in the OECD countries. Gas consumption grew in the major markets. Anxieties around energy security continued, with individual consumer countries facing specific issues related to cost, geography and political relationships with producers. In terms of supply, substantial global reserves of oil and gas are in place but government, energy companies and industry must work together to bring these to market. There is also a clear need for greater energy diversity to address the competing challenges of growing demand and climate change. In terms of human resources, the energy industry also faces a shortage of professionals such as petroleum engineers and scientists.

Acquisitions and disposals

There were no significant acquisitions in 2006, 2007 or 2008.

          In 2008, we completed an asset exchange with Husky Energy Inc., and asset purchases from Chesapeake Energy Corporation as described on page 47.

          In 2007, BP acquired Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis B.V. The acquisition included Chevron’s 31% minority shareholding in Nerefco, its 31% shareholding in the 22.5MW wind farm co-located at the refinery as well as a 22.8% shareholding in the TEAM joint venture terminal and shareholdings in two local pipelines linking the TEAM terminal to the refinery. Disposal proceeds were $4,267 million, which included $1,903 million from the sale of the Coryton refinery and $605 million from the sale of our exploration and production gas infrastructure business in the Netherlands.

          In 2006, BP purchased 9.6% of the shares issued under Rosneft’s IPO for a consideration of $1 billion (included in capital expenditure). This represented an interest of around 1.4% in Rosneft. Disposal proceeds were $6,254 million, which included $2.1 billion on the sale of our interest in the Shenzi discovery and around $1.3 billion from the sale of our producing properties on the Outer Continental Shelf of the Gulf of Mexico to Apache Corporation.

Resegmentation in 2008

On 11 October 2007, BP announced that it was to simplify its organizational structure by reducing the number of business segments.

          From 1 January 2008, BP has two business segments: Exploration and Production and Refining and Marketing. A separate business, Alternative Energy, handles BP’s low-carbon businesses and future growth options outside oil and gas and reports under Other businesses and corporate.

          As a result, and with effect from 1 January 2008:

•		The former Gas, Power and Renewables segment ceased to report separately.
•		The NGLs, LNG and gas and power marketing and trading businesses were transferred from the Gas, Power and Renewables segment to the Exploration and Production segment.
•		The Alternative Energy business was transferred from the Gas, Power and Renewables segment to Other businesses and corporate.
•		The Emerging Consumers Marketing Unit was transferred from Refining and Marketing to Alternative Energy (which is reported in Other businesses and corporate).
•		The Biofuels business was transferred from Refining and Marketing to Alternative Energy (which is reported in Other businesses and corporate).
•		The Shipping business was transferred from Refining and Marketing to Other businesses and corporate.

Exploration and Production

Our Exploration and Production segment includes upstream and midstream activities in 29 countries, including Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), the UK, the US and locations within Asia Pacific, Latin America, North Africa and the Middle East, as well as gas marketing and trading activities, primarily in Canada, Europe, the UK and the US. Upstream activities involve oil and natural gas exploration and field development and production. Our exploration programme is currently focused around Algeria, Angola, Azerbaijan, Canada, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea and onshore US. Major development areas include Algeria, Angola, Asia Pacific, Azerbaijan, Egypt and the deepwater Gulf of Mexico. During 2008, production came from 21 countries. The principal areas of production are Angola, Asia Pacific, Azerbaijan, Egypt, Latin America, the Middle East, Russia, Trinidad, the UK and the US.

          Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing facilities and transportation, and our NGL extraction businesses in the US and UK. Our most significant midstream pipeline interests are the Trans-Alaska Pipeline System in the US, the Forties Pipeline System and the Central Area Transmission System pipeline, both in the UK sector of the North Sea, and the Baku-Tbilisi-Ceyhan pipeline, running through Azerbaijan, Georgia and Turkey. Major LNG activities are located in Trinidad, Indonesia and Australia. BP is also investing in the LNG business in Angola.

          Additionally, our activities include the marketing and trading of natural gas, power and natural gas liquids in the US, Canada, UK and Europe. These activities provide routes into liquid markets for BP’s gas and power, and generate margins and fees associated with the provision of physical and financial products to third parties and additional income from asset optimization and trading.

          Our oil and natural gas production assets are located onshore and offshore and include wells, gathering centres, in-field flow lines, processing facilities, storage facilities, offshore platforms, export systems (e.g. transit lines), pipelines and LNG plant facilities.

          Upstream operations in Argentina, Bolivia, Abu Dhabi, Kazakhstan and TNK-BP and some of the Sakhalin operations in Russia, as well as some of our operations in Canada, Indonesia and Venezuela, are conducted through equity-accounted entities.

Our performance in 2008

Profit before interest and tax for 2008 was $37.9 billion, an increase of 37% compared with 2007. The increase was primarily driven by higher oil and gas realizations. Our financial results are discussed in more detail on pages 48-49.

          In 2008, nine major projects came onstream. Production commenced at the Thunder Horse field, with four wells in operation by the end of the year, producing around 200,000boe/d (gross) making us the largest producer in the Gulf of Mexico. We also started oil production on our Deepwater Gunashli platform in the Azerbaijan sector of the Caspian Sea. Other significant successes included the start of oil and gas production at the Saqqara and Taurt fields in Egypt. Production from our established centres including the North Sea, Alaska, North America Gas and Trinidad & Tobago, was on plan. We are also increasing our ability to get more from fields by improving our overall recovery rates through developing and applying new technology.

In terms of the continued renewal of our oil and natural gas resource base, 2008 was one of our best years this decade for new discoveries.

          Total capital expenditure including acquisitions in 2008 was $22.2 billion (2007 $14.2 billion and 2006 $13.3 billion). In 2008, there were no significant acquisitions. Capital expenditure included $2.8 billion relating to the formation of an integrated North American oil sands business with Husky Energy Inc. It also included $3.7 billion relating to the purchase of all Chesapeake Energy Corporation’s interest in the Woodford Shale assets in the Arkoma basin, and the purchase of a 25% interest in Chesapeake’s Fayetteville Shale assets, enabling further growth of our North American gas business.

          There were no significant acquisitions in 2006 and 2007. Capital expenditure in 2006 included our investment of $1 billion in Rosneft.

          Development expenditure incurred in 2008, excluding midstream activities, was $11,767 million, compared with $10,153 million in 2007 and $9,109 million in 2006.

          Looking ahead, our priorities remain the same: safety, people and performance. We will continue to strive to deliver safe, reliable and efficient operations while maintaining our flexibility so we can respond to oil price volatility.

          In 2009, oil and gas prices are expected to be significantly lower than 2008. In response we will aim to use the operational momentum generated in 2008 to continue to increase the efficiency of our cost base and to build capability for the future. We intend to retain our rigour around capital investment, in particular pacing our development to take advantage of any cost reductions in a deflationary environment, and supporting our strategy of growing the upstream business. We believe that our portfolio of assets is strong and is well positioned to compete and grow in a range of external conditions.

          Comparative information presented in the table on the following page has been restated, where appropriate, to reflect the resegmentation, following transfers of certain businesses between segments, that was effective from 1 January 2008. See page 12 for more details.

Key statistics

										$ million
		2008				2007				2006
Total revenuesa			89,902				69,376				71,868
Profit before interest and tax from continuing operationsb			37,915				27,729				30,953
Total assets			136,665				125,736				124,803
Capital expenditure and acquisitions			22,227				14,207				13,252
million barrels of oil equivalent
Net proved reserves – group			12,562				12,583				13,163
Net proved reserves – equity-accounted entities			5,585				5,231				4,537
thousand barrels per day
Liquids production – group			1,263				1,304				1,351
Liquids production – equity-accounted			1,138				1,110				1,124
entities
million cubic feet per day
Natural gas production – group			7,277				7,222				7,412
Natural gas production – equity-accounted entities			1,057				921				1,005
$  per barrel
Average BP crude oil realizationsc			95.43				69.98				61.91
Average BP NGL realizationsc			52.30				46.20				37.17
Average BP liquids realizationsc d			90.20				67.45				59.23
Average West Texas Intermediate oil price			100.06				72.20				66.02
Average Brent oil price			97.26				72.39				65.14
$  per thousand cubic feet
Average BP natural gas realizationsc			6.00				4.53				4.72
Average BP US natural gas			6.77				5.43				5.74
realizationsc
$  per million British thermal units
Average Henry Hub gas pricee			9.04				6.86				7.24
pence per therm
Average UK National Balancing Point gas price			58.12				29.95				42.19

Total revenues are analysed in more detail below.

										$ million
		2008				2007				2006
Sales and other operating revenues			86,170				65,740				67,950
Earnings from equity-accounted entities (after interest and tax), interest and other revenues			3,732				3,636				3,918
			89,902				69,376				71,868

Upstream activities

Exploration

The group explores for oil and natural gas under a wide range of licensing, joint venture and other contractual agreements. We may do this alone or, more frequently, with partners. BP acts as operator for many of these ventures.

          Our exploration and appraisal costs, excluding lease acquisitions, in 2008 were $2,290 million, compared with $1,892 million in 2007 and $1,765 million in 2006. These costs include exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs, which are charged to income as incurred. Approximately 51% of 2008 exploration and appraisal costs were directed towards appraisal activity. In 2008, we participated in 83 gross (34 net) exploration and appraisal wells in 11 countries. The principal areas of activity were Algeria, Angola, Azerbaijan, Canada, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea and onshore US.

           Total exploration expense in 2008 of $882 million (2007 $756 million and 2006 $1,045 million) included the write-off of expenses related to unsuccessful drilling activities in Azerbaijan ($105 million), Faeroes ($83 million), Egypt ($64 million), deepwater Gulf of Mexico ($38 million), and others ($33 million).

          In 2008, we obtained upstream rights in several new tracts, which include the following:

•		In the Gulf of Mexico, we were awarded 125 blocks through the Outer Continental Shelf Lease Sales 205, 206 and 207.
•		In the US Lower 48 states, we acquired 225,000 net acres of shale gas assets from Chesapeake Energy Corporation.
•		In Canada, BP acquired three licences, covering a total of approximately 6,000 square kilometres in the Canadian Beaufort Sea.
•		In India, BP acquired one block on the East Coast in the New Exploration Licensing Policy seventh round.

In 2008, we were involved in a number of discoveries. In most cases, reserves bookings from these fields will depend on the results of ongoing technical and commercial evaluations, including appraisal drilling. Our most significant discoveries in 2008 included the following:

•		In Angola, we made further discoveries in the ultra deepwater (greater than 1,500 metres) Block 31 (BP 26.7% and operator) with the Portia and Dione wells, bringing the total number of discoveries in Block 31 to 16.
•		In Algeria, we discovered natural gas in the Tin Zaouatene-1 well in the Bourarhet Sud Blocks 230 and 231 (BP 49% and operator).
•		In Egypt, we made a discovery with the Satis (BP 50% and operator) well.
•		In the UK, we made two discoveries with the South West Foinaven (BP 72% and operator) and the Kinnoull (BP 77% and operator) wells.
•		In the deepwater Gulf of Mexico, we made two discoveries with the Kodiak (BP 63.75% and operator) and Freedom (BP 25% and operator) wells.

Reserves and production

Compliance

IFRS does not provide specific guidance on reserves disclosures.
BP estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant guidance notes and letters issued by the SEC staff. As currently required, these proved reserve estimates are based on prices and costs as of the date the estimate is made.

          On 31 December 2008, the SEC published a revised set of rules for the estimation of reserves. These revised rules will be used for the 2009 year-end estimation of reserves, and have not been used in the determination of reserves for year-end 2008.

          By their nature, there is always some risk involved in the ultimate development and production of reserves, including, but not limited to, final regulatory approval, the installation of new or additional infrastructure as well as changes in oil and gas prices, changes in operating and development costs and the continued availability of additional development capital.

All the group’s oil and gas reserves held in consolidated companies have been estimated by the group’s petroleum engineers. Of the equity-accounted volumes in 2008, 18% were based on estimates prepared by group petroleum engineers and 82% were based on estimates prepared by independent engineering consultants, although all of the group’s oil and gas reserves held in equity-accounted entities are reviewed by the group’s petroleum engineers before making the assessment of volumes to be booked by BP.

          Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where title to the hydrocarbons is not conferred, such as production-sharing agreements (PSAs). In a concession, the consortium of which we are a part is entitled to the reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. Sixteen per cent of our proved reserves are associated with PSAs. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam.

          We separately disclose our share of reserves held in equity-accounted entities (jointly controlled entities and associates), although we do not control these entities or the assets held by such entities.

Resource progression

BP manages its hydrocarbon resources in three major categories: prospect inventory, non-proved resources and proved reserves. When a discovery is made, volumes usually transfer from the prospect inventory to the non-proved resource category. The resources move through various non-proved resource sub-categories as their technical and commercial maturity increases through appraisal activity.

          Resources in a field will only be categorized as proved reserves when all the criteria for attribution of proved status have been met, including an internally imposed requirement for project sanction or for sanction typically expected within six months and, for additional reserves in existing fields, the requirement that the reserves be included in the business plan and scheduled for development, typically within three years. Where, on occasion, the group decides to book reserves where development is scheduled to commence after three years, these reserves will be booked only where they satisfy the SEC’s criteria for attribution of proved status. Internal approval and final investment decision are what we refer to as project sanction.

          At the point of sanction, all booked reserves will be categorized as proved undeveloped (PUD). Volumes will subsequently be recategorized from PUD to proved developed (PD) as a consequence of development activity. When part of a well’s reserves depends on a later phase of activity, only that portion of reserves associated with existing, available facilities and infrastructure moves to PD. The first PD bookings will occur at the point of first oil or gas production. Major development projects typically take one to four years from the time of initial booking of PUD reserves to the start of production. Changes to reserves bookings may be made due to analysis of new or existing data concerning production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.

Governance

BP’s centrally controlled process for proved reserves estimation approval forms part of a holistic and integrated system of internal control. It consists of the following elements:

•

Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner.

•		Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects.
•		Internal Audit, whose role includes systematically examining the effectiveness of the group’s financial controls designed to assure the reliability of reporting and safeguarding of assets and examining the group’s compliance with laws, regulations and internal standards.
•		Approval hierarchy, whereby proved reserves changes above certain threshold volumes require central authorization and periodic reviews. The frequency of review is determined according to field size and ensures that more than 80% of the BP reserves base undergoes central review every two years and more than 90% is reviewed every four years.

For the executive directors and senior management, no specific portion of compensation bonuses is directly related to oil and natural gas reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Exploration and Production segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures.

          BP’s variable pay programme for the other senior managers in the Exploration and Production segment is based on individual performance contracts. Individual performance contracts are based on agreed items from the business performance plan, one of which, if chosen, could relate to oil and gas reserves.

Reserve replacement

Total hydrocarbon proved reserves, on an oil equivalent basis and excluding equity-accounted entities, comprised 12,562mmboe at 31 December 2008, a decrease of 0.2% compared with 31 December 2007. Natural gas represents about 55% of these reserves. The decrease includes a net decrease from acquisitions and divestments of 169mmboe, largely comprising a number of assets in Venezuela and the US.

          Total hydrocarbon proved reserves, on an oil equivalent basis for equity-accounted entities alone, comprised 5,585mmboe at 31 December 2008, an increase of 6.8% compared with 31 December 2007. Natural gas represents about 16% of these proved reserves. The increase includes a net increase from acquisitions and divestments of 199mmboe, largely comprising a number of assets in Venezuela. The proved reserves replacement ratio (also known as the production replacement ratio) is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions and discoveries, and may be expressed as a replacement ratio excluding acquisitions and divestments or as a total replacement ratio including acquisitions and divestments.

          BP estimates proved reserves for reporting purposes in accordance with SEC rules and relevant guidance. As currently required, these proved reserve estimates are based on prices and costs as of the date the estimate is made. There was a rapid and substantial decline in oil prices in the fourth quarter of 2008 that was not matched by a similar reduction in operating costs by the end of the year. BP does not expect that these economic conditions will continue. However, our 2008 reserves are calculated on the basis of operating activities that would be undertaken were year-end prices and costs to persist.

										%
		2008				2007				2006
Proved reserves replacement ratio, excluding equity-accounted entities			116				44				34
Proved reserves replacement ratio, excluding equity-accounted entities, including sales and purchases of reserves-in-place			98				38				11
Proved reserves replacement ratio, for equity- accounted entities			132				248				272
Proved reserves replacement ratio, for equity- accounted entities, including sales and purchases of reserves-in-place			172				248				239
million barrels of oil equivalent
Additions to proved developed reserves, excluding equity-accounted entities, including sales and purchases of reserves-in-placea			826				929				675
Additions to proved developed reserves, for equity-accounted entities, including sales and purchases of reserves-in-placea			751				473				936
%
Proved developed reserves replacement ratio, excluding equity-accounted entities, including sales and purchases of reserves-in-place			88				99				70
Proved developed reserves replacement ratio, for equity-accounted entities, including sales and purchases of reserves-in-place			153				101				195

In 2008, net additions to the group’s proved reserves (excluding sales and purchases of reserves-in-place and equity-accounted entities) amounted to 1,085mmboe, principally through improved recovery from, and extensions to, existing fields and discoveries of new fields. Of the reserves additions through improved recovery from, and extensions to, existing fields and discoveries of new fields, approximately half are associated with new projects and are proved undeveloped reserves additions. The remainder are in existing developments where they represent a mixture of proved developed and proved undeveloped reserves. The principal reserves additions were in the US (Arkoma, Thunder Horse, Wamsutter), Trinidad (Mango), Asia-Pacific (Tangguh), Angola (Plutão, Saturno, Vênus and Marte, and Angola LNG) and Azerbaijan (ACG).

Production

Our total hydrocarbon production during 2008 averaged 2,517 thousand barrels of oil equivalent per day (mboe/d) for subsidiaries and 1,321mboe/d for equity-accounted entities, a decrease of 1.2% and an increase of 4.0% respectively compared with 2007. For subsidiaries, 36% of our production was in the US and 12% in the UK. For equity-accounted entities, 70% of production was from TNK-BP.

          Total production is expected to be somewhat higher in 2009. The actual growth rate will depend on a number of factors, including our pace of capital spending, the efficiency of that spend (in turn depending on industry cost deflation), the oil price and its impact on PSAs as well as OPEC quota restrictions.

          The following tables show BP’s estimated net proved reserves as at 31 December 2008.

Estimated net proved reserves of liquids at 31 December 2008^{a b c}

										million barrels
		Developed				Undeveloped				Total
UK			410				119				529
Rest of Europe			81				194				275
US			1,717				1,273				2,990	d
Rest of Americas			58				56				114	e
Asia Pacific			77				69				146
Africa			464				496				960
Russia			–				–				–
Other			174				477				651
Group			2,981				2,684				5,665
Equity-accounted entities			3,125				1,563				4,688	f

Estimated net proved reserves of natural gas at 31 December 2008^{a b c}

										billion cubic feet
		Developed				Undeveloped				Total
UK			1,822				582				2,404
Rest of Europe			61				402				463
US			9,059				5,473				14,532
Rest of Americas			3,975				7,902				11,877	g
Asia Pacific			2,482				4,275				6,757
Africa			1,050				1,382				2,432
Russia			–				–				–
Other			507				1,033				1,540
Group			18,956				21,049				40,005
Equity-accounted entities			3,234				1,969				5,203	h

Net proved reserves on an oil equivalent basis

mmboe
		Developed				Undeveloped				Total
Group			6,249				6,313				12,562
Equity-accounted entities			3,683				1,902				5,585

 

 

United States

2008 liquids production at 538mb/d increased 4.9% from 2007, while natural gas production at 2,157mmcf/d decreased 0.8% compared with 2007.

          Crude oil production increased by 32mb/d, an increase of 8% from 2007, primarily driven by major projects in the Gulf of Mexico, partly offset by natural reservoir decline and the impact of hurricanes in the third quarter.

          The NGLs component of liquids production decreased by 7mb/d, driven mainly by plant turnarounds and operational issues resulting from the hurricanes in the third quarter. BP operates or has interests in NGL extraction plants with a processing capacity of 6.4bcf/d. These facilities are located in major production areas across North America, including Alberta, Canada, the US Rockies, the San Juan basin and the Gulf of Mexico. We also own or have an interest in fractionation plants (that separate the NGL into its component products) in Canada and the US.

          Gas production was 17mmcf/d lower because of natural reservoir decline and the impact of hurricanes, which was partly offset by production from shale acquisitions.

          Development expenditure in the US (excluding midstream) during 2008 was $4,914 million, compared with $3,861 million in 2007 and $3,579 million in 2006. The year-on-year increase is the result of various development projects in progress.

          Our activities within the US take place in three main areas: deepwater Gulf of Mexico, the Lower 48 states and Alaska. Significant events during 2008 within each of these are indicated below.

Deepwater Gulf of Mexico

Deepwater Gulf of Mexico is our largest area of growth in the US. In 2008, our deepwater Gulf of Mexico liquids production was 244mb/d and gas production was 40mboe/d

          Significant events were:

•		On 14 June 2008, first oil was achieved at Thunder Horse (BP 75% and operator). Thunder Horse is the world’s largest semi-submersible production facility, and is located 150 miles south-east of New Orleans. It is designed to process 250,000 barrels of oil per day and 200 million cubic feet per day of natural gas. In 2008 four wells started up with production of around 200,000boe/d (gross) at the year-end, signalling the completion of commissioning. Production started up in the Thunder Horse North field in February 2009.
•		On 3 April 2008, BP announced an oil discovery at its Kodiak prospect (BP 63.75% and operator). The well, located in Mississippi Canyon block 771, approximately 60 miles south-east of the Louisiana Coast, is in about 1,500 metres of water.
•		In September 2008, Hurricanes Gustav and Ike resulted in most of the Gulf of Mexico’s oil production being shut down. There was minimal damage to most of BP’s platforms other than to the drilling derrick on the Mad Dog platform, located approximately 190 miles south of New Orleans. The production impact of both hurricanes was a reduction equivalent to approximately 24mboe/d for the year.
•		In October 2008, BP announced an oil discovery with its Freedom well (BP 25% and operator). The well, located in Mississippi Canyon Block 948, approximately 70 miles south-east of the Louisiana Coast, is in about 1,860 metres of water. It is believed that Freedom straddles Mississippi Canyon Block 948 and Mississippi Canyon Block 992. BP owns a 67.75% interest in Block 992.

Lower 48 states

In the Lower 48 states (onshore), our 2008 natural gas production was 325mboe/d, which was up 2% compared with 2007. Liquids production was 97mb/d, down 10% compared with 2007. Total 2008 production, excluding the impacts from the 2008 hurricanes, was broadly flat compared with 2007.

          In 2008, we drilled approximately 540 wells as operator and continued to maintain a stable programme of drilling activity throughout the year.

          Production is derived from two main areas:

•		In the western basins (Colorado, New Mexico and Wyoming), our assets produced 224mboe/d in 2008.
•		In the Gulf Coast and mid-continental basins (Kansas, Louisiana, Oklahoma and Texas), our assets produced 198mboe/d in 2008.

          Significant events were:

•		In August 2008, BP acquired all Chesapeake Energy Corporation’s interest in approximately 90,000 net acres of leasehold and producing natural gas properties in the Arkoma basin Woodford Shale area for $1.75 billion. BP took over production operations on 1 November and retained three drilling rigs as part of the deal.
•		In September 2008, BP acquired a 25% non-operated interest in Chesapeake’s Fayetteville Shale assets for $1.9 billion comprising $1.1 billion in cash at closing and an $800 million commitment to fund Chesapeake’s 75% share of drilling and completion costs. $183 million of this commitment was met in 2008, with the balance expected to be paid by the end of 2009. The assets include approximately 135,000 net acres of leasehold.
•		In September 2008, in anticipation of Hurricane Gustav, operations and activity were shut down in the Pascagoula NGL plant, South Louisiana (Tuscaloosa field) and East Texas Exploration and Production operations. Also in September, Hurricane Ike resulted in every field location across South Louisiana, East Texas and the Permian Basin having production shut in. Four NGL plants, Pascagoula, Block 31, Crane and Midland, were shut down while other plants suffered production impacts due to widespread outages and disruptions in the midstream infrastructure. The impact of both hurricanes on production was a reduction equivalent to approximately 2mboe/d for the year.
•		In October 2008, BP sanctioned the Wamsutter Full Field Development plan (Phase ll). This builds on the operational and technological results of extensive field trials conducted during the past three years.

Alaska

In Alaska, BP net oil production in 2008 was 197mb/d, a decrease of 6% from 2007, due to normal decline in the large mature fields, partially offset by continued strong reservoir and well performance.

          BP operates 13 North Slope oil fields (including Prudhoe Bay, Northstar and Milne Point) and four North Slope pipelines and owns a significant interest in six other producing fields

          In addition, two key aspects of BP’s business strategy in Alaska are commercializing the large undeveloped natural gas resource within our 26.4% interest in Prudhoe Bay and unlocking the large undeveloped heavy oil resources within existing North Slope fields through the application of advanced technology.

          Significant events in 2008 were:

•

In July 2008, BP announced the commencement of development activities for the Liberty oilfield, which is located on federal leases about six miles offshore in the Beaufort Sea, and east of the Prudhoe Bay oilfield. The planned development includes up to six ultra-extended reach wells, including four producers and two injectors. These wells are expected to be the longest horizontal wells ever drilled in the world, extending two miles deep and as far as eight miles horizontally, guided by 3-D seismic imagery. A specialized rig for drilling in the Arctic is being built for the project. Drilling is expected to start in 2010, from an existing satellite pad that is being expanded for

		the project at the BP-operated Endicott oilfield. BP drilled the Liberty discovery well in 1997, and is the operator and sole owner of the field.
•		In August 2008, BP successfully tested Cold Heavy Oil Production with Sand (CHOPS) technology for the first time in Alaska, initiating a four-well production test programme during the period from August 2008 until the end of 2009. This first test at Milne Point S Pad brought oil and sand to the surface, where it was processed using temporary field facilities, combined with other light oil production, and shipped down the Trans-Alaska Pipeline System (TAPS). The CHOPS well tests are part of a multi-year programme to determine the technical and commercial feasibility of a large scale heavy oil development project on the North Slope using existing cold and thermal technologies.
•		During 2008, all four of the Prudhoe Bay Oil Transit Line segments that were targeted for replacement in response to the oil spills in the Prudhoe Bay field in March and August 2006 were completed and placed in service.

United Kingdom

We are the largest producer of oil, the second largest producer of gas and the largest overall producer of hydrocarbons in the UK. In 2008, total liquids production was 173mb/d, a 14% decrease on 2007, and gas production was 759mmcf/d, a 1% decrease on 2007. This decrease in production was driven by natural decline. Key aspects of our activities in the North Sea include a focus on in-field drilling and selected new field developments. Our development expenditure (excluding midstream) in the UK was $907 million in 2008, compared with $804 million in 2007 and $794 million in 2006. BP operates one NGL plant in the UK.

          Significant events in 2008 were:

•		In February 2008, BP and its partner, Marathon Petroleum West of Shetlands Ltd, announced a new oil discovery in UK Continental Shelf Block 204/23 (BP 72%), following drilling on the South West Foinaven prospect. BP, together with its partner, is evaluating the discovery and the potential for a two-well subsea development, tied back to the Foinaven Floating Production Storage and Offloading vessel (FPSO).
•		In May 2008, BP and its co-venturers made an oil discovery in North Sea Block 16/23s (BP 77.07%), named Kinnoull. The Kinnoull discovery and potential development options, including a subsea development tied back to BP’s Andrew field, are being evaluated.
•		During the third quarter, the first phase of offshore removal activity for the North West Hutton platform decommissioning programme was completed. This is BP’s biggest decommissioning project so far in the North Sea and has seen the removal of 22 separate topsides modules, which were then taken away by barges to the Able UK yard on Teesside for recycling and disposal. It is estimated that around 97% of the material recovered will be recycled and/or reused.
•		In December 2008, BP and BG Group agreed to exchange a package of North Sea assets. This is expected to strengthen BP’s position as a major operator in the Southern North Sea and to facilitate development activity and investment in the UK Continental Shelf. BP agreed to acquire BG’s 24.2% interest in the BP-operated Amethyst field and all its interests in the Easington Catchment Area (ECA) fields, including a 73.3% interest in the Mercury field, a 79% interest in the Neptune field, a 65% interest in the Minerva, Apollo and Artemis fields and BG’s 30.8% interest in the BP-operated Whittle and Wollaston fields. BG Group agreed to acquire BP’s interest and operatorship in the Everest (BP 21.1%) and Lomond (BP 22.2%) fields, BP’s 18.2% interest in the BG-operated Armada field and 32% of the Chevron-operated Erskine field (BP will retain 18% equity in Erskine). The deal is subject to government, regulatory and partner approvals and completion is expected in the second quarter of 2009.

Rest of Europe

Our activities in the Rest of Europe are now centred on Norway. Until February 2007, we also held exploration and production and gas infrastructure interests in the Netherlands. Development expenditure (excluding midstream) in the Rest of Europe was $695 million, compared with $443 million in 2007 and $214 million in 2006. In 2008, our total production in Norway was 47mboe/d, a 16% decrease on 2007. This decrease in production was driven by natural decline. In Norway, progress continued as planned on the Skarv and Valhall Redevelopment projects.

Rest of World

Development expenditure in Rest of World (excluding midstream) was $5,251 million in 2008, compared with $5,045 million in 2007 and $4,522 million in 2006.

Rest of Americas

Canada

•		In Canada, our natural gas and liquids production was 51mboe/d in 2008, a decrease of 1% compared with 2007. The year-on-year decrease in production is mainly due to natural field decline.
•		On 31 March 2008, BP and Husky Energy Inc. (Husky) completed a deal to create an integrated North American oil sands business by means of two separate 50:50 joint ventures, BP-Husky Refinery LLC, operated by BP, and the Sunrise Oil Sands Partnership (SOSP), operated by Husky. BP’s capital expenditure in respect of the creation of SOSP amounted to $2.8 billion.
•		In June 2008, BP successfully acquired three of five exploration licences on offer in the Canadian section of the Beaufort Sea through a Call for Bids process issued by The Department of Indian and Northern Affairs of Canada. The leases awarded to BP cover about 611,000 hectares of the Beaufort seabed, north of Tuktoyaktuk, Northwest Territories. These are in addition to the 15 significant discovery licences that BP currently holds in the Beaufort Sea, and two exploration licences currently in moratorium. The term for exploration licences issued from this Call for Bids is nine years consisting of two consecutive periods. There is a $300 million work obligation associated with acquiring these exploration licences.

Trinidad

•		In Trinidad, natural gas production volumes increased from 420mboe/d in 2007 to 422mboe/d in 2008. The increase was a result of improved operating efficiency on the Atlantic LNG Trains combined with increased demand from the domestic market and full ramp-up of two new fields, Mango and Cashima. Liquids production increased by 7mb/d (23%) to 37mb/d in 2008 from 30mb/d in 2007 as a result of an increase in NGLs associated with higher throughput for the Trains, increased crude and condensate from the two new fields and liquid optimization activities.
•		In December 2008, a new oil export pipeline was commissioned to transport liquids from offshore fields to onshore delivery points. BP owns 100% of the capacity of the pipeline.
•		Progress on Savonette, BP’s next field development in Trinidad, continued throughout the year and first gas is expected to be delivered in 2009.
•		In 2008, the Day Away from Work Case injury frequency (per 200,000 work hours) has been reduced from 0.12 in 2003 to zero in 2008 and the recordable injury frequency has more than halved in the same period. This has come about through the development and implementation of a comprehensive multi-year safety plan, focused on coaching safety leaders, workforce communication, standard implementation and continuous learning.

Venezuela

•		In Venezuela, despite the transition since 2006 of BP’s interests to incorporated joint venture (IJV) entities with the state oil company Petróleos de Venezuela, S.A. (PDVSA), and OPEC quotas, 2008 liquids production increased by 3mb/d compared with 2007.
•		In the second quarter of 2008, BP concluded the migration of the Cerro Negro operations to an IJV with PDVSA while retaining the same equity interest.

Colombia

•		In Colombia, BP’s net production averaged 38mboe/d. The reduction of 8mboe/d compared with 2007 is mainly due to natural field decline and lower gas transfers from Recetor (BP 50%) to Santiago de las Atalayas (BP 31%). The main part of the production comes from the Cusiana, Cupiagua and Cupiagua South fields, with increasing new production from the Cupiagua extension into the Recetor Association Contract and the Floreña and Pauto fields in the Piedemonte Association Contract.
•		On 20 June 2008, the National Hydrocarbon Agency gave its official approval for equalization of RC4 and RC5 Caribbean offshore blocks with partners Ecopetrol and Petrobras, with the main objective of simplifying partner relations and agreements. New equity interests resulting from this approval are BP 40.6%, Ecopetrol 32% and Petrobras 27.4%. Seismic operations for these two blocks were completed successfully. Processing and interpretation of the data to determine potential prospects for offshore field developments and drilling operations is under way and is expected to be completed in 2009.

Argentina, Bolivia and Chile

•		In Argentina, Bolivia and Chile, activity is conducted through Pan American Energy (PAE), a joint venture company in which BP holds a 60% interest, and which is accounted for by the equity method. In 2008, total PAE gross production of 250mboe/d represented an increase of 3% compared with 2007. Most of this production comes from the Cerro Dragón field in the provinces of Chubut and Santa Cruz. The field is now producing at its highest level since inception of the licence area in 1958. PAE also has other assets producing gas and liquids in the Argentine provinces of Salta, Neuguén and Tierra del Fuego, and in Bolivia, as well as interests in exploration areas, pipelines, electricity generation plants and other midstream infrastructure assets, primarily in Argentina.
•		In 2007 and early 2008, PAE was granted extensions of the two principal Cerro Dragón licence areas by the provinces of Chubut and Santa Cruz in exchange for material long-term investment commitments in exploration and production, and for long-term commitments to local community and supplier development. The licence expiry dates have been extended from 2017 to 2027, with further extension potential to 2047.
•		In May 2008, following its decree of 2006 requiring all private owners of shares in Bolivian oil and gas companies to transfer back a majority shareholding to the Bolivian national oil company Yacimientos Petrolíferos Fiscales Bolivianos (YPFB), the Bolivian government issued a second decree requiring this transfer to be made with immediate effect. PAE, as the majority shareholder of Empresa Petrolera Chaco S.A. (Chaco), a company created in the 1990s, was affected by these decrees. PAE was required to sell approximately 1% of the share capital of Chaco to YPFB, such that YPFB would own 50% plus one share of the total. From May 2008 and into January 2009, PAE was in discussions with the government regarding the decrees and options for implementation. However, on 23 January 2009, the president of Bolivia issued a decree nationalizing PAE’s shareholding in Chaco. PAE is currently evaluating all options to preserve the value of its shareholding.

•

On 26 November 2008, the Argentine government issued a decree creating a new regime called Petróleo PLUS. This regime is aimed at increasing oil production and reserves. The detailed rules of Petróleo PLUS were issued on 4 December 2008. On 15 December 2008, PAE made its first applications under Petróleo PLUS for fiscal credit certificates with the Secretary of Energy.

Africa
Algeria

•		BP, through its joint operatorships of the In Salah Gas (33.15%) and In Amenas (12.5%) projects, supplied 33mboe/d (BP net) to markets in Algeria and southern Europe during 2008. This is a decrease of 15% from 39mboe/d in 2007 as a result of lower gross volumes at In Salah due to planned turnaround maintenance and the impact of lower entitlement in our PSAs driven by higher prices, partly offset by improved operating efficiency at In Amenas. Further, BP, through its joint operatorship of the Rhourde El Baguel field, received 4.4mboe/d (BP net) of oil in 2008.
•		Sonatrach and BP announced an exploration success with the Tin Zaouatene-1 (TZN-1) discovery in the Bourarhet Sud Blocks 230 and 231. On 24 September 2008, BP moved into the second prospecting period, which lasts for a further two years.

Angola

•		In Angola, BP net production in 2008 was 202mboe/d, an increase of 45% from 2007 due to the start-up of the Mondo, Saxi and Batuque (Kizomba C, BP 26.67%) fields, and the ramp-up of the Greater Plutonio field (BP 50% and operator), more than offsetting the impact of lower entitlement in our PSAs driven by higher prices in existing fields. We expect to have invested over $15 billion in our Angolan business by 2010.
•		In January 2008, the Kizomba C project (BP 26.67%) came onstream with the start-up of the Mondo field, followed by first production from the Saxi and Batuque fields in July 2008. The Kizomba C development is located approximately 140 kilometres off the coast of Angola in water depths of nearly 800 metres.
•		In June 2008, the Plutão, Saturno, Vênus and Marte (PSVM) project was authorized by Sonangol. The programme is expected to comprise four fields that lie in the north east sector of Block 31 (BP 26.67% and operator), in a water depth of approximately 2,000 metres, some 400 kilometres north west of Luanda. Contracts have been awarded and construction work started during 2008.
•		During the third quarter of 2008, production was shut down at the Greater Plutonio FPSO located in deepwater Block 18 (BP 50% and operator), offshore Angola, due to operational issues. Production was restarted on 12 October 2008. The adverse impact on full-year production was 14mb/d.
•		In the ultra deepwater Block 31 (BP 26.67% and operator), there was further exploration success with the Portia and Dione wells, bringing the total successes for Block 31 to 16. The Portia well is located in a water depth of approximately 2,000 metres, some 386 kilometres north-west of Luanda. The Dione well is located in a water depth of approximately 1,700 metres, some 390 kilometres north-west of Luanda.

Egypt

•		In Egypt, BP net production was 121mboe/d, an increase of 25% from 97mboe/d in 2007. This increase was mainly due to the start-up of two new fields, Saqqara and Taurt, and the full-year impact from Denise, which started up at the end of 2007.
•		In January 2008, BP completed drilling a successful exploration well, Satis-1, in the North El Burg offshore concession (BP 50% and operator). The Satis-1 well was drilled in approximately 90 metres of water, some 50 kilometres offshore, and is in the Oligocene formation.
•		In January 2008, an oil discovery was announced in the North Shadwan (BP 50% and operator) concession located in the southern part of the Gulf of Suez. The NS394-1A exploration well was drilled in shallow water seven kilometres from the Hilal field. This discovery is the first new oil discovery in the south-eastern area of the Gulf of Suez in more than 10 years and is also the first discovery drilled by BP which has been facilitated by modern, high-quality, ocean-bottom cable (OBC) seismic data.
•		On 15 May 2008, oil production from the Saqqara field (BP 100%) started. The Saqqara field, operated by the Gulf of Suez Petroleum Company (GUPCO), a joint venture operating company between BP and the Eygptian General Petroleum Corporation (EGPC), is located 13 kilometres offshore in the central Gulf of Suez. Natural gas production commenced on 26 July 2008. The Saqqara development includes a jacket and unmanned topsides, three wells, and a 13-kilometre pipeline to a new dedicated onshore separation and gas processing plant at Ras Shukeir on the Gulf of Suez. Local contractors were used for design, onshore construction and offshore fabrication work.
•		In July 2008, natural gas production began from the Taurt field (BP 50%). The Taurt field is located between the Ras El Bar Concession (BP 50% and operator) and the Temsah Concession (BP 50%), 70 kilometres offshore to the north-east of Port Said, East Nile Delta. Gross Taurt production ramped up to 230mmcf/d in August. The Taurt development includes a Subsea Production System (SPS), two subsea wells, and a 70-kilometre pipeline and control umbilical back to upgraded facilities at the existing West Harbor processing plant. Taurt is BP’s first subsea development in Egypt and also the first of a planned programme of future subsea developments. Local contractors were used for onshore design/modifications and subsea structure construction.

Libya

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In Libya, BP and its partner, the Libyan Investment Corporation (LIC) commenced seismic operations on the acreage covered under the exploration and production-sharing agreement ratified in December 2007. In September 2008, the offshore seismic acquisition survey commenced in the Mediterranean waters of Libya’s Gulf of Sirt. At the end of 2008, the onshore seismic operations commenced in the northern Ghadames block.

Asia Pacific

Indonesia

•		BP produces crude oil in, and supplies natural gas to, the island of Java through its holding in the Offshore Northwest Java PSA (BP 46%). In 2008, BP net production was 22mboe/d, an increase of 18% from 18.6mboe/d in 2007 as a result of improved operating efficiencies and increased gas demand in Java.
•		BP is operator of the Tangguh LNG project (BP 37.2%), which includes offshore platforms, pipelines and an LNG plant with two production trains with a total capacity of 7.6 million tonnes per annum (mtpa). In May 2008, gas was introduced from one of the two offshore platforms into the Onshore Receiving Facility (ORF). First commercial delivery of LNG is expected in the second quarter of 2009.

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BP has a 50% interest in Virginia Indonesia Company LLC (Vico), the operator of the Sanga-Sanga PSA (BP 38%) supplying feedgas to Indonesia’s largest LNG export facility, the Bontang LNG plant in Kalimantan.

Vietnam

•		BP participates in one of the country’s largest foreign investment projects, the Nam Con Son gas project. This is an integrated resource and infrastructure project, which includes offshore gas production, a pipeline transportation system and a power plant. At midnight on 31 December 2007, the operation of the Nam Con Son Pipeline (BP 32.67%) transferred from BP to PetroVietnam (PVN). In September 2008, capacity of the Nam Con Son Pipeline was increased by 30% to allow for additional current and future expected volumes.
•		In 2008, BP net natural gas production was 61mmcf/d, a decrease of 26% from 82mmcf/d in 2007, primarily due to lower PSA entitlements. Gas sales from Block 6.1 (BP 35% and operator) are made under a long-term agreement for electricity generation at the Phu My 3 power plant (BP 33.3%).
•		BP has determined that its licences in Blocks 5.2 (BP 55.9% and operator) and 5.3 (BP 75% and operator) do not fit within its current portfolio and has decided to withdraw from them. BP is currently in active discussions with PVN, the Vietnamese government and joint venture partners to progress this withdrawal.

China

•		In 2008, natural gas production was 91mmcf/d BP net, an increase of 7% compared with 2007. This increase was mainly due to increased gas demand. A new development project was sanctioned in late 2008 to help meet the expected increase in demand in 2010 and beyond.
•		The Yacheng offshore gas field (BP 34.3%) supplies Castle Peak Power Company with feedgas for up to 70% of Hong Kong’s gas-fired electricity generation. Additional gas is also sold to the Fuel & Chemical Company of Hainan.
•		In March 2007, the National People’s Congress reduced the rate of corporation tax from 33% to 25% with effect from 1 January 2008.

Australia

•		BP is one of seven partners in the North West Shelf (NWS) venture. Six partners (including BP) hold an equal 16.67% interest in the infrastructure and oil reserves and an equal 15.78% interest in the gas and condensate reserves, with a seventh partner owning the remaining 5.32% of gas and condensate reserves. The NWS venture is currently the principal supplier to the domestic market in Western Australia and one of the largest LNG export projects in Asia with five LNG Trains in operation.
•		In 2008, BP net gas production was 380mmcf/d, an increase of 1% from 2007 primarily due to increased domestic gas demand in Western Australia and the startup of NWS Train 5 and the Angel platform in the third quarter. BP net liquids production was 29mb/d, a decrease of 15% from 2007 due to natural field decline.
•		In March 2008, the North Rankin 2 (NR2) project was sanctioned. This links a second platform via a 100-metre bridge to the existing North Rankin A (NRA) platform. On completion, NRA and NR2 platforms are expected to be operated as a single integrated facility and to recover low pressure gas from the North Rankin and Perseus gas fields.
•		In September 2008, a fifth LNG train was successfully completed and commenced production at the Karratha gas plant. Train 5 increases NWS total annual production capacity from 11.9 to 16.3 million tonnes.
•		The Angel platform (BP 16.67%) was successfully commissioned and started producing gas during October 2008. Angel has a gross production capacity of 800 million standard cubic feet of raw gas and up to 50,000 barrels of condensate per day.

Russia

TNK-BP

•		TNK-BP, a joint venture between BP (50%) and Alfa Group and Access-Renova (AAR) (50%), is an integrated oil company operating in Russia and the Ukraine. The TNK-BP group’s major assets are held in OAO TNK-BP Holding. Other assets include the BP-branded retail sites in Moscow and the Moscow region and interests in OAO Rusia Petroleum and the OAO Slavneft group. The workforce comprises more than 60,000 people.
•		BP’s investment in TNK-BP is held by the Exploration and Production segment and the results of TNK-BP are accounted for under the equity method in this segment.
•		TNK-BP has proved reserves of 7.1 billion barrels of oil equivalent (including its 49.9% equity share of Slavneft), of which 5 billion are developed. In 2008, TNK-BP’s average liquids production was 1.65mmb/d, a decrease of just under 1% compared with 2007. The production base is largely centred in West Siberia (Samotlor, Nyagan and Megion), which contributes about 1.2mmboe/d, together with Volga Urals (Orenburg) contributing some 0.4mmboe/d. About 40% of total oil production is currently exported as crude oil and 20% as refined product.
•		Downstream, TNK-BP has interests in six refineries in Russia and the Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl refinery), with throughput of approximately 34 million tonnes per year. During 2008, TNK-BP purchased additional retail and other downstream assets in Russia and the Ukraine from a number of small companies. TNK-BP supplies approximately 1,400 branded filling stations in Russia and the Ukraine and, with the additional sites, is expected to have more than 20% market share of the Moscow retail market.
•		On 9 January 2009, BP reached final agreement on amendments to the shareholder agreement with its Russian partners in TNK-BP. The revised agreement is aimed at improving the balance of interests between the company’s 50:50 owners, BP and Alfa Access-Renova (AAR), and focusing the business more explicitly on value growth.
•		The former evenly-balanced main board structure has been replaced by one with four representatives each from BP and AAR, plus three independent directors. Unanimous board support is required for certain matters including substantial acquisitions, divestments and contracts, and projects outside the business plan, together with approval of key changes to the TNK-BP group’s financial framework and of related party transactions. A number of other matters will be decided by approval of a majority of the board, so that the independent directors will have the ability to decide in the event of disagreement between the shareholder representatives on the board. BP will continue to nominate the chief executive, subject to main board approval, and AAR will continue to appoint the chairman. The three independent directors appointed to the restructured main board are Gerhard Schroeder, former chancellor of the Federal Republic of Germany, James Leng, former chairman of Corus Steel and Alexander Shokhin, president of the Russian Union of Industrialists and Entrepreneurs. In addition, significant TNK-BP subsidiaries will have directors appointed by BP and AAR on their boards. Our investment in TNK-BP will be reclassified from a jointly controlled entity to an associate with effect from 9 January 2009.
•		The parties have confirmed their agreement to a potential future sale of up to 20% of a subsidiary of TNK-BP through an initial public offering (IPO) at an appropriate future point, subject to certain conditions and the consent of the Russian authorities.
•		In 2007, BP and TNK-BP signed heads of terms to create strategic business alliances with OAO Gazprom. Under the terms of this agreement, TNK-BP agreed to sell to Gazprom its stake in OAO Rusia Petroleum, the company that owns the licence for the Kovykta gas condensate field in East Siberia and its interest in East Siberia Gas Company. Discussions to conclude this disposal continue.

Sakhalin

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BP and its Russian partner Rosneft agreed two Shareholder and Operating Agreements (SOAs) on 28 April 2008, recognizing BP as a 49% equity interest holder with Rosneft holding the remaining 51% interest in the two newly formed joint venture companies, Vostok Shmidt Neftegaz and Zapad Shmidt Neftegaz. BP also continues to hold a 49% equity interest in its third joint venture company at Sakhalin, Elvary Neftegaz, with Rosneft holding the remaining 51%. During the year, each of the three joint ventures held Geological and Geophysical Studies licences with the Russian Ministry of Natural Resources (MNR) to perform exploration seismic and drilling operations in these licence areas off the east coast of Russia. To date, 3D seismic data has been acquired in relation to all three licences. In the Elvary Neftegaz licence additional commitment 2D seismic data was acquired during 2008 in preparation for future drilling commitments. Exploration wells have been drilled in the Zapad-Shmidt Neftegaz and Elvary Neftegaz licences. In 2008, it was agreed by both shareholders to allow the Zapad-Shmidt Neftegaz licence to lapse at the end of its normal term.

Other

•		In Azerbaijan, BP’s net production in 2008 was 130mboe/d, a net decrease of 40% from 2007. The primary elements of this were the effects of significantly higher prices resulting in a change in profit oil entitlement in line with the terms of the PSA and reduced cost oil entitlement, partially offset by an increase following the start-up of the Deepwater Gunashli (DWG) platform, the ramping up of three Azeri oil-producing platforms and the Shah Deniz condensate gas platform commencing production in 2007.
•		The DWG platform complex successfully started oil production on schedule on 20 April 2008. DWG completes the third phase of development of the Azeri-Chirag-Gunashli (ACG) field (BP 34.1% and operator) in the Azerbaijan sector of the Caspian Sea. The DWG complex is located in a water depth of 175 metres on the east side of the Gunashli field. The complex comprises two platforms – a drilling and production platform linked by a bridge to a water injection and gas compression platform.
•		On 17 September 2008, a subsurface gas release occurred below the Central Azeri platform. As a precautionary measure, all personnel on the platform were safely transferred onshore. The Central Azeri platform was shut down until 19 December 2008, when following comprehensive investigation and recovery work, BP began to resume oil and gas production. Central Azeri processes oil and gas from West Azeri, and West Azeri was also temporarily shut down and then restored to normal operations on 9 October 2008. Operations of the Compressor and Water Injection Platform (CWP), which is linked by a bridge to Central Azeri, and the provision of power and injection water across three Azeri field platforms were re-established on 12 October 2008.

Middle East and South Asia

•		Production in the Middle East consists principally of the production entitlement of associates in Abu Dhabi, where we have equity interests of 9.5% and 14.7% in onshore and offshore concessions respectively. In 2008, BP’s share of production in Abu Dhabi was 210mb/d, up 9% from 2007 as a result of higher overall OPEC demand despite cuts implemented in the fourth quarter of 2008.
•		In July 2008, BP Sharjah signed a farm-out agreement with RAK Petroleum for the East Sajaa concession. Drilling of the first exploration well is expected in 2009.
•		In Block 61 in Oman, the challenges posed by the world’s largest onshore azimuth 3D seismic survey led the BP Oman team to use a ground-breaking new technique known as Distance Separated Simultaneous Sweeping (DS3). This technique allows the acquisition

		in a single day of as much seismic data as previously obtained in a week. The invention of DS3 along with some other innovations allowed an efficient and cost effective survey of the Block to be completed within a six-month period. The first appraisal well was spudded in September 2008.
•		In Pakistan, BP’s net oil production in 2008 was 8.2mboe/d, an increase of 30% from 2007, and BP’s net gas production was 28.2mboe/d, an increase of 34% from 2007 as a result of the full-year impact of BP increasing its equity in the onshore Badin asset in 2007 to 84%.
•		In Pakistan, BP received an 18-month extension until January 2010 in Phase 1 of the initial term of Exploration Licences in respect of the offshore Indus PSA.
•		On 30 December 2008, BP signed completion documents with Orient Petroleum International Inc., to acquire a 51.3% working interest, along with operatorship, in two joint venture blocks, Mirpurkhas and Khipro, located in the southern Sindh province of Pakistan.
•		On 22 December 2008, BP signed a production-sharing contract with the Indian government for a deepwater exploration block in the Krishna-Godavari Basin, offshore eastern India, which was awarded under the New Exploration Licensing Policy Seventh round. BP is the designated operator with a 30% working interest in the block. Reliance Industries Limited holds the remaining 70% working interest.