In mapping the future of BP, we began with a business purpose – a strategy, a set of assets and market positions that gave us scope, scale and potential as a leader in our industry. Today, this model describes us well – but not completely. Now our strategy is being driven further, by a belief that everything we do can – and should – be done better. Our people put this principle of operational excellence to work every day throughout BP. You can see it in the ways we aim to use resources efficiently to deliver sustainable production; confidently act first in a complex marketplace; focus on the most meaningful markets; fulfil our customers' needs; learn from our best practices; and lead by example. All to perform reliably and responsibly on behalf of our shareholders worldwide. At BP, this is how we're making the right choices.

Performance highlights

These tables and charts show the highlights of BP's achievements in 2004. They reflect more than our financial performance. Our strong profitability has allowed us to increase the dividend year on year, and we are continuing to invest in the future. Environmental and safety performance remains a key focus. We continue to make significant financial commitments in the communities in which we operate.

In this Report, BP presents pro forma results in addition to its reported results, to enable shareholders to evaluate better our performance against that of our competitors. The pro forma result is replacement cost profit excluding acquisition amortization as defined in footnote b to the reconciliation table (below). Both the pro forma result and replacement cost profit include exceptional items and non-operating items as defined in footnote a to the reconciliation table (below). The pro forma result has been derived from our UK GAAP accounting information but is not in itself a recognized UK or US GAAP measure. BP will discontinue pro forma reporting at the time it

adopts International Financial Reporting Standards with effect from the first quarter of 2005. References within BP Annual Report and Accounts 2004 to 'result' are to pro forma results. References to 'capital employed', 'operating capital employed' and 'net debt plus equity' are to these measures on a pro forma basis that excludes the fixed asset revaluation adjustment and goodwill consequent upon the Atlantic Richfield Company (ARCO) and Burmah Castrol acquisitions in 2000. 'Return', 'return on average capital employed' and the 'net debt ratio' (net debt/net debt plus equity) refer to ratios calculated using these measures.

The financial information for 2003 has been restated to reflect (a) the transfer of natural gas liquids (NGLs) operations from the Exploration and Production segment to Gas, Power and Renewables on 1 January 2004; (b) the adoption by the group of Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17) with effect from 1 January 2004; and (c) the adoption by the group of Urgent Issues Task Force Abstract No. 38 'Accounting for ESOP Trusts' with effect from 1 January 2004.

Key financial measures		$ million
	2004	2003
Pro forma result	16,208	12,858
Replacement cost profit	14,088	10,466
Historical cost profit	15,731	10,482
Per ordinary share – cents
Pro forma result	74.27	57.99
Replacement cost profit	64.55	47.20
Historical cost profit	72.08	47.27
Dividends per ordinary share – cents	29.45	26.00
– pence	16.099	15.517
Dividends per ADS – dollars	1.77	1.56

Reconciliation of reported profit/loss to pro forma result						$ million
			2004			2003
	Reporteda	Acquisitionamortizationb	Pro formaresult		AcquisitionReporteda amortizationb	Pro formaresult
Exploration and Production	18,520	1,239	19,759	14,666	1,566	16,232
Refining and Marketing	4,722	881	5,603	2,318	826	3,144
Petrochemicals	(900)	–	(900)	568	–	568
Gas, Power and Renewables	943	–	943	570	–	570
Other businesses and corporate	314	–	314	(184)	–	(184)
Replacement cost profit before interest and tax	23,599	2,120	25,719	17,938	2,392	20,330
Interest and other finance expense	(999)	–	(999)	(1,191)	–	(1,191)
Taxation	(8,282)	–	(8,282)	(6,111)	–	(6,111)
Minority shareholders' interest (MSI)	(230)	–	(230)	(170)	–	(170)
Replacement cost profit	14,088	2,120	16,208	10,466	2,392	12,858
Stock holding gains (losses), net of MSI	1,643			16
Historical cost profit	15,731			10,482

aReplacement cost profit for the period includes the net profit or loss on the sale of fixed assets and businesses or termination of operations. It also includes nonoperating items identified by the group, primarily asset write-downs/impairment, environmental and other provisions and restructuring, integration and rationalization costs. These items do not meet the criteria to be classified as operating exceptional items.

bAcquisition amortization refers to depreciation relating to the fixed asset revaluation adjustment and amortization of goodwill consequent upon the ARCO and Burmah Castrol acquisitions. The results for 2003 and 2004 include accelerated depreciation of the revaluation adjustment in respect of the impairment of former ARCO assets of $381 million and $214 million, respectively.

BP Annual Report and Accounts 2004

Dividends per share (cents/pence)

Result per share (cents)

Environmental performance

	2004	2003
Greenhouse gas emissions (million tonnes)a,b	81.7	83.4
Total number of spills (>1 barrel)c	578	635
Percentage of major operations with ISO 14001d	100	99

aBP share of emissions of carbon dioxide and methane, expressed as an

equivalent mass of carbon dioxide.

bBP share of TNK-BP emissions is not included.

c1 barrel = 159 litres = 42 US gallons.

dISO 14001 is an international environmental management standard.

Days away from work case frequencya,b (per 200,000 hours)

aAn injury that results in a person being unable to work for a day (shift) or more. b2002 data excludes Castrol and Veba contractors and Veba employees.

Return on average capital employed (%)

Senior management profile by gender and nationalitya (%)

aSenior management in 2004 includes the top 610 positions in BP.

Return to shareholders: present value of $1,000 invested ($)

Over 10 years: 1995-2004

Over 3 years: 2002-2004

Shareholder returns comprise annual share price movements, with dividends reinvested, for investments held over the period shown.

Investment in American depositary shares or equivalents for BP, Shell and Total and prime listings for ExxonMobil and ChevronTexaco.

Community investment

By region$ million
	2004	2003	2002	2001	2000
UK	11.7	12.7	13.9	14.9	15.4
(including UK charities	3.0	2.8	3.2	4.7	4.1)
Rest of Europe	6.5	8.2	6.2	8.0	5.3
USA	25.7	31.5	46.3	52.9	46.0
Rest of World	43.8	22.0	18.8	18.9	14.9
Total	87.7	74.4	85.2	94.7	81.6

By theme							$ million
	2004	incl. UKcharities2004	2003	incl. UKcharities2003	2002	2001	2000
Community
development	40.3	0.9	22.8	0.9	24.3	33.3	28.2
Education	33.3	0.6	27.1	0.4	24.2	29.5	21.3
Environment	6.0	0.2	15.4	1.0	19.8	15.5	8.3
Arts and culture	4.8	0.0	5.6	0.1	6.6	8.2	15.0
Other	3.3	1.3	3.5	0.4	10.3	8.2	8.8
Total	87.7	3.0	74.4	2.8	85.2	94.7	81.6

Health investment data for 2000-2003 is included in Environment; the equivalent 2004 data is included in Other.

Chairman's letter

Dear Shareholder BP has delivered another excellent set of results for the year. Sustained high oil and gas prices, coupled with advances in operational performance, have resulted in a strong cash flow, accelerating our returns to shareholders in the near term through significant share repurchases. Returning cash in excess of our investment requirements to our shareholders – both through buybacks and our continued pursuit of a progressive dividend policy – is fundamental to our strategy.

Exchange-rate issues – especially the relative weakness of the dollar in the past year – have been felt by those who receive their dividends in sterling. Over the longer term, fluctuating exchange rates generally benefit shareholders on each side of the Atlantic at different times. For instance, in the five-year period from 1996 to 2001, the sterling dividend rose by 58%. The rationale for declaring our dividend in US dollars remains sound, since our principal businesses all trade in that currency. While headline increases in sterling and dollar dividends show a differential, the key element to note is that both are growing.

2004 has seen a rapid acceleration of our buyback programme, with $7.5 billion worth of shares bought back and cancelled during the year. While this has been welcomed by larger and institutional investors, the benefit for all shareholders committed to long-term investment in BP will be felt through the ultimate capital appreciation of their shares. The board keeps its strategy in this area under review to ensure the balance between dividend and buybacks remains appropriate for our owners as a whole.

Against this background, our confidence in the future of the business enables us to make a step change in the fourth-quarter dividend, which I am pleased to confirm as 8.50 cents per share. This makes the annual payment 29.45 cents per share or 16.099 pence per share, an increase in dollar terms over last year of 13% and an increase of 4% in sterling terms.

2004 saw heightened regulatory attention on our industry, not least in the area of the reporting of hydrocarbon reserves. Reserves reporting is an important measure of our performance as it demonstrates the extent to which we are replacing the hydrocarbons we are producing – a particular strength of BP in recent years. As a UK company, our reserves are estimated in accordance with UK accounting practice. These reserves are stated each year in our Annual Report. For US regulatory purposes we report reserves estimates in accordance with the rules of the Securities and Exchange Commission. During the course of the year, the board and its audit committee have exercised considerable scrutiny in this area. In this year's Annual Report, we have included, for the first time, US SEC-based estimates in addition to our UK reserves bookings.

Our business is global and complex, and we are fortunate to have a first-rate executive team to address these challenges. During the year, the executive management team, so ably led by John Browne, has sustained its formidable track record. They have our full confidence and support. I would like to thank John and his team for their exemplary efforts on your behalf in 2004. Our thanks are also due to all 102,900 BP employees

around the world for their unremitting effort and the value they have created for our shareholders.

Within a company with such a strong executive management team, it is important that the role of the board is understood. As a board, we are conscious that we oversee the activities of the business in the interests of all our owners. The recent debate on corporate governance has focused on the mechanisms of board process and reporting – ensuring appropriate checks and balances are in place. Against this background, too many company directors have complained that they want to 'move away from corporate governance' and 'get back to running our businesses'.

Correctly, I think, our board recognizes that the primary business of the board is corporate governance. Governing BP is not a matter to be driven solely by compliance concerns, but by the business purpose of the company you entrust us to govern on your behalf. Our role as a board therefore focuses on ensuring your interests are promoted and that our business maximizes long-term value for you, our owners.

Ensuring that our business remains nimble and competitive, able to leverage the manifold talents of our managers, is key to the pursuit of that goal. To discharge the trust you place in us as a board, we test the strategic direction of the company's business. We also monitor the operations of the business in pursuit of that strategy to ensure both that BP's activities live out the values we set and also, critically, that shareholder value lies at the heart of all we do.

2004 saw a continuation of our very significant capital investment programme that is key to the long-term future of our business. As a board, we continue to scrutinize the strategic direction of the company, especially as our activities take us to more challenging geographic locations, to ensure that it continues to provide the prospect of the best long-term returns for our shareholders.

In the course of the year, significant work has been undertaken by the chairman's committee and the nomination committee, both of which I chair, as issues of executive and non-executive succession planning and performance come into ever-greater focus. Likewise the remuneration committee, led by Sir Robin Nicholson and his designated successor Dr DeAnne Julius, has been heavily engaged in the development of new incentive plans for our executive directors.

The board performance report on pages 110-115 expands upon the way in which the board and its committees discharge their mandate of governance.

Last year, I commented on board succession and development planning for the coming years. At the forthcoming AGM, two of our senior non-executive directors, Sir Robin Nicholson and Charles (Chuck) Knight, will step down.

Robin has served on the BP board since 1987 and has been an excellent chairman of our remuneration committee. He has had a substantial impact on the board and the company over the past 17 years and been a major contributor to all our board debates; we shall miss his wisdom and insight. On a personal note, I shall miss his sage counsel and technical insight, but am delighted that he has agreed to continue to

chair the group's technology advisory committee in the short term.

Chuck Knight also joined the board in 1987. His perspective on corporate practices in the United States and experience as a senior chief executive operating within the US market have proved invaluable, not least as BP has evolved in that marketplace over the past two decades. I will miss his unique contributions to the board's discussions.

I would like to thank both Robin and Chuck on your behalf for all their years of distinguished service.

The endorsement of the strength of our executive team by the invitation extended to Dick Olver to take on the chairmanship of BAE Systems plc was, of course, tinged with sadness at having to bid farewell to a first-rate colleague, who had served the company so well over the past 31 years. We wish Dick well for the future and thank him for his years of dedicated service to BP.

Three new appointments have been made to the board in the last year. Iain Conn has been appointed an executive director. Iain has had a substantial career within BP and is responsible for strategic resources. Sir Tom McKillop, chief executive of AstraZeneca PLC, joined the board in July 2004 and Douglas Flint, chief financial officer of HSBC Holdings plc, joined in January 2005. Each brings his own particular skills and experience to complement those of his fellow directors in the coming years.

The world in which BP operates is ever more complex and challenging. The coming year will see the continued development of our business strategy. I believe your board is well resourced to address shareholders' interests during this period. I look forward to reporting on their successful advance in the years ahead. We have an exciting future together.

Thank you for all your continued support and interest in this company.

Peter Sutherland Chairman 7 February 2005

Group chief executive's review

Dear Shareholder 2004 was a great year for BP. In terms of overall performance, it was the best since the recent series of mergers and acquisitions.

High demand for energy and higher oil prices certainly contributed to our performance and led to our record financial results. But our success in 2004 was based on more than these external factors.

We showed that we had the capability to deliver our strategy and to translate our scope and scale into competitive advantage. We demonstrated that we had the human talent to increase production, make new discoveries, gain new customers, enhance safety and grow our reputation. Our global workforce worked as a seamless team and I thank every one of them.

As you read this Annual Report and follow our efforts to create value, it may be helpful to understand how we achieve excellent performance.

Our purpose and strategy We begin with our purpose as a group – to provide better goods and services in the form of light, heat, power and mobility to increasing numbers of people. To succeed, we do this in a way that is profitable, sustainable and consistent. This is reflected in value generated for shareholders.

To deliver profitable performance, we provide high-quality products in a competitive way – maximizing revenues and minimizing costs.

To deliver sustainable performance, we also provide these products in a sustainable way – attracting the best people, accessing large-scale oil and gas resources, building markets in which we enjoy customers' trust while doing business in a mutually advantageous way that brings benefits to everyone concerned – customers, communities, governments, suppliers, citizens – and so generates 'repeat business'.

To deliver consistent performance, we invest enough to deliver long-term growth, while balancing this with returns to our shareholders. Too fast a growth rate is unsustainable, while too slow a rate sacrifices competitive advantage. Our analysis gives us confidence that an investment level of around $14 billion is right for 2005 and 2006, taking into account the present level of the dollar and recent sector-specific inflation.

To achieve our purpose, we have a strategy. We make choices about the assets and markets where we operate.

Our business strategy remains unchanged. In Exploration and Production, we seek out long-term assets – the largest, low-cost, new hydrocarbon deposits – while managing the decline of mature fields. In our customer-facing businesses, we look to attract more and more customers through improved quality of products and service. Our challenge is to add new sources of cash flow whose cash returns are at least as good as existing ones.

2004 in context As I wrote last year, we started 2004 with greater scale, common values and a clear strategy. But nothing was a given. We were cautious about our ability to execute – whether our people operating in 100 countries could effectively translate our worldwide assets into world-class performance.

We were wary of global developments, including ongoing conflict in Iraq, the threat of terrorism and public mistrust of large companies. And we found ourselves in one of the more volatile oil markets in history, driven by demand and anxiety about supply. Against this backdrop, the team delivered record performance.

As the world's energy market entered uncharted territory in 2004, the subject of the future of energy supply took centre stage. Rising demand – which matched the rate of global economic growth for the first time in 30 years – produced both short-term anxiety about fuel prices and long-term concern about supply. Had there been a fundamental shift in the oil market? Were there enough reserves? What else could disrupt supply? Were companies investing enough to meet demand?

In this uncertain climate, a little history can be reassuring. Clearly, questions over security of supplies have driven oil prices upwards. But, amid all the market disruptions of the past few years, supply has never fallen short of demand. Increased investment by the private sector has led to production gains of more than 15% a year during the last five years. Global production in 2004 rose at the fourth-highest rate in history.

Choosing our goals We execute our strategy against the context of the time. We make plans to achieve three targets:

To underpin growth by a focus on performance, particularly on cash returns, investing at a rate appropriate for long-term growth.
To increase dividends.
To return to shareholders, by way of share buybacks, 100% of free cash flow generated above what is needed for investment and dividends: this generally occurs, all other things being appropriate, when the price of oil exceeds $20 a barrel.

These plans are executed by applying resources and capabilities across the organization.

In last year's report, I wrote that organizational alignment and operational excellence would shape our future as a group and that we had developed a new management framework to harness the energy and imagination of our people. In 2004, we took further steps to embed these common values and processes, clarifying individual accountability. In 2005, we will issue a new code of conduct to ensure that each individual in BP continues to exhibit high and consistent standards of ethical behaviour.

We continue to innovate and apply leading-edge technology. For example, our new Thunder Horse platform in the deepwater Gulf of Mexico breaks many records as the largest floating facility and will operate in the deepest water, with the harshest reservoir pressure and temperature regime.

We also continue to strengthen the development opportunities that we offer to our people. For example, we have the Projects Academy, in which we partner with the Massachusetts Institute of Technology to help people gain best-in-class project management skills.

We measure the views of our staff through a People Assurance Survey. In 2004, this showed a significant rise in

the overall employee satisfaction index, demonstrating an increasing sense of enthusiasm and teamwork among BP's employees.

Reaching new milestones In a year of great success, there were notable operational highlights:

Our safety record improved for the eighth year running, although tragically we still suffered 11 fatalities among contractors and employees.
Exploration and Production made new discoveries in Angola, Egypt, the deepwater Gulf of Mexico, Trinidad and Sakhalin Island in Russia and brought on stream three new fields.
Our production growth of more than 10% was in line with our indicator of a 7% average for 2003-2008.
Replacement of proved reserves (for subsidiaries and equity-accounted entities) at over 100% exceeded production for the 12th year running. TNK-BP contributed $1.5 billion, after interest and tax, to our result, paid to us $1.9 billion of dividends and increased oil production volumes by 14%.
In Refining and Marketing, refining margins reached their highest levels since at least 1990. We continued to find ways to maximize our global refining capacity.
Premium Ultimate fuels have been newly launched in six markets, attracting new customers to these higherperformance, cleaner, higher-margin products.
BP's retail sales continued to outpace the sector. At our convenience locations worldwide, sales per square metre grew by an average of 3%.
We entered into agreements to sell liquefied natural gas to the US, China, South Korea and Mexico, and produced growth in sales volumes.
Our solar business streamlined its operations, tightened its market focus and delivered its first profit.
We initiated the separation of the Petrochemicals business

into two entities, while still achieving record sales volumes through increased plant use and reliability.

• Through disciplined portfolio management, we made $5 billion of divestments.

Through our activities, BP delivered a record result of $16.2 billion in 2004. With cash inflow of $6 billion and cash returns of 35%, our performance continued to allow for strong investment in our long-term growth as well as to return value to investors in the form of higher dividends – 29.45 cents per share in 2004, an increase of 13% year on year – and significant share buybacks, amounting to $7.5 billion in the year.

BP now has the assets, market positions and organizational capability to continue to deliver its unchanged strategy.

We are meeting our three targets, with disciplined investments, increased dividends and excess free cash flow for significant share buybacks.

We have confidence in our ability to perform sustainably, focusing mainly on conventional oil and gas resources, seeking to add value to products and services in customerfacing businesses.

In my many meetings with BP people around the world, I am constantly struck by their commitment to deliver everimproved performance, but responsibly and with integrity. My role is to provide the framework that guides and encourages them to make the right choices: today, tomorrow and for the long-term future of your company. As always, the best is yet to come.

The Lord Browne of Madingley Group Chief Executive 7 February 2005

What makes a business choice disciplined? What turns complexity into clarity? What connects customer insight to market performance? What converts creativity into productivity? And how do we put our principles into practice?

The fact is, there is no formula for operational excellence. There's no patented system, established path or single way to achieve it. For every company that competes on a global basis, the journey to operational excellence is unique. For BP, operational excellence enables us reliably and responsibly to deliver our strategy. From the assets we've built to the returns we offer our investors – and the ideas we turn into action along the way – individuals and teams across BP are putting operational excellence into practice, making it an organizational principle, not simply an aspiration.

Resourcefulness on a new scale

Our resources business is about renewal. We operate within the world's largest supply-and-demand relationship, a marketplace in which our long-term success depends on the ability of our teams to replace reserves at least as fast as they bring them to market. So how have we done? As we describe later, in each of the last 12 years, we've replaced more than100% of our production and, at the same time, delivered some of the lowest finding costs in our industry. Developing our resources through operational excellence is converting our scale into profitability. Turning our technologies into discoveries. Bringing our projects into production. Connecting our exceptional people through best practices. And extending the potential of the world's energy resources.

Seeing into the future Discovery never ends. That's a principle our people learned long ago. Even in the most mature oil and gas fields, there is hidden potential – if you know where and how to look. Egypt is a great example. As global gas demand and infrastructure have grown, we've rewritten our strategy there. As well as extending the productivity of existing oil fields, BP teams are now applying new technology and capital to discover natural gas resources. In the Nile Delta, leading-edge aeromagnetic and seismic technology is allowing our exploration team to 'see' beneath the sea floor, taking them through deeper water towards uncharted gas reservoirs. The team's efforts in imaging, interpretation, integrated planning, testing and drilling have turned their raw data into real potential, and in 2004 confirmed the presence of a promising new gas field, called Raven. What's the next boundary? The team's newest wells will determine the Raven field's size. But they are already contributing towards BP's development of a major liquefied natural gas (LNG) business to help meet the world's growing demand for cleaner energy.

A mature outlook Conventional oil business wisdom holds that, once a field has reached maturity, its descent into unprofitability is almost inevitable. At BP, however, our people tend to see 'mature' fields differently. Since 2000, our existing profit centres have been run with an efficiency that's led to an average replacement rate of 72% for the proved reserves they have produced over this period. These 'mature' operations, some of which date back to the 1960s, have maintained their vitality. Today, their output is projected to decline at a modest 3% annually until 2008. What's made this possible? Discipline, creativity and the kind of operating efficiency that comes from decades of knowledge and innovative team practices in the field. We aim to extend this life expectancy. In established fields from Alaska to the North Sea, our teams are applying remote control and online field management, increasing well recovery rates, streamlining maintenance and even tapping into new discoveries. All of which means they're getting more from our existing hydrocarbon base with greater reliability and predictable cost – producing our resources as efficiently as we discover them.

Producing in new dimensions How much? How long? What next? These are the biggest questions in the world of energy today. Part of the answer is a broader set of skills in production – creativity, efficiency, speed – to bring discoveries consistently and responsibly to market. In oil and gas fields worldwide, our people are helping to make us productive at an unprecedented scale. We now find oil and deliver new production with an efficiency that's on a par with the industry's best. The ideas, energy and organization of our teams have also led us into our most prolific era for operational start-ups. Over the last two years, we have completed nine major projects. From now until December 2006, we have 10 more major oil and gas project completions planned, including some of the world's largest construction projects in some of the most geologically challenging locations. Among them is the Gulf of Mexico, where our teams are redefining what is possible in deepwater operations at four fields simultaneously under development, including the massive Holstein platform (above).

The best routes to market

In today's energy marketplace, bringing resources to the world involves far more than making deliveries. It takes a business model that consistently finds the most efficient ways of getting there. After years of building assets in the natural gas marketplace, BP is now one of the world's largest non-state gas companies in terms of production and sales volumes. In the world's largest gas market, North America, we sell the largest volumes of end-user and wholesale gas, and are one of the largest marketers of natural gas liquids. Globally, in liquefied natural gas we are the second largest non-state supplier of gas into liquefaction plants. But our real advantage goes beyond our size and reach. It's the way our people run our businesses – the commercial and operational practices they use to open up markets for tomorrow and maximize the value of our resources today.

Building a mobile pipeline The distance between a natural gas field and a market can be measured in miles. It can also be calculated in years. BP's LNG strategy is bringing our gas closer to market. To capture a growing share of future customers for cleaner natural gas, our LNG teams have built a flexible system to supply growing demand – a 'mobile pipeline' to serve major regional markets and meet the needs of customers in the US, UK, Spain, Japan, South Korea and China. These locations increasingly rely on gas imports for primary energy and electricity needs, but they are often far from sources of natural gas. LNG bridges the gap: gas is lifted from underground, chilled to liquid, transported on ships from one part of the world to another, and then warmed back into gas to fuel a power plant, factory or home. As well as managing long-term point-to-point contracts, we are able to use our own ships to direct LNG to markets where demand is greatest and value highest – opening new markets and using the open seas to supply them.

Making the right choices

Flowing with information In the marketplace for oil and gas, one of the most valuable commodities is intelligence – the ability to understand and interpret market information. You'll find our people at this intersection of supply and demand. Their minute-by-minute knowledge of the direction of supply and demand on a global basis is a discipline that allows our teams to find the most productive links between assets and across supply chains. To streamline manufacturing flows. And to serve our customers distinctively and with competitive advantage. We do this by making a significant investment in digital and communications technology. We align that investment with a host of 'people' capabilities – human strengths in analysis, logistics, trading and risk management. Our people use real-time data, information systems, transaction automation and their own trading wisdom to act on some of the best available market intelligence worldwide. All this allows BP to connect the dots in ways that others might not see, giving our customers a better level of service. That's how we take decisions that help to make the most of our resources.

Fine-tuning refining In refining, what matters more – processes or people? Traditional industry benchmarks for operational excellence in the refining business focus on uptime, the reliability of plant and equipment and the productivity of the manufacturing process. But people in our refining operations find that their individual actions – large and small – can help to set an even higher standard. Since 2002, our global refining workforce has started thinking of reliability in personal terms. By adopting the mindset of a High Reliability Organization (HRO), decision-making happens at the level where the knowledge and expertise reside. And this leads to faster, better decisions that drive consistent, high-quality operating performance and commercial production. More than a management technique, HRO is a way of thinking that encourages team members to speak out, find root causes of problems and take action early when they catch even the smallest failures. HRO is the way refining thinks best – and the best way we know to perform reliably for our customers.

Getting closer to customers

Every day, in locations around the world, our people serve about 13 million customers. To put this in perspective, our businesses and brands – among them BP, Castrol, ARCO, Aral, Ultimate, Connect and am/pm – reach nearly as many customers as Wal-Mart, the world's largest retailer. But to be operationally excellent where our products meet the marketplace, our customer relationships have to be defined by quality as well as quantity – the distinctiveness and competitiveness of what we offer and the operating processes that underpin customer experiences. Our customer-facing businesses are gaining advantage and improving performance by carefully determining what customers want. By being consistent and creative in meeting those needs. By strengthening brands through innovation. And by locating facilities where they can most effectively and conveniently deliver our offers.

Building a better brand In the minds of our customers, what our products stand for is just as important as what we make. This means that not only our investment in assets but also every decision we make in choosing routes to market must be sustained by careful management of our brands. As the face of BP, our brands are more than just logos. They are business assets. In combination with the well-defined advantages of our products, they tell a compelling story to our customers – the kind that builds preferences and sustains relationships. Which is why our brands rely on operational excellence. They include Ultimate, which is consistently ranked as the highest quality premium retail fuel by random samples of motorists. In lubricants, our Castrol brand has used its technological advantage, rigorous segmentation and customer loyalty to drive sales consistently ahead of market growth. Our updated and expanded retail locations are accelerating operating performance, increasing customers and driving sales per square metre. Applying operational excellence to the marketplace makes our brands more meaningful – and our businesses more valuable.

Driven by distinctiveness In striving for operational excellence, where you choose to compete is often as important as how efficiently you do it. BP's lubricants team has proved that effective strategic choices in market segmentation, customer relationships and brand visibility can enhance the value of assets and accelerate growth. In global lubricants markets, characterized by limited volume growth and increasing competitive pressure, BP stands out. Our marketing strength, technological distinctiveness and premium position have led to above-market year-on-year sales growth in automotive lubricants. What makes us different? While we sell lubricants, led by Castrol, in more than100 countries worldwide, our people think in terms of market segments – motorcycles, passenger cars, trucks and vehicle manufacturers – rather than marketplaces. This perspective allows them to capture customers for whom our technology, consumer insight and brands add value and can generate higher returns for BP. In applying this strategy to new markets such as China, where lubricants growth is dramatic and preferences form quickly, our teams are already capitalizing on the strength of our brands to build distribution channels, market share and customer loyalty.

Solving the solar equation We all know the appeal of solar power – sustainability, acceptability and independence. Yet its potential as an energy source has often been overshadowed by its economics as a business. At least until now. Beginning in 2003, our BP solar team refocused its activities to become the profit centre that it could be – better understanding customers, operating at the right scale and reaching the best markets. We're now running a profitable solar operation – still small by BP standards, but one that grew its megawatt capacity sales of photovoltaic equipment by more than 30% in 2004. This performance is being driven by manufacturing consolidation, product innovation and, in particular, the team's focus on eight global sectors where well-defined customer needs, improved system performance and government incentives converge. A good example is Germany, the world's second largest solar market after Japan. Our large commercial installation at Geiseltalsee (above) provides sustainable benefits on two fronts: the field generates four megawatts of power, enough to supply 1,000 four-person households each year, and has reclaimed the site of a former oil depot.

The point of excellence

Our upstream and downstream activities reach not only the marketplace but also investors, regulators, government leaders and the public. Our abilities as an organization to sustain and improve our standing among these groups are key to our definition of operational excellence. These abilities support our new scope and scale while retaining the diverse heritage of our people and businesses. They help equip BP with the skills, knowledge and reputation that enable us to conduct business in a chosen country – and let us navigate an increasingly complex and unpredictable world with sensitivity.

Our human potential In business in general, and within BP in particular, the relationship between employee and performance is unbreakable. Simply put, our employees hold the knowledge, skills and energy that enable our enterprise to thrive. At BP, operational excellence includes the ways in which we expand our employees' range of possibilities as they expand ours. A good example is our Projects Academy. In 2003, we began working with the Massachusetts Institute of Technology (MIT) to change how our teams deliver major projects. Focusing on project leadership, business knowledge and technical excellence, the MIT programme is bringing BP's senior project leaders together with recognized leaders in engineering and project management. The first two Projects Academy classes graduated in 2004. Their members are already applying new insights to manage the complexity of their projects, understand team dynamics, clarify priorities and build a well-connected network of ideas. The Projects Academy, Marketing Academy and other practical initiatives give BP the capacity to learn and share knowledge on an everyday, global basis, and to grow our most prized resource – our people.

Financial performance

Business environment

Trading conditions in 2004 were affected by tight supplies in oil markets and by strong world economic growth.

Average crude oil prices in nominal terms in 2004 were the highest for 20 years, driven by exceptionally strong global oil demand growth and the physical disruption to US oil operations caused by Hurricane Ivan. The Brent price averaged $38.27 per barrel, an increase of more than $9 per barrel over the $28.83 per barrel average seen in 2003, and varied between $29.13 and $52.03 per barrel.

Natural gas prices in the US were also strong during 2004. The Henry Hub First of the Month Index averaged $6.13 per million British thermal units (mmBtu), up by more than $0.70 per mmBtu compared with the 2003 average of $5.37 per mmBtu. Prices fell slightly relative to oil prices as the levels of gas in storage rose sharply. UK gas prices were also up strongly in 2004, averaging 24.39 pence per therm at the National Balancing Point compared with a 2003 average of 20.28 pence per therm.

Refining margins averaged record highs in 2004, despite weakening towards the end of the year. This reflected strong oil demand growth and record refinery throughput levels. Retail margins weakened in 2004, as rising product prices and price volatility made their impact in a competitive marketplace.

In Petrochemicals, generally improved market conditions led to a gradual increase in both volumes and margins through the year. Such gains were, however, partially offset by high and volatile energy and feedstock prices, together with adverse foreign exchange impacts.

Results

BP's result for the year was $16,208 million, compared with $12,858 million in 2003. The result per share was 74.27 cents, an increase of 28%. Replacement cost profit was $14,088 million (2003 $10,466 million). Both the result and replacement cost profit include exceptional and non-operating items.

The return on average capital employed was 20%, compared with 18% in 2003. On a replacement cost basis, the 2004 return was 15% (2003 12%), and 17% (2003 12%) on a historical cost basis.

Net exceptional gains of $815 million before tax principally relate to gains from the sale of our interests in PetroChina and Sinopec and the divestment of certain upstream interests, partly offset by net losses on a number of business sales and facility closures.

Non-operating items in 2004 were a net charge of $2,120 million before tax and are shown on page 25. The majority of the asset write-downs and impairments relate to the Petrochemicals segment, reflecting the portfolio separation described on page 28.

Interest expense was $642 million, compared with $644 million in 2003. This primarily reflects lower interest rates and debt buyback costs and an increase in capitalized interest, offset by the inclusion of BP's share of a full year's interest expense from TNK-BP in 2004.

Corporate tax expense was $8,282 million (2003 $6,111 million), representing an effective tax rate of 34% on the pro forma result (2003 32%).

Historical cost profit was $15,731 million, including exceptional net gains after tax of $1,076 million and stock holding gains of $1,643 million. The corresponding figures for 2003 were $10,482 million profit, $708 million net gains and $16 million gains respectively.

Capital expenditure and acquisitions amounted to $17,249 million, including $1,354 million for including TNK's interest in Slavneft within TNK-BP and $1,355 million for the acquisition of Solvay's interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America. Excluding acquisitions, capital expenditure was $14,408 million, compared with $13,986 million in 2003.

Net cash inflow for the year was $6,038 million, compared with an inflow of $1,405 million in 2003; higher operating cash

Reconciliation of reported profit/loss to pro forma result						$ million
			2004			2003
	Reporteda	Acquisitionamortizationb	Pro formaresult		AcquisitionReporteda amortizationb	Pro formaresult
Exploration and Production	18,520	1,239	19,759	14,666	1,566	16,232
Refining and Marketing	4,722	881	5,603	2,318	826	3,144
Petrochemicals	(900)	–	(900)	568	–	568
Gas, Power and Renewables	943	–	943	570	–	570
Other businesses and corporate	314	–	314	(184)	–	(184)
Replacement cost profit before interest and tax	23,599	2,120	25,719	17,938	2,392	20,330
Interest and other finance expense	(999)	–	(999)	(1,191)	–	(1,191)
Taxation	(8,282)	–	(8,282)	(6,111)	–	(6,111)
Minority shareholders' interest (MSI)	(230)	–	(230)	(170)	–	(170)
Replacement cost profit	14,088	2,120	16,208	10,466	2,392	12,858
Stock holding gains (losses), net of MSI	1,643			16
Historical cost profit	15,731			10,482

flow and higher dividends from joint ventures were partly offset by higher tax payments, lower disposal proceeds and higher acquisition spending. Net cash outflow for capital expenditure and acquisitions, net of disposals, was $11,954 million (2003 $9,672 million). During 2004, we made incremental payments of $395 million into a number of the group's pension funds (2003 $2,533 million).

The group's net debt, that is debt less cash and liquid resources, was $21,607 million at the end of 2004, compared with $20,193 million at the end of the previous year. The ratio of net debt to net debt plus equity was 24%, at the bottom of the target range, compared with 26% a year ago. On a reported basis, the percentage was 22% (2003 22%).

In addition to reported debt, BP uses conventional off balance sheet sources of finance such as operating leases and borrowings in joint ventures and associates. The group has access to significant sources of liquidity in the form of committed facilities and other arrangements.

Dividends and share repurchases

The total dividends announced for 2004 were $6,371 million, against $5,753 million in 2003. Dividends per share for 2004 were 29.45 cents, an increase of 13% compared with 2003. In sterling terms, the dividend was 4% higher. This increase is a result of our strong cash flow and improvements in underlying performance in line with strategy. In addition, our confidence in the future enabled us to make a step change in the fourth quarterly dividend. The board sets the dividend based upon the prevailing circumstances of the group, future investment patterns and the sustainability of the group, and the future trading environment. The steady increases in the dollar dividend in recent years reflect the board's progressive dividend policy.

BP intends to continue the operation of the Dividend Reinvestment Plan (DRIP) for shareholders who wish to receive their dividend in the form of shares rather than cash. The BP Direct Access Plan for US and Canadian investors also includes a dividend reinvestment feature.

The group aims to demonstrate financial discipline by balancing cash in and cash out over time. When trading conditions are favourable, cash flow may be in excess of what is needed for operational requirements, including funding the capital programme and any acquisitions and dividend payments. As part of giving a return to shareholders, one of the steps we take from time to time is to repurchase our own shares. During 2004, a total of 827 million shares were repurchased and cancelled at a cost of $7,548 million. The repurchased shares had a nominal value of $207 million and represented 3.7% of ordinary shares in issue at the end of 2003. Since the inception of the share repurchase programme in 2000, 1,602 million shares have been repurchased and cancelled at a cost of $13.5 billion. BP intends to continue making share repurchases, subject to market conditions and continuing authority at the April 2005 annual general meeting.

During the year, shares to the value of $1.25 billion were issued to Alfa Group and Access-Renova (AAR) as the first instalment of the deferred consideration for our investment in TNK-BP. Two more instalments of $1.25 billion are due in the third quarters of 2005 and 2006.

External environment

	2004	2003
BP average liquids realizations ($/barrel)	35.39	27.25
Brent oil price ($/barrel)	38.27	28.83
BP average natural gas realizations
($/thousand cubic feet)	3.86	3.39
Henry Hub gas price ($/mmBtu)	6.13	5.37
Global indicator refining margin ($/barrel)	6.08	3.88
Chemicals indicator margin ($/tonne)	140a	112

aProvisional.

Operating statistics

	2004	2003
Liquids production (thousand b/d)	2,531	2,121
Gas production (million cf/d)	8,503	8,613
Total production (thousand boe/d)	3,997	3,606
Refinery throughputs (thousand b/d)	2,976	3,097
Marketing sales (thousand b/d)	4,002	3,969
Petrochemicals production (thousand tonnes)	28,927	27,943
Gas sales (million cf/d)	31,690	30,439

Non-operating items		$ million
	2004	2003
Asset write-downs/impairment	1,529	357
Environmental and other provisions	489	582
Restructuring, integration and
rationalization costs	141	399
Other	(39)	(559)
Total non-operating items before tax	2,120	779
Taxationa	(559)	(551)
Total non-operating items after tax	1,561	228

a2003 includes tax restructuring benefits.

Capital investment		$ million
	2004	2003
Exploration and Production	9,839	9,658
Refining and Marketing	2,887	3,006
Petrochemicals	929	775
Gas, Power and Renewables	538	359
Other businesses and corporate	215	188
Capital expenditure	14,408	13,986
Acquisitions	2,841	6,026
	17,249	20,012
Disposals	(5,048)	(6,432)
Net investment	12,201	13,580

Business performance

Create new profit centres by accessing areas with the potential for large oil and natural gas fields; exploring successfully; and pursuing the best projects for development.
Manage the performance of producing assets by investing in the best available opportunities and optimizing operating efficiency.
Sell assets that are no longer strategic to us and have greater value to others.

BP invests in a portfolio of large, lower-cost oil and natural gas fields chosen for their potentially strong return on capital employed, and seeks to manage those assets safely with maximum capital and operating efficiency. We continue to develop new profit centres in which we have a distinctive position: Trinidad, Angola, Azerbaijan, deepwater Gulf of Mexico, Asia Pacific gas and Algeria. These new profit centres, in addition to our growing operations in Russia, augment the production assets in our existing profit centres, providing greater reach, investment choice and opportunity for growth.

Exploration and Production

The result for the year was a record $19,759 million, representing an improvement of 22% over 2003, arising from increased production and higher oil and gas prices.

Our production was 3,997 thousand barrels of oil equivalent per day, an increase of more than 10% over 2003, primarily from incremental production in TNK-BP and our new profit centres. The increase was partly offset by a severe hurricane season in the Gulf of Mexico, a blow-out at the non-BP-operated Temsah platform in Egypt, the impact of divestments and decline in our existing profit centres.

We sanctioned four new major projects (Azeri-Chirag-Gunashli phase three in Azerbaijan, Rosa in Angola, Magnus extension in the UK North Sea and viscous oil in Alaska) and completed four major projects (In Salah in Algeria, Australia North West Shelf Train 4, Kizomba A in Angola and Holstein in the Gulf of Mexico). The increase in capital spending this year primarily reflected continued high development activity as we progressed projects in the new profit centres. Despite significant success across the supply chain to minimize the impact, inflationary pressures on our raw materials and the weaker dollar contributed to the increase.

Progress continued in our existing profit centres. Production from the Cerro Dragon field in Argentina grew through further infill drilling. In the North Sea, progress continued as expected on the Rhum development.

Each of our new profit centres progressed in line with our expectations this year.

In Trinidad, from where BP has prime access to US and European liquefied natural gas (LNG) markets, we built on our integrated position. In July, Atlas Methanol, the world's largest methanol plant, came on line. Train 4 of Atlantic LNG remains on track for start-up in the fourth quarter of 2005. It will be supplied in part by the Cannonball gas development, which is Trinidad and Tobago's first major in-country offshore construction project.

In Azerbaijan, construction continued on the Central Azeri field, with topsides commissioning under way. First oil is expected in the first half of 2005. We plan to transport this oil via the 1,760-kilometre Baku-Tbilisi-Ceyhan (BTC) pipeline. When complete, the pipeline will export crude oil from the Caspian to world markets. In addition, construction continued on the Shah Deniz gas field, and in-country assembly of the drilling rig and platform is under way for a planned 2006 start-up.

In the Gulf of Mexico, the Holstein field started production in December, despite the effects of Hurricane Ivan. In 2004, significant progress was made on Mad Dog, currently in the final commissioning stages with first production expected in early 2005, and on Thunder Horse, on track to begin production by the end of 2005. This will be followed by Atlantis, with first production expected in 2006.

In Angola, the Kizomba A field started production in August, ahead of schedule, while Kizomba B remains on track for start-up in late 2005. All major contracts were awarded on the Greater Plutonio development and fabrication of the Floating Production Storage and Offloading topsides began.

In Algeria, the In Salah project started production in mid-2004 and the In Amenas project remains on track for start-up in late 2005-early 2006.

Oil production from TNK-BP (excluding Slavneft) grew by about 14% over 2003. Our result for the year included $2.4 billion from TNK-BP. We also received $1.9 billion of cash dividends from the venture.

We continually seek to enhance our portfolio through a planned annual divestment programme.

In 2004, this yielded $747 million of proceeds and covered assets primarily in Indonesia, the US and Canada. We also signed sales and purchase agreements for the Ormen

Refining and Marketing

Strategy

Focus on refining locations where scale, configuration and operational excellence earn distinctive returns.
Focus on retail fuel and convenience markets where supply advantage and distinctive offer can capture market share.
Leverage our brand and technology with a key focus on automotive-related lubricants markets.
Build strong strategic relationships in the business-tobusiness sector.
Enhance our existing strength in selected emerging markets, particularly China.

Lange field in Norway, which is planned to complete in early 2005.

New oil and gas discoveries were made in Egypt, Angola, the deepwater Gulf of Mexico, Trinidad and offshore Sakhalin Island in Russia. Recoverable oil and gas from these finds is estimated to be more than one billion barrels of oil equivalent.

On the basis of UK generally accepted accounting practice (SORP), our proved reserves replacement ratio (RRR) was 106%, excluding equity-accounted entities. On the same basis, including equity-accounted entities, the RRR was 110%. This was the 12th consecutive year in which our RRR was greater than 100%. We also prepare estimates of our proved reserves on the basis of the rules and interpretation required by the US Securities and Exchange Commission (SEC). On this basis, our RRR was 78%, excluding equity-accounted entities, and 89%, including equity-accounted entities. The differences from our SORP-based estimates arise mainly from the use of yearend pricing, as required by the SEC. All our proved reserves replacement ratios are based on discoveries, extensions, revisions and improved recovery and exclude the effects of acquisitions and disposals. BP has a robust internal process to control the quality of its reserve bookings, which forms part of a holistic and integrated system of internal control. Details of that process and the applicable rules are described on pages 87-88.

Refining and Marketing

Strong refining margins, combined with robust operating performance, led to a result of $5,603 million in 2004, a 78% improvement from 2003. The relative weakening of the US dollar compared with the euro and sterling negatively affected results.

In our marketing businesses, strongly competitive sales growth was maintained. This resulted both from our

Focus

Our marketing businesses, underpinned by world-class manufacturing, generate customer value by providing quality products and offers. Our retail, lubricants and business-tobusiness sectors reach about 13 million customers a day. Our retail strategy provides differentiated fuel and convenience offers to some of the most attractive global markets. Our lubricants brands offer customers benefits through technology and relationships. We have deep business-to-business customer relationships and strategic partnerships. We seek to improve the quality of our manufacturing portfolio and our products.

investment to increase the quality of our portfolio and from our focus on operational excellence. Owing to increased crude product and base oil prices, margins overall declined slightly against those of 2003. We continued to strengthen our competitive position in all our operations through improved site operating models and the development of distinctive offers for customers.

Our investment in China deepened through two new joint ventures with PetroChina and Sinopec. We continued to review our portfolio, resulting in the disposal of our refining, retail and liquefied petroleum gas (LPG) businesses in Singapore, while further retail network asset disposals were completed in 2004. From 1 January 2005, the Aromatics and Acetyls businesses will join the segment and the Lavéra and Grangemouth refineries will be included in the Olefins and Derivatives business.

A record performance for the refining business was underpinned by strong product demand and good availability, which averaged 95.4% in 2004. We concentrated on optimizing our assets and taking advantage of our global scale and presence. Focus on supply optimization, feedstock selection and product value maximization helped us to capture high margins. BP's Global Indicator Refining Margin was $6.08 a barrel, up from $3.88 in 2003. Total global refining throughput was down by about 4% as a result of planned disposals.

In our retail business, the number of sites carrying the BP helios expanded to 19,828 worldwide during 2004. We launched Ultimate gasoline and diesel fuels in Australia, Austria, France, Germany, Poland and Portugal. These enhanced products deliver improved performance with fewer emissions than standard fuel grades, and have received positive responses from customers.

In our lubricants business, we focused on pursuing key

Petrochemicals

Strategy

Separate the portfolio, enabling the individual parts to develop strategic paths that deliver distinctive returns. We plan to divest the Olefins and Derivatives business, possibly starting with an Initial Public Offering in the second half of 2005, subject to market conditions and necessary approvals.
Integrate the Aromatics and Acetyls businesses within the Refining and Marketing segment, gaining operational and organizational synergies. Maintain leading market shares and technology in these high-growth businesses, with a strong presence in Asia.

customer segments and markets where we believe we have a premium position. Our brands continued to experience above-market volume growth, supported by new marketing initiatives. Growth was particularly strong in Asia, with Castrol BikeZone successfully launched in India and Vietnam. New product launches took place across the world, including Castrol GTX Start Up in the US and Castrol GTX High Mileage in Europe.

2004 was also a good year for business-to-business fuels marketing activity in both margin and volume, particularly in the marine and aviation sectors. This was partially offset by margin squeeze and price lag in the lubricants and LPG businesses, although volume demand remained robust. We also successfully launched the innovative new BP Gaslight composite LPG cylinder and Castrol TLX Plus in marine lubricants.

Petrochemicals

Petrochemicals' result was a loss of $900 million in 2004. Record sales and production volumes, underpinned by strong demand and by increased utilization and reliability at manufacturing sites, were more than offset by higher exceptional and non-operating charges.

Focus on commercial and operational excellence, together with generally improved market conditions, accelerated performance. Margin expansion was achieved despite high and volatile prices for energy and feedstocks.

The segment continued to upgrade its portfolio, focusing on areas with competitive advantage. As a consequence, several businesses that did not meet our strategic and financial criteria were sold, together with the announced closure of several manufacturing units. Substantial progress was made in constructing the SECCO chemicals complex near Shanghai (BP 50%) and expanding the Chocolate Bayou olefins operation in Texas. Output from these investments is expected in 2005.

• Focus the overall portfolio on areas with competitive advantage and restructure other assets.

Focus

Our petrochemicals businesses have significant global market positions, underpinned by leading proprietary technology and strong manufacturing capabilities. Our activities focus on those areas with a distinctive and significant competitive position. Our products are ultimately used to service a wide range of consumer applications, increasingly in the fast-growing markets of Asia Pacific and China in particular.

In 2004, we announced that, from 1 January 2005, the Olefins and Derivatives (O&D) business would operate on a standalone basis within the BP group. We plan to divest the O&D business, possibly starting with an Initial Public Offering in the second half of 2005, subject to market conditions and the receipt of necessary approvals. The O&D business markets a wide range of petrochemicals, manufactured in more than 20 locations worldwide.

During 2004, several initiatives were announced, designed to strengthen the competitive standing of the O&D business. The Grangemouth and Lavéra refineries will be incorporated into O&D, so preserving the opportunity to enhance further the benefits of site integration with their neighbouring petrochemicals operations. BP also agreed to acquire Solvay's interests in the two BP Solvay high-density polyethylene ventures for inclusion in O&D. Finally, Nova Chemicals and O&D agreed in principle to combine their respective styrene polymer interests in a joint venture, creating a major European polystyrene operation. Subject to regulatory approval, the joint venture is expected to start in mid-2005.

BP will retain the Aromatics and Acetyls (A&A) operations as an important part of its customer-facing activities. The A&A businesses have among the largest global market shares and advanced technologies in these high-growth sectors. BP aims to grow the A&A businesses and several ongoing expansion projects in Asia will start up in 2005.

With the announced changes, the Petrochemicals segment ceased to report separately as from 1 January 2005. The A&A operations will be included within the Refining and Marketing segment; the O&D business will report within Other businesses and corporate. The new structure is designed to offer the greatest opportunity for further improvement in overall performance and financial returns.

Strategy

• Capture distinctive world-scale market positions ahead of supply.

Gas, Power and Renewables

Expand gross margin by providing distinctive products to selected customer segments and optimizing the gas and power value chains.
Build a sustainable solar business and continue to assess the application of renewable and alternative energy sources.

Focus

In line with changing demand patterns for cleaner fuels, BP seeks to participate at scale in the fast-growing markets for natural gas, gas liquids and solar energy. We currently hold some of the largest market shares in volumes sold in North American gas and natural gas liquids (NGLs) and significant strength in both the liquefied natural gas (LNG) and solar global markets. We are expanding our LNG business by accessing import terminals in Asia Pacific, North America and Europe.

Gas, Power and Renewables

The result for the year was $943 million, an increase of 65% over 2003 and underpinned by record sales volumes achieved across all four principal business areas of LNG, NGLs, gas marketing and solar. The NGLs business benefited from a firm market environment by increasing sales by 14% and achieving high levels of availability. Sales of natural gas increased by 4%, while volumes of gas supplied into liquefaction plants rose by 11%. The solar business grew sales by 38% and delivered a full-year operating profit for the first time.

We took a number of important steps to access major growth markets for the group's equity gas. In Asia Pacific, agreements for the supply of LNG from the proposed Tangguh development in Indonesia (BP 37.16%) were signed with POSCO and K Power for supply to South Korea and with Sempra for supply to Mexico and US markets. Together with an earlier agreement to supply LNG to China, more than seven million tonnes a year of Tangguh LNG have been secured. This was a significant factor in the decision to sanction the development in early 2005.

In the Atlantic and Mediterranean regions, significant progress was also made in creating opportunities to supply LNG to North American and European gas markets. In Egypt, we signed agreements to supply gas to the Damietta LNG plant and to purchase 1.45 billion cubic metres per year of LNG for supply to world markets. Agreements finalized with NGT Transco will make BP and Sonatrach of Algeria the first companies since the 1980s to import LNG into the UK market from 2005.

Plans for the development of new LNG import terminals on the US East and Gulf coasts made good progress. These new access points to market, together with existing capacity rights at Cove Point in Maryland, US, Bilbao in Spain and Isle of Grain, UK, should provide important opportunities to maximize the

value of the group's gas supplies from Trinidad, Egypt and elsewhere.

In the NGLs business, we maintained our position in North America as one of the largest marketers and producers in terms of production and sales volumes. There we had a very strong year, benefiting from the high prices of NGLs seen during 2004 and the wide differences between natural gas feedstocks and liquids prices, which give higher earnings. In Egypt, a new NGLs extraction plant (BP 33.33%) began gas processing at Port Said.

Our gas marketing and trading business had a good year, with an operating result ahead of 2003's record performance. In North America, we are the largest gas marketer in volumes sold to end-use and wholesale markets and have a growing power marketing and trading business. Our marketing and trading scale and scope provide exemplary market access for the group's North American equity gas production and LNG imports. We secured long-term capacity in several new western US pipeline projects to support expected Rockies production growth and avoid capacity constraints seen in the past. We continued to expand our market presence in North America by acquiring two gas marketing companies and extending two key energy alliance agreements.

Our solar business saw a record year, with strong sales growth, a positive operating result and positive cash flow. The business benefited from the restructuring undertaken in 2003, which reduced the cost of supply, and also from strong industry demand, which is supporting higher revenues. We reduced product lines and distributors and improved customer focus and brand loyalty. Our global 'lean manufacturing' initiative delivered major improvements in productivity, and production from our main operating facilities in Madrid, Spain, and Frederick, US, was stepped up to supply the higher sales.

Environmental and social performance

Our fundamental purpose, as defined by BP's board, is to maximize shareholder value on a long-term basis by providing constantly improving goods and services in a strongly competitive way. To be sustainably successful, we have to gain and retain the support of many people, including employees, shareholders, customers and communities. This report summarizes our performance. More detail is published in BP Sustainability Report 2004.

BP: our business

The way we work is guided by values – integrity, honest dealing, treating everyone with respect and dignity, striving for mutual advantage, transparency and contributing to human progress. These values are enshrined in practical policies and standards that govern areas of our activity, including health, safety, security, environment, ethical conduct and business relationships.

We use a system of risk management to assess the impact of our activities on the environment, local economies and communities. Where appropriate, accountability for managing environmental and social impacts is part of managers' performance contracts, with specific objectives and milestones.

People's safety is of the highest priority. Managers are accountable for ensuring that safety risks are properly addressed, staff are trained and facilities are well maintained. We closely monitor our safety performance.

In 2004, the number of injury cases (resulting in our employees or contractors being away from work for a day or more) was 0.08 per 200,000 hours worked, compared with 0.09 in 2003. This performance is approaching the best in our industry and also within our target set at 0.09 for 2004.

Despite meeting this important target and reducing overall injury rates, we deeply regret the 11 workforce fatalities in 2004. This compares with 20 in 2003 and 13 in 2002.

As a global organization, we believe our workforce, leadership and recruitment should reflect the diverse communities in which we operate. We are continuing to focus on employing and developing local staff and leaders in our operations worldwide. Programmes in countries including China, Angola and Azerbaijan are ensuring that we continue to increase the number of local employees.

aDays away from work case frequency (DAFWCF) is the annual frequency (per 200,000 hours) of injuries that result in a person (employee or contractor) being unable to work for a day (shift) or more. For a full understanding of the underlying data on DAFWCF, please refer to our website.

Our policy is to ensure equal opportunity in recruitment, career development, promotion, training and reward for all employees, including those with disabilities. All applicants and employees are assessed against clear criteria related to job requirements. Where existing employees become disabled, our policy is to provide continuing employment and training wherever practicable.

Our People Assurance Survey (PAS), completed by 74% of our employees in 2004, showed a 4% improvement in overall employee satisfaction.

BP values the diversity of its leadership. At the end of 2004, 15% of our top 610 leaders were female and 19% were of nationalities other than the UK or US. Our employee surveys show that an inclusive culture is spreading. In 2004, 70% of BP employees who responded to the PAS believed the company had created an environment where people with diverse backgrounds could succeed, up from 67% in 2003 and 60% in 2000. We strive to build an environment in which everyone can feel part of a meritocratic organization.

During 2004, we made further progress in learning and development opportunities for employees. Around 5,000 people undertook the First Level Leaders programme, which provides training for the first tier of management. More than 1,800 of our 6,000 senior leaders took part in the Senior Level Leaders programme, designed to develop their leadership capabilities.

BP's fourth Global Graduate Forum was attended by around 300 graduates who joined in 2002, while around 250 people attended the Discover BP programme, launched to help senior experienced recruits integrate rapidly into BP.

We continue to support employee share ownership. Through our award-winning ShareMatch plan, run in 75 countries, we match BP shares purchased by employees.

Communications with employees include global and local magazines, intranet sites, DVDs, targeted e-mails and faceto-face communication. Team meetings are the core of our employee consultation, complemented by formal processes through works councils in parts of Europe. This communication, along with training programmes, raises awareness of the financial, economic, social and environmental factors affecting BP's performance and contributes to employee development and motivation.

We continue to emphasize the importance of doing business with high standards of ethical conduct. To enhance our focus on compliance with laws, regulations and internal policies and standards, we developed a new centralized compliance and ethics function during 2004.

We promote our global employee concerns programme – OpenTalk – to give our staff the opportunity to report possible breaches of law or company policy without fear of retaliation. OpenTalk can be contacted via telephone, letter, e-mail or fax and provides a translation service. Matters raised are held in strict confidence and are referred for investigation via regional ombudsmen within BP for resolution. During 2004, 343 reports were received from 44 countries and, where appropriate, action was taken.

Staff in positions of responsibility review with their teams all compliance and ethical issues arising during the year. They then certify to their manager that their personal actions and those of their teams have complied with the law and with company policy, disclosing any areas of possible non-compliance. On completion of the process, the group chief executive prepares his personal certificate on behalf of BP. In future years, these reports will be prepared against the requirements outlined in our new code of conduct.

We continue to apply our strong anti-corruption policy, including prohibiting facilitation payments and identifying and correcting any areas of non-compliance. We take disciplinary measures where appropriate. In 2004, this included the dismissal of 252 people for unethical behaviour, including fraud, theft and dishonesty.

BP does not make corporate political contributions anywhere in the world and specifically made no donations to UK or other EU political parties or organizations in 2004.

Promoting health awareness among our employees, contractors and local communities provides long-term benefits to our people and our business. In many areas of the world we face significant health issues, such as HIV/AIDS. During 2004, we increased our capability to assess health risks and implemented local initiatives.

BP and the environment

BP was the first major oil company to state publicly that the risks of climate change were serious and that precautionary action was justified. While uncertainties remain, we believe business planning and long-term strategy should be based on the need to stabilize atmospheric concentrations of greenhouse gases.

In 2001, BP had succeeded in lowering operational emissions by 10% from 1990 levels. We now aim to offset growth in our emissions by 2012, with reductions achieved partly from operational efficiency projects and partly from the supply of products that are cleaner or offer improved fuel efficiency.

Our 2004 operational emissions of 81.7 million tonnes (Mte) were similar to those of 2003 (83.4Mte). Our emissions would have been higher but for planned improvements in operational efficiencies and divestments. The efficiencies resulted in more than 1Mte of sustainable reductions, which now total about 4Mte since 2001.

BP recognizes the need to protect and conserve sensitive areas that house the rich biodiversity of our planet. We will only work within sensitive areas if we believe we can properly manage any risks to the environment.

We have made a commitment to publish the results of risk assessments relating to any new activities in World Conservation Union (IUCN) designated sites. In 2004, no decisions were taken to go into such areas. Our website details all known IUCN category I to VI areas where we have facilities. During 2004, further work was undertaken to ensure that our approach when entering areas for exploration and production is consistent and transparent.

By the end of 2004, 100% of our major operations had been independently certified to the ISO 14001 international standard on environmental management. This system drives continuous performance improvement at our sites to reduce air emissions, water discharges and accidental releases, including oil spills to sea or land.

Our shipping fleet transports significant volumes of oil and gas around the world. In 2004, BP continued its strategy of increasing its fleet in order to control the risk of a major oil spill more effectively. Our owned and operated fleet has grown from 36 ships in 2003 to 42 ships in December 2004, 38 of which are double-hulled. Most of these vessels are leased, an approach that enables the group to renew the fleet periodically. We also charter additional vessels, which are vetted to ensure they meet our rigorous standards.

In the area of renewable and alternative energies, BP's research and development focus has been on photovoltaics and hydrogen. We are pursuing initiatives aimed at improving the efficiency and cost of solar cells as well as the development of new silicon sources and alternative wafer fabrication techniques. In hydrogen, we use our international portfolio of practical demonstration projects to test new technologies and foster innovation.

BP in society

We try to ensure that our relationships with non-governmental organizations (NGOs), customers, suppliers, communities and governments are founded on the basis of mutual advantage. Our relationships develop over many years by seeking to understand the needs and aspirations of all with whom we do business.

We made further progress on some concerns related to the construction of the BTC pipeline, a project that has attracted some NGO opposition, particularly over human rights issues. The pipeline is being constructed to transport oil from the Caspian to the Mediterranean, so avoiding shipping through the Bosporus, and will help meet growing world demand.

We believe that open and thriving societies create the best environment for business. During 2004, we contributed to international discussions on the issue of transparency. The Extractive Industries Transparency Initiative (EITI) is an important programme that provides guidelines for disclosing the amount of revenue governments receive from energy companies, so demonstrating the scale of the funds available for public spending. Towards the end of 2004, a Memorandum of Understanding was signed in Baku, Azerbaijan, by the government, state and foreign oil companies, setting out clearly the process for implementation of the EITI in Azerbaijan. BP is committed to encouraging the acceleration of this process and will be supporting it with the publication of relevant data and information.

Our business activities affect – and benefit – people worldwide. We seek to extend these benefits as broadly as possible. During 2004, we reviewed our strategy of social investment and intend to focus on education, on the development of thriving local enterprise and on providing access to energy in remote locations. We continue to support many initiatives in the communities in which we operate.

Other financial issues

Critical accounting policies

BP prepares its financial statements in accordance with UK generally accepted accounting practice (UK GAAP). The group's significant accounting policies are summarized on pages 40-43.

The accounts for the year ended 31 December 2004 have been prepared using accounting policies consistent with those adopted in the preparation of the 2003 accounts, except for the change in accounting policy for pensions and other postretirement benefits and for shares held in employee share ownership plans for the benefit of employee share schemes.

Segment information for 2003 has been restated to reflect the transfer of the natural gas liquids (NGLs) activities from Exploration and Production to Gas, Power and Renewables.

Inherent in the application of many of the accounting policies used in the preparation of the financial statements is the need for BP management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the accounts and the reported amounts of revenues and expenses during the reporting period. Actual outcomes could differ from the estimates and assumptions used.

The following summary provides further information about the critical accounting policies that could have a significant impact on the results of the group and should be read in conjunction with the Notes on Accounts.

The accounting policies and areas that require the most significant judgements and estimates to be used in the preparation of the consolidated financial statements are in relation to oil and natural gas accounting, including the estimation of reserves; impairment; and provisions for deferred taxation, decommissioning, environmental liabilities, pensions and other post-retirement benefits.

Accounting policy changes in 2004

From 1 January 2004, BP changed its accounting policies for pensions and other post-retirement benefits. In addition, BP also changed its accounting policy for shares held in employee share ownership plans for the benefit of employee share schemes.

With effect from 1 January 2004, BP has adopted a new UK accounting standard: Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17). FRS 17 requires that the assets and liabilities arising from an employer's retirement benefit obligations and any related funding should be included in the financial statements at fair value and that the operating costs of providing retirement benefits to employees should be recognized in the income statement in the periods in which the benefits are earned by employees. This contrasts with SSAP 24, which requires the cost of providing pensions to be recognized on a systematic and rational basis over the period during which the employer benefits from the employee's services. The difference between the amount charged in the income statement and the amount paid as contributions into the pension fund is shown as a prepayment or provision on the balance sheet.

Urgent Issues Task Force Abstract No. 38 'Accounting for Employee Share Ownership Plan (ESOP) Trusts' (Abstract No. 38) changes the presentation of an entity's own shares held in an ESOP trust from requiring them to be recognized as assets to requiring them to be deducted in arriving at shareholders' funds. Transactions in an entity's own shares by an ESOP trust are similarly recorded as changes in shareholders' funds and do not give rise to gains or losses. This treatment is in line with the accounting for purchases and sales of own shares set out in Urgent Issues Task Force Abstract No. 37 'Purchases and Sales of Own Shares' (Abstract No. 37).

Abstract No. 37 requires a holding of an entity's own shares to be accounted for as a deduction in arriving at shareholders' funds, rather than being recorded as assets. Transactions in an entity's own shares are similarly recorded as changes in shareholders' funds and do not give rise to gains or losses. Abstract No. 37 applies where a company purchases treasury shares under new legislation that came into effect in December 2003.

Urgent Issues Task Force Abstract No. 17 'Employee share schemes' (Abstract No. 17) was amended by Abstract No. 38 to reflect the consequences for the profit and loss account of the changes in the presentation of an entity's own shares held by an ESOP trust. Amended Abstract No. 17 requires that the minimum expense should be the difference between the fair value of the shares at the date of award and the amount that an employee may be required to pay for the shares (i.e. the 'intrinsic value' of the award). The expense was previously determined either as the intrinsic value or, where purchases of shares had been made by an ESOP trust at fair value, by reference to the cost or book value of shares that were available for the award.

These changes in accounting policy have resulted in a prior year adjustment. BP shareholders' interest at 1 January 2003 has been reduced by $5,760 million and the profit for the year ended 31 December 2003 increased by $215 million.

Oil and natural gas accounting Accounting for oil and gas exploration activity is subject to special accounting rules that are unique to the oil and gas industry. In the UK, these are contained in the Statement of Recommended Practice (SORP) 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'.

The group follows the successful efforts method of accounting for its oil and natural gas exploration and production activities.

The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs.

Licence and property acquisition costs are initially capitalized as unproved properties within intangible assets. These costs are amortized on a straight-line basis until such time as either exploration drilling is determined to be successful or it is unsuccessful and all costs are written off. Licence and property acquisition costs are not subject to periodic assessments for impairment.

For exploration wells, costs directly associated with the drilling of wells are temporarily capitalized within intangible fixed assets, pending determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort. These costs include employee remuneration, materials and fuel used, rig costs, delay rentals and payments made to contractors. This is usually made within one year after well completion, but can take longer, depending on the complexity of the geologic structure. If the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and are reported in exploration expense. Exploration wells that discover potentially economic quantities of oil and gas and are in areas where major capital expenditure (e.g. offshore platform or a pipeline) would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration appraisal work is under way or firmly planned.

For complicated offshore exploration discoveries, it is not unusual to have exploration wells remaining suspended on the balance sheet for several years while additional appraisal drilling and seismic work on the potential oil and gas field is performed or while the optimum development plans and timing are established. As with licence and property acquisition costs, there is no periodic impairment assessment of suspended exploration well costs. All such carried costs are subject to regular technical, commercial and management review, on at least an annual basis, to confirm the continued intent to develop, or otherwise extract value from, the discovery. If this is no longer the case, the costs are immediately expensed.

Once a project is sanctioned for development, the carrying values of licence and property acquisition costs and exploration and appraisal costs are transferred to production assets within tangible assets.

The capitalized exploration and development costs for proved oil and gas properties (which include the costs of drilling unsuccessful wells) are amortized on the basis of oil-equivalent barrels that are produced in a period as a percentage of the estimated proved reserves. The estimated proved reserves used in these unit-of-production calculations vary with the nature of the capitalized expenditure. The reserves used in the calculation of the unit-of-production amortization are as follows:

(a) Proved developed reserves for producing wells.
(b) Total proved reserves for development costs.
(c) Total proved reserves for licence and property acquisition costs.
(d) Total proved reserves for future decommissioning costs.

The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining book value of the asset over the expected future production. If proved reserve estimates are revised downwards, earnings could be affected by higher depreciation expense or an immediate write-down of the property's book value (see discussion of impairment of fixed assets and goodwill below).

Given the large number of producing fields in the group's portfolio, it is unlikely that any changes in reserve estimates, year on year, will have a significant effect on prospective charges for depreciation.

Oil and natural gas reserves The group manages its hydrocarbon resources in three major categories: prospect inventory, non-proved reserves and proved reserves. When a discovery is made, volumes transfer from the prospect inventory to the non-proved reserve category. The reserves move through various non-proved reserves sub-categories as their technical and commercial maturity increases through appraisal activity. Reserves in a field will only be categorized as proved when all the criteria for attribution of proved status have been met, including an internally imposed requirement for project sanction, or for sanction expected within six months.

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. 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 to the start of production. Adjustments may be made to booked reserves due to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.

The group reassesses its estimate of proved reserves on an annual basis. The estimated proved reserves of oil and natural gas are subject to future revision. As discussed below, oil and natural gas reserves have a direct impact on certain amounts reported in the financial statements.

Proved reserves do not include reserves that are dependent on the renewal of exploration and production licences unless there is strong evidence to support the assumption of such renewal.

The group estimates its reserves of oil and natural gas according to the UK Statement of Recommended Practice. This differs from the basis for determining reserves required by the US Securities and Exchange Commission. Estimates of the group's proved reserves of oil and natural gas are shown on pages 87-92, together with more information about the group's processes for booking reserves and the difference between the reserves determined for the group's UK and US reporting.

Impairment of fixed assets and goodwill BP assesses its fixed assets, including goodwill, for possible impairment if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable. Such indicators include changes in the group's business plans, changes in commodity prices leading to unprofitable performance and, for oil and gas properties, significant downward revisions of estimated proved reserve quantities. The assessment for impairment entails comparing the carrying value of the incomegenerating unit and associated goodwill with the recoverable amount of the asset, that is, the higher of net realizable value and value in use. Value in use is usually determined on the basis of discounted estimated future net cash flows.

Determination as to whether and how much an asset is impaired involves management estimates on highly uncertain matters such as future commodity prices, the effects of inflation and technology improvements on operating expenses, production profiles and the outlook for global or regional market supply-and-demand conditions for crude oil, natural gas, commodity chemicals and refined products.

For oil and natural gas properties, the expected future cash flows are estimated based on the group's plans to continue to produce and develop proved and associated risk-adjusted probable and possible reserves. Expected future cash flows from the sale or production of reserves are calculated based on the group's best estimate of future oil and gas prices. Previously, these were a Brent Oil price of $20 per barrel and a Henry Hub gas price of $3.50 per mmBtu. Beginning in the fourth quarter of 2004, this has been modified. Prices used for future cash flow calculations are assumed to decline from existing levels in equal steps over the next three years to the long-term planning

assumptions (currently $20/$3.50 for Brent and Henry Hub). These long-term planning assumptions are subject to periodic review and modification. The estimated future level of production is based on assumptions about future commodity prices, lifting and development costs, field decline rates, market demand and supply, economic regulatory climates and other factors.

Charges for impairment are recognized in the group's results from time to time as a result of, among other factors, adverse changes in the recoverable reserves from oil and natural gas fields, low plant utilization or reduced profitability. If there are low oil prices or natural gas prices or refining margins or chemicals margins over an extended period, the group may need to recognize significant impairment charges.

Deferred taxation The group has approximately $7.7 billion of carry-forward tax losses in the UK and Germany, which would be available to offset against future taxable income. It is unlikely that the group's effective tax rate will be significantly affected in the near term by utilization of losses not previously recognized as deferred tax assets. Carry-forward tax losses in other taxing jurisdictions have not been recognized as deferred tax assets, and are unlikely to have a significant effect on the group's tax rate in future years.

Deferred taxation is not generally provided in respect of liabilities that may arise on the distribution of accumulated reserves of overseas subsidiaries, joint ventures and associated undertakings.

Decommissioning costs The group holds provisions for the future decommissioning of oil and natural gas production facilities and pipelines at the end of their economic lives. The largest asset removal obligations facing BP relate to the removal and disposal of oil and natural gas platforms and pipelines around the world. The estimated discounted costs of dismantling and removing these facilities are accrued on the installation of those facilities, reflecting our legal obligations at that time. Most of these removal events are many years in the future and the precise requirements that will have to be met when the removal event actually occurs are uncertain. Asset removal technologies and costs are constantly changing, as well as political, environmental, safety and public expectations. Consequently, the timing and amounts of future cash flows are subject to significant uncertainty.

The timing and amount of future expenditures are reviewed annually, together with the interest rate to be used in discounting the cash flows. The interest rate used to determine the balance sheet obligation at the end of 2004 was 2.0%, 0.5% lower than at the end of 2003. The interest rate represents the real rate (i.e. adjusted for inflation) on long-dated government bonds.

Environmental costs BP also makes judgements and estimates in recording costs and establishing provisions for environmental clean-up and remediation costs, which are based on current information on costs and expected plans for remediation. For environmental provisions, actual costs can differ from estimates because of changes in laws and regulations, public expectations, discovery and analysis of site conditions and changes in clean-up technology.

The provision for environmental liabilities is reviewed at least annually. The interest rate used to determine the balance sheet obligation at 31 December 2004 was 2.0%, 0.5% lower than at the previous balance sheet date.

Pensions and other post-retirement benefits Accounting for pensions and other post-retirement benefits involves judgement about uncertain events, including estimated retirement dates, salary levels at retirement, mortality rates, rates of return on plan assets, determination of discount rates for measuring plan obligations, healthcare cost-trend rates and rates of utilization of healthcare services by retirees. These assumptions are based on the environment in each country. Determination of the projected benefit obligations for the group's defined benefit pension and post-retirement plans is important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The assumptions used may vary from year to year, which will affect future results of operations. Any differences between these assumptions and the actual outcome also affect future results of operations.

Pension and other post-retirement benefit assumptions are discussed and agreed with the independent actuaries in December each year. These assumptions are used to determine the projected benefit obligation at the year end and hence the surplus and deficits recorded on the group's balance sheet, and pension and post-retirement expense for the following year.

Adoption of International Financial Reporting Standards

An 'International Accounting Standards Regulation' was adopted by the Council of the European Union (EU) in June 2002. This regulation requires all EU companies listed on an EU stock exchange to use 'endorsed' International Financial Reporting Standards (IFRS), published by the International Accounting Standards Board (IASB), to report their consolidated results with effect from 1 January 2005. The IASB completed its development of IFRS to be adopted in 2005 during the first half of 2004, but has also published certain amendments and interpretations of IFRS which would be available for early adoption if endorsed by the EU.

The process of endorsement of IFRS by the EU to allow adoption by companies in 2005 is well advanced but not yet complete.

BP's project team includes a broadly based representation from across the group designed to plan for and achieve a smooth transition to IFRS. The project team has examined all implementation aspects, including changes to accounting policies, the presentation of the group's results, systems impacts and the wider business issues that may arise from such a fundamental change. The group is now prepared to report its results from the first quarter of 2005 onwards using IFRS. However, the implementation may still be affected by developments in the IASB's standard-setting process and the endorsement of standards and interpretations by the EU.

The group has decided that, for the purposes of the restatement of prior periods currently reported under UK GAAP, the date of transition to IFRS is 1 January 2003. However, in accordance with the provisions of IFRS 1, the date of adoption of IAS Nos. 32 and 39, which deal with the recognition and presentation of financial instruments, is set at 1 January 2005, with no restatement of prior periods' results.

We are in the process of finalizing the restatements of the

results and financial position for 2003 and 2004 under IFRS, and intend to release this information in mid-March 2005. Our current view is that the major effects of changing from our current accounting practice to IFRS are in the following areas: goodwill acquired in a business combination; deferred tax related to business combinations and in respect of the valuation of stocks; accounting for items falling within the scope of IAS Nos. 32 and 39, including embedded derivatives and hedge accounting; the treatment of major overhaul expenditure; exchanges of fixed assets; recognition of dividend liabilities; and share-based payments. Certain joint arrangements with third parties, where BP currently accounts for its share of individual assets, liabilities, income and expense, will be accounted for using the equity method, resulting in reclassifications within the income statement and balance sheet.

Financial risk management

The group co-ordinates certain key activities on a global basis in order to optimize its financial position and performance. These include the management of the currency, maturity and interest rate profile of finance debt, cash, other significant financial risks and relationships with banks and other financial institutions. International oil, natural gas and power trading and risk management relating to business operations are carried out by the group's oil, natural gas and power trading units.

The main financial risks faced by the group through its normal business activities are market risk, credit risk and liquidity risk. These risks and the group's approach to dealing with them are discussed below.

The adoption of IFRS from 1 January 2005 does not fundamentally change BP's approach to managing financial risk. The new requirement may, however, introduce some volatility into earnings for the recognition and measurement of certain financial instruments.

Market risk Market risk is the possibility that changes in currency exchange rates, interest rates or oil, natural gas and power prices will adversely affect the value of the group's financial assets, liabilities or expected future cash flows. Market risks are managed using a range of derivatives. The group also trades derivatives in conjunction with these risk management activities.

All derivative activity, whether for risk management or trading, is carried out by specialist teams who have the appropriate skills, experience and supervision. These teams are subject to close financial and management control. The appropriate governance, control framework and reporting processes are in place to oversee these internal control and risk management activities. On an ongoing basis, an independent control function monitors compliance with BP's policies that are in line with generally accepted industry practice, reflecting the principles of the Group of Thirty Global Derivatives Study. The control framework includes prescribed trading limits that are reviewed regularly by senior management, daily monitoring of risk exposure using value-at-risk principles, marking trading exposures to market and stress testing to assess the exposure to potentially extreme market situations.

For market risk management and trading, conventional exchange-traded derivative instruments such as futures and options are used, as well as non-exchange-traded

instruments such as swaps, 'over-the-counter' options and forward contracts.

Where derivatives constitute a hedge, the group's exposure to market risk created by the derivative is offset by the opposite exposure arising from the asset, liability, cash flow or transaction being hedged. By contrast, where derivatives are held for trading purposes, changes in market risk factors give rise to gains and losses, which are recognized in earnings in the current period.

Currency exchange rates Fluctuations in exchange rates can have significant effects on the group's reported profit. The effects of most exchange rate fluctuations are absorbed in business operating results through changing cost-competitiveness, lags in market adjustment to movements in rates and conversion differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations is not identifiable separately in the group's reported profit.

The main underlying economic currency of the group's cash flows is the US dollar. This is because BP's major products are priced internationally in US dollars. BP's foreign exchange management policy is to minimize economic and significant transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign exchange risks centrally, by netting off naturally occurring opposite exposures wherever possible, to reduce the risks, and then dealing with any material residual foreign exchange risks. Significant residual non-dollar exposures are managed using a range of derivatives.

In addition, most group borrowings are in US dollars or are hedged with respect to the US dollar.

Interest rates The group is exposed to interest rate risk on short- and long-term floating rate instruments and as a result of the refinancing of fixed rate finance debt. The group is exposed predominantly to US dollar LIBOR (London Inter-Bank Offer Rate) interest rates as borrowings are mainly denominated in, or are swapped into, US dollars. The group uses derivatives to manage the balance between fixed and floating rate debt.

Oil, natural gas and power prices BP's trading function uses financial and commodity derivatives as part of the overall optimization of the value of the group's equity oil production and as part of the associated trading of crude oil, products and related instruments. It also uses financial and commodity derivatives to manage certain of the group's exposures to price fluctuations on natural gas and power transactions.

Credit risk Credit risk is the potential exposure of the group to loss in the event of non-performance by a counterparty. The credit risk arising from the group's normal commercial operations is controlled by individual operating units within guidelines. In addition, as a result of its use of derivatives to manage market risk, the group has credit exposures through its dealings in the financial and specialized oil, natural gas and power markets. The group controls the related credit risk through credit approvals, limits, use of netting arrangements and monitoring procedures. Counterparty credit validation, independent of the dealers, is undertaken before contractual commitment.

Concentrations of credit risk The primary activities of the group are oil and natural gas exploration and production, gas and power marketing and trading, oil refining and marketing and the manufacture and marketing of petrochemicals. The group's principal customers, suppliers and financial institutions with which it conducts business are located throughout the world. The credit ratings of interest rate and currency swap counterparties are all of at least investment grade. The credit quality is actively managed over the life of the swap.

Liquidity risk Liquidity risk is the risk that suitable sources of funding for the group's business activities may not be available. The group has long-term debt ratings of Aa1 and AA+ assigned respectively by Moody's and Standard and Poor's. The group has access to a wide range of funding at competitive rates through the capital markets and banks. It co-ordinates relationships with banks, borrowing requirements, foreign exchange requirements and cash management centrally. The group believes it has access to sufficient funding and also has undrawn committed borrowing facilities to meet currently foreseeable borrowing requirements.

At 31 December 2004, the group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,500 million expiring in 2005 ($3,700 million expiring in 2004). These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. The group expects to renew these facilities on an annual basis. Certain of these facilities support the group's commercial paper programme.

Insurance

The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because external insurance is not considered an economic means of financing losses for the group. Losses will therefore be borne as they arise rather than being spread over time through insurance premia with attendant transaction costs. This position will be reviewed periodically.

Environmental expenditure

Operating and capital expenditure on the prevention, control, abatement or elimination of air, water and solid waste pollution is often not incurred as a separately identifiable transaction. Instead, it forms part of a larger transaction that includes, for example, normal maintenance expenditure. The figures for environmental operating and capital expenditure in the table below are therefore estimates, based on the definitions and guidelines of the American Petroleum Institute.

		$ million
	2004	2003
Operating expenditure	526	498
Clean-ups	25	45
Capital expenditure	524	546
New provisions for
environmental remediation	588	515
New provisions for decommissioning	294	1,159

Environmental operating and capital expenditures for 2004 were broadly in line with 2003. Similar levels of operating and capital expenditures are expected in the foreseeable future. In addition to operating and capital expenditures, we also create provisions for future environmental remediation. Expenditure against such provisions is normally in subsequent periods and is not included in environmental operating expenditure reported for such periods. The charge for environmental remediation provisions in 2004 includes $484 million resulting from a reassessment of existing site obligations and $104 million in respect of provisions for new sites.

Provisions for environmental remediation are made when a clean-up is probable and the amount reasonably determinable. Generally, their timing coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites.

The extent and cost of future remediation programmes are inherently difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions and also the group's share of liability. Although the cost of any future remediation could be significant and may be material to the result of operations in the period in which it is recognized, we do not expect that such costs will have a material effect on the group's financial position or liquidity. We believe our provisions are sufficient for known requirements; and we do not believe that our costs will differ significantly from those of other companies engaged in similar industries, or that our competitive position will be adversely affected as a result.

In addition, we make provisions over the useful lives of our oil- and gas-producing assets and related pipelines to meet the cost of eventual decommissioning. Provisions for environmental remediation and decommissioning are usually set up on a discounted basis, as required by Financial Reporting Standard No. 12, 'Provisions, Contingent Liabilities and Contingent Assets'.

Further details of our environmental and decommissioning provisions appear in Note 30 on Accounts on page 67. New provisions for decommissioning in 2004 include increases in respect of reassessment of existing provisions and new provisions for certain fields on installation of facilities.

Creditor payment policy and practice

Statutory regulations issued under the UK Companies Act 1985 require companies to make a statement of their policy and practice in respect of the payment of trade creditors.

In view of the international nature of the group's operations there is no specific group-wide policy in respect of payments to suppliers. Relationships with suppliers are, however, governed by the group's policy commitment to long-term relationships founded on trust and mutual advantage. Within this overall policy, individual operating companies are responsible for agreeing terms and conditions for their business transactions and ensuring that suppliers are aware of the terms of payment. These terms are adhered to when payments are made, subject to terms and conditions being met by the supplier.

BP p.l.c. is a holding company with no business activity other than the holding of investments in the group and therefore had no trade creditors at 31 December 2004.

Accounts contents

Statement of directors' responsibilities
in respect of the accounts	38
Independent auditors' report	39
Accounting policies	40
Group income statement	44
Balance sheets	45
Group cash flow statement	46
Statement of total recognized gains and losses	46

Notes on accounts
1 Turnover	47
2 Production taxes	47
3 Distribution and administration expenses	47
4 Other income	47
5 Analysis of historical cost profit	48
6 Hire charges and expenditure on research	48
7 Exceptional items	49
8 Interest expense	50
9 Other finance expense	50
10 Auditors' remuneration	50
11 Depreciation and amounts provided	51
12 Taxation	52
13 Distribution to shareholders	54
14 Earnings per ordinary share	54
15 Operating leases	54
16 Acquisitions	55
17 Disposals	56
18 Group balance sheet analysis	57
19 Intangible assets	57
20 Tangible assets – property, plant and equipment	58
21 Fixed assets – investments	59
22 Stocks	59
23 Debtors	60
24 Current assets – investments	60
25 Financial instruments	60
26 Derivative financial instruments	63
27 Fair values of financial assets and liabilities	65
28 Finance debt	66
29 Other creditors	67
30 Other provisions	67
31 Pensions	67

32 Other post-retirement benefits 71

33 Called up share capital	73
34 Capital and reserves	73
35 Reconciliation of movements in shareholders' interest	74
36 Group cash flow statement analysis	75
37 Employee share plans	76
38 Long-term performance plans	77
39 Employee costs and numbers	78
40 Directors' remuneration	78
41 Joint ventures and associated undertakings	79
42 Contingent liabilities	80
43 Capital commitments	80
44 New accounting standards	81
45 Transfer of natural gas liquids activities	83
46 Subsidiary and associated undertakings and joint ventures	84
47 Oil and natural gas exploration and production activities	85
Supplementary information on oil and natural
gas quantities	87
Five-year summaries
Summarized group income statement	95
Summarized group income statement (by quarter)	96
Replacement cost profit before interest and tax
analysed by business and geographical area	98
Exceptional items	98
Turnover	100
Taxation	100
Depreciation and amounts provided	101
Group balance sheet	102
Capital employed	103
Group cash flow statement	104
Movement in net debt	104
Consolidated statement of cash flows presented
on a US GAAP format	105
Capital expenditure and acquisitions	106
Ratios	106
Share prices	106
United States accounting principles	107
Statistics	108
Employee numbers	108
Glossary	109

Statement of directors' responsibilities in respect of the accounts

Company law requires the directors to prepare accounts for each financial year that give a true and fair view of the state of affairs of the company and the group and of the profit or loss of the group for that period. In preparing those accounts, the directors are required:

To select suitable accounting policies and then apply them consistently.
To make judgements and estimates that are reasonable and prudent.
To state whether applicable accounting standards have been followed, subject to any material departures disclosed and explained in the accounts.
To prepare the accounts on the going concern basis unless it is inappropriate to presume that the group will continue in business.

The directors are also responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the financial position of the group and enable them to ensure that the accounts comply with the Companies Act 1985. They are also responsible for taking reasonable steps to safeguard the assets of the group and to prevent and detect fraud and other irregularities.

The directors confirm that they have complied with these requirements, and having a reasonable expectation that the company has adequate resources to continue in operational existence for the foreseeable future, continue to adopt the going concern basis in preparing the accounts.

Independent auditors' report

To the Members of BP p.l.c.

We have audited the group's accounts for the year ended 31 December 2004, which comprise the group income statement, balance sheets, group cash flow statement, statement of total recognized gains and losses, accounting policies and related notes 1 to 47. These accounts have been prepared on the basis of the accounting policies set out therein. We have also audited the information in the Directors' Remuneration Report contained in BP Annual Report and Accounts 2004 that is described as having been subject to audit.

This report is made solely to the company's members, as a body, in accordance with Section 235 of the Companies Act 1985. Our audit work has been undertaken so that we might state to the company's members those matters we are required to state to them in an auditors' report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company's members as a body, for our audit work, for this report or for the opinions we have formed.

Respective responsibilities of directors and auditors

The directors are responsible for preparing the Annual Report and Accounts, including the accounts in accordance with applicable United Kingdom law and accounting standards as set out in the statement of directors' responsibilities in respect of the accounts.

Our responsibility is to audit the accounts and the part of the Directors' Remuneration Report that is subject to audit in accordance with relevant legal and regulatory requirements, United Kingdom Auditing Standards and the Listing Rules of the Financial Services Authority.

We report to you our opinion as to whether the accounts give a true and fair view and whether the accounts and the parts of the Directors' Remuneration Report that are subject to audit have been properly prepared in accordance with the Companies Act 1985. We also report to you if, in our opinion, the Directors' Report, contained in BP Annual Report and Accounts 2004, is not consistent with the accounts, if the company has not kept proper accounting records, if we have not received all the information and explanations we require for our audit, or if the information specified by law or the Listing Rules regarding directors' remuneration and transactions with the group is not disclosed.

We review whether the corporate governance statement contained in BP Annual Report and Accounts 2004 reflects the company's compliance with the nine provisions of the 2003 FRC Code specified for our review by the Listing Rules of the Financial Services Authority, and we report if it does not. We are not required to consider whether the board's statements on internal control cover all risks and controls, or form an opinion on the effectiveness of the group's corporate governance procedures or its risk and control procedures.

We read other information contained in BP Annual Report and Accounts 2004 and consider whether it is consistent with the audited accounts. This other information comprises the United States accounting principles, the supplementary information on oil and natural gas quantities, the five-year summaries, the Directors' Report and the unaudited part of the Directors' Remuneration Report. We consider the implications for our report if we become aware of any misstatements or material inconsistencies with the accounts. Our responsibilities do not extend to any other information.

Basis of audit opinion

We conducted our audit in accordance with United Kingdom Auditing Standards issued by the Auditing Practices Board. An audit includes examination, on a test basis, of evidence relevant to the amounts and disclosures in the accounts and the parts of the Directors' Remuneration Report that are subject to audit. It also includes an assessment of the significant estimates and judgements made by the directors in the preparation of the accounts, and of whether the accounting policies are appropriate to the group's circumstances, consistently applied and adequately disclosed.

We planned and performed our audit so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the accounts and the parts of the Directors' Remuneration Report that are subject to audit are free from material misstatement, whether caused by fraud or other irregularity or error. In forming our opinion we also evaluated the overall adequacy of the presentation of information in the accounts and the part of the Directors' Remuneration Report that is subject to audit.

Opinion

In our opinion:

the accounts give a true and fair view of the state of affairs of the company and of the group as at 31 December 2004 and of the profit of the group for the year then ended; and
the accounts and the part of the Directors' Remuneration Report that is subject to audit have been properly prepared in accordance with the Companies Act 1985.

Ernst & Young LLP

Registered Auditor London 7 February 2005

Accounting policies

Accounting standards

These accounts are prepared in accordance with applicable UK accounting standards. In preparing the financial statements for the current year, the group has adopted Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17) and Urgent Issues Task Force Abstract No. 38 'Accounting for Employee Share Ownership Plan (ESOP) Trusts' (Abstract No. 38). The adoption of FRS 17 and Abstract No. 38 has resulted in changes in accounting policy for pensions and other post-retirement benefits and the accounting of ESOP trusts. (See Note 44 for further information.)

In addition to the requirements of accounting standards, the accounting for exploration and production activities is governed by the Statement of Recommended Practice (SORP) 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities' issued by the UK Oil Industry Accounting Committee on 7 June 2001. These accounts have been prepared in accordance with the provisions of the SORP.

Group consolidation

The group financial statements comprise a consolidation of the accounts of the parent company and its subsidiary undertakings (subsidiaries). The results of subsidiaries acquired or sold are consolidated for the periods from or to the date on which control passes.

An associated undertaking (associate) is an entity in which the group has a long-term equity interest and over which it exercises significant influence. The consolidated financial statements include the group proportion of the operating profit or loss, exceptional items, stock holding gains or losses, interest expense, taxation and net assets of associates (the equity method).

A joint venture is an entity in which the group has a long-term interest and shares control with one or more co-venturers. The consolidated financial statements include the group proportion of turnover, operating profit or loss, exceptional items, stock holding gains or losses, interest expense, taxation, gross assets, gross liabilities and minority shareholders' interest of the joint venture (the gross equity method).

Certain of the group's activities are conducted through joint arrangements and are included in the consolidated financial statements in proportion to the group's interest in the income, expenses, assets and liabilities of these joint arrangements.

On the acquisition of a subsidiary, or of an interest in a joint venture or associate, fair values reflecting conditions at the date of acquisition are attributed to the identifiable net assets acquired. When the cost of acquisition exceeds the fair values attributable to the group's share of such net assets, the difference is treated as purchased goodwill. This is capitalized and amortized on a straight-line basis over its estimated useful economic life, which is usually 10 years.

Where an interest in a separate business of an acquired entity is held temporarily, pending disposal, it is carried on the balance sheet at its estimated net proceeds of sale.

Accounting convention

The accounts are prepared under the historical cost convention, except as explained under stock valuation. Accounts prepared on this basis show the profits available to shareholders and are the most appropriate basis for presentation of the group's balance sheet. Profit or loss

determined under the historical cost convention includes stock holding gains or losses and, as a consequence, does not necessarily reflect underlying trading results.

Replacement cost

The results of individual businesses and geographical areas are presented on a replacement cost basis. Replacement cost operating results exclude stock holding gains or losses and reflect the average cost of supplies incurred during the year, and thus provide insight into underlying trading results. Stock holding gains or losses represent the difference between the replacement cost of sales and the historical cost of sales calculated using the first-in first-out method.

Stock valuation

Stocks, other than stock held for trading purposes, are valued at cost to the group using the first-in first-out method or at net realizable value, whichever is the lower. Stores are valued at cost to the group mainly using the average method or net realizable value, whichever is the lower.

Stock held for trading purposes is marked-to-market and any gains or losses are recognized in the income statement rather than the statement of total recognized gains and losses. The directors consider that the nature of the group's trading activity is such that, in order for the accounts to show a true and fair view of the state of affairs of the group and the results for the year, it is necessary to depart from the requirements of Schedule 4 to the Companies Act 1985. Had the treatment in Schedule 4 been followed, the profit and loss account reserve would have been reduced by $100 million ($150 million) and a revaluation reserve established and increased accordingly.

Revenue recognition

Revenues associated with the sale of oil, natural gas liquids, liquefied natural gas, petroleum and chemical products and all other items are recognized when the title passes to the customer. Supply buy/sell arrangements with common counterparties are reported net, as are physical exchanges. Oil and natural gas forward sales contracts are included in turnover. Generally, revenues from the production of natural gas and oil properties in which the group has an interest with other producers are recognized on the basis of the group's working interest in those properties (the entitlement method). Differences between the production sold and the group's share of production are not significant.

Foreign currency transactions

Foreign currency transactions by group companies are booked in the functional currency at the exchange rate ruling on the date of transaction, or at the forward rate if hedged by a forward exchange contract. Foreign currency monetary assets and liabilities are translated into the functional currency at rates of exchange ruling at the balance sheet date, or at the forward rate. Exchange differences are included in operating profit.

Assets and liabilities of overseas subsidiary and associated undertakings and joint ventures, including related goodwill, are translated into US dollars at rates of exchange ruling at the balance sheet date. The results and cash flows of overseas subsidiary and associated undertakings and joint ventures are translated into US dollars using average rates of exchange. Exchange adjustments arising when the opening net assets and the profits for the year retained by

overseas subsidiary and associated undertakings and joint ventures are translated into US dollars are taken directly to reserves and reported in the statement of total recognized gains and losses. Exchange gains and losses arising on long-term foreign currency borrowings used to finance the group's foreign currency investments are also dealt with in reserves.

Derivative financial instruments

The group uses derivative financial instruments (derivatives) to manage certain exposures to fluctuations in foreign currency exchange rates and interest rates, and to manage some of its margin exposure from changes in oil, natural gas and power prices. Derivatives are also traded in conjunction with these risk management activities.

The purpose for which a derivative contract is used is identified at inception. To qualify as a derivative for risk management, the contract must be in accordance with established guidelines that ensure that it is effective in achieving its objective. All contracts not identified at inception as being for the purpose of risk management are designated as being held for trading purposes and accounted for using the fair value method, as are all oil price derivatives.

The group accounts for derivatives using the following methods:

Fair value method Derivatives are carried on the balance sheet at fair value ('marked-to-market') with changes in that value recognized in earnings of the period. This method is used for all derivatives that are held for trading purposes. Interest rate contracts traded by the group include futures, swaps, options and swaptions. Foreign exchange contracts traded include forwards and options. Oil, natural gas and power price contracts traded include swaps, options and futures.

Accrual method Amounts payable or receivable in respect of derivatives are recognized ratably in earnings over the period of the contracts. This method is used for derivatives held to manage interest rate risk. These are principally swap agreements used to manage the balance between fixed and floating interest rates on long-term finance debt. Other derivatives held for this purpose may include swaptions and futures contracts. Amounts payable or receivable in respect of these derivatives are recognized as adjustments to interest expense over the period of the contracts. Changes in the derivative's fair value are not recognized.

Deferral method Gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. This method is used for derivatives used to convert non-US dollar borrowings into US dollars, to hedge significant non-US dollar firm commitments or anticipated transactions, and to manage some of the group's exposure to natural gas and power price fluctuations. Derivatives used to convert non-US dollar borrowings into US dollars include foreign currency swap agreements and forward contracts. Gains and losses on these derivatives are deferred and recognized on maturity of the underlying debt, together with the matching loss or gain on the debt. Derivatives used to hedge significant non-US dollar transactions include foreign currency forward contracts and options and to hedge natural gas and power price exposures include swaps, futures and options. Gains and losses on these contracts and option premia paid are also deferred and

recognized in the income statement or as adjustments to carrying amounts, as appropriate, when the hedged transaction occurs.

Where derivatives used to manage interest rate risk or to convert non-US dollar debt or to hedge other anticipated cash flows are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying debt or hedged transaction. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement, together with any gain or loss on the terminated item.

The effect of these policies on the accounts is described as follows:

Reporting in the income statement Gains and losses on oil price contracts held for trading and for risk management purposes and natural gas and power price contracts held for trading purposes that are settled for difference in cash are reported in cost of sales in the income statement in the period in which the change in value occurs. Gains and losses on interest rate or foreign currency derivatives used for trading are reported in other income and cost of sales, respectively. Gains and losses in respect of derivatives used to manage interest rate exposures are recognized as adjustments to interest expense.

Where derivatives are used to convert non-US dollar borrowings into US dollars, the gains and losses are deferred and recognized on maturity of the underlying debt, together with the matching loss or gain on the debt. The two amounts offset each other in the income statement.

Gains and losses on derivatives identified as hedges of significant non-US dollar firm commitments or anticipated transactions are not recognized until the hedged transaction occurs. The treatment of the gain or loss arising on the designated derivative reflects the nature and accounting treatment of the hedged item. The gain or loss is recorded in cost of sales in the income statement or as an adjustment to carrying values in the balance sheet, as appropriate.

Gains and losses arising from natural gas and power price derivatives held for risk management purposes are recognized in earnings when the hedged transaction occurs. The gains or losses are reported as components of the related transactions.

Reporting in the balance sheet The carrying amounts of foreign exchange contracts that hedge finance debt are included within finance debt in the balance sheet. The carrying amounts of other derivatives, including option premia paid or received, are included in the balance sheet under debtors or creditors within current assets and current liabilities respectively, as appropriate.

Cash flow effects Interest rate swaps give rise, at specified intervals, to cash settlement of interest differentials. Under currency swaps the counterparties initially exchange a principal amount in two currencies, agreeing to re-exchange the currencies at a future date at the same exchange rate. The group's currency swaps have terms of up to six years.

Interest rate futures require an initial margin payment and daily settlement of margin calls. Interest rate forwards require settlement of the interest rate differential on a specified future date. Currency

forwards require purchase or sale of an agreed amount of foreign currency at a specified exchange rate at a specified future date, generally over periods of up to three years for the group. Currency options involve the initial payment or receipt of a premium and will give rise to delivery of an agreed amount of currency at a specified future date if the option is exercised.

For oil, natural gas and power price futures and options traded on regulated exchanges, gains and losses are settled on a daily basis, while exchange liquidity requirements are funded through letters of credit or cash deposits. For swaps and over-the-counter options, BP settles with the counterparty on conclusion of the pricing period.

In the statement of cash flows, the effect of interest rate derivatives used to manage interest rate exposures is reflected in interest paid. The effect of foreign currency derivatives used for hedging non-US dollar debt is included under financing. The cash flow effects of foreign currency derivatives used to hedge non-US dollar firm commitments and anticipated transactions are included in net cash inflow from operating activities for items relating to earnings or in capital expenditure or acquisitions, as appropriate, for items of a capital nature. The cash flow effects of all oil, natural gas and power price derivatives and all traded derivatives are included in net cash inflow from operating activities.

Oil and natural gas exploration and development expenditure

Oil and natural gas exploration and development expenditure is accounted for using the successful efforts method of accounting.

Licence and property acquisition costs Exploration and property leasehold acquisition costs are capitalized within intangible fixed assets and amortized on a straight-line basis over the estimated period of exploration. Upon determination of economically recoverable reserves ('proved reserves' or 'commercial reserves'), amortization ceases and the remaining costs are aggregated with exploration expenditure and held on a field-by-field basis within intangible fixed assets. When development is sanctioned, the relevant expenditure is transferred to tangible production assets.

Exploration expenditure Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. If hydrocarbons are not found, the exploration expenditure is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of commercial development, the costs continue to be carried as an asset. All such carried costs are subject to regular technical, commercial and management review to confirm the continued intent to develop or otherwise extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined and development is sanctioned, the relevant expenditure is transferred to tangible production assets.

Development expenditure Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, including unsuccessful development or delineation wells, is capitalized within tangible production assets.

Decommissioning

Provision for decommissioning is recognized in full on the installation of oil and natural gas production facilities. The amount recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. A corresponding tangible fixed asset of an amount equivalent to the provision is also created. This is subsequently depreciated as part of the capital costs of the production and transportation facilities.

Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the fixed asset.

Depreciation

Oil and gas production assets are depreciated using a unit-ofproduction method. The cost of producing wells is amortized over proved developed reserves. Licence acquisition, decommissioning and field development costs are amortized over total proved reserves. The field development costs subject to amortization are expenditures incurred to date together with sanctioned future development expenditure.

Other tangible and intangible assets are depreciated on the straightline method over their estimated useful lives. The average estimated useful lives of refineries are 20 years, chemicals manufacturing plants 20 years and service stations 15 years. Other intangibles are amortized over a maximum period of 20 years.

The group undertakes a review for impairment of a fixed asset or goodwill if events or changes in circumstances indicate that the carrying amount of the fixed asset or goodwill may not be recoverable. To the extent that the carrying amount exceeds the recoverable amount, that is, the higher of net realizable value and value in use, the fixed asset or goodwill is written down to its recoverable amount. The value in use is determined from estimated discounted future net cash flows.

Maintenance expenditure

Expenditure on major maintenance, refits or repairs is capitalized where it enhances the performance of an asset above its originally assessed standard of performance; replaces an asset or part of an asset that was separately depreciated and is then written off; or restores the economic benefits of an asset that has been fully depreciated. All other maintenance expenditure is charged to income as incurred.

Petroleum revenue tax

The charge for petroleum revenue tax is calculated using a unit-ofproduction method.

Changes in unit-of-production factors

Changes in factors which affect unit-of-production calculations are dealt with prospectively, not by immediate adjustment of prior years' amounts.

Environmental liabilities

Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future earnings are expensed.

Liabilities for environmental costs are recognized when

environmental assessments or clean-ups are probable and the associated costs can be reasonably estimated. Generally, the timing of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure.

Leases

Assets held under leases that result in group companies receiving substantially all risks and rewards of ownership (finance leases) are capitalized as tangible fixed assets at the estimated present value of underlying lease payments. The corresponding finance lease obligation is included within finance debt. Rentals under operating leases are charged against income as incurred.

Research

Expenditure on research is written off in the year in which it is incurred.

Interest

Interest is capitalized gross of related tax relief during the period of construction where it relates either to the financing of major projects with long periods of development or to dedicated financing of other projects. All other interest is charged against income.

Pensions and other post-retirement benefits

For defined benefit pension and other post-retirement benefit schemes, scheme assets are measured at fair value and scheme liabilities are measured on an actuarial basis using the projected unit method and discounted at an interest rate equivalent to the current rate of return on a high-quality corporate bond of equivalent currency and term to the scheme liabilities. Full actuarial valuations are obtained at least every three years and are updated at each balance sheet date. The resulting surplus or deficit, net of taxation thereon, is presented separately above the total for net assets on the face of the balance sheet.

The service cost of providing pension and other post-retirement benefits to employees for the year is charged to the income statement. The cost of making improvements to pension and other post-retirement benefits is recognized in the income statement on a straight-line basis over the period during which the increase in benefits vests. To the extent that the improvements in benefits vest immediately, the cost is recognized immediately. These costs are recognized as an operating expense.

A charge representing the unwinding of the discount on the scheme liabilities during the year is included within other finance expense.

A credit representing the expected return on the scheme assets during the year is included within other finance expense. This credit is based on the market value of the scheme assets, and expected rates of return, at the beginning of the year.

Actuarial gains and losses may result from: differences between the expected return and the actual return on scheme assets; differences between the actuarial assumptions underlying the scheme liabilities and actual experience during the year; or changes in the actuarial assumptions used in the valuation of the scheme liabilities. Actuarial

gains and losses, and taxation thereon, are recognized in the statement of total recognized gains and losses.

For defined contribution schemes, contributions payable for the year are charged to the income statement as an operating expense.

Deferred taxation

Deferred tax is recognized in respect of all timing differences that have originated but not reversed at the balance sheet date where transactions or events have occurred at that date that will result in an obligation to pay more, or a right to pay less, tax in the future. In particular:

Provision is made for tax on gains arising from the disposal of fixed assets that have been rolled over into replacement assets, only to the extent that, at the balance sheet date, there is a binding agreement to dispose of the replacement assets concerned. However, no provision is made where, on the basis of all available evidence at the balance sheet date, it is more likely than not that the taxable gain will be rolled over into replacement assets and charged to tax only where the replacement assets are sold.
Provision is made for deferred tax that would arise on remittance of the retained earnings of overseas subsidiaries, joint ventures and associated undertakings only to the extent that, at the balance sheet date, dividends have been accrued as receivable.

Deferred tax assets are recognized only to the extent that it is considered more likely than not that there will be suitable taxable profits from which the underlying timing differences can be deducted.

Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which timing differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date.

Discounting

The unwinding of the discount on provisions is included within other finance expense. Any change in the amount recognized for environmental and other provisions arising through changes in discount rates is included within other finance expense.

Use of estimates

The preparation of accounts in conformity with generally accepted accounting practice requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the accounts and the reported amounts of revenues and expenses during the reporting period. Actual outcomes could differ from these estimates.

Comparative figures

Information for 2003 has been restated to reflect the transfer of natural gas liquids activities from Exploration and Production to Gas, Power and Renewables. (See Note 45 for further information.) In addition, certain prior year figures have been restated to conform with the 2004 presentation.

Group income statement

For the year ended 31 December

			$ million
	Note	2004	2003
Turnover		294,849	236,045
Less: Joint ventures		9,790	3,474
Group turnover	1	285,059	232,571
Replacement cost of sales		248,714	201,347
Production taxes	2	2,149	1,723
Gross profit		34,196	29,501
Distribution and administration expenses	3	14,988	14,072
Exploration expense		637	542
		18,571	14,887
Other income	4	675	786
Group replacement cost operating profit	5	19,246	15,673
Share of profits of joint ventures	5	2,933	923
Share of profits of associated undertakings	5	605	511
Total replacement cost operating profit	5	22,784	17,107
Profit (loss) on sale of businesses or termination of operations	7	(695)	(28)
Profit (loss) on sale of fixed assets	7	1,510	859
Replacement cost profit before interest and tax	5	23,599	17,938
Stock holding gains (losses)	5	1,643	16
Historical cost profit before interest and tax	5	25,242	17,954
Interest expense	8	642	644
Other finance expense	9	357	547
Profit before taxation		24,243	16,763
Taxation	12	8,282	6,111
Profit after taxation		15,961	10,652
Minority shareholders' interest (MSI)		230	170
Profit for the year		15,731	10,482
Distribution to shareholders	13	6,371	5,753
Retained profit for the year		9,360	4,729
Earnings per ordinary share – cents
Basic	14	72.08	47.27
Diluted	14	70.79	46.83
Replacement cost results
Historical cost profit for the year		15,731	10,482
Stock holding (gains) losses (net of MSI)		(1,643)	(16)
Replacement cost profit for the year		14,088	10,466
Earnings per ordinary share – cents
On replacement cost profit for the year	14	64.55	47.20

Balance sheets

At 31 December

					$ million
			Group		Parent
	Note	2004	2003	2004	2003
Fixed assets
Intangible assets	19	12,076	13,642	–	–
Tangible assets	20	96,748	91,911	–	–
Investments
Joint ventures – Gross assets		18,244	15,265
– Gross liabilities		(6,316)	(5,111)
– Minority shareholders' interest		(542)	(365)
	21	11,386	9,789
– Loans	21	1,065	1,220
		12,451	11,009	–	–
Associated undertakings	21	5,488	4,870	2	2
Other	21	467	1,579	87,328	55,908

		18,406	17,458	87,330	55,910
Total fixed assets		127,230	123,011	87,330	55,910
Current assets
Stocks	22	15,698	11,617	–	–
Debtors – amounts falling due:
Within one year	23	44,395	31,384	791	865
After more than one year	23	2,301	2,518	1,451	23,751
Investments	24	328	185	–	–
Cash at bank and in hand		1,156	1,947	4	3
		63,878	47,651	2,246	24,619
Creditors – amounts falling due within one year
Finance debt	28	10,184	9,456	–	–
Other creditors	29	54,341	41,128	9,508	6,802
Net current assets (liabilities)		(647)	(2,933)	(7,262)	17,817
Total assets less current liabilities		126,583	120,078	80,068	73,727
Creditors – amounts falling due after more than one year
Finance debt	28	12,907	12,869	–	–
Other creditors	29	4,505	6,030	76	50
Provisions for liabilities and charges
Deferred taxation	12	15,050	14,371	–	–
Other provisions	30	9,608	8,599	–	–
Net assets excluding pension and other
post-retirement benefit balances		84,513	78,209	79,992	73,677
Defined benefit pension plan surpluses	31	1,475	1,146	1,465	1,093
Defined benefit pension plan deficits	31	(5,863)	(5,005)	–	–
Other post-retirement benefit plan deficit	32	(2,126)	(2,630)	–	–
Net assets		77,999	71,720	81,457	74,770
Minority shareholders' interest – equity		1,343	1,125	–	–
BP shareholders' interest		76,656	70,595	81,457	74,770
Represented by
Capital and reserves
Called up share capital	33	5,403	5,552	5,403	5,552
Share premium account	34	5,636	3,957	5,636	3,957
Capital redemption reserve	34	730	523	730	523
Merger reserve	34	27,162	27,077	26,465	26,380
Other reserves	34	44	129	44	129
Shares held by ESOP trusts	34	(82)	(96)	(82)	(96)
Profit and loss account	34	37,763	33,453	43,261	38,325
	35	76,656	70,595	81,457	74,770

The accounts on pages 40-86 were approved by a duly appointed and authorized committee of the board of directors on 7 February 2005 and were signed on its behalf by:

Peter Sutherland, Chairman

The Lord Browne of Madingley, Group Chief Executive

Group cash flow statement

For the year ended 31 December

		$ million
Note	2004	2003
Net cash inflow from operating activities36	28,554	21,698
Dividends from joint ventures	1,908	131
Dividends from associated undertakings	291	417
Servicing of finance and returns on investments
Interest received	332	175
Interest paid	(694)	(1,006)
Dividends received	53	140
Dividends paid to minority shareholders	(33)	(20)
Net cash outflow from servicing of finance and returns on investments	(342)	(711)
Taxation
UK corporation tax	(1,447)	(1,185)
Overseas tax	(4,931)	(3,619)
Tax paid	(6,378)	(4,804)
Capital expenditure and financial investment
Payments for tangible and intangible fixed assets	(13,035)	(12,368)
Payments for fixed assets – investments	–	(9)
Proceeds from the sale of fixed assets17	4,323	6,253
Net cash outflow for capital expenditure and financial investment	(8,712)	(6,124)
Acquisitions and disposals
Acquisitions, net of cash acquired	(1,503)	(211)
Proceeds from the sale of businesses17	725	179
Acquisition of investment in TNK-BP joint venture	(1,250)	(2,351)
Net investment in other joint ventures	(272)	(178)
Investments in associated undertakings	(942)	(987)
Net cash outflow for acquisitions and disposals	(3,242)	(3,548)
Equity dividends paid	(6,041)	(5,654)
Net cash inflow (outflow)	6,038	1,405
Financing36	6,777	1,129
Management of liquid resources36	132	(41)
Increase (decrease) in cash36	(871)	317
	6,038	1,405

Statement of total recognized gains and losses

For the year ended 31 December

		$ million
	2004	2003
Profit for the year	15,731	10,482
Currency translation differences	2,344	3,673
Actuarial gain relating to pensions and other post-retirement benefits	107	76
Unrealized gain on acquisition of further investment in equity-accounted investments	94	–
Tax on currency translation differences	(208)	(37)
Tax on actuarial gain relating to pensions and other post-retirement benefits	96	(16)
Total recognized gains and losses relating to the year	18,164	14,178
Prior year adjustment – change in accounting policy	(5,198)
Total recognized gains and losses since last annual accounts	12,966

Notes on accounts

1 Turnover		$ million
	2004	2003
Sales and operating revenue	352,316	278,859
Customs duties and sales taxes	67,257	46,288
Group turnover	285,059	232,571

		Sales	Sales to		Sales	Sales to
Turnovera	Totalsales	betweenbusinesses	thirdparties	Totalsales	betweenbusinesses	thirdparties
By business
Exploration and Production	34,914	24,756	10,158	30,753	22,885	7,868
Refining and Marketing	179,587	6,539	173,048	149,477	4,448	145,029
Petrochemicals	21,209	780	20,429	16,075	592	15,483
Gas, Power and Renewables	83,320	2,442	80,878	65,639	1,963	63,676
Other businesses and corporate	546	–	546	515	–	515
Group turnover	319,576	34,517	285,059	262,459	29,888	232,571
Share of sales by joint ventures			9,790			3,474
			294,849			236,045
	Totalsales	Salesbetweenareas	Sales tothirdparties	Totalsales	Salesbetweenareas	Sales tothirdparties

By geographical area
UKb	81,155	28,484	52,671	54,971	15,275	39,696
Rest of Europe	54,422	6,928	47,494	50,582	8,672	41,910
USA	130,652	3,603	127,049	108,910	2,169	106,741
Rest of World	68,052	10,207	57,845	52,498	8,274	44,224
	334,281	49,222	285,059	266,961	34,390	232,571
Share of sales by joint ventures
UK			155			144
Rest of Europe			296			290
USA			212			177
Rest of World			9,127			2,863
			9,790			3,474

aTurnover to third parties is stated by origin, which is not materially different from turnover by destination. Transfers between group companies are made at market prices

taking into account the volumes involved. bUK area includes the UK-based international activities of Refining and Marketing.

2 Production taxes $ million

	2004	2003
UK petroleum revenue tax	335	300
Overseas production taxes	1,814	1,423
	2,149	1,723

3 Distribution and administration expenses		$ million
	2004	2003
Distribution	13,577	12,559
Administration	1,411	1,513
	14,988	14,072

4 Other income		$ million
	2004	2003
Income from other fixed asset investments	76	157
Other interest and miscellaneous income	599	629
	675	786
Income from listed investments included above	21	60

5 Analysis of historical cost profit $ million

								2004
	Groupreplacementcostoperatingprofita,b	Jointventures	Associatedundertakings	Totalreplacementcostoperatingprofita,b	Exceptionalitemsc	Replacementcost profitbeforeinterestand tax	Stockholdinggains(losses)	Historicalcost profitbeforeinterestand tax
By business
Exploration and Production	15,185	2,948	235	18,368	152	18,520	10	18,530
Refining and Marketing	4,676	31	132	4,839	(117)	4,722	1,245	5,967
Petrochemicalsd	(514)	(46)	223	(337)	(563)	(900)	349	(551)
Gas, Power and Renewables	872	–	15	887	56	943	39	982
Other businesses and corporatee	(973)	–	–	(973)	1,287	314	–	314
	19,246	2,933	605	22,784	815	23,599	1,643	25,242
By geographical areaUKf	2,267	(6)	9	2,270	(343)	1,927	138	2,065
Rest of Europe	2,758	(14)	34	2,778	(87)	2,691	379	3,070
USA	8,151	29	70	8,250	(205)	8,045	888	8,933
Rest of World	6,070	2,924	492	9,486	1,450	10,936	238	11,174
	19,246	2,933	605	22,784	815	23,599	1,643	25,242
								2003
By business
Exploration and Production	12,567	914	272	13,753	913	14,666	3	14,669
Refining and Marketing	2,367	29	135	2,531	(213)	2,318	(48)	2,270
Petrochemicalsd	461	(20)	89	530	38	568	55	623
Gas, Power and Renewables	579	–	(3)	576	(6)	570	6	576
Other businesses and corporatee	(301)	–	18	(283)	99	(184)	–	(184)
	15,673	923	511	17,107	831	17,938	16	17,954
By geographical area
UKf	1,941	(22)	14	1,933	717	2,650	(9)	2,641
Rest of Europe	2,484	2	15	2,501	(151)	2,350	(230)	2,120
USA	6,177	26	79	6,282	(347)	5,935	390	6,325
Rest of World	5,071	917	403	6,391	612	7,003	(135)	6,868
	15,673	923	511	17,107	831	17,938	16	17,954

aReplacement cost operating profit is before stock holding gains and losses and interest expense, which is attributable to the corporate function. Transfers between group companies are made at market prices taking into account the volumes involved.

bAccounted net foreign currency exchange gains included in the determination of profit for the year amounted to $41 million ($171 million gains). cExceptional items comprise profit or loss on the sale of fixed assets and the sale of businesses or termination of operations.

dIncludes $39 million stock holding losses ($4 million gains) in respect of joint ventures and associated undertakings.

eOther businesses and corporate comprises Finance, the group's coal asset (divested in October 2003) and aluminium asset, its investments in PetroChina and Sinopec (both divested in early 2004), interest income and costs relating to corporate activities worldwide.

f UK area includes the UK-based international activities of Refining and Marketing.

6 Hire charges and expenditure on research $ million

	2004	2003
Hire charges under operating leases
Tanker charters	747	440
Plant and machinery	428	457
Land and buildings	555	548
	1,730	1,445
Expenditure on research	439	349

7 Exceptional items		$ million
	2004	2003
Loss on sale of businesses or termination of operations	(695)	(28)
	(695)	(28)
Profit on sale of fixed assets	1,829	1,894
Loss on sale of fixed assets	(319)	(1,035)
Exceptional items	815	831
Taxation credit (charge)
Sale of businesses or termination of operations	238	–
Sale of fixed assets	23	(123)
Exceptional items (net of tax)	1,076	708

Exceptional items comprise profit (loss) on sale of fixed assets and the sale of businesses or termination of operations. The principal transactions giving rise to these profits and losses for each segment are described below.

Loss on sale of businesses or termination of operations

Refining and Marketing $132 million ($28 million) The closure of the lubricants operation of the Coryton refinery in the UK and of refining operations at the ATAS refinery in Mersin, Turkey. For 2003, the sale of the group's European oil speciality products business. Petrochemicals $563 million (nil) The sale of the speciality intermediate chemicals business; the sale of the fabrics and fibres business; the closure of two manufacturing plants at Hull, UK, which produced acids; and the closure of the linear alpha-olefins production facility at Pasadena, Texas.

Profit on sale of fixed assets

Exploration and Production $379 million ($1,591 million) The group divested interests in a number of oil and natural gas properties in both years. For 2004, this included interests in oil and natural gas properties in Australia, Canada and the Gulf of Mexico, and the reversal of the provision for the loss on sale of $217 million for the Desarrollo Zuli Occidental (DZO) and Boqueron fields in Venezuela (see below). For 2003, the divestment of a further 20% interest in BP Trinidad and Tobago LLC to Repsol; the sale of the group's 96.14% interest in the Forties oil field in the UK North Sea; the sale of a package of UK Southern North Sea gas fields; and the divestment of our interest in the In Amenas gas condensate project in Algeria to Statoil.

Refining and Marketing $107 million ($89 million) The sale of the Cushing and other pipeline interests in the US and the churn of retail assets. In 2003, the divestment of pipeline interests in the US.

Gas, Power and Renewables $56 million ($11 million) The divestment of BP's interest in two natural gas liquids plants in Canada. For 2003, the sale and leaseback of rail cars.

Petrochemicals nil ($55 million) For 2003, the sale of our interest in AG International Chemical Company, a purified isophthalic acid associated undertaking in Japan and other minor divestments.

Other businesses and corporate $1,287 million ($148 million) The divestment of the group's investments in PetroChina and Sinopec. In 2003, the group sold its 50% interest in Kaltim Prima Coal, an Indonesian company, and certain other investments.

Loss on sale of fixed assets

Exploration and Production $227 million ($678 million) The group divested interests in a number of oil and natural gas properties in both years. For 2004, this included interests in oil and natural gas properties in Indonesia and the Gulf of Mexico. In 2003, this included losses on exploration and production properties in China, Norway and the US and the provision for losses on sale in early 2004 of exploration and production properties in Canada and Venezuela. In respect of Venezuela, the sales agreement for our interests in the DZO and Boqueron fields lapsed in early 2004, and the fields have been retained. The provision for a loss on disposal of $217 million recognized in 2003 was reversed in 2004 and an impairment charge of $186 million was recognized.

Refining and Marketing $92 million ($274 million) The divestment of the Singapore refinery and retail churn. For 2003, retail churn and the sale of refinery and retail interests in Germany and Central Europe.

Gas, Power and Renewables nil ($17 million)

Petrochemicals nil ($17 million)

Other businesses and corporate nil ($49 million)

Additional information on the sale of businesses and fixed assets is given in Note 17 Disposals.

8 Interest expense		$ million
	2004	2003
Bank loans and overdrafts	34	38
Other loansa	573	628
Finance leases	37	34
	644	700
Capitalized at 3% (3%)b	208	190
Group	436	510
Joint ventures	158	89
Associated undertakings	48	45
Total charged against profit	642	644

aInterest expense for 2003 includes a charge of $31 million relating to early redemption of debt.

bTax relief on capitalized interest is $73 million ($68 million).

9 Other finance expense $ million

	2004	2003
Interest on pension and other post-retirement benefit plan liabilities	2,012	1,840
Expected return on pension and other post-retirement benefit plan assets	(1,983)	(1,500)
Interest net of expected return on plan assets	29	340
Unwinding of discount on provisions	196	173
Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP	91	34
Change in discount rate for provisionsa	41	–
Total charged against profit	357	547

aRevaluation of environmental and other provisions at a lower discount rate.

10 Auditors' remuneration $ million

		2004		2003
Audit fees – Ernst & Young	UK	Total	UK	Total
Group audit	13	27	8	18
Audit-related regulatory reporting	4	7	2	5
Statutory audit of subsidiaries	4	16	3	13
	21	50	13	36
Fees for other services – Ernst & Young
Further assurance services
Acquisition and disposal due diligence	6	7	9	9
Pension scheme audits	–	1	–	1
Other further assurance services	6	9	5	9
Tax services
Compliance services	3	13	3	17
Advisory services	–	1	–	2
	15	31	17	38

Group audit fees for 2004 include $1 million of additional fees for 2003. Group audit fees include $4 million ($2 million) in respect of the parent company. Audit fees are included in the income statement within distribution and administration expenses.

The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements and were pre-approved by the committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of Ernst & Young relative to that of other potential service providers. These services are for a fixed term.

Fees paid to major firms of accountants other than Ernst & Young for other services amount to $82 million ($44 million).

11 Depreciation and amounts provided		$ million
Included in the income statement under the following headings:	2004	2003
Depreciation and amortization of goodwill and other intangibles
Replacement cost of sales	11,109	9,748
Distribution	1,334	1,044
Administration	128	148
	12,571	10,940
Amounts provided against fixed asset investments
Replacement cost of sales	12	–
	12,583	10,940
Depreciation of capitalized leased assets included above	164	46

The charge for depreciation and amortization of goodwill and other intangibles in 2004 includes asset write-downs and impairment charges of $1,743 million in total. Exploration and Production recognized a charge of $621 million for the impairment of certain assets. During the year, as a result of impairment triggers, reviews were conducted which have resulted in impairment charges of $83 million in respect of King's Peak in the Gulf of Mexico, $20 million in respect of two fields in the Gulf of Mexico Shelf Matagorda Island area and $184 million in respect of various US onshore fields. A charge of $88 million was reflected in respect of a gas processing plant in the US and a charge of $60 million following the blowout of the Temsah platform in Egypt. In addition, following the lapse of the sale agreement for DZO and Boqueron in Venezuela, an impairment charge of $186 million was reflected. In connection with the Solvay transactions, the group has recognized impairment charges of $325 million for goodwill and $306 million for tangible fixed assets in BP Solvay Polyethylene Europe. As part of a restructuring of the North American Olefins and Derivatives businesses, decisions were taken to exit certain businesses and facilities resulting in impairments and write-downs of $291 million. With the formation of Olefins and Derivatives and its planned divestment, certain agreements and assets have been restructured to reflect the arm's-length relationship that will exist in the future. This has resulted in a $188 million impairment of the facilities at Hull, UK. Other businesses and corporate recognized an impairment charge of $12 million for certain investments.

The 2003 charge for depreciation and amortization of goodwill and other intangibles includes asset write-downs and impairment charges on exploration and production properties of $738 million. This includes a charge of $296 million for four fields in the Gulf of Mexico following technical reassessment and re-evaluation of future investment options; charges of $133 million and $49 million respectively for the Miller and Viscount fields in the UK North Sea as a result of a decision not to proceed with waterflood and gas import options and a reserve write-down respectively; a charge of $105 million for the Yacheng field in China; a charge of $108 million for the Kepadong field in Indonesia; and $47 million for the Eugene Island/West Cameron fields in the US as a result of reserve write-downs following completion of our routine full technical reviews.

In assessing the value in use of potentially impaired assets, a nominal discount rate of 9% before tax has been used. Asset values are determined by deriving the net present value of the future cash flows; the cash flows are adjusted for the risks specific to the asset.

12 Taxation		$ million
Tax on profit on ordinary activities	2004	2003
Current tax
UK corporation tax	8,917	11,435
Overseas tax relief	(7,078)	(10,293)
	1,839	1,142
Overseas	5,070	3,525
Group	6,909	4,667
Joint ventures	880	158
Associated undertakings	119	94
	7,908	4,919
Deferred tax
UK	(140)	289
Overseas	340	931
Group	200	1,220
Joint ventures	170	(14)
Associated undertakings	4	(14)
	374	1,192
Tax on profit on ordinary activities	8,282	6,111

Included in the charge for the year is a credit of $261 million ($123 million charge) relating to exceptional items.

		$ million
Tax included in statement of total recognized gains and losses	2004	2003
Current tax
UK	43	–
Overseas	(20)	(11)
	23	(11)
Deferred tax
UK	165	64
Overseas	(76)	–
	89	64
Tax included in statement of total recognized gains and losses	112	53

Factors affecting current tax charge

The following table provides a reconciliation of the UK statutory corporation tax rate to the effective current tax rate of the group on profit before taxation.

		$ million
	2004	2003
Analysis of profit before taxation
UK	7,671	4,990
Overseas	16,572	11,773
	24,243	16,763
Taxation	8,282	6,111
Effective tax rate	34%	36%
		% of profit before tax
UK statutory corporation tax rate	30	30
Increase (decrease) resulting from
UK supplementary and overseas taxes at higher rates	8	10
Tax credits	–	(1)
Restructuring benefits	(2)	(2)
Current year losses unrelieved (prior year losses utilized)	(2)	(3)
No relief for inventory holding losses (inventory holding gains not taxed)	(2)	(1)
Acquisition amortization	3	4
Other	(1)	(1)
Effective tax rate	34	36
Current year timing differences	(1)	(6)
Effective current tax rate	33	30

Current year timing differences arise mainly from the excess of tax depreciation over book depreciation.

12 Taxation continued

Factors that may affect future tax charges

From 1 January 2005, the group has adopted International Financial Reporting Standards (IFRS). As a consequence, there will be a change in the basis of providing deferred taxation in such areas as business combinations and the valuation of stock, which will lead to changes to certain of the factors described below and may lead to a change in the group's effective tax rate.

The group earns income in many different countries and, on average, pays taxes at rates higher than the UK statutory rate. The overall impact of these higher taxes, which include the supplementary charge of 10% on UK North Sea profits, is subject to changes in enacted tax rates and the country mix of the group's income. However, it is not expected to change significantly in the near term.

The group has around $7.7 billion ($4.5 billion) of carry-forward tax losses in the UK and Germany, which would be available to offset against future taxable income. At the end of 2004, no tax assets were recognized on these losses (at the end of 2003, $285 million of assets were recognized). Tax assets are recognized only to the extent that it is considered more likely than not that suitable taxable income will arise. Carry-forward losses in other taxing jurisdictions have not been recognized as deferred tax assets, and are unlikely to have a significant effect on the group's tax rate in future years.

The group's profit before taxation includes stock holding gains or losses. These gains (or losses) are not taxed (or deductible) in certain jurisdictions in which the group operates, and therefore give rise to decreases or increases in the effective tax rate. The impact of this item will be reduced under IFRS.

The impact on the tax rate of acquisition amortization (non-deductible depreciation and amortization relating to the fixed asset revaluation adjustments and goodwill consequent upon the ARCO and Burmah Castrol acquisitions) is likely to be eliminated when the group reports its results under IFRS.

The major component of timing differences in the current year is accelerated tax depreciation. Based on current capital investment plans, the group expects to continue to be able to claim tax allowances in excess of depreciation in future years at a level similar to the current year.

Deferred tax		$ million
	2004	2003
Analysis of provision
Depreciation	15,936	15,613
Other taxable timing differences	2,090	1,882
Petroleum revenue tax	(578)	(601)
Decommissioning and other provisions	(2,142)	(2,256)
Pensions and other post-retirement benefits	(1,720)	(1,652)
Tax credit and loss carry forward	(51)	(105)
Other deductible timing differences	(205)	(162)
Deferred tax provision	13,330	12,719
of which – UK	3,932	4,179
– Overseas	9,398	8,540
		$ million
	2004	2003
Analysis of movements during the year
At 1 January	12,719	10,894
Exchange adjustments	329	541
Charge for the year on ordinary activities	200	1,220
Charge for the year in the statement of total recognized gains and losses	89	64
Deletions/transfers	(7)	–
At 31 December	13,330	12,719
of which – pensions	147	172
– other post-retirement benefits	1,573	1,480
	15,050	14,371
		$ million
	2004	2003
The charge for deferred tax on ordinary activities
Origination and reversal of timing differences	200	1,220
	200	1,220
The charge for deferred tax in the statement of total recognized gains and losses
Origination and reversal of timing differences	89	64

13 Distribution to shareholders		pence per share		cents per share		$ million
	2004	2003	2004	2003	2004	2003
Preference dividends (non-equity)					2	2
Dividends per ordinary share
First quarterly	3.807	3.947	6.75	6.25	1,483	1,386
Second quarterly	3.860	4.039	7.10	6.50	1,535	1,433
Third quarterly	3.910	3.857	7.10	6.50	1,530	1,438
Fourth quarterly	4.522	3.674	8.50	6.75	1,821	1,494
	16.099	15.517	29.45	26.00	6,371	5,753

14 Earnings per ordinary share		cents per share
	2004	2003
Basic earnings per share	72.08	47.27
Diluted earnings per share	70.79	46.83

The calculation of basic earnings per ordinary share is based on the profit attributable to ordinary shareholders, i.e. profit for the year less preference dividends, related to the weighted average number of ordinary shares outstanding during the year. The profit attributable to ordinary shareholders is $15,729 million ($10,480 million). The average number of shares outstanding excludes the shares held by the Employee Share Ownership Plans.

The calculation of diluted earnings per share is based on profit attributable to ordinary shareholders, adjusted for the unwinding of the discount on the deferred consideration for the acquisition of our interest in TNK-BP, of $15,793 million ($10,504 million). The number of shares outstanding is adjusted to show the potential dilution if employee share options are converted into ordinary shares, and for the ordinary shares issuable, in two further annual tranches, in respect of the TNK-BP joint venture. The number of ordinary shares outstanding for basic and diluted earnings per share may be reconciled as follows:

		shares thousand
	2004	2003
Weighted average number of ordinary shares	21,820,535	22,170,741
Potential dilutive effect of ordinary shares issuable under employee share schemes	74,775	71,651
Potential dilutive effect of ordinary shares issuable as consideration for BP's interest in the TNK-BP joint venture	415,016	186,980
	22,310,326	22,429,372

In addition to basic earnings per share based on the historical cost profit for the year, a further measure, based on replacement cost profit for the year, is provided as it is considered that this measure gives an indication of underlying performance.

		cents per share
	2004	2003
Profit for the year	72.08	47.27
Stock holding (gains) losses	(7.53)	(0.07)
Replacement cost profit for the year	64.55	47.20

15 Operating leases $ million

	Land and	2004	Land and	2003
Annual commitments under operating leases	buildings	Other	buildings	Other
Expiring within
1 year	79	359	70	186
2 to 5 years	180	261	173	388
Thereafter	268	387	262	291
	527	1,007	505	865
Minimum future lease payments		Total		Total
Payable within
1 year		1,450		1,275
2 to 5 years		3,550		3,488
Thereafter		3,091		3,352
		8,091		8,115

16 Acquisitions			$ million
			2004
	Book valueon	Fair value
	acquisition	adjustments	Fair value
Intangible fixed assets	15	–	15
Tangible fixed assets	703	636	1,339
Current assets (excluding cash)	721	–	721
Cash at bank and in hand	36	–	36
Other creditors	(329)	–	(329)
Pension liability	(3)	–	(3)
Net investment in equity-accounted entities transferred to full consolidation	(547)	(94)	(641)
Net assets acquired	596	542	1,138
Negative goodwill			(61)
Goodwill			328
Consideration			1,405

Acquisitions in 2004

On 2 November 2004, Solvay exercised its option to sell its interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America to BP. Solvay held 50% of BP Solvay Polyethylene Europe and 51% of BP Solvay Polyethylene North America. On completion, the two entities, which manufacture and market high-density polyethylene, became wholly owned subsidiaries of BP. The total consideration for the acquisition was $1,391 million. The consideration is subject to final closing adjustments. Other minor acquisitions were made for a total consideration of $14 million. All business combinations have been accounted for using the acquisition method of accounting. The fair value of the tangible fixed assets has been estimated by determining the net present value of future cash flows. No significant adjustments were made to the other assets and liabilities acquired. The assets and liabilities acquired as part of the 2004 acquisitions are shown in aggregate in the table above.

During the year, BP China and Sinopec announced the establishment of the BP-Sinopec (Zhejiang) Petroleum Co. Ltd, a retail joint venture between BP and Sinopec. Based on the existing service station network of Sinopec, the new joint venture will build, operate and manage a network of 500 service stations in Hangzhou, Ningbo and Shaoxing. Also during the year, BP China and PetroChina announced the establishment of BP-PetroChina Petroleum Company Limited. Located in Guangdong, one of the most developed provinces in China, the joint venture will acquire, build, operate and manage 500 service stations in the province. The initial investment in both joint ventures amounted to $106 million.

Acquisitions in 2003

BP made a number of minor acquisitions in 2003 for a total consideration of $82 million. All these business combinations were accounted for using the acquisition method of accounting. No significant fair value adjustments were made to the acquired assets and liabilities. Goodwill of $5 million arose on these acquisitions. In addition, the group redeemed the outstanding stock in CH-Twenty, Inc., a subsidiary undertaking, for $150 million.

TNK-BP

On 29 August 2003, BP and the Alfa Group and Access-Renova (AAR) combined certain of their Russian and Ukranian oil and gas businesses to create TNK-BP, a new company owned and managed 50:50 by BP and AAR. TNK-BP is a joint venture and accounted for under the gross equity method. BP contributed its 29% interest in Sidanco, its 29% interest in Rusia Petroleum and its holding in the BP Moscow retail network. There was additional consideration from BP to AAR comprising an immediate $2,604 million in cash (which was subsequently reduced by receipt of pre-acquisition dividends net of other adjustments, of $298 million) together with annual tranches of $1,250 million in BP shares payable in 2004, 2005 and 2006. There were costs of $45 million in connection with the transaction. The first tranche was issued in September 2004.

BP also agreed with AAR to incorporate AAR's 50% interest in Slavneft into TNK-BP in return for $1,418 million in cash (which was subsequently reduced by receipt of pre-acquisition dividends of $64 million to $1,354 million). This transaction was completed on 16 January 2004.

17 Disposals

As part of the strategy to upgrade the quality of its asset portfolio, the group has an active programme to dispose of non-strategic assets. In the normal course of business in any particular year, the group may sell interests in exploration and production properties, service stations and pipeline interests as well as non-core businesses. Disposal proceeds also include monies received from the repayment of loans.

Cash received during the year from disposals amounted to $5.0 billion ($6.4 billion). The major transactions in 2004 which generated over $2.3 billion of proceeds were the sale of the group's investments in PetroChina and Sinopec. For 2003, the major disposals representing over $3.0 billion of the proceeds were the divestment of a further 20% interest in BP Trinidad and Tobago LLC; the sale of 50% of our interest in the In Amenas gas condensate project and 49% of our interest in the In Salah gas development in Algeria; and the sale of the UK North Sea Forties oil field, together with a package of 61 shallow-water assets in the Gulf of Mexico. The principal transactions generating the proceeds for each segment are described below.

Exploration and Production $921 million ($4,867 million) The group divested interests in a number of oil and natural gas properties in both years. During 2004, in the US we sold 45% of our interest in King's Peak in the deepwater Gulf of Mexico to Marubeni Oil & Gas; divested our interest in Swordfish; and additionally, we sold various properties including our interest in the South Pass 60 property in the Gulf of Mexico Shelf. In Canada, BP sold various assets in Alberta to Fairborne Energy. In Indonesia, we disposed of our interest in the Kangean Production Sharing Contract and our participating interest in the Muriah Production Sharing Contract. In 2003, the UK North Sea Forties oil field, together with a package of 61 shallowwater assets in the Gulf of Mexico, were sold to Apache. A 12.5% interest in the Tangguh liquefied natural gas project in Indonesia was sold to CNOOC. Interests in 14 UK Southern North Sea gas fields, together with associated pipelines and onshore processing facilities, including the Bacton terminal, were sold to Perenco. BP sold 50% of its interest in the In Amenas gas condensate project and 49% of its interest in the In Salah gas development in Algeria to Statoil. In January 2003, Repsol exercised its option to acquire a further 20% interest in BP Trinidad and Tobago LLC. BP's interest in the company is now 70%. In February 2003, BP called its $420 million Exchangeable Bonds which were exchangeable for Lukoil American Depositary Shares (ADSs). Bondholders converted to ADSs before the redemption date.

Refining and Marketing $906 million ($1,053 million) The churn of retail assets represents a significant element of the total in both years. In addition, for 2004, major asset transactions included the sale of the Singapore refinery, and the Cushing and other pipeline interests in the US. As a condition of the approval of the acquisition of Veba in 2002, BP was, among other things, required to divest approximately 4% of its retail market share in Germany and a significant portion of its Bayernoil refining interests. The sale of 494 retail sites in the northern and north-eastern part of Germany to PKN Orlen and the sale of retail and refinery assets in Germany and Central Europe to OMV in 2003 completed the divestments required.

Petrochemicals $717 million ($236 million) In 2004, these related principally to the sale of the speciality intermediate chemicals and fabrics and fibres businesses. For 2003, the proceeds related to the completion of the divestment of the former Burmah Castrol speciality chemicals business Sericol and Fosroc Mining.

Gas, Power and Renewables $144 million ($67 million) In 2004, the group sold its interest in two Canadian natural gas liquids plants. Other businesses and corporate $2,360 million ($209 million) The disposal of the group's investments in PetroChina and Sinopec were the major transactions in 2004. In 2003, the group sold its 50% interest in Kaltim Prima Coal, an Indonesian company.

Total proceeds received for disposals represent the following amounts shown in the cash flow statement:

		$ million
	2004	2003
Proceeds from the sale of businesses	725	179
Proceeds from the sale of fixed assets	4,323	6,253
	5,048	6,432
		$ million
	2004	2003
The disposals comprise the following
Intangible assets	215	322
Tangible assetsa	2,549	6,212
Fixed assets – investments	1,197	890
Finance debt	–	(420)
Current assets less current liabilities	417	(498)
Other provisions	(105)	(971)
	4,273	5,535
Profit (loss) on sale of businesses or termination of operations	(695)	(28)
Profit (loss) on sale of fixed assets	1,510	859
Total consideration	5,088	6,366
(Increase) decrease in amounts receivable from disposals	(40)	66
Net cash inflow	5,048	6,432

a2003 includes provision for loss on disposal of $275 million.

18 Group balance sheet analysis				$ million
		Capital expenditureand acquisitions		Operating capitalemployed
	2004	2003	2004	2003
By business
Exploration and Production	11,193	15,370	68,718	63,618
Refining and Marketing	3,014	3,080	38,577	35,111
Petrochemicals	2,289	775	14,755	13,484
Gas, Power and Renewables	538	441	4,901	4,292
Other businesses and corporate	215	346	(8,559)	(6,392)
	17,249	20,012	118,392	110,113
By geographical area
UKa	1,832	1,556	21,342	18,788
Rest of Europe	2,105	1,277	13,109	11,030
USA	6,301	6,291	43,507	44,322
Rest of World	7,011	10,888	40,434	35,973
	17,249	20,012	118,392	110,113
Operating capital employed			118,392	110,113
Liabilities for current and deferred taxation			(17,302)	(16,068)
Capital employed			101,090	94,045
Financed by
Finance debt			23,091	22,325
Minority shareholders' interest			1,343	1,125
BP shareholders' interest			76,656	70,595
			101,090	94,045

aUK area includes the UK-based international activities of Refining and Marketing.

19 Intangible assets						$ million
	Goodwill	Negativegoodwill	Totalgoodwill	Explorationexpenditure	Otherintangibles	Total
Cost
At 1 January 2004	14,384	–	14,384	4,977	833	20,194
Exchange adjustments	451	–	451	41	57	549
Acquisitions	328	(61)	267	–	15	282
Additions	–	–	–	754	246	1,000
Transfers	–	–	–	(1,036)	–	(1,036)
Deletions	(96)	–	(96)	(425)	–	(521)
At 31 December 2004	15,067	(61)	15,006	4,311	1,151	20,468
Depreciation
At 1 January 2004	5,215	–	5,215	741	596	6,552
Exchange adjustments	194	–	194	1	40	235
Charge for the year	1,761	–	1,761	274	72	2,107
Transfers	–	–	–	(196)	–	(196)
Deletions	(36)	–	(36)	(270)	–	(306)
At 31 December 2004	7,134	–	7,134	550	708	8,392
Net book amount
At 31 December 2004	7,933	(61)	7,872	3,761	443	12,076
At 31 December 2003	9,169	–	9,169	4,236	237	13,642

20 Tangible assets – property, plant and equipment $ million

	Land	Buildings	Oil andgasproperties	Plant,machineryandequipment	Fixtures,fittings andofficeequipment	Transport-ation	Oil depots,storagetanks andservicestations	Total	Of which:assetsunderconstruction
Cost
At 1 January 2004	4,442	3,745	96,991	46,413	3,482	11,738	8,969	175,780	13,957
Exchange adjustments	493	71	1,641	2,461	37	182	718	5,603	158
Acquisitions	10	–	–	1,329	–	–	–	1,339	–
Additions	308	121	8,048	2,201	513	852	861	12,904	10,084
Transfers	–	–	1,036	–	–	–	–	1,036	(8,879)
Deletions	(123)	(415)	(3,749)	(2,770)	(314)	(365)	(688)	(8,424)	(282)
At 31 December 2004	5,130	3,522	103,967	49,634	3,718	12,407	9,860	188,238	15,038
Depreciation
At 1 January 2004	702	1,351	50,028	19,590	1,793	6,324	4,081	83,869
Exchange adjustments	90	9	948	1,064	3	83	365	2,562
Charge for the year	50	116	5,871	3,182	334	278	907	10,738
Transfers	–	–	196	–	–	–	–	196
Deletions	(89)	(285)	(3,031)	(1,539)	(370)	(202)	(359)	(5,875)
At 31 December 2004	753	1,191	54,012	22,297	1,760	6,483	4,994	91,490
Net book amount
At 31 December 2004	4,377	2,331	49,955	27,337	1,958	5,924	4,866	96,748	15,038
At 31 December 2003	3,740	2,394	46,963	26,823	1,689	5,414	4,888	91,911	13,957

Assets held under finance leases, capitalized interest, decommissioning asset and land at net book amount included above:

						$ million
			Leased assets			Capitalized interest
	Cost	Depreciation	Net	Cost	Depreciation	Net
At 31 December 2004	2,831	1,127	1,704	3,881	2,547	1,334
At 31 December 2003	2,737	955	1,782	3,281	2,127	1,154
						$ million
						Decommissioning asset
				Cost	Depreciation	Net
At 31 December 2004				4,425	1,908	2,517
At 31 December 2003				3,686	1,606	2,080
						$ million
			Freehold land			Leasehold land
					Over 50 years unexpired	Other
At 31 December 2004			4,177		116	84
At 31 December 2003			3,466		71	203

21 Fixed assets – investments $ million

		Joint ventures		Associated undertakings
	Net assets		Net assets		Other	Listedinvestmentsa	Otherb
Group	(liabilities)	Loans	(liabilities)	Loans	loans			Total
Cost
At 1 January 2004	9,789	1,220	3,992	1,076	129	1,284	179	17,669
Exchange adjustments	18	–	44	9	1	20	6	98
Additions and net movements in joint
ventures and associated undertakings	494	(155)	117	682	–	–	–	1,138
Acquisitions	1,472	–	–	–	–	–	–	1,472
Transfers	(387)	–	20	(180)	–	–	–	(547)
Deletions	–	–	(73)	(57)	(55)	(1,041)	(28)	(1,254)
At 31 December 2004	11,386	1,065	4,100	1,530	75	263	157	18,576
Amounts provided
At 1 January 2004	–	–	21	177	2	–	11	211
Exchange adjustments	–	–	1	–	–	–	3	4
Provided in the year	–	–	–	–	–	–	12	12
Transfers	–	–	–	–	–	–	–	–
Deletions	–	–	–	(57)	–	–	–	(57)
At 31 December 2004	–	–	22	120	2	–	26	170
Net book amount
At 31 December 2004	11,386	1,065	4,078	1,410	73	263	131	18,406
At 31 December 2003	9,789	1,220	3,971	899	127	1,284	168	17,458

				$ million
	Subsidiaryundertakingsc		Associatedundertakingsc
Parent	Shares	Shares	Loans	Total
Cost
At 1 January 2004	55,913	2	2	55,917
Exchange adjustments	–	–	–	–
Additions	31,517	–	–	31,517
Deletions	(85)	–	–	(85)
At 31 December 2004	87,345	2	2	87,349
Amounts provided
At 1 January 2004	5	–	2	7
Provided in the year	12	–	–	12
At 31 December 2004	17	–	2	19
Net book amount
At 31 December 2004	87,328	2	–	87,330
At 31 December 2003	55,908	2	–	55,910

aThe market value of listed investments at 31 December 2004 was $543 million ($3,212 million). bOther investments are unlisted.

cSubstantially all the investments in subsidiary and associated undertakings are unlisted.

22 Stocks		$ million
	2004	2003
Petroleum	9,612	6,623
Chemicals	1,771	1,165
Other	474	961
	11,857	8,749
Stores	925	938
	12,782	9,687
Trading stocks	2,916	1,930
	15,698	11,617
Replacement cost	15,765	11,717

23 Debtors $ million

	Group						Parent
	Within1 year	2004After1 year	Within1 year	2003After1 year	Within1 year	2004After1 year	Within1 year	2003After1 year
Trade	31,223	–	23,487	–	–	–	–	–
Group undertakings	–	–	–	–	647	1,411	774	23,715
Joint ventures	14	–	44	–	–	–	–	–
Associated undertakings	210	23	337	53	–	–	–	–
Prepayments and accrued income	7,188	1,874	3,445	2,023	–	–	6	–
Taxation recoverable	157	2	78	14	–	–	–	–
Other	5,603	402	3,993	428	144	40	85	36
	44,395	2,301	31,384	2,518	791	1,451	865	23,751

24 Current assets – investments $ million

	2004	2003
Listed
UK	21	42
Foreign	42	37
	63	79
Unlisted	265	106
	328	185
Stock exchange value of listed investments	63	79

25 Financial instruments

An outline of the group's financial risks and the policies and objectives pursued in relation to those risks is set out in the financial risk management section of Other Financial Issues on pages 35-36.

Financial instruments comprise primary financial instruments (cash, fixed and current asset investments, debtors, creditors, finance debt and provisions) and derivative financial instruments (interest rate contracts, foreign exchange contracts, oil price contracts, natural gas price contracts and power price contracts). Interest rate contracts include futures contracts, swap agreements and options. Foreign exchange contracts include forwards, futures contracts, swap agreements and options. Oil, natural gas and power price contracts are those that require settlement in cash and include futures contracts, swap agreements and options. Oil, natural gas and power price contracts that require physical delivery are not financial instruments. However, if it is normal market practice for a particular type of oil, natural gas and power contract, despite having contract terms that require settlement by delivery, to be extinguished other than by physical delivery (e.g. by cash payment), it is called a cash-settled commodity contract. Contracts of this type are included with derivatives in the disclosures in Notes 26 and 27.

With the exception of the table of currency exposures shown on page 61, short-term debtors and creditors that arise directly from the group's operations have been excluded from the disclosures contained in this note, as permitted by Financial Reporting Standard No. 13 'Derivatives and Other Financial Instruments: Disclosures'.

Maturity profile of financial liabilities

The profile of the maturity of the financial liabilities included in the group's balance sheet at 31 December is shown in the table below.

						$ million
			2004			2003
	Financedebt	Otherfinancialliabilities	Total	Financedebt	Otherfinancialliabilities	Total
Due within
1 year	10,184	–	10,184	9,456	–	9,456
1 to 2 years	3,046	2,049	5,095	2,702	2,087	4,789
2 to 5 years	6,105	744	6,849	5,105	1,834	6,939
Thereafter	3,756	1,577	5,333	5,062	1,990	7,052
	23,091	4,370	27,461	22,325	5,911	28,236

25 Financial instruments continued

Interest rate and currency of financial liabilities

The interest rate and currency profile of the financial liabilities of the group, at 31 December, after taking into account the effect of interest rate swaps, currency swaps and forward contracts, is set out below.

			Fixed rate		Floating rate		Interest free
	Weightedaverageinterestrate%	Weightedaveragetime forwhich rateis fixedYears	Amount$ million	Weightedaverageinterestrate%	Amount$ million	Weightedaveragetime untilmaturityYears	Amount$ million	Total$ million
								2004
Finance debtUS dollarSterlingOther currencies	7–9	11–15	707–167	354	21,78996332	–––	–––	22,49696499
			874		22,217		–	23,091
Other financial liabilitiesUS dollar	3	2	1,522	5	573	5	1,847	3,942
Sterling	–	–	–	–	–	4	193	193
Other currencies	4	4	15	2	46	4	174	235
			1,537		619		2,214	4,370
Total			2,411		22,836		2,214	27,461
								2003
Finance debt
US dollar	8	14	578	2	20,991	–	–	21,569
Sterling	–	–	–	4	107	–	–	107
Other currencies	9	15	141	3	508	–	–	649
			719		21,606			22,325
Other financial liabilities
US dollar	3	3	2,899	5	242	4	1,817	4,958
Sterling	–	–	–	–	–	5	267	267
Other currencies	5	4	303	–	–	6	383	686
			3,202		242		2,467	5,911
Total			3,921		21,848		2,467	28,236
								$ million
							2004	2003
Analysis of the above financial liabilities by balance sheet captionCreditors – amounts falling due within one year
Finance debtCreditors – amounts falling due after more than one year							10,184	9,456
Finance debt							12,907	12,869
Other creditors							2,978	4,480
Provisions for liabilities and charges
Other provisions							1,392	1,431
							27,461	28,236

The other financial liabilities comprise various accruals, sundry creditors and provisions relating to the group's normal commercial operations, with payment dates spread over a number of years.

The proportion of floating rate debt at 31 December 2004 was 96% of total finance debt outstanding. Aside from debt issued in the US municipal bond markets, interest rates on floating rate debt denominated in US dollars are linked principally to London Inter-Bank Offer Rate (LIBOR), while rates on debt in other currencies are based on local market equivalents. The group monitors interest rate risk using a process of sensitivity analysis. Assuming no changes to the finance debt and hedges described above, it is estimated that a change of 1% in the general level of interest rates on 1 January 2005 would change 2005 profit before tax by approximately $215 million.

25 Financial instruments continued

Interest rate swaps and futures are used by the group to modify the interest characteristics of its long-term finance debt from a fixed to a floating rate basis or vice versa. The following table indicates the types of instruments used and their weighted average interest rates as at 31 December.

		$ millionexcept percentages
	2004	2003
Receive fixed rate swaps – notional amount	8,182	7,432
Average receive fixed rate	3.1%	3.1%
Average pay floating rate	2.3%	1.1%

Currency exchange rate risk

The monetary assets and monetary liabilities of the group in currencies other than the functional currency of individual operating units are summarized below. These currency exposures arise from normal trading activities.

					$ million
				Net foreign currency monetary assets (liabilities)
Functional currency	US dollar	Sterling	Euro	Othercurrencies	Total
					2004
US dollar	–	374	2	(942)	(566)
Sterling	314	–	380	66	760
Other currencies	(269)	(51)	(25)	(237)	(582)
Total	45	323	357	(1,113)	(388)
					2003
US dollar	–	191	(24)	39	206
Sterling	67	–	308	34	409
Other currencies	(1,148)	(25)	(27)	(131)	(1,331)
Total	(1,081)	166	257	(58)	(716)

In accordance with its policy for managing its foreign exchange rate risk, the group enters into various types of foreign exchange contracts, such as currency swaps, forwards and options. The fair values and carrying amounts of these derivatives are shown in the fair value table in Note 27.

Interest rate and currency of financial assets

The following table shows the interest rate and currency profile of the group's material financial assets at 31 December.

			Fixed rate		Floating rate		Interest free
	Weightedaverageinterestrate%	Weightedaveragetime forwhich rateis fixedYears	Amount$ million	Weightedaverageinterestrate%	Amount$ million	Weightedaveragetime untilmaturityYears	Amount$ million	Total$ million
								2004
US dollar	10	11	72	4	186	5	252	510
Sterling	8	2	101	2	292	3	242	635
Other currencies	–	–	–	2	510	1	695	1,205
			173		988		1,189	2,350
								2003
US dollar	–	–	–	2	656	2	154	810
Sterling	8	2	91	3	907	2	257	1,255
Other currencies	3	2	19	1	189	1	1,866	2,074
			110		1,752		2,277	4,139

25 Financial instruments continued		$ million
	2004	2003
Analysis of the above financial assets by balance sheet caption
Fixed assets
Investments	464	1,579
Current assets
Debtors – amounts falling due after more than one year	402	428
Investments	328	185
Cash at bank and in hand	1,156	1,947
	2,350	4,139

The floating rate financial assets earn interest at various rates set principally with respect to LIBOR or the local market equivalent. Fixed asset investments included in the table above are held for the long term and have no maturity period. They are excluded from the calculation of weighted average time until maturity.

26 Derivative financial instruments

In the normal course of business, the group is a party to derivative financial instruments (derivatives) with off balance sheet risk, primarily to manage its exposure to fluctuations in foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate debt. The group also manages certain of its exposures to movements in oil, natural gas and power prices. In addition, the group trades derivatives in conjunction with these risk management activities.

Risk management

Gains and losses on derivatives used for risk management purposes are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate, when the underlying debt matures or the hedged transaction occurs. When an anticipated transaction is no longer likely to occur or finance debt is terminated before maturity, any deferred gain or loss that has arisen on the related derivative is recognized in the income statement, together with any gain or loss on the terminated item. Where such derivatives used for hedging purposes are terminated before the underlying debt matures or the hedged transaction occurs, the resulting gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying hedged item. The unrecognized and carried-forward gains and losses on derivatives used for hedging, and the movements therein, are shown in the following table.

						$ million
			Unrecognized		Carried forward in the balance sheet
	Gains	Losses	Total	Gains	Losses	Total
Gains and losses at 1 January 2004	331	(130)	201	1,003	(425)	578
of which accounted for in income in 2004	98	(28)	70	438	(75)	363
Gains and losses at 31 December 2004	487	(408)	79	1,063	(364)	699
of which expected to be recognized in income in 2005	259	(267)	(8)	265	(77)	188
Gains and losses at 1 January 2003	526	(450)	76	352	(28)	324
of which accounted for in income in 2003	96	(51)	45	200	(14)	186
Gains and losses at 31 December 2003	331	(130)	201	1,003	(425)	578
of which expected to be recognized in income in 2004	98	(28)	70	438	(75)	363

Trading activities

The group maintains active trading positions in a variety of derivatives. This activity is undertaken in conjunction with risk management activities. Derivatives held for trading purposes are marked-to-market and any gain or loss recognized in the income statement. For traded derivatives, many positions have been neutralized, with trading initiatives being concluded by taking opposite positions to fix a gain or loss, thereby achieving a zero net market risk.

The following table shows the fair value at 31 December of derivatives and other financial instruments held for trading purposes. The fair values at the year end are not materially unrepresentative of the position throughout the year.

				$ million
		2004		2003
	Fair valueasset	Fair valueliability	Fair valueasset	Fair valueliability
Interest rate contracts	–	–	–	–
Foreign exchange contracts	36	(90)	30	(54)
Oil price contracts	1,162	(1,177)	586	(667)
Natural gas price contracts	802	(624)	858	(711)
Power price contracts	82	(12)	548	(514)
	2,082	(1,903)	2,022	(1,946)

26 Derivative financial instruments continued

The group measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using value-at-risk techniques. These techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a snapshot of the end-of-day exposures, and the history of one-day price movements over the previous 12 months, together with the correlation of these price movements. The potential movement in fair values is expressed to three standard deviations, which is equivalent to a 99.7% confidence level. This means that, in broad terms, one would expect to see an increase or a decrease in fair values greater than the value at risk on only one occasion per year if the portfolio were left unchanged.

The group calculates value at risk on all instruments that are held for trading purposes and that therefore give an exposure to market risk. The value-at-risk model takes account of derivative financial instruments such as interest rate forward and futures contracts, swap agreements, options and swaptions; foreign exchange forward and futures contracts, swap agreements and options; and oil, natural gas and power price futures, swap agreements and options. Financial assets and liabilities and physical crude oil and refined products that are treated as trading positions are also included in these calculations. The value-at-risk calculation for oil, natural gas and power price exposure also includes cash-settled commodity contracts such as forward contracts.

The following table shows values at risk for trading activities.

								$ million
				2004				2003
	High	Low	Average	Year end	High	Low	Average	Year end
Interest rate trading	1	–	–	–	1	–	–	–
Foreign exchange trading	4	1	1	1	4	–	2	1
Oil price trading	55	18	29	45	34	17	26	27
Natural gas price trading	23	6	13	10	29	4	16	18
Power price trading	10	1	4	4	13	–	4	6

The presentation of trading results shown in the table below includes certain activities of BP's trading units that involve the use of derivative financial instruments in conjunction with physical and paper trading of oil, natural gas and power. It is considered that a more comprehensive representation of the group's oil, natural gas and power price trading activities is given by aggregating the gain or loss on such derivatives together with the gain or loss arising from the physical and paper trades to which they relate, representing the net result of the trading portfolio.

		$ million
	2004	2003
	Netgain (loss)	Netgain (loss)
Interest rate trading	4	9
Foreign exchange trading	136	118
Oil price trading	1,371	825
Natural gas price trading	461	341
Power price trading	160	119
	2,132	1,412

27 Fair values of financial assets and liabilities

The estimated fair value of the group's financial instruments is shown in the table below. The table also shows the 'net carrying amount' of the financial asset or liability. This amount represents the net book value, i.e. market value when acquired or later marked-to-market. Interest rate contracts include futures contracts, swap agreements and options. Foreign exchange contracts include forward and futures contracts, swap agreements and options. Oil, natural gas and power price contracts include futures contracts, swap agreements and options and cash-settled commodity contracts such as forward contracts.

Short-term debtors and creditors that arise directly from the group's operations have been excluded from the disclosures contained in this note, as permitted by Financial Reporting Standard No. 13 'Derivatives and Other Financial Instruments: Disclosures'.

The fair value and carrying amounts of finance debt shown below exclude the effects of currency swaps, interest rate swaps and forward contracts (which are included for presentation in the balance sheet). Long-term borrowings in the table below include debt that matures in the year from 31 December 2004, whereas in the balance sheet long-term debt of current maturity is reported under amounts falling due within one year. Long-term borrowings also include US Industrial Revenue/Municipal Bonds classified on the balance sheet as repayable within one year.

				$ million
		2004		2003
Primary financial instruments	Net fairvalueasset(liability)	Net carryingamountasset(liability)	Net fairvalueasset(liability)	Net carryingamountasset(liability)
Fixed assets – investments	748	464	3,507	1,579
Current assets
Debtors – amounts falling due after more than one year	402	402	428	428
Investments	328	328	185	185
Cash at bank and in hand	1,156	1,156	1,947	1,947
Finance debt
Short-term borrowings	(5,003)	(5,003)	(5,059)	(5,059)
Long-term borrowings	(16,800)	(16,344)	(16,190)	(15,559)
Net obligations under finance leases	(2,608)	(2,579)	(2,479)	(2,452)
Creditors – amounts falling due after more than one year
Other creditors	(2,978)	(2,978)	(4,480)	(4,480)
Provisions for liabilities and charges
Other provisions	(1,392)	(1,392)	(1,431)	(1,431)
Derivative financial or commodity instruments
Risk management
Interest rate contracts	(73)	–	5	–
Foreign exchange contracts	1,084	835	941	745
Oil price contracts	7	7	(5)	(5)
Natural gas price contracts	35	35	(5)	(5)
Power price contracts	–	–	(10)	(10)
Trading
Interest rate contracts	–	–	–	–
Foreign exchange contracts	(54)	(54)	(24)	(24)
Oil price contracts	(15)	(15)	(81)	(81)
Natural gas price contracts	178	178	147	147
Power price contracts	70	70	34	34

The following methods and assumptions were used by the group in estimating its fair value disclosures for its financial instruments:

Fixed assets – Investments The carrying amount reported in the balance sheet for unlisted fixed asset investments approximates their fair value. The fair value of listed fixed asset investments has been determined by reference to market prices.

Current assets – Debtors falling due after more than one year The fair value of other debtors due after one year is estimated not to be materially different from its carrying value.

Current assets – Investments and cash at bank and in hand The carrying amount reported in the balance sheet for unlisted current asset investments and cash at bank and in hand approximates their fair value. The fair value of listed current asset investments has been determined by reference to market prices.

Finance debt The carrying amount of the group's short-term borrowings, which mainly comprise commercial paper, bank loans and overdrafts, approximates their fair value. The fair value of the group's long-term borrowings and finance lease obligations is estimated using quoted prices or, where these are not available, discounted cash flow analyses, based on the group's current incremental borrowing rates for similar types and maturities of borrowing.

Creditors – Amounts falling due after more than one year – Other creditors Deferred consideration for the acquisition of our interest in TNK-BP is discounted to the present value of the future payments. The carrying value thus approximates the fair value. The remaining liabilities are predominantly interest-free. In view of their short maturities, the reported carrying amount is estimated to approximate the fair value. Provisions for liabilities and charges – Other provisions Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure. The carrying amount of provisions thus approximates the fair value.

Derivative financial instruments and cash-settled commodity contracts The fair values of the group's interest rate and foreign exchange contracts are based on pricing models that take into account relevant market data. The fair values of the group's oil, natural gas and power price contracts (futures contracts, swap agreements, options and forward contracts) are based on market prices.

28 Finance debt						$ million
			2004			2003
	Within1 year	After1 year	Total	Within1 year	After1 year	Total
Bank loans	250	457	707	205	253	458
Other loans	9,819	10,167	19,986	9,161	10,524	19,685
Total borrowings	10,069	10,624	20,693	9,366	10,777	20,143
Net obligations under finance leases	115	2,283	2,398	90	2,092	2,182
	10,184	12,907	23,091	9,456	12,869	22,325

Where finance debt is swapped into another currency, the finance debt is accounted in the swap currency and not in the original currency of denomination. Total finance debt includes an asset of $835 million ($745 million) for the carrying value of currency swaps and forward contracts.

Included within Other loans repayable within one year are US Industrial Revenue/Municipal Bonds of $2,487 million ($2,503 million) with maturity periods ranging up to 34 years. They are classified as repayable within one year, as required under UK GAAP, as the bondholders typically have the option to tender these bonds for repayment on interest reset dates. Any bonds that are tendered are usually remarketed and BP has not experienced any significant repurchases. BP considers these bonds to represent long-term funding when assessing the maturity profile of its finance debt.

At 31 December 2004, the group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,500 million expiring in 2005 ($3,700 million expiring in 2004). These facilities are with a number of international banks and borrowings under them would be at pre-agreed rates. The group expects to renew the facilities on an annual basis. Certain of these facilities support the group's commercial paper programme.

At 31 December 2004, the group's share of third-party finance debt of joint ventures and associated undertakings was $2,821 million ($2,151 million) and $1,048 million ($922 million) respectively. These amounts are not reflected in the group's debt on the balance sheet.

						$ million
			2004			2003
Analysis of borrowings by year of repayment	Bank loans	Other loans	Total	Bank loans	Other loans	Total
Due after 10 years	1	773	774	–	721	721
Due within 10 years	29	1	30	–	17	17
9 years	20	5	25	–	337	337
8 years	22	365	387	–	291	291
7 years	28	286	314	–	–	–
6 years	36	99	135	7	1,700	1,707
5 years	33	1,691	1,724	7	938	945
4 years	29	1,510	1,539	8	1,291	1,299
3 years	251	2,431	2,682	193	2,593	2,786
2 years	8	3,006	3,014	38	2,636	2,674
	457	10,167	10,624	253	10,524	10,777
1 year	250	9,819	10,069	205	9,161	9,366
	707	19,986	20,693	458	19,685	20,143

Amounts included above repayable by instalments, part of which falls due after five years from 31 December, are as follows:

After 5 years	204	14
Within 5 years	76	82
	280	96

Interest rates on borrowings repayable wholly or partly more than five years from 31 December 2004 range from 1% to 12% with a weighted average of 4%. The weighted average interest rate on finance debt is 3%.

		$ million
Obligations under finance leases	2004	2003
Minimum future lease payments payable within
1 year	152	127
2 to 5 years	1,060	979
Thereafter	3,540	3,528
	4,752	4,634
Less finance charges	2,354	2,452
Net obligations	2,398	2,182

29 Other creditors $ million

				Group				Parent
		2004		2003		2004		2003
	Within1 year	After1 year	Within1 year	After1 year	Within1 year	After1 year	Within1 year	After1 year
Trade	28,340	–	20,858	–	–	–	–	–
Group undertakings	–	–	–	–	7,449	–	5,061	–
Joint ventures	137	–	126	–	–	–	–	–
Associated undertakings	364	5	322	4	–	–	–	–
Production taxes	517	1,520	421	1,544	–	–	–	–
Taxation on profits	4,131	–	3,441	–	–	–	–	–
Social security	122	–	96	–	57	–	46	–
Accruals and deferred income	9,569	1,000	6,411	1,321	7	76	22	50
Dividends	1,822	–	1,495	–	1,822	–	1,495	–
Other	9,339	1,980	7,958	3,161	173	–	178	–
	54,341	4,505	41,128	6,030	9,508	76	6,802	50

30 Other provisions					$ million
				Group	Parent
	Decom-missioning	Environ-mental	Other	Total	Otherprovisions
At 1 January 2004	4,720	2,298	1,797	8,815	216
Prior year adjustment – change in accounting policy	–	–	(216)	(216)	(216)
Restated	4,720	2,298	1,581	8,599	–
Exchange adjustments	213	21	25	259	–
New provisions	294	588	298	1,180	–
Write-back of unused provisions	–	(151)	(64)	(215)	–
Unwinding of discount	118	55	23	196	–
Change in discount rate	434	40	1	475	–
Utilized/deleted	(199)	(393)	(294)	(886)	–
At 31 December 2004	5,580	2,458	1,570	9,608	–

The group makes full provision for the future cost of decommissioning oil and natural gas production facilities and related pipelines on a discounted basis on the installation of those facilities. At 31 December 2004, the provision for the costs of decommissioning these production facilities and pipelines at the end of their economic lives was $5,580 million ($4,720 million). The provision has been estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2.5%). These costs are expected to be incurred over the next 30 years. While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of incurring these costs.

Provisions for environmental remediation are made when a clean-up is probable and the amount reasonably determinable. Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or closure of inactive sites. The provision for environmental liabilities at 31 December 2004 was $2,458 million ($2,298 million). The provision has been estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2.5%). The majority of these costs are expected to be incurred over the next 10 years. The extent and cost of future remediation programmes are inherently difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions, and also the group's share of liability.

The group also holds provisions for expected rental shortfalls on surplus properties, litigation and sundry other liabilities. To the extent that these liabilities are not expected to be settled within the next three years, the provisions are discounted using either a nominal discount rate of 4.5% (4.5%) or a real discount rate of 2.0% (2.5%), as appropriate.

31 Pensions

Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned. Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and other types of schemes with committed pension payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such factors as the employees' pensionable salary and length of service. Defined benefit plans may be externally funded or unfunded. The assets of funded plans are generally held in separately administered trusts.

Contributions to funded defined benefit plans are based on advice from independent actuaries using actuarial methods, the objective of which is to provide adequate funds to meet pension obligations as they fall due. The pension plans in the UK and US are reviewed annually by the independent actuaries and subject to a formal actuarial valuation at least every three years. The date of the latest actuarial valuation for the UK and US plans was 1 January 2003 and 1 January 2004 respectively. The date of the most recent actuarial reviews was 31 December 2004.

During 2004, contributions of $249 million ($258 million) and $30 million ($2,189 million) were made to the UK plans and US plans respectively. In addition, contributions of $116 million ($86 million) were made to other funded defined benefit plans. The aggregate level of contributions in 2005 is expected to be approximately $600 million.

31 Pensions continued

The pension assumptions for the principal plans are set out below. The assumptions used to evaluate accrued pension benefits at 31 December in any year are used to determine pension expense for the following year, that is, the assumptions at 31 December 2004 are used to determine the pension liabilities at that date and the pension cost for 2005. The assumptions for the parent company are the same as those shown for the UK.

									%
			UK			USA			Other
	2004	2003	2002	2004	2003	2002	2004	2003	2002
Discount rate for plan liabilities	5.25	5.5	5.75	5.75	6.0	6.75	5.0	5.5	5.75
Rate of increase in salaries	4.0	4.0	4.0	4.0	4.0	4.0	4.0	4.0	4.0
Rate of increase for pensions
in payment	2.5	2.5	2.5	nil	nil	nil	2.5	2.5	2.5
Rate of increase in deferred pensions	2.5	2.5	2.5	nil	nil	nil	2.5	2.5	2.5
Inflation	2.5	2.5	2.5	2.5	2.5	2.5	2.5	2.5	2.5

The assumed rate of investment return and discount rate have a significant effect on the amounts reported. A one-percentage-point change in these assumptions for the group's plans would have had the following effects:

		$ million
		One-percentage point
	Increase	Decrease
Investment return
Effect on pension expense in 2005	(312)	314
Discount rate
Effect on pension expense in 2005	(87)	88
Effect on pension obligation at 31 December 2004	(4,508)	5,575

The expected long-term rates of return and market values of the various categories of asset held by the significant defined benefit plans at 31 December are set out below.

						Group			Parent
		2004		2003		2002	2004	2003	2002
	Expectedlong-termrate ofreturn%	Marketvalue$ million	Expectedlong-termrate ofreturn%	Marketvalue$ million	Expectedlong-termrate ofreturn%	Marketvalue$ million	Marketvalue$ million	Marketvalue$ million	Marketvalue$ million
UK plans
Equities	7.5	17,329	7.5	14,642	7.5	10,815	16,263	13,815	10,186
Bonds	4.5	2,859	4.75	2,477	5.0	2,263	2,396	2,092	1,914
Property	6.5	1,660	6.5	1,336	6.5	1,352	1,645	1,325	1,341
Cash	4.0	459	4.0	769	4.0	708	402	618	691
	7.0	22,307	7.0	19,224	7.0	15,138	20,706	17,850	14,132
Present value of plan liabilities		20,399		17,766		14,822	18,613	16,288	13,635
Surplus in the plans		1,908		1,458		316	2,093	1,562	497
Deferred tax		(572)		(437)		(95)	(628)	(469)	(149)
At 31 December		1,336		1,021		221	1,465	1,093	348
US plans
Equities	8.5	6,043	8.5	5,650	8.5	3,371
Bonds	4.75	1,057	4.75	1,018	5.5	720
Property	8.0	28	8.0	41	8.0	49
Cash	3.0	55	3.5	148	3.5	66
	8.0	7,183	8.0	6,857	8.0	4,206
Present value of plan liabilities		7,826		7,709		6,765
Deficit in the plans		(643)		(852)		(2,559)
Deferred tax		231		307		921
At 31 December		(412)		(545)		(1,638)
Other plans
Equities	8.0	933	7.5	686	7.5	515
Bonds	4.25	857	4.75	737	5.0	672
Property	5.25	114	6.5	129	6.5	101
Cash	3.5	288	4.0	187	4.0	159
	6.0	2,192	6.0	1,739	6.0	1,447
Present value of plan liabilities		8,044		6,376		5,141
Deficit in the plans		(5,852)		(4,637)		(3,694)
Deferred tax		540		302		249
At 31 December		(5,312)		(4,335)		(3,445)

31 Pensions continued $ million

				2004			2003				2002

	Surplus	Deficit		Net	Surplus	Deficit	Net		Surplus	Deficit	Net
UK plans	1,465	(129)		1,336	1,093	(72)	1,021		348	(127)	221
US plans	–	(412)		(412)	–	(545)	(545)		–	(1,638)	(1,638)
Other plans	10	(5,322)		(5,312)	53	(4,388)	(4,335)		40	(3,485)	(3,445)
At 31 December	1,475	(5,863)		(4,388)	1,146	(5,005)	(3,859)		388	(5,250)	(4,862)
											$ million
									Group		Parent

					2004				2003	2004	2003
Analysis of the amount charged to operating profit		UK	USA	Other	Total	UK	USA	Other	Total
Current service cost		363	215	118	696	290	177	116	583	341	261
Past service cost		5	–	38	43	–	14	–	14	5	–
Settlement, curtailment and
special termination benefitsPayments to defined contribution plans		37–	–150	2712	64162	––	(11)134	8736	76170	36–	––

Total operating charge		405	365	195	965	290	314	239	843	382	261
Analysis of the amount credited (charged) to
other finance income
Expected return on pension plan assets		1,351	526	104	1,981	1,053	351	94	1,498	1,257	983
Interest on pension plan liabilities		(981)	(445)	(346)	(1,772)	(848)	(432)	(301)	(1,581)	(899)	(779)
Other finance income (expense)		370	81	(242)	209	205	(81)	(207)	(83)	358	204

Analysis of the amount recognized in the
statement of total recognized gains and losses
Actual return less expected return on pension
plan assets		818	379	152	1,349	1,639	749	2	2,390	750	1,526
Experience gains and losses arising on
plan liabilities		83	(22)	(562)	(501)	641	30	135	806	157	621
Change in assumptions underlying the present
value of plan liabilities		(795)	(108)	(366)	(1,269)	(1,437)	(1,030)	(279)	(2,746)	(710)	(1,306)
Actuarial gain (loss) recognized in statement
of total recognized gains and losses		106	249	(776)	(421)	843	(251)	(142)	450	197	841

Movement in surplus (deficit) during the year
Surplus (deficit) in schemes at 1 January		1,458	(852)	(4,637)	(4,031)	316	(2,559)	(3,694)	(5,937)	1,563	497
Movement in year
Current service cost		(363)	(215)	(118)	(696)	(290)	(177)	(116)	(583)	(341)	(261)
Past service cost		(5)	–	(38)	(43)	–	(14)	–	(14)	(5)	–
Settlement, curtailment and special
termination benefits		(37)	–	(27)	(64)	–	11	(87)	(76)	(36)	–
Acquisitions		–	–	(3)	(3)	–	–	1	1	–	–
Disposals		–	32	59	91	–	–	–	–	–	–
Other finance income (expense)		370	81	(242)	209	205	(81)	(207)	(83)	358	204
Actuarial gain (loss)		106	249	(776)	(421)	843	(251)	(142)	450	197	841
Employers' contributions – funded plans		249	30	116	395	258	2,189	86	2,533	214	142
Employers' contributions – unfunded plans		–	32	285	317	–	30	209	239	–	–
Exchange adjustments		130	–	(471)	(341)	126	–	(687)	(561)	142	140
Surplus (deficit) in plans at 31 December		1,908	(643)	(5,852)	(4,587)	1,458	(852)	(4,637)	(4,031)	2,092	1,563

31 Pensionscontinued				Group	Parent
History of experience gains and losses	UK	USA	Other	Total
				2004	2004
Difference between the expected and actual return on plan assets
Amount ($ million)	818	379	152	1,349	750
Percentage of plan assets	4%	5%	7%	4%	4%
Experience gains and losses on plan liabilities
Amount ($ million)	83	(22)	(562)	(501)	157
Percentage of the present value of plan liabilities	0%	0%	(7)%	(1)%	1%
Total amount recognized in statement of total recognized gains and losses
Amount ($ million)	106	249	(776)	(421)	197
Percentage of the present value of plan liabilities	1%	3%	(10)%	(1)%	1%
				2003	2003
Difference between the expected and actual return on plan assets
Amount ($ million)	1,639	749	2	2,390	1,526
Percentage of plan assets	9%	11%	0%	9%	9%
Experience gains and losses on plan liabilities
Amount ($ million)	641	30	135	806	621
Percentage of the present value of plan liabilities	4%	0%	2%	3%	4%
Total amount recognized in statement of total recognized gains and losses
Amount ($ million)	843	(251)	(142)	450	841
Percentage of the present value of plan liabilities	5%	(3)%	(2)%	1%	5%
				2002	2002
Difference between the expected and actual return on plan assets
Amount ($ million)	(3,874)	(1,305)	(137)	(5,316)	(3,655)
Percentage of plan assets	(26)%	(31)%	(9)%	(26)%	(26)%
Experience gains and losses on plan liabilities
Amount ($ million)	212	(290)	90	12	230
Percentage of the present value of plan liabilities	1%	(4)%	2%	0%	2%
Total amount recognized in statement of total recognized gains and losses
Amount ($ million)	(4,142)	(1,938)	(487)	(6,567)	(3,808)
Percentage of the present value of plan liabilities	(28)%	(29)%	(9)%	(25)%	(28)%

32 Other post-retirement benefits

Certain group companies in the US provide post-retirement healthcare and life insurance benefits to their retired employees and dependants. The entitlement to these benefits is usually based on the employee remaining in service until retirement age and completion of a minimum period of service. The plans are funded to a limited extent. The cost of providing post-retirement benefits is assessed annually by independent actuaries using the projected unit method. The date of the latest actuarial valuation was 1 January 2004 and the date of the most recent actuarial review was 31 December 2004.

At 31 December 2004, the independent actuaries reassessed the obligation for post-retirement benefits at $3,676 million ($4,143 million). The discount rate used to assess the obligation at 31 December 2004 of the plans was 5.75% (6.0%).

Assumed future healthcare cost trend rate	2005	2006	2007	2008	2009 andsubsequentyears
Beneficiaries aged under 65	9%	8%	7%	6%	5%
Beneficiaries aged over 65	12%	10%	8%	7%	6%

The assumed healthcare cost trend rate has a significant effect on the amounts reported. A one-percentage-point change in the assumed healthcare cost trend rate would have had the following effects:

		$ million
		One-percentage point
	Increase	Decrease
Effect on post-retirement benefit expense in 2005	39	(31)
Effect on post-retirement obligation at 31 December 2004	458	(373)

BP's post-retirement medical plans in the US provide prescription drug coverage for Medicare-eligible retirees. The group's obligation for other post-retirement benefits at 31 December 2004 reflects the effects of the recent Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act). The provisions of the Act provide for a federal subsidy for plans that provide prescription drug benefits and meet certain qualifications, and alternatively would allow prescription drug plan sponsors to co-ordinate with the Medicare benefit. BP reflected the impact of the legislation by reducing its actuarially determined obligation for post-retirement benefits at 31 December 2004 and will reduce the net cost for postretirement benefits in subsequent periods. The reduction in liability was reflected in the 2004 results as an actuarial gain (assumption change).

The expected long-term rates of return and market values of the various categories of assets held by the plans at 31 December are set out below.

		2004		2003		2002
	Expectedlong-termrate of return%	Marketvalue$ million	Expectedlong-termrate of return%	Marketvalue$ million	Expectedlong-termrate of return%	Marketvalue$ million
US plans
Equities	8.5	21	8.5	24	8.5	24
Bonds	4.75	9	4.75	9	5.5	9
	7.25	30	8.0	33	8.0	33
Present value of plan liabilities		3,676		4,143		4,326
Other post-retirement benefits liability before deferred tax		(3,646)		(4,110)		(4,293)
Deferred tax		1,520		1,480		1,545
At 31 December		(2,126)		(2,630)		(2,748)

32 Other post-retirement benefits continued			$ million
		2004	2003
Analysis of the amount charged to operating profit
Current service cost		61	54
Past service cost		(4)	14
Settlement, curtailment and special termination benefits		–	(669)
Total operating charge (income)		57	(601)
Analysis of the amount charged to other finance costs
Expected return on plan assets		2	2
Interest on plan liabilities		(240)	(259)
Other finance expense		(238)	(257)
Analysis of the amount recognized in the statement of total recognized gains and losses
Actual return less expected return on plan assets		–	2
Experience gains and losses arising on plan liabilities		33	67
Change in assumptions underlying the present value of plan liabilities		495	(443)
Actuarial gain (loss) recognized in statement of total recognized gains and losses		528	(374)
Movement in deficit during the year
Deficit in plans at 1 January		(4,110)	(4,293)
Movement in year
Current service cost		(61)	(54)
Past service cost		4	(14)
Settlement, curtailment and special termination benefits		–	669
Disposals		18	–
Other finance expense		(238)	(257)
Actuarial gain (loss)		528	(374)
Employers' contributions		213	213
Exchange adjustments		–	–
Deficit in schemes at 31 December		(3,646)	(4,110)
History of experience gains and losses	2004	2003	2002

Difference between the expected and actual return on plan assetsAmount ($ million)
Percentage of plan assets	–	2	(8)
Experience gains and losses on plan liabilities	0%	6%	(24)%
Amount ($ million)	33	67	(89)
Percentage of the present value of plan liabilities	1%	2%	(2)%
Total amount recognized in statement of total recognized gains and losses
Amount ($ million)	528	(374)	(1,262)
Percentage of the present value of plan liabilities	14%	(9)%	(29)%

33 Called up share capital

The company's authorized ordinary share capital remains unchanged at 36 billion shares of 25 cents each, amounting to $9 billion. In addition, the company has authorized preference share capital of 12,750,000 shares of £1 each ($21 million). During 2004, the number of ordinary shares in issue decreased by 596,632,202. The number of ordinary shares bought back for cancellation exceeded the number issued in connection with the deferred consideration for the TNK-BP transaction, for employee share schemes and in connection with the ARCO acquisition. Further details of movements in share capital are shown in Note 34.

The allotted, called up and fully paid share capital at 31 December was as follows:

		2004		2003
	Shares	$ million	Shares	$ million
Non-equity
8% cumulative first preference shares of £1 each	7,232,838	12	7,232,838	12
9% cumulative second preference shares of £1 each	5,473,414	9	5,473,414	9
Equity
Ordinary shares of 25 cents each	21,525,977,902	5,382	22,122,610,104	5,531
		5,403		5,552

Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.

In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference shares plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.

34 Capital and reserves $ million

Group	Sharecapital	Sharepremiumaccount	Capitalredemptionreserve	Mergerreserve	Otherreserves	Ownshares	Profitand lossaccount	Total
At 1 January 2004	5,552	3,957	523	27,077	129	–	38,700	75,938
Prior year adjustment – change in accounting policy	–	–	–	–	–	(96)	(5,247)	(5,343)
Restated	5,552	3,957	523	27,077	129	(96)	33,453	70,595
Currency translation differences (net of tax)	–	–	–	–	–	(7)	2,143	2,136
Actuarial gain (net of tax)	–	–	–	–	–	–	203	203
Unrealized gain on acquisition of further
investment in equity-accounted investments	–	–	–	–	–	–	94	94
Employee share schemes	16	311	–	–	–	–	–	327
ARCO	7	153	–	85	(85)	–	–	160
Issue of ordinary share capital for TNK-BP	35	1,215	–	–	–	–	–	1,250
Purchase of shares by ESOP trusts	–	–	–	–	–	(147)	–	(147)
Charge for long-term performance plans and
employee share schemes	–	–	–	–	–	–	226	226
Release of shares by ESOP trusts	–	–	–	–	–	168	(168)	–
Repurchase of ordinary share capital	(207)	–	207	–	–	–	(7,548)	(7,548)
Profit for the year	–	–	–	–	–	–	15,731	15,731
Dividends	–	–	–	–	–	–	(6,371)	(6,371)
At 31 December 2004	5,403	5,636	730	27,162	44	(82)	37,763	76,656

34 Capital and reserves continued $ million

Parent	Sharecapital	Sharepremiumaccount	Capitalredemptionreserve	Mergerreserve	Otherreserves	Ownshares	Profitand lossaccount	Total
At 1 January 2004	5,552	3,957	523	26,380	129	–	40,370	76,911
Prior year adjustment – change in accounting policy	–	–	–	–	–	(96)	(2,045)	(2,141)
Restated	5,552	3,957	523	26,380	129	(96)	38,325	74,770
Currency translation differences (net of tax)	–	–	–	–	–	(7)	–	(7)
Actuarial gain (net of tax)	–	–	–	–	–	–	138	138
Employee share schemes	23	464	–	–	–	–	–	487
ARCO	–	–	–	85	(85)	–	–	–
Issue of ordinary share capital for TNK-BP	35	1,215	–	–	–	–	–	1,250
Purchase of shares by ESOP trusts	–	–	–	–	–	(147)	–	(147)
Charge for long-term performance plans and
employee share schemes	–	–	–	–	–	–	208	208
Release of shares by ESOP trusts	–	–	–	–	–	168	(168)	–
Repurchase of ordinary share capital	(207)	–	207	–	–	–	(7,548)	(7,548)
Profit for the year	–	–	–	–	–	–	18,677	18,677
Dividends	–	–	–	–	–	–	(6,371)	(6,371)
At 31 December 2004	5,403	5,636	730	26,465	44	(82)	43,261	81,457

Employee share schemes

During the year, 62,224,092 ordinary shares were issued under the BP, Amoco and Burmah Castrol employee share schemes.

ARCO

29,288,178 ordinary shares were issued in respect of ARCO employee share option schemes.

Repurchase of ordinary share capital

The company purchased for cancellation 827,240,360 ordinary shares for a total consideration of $7,548 million.

As a consolidated income statement is presented, a separate income statement for the parent company is not required to be published.

The profit and loss account reserve includes the following amounts, the distribution of which is limited by statutory or other restrictions:

		$ million
	2004	2003
Parent company	25,026	24,107
Subsidiary undertakings	2,927	2,115
Joint ventures and associated undertakings	441	566
	28,394	26,788

35 Reconciliation of movements in shareholders' interest $ million

Note	2004	2003
Profit for the year	15,731	10,482
Currency translation differences	2,344	3,673
Actuarial gain relating to pensions and other post-retirement benefits	107	76
Tax on currency translation differences	(208)	(37)
Tax on actuarial gain (loss) relating to pensions and other post-retirement benefits	96	(16)
Unrealized gain on acquisition of further investment in equity-accounted investments	94	–
Dividends13	(6,371)	(5,753)
Issue of ordinary share capital for employee share schemes	487	173
Issue of ordinary share capital for TNK-BP	1,250	–
Purchase of shares by ESOP trusts	(147)	(63)
Charge for long-term performance plans and employee share schemes	226	225
Repurchase of ordinary share capital	(7,548)	(1,999)
Net increase in shareholders' interest	6,061	6,761
Shareholders' interest at 1 January	70,595	63,834
Shareholders' interest at 31 December	76,656	70,595

		36 Group cash flow statement analysis		$ million
--	--	---------------------------------------	--	------------

Reconciliation of historical cost profit before interest and tax to net cash inflow from operating activities	2004	2003
Historical cost profit before interest and tax	25,242	17,954
Depreciation and amounts provided	12,583	10,940
Exploration expenditure written off	274	297
Net operating charge for pensions and other post-retirement benefits, less contributions	(67)	(2,913)
Share of profits of joint ventures and associated undertakings	(3,574)	(1,438)
Interest and other income	(325)	(341)
(Profit) loss on sale of fixed assets and businesses or termination of operations	(815)	(831)
Charge for provisions	671	782
Utilization of provisions	(781)	(716)
(Increase) decrease in stocks	(3,595)	(841)
(Increase) decrease in debtors	(10,920)	(3,042)
Increase (decrease) in creditors	9,861	1,847
Net cash inflow from operating activities	28,554	21,698
		$ million
Financing	2004	2003
Long-term borrowing	(2,675)	(4,322)
Repayments of long-term borrowing	2,204	3,560
Short-term borrowing	(3,335)	(4,706)
Repayments of short-term borrowing	3,375	4,708
	(431)	(760)
Issue of ordinary share capital for employee share schemes	(487)	(173)
Purchase of shares by ESOP trusts	147	63
Repurchase of ordinary share capital	7,548	1,999

Management of liquid resources

Liquid resources comprise current asset investments, which are principally commercial paper issued by other companies. The net cash outflow from the management of liquid resources was $132 million ($41 million inflow).

Net cash outflow (inflow) 6,777 1,129

Commercial paper

Net movements in commercial paper are included within short-term borrowings or repayment of short-term borrowings as appropriate.

								$ million
				2004				2003
Movement in net debt	Financedebt	Cash	Currentassetinvestments	Netdebt	Financedebt	Cash	Currentassetinvestments	Netdebt
At 1 January	(22,325)	1,947	185	(20,193)	(22,008)	1,520	215	(20,273)
Exchange adjustments	(403)	80	11	(312)	(199)	110	11	(78)
Debt acquired	–	–	–	–	(15)	–	–	(15)
Net cash flow	(431)	(871)	132	(1,170)	(760)	317	(41)	(484)
Debt transferred to TNK-BP	–	–	–	–	93	–	–	93
Exchange of Exchangeable Bonds for Lukoil
American Depositary Shares	–	–	–	–	420	–	–	420
Other movements	68	–	–	68	144	–	–	144
At 31 December	(23,091)	1,156	328	(21,607)	(22,325)	1,947	185	(20,193)

37 Employee share plans

Employee share options granted during the yeara (options thousand)	2004	2003
Executive Directors' Incentive Plan	2,783	2,728
BP Share Option Plan	71,750	78,109
Savings-related schemes	5,861	23,922
	80,394	104,759

aThe exercise prices for BP options granted during the year were £4.22/$7.73 (weighted average price) for Executive Directors' Incentive Plan (2,783,333 options); £4.38/$8.01 (weighted average price) for 71,750,436 options granted under the BP Share Option Plan; and £3.86/$7.06 (5,860,991 options) for savings-related and similar plans.

BP offers most of its employees the opportunity to acquire a shareholding in the company through savings-related and/or matching share plan arrangements. Such arrangements are now in place in more than 80 countries. BP also uses long-term performance plans (see Note 38) and the granting of share options as elements of remuneration for executive directors and senior employees.

During 2004, share options were granted to the executive directors under the Executive Directors' Incentive Plan (EDIP). For these options, the option exercise price was the market value (as determined in accordance with the plan rules) on the grant date. The options granted to executive directors reflect BP's performance in terms of total shareholder return, that is, share price increase with all dividends reinvested, relative to the FTSE Global 100 group of companies over the three years preceding the grant as well as the underlying health of the business and the competitive marketplace. Options have not been granted in any year unless the criteria for an award of shares under the share element of the EDIP (see Note 38) have been met. Options vest over three years (one-third each after one, two and three years respectively) and have a life of seven years after the grant.

Share options were also granted in 2004 under the BP Share Option Plan to certain categories of employees. Subject to certain vesting requirements, the options are exercisable between the third and 10th anniversaries of the date of grant. There are no performance conditions attaching to the options granted during the year.

Under the BP ShareSave Plan (a savings-related share option plan), employees save on a monthly basis over a three- or five-year period towards the purchase of shares at a price fixed when the option is granted. The option price is usually set at a 20% discount to the market price at the time of grant. The option must be exercised within six months of maturity of the savings contract; otherwise it lapses. The plan is run in the UK and a small number of other countries.

Under the BP ShareMatch Plan, BP matches employees' own contributions of shares, up to a predetermined limit. The shares are then held in trust for a defined minimum period. The plan is run in the UK and in over 70 other countries.

The group takes advantage of the exemption granted under Urgent Issues Task Force Abstract No. 17 (revised 2003) 'Employee Share Schemes', whereby no compensation expense need be recognized for the BP ShareSave Plan. BP does not recognize an expense in respect of share options granted to employees under the BP Share Option Plan. If the fair value of options granted in any particular year is estimated and this value amortized over the vesting period of the options, an indication of the cost of granting options to employees can be made. The fair value of each share option granted has been estimated using a Black Scholes option pricing model with the following assumptions:

	2004	2003
Risk-free interest rate	4.00%	3.5%
Expected volatility	22%	30%
Expected life in years	1 to 5	1 to 5
Expected dividend yield	3.75%	4.00%
Weighted average fair value of options granted ($)	1.40	1.44

The additional expense that would have been recognized in 2004 on this basis would be $79 million ($79 million) and the impact on earnings per share would be 1 cent (1 cent).

The company sponsors a number of savings plans covering most US employees. Under these plans, most employees may contribute up to 100% of their salary subject to certain regulatory limits. Most employees are eligible for a dollar-for-dollar company-matched contribution for the first 7% of eligible pay contributed on a before-tax or after-tax basis, or a combination of both. The precise arrangement may vary in certain business units. Plan participants may invest contributions in more than 200 investment options, including a fund comprised primarily of BP ADSs. The company's contributions generally vest over a period of three years (0% for years one and two and 100% after completion of three years). Company contributions to savings plans during the year were $138 million ($130 million).

An Employee Share Ownership Plan (ESOP) was established in 1997 to acquire BP shares to satisfy future requirements of employee share plans, principally the BP ShareMatch Plan. The ESOP holds the shares for participants during the retention period of the plan. The company provides funding to the ESOP. Until such time as the company's own shares held by the ESOP trust vest unconditionally in employees, the amount paid for those shares is deducted in arriving at shareholders' interest (see Notes 34 and 35). Other assets and liabilities of the ESOP are recognized as assets and liabilities of the company. The ESOP has waived its rights to dividends.

During 2004, the ESOP released 14,156,047 shares (16,892,853 shares) for the matching share plans. The cost of shares released for these plans has been charged in these accounts. At 31 December 2004, the ESOP held 2,682,860 shares (7,811,544 shares), which had a market value of $26 million ($63 million).

37 Employee share plans continued

Shares issued in respect of options exercised during the year (shares thousand)	2004	2003
Savings-related schemes	3,163	5,325
BP, Amoco and Burmah Castrol executive share option plans	59,061	27,564
	62,224	32,889

Options outstanding at 31 December	2004	2003
BP options (shares thousand)	470,264	461,886
Exercise period	2005-2014	2004-2013
Price	£2.04-£6.40	£1.86-£6.40
Price	$3.95-$9.97	$3.47-$9.97

Details of directors' individual participation in share schemes are given in the directors' remuneration report on pages 116-125.

38 Long-term performance plans

During 2004, the company operated two long-term performance plans: the Executive Directors' Incentive Plan (EDIP) for executive directors and the Long Term Performance Plan (LTPP) for senior employees. Executive directors participated in the LTPP prior to 2002 or to their appointment as an executive director, whichever was the later. Both plans are incentive schemes under which the company may award shares to participants or fund the purchase of shares for participants if long-term targets are met. Awards were made in 2004 in respect of the 2001-2003 LTPP. Further details of the plans are given in the directors' remuneration report on pages 116-125.

The costs of potential future awards for both the EDIP and LTPP are accrued over the three-year performance periods of each plan. The amount charged in 2004 was $89 million ($94 million). The value of awards under the 2001-2003 LTPP made in 2004 was $42 million (2000-2002 LTPP $35 million). Employees are able to defer the date of their potential award beyond the end of the performance period. The amount charged in respect of the increase in deferred awards after the expiry of the relevant performance periods was $23 million ($17 million).

Employee Share Ownership Plans (ESOPs) have been established to acquire BP shares to satisfy any awards made to participants under the EDIP and LTPP and then to hold them for the participants during the retention period of the plan. The company provides funding to the ESOPs. Until such time as the company's own shares held by the ESOP trusts vest unconditionally in employees, the amount paid for those shares is deducted in arriving at shareholders' interest (see Notes 34 and 35). Other assets and liabilities of the ESOPs are recognized as assets and liabilities of the company. The ESOPs have waived their rights to dividends on shares held for future awards.

At 31 December 2004, the ESOPs held 5,938,359 shares (4,118,835 shares) for potential future awards, which had a market value of $58 million ($33 million).

39 Employee costs and numbers		$ million
Employee costs	2004	2003
Wages and salaries	7,922	7,142
Social security costs	667	622
Pension and other post-retirement benefit costs	1,051	582
	9,640	8,346

Number of employees at 31 December	2004	2003
Exploration and Production	15,650	15,150
Refining and Marketinga	67,250	66,150
Petrochemicals	12,400	15,950
Gas, Power and Renewables	4,050	3,750
Other businesses and corporate	3,550	2,700
	102,900	103,700

aIncludes 27,950 (26,950) service station staff.

					2004					2003
Average number		Rest of		Rest of			Rest of		Rest of
of employees	UK	Europe	USA	World	Total	UK	Europe	USA	World	Total
Exploration and Production	2,900	650	4,900	6,950	15,400	3,200	750	5,000	6,900	15,850
Refining and Marketing	10,100	18,250	25,900	12,550	66,800	9,900	19,600	26,950	12,300	68,750
Petrochemicals	2,400	5,750	5,450	1,250	14,850	2,650	5,950	6,250	1,800	16,650
Gas, Power
and Renewables	200	800	1,400	1,550	3,950	250	950	1,450	1,550	4,200
Other businesses
and corporate	1,550	–	1,550	100	3,200	1,250	–	1,350	100	2,700
	17,150	25,450	39,200	22,400	104,200	17,250	27,250	41,000	22,650	108,150

40 Directors' remuneration $ million

	2004	2003
Total for all directors
Emoluments	19	17
Ex-gratia payments to executive directors retiring in the year	–	1
Gains made on the exercise of share options	3	1
Amounts awarded under incentive schemes	6	4

Emoluments

These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned during the relevant financial year, plus bonuses awarded for the year.

Pension contributions

Six executive directors participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which contributions are made by BP based on actuarial advice. One US executive director participated in the US BP Retirement Accumulation Plan during 2004.

Office facilities for former chairmen and deputy chairmen

It is customary for the company to make available to former chairmen and deputy chairmen, who were previously employed executives, the use of office and basic secretarial facilities following their retirement. The cost involved in doing so is not significant.

Further information

Full details of individual directors' remuneration are given in the directors' remuneration report on pages 116-125.

41 Joint ventures and associated undertakings

The significant joint ventures and associated undertakings of the BP group at 31 December 2004 are shown in Note 46. The principal joint venture is the TNK-BP joint venture. Summarized financial information for the group's share of joint ventures is shown below.

						$ million
			2004			2003
	TNK-BP	Other	Total	TNK-BP	Other	Total
Turnover	7,839	1,951	9,790	1,864	1,610	3,474
Profit for the period before tax	2,320	455	2,775	475	360	835
Taxation	752	298	1,050	83	61	144
Profit for the period after tax	1,568	157	1,725	392	299	691
Fixed assets	9,955	4,556	14,511	8,389	3,558	11,947
Current assets	2,565	1,168	3,733	1,950	1,368	3,318
	12,520	5,724	18,244	10,339	4,926	15,265
Liabilities due within one year	1,959	686	2,645	1,575	752	2,327
Liabilities due after one year	1,851	1,820	3,671	1,350	1,434	2,784
	8,710	3,218	11,928	7,414	2,740	10,154
Minority shareholders' interest	542	–	542	365	–	365
	8,168	3,218	11,386	7,049	2,740	9,789

The joint venture TNK-BP was created on 29 August 2003. (See Note 16 for further information.) TNK-BP, in which BP holds a 50% interest, is an integrated oil company operating, inter alia, in Russia.

The preliminary fair values attributed to the assets and liabilities of TNK-BP in 2003 have been revised in 2004 as permitted by Financial Reporting Standard No. 7 'Fair Values in Acquisition Accounting'.

The results for TNK-BP for 2004 have been estimated. Any difference between the estimated and actual results for this period will be included in the results for 2005. The adjustment included in 2004 in respect of 2003 was a charge of $36 million.

BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America became subsidiary undertakings with effect from 2 November 2004. (See Note 16 for further information.)

Transactions between the significant joint ventures and associated undertakings and the group are summarized below.

Sales to joint ventures and associated undertakings					$ million
			2004		2003
	Product	Sales	Amountreceivable at31 December	Sales	Amountreceivable at31 December
Joint ventures
BP Solvay Polyethylene Europea	Chemicals feedstocks	230	–	259	33
Pan American Energy	Crude oil	118	4	171	5
Watson Cogeneration	Natural gas	214	10	73	6
Associated undertakings
BP Solvay Polyethylene North Americaa	Chemicals feedstocks	217	–	241	17
China American Petrochemical Co.	Chemicals feedstocks	385	81	240	67
Samsung Petrochemical Co.	Chemicals feedstocks	62	8	55	10
Purchases from joint ventures and associated undertakings			2004		$ million2003

	Product	Purchases	Amountpayable at31 December	Purchases	Amountpayable at31 December
Joint ventures
BP Solvay Polyethylene Europea	Chemicals feedstocks	–	–	18	14
Pan American Energy	Crude oil	481	43	381	48
TNK-BPb	Crude oil and oil products	1,809	80	349	52
Watson Cogeneration	Electricity and steam	149	14	248	12
Associated undertakings
Abu Dhabi Marine Areas	Crude oil	866	91	661	61
Abu Dhabi Petroleum Co.	Crude oil	1,547	145	1,122	118
BP Solvay Polyethylene North Americaa	Chemicals feedstocks	9	–	11	1
China American Petrochemical Co.	Petrochemicals	455	111	197	83
Samsung Petrochemical Co.	Chemicals feedstocks	290	17	187	38

aThe 2004 BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America sales and purchases shown above relate to the period to 2 November 2004. bThe 2003 TNK-BP purchases shown above relate to the period from 29 August to 31 December 2003.

42 Contingent liabilities

There were contingent liabilities at 31 December 2004 in respect of guarantees and indemnities entered into as part of the ordinary course of the group's business. No material losses are likely to arise from such contingent liabilities.

Approximately 200 lawsuits were filed in State and Federal Courts in Alaska seeking compensatory and punitive damages arising out of the Exxon Valdez oil spill in Prince William Sound in March 1989. Most of those suits named Exxon (now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies that own Alyeska. Alyeska initially responded to the spill until the response was taken over by Exxon. BP owns a 47% interest (reduced during 2001 from 50% by a sale of 3% to Phillips) in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP's combination with Atlantic Richfield Company (Atlantic Richfield). Alyeska and its owners have settled all the claims against them under these lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages which it has incurred. If any claims are asserted by Exxon that affect Alyeska and its owners, BP will defend the claims vigorously.

Since 1987, Atlantic Richfield, a current subsidiary of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed as against Atlantic Richfield. Atlantic Richfield (and in one case two of its affiliates) is named in these lawsuits as alleged successor to International Smelting & Refining which, along with a predecessor company, manufactured lead pigment during the period 1920-1946. Plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be class actions. The lawsuits (depending on plaintiff) seek various remedies, including: compensation to lead-poisoned children; cost to find and remove lead paint from buildings; medical monitoring and screening programmes; public warning and education on lead hazards; reimbursement of government healthcare costs and special education for lead-poisoned citizens; and punitive damages. No lawsuit against Atlantic Richfield has been settled or tried to conclusion. The amounts claimed and, if such suits were successful, the costs of implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions, Atlantic Richfield believes that it has valid defences and it intends to defend such actions vigorously and thus the incurring of a liability by Atlantic Richfield is remote. Consequently, BP believes that the impact of these lawsuits on the group's results of operations, financial position or liquidity will not be material.

The group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations has been provided in these accounts in accordance with the group's accounting policies. While the amounts of future costs could be significant and could be material to the group's results of operations in the period in which they are recognized, BP does not expect these costs to have a material effect on the group's financial position or liquidity.

The parent company has issued guarantees under which amounts outstanding at 31 December 2004 were $21,106 million ($20,903 million), including $21,050 million ($20,847 million) in respect of borrowings by its subsidiary undertakings and $56 million ($56 million) in respect of liabilities of other third parties. In addition, other group companies have issued guarantees under which amounts outstanding at 31 December 2004 were $1,281 million ($635 million) in respect of borrowings of joint ventures and associated undertakings and $650 million ($304 million) in respect of liabilities of other third parties.

43 Capital commitments

Authorized future capital expenditure by group companies for which contracts had been placed at 31 December 2004 amounted to $6,765 million ($6,420 million).

44 New accounting standards

Comparative information for 2003 has been restated to reflect the changes described below:

(a) New accounting standard for pensions and other post-retirement benefits

With effect from 1 January 2004, BP has adopted Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17). FRS 17 requires that financial statements reflect at fair value the assets and liabilities arising from an employer's retirement benefit obligations and any related funding. The operating costs of providing retirement benefits are recognized in the period in which they are earned, together with any related finance costs and changes in the value of related assets and liabilities. This contrasts with Statement of Standard Accounting Practice No. 24 'Accounting for Pension Costs', which required the cost of providing pensions to be recognized on a systematic and rational basis over the period during which the employer benefited from the employee's services. The difference between the amount charged in the income statement and the amount paid as contributions into the pension fund was shown as a prepayment or provision on the balance sheet.

This change in accounting policy has resulted in a prior year adjustment. Shareholders' interest at 1 January 2003 has been reduced by $5,601 million and the profit for the year ended 31 December 2003 increased by $215 million. Profit for the current year has been increased by approximately $301 million as a result of the change in accounting policy.

(b) Accounting for Employee Share Ownership Plans

With effect from 1 January 2004, BP has adopted Urgent Issues Task Force Abstract No. 38 'Accounting for Employee Share Ownership Plan (ESOP) Trusts'. This abstract requires that BP shares held by the group for the purposes of Employee Share Ownership Plans (ESOPs) are deducted from equity on the balance sheet. Such shares were previously classified as fixed asset investments. In addition, accruals for awards under the Long Term Performance Plan have also been included in reserves.

This change in accounting policy has resulted in a prior year adjustment. Shareholders' interest at 1 January 2003 has been increased by $26 million. The impact of the change in accounting policy on profit for the years ended 31 December 2003 and 2004 is not significant.

		$ million
Group income statement for the year ended 31 December 2003	Restated	Reported
Turnover	236,045	236,045
Less: Joint ventures	3,474	3,474
Group turnover	232,571	232,571
Replacement cost of sales	201,347	202,041
Production taxes	1,723	1,723
Gross profit	29,501	28,807
Distribution and administration expenses	14,072	14,072
Exploration expense	542	542
	14,887	14,193
Other income	786	786
Group replacement cost operating profit	15,673	14,979
Share of profits of joint ventures	923	923
Share of profits of associated undertakings	511	511
Total replacement cost operating profit	17,107	16,413
Profit (loss) on sale of businesses or termination of operations	(28)	(28)
Profit (loss) on sale of fixed assets	859	859
Replacement cost profit before interest and tax	17,938	17,244
Stock holding gains (losses)	16	16
Historical cost profit before interest and tax	17,954	17,260
Interest expense	644	851
Other finance expense	547	–
Profit before taxation	16,763	16,409
Taxation	6,111	5,972
Profit after taxation	10,652	10,437
Minority shareholders' interest	170	170
Profit for the year	10,482	10,267
Distribution to shareholders	5,753	5,753
Retained profit for the year	4,729	4,514
Earnings per ordinary share – cents
Basic	47.27	46.30
Diluted	46.83	45.87

44 New accounting standards continued		$ million
Group balance sheet at 31 December 2003	Restated	Reported
Fixed assets
Intangible assets	13,642	13,642
Tangible assets	91,911	91,911
Investments	17,458	17,554
	123,011	123,107
Current assets	47,651	54,465
Creditors – amounts falling due within one year	50,584	50,584
Net current liabilities	(2,933)	3,881
Total assets less current liabilities	120,078	126,988
Creditors – amounts falling due after more than one year	18,899	18,959
Provisions for liabilities and charges
Deferred taxation	14,371	15,273
Other provisions	8,599	15,693
Net assets excluding pension and other post-retirement benefit balances	78,209	77,063
Defined benefit pension plan surplus	1,146	–
Defined benefit pension plan deficits	(5,005)	–
Other post-retirement benefit plan deficits	(2,630)	–
Net assets	71,720	77,063
Minority shareholders' interest	1,125	1,125
BP shareholders' interest	70,595	75,938
		$ million
Statement of total recognized gains and losses for the year ended 31 December 2003	Restated	Reported
Profit for the year	10,482	10,267
Currency translation differences (net of tax)	3,636	3,841
Actuarial gain (net of tax)	60	–
Total recognized gains and losses	14,178	14,108
		$ million
Group cash flow statement for the year ended 31 December 2003	Restated	Reported
Net cash inflow from operating activities	21,698	21,698
Dividends from joint ventures	131	131
Dividends from associated undertakings	417	417
Net cash outflow from servicing of finance and returns on investments	(711)	(711)
Tax paid	(4,804)	(4,804)
Net cash outflow for capital expenditure and financial investment	(6,124)	(6,187)
Net cash (outflow) inflow from acquisitions and disposals	(3,548)	(3,548)
Equity dividends paid	(5,654)	(5,654)
Net cash inflow (outflow) before financing	1,405	1,342
Financing	1,129	1,066
Management of liquid resources	(41)	(41)
Increase (decrease) in cash	317	317
	1,405	1,342

44 New accounting standards continued		$ million
Reconciliation of historical cost profit before interest and tax to net cash inflow from operating activities	Restated	Reported
Historical cost profit before interest and tax	17,954	17,260
Depreciation and amounts provided	10,940	10,940
Exploration expenditure written off	297	297
Net operating charge for pensions and other post-retirement benefits, less contributions	(2,913)	–
Share of profits of joint ventures and associated undertakings	(1,438)	(1,438)
Interest and other income	(341)	(341)
(Profit) loss on sale of fixed assets and businesses	(831)	(831)
Charge for provisions	782	1,734
Utilization of provisions	(716)	(1,204)
(Increase) decrease in stocks	(841)	(841)
(Increase) decrease in debtors	(3,042)	(5,628)
Increase (decrease) in creditors	1,847	1,750
Net cash inflow from operating activities	21,698	21,698

45 Transfer of natural gas liquids activities

With effect from 1 January 2004, natural gas liquids activities were transferred from Exploration and Production to Gas, Power and Renewables. The adjustments between these two segments for 2003 are set out below.

	$ million
Group replacement cost operating profit	106
Share of profits of joint ventures	–
Share of profits of associated undertakings	–
Total replacement cost operating profit	106
Exceptional items	–
Replacement cost profit before interest and tax	106
Stock holding gains (losses)	–
Historical cost profit before interest and tax	106
Capital expenditure and acquisitions	82
Operating capital employed	389
Tangible fixed assets	289
Number of employees
Year end	200
Average	200

46 Subsidiary and associated undertakings and joint ventures

The more important subsidiary and associated undertakings and joint ventures of the group at 31 December 2004 and the group percentage of ordinary share capital or joint venture interest (to nearest whole number) are set out below. The principal country of operation is generally indicated by the company's country of incorporation or by its name. Those held directly by the parent company are marked with an asterisk (*), the percentage owned being that of the group unless otherwise indicated. A complete list of investments in subsidiary and associated undertakings and joint ventures will be attached to the parent company's annual return made to the Registrar of Companies. Advantage has been taken of the exemption conferred by regulation 7 of The Partnerships and Unlimited Companies (Accounts) Regulations 1993 from the requirements to deliver to the Registrar of Companies and publish the annual accounts of the CaTO Finance V Limited Partnership.

Subsidiary		Country of		Subsidiary		Country of
undertakings	%	incorporation	Principal activities	undertakings	%	incorporation	Principal activities
InternationalBP ChemicalsInvestments	100	England	Petrochemicals	NetherlandsBP CapitalBP Nederland	100100	NetherlandsNetherlands	FinanceRefining and marketing
BP Exploration Op. Co.BP Global InvestmentsBP InternationalBP Oil International	100100100100	EnglandEnglandEnglandEngland	Exploration and productionInvestment holdingIntegrated oil operationsIntegrated oil operations	New ZealandBP Oil New Zealand	100	New Zealand	Marketing
BP ShippingBurmah Castrol	100100	EnglandScotland	ShippingLubricants	NorwayBP Norge	100	Norway	Exploration and production
AlgeriaBP Amoco Exploration(In Amenas)	100	Scotland	Exploration and production	SpainBP España	100	Spain	Refining and marketing
BP Exploration (ElDjazair)	100	Bahamas	Exploration and production	South Africa*BP Southern Africa	75	South Africa	Refining and marketing
AngolaBP Exploration (Angola)	100	England	Exploration and production	TrinidadBP Trinidad (LNG)BP Trinidad and Tobago	10070	NetherlandsUS	Exploration and productionExploration and production
AustraliaBP Australia	100	Australia	Integrated oil operations	UK
BP Australia CapitalMarketsBP Developments	100	Australia	Finance	BP Capital MarketsBP ChemicalsBP Oil UK	100100100	EnglandEnglandEngland	FinancePetrochemicalsRefining and marketing
AustraliaBP Finance Australia	100100	AustraliaAustralia	Exploration and productionFinance	BritoilJupiter Insurance	100100	ScotlandGuernsey	Exploration and productionInsurance
AzerbaijanAmoco Caspian SeaPetroleum	100	British VirginIslands	Exploration and production	USAtlantic Richfield Co.*BP America
BP Exploration(Caspian Sea)	100	England	Exploration and production	BP AmericaProduction CompanyBP Amoco Chemical
CanadaBP Canada EnergyBP Canada Finance	100100	CanadaCanada	Exploration and productionFinance	CompanyBP CompanyNorth AmericaBP Corporation	100	US	Exploration and production,gas, power and renewables,refining and marketing,pipelines and petrochemicals
EgyptBP Egypt Co.BP Egypt Gas Co.	100100	USUS	Exploration and productionExploration and production	North AmericaBP ProductsNorth AmericaBP West Coast
FranceBP France	100	France	Refining and marketingand petrochemicals	ProductsStandard Oil Co.BP Capital Markets
GermanyDeutsche BP	100	Germany	Refining and marketing	America			Finance
Veba Oil	100	Germany	and petrochemicalsRefining and marketingand petrochemicals
Associated undertakings		%	Country ofincorporation	Principal activities
Abu Dhabi
Abu Dhabi Marine AreasAbu Dhabi Petroleum Co.		3724	EnglandEngland	Crude oil productionCrude oil production
AzerbaijanThe Baku-Tbilisi-Ceyhan Pipeline Co.Korea		30	Cayman Islands	Pipelines
Samsung Petrochemical Co.Taiwan		47	England	Petrochemicals
China American Petrochemical Co.		61	Taiwan	Petrochemicals
Joint ventures		%	Country of incorporationor registration	Principal activities
CaTO Finance V Limited PartnershipLukarcoPan American EnergyShanghai Secco Petrochemical Co.TNK-BP		5046605050	EnglandNetherlandsUSChinaBritish Virgin Islands	FinanceExploration and production, pipelinesExploration and productionPetrochemicalsIntegrated oil operations
Unimar LLCWatson Cogeneration		5051	USUS	Exploration and productionPower generation

$ million

		47 Oil and natural gas exploration and production activitiesa

									2004
	UK	Rest ofEurope	USA	Rest ofAmericas	AsiaPacific	Africa	Russia	Other	Total
Capitalized costs at 31 December
Gross capitalized costs
Proved properties	27,540	4,691	43,518	10,450	2,892	10,401	–	3,834	103,326
Unproved properties	271	154	1,265	411	1,121	476	107	96	3,901
	27,811	4,845	44,783	10,861	4,013	10,877	107	3,930	107,227
Accumulated depreciation	17,637	2,787	19,783	5,532	1,347	5,559	–	1,011	53,656
Net capitalized costs	10,174	2,058	25,000	5,329	2,666	5,318	107	2,919	53,571

The group's share of joint ventures' and associated undertakings' net capitalized costs at 31 December 2004 was $12,077 million.

Costs incurred for theyear ended 31 DecemberAcquisition of properties
Proved	–	–	–	–	–	–	–	–	–
Unproved	2	–	58	5	–	13	–	–	78
	2	–	58	5	–	13	–	–	78
Exploration and appraisal costsb	51	17	422	199	85	142	113	9	1,038
Development costs	679	262	3,248	527	88	1,460	–	1,007	7,271
Total costs	732	279	3,728	731	173	1,615	113	1,016	8,387

The group's share of joint ventures' and associated undertakings' costs incurred in 2004 was $1,435 million.

Results of operations for theyear ended 31 December
Turnoverc
Third parties	3,458	626	1,735	1,785	989	524	5	467	9,589
Sales between businesses	2,423	609	11,603	2,547	519	1,407	–	2,847	21,955
	5,881	1,235	13,338	4,332	1,508	1,931	5	3,314	31,544
Exploration expenditure	26	25	361	141	14	45	17	8	637
Production costs	873	117	1,428	535	142	323	–	131	3,549
Production taxes	273	30	477	239	45	–	–	1,023	2,087
Other costs (income)d	(211)	38	1,884	458	96	122	(3)	1,380	3,764
Depreciation	1,524	172	2,673	797	174	347	–	121	5,808
	2,485	382	6,823	2,170	471	837	14	2,663	15,845
Profit before taxatione	3,396	853	6,515	2,162	1,037	1,094	(9)	651	15,699
Allocable taxes	1,288	534	2,290	870	104	441	2	151	5,680
Results of operations	2,108	319	4,225	1,292	933	653	(11)	500	10,019

The group's share of joint ventures' and associated undertakings' results of operations in 2004 was a profit of $1,908 million after deducting a tax charge of $1,078 million.

aThis note relates to the requirements contained within the UK Statement of Recommended Practice 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities'. Mid-stream activities of natural gas gathering and distribution and the operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central Area Transmission System. The group's share of joint ventures' and associated undertakings' activities is excluded from the tables and included in the footnotes, with the exception of the Abu Dhabi operations, which are included in the income and expenditure items above. Profits (losses) on sale of fixed assets and businesses or termination of operations relating to the oil and natural gas exploration and production activities, which have been accounted as exceptional items, are also excluded.

bIncludes 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. cTurnover represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is payable in cash. dIncludes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes and other government take. eThe exploration and production total replacement cost operating profit comprises:

	$ million
	2004
Exploration and production activities
Group (as above)	15,699
Joint ventures and associated undertakings	2,986
Mid-stream activities	(317)
Total replacement cost operating profit	18,368

47 Oil and natural gas exploration and production activitiesa					continued				$ million
		Rest of		Rest of	Asia				2003
	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Capitalized costs at 31 December
Gross capitalized costs
Proved properties	25,212	4,506	43,480	10,404	3,905	9,751	1	3,260	100,519
Unproved properties	266	211	1,127	661	1,642	506	37	54	4,504
	25,478	4,717	44,607	11,065	5,547	10,257	38	3,314	105,023
Accumulated depreciation	15,346	2,912	19,807	5,067	1,890	5,516	32	1,218	51,788
Net capitalized costs	10,132	1,805	24,800	5,998	3,657	4,741	6	2,096	53,235

The group's share of joint ventures' and associated undertakings' net capitalized costs at 31 December 2003 was $10,232 million.

Costs incurred for theyear ended 31 DecemberAcquisition of properties
Proved	–	–	–	–	–	–	–	–	–
Unproved	–	–	–	–	–	–	–	–	–
	–	–	–	–	–	–	–	–	–
Exploration and appraisal costsb	20	69	290	119	57	205	26	40	826
Development costs	740	236	3,474	512	42	1,614	–	917	7,535
Total costs	760	305	3,764	631	99	1,819	26	957	8,361

The group's share of joint ventures' and associated undertakings' costs incurred in 2003 was $6,282 million.

Results of operations for the
year ended 31 December
Turnoverc
Third parties	2,257	441	1,491	1,222	421	444	–	777	7,053
Sales between businesses	2,901	568	10,930	2,684	925	974	–	1,707	20,689
	5,158	1,009	12,421	3,906	1,346	1,418	–	2,484	27,742
Exploration expenditure	17	37	204	164	15	32	21	52	542
Production costs	800	113	1,262	463	166	241	–	135	3,180
Production taxes	233	14	439	189	40	–	–	742	1,657
Other costs (income)d	(151)	57	2,019	447	160	38	30	946	3,546
Depreciation	1,830	169	3,384	560	445	222	–	136	6,746
	2,729	390	7,308	1,823	826	533	51	2,011	15,671
Profit before taxatione	2,429	619	5,113	2,083	520	885	(51)	473	12,071
Allocable taxes	1,060	360	2,130	881	97	342	(12)	158	5,016
Results of operations	1,369	259	2,983	1,202	423	543	(39)	315	7,055

The group's share of joint ventures' and associated undertakings' results of operations in 2003 was a profit of $851 million after deducting a tax charge of $171 million.

bIncludes exploration and appraisal drilling expenditures, which are capitalized within intangible fixed assets, and geological and geophysical exploration costs which are

	$ million
	2003
Exploration and production activities
Group (as above)	12,071
Joint ventures and associated undertakings	1,022
Mid-stream activities	660
Total replacement cost operating profit	13,753

Supplementary information on oil and natural gas quantities

BP reserves governance

BP manages its hydrocarbon resources in three major categories: prospect inventory, non-proved reserves and proved reserves. When a discovery is made, volumes transfer from the prospect inventory to the non-proved reserve category. The reserves move through various non-proved reserves sub-categories as their technical and commercial maturity increases through appraisal activity. Reserves in a field will only be categorized as proved when all the criteria for attribution of proved status have been met, including an internally imposed requirement for project sanction, or for sanction expected within six months, or as part of a rolling drilling programme included within our business planning process. 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. 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 to the start of production. Adjustments may be made to booked reserves owing to production, reservoir performance, commercial factors, acquisition and divestment activity and additional reservoir development activity.

BP has an internal process to control the quality of reserve bookings that forms part of a holistic and integrated system of internal control. BP's process to manage reserve bookings has been centrally controlled for over 15 years and it currently has several key elements.

The first element is the accountabilities of certain officers of the company, which ensure that there is clear responsibility for review and, where appropriate, endorsement of changes to reserves bookings; that the review is independent of the operating business unit for the integrity and accuracy of the reserve estimates; and that there are effective controls in the reserve approval process and verification that the group's reserve estimates and the related financial impacts are reported in a timely manner.

The second element is the 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 review that both technical and commercial criteria are met prior to the commitment of capital to projects.

The third element is 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.

The fourth element is a quarterly due diligence review, which is separate and independent from the operating business units, of reserves associated with properties where technical, operational or commercial issues have arisen.

The fifth element is the established criteria whereby reserves above certain thresholds require central authorization. Furthermore, the volumes booked under these authorization levels are reviewed on a periodic basis. The frequency of review is determined according to field size and ensures that more than 70% of the BP reserves base undergoes central review every two years and more than 80% is reviewed every four years.

Reserves reporting

Our proved reserves are associated with both concessions (tax and royalty arrangements) and 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. Twenty-one per cent of our proved reserves are associated with PSAs. The main countries in which we operate under PSA arrangements are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam.

As a UK-registered company reporting under UK GAAP, BP estimates its proved reserves under UK accounting rules for oil and gas companies contained in the Statement of Recommended Practice, 'Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities' (UK SORP). In estimating its reserves under UK SORP, BP uses long-term planning prices; these are the longterm price assumptions on which the group makes decisions to invest in the development of a field. Using planning prices for estimating proved reserves removes the impact of the volatility inherent in using year-end spot prices on our reserve base and on cash flow expectations over the long term. The group's planning prices for estimating reserves through the end of 2004 were $20 per barrel for oil and $3.50 per mmBtu for natural gas.

In determining 'reasonable certainty' for UK SORP purposes, BP applies a number of additional internally imposed assessment principles, such as the requirement for internal approval and final investment decision (which we refer to as project sanction), or for such project sanction 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 within three years.

On the basis of UK SORP, our total proved reserves for subsidiaries and equity-accounted entities at the end of 2004 increased to 18,583 mmboe, representing a proved reserve replacement ratio (RRR) before acquisitions and divestments of 110%, versus 109% in 2003. Our principal equity-accounted entity is TNK-BP. For subsidiaries only, the RRR is 106% and, for equity-accounted entities only, the RRR is 118%. The proved reserve replacement ratio (also known as the production replacement ratio) is the extent to which production is replaced by proved reserve additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery, extensions, discoveries and other additions, excluding the impact of acquisitions and divestments. Natural gas is converted to oil equivalent at 5.8 billion cubic feet equals 1 million barrels. By their nature, there is always some risk involved in the ultimate development and production of reserves, including but not limited to final regulatory approval, the installation of new or additional infrastructure as well as changes in oil and gas prices and the continued availability of additional development capital. The estimated proved oil and natural gas reserves on this basis are shown on pages 89-90.

The US Securities and Exchange Commission (SEC) rules for estimating reserves are different in certain respects from SORP; in particular, the SEC requires the use of year-end prices.

At 31 December 2004, the marker price for Brent crude was $40.24 per barrel and for Henry Hub gas it was $6.01 per thousand cubic feet.

Applying higher year-end prices to reserve estimates and assuming they apply to the end-of-field life has the effect of increasing proved reserves associated with concessions (tax and royalty arrangements) for which additional development opportunities become economic at higher prices or where higher prices make it more economic to extend the life of a field. On the other hand, applying higher year-end prices to reserves in fields subject to PSAs has the effect of decreasing proved reserves from those fields because higher prices result in lower volume entitlements.

The company's proved reserves estimates on an SEC basis for the year ended 31 December 2004 reflect year-end prices and some adjustments that have been made vis-à-vis individual asset reserve estimates based on different applications of certain SEC interpretations of SEC regulations relating to the use of technology (mainly seismic) to estimate reserves in the reservoir away from wellbores and the reporting of fuel gas (i.e. gas used for fuel in operations on the lease) within proved reserves. On an aggregate basis, the net impact of these changes, comprising some reductions and some additions, is a decrease of 286 mmboe, resulting in total proved reserves of 18,297 mmboe (including equity-accounted entities) compared with

our reserves under UK SORP. Excluding equity-accounted entities, our proved reserves on an SEC basis were 14,625 mmboe.

The total net movement in subsidiaries and equity-accounted entities comprises a decrease of 452 mmboe as a result of using the year-end price, offset by a net increase of 166 mmboe in respect of fuel gas and technology interpretations.

On an SEC basis, our total proved reserves for subsidiaries and equity-accounted entities at the end of 2004 decreased by 64 mmboe from 18,361 to 18,297 mmboe, representing a proved reserve replacement ratio (RRR) before acquisitions and divestments of 89% versus 111% in 2003. For subsidiaries only, the RRR is 78% and, for equity-accounted entities only, the RRR is 114%.

We have included certain reserve replacement ratios that are calculated using proved reserves attributed to equity-accounted entities as well as consolidated entities and which exclude acquisitions and divestments. SEC staff guidance states that such measures should not include both proved reserve additions attributable to consolidated entities and equity-accounted entities and should be based on beginning and ending proved reserve quantities as disclosed in the Annual Report on Form 20-F. On this basis our RRR would be 64% (39% for 2003).

The estimated proved oil and natural gas reserves prepared on an SEC basis are shown on pages 91-92.

Movements in estimated net proved reserves on a UK GAAP/SORP basis 2004

Crude oila									million barrels
		Rest of		Rest of	Asia
	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Subsidiary
At 1 January 2004
Developed	678	231	1,885	378	83	206	–	115	3,576
Undeveloped	216	87	1,353	366	83	967	–	801	3,873
	894	318	3,238	744	166	1,173	–	916	7,449
Changes attributable to
Revisions of previous estimates	(97)	32	63	(111)	5	38	–	194	124
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries
and other additions	22	–	74	5	8	48	–	212	369
Improved recovery	57	4	55	31	–	6	–	3	156
Productionb	(121)	(28)	(217)	(63)	(17)	(48)	–	(21)	(515)
Sales of reserves-in-place	–	–	(17)	(10)	(6)	–	–	–	(33)
	(139)	8	(42)	(148)	(10)	44	–	388	101
At 31 December 2004c
Developed	548	217	1,938	296	70	275	–	79	3,423
Undeveloped	207	109	1,258	300	86	942	–	1,225	4,127
	755	326	3,196	596	156	1,217	–	1,304	7,550
Equity-accounted entities (BP share)
At 1 January 2004
Developed	–	–	–	206	1	–	1,384	705	2,296
Undeveloped	–	–	–	134	–	–	410	27	571
	–	–	–	340	1	–	1,794	732	2,867

Changes attributable to
Revisions of previous estimates	–	–	–	(4)	–	–	382	15	393
Purchases of reserves-in-place	–	–	–	–	–	–	252	–	252
Extensions, discoveries
and other additions	–	–	–	2	–	–	–	–	2
Improved recovery	–	–	–	17	–	–	37	–	54
Production	–	–	–	(25)	–	–	(304)	(55)	(384)
Sales of reserves-in-place	–	–	–	–	–	–	(4)	–	(4)
	–	–	–	(10)	–	–	363	(40)	313
At 31 December 2004d
Developed	–	–	–	204	1	–	1,863	593	2,661
Undeveloped	–	–	–	126	–	–	294	99	519
	–	–	–	330	1	–	2,157	692	3,180
Total group and BP share of
equity-accounted entities	755	326	3,196	926	157	1,217	2,157	1,996	10,730

aCrude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind.

bExcludes NGLs from processing plants in which an interest is held of 67 thousand barrels a day.

cIncludes 39 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 127 million barrels of crude oil in respect of the 5.9% minority interest in TNK-BP.

Movements in estimated net proved reserves on a UK GAAP/SORP basis continued									2004
Natural gasa									billion cubic feet
		Rest of		Rest of	Asia
	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Subsidiary
At 1 January 2004
Developed	2,673	214	11,290	4,087	1,923	651	–	235	21,073
Undeveloped	817	1,211	2,547	12,484	2,988	2,028	–	828	22,903
	3,490	1,425	13,837	16,571	4,911	2,679	–	1,063	43,976
Changes attributable to
Revisions of previous estimates	(226)	16	(791)	(1,889)	(2)	(9)	–	338	(2,563)
Purchases of reserves-in-place	–	–	3	2	–	–	–	–	5
Extensions, discoveries
and other additions	31	–	140	991	2,478	233	–	3	3,876
Improved recovery	134	4	870	75	–	29	–	38	1,150
Production	(427)	(46)	(1,097)b	(854)	(284)	(98)	–	(73)	(2,879)
Sales of reserves-in-place	–	–	(202)	(91)	(247)	(103)	–	–	(643)
	(488)	(26)	(1,077)	(1,766)	1,945	52	–	306	(1,054)
At 31 December 2004c
Developed	2,079	216	10,207	3,981	1,578	1,054	–	257	19,372
Undeveloped	923	1,183	2,553	10,824	5,278	1,677	–	1,112	23,550

	3,002	1,399	12,760	14,805	6,856	2,731	–	1,369	42,922
Equity-accounted entities (BP share)
At 1 January 2004
Developed	–	–	–	1,437	130	–	–	58	1,625
Undeveloped	–	–	–	823	77	–	–	28	928
	–	–	–	2,260	207	–	–	86	2,553
Changes attributable to
Revisions of previous estimates	–	–	–	68	(13)	–	319	–	374
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries
and other additions	–	–	–	–	–	–	–	–	–
Improved recovery	–	–	–	23	–	–	–	–	23
Production	–	–	–	(129)	(22)	–	(168)	(3)	(322)
Sales of reserves-in-place	–	–	–	–	–	–	–	–	–
	–	–	–	(38)	(35)	–	151	(3)	75
At 31 December 2004d
Developed	–	–	–	1,318	103	–	151	60	1,632
Undeveloped	–	–	–	904	69	–	–	23	996
	–	–	–	2,222	172	–	151	83	2,628
Total group and BP share of
equity-accounted entities	3,002	1,399	12,760	17,027	7,028	2,731	151	1,452	45,550

aNet proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.

bIncludes 76 billion cubic feet of natural gas consumed in operations.

cIncludes 4,117 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 9 billion cubic feet of natural gas in respect of the 5.9% minority interest in TNK-BP.

Movements in estimated net proved reserves on an SEC basis									2004
Crude oila									million barrels
		Rest of		Rest of	Asia
	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Subsidiary
At 1 January 2004
Developed	697	236	1,902	385	82	190	–	73	3,565
Undeveloped	245	127	1,499	354	81	632	–	711	3,649
	942	363	3,401	739	163	822	–	784	7,214
Changes attributable to
Revisions of previous estimates	(133)	1	(44)	(92)	2	19	–	(192)	(439)
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries
and other additions	24	–	74	5	8	48	–	213	372
Improved recovery	57	4	55	31	–	6	–	3	156
Productionb	(121)	(28)	(217)	(63)	(17)	(48)	–	(21)	(515)
Sales of reserves-in-place	–	–	(17)	(10)	(6)	–	–	–	(33)
	(173)	(23)	(149)	(129)	(13)	25	–	3	(459)
At 31 December 2004c
Developed	559	231	2,041	311	65	204	–	62	3,473
Undeveloped	210	109	1,211	299	85	643	–	725	3,282

	769	340	3,252	610	150	847	–	787	6,755
Equity-accounted entities (BP share)
At 1 January 2004
Developed	–	–	–	206	1	–	1,384	705	2,296
Undeveloped	–	–	–	134	–	–	410	27	571
	–	–	–	340	1	–	1,794	732	2,867
Changes attributable to
Revisions of previous estimates	–	–	–	(5)	–	–	382	15	392
Purchases of reserves-in-place	–	–	–	–	–	–	252	–	252
Extensions, discoveries
and other additions	–	–	–	2	–	–	–	–	2
Improved recovery	–	–	–	17	–	–	37	–	54
Production	–	–	–	(25)	–	–	(304)	(55)	(384)
Sales of reserves-in-place	–	–	–	–	–	–	(4)	–	(4)
	–	–	–	(11)	–	–	363	(40)	312
At 31 December 2004d
Developed	–	–	–	204	1	–	1,863	592	2,660
Undeveloped	–	–	–	125	–	–	294	100	519

	–	–	–	329	1	–	2,157	692	3,179

aCrude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash or in kind.

bExcludes NGLs from processing plants in which an interest is held of 67 thousand barrels a day.

cIncludes 40 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 127 million barrels of crude oil in respect of the 5.9% minority interest in TNK-BP.

Movements in estimated net proved reserves on an SEC basis continued									2004
Natural gasa									billion cubic feet
		Rest of		Rest of	Asia
	UK	Europe	USA	Americas	Pacific	Africa	Russia	Other	Total
Subsidiary
At 1 January 2004
Developed	2,996	262	11,482	4,212	1,976	640	–	255	21,823
Undeveloped	1,095	1,255	3,337	11,531	3,026	2,188	–	900	23,332
	4,091	1,517	14,819	15,743	5,002	2,828	–	1,155	45,155
Changes attributable to
Revisions of previous estimates	(210)	28	(438)	(1,081)	106	16	–	558	(1,021)
Purchases of reserves-in-place	–	–	3	2	–	–	–	–	5
Extensions, discoveries
and other additions	127	–	140	991	2,478	233	–	3	3,972
Improved recovery	134	4	870	76	–	29	–	38	1,151
Productionb	(461)	(47)	(1,111)	(875)	(296)	(102)	–	(76)	(2,968)
Sales of reserves-in-place	–	–	(202)	(92)	(247)	(103)	–	–	(644)
	(410)	(15)	(738)	(979)	2,041	73	–	523	495
At 31 December 2004c
Developed	2,498	248	10,811	4,101	1,624	1,015	–	282	20,579
Undeveloped	1,183	1,254	3,270	10,663	5,419	1,886	–	1,396	25,071
	3,681	1,502	14,081	14,764	7,043	2,901	–	1,678	45,650

Equity-accounted entities (BP share)
At 1 January 2004
Developed	–	–	–	1,591	136	–	46	58	1,831
Undeveloped	–	–	–	916	80	–	14	28	1,038
	–	–	–	2,507	216	–	60	86	2,869
Changes attributable to
Revisions of previous estimates	–	–	–	(12)	(17)	–	341	–	312
Purchases of reserves-in-place	–	–	–	–	–	–	–	–	–
Extensions, discoveries
and other additions	–	–	–	–	–	–	–	–	–
Improved recovery	–	–	–	23	–	–	–	–	23
Productionb	–	–	–	(144)	(23)	–	(177)	(3)	(347)
Sales of reserves-in-place	–	–	–	–	–	–	–	–	–
	–	–	–	(133)	(40)	–	164	(3)	(12)
At 31 December 2004d
Developed	–	–	–	1,397	107	–	214	60	1,778
Undeveloped	–	–	–	977	69	–	10	23	1,079
	–	–	–	2,374	176	–	224	83	2,857

aNet proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.

bIncludes 190 billion cubic feet of natural gas consumed in operations (165 bcf in subsidiaries, 25 bcf in equity-accounted entities). cIncludes 4,064 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.

dIncludes 13 billion cubic feet of natural gas in respect of the 5.9% minority interest in TNK-BP.

	Group production interests – oil (includes NGLs and condensate)			BP net share of production	thousand barrels a daya
		Field	Interest %	2004	2003
UK	Offshore	ETAPb	Various	55	56
		Foinavenc	Various	48	55
		Schiehallion/Loyalc	Various	39	42
		Magnusc	85.0	34	39
		Hardingc	70.0	27	34
		Andrewc	62.8	12	17
		Other	Various	89	105
	Onshore	Wytch Farmc	67.8	26	29
				330	377
Rest of Europe	Netherlands	Various	Various	1	22
	Norway	Draugen	18.4	27	25
		Valhallc	28.1	25	21
		Ulac	80.0	16	16
		Other	Various	8	–

				77	84
USA	Alaska	Prudhoe Bayc	26.4	97	105
		Kuparuk	39.2	68	73
		Northstarc	98.6	49	46
		Milne Pointc	100.0	44	44
		Other	Various	37	43
	Lower 48 onshore	Various	Various	142	160
	Gulf of Mexico	Horn Mountainc	66.6	41	42
		Mars	28.5	35	43
		Ursa	22.7	29	17
		Na Kikac	50.0	27	–
		Kingc	100.0	26	31
		Other	Various	71	122
				666	726
Rest of World	Angola	Girassol	16.7	31	33
		Xikomba	26.7	18	2
		Kizomba A	26.7	16	–
		Other	Various	6	–
	Australia	Various	15.8	36	40
	Azerbaijan	ACG (Chirag)c	34.1	39	38
	Canada	Various	Various	11	13
	Colombia	Various	Various	48	53
	Egypt	Various	Various	57	73
	Trinidad	Various	100.0	59	74
	Venezuela	Various	Various	55	53
	Other	Various	Various	31	49
				407	428
Total group				1,480	1,615
Equity-accounted entities (BP share)	Abu Dhabi	Various	Various	142	138
	Argentina – Pan American Energy	Various	Various	64	60
	Russia – TNK-BP	Various	Various	831	296
	Other	Various	Various	14	12

Total equity-accounted entities				1,051	506
Total group and BP share of equity-accounted entitiesd				2,531	2,121

aNet of royalty, whether payable in cash or in kind.

bOut of nine fields, BP operates six and Shell three.

cBP operator.

dIncludes natural gas liquids (NGLs) from processing plants in which an interest is held of 67 thousand barrels a day (70 thousand barrels a day in 2003).

Group production interests – natural gas				BP net share of production	million cubic feet a daya
		Field	Interest %	2004	2003
UK	Offshore	Bruceb	37.0	163	222
		Braes	Various	147c	174
		Shearwater	27.5	76	70
		Marnockb	62.0	70	98
		West Soleb	100.0	67	73
		Britannia	9.0	54	55
		Armada	18.2	50	58
		Other	Various	547	696
				1,174	1,446
Rest of Europe	Netherlands	P/18-2b	48.7	34	30
		Other	Various	46	37
	Norway	Various	Various	45	52
				125	119
USA	Lower 48 onshore	San Juanb	Various	772	802
		Arkoma	Various	183	201
		Hugotonb	Various	158	182
		Jonahb	65.0	114	119
		Wamsutterb	70.5	105	111
		Tuscaloosa	Various	96	136
		Other	Various	514	558
	Gulf of Mexico	Na Kikab	50.0	133	–
		Marlinb	78.2	43	93
		King's Peakb	55.0	39	91
		Other	Various	514	752
	Alaska	Various	Various	78	83
				2,749	3,128
Rest of World	Australia	Various
			15.8	308	285
	Canada	VariousYachengb	Various	349	422
	China	Ha'pyb	34.3	99	74
	Egypt		50.0	80	83
	Indonesia	OtherSanga-Sanga (direct)b	Various	115	170
		Pagerungand	26.3	137	165
		Otherb	100.0	68	121
		Sajaab	46.0	76	97
	Sharjah		40.0	103	101
		OtherKapokb	40.0	14	19
	Trinidad	Mahoganyb	100.0	553	79
		Amherstiab	100.0	453	503
		Immortelleb	100.0	408	624
		Parangb	100.0	172	235
		Cassiab	100.0	137	152
		Flamboyantb	100.0	85	30
		Otherb	100.0	67	68
	Other	Various	100.0Various	44	3
				308	168
				3,576	3,399
Total group				7,624	8,092
Equity-accounted entities (BP share)	Argentina – Pan American Energy	Various	Various	317	281
	Russia – TNK-BP	Various	Various	458	129
	Other	Various	Various	104	111
Total equity-accounted entities				879	521
Total group and BP share of equity-accounted entities				8,503	8,613

aNet of royalty, whether payable in cash or in kind.

bBP operator.

cIncludes 7 million cubic feet a day of natural gas received as in-kind tariff payments.

dInterest divested during 2004.

Five-year summaries*

Summarized group income statement $ million

	2000	2001	2002	2003	2004
Turnover	161,826	175,389	180,186	236,045	294,849
Less: joint ventures	13,764	1,171	1,465	3,474	9,790
Group turnover	148,062	174,218	178,721	232,571	285,059
Replacement cost of sales	120,797	147,001	155,742	201,347	248,714
Production taxes	2,061	1,689	1,274	1,723	2,149
Gross profit	25,204	25,528	21,705	29,501	34,196
Distribution and administration expensesa	9,331	10,918	12,632	14,072	14,988
Exploration expense	599	480	644	542	637
	15,274	14,130	8,429	14,887	18,571
Other income	805	694	641	786	675
Group replacement cost operating profit	16,079	14,824	9,070	15,673	19,246
Share of profits of joint ventures	808	443	346	923	2,933
Share of profits of associated undertakings	792	760	616	511	605
Total replacement cost operating profit	17,679	16,027	10,032	17,107	22,784
Exceptional items	220	535	1,168	831	815
Replacement cost profit before interest and tax	17,899	16,562	11,200	17,938	23,599
Stock holding gains (losses)	728	(1,900)	1,129	16	1,643
Historical cost profit before interest and tax	18,627	14,662	12,329	17,954	25,242
Interest expense	1,581	1,432	1,067	644	642
Other finance expense	189	238	73	547	357
Profit before taxation	16,857	12,992	11,189	16,763	24,243
Taxation	6,648	6,375	4,317	6,111	8,282
Profit after taxation	10,209	6,617	6,872	10,652	15,961
Minority shareholders' interest	89	61	77	170	230
Profit for the year	10,120	6,556	6,795	10,482	15,731
Distribution to shareholders	4,625	4,935	5,375	5,753	6,371
Retained profit for the year	5,495	1,621	1,420	4,729	9,360
Earnings per ordinary share – cents
Basic	46.77	29.21	30.33	47.27	72.08
Diluted	46.46	29.04	30.19	46.83	70.79
Dividends per ordinary share – cents	20.50	22.00	24.00	26.00	29.45

Replacement cost resultsb
Historical cost profit for the year	10,120	6,556	6,795	10,482	15,731
Stock holding (gains) losses	(728)	1,900	(1,104)	(16)	(1,643)
Replacement cost profit for the year	9,392	8,456	5,691	10,466	14,088
Earnings per ordinary share – cents
On replacement cost profit for the year	43.40	37.68	25.40	47.20	64.55
a

bReplacement cost profit excludes stock holding gains and losses. The effect of this is to set against income for the period the average cost of supplies incurred in the same period rather than applying costs obtained by using the first-in first-out method. Profit on the replacement cost basis therefore reflects more immediately changes in purchase costs and provides an indication of the underlying trend in trading performance in a continuing business. This basis is used to assist in the interpretation of operating profit.

Research and development expenditure amounted to: 434 385 373 349 439

US dollar/sterling exchange rates

Average exchange rate for the year	1.51	1.44	1.50	1.63	1.83
Year-end exchange rate	1.49	1.45	1.60	1.78	1.92

US dollar/euro exchange rates

Average exchange rate for the year	0.92	0.89	0.94	1.13	1.24
Year-end exchange rate	0.93	0.88	1.05	1.25	1.36

*The financial information for 2002 and 2003 has been restated to reflect the adoption by the group of Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17) with effect from 1 January 2004. The financial information for 2000 and 2001 has not been restated for FRS 17.

Summarized group income statement (by quarter)

Replacement cost results

	Q1	Q2	Q3	Q4	2000	Q1	Q2	Q3	Q4	2001
Replacement cost profit before interest and tax
By businessa
Exploration and Production	3,211	3,147	3,517	4,098	13,973	4,584	3,729	2,613	1,546	12,472
Refining and Marketing	603	1,177	1,112	692	3,584	1,005	1,405	1,237	397	4,044
Petrochemicals	49	320	233	(54)	548	75	(71)	24	(197)	(169)
Gas, Power and Renewables	165	134	154	199	652	139	178	142	113	572
Other businesses and corporateb	(224)	(303)	(210)	(121)	(858)	(113)	(125)	(102)	(17)	(357)
Replacement cost profit before interest and tax	3,804	4,475	4,806	4,814	17,899	5,690	5,116	3,914	1,842	16,562
Interest expense	260	358	412	551	1,581	393	391	322	326	1,432
Other finance expense	36	45	48	60	189	53	50	47	88	238
Replacement cost profit before taxation	3,508	4,072	4,346	4,203	16,129	5,244	4,675	3,545	1,428	14,892
Taxation	1,253	1,712	1,873	1,810	6,648	2,168	1,956	1,540	711	6,375
Replacement cost profit after taxation	2,255	2,360	2,473	2,393	9,481	3,076	2,719	2,005	717	8,517
Minority shareholders' interest	68	(5)	12	14	89	8	18	12	23	61
Replacement cost profit for the period	2,187	2,365	2,461	2,379	9,392	3,068	2,701	1,993	694	8,456
Earnings on replacement cost profit
per ordinary share – cents	11.26	10.70	10.89	10.55	43.40	13.65	12.03	8.89	3.11	37.68
per ADS – dollars	0.68	0.64	0.65	0.63	2.60	0.82	0.72	0.53	0.19	2.26
Historical cost results
Replacement cost profit for the period	2,187	2,365	2,461	2,379	9,392	3,068	2,701	1,993	694	8,456
Stock holding gains (losses)	532	213	544	(561)	728	(238)	40	(405)	(1,297)	(1,900)
Historical cost profit (loss) for the period	2,719	2,578	3,005	1,818	10,120	2,830	2,741	1,588	(603)	6,556
Earnings on historical cost profit
per ordinary share – cents
Basic	14.00	11.56	13.34	7.87	46.77	12.59	12.21	7.08	(2.67)	29.21
Diluted	13.90	11.47	13.26	7.83	46.46	12.51	12.14	7.03	(2.64)	29.04
per ADS – dollars
Basic	0.84	0.69	0.80	0.47	2.80	0.76	0.73	0.43	(0.16)	1.76
Diluted	0.83	0.69	0.80	0.47	2.79	0.75	0.73	0.42	(0.16)	1.74

aReplacement cost profit is after exceptional items and excluding stock holding gains and losses. bOther businesses and corporate comprises Finance, the group's coal asset (divested in October 2003) and aluminium asset, its investments in PetroChina and Sinopec (both divested in early 2004), interest income and costs relating to corporate activities worldwide.

														$ million
Q1	Q2	Q3	Q4	2002	Q1	Q2	Q3	Q4	2003	Q1	Q2	Q3	Q4	2004


1,887	2,839	1,490	2,061	8,277	4,718	3,434	3,666	2,848	14,666	4,242	4,302	4,883	5,093	18,520
35	647	511	340	1,533	628	888	482	320	2,318	720	1,344	1,081	1,577	4,722
(8)	94	120	(41)	165	137	306	84	41	568	(25)	208	188	(1,271)	(900)
123	125	1,664	57	1,969	216	141	127	86	570	198	216	130	399	943
(141)	(131)	(287)	(185)	(744)	(166)	(153)	(330)	465	(184)	1,129	(164)	(424)	(227)	314
1,896	3,574	3,498	2,232	11,200	5,533	4,616	4,029	3,760	17,938	6,264	5,906	5,858	5,571	23,599
290	272	257	248	1,067	176	149	159	160	644	152	145	156	189	642
8	7	8	50	73	129	127	139	152	547	76	76	79	126	357
1,598	3,295	3,233	1,934	10,060	5,228	4,340	3,731	3,448	16,747	6,036	5,685	5,623	5,256	22,600
747	1,746	707	1,117	4,317	1,782	1,744	1,428	1,157	6,111	1,822	2,199	2,109	2,152	8,282
851	1,549	2,526	817	5,743	3,446	2,596	2,303	2,291	10,636	4,214	3,486	3,514	3,104	14,318
9	34	3	6	52	26	60	43	41	170	44	52	58	76	230
842	1,515	2,523	811	5,691	3,420	2,536	2,260	2,250	10,466	4,170	3,434	3,456	3,028	14,088

3.76	6.75	11.26	3.63	25.40	15.32	11.45	10.25	10.18	47.20	18.88	15.68	15.96	14.03	64.55
0.23	0.41	0.68	0.22	1.52	0.92	0.69	0.62	0.61	2.83	1.13	0.94	0.96	0.84	3.87
														$ million
842	1,515	2,523	811	5,691	3,420	2,536	2,260	2,250	10,466	4,170	3,434	3,456	3,028	14,088
442	531	305	(174)	1,104	799	(951)	84	84	16	648	462	1,027	(494)	1,643
1,284	2,046	2,828	637	6,795	4,219	1,585	2,344	2,334	10,482	4,818	3,896	4,483	2,534	15,731


5.73	9.12	12.62	2.86	30.33	18.90	7.19	10.62	10.56	47.27	21.81	17.80	20.67	11.80	72.08
5.70	9.07	12.56	2.86	30.19	18.84	7.16	10.51	10.32	46.83	21.34	17.43	20.41	11.61	70.79

0.34	0.55	0.76	0.17	1.82	1.13	0.43	0.64	0.63	2.84	1.31	1.07	1.24	0.70	4.32
0.34	0.54	0.75	0.17	1.81	1.13	0.43	0.63	0.62	2.81	1.28	1.05	1.22	0.70	4.25

Replacement cost profit before interest and tax analysed by business and geographical area

By business	Q1	Q2	Q3	Q4	2000	Q1	Q2	Q3	Q4	2001
Exploration and Production
UK	1,098	875	990	1,067	4,030	1,150	951	726	568	3,395
Rest of Europe	188	185	221	232	826	234	191	188	143	756
USA	1,206	1,355	1,220	1,570	5,351	2,047	1,186	824	404	4,461
Rest of World	719	732	1,086	1,229	3,766	1,153	1,401	875	431	3,860
	3,211	3,147	3,517	4,098	13,973	4,584	3,729	2,613	1,546	12,472
Refining and Marketing
UKa	34	148	71	(76)	177	(102)	(119)	(62)	(410)	(693)
Rest of Europe	55	135	233	313	736	129	175	220	269	793
USA	405	798	740	334	2,277	868	1,211	943	(168)	2,854
Rest of World	109	96	68	121	394	110	138	136	706	1,090
	603	1,177	1,112	692	3,584	1,005	1,405	1,237	397	4,044
Petrochemicals
UK	(29)	(33)	(43)	36	(69)	(49)	(33)	(124)	(99)	(305)
Rest of Europe	76	118	76	14	284	79	19	81	(1)	178
USA	158	177	145	49	529	(6)	(94)	42	(28)	(86)
Rest of World	(156)	58	55	(153)	(196)	51	37	25	(69)	44
	49	320	233	(54)	548	75	(71)	24	(197)	(169)
Gas, Power and Renewables
UK	–	7	18	4	29	14	41	39	(25)	69
Rest of Europe	54	11	28	57	150	63	35	27	64	189
USA	34	64	32	45	175	60	99	94	43	296
Rest of World	77	52	76	93	298	2	3	(18)	31	18
	165	134	154	199	652	139	178	142	113	572
Other businesses and corporate
UK	(111)	(29)	(53)	(189)	(382)	(76)	(51)	(91)	100	(118)
Rest of Europe	10	17	21	(50)	(2)	(18)	8	(12)	(47)	(69)
USA	(129)	(297)	(165)	(114)	(705)	(58)	(64)	(101)	(119)	(342)
Rest of World	6	6	(13)	232	231	39	(18)	102	49	172
	(224)	(303)	(210)	(121)	(858)	(113)	(125)	(102)	(17)	(357)
By geographical area
UKa	992	968	983	842	3,785	937	789	488	134	2,348
Rest of Europe	383	466	579	566	1,994	487	428	504	428	1,847
USA	1,674	2,097	1,972	1,884	7,627	2,911	2,338	1,802	132	7,183
Rest of World	755	944	1,272	1,522	4,493	1,355	1,561	1,120	1,148	5,184
Total replacement cost profit before interest and tax	3,804	4,475	4,806	4,814	17,899	5,690	5,116	3,914	1,842	16,562

aUK area includes the UK-based international activities of Refining and Marketing.

Exceptional items

	Q1	Q2	Q3	Q4	2000	Q1	Q2	Q3	Q4	2001
Exploration and Production	38	168	9	(96)	119	(42)	319	3	(85)	195
Refining and Marketing	19	5	161	(87)	98	265	(59)	247	18	471
Petrochemicals	(210)	–	(30)	28	(212)	(6)	(80)	(81)	(130)	(297)
Gas, Power and Renewables	–	–	(1)	3	2	(1)	–	–	1	–
Other businesses and corporate	(4)	(12)	(1)	230	213	2	(9)	15	158	166
Profit (loss) on sale of fixed assets and
businesses or termination of operations	(157)	161	138	78	220	218	171	184	(38)	535
Taxation	101	(104)	(89)	(50)	(142)	(151)	(118)	(127)	26	(370)
Exceptional items after taxation and
minority shareholders' interest	(56)	57	49	28	78	67	53	57	(12)	165

														$ million
Q1	Q2	Q3	Q4	2002	Q1	Q2	Q3	Q4	2003	Q1	Q2	Q3	Q4	2004

682	587	107	918	2,294	1,078	993	672	654	3,397	823	835	745	981	3,384
159	176	212	177	724	195	143	95	154	587	163	206	246	222	837
317	1,258	666	117	2,358	1,658	1,374	1,352	716	5,100	1,494	1,503	1,566	1,531	6,094
729	818	505	849	2,901	1,787	924	1,547	1,324	5,582	1,762	1,758	2,326	2,359	8,205
1,887	2,839	1,490	2,061	8,277	4,718	3,434	3,666	2,848	14,666	4,242	4,302	4,883	5,093	18,520

(183)	(98)	(185)	(224)	(690)	(43)	(117)	(160)	(152)	(472)	(189)	(195)	(152)	101	(435)
193	301	374	95	963	361	499	355	158	1,373	289	444	533	593	1,859
(105)	294	227	354	770	145	337	92	174	748	409	872	536	661	2,478
130	150	95	115	490	165	169	195	140	669	211	223	164	222	820
35	647	511	340	1,533	628	888	482	320	2,318	720	1,344	1,081	1,577	4,722

(63)	(67)	(47)	(88)	(265)	(90)	(38)	(132)	(65)	(325)	(156)	(62)	(107)	(716)	(1,041)
48	16	195	65	324	117	232	93	34	476	154	183	130	(282)	185
(41)	48	45	23	75	54	82	63	6	205	(109)	3	30	(215)	(291)
48	97	(73)	(41)	31	56	30	60	66	212	86	84	135	(58)	247
(8)	94	120	(41)	165	137	306	84	41	568	(25)	208	188	(1,271)	(900)

5	4	(30)	(26)	(47)	4	17	15	40	76	12	(2)	(46)	133	97
47	34	1,569	35	1,685	(9)	(5)	(12)	(11)	(37)	(11)	(3)	(9)	(4)	(27)
(15)	23	48	(43)	13	57	126	78	5	266	79	114	139	90	422
86	64	77	91	318	164	3	46	52	265	118	107	46	180	451
123	125	1,664	57	1,969	216	141	127	86	570	198	216	130	399	943

(62)	(90)	(138)	29	(261)	(93)	(149)	(108)	324	(26)	(163)	(50)	(147)	282	(78)
1	6	(7)	33	33	(8)	(2)	3	(42)	(49)	(6)	(1)	21	(177)	(163)
(71)	(22)	(122)	(237)	(452)	(81)	(43)	(237)	(23)	(384)	(30)	(109)	(268)	(251)	(658)
(9)	(25)	(20)	(10)	(64)	16	41	12	206	275	1,328	(4)	(30)	(81)	1,213
(141)	(131)	(287)	(185)	(744)	(166)	(153)	(330)	465	(184)	1,129	(164)	(424)	(227)	314

379	336	(293)	609	1,031	856	706	287	801	2,650	327	526	293	781	1,927
448	533	2,343	405	3,729	656	867	534	293	2,350	589	829	921	352	2,691
85	1,601	864	214	2,764	1,833	1,876	1,348	878	5,935	1,843	2,383	2,003	1,816	8,045
984	1,104	584	1,004	3,676	2,188	1,167	1,860	1,788	7,003	3,505	2,168	2,641	2,622	10,936
1,896	3,574	3,498	2,232	11,200	5,533	4,616	4,029	3,760	17,938	6,264	5,906	5,858	5,571	23,599

														$ million
Q1	Q2	Q3	Q4	2002	Q1	Q2	Q3	Q4	2003	Q1	Q2	Q3	Q4	2004
5	427	(25)	(1,133)	(726)	433	333	196	(49)	913	211	(114)	23	32	152
(45)	31	262	365	613	(52)	(49)	(21)	(91)	(213)	(140)	(18)	(17)	58	(117)
(60)	(85)	11	(122)	(256)	7	2	13	16	38	(154)	6	(38)	(377)	(563)
–	(1)	1,585	(33)	1,551	–	6	(2)	(10)	(6)	–	–	16	40	56
(9)	4	(39)	30	(14)	6	(12)	(14)	119	99	1,313	(1)	1	(26)	1,287

(109)	376	1,794	(893)	1,168	394	280	172	(15)	831	1,230	(127)	(15)	(273)	815
39	(160)	(25)	21	(125)	(54)	(149)	(4)	84	(123)	70	28	33	130	261

(70)	216	1,769	(872)	1,043	340	131	168	69	708	1,300	(99)	18	(143)	1,076

Turnover

				$ million
2000	2001	2002	2003	2004
30,272	27,540	25,083	30,753	34,914
107,883	120,233	125,836	149,477	179,587
11,247	11,515	13,064	16,075	21,209
21,426	39,671	37,580	65,639	83,320
59	549	510	515	546
				319,576
22,825	25,290	23,352	29,888	34,517
				285,059
13,764	1,171	1,465	3,474	9,790
161,826	175,389	180,186	236,045	294,849

				81,155
				54,422
71,084	84,696	80,381	108,910	130,652
31,014	33,911	34,401	52,498	68,052
				334,281
19,989	28,708	31,327	34,390	49,222
148,062	174,218	178,721	232,571	285,059
	170,887148,06245,40020,553168,051	199,508174,21847,61836,701202,926	202,073178,72148,74846,518210,048	262,459232,57154,97150,582266,961

aUK area includes the UK-based international activities of Refining and Marketing.

Taxation

					$ million
	2000	2001	2002	2003	2004
Production taxes provided for
UK petroleum revenue tax	707	600	309	300	335
Overseas production taxes	1,354	1,089	965	1,423	1,814
	2,061	1,689	1,274	1,723	2,149
Production taxes paid
UK petroleum revenue tax	676	410	231	424	498
Overseas production taxes	1,466	1,114	930	1,386	1,709
	2,142	1,524	1,161	1,810	2,207
Tax on profit on ordinary activities
Current tax
UK	1,195	988	1,003	1,142	1,839
Overseas	3,704	3,846	1,883	3,525	5,070
Group	4,899	4,834	2,886	4,667	6,909
Joint ventures	57	94	75	158	880
Associated undertakings	128	203	187	94	119
	5,084	5,131	3,148	4,919	7,908
Deferred tax
UK	12	(48)	390	289	(140)
Overseas	1,552	1,292	779	931	340
Group	1,564	1,244	1,169	1,220	200
Joint ventures	–	–	–	(14)	170
Associated undertakings	–	–	–	(14)	4
	1,564	1,244	1,169	1,192	374
Tax on profit on ordinary activities	6,648	6,375	4,317	6,111	8,282
Effective tax rates on
Replacement cost basis	41%	43%	43%	36%	37%
Historical cost basis	39%	49%	39%	36%	34%
Profit taxes paid
UK	869	1,058	979	1,185	1,447
Overseas	5,329	3,602	2,115	3,619	4,931
	6,198	4,660	3,094	4,804	6,378

Depreciation and amounts provided $ million








































a

Refining and Marketing	477	770	794	826	881

bUK area includes the UK-based international activities of Refining and Marketing.

cIncludes amounts provided against fixed asset investments.

Group balance sheet
	2000	2001	2002	2003	$ million2004
Tangible assetsa
Exploration and Production	46,447	47,983	51,915	53,543	57,592
Refining and Marketing	17,619	16,903	22,433	24,255	24,640
Petrochemicals	8,360	9,242	10,080	10,591	10,660
Gas, Power and Renewables	1,744	1,931	1,889	2,158	2,331
Other businesses and corporate	1,003	1,351	1,365	1,364	1,525
	75,173	77,410	87,682	91,911	96,748
Intangible assetsa	17,897	16,489	15,566	13,642	12,076
Investmentsa
Net investment in joint venturesb	2,884	3,861	4,031	11,009	12,451
Associated undertakings	5,375	5,433	4,626	4,870	5,488
Other	3,054	2,403	1,995	1,579	467
	11,313	11,697	10,652	17,458	18,406
Total fixed assets	104,383	105,596	113,900	123,011	127,230
Current assets
Business held for resale	636	–	–	–	–
Stocks	9,234	7,631	10,181	11,617	15,698
Debtors	28,418	26,669	29,251	33,902	46,696
Investments	661	450	215	185	328
Cash at bank and in hand	1,170	1,358	1,520	1,947	1,156
	40,119	36,108	41,167	47,651	63,878
Creditors – amounts falling due within one yearFinance debt	6,418	9,090	10,086	9,456	10,184
Other creditors	32,110	28,524	36,215	41,128	54,341
Net current assets (liabilities)	1,591	(1,506)	(5,134)	(2,933)	(647)
Total assets less current liabilities	105,974	104,090	108,766	120,078	126,583
Creditors – amounts falling due after one year
Finance debt	14,772	12,327	11,922	12,869	12,907
Other creditors	3,821	3,054	3,412	6,030	4,505
Provisions for liabilities and charges
Deferred taxation	10,595	11,702	13,514	14,371	15,050
Other provisions	10,776	11,266	7,836	8,599	9,608
Net assets excluding pension and other post-retirement benefit balances	66,010	65,741	72,082	78,209	84,513
Defined benefit pension plan surplus	–	–	388	1,146	1,475
Defined benefit pension plan deficits	–	–	(5,250)	(5,005)	(5,863)
Other post-retirement benefit plan deficit	–	–	(2,748)	(2,630)	(2,126)
Net assets	66,010	65,741	64,472	71,720	77,999
Minority shareholders' interest – equity	568	598	638	1,125	1,343
BP shareholders' interest	65,442	65,143	63,834	70,595	76,656
Represented by
Called up share capital	5,653	5,629	5,616	5,552	5,403
Share premium account	3,385	3,590	3,794	3,957	5,636
Capital redemption reserve	385	424	449	523	730
Merger reserve	26,869	26,983	27,033	27,077	27,162
Other reserves	456	223	173	129	44
Shares held by ESOP trusts	(360)	(266)	(159)	(96)	(82)
Profit and loss account	29,054	28,560	26,928	33,453	37,763
Capital and reservesa	65,442	65,143	63,834	70,595	76,656
Fixed asset revaluation adjustment and goodwill consequent upon the
ARCO and Burmah Castrol acquisitions
Tangible assetsIntangible assets	9,08512,927	6,78711,663	5,80410,439	3,9839,125	3,5207,638
Fixed asset investments	584	432	429	254	232
	22,596	18,882	16,672	13,362	11,390
bNet investment in joint ventures
Gross assets	3,641	4,661	4,829	16,485	19,309
Gross liabilities	(757)	(800)	(798)	(5,111)	(6,316)
Minority shareholders' interest	–	–	–	(365)	(542)
	2,884	3,861	4,031	11,009	12,451

Capital employed
					$ million
By business	2000	2001	2002	2003	2004
Exploration and Productiona
UK	10,414	10,045	9,160	8,974	8,952
Rest of Europe	814	1,049	1,452	1,476	1,558
USA	27,354	28,703	28,169	26,853	27,354
Rest of World	18,089	20,035	22,679	26,315	30,854
	56,671	59,832	61,460	63,618	68,718
Refining and Marketinga
UKb	6,731	6,113	6,125	6,510	6,616
Rest of Europe	3,244	2,621	9,488	9,832	11,618
USA	14,026	12,984	13,952	14,125	15,296
Rest of World	4,306	3,601	3,919	4,644	5,047
	28,307	25,319	33,484	35,111	38,577
Petrochemicals
UK	2,989	2,976	2,512	2,907	3,048
Rest of Europe	1,990	2,421	3,340	3,850	4,900
USA	4,211	4,352	4,480	4,478	4,337
Rest of World	1,818	2,247	2,204	2,249	2,470
	11,008	11,996	12,536	13,484	14,755
Gas, Power and Renewables
UK	450	469	443	798	902
Rest of Europe	763	938	426	425	463
USA	1,149	1,115	1,056	1,672	1,700
Rest of World	1,176	917	1,054	1,397	1,836
	3,538	3,439	2,979	4,292	4,901
Other businesses and corporate
UK	(654)	(176)	65	(401)	1,641
Rest of Europe	276	317	(3,531)	(4,553)	(5,247)
USA	(1,317)	(2,183)	(4,962)	(2,806)	(5,180)
Rest of World	3,647	3,429	(1,340)	1,368	227
	1,952	1,387	(9,768)	(6,392)	(8,559)
Total operating capital employed	101,476	101,973	100,691	110,113	118,392
By geographical area
UKb	19,930	19,427	18,305	18,788	21,342
Rest of Europe	7,087	7,346	11,175	11,030	13,109
USA	45,423	44,971	42,695	44,322	43,507
Rest of World	29,036	30,229	28,516	35,973	40,434
Total operating capital employed	101,476	101,973	100,691	110,113	118,392
Liabilities for current and deferred taxation	(14,276)	(14,815)	(14,211)	(16,068)	(17,302)
Capital employed	87,200	87,158	86,480	94,045	101,090
Financed by
Finance debt	21,190	21,417	22,008	22,325	23,091
Minority shareholders' interest	568	598	638	1,125	1,343
BP shareholders' interest	65,442	65,143	63,834	70,595	76,656
Capital employed	87,200	87,158	86,480	94,045	101,090
aCapital employed acquisition adjustment consequent upon the ARCO
and Burmah Castrol acquisitions
Exploration and Production	14,348	11,506	9,737	6,983	5,665
Refining and Marketing	8,248	7,376	6,935	6,379	5,725
	22,596	18,882	16,672	13,362	11,390

bUK area includes the UK-based international activities of Refining and Marketing.

Group cash flow statement $ million

	2000	2001	2002	2003	2004
Net cash inflow from operating activities	20,416	22,409	19,342	21,698	28,554
Dividends from joint ventures	645	104	198	131	1,908
Dividends from associated undertakings	394	528	368	417	291
Servicing of finance and returns on investments
Interest received	444	256	231	175	332
Interest paid	(1,354)	(1,282)	(1,204)	(1,006)	(694)
Dividends received	42	132	102	140	53
Dividends paid to minority shareholders	(24)	(54)	(40)	(20)	(33)
Net cash outflow from servicing of finance and returns on investments	(892)	(948)	(911)	(711)	(342)
Taxation
UK corporation tax	(869)	(1,058)	(979)	(1,185)	(1,447)
Overseas tax	(5,329)	(3,602)	(2,115)	(3,619)	(4,931)
Tax paid	(6,198)	(4,660)	(3,094)	(4,804)	(6,378)
Capital expenditure and financial investment
Payments for tangible and intangible fixed assets	(8,837)	(12,142)	(12,049)	(12,368)	(13,035)
Payments for fixed assets – investments	(1,200)	(39)	(49)	(9)	–
Proceeds from the sale of fixed assets	3,029	2,365	2,470	6,253	4,323
Net cash outflow for capital expenditure and financial investment	(7,008)	(9,816)	(9,628)	(6,124)	(8,712)
Acquisitions and disposals
Acquisitions, net of cash acquired	(6,265)	(1,210)	(4,324)	(211)	(1,503)
Proceeds from the sale of businesses	8,333	538	1,974	179	725
Acquisition of investment in TNK-BP joint venture	–	–	–	(2,351)	(1,250)
Net investment in other joint ventures	(218)	(497)	(354)	(178)	(272)
Investments in associated undertakings	(985)	(586)	(971)	(987)	(942)
Proceeds from sale of investment in Ruhrgas	–	–	2,338	–	–
Net cash (outflow) inflow from acquisitions and disposals	865	(1,755)	(1,337)	(3,548)	(3,242)
Equity dividends paid	(4,415)	(4,827)	(5,264)	(5,654)	(6,041)
Net cash inflow (outflow) before financing	3,807	1,035	(326)	1,405	6,038
Financing	3,477	1,005	(163)	1,129	6,777
Management of liquid resources	452	(211)	(220)	(41)	132
Increase (decrease) in cash	(122)	241	57	317	(871)
	3,807	1,035	(326)	1,405	6,038

Movement in net debt

					$ million
	2000	2001	2002	2003	2004
Opening balance
Finance debt	14,544	21,190	21,417	22,008	22,325
Cash	1,331	1,170	1,358	1,520	1,947
Current asset investments	220	661	450	215	185
Opening net debt	12,993	19,359	19,609	20,273	20,193
Closing balance
Finance debt	21,190	21,417	22,008	22,325	23,091
Cash	1,170	1,358	1,520	1,947	1,156
Current asset investments	661	450	215	185	328
Closing net debt	19,359	19,609	20,273	20,193	21,607
Decrease (increase) in net debt	(6,366)	(250)	(664)	80	(1,414)
Movement in cash/bank overdrafts	(122)	241	57	317	(871)
Increase (decrease) in current asset investments	452	(211)	(220)	(41)	132
Net cash (inflow) outflow from financing (excluding share capital)	1,374	(128)	(736)	(760)	(431)
Partnership interests exchanged for BP loan notes	–	–	1,135	–	–
Debt transferred to TNK-BP	–	–	–	93	–
Exchange of Exchangeable Bonds for Lukoil American Depositary Shares	–	–	–	420	–
Other movements	(44)	(36)	76	144	68
Debt acquired	(8,072)	(55)	(1,002)	(15)	–
Movement in net debt before exchange effects	(6,412)	(189)	(690)	158	(1,102)
Exchange adjustments	46	(61)	26	(78)	(312)
Decrease (increase) in net debt	(6,366)	(250)	(664)	80	(1,414)

Consolidated statement of cash flows presented on a US GAAP format $ million

	2000	2001	2002	2003	2004
Operating activities
Profit after taxation	10,209	6,617	6,872	10,652	15,961
Adjustments to reconcile profits after tax to net cash
provided by operating activities
Depreciation and amounts provided	7,526	8,858	10,401	10,940	12,583
Exploration expenditure written off	264	238	385	297	274
Net charge for pensions and other post-retirement
benefits, less contributions	–	–	(178)	(2,573)	(39)
Share of (profit) loss of joint ventures and associated
undertakings less dividends received	(377)	(60)	3	(532)	2
Loss (profit) on sale of businesses and fixed assets	(196)	(537)	(1,166)	(831)	(815)
Working capital movement (see analysis below)	(2,729)	1,399	(1,060)	(2,270)	(4,073)
Deferred taxation	1,564	1,244	1,169	1,192	200
Other	(1,657)	(191)	(383)	66	181
Net cash provided by operating activities	14,604	17,568	16,043	16,941	24,274
Investing activities
Capital expenditures	(10,156)	(12,262)	(12,198)	(12,567)	(13,243)
Acquisitions, net of cash acquired	(6,265)	(1,210)	(4,324)	(211)	(1,503)
Acquisition of investment in TNK-BP joint venture	–	–	–	(2,351)	(1,250)
Investment in associated undertakings	(985)	(586)	(971)	(987)	(942)
Net investment in joint ventures	(218)	(497)	(354)	(178)	(272)
Proceeds from disposal of assets	11,362	2,903	6,782	6,432	5,048
Net cash used in investing activities	(6,262)	(11,652)	(11,065)	(9,862)	(12,162)
Financing activities
Proceeds from shares issued (repurchased)	(2,103)	(1,133)	(573)	(1,889)	(7,208)
Proceeds from long-term financing	1,680	1,296	3,707	4,322	2,675
Repayments of long-term financing	(2,353)	(2,602)	(2,369)	(3,560)	(2,204)
Net increase (decrease) in short-term debt	(701)	1,434	(602)	(2)	(40)
Dividends paid
BP shareholders	(4,415)	(4,827)	(5,264)	(5,654)	(6,041)
Minority shareholders	(24)	(54)	(40)	(20)	(33)
Net cash used in financing activities	(7,916)	(5,886)	(5,141)	(6,803)	(12,851)
Currency translation differences relating to cash and cash equivalents	(50)	(53)	90	121	91
Increase (decrease) in cash and cash equivalents	376	(23)	(73)	397	(648)
Cash and cash equivalents at beginning of year	1,455	1,831	1,808	1,735	2,132
Cash and cash equivalents at end of year	1,831	1,808	1,735	2,132	1,484
Analysis of working capital movement
(Increase)/decrease in stocks	(1,449)	1,490	(1,521)	(841)	(3,595)
(Increase)/decrease in debtors	(5,501)	1,905	(2,445)	(3,025)	(10,770)
Increase/(decrease) in creditors	4,221	(1,996)	2,906	1,596	10,292
Total working capital movement	(2,729)	1,399	(1,060)	(2,270)	(4,073)

Capital expenditure and acquisitions $ million

By business	2000	2001	2002	2003	2004
Exploration and Productiona	6,365	8,853	9,659	15,370	11,193
Refining and Marketingb,c	8,693	2,415	7,753	3,080	3,014
Petrochemicals	1,585	1,926	823	775	2,289
Gas, Power and Renewables	394	500	448	441	538
Other businesses and corporated	30,512	397	410	346	215
	47,549	14,091	19,093	20,012	17,249
By geographical area
UKb,e	7,374	2,095	1,619	1,556	1,832
Rest of Europec	2,041	1,787	6,556	1,277	2,105
USAd	34,037	6,160	6,095	6,291	6,301
Rest of Worlda	4,097	4,049	4,823	10,888	7,011
	47,549	14,091	19,093	20,012	17,249

a2003 includes $5,794 million for the acquisition of our interest in TNK-BP. b2000 includes $4,779 million for the acquisition of Burmah Castrol.

c2002 includes $5,038 million for the acquisition of Veba.

d2000 includes $27,506 million for the acquisition of ARCO.

eUK area includes the UK-based international activities of Refining and Marketing.

Ratios
					%
	2000	2001	2002	2003	2004
Return on average capital employed
Replacement cost profit	14.9	10.7	7.3	12.2	15.0
Historical cost profit	15.9	8.5	8.7	12.2	16.6
(Based on profit after taxation before deducting interest expense)a
Return on average BP shareholders' interest
Replacement cost profit	18.4	13.0	8.8	15.6	19.1
Historical cost profit	19.8	10.0	10.6	15.6	21.4
(Based on profit after taxation and minority shareholders' interest)
Payout ratio
Replacement cost profit	49.3	58.4	94.4	55.0	45.2
Historical cost profit	45.7	75.3	79.1	54.9	40.5
(Dividend: profit)
Debt to debt-plus-equity ratio	24.3	24.6	25.4	23.7	22.8
(Finance debt: finance debt plus BP and minority shareholders' interest)
Debt to equity ratio	32.1	32.6	34.1	31.1	29.6
(Finance debt: BP and minority shareholders' interest)
Net debt to net debt-plus-equity ratio	22.7	23.0	23.9	22.0	21.7
Net debt to equity ratio	29.3	29.8	31.4	28.2	27.7
(Net debt equals finance debt less cash and liquid resources)

aExcludes interest on joint venture and associated undertakings' debt and is on a post-tax basis, using a deemed tax rate equal to the US statutory tax rate.

Share prices
					pence
Ordinary share	2000	2001	2002	2003	2004
High	671	647	625	455	557
Daily average	579	575	512	418	489
Low	445	492	393	357	414
End year	540	534	427	453	508

					$
American depositary sharea	2000	2001	2002	2003	2004
High	60.63	54.86	53.88	49.35	61.66
Daily average	52.65	49.67	45.87	41.48	54.06
Low	43.63	43.23	36.78	35.37	47.27
End year	47.88	46.51	40.65	49.35	58.40

aOne American depositary share (ADS) is equivalent to six 25 cent ordinary shares.

United States accounting principles

The following is a summary of adjustments to profit for the year and to BP shareholders' interest which would be required if generally accepted accounting principles in the United States (US GAAP) had been applied instead of those generally accepted in the United Kingdom (UK GAAP). The results are stated using the first-in first-out method of stock valuation.

Profit for the year (historical cost) under US GAAP					$ million
	2000	2001	2002	2003	2004
Profit for the year as reported	10,120	6,556	6,795	10,482	15,731
Adjustments
Deferred taxation/business combinations	52	(512)	(603)	(169)	(591)
Provisions	(68)	(182)	8	49	(140)
Oil and natural gas reserve differences	–	–	–	–	30
Revisions to fair market values	–	(911)	–	289	–
Sale and leaseback	(34)	(36)	24	69	(6)
Goodwill and intangible assets	43	60	1,302	1,376	1,429
Derivative financial instruments	–	(313)	540	12	(286)
Gain arising on asset exchange	–	157	(18)	(17)	(68)
Pensions and other post-retirement benefits	–	–	50	(215)	(47)
Impairments	–	–	–	–	677
Provisions for severance and operating costs	–	–	–	–	60
Equity-accounted investments	–	–	–	–	226
Other	51	10	11	13	(43)
Profit for the year before cumulative effect of accounting change as adjusted
to accord with US GAAP	10,164	4,829	8,109	11,889	16,972
Cumulative effect of accounting changes
Provisions	–	–	–	1,002	–
Derivative financial instruments	–	(362)	–	50	–
Profit for the year as adjusted to accord with US GAAP	10,164	4,467	8,109	12,941	16,972
Dividend requirements on preference shares	2	2	2	2	2
Profit for the year applicable to ordinary shares as adjusted to accord with US GAAP	10,162	4,465	8,107	12,939	16,970
Per ordinary share – cents
Basic – before cumulative effect of accounting changes	46.96	21.51	36.20	53.62	77.77
Cumulative effect of accounting changes	–	(1.61)	–	4.74	–
	46.96	19.90	36.20	58.36	77.77
Diluted – before cumulative effect of accounting changes	46.65	21.38	36.02	53.10	76.35
Cumulative effect of accounting changes	–	(1.60)	–	4.69	–
	46.65	19.78	36.02	57.79	76.35
Per American depositary share – centsa

Basic – before cumulative effect of accounting changes	281.76	129.06	217.20	321.72	466.62
Cumulative effect of accounting changes	–	(9.66)	–	28.44	–
	281.76	119.40	217.20	350.16	466.62
Diluted – before cumulative effect of accounting changes	279.90	128.28	216.12	318.60	458.10
Cumulative effect of accounting changes	–	(9.60)	–	28.14	–
	279.90	118.68	216.12	346.74	458.10
BP shareholders' interest under US GAAP					$ million

	2000	2001	2002	2003	2004
BP shareholders' interest as reported	65,442	65,143	63,834	70,595	76,656
Adjustments
Deferred taxation/business combinations	358	(139)	(748)	(938)	(1,533)
Provisions	(913)	(1,054)	(1,088)	(128)	(137)
Oil and natural gas reserve differences	–	–	–	–	30
Sale and leaseback	(104)	(134)	(106)	(37)	(43)
Goodwill and intangible assets	(563)	(1,414)	(84)	1,669	3,200
Derivative financial instruments	–	(675)	(135)	(72)	(361)
Gain arising on asset exchange	–	157	142	129	61
Pensions and other post-retirement benefits	(145)	(942)	3,437	5,246	5,008
Impairments	–	–	–	–	677
Provisions for severance and operating costs	–	–	–	–	60
Equity-accounted investments	–	–	–	–	226
Dividends	1,178	1,288	1,398	1,495	1,822
Investments	(112)	(2)	34	1,251	183
Other	(54)	(40)	(48)	(43)	–
BP shareholders' interest as adjusted to accord with US GAAP	65,087	62,188	66,636	79,167	85,849

aOne American depositary share (ADS) is equivalent to six 25 cent ordinary shares.

Statistics

Crude oil, natural gas and natural gas liquids production (net of royalties)

	2000	2001	2002	2003	2004
UK	534	485	462	377	330
USA	729	744	765	726	666
Other	665	702	791	1,018	1,535
Crude oil and liquids production (thousand barrels a day)	1,928	1,931	2,018	2,121	2,531
UK	1,652	1,713	1,555	1,446	1,174
USA	3,054	3,554	3,483	3,128	2,749
Other	2,903	3,365	3,669	4,039	4,580
Natural gas production (million cubic feet a day)	7,609	8,632	8,707	8,613	8,503
Total production (thousand barrels oil equivalent a day)	3,240	3,419	3,519	3,606	3,997
Refinery throughputs					thousand barrels a day
Group refinery throughputsa	2,916b	2,929	3,103	3,097	2,976
For BP by others	12	14	14	–	–
Total	2,928	2,943	3,117	3,097	2,976

Crude oil and refined petroleum product sales					thousand barrels a day
Crude oil	4,181	3,910	3,935	3,837	3,808
Refined petroleum products	5,523c	6,206	6,563	6,688	6,398
Total oil sales	9,704	10,116	10,498	10,525	10,206
Estimated net proved reserves of crude oild				millions of barrels at 31 December
Developed	4,318	4,308	4,335	3,576	3,423
Undeveloped	2,190	2,909	3,427	3,873	4,127
Group companies	6,508	7,217	7,762	7,449	7,550
Equity-accounted entities (BP share)	1,135	1,159	1,403	2,867	3,180
Estimated net proved reserves of natural gase				billions of cubic feet at 31 December
Developed	24,269	23,749	23,773	21,073	19,372
Undeveloped	16,831	19,210	22,071	22,903	23,550
Group companies	41,100	42,959	45,844	43,976	42,922
Equity-accounted entities (BP share)	2,818	3,216	2,945	2,553	2,628
Average realizations
BP average crude oil and natural gas liquids realizations ($/bbl)	26.6	22.5	22.7	27.3	35.4
Brent oil price ($/bbl)	28.4	24.4	25.0	28.8	38.3
Henry Hub gas price ($/mmBtu)	3.9	4.3	3.2	5.4	6.1

aIncludes crude oil and other feedstock input to BP's crude distillation units both for BP and third parties.bIncludes BP share of the BP/Mobil joint venture.

cIncludes BP share of the BP/Mobil joint venture.

dNet proved reserves of crude oil exclude production royalties due to others.

eNet proved reserves of natural gas exclude production royalties due to others.

Further information is included in BP Financial and Operating Information 2000-2004. (To obtain a copy, see page 129.)

Employee numbers year end

By business	2000	2001	2002	2003	2004
Exploration and Production	15,900	16,350	16,600	15,150	15,650
Refining and Marketing	39,500	36,100	42,050	39,200	39,300
Petrochemicals	17,600	21,950	18,950	15,950	12,400
Gas, Power and Renewables	3,500	4,400	4,600	3,750	4,050
Other businesses and corporate	3,100	2,850	2,800	2,700	3,550
Sub-total	79,600	81,650	85,000	76,750	74,950
Service station staff	27,600	28,500	30,250	26,950	27,950
	107,200	110,150	115,250	103,700	102,900
By geographical area
UK	18,900	19,650	17,750	17,050	17,400
Rest of Europe	22,500	22,800	29,850	25,250	26,000
USA	44,000	42,750	43,200	39,100	36,950
Rest of World	21,800	24,950	24,450	22,300	22,550
	107,200	110,150	115,250	103,700	102,900

Glossary

Term used in

BP Annual Report and Accounts	US equivalent or definition
Accounts	Financial statements
Acquisition accounting	Purchase accounting
Associated undertakings	Equity affiliates or investees
Called up share capital	Shares, capital stock or common stock issued
	and fully paid
Capital allowances	Tax depreciation
Capital redemption reserve	Other additional capital
Cash at bank	Cash
Creditors	Accounts payable and accrued liabilities
Creditors: amounts falling due within one year	Current liabilities
Creditors: amounts falling due after more than one year	Long-term liabilities
Debtors	Accounts receivable
Debtors: amounts falling due within one year	Other current assets
Debtors: amounts falling due after more than one year	Other non-current assets
Decommissioning	Dismantlement, restoration and abandonment
Employee share schemes	Employee stock benefit plans
Employment costs	Payroll costs
Finance lease	Capital lease
Financial year	Fiscal year
Fixed asset investment	Non-current investments
Freehold	Ownership with absolute rights in perpetuity
Hire charges	Rent
Interest payable	Interest expense
Interest receivable	Interest income
Joint ventures	Equity affiliates or investees
Merger accounting	Pooling of interests accounting
Net asset value	Book value
Other debtors	Other current assets
Own shares	Treasury stock
Profit	Income or earnings
Profit and loss account (statement)	Income statement
Profit and loss account	Retained earnings
(under 'capital and reserves' in balance sheet)
Profit for year	Net income
Profit on sale of fixed assets or businesses	Gain on disposal of properties or long-term investments
Provision for doubtful debts	Allowance for doubtful accounts
Provisions	Non-current liabilities other than debt and specific accounts payable
Redundancy charges	Severance costs
Reserves	Retained earnings
Scrip dividend	Stock dividend
Shareholders' funds	Shareholders' equity
Share premium account	Amounts subscribed for share capital in excess of nominal value
Statement of total recognised gains and losses	Statement of comprehensive income
Stocks	Inventories
Tangible fixed assets	Property, plant and equipment
Turnover	Sales and other operating revenue

Governance: board performance report

Governance and the role of our board

Good governance is often defined in terms of the presence or absence of particular practices without reference to the underlying purpose of governance processes. We believe that governance is a more powerful concept.

Governance is not an exercise in compliance nor is it a higher form of management. Governance lies at the heart of all the board does and it is the task our owners entrust to the board. It has a clear objective – ensuring the pursuit of the company's purpose. The board's role is focused on this task, which is unique to it as the representative of BP's owners. This task is discharged by the board through undertaking such activities as are necessary for the effective promotion of shareholder interest.

Governance is the system by which the company's owners and their representatives on the board ensure that it pursues, does not deviate from and only allocates resources to its defined purpose.

As a company, we recognize the importance of good governance and that it is a discrete task from management. Clarity of roles is key to our approach. Policies and processes depend upon the people who operate them. Governance requires distinct skills and processes. In the context of BP, governance is overseen by our board while management is delegated to the group chief executive by means of the board governance policies.

Our board governance policies use a coherent, principles-based approach, which anticipated many developments in UK governance regulation. They ensure that our board and management operate within a clear and efficient governance framework that goes beyond regulatory compliance and places shareholder interest at the heart of all we do.

Accountability to shareholders

Our board is accountable in a variety of ways. It is required to be proactive in obtaining an understanding of shareholder preferences and to evaluate systematically the economic, social, environmental and ethical matters that may influence or affect the interest of our shareholders.

Our board is accountable to shareholders for the performance and activities of the entire BP group. It embeds shareholder interest in the goals established for the company.

In carrying out its work in policy-making and monitoring and in its active consideration of group strategy, our board exercises judgement on how best to further shareholder interest. The board seeks to do so by maximizing the expected value of shareholders' interest in the company, not by eliminating the possibility of any adverse outcomes.

Reporting Our board makes use of a number of formal communication channels to account to shareholders for the performance of the company. These include the Annual Report and Accounts, the Annual Review, the Annual Report on Form 20-F, quarterly Forms 6-K and announcements made through stock exchanges on which BP shares are listed, as well as through the annual general meeting (AGM). Dialogue with directors Presentations given at appropriate intervals to representatives of the investment community are available to all shareholders by internet broadcast or open conference call. Less formal processes include contacts with institutional shareholders by

the chairman and other non-executive directors. This is supported by the dialogue with shareholders concerning the governance and operation of the group maintained by the company secretary's office, investor relations and other BP teams.

AGM and voting Given the size and geographical diversity of our shareholder base, the opportunities for shareholder interaction at the AGM are limited. However, the chairman and all board committee chairmen were present at the 2004 AGM to answer shareholders' questions and hear their views during the meeting. Members of the board met informally with shareholders afterwards. All votes at shareholder meetings, whether by proxy or in person, are counted since votes on all matters, except procedural issues, are taken by way of a poll. We have pioneered the use of electronic communications to facilitate the exercise of shareholder control rights and continue to promote the use of electronic voting through our registrar's website and through CREST.

Directors' elections Directors are required to stand for re-election each year. New directors are subject to election at the first opportunity following their appointment. All names submitted to shareholders for election are accompanied by detailed biographies.

How our board governs the company

The board's governance policies regulate its relationship with shareholders, the conduct of board affairs and the board's relationship with the group chief executive. The policies recognize the board's separate and unique role as the link in the chain of authority between the shareholders and the group chief executive. It is this unique task that gives the board its central role in governance.

The dual role played by the group chief executive and executive directors as both members of the board and leaders of the executive management is also recognized and addressed. The policies require a majority of the board to be composed of independent non-executive directors. To assure the integrity of the governance process, the relationship between the board and the group chief executive is governed by the non-executive directors, particularly through the work of the board committees they populate.

Recognizing that as a group its capacity is limited, our board reserves to itself the making of broad policy decisions. It delegates more detailed considerations involved in meeting its stated requirements either to board committees and officers (in the case of its own processes) or to the group chief executive (in the case of the management of the company's business activities). The board governs BP through setting general policy for the conduct of business (and critically, by clearly articulating its objective) and by monitoring its implementation by the group chief executive.

To discharge its governance function in the most effective manner, our board has laid down rules for its own activities in a board process policy. The board process policy covers:

The conduct of members at meetings.
The cycle of board activities and the setting of agendas.
The provision of timely information to the board.
Board officers and their roles.
Board committees their tasks and composition.
Qualifications for board membership and the process of the nomination committee.
The evaluation and assessment of board performance.
The remuneration of non-executive directors.
The process for directors to obtain independent advice.
The appointment and role of the company secretary.

The responsibility for implementation of this policy is placed on the chairman.

The board-executive linkage policy sets out how the board delegates authority to the group chief executive and the extent of that authority. In its goals policy, the board states the long-term outcome and required results it expects the group chief executive to deliver. The restrictions on the manner in which the group chief executive may achieve the required results are set out in the executive limitations policy. This policy addresses internal control, risk preferences, financing, ethical behaviour, health, safety, the environment, treatment of employees and political considerations. Through the goals and executive limitations policies, the board shapes BP's values and standards.

Accountability in our business

Our group chief executive outlines how he intends to deliver the required outcome in annual and medium-term plans, which also address a comprehensive assessment of the group's risks. Progress towards the expected outcome forms the basis of a report to the board that covers actual results and a forecast of results for the current year. This report is reviewed at each board meeting.

The group chief executive is obliged through dialogue and systematic review to discuss with our board all material matters currently or prospectively affecting the company and its performance and all strategic projects or developments. This key dialogue specifically includes any materially under-performing business activities and actions that breach the executive limitations policy and material matters of a social, environmental and ethical nature.

The board-executive linkage policy also sets out how the group chief executive's performance will be monitored and recognizes that, in the multitude of changing circumstances, judgement is always involved. The systems set out in the board-executive linkage policy are designed to manage, rather than to eliminate, the risk of failure to achieve the board goals policy or observe the executive limitations policy. They provide reasonable, not absolute, assurance against material misstatement or loss.

Who is on the board?

The board is composed of the chairman, 12 non-executive and six executive directors. In total, five nationalities are represented on the board. Directors' biographies are set out on pages 126-127. As reported last year, the board is actively engaged in succession planning issues. As a result, the size of the board has increased during the past year despite the departure of Mr Maljers and Mr Olver. Mr Burgmans (February), Sir Tom McKillop (July) and Mr Flint (from January 2005)

were appointed as non-executive directors, while Mr Conn joined the board as an executive director in July.

The efficiency and effectiveness of the board are paramount concerns. Our board is large but this is necessary to allow sufficient executive director representation to cover the breadth of the group's business activities and sufficient non-executive representation to reflect the scale and complexity of BP and to staff our board committees. A board of this size allows orderly succession planning for key roles.

Governance policies and processes depend upon the quality and commitment of the people who operate them.

New non-executive directors will be appointed over the coming years. Mr Knight and Sir Robin Nicholson will retire at the 2005 AGM. Subject to their annual re-election, Mr Miles will retire in 2006 and Mr Bryan and Mr Wilson in 2007. We believe refreshing the composition of the board should be an orderly process of evolution that ensures its continuing effectiveness.

Board independence

The qualification for board membership includes a requirement that all our non-executive directors be free from any relationship with the executive management of the company that could materially interfere with the exercise of their independent judgement. In the board's view, all our non-executive directors fulfil this requirement. It determined all 12 who served during 2004 to be independent directors.

Mr Knight and Sir Robin Nicholson were appointed to the BP board in 1987 and Mr Miles was appointed in 1994. The length of their respective service on the board exceeds the nine years referred to in the Combined Code. The board considers that the experience and long-term perspective of each of these directors on BP's business during its recent period of growth provide a valuable contribution to the board, given the long-term nature of our business. The integrity and independence of character of these directors are beyond doubt. Both Mr Knight and Sir Robin will retire at the 2005 AGM. Mr Miles will retire in 2006.

Those directors who joined the BP board in 1998 after service on the board of Amoco Corporation (Messrs Bryan, Massey, Wilson and Davis) are considered independent since the most senior executive management of BP comprises individuals who were not previously Amoco employees. While Amoco businesses and assets are a key part of the group, the scope and scale of BP since its acquisition of the ARCO, Burmah Castrol and Veba businesses are fundamentally different from those of the former Amoco Corporation.

The board has satisfied itself that there is no compromise to the independence of those directors who serve together as directors on the boards of outside entities (or who have other appointments in outside entities). Where necessary, our board ensures appropriate processes are in place to manage any possible conflict of interest.

Sir Robin Nicholson received fees during 2004 for representing the board on the BP technology advisory council. Since these fees relate to board representation, they do not compromise Sir Robin's independence. Full details of these fees are disclosed on page 125.

Directors' appointments, retirement policies and insurance

The chairman and non-executive directors of BP are elected each year and, subject to BP's Articles of Association, serve on the basis of letters of appointment. Executive directors of BP have service contracts with the company. Details of all payments to directors are reviewed in the directors' remuneration report on pages 116-125. Annual elections for all directors and the provision of independent support to our board and board committees underscore our commitment to good governance practice.

BP's policy on directors' retirement is as follows: executive directors retire at age 60, while non-executive directors ordinarily retire at the AGM following their 70th birthday. It is the board's policy that nonexecutive directors are not generally expected to hold office for more than 10 years.

In accordance with BP's Articles of Association, directors are granted an indemnity from the company to the extent permitted by law in respect of liabilities incurred as a result of their office. In respect of those liabilities for which directors may not be indemnified, the company purchased and maintained a directors' and officers' liability insurance policy throughout 2004. This insurance cover was renewed at the beginning of 2005. Neither the company's indemnity nor insurance provides cover in the event that the director is proved to have acted fraudulently or dishonestly.

Board and committees: meetings and attendance

In addition to the AGM (which all but one director attended), the board met eight times during 2004, five times in the UK, twice in the US and once in continental Europe. Two of these meetings were two-day strategy discussions. 2004 saw an increased number of committee meetings, with no sign that this trend will reverse.

The board requires all members to devote sufficient time to the work of the board to discharge the office of director and to use their best endeavours to attend meetings. Directors' attendance at board and committee meetings is set out below. All directors attended at least 75% of meetings, except Mr Burgmans. Several board meetings coincided with commitments entered into by Mr Burgmans before his appointment to the board in February 2004, a matter made known to the board on his appointment. The board and Mr Burgmans are looking forward to his full participation in the years ahead.

Serving as a director: induction, training and evaluation

Induction Directors receive induction on their appointment to the board as appropriate, covering matters such as the operation and

activities of the group (including key financial, business, social and environmental risks to the group's activities), the role of the board and the matters reserved for its decision, the tasks and membership of the principal board committees, the powers delegated to those committees, the board's governance policies and practices, and the latest financial information about the group. The chairman is accountable for the induction of new board members.

Training Our directors are updated on BP's business, the environment in which it operates and other matters throughout their period in office. We advise directors on their appointment of the legal and other duties and obligations they have as directors of a listed company. The board regularly considers the implications of these duties under our board governance policies. Our non-executive directors receive training specific to the tasks of the particular board committees on which they serve.

Outside appointments As part of their ongoing development, our executive directors are permitted to take up an external board appointment, subject to the agreement of our board. Executive directors retain any fees received in respect of such external appointments.

Generally outside appointments for executive directors are limited to one outside company board only, although our group chief executive, by exception, serves on two outside company boards. Our board is satisfied that these appointments do not conflict with his duties and commitment to BP. Non-executive directors may serve on a number of outside boards, always provided they continue to demonstrate the requisite commitment to discharge effectively their duties to BP. The nomination committee keeps the extent of directors' other interests under review to ensure that the effectiveness of our board is not compromised.

As the board attendance table below illustrates, our directors' commitment to the work of the board is manifest.

Evaluation During 2004, our board continued its ongoing evaluation processes to assess its performance and identify areas in which its effectiveness, policies or processes might be enhanced. The board reviewed the conclusions and actions from the 2003 evaluation and determined that there should be a focus on evaluating the performance of the board committees during 2004.

Directors' attendance

	Boardmeetings		Audit committeemeetings		EEACmeetings		Chairman'scommittee meetings		Remunerationcommittee meetings		Nominationcommittee meetings
	Attended	Possible	Attended	Possible	Attended	Possible	Attended	Possible	Attended	Possible	Attended	Possible
P D Sutherland	7	8	–	–	–	–	3	3	7a	7a	2	2
Sir Ian Prosser	8	8	13	13	–	–	3	3	6	7	2	2
J H Bryan	8	8	13	13	–	–	3	3	2	2	–	–
A Burgmans	3	7	–	–	–	2	1	3	–	–	–	–
E B Davis, Jr	7	8	13	13	–	–	2	3	7	7	–	–
Dr D S Julius	8	8	–	–	–	–	3	3	7	7	–	–
C F Knight	7	8	–	–	–	–	3	3	6	7	–	–
Sir Tom McKillop	3	4	–	–	–	–	2	2	2	2	–	–
F A Maljers	3	3	–	–	2	2	1	1	–	–	–	–
Dr W E Massey	8	8	–	–	6	6	3	3	–	–	2	2
H M P Miles	8	8	12	13	6	6	3	3	–	–	–	–
Sir Robin Nicholson	8	8	–	–	–	–	3	3	7	7	2	2
M H Wilson	8	8	13	13	6	6	3	3	–	–	–	–
Lord Browne	8	8	–	–	–	–	–	–	–	–	–	–
Dr D C Allen	8	8	–	–	–	–	–	–	–	–	–	–
I C Conn	4	4	–	–	–	–	–	–	–	–	–	–
Dr B E Grote	8	8	–	–	–	–	–	–	–	–	–	–
Dr A B Hayward	8	8	–	–	–	–	–	–	–	–	–	–
J A Manzoni	8	8	–	–	–	–	–	–	–	–	–	–
R L Olver	4	4	–	–	–	–	–	–	–	–	–	–

a Attended all remuneration committee meetings as chairman of the board.

Regular evaluation of board effectiveness underpins our confidence in BP's governance policies and processes and affords opportunity for their development.

Evaluations of both the audit and the ethics and environment assurance committees took place during the year. An evaluation of the work of the remuneration committee will take place this year as the review of executive remuneration is concluded and Dr Julius assumes chairmanship of the committee. Work on a further evaluation of the board and the performance of individual directors has commenced.

The chairman and senior independent director

BP's board governance policies require the chairman and deputy chairman to be non-executive directors; throughout 2004 the posts were held by Mr Sutherland and Sir Ian Prosser respectively. Sir Ian also acts as our senior independent director and is the director whom shareholders may contact if they feel their concerns are not being addressed through normal channels.

Between board meetings, the chairman has responsibility for ensuring the integrity and effectiveness of the board/executive relationship. This requires his interaction with the group chief executive between board meetings, as well as his contact with other board members and shareholders. The chairman represents the views of the board to shareholders on key issues, not least in succession planning issues for both executive and non-executive appointments. The chairman and all the non-executive directors meet periodically as the chairman's committee (see report on page 114). The performance of the chairman is evaluated each year at a meeting of the chairman's committee, for which item of business he is not present. The company secretary reports to the chairman and is not part of the executive management.

Board committees

The board process policy allocates the tasks of monitoring executive actions and assessing performance to certain board committees. These tasks, rather than any terms of reference, prescribe the authority and the role of the board committees. Reports for each of the committees for 2004 appear below. In common with the board, each committee has access to independent advice and counsel as required and each is supported by the company secretary and his office, which is demonstrably independent of the executive management of the group.

Audit committee report

Schedule and composition The committee met 13 times during 2004 and comprised the following directors: Sir Ian Prosser (chairman), J H Bryan, E B Davis, Jr, H M P Miles, M H Wilson.

All members of the audit committee are independent non-executive directors. The board considers that the membership of the audit committee as a whole has sufficient recent and relevant financial experience to discharge its functions, but it has determined not to identify any single member as having such experience. The external auditors' lead partner, the BP general auditor (head of internal audit), together with the group chief financial officer, the chief accounting officer and the group controller, attend each meeting at the request of the committee chairman. At least twice a year, the committee meets with the external auditor without the executive management being present. The committee also meets in private session with the general auditor.

Role and authority The audit committee's tasks are considered by the committee to be broader than those envisaged under Combined Code Provision C.3.2. The committee is satisfied that it addresses each of those matters identified as properly falling within an audit committee's purview. The committee has full delegated authority from the board to address those tasks assigned to it. In common with the board and all committees, it may request any information from the executive management necessary to discharge its functions and may, where it considers necessary, seek independent advice and counsel. Process The committee structures its work programme so as to discharge its tasks, which include systematic monitoring and obtaining assurance that the legally required standards of disclosure are being fully and fairly observed and that the executive limitations relating to financial matters are being observed. The committee chairman reports on the committee's activities to the board meeting immediately following a committee meeting. Between meetings, the committee chairman reviews emerging issues with the group chief financial officer, the external auditor and the BP general auditor. He is supported in this task by the company secretary's office.

During the year, external specialist legal and regulatory advice has also been provided to the committee by Sullivan & Cromwell LLP. With significant changes in accounting practices being introduced in 2005, the committee undertook initial training in the implementation of International Financial Reporting Standards (IFRS) and how these standards are expected to affect the group's reported results. Activities in 2004 Financial reports: During the year, the committee reviewed all annual and quarterly financial reports before recommending their publication on behalf of the board. In particular, the committee discussed significant accounting policies, estimates and judgements that had been applied in preparing these reports and received independent advice from the external auditors.

Accounting treatment: The committee also received during the year separate reports concerning the group's environmental and decommissioning provisions, tax exposures, pension assumptions and the status of current litigation. The committee gained assurance that such liabilities and contingencies were appropriately reflected in the financial results.

System of internal control: Each year, specific reports on risk management and internal control within selected business and functional activities are considered. During 2004, the exploration and production and petrochemicals segments were reviewed, along with accounting issues of the supply and trading function that services all BP's businesses. Given the increased public and regulatory attention to hydrocarbon reserves reporting, the committee sought and received additional assurance that BP's management and recording processes are applied in a consistent and coherent manner throughout the group. Following the adoption of the US Sarbanes-Oxley Act of 2002, an increased regulatory requirement has been placed on all companies that offer shares by listing on US stock exchanges. The committee has monitored the company's response to the applicable requirements of this Act and, in particular, its progress in evaluating internal controls as required by rules pursuant to Section 404 of the Act. Employee concerns reporting/whistleblowing: The committee receives regular reports of the matters raised through the employee concerns programme (OpenTalk) and, through this process, is alerted to instances of potential fraud or matters of concern raised related to the finances and financial accounting policies of the group. Auditor independence and rotation: The committee reviews on behalf of the board the independence, objectivity and viability of the auditors before an appointment recommendation is made to shareholders at

the AGM. A new lead audit partner is appointed every five years and other senior audit staff are rotated every seven years.

Policy on non-audit services provided by the auditor: To safeguard the independence of the audit process, non-audit services provided by the auditor are limited to defined audit-related work and tax services that fall within specific categories. Additionally, all such services must be pre-approved by the committee. These services have been substantially reduced in 2004 but overall fees paid to Ernst & Young have increased, since audit fees have risen significantly across the market due to the increased regulatory burden on listed companies (see page 50 for details).

Internal audit: The committee considers the internal auditor's programme and its effectiveness twice a year. It receives regular reports of work undertaken, actions recommended and the executive management's responses to those recommendations.

Performance evaluation: Each year the committee critically reviews its own performance and considers where improvements can be made. During 2004, the committee strengthened its tracking of outstanding issues and clarified the scope of its role and relationship with that of the ethics and environment assurance committee. It also allocated additional time to training, not least on the implications of the introduction of IFRS. To accommodate all such matters and discharge its ongoing tasks the committee increased the number of meetings from nine in 2003 to 13 in 2004.

Ethics and environment assurance committee report

Schedule and composition The committee met six times during 2004 and comprised the following directors: Dr W E Massey (chairman), A Burgmans (from October 2004), F A Maljers (to April 2004), H M P Miles, M H Wilson.

All members of the ethics and environment assurance committee are independent non-executive directors. The external auditors' lead partner and the BP general auditor (head of internal audit) attend each meeting at the request of the committee chairman. The committee met once during 2004 with the general auditor and external auditor but without the executive management being present.

Role and authority The task of the committee is to monitor matters relating to the executive management's processes to address environmental, health and safety, security and ethical behaviour issues. The committee monitors the observance of the executive limitations relating to non-financial risks to the group.

Process and activities in 2004 At each meeting, the committee considered a report from executive management on current developments in business and functional areas giving rise to ongoing and emergent non-financial risks to the group's activities. In particular, during the course of 2004, the committee directed its attention to the BTC pipeline project and operations in Alaska and Russia. The committee's work programme also addressed:

Environmental liabilities: Including a review of the group's approach to remediation at operational and disused sites, encompassing all businesses ranging from mining activities to oil terminals to service stations.

Health, safety and environmental performance: Greenhouse gas and other emissions, spills and containment practices and safety at work issues, both group-wide and in specific businesses and locations (for example, shipping, road safety and the operational integrity of plant and equipment).

Security: Group preparedness and mitigation plans in respect of identified and potential security threats to staff, physical infrastructure and the digital infrastructure of the group.

Employees: The results of the annual People Assurance Survey, employee health and welfare and the impact of HIV/AIDS on our business.

Ethical behaviour: Matters arising from the annual ethics certification process and OpenTalk (BP's employee concerns reporting programme), as well as other conduct and compliance issues.

Disaster recovery and business continuity planning and capability: Development of the group's capacity and capability to respond to catastrophic events and to maintain its business activities. Performance evaluation: The committee addressed the nature of its remit and authority, its interface with the audit committee and the scope and focus of its activities, as well as its overall effectiveness and refinements to its processes. The committee increased the number of its meetings from five in 2003 to six in 2004.

Remuneration committee report

Schedule and composition The committee met seven times during 2004 and comprised the following directors: Sir Robin Nicholson (chairman, retiring at the 2005 AGM), Dr D S Julius (chairman elect), E B Davis, C F Knight (retiring at the 2005 AGM), Sir Ian Prosser, J H Bryan

(from November 2004), Sir Tom McKillop (from November 2004). All members of the remuneration committee are non-executive directors and are considered by the board to be independent. The chairman of the board also attends committee meetings. The committee is independently advised.

Role and authority The committee's main task is to determine the terms of engagement and remuneration of the executive directors. A key priority for the committee in 2004 has been its review of executive directors' remuneration policy in preparation for the renewal of the long-term incentive plan for executive directors at the 2005 AGM.

Process and activities in 2004 Full details of the committee's remit and work are set out in the remuneration report on pages 116-125, which is the subject of a vote by shareholders at the forthcoming AGM.

Chairman's committee report

Schedule and composition The chairman's committee met three times during 2004 and comprised all the non-executive directors.

Role and authority The task of the committee is to consider

broad issues of governance, including the performance of the chairman and the group chief executive, succession planning, the organization of the group and any matters referred to it for an opinion from another board committee.

Process and activities in 2004 At its various meetings, the committee evaluated the performance of the chairman and the group chief executive, considered the plan for executive succession and considered a number of other broad matters of governance, including the future governance of the Olefins and Derivatives business as it is prepared for its planned disposal. Additionally, the committee addressed non-executive succession planning issues in co-ordination with the nomination committee.

Nomination committee report

Schedule and composition The committee met twice during 2004 and comprised the following directors: P D Sutherland (chairman), Dr W E Massey, Sir Robin Nicholson, Sir Ian Prosser.

All members of the nomination committee are considered by the board to be independent.

Role and authority The task of the nomination committee is to identify and evaluate candidates for appointment and reappointment as director or company secretary of BP.

Process During the year, the nomination committee carried out a detailed review of the skills and expertise of the non-executive directors as part of the board succession planning described earlier. The committee receives external assistance as required. The committee consults with the group chief executive concerning the identification and appointment of new executive directors. Activities in 2004 The committee considered the composition of the board and board committees in the context of forthcoming work programmes, BP's strategy and business activities and retirements from the board. Board and committee evaluation processes informed its work in identifying the skills and experiences sought from potential candidates.

External search consultants were retained in the UK, continental Europe and the US to assist the committee in the identification of potential candidates as non-executive directors. In close co-ordination with the chairman's committee (all the non-executive directors), the nomination committee recommended the appointment of the following directors during the year: Sir Tom McKillop, I C Conn and D J Flint.

Combined Code compliance

BP complied throughout 2004 with the provisions of the Combined Code Principles of Good Governance and Code of Best Practice, except in the following aspects:

A.4.4 Letters of appointment do not set out fixed time commitments since the schedule of board and committee meetings is subject to change according to the exigencies of the business. All directors are expected to demonstrate their commitment to the work of the board on an ongoing basis. This is reviewed by the nomination committee in recommending candidates for annual re-election.

B.1.4 The amount of fees received by executive directors in respect of their service on outside boards is not disclosed since this information is not considered relevant to BP.

B.2.2 The remuneration of the chairman is fixed by the board as a whole (rather than by the remuneration committee) within the limits set by shareholders, since the chairman's performance is a matter for the whole board.

Internal control review

The board governance policies include a process for the board to review regularly the effectiveness of the system of internal control as required by Code provision C.2.1. As part of this process, the board, the audit and the ethics and environment assurance committees requested, received and reviewed reports from executive management, including management of the principal business segments, at their regular meetings. That enabled them to assess the effectiveness of the system of internal control in operation for managing significant risks (including social, environmental and ethical risks) throughout the year. This process did not extend to joint ventures or associates.

The executive management presented reports to the January and February 2005 meetings of both the audit and the ethics and environment assurance committees to support the board in its annual assessment of internal control. The reports described how significant risks were identified and embedded within business segment and function plans across the group. They reviewed the executive management's assurance process and the continuing development of the systems of internal controls in place to identify, address and manage risks. The reports also highlighted future potentially significant risks to the company's plans. The two committees engage with executive management on a regular basis to monitor the management of these risks. Significant incidents that occurred and management's response to them were considered by the committees during the year.

In the board's view, the information it received was sufficient to enable it to review the effectiveness of the company's system of internal control in accordance with the Guidance for Directors on Internal Control (Turnbull).

Directors' interests

		At 1 Jan 2004	Change from
	At 31 Dec 2004	or onappointment	31 Dec 2004-8 Feb 2005
Current directors(excluding director appointed in 2005)
Dr D C Allen	408,342a	371,365a	–
Lord Browne	2,031,279b	1,816,054b	–
J H Bryan	158,760c	158,760c	–
A Burgmans	10,000	10,000d	–
I C Conn	121,187	119,098e	71
E B Davis, Jr	66,349c	65,162c	–
Dr B E Grote	888,213c	788,313c	–
Dr A B Hayward	206,084	121,692	71
Dr D S Julius	15,000	15,000	–
C F Knight	98,578c	95,610c	–
Sir Tom McKillop	20,000	–e	–
J A Manzoni	196,336	127,821	68
Dr W E Massey	49,722c	49,261c	–
H M P Miles	22,145	22,145	–
Sir Robin Nicholson	4,020	3,897	–
Sir Ian Prosser	16,301	16,301	–
P D Sutherland	30,079	30,079	–
M H Wilson	60,000c	60,000c	–

	At retirement	At 1 Jan 2004
Directors leaving the board in 2004
F A Maljers	33,492c	33,492c
R L Olver	884,408	798,326

	Onappointment1 January 2005	Change from1 Jan 2005-7 Feb 2005
Director appointed in 2005

D J Flint – –

aIncludes 25,368 shares held as ADSs. dOn appointment at 5 February 2004. bIncludes 50,368 shares held as ADSs. eOn appointment at 1 July 2004. cHeld as ADSs.

In disclosing the above interests to the company under the Companies Act 1985, directors did not distinguish their beneficial and non-beneficial interests.

Executive directors are also deemed to have an interest in such shares of the company held from time to time by BP QUEST Company Limited and The BP Employee Share Ownership Plan (No. 2) to facilitate the operation of the company's option schemes.

No director has any interest in the preference shares or debentures of the company, or in the shares or loan stock of any subsidiary company.

Directors' remuneration report

The directors' remuneration report covers all directors, both executive and non-executive, and is set out on pages 116-125.

It is divided into two parts. Executive directors' remuneration is in the first part, which was prepared by the remuneration committee.

Non-executive directors' remuneration is in the second part,

which was prepared by the company secretary on behalf of the board.

The report has been approved by the board and signed on its behalf by the company secretary. This report is subject to the approval of shareholders at the annual general meeting (AGM).

Part 1 – Executive directors' remuneration

Dear Shareholder

2004 was a good year. Company results, as explained elsewhere, were excellent and the remuneration committee's priority on relating pay to performance is reflected in the annual bonus payments commensurate with this high level of achievement. These and all other aspects of the executive directors' remuneration during the year are set out in detail in the committee's report that follows.

The committee also undertook a comprehensive and independent review of remuneration policy for the executive directors during 2004, prior to seeking your approval for the renewal of the long-term incentive plan at this year's AGM (resolution 23). As part of this review, we commissioned significant and wide-ranging academic research and sought the views of major shareholders in an effort to consider the fundamental bases underlying our remuneration policies and practices. The depth and extensive nature of this review have meant that our policy and practices are underpinned by a strong set of principles, which guide the committee's deliberations. Full details of these are set out in the report.

Measures of performance lie at the heart of any performance-based system and we have, with extensive advice and considerable time, examined different approaches. While there is no perfect measure, we believe the selected quantitative and qualitative measures are the most appropriate for BP. Given the inherent imperfections of any measure of performance, we also see the use of our judgement as an integral part of the process. We recognize that our relationship with you is built on trust, and we are clear that it is important for us to be transparent in our explanations to you of how we have reached decisions and exercised our discretion.

We have an excellent team of world-class executive directors leading the company. The remuneration decisions we have taken for 2004 appropriately reflect the high level of performance achieved during the year. The policy we have set out for the future should continue to align their remuneration with shareholders' interests as well as to engage them in pursuing long-term shareholder value.

Sir Robin Nicholson Dr D S Julius 7 February 2005

Chairman, Remuneration Committee Chairman elect, Remuneration Committee

The remuneration committee

Tasks The committee's tasks are:

To determine on behalf of the board the terms of engagement and remuneration of the group chief executive and the executive directors and to report on those to the shareholders.
To determine on behalf of the board matters of policy over which the company has authority relating to the establishment or operation of the company's pension scheme of which the executive directors are members.
To nominate on behalf of the board any trustees (or directors of corporate trustees) of such scheme.
To monitor the policies being applied by the group chief executive in remunerating senior executives other than executive directors.

Constitution and operation The committee members are all nonexecutive directors. Sir Robin Nicholson (chairman), Mr Davis, Dr Julius, Mr Knight and Sir Ian Prosser were members of the committee throughout the year, with Sir Tom McKillop and Mr Bryan joining them in November 2004. Sir Robin Nicholson and Mr Knight will both be

retiring at the 2005 AGM and Dr Julius will become the committee chairman. Each member is now subject to annual re-election as a director of the company. The board considers all committee members to be independent (see page 111). They have no personal financial interest, other than as shareholders, in the committee's decisions. The committee met seven times in the period under review. There was a full attendance record, except that Sir Ian Prosser and Mr Knight were each unable to attend one meeting. Mr Sutherland, as chairman of the board, has attended all committee meetings.

The committee is accountable to shareholders through its annual report on executive directors' remuneration. It will consider the outcome of the vote at the AGM on the remuneration report, and the views of shareholders will be taken into account by the committee in its future decisions. The committee values its dialogue with major shareholders on remuneration matters.

Advice Advice is provided to the committee by the company secretary's office, which is independent of executive management and reports to the chairman of the board. Mr Aronson, an independent consultant, is the committee's secretary and special adviser. Advice was also received from Mr Jackson (company secretary) and Mrs Martin (senior counsel, company secretary's office).

The committee also appoints external professional advisers to provide specialist advice and services on particular remuneration matters. The independence of advice is subject to annual review.

In 2004, the committee consulted three independent academics, Michael Jensen, professor emeritus of Harvard Business School, and professors Sir Andrew Likierman and James Dow, both of London Business School, in connection with its fundamental review of remuneration policy.

The committee appointed Towers Perrin as its principal external adviser during 2004. Towers Perrin also provided limited ad hoc remuneration and benefits advice to parts of the group, mainly comprising pensions advice in Canada, as well as providing some market information on pay structures. The committee also appointed Kepler Associates to advise on performance measurement. Kepler Associates also provided performance data and limited ad hoc advice on performance measurement to the group.

Freshfields Bruckhaus Deringer and Martin Moore, QC, have provided legal advice on specific matters to the committee. Freshfields Bruckhaus Deringer also provided some legal advice, principally overseas, to subsidiaries in the group.

Ernst & Young, in their capacity as auditors, reviewed the calculations in respect of financial-based targets that form the basis of the performance-related pay for the executive directors. They also provided audit, audit-related and taxation services to the group.

Lord Browne (group chief executive) was consulted on matters relating to the other executive directors who report to him and, together with Dr Allen (group chief of staff), on matters relating to the performance of the company. Neither was present when matters affecting his own remuneration were considered.

Policy on executive directors' remuneration

A key priority for the committee in 2004 has been its comprehensive and independent review of all elements of remuneration policy for executive directors prior to seeking specific shareholder approval for renewal of the Executive Directors' Incentive Plan, which expires in 2005. This wide-ranging review sought to address the fundamental bases of the remuneration policies and plans for the executive directors. It involved significant academic research as well as seeking the views of plan participants, major shareholders and professional advisers. The committee focused on seeking to ensure that, in determining remuneration policy, there is a clear link between the company's purpose, the business plans and executive reward.

As part of its review, the committee developed the following key principles to guide its policy:

Policy for the remuneration of executive directors shall be determined and regularly reviewed independently of executive management and will set the tone for the remuneration of other senior executives.
The remuneration structure shall support and reflect BP's stated purpose to maximize long-term shareholder value.
The remuneration structure shall reflect a just system of rewards for the participants.
The overall quantum of all potential remuneration components shall be determined by the exercise of informed judgement of the independent remuneration committee, taking into account the success of BP and the competitive global market.
The majority of the remuneration shall be linked to the achievement of demanding performance targets that are independently set and reflect the creation of long-term shareholder value.
Assessment of performance shall be quantitative and qualitative and shall include exercise of informed judgement by the remuneration committee within a framework that takes account of sector characteristics and is approved by shareholders.
The committee shall be proactive in obtaining an understanding of shareholder preferences.
Remuneration policy and practices shall be as transparent as possible both for participants and shareholders.

Key policy decisions The committee then reviewed the existing remuneration policies and plans against these principles and made the following key policy decisions:

The overall quantum of remuneration and the general balance between short-term and long-term elements are to be maintained.
Salary levels will continue to be reviewed regularly by reference to those in Europe-based top global companies and the US oil and gas sector applying the committee's judgement.
The long-term incentives framework of the existing Executive Directors' Incentive Plan (EDIP) remains sound, although some changes to policy and application are now appropriate. Specific shareholder approval is being sought for renewal of the EDIP for a further five years.
The share element of the EDIP will provide the long-term performance-based component of the executive directors' remuneration package. There is no current intention to make further share options grants.
The majority of the value previously attributed to share options is to be redistributed to the share element, with the remainder going to the annual bonus.
The measure of long-term performance for the share element will be relative total shareholder return (TSR) compared with the other oil majors over three-year periods, with underlying relative performance also being assessed by the committee.
A proportion of the share element for the current group chief executive will be based on long-term personal leadership measures.
To simplify the operation of the EDIP and increase transparency, the share element will use performance shares rather than the current performance units and multiples.
The performance shares will accrue dividends during the performance period.
The current shareholding requirement for executive directors is to be maintained at 5 x the director's base salary, to ensure alignment of their interests with those of shareholders.
The current pension approach based on national policies is to be maintained.
The wider scene, including pay and employment conditions elsewhere in the group, will be taken into account, especially when determining annual salary increases.

Elements of remuneration The executive directors' total remuneration will continue to consist of salary, annual bonus, long-term incentives, pensions and other benefits. This reward structure will be regularly reviewed by the committee to ensure that it is achieving its objectives. In 2005, over three-quarters of executive directors' potential direct remuneration will again be performance-related (see illustrative chart on page 118).

This chart reflects on-target values for annual bonus and share element.

Salary The committee expects to review salaries in 2005. In doing so, the committee considers both Europe-based top global companies and the US oil and gas sector; each of these groups is defined and analysed by the committee's independent external remuneration advisers. The committee then assesses the market information and advice and applies its judgement in setting the salary levels.

Annual bonus Each executive director is eligible to participate in an annual performance-based bonus scheme. The committee reviews and sets bonus targets and levels of eligibility annually.

For 2005, the target level will be increased from 100% to 120% of base salary (except for Lord Browne, for whom, as group chief executive, it is considered appropriate to increase his target from 110% to 130%). These increases reflect part of the value previously attributed to the share option element of their remuneration packages. In normal circumstances, the maximum payment level for substantially exceeding targets will continue to be 150% (165% for the group chief executive) of base salary. In exceptional circumstances, outstanding performance may be recognized by bonus payments moderately in excess of the 150% (and 165%) levels at the discretion of the remuneration committee. Similarly, bonuses may be reduced where the committee considers that this is warranted and, in exceptional circumstances, bonuses can be reduced to zero.

The committee recognizes that it is responsible to shareholders to use its discretion in a reasonable and informed manner in the best interests of the company and that it has a corresponding duty to be accountable and transparent as to the manner in which it exercises its discretion. The committee will explain any significant exercise of discretion in the subsequent directors' remuneration report.

The key aim of the revised annual bonus is to ensure that it is closely tied to the annual business plan and that it reflects short-term deliverables towards the creation of long-term shareholder value.

Executive directors' annual bonus awards for 2005 will be based on a mix of demanding financial targets, based on the company's annual plan and leadership objectives established at the beginning of the year, in accordance with the following weightings:

50% financial measures from the annual plan principally on cash flow.
30% annual strategic metrics and milestones taken from the five-year group business plan. There is a wide range of measures, including those relating to people, safety, environment, technology and organization, as well as operational actions and business development.
20% individual performance against leadership objectives and living the values of the group which incorporates BP's code of conduct.

In assessing the final outcome of the individual bonuses each year, the committee will also carefully review the underlying performance of the group in the context of the five-year group business plan, as well as looking at competitor results, analysts' reports and the views from the chairmen of other BP board committees. All the calculations are reviewed by the auditors.

Long-term incentives Long-term incentives will continue to be provided under the EDIP. It will continue to have within its framework three elements: a share element, a share option element and a cash element. The committee does not currently intend to use either the share option or cash elements but, in exceptional circumstances, may do so.

Each executive director participates in the EDIP. The committee's policy, subject to unforeseen circumstances, is that this should continue until the EDIP expires or is renewed in 2010.

The committee's policy continues to be that each executive director should hold shares equivalent in value to 5 x the director's base salary within five years of being appointed an executive director. This policy is reflected in the terms of the EDIP, as shares awarded under the share element will only be released at the end of the three-year retention period (as described below) if the minimum shareholding guidelines have been met.

Share element The committee may make conditional share awards (performance shares) to executive directors, which will only vest to the extent that a demanding performance condition imposed by the committee is met at the end of a three-year performance period. As explained above, for 2005 and future years, the committee currently intends that the share element alone will provide the long-term performance-based component of the executive directors' package, and award levels have been adjusted to reflect this.

Share element awards have been made in 2001 to 2004 inclusive using performance units that may convert into ordinary shares at a ratio of up to two shares for each performance unit (full details of which are set out on page 123). To simplify the operation of the plan and increase transparency, the award of performance shares will, for 2005 and future years, replace performance units. Vesting of performance shares will be at a maximum ratio of one-for-one. This change will not increase the value of the award levels or make performance conditions easier to achieve.

The maximum number of performance shares that may be awarded to an executive director in any one year will be determined at the discretion of the remuneration committee and will not normally exceed 5.5 x base salary and, in the case of the group chief executive, 7.5 x base salary.

In addition to the performance condition described below, the committee will have an overriding discretion, in exceptional circumstances, to reduce the number of shares which vest (or to provide that no shares vest).

The shares which vest will normally be subject to a compulsory retention period determined by the committee, which will not normally be less than three years. This gives executive directors a six-year incentive structure, and is designed to ensure that their interests are aligned with those of shareholders. Where shares vest under awards made in 2005 and future years, the executive director will receive additional shares representing the value of reinvested dividends on these shares.

Timeline for 2005-2007 EDIP share element

For share element awards in 2005, the performance condition will relate to BP's total shareholder return (TSR) performance against the other oil majors (ExxonMobil, Shell, Total and ChevronTexaco) over a three-year period. TSR is calculated by taking the share price performance of a company over the period, assuming dividends to be reinvested in the company's shares. All share prices will be averaged over the three months before the beginning and end of the performance period and will be measured in US dollars. At the end of the performance period, the TSR performance of each of the companies will be ranked to establish the relative total return to shareholders over the period. Shares under the award will vest as to 100%, 70% and 35% if BP achieves first, second or third place respectively; no shares will vest if BP achieves fourth or fifth place.

Extensive research was independently commissioned by the committee into alternative measures of business performance. After careful review of the studies, the committee is satisfied that relative TSR is the most appropriate measure of performance for BP's longterm incentives for executive directors as it best reflects the creation of long-term shareholder value. Relative performance of the peer group is particularly key in order to minimize the influence of sector-specific effects, including oil price.

The committee is convinced that this comparator group, while small, has the distinct advantage of being very clearly comprised of BP's global competitors. Consultation with major shareholders confirmed that this is the group already used by most of them, as well as by management, in assessing BP's comparative performance. The committee will have the discretion to amend this peer group in appropriate circumstances, for example, in the case of any significant consolidations in the industry.

The committee is mindful of the possibility that a simple ranking system may in some circumstances give rise to distorted results in view of the broad similarity of the oil majors' underlying businesses, the small size of the comparator group and inherent imperfections in measurement. To counter this, the committee will have the ability to exercise discretion in a reasonable and informed manner to adjust (upwards or downwards) the vesting level derived from the ranking if it considers that the ranking does not fairly reflect BP's underlying business performance relative to the comparator group.

The exercise of this discretion would be made after a broad analysis of the underlying health of BP's business relative to competitors, as shown by a range of other measures including, but not limited to, return on average capital employed, earnings per share growth, reserves replacement and cash flow. This will enable a more comprehensive review of long-term performance, with the aims of tempering anomalies created by relying solely on a formula-based approach and ensuring that the objectives of the plan are met.

It is anticipated that the need to use discretion is most likely to arise where the TSR performance of some companies is clustered, so that a relatively small difference in TSR performance would produce a major difference in vesting levels. In these circumstances, the committee will have power to adjust the vesting level, normally

by determining an average vesting level for the companies affected by the clustering.

In line with its policy on transparency, the committee will explain any adjustment to the relative TSR ranking in the next directors' remuneration report following the vesting.

The committee may amend the performance conditions if events occur that would make the amended condition a fairer measure of performance and provided that any amended condition is no easier to satisfy.

For 2005, all executive directors will receive performance share awards on the above basis, over a maximum number of shares set by reference to 5.5 x base salary. For awards under the share element in future years, the committee may continue with the same performance condition, or may impose a different condition which it considers to be no less demanding.

As group chief executive, Lord Browne is eligible for performance share awards of up to 7.5 x base salary. The committee has determined that, while the largest part of this should relate to the TSR measure described above, it is appropriate that a specific part (up to 2 x base salary) should be based on long-term leadership measures. These will focus on sustaining BP's financial, strategic and organizational health and will include, but not be limited to, maintenance of BP's performance culture and the continued development of BP's business strategy, executive talent and internal organization. As with the TSR part of his award, this part will be measured over three-year performance periods.

Share element awards made in previous years

For outstanding awards of performance units made under the plans for the periods 2002-2004, 2003-2005 and 2004-2006, the existing performance conditions will apply for the three-year performance periods in each of the plans. The primary measure is BP's shareholder return against the market (SHRAM), which accounts for nearly twothirds of the potential total award, the remainder being assessed on BP's relative return on average capital employed (ROACE) and earnings per share growth (EPS).

BP's SHRAM is measured against the companies in the FTSE All World Oil & Gas Index. Companies within the index are weighted according to their market capitalization at the beginning of each three-year period in order to give greatest emphasis to oil majors. BP's ROACE and EPS growth are measured against ExxonMobil, Shell, Total and ChevronTexaco. All calculations are reviewed by the auditors to ensure that they meet an independent objective standard. The relative position of the company within the comparator group determines the number of shares awarded per performance unit, subject to a maximum of two shares per unit.

Share option element The share option element of the EDIP permits options to be granted to executive directors at an exercise price no lower than the market value of a share at the date the option is granted. The committee does not currently intend to use this element.
Cash element The cash element allows the committee to grant long-term cash-based incentives. This element was not used during the first five years of the EDIP and the committee would only do so in special circumstances.

Pensions Executive directors are eligible to participate in the appropriate pension schemes applying in their home countries. UK directors UK directors are members of the regular BP Pension Scheme. Scheme members' core benefits are non-contributory. They include a pension accrual of 1/60th of basic salary for each year of service, subject to a maximum of two-thirds of final basic salary; and a dependant's benefit of two-thirds of the member's pension. Bonuses are not pensionable for UK directors. The scheme pension is not integrated with state pension benefits.

Normal retirement age is 60, but scheme members who have 30 or more years' pensionable service at age 55 can elect to retire early without an actuarial reduction being applied to their pension.

In accordance with the company's past practice for executive directors who retire from BP on or after age 55 having accrued at least 30 years' service, Lord Browne remains eligible for consideration for a payment from the company of an ex-gratia lump-sum superannuation payment equal to one year's base salary following his retirement. All matters relating to such superannuation payments are considered by the remuneration committee. Any such payment would be additional to his pension entitlements referred to above. No other executive director is eligible for consideration for a superannuation payment on retirement, as the remuneration committee decided in 1996 that appointees to the board after that time should cease to be eligible for consideration for such a payment.

The UK government has announced important proposals on pensions, the impact of which will be reviewed further by the committee in 2005 in conjunction with studies being carried out by the company into the wider effects of the new legislation for employees. The intention is that the approach to the new legislation should be consistent for directors and other employees. The committee will report further on the outcome of these studies in the next remuneration report.

US director Dr Grote as a US director participates in the US BP Retirement Accumulation Plan (US plan), which features a cash balance formula. The current design of the US plan became effective on 1 July 2000.

Consistent with US tax regulations, pension benefits are provided through a combination of tax-qualified and non-qualified benefit restoration plans, as applicable.

The Supplemental Executive Retirement Benefit (supplemental plan) is a non-qualified top-up arrangement that became effective on 1 January 2002 for US employees above a specified salary level.

The benefit formula is 1.3% of final average earnings, which comprise base salary and bonus in accordance with standard US practice (as specified under the qualified arrangement) multiplied by years of service, with an offset for benefits payable under all other BP qualified and non-qualified pension arrangements. This benefit is unfunded and therefore paid from corporate assets.

Dr Grote is an eligible participant under the supplemental plan, and his pension accrual for 2004 includes the total amount that may become payable under all plans.

Other benefits

Benefits and other share schemes: Executive directors are eligible to participate in regular employee benefit plans and in all-employee share schemes and savings plans applying in their home countries. Benefits in kind are not pensionable.
Resettlement allowance: Expatriates may receive a resettlement allowance for a limited period.

Service contracts

Director	Contract date	Current salary
Lord Browne	11 November 1993	£1,415,600
Dr D C Allen	29 January 2003	£420,000
I C Conn	22 July 2004	£400,000
Dr B E Grote	7 August 2000	$900,000
Dr A B Hayward	29 January 2003	£420,000
J A Manzoni	29 January 2003	£420,000
Director leaving the board in 2004
R L Olver	31 December 1997

The committee's policy is for service contracts to expire at normal retirement date and have a notice period of one year. All contracts comply with this.

The service contracts of Dr Allen, Dr Hayward, Mr Manzoni and Mr Conn may also be terminated by the company at any time with immediate effect on payment in lieu of notice equivalent to one year's salary or the amount of salary that would have been paid if the contract had terminated on the expiry of the remainder of the notice period.

Dr Grote's service contract is with BP Exploration (Alaska) Inc. He is seconded to BP p.l.c. under a secondment agreement dated 7 August 2000 that had an unexpired term of three years at 31 December 2004. The secondment may be terminated by one month's notice by either party and terminates automatically on the termination of Dr Grote's service contract.

There are no other provisions for compensation payable on early termination of the above contracts. In the event of early termination under any of the above contracts by the company other than for cause (or under a specific termination payment provision), the relevant director's then current salary and benefits would be taken into account in calculating any liability of the company.

Since January 2003, the committee has included a provision in new service contracts to allow for severance payments to be phased, where appropriate to do so. It will also consider mitigation to reduce compensation to a departing director, where appropriate to do so.

Historical TSR performance

This graph is included to meet a legislative requirement and shows the growth in the value of a hypothetical £100 holding in BP p.l.c. ordinary shares over five years relative to the FTSE 100 and to the FTSE All World Oil & Gas Index. These are considered to be the most relevant broad equity market indices for this purpose and the company is a constituent of both indices.

Information subject to audit

Summary of 2004 remuneration

Annual remuneration						Long-term remuneration
						Share element of EDIP/LTPPs				Grants under EDIP
						2002-2004 plan		2001-2003 plan
						(to be awarded inFeb 2005)		(awarded inFeb 2004)		(granted inFeb 2004)
	Salary(thousand)2003	2004	2003	Annualperformance bonus(thousand)2004	Non-cash benefits& other emoluments(thousand)2003	2004	2003	Total(thousand)2004	Expectedawarda(shares)	Valueb(thousand)	Actualaward(shares)	Valuec(thousand)	2004-2006shareelementd(perform-ance units)	Shareoptionelemente(options)
Lord Browne	£1,316	£1,382	£1,882	£2,280	£79	£82	£3,277	£3,744	356,667	£1,905	352,750	£1,457		634,447 1,500,000
Dr D C Allen	£367	£410	£459	£615	£2	£11	£828	£1,036	60,000	£320	62,518	£258	188,235	275,000
I C Connf	n/a	£200	n/a	£300	n/a	£42	n/a	£542	51,750	£276	n/a	n/a	n/a	n/a
Dr B E Grote	$770	$841	$1,001	$1,262	$179g	–	$1,950	$2,103	136,960	$1,381	131,750	$1,053	212,669	349,998
Dr A B Hayward	£367	£410	£459	£615	£3	£36	£829	£1,061	55,125	£294	54,825	£226	188,235	275,000
J A Manzonih	£367	£410	£477	£615	£34	£46	£878	£1,071	60,000	£320	51,170	£211	188,235	275,000
Director leaving the board in 2004
R L Olveri	£570	£292	£741	£438	£43	£42	£1,354	£772	147,222	£786	144,500	£597	n/a	n/a

Amounts shown are in the currency received by executive directors. Annual bonus is shown in the year it was earned.

aGross award of shares based on a performance assessment by the remuneration committee and on the other terms of the plan. Sufficient shares are sold to pay

for tax applicable. Remaining shares are held in trust for current directors until 2008, when they are released to the individual. bBased on closing price of BP shares on 3 February 2005 (£5.34 per share/$60.49 per ADS). cBased on average market price on date of award (£4.13 per share/$47.96 per ADS). dPerformance units granted under the 2004-2006 share element of the EDIP are converted to shares at the end of the performance period. Maximum of two shares per performance unit.

eOptions granted in February 2004 have a grant price of £4.22 per share. Dr Grote holds options over ADSs; the above numbers reflect calculated equivalents. f Reflects remuneration received by Mr Conn since appointment as executive director on 1 July 2004. gIncludes resettlement allowance for Dr Grote of $175,000, which expired in 2003.

hMr Manzoni also received compensation of £50,000 in 2004 relating to expatriate costs prior to his appointment as an executive director. i Amounts for Mr Olver reflect the period until his retirement on 1 July 2004.

2004 actual remuneration elements

Base salary

Performance-related annual bonus
Performance-related long-term incentives include a share element and share options

This chart reflects the average mix of total remuneration received by executive directors in 2004 and includes actual salary, bonus and share element award as well as a Black Scholes value of options granted.

Salary Following a review of appropriate comparator groups of Europe-based top global companies and the US oil and gas sector, base salaries for Lord Browne, Dr Allen, Dr Hayward and Mr Manzoni were increased by 5% per annum with effect from 1 July 2004. On his appointment to the board in 2004, Mr Conn's salary was determined by reference to the same comparator groups.

In deciding upon these new salary levels the committee applied its judgement, taking into account the modest market movements in Europe and the US and the fact that no salary increases had been received by the three executive directors appointed in February 2003 since that time.

Dr Grote's salary was increased in the context of the comparative market information by approximately 15% with effect from 1 July 2004 to reflect his expanded senior role following the retirement of Mr Olver.

Annual bonus Fifty per cent of the annual bonus awards for 2004 is based on a mix of financial targets (primarily cash from operations) and 50% is based on long-run metrics and wide-ranging milestones that drive performance improvement and measure the continuing delivery of strategy (including production and sales levels, efficiency, cost management, business development, project delivery and technology progress). All the targets were established at the beginning of the year by the remuneration committee. 2004 was an extremely good year. The group met or exceeded its annual plan in all material respects. The primary financial target, cash from operations, was exceeded. All the key metrics and milestones were delivered, along with some notable successes in relation to Russia and exploration in Egypt and the Gulf of Mexico. Assessment of all the results, including those on people, safety, environment and organization, resulted in awards of 150% of salary for the executive directors. The committee determined that, given the year's excellent performance, it was appropriate that Lord Browne receive 165% of salary, reflecting his higher bonus target level. All calculations have been reviewed by the auditors.

	Option type	At 1 Jan 2004	Granted	Exercised	At 31 Dec 2004	Option price	Market priceat date ofexercise	Date fromwhich firstexercisable	Expiry date
Lord Browne	SAYE	4,550	--	–	4,550	£3.50	–	1 Sept 2008	28 Feb 2009
	EDIP	408,522	--	–	408,522	£5.99	–	15 May 2001	15 May 2007
	EDIP	1,269,843	–	–	1,269,843	£5.67	–	19 Feb 2002	19 Feb 2008
	EDIP	1,348,032	–	–	1,348,032	£5.72	–	18 Feb 2003	18 Feb 2009
	EDIP	1,348,032	–	–	1,348,032	£3.88	–	17 Feb 2004	17 Feb 2010
	EDIP	–	1,500,000	–	1,500,000	£4.22	–	25 Feb 2005	25 Feb 2011
Dr D C Allen	EXEC	37,000	–	–	37,000	£5.99	–	15 May 2003	15 May 2010
	EXEC	87,950	–	–	87,950	£5.67	–	23 Feb 2004	23 Feb 2011
	EXEC	175,000	–	–	175,000	£5.72	–	18 Feb 2005	18 Feb 2012
	EDIP	220,000	–	–	220,000	£3.88	–	17 Feb 2004	17 Feb 2010
	EDIP	–	275,000	–	275,000	£4.22	–	25 Feb 2005	25 Feb 2011
Dr B E Grotea	SAR	40,800	–	40,800	–	$16.63	$48.67	25 Mar 1997	25 Mar 2004
	SAR	35,600	–	35,600	–	$19.16	$61.60	28 Feb 1998	28 Feb 2005
	SAR	35,200	–	–	35,200	$25.27	–	6 Mar 1999	6 Mar 2006
	SAR	40,000	–	–	40,000	$33.34	–	28 Feb 2000	28 Feb 2007
	BPA	10,404	–	–	10,404	$53.90	–	15 Mar 2000	14 Mar 2009
	BPA	12,600	–	–	12,600	$48.94	–	28 Mar 2001	27 Mar 2010
	EDIP	40,182	–	–	40,182	$49.65	–	19 Feb 2002	19 Feb 2008
	EDIP	58,173	–	–	58,173	$48.82	–	18 Feb 2003	18 Feb 2009
	EDIPEDIP	58,173–	–58,333	––	58,17358,333	$37.76$48.53	––	17 Feb 200425 Feb 2005	17 Feb 201025 Feb 2011

Dr A B Hayward	SAYE	3,302	–	–	3,302	£5.11	–	1 Sept 2006	28 Feb 2007
	EXEC	34,000	–	–	34,000	£5.99	–	15 May 2003	15 May 2010
	EXEC	77,400	–	–	77,400	£5.67	–	23 Feb 2004	23 Feb 2011
	EXECEDIP	160,000220,000	––	––	160,000220,000	£5.72£3.88	––	18 Feb 200517 Feb 2004	18 Feb 201217 Feb 2010
	EDIP	–	275,000	–	275,000	£4.22	–	25 Feb 2005	25 Feb 2011

J A Manzoni	SAYE	750	–	750	–	£4.50	£5.04	1 Sept 2004	28 Feb 2005
	SAYE	878	–	–	878	£4.52	–	1 Sept 2007	28 Feb 2008
	SAYESAYE	2,548–	–847	––	2,548847	£3.50£3.86	––	1 Sept 20081 Sept 2009	28 Feb 200928 Feb 2010
	EXEC	12,000	–	–	12,000	£2.04	–	28 Feb 1998	28 Feb 2005
	EXEC	34,000	–	–	34,000	£5.99	–	15 May 2003	15 May 2010
	EXEC	72,250	–	–	72,250	£5.67	–	23 Feb 2004	23 Feb 2011
	EXEC	175,000	–	–	175,000	£5.72	–	18 Feb 2005	18 Feb 2012
	EDIP	220,000	–	–	220,000	£3.88	–	17 Feb 2004	17 Feb 2010
	EDIP	–	275,000	–	275,000	£4.22	–	25 Feb 2005	25 Feb 2011
Director appointed to the board in 2004
I C Conn	SAYE	1,050b	–	1,050	–	£4.50	£5.04	1 Sept 2004	28 Feb 2005
	SAYE	1,355b	–	–	1,355	£4.98	–	1 Sept 2005	28 Feb 2006
	SAYE	1,456b	–	–	1,456	£3.50	–	1 Sept 2008	28 Feb 2009
	SAYE	–	1,186	–	1,186	£3.86	–	1 Sept 2009	28 Feb 2010
	EXEC	900b	–	–	900	£5.67	–	23 Feb 2004	23 Feb 2011
	EXEC	71,350b4,356b	–	–	71,350	£5.67	–	23 Feb 2004	23 Feb 2011
	EXEC	125,644b	–	–	4,356	£5.72	–	18 Feb 2005	18 Feb 2012
	EXECEXEC	160,000b	––	––	125,644160,000	£5.72£3.88	––	18 Feb 200517 Feb 2006	18 Feb 201217 Feb 2013
	EXEC	126,000b	–	–	126,000	£4.22	–	25 Feb 2007	25 Feb 2014
Director leaving the board in 2004
R L Olver	SAYE	2,642	–	–	2,642c	£3.50	–	1 Sept 2006	28 Feb 2007
	EDIP	71,847	–	–	71,847c	£5.99	–	15 May 2001	15 May 2007
	EDIP	260,319	–	–	260,319c	£5.67	–	19 Feb 2002	19 Feb 2008
	EDIP	370,956	–	–	247,304c,d	£5.72	–	18 Feb 2003	18 Feb 2009
	EDIP	370,956	–	–	123,652c,d	£3.88	–	17 Feb 2004	17 Feb 2010

The closing market prices of an ordinary share and of an ADS on 31 December 2004 were £5.08 and $58.40 respectively. During 2004, the highest market prices were £5.56 and $62.10 respectively, and the lowest market prices were £4.13 and $46.65 respectively.

EDIP – 400,000 – –c,d £4.22–––

EDIP = Executive Directors' Incentive Plan adopted by shareholders in April 2000 as described on pages 118-119. The grants were made taking into consideration the ranking of the company's TSR against the TSR of the FTSE Global 100 group of companies over the three-year period prior to the grant. BPA = BP Amoco share option plan, which applied to US executive directors prior to the adoption of the EDIP.

SAR = Stock Appreciation Rights under BP America Inc. Share Appreciation Plan. In keeping with the US market practice, none of the options under the BPA and SAR is subject to performance conditions because they were granted under American plans to the relevant individuals.

SAYE = Save As You Earn employee share option scheme. These options are not subject to performance conditions because this is an all-employee share scheme governed by specific tax legislation.

EXEC = Executive Share Option Scheme. These options were granted to the relevant individuals prior to their appointments as directors and are not subject to performance conditions.

aNumbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.

bOn appointment to the board of BP p.l.c. on 1 July 2004.

cOn leaving the board of BP p.l.c. on 1 July 2004.

Share options

dRemaining options after deduction of those that lapsed on retirement.

Share element of EDIP and Long Term Performance Plans (LTPPs)

Under the share element of the EDIP and the Long Term Performance Plans, performance units were granted at the beginning of the threeyear period and converted into an award of shares at the end of the period, depending on performance. There is a maximum of two shares per performance unit. For 2005 and future years, a different grant mechanism will apply (as described on page 118).

For the 2002-2004 share element of the EDIP and the LTPPs, BP's performance was assessed in terms of SHRAM, ROACE and EPS

growth. BP's three-year SHRAM was measured against the companies in the FTSE All World Oil & Gas Index. Companies within the index are weighted according to their market capitalization at the beginning of each three-year period in order to give greatest emphasis to oil majors. BP's ROACE and EPS were measured against ExxonMobil, Shell, Total and ChevronTexaco. Based on a performance assessment of 75 points out of 200 (0 for SHRAM, 50 for ROACE and 25 for EPS growth), the committee expects to make awards of shares to executive directors as highlighted in the 2002-2004 lines of the table below.

Share element of EDIP and LTPPs

					Share element/LTPP interests		Interests vested in 2004
	Performanceperioda	Date ofgrant ofperformanceunits	Market priceof each shareat date of grantof performanceunits£	At 1 Jan2004	Performance unitsbGranted2004	At 31 Dec2004	Numberof ordinarysharesawardedc	Share awarddate	Market priceof each shareat shareaward date£
Lord Browne	2001–20032002–20042003–20052004–2006	19 Feb 200118 Feb 200217 Feb 200325 Feb 2004	5.805.733.964.25	415,000475,556632,512–	–––634,447	–475,556632,512634,447	352,750356,667––	12 Feb 2004––	4.13expected award Feb 2005––
Dr D C Allen	2001–20032002–20042003–20052004–2006	12 Mar 20016 Mar 200217 Feb 200325 Feb 2004	5.885.993.964.25	73,55080,000197,044–	–––188,235	–80,000197,044188,235	62,51860,000––	12 Feb 2004––	4.13expected award Feb 2005––
Dr B E Grote	2001–20032002–20042003–20052004–2006	19 Feb 200118 Feb 200217 Feb 200325 Feb 2004	5.805.733.964.25	155,000182,613233,638–	–––212,669	–182,613233,638212,669	131,750136,960––	12 Feb 2004––	4.13expected award Feb 2005––
Dr A B Haywardd	2001–20032002–20042003–20052004–2006	12 Mar 20016 Mar 200217 Feb 200325 Feb 2004	5.885.993.964.25	64,50073,500197,044–	–––188,235	–73,500197,044188,235	54,82555,125––	12 Feb 2004––	4.13expected award Feb 2005––
J A Manzonid	2001–20032002–20042003–20052004–2006	12 Mar 20016 Mar 200217 Feb 200325 Feb 2004	5.885.993.964.25	60,20080,000197,044–	–––188,235	–80,000197,044188,235	51,17060,000––	12 Feb 2004––	4.13expected award Feb 2005––
Director appointed to the board in 2004
I C Conn	2001–20032002–20042003–20052004–2006	12 Mar 20016 Mar 200217 Feb 200325 Feb 2004	5.885.993.964.25	60,200e69,000e91,000e–	–––91,000	–69,00091,00091,000	51,17051,750––	12 Feb 2004––	4.13expected award Feb 2005––
Director leaving the board in 2004
R L Olver	2001–20032002–20042003–2005	19 Feb 200118 Feb 200217 Feb 2003	5.805.733.96	170,000196,296274,138	–––	–196,296f274,138f	144,500147,222–	12 Feb 2004–	4.13expected award Feb 2005–
Past directors
R F Chase	2001–20032002–20042002–2004	19 Feb 200118 Feb 200213 Mar 2002	5.805.736.17	205,000237,03734,994	–––	–237,03734,994	174,250177,77826,245	12 Feb 2004	4.13expected award Feb 2005expected award Feb 2005
Dr J G S Buchanan 1998-2000	2001-20032002-20042002-2004	5 Feb 199819 Feb 200118 Feb 200213 Mar 2002	4.055.805.736.17	159,000165,000192,59328,433	––––	192,59328,433	351,453g140,250144,44521,325	12 Feb 200412 Feb 2004	4.134.13expected award Feb 2005expected award Feb 2005
W D Ford	2001–2003	19 Feb 2001	5.80	170,000	–	–	144,500	12 Feb 2004	4.13

aDr Allen, Dr Hayward and Mr Manzoni continue to have performance units for the performance periods 2001-2003 and 2002-2004 granted under LTPPs, and Mr Conn for the periods 2001-2003 to 2004-2006 inclusive. They are not required to relinquish these rights, which were granted prior to their appointments as executive directors. All other units were granted under the EDIP as explained on pages 118-119. BP's performance is assessed against the oil sector. For 1998-2000, BP's SHRAM was measured against ExxonMobil, Shell, Total and ChevronTexaco. For 2001-2003, BP's SHRAM, ROACE and EPS growth were measured against ExxonMobil, Shell, Total, ChevronTexaco, ENI and Repsol. For 2004-2006, BP's SHRAM is measured against companies in the All World Oil & Gas Index and BP's ROACE and EPS growth against ExxonMobil, Shell, Total and ChevronTexaco. Each performance period ends on 31 December of the third year.

bRepresents number of performance units, each having a maximum potential of two shares depending on performance. cRepresents awards of shares made or expected to be made at the end of the relevant performance period based on performance achieved under rules of the plan. dDr Hayward and Mr Manzoni elected to defer to 2005 the determination of whether LTPP awards should be made for the 1999-2001 performance period.

As this period ended prior to their appointment as directors, the expected awards are not included in the table. eOn appointment to the board of BP p.l.c. on 1 July 2004.

f On leaving the board of BP p.l.c. on 1 July 2004.

gDr Buchanan elected to defer to 2004 the determination of whether an award should be made for the 1998-2000 period. This number includes dividends.

Pensions

thousand	Service at31 Dec 2004	Accruedpension entitlementat 31 Dec 2004	Additional pensionearned during the yearended 31 Dec 2004	Transfer value ofaccrued benefitaat 31 Dec 2003 (A)	Transfer value ofaccrued benefitaat 31 Dec 2004 (B)	Amount of B-A lesscontributions made bythe director in 2004
Lord Browne (UK)	38 years	£944	£45	£13,921	£15,189	£1,268
Dr D C Allen (UK)	26 years	£183	£15	£2,089	£2,264	£175
I C Conn (UK)	19 years	£127	£35	£849	£1,217	£368
Dr B E Grote (US)	25 years	$465	$94	$4,814	$5,529	$715
Dr A B Hayward (UK)	23 years	£188	£18	£1,967	£2,255	£288
J A Manzoni (UK)	21 years	£149	£14	£1,395	£1,595	£200
Director leaving the board in 2004
R L Olver (UK)b	31 years	£390	–	£6,271	£9,098	£2,827

aTransfer values have been calculated in accordance with version 8.1 of guidance note GN11 issued by the actuarial profession. bMr Olver retired on 1 July 2004 and elected to take a lump sum of £905,194 in lieu of part of his entitlement. The figures in the table include the allowance for this lump sum.

Past directors

Following his retirement from BP p.l.c., Mr Olver was appointed on 1 July 2004 as a consultant to BP in relation to its activities in Russia. He had previously been appointed as a BP-nominated director of TNK-BP Limited, a joint venture company owned 50% by BP, effective 20 April 2004. Under the consultancy agreement, he received £150,000 in fees in 2004 and, as a director, deputy chairman and chairman of the audit committee of the joint venture company, he received $90,000 in fees from TNK-BP Limited.

Mr Chase's consultancy to BP in relation to the TNK-BP transaction ended in May 2004 and he left the board of TNK-BP Limited in March 2004. Under the consultancy agreement, he received $250,000 in 2004 and as a director, deputy chairman and chairman of the audit committee of TNK-BP Limited he received $30,000 in fees from that company.

Long-term awards for both former directors of BP p.l.c. are in accordance with scheme rules and are outlined in the table on page 123.

Part 2 – Non-executive directors' remuneration

Policy on non-executive directors' remuneration

The board sets the level of remuneration for all non-executive directors within the limit approved from time to time by shareholders. In line with BP's governance policies, by the remuneration of the chairman is set by the board rather than by the remuneration committee, since the performance of the chairman is a matter for the board as a whole rather than any one committee.

The board has adopted the following policies to guide its current and future decision-making with regard to non-executive directors' remuneration.

Within the limits set by the shareholders from time to time, remuneration should be sufficient to attract, motivate and retain world-class non-executive talent.
Remuneration of non-executive directors is set by the board and should be proportional to their contribution towards the interests of the company.
Remuneration practice should be consistent with recognized best-practice standards for non-executive directors' remuneration.
Remuneration should be in the form of cash fees, payable monthly.
Non-executive directors should not receive share options from the company.

• Non-executive directors should be encouraged to establish a holding in BP shares broadly related to one year's base fee, to be held directly or indirectly in a manner compatible with their personal investment activities, and any applicable legal and regulatory requirements.

Elements of remuneration

Non-executive directors' pay comprises cash fees, paid monthly, with increments for positions of additional responsibility, reflecting additional workload and consequent potential liability. For all nonexecutive directors, except the chairman, a fixed sum allowance is paid for transatlantic travel undertaken for the purpose of attending a board or board committee meeting. In addition, nonexecutive directors receive reimbursement of reasonable travel and related business expenses. No share or share option awards are made to any non-executive director in respect of service on the board.

Letters of appointment

Non-executive directors have letters of appointment, which recognize that, subject to the Articles of Association, their service is at the discretion of the shareholders. All directors stand for re-election at each annual general meeting.

Non-executive directors' annual fee structure

The fees paid to non-executive directors are set by the board within the limit set by shareholders in accordance with the Articles. Shareholders approved an increase to this limit at the 2004 AGM. All fees are fixed and paid in pounds sterling. Fees payable to non-executive directors were last adjusted during 2002.

	£ thousand
Chairman	390a
Deputy chairman	85b
Board member	65
Committee chairmanship fee	15
Transatlantic attendance allowancec	5

a The chairman is not eligible for committee chairmanship fees or transatlantic attendance allowance but has the use of a fully maintained office for company business and a chauffeured car.

b The deputy chairman receives a £20,000 increment on top of the standard board fee. In addition, he is eligible for committee chairmanship fees and the transatlantic attendance allowance. The deputy chairman is currently chairman of the audit committee.

c This allowance is payable to non-executive directors undertaking transatlantic travel for the purpose of attending a board meeting or board committee meeting.

Long-term incentives (residual)

The table in the right-hand column sets out the residual entitlements of non-executive directors who were formerly non-executive directors of Amoco Corporation under the Amoco Non-Employee Directors' Restricted Stock Plan.

Information subject to audit

£ thousand

Current directors	2004	2003
J H Bryan	100	95
A Burgmansa	53	n/a
E B Davis, Jr	105	90
Dr D S Julius	75	80
C F Knight	90	95
Sir Tom McKillopb	38	n/a
Dr W E Massey	115	110
H M P Miles	75	80c
Sir Robin Nicholsond	90	95
Sir Ian Prosser	110	115
P D Sutherland	390	390
M H Wilson	95	95
Director leaving the board in 2004
F A Maljerse	16	80

a Appointed on 5 February 2004.

b Appointed on 1 July 2004.

c Also received £600 in 2003 for serving as a director of BP Pension Trustees

Limited. These fees are no longer payable to BP non-executive directors. d Also received £20,000 each year for serving as the board's representative

on the BP technology advisory council. e Retired at AGM on 15 April 2004.

Amoco Non-Employee Directors' Restricted Stock Plan

Non-executive directors of Amoco Corporation were allocated restricted stock in the Amoco Non-Employee Directors' Restricted Stock Plan by way of remuneration for their service on the board of Amoco Corporation prior to its merger with BP in 1998. On merger, interests in Amoco shares in the plan were converted into interests in BP ADSs. Under the terms of the plan, the restricted stock will vest upon the retirement of the non-executive director having reached age 70 or upon earlier retirement at the discretion of the board. Since the merger, no further entitlements have accrued to any director under the plan. These residual interests require disclosure under the directors' remuneration report regulations 2002 as interests in a long-term incentive scheme.

	Interest in BP ADSsat 1 January 2004 and31 December 2004a	Date onwhich directorreaches age 70b
J H Bryan	5,546	5 October 2006
E B Davis, Jr	4,490	5 August 2014
Dr W E Massey	3,346	5 April 2008
M H Wilson	3,170	4 November 2007
Director leaving the board in 2004
F A Maljersc	2,906	12 August 2003

a No awards were granted and no awards lapsed during the year. b For the purposes of the regulations, the date on which the director retires from the board at or after the age of 70 is the end of the qualifying period.

If the director retires prior to this date, the board may waive the restrictions. c Mr Maljers retired from the board on 15 April 2004 and, in accordance with the terms of the plan, his awards vested on that date (when the BP ADS closing price was $54.16) without payment by him. These awards over BP ADSs derived from awards over Amoco shares granted between 26 April 1994 and 28 April 1998. The awards were granted over Amoco stock prior to the merger but their notional weighted average market value at the date of grant (applying the subsequent merger ratio of 0.66167 of a BP ADS for every Amoco share) was $27.87 per BP ADS.

Superannuation gratuities

In accordance with the company's long-standing practice, nonexecutive directors who retire from the board after at least six years' service are, at the time of their retirement, eligible for consideration for a superannuation gratuity. The board is authorized to make such payments under the company's Articles. The amount of the payment is determined at the board's discretion (having regard to the director's period of service as a director and other relevant factors).

In 2002, the board revised its policy with respect to such payments so that: (i) non-executive directors appointed to the board after 1 July 2002 would not be eligible for consideration for such a payment; and (ii) while non-executive directors in service at 1 July 2002 would remain eligible for consideration for a payment, service after that date would not be taken into account by the board in considering the amount of any such payment.

The board made no superannuation gratuity payments during the year.

This directors' remuneration report was approved by the board and signed on its behalf by David J Jackson, company secretary, on 7 February 2005.

Board of directors

Executive directors 1 The Lord Browne of Madingley, FREng Group Chief Executive

Lord Browne (56) joined BP in 1966 and subsequently held a variety of exploration and production and finance posts in the US, UK and Canada. He was appointed an executive director in 1991 and group chief executive in 1995. He is a non-executive director of Intel Corporation and Goldman Sachs. He was knighted in 1998 and made a life peer in 2001.

2 Dr D C Allen, Group Chief of Staff

David Allen (50) joined BP in 1978 and subsequently undertook a number of corporate and exploration and production roles in London and New York. He moved to BP's corporate planning function in 1986, becoming group vice president in 1999. He was appointed an executive vice president and group chief of staff in 2000 and an executive director of BP in 2003.

3 I C Conn, Group Executive Officer, Strategic Resources

Iain Conn (42) joined BP in 1986. Following a variety of roles in oil trading, refining, commercial marketing, exploration and production, in 2000 he became group vice president of BP's refining and marketing business. From 2002 to 2004, he was chief executive of petrochemicals. He was appointed group executive officer with a range of regional and functional responsibilities and an executive director in July 2004. He was appointed to the board of Rolls-Royce Group plc in January 2005.

4 Dr B E Grote, Chief Financial Officer

Byron Grote (56) joined BP in 1987 following the acquisition of The Standard Oil Company of Ohio, where he had worked since 1979. He became group treasurer in 1992 and in 1994 regional chief executive in Latin America. In 1999, he was appointed an executive vice president of exploration and production, and chief executive of chemicals in 2000. He was appointed an executive director of BP in 2000 and chief financial officer in 2002.

5 Dr A B Hayward, Chief Executive, Exploration and Production

Tony Hayward (47) joined BP in 1982. He became a director of exploration and production in 1997, the segment in which he had previously held a series of roles. In 2000, he was made group treasurer and an executive vice president in 2002. He was appointed chief operating officer for exploration and production in 2002 and an executive director of BP in 2003. He is a non-executive director of Corus Group.

6 J A Manzoni, Chief Executive, Refining and Marketing

John Manzoni (45) joined BP in 1983. He became group vice president for European marketing in 1999 and BP regional president for the eastern US in 2000. In 2001, he became an executive vice president and chief executive for gas and power. He was appointed chief executive of refining and marketing in 2002 and an executive director of BP in 2003. He is a non-executive director of SABMiller plc.

Non-executive directors 7 P D Sutherland, KCMG Chairman

Peter Sutherland (58) rejoined BP's board in 1995, having been a non-executive director from 1990 to 1993, and was appointed chairman in 1997. He is non-executive chairman of Goldman Sachs International and a non-executive director of Investor AB and The Royal Bank of Scotland Group plc.

Chairman of the chairman's and nomination committees

8 Sir Ian Prosser, Deputy Chairman

Sir Ian (61) joined BP's board in 1997 and was appointed non-executive deputy chairman in 1999. He retired as chairman of InterContinental Hotels Group PLC, previously Bass PLC, in 2003. He was a non-executive director of The Boots Company from 1984 to 1996, of Lloyds Bank PLC from 1988 to 1995 and of Lloyds TSB Group PLC from 1995 to 1999. In 1999, he was appointed a nonexecutive director of GlaxoSmithKline and in 2004 he was appointed a non-executive director of Sara Lee Corporation.

Member of the chairman's, nomination and remuneration committees and chairman of the audit committee

9 J H Bryan

John Bryan (68) joined BP's board in 1998, having previously been a director of Amoco. He serves on the boards of General Motors Corporation and Goldman Sachs. He retired as chairman of Sara Lee Corporation in 2001. He is chairman of Millennium Park Inc. in Chicago.

Member of the chairman's, remuneration and audit committees

10 A Burgmans

Antony Burgmans (58) joined BP's board in 2004. He was appointed to the board of Unilever in 1991. In 1999, he became chairman of Unilever NV and vice chairman of Unilever PLC. He is also a member of the supervisory board of ABN AMRO Bank NV.

Member of the chairman's and ethics and environment assurance committees

11 E B Davis, Jr

Erroll B Davis, Jr (60) joined BP's board in 1998, having previously been a director of Amoco. He is chairman and chief executive officer of Alliant Energy, a member of the advisory board of the Federal Reserve Bank of Chicago and a non-executive director of PPG Industries, Union Pacific Corporation and the US Olympic Committee.

Member of the chairman's, audit and remuneration committees

12 D J Flint

Douglas Flint (49) joined BP's board in January 2005. He trained as a chartered accountant and became a partner at KPMG in 1988. In 1995, he was appointed group finance director of HSBC Holdings plc. He is chairman of the Financial Reporting Council's review of the Turnbull Guidance on Internal Control. Between 2001 and 2004, he served on the Accounting Standards Board and the advisory council of the International Accounting Standards Board.

13 Dr D S Julius, CBE

DeAnne Julius (55) joined BP's board in 2001. She began her career as a project economist with the World Bank in Washington. From 1986 until 1997, she held a succession of posts, including chief economist at British Airways and Royal Dutch Shell Group. From 1997 to 2001, she was a full-time member of the Monetary Policy Committee of the Bank of England. She is chairman of the Royal Institute of International Affairs and a non-executive director of Lloyds TSB Group PLC, Serco and Roche Holdings SA.

Member of the chairman's and remuneration committees and chairman elect of the remuneration committee

14 C F Knight

Charles Knight (69) joined BP's board in 1987. He was employed by Lester B Knight and Associates of Chicago, consulting engineers, from 1961 to 1973. In 1972, he joined Emerson Electric Co., became chairman in 1974 and retired in 2004. He is a nonexecutive director of Anheuser-Busch, Morgan Stanley Dean Witter, SBC Communications and IBM.

Member of the chairman's and remuneration committees

15 Sir Tom McKillop

Sir Tom McKillop (61) joined BP's board in July 2004. Sir Tom was appointed chief executive of AstraZeneca PLC after the merger of Astra AB and Zeneca Group PLC in 1999. He was a non-executive director of Lloyds TSB Group PLC until 2004 and is chairman of the British Pharma Group.

Member of the chairman's and remuneration committees

16 Dr W E Massey

Walter Massey (66) joined BP's board in 1998, having previously been a director of Amoco. He is president of Morehouse College, a non-executive director of Motorola, Bank of America and McDonald's Corporation and a member of President Bush's Council of Advisors on Science and Technology.

Member of the chairman's and nomination committees and chairman of the ethics and environment assurance committee

17 H M P Miles, OBE

Michael Miles (68) joined BP's board in 1994. In 1988, he became an executive director of John Swire & Sons Ltd. He was chairman of Swire Pacific between 1984 and 1988. He is chairman of Schroders plc, non-executive chairman of Johnson Matthey Plc and a director of BP Pension Trustees Ltd.

Member of the chairman's, audit and ethics and environment assurance committees

18 Sir Robin Nicholson, FREng, FRS

Sir Robin (70) joined BP's board in 1987. He represents the board on the BP technology advisory council. In 1976, he became managing director of Inco Europe Limited. He was chief scientific adviser in the Cabinet Office from 1981 to 1985. Between 1986 and 1996, he was an executive director of Pilkington. He is a non-executive director of Rolls-Royce Group plc.

Member of the chairman's and nomination committees and chairman of the remuneration committee

19 M H Wilson

Michael Wilson (67) joined BP's board in 1998, having previously been a director of Amoco. He was a member of the Canadian Parliament from 1979 to 1983 and held various ministerial posts, including Finance, Industry, Science, Technology, and International Trade. He is chairman of UBS Canada and a non-executive director of Manufacturers Life Insurance Company. He is an Officer of the Order of Canada.

Member of the chairman's, audit and ethics and environment assurance committees

Changes to the board

Floris Maljers retired on 15 April 2004. On 1 July 2004, Dick Olver retired, Iain Conn was appointed an executive director and Sir Tom McKillop was appointed a non-executive director. Douglas Flint was appointed a nonexecutive director on 1 January 2005.

Company secretary

David Jackson (52) was appointed company secretary in 2003. A solicitor, he is a member of the Listing Authorities Advisory Committee and a director of Business in the Community.

Shareholdings and Annual General Meeting

Register of members holding BP ordinary shares as at 31 December 2004	Number of	Percentageof total	Percentageof total share
Range of holdings	shareholders	shareholders	capital
1 – 200	59,200	17.13	0.01
201 – 1,000	132,091	38.22	0.31
1,001 – 10,000	138,359	40.04	1.96
10,001 – 100,000	13,764	3.98	1.31
100,001 – 1,000,000	1,300	0.38	2.15
Over 1,000,000a	867	0.25	94.26
	345,581	100.00	100.00

aIncludes JPMorgan Chase Bank, holding 32.50% of the total share capital as the approved depositary for ADSs, a breakdown of which is shown in the table below.

Register of holders of American depositary shares as at 31 December 2004a	Number of	Percentageof total	Percentageof total
Range of holdings	ADS holders	ADS holders	ADSs
1 – 200	38,971	23.85	0.04
201 – 1,000	38,789	23.74	0.30
1,001 – 10,000	65,628	40.16	3.35
10,001 – 100,000	19,249	11.78	7.21
100,001 – 1,000,000	746	0.46	1.92
Over 1,000,000b	14	0.01	87.18
	163,397	100.00	100.00

aOne ADS represents six ordinary shares.

bOne of the holders of ADSs represents some 824,700 underlying holders.

At 31 December 2004, there were also 1,664 preference shareholders.

Substantial shareholdings

At the date of this report, the company has been notified that JPMorgan Chase Bank, as depositary for American depositary shares (ADSs), holds interests through its nominee, Guaranty Nominees Limited, in 6,995,048,776 ordinary shares (32.50% of the company's ordinary share capital). Included in this total is part of the holding of the Kuwait Investment Office (KIO). Either directly or through nominees, the KIO holds interests in 715,040,000 ordinary shares (3.32% of the company's ordinary share capital). Barclays plc holds interests in 747,585,529 ordinary shares (3.47% of the company's ordinary share capital) and Legal and General Investment Management holds interests in 768,172,570 ordinary shares (3.57% of the company's share capital).

At the date of this report, the company has been notified of the following interests in preference shares. Co-operative Insurance Society Limited holds interests in 1,550,538 8% 1st preference shares (21.44% of that class) and 1,789,796 9% 2nd preference shares (32.70% of that class). The National Farmers Union Mutual Insurance Society Ltd holds 945,000 8% 1st preference shares (13.07% of that class) and 987,000 9% 2nd preference shares (18.03% of that class). Prudential plc holds interests in 528,150 8% 1st preference shares (7.30% of that class) and 644,450 9% 2nd preference shares (11.77% of that class). Royal & SunAlliance Insurance plc holds interests in 287,500 8% 1st preference shares (3.97% of that class) and 250,000 9% 2nd preference shares (4.57% of that class). Ruffer Limited Liability Partnership holds interests in 750,000 9% 2nd preference shares (13.70% of that class).

It should be noted that the total preference shares in issue comprise only 0.39% of the company's total issued nominal share capital, the rest being ordinary shares.

Annual General Meeting

The 2005 annual general meeting will be held on Thursday 14 April 2005 at 11.00 a.m. at the Royal Festival Hall, Belvedere Road, London SE1 8XX, UK. A separate notice convening the meeting is sent to shareholders with this Report, together with an explanation of the items of special business to be considered at the meeting.

All resolutions of which notice has been given will be decided on a poll.

Ernst & Young LLP have expressed their willingness to continue in office as auditors and a resolution for their reappointment is included in the notice of the annual general meeting.

By order of the board David J Jackson Secretary 7 February 2005

AI assistant

BP PLC — Annual Report 2004

4622_10-k_2004-12-31_e2a55122-65ec-4244-893c-6b56f9468dd4.pdf

Performance highlights

BP Annual Report and Accounts 2004

Dividends per share (cents/pence)

Result per share (cents)

Environmental performance

Days away from work case frequencya,b (per 200,000 hours)

Return on average capital employed (%)

Senior management profile by gender and nationalitya (%)

Return to shareholders: present value of $1,000 invested ($)

Over 3 years: 2002-2004

Community investment

Chairman's letter

Group chief executive's review

Resourcefulness on a new scale

The best routes to market

Getting closer to customers

The point of excellence

Financial performance

Business environment

Results

Dividends and share repurchases

External environment

Operating statistics

Business performance

Exploration and Production

Refining and Marketing

Strategy

Refining and Marketing

Focus

Petrochemicals

Strategy

Petrochemicals

Focus

Strategy

Focus

Gas, Power and Renewables

Environmental and social performance

BP: our business

BP and the environment

BP in society

Other financial issues

Critical accounting policies

Accounting policy changes in 2004

Adoption of International Financial Reporting Standards

Financial risk management

Insurance

Environmental expenditure

Creditor payment policy and practice

Accounts contents

Statement of directors' responsibilities in respect of the accounts

Independent auditors' report

To the Members of BP p.l.c.

Respective responsibilities of directors and auditors

Basis of audit opinion

Opinion

Ernst & Young LLP

Accounting policies

Accounting standards

Group consolidation

Accounting convention

Replacement cost

Stock valuation

Revenue recognition

Foreign currency transactions

Derivative financial instruments

Oil and natural gas exploration and development expenditure

Decommissioning

Depreciation

Maintenance expenditure

Petroleum revenue tax

Changes in unit-of-production factors

Environmental liabilities

Leases

Research

Interest

Pensions and other post-retirement benefits

Deferred taxation

BP PLC Annual Report 2004