BP Annual Report 2008 | Quarterlytics

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FY2008 Annual Report · BP

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beyond petroleum®

Annual Report
and Accounts
2008

bp.com/annualreport

What’s inside?

2 Chairman’s letter

89 A dditional information for

shareholders
90 Share ownership
91 Major shareholders and related party transactions
92 Dividends
92 Legal proceedings
93 The offer and listing
95 Memorandum and Articles of Association
96 Exchange controls
96
98 Documents on display
99 Purchases of equity securities by the issuer and

Taxation

affiliated purchasers

100 Called-up share capital
100 Annual general meeting
100 Administration

101 Financial statements

102 Consolidated financial statements of the BP group
108 Notes on financial statements
180 Additional information for US reporting
182 Supplementary information on oil and natural gas
191 Parent company financial statements of BP p.l.c.

4 Group chief executive’s review

6 Our performance

9 Performance review

Information on the company

Forward-looking statements

10 Selected financial and operating information
12 Risk factors
14
14 Statements regarding competitive position
15
17 Exploration and Production
31 Refining and Marketing
37 Other businesses and corporate
40 Research and technology
41 Regulation of the group’s business
41 Safety
43 Environment
48 Employees
49 Social and community issues
49 Essential contracts
49 Property, plants and equipment
49 Organizational structure
50 Financial and operating performance
58 Liquidity and capital resources
61 Critical accounting policies

65 Board performance and biographies

66 Directors and senior management
69 BP board performance report

77 Directors’ remuneration report

78 Part 1 Summary
80 Part 2 Executive directors’ remuneration
86 Part 3 Non-executive directors’ remuneration

BP Annual Report and Accounts 2008

Information about this report

This document constitutes the Annual Report and Accounts of BP p.l.c. for the year ended 31 December 2008 in accordance with UK requirements
and is dated 24 February 2009. This document also contains information that will be included in the company’s Annual Report on Form 20-F 2008 in
accordance with the requirements of the US Securities and Exchange Commission (SEC). Such information will be supplemented and may be updated
at the time of filing that document with the SEC, or later amended, if necessary.

The Annual Report and Accounts for the year ended 31 December 2008 contains the Directors’ Report, including the Business Review and

Management Report, on pages 2-76 and 89-100, 102 and 191. The Directors’ Remun eration Report is on pages 77-87. The consolidated financial
statements are on pages 101-190. The report of the auditor is on page 103 for the group and page 192 for the company.

BP Annual Report and Accounts 2008 and BP Annual Review 2008 may be downloaded from www.bp.com/annualreport. No material on the

BP website, other than the items identified as BP Annual Report and Accounts 2008 and BP Annual Review 2008, forms any part of those documents.

Reconciliation of profit for the year to replacement cost profit
For the year ended 31 December

Profit before interest and taxation from continuing operations
Finance costs and net finance income relating to pensions and other post-retirement benefits
Taxation
Minority interest
Profit for the year from continuing operations attributable to BP shareholders
Profit (loss) for the year from Innovene operations
Inventory holding (gains) losses, net of tax
Replacement cost profita b
Replacement cost profit from continuing operations attributable to BP shareholders
Replacement cost profit (loss) from Innovene operations
Replacement cost profit
Exploration and Production
Refining and Marketing
Other businesses and corporate
Consolidation adjustments – Unrealized profit in inventory
Replacement cost profit before interest and taxation
Finance costs and net finance income relating to pensions and other post-retirement benefits
Taxation on a replacement cost basis
Minority interest
Replacement cost profit from continuing operations attributable to BP shareholders
Per ordinary share – cents

Profit for the year attributable to BP shareholders
Replacement cost profit

Dividends paid per ordinary share – cents
– pence

Dividends paid per American depositary share (ADS) – dollars

2008
35,239
(956)
(12,617)
(509)
21,157
–
4,436
25,593
25,593
–
25,593
38,308
4,176
(1,223)
466
41,727
(956)
(14,669)
(509)
25,593

112.59
136.20
55.05
29.387
3.303

2007
32,352
(741)
(10,442)
(324)
20,845
–
(2,475)
18,370
18,370
–
18,370
27,602
2,621
(1,209)
(220)
28,794
(741)
(9,359)
(324)
18,370

108.76
95.85
42.30
20.995
2.538

$ million

2006
35,158
(516)
(12,331)
(286)
22,025
(25)
222
22,222
22,247
(25)
22,222
31,026
5,161
(841)
65
35,411
(516)
(12,362)
(286)
22,247

109.84
110.95
38.40
21.104
2.304

aReplacement cost profit reflects the replacement cost of supplies. The replacement cost profit for the year is arrived at by excluding from profit inventory holding gains and losses and their
associated tax effect. Inventory holding gains and losses, for this purpose, are calculated for all inventories except for those that are held as part of a trading position and certain other temporary
inventory positions. BP uses this measure to assist investors in assessing BP’s performance from period to period. Replacement cost profit is not a recognized GAAP measure.
b
Effective 1 January 2008, replacement cost profit for the year is determined by excluding from profit inventory holding gains and losses as well as their associated tax effect. Previously,
replacement cost profit excluded inventory holding gains and losses while the tax charge remained unadjusted and included the tax effect on inventory holding gains and losses. Comparative
amounts have been amended to the new basis and the impact of the change is shown in the table below. There is no impact on profit for the year.

For the year ended 31 December

Replacement cost profit

– as previously reported
– tax effect on inventory holding gains and losses

– as amended

2007

17,287
1,083

18,370

$ million

2006

22,253
(31)

22,222

Comparative information presented in the ’Reconciliation of profit for the year to replacement cost profit’ table above has been restated, where appropriate, to reflect the resegmentation, following
transfers of businesses between segments, that was effective from 1 January 2008. See page 16 for more details.

On pages 2-7, references within BP Annual Report and Accounts 2008 to ‘profits’, ‘results’ and ‘return on average capital employed’ are to those measures on a replacement cost basis unless

otherwise indicated.

BP p.l.c. is the parent company of the BP group of companies. Unless otherwise stated, the text does not distinguish between the activities and operations of the parent company and those

of its subsidiaries.

The term ‘shareholder’ in this Annual Report and Accounts means, unless the context otherwise requires, investors in the equity capital of BP p.l.c., both direct and/or indirect. As BP shares,

in the form of ADSs, are listed on the New York Stock Exchange (NYSE), an Annual Report on Form 20-F will be filed with the SEC in accordance with the US Securities Exchange Act of 1934. When
filed, copies may be obtained, free of charge (see page 98).

Cautionary statement
BP Annual Report and Accounts 2008 contains certain forward-looking statements within the meaning of the US Private Securities Litigation Reform Act of 1995 with respect to the financial condition,
results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. For more details, please see forward-looking statements on page 14.

The registered office of BP p.l.c. is 1 St James’s Square, London SW1Y 4PD, UK. Tel +44 (0)20 7496 4000. Registered in England and Wales No. 102498. Stock exchange symbol ‘BP’.

2008 was a year we will all remember. There are
few precedents in history for such a rapid and dramatic
change in the business environment. In the space of a
few months we went from a record oil price of more
than $140 per barrel, and BP reporting two consecutive
quarters of record proﬁ ts for the group, to a recession
in most of our major markets. Despite this changing
environment, I am glad to say that BP is in an enviably
strong position in terms of its balance sheet, its assets
and its people.

That strength is in no small part due to the period

of critical self-examination the group has undergone
since 2005. The resulting strategy, devised by Tony
Hayward and his team and endorsed by the board,
is already bearing fruit and has put us in a much better
position to weather the savage economic storms we
now face.

The price of oil ended the year at its lowest level

for more than four years. That has obviously affected
our ﬁ nancial performance. The board understands the
importance of the dividend to investors in these difﬁ cult
times and, despite the weaker environment, we have
held the quarterly dividend to be paid in March at
14 cents per share, compared with 13.525 cents per
share for the same quarter of 2007. In sterling terms,
the quarterly dividend is 9.818 pence per share,
compared with 6.813 pence per share for the same
quarter of 2007. During the year $2.9 billion of shares
were repurchased for cancellation, compared with
$7.5 billion in 2007. In response to feedback from
investors we are now weighting shareholder returns
towards dividends, as opposed to buybacks.

The search for my successor has unfortunately

taken longer than originally expected, in part due to
the turbulent business environment. It is important that
we ﬁ nd the right person and we envisage making an
announcement in the coming months. In the meantime
I have agreed, at the board’s request, to stay on as
chairman and will seek re-election.

So, this will be my last annual general meeting.
It has truly been an honour for me to serve 12 years as
chairman – and before that as a director – of what is one
of the world’s great enterprises. During that time I have
seen BP constantly evolve and, by most measures,
nearly double in size. But the underlying principles of
the international oil company’s business model continue
to endure. BP and its peers make the energy markets
work, by forming partnerships with resource-holding
governments and applying our technology to bringing
supplies of energy to millions of customers, every day.
2008 has been a reminder that the world economy
depends on our efforts.

BP Annual Report and Accounts 2008

Chairman’s letter

Gathering
pace

Peter Sutherland Chairman
24 February 2009

Highlights

• Dramatic change in business environment.

• BP in strong position.

BP and its peers make the energy

markets work, by forming partnerships with
resource-holding governments and applying
our technology to bringing supplies of energy
to millions of customers, every day. 2008 has
been a reminder that the world economy
depends on our efforts.

Throughout the year the board has supported Tony and
his executive team in reforming the way in which the
group works to ensure that everyone within BP is clear
on its long-term purpose. It is vital that the role of the
international oil company is deﬁned and understood both
inside and outside the organization. While sticking to its
principles, BP needs to be ﬂexible in the manner in which
business is approached, developing a diverse portfolio of
projects, with a robust cost structure, enabling the group
to perform throughout the cycle.

All our activities need to take place against a very
clear view of risk. Events during the year have powerfully
reinforced the need for boards to have a very clear
understanding of the risks their businesses face. I believe
the BP board and its committees have set a high
standard in this regard and we continue to improve
the manner in which we understand and evaluate
risks whether they be strategic, geopolitical, compliance
or operational. No business can be without risk. Indeed
it is by taking strategic and commercial risks that we
earn a return.

We have had some notable operational and
engineering successes in the year, which are described
within this Annual Report and Accounts. There are
several I could mention, including restoring economic
capability at the Texas City reﬁnery, but I would
particularly like to focus on the Gulf of Mexico, which
is a proving to be a showcase for BP’s deepwater
skills and technology. BP is now the number one
producer there and Thunder Horse, the world’s largest
semi-submersible platform, is on track to reach capacity
of about 280,000boe/d in 2009. Thunder Horse is
expected to be the second biggest producing ﬁeld in the
US and is a powerful symbol of what BP can achieve.

I am pleased we have reached an amicable settlement
with our partners in our Russian joint venture, TNK-BP.
This means BP has retained 50% ownership of what is
an important option in one of the world’s most proliﬁ c
hydrocarbon provinces.

I would not normally single out individual

executives, but I do want to pay tribute to the work
that Bob Dudley has done as chief executive of
TNK-BP. During his ﬁve-year tenure he transformed
TNK-BP and it now leads the Russian oil industry on
the basis of production growth, reserves replacement
and total shareholder return. I am delighted that Bob
will join the BP board in April. As a managing director,
he will assume responsibility for broad oversight of
the group’s activities in the Americas and Asia. We had a
settled board for much of 2008, but we expect Bob to be
the ﬁrst of several new appointments as we refresh the
cadre of non-executive directors through 2009.

In the past 12 years the energy industry has

consolidated and taken major technical steps forward,
beginning production in some of the more remote areas
of the world, such as the deepwater Gulf of Mexico and
the Russian Arctic. Our role has been deﬁ ned and
redeﬁned and BP has led the way in accepting the need
to tackle the threat of climate change. Throughout that
time the BP board has had outstanding members and,
without exception, I have worked with a group of
extremely talented executives.

I would like to thank all my board and executive
colleagues past and present, and all BP’s employees.
I would also like to thank the two company secretaries,
Judith Hanratty and David Jackson, who have provided
me with admirable support during my term. Finally,
I thank all our shareholders for their support. During
2009 we are celebrating BP’s centenary and I am
conﬁdent that BP can face the next 100 years with
pride and a renewed sense of purpose. •

BP Annual Report and Accounts 2008

Group chief
executive’s review

Driving

forward

Tony Hayward Group Chief Executive
24 February 2009

Highlights

• Progress with safe and reliable operations.

• Major projects delivered and revenues restored.

• Complexity and costs being reduced.

In a year that will be remembered for extremely volatile
oil prices and exceptional stock market turbulence, BP
delivered an excellent set of results. We made good
progress on achieving safe and reliable operations, and
delivered strong operational momentum that reduced
the performance gap with our competitors.

During the year we beneﬁted from record

high oil prices. Replacement cost proﬁt for the year
was a record $25.6 billion, with a return on average
capital employed greater than 20%. We outperformed
the FTSE 100 by 17% and our ADSs outperformed
the S&P 500 index of large cap US by 2%.

At the start of the year what priorities
did you set out for BP?

Safety, people and performance, and these remain
our priorities. Our number one priority was to do
everything possible to achieve safe, compliant and
reliable operations.

Good policies and processes are essential but,

ultimately, safety is about how people think and act.
That’s critical at the front line but it is also true for the
entire group. Safety must inform every decision and
every action. The BP operating management system
(OMS) turns the principle of safe and reliable operations
into reality by governing how every BP project, site,
operation and facility is managed.

Our work on safety has been acknowledged inside
and outside the group. For instance, the board’s
independent expert, L Duane Wilson, continues to
report on our progress in implementing the improvements
recommended by the BP US Reﬁ neries Independent
Safety Review Panel and identify areas that need more
focused attention. Our most recent employee survey
indicated employees are also seeing the results of our
work to enhance safety. Clearly, there is more to do
and safety remains at the front of our minds. Beyond
safety, we are also committed to high ethical standards
and legal compliance in all aspects of our business.
We have continued to enhance and improve compliance
programmes in areas such as our integrated supply
and trading function.

In last year’s Annual Report and Accounts

I described the forward agenda we were pursuing to
close the competitive gap by making BP a simpler
and more efﬁcient organization. Throughout 2008
we maintained our focus on reducing cost and
complexity, and embedding a strong performance
culture throughout the group. We achieved success
on both counts. Layers of management have been
removed, there is accountability for performance
at all levels and we have created a strong focus
on leadership behaviours.

How have these priorities affected your people?
First, I would like to thank our employees for

the part they have played in turning around BP’s
performance. Their determination and commitment
have been truly remarkable and we have come a long
way in a short time. At the same time, we continue to
provide excellent support for employees. From learning
and development to diversity and inclusion, we are
enabling people to achieve sustained high performance.
Less complexity means we can now clearly identify
top performers – both businesses and individuals –
and reward them appropriately.

How did Exploration and Production perform?
It was an excellent year, with major projects such
as Thunder Horse in the Gulf of Mexico and Deepwater
Gunashli in Azerbaijan coming onstream. That, together
with safe and reliable performance from our existing
operations, contributed to underlying production
growth – in contrast to the falling output of our major
competitors – and more than compensated for the
effects of Hurricanes Ike and Gustav and other
operational issues. Rigorous cost control and efﬁ ciency
offset the signiﬁcant cost inﬂation that hit our sector.
The start of production at Thunder Horse was an
important milestone in terms of recovery and renewal.
It was also a good year for exploration with major new
discoveries in Algeria, Angola, Egypt and the Gulf of
Mexico. We also gained new access to oil sands in
Canada and shale gas in the US, as well as gaining
licences to explore in the Canadian Arctic. 2008
was our 15th consecutive year of delivering reported
reserves replacement of more than 100%.

exploration, appraisal, development and the turnaround
in Reﬁning and Marketing, we also invested $1.4 billion
in alternative forms of energy such as wind, solar,
biofuels and carbon capture and storage (CCS). Looking
ahead, on the issue of greenhouse gas (GHG) emissions,
we believe legislation is required to ensure that a cost
of carbon is included in the price of everything. This
would enable companies such as BP to make even
greater investments in low-carbon energy. We favour
cap-and-trade as it provides environmental certainty
based on an absolute emissions cap. A global system
is the ultimate objective, but progress must be made
at national and regional levels ﬁ rst.

It is getting tougher for BP and others to
access new resources; do international oil

companies really have a sustainable future?
International oil companies thrive at the frontiers of the
energy industry taking on challenges others are either
unwilling or unable to address. BP continues to agree
signiﬁcant new deals, from oil sands to the Beaufort
Sea in Canada as well as making new discoveries in
Algeria, Angola, Egypt and the Gulf of Mexico. We
have also resolved the dispute with our TNK-BP joint
venture partners in Russia.

We secure these agreements because we
can build enduring relationships and have technical
capabilities and experience distinct in our industry.
Research and technology play a vital role here. By
improving the efﬁciency of fossil fuel recovery and
discovery, promoting fuel conversion and developing
low-carbon alternatives, we are helping to provide
affordable, sustainable energy for today and tomorrow.

What is the plan for Alternative Energy;
what role will it play in BP’s portfolio?

With both energy demand and carbon emissions rising,
the world needs every sustainable, affordable energy
source available. We invest a signiﬁcant amount in
alternative energy technology compared with our peers
and, for us, the key question is which technologies
will make the greatest contribution to meeting energy
demand while providing BP with strong growth
businesses. In 2008 we prioritized areas with signiﬁ cant
long-term growth potential – wind, solar, biofuels and
CCS – and directed the majority of our $1.4 billion
investment in the year to these areas.

Is BP entering its centenary year in

good shape?

On the basis of our 2008 performance, I believe we
can declare that ‘BP is back’. Clearly, however, we
must continue to adjust to market conditions. Oil and
gas prices go up and down; our job is to ensure we
can compete and thrive through every part of the cycle,
something we’ve been doing for 100 years. Despite
the challenges ahead, I am conﬁdent that we now
have the positive momentum and ﬂ exibility required
to achieve success as we begin our next century. •

November 2008
Tony Hayward
discusses operating
priorities with
employees at the
BP Carson reﬁ nery,
California, US.

How far has Reﬁning and Marketing
addressed its most critical problems?
We made good progress on achieving safe, compliant
and reliable operations. We improved reﬁ ning availability
on an annualized basis from 83% to 89% and restored
full economic capability at the Texas City and Whiting
reﬁneries. In our fuels value chains we are achieving
greater integration between reﬁ neries, terminals,
pipelines and retail sites. The international businesses,
which include lubricants, petrochemicals, aviation
and marine fuels and liqueﬁed petroleum gas, have
performed well. We have also started to address
overhead cost by reducing senior level headcount and
by simplifying the marketing footprint. Now it’s about
driving greater consistency and efﬁ ciency through
the business to capitalize on the leadership positions
we enjoy in the most valuable markets.

How is BP responding to the twin challenges
of energy security and climate change?
Our job is to help meet the world’s energy needs
today, invest in the next generation of energy sources
and support the transition to a low-carbon economy.
Alternative energy production is growing but currently
represents just 2% of global energy production, so the
world will need fossil fuels for years to come – even
if demand slows – and we will play an important role
by meeting this need while developing options for
the future.

In 2008 we responded to these challenges by

investing nearly $22 billiona in our businesses – an increase
of 13% on 2007. Along with supporting our work on

a Excluding acquisitions and asset exchanges and excluding the
accounting for our transactions with Husky Energy Inc. and
Chesapeake Energy Corporation.

BP Annual Report and Accounts 2008

Our performance

Progress in 2008

Safety

Personal safety – recordable
injury frequency

Process safety –
oil spills

Environment – greenhouse
gas emissions (million tonnes
of carbon dioxide equivalent)

Employees
Contractors

0.35

0.50

0.59

0.40

0.55a

335

340

417

61.4

63.5

64.4

Recordable injury frequency measures
the number of reported work-related
incidents that result in a fatality or
injury (apart from minor first aid cases)
per 200,000 hours worked.

a 2006 contractor data corrected from

0.54 to 0.55.

All spills of hydrocarbon greater than
or equal to one barrel (159 litres,
42 US gallons).

GHG emissions are emissions of
CO2 and methane in million tonnes
of CO2 equivalent. This is BP’s share
of direct GHG emissions, representing
all consolidated subsidiaries and BP’s
share of equity-accounted entities
except TNK-BP.

People

Employee satisfactiona (%)

Number of employeesa

Diversity and inclusion (%)

92,000

98,100b

97,000

Women
Non-UK/US

The overall Employee Satisfaction
Index comprises 10 key questions that
provide insight into levels of employee
satisfaction across a range of topics,
such as pay.

Employees includes all individuals
who have a contract of employment
with a BP group entity.

a As at 31 December.
b 2007 data corrected from 97,600

a The People Assurance Survey, conducted

to 98,100.

The percentage of women and
individuals from countries other
than the UK and US among BP’s
top 583 leaders (2007 624, 2006 625).

in 2004 and 2006, used a census methodology
and targeted the entire BP employee
population. Based on the same set of
questions, the Pulse Plus Survey, in 2008,
adopted a sample-based approach, which
achieved a representative view of BP.

Here we present our key measures of progress
in the three priority areas of safety, people and
performance. While the measures we use to
chart financial performance are well established,
we continue to evolve safety and people
measures to further enhance our reporting.

Performance

Production (thousand barrels
of oil equivalent per day)

Reserves replacement
ratioa b (%)

Refining availability (%)

Operating cash flow ($ billion)

3,838

3,818

3,926

121c

112

113

38.1

24.7

28.2

Crude oil, natural gas liquids (NGLs)
and natural gas produced from
subsidiaries and equity-accounted
entities. Converted to barrels of
oil equivalent (boe) at 1 barrel of
NGL = 1boe and 5,800 standard
cubic feet of natural gas = 1boe.

Proved reserves replacement ratio (also
known as the production replacement
ratio) is the extent to which production
is replaced by proved reserves additions.
The ratio is expressed in oil equivalent
terms and includes changes resulting
from revisions to previous estimates,
improved recovery and extensions
and discoveries.

a Combined basis of subsidiaries and
equity-accounted entities, excluding
acquisitions and disposals.

b See page 21, footnote f.
c See page 11, footnote f.

Refining availability represents Solomon
Associates’ operational availability, which
is defined as the percentage of the year
that a unit is available for processing after
subtracting the annualized time lost due
to turnaround activity and all planned
mechanical, process and regulatory
maintenance downtime.

Operating cash flow is net cash
flow provided by operating activities,
from the group cash flow statement.
Operating activities are the principal
revenue-producing activities of the
group and other activities that are
not investing or financing activities.

Replacement cost profit
per ordinary share (cents)

Dividends paid per
ordinary share

Total shareholder return (%)

136.20

95.85

110.95

29.387

20.995

42.30

38.40

21.104

55.05

-34.5

-15.1

0808

0707

06 06

14.0

7.0

4.7

-4.6

Cents
Pence

ADS basis
Ordinary share basis

Replacement cost profit reflects the
replacement cost of supplies. It is
arrived at by excluding from profit
inventory holding gains and losses
and their associated tax effect.
(See footnotes a and b on page 1.)

The total dividend per share paid to
ordinary shareholders in the year.

Total shareholder return represents
the change in value of a shareholding
over a calendar year, assuming that
dividends are re-invested to purchase
additional shares at the closing price
applicable on the ex-dividend date.

Performance
review

10 Selected financial and operating

43 Environment

information

12 Risk factors

14 Forward-looking statements

14 Statements regarding competitive

position

15 Information on the company

17 Exploration and Production

31 Refining and Marketing

37 Other businesses and corporate

40 Research and technology

41 Regulation of the group’s business

41 Safety

48 Employees

49 Social and community issues

49 Essential contracts

49 Property, plants and equipment

49 Organizational structure

50 Financial and operating

performance

58 Liquidity and capital resources

61 Critical accounting policies

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BP Annual Report and Accounts 2008

Performance review

Selected financial and operating
information

This information, insofar as it relates to 2008, has been extracted or
derived from the audited financial statements of the BP group presented
on pages 101-179. Note 1 to the Financial statements includes details
on the basis of preparation of these financial statements. The selected
information should be read in conjunction with the audited financial
statements and related Notes elsewhere herein.

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

Income statement data

Total revenuesa
Profit before interest and taxation from continuing operationsa
Profit from continuing operationsa
Profit for the year
Profit for the year attributable to BP shareholders
Capital expenditure and acquisitionsb
Per ordinary share – cents

Profit for the year attributable to BP shareholders

Basic
Diluted

Profit from continuing operations attributable to BP shareholdersa

Basic
Diluted

Dividends paid per share – cents
– pence

Ordinary share datac
Average number outstanding of 25 cent ordinary shares (shares million undiluted)
Average number outstanding of 25 cent ordinary shares (shares million diluted)

Balance sheet data

Total assets
Net assets
Share capital
BP shareholders’ equity
Finance debt due after more than one year
Net debt to net debt plus equityd

2008

2007

2006

2005

2004

$ million except per share amounts

365,700
35,239
21,666
21,666
21,157
30,700

112.59
111.56

112.59
111.56
55.05
29.387

288,951
32,352
21,169
21,169
20,845
20,641

108.76
107.84

108.76
107.84
42.30
20.995

270,602
35,158
22,311
22,286
22,000
17,231

109.84
109.00

109.97
109.12
38.40
21.104

243,948
32,682
22,448
22,632
22,341
14,149

194,919
25,746
17,884
17,262
17,075
16,651

105.74
104.52

104.87
103.66
34.85
19.152

78.24
76.87

81.09
79.66
27.70
15.251

18,790
18,963

19,163
19,327

20,028
20,195

21,126
21,411

21,821
22,293

228,238
92,109
5,176
91,303
17,464
21%

236,076
94,652
5,237
93,690
15,651
22%

217,601
85,465
5,385
84,624
11,086
20%

206,914
80,765
5,185
79,976
10,230
17%

194,630
78,235
5,403
76,892
12,907
22%

aExcludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2004, 2005 and 2006.
b2008 included capital expenditure of $2,822 million and an asset exchange of $1,909 million, both in respect of our transaction with Husky, as well as capital expenditure of $3,667 million in respect of our
transactions with Chesapeake (see page 51). 2007 included $1,132 million for the acquisition of Chevron’s Netherlands manufacturing company. Capital expenditure in 2006 included $1 billion in respect
of our investment in Rosneft. Capital expenditure and acquisitions for 2004 included $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. With the exception of the shares issued to Alfa Group and Access Renova (AAR) in connection with TNK-BP
(2004-2006), all capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing.
cThe number of ordinary shares shown has been used to calculate per share amounts.
dNet debt and the ratio of net debt to net debt plus equity ratio are non-GAAP measures. We believe that these measures provide useful information to investors. Net debt enables investors to see the
economic effect of gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity from shareholders. Net debt
has been redefined to include the fair value of associated derivative financial instruments that are used to hedge foreign exchange and interest rate risks relating to finance debt, for which hedge
accounting is claimed. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. Amounts for comparative periods are presented on a consistent basis.

Revised definition of net debt

As reported

Net debt
Equity

Ratio of net debt to net debt plus equity
As amended

Net debt
Equity

Ratio of net debt to net debt plus equity

2007

2006

2005

27,483
94,652
23%

26,817
94,652
22%

21,420
85,465
20%

21,122
85,465
20%

16,202
80,765
17%

16,373
80,765
17%

$ million

2004

21,732
78,235
22%

BP Annual Report and Accounts 2008
Performance review

Production and net proved oil and natural gas reserves
The following table shows our production for the past five years and the estimated net proved oil and natural gas reserves at the end of each
of those years.

Production and net proved reservesa

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

2008f
1,263
1,138
7,277
1,057
5,665
4,688
40,005

2007
1,304
1,110
7,222
921
5,492
4,581
41,130

2006
1,351
1,124
7,412
1,005
5,893
3,888
42,168

2005
1,423
1,139
7,512
912
6,360
3,205
44,448

2004
1,480
1,051
7,624
879
6,755
3,179
45,650

(billion cubic feet)e

5,203

3,770

3,763

3,856

2,857

aCrude oil includes natural gas liquids (NGLs) and condensate. Production and proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct
interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations.
bIncludes 21 million barrels (20 million barrels at 31 December 2007 and 23 million barrels at 31 December 2006) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
cIncludes 216 million barrels (210 million barrels at 31 December 2007 and 179 million barrels at 31 December 2006) in respect of the 6.80% minority interest in TNK-BP (6.51% at 31 December 2007
and 6.29% at 31 December 2006).
dIncludes 3,108 billion cubic feet of natural gas (3,211 billion cubic feet at 31 December 2007 and 3,537 billion cubic feet at 31 December 2006) in respect of the 30% minority interest in BP Trinidad
and Tobago LLC.
eIncludes 131 billion cubic feet (68 billion cubic feet at 31 December 2007 and 99 billion cubic feet at 31 December 2006) in respect of the 5.92% minority interest in TNK-BP (5.88% at
31 December 2007 and 7.77% at 31 December 2006).
fBP estimates proved reserves for reporting purposes in accordance with SEC rules and relevant guidance. As currently required, these proved reserve estimates are based on prices and costs as of the
date the estimate is made. There was a rapid and substantial decline in oil prices in the fourth quarter of 2008 that was not matched by a similar reduction in operating costs by the end of the year.
BP does not expect that these economic conditions will continue. However, our 2008 reserves are calculated on the basis of operating activities that would be undertaken were year-end prices and costs
to persist.

During 2008, 1,085 million barrels of oil and natural gas, on an oil equivalent* basis (mmboe), were added to BP’s proved reserves for subsidiaries
(excluding purchases and sales). After allowing for production, which amounted to 937mmboe, BP’s proved reserves for subsidiaries were
12,562mmboe at 31 December 2008. These proved reserves are mainly located in the US (44%), Rest of Americas (17%), Asia Pacific (10%),
Africa (11%) and the UK (8%).

For equity-accounted entities, 646mmboe were added to proved reserves (excluding purchases and sales), production was 491mmboe

and proved reserves were 5,585mmboe at 31 December 2008.

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

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BP Annual Report and Accounts 2008
Performance review

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

If there is an extended period of constraint in the capital markets,

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

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

The risks are categorized against the following areas: strategic;

compliance and control; and operational.

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

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

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

Refining profitability can be volatile, with both periodic oversupply

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

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

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

We set ourselves high standards of corporate citizenship and

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

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

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

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

BP Annual Report and Accounts 2008
Performance review

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

Crude oil prices are generally set in US dollars, while sales of

refined products may be in a variety of currencies. Fluctuations in
exchange rates can therefore give rise to foreign exchange exposures,
with a consequent impact on underlying costs and revenues.

For more information on financial instruments and financial risk

factors see Financial statements – Note 28 on page 142 and Note 34
on page 150.

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

Environment on page 43.

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

For certain legal proceedings involving the group, see Legal

proceedings on page 92.

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

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

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

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

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

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

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

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

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

Major project delivery
Successful execution of our group plan (see page 15) depends critically
on implementing the activities to deliver the major projects over the plan
period. Poor delivery of any major project that underpins production
growth and/or a major programme designed to enhance shareholder
value could adversely affect our financial performance.

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

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By their nature, forward-looking statements involve risk and uncertainty
because they relate to events and depend on circumstances that will or
may occur in the future and are outside the control of BP. Actual results
may differ materially from those expressed in such statements,
depending on a variety of factors, including the specific factors identified
in the discussions accompanying such forward-looking statements; the
timing of bringing new fields onstream; future levels of industry product
supply, demand and pricing; operational problems; general economic
conditions; political stability and economic growth in relevant areas of the
world; changes in laws and governmental regulations; exchange rate
fluctuations; development and use of new technology; the success or
otherwise of partnering; the actions of competitors; natural disasters and
adverse weather conditions; changes in public expectations and other
changes to business conditions; wars and acts of terrorism or sabotage;
and other factors discussed elsewhere in this report including under ‘Risk
factors’ on pages 12-14. In addition to factors set forth elsewhere in this
report, those set out above are important factors, although not exhaustive,
that may cause actual results and developments to differ materially from
those expressed or implied by these forward-looking statements.

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

BP Annual Report and Accounts 2008
Performance review

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

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

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

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

Forward-looking statements
In order to utilize the ‘Safe Harbor’ provisions of the United States Private
Securities Litigation Reform Act of 1995, BP is providing the following
cautionary statement. This document contains certain forward-looking
statements with respect to the financial condition, results of operations
and businesses of BP and certain of the plans and objectives of BP with
respect to these items. These statements may generally, but not always,
be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’,
‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’,
‘we see’ or similar expressions. In particular, among other statements, (i)
certain statements in Performance review (pages 10-60) with regard to
strategy, management aims and objectives, future capital expenditure,
future hydrocarbon production volume, date(s) or period(s) in which
production is scheduled or expected to come onstream or a project or
action is scheduled or expected to begin or be completed, capacity of
planned plants or facilities and impact of health, safety and environmental
regulations; (ii) the statements in Performance review (pages 10-49) with
regard to planned expansion, investment or other projects and future
regulatory actions; and (iii) the statements in Performance review (pages
50-63) with regard to the plans of the group, the cost of and provision for
future remediation programmes, taxation, liquidity and costs for providing
pension and other post-retirement benefits; and including under ‘Liquidity
and capital resources’ with regard to oil prices, production, demand for
refining products, refining volumes and margins and impact on the
petrochemicals sector, refining availability, continuing priority of safe,
compliant and reliable operations, and focus on cost efficiency, cost
deflation, capital expenditure, expected disposal proceeds, cash flows,
shareholder distributions, gearing, working capital, guarantees, expected
payments under contractual and commercial commitments and purchase
obligations; are all forward-looking in nature.

BP Annual Report and Accounts 2008
Performance review

Information on the company

General
Unless otherwise indicated, information in this document reflects 100%
of the assets and operations of the company and its subsidiaries that
were consolidated at the date or for the periods indicated, including
minority interests. Also, unless otherwise indicated, figures for total
revenues include sales between BP businesses.

The company was incorporated in 1909 in England and Wales

and changed its name to BP p.l.c. in 2001.

BP is one of the world’s leading oil companies on the basis of

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

Overview of the group

BP is a global group, with interests and activities held or operated

through subsidiaries, jointly controlled entities or associates established
in, and subject to the laws and regulations of, many different
jurisdictions. These interests and activities covered two business
segments in 2008: Exploration and Production and Refining and
Marketing. With effect from 1 January 2008, the former Gas, Power and
Renewables segment ceased to report separately (see Resegmentation
in 2008 on page 16).

A separate business, Alternative Energy, reported in Other

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

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

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

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

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

During 2008, we continued to pursue our three strategic

priorities of ‘Safety’, ‘People’ and ‘Performance’, which underpin BP’s
’forward agenda’.

Through this, we have taken steps to restore revenues, reduce

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

We expect Exploration and Production to be our core source of

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

In Refining and Marketing, we expect to continue building our

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

In Alternative Energy, we are focusing our investment activity in

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

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

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

We believe that BP has a strong portfolio of assets:
• In Exploration and Production, we have upstream interests in 29

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

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

In 2008, we completed an asset exchange with Husky Energy

Inc., and asset purchases from Chesapeake Energy Corporation as
described on page 51.

In 2007, BP acquired Chevron’s Netherlands manufacturing

company, Texaco Raffiniderij Pernis B.V. The acquisition included
Chevron’s 31% minority shareholding in Nerefco, its 31% shareholding in
the 22.5MW wind farm co-located at the refinery as well as a 22.8%
shareholding in the TEAM joint venture terminal and shareholdings in two
local pipelines linking the TEAM terminal to the refinery. Disposal
proceeds were $4,267 million, which included $1,903 million from the
sale of the Coryton refinery and $605 million from the sale of our
exploration and production gas infrastructure business in the Netherlands.
In 2006, BP purchased 9.6% of the shares issued under Rosneft’s

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

Resegmentation in 2008
On 11 October 2007, BP announced that it was to simplify its
organizational structure by reducing the number of business segments.
From 1 January 2008, BP has two business segments:

Exploration and Production and Refining and Marketing. A separate
business, Alternative Energy, handles BP’s low-carbon businesses and
future growth options outside oil and gas and reports under Other
businesses and corporate.

As a result, and with effect from 1 January 2008:
• The former Gas, Power and Renewables segment ceased to

report separately.

• The NGLs, LNG and gas and power marketing and trading businesses
were transferred from the Gas, Power and Renewables segment to
the Exploration and Production segment.

• The Alternative Energy business was transferred from the Gas, Power

and Renewables segment to Other businesses and corporate.

• The Emerging Consumers Marketing Unit was transferred from

Refining and Marketing to Alternative Energy (which is reported in
Other businesses and corporate).

• The Biofuels business was transferred from Refining and Marketing

to Alternative Energy (which is reported in Other businesses
and corporate).

• The Shipping business was transferred from Refining and Marketing to

Other businesses and corporate.

BP Annual Report and Accounts 2008
Performance review

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

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

BP sells small quantities of lubricants in Cuba through a 50/50

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

Market context
Our market is a complex and fast-moving environment. In 2008, volatile
energy price movements mirrored unsettled financial markets and wider
economic uncertainty (see Risk factors on page 12). World oil
consumption fell in 2008, with growing demand in fast growing non-
OECD countries more than offset by falling consumption in the OECD
countries. Gas consumption grew in the major markets. Anxieties
around energy security continued, with individual consumer countries
facing specific issues related to cost, geography and political
relationships with producers. In terms of supply, substantial global
reserves of oil and gas are in place but government, energy companies
and industry must work together to bring these to market. There is also
a clear need for greater energy diversity to address the competing
challenges of growing demand and climate change. In terms of human
resources, the energy industry also faces a shortage of professionals
such as petroleum engineers and scientists.

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

Total capital expenditure including acquisitions in 2008 was

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

There were no significant acquisitions in 2006 and 2007. Capital

expenditure in 2006 included our investment of $1 billion in Rosneft.

Development expenditure incurred in 2008, excluding midstream

activities, was $11,767 million, compared with $10,153 million in 2007
and $9,109 million in 2006.

Looking ahead, our priorities remain the same: safety, people

and performance. We will continue to strive to deliver safe, reliable and
efficient operations while maintaining our flexibility so we can respond
to oil price volatility.

In 2009, oil and gas prices are expected to be significantly lower

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

Comparative information presented in the table on the following

page has been restated, where appropriate, to reflect the
resegmentation, following transfers of certain businesses between
segments, that was effective from 1 January 2008. See page 16 for more
details.

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BP Annual Report and Accounts 2008
Performance review

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

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

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

Our oil and natural gas production assets are located onshore and

offshore and include wells, gathering centres, in-field flow lines,
processing facilities, storage facilities, offshore platforms, export
systems (e.g. transit lines), pipelines and LNG plant facilities.

Upstream operations in Argentina, Bolivia, Abu Dhabi, Kazakhstan

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

Our performance in 2008
Profit before interest and tax for 2008 was $37.9 billion, an increase of
37% compared with 2007. The increase was primarily driven by higher oil
and gas realizations. Our financial results are discussed in more detail on
pages 52-53.

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

BP Annual Report and Accounts 2008
Performance review

Key statistics

Total revenuesa
Profit before interest and tax

from continuing operationsb

Total assets
Capital expenditure and

acquisitions

Net proved reserves – group
Net proved reserves – equity-

accounted entities

Liquids production – group
Liquids production – equity-
accounted entities

Natural gas production – group
Natural gas production – equity-

2008
89,902

2007
69,376

$ million

2006
71,868

37,915
136,665

27,729
125,736

30,953
124,803

22,227

14,207

13,252

million barrels of oil equivalent

12,562

12,583

13,163

5,585

5,231

4,537

thousand barrels per day

1,263

1,304

1,351

1,138

1,110

1,124

million cubic feet per day

7,277

7,222

7,412

accounted entities

1,057

921

1,005

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

Our exploration and appraisal costs, excluding lease acquisitions,
in 2008 were $2,290 million, compared with $1,892 million in 2007 and
$1,765 million in 2006. These costs include exploration and appraisal
drilling expenditures, which are capitalized within intangible fixed assets,
and geological and geophysical exploration costs, which are charged to
income as incurred. Approximately 51% of 2008 exploration and appraisal
costs were directed towards appraisal activity. In 2008, we participated in
83 gross (34 net) exploration and appraisal wells in 11 countries. The
principal areas of activity were Algeria, Angola, Azerbaijan, Canada, Egypt,
the deepwater Gulf of Mexico, Libya, the North Sea and onshore US.
Total exploration expense in 2008 of $882 million (2007

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

In 2008, we obtained upstream rights in several new tracts, which

include the following:
• In the Gulf of Mexico, we were awarded 125 blocks through the Outer

Continental Shelf Lease Sales 205, 206 and 207.

$ per barrel

• In the US Lower 48 states, we acquired 225,000 net acres of shale

Average BP crude oil realizationsc
Average BP NGL realizationsc
Average BP liquids realizationsc d
Average West Texas Intermediate

oil price

Average Brent oil price

95.43
52.30
90.20

100.06
97.26

Average BP natural gas realizationsc
Average BP US natural gas realizationsc

6.00
6.77

69.98
46.20
67.45

72.20
72.39

61.91
37.17
59.23

66.02
65.14

$ per thousand cubic feet

4.53
5.43

4.72

5.74

Average Henry Hub gas pricee

9.04

6.86

7.24

$ per million British thermal units

Average UK National Balancing

Point gas price

58.12

29.95

42.19

pence per therm

aIncludes sales between businesses.
bIncludes profit after interest and tax of equity-accounted entities.
cRealizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted
entities.
dCrude oil and natural gas liquids.
eHenry Hub First of Month Index.

Total revenues are analysed in more detail below.

Sales and other operating revenues
Earnings from equity-accounted

entities (after interest and tax),
interest and other revenues

2008
86,170

2007
65,740

$ million

2006
67,950

3,732
89,902

3,636
69,376

3,918
71,868

gas assets from Chesapeake Energy Corporation.

• In Canada, BP acquired three licences, covering a total of

approximately 6,000 square kilometres in the Canadian Beaufort Sea.

• In India, BP acquired one block on the East Coast in the New

Exploration Licensing Policy seventh round.

In 2008, we were involved in a number of discoveries. In most cases,
reserves bookings from these fields will depend on the results of
ongoing technical and commercial evaluations, including appraisal drilling.
Our most significant discoveries in 2008 included the following:
• In Angola, we made further discoveries in the ultra deepwater (greater
than 1,500 metres) Block 31 (BP 26.7% and operator) with the Portia
and Dione wells, bringing the total number of discoveries in Block 31
to 16.

• In Algeria, we discovered natural gas in the Tin Zaouatene-1 well in the

Bourarhet Sud Blocks 230 and 231 (BP 49% and operator).

• In Egypt, we made a discovery with the Satis (BP 50% and operator)

well.

• In the UK, we made two discoveries with the South West Foinaven

(BP 72% and operator) and the Kinnoull (BP 77% and operator) wells.

• In the deepwater Gulf of Mexico, we made two discoveries with
the Kodiak (BP 63.75% and operator) and Freedom (BP 25% and
operator) wells.

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

On 31 December 2008, the SEC published a revised set of rules

for the estimation of reserves. These revised rules will be used for the
2009 year-end estimation of reserves, and have not been used in the
determination of reserves for year-end 2008.

By their nature, there is always some risk involved in the ultimate

development and production of reserves, including, but not limited to,
final regulatory approval, the installation of new or additional
infrastructure as well as changes in oil and gas prices, changes in
operating and development costs and the continued availability of
additional development capital.

BP Annual Report and Accounts 2008
Performance review

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

Our proved reserves are associated with both concessions (tax

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

accounted entities (jointly controlled entities and associates), although
we do not control these entities or the assets held by such entities.

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

Resources in a field will only be categorized as proved reserves

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

At the point of sanction, all booked reserves will be categorized as

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

Governance
BP’s centrally controlled process for proved reserves estimation approval
forms part of a holistic and integrated system of internal control. It
consists of the following elements:
• Accountabilities of certain officers of the group to ensure that there is

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

• Capital allocation processes, whereby delegated authority is exercised
to commit to capital projects that are consistent with the delivery of
the group’s business plan. A formal review process exists to ensure
that both technical and commercial criteria are met prior to the
commitment of capital to projects.

• Internal Audit, whose role includes systematically examining the

effectiveness of the group’s financial controls designed to assure the
reliability of reporting and safeguarding of assets and examining the
group’s compliance with laws, regulations and internal standards.
• Approval hierarchy, whereby proved reserves changes above certain
threshold volumes require central authorization and periodic reviews.
The frequency of review is determined according to field size and
ensures that more than 80% of the BP reserves base undergoes
central review every two years and more than 90% is reviewed every
four years.

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

BP’s variable pay programme for the other senior managers in the

Exploration and Production segment is based on individual performance
contracts. Individual performance contracts are based on agreed items
from the business performance plan, one of which, if chosen, could
relate to oil and gas reserves.

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

Total hydrocarbon proved reserves, on an oil equivalent basis

for equity-accounted entities alone, comprised 5,585mmboe at
31 December 2008, an increase of 6.8% compared with 31 December
2007. Natural gas represents about 16% of these proved reserves. The
increase includes a net increase from acquisitions and divestments of
199mmboe, largely comprising a number of assets in Venezuela.
The proved reserves replacement ratio (also known as the production
replacement ratio) is the extent to which production is replaced by proved
reserves additions. This ratio is expressed in oil equivalent terms and
includes changes resulting from revisions to previous estimates,
improved recovery and extensions and discoveries, and may be
expressed as a replacement ratio excluding acquisitions and divestments
or as a total replacement ratio including acquisitions and divestments.
BP estimates proved reserves for reporting purposes in
accordance with SEC rules and relevant guidance. As currently required,
these proved reserve estimates are based on prices and costs as of the
date the estimate is made. There was a rapid and substantial decline in
oil prices in the fourth quarter of 2008 that was not matched by a similar
reduction in operating costs by the end of the year. BP does not expect
that these economic conditions will continue. However, our 2008
reserves are calculated on the basis of operating activities that would be
undertaken were year-end prices and costs to persist.

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BP Annual Report and Accounts 2008
Performance review

2008

2007

2006

million barrels

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

Proved reserves replacement ratio, excluding

equity-accounted entities

116

Proved reserves replacement ratio, excluding
equity-accounted entities, including
sales and purchases of reserves-in-place
Proved reserves replacement ratio, for equity-

accounted entities

132

248

272

Proved reserves replacement ratio, for equity-
accounted entities, including sales and
purchases of reserves-in-place

Additions to proved developed reserves,
excluding equity-accounted entities,
including sales and purchases of
reserves-in-placea

Additions to proved developed reserves, for

equity-accounted entities, including sales
and purchases of reserves-in-placea

Proved developed reserves replacement ratio,
excluding equity-accounted entities,
including sales and purchases of
reserves-in-place

Proved developed reserves replacement ratio,
for equity-accounted entities, including
sales and purchases of reserves-in-place

172

248

239

million barrels of oil equivalent

826

929

675

751

473

936

153

101

195

aThis includes some reserves that were previously classified as proved undeveloped.

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

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

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

The following tables show BP’s estimated net proved reserves as

at 31 December 2008.

UK
Rest of Europe
US
Rest of Americas
Asia Pacific
Africa
Russia
Other
Group
Equity-accounted entities

Developed
410
81
1,717
58
77
464
–
174
2,981
3,125

Undeveloped
119
194
1,273
56
69
496
–
477
2,684
1,563

Total
529
275
2,990d
114e
146
960
–
651
5,665
4,688f

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

billion cubic feet

UK
Rest of Europe
US
Rest of Americas
Asia Pacific
Africa
Russia
Other
Group
Equity-accounted entities

Developed
1,822
61
9,059
3,975
2,482
1,050
–
507
18,956
3,234

Undeveloped
582
402
5,473
7,902
4,275
1,382
–
1,033
21,049
1,969

Net proved reserves on an oil equivalent basis

Group
Equity-accounted entities

Developed
6,249
3,683

Undeveloped
6,313
1,902

Total
2,404
463
14,532
11,877g
6,757
2,432
–
1,540
40,005
5,203h

mmboe

Total
12,562
5,585

a
Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the
royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently, and include minority interests in consolidated
operations. We disclose our share of reserves held in joint ventures and associates that are
accounted for by the equity method although we do not control these entities or the assets held by
such entities.
b
In certain deepwater fields, such as fields in the Gulf of Mexico, BP has claimed proved reserves
before production flow tests are conducted, in part because of the significant safety, cost and
environmental implications of conducting these tests. The industry has made substantial
technological improvements in understanding, measuring and delineating reservoir properties
without the need for flow tests. The general method of reserves assessment to determine
reasonable certainty of commercial recovery which BP employs relies on the integration of three
types of data: (1) well data used to assess the local characteristics and conditions of reservoirs and
fluids; (2) field scale seismic data to allow the interpolation and extrapolation of these characteristics
outside the immediate area of the local well control; and (3) data from relevant analogous fields.
Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples.
BP considers the integration of this data in certain cases to be superior to a flow test in providing a
better understanding of the overall reservoir performance. The collection of data from logs, cores,
wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic
data can allow reservoir properties to be determined over a greater volume than the localized
volume of investigation associated with a short-term flow test. Historically, proved reserves
recorded using these methods have been validated by actual production levels. As at the end of
2008, BP had proved reserves in 20 fields in the deepwater Gulf of Mexico that had been initially
booked prior to production flow testing. Of these fields, 18 are in production and two, Dorado and
Great White, are expected to begin production in 2009. Six other fields are in the early stages of
appraisal and development.
cThe 2008 year-end marker prices used were Brent $36.55/bbl (2007 $96.02/bbl and 2006
$58.93/bbl) and Henry Hub $5.63/mmBtu (2007 $7.10/mmBtu and 2006 $5.52/mmBtu).
d
Proved reserves in the Prudhoe Bay field in Alaska include an estimated 54 million barrels on which
a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay
Royalty Trust.
e
Includes 21 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and
Tobago LLC.
fIncludes 216 million barrels of crude oil in respect of the 6.80% minority interest in TNK-BP.
g
Includes 3,108 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad
and Tobago LLC.
h
Includes 131 billion cubic feet of natural gas in respect of the 5.92% minority interest in TNK-BP.

BP Annual Report and Accounts 2008
Performance review

The following tables show BP’s production by major field for 2008, 2007 and 2006.

Liquids

Alaska

Total Alaska
Lower 48 onshorec
Gulf of Mexico deepwaterc

Total Gulf of Mexico
Total US
UK offshorec

Total UK offshore
Onshore
Total UK
Netherlandsc
Norway

Total Rest of Europe
Angola

Australia
Azerbaijan

Canadac
Colombia
Egypt
Trinidad & Tobago
Venezuelac
Otherc
Total Rest of World
Total groupe
Equity-accounted entities (BP share)
Abu Dhabif
Argentina – Pan American Energy
Russia – TNK-BPc
Otherc
Total equity-accounted entities

Field or Area
Prudhoe Bayb
Kuparuk
Northstarb
Milne Pointb
Other

Various
Na Kikab
Thunder Horseb
Horn Mountainb
Kingb
Mars
Mad Dogb
Atlantisb
Other

ETAPd
Foinavenb
Magnusb
Schiehallion/Loyalb
Clairb
Hardingb
Andrewb
Other

Wytch Farmb

Various
Valhallb
Draugen
Ulab
Other

Dalia
Girassol
Greater Plutoniob
Kizomba A
Kizomba B
Other
Various
Azeri-Chirag-Gunashlib
Shah Denizb
Variousb
Variousb
Various
Variousb
Various
Various

Various
Various
Various
Various

w
e
v
e
r
e
c
n
a
m
r
o
f
r
e
P

thousand barrels per day

BP net share of productiona

Interest
26.4
Various
98.6
Various
Various

Various
Various
75.0
100.0
100.0
28.5
60.5
56.0
Various

Various
Various
85.0
Various
28.6
70.0
62.8
Various

67.8

Various
28.1
18.4
80.0
Various

16.7
16.7
50.0
26.7
26.7
Various
15.8
34.1
25.5
Various
Various
Various
100.0
Various
Various

Various
Various
Various
Various

2008
72
48
22
27
28
197
97
29
24
18
23
28
31
42
49
244
538
27
26
18
18
13
11
7
37
157
16
173
–
14
13
8
8
43
34
6
69
15
16
62
29
97
8
9
24
57
37
4
42
509
1,263

210
70
826
32
1,138

2007
74
52
28
28
27
209
108
32
–
18
22
30
25
2
67
196
513
32
37
16
20
9
14
8
50
186
15
201
–
17
14
12
8
51
31
14
12
36
35
12
34
200
5
8
28
43
30
16
35
539
1,304

192
69
832
17
1,110

2006
71
57
38
31
27
224
125
41
–
23
28
19
17
–
70
198
547
49
37
30
26
7
17
7
62
235
18
253
1
21
15
14
10
61
–
17
–
54
58
4
34
145
–
8
34
42
40
26
28
490
1,351

163
69
876
16
1,124

aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
bBP-operated.
cIn 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position and TNK-BP disposed of some non-core interests.
In 2007, BP divested its producing properties in the Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. In
2006, BP divested its producing properties on the Outer Continental Shelf of the Gulf of Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in the Boqueron, Desarollo
Zulia Occidental (DZO) and Jusepin projects in Venezuela were reduced following a decision by the Venezuelan government. TNK-BP disposed of its non-core interests in the Udmurtneft assets.
dVolumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell.
eIncludes 19 net mboe/d of NGLs from processing plants in which BP has an interest (2007 54mboe/d and 2006 55mboe/d).
fThe BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. During the second quarter of 2007, we updated our
reporting policy in Abu Dhabi to be consistent with general industry practice and as a result have started reporting production and reserves there gross of production taxes.

BP Annual Report and Accounts 2008
Performance review

Natural gas

Lower 48 onshoreb

Total Lower 48 onshore
Gulf of Mexico deepwaterb

Gulf of Mexico Shelfb
Total Gulf of Mexico
Alaska
Total US
UK offshoreb

Total UK
Netherlandsb

Norway
Total Rest of Europe
Australia
Canadab
China
Egypt

Indonesia

Sharjah

Azerbaijan
Trinidad & Tobago

Field or Area
San Juanc
Arkomac
Hugotonc
Tuscaloosac
Wamsutterc
Jonahc
Other

Na Kikac
Marlinc
Other
Other

Various

Braes
Brucec
West Solec
Marnockc
Britannia
Shearwater
Armada
Other

P/18-2
Other
Various

Interest
Various
Various
Various
Various
66.6
Various
Various

51.9
78.2
Various
Various

Various

Various
37.0
100.0
62.1
9.0
27.5
18.2
Various

48.7
Various
Various

Various
Variousc
Yachengc
Ha’pyc
Other
Sanga-Sanga (direct)c
Otherc
Sajaac
Other
Shah Denizc
Kapokc
Mahoganyc
Amherstiac
Parangc
Immortellec
Cassiac
Otherc
Various

million cubic feet per day

BP net share of productiona

2008
682
240
91
65
136
221
451
1,886
62
46
122
–
230
41
2,157
75
65
51
24
30
17
16
481
759
–
–
23
23
380
245
91
94
278
69
98
65
8
143
619
323
288
–
136
5
1,075
421
4,338
7,277

2007
694
204
123
78
120
173
458
1,850
50
13
205
1
269
55
2,174
69
72
55
25
37
19
16
475
768
–
3
26
29
376
255
85
108
206
75
81
83
9
73
984
454
155
–
153
25
663
466
4,251
7,222

2006
765
225
137
86
113
133
461
1,920
97
16
210
66
389
67
2,376
101
107
56
42
42
31
28
529
936
23
33
35
91
364
282
102
99
172
84
80
111
9
–
946
321
176
120
219
30
453
441
4,009
7,412

15.8
Various
34.3
50.0
Various
26.3
46.0
40.0
40.0
25.5
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Various

Otherb
Total Rest of World
Total groupd
Equity-accounted entities (BP share)
362
Argentina – Pan American Energy
Russia – TNK-BPb
544
Otherb
99
Total equity-accounted entitiesd
1,005
aProduction excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
bIn 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position. In 2007, BP divested its producing properties in the
Netherlands and some producing properties in the US Lower 48 and Canada. TNK-BP disposed of its interests in several non-core properties. In 2006, BP divested its producing properties on the
Outer Continental Shelf of the Gulf of Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in the Boqueron, Desarollo Zulia Occidental (DZO) and Jusepin projects in
Venezuela were reduced following a decision by the Venezuelan government. TNK-BP disposed of its non-core interests in the Udmurtneft assets.
cBP-operated.
dNatural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.

385
564
108
1,057

Various
Various
Various

379
451
91
921

BP Annual Report and Accounts 2008
Performance review

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

Crude oil production increased by 32mb/d, an increase of 8%

from 2007, primarily driven by major projects in the Gulf of Mexico, partly
offset by natural reservoir decline and the impact of hurricanes in the
third quarter.

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

Gas production was 17mmcf/d lower because of natural reservoir

decline and the impact of hurricanes, which was partly offset by
production from shale acquisitions.

Development expenditure in the US (excluding midstream) during

2008 was $4,914 million, compared with $3,861 million in 2007 and
$3,579 million in 2006. The year-on-year increase is the result of various
development projects in progress.

Our activities within the US take place in three main areas:

deepwater Gulf of Mexico, the Lower 48 states and Alaska. Significant
events during 2008 within each of these are indicated below.

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

• On 14 June 2008, first oil was achieved at Thunder Horse (BP 75%

and operator). Thunder Horse is the world’s largest semi-submersible
production facility, and is located 150 miles south-east of New
Orleans. It is designed to process 250,000 barrels of oil per day and
200 million cubic feet per day of natural gas. In 2008 four wells
started up with production of around 200,000boe/d (gross) at the
year-end, signalling the completion of commissioning. Production
started up in the Thunder Horse North field in February 2009.

• On 3 April 2008, BP announced an oil discovery at its Kodiak prospect
(BP 63.75% and operator). The well, located in Mississippi Canyon
block 771, approximately 60 miles south-east of the Louisiana Coast,
is in about 1,500 metres of water.

• In September 2008, Hurricanes Gustav and Ike resulted in most of
the Gulf of Mexico’s oil production being shut down. There was
minimal damage to most of BP’s platforms other than to the drilling
derrick on the Mad Dog platform, located approximately 190 miles
south of New Orleans. The production impact of both hurricanes was
a reduction equivalent to approximately 24mboe/d for the year.
• In October 2008, BP announced an oil discovery with its Freedom

well (BP 25% and operator). The well, located in Mississippi Canyon
Block 948, approximately 70 miles south-east of the Louisiana Coast,
is in about 1,860 metres of water. It is believed that Freedom
straddles Mississippi Canyon Block 948 and Mississippi Canyon Block
992. BP owns a 67.75% interest in Block 992.

w
e
v
e
r
e
c
n
a
m
r
o
f
r
e
P

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

In 2008, we drilled approximately 540 wells as operator and

continued to maintain a stable programme of drilling activity throughout
the year.

Production is derived from two main areas:

• In the western basins (Colorado, New Mexico and Wyoming), our

assets produced 224mboe/d in 2008.

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

Significant events were:

• In August 2008, BP acquired all Chesapeake Energy Corporation’s

interest in approximately 90,000 net acres of leasehold and producing
natural gas properties in the Arkoma basin Woodford Shale area for
$1.75 billion. BP took over production operations on 1 November and
retained three drilling rigs as part of the deal.

• In September 2008, BP acquired a 25% non-operated interest in
Chesapeake’s Fayetteville Shale assets for $1.9 billion comprising
$1.1 billion in cash at closing and an $800 million commitment to
fund Chesapeake’s 75% share of drilling and completion costs.
$183 million of this commitment was met in 2008, with the balance
expected to be paid by the end of 2009. The assets include
approximately 135,000 net acres of leasehold.

• In September 2008, in anticipation of Hurricane Gustav, operations
and activity were shut down in the Pascagoula NGL plant, South
Louisiana (Tuscaloosa field) and East Texas Exploration and Production
operations. Also in September, Hurricane Ike resulted in every field
location across South Louisiana, East Texas and the Permian Basin
having production shut in. Four NGL plants, Pascagoula, Block 31,
Crane and Midland, were shut down while other plants suffered
production impacts due to widespread outages and disruptions in the
midstream infrastructure. The impact of both hurricanes on production
was a reduction equivalent to approximately 2mboe/d for the year.

• In October 2008, BP sanctioned the Wamsutter Full Field

Development plan (Phase ll). This builds on the operational and
technological results of extensive field trials conducted during the
past three years.

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

BP operates 13 North Slope oil fields (including Prudhoe Bay,

Northstar and Milne Point) and four North Slope pipelines and owns a
significant interest in six other producing fields.

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

Significant events in 2008 were:

•

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

BP Annual Report and Accounts 2008
Performance review

the project at the BP-operated Endicott oilfield. BP drilled the Liberty
discovery well in 1997, and is the operator and sole owner of the field.

• In August 2008, BP successfully tested Cold Heavy Oil Production

with Sand (CHOPS) technology for the first time in Alaska, initiating a
four-well production test programme during the period from August
2008 until the end of 2009. This first test at Milne Point S Pad brought
oil and sand to the surface, where it was processed using temporary
field facilities, combined with other light oil production, and shipped
down the Trans-Alaska Pipeline System (TAPS). The CHOPS well tests
are part of a multi-year programme to determine the technical and
commercial feasibility of a large scale heavy oil development project
on the North Slope using existing cold and thermal technologies.

• During 2008, all four of the Prudhoe Bay Oil Transit Line segments

that were targeted for replacement in response to the oil spills in the
Prudhoe Bay field in March and August 2006 were completed and
placed in service.

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

Significant events in 2008 were:

• In February 2008, BP and its partner, Marathon Petroleum West of

Shetlands Ltd, announced a new oil discovery in UK Continental Shelf
Block 204/23 (BP 72%), following drilling on the South West Foinaven
prospect. BP, together with its partner, is evaluating the discovery and
the potential for a two-well subsea development, tied back to the
Foinaven Floating Production Storage and Offloading vessel (FPSO).
• In May 2008, BP and its co-venturers made an oil discovery in North

Sea Block 16/23s (BP 77.07%), named Kinnoull. The Kinnoull
discovery and potential development options, including a subsea
development tied back to BP’s Andrew field, are being evaluated.
• During the third quarter, the first phase of offshore removal activity
for the North West Hutton platform decommissioning programme
was completed. This is BP’s biggest decommissioning project so far
in the North Sea and has seen the removal of 22 separate topsides
modules, which were then taken away by barges to the Able UK yard
on Teesside for recycling and disposal. It is estimated that around
97% of the material recovered will be recycled and/or reused.

• In December 2008, BP and BG Group agreed to exchange a package
of North Sea assets. This is expected to strengthen BP’s position
as a major operator in the Southern North Sea and to facilitate
development activity and investment in the UK Continental Shelf. BP
agreed to acquire BG’s 24.2% interest in the BP-operated Amethyst
field and all its interests in the Easington Catchment Area (ECA)
fields, including a 73.3% interest in the Mercury field, a 79% interest
in the Neptune field, a 65% interest in the Minerva, Apollo and
Artemis fields and BG’s 30.8% interest in the BP-operated Whittle
and Wollaston fields. BG Group agreed to acquire BP’s interest and
operatorship in the Everest (BP 21.1%) and Lomond (BP 22.2%)
fields, BP’s 18.2% interest in the BG-operated Armada field and 32%
of the Chevron-operated Erskine field (BP will retain 18% equity in
Erskine). The deal is subject to government, regulatory and partner
approvals and completion is expected in the second quarter of 2009.

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

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

Rest of Americas
Canada
• In Canada, our natural gas and liquids production was 51mboe/d in
2008, a decrease of 1% compared with 2007. The year-on-year
decrease in production is mainly due to natural field decline.

• On 31 March 2008, BP and Husky Energy Inc. (Husky) completed a
deal to create an integrated North American oil sands business by
means of two separate 50:50 joint ventures, BP-Husky Refinery LLC,
operated by BP, and the Sunrise Oil Sands Partnership (SOSP),
operated by Husky. BP’s capital expenditure in respect of the creation
of SOSP amounted to $2.8 billion.

• In June 2008, BP successfully acquired three of five exploration

licences on offer in the Canadian section of the Beaufort Sea through
a Call for Bids process issued by The Department of Indian and
Northern Affairs of Canada. The leases awarded to BP cover about
611,000 hectares of the Beaufort seabed, north of Tuktoyaktuk,
Northwest Territories. These are in addition to the 15 significant
discovery licences that BP currently holds in the Beaufort Sea, and
two exploration licences currently in moratorium. The term for
exploration licences issued from this Call for Bids is nine years
consisting of two consecutive periods. There is a $300 million work
obligation associated with acquiring these exploration licences.

Trinidad
• In Trinidad, natural gas production volumes increased from

420mboe/d in 2007 to 422mboe/d in 2008. The increase was a result
of improved operating efficiency on the Atlantic LNG Trains combined
with increased demand from the domestic market and full ramp-up of
two new fields, Mango and Cashima. Liquids production increased by
7mb/d (23%) to 37mb/d in 2008 from 30mb/d in 2007 as a result of
an increase in NGLs associated with higher throughput for the Trains,
increased crude and condensate from the two new fields and liquid
optimization activities.

• In December 2008, a new oil export pipeline was commissioned

to transport liquids from offshore fields to onshore delivery points.
BP owns 100% of the capacity of the pipeline.

• Progress on Savonette, BP’s next field development in Trinidad,
continued throughout the year and first gas is expected to be
delivered in 2009.

• In 2008, the Day Away from Work Case injury frequency (per 200,000
work hours) has been reduced from 0.12 in 2003 to zero in 2008 and
the recordable injury frequency has more than halved in the same
period. This has come about through the development and
implementation of a comprehensive multi-year safety plan, focused
on coaching safety leaders, workforce communication, standard
implementation and continuous learning.

BP Annual Report and Accounts 2008
Performance review

Venezuela
• In Venezuela, despite the transition since 2006 of BP’s interests to
incorporated joint venture (IJV) entities with the state oil company
Petróleos de Venezuela, S.A. (PDVSA), and OPEC quotas, 2008 liquids
production increased by 3mb/d compared with 2007.

• In the second quarter of 2008, BP concluded the migration of the
Cerro Negro operations to an IJV with PDVSA while retaining the
same equity interest.

Colombia
• In Colombia, BP’s net production averaged 38mboe/d. The reduction

of 8mboe/d compared with 2007 is mainly due to natural field decline
and lower gas transfers from Recetor (BP 50%) to Santiago de las
Atalayas (BP 31%). The main part of the production comes from the
Cusiana, Cupiagua and Cupiagua South fields, with increasing new
production from the Cupiagua extension into the Recetor Association
Contract and the Floreña and Pauto fields in the Piedemonte
Association Contract.

• On 20 June 2008, the National Hydrocarbon Agency gave its official
approval for equalization of RC4 and RC5 Caribbean offshore blocks
with partners Ecopetrol and Petrobras, with the main objective of
simplifying partner relations and agreements. New equity interests
resulting from this approval are BP 40.6%, Ecopetrol 32% and
Petrobras 27.4%. Seismic operations for these two blocks were
completed successfully. Processing and interpretation of the data to
determine potential prospects for offshore field developments and
drilling operations is under way and is expected to be completed
in 2009.

Argentina, Bolivia and Chile
• In Argentina, Bolivia and Chile, activity is conducted through Pan

American Energy (PAE), a joint venture company in which BP holds
a 60% interest, and which is accounted for by the equity method.
In 2008, total PAE gross production of 250mboe/d represented an
increase of 3% compared with 2007. Most of this production comes
from the Cerro Dragón field in the provinces of Chubut and Santa
Cruz. The field is now producing at its highest level since inception of
the licence area in 1958. PAE also has other assets producing gas and
liquids in the Argentine provinces of Salta, Neuguén and Tierra del
Fuego, and in Bolivia, as well as interests in exploration areas,
pipelines, electricity generation plants and other midstream
infrastructure assets, primarily in Argentina.

• In 2007 and early 2008, PAE was granted extensions of the two
principal Cerro Dragón licence areas by the provinces of Chubut
and Santa Cruz in exchange for material long-term investment
commitments in exploration and production, and for long-term
commitments to local community and supplier development. The
licence expiry dates have been extended from 2017 to 2027, with
further extension potential to 2047.

• In May 2008, following its decree of 2006 requiring all private owners
of shares in Bolivian oil and gas companies to transfer back a majority
shareholding to the Bolivian national oil company Yacimientos
Petrolíferos Fiscales Bolivianos (YPFB), the Bolivian government
issued a second decree requiring this transfer to be made with
immediate effect. PAE, as the majority shareholder of Empresa
Petrolera Chaco S.A. (Chaco), a company created in the 1990s, was
affected by these decrees. PAE was required to sell approximately
1% of the share capital of Chaco to YPFB, such that YPFB would own
50% plus one share of the total. From May 2008 and into January
2009, PAE was in discussions with the government regarding the
decrees and options for implementation. However, on 23 January
2009, the president of Bolivia issued a decree nationalizing PAE’s
shareholding in Chaco. PAE is currently evaluating all options to
preserve the value of its shareholding.

• On 26 November 2008, the Argentine government issued a decree

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

Africa
Algeria
• BP, through its joint operatorships of the In Salah Gas (33.15%) and
In Amenas (12.5%) projects, supplied 33mboe/d (BP net) to markets
in Algeria and southern Europe during 2008. This is a decrease of
15% from 39mboe/d in 2007 as a result of lower gross volumes at In
Salah due to planned turnaround maintenance and the impact of
lower entitlement in our PSAs driven by higher prices, partly offset by
improved operating efficiency at In Amenas. Further, BP, through its
joint operatorship of the Rhourde El Baguel field, received 4.4mboe/d
(BP net) of oil in 2008.

• Sonatrach and BP announced an exploration success with the Tin

Zaouatene-1 (TZN-1) discovery in the Bourarhet Sud Blocks 230 and
231. On 24 September 2008, BP moved into the second prospecting
period, which lasts for a further two years.

Angola
• In Angola, BP net production in 2008 was 202mboe/d, an increase of
45% from 2007 due to the start-up of the Mondo, Saxi and Batuque
(Kizomba C, BP 26.67%) fields, and the ramp-up of the Greater
Plutonio field (BP 50% and operator), more than offsetting the impact
of lower entitlement in our PSAs driven by higher prices in existing
fields. We expect to have invested over $15 billion in our Angolan
business by 2010.

• In January 2008, the Kizomba C project (BP 26.67%) came onstream
with the start-up of the Mondo field, followed by first production from
the Saxi and Batuque fields in July 2008. The Kizomba C development
is located approximately 140 kilometres off the coast of Angola in
water depths of nearly 800 metres.

• In June 2008, the Plutão, Saturno, Vênus and Marte (PSVM) project

was authorized by Sonangol. The programme is expected to comprise
four fields that lie in the north east sector of Block 31 (BP 26.67%
and operator), in a water depth of approximately 2,000 metres, some
400 kilometres north west of Luanda. Contracts have been awarded
and construction work started during 2008.

• During the third quarter of 2008, production was shut down at the

•

Greater Plutonio FPSO located in deepwater Block 18 (BP 50% and
operator), offshore Angola, due to operational issues. Production was
restarted on 12 October 2008. The adverse impact on full-year
production was 14mb/d.
In the ultra deepwater Block 31 (BP 26.67% and operator), there was
further exploration success with the Portia and Dione wells, bringing the
total successes for Block 31 to 16. The Portia well is located in a water
depth of approximately 2,000 metres, some 386 kilometres north-west
of Luanda. The Dione well is located in a water depth of approximately
1,700 metres, some 390 kilometres north-west of Luanda.

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Egypt
• In Egypt, BP net production was 121mboe/d, an increase of 25%

•

from 97mboe/d in 2007. This increase was mainly due to the start-up
of two new fields, Saqqara and Taurt, and the full-year impact from
Denise, which started up at the end of 2007.
In January 2008, BP completed drilling a successful exploration well,
Satis-1, in the North El Burg offshore concession (BP 50% and
operator). The Satis-1 well was drilled in approximately 90 metres of
water, some 50 kilometres offshore, and is in the Oligocene formation.

• In January 2008, an oil discovery was announced in the North

Shadwan (BP 50% and operator) concession located in the southern
part of the Gulf of Suez. The NS394-1A exploration well was drilled in
shallow water seven kilometres from the Hilal field. This discovery is
the first new oil discovery in the south-eastern area of the Gulf of
Suez in more than 10 years and is also the first discovery drilled by
BP which has been facilitated by modern, high-quality, ocean-bottom
cable (OBC) seismic data.

• On 15 May 2008, oil production from the Saqqara field (BP 100%)
started. The Saqqara field, operated by the Gulf of Suez Petroleum
Company (GUPCO), a joint venture operating company between BP
and the Eygptian General Petroleum Corporation (EGPC), is located
13 kilometres offshore in the central Gulf of Suez. Natural gas
production commenced on 26 July 2008. The Saqqara development
includes a jacket and unmanned topsides, three wells, and a
13-kilometre pipeline to a new dedicated onshore separation
and gas processing plant at Ras Shukeir on the Gulf of Suez.
Local contractors were used for design, onshore construction and
offshore fabrication work.

• In July 2008, natural gas production began from the Taurt field (BP

50%). The Taurt field is located between the Ras El Bar Concession
(BP 50% and operator) and the Temsah Concession (BP 50%),
70 kilometres offshore to the north-east of Port Said, East Nile Delta.
Gross Taurt production ramped up to 230mmcf/d in August. The Taurt
development includes a Subsea Production System (SPS), two
subsea wells, and a 70-kilometre pipeline and control umbilical back
to upgraded facilities at the existing West Harbor processing plant.
Taurt is BP’s first subsea development in Egypt and also the first
of a planned programme of future subsea developments. Local
contractors were used for onshore design/modifications and subsea
structure construction.

Libya
• In Libya, BP and its partner, the Libyan Investment Corporation (LIC)

commenced seismic operations on the acreage covered under the
exploration and production-sharing agreement ratified in December
2007. In September 2008, the offshore seismic acquisition survey
commenced in the Mediterranean waters of Libya's Gulf of Sirt.
At the end of 2008, the onshore seismic operations commenced
in the northern Ghadames block.

Asia Pacific
Indonesia
• BP produces crude oil in, and supplies natural gas to, the island
of Java through its holding in the Offshore Northwest Java PSA
(BP 46%). In 2008, BP net production was 22mboe/d, an increase
of 18% from 18.6mboe/d in 2007 as a result of improved operating
efficiencies and increased gas demand in Java.

• BP is operator of the Tangguh LNG project (BP 37.2%), which

includes offshore platforms, pipelines and an LNG plant with two
production trains with a total capacity of 7.6 million tonnes per annum
(mtpa). In May 2008, gas was introduced from one of the two
offshore platforms into the Onshore Receiving Facility (ORF).
First commercial delivery of LNG is expected in the second
quarter of 2009.

• BP has a 50% interest in Virginia Indonesia Company LLC (Vico),

the operator of the Sanga-Sanga PSA (BP 38%) supplying feedgas
to Indonesia’s largest LNG export facility, the Bontang LNG plant
in Kalimantan.

Vietnam
• BP participates in one of the country’s largest foreign investment

projects, the Nam Con Son gas project. This is an integrated resource
and infrastructure project, which includes offshore gas production, a
pipeline transportation system and a power plant. At midnight on
31 December 2007, the operation of the Nam Con Son Pipeline (BP
32.67%) transferred from BP to PetroVietnam (PVN). In September
2008, capacity of the Nam Con Son Pipeline was increased by 30%
to allow for additional current and future expected volumes.

• In 2008, BP net natural gas production was 61mmcf/d, a decrease

of 26% from 82mmcf/d in 2007, primarily due to lower PSA
entitlements. Gas sales from Block 6.1 (BP 35% and operator) are
made under a long-term agreement for electricity generation at the
Phu My 3 power plant (BP 33.3%).

• BP has determined that its licences in Blocks 5.2 (BP 55.9% and

operator) and 5.3 (BP 75% and operator) do not fit within its current
portfolio and has decided to withdraw from them. BP is currently in
active discussions with PVN, the Vietnamese government and joint
venture partners to progress this withdrawal.

China
• In 2008, natural gas production was 91mmcf/d BP net, an increase of
7% compared with 2007. This increase was mainly due to increased
gas demand. A new development project was sanctioned in late 2008
to help meet the expected increase in demand in 2010 and beyond.
• The Yacheng offshore gas field (BP 34.3%) supplies Castle Peak Power

Company with feedgas for up to 70% of Hong Kong’s gas-fired
electricity generation. Additional gas is also sold to the Fuel & Chemical
Company of Hainan.

• In March 2007, the National People’s Congress reduced the rate of
corporation tax from 33% to 25% with effect from 1 January 2008.

Australia
• BP is one of seven partners in the North West Shelf (NWS) venture.
Six partners (including BP) hold an equal 16.67% interest in the
infrastructure and oil reserves and an equal 15.78% interest in the
gas and condensate reserves, with a seventh partner owning the
remaining 5.32% of gas and condensate reserves. The NWS venture
is currently the principal supplier to the domestic market in Western
Australia and one of the largest LNG export projects in Asia with five
LNG Trains in operation.

• In 2008, BP net gas production was 380mmcf/d, an increase of 1%
from 2007 primarily due to increased domestic gas demand in
Western Australia and the startup of NWS Train 5 and the Angel
platform in the third quarter. BP net liquids production was 29mb/d,
a decrease of 15% from 2007 due to natural field decline.

• In March 2008, the North Rankin 2 (NR2) project was sanctioned.
This links a second platform via a 100-metre bridge to the existing
North Rankin A (NRA) platform. On completion, NRA and NR2
platforms are expected to be operated as a single integrated facility
and to recover low pressure gas from the North Rankin and Perseus
gas fields.
In September 2008, a fifth LNG train was successfully completed and
commenced production at the Karratha gas plant. Train 5 increases
NWS total annual production capacity from 11.9 to 16.3 million tonnes.

•

• The Angel platform (BP 16.67%) was successfully commissioned
and started producing gas during October 2008. Angel has a gross
production capacity of 800 million standard cubic feet of raw gas
and up to 50,000 barrels of condensate per day.

BP Annual Report and Accounts 2008
Performance review

Russia
TNK-BP
• TNK-BP, a joint venture between BP (50%) and Alfa Group and

Access-Renova (AAR) (50%), is an integrated oil company operating
in Russia and the Ukraine. The TNK-BP group’s major assets are held
in OAO TNK-BP Holding. Other assets include the BP-branded retail
sites in Moscow and the Moscow region and interests in OAO Rusia
Petroleum and the OAO Slavneft group. The workforce comprises
more than 60,000 people.

• BP’s investment in TNK-BP is held by the Exploration and Production
segment and the results of TNK-BP are accounted for under the
equity method in this segment.

• TNK-BP has proved reserves of 7.1 billion barrels of oil equivalent

(including its 49.9% equity share of Slavneft), of which 5 billion are
developed. In 2008, TNK-BP’s average liquids production was
1.65mmb/d, a decrease of just under 1% compared with 2007. The
production base is largely centred in West Siberia (Samotlor, Nyagan
and Megion), which contributes about 1.2mmboe/d, together with
Volga Urals (Orenburg) contributing some 0.4mmboe/d. About 40%
of total oil production is currently exported as crude oil and 20% as
refined product.

• Downstream, TNK-BP has interests in six refineries in Russia and the
Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl
refinery), with throughput of approximately 34 million tonnes per
year. During 2008, TNK-BP purchased additional retail and other
downstream assets in Russia and the Ukraine from a number of
small companies. TNK-BP supplies approximately 1,400 branded
filling stations in Russia and the Ukraine and, with the additional sites,
is expected to have more than 20% market share of the Moscow
retail market.

• On 9 January 2009, BP reached final agreement on amendments to
the shareholder agreement with its Russian partners in TNK-BP. The
revised agreement is aimed at improving the balance of interests
between the company's 50:50 owners, BP and Alfa Access-Renova
(AAR), and focusing the business more explicitly on value growth.
• The former evenly-balanced main board structure has been replaced
by one with four representatives each from BP and AAR, plus three
independent directors. Unanimous board support is required for
certain matters including substantial acquisitions, divestments and
contracts, and projects outside the business plan, together with
approval of key changes to the TNK-BP group’s financial framework
and of related party transactions. A number of other matters will be
decided by approval of a majority of the board, so that the
independent directors will have the ability to decide in the event of
disagreement between the shareholder representatives on the board.
BP will continue to nominate the chief executive, subject to main
board approval, and AAR will continue to appoint the chairman. The
three independent directors appointed to the restructured main board
are Gerhard Schroeder, former chancellor of the Federal Republic
of Germany, James Leng, former chairman of Corus Steel and
Alexander Shokhin, president of the Russian Union of Industrialists
and Entrepreneurs. In addition, significant TNK-BP subsidiaries will
have directors appointed by BP and AAR on their boards. Our
investment in TNK-BP will be reclassified from a jointly controlled
entity to an associate with effect from 9 January 2009.

• The parties have confirmed their agreement to a potential future sale

of up to 20% of a subsidiary of TNK-BP through an initial public
offering (IPO) at an appropriate future point, subject to certain
conditions and the consent of the Russian authorities.

• In 2007, BP and TNK-BP signed heads of terms to create strategic
business alliances with OAO Gazprom. Under the terms of this
agreement, TNK-BP agreed to sell to Gazprom its stake in OAO Rusia
Petroleum, the company that owns the licence for the Kovykta gas
condensate field in East Siberia and its interest in East Siberia Gas
Company. Discussions to conclude this disposal continue.

Sakhalin
• BP and its Russian partner Rosneft agreed two Shareholder and

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

Other
Azerbaijan
• In Azerbaijan, BP’s net production in 2008 was 130mboe/d, a net

decrease of 40% from 2007. The primary elements of this were the
effects of significantly higher prices resulting in a change in profit oil
entitlement in line with the terms of the PSA and reduced cost oil
entitlement, partially offset by an increase following the start-up of
the Deepwater Gunashli (DWG) platform, the ramping up of three
Azeri oil-producing platforms and the Shah Deniz condensate gas
platform commencing production in 2007.

• The DWG platform complex successfully started oil production

on schedule on 20 April 2008. DWG completes the third phase of
development of the Azeri-Chirag-Gunashli (ACG) field (BP 34.1%
and operator) in the Azerbaijan sector of the Caspian Sea. The DWG
complex is located in a water depth of 175 metres on the east side of
the Gunashli field. The complex comprises two platforms – a drilling
and production platform linked by a bridge to a water injection and
gas compression platform.

• On 17 September 2008, a subsurface gas release occurred below the
Central Azeri platform. As a precautionary measure, all personnel on
the platform were safely transferred onshore. The Central Azeri
platform was shut down until 19 December 2008, when following
comprehensive investigation and recovery work, BP began to resume
oil and gas production. Central Azeri processes oil and gas from West
Azeri, and West Azeri was also temporarily shut down and then
restored to normal operations on 9 October 2008. Operations of the
Compressor and Water Injection Platform (CWP), which is linked
by a bridge to Central Azeri, and the provision of power and injection
water across three Azeri field platforms were re-established on
12 October 2008.

Middle East and South Asia
• Production in the Middle East consists principally of the production
entitlement of associates in Abu Dhabi, where we have equity
interests of 9.5% and 14.7% in onshore and offshore concessions
respectively. In 2008, BP’s share of production in Abu Dhabi was
210mb/d, up 9% from 2007 as a result of higher overall OPEC
demand despite cuts implemented in the fourth quarter of 2008.
• In July 2008, BP Sharjah signed a farm-out agreement with RAK
Petroleum for the East Sajaa concession. Drilling of the first
exploration well is expected in 2009.

• In Block 61 in Oman, the challenges posed by the world’s largest

onshore azimuth 3D seismic survey led the BP Oman team to use
a ground-breaking new technique known as Distance Separated
Simultaneous Sweeping (DS3). This technique allows the acquisition

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in a single day of as much seismic data as previously obtained in
a week. The invention of DS3 along with some other innovations
allowed an efficient and cost effective survey of the Block to be
completed within a six-month period. The first appraisal well was
spudded in September 2008.
In Pakistan, BP’s net oil production in 2008 was 8.2mboe/d, an
increase of 30% from 2007, and BP’s net gas production was
28.2mboe/d, an increase of 34% from 2007 as a result of the full-year
impact of BP increasing its equity in the onshore Badin asset in 2007
to 84%.
In Pakistan, BP received an 18-month extension until January 2010
in Phase 1 of the initial term of Exploration Licences in respect of
the offshore Indus PSA.

•

• On 30 December 2008, BP signed completion documents with
Orient Petroleum International Inc., to acquire a 51.3% working
interest, along with operatorship, in two joint venture blocks,
Mirpurkhas and Khipro, located in the southern Sindh province
of Pakistan.

• On 22 December 2008, BP signed a production-sharing contract
with the Indian government for a deepwater exploration block in
the Krishna-Godavari Basin, offshore eastern India, which was
awarded under the New Exploration Licensing Policy Seventh
round. BP is the designated operator with a 30% working interest
in the block. Reliance Industries Limited holds the remaining
70% working interest.

Midstream activities
Oil and natural gas transportation
The group has direct or indirect interests in certain crude oil
transportation systems, the principal ones being the Trans-Alaska Pipeline
System (TAPS) in the US, the Forties Pipelines System (FPS) in the UK
sector of the North Sea and the Baku-Tbilisi-Ceyhan (BTC) oil pipeline.
In addition to these, we also operate the Central Area

Transmission System (CATS) for natural gas in the UK sector of the North
Sea, the Western Export Route Pipeline between Azerbaijan and the
Black Sea coast of Georgia (as operator of AIOC), and, as technical
operator, the South Caucasus Pipeline (SCP) (BP 25.5%), which takes
gas from Azerbaijan through Georgia to the Turkish border.

BP’s onshore US crude oil and product pipelines and related

transportation assets are included under Refining and Marketing (see
page 31).

Assets and activity during 2008 included:

Alaska
• BP owns a 46.9% interest in TAPS, with the balance owned by four

other companies. Production transported by TAPS from Alaska North
Slope fields averaged 700mb/d during 2008.

• Work on the strategic reconfiguration project to upgrade and

automate four TAPS pump stations continued to progress in 2008.
This project is installing electrically-driven pumps at four critical pump
stations, along with increased automation and upgraded control
systems. Two of the reconfigured pump stations came online during
2007. The remaining two reconfigured pump stations are expected to
come online sequentially, one in 2009 and one in 2010.

• On 8 April 2008, BP and ConocoPhillips announced the formation

of a joint venture company called Denali – The Alaska Gas Pipeline.
The joint venture has begun work on an Alaska gas pipeline project
consisting of a gas treatment plant on Alaska’s North Slope, a large
diameter pipeline that is intended to pass through Alaska into Canada,
and should it be required, a large-diameter pipeline from Alberta to
the Lower 48 United States. When completed, the pipeline is
expected to move approximately 4 billion cubic feet of natural gas per
day to market. The joint venture plans to spend up to $600 million
prior to reaching the first major project milestone, an ’open season’,
before the end of 2010. An open season is a process during which

the joint venture seeks customers to make firm, long-term
transportation commitments to the project. Should the open season
be successful, the joint venture will seek certification from the
Federal Energy Regulatory Commission (FERC) of the US and the
National Energy Board (NEB) of Canada to move forward with project
construction. The new joint venture company will manage the project,
and will own and operate the pipeline when completed. BP and
ConocoPhillips may consider other equity partners, including pipeline
companies, who can add value to the project and help manage the
risks involved. On 22 May 2008, the office of the Governor of Alaska
announced that it would be supporting an alternative gas pipeline
project proposed by TransCanada Alaska Company in response to the
State of Alaska’s request for bids under the Alaska Gas Inducement
Act (AGIA) in 2007. BP’s commitment to move forward with the
Denali project is independent of any decisions made or inducement
offered by the State under the AGIA process and BP believes that the
Denali project offers the best opportunity for a successful Alaska gas
pipeline project.

• Alaska state courts issued two noteworthy rulings in 2008, related to
challenges filed by in-state refiners against BP and the other TAPS
carriers, regarding intrastate tariffs charged for shipping oil through
TAPS during the period from 1997 through 2003. These rulings are
related to long-standing challenges that were originally filed with the
Regulatory Commission of Alaska (RCA). In 2002, the RCA issued
Order 151, which determined that TAPS transportation rates charged
from the beginning of 1997 were excessive, and that refunds should
be paid. BP and the other TAPS carriers appealed the RCA’s 2002
ruling in the State of Alaska court system. In the interim, the RCA
issued Order 34, which imposed intrastate tariff rates consistent with
Order 151, effective from 1 July 2003 forward. On 15 February 2008,
the Alaska Supreme Court affirmed the determination in RCA’s Order
151, and on 26 February 2008, the Alaska Superior Court affirmed the
RCA’s Order 34, and imposed the application of Order 151 to
intrastate tariff rates charged from 2001 forward. BP and the other
TAPS carriers decided not to appeal these matters any further in the
courts, and on 25 March 2008, BP Pipelines Alaska paid refunds to
intrastate shippers totalling $71 million covering the period 1997
through 2000. During the third quarter of 2008, BP Pipelines Alaska
paid out an additional $75 million to intrastate shippers covering the
period from 2001 through 30 June 2003. In 2008, intrastate transport
made up approximately 13.7% of total TAPS throughput.

• Tariffs for interstate transportation of oil through TAPS are calculated

using the TAPS Tariff Settlement Methodology (TSM), which is
defined in an agreement entered into with the State of Alaska in
1985. The TSM was also accepted at that time by the Regulatory
Commission of Alaska (RCA) and the Federal Energy Regulatory
Commission (FERC). Since then, Anadarko, Tesoro, and the State of
Alaska have challenged the interstate tariffs charged by BP and the
other TAPS carriers in the years 2005, 2006 and 2007 with the FERC.
Anadarko and the State of Alaska have also challenged the 2008
tariffs. In 2006, the FERC consolidated the proceedings related to the
years 2005-2006, and determined that the challenges pertaining to
2007 tariff rates would be held in abeyance until a decision was
issued in the proceedings on 2005 and 2006 tariff rates. The FERC’s
hearings on the consolidated proceedings commenced in October
2006 and concluded in January 2007. On 17 May 2007, a FERC
Administrative Law Judge (ALJ) issued an initial decision on 2005 and
2006 tariff rates that was adverse to BP and the other TAPS carriers,
and established a floor of $3.01/bbl for the 2005-2006 period, as this
was the last uncontested tariff rate. On 20 June 2008, the FERC
issued a ruling on the 2005-2006 period, which substantially affirmed
the initial ruling by the ALJ, and ordered the TAPS carriers to pay
refunds to shippers. On 20 November 2008, the FERC affirmed its
20 June 2008 ruling in response to applications for rehearing filed by
BP and the other TAPS carriers. Accordingly, in December 2008 BP as

BP Annual Report and Accounts 2008
Performance review

a TAPS carrier paid third party shippers tariff refunds of $52 million;
and BP as a TAPS shipper received tariff refunds from third party
carriers of $27 million. The FERC’s 20 November 2008 ruling also
concluded that a unified tariff rate should be established for interstate
transportation through TAPS, and the TAPS carriers were ordered to
implement a revenue pooling methodology in the TAPS Operating
Agreement. Some TAPS carriers other than BP have filed legal
challenges to this aspect of the FERC’s 20 November 2008 ruling,
which are still pending. As of the end of 2008, there have been no
proceedings in the challenges to BP’s and the other TAPS carriers’
2007 and 2008 tariff rates. In 2008, interstate transport made up
approximately 86% of total TAPS throughput.

North Sea
• FPS (BP 100%) is an integrated oil and NGLs transportation and

processing system that handles production from more than 50 fields
in the Central North Sea. The system has a capacity of more than one
million barrels per day, with average throughput in 2008 of 662mb/d.

• BP operates and has a 29.5% interest in CATS, a 400-kilometre

natural gas pipeline system in the central UK sector of the North Sea.
The pipeline has a transportation capacity of 1,700mmcf/d to a natural
gas terminal at Teesside in north-east England. CATS offers natural
gas transportation and processing services. In 2008, throughput was
836mmcf/d (gross), 247mmcf/d (net).

• BP operates the Dimlington/Easington gas processing terminal

(BP 100%) on Humberside and the Sullom Voe oil and gas terminal
in Shetland.

Asia (including the former Soviet Union)
• BP, as operator, manages and holds a 30.1% interest in the BTC
oil pipeline. The 1,768-kilometre pipeline transports oil from the
BP-operated ACG oil field in the Caspian Sea to the eastern
Mediterranean port of Ceyhan. The Turkish section of the pipeline is
operated by Botas.

• On 6 August 2008, the Baku-Tbilisi-Ceyhan (BTC) pipeline was shut
down for 14 days as a result of a fire that occurred at Block Valve 30,
located in the Erzincan province in Eastern Turkey. The pipeline
restarted on 20 August 2008. The Azeri-Chirag-Gunashli (ACG) and
Shah Deniz (SD) fields reduced offshore production to manage stock
levels at the Sangachal Terminal. Some exports were maintained via
the Northern Route Export Pipeline (NREP) and by rail through Georgia.

• BP is technical operator of, and holds a 25.5% interest in, the

693-kilometre South Caucasus Pipeline (SCP), which takes gas from
Azerbaijan through Georgia to the Turkish border. During August 2008,
the South Caucasus gas and Western Route oil export pipelines were
shut down for a short period as a precautionary measure during a
period of military activity in the region.

• In February 2008, BP, on behalf of AIOC, handed over operatorship of
the Azerbaijani section of the NREP between Azerbaijan and Russia to
the State Oil Company of Azerbaijan Republic (SOCAR).

• Through the LukArco joint venture, BP holds a 5.75% interest in the
Caspian Pipeline Consortium (CPC) pipeline and a 2.3% interest in
Tengizchevroil (TCO). CPC is a 1,510-kilometre pipeline from
Kazakhstan to the Russian port of Novorossiysk and carries crude oil
from a number of Kazakh fields, including Tengiz. In addition to our
interest in LukArco, we hold a separate 0.87% interest in CPC
through a 49% holding in Kazakhstan Pipeline Ventures (KPV). In
2008, CPC total throughput reached 32.2 million tonnes. During 2008,
the majority of shareholders in CPC agreed on the commercial terms
for expansion of CPC to 67 million tonnes. These terms strongly
favour the upstream, and as BP has no additional volumes of Kazakh
crude to ship in an expanded CPC, BP has been unable to support
these new commercial terms. In order not to delay the expansion
of CPC, BP has obtained the agreement of its KPV joint venture
partners and CPC shareholders to dispose of its interest in KPV

and is seeking the agreement of its joint venture partners, CPC
shareholders and TCO partners to dispose of its interest in LukArco.
• On 25 September 2008, Chevron announced that Tengizchevroil had

completed a major expansion at the Tengiz field in Kazakhstan in which
BP holds a 2.3% interest through its joint venture with LukArco.
The completion of the expansion brings daily crude capacity of the
field to 540mb/d.

Liquefied natural gas
Our LNG activities are focused on building competitively advantaged
liquefaction projects, establishing diversified market positions to create
maximum value for our upstream natural gas resources and capturing
third party LNG supply to complement our equity flows.
Assets and activity during 2008 included:

• In Trinidad, BP’s net share of the capacity of Atlantic LNG Trains 1, 2, 3

and 4 is 6 million tonnes of LNG per year (292 billion cubic feet
equivalent re-gasified), with the Atlantic LNG Train 4 (BP 37.8%)
designed to produce 5.2 million tonnes (253 billion cubic feet) per
year of LNG. All of the LNG from Atlantic Train 1 and most of the LNG
from Trains 2 and 3 is sold to third parties in the US and Spain under
long-term contracts. All of BP’s LNG entitlement from Atlantic LNG
Train 4 and some of its LNG entitlement from Trains 2 and 3 is
marketed via BP's LNG marketing and trading business to a variety of
markets including the US, the Dominican Republic, Spain, the UK and
the Far East.

• We have a 10% equity shareholding in the Abu Dhabi Gas

Liquefaction Company, which in 2008 supplied 5.8 million tonnes
(298.746mmcf) of LNG, up 3% from 2007.

• BP has a 13.6% share in the Angola LNG project, which is expected
to receive approximately one billion cubic feet of associated gas per
day from offshore producing blocks and to produce 5.2 million tonnes
gross per year of LNG, as well as related gas liquids products. With
the completion of the necessary agreements and the approval of the
Angolan government, the project investors have authorized Angola
LNG Limited to proceed with the construction and implementation of
the project.

• In Indonesia, BP is involved in two of the three LNG centres in the
country. BP participates in Indonesia’s LNG exports through its
holdings in the Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently
delivers around 13% of the total gas feed to Bontang, one of the
world’s largest LNG plants. The Bontang plant produced 18.4 million
tonnes of LNG in 2008.

• Also in Indonesia, BP has interests in the Tangguh LNG joint venture
(BP 37.2% and operator) and in each of the Wiriagar (BP 38% and
operator), Berau (BP 48% and operator) and Muturi (BP 1%) PSAs
in north-west Papua that are expected to supply feed gas to the
Tangguh LNG plant. During 2008, construction continued on two LNG
trains and the offshore facilities, with commercial delivery planned in
the second quarter of 2009. Tangguh will be the third LNG centre in
Indonesia, with an expected initial capacity of 7.6 million tonnes of
LNG (388,000mmcf) per year. Tangguh has signed LNG sales
contracts for delivery to China, Korea and North America.

• In Australia, we are one of seven partners in the North West Shelf

(NWS) venture. The joint venture operation covers offshore
production platforms, an FPSO, trunklines, onshore gas and LNG
processing plants and LNG carriers. BP’s net share of the capacity of
NWS LNG Trains 1-5 is 2.7 million tonnes of LNG per year.

• BP has a 30% equity stake in the 7 million tonne per annum capacity
Guangdong LNG re-gasification and pipeline project in south-east
China, making it the only foreign partner in China’s LNG import
business. In addition to LNG supplied under a long-term contract with
Australia’s NWS project, the terminal took delivery of an additional
eight spot LNG cargoes during 2008, to meet rapidly growing local
demand for gas.

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delivery and settlement at a future date. Typically, these contracts specify
delivery terms for the underlying commodity. Certain of these transactions
are not settled physically. This can be achieved by transacting offsetting
sale or purchase contracts for the same location and delivery period that
are offset during the scheduling of delivery or dispatch. The contracts
contain standard terms such as delivery point, pricing mechanism,
settlement terms and specification of the commodity. Typically, volume
and price are the main variable terms. Swaps can be contractual
obligations to exchange cash flows between two parties. One usually
references a floating price and the other a fixed price, with the net
difference of the cash flows being settled. Options give the holder the
right, but not the obligation, to buy or sell natural gas products or power at
a specified price on or before a specific future date. Amounts under these
derivative financial instruments are settled at expiry, typically through
netting agreements to limit credit exposure and support liquidity.

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

BP Annual Report and Accounts 2008
Performance review

• BP Shipping took delivery of four LNG ships during 2007 and 2008.
The ‘Gem’ class ships can carry 155,000m3 of LNG and are among
the first ships in the industry to be powered by low-emission, fuel-
efficient, diesel-electric propulsion. BP Shipping provides safe,
environmentally responsible marine and shipping solutions in support
of BP group activities.

• In both the Atlantic and Asian regions, BP is marketing LNG using BP

LNG shipping and contractual rights to access import terminal
capacity in the liquid markets of the US (via Cove Point and Elba
Island) and the UK (via the Isle of Grain), and is supplying Asian
customers in Japan, South Korea and Taiwan.

Gas marketing and trading activities
Gas and power marketing and trading activity is undertaken primarily in
the US, Canada, the UK and Europe to market both BP production and
third-party natural gas and manage market price risk as well as to create
incremental trading opportunities through the use of commodity
derivative contracts. Additionally, this activity generates fee income
and enhanced margins from sources such as the management of price
risk on behalf of third-party customers. These markets are large, liquid
and volatile.

In connection with the above activities, the group uses a range of

commodity derivative contracts and storage and transport contracts.
These include commodity derivatives such as futures, swaps and options
to manage price risk and forward contracts used to buy and sell gas and
power in the marketplace. Using these contracts, in combination with
rights to access storage and transportation capacity, allows the group to
access advantageous pricing differences between locations, time periods
and arbitrage between markets. Natural gas futures and options are
traded through exchanges, while over-the-counter (OTC) options and
swaps are used for both gas and power transactions through bilateral
and/or centrally cleared arrangements. Futures and options are primarily
used to trade the key index prices such as Henry Hub, while swaps can
be tailored to price with reference to specific delivery locations where
gas and power can be bought and sold. OTC forward contracts have
evolved in both the US and UK markets, enabling gas and power to be
sold forward in a variety of locations and future periods. These contracts
are used both to sell production into the wholesale markets and as
trading instruments to buy and sell gas and power in future periods.
Storage and transportation contracts allow the group to store and
transport gas, and transmit power between these locations. The group
has developed a risk governance framework to manage and oversee the
financial risks associated with this trading activity, which is described
in Note 28 to the Financial statements on pages 142-147.

The range of contracts that the group enters into is described

below in more detail:

Exchange-traded commodity derivatives
Exchange-traded commodity derivatives include gas and power futures
contracts. Though potentially settled physically, these contracts are
typically settled financially. Gains and losses, otherwise referred to as
variation margins, are settled on a daily basis with the relevant exchange.
Realized and unrealized gains and losses on exchange-traded commodity
derivatives are included in total revenues for accounting purposes.

OTC contracts
These contracts are typically in the form of forwards, swaps and options.
Some of these contracts are traded bilaterally between counterparties;
others may be cleared by a central clearing counterparty. These contracts
can be used for both trading and risk management activities. Realized and
unrealized gains and losses on OTC contracts are included in total
revenues for accounting purposes. Highly developed markets exist in
North America and the UK where gas and power can be bought and sold
for delivery in future periods. These contracts are negotiated between two
parties to purchase and sell gas and power at a specified price, with

BP Annual Report and Accounts 2008
Performance review

Refining and Marketing
Our Refining and Marketing business is responsible for the supply and
trading, refining, manufacturing, marketing and transportation of crude
oil, petroleum, chemicals products and related services to wholesale and
retail customers. BP markets its products in more than 100 countries. We
operate primarily in Europe and North America and also manufacture and
market our products across Australasia, in China and other parts of Asia,
Africa and Central and South America.

In 2008 we restructured the Refining and Marketing organization

into two main business groupings: fuels value chains (FVCs) and
international businesses (IBs). The FVCs integrate the activities of
refining, logistics, marketing, supply and trading, on a regional basis,
recognizing that the markets for our main fuels products operate
regionally. This shift to a more geographic and integrated model
represents a major simplification step and the opportunity to create
better value from our physical assets (refineries, terminals, pipelines and
retail stations). The IBs include the manufacturing, supply and marketing
of lubricants, petrochemicals, liquefied petroleum gas (LPG) and aviation
and marine fuels. We believe each of these IBs is competitively
advantaged in the markets in which we have chosen to participate. Such
advantage is derived from several factors, including location, proximity of
manufacturing assets to markets, physical asset quality, operational
efficiency, technology advantage and the strength of our brands. Each
business has a clear strategy focused on investing in its key assets and
market positions in order to deliver value to its customers and out
perform its competitors.

During the past five years, our focus has been on process safety,
upgrading organizational capability and significant integrity management
investment. The construction of new production units at many of our
refineries as well as upgrades of existing conversion units at a number of
our facilities has positioned our assets to produce the high-quality fuels
needed to meet today's heightened product specifications.

Our performance in 2008
The 2008 environment in which the segment operated was very
challenging, characterized by high and volatile crude and product prices,
which resulted in substantial margin volatility as well as higher energy
costs in manufacturing. Crude prices fell significantly in the second half of
the year and at the end of the year, prices were around $50/bbl lower
than the start of the year. Refining margins in the US were significantly
weaker than 2007 due to weaker gasoline demand. Conversely, in
Europe, where diesel accounts for a larger share of regional demand,
margins were stronger than a year ago. Demand for fuels has fallen,
initially due to high oil prices and subsequently due to the slowing of
global economies and the impact of the financial crisis. During the fourth
quarter, we saw a dramatic decline in the demand for our petrochemicals
products as a consequence of the economic slowdown. The year also
saw material swings in foreign exchange rates, particularly in the second
half, that affected our results.

Our 2008 performance reflects the benefits of the fundamental

improvements we are making across the business, including the
measures we have taken to restore the availability of our refining system,
reduce costs and simplify the organization. The loss before interest and
tax was $1.9 billion for 2008, compared with a profit before interest and
tax of $6.1 billion in 2007. The decrease was primarily driven by inventory-
holding losses. Our financial results are discussed in more detail on
pages 54-55.

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Safety, both process and personal, remains our top priority. During 2008,
we started the migration to the new BP Operating Management System
(OMS) with an increased focus on process safety and continuous
improvement. The OMS is described in further detail on page 44. At the
end of the year, two of our petrochemicals plants in the US and two of
our refineries in Europe were operating on OMS. Within our US
refineries, we continue to implement the recommendations from the BP
US Refineries Independent Safety Review Panel. We have worked closely
with the independent expert, L Duane Wilson. The number of major
incidents associated with integrity management has decreased by 90%
since 2005. We have also reduced the number of oil spills by 60% and
the recordable injury rate by more than 57% since 1999. Regrettably, in
2008 there were four workforce fatalities associated with our operations,
one of which was a process safety incident.

In 2008, we saw the first substantial benefits of our operational

improvements. The Whiting refinery was restored to its full clean fuel
capability of 360mb/d in March 2008 following the compressor failure and
fire that took place during 2007. Texas City was also restored to full
economic capability by the end of the year. In Europe and Rest of World,
we commissioned new upgrading units at the Rotterdam and Kwinana
refineries, enhanced processing capability at the Gelsenkirchen refinery,
reconfigured the Bayernoil refinery for more efficient and competitive
operation, and completed construction of a new coker at the Castellón
refinery. During the next five years, we intend to continue the focus on
process safety, improve the competitive performance of our refineries
and complete the previously announced investment in the Whiting
refinery to increase its ability to process Canadian heavy crude.

In total, our 17 refineries worldwide, including those partially

owned, achieved throughputs of 2,155mb/d on average, a 5% increase
on 2007 after adjusting for the net loss of throughput from previous
disposals and acquisitions. The performance of Texas City was impacted
by Hurricane Ike in September, which meant we had to shut down the
refinery in advance as a precautionary measure, along with other
refineries in the area. Operational disruption was minimized as crude
processing was restored in seven days and full operations restored within
three weeks. This was due to a terrific response from employees and
also reflected the improvements we have made to our assets at Texas
City over the last few years.

During 2008, we fully integrated our refining, logistics, marketing,

supply and trading activities, establishing six refining-to-marketing
integrated FVCs focused on refining and selling ground transportation
fuels in each region. This has enabled us to simplify internal interfaces,
optimize margins, reduce overhead costs and drive continuous
improvement. During the year, we continued the implementation of our
ampm convenience retail franchise model in the US, which we expect to
provide reliable long-term sales growth for our refinery systems, together
with reduced costs and lower levels of capital investment. In Europe,
where we are one of the largest forecourt convenience retailers, with
about 2,500 shops in 10 countries, we are growing our food-on-the-go
and fresh grocery services through BP-owned brands and partnerships
with leading retailers such as Marks & Spencer.

In relation to our IBs during 2008, in the lubricants business we

focused on enhancing our customer relationships and brand
distinctiveness, together with simplifying operations and improving
efficiency. Although 2008 was a difficult year for the aviation industry, in
Air BP, we simplified our footprint by exiting non-core countries resulting
in a reduction in working capital and improved returns on operating
capital employed. During the year, the environment in which our
petrochemicals businesses operate became more challenging as
deterioration in the global economic market led to reduced demand for
our products.

We are simplifying the structure of our organization, improving the

efficiency of our back office and reducing our headcount, including the
number of senior management positions.

BP Annual Report and Accounts 2008
Performance review

Looking ahead, in 2009 the overall economic environment is expected to
be challenging with reduced demand for our products leading to lower
volumes and pressure on margins. The impact is expected to be greatest
in the petrochemicals sector.

Against this background, we intend to continue actively managing

our cost base, simplifying our marketing footprint and developing the market
positions where we have competitive advantage based on brand and
technology strengths. We also intend to improve the efficiency of our back
office, including customer service, accounting services and procurement
systems, by centralizing these activities in a few global centres to remove
duplication and reduce cost. We intend to focus on cash generation through
active management of our working capital and credit exposure.
We intend to limit our capital investment to maintaining and improving our
core positions. To continue the progress we have made in recent years, our
top priority for spending will remain safety and operational integrity. The
other area of focus will be delivering integrated value in our key markets
through investment in terminals and pipeline infrastructure. Our largest
investment is expected to be at the Whiting refinery, where we have
started a major upgrading and modernization programme that will enable
the refinery to operate on Canadian heavy crude oil. We also intend to
complete the planned projects in petrochemicals (see page 36).

Sales of refined productsa
Marketing sales

UKb
Rest of Europe
US
Rest of World
Total marketing salesc
Trading/supply salesd
Total refined products

thousand barrels per day

2008

2007

2006

310
1,256
1,460
685
3,711
1,987
5,698

339
1,294
1,533
640
3,806
1,818
5,624

356
1,340
1,595
581
3,872
1,929
5,801

$ million

Proceeds from sale of refined

products

248,561

194,979

177,995

aExcludes sales to other BP businesses, sales of Aromatics & Acetyls products and Olefins &
Derivatives sales through equity-accounted entities.
bUK area includes the UK-based international activities of Refining and Marketing.
cMarketing sales are sales to service stations, end-consumers, bulk buyers and jobbers (i.e. third
parties who own networks of a number of service stations and small resellers).
dTrading/supply sales are sales to large unbranded resellers and other oil companies.

Comparative information presented in the table below has been

The following table sets out marketing sales by major product group.

restated, where appropriate, to reflect the resegmentation, following
transfers of businesses between segments, that was effective from
1 January 2008. See page 16 for further details.

Key statistics

Total revenuesa
Profit before interest and tax from

continuing operationsb

Total assets
Capital expenditure and acquisitions

2008
320,458

2007
250,897

(1,884)
75,329
6,634

6,076
95,311
5,495

$ million

2006
232,833

4,919
80,738
3,127
$ per barrel

Global Indicator Refining Marginc

6.50

9.94

8.39

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

cThe Global Indicator Refining Margin (GIM) is the average of regional industry indicator margins,

which we weight for BP’s crude refining capacity in each region. Each regional indicator margin is
based on a single representative crude with product yields characteristic of the typical level of
upgrading complexity. The refining margins are industry-specific rather than BP-specific measures,
which we believe are useful to investors in analyzing trends in the industry and their impact on our
results. The margins are calculated by BP based on published crude oil and product prices and take
account of fuel utilization and catalyst costs. No account is taken of BP’s other cash and non-cash
costs of refining, such as wages and salaries and plant depreciation. The indicator margin may not
be representative of the margins achieved by BP in any period because of BP’s particular refining
configurations and crude and product slate.

Total revenues are analysed in more detail below.

Sale of crude oil through spot and

term contracts

54,901

43,004

38,577

2008

2007

$ million

2006

Marketing, spot and term sales

of refined products

Other sales and operating revenues
Earnings from equity-accounted

entities (after interest and tax),
interest, and other revenues

248,561
16,577

194,979
12,238

177,995
15,814

419
320,458

676
250,897

447
232,833

thousand barrels per day

Sale of crude oil through spot and

term contracts

1,689

1,885

2,110

Marketing, spot and term sales

of refined products

5,698

5,624

5,801

Marketing sales by refined product
Aviation fuel
Gasolines
Middle distillates
Fuel oil
Other products
Total marketing sales

2008
501
1,500
1,055
460
195
3,711

thousand barrels per day

2007
490
1,572
1,119
429
196
3,806

2006
488
1,603
1,170
388
223
3,872

Marketing volumes were 3,711mb/d, slightly lower than last year,
reflecting the impacts from the slowing of global economies and reduced
industry demand in the US and Europe.

Fuels value chains
Following our reorganization we have six integrated FVCs. They are
organized regionally, covering the West Coast and Mid-West regions of
the US, the Rhine region, Southern Africa, Australasia (ANZ) and Iberia.
Each of these is a material business, optimizing activities across the
supply chain – from crude delivery to the refineries; manufacture
of high-quality fuels to meet market demand; pipeline and terminal
infrastructure and the marketing and sales to our customers. The Texas
City refinery is operated as a standalone predominantly merchant refining
business that also supports our marketing operations on the east and
gulf coasts.

Refining
The group’s global refining strategy is to own and operate strategically
advantaged refineries that benefit from vertical integration with our
marketing and trading operations, as well as horizontal integration with
other parts of the group’s business. Refining’s focus is to maintain and
improve its competitive position through sustainable, safe, reliable and
efficient operations of the refining system and disciplined investment
for integrity management, to achieve competitively advantaged
configuration and growth.

For BP, the strategic advantage of a refinery relates to its location,

scale and configuration to produce fuels from lower-cost feedstocks in
line with the demand of the region. Strategic investments in our
refineries are focused on securing the safety and reliability of our assets
while improving our competitive position. In addition, we continue to
invest to develop the capability to produce the cleaner fuels that meet
the requirements of our customers and their communities.

BP Annual Report and Accounts 2008
Performance review

The following table summarizes the BP group’s interests in refineries and crude distillation capacities at 31 December 2008.

Refinery

Fuels value chain

Group interestb

thousand barrels per day
Crude distillation capacitiesa
BP
share

Total

Rest of Europe
Germany

Netherlands
Spain
Total Rest of Europe
US
California
Washington
Indiana
Ohio
Texas
Total US
Rest of World
Australia

New Zealand
Kenya
South Africa
Total Rest of World
Total

Bayernoil
Gelsenkirchen*
Karlsruhe
Lingen*
Schwedt
Rotterdam*
Castellón*

Carson*
Cherry Point*
Whiting*
Toledo*
Texas City*

Bulwer*
Kwinana*
Whangerei
Mombasac
Durban

Rhine
Rhine
Rhine
Rhine
Rhine
Rhine
Iberia

US West Coast
US West Coast
US Mid-West
US Mid-West
–

ANZ
ANZ
ANZ
Southern Africa
Southern Africa

22.5%
50.0%
12.0%
100.0%
18.8%
100.0%
100.0%

100.0%
100.0%
100.0%
50.0%
100.0%

100.0%
100.0%
23.7%
17.1%
50.0%

215
266
323
93
226
386
110
1,619

266
234
405
155
475
1,535

102
137
102
94
180
615
3,769

48
133
39
93
42
386
110
851

266
234
405
78
475
1,458

102
137
24
16
90
369
2,678

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*Indicates refineries operated by BP.
aCrude distillation capacity is gross rated capacity, which is defined as the maximum achievable utilization of capacity (24-hour assessment) based on standard feed.
bBP share of equity, which is not necessarily the same as BP share of processing entitlements.
cOn 15 January 2008, it was announced that Essar Energy Overseas Ltd, a subsidiary of Essar Oil Limited, had entered into an agreement to acquire 50% of Kenya Petroleum Refineries Ltd.
The transaction was initially expected to be finalized in 2008, but has since been delayed in negotiations.

The following table outlines by region the volume of crude oil and feedstock processed by BP for its own account and for third parties. Corresponding
BP refinery capacity utilization data is summarized.

Refinery throughputsa
UK
Rest of Europe
US
Rest of World
Total
Refinery capacity utilization
Crude distillation capacity at 31 Decemberb
Crude distillation capacity utilizationc
US
Europe
Rest of World

2008
–
739
1,121
295
2,155

2,678
78%
72%
85%
83%

thousand barrels per day

2007
67
691
1,064
305
2,127

2,769
72%
62%
84%
84%

2006
165
648
1,110
275
2,198

2,823
76%
70%
87%
78%

aRefinery throughputs reflect crude and other feedstock volumes.
bCrude distillation capacity is gross rated capacity, which is defined as the maximum achievable utilization of capacity (24-hour assessment) based on standard feed.
cCrude distillation capacity utilization is defined as the percentage utilization of capacity per calendar day during the year after making allowances for average annual shutdowns at BP refineries (i.e. net
rated capacity).

BP Annual Report and Accounts 2008
Performance review

Excluding portfolio impacts, underlying refining throughputs in 2008
increased by 5% relative to 2007, driven principally by improved
operational performance in the US. Higher US throughputs were
attributable to the recoveries at the Texas City and Whiting refineries,
partially offset by the reduced equity interest in the Toledo refinery
stemming from the Husky joint venture (see below). The improvement
achieved in the US was lower than it would have been as crude runs
were reduced as a result of the low-margin environment as well as the
disruption at the Texas City refinery in September caused by Hurricane Ike.

The increase in Rest of Europe throughputs in 2008 is primarily

related to the purchase of Chevron’s 31% interest in the Rotterdam
refinery in 2007. The decrease in UK throughputs is due to the sale of the
Coryton refinery to Petroplus.

Significant events in Refining were as follows:

• On 21 March 2008, the Whiting refinery in the US was restored to its

full clean fuel capability of 360mb/d.

• BP completed recommissioning the Texas City refinery in the US.

With the successful return to service of Ultraformer No. 3 in the
fourth quarter, the site’s full economic capability was restored.
• On 31 March 2008, we completed a deal with Husky Energy Inc. to
create an integrated North American oil sands business by means of
two separate joint ventures, one of which entailed Husky taking a
50% interest in BP’s Toledo refinery. The Toledo refinery is intended to
be expanded to process approximately 170mb/d of heavy oil and
bitumen by 2015.

• In July, a final investment decision was taken to progress the

significant upgrade of the Whiting refinery. This project repositions
Whiting competitively by increasing its Canadian heavy crude
processing capability by 260mb/d and modernizing it with equipment
of significant size and scale.

• On 17 March 2008, BP and Irving Oil entered into a memorandum of
understanding to work together on evaluating the feasibility of the
proposed Eider Rock refinery in Saint John, New Brunswick, Canada.

Fuels marketing, supply and logistics
Our fuels marketing strategy focuses on optimizing the integrated value
of each fuels value chain that is responsible for the delivery of ground
fuels to the market. We do this by co-ordinating our marketing, refining
and trading activities to maximize synergies across the whole value chain.
Our priorities are to operate an advantaged infrastructure and logistics
network (which includes pipelines, storage terminals and road or rail
tankers), drive excellence in operating and transactional processes and
deliver compelling customer offers in the various markets where we
operate. The fuels business markets a comprehensive range of refined oil
products primarily focused on the ground fuels sector.

On 29 August 2008, BP announced an agreement with Enbridge

Inc. to build and reconfigure a pipeline system to transport Canadian
heavy crude oil from Flanagan, Illinois, to Houston and Texas City, Texas.
The system is expected to be in service by late 2012 with an initial
capacity of 250mb/d. The joint investment of the phased capacity
additions is expected to be in the range of $1-2 billion.

The ground fuels business supplies fuel and related
convenience services to retail consumers through company-owned
and franchised retail sites as well as other channels including wholesalers
and jobbers. It also supplies commercial customers within the road and
rail transport sectors.

BP’s value creation in ground fuels is obtained through the

integration of the value chain from the refinery gates or import hubs
across retail and commercial channels to market. Convenience retail
offers are focused on delivering appealing convenience offers across the
various markets in which we operate, through the BP Connect, ampm
and Aral brands.

Our retail network is largely concentrated in Europe and the US, and also
has established operations in Australasia and southern and eastern
Africa. We are developing networks in China in two separate joint
ventures, one with Petrochina and the other with China Petroleum and
Chemical Corporation (Sinopec).

Retail sitesa b
UK
Rest of Europe
US (excluding jobbers)
US jobbers
Rest of World
Total

Number of retail sites operated under a BP brand

2008
1,200
7,400
2,500
9,200
2,300
22,600

2007
1,200
7,400
2,500
9,700
2,500
23,300

2006
1,300
7,700
2,700
9,600
2,600
23,900

a
Changes in the number of retail sites over time are affected by, among other things, dealer/jobber
owned sites that move to or from the BP brand as their fuel supply agreements expire and are
renegotiated in the normal course of business.
b
Excludes our interest in equity-accounted entities. Comparative information has been amended to
this basis.

At 31 December 2008, BP’s worldwide network consisted of some
22,600 locations branded BP, Amoco, ARCO and Aral, around the same
as in the previous year. We continue to improve the efficiency of our retail
network and increase the consistency of our site offer through a process
of regular review. In 2008, we sold 470 company-owned sites to dealers,
jobbers and franchisees who continue to operate these sites under the
BP brand. We also divested an additional 160 company-owned sites to
third parties.

At 31 December 2008, BP’s retail network in the US comprised
approximately 11,700 sites, of which approximately 9,200 were owned
by jobbers and 900 operated under a franchise agreement. In November
2007, BP announced that it would sell all of its company-owned and
company-operated convenience sites in the US. Despite the challenges
in the global credit market, we expect the sale of these sites to be
completed by the end of 2009. At the end of 2008, sales of 293 of sites
had been successfully completed. The sites will continue to market BP-
branded fuels in the eastern US and ARCO-branded fuels in the western
US. The franchise agreement has a term of 20 years and requires sites to
be supplied with BP- or ARCO-branded fuels for the term of the contract.

At the end of 2008, our European retail network consisted of

approximately 8,600 sites and we had approximately 2,300 sites in the
Rest of World.

Our retail convenience operations offer consumers a range of

food, drink and other consumables and services on the fuel forecourt in a
safe, convenient and innovative manner. With operations in both Europe
and the US, using recognized and distinctive brands, BP is working to
maximize the efficiency and effectiveness of its retail network in each of
its chosen market areas. By the end of 2008, we completed the roll-out
of more than 100 Marks & Spencer Simply Food sites as an integral part
of the convenience network in the UK, while a refresh of the Petit Bistro
brand in Germany and the Wild Bean Café brand in other European
locations has re-energized consumers’ convenience shopping choices. In
the US, BP has embarked on a roll-out of its successful ampm brand
across all targeted national markets as its single convenience flagship;
this programme roll-out is intended to be completed by the end of 2009.

BP Annual Report and Accounts 2008
Performance review

Supply and trading
The group has a long-established integrated supply and trading function
responsible for delivering value across the overall crude and oil products
supply chain. This structure enables BP to maintain a single face to the oil
trading markets and to operate with a single set of trading compliance
processes, systems and controls. Operating through trading offices
located in Europe, the US and Asia, the function is able to maintain a
presence in the regionally connected global markets.

The function seeks to identify the best markets and prices for our

crude oil, source optimal feedstocks for our refineries and provide
competitive supply for our marketing businesses. In addition, where
refinery production is surplus to marketing requirements or can be
sourced more competitively, it is sold into the market. Wherever possible,
the group will look to optimize value across the supply chain. For
example, BP will often sell its own crude production into the market and
purchase alternative crude for its refineries where this will provide
incremental margin.

In addition to the supply activity described above, the function

seeks to create incremental trading opportunities. It enters into the full
range of exchange-traded commodity derivatives, over-the-counter (OTC)
contracts and spot and term contracts that are described in detail below.
In order to facilitate the generation of trading margin from arbitrage,
blending and storage opportunities, it also both owns and contracts for
storage and transport capacity. The group has developed a risk
governance framework to manage and oversee the financial risks
associated with this trading activity, which is described in the Financial
statements – Note 28 on pages 142-147.

The range of transactions that the group enters into is

described below:

Exchange-traded commodity derivatives
These contracts are typically in the form of futures and options traded on
a recognized exchange, such as Nymex, SGX, ICE and Chicago Board of
Trade. Such contracts are traded in standard specifications for the main
marker crude oils, such as Brent and West Texas Intermediate, and the
main product grades, such as gasoline and gasoil. Gains and losses,
otherwise referred to as variation margins, are settled on a daily basis
with the relevant exchange. These contracts are used for the trading and
risk management of both crude oil and refined products. Realized and
unrealized gains and losses on exchange-traded commodity derivatives
are included in total revenues for accounting purposes.

The main grades of crude oil bought and sold forward using
standard contracts are West Texas Intermediate and a standard North Sea
crude blend (Brent, Forties and Osberg or BFO). Although the contracts
specify physical delivery terms for each crude blend, a significant volume
are not settled physically. The contracts typically contain standard
delivery, pricing and settlement terms. Additionally, the BFO contract
specifies a standard volume and tolerance given that the physically
settled transactions are delivered by cargo.

Swaps are often contractual obligations to exchange cash flows between
two parties: a typical swap transaction usually references a floating price
and a fixed price with the net difference of the cash flows being settled.
Options give the holder the right, but not the obligation, to buy or sell
crude or oil products at a specified price on or before a specific future
date. Amounts under these derivative financial instruments are settled at
expiry, typically through netting agreements, to limit credit exposure and
support liquidity.

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

International businesses
Our IBs provide quality products and offers to customers in more than
100 countries worldwide with a significant focus on Europe, North
America and Asia. Our products include aviation and marine fuels,
lubricants that meet the needs of various industries and consumers,
LPG, and a range of petrochemicals that are sold for use in the
manufacture of other products such as fabrics, fibres and various plastics.

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Lubricants
We manufacture and market lubricants and related products and services
to the automotive, industrial, marine and energy markets across the
world. Following a decision to simplify and focus our channels of trade,
we now sell products direct to our customers in around 50 countries and
use approved local distributors for the remaining locations. Customer
focus, distinctive brands, superior technology and relationships remain
the cornerstones of our long-term strategy.

BP markets primarily through its major brands of Castrol and BP,

plus the Aral brand in some specific markets. Castrol is recognized as
one of the most powerful lubricants brands worldwide and we believe it
provides us with a significant competitive advantage. In the automotive
lubricants sector, we supply lubricants and other related products and
services to intermediate customers such as retailers and workshops.
These, in turn, serve end-consumers such as car, truck and motorcycle
owners in the mature markets of Western Europe and North America as
well as the markets of Russia, China, India, the Middle East, South
America and Africa, which we believe have the potential for significant
long-term growth.

BP’s marine lubricants business is a global market leader,
supplying many types of vessels from deep-sea fleets to marine leisure-
craft from around 1,200 ports across the globe. BP’s industrial lubricants
business is a leading supplier to those sectors of the market involved in
the manufacture of automobiles, trucks, machinery components and
steel. BP is also a leading supplier of lubricants for the offshore oil and
aviation industries.

BP Annual Report and Accounts 2008
Performance review

Petrochemicals
Our petrochemicals operations are comprised of the global Aromatics &
Acetyls businesses (A&A) and the Olefins & Derivatives (O&D)
businesses, predominantly in Asia. New investments are targeted
principally in the higher growth Asian markets.

In A&A, we manufacture and market three main product lines:

purified terephthalic acid (PTA), paraxylene (PX) and acetic acid. Our A&A
strategy is to leverage our industry-leading technology in selected
markets, to grow the business and to deliver industry-leading returns.
PTA is a raw material used in the manufacture of polyesters used in
fibres, textiles and film, and PET bottles. Acetic acid is a versatile
intermediate chemical used in a variety of products such as paints,
adhesives and solvents, as well as its use in the production of PTA.
We have a strong global market share in the PTA and acetic markets
with a major manufacturing presence in Asia, particularly China. PX
is a feedstock for PTA production.

Significant events in petrochemicals were as follows:
• The second PTA plant at the BP Zhuhai Chemical Company Limited

site in Guangdong province (China) successfully completed
commissioning in the first quarter of 2008. This 900+ ktepa plant is
the single largest PTA manufacturing train in the world and employs
BP’s latest, proprietary technology.

• Construction continued on the new 500ktepa acetic acid plant in

Jiangsu province (China) by BP YPC Acetyls Company (Nanjing)
Limited (BYACO). This is a BP joint venture with Yangzi Petrochemical
Co. Ltd (a subsidiary of Sinopec). Construction is scheduled to be
completed in June 2009 with commercial sales expected to begin in
the third quarter of 2009.

• Commissioning of our expanded Geel (Belgium) PTA facility

commenced at the end of 2008. The 350ktepa expansion improves
overall operating costs and increases the site’s PTA capacity to
1,425ktepa.

In O&D, we manufacture ethylene and propylene from naphtha

• In January 2008, BP and Sinopec signed a memorandum of

and also produce a number of downstream derivative products.

Our O&D business has operations in both China and Malaysia. In
China, our SECCO joint venture between BP, Sinopec and its subsidiary,
Shanghai Petrochemical Company is the largest foreign-invested olefins
cracker in China. SECCO is BP’s single largest investment in China. This
naphtha cracker produces ethylene and propylene plus derivatives
acrylonitrile, polyethylene, polypropylene, styrene, polystyrene, and other
products. In Malaysia, BP participates in two joint-ventures: Ethylene
Malaysia Sdn. Bhd. (EMSB), which produces ethylene from gas feedstock
in a joint venture between BP, Petronas and Idemitsu; while Polyethylene
Malaysia Sdn. Bhd. (PEMSB) produces polyethylene in a joint venture
between BP and Petronas. Each of these ventures has demonstrated a
strong track record of project delivery and performance. BP also owns
one other naphtha cracker outside Asia, which is integrated with our
Gelsenkirchen refinery in Germany.

The following table shows BP’s petrochemicals production
capacity at 31 December 2008. This production capacity is based on the
original design capacity of the plants plus expansions.

BP share of capacity

Geographic area
US
Europe
Asia (excluding China)
China

PTA

Acetic
acid
PX
546
2,385 2,373
544
622
1,075
815
–
2,209
1,554
215
–
7,223 2,995 2,120

thousand tonnes per year

O&D

Other
Total
151
– 5,455
158 1,629 4,028
56
257 3,337
51 2,290 4,110
416 4,176 16,930

During 2008, the environment in which our petrochemicals businesses
operate became more challenging as deterioration in the global economic
environment has led to a reduced demand for our products.

understanding to add a new acetic acid plant at their Yangtze River
Acetyls Co. (YARACO) joint venture site in Chongqing (China). This
world-scale (650ktepa) acetic acid plant will use BP’s leading Cativa™
technology. The expected plant start-up date, which was originally
anticipated to be during 2011, is under review due to the market
conditions. When complete, total production at the YARACO site is
expected to be well over one million tonnes per annum, making this
one of the largest acetic acid production locations in the world.

Aviation and marine fuels
Air BP is one of the world’s largest and best known aviation fuels
suppliers, serving all the major commercial airlines as well as the general
aviation and military sectors. During 2008, which was a tough year for the
aviation industry, we simplified our geographical footprint by exiting non-
core countries and now supply customers in approximately 70 countries.
We have annual marketing sales in excess of 27 billion litres and we have
relationships with many of the world’s major commercial airlines. Air BP’s
strategic aim is to grow its position in the core locations of Europe, the
US, Australasia and the Middle East, while focusing its portfolio towards
airports that offer long-term competitive advantage. BP’s marine fuels
business focuses on the distribution and sale of refined fuel oils to the
shipping industry at locations in more than 100 ports across the world.
During 2008, this business performed well, supported by strong growth
in the shipping market.

LPG
The LPG business sells bulk, bottled, automotive and wholesale LPG
products to a wide range of customers in 13 countries. During the past
few years, our LPG business has consolidated its position in established
markets, pursued opportunities in new and emerging markets such as
China and announced the exit from the Vietnam market in December
2008. LPG product sales in 2008 were approximately 68mbpd.

BP Annual Report and Accounts 2008
Performance review

Other businesses and corporate
Other businesses and corporate comprizes Treasury (which includes
interest income on the group’s cash and cash equivalents) and corporate
activities worldwide, the group’s aluminium asset, the Alternative Energy
business and Shipping.

Comparative information presented in the table below has been

restated, where appropriate, to reflect the resegmentation, following
transfers of businesses between segments, that was effective from
1 January 2008. See page 16 for more details.

Alternative Energy
BP invested $1.4 billion in our Alternative Energy business during 2008,
bringing the total investment in this business to $2.9 billion since its
launch in 2005. We expect to fulfil our original 2005 commitment to
invest a total of $8 billion over 10 years. In 2008, we prioritized four
areas with significant long-term growth potential – wind, solar, biofuels
and carbon capture and storage (CCS). We have also developed a fifth
area – gas-fired power – that offers synergies with other BP operations.
We have concentrated our 2008 investment in these areas.

2008
5,040

2007
3,972

Wind – net rated capacity

as at year-end (megawatts)a
Solar – cell production capacity
as at year-end (megawatts)b

$ million

2006
3,703

2008

2007

2006

432

213

172

228

201

Key statistics

Total revenuesa
Profit (loss) before interest and tax
from continuing operationsb

Total assets
Capital expenditure and acquisitions

(1,258)
19,079
1,839

(1,233)
20,595
939

(779)
16,315
852

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

Treasury
Treasury co-ordinates the management of the group’s major financial

assets and liabilities. From locations in the UK, the US and the Asia

Pacific region, it provides the link between BP and the international

financial markets and makes available a range of financial services to

the group, including supporting the financing of BP’s projects around

the world.

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 are therefore borne as they arise, rather
than being spread over time through insurance premiums with attendant
transaction costs. This position is reviewed periodically.

Aluminium
Our aluminium business is a non-integrated producer and marketer of
rolled aluminium products, headquartered in Louisville, Kentucky, US.
Production facilities are located in Logan County, Kentucky, and are jointly
owned with Novelis. The primary activity of our aluminium business is
the supply of aluminium coil to the beverage can business, which it
manufactures primarily from recycled aluminium.

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a
Net wind capacity is the sum of the rated capacities of the assets/turbines that have entered into
commercial operation, including BP’s share of equity-accounted entities. The equivalent capacities
on a gross-JV basis (which includes 100% of the capacity of equity-accounted entities where BP
has partial ownership) were 785MW in 2008, 373MW in 2007 and 43MW in 2006.
b
Solar capacity is the theoretical cell production capacity per annum of in-house
manufacturing facilities.

Wind
Since the launch of Alternative Energy we have substantially grown our
wind portfolio, increasing from 32 megawatts (MW) in operation to
432MW (785MW gross) at the end of 2008. In total, we have more than
500MW (1,000MW gross) of installed capacity. This increase in capacity
was led by the US with installations at Cedar Creek, Silver Star, Sherbino
and Edom Hills.

To accelerate our growth in the US wind energy market, we
acquired two fully integrated wind power development companies –
Greenlight Energy Inc. and Orion Energy LLC, during 2006. To secure
the continuing availability of turbines we have signed agreements with
Nordex (Germany) and GE (the US) for a combined 900MW to be
delivered during the next two years. This is in addition to a five-year wind
turbine contract we previously signed with Clipper Windpower Inc.
in 2006.

We also operate wind farms in the Netherlands and in

Maharashtra, India.

Solar
We continued to implement BP Solar’s strategy to invest in lower cost
manufacturing and technology to enable energy sourced from our
products to compete with conventional electricity. Our global business
model spans the entire solar ‘value chain’ – from the acquisition of
silicon as a raw material, the production of wafers and cells to the
creation of solar panels that are then sold and distributed as solar
systems on the roofs of residential homes, large commercial buildings
and on vacant land.

Today, BP Solar’s main production facilities are located in

Maryland (US), Madrid (Spain), Xi’an (China) and Bangalore (India).
During 2008, due to increasingly competitive market conditions, BP
Solar announced plans to refocus operations at larger scale plants to
achieve lower-cost manufacturing. This resulted in the start of an
intensive programme of operational efficiency improvement in the
remaining BP Solar plants and plans to close our manufacturing plant in
Australia. During 2008, BP Solar signed contracts with a select set of
third-party strategic partners in Asia who specialize in the production of
low-cost, high-quality wafers, cells and modules.

During 2008, BP Solar achieved sales of 162MW, an increase of

41% from 115MW in 2007. The slight decrease in solar production
capacity was due to fire damage in a section of our manufacturing plant
in India.

BP Annual Report and Accounts 2008
Performance review

More than 70% of our sales volume is through third-party distributors in
the residential markets in Europe, the US and Australasia. We have
continued to roll out our Certified Installer Programme (CIP), first
established in Germany, to ensure the safe, high-quality installation of
products by third parties. The CIP has grown rapidly in Germany and this
year has been rolled out in Spain and Australia.

In the US, in 2008, we continued to supply large corporations with

sustainable energy solutions, completing a second solar system
for FedEx Freight in California and a further six installations for Wal-Mart.
In Europe, we expanded the relationship with Banco Santander to jointly
build and finance a number of solar plants in Spain, with the construction
of an 8 megawatts-peak (MWp) solar farm in Toledo and a 6MWp project
in Tenerife. In Asia, we completed the installation of a solar power
demonstration project (SolarSail) at the Guangdong Science Center; the
SolarSail absorbs sunlight to produce power, while providing cool shade
for visitors. In Australia, the largest roof-top solar system (100 kilowatt) in
New South Wales commenced operation in February 2008, representing
the first commercial solar power installation for the Blacktown Solar City
Project. The Solar Cities Programme is a government initiative to
implement distributed solar and other energy efficient technologies in
seven Australian cities.

We are developing a new silicon growth process named

Mono2 TM, which will increase cell efficiency over traditional
multicrystalline-based solar cells. We have moved from a prototype to
low-volume production and have converted our casting stations in
Frederick, Maryland, delivering 1.2MW Mono² TM. From the trials, we are
seeing significant improvement in power and generated kWh when
compared with multicrystalline-based solar cells particularly when
modules are used where sunlight is low.

BP Solar has long-term relationships with world-class universities

and invests in research programmes with organizations including the
University of Delaware, California Institute of Technology (Cal Tech) and
the Fraunhofer Institute (Germany). BP Solar was selected for the Solar
America Initiative (SAI) award from the US Department of Energy – a
$40-million research and development programme aimed at decreasing
the cost of solar cells and increasing their efficiency. BP Solar is also a
member of the broad consortium led by DuPont in conjunction with the
University of Delaware, funded by the Defense Advanced Research
Projects Agency (DARPA), to develop high-efficiency solar cells.

Biofuels
BP has a key role to play in enabling the transport sector to respond to
the dual challenges of energy security and climate change. Our
investments are focused on sustainable feedstocks that minimize
pressure on food supplies and on research into advanced technologies
and practices to make good biofuels even better.

We have embarked on a focused programme of biofuels
development based around the most efficient transformation of
sustainable and low-cost sugars into a range of fuel molecules. These
include bioethanol from Brazilian sugar cane, more efficient fuel
molecules like biobutanol and advanced biofuels like lignocellulosic
bioethanol produced from non-food energy grasses and ‘for-purpose’
feedstocks such as miscanthus and energy cane.

BP has announced it has plans to invest in excess of $1 billion in

building our own biofuels business operations, including partnerships
with other companies to develop the technologies, feedstocks and
processes required to produce advanced biofuels.

These investments include: a 50% stake in Tropical BioEnergia, a joint
venture with Santelisa Vale and Maeda Group, to produce bioethanol
from sugar cane; and a $90-million investment and strategic alliance
with Verenium Corporation to accelerate the development and
commercialization of biofuels produced from lignocellulosic bioethanol.
We have been working with DuPont since 2003 to explore new
approaches to the development of biofuels. The first product from this
collaboration will be an advanced fuel molecule called biobutanol, which
has a higher energy content than ethanol. We have partnered with
ABF (British Sugar) and DuPont to construct a world-scale biofuels plant
in Hull.

Innovation begins with research. In 2006, we announced plans
to invest $500 million over 10 years in the Energy Biosciences Institute
(EBI), at which biotechnologists are investigating applications of
biotechnology to energy, including advanced fuels. This amount is
incremental to the $1 billion of investments mentioned above. Our
partners are the University of California, Berkeley and the University
of Illinois at Urbana Champaign and the Lawrence Berkeley National
Laboratory. The EBI is focusing on the integrated development of better
crops, better processing technologies and better biofuels, leading to
cleaner energy.

Hydrogen power
In May 2007, BP and Rio Tinto announced the formation of a new jointly
owned company, Hydrogen Energy International Limited, which will
develop decarbonized energy projects around the world. The venture will
initially focus on hydrogen-fuelled power generation, using fossil fuels and
CCS technology to produce new large-scale supplies of clean electricity.

Hydrogen Energy is working on developing low-carbon power

plants with projects in Abu Dhabi and California – manufacturing
hydrogen for power generation. In both instances, the captured CO2 will
be transported to nearby oil fields for use in enhanced oil recovery, with
the CO2 stored deep underground. General Electric and BP have formed
a global alliance to jointly develop and deploy technology for hydrogen
power plants that could significantly reduce emissions of the greenhouse
gas CO2 from electricity generation.

Through these initiatives, BP intends to continue to shape
the development of the CCS value chain and to seek to minimize
the carbon footprint exposure of the BP group as carbon pricing and
policy develops globally.

Gas-fired power
Our gas-fired power activities comprise modern combined cycle gas turbine
plants, which emit around 50% less CO2 than a conventional coal plant of
the same capacity, and several low-carbon co-generation gas power
facilities. We have stakes in eight plants worldwide and this year increased
the total power they are capable of producing from 5GW to 6GW and,
where possible, we integrate plants with other BP production facilities. The
Whiting Clean Energy facility, acquired in July 2008, now provides a reliable
source of steam for our Whiting refinery and we are adding a 250MW
steam turbine to our existing plant at our Texas City refinery. Our combined
cycle plants are providing base-load demand for BP’s major upstream gas
production developments.

BP Annual Report and Accounts 2008
Performance review

Shipping
We transport our products across oceans, around coastlines and along
waterways, using a combination of BP-operated, time-chartered and
spot-chartered vessels. All vessels conducting BP activities are subject to
our health, safety, security and environmental requirements.

International fleet
At the end of 2008, we had an international fleet of 54 vessels (37
medium-size crude and product carriers, four very large crude carriers,
one North Sea shuttle tanker, eight LNG carriers and four LPG carriers).
All these ships are double-hulled. Of the eight LNG carriers, BP manages
one on behalf of a joint venture in which it is a participant and operates
seven LNG carriers.

Regional and specialist vessels
In Alaska, during 2008, we redelivered one of our time-chartered vessels
back to the owner, leaving a fleet of four double-hulled vessels. In the
Lower 48, the two remaining heritage Amoco barges were phased out
of BP’s service. Outside the US, at the end of 2008, we had 14 specialist
vessels (two double-hulled lubricants oil barges and 12 offshore
support vessels).

Time-charter vessels
At the end of 2008, BP had 115 hydrocarbon-carrying vessels above 600
deadweight tonnes on time-charter, of which 107 are double-hulled and
one is double-bottomed. All these vessels participate in BP’s Time
Charter Assurance Programme.

Spot-charter vessels
BP spot-charters vessels, typically for single voyages. These vessels are
always vetted for safety assurance prior to use.

Other vessels
BP uses various craft such as tugs, crew boats and seismic vessels in
support of the group’s business. We also use sub-600 deadweight tonne
barges to carry hydrocarbons on inland waterways.

Maritime security issues
2008 has seen a significant escalation in piracy activity, specifically off
the north coast of Somalia. At a strategic level, BP avoids known areas of
pirate attack or armed robbery; where this is not possible for trading
reasons and we consider it safe to do so, we will continue to trade
vessels through areas of known piracy, subject to the adoption of
heightened security measures. BP will continue to route vessels through
the Gulf of Aden for as long as it considers it to be safe to do so, having
regard to available military and government agency advice. At present,
we are following such advice and are participating in protective group
transits through the Gulf of Aden Maritime Security Patrol Area
transit corridor.

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BP Annual Report and Accounts 2008
Performance review

Research and technology
Research and technology (R&T) has a critical role to play in addressing the
world’s energy challenges, from fundamental research through to wide-
scale deployment. The full breadth of these R&T activities is carried out
by each of the business segments. We also conduct long-term research
within the central R&T group.

Inside the segments, research and technology activities are
in service of competitive business performance and new business
development, through the research, development or acquisition of new
technologies. The central R&T group provides leadership for scientific and
technological activities throughout the group and, in particular, provides
input to the group’s long-term strategy. It ensures that the right capability
is in place in critical areas and ensures the quality of BP’s major
technology programmes. It also illuminates the potential of emerging
technologies and conducts research and development (R&D) in support
of BP’s long-term corporate renewal. In addition, a group of eminent
industrialists and academics forms the Technology Advisory Council,
which advises the board and executive management on the state of
research and technology within the group and helps to identify current
trends and future developments in technology.

Research and development (R&D) is carried out using a balance of
internal and external resources. Involving third parties in the various steps
of technology development and application enables a wider range of
ideas and technologies to be considered and implemented, improving
the impact of research and development activities.

Across the group, expenditure on R&D for 2008 was $595 million,

compared with $566 million in 2007 and $395 million in 2006. See
Financial statements note 15 on page 132. The 5% increase in 2008
compared with 2007 reflects increased investment in biosciences,
conversion and carbon capture and storage technologies.

Beyond R&D, we also invest in technologies to get them to the

point of commercial readiness: this includes field trials, support for
technology deployment, specialist technical services and central
investment in functional excellence and capability development have
deepened our current areas of technology leadership.

In our Exploration and Production segment, we have organized

leading technologies under 10 flagship programmes, each with the
potential to add more than 1 billion boe to reserves through their
development and deployment in our assets worldwide. These
technologies contributed to exploration and production success in
Algeria, Angola, Azerbaijan, Egypt, the North Sea and the Gulf of Mexico
deepwater. Our advanced seismic imaging expertise, which is one of
these programmes, continues to lead the industry, pioneering new wide-
azimuth seismic acquisition and processing in deepwater Angola, Egypt
and the Gulf of Mexico. In addition, BP has developed new technologies
that have significantly reduced the time needed for land seismic
acquisition in Oman, and these are now being deployed in Libya. Our
enhanced oil recovery technologies are pushing recovery factors to new
limits. For example, recovery factors have already increased from 40%
to 60% in Alaska, where BP operates the world’s largest miscible gas
enhanced oil recovery project. BP also leads the industry in the
application of new inter-well polymer treatments aimed at improving
waterflood recovery, with more than 25 treatments delivering an increase
of around five million barrels. Also in Alaska, BP’s first hexalateral well
came online in 2008 in the Orion field, which is capable of producing
9,500 barrels of oil per day – the largest producer in BP’s operations on
the North Slope; while our first well using cold heavy oil production with
sand (CHOPS) technology began producing heavy oil at a production rate
of 100 barrels of oil per day. Unconventional gas is another area of focus;
for example, using new technologies, BP has drilled in 17 unconventional
coalbed methane basins around the world, including some of the largest
reservoirs in North America. Another flagship programme is our use of
digital technologies to optimize production and improve recovery, where
BP has established an industry-leading position. In 2008, BP’s oil and gas

operations, enabled by real-time data and Field-of-the-Future®
technologies delivered an extra 30,000 to 50,000 boepd gross production.
Also in 2008, as part of its Inherently Reliable Facilities flagship, BP
completed a field trial of a new fibre-optic system that represents a step-
change in onshore pipeline monitoring, and which will now be deployed
in Azerbaijan, Canada and Scotland.

In our Refining and Marketing segment, technology

advancements are enabling our refineries to understand and process
feedstocks of varying quality and optimize our assets in real time,
enhancing the flexibility and reliability of our refineries and, in turn,
improving the margins of our existing asset base. In 2008, BP began
upgrading its Whiting refinery in Indiana to process heavy crude oil from
Canada using one of the industry’s most technologically advanced coking
operations. In Naperville, US, we opened a new refining R&D centre,
installing more than 50 new pilot units at the forefront of experimental
technology and modelling. We have installed predictive analytics
technology for fault detection and prediction on critical machinery across
seven of our refineries reducing losses from machinery failure. BP’s
leading technologies in fuels and lubricants mean that it can keep ahead
of increasingly stringent regulations, balancing greater fuel efficiency and
performance and developing superior formulations across its entire
product slate. For example, our BP Ultimate fuels deliver performance
benefits such as improved fuel economy, lower emissions and a cleaner
engine; and we have launched Greendeck and Greenfield, a suite of high-
performance and environmentally friendly marine and offshore lubricants.
Our proprietary processing technologies and operational experience
continue to reduce the manufacturing costs and environmental impact of
our petrochemicals plants, helping to maintain competitive advantage.
For example, our new 900ktepa purified terephthalic acid (PTA) plant in
Zhuhai, China was officially opened in 2008, occupying a plot just half the
size of its older, neighbouring plant, but with double the production
capacity. In the field of conversion technology, our Nikiski Fischer-Tropsch
demonstration plant in Alaska operated at levels to prove that we have a
working catalyst at industrial scale.

In Alternative Energy, our low-carbon research and technology
activity continues apace. In 2008, we filed patents covering biofuels,
carbon capture and storage (CCS), and hydrogen membranes. Our solar
business produced the first prototype of a cut-cell high voltage module,
giving a 5% increase in power over conventional modules. Working as
part of the UK’s Energy Technologies Institute – a public/private
partnership to accelerate low-carbon technology development – BP is
proceeding with investments in projects to develop new offshore wind
and marine turbines. We also published results of the satellite monitoring
programme, verified by well and tracer detection, of the CCS project at
the In Salah gas field in Algeria with our partners Sonatrach.

Collaboration plays an important role across the breadth of BP’s
research and development activities, but particularly in those areas that
benefit from fundamental scientific research. BP has 11 significant long-
term research programmes with major universities and research
institutions around the world, exploring areas from energy bioscience and
conversion technology to carbon mitigation and nanotechnology in solar
power. In 2008, our Energy Biosciences Institute at Berkeley (see
page 38) became fully operational, with 49 research projects, all focused
on lignocellulosic biofuel production; we announced the renewal of our
Carbon Mitigation Initiative at Princeton; and signed the joint venture
agreement for the Clean Energy Commercialisation Centre with the
Chinese Academy of Sciences.

BP Annual Report and Accounts 2008
Performance review

Regulation of the group’s business
BP’s activities, including its oil and gas exploration and production,
pipelines and transportation, refining and marketing, petrochemicals
production, trading, alternative energy and shipping activities, are
conducted in many different countries and are therefore subject to a
broad range of EU, US, international, regional and local legislation and
regulations, including legislation that implements international
conventions and protocols. These cover virtually all aspects of our
activities and include matters such as licence acquisition, production
rates, royalties, environmental, health and safety protection, fuel
specifications and transportation, trading, pricing, anti-trust, export, taxes
and foreign exchange.

The terms and conditions of the leases, licences and contracts

under which our oil and gas interests are held vary from country to
country. These leases, licences and contracts are generally granted
by or entered into with a government entity or state company and are
sometimes entered into with private property owners. These
arrangements with governmental or state entities usually take the form
of licences or production-sharing agreements. Arrangements with private
property owners are usually in the form of leases.

Licences (or concessions) give the holder the right to explore for

and exploit a commercial discovery. Under a licence, the holder bears the
risk of exploration, development and production activities and provides
the financing for these operations. In principle, the licence holder is
entitled to all production, minus any royalties that are payable in kind. A
licence holder is generally required to pay production taxes or royalties,
which may be in cash or in kind. Less typically, BP may explore for and
exploit hydrocarbons under a service agreement with the host entity in
exchange for reimbursement of costs and/or a fee paid in cash rather
than production.

PSAs entered into with a government entity or state company

generally require BP to provide all the financing and bear the risk of
exploration and production activities in exchange for
a share of the production remaining after royalties, if any.

In certain countries, separate licences are required for exploration

and production activities and, in certain cases, production licences are
limited to a portion of the area covered by the exploration licence. Both
exploration and production licences are generally for a specified period of
time (except for licences in the US, which typically remain in effect until
production ceases). The term of BP’s licences and the extent to which
these licences may be renewed vary by area.

Frequently, BP conducts its exploration and production activities in

joint venture with other international oil companies, state companies or
private companies.

In general, BP is required to pay income tax on income generated
from production activities (whether under a licence or production-sharing
agreement). In addition, depending on the area, BP’s production activities
may be subject to a range of other taxes, levies and assessments,
including special petroleum taxes and revenue taxes. The taxes imposed
on oil and gas production profits and activities may be substantially higher
than those imposed on other activities, particularly in Angola, Norway,
the UK, Russia, South America and Trinidad & Tobago.

For a discussion of environmental and certain health and safety

regulations and environmental proceedings, see Environment on
page 43. See also Legal proceedings on page 92.

Safety
This section reviews BP’s safety performance in 2008.

There were five workforce fatalities in 2008, compared with seven

in 2007. One resulted from fatal injuries sustained during operations at
our Texas City refinery; one was the result of a fall from height at the
Tangguh operations in Indonesia; one fatality was on a land farm near
Texas City, and two were driving fatalities incidents in Mozambique and
South Africa. We deeply regret this loss of life. By learning from these
incidents and implementing appropriate improvement actions, we
continue to seek to secure the safety of all members of our workforce.
Our workforce reported recordable injury frequency, which measures the
number of injuries per 200,000 hours worked, was 0.43 in 2008. This was
a good improvement on the rate of 0.48 recorded in both 2007 and 2006.
Throughout 2008, senior leadership across the group continued to

hold safety as their highest priority. Site visits, in which safety was a
focus, were undertaken by the group chief executive (GCE) and members
of the executive team to reinforce the importance of their commitment
to safe and reliable operations.

Management systems
We continue to implement our new operating management system
(OMS), a framework for operations across BP that is integral to improving
safety and operating performance in every site.

When fully implemented, OMS will be the single framework

within which we will operate, consolidating BP’s requirements relating
to process safety, environmental performance, legal compliance in
operations, and personal, marine and driving safety. It embraces
recommendations made by the BP US Refineries Independent Safety
Review Panel (the panel), which reported in January 2007 on safety
management at our US refineries and our safety management culture.
The OMS establishes a set of requirements, and provides sites

with a systematic way to improve operating performance on a
continuous basis. BP businesses implementing OMS must work to
integrate group requirements within their local system to meet legal
obligations, address local stakeholder needs, reduce risk and improve
efficiency and reliability. A number of mandatory operating and
engineering technical requirements have been defined within the OMS,
to address process safety and related risks.

All operated businesses plan to transition to OMS by the end of

2010. Eight sites completed the transition to OMS in 2008; two
petrochemicals plants, Cooper River and Decatur, two refineries, Lingen
and Gelsenkirchen and four Exploration and Production sites, North
America Gas, the Gulf of Mexico, Colombia and the Endicott field in
Alaska. Implementation is continuing across the group and a number of
other sites, including all refineries not already operating the OMS, are
expected to complete the transition in 2009.

For the sites already involved, implementing OMS has involved

detailed planning, including gap assessments supported by external
facilitators. A core aspect of OMS implementation is that each site
produces its own ‘local OMS’, which takes account of relevant risks at
the site and details the site’s approach to managing those risks. As part
of its transition to OMS, a site issues its local OMS handbook, and this
summarizes its approach to risk management. Each site also develops a
plan to close gaps that is reviewed annually. The transition to OMS, at
local and group level, has been handled in a formal and systematic way,
to ensure the change is managed safely and comprehensively.

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BP Annual Report and Accounts 2008
Performance review

Experience so far has supported our expectation that having one
integrated and coherent system brings benefits of simplification and
clarity, and that the process of change is supporting our renewed
commitment to safe operations.

We are on track to meet our target of implementing OMS across

the group by the end of 2010.

Capability development
In addition to ongoing training programmes we are undertaking a group
wide programme to enhance the capability of our staff from front line to
executive level to deliver operational excellence.

Almost 1,000, around a third, of our front-line supervisors have

started the Operating Essentials programme, which includes training on
leadership, process safety, operating culture, practices and coaching and
effective performance conversations.

More than 190, around half, of our operations leaders started the
Operations Academy programme in 2008. The academy, which has been
established in partnership with the Massachusetts Institute of
Technology (MIT), provides participants with a total of six weeks of
operations training, concentrating on the management of change and
continuous improvement.

The Executive Operations programme, which seeks to increase

insight into manufacturing and operation activities among senior business
leaders, has built on its successful launch with the first group, which
included the group chief executive and his executive team. By the end of
2008, 99 executives had attended the three-day programme.

In addition to action in these areas, we have continued to participate in
industry-wide forums on process safety and have made efforts to share
our learning with other organizations.

The independent expert has been tasked with reporting to the

board on BP’s progress in implementing the panel’s recommendations.
We welcome the independent expert’s view expressed in his first report
(May 2008) that BP ‘appears to be making substantial progress in
changing culture and addressing needed process safety improvements’.
However, we also acknowledge his observation that ‘a significant amount
of work remains to be done on the process safety journey’ and that
’successful completion of the task will require the continued support and
involvement of the board, executive management, and refinery
leadership along with a sustained effort over an extended period of time’.
The independent expert’s second report is expected in the first half
of 2009.

Operational integrity
We continue to implement the six-point plan launched in 2006 to address
immediate priorities for improving process safety and minimizing risk at
our operations worldwide.

We have met our commitment to remove occupied portable
buildings (OPBs) from high-risk zones within onshore process plant areas
and to remove all blow-down stacks in heavier-than-air, light hydrocarbon
service. All major sites and our fuels value chains have completed major
accident risk assessments, which identify major accident risks and
develop mitigation plans to manage and respond to them.

In addition, new cadres of projects and engineering staff have

We continue to implement the Control of Work and Integrity

Management standards. We have made progress in ensuring our
operations meet the requirements of a group framework designed to
ensure we stay in compliance with legal requirements on health and
safety. We are continuing to take steps to close out past audit actions.
Leadership competency assessments, which involve assessment of the
experience of BP management teams responsible for major production
sites or manufacturing plant, have been completed in Exploration and
Production and in all major Refining and Marketing manufacturing sites.
Implementation of these actions is expected to be largely

complete by the end of 2009, with some aspects of implementation
being incorporated into the transition to the OMS, expected to be
completed by the end of 2010. The GORC regularly monitors progress
against the plan.

We monitor and report separately on major incidents such as

those covering fatal accidents, significant property damage or significant
environmental impact. We also track and analyze ‘high potential’ incidents
– those that could have resulted in a major incident. All major incidents
and many high-potential incidents are discussed by the GORC and we
continue to seek to learn as much as possible from each incident.

A total of 21 major incidents were reported in 2008. Two of the

major incidents were related to hurricanes and eight were related to
driving incidents.

There were 335 oil spills of one barrel or more in 2008, similar to
2007 performance of 340 oil spills. The volume of oil spilled in 2008 was
approximately 3.5 million litres, an increase of 2.5 million litres, compared
with 2007. This was largely the result of two incidents, one at Texas City
and one at the Whiting refinery, which accounted for two-thirds of the
total reported volume of oil spilled, the great majority of which remained
contained and the oil recovered.

progressed through the Project and Engineering Academy at MIT and 13
process safety courses have been delivered for project and project
engineering managers at the Project Management College. We have
continued to develop training on hazard evaluation and risk assessment
techniques for all engineers, operators and HSSE professionals.

Process safety management
We remain fully committed to becoming a recognized industry leader in
process safety management and are working to achieve this. We have
taken a range of steps, including acting on the recommendations
from both the panel and those within the first annual report of the
independent expert.

Our actions can be summarized in three principal areas:
• We have made progress in reducing process safety risk at our US

refineries. For example, we have completed and learned from safety
and operations audits, relocated workers to lower-risk accommodation
and implemented fatigue reduction programmes.

• Executive management has taken a range of actions to demonstrate
their leadership and commitment to safety. The group chief executive
has consistently emphasized that safety, people, and performance are
our top priority, a belief made clear in his 2007 announcement of a
forward agenda for simplification and cultural change in BP. Safety
performance has been scrutinized by the Group Operations Risk
Committee (the GORC), chaired by the group chief executive and
tasked with assuring the group chief executive that group operational
risks are identified and managed appropriately. We continued to build
our team of safety and operations auditors. A team of 45 auditors is
now in place, with 36 audits completed in 2008.

• Many of the process-safety related improvements recommended by
the panel are being implemented across the group through the OMS.
The group essentials within the OMS (which cover diverse aspects
of operating activity including legal compliance, process and
environmental safety and basic operating practices) in some cases go
beyond the panel’s process safety recommendations, a point noted
by the independent expert in his first report.

BP Annual Report and Accounts 2008
Performance review

Performance indicators
We have well-developed systems, processes and metrics for reporting
personal safety and environmental metrics that support internal
performance management as well as public reporting.

We introduced several new metrics in 2008 that aim to enhance

our monitoring of process safety performance within BP’s operating
entities. These include, for example, a process safety incident index, as
recommended by the panel, which uses weighted severity scores to
record and assess process safety events, and a measure to record any
loss of hydrocarbon from primary containment.

Our indicators include industry-aligned ‘lagging’ process safety

metrics that register events that have already occurred, and ‘leading’
indicators that focus on the strength of our controls to prevent undesired
events in future. A suite of indicators is regularly reported to the GORC
within the quarterly ‘HSE and Operations Integrity Report’ and several
new metrics have also been piloted. To further enhance the management
of health risks across the group, we began the systematic reporting of
recordable illness rates within the HSE and Operations Integrity Report.
We continue to work with industry bodies such as the Centre for
Chemical Process Safety and the American Petroleum Institute on the
development of process safety metrics, definitions and guidance.

Continuing to focus on health
In addition to our efforts to improve process safety performance, we
strive to protect the personal health and safety of our workforce,
recognizing that healthy performance is delivered through healthy people,
healthy processes and healthy plant.

In the course of 2008, we defined health ‘group essentials’, which

specify requirements designed to prevent harm to the health of
employees, contractors, visitors and local communities. These were
incorporated within the OMS framework. Our health strategy and plan
was also refreshed in 2008. Priorities include reducing significant
occupational exposure and infectious disease risks, maintaining robust
regulatory compliance in product health and safety and addressing the
issue of fatigue management raised by the panel by providing training
and awareness-raising.

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Environment
Regulation and claims
We are subject to extensive international, national, state and local
environmental regulations concerning our products, operations and
activities. Current and proposed fuel and product specifications,
emission controls and climate change programmes under a number of
environmental laws will have a significant effect on the production, sale
and profitability of many of our products. Environmental laws also require
us to remediate the environmental impacts of prior disposal or releases
of chemicals or petroleum substances by the group or other parties. Such
contingencies may exist for various locations where products are, or have
been, produced, processed, stored, distributed, sold or disposed of, such
as refineries, chemical plants, natural gas processing plants, oil and
natural gas fields, service stations, terminals and waste disposal sites.
Some of these obligations relate to prior asset sales or closed facilities.
Provisions for environmental restoration and remediation are made when
a clean-up is probable and the amount of the obligation can be reliably
estimated. Generally this coincides with commitment to a formal plan of
action or, if earlier, on divestment or on closure of inactive sites. The
provisions made are considered by management to be sufficient to meet
known requirements.

The extent and cost of future environmental restoration,
remediation and abatement programmes are often inherently difficult
to estimate. They often depend on the extent of contamination, and
the associated impact and timing of the corrective actions required,
technological feasibility and BP’s share of liability. Though the costs of
future programmes could be significant and may be material to the
results of operations in the period in which they are recognized, it is not
expected that such costs will be material to the group’s overall results of
operations or financial position or liquidity. See Financial statements –
Note 37 on page 158 for the amounts provided in respect of
environmental remediation and decommissioning.

We are also subject to environmental and common law claims for
personal injury and property damage alleging the release or exposure to
hazardous substances. A number of proceedings involving governmental
authorities are pending or known to be contemplated against BP and
certain of its subsidiaries under federal, state or local environmental laws,
each of which could result in monetary sanctions of $100,000 or more. No
individual proceeding is, nor are the proceedings in aggregate, expected
to be material to the group’s results of operations or financial position.

We cannot accurately predict the effect of future developments,

such as stricter environmental laws or enforcement policies on the
group’s operations, products or profitability. A risk of increased
environmental costs and operational impacts is inherent in grouping our
businesses and there can be no assurance that material liabilities and
costs will not be incurred in the future. We believe that the group’s
activities are in material compliance with applicable environmental laws
and regulations, or that the group has disclosed such non-compliance and
is working with the relevant regulatory authorities to ensure compliance.
For a discussion of the group’s environmental expenditure see page 57.

BP operates in more than 90 countries worldwide. In each of
these areas, BP has, or is developing, processes designed to ensure
compliance with applicable regulations. In addition, each employee is
required to comply with BP health, safety and environmental policies
as embedded in the BP code of conduct. Our partners, suppliers and
contractors are also encouraged to adopt them.

This Environment section focuses primarily on the US and the EU,

where around 61% of our fixed assets are located, and on issues of a
global nature such as our operations and the environment, climate
change programmes and maritime oil spills regulations.

Our operations and the environment
During 2008, we continued to use environmental management systems
to seek improvements on a wide range of environmental issues. Except
at two locations, the operations at our major operating sites are covered

BP Annual Report and Accounts 2008
Performance review

by certification to the ISO 14001 international environmental
management system standard. The Texas City refinery, after completing
planned work to strengthen its environmental management systems, is
planning to seek recertification in 2009. Our Angola business is working
towards an expansion of its existing ISO 14001 certificate to include
its offshore production facilities by the end of 2009. Progressive
implementation of the Operating Management System (OMS), including
ISO 14001, will also help us strengthen our management of
environmental performance.

In support of ongoing risk management, one element of the OMS

applies, at least annually, a formal systematic process to identify and
assess risks; this process provides to identify emerging issues including
those with an environmental impact. To assist us in measuring the
effectiveness of our risk mitigation actions we have established
environmental metrics, which are available within BP Sustainability
Report 2008, at www.bp.com/sustainability. The 2008 information is
planned to be available in conjunction with the publication of our 2008
Sustainability Report.

After two years of implementation, our Environmental
Requirements for New Projects (ERNP) practice has been updated in line
with the OMS. We have simplified applicability, clarified the governance
process and updated the text to reflect organizational changes. This
practice, now called the Environmental Group Defined Practice (GDP) is a
full life cycle environmental assessment process. It requires all new
major projects and projects in sensitive areas, to undertake screening to
determine the potential environmental sensitivities associated with the
proposed projects. Requirements and project recommendations now
extend to include appropriate considerations for decommissioning of
assets. A new project with the highest level of environmental sensitivity
requires more rigorous and specific environmental management
activities. The board-appointed Safety, Environment and Ethics Assurance
Committee reviewed the progress of ERNP during summer 2008. This
review included the 12 projects that have been classified as requiring
management at the highest level of sensitivity. We are currently
integrating social considerations into the Environmental GDP and plan to
issue this in 2009 as an integrated set of requirements addressing social
and environmental issues.

In 2008, BP used the ERNP to review risks and establish

mitigation measures prior to entry in connection with the decision to
develop adjacent to a Protected Area at Hamble Oil Terminal in the UK.
We intend to make a summary of the risk assessment publicly available
at the end of April 2009.

Our focus on asset decommissioning is demonstrated by the

North West Hutton offshore platform project in the North Sea. 2008 saw
the topsides of the North West Hutton platform safely brought onshore
for further dismantling. This decommissioning is expected to result in
20,000 tonnes of recycled steel, in line with our aim to have 97% of the
decommissioned materials recycled and/or reused.

We seek to limit the environmental impact of our operations by

using resources responsibly and reducing waste and emissions.

Climate change programmes
In response to rising concerns about climate change, governments
continue to identify fiscal and regulatory measures at local, national and
international levels.

In December 1997, at the Third Conference of the Parties to the
United Nations Framework Convention on Climate Change (UNFCCC) in
Kyoto, Japan, the participants agreed on a system of differentiated
international legally-binding targets for the first commitment period of
2008-2012. In 2005, the Kyoto protocol came into force, committing the
176 participating countries to emissions targets. However, Kyoto was
only designed as a first step and policymakers continue to discuss what
new agreement might follow it after 2012, most recently at the UNFCCC
conference in Poznan, Poland in December 2008.

Many of our larger EU stationary assets are subject to the EU

Emissions Trading Scheme (EU ETS), which was extended to Norway by

reciprocal agreement. After inclusion of our Norwegian assets, around
one-fifth of our reported 2008 global CO2 emissions are now covered by
this scheme.

At the March 2007 European Council, the European Heads of

Government decided to adopt their Climate Action and Renewable
Energy Package. This legislation was voted through by the European
Parliament in December 2008. The package includes a commitment to
reduce greenhouse gas (GHG) emissions by 20% by 2020 (the target
being 30% if an international agreement is reached), as well as an
improved energy efficiency within the EU Member States of 20% by
2020 and a 20% renewable energy target by 2020.

The Australian government has set a target to reduce GHG

emissions by 60% below 2000 levels by 2050. In December 2008, the
Australian government released its Carbon Pollution Reduction Scheme
White Paper, outlining the design of an emissions trading scheme that
will go into effect in mid-2010; draft legislation is expected in early 2009.
The Australian government proposes to cover 70% of emissions sources
and sectors via a combination of direct obligations on facilities with large
emissions, and obligations on upstream fuel suppliers for the emissions
resulting from the combustion of fuel. In December the government also
announced 2020 GHG emission targets that range from a 5 to 15%
reduction from 2000 levels. The scheme builds on the existing National
Greenhouse and Energy Reporting System, the Australian mandatory
reporting system for corporate greenhouse gas emissions and energy
production and consumption. The first reporting period commenced on
1 July 2008.

The US congress continues to propose new climate change
legislation and regulation. A new bill became law in December 2007, that
includes stricter corporate average fuel emissions standards for
automobiles sold in the US and biofuel mandates. Other bills currently
under consideration propose stricter emissions limits on large GHG
sources and/or the introduction of a cap-and-trade programme on CO2
and other GHG emissions.

An April 2007 US Supreme Court decision will require the US

Environmental Protection Agency (EPA) to reconsider its determination
that it is not required to regulate GHGs from motor vehicles under the
Clean Air Act (CAA). The Supreme Court’s ruling is expected to result in
the EPA regulating motor vehicle GHG emissions. It is also expected to
increase pressure on the EPA to regulate stationary sources of GHGs
(e.g. refineries and chemical plants) under other provisions of the CAA.

In response to the US Supreme Court’s decision, the EPA issued

an Advanced Notice of Proposed Rulemaking (ANPR). The ANPR
addresses complexities involved in controlling greenhouse gases under
the CAA including potential overlap between future legislation and
regulation under the existing CAA.

In its Fiscal Year 2008 Consolidated Appropriations Act, US
Congress directed the EPA to publish a mandatory GHG reporting rule,
issuing a proposed rule within nine months (by September 2008), and a
final rule within 18 months (by June 2009). The EPA has developed draft
language and the proposed rule could be released early in the new
US administration.

Congress will likely develop new legislation for GHG regulation,
and new regulation under the CAA will likely proceed as well. Additional
GHG regulation may also be issued under other laws, such as the
National Environmental Protection Act (NEPA) and Endangered Species
Act (ESA).

In December 2008, the California Air Resources Board (CARB)

approved the final Proposed Scoping Plan for implementing Assembly Bill
32, California’s law to reduce GHG emissions to 1990 levels by 2020.
Implementation measures are due to be developed by 2012. In advance
of the Scoping Plan, CARB has taken early actions with the development
of mandatory GHG reporting and a Low Carbon Fuel Standard (LCFS).
The LCFS will require all refiners, producers, blenders and importers to
reduce the carbon intensity of transport fuel sold in California by 10% by
2020. CARB released draft LCFS regulations in October 2008, with final
regulations expected to be taken up in March 2009.

BP Annual Report and Accounts 2008
Performance review

In March 2008, the Canadian federal government updated its April 2007
Framework Report with an Action Plan to address climate change and
reduce emissions 20% below 2006 levels by 2020 and by greater than
60% by 2050, through both a sector approach and domestic
development and deployment of new technologies and projects. For the
conventional oil and gas industry, the intensity based targets as included
in the plan of the April 2007 Framework Report remain likely. For the oil
sands industry, more stringent requirements are likely to emerge for
upcoming projects that may include requirements for significant
reductions, including the implementation of large scale carbon capture
and sequestration. Since the conclusion of the recent Canadian and US
Federal elections there has been increased discussion on the possibility
of aligning regulations, including possible inclusion of a North America
wide cap-and-trade system.

Since 1997, BP has been actively involved in the policy debate.

We also ran a global programme that reduced our operational GHG
emissions by 10% between 1998 and 2001. We continue to look at two
principal kinds of GHG emissions: operational emissions, which are
generated from our operations such as refineries, chemicals plants and
production facilities; and product emissions, generated by our customers
when they use the fuels and products that we sell. Since 2001, we have
been focusing on measuring and improving the carbon intensity of our
operations as well as developing sustainable low-carbon technologies
and businesses.

After seven years, we estimate that our operations have delivered

some 7.5 million tonnes (Mte) of GHG reductions. Our 2008 operational
GHG emissions were 61.4Mte of CO2 equivalent on a direct equity
basis, nearly 2.1Mte lower than the reported figure of 63.5Mte in 2007.
The primary reason for the lower reported emissions is a reporting
protocol change for BP Shipping (1.9Mte) to align us more closely with
industry practice.

In 2007, as part of our technology development, two major
BP-backed research institutes came into full operation: the Energy
Biosciences Institute (EBI) in the US, and the Energy Technologies
Institute (ETI) in the UK. The EBI is a strategic partnership between BP,
the University of California, Berkeley, the Lawrence Berkeley National
Laboratory and the University of Illinois, Urbana-Champaign to conduct
research into the production of new and cleaner energy, initially focusing
on advanced biofuels for road transport. The EBI will also pursue
bioscience-based research into the conversion of heavy hydrocarbons to
clean fuels, improved recovery from existing oil and gas reservoirs and
carbon sequestration. In the UK, the ETI has been established as a 50:50
public private partnership, funded equally by member companies,
including BP, and the government. The ETI aims to accelerate the
development, demonstration and eventual commercial deployment of a
focused portfolio of energy technologies, which will increase energy
efficiency, reduce GHG emissions and help achieve energy security
and climate change goals. The ETI has issued its first invitation for
expressions of interest to participate in programmes to develop new
technologies for offshore wind and for marine, tidal and wave energy.
BP established the Carbon Mitigation Initiative in 2000 at Princeton
University in the US to research the fundamental scientific,
environmental, and technological issues that will determine how carbon
is managed in the future and examine the policy impact of different
options. BP’s original 10-year commitment initially funded the programme
at $1.5 million per year and later increased it to more than $2 million per
year. In October 2008, BP committed to a five-year renewal of the
partnership and to support Princeton to at least its current level of
funding for the years 2011 to 2015.

Maritime oil spill regulations
Within the US, the Oil Pollution Act of 1990 (OPA 90) imposes oil spill
prevention and planning requirements liability for tankers and barges
transporting oil and for offshore facilities such as platforms and onshore
terminals. To ensure adequate funding for oil spill response and
compensation, OPA 90 created the Oil Spill Liability Trust Fund that is

financed by a tax on imported and domestic oil. In 2006, the Coast Guard
and Maritime Transportation Act 2006, increased the size of the fund from
the original amount of $1 billion to $2.7 billion. In late 2008, as part of the
Emergency Economic Stabilization Act, further amendments were made
to increase the per-barrel contribution rate of tax and to remove the
provision for cessation of the tax when the fund reached $2.7 billion.
There is now no limit on the size of the fund. The same 2008 legislation
amended the termination date of this tax from 31 December 2014 to
31 December 2017. The 2006 legislation also increased the OPA limitation
amount relating to the liability of double-hulled tankers from $1,200 per
gross tonne to $1,900 per gross tonne. In addition to the spill liabilities
imposed by OPA 90 on the owners and operators of carrying vessels,
some states, including Alaska, Washington, Oregon and California, impose
additional liability on the shippers or owners of oil spilled from such
vessels. The exposure of BP to such liability is mitigated by the vessels’
marine liability insurance, which has a maximum limit of $1 billion for each
accident or occurrence. OPA 90 also provides that all new tank vessels
operating in US waters must have double hulls and existing tank vessels
without double hulls must be phased out by 2015. At the end of 2008, BP
owned four double-hulled tankers built between 2004 and 2006, demise-
chartered to and operated by Alaska Tanker Company, L.L.C. (ATC), which
transports BP Alaskan crude oil from Valdez.

Outside of US territorial waters, the BP-operated fleet of tankers

is subject to international spill response and preparedness regulations
that are typically promulgated through the International Maritime
Organization (IMO) and implemented by the relevant flag state
authorities. The International Convention for the Prevention of Pollution
from Ships (Marpol 73/78) requires vessels to have detailed shipboard
emergency and spill prevention plans. The International Convention on Oil
Pollution, Preparedness, Response and Co-operation requires vessels to
have adequate spill response plans and resources for response anywhere
the vessel travels. These conventions and separate Marine Environmental
Protection Circulars also stipulate the relevant state authorities around
the globe that require engagement in the event of a spill. All these
requirements together are addressed by the vessel owners in Shipboard
Oil Pollution Emergency Plans. BP Shipping’s liabilities for oil pollution
damage under the OPA 90 and outside the US under the 1969/1992
International Convention on Civil Liability for Oil Pollution Damage (CLC)
are covered by marine liability insurance, having a maximum limit of
$1 billion for each accident or occurrence. This insurance cover is
provided by three mutual insurance associations (P&I Clubs): The United
Kingdom Steam Ship Assurance Association (Bermuda) Limited; The
Britannia Steam Ship Insurance Association Limited; and The Standard
Steamship Owners’ Protection and Indemnity Association (Bermuda)
Limited. With effect from 20 February 2006, two new complementary
voluntary oil pollution compensation schemes were introduced by tanker
owners, supported by their P&I Clubs, with the agreement of the
International Oil Pollution Compensation Fund at the IMO. Pursuant to
both these schemes, tanker owners will voluntarily assume a greater
liability for oil pollution compensation in the event of a spill of persistent
oil than is provided for in CLC. The first scheme, the Small Tanker
Owners’ Pollution Indemnification Agreement (STOPIA), provides for a
minimum liability of 20 million Special Drawing Rights (around $30
million) for a ship at or below 29,548 gross tonnes, while the second
scheme, the Tanker Owners’ Pollution Indemnification Agreement
(TOPIA), provides for the tanker owner to take a 50% stake in the 2003
Supplementary Fund, that is, an additional liability of up to 273.5 million
Special Drawing Rights (around $405 million). Both STOPIA and TOPIA
will only apply to tankers whose owners are party to these agreements
and who have entered their ships with P&I Clubs in the International
Group of P&I Clubs, so benefiting from those clubs’ pooling and
reinsurance arrangements. All BP Shipping’s managed and time-
chartered vessels participate in STOPIA and TOPIA.

For information regarding maritime security issues, see Shipping

on page 39.

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BP Annual Report and Accounts 2008
Performance review

US
The following is a summary of significant US environmental issues and
environment and health and safety legislation or regulations affecting BP.

The CAA and its regulations, administered by the United States

disposed and certain other parties are strictly liable for the cost of
responding to related hazardous substance contamination. EPA
administers CERCLA. Additionally, states have separate laws similar
to CERCLA.

Environmental Protection Agency (EPA) require, among other things:
stringent air emission limits and operating permits for chemicals plants,
refineries, marine and distribution terminals and exploration and
production facilities, strict fuel specifications and sulphur reductions;
enhanced monitoring of major sources of specified pollutants; and risk
management plans for storage of hazardous substances. This law affects
BP facilities producing, storing, refining, manufacturing and distributing oil
and products as well as the fuels themselves. Federal and state controls
on ozone, particulate matter, carbon monoxide, benzene, sulphur, MTBE,
nitrogen dioxide, oxygenates, lead and Reid Vapor Pressure affect BP’s
activities and products. Under the CAA all gasoline produced by BP is
subject to the EPA’s stringent low-sulphur standards. By June 2006, at
least 80% of the highway diesel fuel produced each year by BP was
required to meet a sulphur cap of 15 parts per million (ppm). By June
2007, all non-road locomotive and marine diesel fuel produced each year
by BP was required to meet a sulphur cap of 500ppm. Additionally, states
have separate laws similar to the CAA.

The Energy Policy Act of 2005 affects the US fuels market by:

eliminating the Federal Reformulated Gasoline (RFG) oxygen requirement
in May 2006; establishing a renewable fuels mandate (4 billion gallons in
2006, increasing to 7.5 billion in 2012); consolidating the summertime
RFG volatile organic compound (VOC) standards for EPA Regions 1 and 2;
allowing the Ozone Transport Commission states on the east coast to
opt any area into RFG; and allowing states to repeal the 1psi Reid Vapor
Pressure waiver for 10% ethanol blends.

The Energy Independence and Security Act of 2007 increased the
renewable fuel mandate to 9 billion gallons in 2008 and further each year
to a maximum of 36 billion gallons in 2022.

In 2001, BP entered into a consent decree with the EPA and
several states that settled alleged violations of various CAA requirements
related largely to emissions of sulphur dioxide and nitrogen oxides at BP’s
US refineries. Implementation of the decree’s requirements continues.

In 2001, BP’s US refineries entered into a civil consent decree with

the EPA to resolve alleged violations of the CAA. The decree applies to all
the US refineries of BP Products North America Inc. (BP Products). On
19 February 2009, the EPA and US Department of Justice (DOJ) lodged an
amendment to the 2001 decree. The amendment applies only to the Texas
City refinery and resolves alleged violations of both the 2001 decree and
the CAA. The decree requires that BP Products pays a $12 million civil fine,
funds a $6 million supplemental environmental project and takes steps at
the Texas City refinery to enhance compliance with CAA rules.
The estimated cost of these compliance measures is approximately
$150 million. The decree amendment is subject to court approval.

The Clean Water Act (CWA) and its regulations, administered by

EPA and the US Coast Guard, regulate the discharge of wastewater,
stormwater and toxic discharges from BP’s onshore and offshore
operations to navigable waters. Facilities are required to obtain discharge
permits, install control equipment and implement operational controls
and preventative measures. Additionally, states have separate laws
similar to the CWA.

The Resource Conservation and Recovery Act (RCRA) and its

regulations, administered by the EPA, regulate the storage, handling,
treatment, transportation and disposal of hazardous and non-hazardous
wastes and require the investigation and remediation of locations at a
facility where such wastes have been managed. Many BP facilities
generate and manage wastes regulated by RCRA and several include
locations that are subject to investigation and corrective action.
Additionally, states have separate laws similar to RCRA.

Under the Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA or Superfund), persons who
arranged to dispose of hazardous substances at a site, persons who
currently own or operate a site where such substances have been

BP has been identified as a Potentially Responsible Party (PRP)

under CERCLA or otherwise named under similar state statutes at
approximately 809 sites. A PRP or named party can incur joint and
several liability for site remediation costs under some of these statutes
and so BP may be required to assume, among other costs, the share
attributed to insolvent, unidentified or other parties. BP has the most
significant exposure for remediation costs at 50 of these sites. For the
remaining sites, BP is one of many potentially responsible parties, and
BP expects its share of remediation costs at these sites to be small in
comparison with the major sites. BP has estimated its potential exposure
at all sites where it has been identified as a PRP or is otherwise named
at a site is approximately $1.7 billion.

BP is also subject to claims for natural resource damages (NRD)

under CERCLA, the OPA 90 and other federal and state laws. NRD claims
have been asserted by government trustees against a number of BP
operations. Many environmental clean-ups are driven by state and federal
groundwater protection standards. Contamination or the threat of
contamination of current or potential potable (and occasionally non-
potable) water resources can result in stringent clean-up requirements.
BP has encouraged risk-based approaches to these issues and seeks
to tailor remedies at its facilities to match the level of risk presented
by the contamination.

Other legislation that significantly affect BP operations includes:
the Toxic Substances Control Act, administered by EPA, which regulates
the development, testing, import, export and introduction of new
chemical products into commerce; the Occupational Safety and Health
Act, administered by the Occupational Safety and Health Administration,
which imposes workplace safety and health, training and process safety
requirements to reduce the risks of physical and chemical hazards and
injury to employees; the CAA, which created the US Chemical Safety and
Hazard Investigation Board which investigates the causes of chemical
accidents and makes non-binding recommendations to industry,
government and non-governmental organizations; and the Emergency
Planning and Community Right-to-Know Act, administered by the EPA,
which requires emergency planning and hazardous substance release
notification as well as public disclosure of chemical usage and emissions.
In addition, the US Department of Transportation (DOT) regulates the
transportation of the BP’s petroleum products such as crude oil, gasoline
and chemicals.

BP is subject to the Marine Transportation Security Act (MTSA)
and regulations and the DOT Hazardous Materials (HAZMAT) security
compliance regulations. These regulations require many of BP’s
businesses to conduct security vulnerability assessments and prepare
security mitigation plans that require upgrades to security measures, the
appointment and training of security personnel and the submission
of plans for approval and inspection by government agencies.
The US government through the Department of Homeland Security, in an
effort to further mitigate the threat of terrorism to critical US
infrastructure, has implemented two new security legislation initiatives,
that began in 2007 and has continued through 2008:
• Chemical Facility Anti-Terrorism Standard (CFATS).
• Transportation Workers Identification Credential (TWIC).
CFATS is intended to provide an enhanced security posture for US
facilities that manufacture or store Chemicals of Interest, including
gasoline. Additionally, in the future, it will cover facilities that have national
economic impact to the US, should these facilities be a target for
terrorism. A number of BP facilities may be required to conduct a detailed
security vulnerability assessment and a detailed security plan for each
facility impacted.

TWIC requires all designated personnel with unescorted access to

restricted areas of MTSA designated facilities to submit to a background
screening programme and to obtain a biometric identification card. All of

BP Annual Report and Accounts 2008
Performance review

BP’s MTSA-regulated facilities will be impacted and will be required to
comply by the end of 2008 or beginning of 2009 in a phased approach.

The BP Americas Response Team consists of approximately

210 trained emergency responders at BP locations throughout North
America. In addition, there are five Regional Response Incident
Management Teams, a number of HAZMAT Teams and emergency
response teams at BP’s major facilities. Collectively, these teams are
ready to assist in a response to a major incident.

In 2008, BP Products obtained and renewed environmental
permits that enabled it to commence construction on the project to
upgrade the Whiting refinery. Various environmental groups have
challenged these permits in state and federal proceedings.

In November 2007, the EPA began issuing a series of notices of
violations, alleging clean air act violations, to the Whiting, Toledo, Carson
and Cherry Point refineries. Settlement negotiations continue between
BP Products, the EPA and the DOJ in an effort to resolve these matters.
In October 2008, the EPA issued an amended notice of violation alleging
that BP Products began construction on the Whiting upgrade in 2005 prior
to receiving the necessary permits. This allegation has been incorporated
into the permit challenges filed by the environmental groups. The subject
matter of the notices of violation could be resolved as an amendment to
the 2001 EPA consent decree or as a separate matter.
See also Legal proceedings on page 92.

European Union
The following is a summary of significant EU level environmental
legislation and UK health and safety legislation affecting BP.

At the March 2007 European Council, the European Heads of

Government decided to adopt:
• a commitment to reduce GHG emissions by at least 20% by 2020 as
compared with 1990 levels and the objective of a 30% reduction by
2020, subject to the conclusion of a comprehensive international
climate change agreement; and

contributing to the achievement of the targets set in the EC’s Thematic
Strategies on Air, Soil and Waste. The proposal merges and revises
several separate directives related to industrial emissions (including the
Large Combustion Plant Directive) into one Directive. It proposes tighter
minimum standards for emissions from large combustion plant
(>50MW), and introduces a mandatory requirement to achieve emission
limit values indicated by use of ‘Best Available Techniques’ (with
derogations from this requirement allowed where justified).

The proposal would also extend the scope of IPPC to specifically

cover organic chemical manufacture by biological treatment (biofuels) and
may open the way for NOx and SOx trading by member states.

The EC proposal has triggered considerable debate and the
timetable for the completion of the legislative process and the likely
outcome are not clear. However, the revision has already triggered a
greater focus on the information sharing process that is used to determine
and document the BAT for each industry sector, and will raise the profile of
the outputs from this process – the BAT Reference Documents (BREFs).
In 2005, the EC published its Thematic Strategy on Air Pollution,

which outlines EU-wide targets for health and environmental benefits
from improved air quality to be achieved through further controls on
emissions of fine particulates (PM 2.5 – particulate matter less than
2.5 microns diameter), sulphur dioxide, oxides of nitrogen, volatile organic
compounds and ammonia. Associated with this is the revision to the
National Emissions Ceiling Directive (NECD), which would introduce new
emissions ceilings for each member state for fine particles and tighten
existing ceilings for sulphur dioxide, oxides of nitrogen, volatile organic
compounds and ammonia. There is currently uncertainty regarding the
costs to industry of implementing possible outcomes from the NECD
and IPPC revisions.

The proposed revision of the current EU Fuel Quality Directive is

referred to in the Climate Change Programmes section above. In addition
to its provisions regarding life cycle GHG emission reductions, it would
also facilitate the introduction of biofuels into gasoline and diesel.

• a mandatory EU target of 20% renewable energy by 2020 including a

Registration, Evaluation and Authorization of Chemicals (REACH)

10% biofuels target.

In December 2008, the European Parliament approved the

‘Climate Action and Renewable Energy Package’, which:
• revises the EU’s Emissions Trading System to establish auctioning of

emission allowances from 2013;

• sets binding national targets for each EU member state;
• equips power plants to capture and store CO2 underground;
• sets mandatory national targets for each EU member state with the

goal of delivering 20% renewable energy target by 2020; and

• provides for a revised Fuel Quality Directive requiring fuel suppliers to
reduce the life cycle emission of the fuels they provide by up to 10%
by 2020.

BP was involved at the highest levels in the preparation of the ‘Climate
Action and Renewable Energy Package’, as part of our efforts to actively
contribute to the formulation of energy security and climate change
policy in the EU.

An EC directive for a system of integrated pollution prevention
and control (IPPC) was adopted in 1996. This system requires certain
listed industrial installations, including most activities and processes
undertaken by the oil and petrochemicals industry within the EU, to
obtain an IPPC permit, which is designed to address an installation’s
environmental impacts, air emissions, water discharges and waste in a
comprehensive and integrated fashion. The permit requires, among other
things, the application of Best Available Techniques (BAT), taking into
account the costs and benefits, unless an applicable environmental
quality standard requires more stringent restrictions, and an assessment
of existing environmental impacts and future site closure obligations. All
such plants had to obtain such a permit by 30 October 2007 and permits
included an environmental improvement programme where necessary.
In December 2007, the EC issued a proposal for the revision to

legislation became effective 1 June 2007 across all member states of the
EU. All chemical substances manufactured within, or imported into, the
EU in quantities above 1 tonne per annum must be registered fully by
each manufacturer/importer with the new European Chemical Agency
(ECHA). Failure to comply with REACH in respect of such a substance
will immediately remove a company’s legal right to manufacture or import
that substance. Initially all existing manufactured and imported
substances had to be pre-registered by 1 December 2008, to qualify for a
timed phase-in for full registration during the period 2010-2018, with the
exact timing being determined by the volumes of chemicals
manufactured/imported, and by the health, safety and environmental
hazards the chemical may possess. Failure to pre-register an existing
chemical will result in an immediate requirement to register fully the
chemical with the ECHA prior to continued manufacture within, or import
into, the EU. Time-limited authorizations may be granted for substances
of ‘high concern’ and in some cases restrictions in use may apply. Crude
oil and natural gas are exempt from registration requirements, while fuels
are exempt from authorization but not registration. In BP, REACH affects
our refining, petrochemicals and other chemical manufacturing
operations, with many other businesses, such as lubricants, also being
impacted in their roles as major importers and downstream users of
chemicals. In 2008, BP submitted around 700 pre-registrations, covering
approximately 250 individual chemical substances. For almost 60% of
these, ‘full’ registration dossiers must be submitted to ECHA by
1 December 2010, the balance being required in the period 2013-2018.
Total REACH registration fees to be incurred by BP’s businesses are
estimated to be in the region of $15 million and these contribute to an
estimated overall cost of $60 million during the period 2008-2018 for pre
registration, registration and provision of additional testing requirements.

In the UK, significant health and safety legislation affecting BP

the IPPC Directive with the aims of streamlining legislation on industrial
emissions, improving the implementation of BATs across Europe, and

includes the Health and Safety at Work Act and regulations made
thereunder and the Control of Major Accident Hazards Regulations.

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BP Annual Report and Accounts 2008
Performance review

Employees

Number of employees at 31 December
2008
Exploration and Production
Refining and Marketing
Other businesses and corporate

2007
Exploration and Production
Refining and Marketing
Other businesses and corporatea

2006
Exploration and Production
Refining and Marketing
Other businesses and corporate

Rest of
Europe

Rest of
World

3,600
9,000
3,300
15,900

3,800
9,700
3,500
17,000

3,600
10,200
3,100
16,900

700
18,000
700
19,400

700
18,400
800
19,900

1,000
18,600
600
20,200

7,700
19,000
2,600
29,300

7,800
22,700
2,500
33,000

7,600
23,800
2,300
33,700

9,400
15,500
2,500
27,400

9,500
16,400
2,300
28,200

9,200
15,400
1,600
26,200

Total

21,400
61,500
9,100
92,000

21,800
67,200
9,100
98,100

21,400
68,000
7,600
97,000

aA minor amendment has been made to the comparative figure for Rest of the World to correct headcount data.

People and their capabilities are fundamental to our sustainability as a
business. To build an enduring business in an increasingly complex and
competitive industry, we need people with world-class capabilities,
ranging from deepwater drilling and operating refineries to negotiating
with governments and planning wind farms.

Our 2008 focus has been on reducing complexity and embedding
the performance culture throughout the company. We have implemented
structured transformational programmes in a number of strategic
performance units (SPUs) and the major functions. We have stopped
activity that was being repeated at multiple layers, removed layers
of management and have established the SPUs as the principal
units of delivery.

There is a greater focus on individual performance management.

We have simplified the performance management process and can
clearly identify and reward top performing businesses and individuals.
Our incentive plans provide a direct link between SPU performance, the
individual’s contribution, and the bonus outcome.

We had approximately 92,000 employees at 31 December 2008,

In 2008, a global diversity and inclusion (D&I) council was established.
This council, chaired by Tony Hayward, is supported by a North American
regional council and segment councils. The aim is to harmonize
processes and tools for managing D&I across all Segments and
Functions. Responsibility for delivering D&I plans sits at the
business/SPU level.

The group people committee, formed in 2007, continues to take
overall responsibility for policy decisions relating to employees. In 2008,
these ranged from senior level talent review and succession planning,
embedding of diversity and inclusion plans in the businesses and the
structure of long-term incentive plans.

We continue to increase the number of local leaders and

employees in our operations so that they reflect the communities in
which we operate. For example, in Colombia, national employees now
make up 98% of BP’s team, while in Azerbaijan, the equivalent proportion
is 83%. By 2020, more than half our operations are expected to be in
non-OECD countries and we see this as an opportunity to develop a new
generation of experts and skilled employees.

compared with approximately 98,100 at 31 December 2007.

At the end of 2008, 14% of our top 583 leaders were female and

In managing our people, we seek to attract, develop and retain
highly talented individuals in order to maintain BP’s capability to deliver
our strategy and plans. Our three-year graduate development programme
currently has 1,200 participants from all over the world.

We are focusing on the need for deep specialist skills.
Accordingly, we have increased external hiring in infrastructure and
technical areas. The energy industry faces a shortage of professionals
such as petroleum engineers. The number of experienced workers
retiring is expected to exceed that of new graduate hires. To help address
this issue we are developing more robust resourcing plans supported by
initiatives aimed at increasing the numbers of recruits and diversifying the
sources from which we recruit. The external hiring initiatives are
supported by plans for accelerated discipline development, prioritized
deployment and retention schemes.

The continuous improvement we are making to performance
management and reward will help ensure that BP meets the expectations
of these new recruits who are highly mobile and are more conscious that
they have a choice about where to work.

Our policy is to ensure equal opportunity in recruitment,
career development, promotion, training and reward for all employees,
including those with disabilities. Where existing employees become
disabled, our policy is to provide continuing employment and training
wherever practicable.

19% came from countries other than the UK and the US. When we
started tracking the composition of our group leadership in 2000, these
percentages were 9% and 14% respectively. We continue to raise our
senior level leaders’ awareness of D&I, and further training is planned
in 2009.

We aim to develop our leaders internally, although we recruit
outside the group when we do not have specialist skills in-house or when
exceptional people are available. In 2008, we appointed 73 people
to positions in the group leadership population. Of these, 39 were
internal candidates.

We provide development opportunities for our employees,

including training courses, international assignments, mentoring, team
development days, workshops, seminars and online learning. We
encourage all employees to take five training days per year.

A leadership, development and learning steering group was set up

in 2008. This body of senior executives has responsibility for guiding and
advising on leadership and management development. As part of this,
the steering group oversees the Managing Essentials programme, which
was successfully rolled out in 2007.

Through our award-winning ShareMatch plan, run in more than

70 countries, we match BP shares purchased by employees.

BP Annual Report and Accounts 2008
Performance review

Communications with employees include magazines, intranet sites,
DVDs, targeted emails and face-to-face communication. Team meetings
are the core of our employee consultation, complemented by formal
processes through works councils in parts of Europe. These
communications, along with training programmes, are designed to
contribute to employee development and motivation by raising
awareness of financial, economic, social and environmental factors
affecting our performance.

The group seeks to maintain constructive relationships with

labour unions.

‘Pulse’ surveys conducted in 2008 among samples of employees

indicated that BP’s safety culture is growing but that overall satisfaction
levels have fallen. The surveys also revealed that more work needs to be
done to ensure all employees fully understand what they need to do to
deliver sustainable high performance.

We continue to make significant efforts to communicate the

intent and progress of the forward agenda to reduce the potential
negative impacts of this change on the business. We have moved quickly,
but our management of change practices keep the focus on safety and
ensure that the changes are sustainable. These improvements are
expected to continue in 2009, but we have already delivered material
reductions in activity, cost and headcount.

The code of conduct
We have a code of conduct designed to ensure that all employees
comply with legal requirements and our own standards. The code defines
what BP expects of its people in key areas such as safety, workplace
behaviour, bribery and corruption and financial integrity. Our employee
concerns programme, OpenTalk, enables employees to seek guidance
on the code of conduct as well as to report suspected breaches of
compliance or other concerns. The number of cases raised through
OpenTalk in 2008 was 925, compared with 973 in 2007.

In the US, former US district court judge Stanley Sporkin acts

as an ombudsperson. Employees and contractors can contact him
confidentially to report any suspected breach of compliance, ethics
or the code of conduct, including safety concerns.

We take steps to identify and correct areas of non-compliance

and take disciplinary action where appropriate. In 2008, 765 dismissals
were reported by BP’s businesses for non-compliance or unethical
behaviour. This number excludes dismissals of staff employed at our
retail service station sites, for incidents such as thefts of small amounts
of money.

BP continues to apply a policy that the group will not participate

directly in party political activity or make any political contributions,
whether in cash or in kind. BP specifically made no donations to UK or
other EU political parties or organizations in 2008.

Social and community issues
Contributing to communities
We aim to make a difference in the communities where we operate in a
manner that brings benefits to BP as well as the local society. Investment
in education, for example, promotes sustainable development as well as
providing skilled workers for BP and other companies. Support for local
enterprise drives economic growth as well as helping local companies
qualify as our suppliers.

BP operates in a diverse range of locations with varying levels

of economic and national development. We contribute to communities
in ways that are relevant to local circumstances, and which offer
opportunities for mutual benefit to our business. Given the scale of our
business, our impact often reaches beyond the local community to the
national and, in some cases, the international level.

We support education because it creates opportunities for

communities, while at the same time providing skills that are critical
to BP business and the wider industry. Our interventions in education

are diverse and wide-ranging. We help fund a range of educational
programmes, from early years learning to advanced university research,
building skills and capability in communities as well advancing knowledge
on issues such as climate change and effective economic management
of natural resource rich countries. In further and higher education, a major
driver for our involvement is the need to encourage more people to
develop the particular skills needed for the energy industry. In supporting
school education, BP looks to develop children’s awareness of links
between energy and the environment as well as stimulating interest in
science and engineering. In addition to its investment in the formal
learning system, BP supports public education on specific pressing social
issues when there is a particular need within a local community.

Through training and financing programmes, BP seeks to support
the development of local suppliers by building their skills, sharing internal
standards and practice and stimulating business development. This
enables greater participation in the supply chain by local business and
greater competitiveness overall.

We support several initiatives designed to promote the
effectiveness of natural resource led national development. Through
the support of the Oxford Centre for the Analysis of Resource Rich
Economies, we seek to improve the understanding of the development
challenges and policy options available to emerging economies that are
rich in natural resources such as oil and gas. We remain a member of the
Extractive Industries Transparency Initiative (EITI), which supports the
creation of a standardized process for transparent reporting of company
payments and government revenues from oil, gas and mining.
In the US, amongst various other initiatives in 2008, we

provided more than $17 million to assist with relief and recovery
efforts for the wider community following Hurricanes Ike and Gustav
in the Gulf of Mexico.

We make direct contributions to communities through community

programmes. Our total contribution in 2008 was $125.6 million. This
included $0.2 million contributed by BP to UK charities. The growing
focus of this is on education, the development of local enterprise and
providing access to energy in remote locations.

In 2008, we spent $59.5 million promoting education, with
investment in three broad areas: energy and the environment; business
leadership skills; and basic education in developing countries where we
operate large projects.

Essential contracts
BP has contractual and other arrangements with numerous third parties
in support of its business activities. This report does not contain
information about any of these third parties as none of our arrangements
with them are considered to be essential to the business of BP.

Property, plants and equipment
BP has freehold and leasehold interests in real estate in numerous
countries, but no individual property is significant to the group as a
whole. See Exploration and Production on page 17 for a description of
the group’s significant reserves and sources of crude oil and natural gas.
Significant plans to construct, expand or improve specific facilities are
described under each of the business headings within this section.

Organizational structure
The significant subsidiaries of the group at 31 December 2008 and to the
group percentage of ordinary share capital (to the nearest whole number)
are set out in Financial statements – Note 46 on page 175. See Financial
statements – Notes 26 and 27 on pages 140 and 141 respectively for
information on significant jointly controlled entities and associates of
the group.

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BP Annual Report and Accounts 2008
Performance review

Financial and operating performance

Group operating results
The following summarizes the group’s operating results.

Total revenuesa
Profit from continuing operationsa
Profit for the year
Profit for the year attributable to BP shareholders
Profit attributable to BP shareholders per ordinary share – cents
Dividends paid per ordinary share – cents

$ million except per share amounts

2008
365,700
21,666
21,666
21,157
112.59
55.05

2007
288,951
21,169
21,169
20,845
108.76
42.30

2006
270,602
22,311
22,286
22,000
109.84
38.40

aExcludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2004, 2005 and 2006.

Hydrocarbon production
Our total hydrocarbon production during 2008 averaged 2,517mboe/d for
subsidiaries and 1,321mboe/d for equity accounted-entities, a decrease
of 1.2% (a decrease of 3.1% for liquids and an increase of 0.7% for gas)
and an increase of 4.0% (an increase of 2.5% for liquids and an increase
of 14.8% for gas) respectively compared with 2007. In aggregate, after
adjusting for the effect of lower entitlement in our PSAs, production was
5% higher than 2007. This reflected strong performance from our
existing assets, the continued ramp-up of production following the start
up of major projects in late-2007 and a further nine major project start
ups in 2008. Our total hydrocarbon production during 2007 averaged
2,549mboe/d for subsidiaries and 1,269mboe/d for equity-accounted
entities, a decrease of 3% (3.5% for liquids and 2.6% for gas) and 2%
(1.3% for liquids and 8.4% for gas) respectively compared with 2006. In
aggregate, the decrease primarily reflected the effect of disposals and
net entitlement reductions in our PSAs.

Profit attributable to BP shareholders
Profit attributable to BP shareholders for the year ended 31 December
2008 was $21,157 million, including inventory holding losses, net of tax,
of $4,436 million and a net charge for non-operating items, after tax, of
$796 million. In addition, fair value accounting effects had a favourable
impact, net of tax, of $146 million relative to management’s measure of
performance. Inventory holdings gains or losses, net of tax, are described
in footnote (a) on the following page. Further information on non-
operating items and fair value accounting effects can be found on
page 55.

Profit attributable to BP shareholders for the year ended

31 December 2007 was $20,845 million, including inventory holding
gains, net of tax, of $2,475 million and a net charge for non-operating
items, after tax, of $373 million (see page 56). In addition, fair value
accounting effects had an unfavourable impact, net of tax, of $198 million
(see page 56) relative to management’s measure of performance.

Profit attributable to BP shareholders for the year ended

31 December 2006 was $22,000 million, including inventory holding
losses, net of tax, of $222 million and a net credit for non-operating
items, after tax, of $1,237 million (see page 56). In addition, fair value
accounting effects had a favourable impact, net of tax, of $72 million (see
page 56) relative to management’s measure of performance. The profit
attributable to BP shareholders for the year ended 31 December 2006
included a loss from Innovene operations of $25 million.

Business environment
Crude oil prices reached new record highs in 2008, in nominal terms.
The average dated Brent price for the year rose to $97.26 per barrel, an
increase of 34% over the $72.39 per barrel average seen in 2007. Daily
prices began the year at $96.02 per barrel, peaked at $144.22 per barrel
on 3 July 2008, and fell to $36.55 per barrel at year-end. The sharp drop in
prices was due to falling demand in the second half of the year, caused
by the OECD falling into recession and the lagged effect on demand of
high prices in the first half of the year. OPEC had increased production
significantly through the first three quarters; and, as a result of falling
consumption and rising OPEC production, inventories rose. As prices
continued to decline, OPEC responded with successive announcements
of production cuts in September, October, and December.

Natural gas prices in the US and the UK increased in 2008. The
Henry Hub First of Month Index averaged $9.04/mmBtu, 32% higher
than the 2007 average of $6.86/mmBtu. Prices peaked at $13.11/mmBtu
in July amid robust demand and falling US gas imports, but fell to
$6.90/mmBtu in December as demand weakened and production
remained strong. Average UK gas prices rose to 58.12 pence per therm
at the National Balancing Point in 2008, 94% above the 2007 average of
29.95 pence per therm.

Refining margins fell back in 2008, with the BP Global Indicator

Margin (GIM) averaging $6.50 per barrel. The premium for light products
above fuel oils remained high, reflecting a continuing shortage of
upgrading capacity and the favouring of fully upgraded refineries over
less complex sites.

The retail environment continued to be extremely competitive in

2008 with market volatility, high absolute prices, as well as large price
shifts in the crude market.

In 2007, the average dated Brent price rose to $72.39 per barrel,

an increase of 11% over the $65.14 per barrel average seen in 2006.
Daily prices began the year at $58.62 per barrel and rose to $96.02 per
barrel at year-end due to OPEC production cuts in early 2007, sustained
consumption growth and a resulting drop in commercial inventories after
the summer.

Natural gas prices in the US and the UK declined in 2007. The

Henry Hub First of Month Index averaged $6.86/mmBtu, 5% lower than
the 2006 average of $7.24/mmBtu. Prices were pressured by strong LNG
imports in summer, continued domestic production growth and high
inventories. Average UK gas prices fell to 29.95 pence per therm at
the National Balancing Point in 2007, 29% below the 2006 average of
42.19 pence per therm.

Refining margins had reached a new record high in 2007, with

the BP Global Indicator Margin (GIM) averaging $9.94 per barrel. The
premium for light products above fuel oils remained exceptionally high,
reflecting a shortage of upgrading capacity and the favouring of fully
upgraded refineries over less complex sites.

BP Annual Report and Accounts 2008
Performance review

The primary additional factors reflected in profit for 2008, compared

with 2007, were higher realizations, a higher contribution from the gas

marketing and trading business, improved oil supply and trading

performance, improved marketing performance and strong cost

management; however, these positive effects were partly offset by

weaker refining margins, particularly in the US, higher production taxes,

higher depreciation, and adverse foreign exchange impacts.

The primary additional factors reflected in profit for 2007,
compared with 2006, were higher liquids realizations, stronger refining
and marketing margins and improved NGLs performance; however,
these were more than offset by lower gas realizations, lower reported
production volumes, higher production taxes in Alaska, higher costs
(primarily reflecting the impact of sector-specific inflation and higher
integrity spend), the impact of outages and recommissioning costs at the
Texas City and Whiting refineries, reduced supply optimization benefits
and a lower contribution from the marketing and trading business.

Profits and margins for the group and for individual business

segments can vary significantly from period to period as a result of

changes in such factors as oil prices, natural gas prices and refining

margins. Accordingly, the results for the current and prior periods do not

necessarily reflect trends, nor do they provide indicators of results for

future periods.

Employee numbers were approximately 92,000 at 31 December

2008, 98,100 at 31 December 2007 and 97,000 at 31 December 2006.

a Inventory holding gains and losses represent the difference between the cost of sales calculated
using the average cost to BP of supplies incurred during the year and the cost of sales calculated
on the first-in first-out (FIFO) method including any changes in provisions where the net realizable
value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS
reporting, the cost of inventory charged to the income statement is based on the historic cost of
acquisition or manufacture rather than the current replacement cost. In volatile energy markets,
this can have a significant distorting effect on reported income. The amounts disclosed represent
the difference between the charge to the income statement on a FIFO basis (and any related
movements in net realizable value provisions) and the charge that would arise using average cost
of supplies incurred during the period. For this purpose, average cost of supplies incurred during
the period is calculated by dividing the total cost of inventory purchased in the period by the
number of barrels acquired. The amounts disclosed are not separately reflected in the financial
statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as
part of a trading position and certain other temporary inventory positions.

Management believes this information is useful to illustrate to investors the fact that crude

oil and product prices can vary significantly from period to period and that the impact on our
reported result under IFRS can be significant. Inventory holding gains and losses vary from period
to period due principally to changes in oil prices as well as changes to underlying inventory levels.
In order for investors to understand the operating performance of the group excluding the impact
of oil price changes on the replacement of inventories, and to make comparisons of operating
performance between reporting periods, BP’s management believes it is helpful to disclose this
information.

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Capital expenditure and acquisitions

Exploration and Production
Refining and Marketing
Other businesses and corporate
Capital expenditure
Acquisitions and asset exchanges

Disposals
Net investment

2008
22,026
4,710
1,450
28,186
2,514
30,700
(929)
29,771

2007
13,904
4,356
934
19,194
1,447
20,641
(4,267)
16,374

$ million

2006
13,209
3,105
596
16,910
321
17,231
(6,254)
10,977

Capital expenditure and acquisitions in 2008, 2007 and 2006 amounted
to $30,700 million, $20,641 million and $17,231 million respectively.
In 2008, this included $4,731 million in respect of our transaction with
Husky Energy Inc. and $3,667 million in respect of our purchase of all
Chesapeake Energy Corporation’s interest in the Arkoma Basin Woodford
Shale assets and the purchase of a 25% interest in Chesapeake’s
Fayetteville Shale assets. Acquisitions in 2007 included the remaining
31% of the Rotterdam (Nerefco) refinery from Chevron’s Netherlands
manufacturing company.

Excluding acquisitions and asset exchanges, capital expenditure

for 2008 was $28,186 million compared with $19,194 million in 2007 and
$16,910 million in 2006. In 2006, this included $1 billion in respect of our
investment in Rosneft.

Finance costs and net finance income relating to pensions and other
post-retirement benefits
Finance costs comprises group interest less amounts capitalized, and
interest accretion on provisions and long-term other payables. Finance
costs for continuing operations in 2008 were $1,547 million compared
with $1,393 million in 2007 and $986 million in 2006. The increase in
2008, when compared with 2007, is largely the outcome of reductions
in capitalized interest as capital construction projects concluded. The
increase in 2007, when compared with 2006, reflected a higher average
gross debt balance and lower capitalized interest as capital construction
projects concluded.

Net finance income relating to pensions and other post-retirement

benefits in 2008 was $591 million compared with $652 million in 2007
and $470 million in 2006. The expected return on assets has increased
year on year as the pension asset base applicable to each year increased,
but this has been offset in 2008 by higher interest costs reflecting the
increase in discount rates applied to pension plan liabilities.

Taxation
The charge for corporate taxes for continuing operations in 2008 was
$12,617 million, compared with $10,442 million in 2007 and $12,331
million in 2006. The effective rate was 37% in 2008, 33% in 2007 and
36% in 2006. The group earns income in many countries and, on average,
pays taxes at rates higher than the UK statutory rate of 28% for 2008.
The increase in the effective rate in 2008 compared with 2007 primarily
reflects the change in the country mix of the group’s income, resulting in
a higher overall tax burden. The reduction in the effective rate in 2007
compared with 2006 primarily reflects the reduction in the UK tax rate
and the fact that a higher proportion of income arose in countries bearing
a lower tax rate and other factors.

Business results
Profit before interest and taxation from continuing operations, which is
before finance costs, other finance expense, taxation and minority
interests, was $35,239 million in 2008, $32,352 million in 2007 and
$35,158 million in 2006.

BP Annual Report and Accounts 2008
Performance review

Exploration and Production

For the year ended 31 December

Total revenuesa
Profit before interest and tax from continuing operationsb
Results include:

Exploration expense
Of which: Exploration expenditure written off

Key statistics
Average BP crude oil realizationsc

UK
US
Rest of World
BP average

Average BP NGL realizationsc

UK
US
Rest of World
BP average

Average BP liquids realizationsc d

UK
US
Rest of World
BP average

Average BP natural gas realizationsc

UK
US
Rest of World
BP average

Average West Texas Intermediate oil price
Alaska North Slope US West Coast
Average Brent oil price

Average Henry Hub gas pricee

Average UK National Balancing Point gas price

Total liquids production for subsidiariesd f
Total liquids production for equity-accounted entitiesd f

Natural gas production for subsidiariesf
Natural gas production for equity-accounted entitiesf

Total production for subsidiariesf g
Total production for equity-accounted entitiesf g

aIncludes sales between businesses.
bIncludes profit after interest and tax of equity-accounted entities.
cRealizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.
dCrude oil and natural gas liquids.
eHenry Hub First of Month Index.

fNet of royalties.

gExpressed in thousands of barrels of oil equivalent per day (mboe/d). Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.

2008
89,902
37,915

882
385

92.09
97.37
94.74
95.43

57.24
52.14
50.84
52.30

89.82
89.22
91.05
90.20

8.41
6.77
5.19
6.00

100.06
98.86
97.26

2007
69,376
27,729

$ million

2006
71,868
30,953

756
347

1,045
624

$ per barrel

70.36
68.51
70.86
69.98

52.71
44.59
48.14
46.20

69.17
64.18
69.56
67.45

62.45
62.03
61.11
61.91

47.21
36.13
36.03
37.17

61.67
57.25
59.54
59.23

$ per thousand cubic feet

6.40
5.43
3.71
4.53

72.20
71.68
72.39

6.33
5.74
3.70
4.72

$ per barrel

66.02
63.57
65.14

$ per million British thermal units

9.04

6.86

7.24

pence per therm

58.12

29.95

42.19

1,263
1,138

7,277
1,057

thousand barrels per day

1,304
1,110

1,351
1,124

million cubic feet per day

7,222
921

7,412
1,005

thousand barrels of oil equivalent per day

2,517
1,321

2,549
1,269

2,629
1,297

BP Annual Report and Accounts 2008
Performance review

Total revenues are analysed in more detail below.

Sales and other operating revenues
Earnings from equity-accounted entities (after interest and tax), interest and other revenues

2008
86,170
3,732
89,902

2007
65,740
3,636
69,376

$ million

2006
67,950
3,918
71,868

Total revenues for 2008 were $90 billion, compared with $69 billion in
2007 and $72 billion in 2006. The increase in 2008 primarily reflected
higher oil and gas realizations. Gas marketing sales also increased
primarily as a result of higher prices. The decrease in 2007 compared with
2006 primarily reflected lower volumes of subsidiaries and lower gas
marketing sales, partly offset by higher realizations.

Profit before interest and tax for the year ended 31 December

2008 was $37,915 million. This included inventory holding losses of
$393 million and a net charge for non-operating items of $990 million (see
page 56), with the most significant items being net impairment charges
(primarily driven by the current low price environment) and net fair value
losses on embedded derivatives, partly offset by the reversal of certain
provisions. The impairment charge includes a $517 million write-down of
our investment in Rosneft based on its quoted market price at the end of
the year. In addition, fair value accounting effects had an unfavourable
impact of $282 million relative to management’s measure of performance
(see page 56).

Profit before interest and tax for the year ended 31 December

2007 was $27,729 million. This included inventory holding gains of
$127 million and a net credit from non-operating items of $491 million
(see page 56), with the most significant items being net gains from the
sale of assets (primarily from the disposal of our production and gas
infrastructure in the Netherlands, our interests in non-core Permian
assets in the US and our interests in the Entrada field in the Gulf of
Mexico), partly offset by a restructuring charge and a charge in respect of
the reassessment of certain provisions. In addition, fair value accounting
effects had a favourable impact of $48 million relative to management’s
measure of performance (see page 56).

Profit before interest and tax for the year ended 31 December

2006 was $30,953 million. This included inventory holding losses of
$73 million and a net credit from non-operating items of $2,563 million
(see page 56), with the most significant items being net gains from the
sale of assets (primarily from the sales of interests in the Shenzi
discovery in the Gulf of Mexico in the US and interests in the North Sea
partly offset by a loss on the sale of properties in the Gulf of Mexico
Shelf) and net fair value gains on embedded derivatives, partly offset by a
charge for legal provisions. In addition, fair value accounting effects had
an unfavourable impact of $32 million relative to management’s measure
of performance (see page 56).

The primary additional factor contributing to the 37% increase in profit
before interest and tax for the year ended 31 December 2008 compared
with the year ended 31 December 2007 was higher realizations. In
addition, the result reflected a higher contribution from the gas marketing
and trading business but was impacted by higher production taxes and
higher depreciation. The impact of inflation within other costs was
mitigated by rigorous cost control and a focus on simplification
and efficiency.

The primary additional factors reflected in profit before interest
and tax for the year ended 31 December 2007 compared with the year
ended 31 December 2006 were higher overall realizations (liquids
realizations were higher and gas realizations were lower) and a favourable
effect from lagged tax reference prices in TNK-BP; however, these factors
were more than offset by the impact of lower reported volumes, a lower
contribution from the gas marketing and trading business, higher
production taxes in Alaska and higher costs, reflecting the impacts of
sector-specific inflation, increased integrity spend and higher depreciation
charges. Additionally, the result was lower due to the absence of disposal
gains in 2006 in equity-accounted entities.

Reported production for 2008 was 2,517mboe/d for subsidiaries

and 1,321mboe/d for equity-accounted entities, compared with
2,549mboe/d and 1,269mboe/d respectively in 2007. In aggregate, after
adjusting for the effect of lower entitlement in our PSAs, production was
5% higher than 2007. This reflected strong performance from our
existing assets, the continued ramp-up of production following the start
up of major projects in late-2007 and the start-up of a further nine major
projects in 2008.

Reported production for 2007 was 2,549mboe/d for subsidiaries

and 1,269mboe/d for equity-accounted entities, compared with
2,629mboe/d and 1,297mboe/d respectively in 2006. In aggregate, the
decrease primarily reflected the effect of disposals and net entitlement
reductions in our PSAs.

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BP Annual Report and Accounts 2008
Performance review

Refining and Marketing

Total revenuesa
Profit before interest and tax from continuing operationsb

Global Indicator Refining Margin (GIM)c
Northwest Europe
US Gulf Coast
Midwest
US West Coast
Singapore
BP average

Refining availabilityd

Refinery throughputs

2008
320,458
(1,884)

2007
250,897
6,076

6.72
6.78
5.17
7.42
6.30
6.50

4.99
13.48
12.81
15.05
5.29
9.94

88.8

82.9

$ million

2006
232,833
4,919

$ per barrel

3.92
12.00
9.14
14.84
4.22
8.39

%
82.5

2,155

thousand barrels per day
2,198
2,127

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

cThe GIM is the average of regional industry indicator margins that we weight for BP’s crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with

product yields characteristic of the typical level of upgrading complexity. The refining margins are industry-specific rather than BP-specific measures, which we believe are useful to investors in analyzing
trends in the industry and their impact on our results. The margins are calculated by BP based on published crude oil and product prices and take account of fuel utilization and catalyst costs. No account
is taken of BP’s other cash and non-cash costs of refining, such as wages and salaries and plant depreciation. The indicator margin may not be representative of the margins achieved by BP in any period
because of BP’s particular refining configurations and crude and product slate.
dRefining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost
due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime.

Total revenues are explained in more detail below.

Sale of crude oil through spot and term contracts
Marketing, spot and term sales of refined products
Other sales and operating revenues
Earnings from equity-accounted entities (after interest and tax), interest, and other revenues

2008
54,901
248,561
16,577
419
320,458

1,689
5,698

2007
43,004
194,979
12,238
676
250,897

$ million

2006
38,577
177,995
15,814
447
232,833

thousand barrels per day
2,110
1,885
5,801
5,624

Sale of crude oil through spot and term contracts
Marketing, spot and term sales of refined products

Total revenues for 2008 were $320 billion, compared with $251 billion in
2007 and $233 billion in 2006. The increase in 2008 compared with 2007
primarily reflected an increase in marketing, spot and term sales of
refined products, mainly driven by higher prices. Additionally, sales of
crude oil, spot and term contracts increased, as a result of higher prices,
partly offset by lower volumes. The increase in 2007 compared with 2006
was principally due to an increase in marketing, spot and term sales of
refined products. This was due to higher prices and a positive foreign
exchange impact due to a weaker dollar, partially offset by lower volumes.
Additionally, sales of crude oil, spot and term contracts increased,
primarily reflecting higher prices, and other sales decreased due to lower
volumes partially offset by a positive foreign exchange impact.

The loss before interest and tax for the year ended 31 December

2008 was $1,884 million. This included inventory holding losses of
$6,060 million and a net credit for non-operating items of $347 million
(see page 56). The most significant non-operating items were net gains
on disposal (primarily in respect of the gain recognized on the contribution
of the Toledo refinery into a joint venture with Husky Energy Inc.) partly
offset by restructuring charges. In addition, fair value accounting effects
had a favourable impact of $511 million relative to management’s
measure of performance (see page 56).

Profit before interest and tax for the year ended 31 December 2007 was
$6,076 million. This included inventory holding gains of $3,455 million
and a net charge for non-operating items of $952 million (see page 56).
The most significant non-operating items were net disposal gains
(primarily related to the sale of BP’s Coryton refinery in the UK, its
interest in the West Texas pipeline system in the US and its interest in
the Samsung Petrochemical Company in South Korea), net impairment
charges (primarily related to the sale of the majority of our US
Convenience Retail business, a write-down of certain assets at our Hull
site and write-down of our retail assets in Mexico) and a charge related
to the March 2005 Texas City refinery incident. In addition, fair value
accounting effects had an unfavourable impact of $357 million relative to
management’s measure of performance (see page 56).

Profit before interest and tax for the year ended 31 December

2006 was $4,919 million. This included inventory holding losses of
$242 million and a net charge for non-operating items of $387 million
(see page 56). The most significant non-operating items were net
disposal gains (related primarily to the sale of BP’s Czech Republic retail
business, the disposal of BP’s shareholding in Zhenhai Refining and
Chemicals Company, the sale of BP’s shareholding in Eiffage, the
French-based construction company, and pipelines assets) and a charge
related to the March 2005 Texas City refinery incident. In addition, fair

BP Annual Report and Accounts 2008
Performance review

value accounting effects had a favourable impact of $211 million relative
to management’s measure of performance (see page 56).

During 2008, significant performance improvements in both our
Fuels Value Chains and International Businesses mitigated cost inflation
and, to a large extent, the much weaker environment. The main sources
of improvement were from restoring the revenues of our refining
operations; improved supply and trading performance; improved
marketing performance, particularly from the International Businesses,
and reduced costs. The cost reductions have been driven by the
simplification of our business structure through the establishment of
Fuels Value Chains and a reduction in our geographical footprint, as well
as by strong cost management. The most significant environmental factor
was the weaker refining environment, particularly due to lower refining
margins in the US and the adverse impact in the second half of 2008 of
prior-month pricing of domestic pipeline barrels for our US refining
system, but there were also adverse foreign exchange effects.

During 2007, the segment continued to focus on the restoration

of operations at the Texas City refinery and on investments in integrity
management throughout our refining portfolio. We have also focused on
the repair and recommissioning of the Whiting refinery following the
operational issues in March 2007. In many parts of the refining portfolio
and the other market-facing businesses, we delivered high reliability and
improved results compared with 2006. However, for the full year,
compared with 2006, the impact of the outages and recommissioning
costs at the Texas City and Whiting refineries, as well as investments in
integrity management and scheduled turnarounds throughout our refining
portfolio, cost inflation and lower results from supply optimization
decreased our result. These factors more than offset increased margins
in both refining and marketing.

The average refining Global Indicator Margin (GIM) in 2008 was

lower than in 2007.

Refining throughputs in 2008 were 2,155mb/d, 28mb/d higher

than in 2007. Refining availability was 88.8%, six percentage points
higher than in 2007, the increase being driven primarily by improvement
at the Texas City and Whiting refineries. Marketing volumes at 3,711mb/d
were around 2.5% lower than in 2007.

Other businesses and corporate

Total revenuesa
Profit (loss) before interest and tax
from continuing operationsb

2008
5,040

2007
3,972

$ million

2006
3,703

(1,258)

(1,233)

(779)

aIncludes sales between businesses.

bIncludes profit after interest and tax of equity-accounted entities.

Other businesses and corporate comprises the Alternative Energy
business, Shipping, the group’s aluminium asset, Treasury (which includes
all the group’s cash, cash equivalents), and corporate activities worldwide.
The loss before interest and tax for the year ended 31 December

2008 was $1,258 million and included inventory holding losses of
$35 million and a net charge for non-operating items of $633 million
(see page 56).

The loss before interest and tax for the year ended 31 December

2007 was $1,233 million and included inventory holding losses of
$24 million and a net charge for non-operating items of $262 million
(see page 56).

The loss before interest and tax for the year ended 31 December

2006 was $779 million and included inventory holding gains of
$62 million and a net charge for non-operating items of $72 million
(see page 56).

Non-operating items
Non-operating items are charges and credits that BP discloses separately
because it considers such disclosures to be meaningful and relevant to

investors. The main categories of non-operating items in the periods
presented are: impairments; gains or losses on sale of fixed assets and
the sale of businesses; environmental remediation; restructuring,
integration and rationalization costs; and changes in the fair value of
embedded derivatives. These disclosures are provided in order to enable
investors better to understand and evaluate the group’s financial
performance. An analysis of non-operating items is shown on page 56.

Non-GAAP information on fair value accounting effects
BP uses derivative instruments to manage the economic exposure
relating to inventories above normal operating requirements of crude oil,
natural gas and petroleum products as well as certain contracts to supply
physical volumes at future dates. Under IFRS, these inventories and
contracts are recorded at historic cost and on an accruals basis
respectively. The related derivative instruments, however, are required
to be recorded at fair value with gains and losses recognized in income
because hedge accounting is either not permitted or not followed,
principally due to the impracticality of effectiveness testing requirements.
Therefore, measurement differences in relation to recognition of gains
and losses occur. Gains and losses on these inventories and contracts
are not recognized until the commodity is sold in a subsequent
accounting period. Gains and losses on the related derivative commodity
contracts are recognized in the income statement from the time the
derivative commodity contract is entered into on a fair value basis using
forward prices consistent with the contract maturity.

IFRS requires that inventory held for trading be recorded at its
fair value using period end spot prices whereas any related derivative
commodity instruments are required to be recorded at values based on
forward prices consistent with the contract maturity. Depending on
market conditions, these forward prices can be either higher or lower
than spot prices resulting in measurement differences.

BP enters into contracts for pipelines and storage capacity that,
under IFRS, are recorded on an accruals basis. These contracts are risk-
managed using a variety of derivative instruments that are fair valued
under IFRS. This results in measurement differences in relation to
recognition of gains and losses.

The way that BP manages the economic exposures described

above, and measures performance internally, differs from the way these
activities are measured under IFRS. BP calculates this difference by
comparing the IFRS result with management’s internal measure of
performance, under which the inventory and the supply and capacity
contracts in question are valued based on fair value using relevant
forward prices prevailing at the end of the period. We believe that
disclosing management’s estimate of this difference provides useful
information for investors because it enables investors to see the
economic effect of these activities as a whole. The impacts of fair value
accounting effects, relative to management’s internal measure of
performance, are shown in the table below and on the following page.

Reconciliation of non-GAAP information
Exploration and Production

2008

2007

Profit before interest and tax adjusted
for fair value accounting effects
Impact of fair value accounting effects
Profit before interest and tax

38,197
(282)
37,915

27,681
48
27,729

$ million

2006

39,985
(32)
39,953

Refining and Marketing

Profit before interest and tax adjusted
for fair value accounting effects
Impact of fair value accounting effects
Profit before interest and tax

(2,395)
511
(1,884)

6,433
(357)
6,076

4,708
211
4,919

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BP Annual Report and Accounts 2008
Performance review

Non-operating items

Exploration and Production
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other

Refining and Marketing
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other

Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other

Total before taxation for continuing operations
Taxationa
Total after taxation for continuing operations

Fair value accounting effects

Exploration and Production
Unrecognized gains (losses) brought forward from previous period
Unrecognized (gains) losses carried forward
Favourable (unfavourable) impact relative to management’s measure of performance

Refining and Marketing
Unrecognized gains (losses) brought forward from previous period
Unrecognized (gains) losses carried forward
Favourable (unfavourable) impact relative to management’s measure of performance

Taxationa

By region
Exploration and Production

UK
Rest of Europe
US
Rest of World

Refining and Marketing

UK
Rest of Europe
US
Rest of World

aThe amounts shown for taxation are based upon the effective tax rate on group profit.

2008

2007

(1,015)
(12)
(57)
(163)
257
(990)

801
(64)
(447)
57
–
347

(166)
(117)
(254)
(5)
(91)
(633)
(1,276)
480
(796)

857
(12)
(186)
–
(168)
491

(35)
(138)
(118)
–
(661)
(952)

(14)
(35)
(34)
(7)
(172)
(262)
(723)
350
(373)

2008

2007

107
(389)
(282)

429
82
511
229
(83)
146

45
–
(231)
(96)
(282)

186
54
231
40
511

155
(107)
48

72
(429)
(357)
(309)
111
(198)

1
–
(77)
124
48

(52)
(110)
(165)
(30)
(357)

$ million

2006

2,410
(17)
–
603
(433)
2,563

726
(33)
–
–
(1,080)
(387)

29
94
–
5
(200)
(72)
2,104
(867)
1,237

$ million

2006

123
(155)
(32)

283
(72)
211
179
(107)
72

63
–
(59)
(36)
(32)

109
101
13
(12)
211

BP Annual Report and Accounts 2008
Performance review

Environmental expenditure
Operating expenditure
Clean-ups
Capital expenditure
Additions to environmental remediation provision
Additions to decommissioning provision

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 are therefore estimates, based on the definitions and guidelines of
the American Petroleum Institute.

Environmental operating expenditure of $755 million in 2008 was

higher than in 2007 and reflects continuing integrity management activity.
There were no individually significant factors driving the increase.

The increase in environmental operating expenditure in 2007

compared with 2006 is primarily due to increased integrity management
activity and activity associated with the implementation of the Baker
Panel recommendations. 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 2008 includes $234 million
resulting from a reassessment of existing site obligations and $36 million
in respect of provisions for new sites.

Provisions for environmental remediation are made when a clean-
up is probable and the amount of the obligation can be reliably estimated.
Generally, this 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 environment restoration,

remediation and abatement programmes are often inherently difficult to
estimate. They often depend on the extent of contamination, and the
associated impact and timing of the corrective actions required,
technological feasibility and BP’s share of liability. Though the costs of
future programmes could be significant and may be material to the
results of operations in the period in which they are recognized, it is not
expected that such costs will be material to the group’s overall results of
operations or financial position.

2008

2007

755
64
1,104
270
326

662
62
1,033
373
1,163

$ million

2006

596
59
806
423
2,142

In addition, we make provisions on installation of our oil- and gas-
producing assets and related pipelines to meet the cost of eventual
decommissioning. On installation of an oil or natural gas production
facility a provision is established that represents the discounted value of
the expected future cost of decommissioning the asset. Additionally, we
undertake periodic reviews of existing provisions. These reviews take
account of revised cost assumptions, changes in decommissioning
requirements and any technological developments. The level of increase
in the decommissioning provision varies with the number of new
fields coming onstream in a particular year and the outcome of the
periodic reviews.

Provisions for environmental remediation and decommissioning

are usually set up on a discounted basis, as required by IAS 37
‘Provisions, Contingent Liabilities and Contingent Assets’.

Further details of decommissioning and environmental provisions

appear in Financial statements – Note 37 on page 158. See also
Environment on page 43.

Suppliers and contractors
Our processes are designed to enable us to choose suppliers carefully
on merit, avoiding conflicts of interest and inappropriate gifts and
entertainment. We expect suppliers to comply with legal requirements
and we seek to do business with suppliers who act in line with BP’s
commitments to compliance and ethics, as outlined in the code of
conduct. We engage with suppliers in a variety of ways, including
performance review meetings to identify mutually advantageous ways
to improve performance.

Creditor payment policy and practice
Statutory regulations issued under the UK Companies Act 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.

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BP Annual Report and Accounts 2008
Performance review

Liquidity and capital resources

Cash flow
The following table summarizes the group’s cash flows.

Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year

Net cash provided by operating activities for the year ended
31 December 2008 was $38,095 million compared with $24,709 million
for the equivalent period of 2007 reflecting a decrease in working capital
requirements of $11,250 million, an increase in profit before taxation of
$2,672 million and an increase in dividends from jointly controlled entities
and associates of $1,255 million; these were partly offset by an increase
in income taxes paid of $3,752 million.

Net cash provided by operating activities for the year ended
31 December 2007 was $24,709 million, compared with $28,172 million
for the equivalent period for 2006 reflecting an increase in working capital
requirements of $6,282 million, a decrease in profit before taxation from
continuing operations of $3,031 million, a decrease in dividends from
jointly controlled entities and associates of $2,022 million; these were
partially offset by a decrease in income taxes paid of $4,661 million,
a lower net credit for impairment and gains and losses on sale of
businesses and fixed assets of $2,357 million and higher depreciation,
depletion and amortization of $1,451 million.

Net cash used in investing activities was $22,767 million in 2008,

compared with $14,837 million and $9,518 million in 2007 and 2006.
The increase in 2008 reflected a reduction in disposal proceeds of
$3,338 million and an increase in capital expenditure of $5,303 million.
The increase in 2007 reflected a reduction in disposal proceeds of
$1,987 million and an increase in capital expenditure of $2,713 million.

Net cash used in financing activities was $10,509 million in 2008

compared with $9,035 million in 2007 and $19,071 million in 2006. The
increase in 2008 reflects a decrease in short-term debt of $2,809 million
and an increase in dividends paid of $2,434 million; these were partly
offset by a $4,546 million decrease in the net repurchase of shares.
The reduction in 2007 compared with 2006 reflects a reduction in net
repurchases of shares of $8,038 million and an increase in proceeds from
long-term financing of $4,278 million; these were partially offset by a net
decrease in short-term debt of $2,379 million.

The group has had significant levels of capital investment for

many years. Cash flow in respect of capital investment, excluding
acquisitions, was $23.7 billion in 2008, $18.4 billion in 2007 and
$15.7 billion in 2006. Sources of funding are completely fungible, but the
majority of the group’s funding requirements for new investment come
from cash generated by existing operations. The group’s level of net debt,
that is debt less cash and cash equivalents, was $25.0 billion at the end
of 2008, $26.8 billion at the end of 2007 and was $21.1 billion at the end
of 2006.

During the period 2006 to 2008, our total sources of cash

amounted to $104 billion, whilst our total uses of cash amounted to
$112 billion. The net cash usage of $8 billion was financed by an increase
in finance debt of $13 billion over the three-year period, offset by an
increase in our balance of cash and cash equivalents of $5 billion. During
this period, the price of Brent has averaged $78.26 per barrel. The
following table summarizes the three-year sources and uses of cash.

2008
38,095
(22,767)
(10,509)
(184)
4,635
3,562
8,197

2007
24,709
(14,837)
(9,035)
135
972
2,590
3,562

Sources of cash

Net cash provided by operating activities
Divestments

Uses of cash

Capital expenditure
Acquisitions
Net repurchase of shares
Dividends to BP shareholders
Dividends to minority interests

Net use of cash
Financed by

Increase in finance debt
Increase in cash and cash equivalents

$ million

2006
28,172
(9,518)
(19,071)
47
(370)
2,960
2,590

$ billion

91
13
104

58
2
25
26
1
112
(8)

(13)
5
(8)

Acquisitions made for cash were more than offset by divestments. Net
investment during the same period has averaged $16 billion per year.
Dividends to BP shareholders, which grew on average by 16.8% per year
in dollar terms, used $26 billion. Net repurchase of shares was
$25 billion, which includes $26 billion in respect of our share buyback
programme less net proceeds from shares issued in connection with
employee share schemes. Finally, cash was used to strengthen the
financial condition of certain of our pension plans. In the past three years,
$2 billion has been contributed to funded pension plans. This is reflected
in net cash provided by operating activities in the table above.

Trend information
We expect the short-term outlook for oil prices to be impacted by OPEC
cuts on the one hand, and the outlook for the world economy and oil
demand on the other. We expect continued volatility and our current
expectation is that oil prices, relative to 2008, will continue to be low in
2009, and that this could extend into 2010.

In Exploration and Production, total production is expected to be

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

In Refining and Marketing, 2009 is expected to be a challenging

environment with reduced demand for our products, leading to lower
volumes and pressure on margins. The impact is expected to be greatest
in the petrochemicals sector. In 2009, with our US refining system fully
operational, we expect our overall refining availability to be higher than in
2008.

BP Annual Report and Accounts 2008
Performance review

During 2008, we established momentum in cost control, mitigating the
cost inflation that was primarily driven by rising oil prices. In 2009, our
highest priority will continue to be achieving safe, compliant and reliable
operations and we intend to continue our focus on cost efficiency. We
expect cost deflation to be increasingly visible as we move through 2009.

We expect capital expenditure, excluding acquisitions and asset

Financing the group’s activities
The group’s principal commodity, oil, is priced internationally in US
dollars. Group policy has been to minimize economic exposure to
currency movements by financing operations with US dollar debt
wherever possible, otherwise by using currency swaps when funds
have been raised in currencies other than US dollars.

exchanges, to be around $20-21 billion in 2009. This reflects our
intention in Exploration and Production to maintain investment whilst
vigorously working to drive down costs and to reduce spending in our
Refining and Marketing and Alternative Energy businesses in keeping
with the current weak economic environment. We expect disposal
proceeds to be between $2-3 billion in 2009.

On the basis of our current plans, we expect cash inflows and
outflows in 2009 would balance at oil prices of around $60/bbl, taking
account of expected disposal proceeds. We would expect that break
even point to lower as we realize the benefits of our operational
momentum and our action on costs.

Dividends and other distributions to shareholders
The total dividend paid to BP shareholders in 2008 was $10,342 million,
compared with $8,106 million for 2007. The dividend paid per share was
55.05 cents, an increase of 30% compared with 2007. In sterling terms,
the dividend increased 40% due to the strengthening of the dollar
relative to sterling. We determine the dividend in US dollars, the
economic currency of BP.

During 2008, the company repurchased 269.8 million of its own
shares for cancellation at a cost of $2.9 billion. The repurchased shares
had a nominal value of $67.5 million and represented 1.4% of ordinary
shares in issue, net of treasury shares, at the end of 2007. Since the
inception of the share repurchase programme in 2000, we have
repurchased 4,929 million shares at a cost of $51.1 billion.

Our aim is to strike the right balance for shareholders, between

current returns via the dividend, sustained investment for long-term
growth, and maintaining a prudent gearing level. At the beginning of
2008, we rebalanced our distributions away from share buybacks in
favour of dividends.

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 shareholders also includes a dividend
reinvestment feature.

The discussion above and following contains forward-looking
statements with regard to oil prices, production, demand for refining
products, refining volumes and margins and impact on the
petrochemicals sector, refining availability, continuing priority of safe,
compliant and reliable operations, and focus on cost efficiency, cost
deflation, capital expenditure, expected disposal proceeds, cash flows,
shareholder distributions, gearing, working capital, guarantees, expected
payments under contractual and commercial commitments and
purchase obligations. These forward-looking statements are based on
assumptions that management believes to be reasonable in the light of
the group’s operational and financial experience. However, no assurance
can be given that the forward-looking statements will be realized. You
are urged to read the cautionary statement under Forward-looking
statements on page 14 and Risk factors on pages 12-14, which describe
the risks and uncertainties that may cause actual results and
developments to differ materially from those expressed or implied by
these forward-looking statements. The company provides no
commitment to update the forward-looking statements or to publish
financial projections for forward-looking statements in the future.

The group’s finance debt is almost entirely in US dollars and at

31 December 2008 amounted to $33,204 million (2007 $31,045 million)
of which $15,740 million (2007 $15,394 million) was short term.

Net debt was $25,041 million at the end of 2008, a decrease of

$1,776 million compared with 2007. We believe that a net debt ratio,
that is net debt to net debt plus equity, of 20-30% provides an efficient
capital structure and the appropriate level of financial flexibility. The net
debt ratio was 21% at the end of 2008 and 22% at the end of 2007,
close to the lower end of our target band. Net debt, which BP uses as a
measure of financial gearing, includes the fair value of associated
derivative financial instruments that are used to hedge foreign exchange
and interest rate risks relating to finance debt, for which hedge
accounting is claimed.

The maturity profile and fixed/floating rate characteristics of the
group’s debt are described in Financial statements – Note 28 on page
142 and Note 35 on page 155.

We have in place a European Debt Issuance Programme (DIP)

under which the group may raise $20 billion of debt for maturities of
one month or longer. At 31 December 2008, the amount drawn down
against the DIP was $10,334 million (2007 $10,438 million).

In addition, the group has in place a US Shelf Registration under

which it may raise $10 billion of debt with maturities of one month or
longer. At 31 December 2008, the amount raised under the US Shelf
Registration was $6,500 million (2007 $2,500 million).

Commercial paper markets in the US and Europe are a primary

source of liquidity for the group. At 31 December 2008, the outstanding
commercial paper amounted to $4,268 million (2007 $5,881 million).
The group also has access to significant sources of liquidity in
the form of committed facilities and other funding through the capital
markets. At 31 December 2008, the group had available undrawn
committed borrowing facilities of $4,950 million (2007 $4,950 million).
Despite current uncertainty in the financial markets, including a

lack of liquidity for some borrowers, we have been able to issue
$5 billion of long-term debt in the fourth quarter of 2008. In addition, we
have been able to issue short-term commercial paper at competitive
rates. In the context of unforeseen market volatility, we have however,
increased the cash and cash equivalents held by the group to $8.2 billion
at the end of 2008, compared with $3.6 billion at the end of 2007.

BP believes that, taking into account the substantial amounts of
undrawn borrowing facilities available, the group has sufficient working
capital for foreseeable requirements.

Off-balance sheet arrangements
At 31 December 2008, the group’s share of third-party finance debt
of equity-accounted entities was $6,675 million (2007 $6,764 million).
These amounts are not reflected in the group’s debt on the
balance sheet.

The group has issued third-party guarantees under which

amounts outstanding at 31 December 2008 are summarized on the
following page. Some guarantees outstanding are in respect of
borrowings of jointly controlled entities and associates noted above. The
analysis by time period indicates the ultimate expiry of the guarantees.

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BP Annual Report and Accounts 2008
Performance review

Guarantees issued in respect ofa

Liabilities and borrowings of jointly controlled entities

and associates

Liabilities and borrowings of other third parties

Total

2009

2010

2011

2012

2013

2014 and
thereafter

$ million

Guarantees expiring by period

223
613

70
94

32
19

25
30

6
35

6
34

84
401

aOf the amounts shown in the table, $215 million of the jointly controlled entities and associates guarantees relate to guarantees of borrowings and for other third party guarantees, $582 million relates to
guarantees of borrowings.

Contractual commitments
The following table summarizes the group’s principal contractual obligations at 31 December 2008. Further information on borrowings and finance
leases is given in Financial statements – Note 35 on page 155 and more information on operating leases is given in Financial statements – Note 16
on page 132.

Expected payments by period under contractual
obligations and commercial commitments
Borrowingsa
Finance lease future minimum lease payments
Operating leasesb
Decommissioning liabilities
Environmental liabilities
Pensions and other post-retirement benefitsc
Purchase obligationsd
Total

$ million

Payments due by period

Total
35,192
916
18,795
12,347
1,797
26,288
115,642
210,977

2009
16,554
116
4,135
348
422
1,105
64,479
87,159

2010
5,817
117
3,215
361
380
1,352
13,317
24,559

2011
3,303
116
2,340
211
204
1,346
6,559
14,079

2012
2,577
70
1,897
157
177
1,346
5,100
11,324

2013
5,014
58
1,688
197
129
1,342
4,531
12,959

2014 and
thereafter
1,927
439
5,520
11,073
485
19,797
21,656
60,897

aExpected payments include interest payments on borrowings totalling $2,607 million ($907 million in 2009, $608 million in 2010, $421 million in 2011, $318 million in 2012, $236 million in 2013 and
$117 million thereafter).
bThe future minimum lease payments are before deducting related rental income from operating sub-leases. Where an operating lease is entered into solely by the group as the operator of a jointly
controlled asset, the total cost is included irrespective of any amounts that will be reimbursed by joint venture partners. Where operating lease costs are incurred in relation to the hire of equipment used
in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project.
cRepresents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post- retirement benefits.
dRepresents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The amounts shown include arrangements to secure long-term
access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2009 include purchase commitments existing at 31 December 2008 entered into
principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements
– Note 28 on page 142.

The following table summarizes the nature of the group’s unconditional purchase obligations.

Purchase obligations
Crude oil and oil products
Natural gas
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total

Total
42,261
43,242
12,223
6,156
690
3,820
7,250
115,642

2009
31,308
22,949
3,010
4,910
111
759
1,432
64,479

2010
2,972
5,982
1,724
1,168
101
464
906
13,317

2011
970
2,844
1,295
60
86
416
888
6,559

2012
1,203
1,837
837
16
83
341
783
5,100

$ million

Payments due by period

2013
953
1,619
847
2
57
314
739
4,531

2014 and
thereafter
4,855
8,011
4,510
–
252
1,526
2,502
21,656

The group expects its total capital expenditure, excluding acquisitions and asset exchanges to be around $20-21 billion in 2009. The following table
summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2008 and the proportion of that
expenditure for which contracts have been placed. Capital expenditure is considered to be committed when the project has received the appropriate
level of internal management approval. For jointly controlled assets, the net BP share is included in the amounts shown. Where operating lease costs
are incurred in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. Such costs are
included in the amounts shown.

Capital expenditure commitments
Committed on major projects
Amounts for which contracts have been placed

Total
35,845
14,062

2009
14,936
8,175

2010
8,154
2,908

2011
5,175
1,197

2012
3,136
621

2013
1,580
402

$ million

2014 and
thereafter
2,864
759

In addition, at 31 December 2008, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to
$1.2 billion. Contracts were in place for $0.8 billion of this total.

BP Annual Report and Accounts 2008
Performance review

Critical accounting policies
The significant accounting policies of the group are summarized in
Financial statements – Note 1 on page 108.

Inherent in the application of many of the accounting policies

used in preparing 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 financial
statements 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 more
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 financial statements.

The accounting policies and areas that require the most significant

judgements and estimates used in the preparation of the consolidated
financial statements are in relation to oil and natural gas accounting,
including the estimation of reserves, the recoverability of asset carrying
values, taxation, derivative financial instruments, provisions and
contingencies, and pensions and other post-retirement benefits.

Oil and natural gas accounting
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.

Exploration licence and leasehold property acquisition costs are
capitalized within intangible assets and are reviewed at each reporting
date to confirm that there is no indication that the carrying amount
exceeds the recoverable amount. This review includes confirming that
exploration drilling is still under way or firmly planned or that it has been
determined, or work is under way to determine, that the discovery is
economically viable based on a range of technical and commercial
considerations and sufficient progress is being made on establishing
development plans and timing. If no future activity is planned, the
remaining balance of the licence and property acquisition costs is written
off. Lower value licences are pooled and amortized on a straight-line
basis over the estimated period of exploration.

For exploration wells and exploratory-type stratigraphic test wells,

costs directly associated with the drilling of wells are initially capitalized
within intangible 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. The
determination is usually made within one year after well completion, but
can take longer, depending on the complexity of the geological 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 on 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.

It is not unusual to have exploration wells and exploratory-type
stratigraphic test 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.

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. Where
this is no longer the case, the costs are immediately expensed.

Once a project is sanctioned for development, the carrying values
of exploration licence and leasehold property acquisition costs and costs
associated with exploration wells and exploratory-type stratigraphic
test wells, are transferred to production assets within property, plant
and equipment.

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.
Field development costs subject to depreciation are expenditures
incurred to date, together with approved future development expenditure
required to develop 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:
• Producing wells – proved developed reserves.
• Licence and property acquisition, field development and future

decommissioning costs – total proved reserves.

The impact of changes in estimated proved reserves is dealt with
prospectively by amortizing the remaining carrying value of the asset over
the expected future production. If proved reserves estimates are revised
downwards, earnings could be affected by higher depreciation expense
or an immediate write-down of the property’s carrying value (see
discussion of recoverability of asset carrying values on the following
page).

At the end of 2006, BP adopted the SEC rules for estimating

reserves instead of the UK accounting rules contained in the UK
Statement of Recommended Practice. These changes are explained in
Financial statements – Note 10 on page 127.

The estimation of oil and natural gas reserves and BP’s process

to manage reserves bookings is described in Exploration and Production
– Reserves and production on page 18. As discussed on the following
page, oil and natural gas reserves have a direct impact on the
assessment of the recoverability of asset carrying values reported in the
financial statements.

The 2008 movements in proved reserves are reflected in the

tables showing movements in oil and gas reserves by region in Financial
statements – Supplementary information on oil and natural gas on pages
182 to 190.

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Taxation
The computation of the group’s income tax expense involves the
interpretation of applicable tax laws and regulations in many jurisdictions
throughout the world. The resolution of tax positions taken by the group,
through negotiations with relevant tax authorities or through litigation,
can take several years to complete and in some cases it is difficult to
predict the ultimate outcome.

In addition, the group has carry-forward tax losses in certain
taxing jurisdictions that are available to offset against future taxable
profit. However, deferred tax assets are recognized only to the extent
that it is probable that taxable profit will be available against which the
unused tax losses can be utilized. Management judgement is exercised
in assessing whether this is the case.

To the extent that actual outcomes differ from management’s
estimates, taxation charges or credits may arise in future periods. For
more information see Financial statements – Note 20 on page 135 and
Note 44 on page 174.

Derivative financial instruments
The group uses derivative financial instruments to manage certain
exposures to fluctuations in foreign currency exchange rates, interest
rates and commodity prices as well as for trading purposes. In addition,
derivatives embedded within other financial instruments or other host
contracts are treated as separate derivatives when their risks and
characteristics are not closely related to those of the host contract. All
such derivatives are initially recognized at fair value on the date on which
a derivative contract is entered into and are subsequently remeasured at
fair value. Gains and losses arising from changes in the fair value of
derivatives that are not designated as effective hedging instruments are
recognized in the income statement.

In some cases the fair values of derivatives are estimated using

models and other valuation methods due to the absence of quoted prices
or other observable, market-corroborated data. In particular, this applies
to the majority of the group’s natural gas and LNG embedded derivatives.
These are primarily long-term UK gas contracts that use pricing formulae
not related to gas prices, for example, oil product and power prices.
These contracts are valued using models with inputs that include price
curves for each of the different products that are built up from active
market pricing data and extrapolated to the expiry of the contracts using
the maximum available external pricing information. Additionally, where
limited data exists for certain products, prices are interpolated using
historic and long-term pricing relationships. Price volatility is also an input
for the models. Changes in the key assumptions could have a material
impact on the gains and losses on embedded derivatives recognized in
the income statement. For more information see Financial statements –
Note 34 on page 150. An analysis of the sensitivity of the fair value of the
natural gas and LNG derivatives to changes in the key assumptions is
provided in Financial statements – Note 28 on page 142.

BP Annual Report and Accounts 2008
Performance review

Recoverability of asset carrying values
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 and, as a result, charges for
impairment are recognized in the group’s results from time to time. Such
indicators include changes in the group’s business plans, changes in
commodity prices leading to unprofitable performance, low plant
utilization, evidence of physical damage and, for oil and gas properties,
significant downward revisions of estimated volumes or increases in
estimated future development expenditure. If there are low oil prices,
natural gas prices, refining margins or marketing margins during
an extended period, the group may need to recognize significant
impairment charges.

The assessment for impairment entails comparing the carrying
value of the cash-generating unit with its recoverable amount, that is,
the higher of fair value less costs to sell 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 on operating expenses,
discount rates, production profiles and the outlook for global or regional
market supply-and-demand conditions for crude oil, natural gas 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 develop and
produce proved reserves and associated risk-adjusted probable and
possible volumes. Expected future cash flows from the sale or
production of these volumes are calculated based on the management’s
best estimate of future oil and gas prices. Prices for oil and natural gas
used for future cash flow calculations are based on market prices for the
first five years and the group’s long-term planning assumptions
thereafter. As at 31 December 2008, the group’s long-term planning
assumptions were $75 per barrel for Brent and $7.50/mmBtu for Henry
Hub (2007 $60 per barrel and $7.50/mmBtu). 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.

The future cash flows are adjusted for risks specific to the cash-

generating unit and are discounted using a pre-tax discount rate. The
discount rate is derived from the group’s post-tax weighted average cost
of capital and is adjusted where applicable to take into account any
specific risks relating to the country where the cash-generating unit is
located. Typically rates of 11% or 13% are used (2007 11% or 13%).
The rate applied in each country is re-assessed each year by analyzing
relevant information.

Irrespective of whether there is any indication of impairment,

BP is required to test annually for impairment of goodwill acquired in a
business combination. The group carries goodwill of approximately
$9.9 billion on its balance sheet, principally relating to the Atlantic
Richfield and Burmah Castrol acquisitions. In testing goodwill for
impairment, the group uses a similar approach to that described above.
If there are low oil prices or natural gas prices or refining margins or
marketing margins for an extended period, the group may need to
recognize significant goodwill impairment charges.

BP Annual Report and Accounts 2008
Performance review

Provisions and contingencies
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. A corresponding asset of an
amount equivalent to the provision is also created within property, plant
and equipment. This asset is depreciated over the expected life of the
production facility or pipeline. 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.
Changes in the expected future costs are reflected in both the provision
and the asset.

Decommissioning provisions associated with downstream and

petrochemicals facilities are generally not provided for, as such potential
obligations cannot be measured, given their indeterminate settlement
dates. The group performs periodic reviews of its downstream
and petrochemicals long-lived assets for any changes in facts
and circumstances that might require the recognition of a
decommissioning provision.

The timing and amount of future expenditures are reviewed

annually, together with the interest rate used in discounting the cash
flows. The interest rate used to determine the balance sheet obligation at
the end of 2008 was 2%, unchanged from the end of 2007. The interest
rate represents the real rate (i.e. adjusted for inflation) on long-dated
government bonds.

Other provisions and liabilities are recognized in the period when
it becomes probable that there will be a future outflow of funds resulting
from past operations or events and the amount of cash outflow can be
reliably estimated. The timing of recognition requires the application of
judgement to existing facts and circumstances, which can be subject to
change. Since the actual cash outflows can take place many years in the
future, the carrying amounts of provisions and liabilities are reviewed
regularly and adjusted to take account of changing facts and
circumstances.

A change in estimate of a recognized provision or liability would

result in a charge or credit to net income in the period in which the
change occurs (with the exception of decommissioning costs as
described above).

Provisions for environmental clean-up and remediation costs are
based on current legal and constructive requirements, technology, price
levels and expected plans for remediation. Actual costs and cash
outflows can differ from estimates because of changes in laws and
regulations, public expectations, prices, 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 2008 was 2%, the same rate as at the previous balance
sheet date.

As further described in Financial statements – Note 44 on

page 174, the group is subject to claims and actions. The facts and
circumstances relating to particular cases are evaluated regularly in
determining whether it is ‘probable’ that there will be a future outflow of
funds and, once established, whether a provision relating to a specific
litigation should be adjusted. Accordingly, significant management
judgement relating to contingent liabilities is required, since the outcome
of litigation is difficult to predict.

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

reviewed by management at the end of each year. These assumptions
are used to determine the projected benefit obligation at the year-end
and hence the surpluses and deficits recorded on the group’s balance
sheet, and pension and other post-retirement benefit expense for the
following year.

The pension and other post-retirement benefit assumptions at

31 December 2008, 2007 and 2006 are provided in Financial statements
– Note 38 on page 159.

The assumed rate of investment return, discount rate and the

US healthcare cost trend rate have a significant effect on the amounts
reported. A sensitivity analysis of the impact of changes in these
assumptions on the benefit expense and obligation is provided in
Financial statements – Note 38 on page 159.

In addition to the financial assumptions, we regularly review the
demographic and mortality assumptions. Mortality assumptions reflect
best practice in the countries in which we provide pensions and have
been chosen with regard to the latest available published tables adjusted
where appropriate to reflect the experience of the group and an
extrapolation of past longevity improvements into the future. BP’s most
substantial pension liabilities are in the UK, US and Germany and the
mortality assumptions for these countries are detailed in Financial
statements – Note 38 on page 159.

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Board performance
and biographies

66 Directors and

senior management

69 BP board performance report

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BP Annual Report and Accounts 2008
Directors and senior management

Directors and senior management

The following lists the company’s directors and senior management as at 18 February 2009.

Name
P D Sutherland

Chairman

Sir Ian Prosser

Non-Executive Deputy Chairman

A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Dr A B Hayward

Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Executive Director (Group Chief Executive)

I C Conn
Dr B E Grote
A G Inglis
R Bondy
S Bott
V Cox
H L McKay
J Mogford

S Westwell

Executive Director (Chief Executive, Refining and Marketing)
Executive Director (Chief Financial Officer)
Executive Director (Chief Executive, Exploration and Production)
Group General Counsel
Executive Vice President, Human Resources
Executive Vice President, Alternative Energy
Executive Vice President (Chairman and President of BP America Inc.)
Executive Vice President (Chief Operating Officer, Refining
and US Fuels Value Chains)
Executive Vice President (Group Chief of Staff)

Initially elected or appointed
Chairman since May 1997
Director since July 1995
Deputy chairman since February 1999
Director since May 1997
February 2004
June 2007
July 2006
February 2008
December 1998
January 2005
November 2001
July 2004
Group Chief Executive since May 2007
Director since February 2003
July 2004
August 2000
February 2007
May 2008
March 2005
July 2004
June 2008
October 2007

January 2008

Mr H L McKay, previously executive vice president (special projects), was appointed chairman and president of BP America Inc. on the retirement
of Mr R A Malone on 1 February 2009.

Dr D C Allen retired as a director on 31 March 2008 and Dr W E Massey retired as a director on 17 April 2008. Mr G David was appointed a non-
executive director on 11 February 2008. At the company’s 2008 annual general meeting (AGM), the following directors retired, offered themselves
for election/re-election and were duly elected/re-elected: Mr A Burgmans; Mrs C B Carroll; Sir William Castell; Mr I C Conn; Mr G David,
Mr E B Davis, Jr; Mr D J Flint; Dr B E Grote; Dr A B Hayward; Mr A G Inglis; Dr D S Julius; Sir Tom McKillop; Sir Ian Prosser and Mr P D Sutherland.

Mr R Dudley has been appointed to the board with effect from 6 April 2009. All of the directors, including Mr Dudley, will offer themselves for election/
re-election at the company’s 2009 AGM.

David Jackson (56) was appointed company secretary in 2003. A solicitor, he is a director of BP Pension Trustees Limited and a member of the Listing
Authorities Advisory Committee.

BP Annual Report and Accounts 2008
Directors and senior management

Directors
P D Sutherland, SC, KCMG
Chairman of the chairman’s and the nomination committees and attends
meetings of the remuneration committee
Peter Sutherland (62) 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
was a non-executive director of The Royal Bank of Scotland Group PLC
from 2001 to 6 February 2009.

Sir Ian Prosser
Member of the chairman’s, the nomination and the remuneration
committees and chairman of the audit committee
Sir Ian (65) joined BP’s board in 1997 and was appointed non-executive
deputy chairman in 1999. He is the senior independent director. In 2003,
he retired as chairman of InterContinental Hotels Group PLC, a spin-off
from the former Bass PLC where he was chief executive.
He is a non-executive director and senior independent director of
GlaxoSmithKline plc, a non-executive director of the Sara Lee Corporation
and non-executive chairman of The Navy, Army and Air Force Institutes
(NAAFI). He was previously on the boards of The Boots Company PLC
and Lloyds TSB PLC.

A Burgmans, KBE
Member of the chairman’s and the safety, ethics and environment
assurance committees
Antony Burgmans (62) 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. In 2005, he became non-executive
chairman of Unilever PLC and Unilever NV, retiring from these
appointments in May 2007. He is also a member of the supervisory
boards of Akzo Nobel NV and Aegon NV.

C B Carroll
Member of the chairman’s and safety, ethics and environment assurance
committees
Cynthia Carroll (52) joined BP’s board in June 2007. She started her
career at Amoco and in 1989 she joined Alcan, where in 2002 she was
appointed president and chief executive officer of Alcan’s primary metals
group and an officer of Alcan, Inc. She was appointed as chief executive
of Anglo American plc, the global mining group, in March 2007. She is
also a director of De Beers s.a. and Anglo Platinum Ltd.

Sir William Castell, LVO
Member of the chairman’s committee and chairman of the safety, ethics
and environment assurance committee
Sir William (61) joined BP’s board in 2006. From 1990 to 2004, he was
chief executive of Amersham plc and subsequently president and chief
executive officer of GE Healthcare. He was appointed as a vice chairman
of the board of GE in 2004, stepping down from this post in 2006 when
he became chairman of the Wellcome Trust. He remains a non-executive
director of GE.

G David
Member of the chairman’s and the audit committees
George David (66) joined BP’s board on 11 February 2008. He has spent
his career with United Technologies Corporation (UTC), as its chief
executive officer from 1994 to 2008 and chairman since 1997. He joined
UTC’s Otis elevator subsidiary in 1975.

E B Davis, Jr
Member of the chairman’s, the audit and the remuneration committees
Erroll B Davis, Jr (64) joined BP’s board in 1998, having previously been a
director of Amoco. He was chairman and chief executive officer of Alliant
Energy, relinquishing this dual appointment in 2005. He continued as
chairman of Alliant Energy until February 2006, leaving to become
chancellor of the University System of Georgia. He is a member of the
board of General Motors Corporation and Union Pacific Corporation.

D J Flint, CBE
Member of the chairman’s and the audit committees
Douglas Flint (53) joined BP’s board in 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 was 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 Standards Advisory Council of the International
Accounting Standards Board.

Dr D S Julius, CBE
Member of the chairman’s and the nomination committees and chairman
of the remuneration committee
DeAnne Julius (59) 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 Roche Holdings SA and Jones Lang LaSalle, Inc.

Sir Tom McKillop
Member of the chairman’s, the remuneration and the safety, ethics and
environment assurance committees
Sir Tom (65) joined BP’s board in 2004. Sir Tom was chief executive of
AstraZeneca PLC from the merger of Astra AB and Zeneca Group PLC in
1999 until December 2005. He was a non-executive director of Lloyds
TSB Group PLC until 2004 and was appointed to the board of The Royal
Bank of Scotland Group PLC in 2005, where he was chairman from 2006
to 3 February 2009.

Dr A B Hayward
Tony Hayward (51) joined BP in 1982. He held a series of roles in
exploration and production, becoming a director of exploration and
production in 1997. In 2000, he was made group treasurer, and an
executive vice president in 2002. He was chief executive officer of
exploration and production between 2002 and February 2007. He
became an executive director of BP in 2003 and was appointed as group
chief executive in May 2007. Dr Hayward is a non-executive director and
senior independent director of Tata Steel.

I C Conn
Iain Conn (46) joined BP in 1986. Following a variety of roles in oil trading,
commercial refining, retail and commercial marketing operations, and
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 2004. He was appointed chief executive of refining and
marketing in June 2007. He is a non-executive director and senior
independent director of Rolls-Royce Group plc.

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H L McKay
Lamar McKay (50) was appointed chairman and president of BP America,
Inc. from 1 February 2009. He joined Amoco Production Company as a
petroleum engineer in 1980 and later served in a variety of operating,
commercial and M&A roles. In 1993, he became general manager of
Arkoma Basin and in 1997, the business unit leader for the Gulf of
Mexico Shelf. During 1998-2000, he worked on the BP-Amoco merger
and served as general manager for BP p.l.c. worldwide exploration and
production strategy and planning. In 2000, he became business unit
leader for the Central North Sea in Aberdeen, and subsequently chief of
staff for worldwide exploration and production in London, following which
he served as chief of staff for the BP deputy group chief executive.
Lamar then worked as group vice president for Russia & Kazakhstan,
during which time he was appointed to the board of TNK-BP. He was
named executive vice-president of BP America and COO in the USA in
May 2007. In early 2008, he became executive vice president of BP p.l.c.
special projects, focusing on Russia, subsequently joining the group
executive management team in June 2008.

J Mogford
John Mogford (55) joined BP in 1977, spending the early part of his
career in a variety of drilling and production roles. In 1999, he became
group vice president for health, safety and the environment before being
appointed as group vice president for gas, power and renewables in
2002. In 2004, he returned to exploration and production as group vice
president (technology and functions). In 2005, he was appointed as
senior group vice president of safety and operations before becoming
executive vice president, safety and operations in October 2007.
He became chief operating officer of refining from 1 March 2008.
On 15 January 2009, he moved to chief operating officer for US fuels
value chains and head of refining.

S Westwell
Steve Westwell (50) joined BP in the manufacturing and supply division of
BP Southern Africa in 1988. Following various retail positions in the UK
and the US he was appointed head of retail and a member of the board
of BP Southern Africa Pty. In 2003, he became president and chief
executive officer of BP solar, and in 2004, group vice president of natural
gas liquids, power, solar and renewables. In 2005, he was appointed
group vice president of alternative energy. He was appointed group chief
of staff on 1 January 2008.

BP Annual Report and Accounts 2008
Directors and senior management

Dr B E Grote
Byron Grote (60) 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. He is a non-executive director of Unilever NV and
Unilever PLC.

A G Inglis
Andy Inglis (49) joined BP in 1980, working on various North Sea
projects. Following a series of commercial roles in exploration, in 1996 he
became chief of staff, exploration and production. From 1997 until 1999,
he was responsible for leading BP’s activities in the deepwater Gulf of
Mexico. In 1999, he was appointed vice president of BP’s US western
gas business unit. In 2004, he became executive vice president and
deputy chief executive of exploration and production. He was appointed
chief executive of BP’s exploration and production business and an
executive director in February 2007. He is a non-executive director of
BAE Systems plc.

Senior management
R Bondy
Rupert Bondy (47) joined BP as group general counsel in May 2008.
In 1989 he joined US law firm Morrison & Foerster, working in San
Francisco and London. From 1994 to 1995, he worked for UK law firm
Lovells in London. In 1995, he joined SmithKline Beecham as senior
counsel for mergers and acquisitions and other corporate matters. He
subsequently held positions of increasing responsibility and following the
merger of SmithKline Beecham and GlaxoWellcome he was appointed
senior vice president and general counsel of GlaxoSmithKline in 2001.

S Bott
Sally Bott (59) joined BP in 2005 as an executive vice president
responsible for global human resources. Sally joined Citibank in 1970 and,
following a variety of roles, was appointed a vice president in human
resources in 1979 and subsequently held a series of positions as a
human resources director to sectors of Citibank. In 1994, she joined
Barclays De Zoete Wedd, an investment bank, as head of human
resources and in 1997 became group human resources director of
Barclays plc. From 2000 to early 2005, she was managing director of
Marsh and McLennan and head of global human resources at Marsh Inc.
In 2008, Sally was elected as a non-executive director of UBS AG.

V Cox
Vivienne Cox (49) joined BP in 1981. Following a series of commercial
roles, she was appointed chief executive of Air BP in 1998. From 1999
until 2001, she was group vice president of BP Oil, responsible for
business-to-business marketing and oil supply and trading. From 2001 to
2004, she was group vice president for integrated supply and trading. In
2004, she was appointed an executive vice president, responsible for
gas, power and renewables in addition to the supply and trading
businesses. In late 2005, she became responsible for Alternative Energy.
She is a non-executive director of Rio Tinto plc and Climate Change
Capital Limited.

BP Annual Report and Accounts 2008
BP board performance report

BP board performance report

year depending on the exigencies of the business as they arise. During
the year the board was involved in the following activities:

Letter from the chairman
I am once again pleased to introduce our board performance report. The
report reviews the work of the board and its committees as my tenure as
chairman moves to a close. Over the past 12 years, both the calibre of
individuals who have served on the board and our system of governance
has stood us in good stead. The strong set of principles on which we
base our governance framework, which include clarity of roles, separation
of powers, independence and appropriate skills, remain valid today.

I have been encouraged from discussions with shareholders over

time that our approach to governance and the dialogue which we
continue to have with them is welcomed. This is important to us and no
more so than during the testing times in which we operate.

Recent events and the current economic climate have inevitably

triggered further debate about governance. This I welcome. The
framework of governance does need to be kept under review and, where
necessary, challenged by investors, regulators and companies
themselves to ensure that the system is delivering.

Under such a review I believe that BP’s governance approach can

show its strength. It requires active engagement on behalf of the
company and investors alike. I do not believe that our comply or explain
system is broken and it is important for us that the principles-based
system continues.

Peter Sutherland
Chairman
24 February 2009

Board governance principles
The board governance principles (‘principles’) are designed to enable the
board and the executive management to operate within a clear
framework. The principles describe the role of the board, its processes,
its relationship with executive management and the main tasks and
requirements of the board committees. The principles are available at
www.bp.com/corporategovernance.

In carrying out its work, the board focuses on key tasks, which

include the active review of the long-term strategy and the annual plan,
monitoring the decisions and actions of the group chief executive, the
performance of BP, the succession of executive management and the
oversight of risk.

The principles outline how the board delegates its authority for
executive management of the company to the group chief executive,
subject to monitoring by the board and a clearly defined set of limitations.
These ‘executive limitations’ require that any executive action taken in the
course of business takes specific issues into consideration, including
health, safety and the environment, any reputational impact on BP, risk
and the framework for internal control.

Operating the principles
The group chief executive through the annual plan describes to the board
how the strategy is to be delivered, together with an assessment of the
group’s risks. During the year, the board monitors progress and keeps the
strategy under review.

The group chief executive is obliged to review and discuss with

the board all strategic projects or developments and all material matters
currently or prospectively affecting the company and its performance.

The principles are kept under review by the board to ensure they

remain relevant and up to date.

Board activities in 2008
As outlined above, the board focuses on key areas in carrying out
its work. Forward agendas are set to determine a high level work
programme for the board based on its core tasks (including dealing with
strategy and monitoring) but additional items are added throughout the

Strategy and Risk
The board undertook extensive discussions on strategic options for the
group, including the future business and competitive environment,
technology developments, pricing and demand models and portfolio
options. The identification and management of group risks were reviewed
by the board, together with how these risks and their mitigation were
embedded in the group’s annual plan.

Review of capital expenditure and post investment review
While the audit committee reviewed project delivery performance, the
board undertook an annual review of the group’s project sanctioning
process and delegation of authority. The process and criteria for each
stage of a project was discussed, together with examples of projects
with different lead times and complexities.

Business review
Business reviews were held with both segments (Exploration and
Production and Refining and Marketing) and the finance and information
technology and services (IT&S) functions.

Global economic environment and energy markets
The board actively monitored developments in the global energy
markets and economic environment. Issues considered included
the supply/demand balance, the relationship between oil prices,
energy consumption and GDP growth and turbulence in the
financial markets.

Other areas
Other areas discussed by the board included interactions with BP’s
partners in TNK-BP, the results of a group-wide employee satisfaction
survey and the findings of a report on BP’s reputation in the UK and US.
The board also received a presentation from the independent expert
appointed to provide an objective assessment of BP’s progress in
implementing the recommendations of the BP US Refineries
Independent Safety Review Panel (the Panel).

The board is supported in its tasks by the company secretary,

who reports to the chairman and has no executive functions. His
remuneration is determined by the remuneration committee.

Board meetings and attendance
The board met nine times during 2008, of which one meeting was a
two-day strategy session and another meeting was a one-day strategy
session.

P D Sutherland
Sir Ian Prosser
A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Dr W E Massey
Dr D C Allen
I C Conn
Dr B E Grote
Dr A B Hayward
A G Inglis

Board meetings
eligible to attend
9
9
9
9
9
7
9
9
9
9
4
3
9
9
9
9

Board meetings
attended
9
9
9
9
9
7
8
7
9
9
4
3
9
9
9
9

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BP Annual Report and Accounts 2008
BP board performance report

The chairman and senior independent director
The principles require that neither the chairman nor deputy chairman be
employed as an executive of the group. During 2008, these posts were
held by Peter Sutherland and Sir Ian Prosser respectively.

The chairman provides leadership of the board, acts as facilitator

for meetings and ensures that the governance framework of the board is
maintained and operated. The chairman also leads board performance
appraisals. He represents the views of the board to shareholders on key
issues, in particular those relating to governance and succession planning
and informs the board of shareholder views.

Between board meetings, the chairman has responsibility for
ensuring the integrity and effectiveness of the relationship with executive
management. This requires his interaction with the group chief executive,
as well as his contact with other board members, senior management
and stakeholders.

The deputy chairman acts for the chairman in his absence or at his

request. The deputy chairman also serves as the board’s senior
independent director and is available to shareholders where there are
issues that cannot be addressed through normal channels.

The chairman and all the non-executive directors meet periodically

without the presence of executive management as the chairman’s
committee. The performance of the chairman is evaluated each year, with
the evaluation discussion taking place when the chairman is not present.
The principles require that the board develop and maintain a plan for the
succession of both the chairman and deputy chairman.

Board composition
The principles require that over half the board, excluding the chairman,
comprise independent non-executive directors and that the number of
directors to not normally exceed 16. The board is composed of the
chairman, nine non-executive and four executive directors.

The board considers that it is of an appropriate size to govern BP,

with its directors possessing the relevant backgrounds and mix of
experience, knowledge and skills to maximize its effectiveness.

Board renewal and skills
The board remains actively engaged in orderly succession planning for
both executive and non-executive directors and is assisted in this task by
the nomination committee. The committee keeps under review the
composition, skills and diversity of the board to ensure that it remains
appropriate to the tasks and work it undertakes. The nomination
committee believes a breadth of skills is required for the board to meet
the demands of a business with global operations. These skills include
deep operational, engineering, safety and financial expertise, experience
of leading industrial, capital intensive or ‘long lead time’ businesses and
insight into key emerging markets and technology development.

The board: terms of appointment
The chairman and non-executive directors of BP 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 described in
the directors’ remuneration report.

The service contracts of executive directors are expressed to

expire at a normal retirement age of 60 (subject to age discrimination),
while non-executive directors ordinarily retire at the AGM following their
70th birthday.

In accordance with BP’s Articles of Association, directors are

granted an indemnity from the company in respect of liabilities incurred
as a result of their office, to the extent permitted by law. In respect of
those liabilities for which directors may not be indemnified, the company
maintained a directors’ and officers’ liability insurance policy throughout
2008. During the year, a review of the terms and nature of the policy was
undertaken and has been renewed for 2009. Although their defence
costs may be met, neither the company’s indemnity nor insurance
provides cover in the event that the director is proved to have acted

fraudulently or dishonestly. Following recent changes to company law,
the company is also permitted to advance costs to directors for their
defence in investigations or legal actions.

Director elections
New board directors are subject to election by shareholders at the first
AGM following their appointment. All existing directors stand for
re-election each year – a practice the company has followed since 2004.
All directors proposed to shareholders for election are accompanied by a
biography and a description of the skills and experience that the company
feels are relevant.

Voting levels at the 2008 AGM demonstrated continued support

for all board directors.

Board independence
Non-executive directors are required by the principles to be independent
in character and free from any business or other relationship that could
materially interfere with the exercise of their judgement. The board has
determined that the non-executive directors who served during 2008
fulfilled this requirement and were independent.

BP believes that tenure of board members should be determined

on the basis of contribution and continued evidence of the exercise of
independent judgement. As all directors are proposed for annual
re-election by shareholders, the board considers that arbitrary term limits
on a director’s service are not appropriate.

Sir Ian Prosser joined the board in 1997. It is the view of the board

that he remains firmly independent. His experience and long-term
perspective on BP’s business have provided and continue to provide a
valuable contribution to the board and the audit committee, which he
chairs. As deputy chairman and senior independent director, Sir Ian is
leading the board’s search for the successor to the current chairman. He
has been asked by the board to remain in post until April 2010 in order
that he may conclude both the chairman’s succession process and the
identification and appointment by the new chairman of a senior
independent director.

Mr Davis joined the board on the completion of the Amoco

merger in December 1998. The board believes Mr Davis continues to
demonstrate his independence. He is an active participant at the board
and sits on the audit and remuneration committees, and the high level of
his independence is demonstrated by his engagement in these forums.

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).

From 1 October 2008, there has been a requirement that
directors must avoid a situation where they have, or can have, a direct
or indirect interest that conflicts, or possibly may conflict, with the
company’s interests. Directors of public companies may authorize
conflicts and potential conflicts, where appropriate, if a company’s
articles of association permit and shareholders have approved
appropriate amendments.

Procedures have been put in place for the disclosure by directors

of any such conflicts and also for the consideration and authorization of
these conflicts by the board. These procedures allow for the imposition of
limits or conditions by the board when authorizing any conflict, if they
think this is appropriate. These procedures were duly followed to approve
appropriate conflicts immediately prior to the enactment of the conflict
provisions in October 2008, and are now included as a regular standing
item for consideration by the board at its meetings.

BP Annual Report and Accounts 2008
BP board performance report

Serving as a director
Induction
The induction of new board members is the responsibility of the
chairman, who is assisted by the company secretary in this task. All new
directors receive a full induction programme, including a ‘core’ element
covering the principles and the legal and regulatory duties of directors.
Non-executive directors receive further induction content devised
according to their own interests and needs, together with the
requirements of the committees on which they will serve. This would
include meetings and briefings on the operations and activities of the
group, the strategy and the annual plan and the company’s financial
performance. The induction programme is targeted for completion within
the first nine to 12 months of non-executive directors taking office, while
the executive director programme is arranged in the course of their
business activities.

Training and site visits
Directors and committee members receive briefings on BP’s business,
its markets, operating environment and other key issues during their
tenure as directors to ensure they have the necessary skill and
knowledge to perform their duties effectively. Board members are also
kept updated on legal and regulatory developments that may impact their
duties and obligations as directors of a listed company.

In the past two years, the board and its committees have sought

greater opportunity to meet at BP’s operating sites. This has enabled
board members to see a selection of BP’s businesses e.g. the Texas City
refinery, gas production in Colorado, exploration and production activities
in Azerbaijan and the alternative energy solar facility in Maryland. These
site visits have given directors the opportunity to meet both operational
staff and government and community leaders in the parts of the world
where BP operates. All non-executive directors are required to participate
in at least one site visit per year.

Outside appointments
BP recognizes that executive directors may be invited to become non-
executive directors of other companies and that such appointments can
broaden their knowledge and experience, to the benefit of the individual
and the group. Executive directors are permitted to take up one external
board appointment, subject to the agreement of the chairman and
reported to the BP board. Fees received for these external appointments
may be retained by the executive director and are reported in the
directors’ remuneration report.

Non-executive directors may serve on a number of outside

boards, provided they continue to demonstrate the requisite
commitment to discharge their duties to BP effectively. The nomination
committee keeps under review the nature of directors’ other interests to
ensure that the efficacy of the board is not compromised and may make
recommendations to the board if it concludes that a director’s other
commitments are inconsistent with those required by BP.

Board evaluation
The principles stipulate that the performance and effectiveness of the
board, including the work of its committees, should be evaluated
annually. In 2008, this evaluation was undertaken internally with the use
of a questionnaire. The questionnaire focused on areas including the
conduct of meetings, activities of the board versus committees,
monitoring and information and board support and built on the review of
board operations and governance that had taken place in 2007. The main
outcome of the evaluation was a requirement for a more systematic
approach to ensure that the skills of the directors met the changing
demands of the business and the environment in which it operates.

Engagement with shareholders
The board is accountable to shareholders for the performance and
activities of the BP group and engages in regular dialogue to
understand their views and preferences. However, the board also
recognizes that, in conducting its business, BP should be responsive
to other relevant constituencies.

During the year, the chairman and deputy chairman met with

institutional shareholders to discuss issues relating to the board,
governance, strategy and performance. The remuneration committee
chairman met with larger shareholders to discuss executive director
remuneration.

The group chief executive, other executive directors and senior
management, company secretary’s office, investor relations and other
teams within BP also engage with a range of shareholders on wider
issues relating to the group, including in particular its safety, operational
and financial performance. Presentations given by the group to the
investment community are available to download from the ‘Investors’
section of BP’s website, as are speeches on topics of broad interest to
shareholders made by the group chief executive and other senior
members of the management team.

AGM
BP’s AGM enables shareholders to ask questions and hear the resulting
discussion about the company’s performance and the directors’
stewardship of the company. Votes on all matters (except procedural
issues) are taken by a poll at the AGM, meaning that every vote cast –
whether by proxy or in person at the meeting – is counted.

The chairman, board committee chairmen and other directors

were present during the 2008 AGM and met shareholders on an
informal basis after the main business of the meeting. In 2008, voting
levels at the AGM increased to 64%, compared with 61% in 2007.
Last year was also the first time that the AGM was webcast. This will
be repeated for the company’s forthcoming meeting. The webcast,
speeches and presentations given at the AGM are available to
download from the BP website after the event, together with the
outcome of voting on the resolutions.

Board committees
The principles allocate the tasks of monitoring executive actions and
assessing performance to certain board committees. These tasks
prescribe the authority and role of the board committees.

Reports for each of the main board committees follow. In

common with the board, each committee has access to independent
advice and counsel as required and each is supported by the company
secretary’s office, which is independent of the executive management of
the group. The main tasks and requirements of each of the board’s
committees are set out in the principles, available at
www.bp.com/corporategovernance.

Audit committee report
Membership
The audit committee comprises four independent non-executive directors
who have been selected to provide a wide range of financial, international
and commercial expertise appropriate to fulfil the committee’s duties.

During the year, Sir Ian Prosser (chairman), Douglas Flint and Erroll

Davis, Jr were members of the audit committee. Sir William Castell
retired from the committee in April 2008 and George David joined in May
2008. The secretary to the committee is David Pearl, deputy company
secretary of BP.

The board considers that Douglas Flint possesses the financial

and audit committee experience, as defined by the Combined Code
guidance and the SEC, and has nominated him as the audit committee’s
financial expert.

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BP Annual Report and Accounts 2008
BP board performance report

Attendance
The audit committee met 13 times during 2008.

Sir Ian Prosser (chairman)
E B Davis, Jr
D J Flint
G David
Sir William Castell (former member)

Audit
committee
meetings eligible
to attend
13
13
13
6
7

Audit
committee
meetings
attended
13
10
13
6
7

In addition to the above members, the committee invites the lead partner
of the external auditors (Ernst & Young), the group chief financial officer,
the general auditor (head of internal audit), the chief accounting officer
and the deputy chief financial officer to attend each meeting. Other
senior management attend on request to enable the committee to
discharge its duties. The committee also holds private sessions during
the year without the presence of executive management.

Role and authority of the audit committee
The audit committee assists the board in carrying out its responsibilities
in relation to financial risk, internal controls, financial and regulatory
reporting requirements and the broader observance of the ‘executive
limitations’ relating to financial matters.

The main tasks and requirements for the audit committee are

set out in the principles. The audit committee believes that these meet
each of the tasks and activities outlined by the Combined Code as falling
within the remit of an audit committee.

Information
The committee receives information and reports from internal and
external sources, including a wide cross-section of BP’s business and
financial control management, with the attendance of additional Ernst &
Young staff if appropriate to a particular business or functional review.
The audit committee is able to access independent advice and

counsel when needed, on an unrestricted basis. Further support is
provided to the committee by the company secretary’s office and during
2008 external specialist legal and regulatory advice was provided by
Sullivan & Cromwell LLP.

The wider board is kept informed of the activities of the
committee, and any issues that have arisen, through the regular update
given by the audit committee chair after each meeting.

Training and induction
BP provides an induction programme for new committee members and
ongoing training to assist them in carrying out their duties. Elements of
the induction programme include familiarization with the tasks and
requirements of the audit committee, an overview of the key financial
and operational aspects of the businesses and an introduction to the
group’s system of internal control. During the year, George David
participated in the audit committee induction, including private sessions
with the lead external audit partner and the general auditor.

In 2008, the training programme for the audit committee included
briefings on developments in financial reporting and financial standards, a
site visit to BP’s UK trading operations and an externally facilitated
session on tax risk management.

Committee activities in 2008
The chart at the end of this section shows how the audit committee
allocated its agenda time in 2008.

Financial reporting
During the year, the committee reviewed all financial reports, including
the Annual Report and Accounts and Annual Report on Form 20-F, before
recommending their publication to the board.

Monitoring risk in the business
In 2008, the audit committee reviewed reports on risks, controls and
assurance for the BP business segments (Exploration and Production,
Refining and Marketing), together with alternative energy, information
technology and services, the proposed reorganization of the group
finance function and BP’s trading function. The committee also reviewed
BP’s long-term contractual commitments and the provisions made for
environmental remediation and decommissioning.

Internal controls
A joint meeting with the safety, ethics and environment assurance
committee was held to review the general auditor’s report on internal
controls and risk management. A further joint meeting was held in early
2009 to assist the board in its assessment of the effectiveness of internal
controls and risk management in 2008.

The committee discussed key regulatory issues during the year as

part of its standing agenda items, including the quarterly internal audit
findings report and a review of the company’s evaluation of its internal
controls systems as part of the requirement of Section 404 of the
Sarbanes-Oxley Act. The effectiveness of BP’s enterprise level controls
was examined through the annual assessment undertaken by the internal
audit function.

External auditors
The lead audit partner from Ernst & Young attends all meetings of the
audit committee at the request of the committee chairman. Other
external audit staff are invited to attend meetings where their
expertise is relevant to the agenda item, for example during business
or technical reviews.

The committee held two private meetings during the year with

the external auditors without the presence of BP management, in order
to discuss issues or concerns from either the committee or the auditors.

Performance of the external auditors is evaluated by the audit
committee each year, with particular scrutiny of their independence,
objectivity and viability. Independence is maintained through the limiting
of non-audit services to tax and audit-related work that fall within defined
categories. This work is pre-approved by the audit committee and all
non-audit services are monitored quarterly.

Fees paid to the external auditors for the year (see Financial
statements – Note 18 on page 134) were $67 million, of which 14% was
for non-audit work. The fees and services provided by Ernst & Young for
both audit and non-audit work have decreased in comparison to the
previous year due to improved audit efficiency, ongoing systems
improvements and BP’s new business structure.

During the year, a new lead partner from Ernst & Young replaced

the existing partner who had completed five years’ service on the BP
audit in early 2008. Under BP policy and pursuant to external regulation,
a new lead audit partner is appointed every five years and other senior
audit staff are rotated every seven years. No partners or senior staff
from Ernst & Young who are connected with the BP audit may transfer
to the group.

The audit committee has considered both the proposed fee

structure and the audit engagement terms for 2009 and has
recommended to the board that the reappointment of the external
auditors be proposed to shareholders at the 2009 AGM.

BP Annual Report and Accounts 2008
BP board performance report

Internal audit
The general auditor attends each committee meeting at the invitation of
the audit committee chairman. With the retirement of the general auditor
in early 2008, a new general auditor was appointed following an
externally facilitated recruitment process.

During the year, the audit committee evaluated the performance
of the internal audit function and agreed to the proposed programme of
work for the year (being satisfied that it appropriately responded to the
key risks facing the company and that the function had adequate staff
and resources to complete its work).

In 2008, the committee met once with the general auditor in a

private session without the presence of executive management. In
addition, the general auditor met with the chairman of the committee
from time to time between meetings.

Fraud and employee concerns on financial matters
The audit committee received an annual certification report from the
group compliance and ethics function, together with quarterly reports
that highlighted financial issues raised through OpenTalk, the group-wide
employee concerns programme.

The committee further received quarterly updates from internal

audit on instances of actual or potential fraud.

Audit committee activities
Approximate allocation of agenda time in 2008*

4% 34%

26%

36%

Financial reporting
Monitoring business risk
Internal controls and audit
Other agenda items

*Excludes time spent on site visits

Committee performance evaluation
The committee conducts a yearly evaluation of its performance through
one-to-one interviews or questionnaires. The results are collated and
reported by the committee secretary. Actions taken in 2008 as a result of
the end 2007 evaluation included participation in an externally facilitated
training session and improved tracking of outstanding issues. In addition,
the committee considers performance during its private sessions
throughout the year.

The 2008 evaluation was conducted through individual interviews

and the outcomes discussed by the committee in January 2009. The
forward agenda for the year ahead was set following this review, and
consideration was given to building on the training provided to members
through site visits.

The audit committee plans to meet 13 times during 2009.

Safety, ethics and environment assurance committee report
Membership
The committee consists solely of independent non-executive directors
who have been selected to provide a wide range of operational and
international expertise appropriate to fulfil the committee’s duties.

Members of the safety, ethics and environment assurance committee
(SEEAC) during 2008 were Antony Burgmans, Sir William Castell and
Sir Tom McKillop. Dr Massey retired as chairman of SEEAC in April 2008
and Sir William Castell became the committee chairman from that date.
Cynthia Carroll joined the committee in June 2008. Support was provided
by the committee secretary, David Pearl (deputy company secretary).

Attendance
SEEAC met eight times during 2008.

Sir William Castell (chairman)
A Burgmans
C B Carroll
Sir Tom McKillop
Dr W E Massey (former member)

SEEAC meetings
eligible to attend
8
8
3
8
4

SEEAC meetings
attended
8
8
2
8
4

In addition to the above members, each SEEAC meeting is attended by
the lead partner of the external auditors (Ernst & Young) and the BP
general auditor (head of internal audit) on the invitation of the committee
chairman. The group chief executive also attends committee meetings as
the executive liaison with SEEAC: Dr Hayward attended all eight
meetings of the committee in 2008. The committee holds private
sessions without executive management in attendance at the end of
each meeting.

Role and authority of the committee
The main tasks and requirements for SEEAC are set out in the
principles and include among others:
(cid:129) Monitoring and obtaining assurance on behalf of the board that the
management or mitigation of significant BP risks of a non-financial
nature is appropriately addressed by the group chief executive.
(cid:129) Reviewing material to be placed before shareholders that addresses

environmental, safety and ethical performance and make
recommendations to the board about their adoption and publication.

(cid:129) Reviewing reports on the group’s compliance with its code of

conduct and on the employee concerns programme (OpenTalk) as it
relates to non-financial issues.

Information
The committee receives information and reports from the safety and
operations function, internal and external sources, including internal audit
and the group compliance and ethics function. Staff from Ernst & Young
attend if appropriate to a particular business or activity review.
Like BP’s other board committees, SEEAC can access
independent advice and counsel if it requires, on an unrestricted basis.
The wider board is kept informed of the activities of the committee and
any issues that have arisen through the regular update given by the
SEEAC chair after each meeting.

Training and induction
Members of the committee receive ongoing training to assist them in
carrying out their duties and an induction programme was provided for
Mrs Carroll on joining the committee.

To develop a deeper understanding of BP’s business and
operations, Sir William Castell undertook a number of private briefings
and several site visits on becoming SEEAC chairman. These visits
included the Texas City refinery, where progress in implementing the
recommendations of the Panel was observed and to the North Sea ETAP
platforms where safety, operational and environmental management on
an offshore production facility were reviewed.

Committee activities in 2008
The chart at the end of this section shows how SEEAC allocated its
agenda time in 2008.

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BP Annual Report and Accounts 2008
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Safety and operations
The group operations risk committee (GORC) was formed at the end of
2006 and is an executive level committee, chaired by the group chief
executive. The GORC made regular reports to SEEAC during the year,
including progress on the group-wide implementation of the operating
management system (OMS) and BP’s six-point plan, the development
and utilization of the process safety index and statistics relating to the
group’s safety and operational performance.

L Duane Wilson was appointed by the board in 2007 as an
independent expert to provide an objective assessment of BP’s progress
in implementing the Panel recommendations, aimed at improving
process safety performance at BP’s five US refineries. Mr Wilson, who
was a member of the Panel, reports to the chairman of SEEAC and is
independently funded through the company secretary’s office.

Mr Wilson attended six meetings of the committee during 2008

and a private meeting with the committee during the year without the
presence of executive management. Topics discussed included a
presentation on his detailed work plan and progress updates. In May
2008, Mr Wilson published his first annual report where he assessed
BP’s progress against the 10 Panel recommendations. The report noted
that while significant progress had been made, areas for improvement
still remained. Further information on the report is available on
BP’s website.

Performance evaluation and forward agenda
The committee undertakes an annual review of its performance and
process. In 2008, the review involved interviews with each committee
member, with the results discussed at the committee’s November
meeting. Conclusions from the evaluation included noting the helpful
insight gained from site visits and the value to the committee of the
knowledge and expertise of the independent expert in respect of
safety in the US refineries. The committee also reviewed its forward
agenda for 2009.

SEEAC plans to meet seven times during 2009.

Remuneration committee report
Membership
The committee consists solely of non-executive directors who are
considered by the board to be independent.

Members of the remuneration committee during the year were

Dr DeAnne Julius (chairman), Erroll Davis, Jr, Sir Tom McKillop and
Sir Ian Prosser. The chairman of the board also attends meetings of
the committee.

Attendance
The committee met six times during 2008.

Regional reviews and site visits
During the year, the committee reviewed reports on Alaska, the BTC
pipeline, shipping and TNK-BP. The committee visited BP’s refinery
operations in Rotterdam, and coal bed methane operations in Durango,
Colorado. In addition, some members visited the BP solar manufacturing
facilities in Maryland and the group’s operations in Azerbaijan.

Dr D S Julius (chairman)
E B Davis, Jr
Sir Tom McKillop
Sir Ian Prosser
P D Sutherland

Remuneration committee
meetings eligible to attend
6
6
6
6
6

Remuneration committee
meetings attended
6
5
6
6
6

Other topics
Other topics reviewed by the committee during the year included
business continuity and crisis management, environmental requirements
for new projects, results from a survey on safety culture in BP’s US
refineries and a report from the US ombudsman on concerns raised by
employees in Alaska. The committee also received and discussed
quarterly reports from the general auditor and the group compliance and
ethics officer.

SEEAC 2008 Activities
Approximate allocation of agenda time*

51%

13%

20%

16%

Safety and operations
Regional and functional reports
Internal audit and compliance and ethics
Other topics

*Excludes time spent on site visits

Role and authority of the committee
The committee determines, on behalf of the board, the terms of
engagement and remuneration of the group chief executive, the chairman
and executive directors and reports on those to shareholders. The
committee is independently advised.

Further details on the committee’s role, authority and activities

during the year are set out in the directors’ remuneration report, which
is the subject of a vote by shareholders at the 2009 AGM.

The remuneration committee plans to meet five times in 2009.

Chairman’s committee report
Membership
The committee consists of the chairman and all non-executive directors.

Attendance
The committee met four times during 2008.

P D Sutherland (chairman)
Sir Ian Prosser
A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Dr W E Massey (former member)

Chairman’s committee meetings
eligible to attend
4
4
4
4
4
2
4
4
4
4
2

Chairman’s committee
meetings attended
4
4
4
3
4
2
4
4
4
4
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BP Annual Report and Accounts 2008
BP board performance report

Role and authority of the committee
The main tasks and requirements for the committee are set out in the
principles and are:
• Evaluating the performance and effectiveness of the group

chief executive;

• Reviewing the structure and effectiveness of the business

organization of BP;

• Reviewing the systems for senior executive development

and determining the succession plan for the group chief executive,
executive directors and other senior members of executive
management;

• Determining any other matter that is appropriate to be considered by

all of the non-executive directors;

• Opining on any matter referred to it by the chairman of any
committee comprised solely of non-executive directors.

Committee activities
The chairman’s committee considered aspects of a number of strategic
issues including the relationship with the company’s partners in TNK-BP.
The committee has reviewed with Dr Hayward the short- and long-term
challenges facing the group. Dr Hayward has kept the committee briefed
on the implementation of the forward agenda and its implications for the
evolution of the executive team and succession within the leadership
cadre. The committee has also reviewed the steps taken by Dr Hayward
to refine the corporate culture and the values within BP. There have been
active discussions around the ‘tone from the top’.

The committee has reviewed the performance of the chairman

and Dr Hayward.

The chairman’s committee plans to meet four times in 2009.

Nomination committee report
Membership
The committee’s members nominally consist of the chairman and the
chairs of SEEAC, audit and remuneration committees.

Members of the nomination committee during the year were

Peter Sutherland (chairman), Dr DeAnne Julius, Sir Ian Prosser and
Dr Walter Massey. Dr Massey remained a member of the nomination
committee during the year after his retirement from the board to assist in
the search for a successor to BP’s chairman. Sir William Castell has now
joined the committee.

Attendance
The committee met six times during 2008.

P D Sutherland (chairman)
Dr D S Julius
Dr W E Massey
Sir Ian Prosser

Nomination committee meetings
eligible to attend
6
6
6
6

Nomination committee
meetings attended
6
6
6
6

Role and authority of the committee
The main tasks and requirements for the committee are set out in the
principles and are:
• Identifying, evaluating and recommending candidates for

appointment or reappointment as directors.

• Identifying, evaluating and recommending candidates for

appointment as company secretary.

• Keeping under review the mix of knowledge, skills and experience of

the board to ensure the orderly succession of directors.
• Reviewing the outside directorship/commitments of the non-

executive directors.

Committee activities
During 2008 the primary work of the committee has been the
continuation of the process to select a successor to Mr Sutherland who
is to stand down as chairman.

For this purpose, Sir Ian Prosser, as Senior Independent Director, has
chaired the committee. The committee has been assisted in this
task by Dr Anna Mann of MWM Consulting LLP. The committee has
adopted a robust process. Key strategic issues facing BP for the coming
years were identified through discussions with individual board
members. From these discussions a role description was developed.
This formed the basis of a worldwide search from which in excess of
30 candidates emerged. This broad group has been refined and the
process is continuing. The board has been regularly briefed on the
work of the committee.

As part of the chairman selection process, potential candidates for

non-executive directors roles have been revealed. The committee will
continue actively to keep the skills of the board under review and pursue
its refreshment.

Combined Code compliance
BP complied throughout 2008 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.2.2 The remuneration of the chairman is reviewed by the

remuneration committee, which makes a recommendation to
the board as a whole for final approval, within the limits set by
shareholders. This approach represents a change in policy from
previous years where the chairman’s remuneration was set by the
board without specific reference to the remuneration committee.

Internal control review
In discharging its responsibility for the company’s system of internal
control the board, through its governance principles, requires the group
chief executive to operate with a comprehensive system of controls and
internal audit to identify and manage the risks that are material to BP.
The governance principles were reviewed and confirmed by the board
this year and are consistent with the requirements of the Combined
Code including principle C.2.

The board has established a process by which the effectiveness

of this system of internal control is reviewed as required by provision
C.2.1 of the Combined Code. This process enabled the board and its
committees to consider the system of internal control being operated for
managing significant risks, including social, environmental, safety and
ethical risks, throughout the year. The process did not extend to joint
ventures or associates.

As part of this process, the board and the audit and safety, ethics

and environment assurance committees requested, received and
reviewed reports from executive management, including management of
the business segments and functions, at their regular meetings.

In considering the system, the board noted that such a system is

designed to manage, rather than eliminate, the risk of failure to achieve
business objectives and can only provide reasonable, and not absolute,
assurance against material misstatement or loss.

During the year, the board through its committees regularly
reviewed with the general auditor and executive management processes
whereby risks are identified, evaluated and managed. These processes
were in place for the year under review, remain current at the date of this
report and accord with the guidance on the Combined Code provided by
the Financial Reporting Council. In November, the board considered the
group’s significant risks within the context of the annual plan presented
by the group chief executive.

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BP Annual Report and Accounts 2008
BP board performance report

A joint meeting of the audit and safety, ethics and environment
assurance committees in January 2009 reviewed reports from the
general auditor as part of the board’s annual review of the system of
internal control. The reports described the significant risks identified
across the group within the categories of strategic, operational and
compliance and control and considered the control environment that
responds to such risks. The reports also highlighted the results of audit
work conducted during the year and the remedial actions taken by
executive management in response to significant failings and
weaknesses identified.

During the year, these committees engaged with executive

management, the general auditor and other monitoring and assurance

providers (such as the group compliance and ethics officer and the
external auditor) on a regular basis to monitor the management of
risks. Significant incidents that occurred and management’s response
to them were considered by the appropriate committee and reported
to the board.

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 ‘Internal Control Revised Guidance for
Directors’ in the Combined Code (Turnbull).

The board is satisfied that, where significant failings or

weaknesses in internal controls were identified during the year,
appropriate remedial actions were taken or are being taken.

Directors’ interests

Current directors
A Burgmans
C B Carroll
Sir William Castell
I C Conn
G David
E B Davis, Jr
D J Flint
Dr B E Grote
Dr A B Hayward
A G Inglis
Dr D S Julius
Sir Tom McKillop
Sir Ian Prosser
P D Sutherland
Directors leaving the board in 2008
Dr D C Allen (retired 31 March 2008)
Dr W E Massey (retired 17 April 2008)

10,000
–
82,500
240,789a
9,000b
73,185b
15,000

Change from
31 Dec 2008
At 31 Dec 2008 At 1 Jan 2008 to 18 Feb 2009
–
–
–
39,148
–
–
–
47,334
39,148
29,249
–
–
–
–

10,000
–
50,000
229,969a
– c
70,602b
15,000
1,214,330d 1,193,137d
482,398
488,459
224,006e
226,175e
15,000
15,000
20,000
20,000
16,301
16,301
30,906
30,906
At resignation/retirement At 1 Jan 2008
597,568f
597,568f
49,722b
49,722b

aIncludes 44,158 shares held as ADSs at 31 December 2008 and 41,692 shares held as ADSs at 1 January 2008.

bHeld as ADSs.

cOn appointment at 11 February 2008.

dHeld as ADSs, except for 94 shares held as ordinary shares.

eIncludes 34,962 shares held as ADSs.

fIncludes 25,368 shares held as ADSs.

The above figures indicate and include all the beneficial and non-beneficial interests of each director of the company in shares of the company (or
calculated equivalents) that have been disclosed to the company under the Disclosure and Transparency Rules and Companies Acts 1985 or 2006
(as the case may be) as at the applicable dates. The above figures do not include share options granted or interests in performance shares that have
yet to vest. Details of these are set out in full in the directors’ remuneration report on pages 83 and 84.

Executive directors are also deemed to have an interest in such shares of the company held from time to time by 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

78 Part 1 Summary

80 Part 2 Executive directors’

remuneration

86 Part 3 Non-executive directors’

remuneration

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BP Annual Report and Accounts 2008

Directors’ remuneration report

Part 1 Summary

BP executives delivered a strong performance in a turbulent environment
during 2008 and restored the group’s operations to a high standard after
several years of focused effort. We commend them for a job well done.

Key financial targets for the year were exceeded, even after
adjusting for the effect of high oil prices during part of the year. Safe and
reliable operations remained at the top of the agenda and key safety
metrics and milestones were achieved. The year’s results were especially
strong in Exploration and Production, with the start-up of the Thunder
Horse platform and excellent overall reserves replacement. Key targets
were also met in Refining and Marketing and both the Texas City and
Whiting refineries were safely restored to full capacity by the end of the
year. The annual bonus results, set out in the table opposite, reflect this
strong performance and determined leadership.

The committee undertook a detailed review of BP’s underlying
performance against competitors in determining the 2006-2008 share
element vesting under the executive directors’ incentive plan (EDIP). This
review included financial measures such as earnings per share, returns on
average capital employed, free cash flow, operating measures for both
Exploration and Production and Refining and Marketing, and non-financial
measures for safety and reputation. All measures were compared across
competitors and showed BP firmly in the pack of the other European oil
majors. The comparison of total shareholder return (TSR) was less
favourable to BP, partly due to exchange rate movements and turbulence in
the financial markets. After careful review, the committee concluded that
TSR alone was not a fair reflection of underlying performance over the
2006-2008 period. We concluded that it was appropriate to approve the
vesting of 15% of the shares in the plan for the current directors. This too
is set out in the table opposite.

Salaries were increased mid-2008 after our normal review. For

2009, we have agreed with the group chief executive’s view that salaries
should be frozen at their current level. There also will be no change in the
target and normal maximum levels of bonus for 2009. The group chief
executive’s and group chief financial officer’s bonuses will be based 70%
on group performance against key metrics in the annual plan, 15% on
safety performance and 15% on people. The chief executives of
Exploration and Production and Refining and Marketing will have 50% of
their bonuses determined on the above basis and 50% on the
performance of their respective businesses.

The EDIP share element will again provide the long-term
component of remuneration for the 2009-2011 period, with some slight
modifications. First, reflecting its recent growth, ConocoPhillips will be
added to the peer group of comparators (currently ExxonMobil, Shell,
Total and Chevron). Second, to provide a more balanced assessment,
vesting will be based half on BP’s total shareholder return relative to the
peer group and half on underlying performance compared with this same
peer group. BP’s performance will be compared on an interpolated basis
relative to the performance of the other five. As in previous years, shares
will vest at 100%, 70% and 35% for performance equivalent to first,
second and third rank respectively and none for fourth or fifth.

We remain committed to a remuneration policy and practice that

aligns with the long-term interests of shareholders and provides an
appropriate reward for talented and committed executives. In the current
volatile climate, executive leadership is more important than ever. The
committee will continue to use careful and rigorous judgement in
assessing performance, and to communicate our assessment in a clear
way to shareholders.

Dr DeAnne S Julius
Chairman, Remuneration Committee
24 February 2009

BP Annual Report and Accounts 2008
Directors’ remuneration report

Summary of remuneration of executive directors in 2008a

Annual remuneration

Long-term remuneration

Share element of EDIPb

2005-2007 plan
(vested in Feb 2008)

2006-2008 plan
(vested in Feb 2009)

2008-2010
plan

Dr A B Hayward
I C Conn
Dr B E Grote
A G Inglis

Salary
(thousand)
2008
£998
£670
$1,340
£670

2007
£877
£581
$1,175
£556

2007

Annual
performance bonus
(thousand)
2008
£1,262 £1,496
£871
$1,551 $1,742
£800 £1,173

£698

Non-cash benefits and
other emoluments
(thousand)
2008
£15
£45
$8

2007
£14
£45
$10
£188

2007
£2,153
£1,324
$2,736
£212g £1,544

Total
(thousand)
2008
£2,509
£1,586
$3,090
£2,055

Directors leaving the board in 2008
Dr D C Allenh

£500

£128

£539

£163

£13

£3

£1,052

£294

Amounts shown are in the currency received by executive directors. Annual bonuses are shown in the year they were earned.

Actual
shares
Value
vested (thousand)

Actualc
Valued
shares
vested (thousand)
£336
£336
$603
£279

0 66,136
0 66,136
0 80,231f
0 54,994

Potential
maximum
performance
sharese
845,319
578,376
581,748
578,376

0 34,518

£175

n/a

0
0
0
0

aThis information has been subject to audit.
bOr equivalent plans in which the individual participated prior to joining the board.
cIncludes shares representing reinvested dividends received on the shares that vested at the end of the performance period.
dBased on market price on vesting date (£5.08 per share/$45.13 per ADS).
eMaximum potential shares that could vest at the end of the three-year period depending on performance.
fDr Grote holds shares in the form of ADSs. The above number reflects calculated equivalent in ordinary shares.
gThis amount includes costs of London accommodation provided to Mr Inglis. In addition, under a tax equalization arrangement, BP also discharged a US tax liability arising on his
participation in the UK pension scheme amounting to $553,175.
hDr Allen resigned from the board on 31 March 2008. In addition to the above, he was awarded compensation for loss of office equal to one year’s salary (£510,000). He also received £30,000
in respect of statutory rights and retained his company car.

Pensions
All executive directors are part of a final salary pension scheme. Accrued
annual pension earned as at 31 December 2008 is £561,000 for
Dr Hayward, £264,000 for Mr Conn, $868,000 for Dr Grote and £326,000
for Mr Inglis.

Historical TSR performance

FTSE 100

300

250

200

150

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1
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100 V

Dec 03

Dec 04

Dec 05

Dec 06

Dec 07

Dec 08

This graph shows the growth in value of a hypothetical £100 holding in
BP p.l.c. ordinary shares over five years, relative to the FTSE 100 Index
(of which the company is a constituent). The values of the hypothetical
£100 holdings at the end of the five-year period were £144.36 and
£115.05 respectively.

Remuneration of non-executive directors in 2008a

A Burgmans
Sir William Castell
C B Carroll
G Davidb
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Sir Ian Prosser
P D Sutherland

Directors leaving the board in 2008
Dr W E Masseyc

aThis information has been subject to audit.
bAppointed on 11 February 2008.
cAlso received a superannuation gratuity of £23,000.

£ thousand

2008
90
108
93
100
105
90
110
95
170
600

2007
86
87
43
n/a
107
86
106
87
137
517

133

In 2008 the board, after a review, determined that in future it would
continue to set the remuneration of the non-executive directors. However,
in the case of the chairman this would be based on a recommendation
from the remuneration committee and, for the non-executive directors, it
would be based on a recommendation from the chairman.

This process was adopted in 2008 and recommendations were

made. However, the chairman and the non-executive directors informed
the board that, in the current economic circumstances, they did not
wish to receive any increase in remuneration for 2009. The board
accordingly maintained the fees at the 2008 level for 2009 save that
no committee membership fee would in future be paid to members
of the nomination committee.

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BP Annual Report and Accounts 2008
Directors’ remuneration report

Part 2 Executive directors’ remuneration
2008 remuneration
Salary increases
As part of our normal cycle, salaries were reviewed mid-year and were
increased to reflect market competitiveness and personal performance.
Dr Hayward’s salary was increased 10% to £1,045,000, and the other
executive directors by 6% to the following: Mr Conn £690,000, Dr Grote
$1,380,000 and Mr Inglis £690,000.

Annual bonus result
Performance measures and targets were set at the beginning of the year
based on the annual plan. The target level bonus of 120% of base salary
placed 50% on group financial and operating results including earnings
before interest, taxes, depreciation and amortization (EBITDA), cash
costs, cash flow, return on average capital employed (ROACE) and capital
expenditure. The remaining portion was weighted 25% on safety, 25%
on people and 20% on individual performance, principally operating
results and leadership.

Overall performance for 2008 was very strong and is more fully

set out in other parts of this report. Financial results exceeded targets for
EBITDA, free cash flow and returns on average capital employed, even
after adjusting for the high oil prices for part of the year. Cash costs were
managed below target, and capital expenditure within expected levels.

Operationally, the upstream business had an excellent year,
replacing a high proportion of proved reserves, exceeding its production
target and successfully starting up the important Thunder Horse
development in the Gulf of Mexico. The downstream business
successfully and safely completed the full re-commissioning of the Texas
City and Whiting refineries and improved overall performance. Alternative
Energy exceeded its targets for wind and met its solar sales target.

Safe and reliable operations remained at the top of the agenda

and performance, both in terms of safety metrics and progress on OMS
implementation, was assessed as satisfactory by the safety, ethics and
environment assurance committee (SEEAC). On the people front,
significant progress was made in reducing complexity and embedding a
performance culture throughout the group.

Annual bonus results for 2008 reflect this overall strong
performance and committed leadership and are set out in the table on
page 79.

2006-2008 share element result
Performance for the share element is assessed relative to the TSR of the
company compared with the other oil majors – ExxonMobil, Shell, Total and
Chevron. Recognizing the inherent imperfections in a TSR ranking, the EDIP
rules give the committee power to adjust (upwards or downwards) the
vesting level derived from the TSR ranking if it considers that the ranking
does not fairly reflect BP’s underlying business performance relative to the
comparators. This is designed to enable a more comprehensive review of
BP’s long-term performance, with the aims of tempering anomalies created
by relying solely on a formula-based approach.

For the 2006-2008 plan, BP was fifth relative to the other majors in
terms of TSR when calculated on a common currency (US dollar) basis as
originally anticipated. However, unusually large currency movements at
the end of this period were an extraneous influence on this result. On a
local currency basis, the TSRs of BP, Shell and Total were tightly bunched
together. The committee also reviewed BP’s underlying business
performance relative to the comparator companies over the full three-year
period. This review included financial measures (earning per share growth,
ROACE, free cash flow, net income), operating measures (production,
reserves replacement and Refining and Marketing profitability), and non-
financial measures (health, safety and environmental and reputation).
Again, the performance of the European comparators was quite similar:
BP led the group on some measures (notably free cash flow and reserves
replacement) but lagged on Refining and Marketing profitability.

The committee concluded that the TSR result, by itself, was not a fair
reflection of BP’s relative underlying performance over the period. After
thorough consideration, the committee determined that 15% of the
shares under the 2006-08 award should vest – this being a fair reflection
of the overall results achieved and consistent with its approach to the
clustering of results, as anticipated in the EDIP rules approved by
shareholders in 2005.

In accordance with its powers under the EDIP rules, the

committee also determined that, as there was clear evidence of a
progressive turnaround of performance over the final 18 months of the
performance period, individual vesting levels should only occur to the
extent that eligible individuals contributed to the turnaround. The resulting
final vesting for all eligible participants is shown in the table on page 83.
Mr Inglis’s award was made prior to his appointment as an
executive director under the MTPP (medium term performance plan) that
is the comparable plan to the EDIP. Vesting conditions were the same as
for the EDIP for Mr Inglis but, unlike the EDIP, the MTPP does not have a
three-year retention period.

Lord Browne also held an award under the 2006-08 share element

related to long-term leadership measures. These focused on sustaining
BP’s financial, strategic and organizational health. Performance relative to
the award was assessed by the chairman’s committee and, based on this
assessment, no shares were vested.

Remuneration policy
Our remuneration policy for executive directors aims to ensure there is a
clear link between the company’s purpose, its business plans and
executive reward, with pay varying with performance. In order to achieve
this, the policy is based on these key principles:
• The majority of executive remuneration will be linked to the

achievement of demanding performance targets, independently set
to support the creation of long-term shareholder value.

• The structure will reflect a fair system of reward for all the participants.
• The remuneration committee will determine the overall amount of

each component of remuneration, taking into account the success of
BP and the competitive environment.

• There will be a quantitative and qualitative assessment of

performance, with the remuneration committee making an informed
judgement within a framework approved by shareholders.

• Remuneration policy and practice will be as transparent as possible.
• Executives will develop a significant personal shareholding in order to

align their interests with those of shareholders.

• Pay and employment conditions elsewhere in the group will be taken

into account, especially in setting annual salary increases.

• The remuneration policy for executive directors will be reviewed

regularly, independently of executive management, and will set the
tone for the remuneration of other senior executives.

• The remuneration committee will actively seek to understand

shareholder preferences.

Executive directors’ total remuneration consists of salary, annual
bonus, long-term incentives, pensions and other benefits. The
remuneration committee reviews this structure regularly to ensure it is
achieving its aims. In 2008, over three-quarters of executive directors’
total potential remuneration was performance related. The same will be
true for total potential remuneration in 2009.

BP Annual Report and Accounts 2008
Directors’ remuneration report

Salary
The remuneration committee normally reviews salaries annually, taking
into account other large Europe-based global companies and companies
in the US oil and gas sector. These groups are each defined and analyzed
by the committee’s independent remuneration advisers. For 2009, the
committee has agreed with the group chief executive’s view that salaries
should be frozen at their current level.

Policy for performance share awards
The remuneration committee can award shares to executive directors
that will only vest to the extent that demanding performance conditions
are satisfied at the end of a three-year period. The maximum number of
these performance shares that can be awarded to an executive director
in any year is at the discretion of the remuneration committee, but will
not normally exceed 5.5 times base salary.

Annual bonus
All executive directors are eligible to take part in an annual performance-
based bonus scheme. The remuneration committee sets bonus targets
and levels of eligibility each year.

The target level for 2009 is 120% of base salary. In normal
circumstances, the maximum payment for substantially exceeding
performance targets will continue to be 150% of base salary.

The group chief executive’s and group chief financial officer’s

bonus will be determined on group results as follows:
• 70% on group performance compared with key metrics and

milestones from the annual plan including:
• Cash costs and organic capex.
• Underlying replacement cost profit and operating cash flow.
• Production and reserves replacement.
• Refining availability and earnings/barrel.
• Installed wind capacity.

• 15% on safety performance, including satisfactory and improving key

metrics as well as progress on OMS implementation.
• 15% on people, including behaviour, culture and values.
For the chief executive of Exploration and Production, and the chief
executive of Refining and Marketing, 50% of their bonus will be based on
the above group results and 50% on the results of their respective
businesses as measured by key metrics and milestones set out in the
annual plan. For Exploration and Production, these include production
costs and reserves replacement as well as safety and new opportunities.
For Refining and Marketing, they include refining availability, earnings and
cash costs, as well as safety and work simplification.

The remuneration committee will also review carefully the
underlying performance of the group in light of company business
plans and will look at competitors’ results, analysts’ reports and
the views of the chairmen of other BP board committees when
assessing results.

In exceptional circumstances, the remuneration committee can

decide to award bonuses moderately above the maximum level. The
committee can also decide to reduce bonuses where this is warranted
and, in exceptional circumstances, bonuses could be reduced to zero.
We have a duty to shareholders to use our discretion in a reasonable and
informed manner, acting to promote the success of the company, and
also to be accountable and transparent in our decisions. Any significant
exercise of discretion will be explained in the subsequent directors’
remuneration report.

Long-term incentives
Each executive director participates in the EDIP. It has three elements:
shares, share options and cash. The remuneration committee does not
intend to use either the share option or cash elements in 2009, nor to
grant any retention awards which are also permitted under the EDIP.
We intend that executive directors will continue to receive performance
shares under the EDIP, barring unforeseen circumstances, until it expires
or is renewed in 2010.

In exceptional circumstances, the committee also has an

overriding discretion to reduce the number of shares that vest or to
decide that no shares vest.

The compulsory retention period will also be decided by the

committee and will not normally be less than three years. Together with
the performance period, this gives executive directors a six-year incentive
structure, as shown in the timeline below, which is designed to ensure
their interests are aligned with those of shareholders.

Timeline for 2009-2011 EDIP share element

Performance period

Retention period

Award

2009

Vesting

Release

2010

2011

2012

2013

2014

2015

Where shares vest, the executive director will receive additional shares
representing the value of the reinvested dividends.

The committee’s policy continues to be that each executive

director build a significant personal shareholding, with a target of
shares equivalent in value to five times his or her base salary within
a reasonable timeframe from appointment as an executive director.
This policy is reflected in the terms of the performance shares under the
EDIP, as shares vested will normally only be released at the end of the
three-year retention period, described above, if these minimum
shareholding guidelines are met.

Performance conditions
Performance conditions for the 2009-11 share element will be somewhat
modified from previous years. First, the peer group of oil majors against
which we compare will be increased to include ConocoPhillips as well as
ExxonMobil, Shell, Total and Chevron as previously. This change reflects
ConocoPhillips’ significant growth over the last few years, providing it
with similar scale and global reach to the other oil majors.

Second, vesting of the shares will be based 50% on total

shareholder return (TSR) versus the competitor group and 50% on a
balanced scorecard of underlying performance versus the same
competitors. The underlying performance will be assessed on three
measures reflecting key priorities in BP’s strategy – in Exploration and
Production, hydrocarbon production growth, in Refining and Marketing,
improvement in earnings per barrel, and group increase in underlying
net income. Both Exploration and Production production growth and
Refining and Marketing earnings improvement are key strategic
objectives for the group and this inclusion aligns key measures with
both executive director priorities as well as key drivers of value for
shareholders. Group increase in underlying net income acts as a holistic
measure of success reflecting revenues, costs and complexity as well
as safe and reliable operations.

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Directors’ remuneration report

All the above measures will be compared with the five other oil majors to
determine the overall vesting result. The methodology used will rank each
of the five other majors on each of the measures. BP’s performance will
then be compared on an interpolated basis relative to the performance of
the other five. For performance between second and third or first and
second, the result will be interpolated based on BP’s performance
relative to the company ranked directly above and below it. As in previous
years, performance shares will vest at 100%, 70% and 35% for
performance equivalent to first, second and third rank respectively and
none for fourth or fifth place. The three underlying measures will be
averaged to form the balanced scorecard component.

The committee considers that this combination of measures

provides a good balance of external as well as internal metrics reflecting
both shareholder value and operating priorities. As in previous years, the
committee will exercise its discretion, in a reasonable and informed
manner to adjust vesting levels upwards or downwards if it concludes the
above quantitative approach does not reflect the true underlying health
and performance of BP’s business relative to its peers. It will explain any
adjustments in the next directors’ remuneration report following the
vesting, in line with its commitment to transparency.

Pensions
Executive directors are eligible to participate in the appropriate pension
schemes applying in their home countries. Additional details are given
in the table below.

UK directors
UK directors are members of the regular BP Pension Scheme. The core
benefits under this scheme are non-contributory. They include a pension
accrual of 1/60th of basic salary for each year of service, up to a
maximum of two-thirds of final basic salary and a dependant’s benefit of
two-thirds of the member’s pension. The scheme pension is not
integrated with state pension benefits.

The rules of the BP Pension Scheme were amended in 2006 such
that the normal retirement age is 65. Prior to 1 December 2006, scheme
members could retire on or after age 60 without reduction. Special early
retirement terms apply to pre-1 December 2006 service for members
with long service as at 1 December 2006.

Pension benefits in excess of the individual lifetime allowance set by
legislation are paid via an unapproved, unfunded pension arrangement
provided directly by the company.

Although Mr Inglis is, like other UK directors, a member of the

BP Pension Scheme, he is currently based in Houston, US. His
participation in the BP Pension Scheme gives rise to a US tax liability.
During 2008, the committee approved the discharge of this US tax liability
under a tax equalization arrangement in respect of the period since
Mr Inglis became a director in February 2007, amounting to $553,175.

US directors
Dr Grote participates in the US BP Retirement Accumulation Plan
(US plan), which features a cash balance formula. Pension benefits are
provided through a combination of tax-qualified and non-qualified benefit
restoration plans, consistent with US tax regulations 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 (and as
specified under the qualified arrangement), multiplied by years of service.
There is 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 eligible to participate under the supplemental plan.

His pension accrual for 2008, shown in the table below, includes the
total amount that could become payable under all plans.

Other benefits
Executive directors are eligible to participate in regular employee benefit
plans and in all-employee share saving schemes and savings plans
applying in their home countries. Benefits in kind are not pensionable.
Expatriates may receive a resettlement allowance for a limited period.

As Mr Inglis is currently based in Houston, US, BP provides

accommodation in London.

Pensionsa

Dr A B Hayward (UK)
I C Conn (UK)
Dr B E Grote (US)
A G Inglis (UK)

Directors leaving the board in 2008
Dr D C Allen (UK)d

Service at
31 Dec 2008
27 years
23 years
29 years
28 years

Accrued pension
entitlement
at 31 Dec 2008
£561
£264
$868
£326

Additional pension
earned during the
year ended
31 Dec 2008b
£72
£26
$45
£30

Transfer value of
accrued benefitc
at 31 Dec 2007 (A)
£7,986
£3,375
$7,901
£4,613

Transfer value of
accrued benefitc
at 31 Dec 2008 (B)
£8,045
£3,161
$11,220
£4,399

Amount of B-A less
contributions made by
the director in 2008
£9
(£214)
$2,860
(£214)

thousand

n/a

£260

£12

£4,256

£5,580

£1,324

aThis information has been subject to audit.
bAdditional pension earned during the year includes an inflation increase of 4.0% for UK directors and 5.8% for US directors.
cTransfer values have been calculated in accordance with version 8.1 of guidance note GN11 issued by the actuarial profession.
dDr D C Allen retired on 31 March 2008 and commuted part of his pension for a lump sum. The figures above make no allowance for the payment of this lump sum. If allowance is made (in line with the
strict requirements of the regulations), and the transfer value at the end of the year is based on the pension in payment at that time, then the transfer value at 31 December 2008 would be £4.55 million
and the change in value over the year would be £0.29 million.

BP Annual Report and Accounts 2008
Directors’ remuneration report

Share element of EDIPa

Dr A B Hayward

I C Conn

Dr B E Grotee

A G Inglis

Date of
award of
performance
Performance
shares
period
28 Apr 2005
2005-2007
16 Feb 2006
2006-2008
06 Mar 2007
2007-2009
13 Feb 2008
2008-2010
28 Apr 2005
2005-2007
16 Feb 2006
2006-2008
06 Mar 2007
2007-2009
13 Feb 2008
2008-2010
13 Feb 2008
2008-2011d
13 Feb 2008
2008-2013d
28 Apr 2005
2005-2007
16 Feb 2006
2006-2008
06 Mar 2007
2007-2009
13 Feb 2008
2008-2010
2005-2007
8 Mar 2005
2006-2008 27 Mar 2006
06 Mar 2007
2007-2009
13 Feb 2008
2008-2010
13 Feb 2008
2008-2011d
13 Feb 2008
2008-2013d

Directors leaving the board in 2008

Dr D C Allen

Former directors

Lord Browne

J A Manzoni

2005-2007
2006-2008
2007-2009

28 Apr 2005
16 Feb 2006
06 Mar 2007

2005-2007
2006-2008
2005-2007
2006-2008

28 Apr 2005
16 Feb 2006
28 Apr 2005
16 Feb 2006

Market price
of each share
at date of award
of performance
shares
£
5.33
6.54
5.12
5.61
5.33
6.54
5.12
5.61
5.61
5.61
5.33
6.54
5.12
5.61
5.70
6.59
5.12
5.61
5.61
5.61

5.33
6.54
5.12

5.33
6.54
5.33
6.54

Share element interests
Potential maximum performance sharesb

Interests vested in 2008 and 2009

At 1 Jan
2008
436,623
383,200
706,311
–
415,832
383,200
456,748
–
–
–
501,782
470,432
491,640
–
209,000
325,750
400,243
–
–
–

436,623
383,200
456,748

2,006,767
1,761,249
436,623
383,200

Awarded
2008
–
–
–
845,319
–
–
–
578,376
133,452
133,452
–
–
–
581,748
–
–
–
578,376
133,452
133,452

At 31 Dec
2008
–
383,200
706,311
845,319
–
383,200
456,748
578,376
133,452
133,452
–
470,432
491,640
581,748
–
325,750
400,243
578,376
133,452
133,452

–
–
–

–
383,200
456,748

–
–
– 1,761,249
–
–
383,200
–

Number of
ordinary
shares
vestedc
0
66,136
–
–
0
66,136
–
–
–
–
0
80,231
–
–
0
54,994
–
–
–
–

0
34,518
–

90,232
0
0
0

Vesting
date
n/a
6 Feb 2009
–
–
n/a
6 Feb 2009
–
–
–
–
n/a
6 Feb 2009
–
–
n/a
6 Feb 2009
–
–
–
–

n/a
6 Feb 2009
–

6 Feb 2008
n/a
n/a
n/a

Market price
of each share
at vesting
£
n/a
5.08
–
–
n/a
5.08
–
–
–
–
n/a
5.08
–
–
n/a
5.08
–
–
–
–

n/a
5.08
–

5.45
n/a
n/a
n/a

aThis information has been subject to audit. Includes equivalent plans in which the individual participated prior to joining the board.

bBP’s performance is measured against the oil sector. For the 2005-2007 and subsequent awards, the performance condition is TSR measured against ExxonMobil, Shell, Total and Chevron.

Each performance period ends on 31 December of the third year.

cRepresents awards of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares awarded.

dRestricted award under share element of EDIP. As reported in the 2007 directors’ remuneration report in February 2008, the committee awarded both Mr Inglis and Mr Conn restricted shares,

as set out above.

These one-off awards will vest on the third and fifth anniversary of the award, dependent on the remuneration committee being satisfied as to their personal performance at the date of vesting.

Any unvested tranche will lapse in the event of cessation of employment with the company.

eDr Grote receives awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares.

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Directors’ remuneration report

Share optionsa

Dr A B Hayward

I C Conn

Dr B E Grotec

A G Inglis

Directors leaving the
board in 2008

Dr D C Allen

Option
type
SAYE
EXEC
EXEC
EXEC
EDIP
EDIP
SAYE
SAYE
SAYE
SAYE
EXEC
EXEC
BPA
BPA
EDIP
EDIP
EDIP
EDIP
SAYE
EXEC
EXEC
EXEC
EXEC

EXEC
EXEC
EXEC
EDIP
EDIP

At 1 Jan 2008
3,220
34,000
77,400
160,000
220,000
275,000
1,456
1,186
1,498
–
72,250
130,000
10,404
12,600
40,182
58,173
58,173
58,333
4,550
72,250
119,000
119,000
100,500

37,000
87,950
175,000
220,000
275,000

Granted
–
–
–
–
–
–
–
–
–
617
–
–
–
–
–
–
–
–
–
–
–
–
–

–
–
–
–
–

Exercised
–
–
–
–
–
–
1,456
–
–
–
–
–
–
–
40,182
–
–
–
–
–
–
–
–

At 31 Dec
2008
3,220
34,000
77,400
160,000
220,000
275,000
–
1,186
1,498
617
72,250
130,000
10,404
12,600
–
58,173
58,173
58,333
4,550
72,250
119,000
119,000
100,500

Market price
at date of
exercise

Date from
which first
exercisable

Option
Expiry date
price
01 Sep 2011 29 Feb 2012

£5.00
15 May 2003 15 May 2010

£5.99
23 Feb 2004 23 Feb 2011

£5.67
18 Feb 2005 18 Feb 2012

£5.72
17 Feb 2004 17 Feb 2010

£3.88
25 Feb 2005 25 Feb 2011

£4.22
£4.72b 01 Sep 2008 28 Feb 2009
£3.50
01 Sep 2009 28 Feb 2010
£3.86
01 Sep 2010 28 Feb 2011
£4.41
01 Sep 2011 01 Feb 2012
£4.87
23 Feb 2004 23 Feb 2011
£5.67
18 Feb 2005 18 Feb 2012
£5.72
15 Mar 2000 14 Mar 2009

$53.90
$48.94
28 Mar 2001 27 Mar 2010

$49.65 $65.58-$66.50 19 Feb 2002 19 Feb 2008

18 Feb 2003 18 Feb 2009

$48.82
17 Feb 2004 17 Feb 2010

$37.76
25 Feb 2005 25 Feb 2011

$48.53
£3.50d
01 Sep 2008 28 Feb 2009
23 Feb 2004 22 Feb 2011
£5.67
18 Feb 2005 17 Feb 2012
£5.72
17 Feb 2006 16 Feb 2013
£3.88
25 Feb 2007 24 Feb 2014
£4.22

–
–
–
–
–

37,000e
87,950e
175,000e
220,000e
275,000e

£5.99
£5.67
£5.72
£3.88
£4.22

15 May 2003 15 May 2010

23 Feb 2004 23 Feb 2011

18 Feb 2005 18 Feb 2012

17 Feb 2004 17 Feb 2010

25 Feb 2005 25 Feb 2011

The closing market prices of an ordinary share and of an ADS on 31 December 2008 were £5.26 and $46.74 respectively.

During 2008, the highest market prices were £6.50 and $76.12 respectively and the lowest market prices were £3.76 and $39.56 respectively.

BPA = BP Amoco share option plan, which applied to US executive directors prior to the adoption of the EDIP.

EDIP = Executive Directors’ Incentive Plan adopted by shareholders in April 2005 as described on page 80.

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.

SAYE = Save As You Earn employee share scheme.

aThis information has been subject to audit.

bClosing market price for information. Shares were retained when exercised.

cNumbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.

dOptions exercised on 21 January 2009 and the shares were retained by Mr Inglis. Closing market price for information on that date was £4.86.

eOn leaving the board on 31 March 2008.

BP Annual Report and Accounts 2008
Directors’ remuneration report

Service contracts
Director

Dr A B Hayward
I C Conn
Dr B E Grote
A G Inglis

Contract
date

Salary as at
31 Dec 2008
29 Jan 2003 £1,045,000
22 Jul 2004 £690,000
7 Aug 2000 $1,380,000
1 Feb 2007 £690,000

Executive director

Dr A B Hayward

Service contracts have a notice period of one year and may 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 been terminated on
the expiry of the remainder of the notice period. The service contracts
are expressed to expire at a normal retirement age of 60 (subject to
age discrimination).

Dr Grote’s contract is with BP Exploration (Alaska) Inc. He is
seconded to BP p.l.c. under a secondment agreement of 7 August 2000,
which expires on 31 March 2010. The secondment can 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 the early termination
of any of the 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, new service contracts include a provision to

allow for severance payments to be phased, when appropriate. The
committee will also consider mitigation to reduce compensation to a
departing director, when appropriate to do so.

Director leaving the board in 2008
Dr Allen left the company at the end of March 2008. He was entitled to
one year’s salary (£510,000) as compensation in accordance with his
contractual entitlement, as well as a pro rata bonus for 2008 and
continued full participation in the 2006-08 and 2007-09 share elements,
according to the normal rules of the plan.

Executive directors – external appointments
The board encourages executive directors to broaden their knowledge
and experience by taking up appointments outside the company. Each
executive director is permitted to accept one non-executive appointment,
from which they may retain any fee. External appointments are subject
to agreement by the chairman and reported to the board. Any external
appointment must not conflict with a director’s duties and commitments
to BP.

During the year, the fees received by executive directors for external
appointments were as follows:

I C Conn

Dr B E Grote

A G Inglis

Appointee
company
Tata Steel

Additional postion
held at appointee
company
Senior
Independent
Director
Senior
Independent
Director
Unilever Audit committee
member

Rolls-Royce

BAE
Systems

Chair of
Corporate
Responsibility
Committee

Total
fees
£83,000

£65,000

Unilever PLC
£33,500
Unilever NV
Z48,625
£86,754

Remuneration committee
All the members of the committee are independent non-executive
directors. Throughout the year, Dr Julius (chairman), Mr Davis, Sir Tom
McKillop and Sir Ian Prosser were members. The group chief executive
was consulted on matters relating to the other executive directors who
report to him and on matters relating to the performance of the
company; neither he nor the chairman were present when matters
affecting their own remuneration were discussed.

Tasks
The remuneration 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 these to the shareholders.

• To determine, on behalf of the board, matters of policy over which the
company has authority regarding 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 the scheme.

• To review the policies being applied by the group chief executive in
remunerating senior executives other than executive directors to
ensure alignment and proportionality.

• To recommend to the board the quantum and structure of

remuneration for the chairman.

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Directors’ remuneration report

Constitution and operation
Each member of the remuneration committee is subject to annual
re-election as a director of the company. The board considers all
committee members to be independent (see page 70).

They have no personal financial interest, other than as

shareholders, in the committee’s decisions.

The committee met six times in the period under

review. Mr Sutherland, as chairman of the board, attended all
the 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 directors’ remuneration report
and take into account the views of shareholders 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 independent adviser. Advice was also
received from Mr Jackson, the company secretary.

The committee also appoints external advisers to provide
specialist advice and services on particular remuneration matters.
The independence of the advice is subject to annual review.

In 2008, the committee continued to engage Towers Perrin as its

principal external adviser. Towers Perrin also provided limited ad hoc
remuneration and benefits advice to parts of the group, principally
changes in employee share plans and some market information on
pay structures.

Freshfields Bruckhaus Deringer LLP provided legal advice on
specific matters to the committee, as well as providing some legal advice
to the group.

Ernst & Young reviewed the calculations on the financial-based

targets that form the basis of the performance-related pay for executive
directors, that is, the annual bonus and share element awards described
on page 79, to ensure they met an independent, objective standard. They
also provided audit, audit-related and taxation services for the group.

Part 3 Non-executive directors’
remuneration

Policy
Remuneration of the chairman and the non-executive directors continues
to be set by the board. The process by which the board determines that
remuneration was reviewed during the year with the result that:
• The quantum and structure of the chairman’s remuneration would
be reviewed by the remuneration committee. The remuneration
committee would then make a recommendation to the board but
the chairman would not vote on his own remuneration; and

• The quantum and structure of non-executive director remuneration
would be reviewed by the chairman, with support and analysis
provided by the company secretary. The chairman would then make
a recommendation to the board but non-executive directors would
not vote on their own remuneration.

The above changes came into effect for the 2008 review of remuneration.

The other elements of BP’s non-executive director remuneration

policy remain unchanged:
• 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.

Fee structure
The table below shows the current fee structure for
non-executive directors:

Chairmana
Deputy chairmanb
Board member
Audit committee and SEEAC chairmanship feesc
Remuneration committee chairmanship feec
Transatlantic attendance allowance
Committee membership feed

£ thousand

Fee level
600
120
75
30
20
5
5

The chairman remains ineligible for committee chairmanship and membership fees or
transatlantic attendance allowance, but has the use of a fully maintained office for company
business, a chauffeured car and security advice.
b
The role of deputy chairman is combined with that of senior independent director. The deputy
chairman is still eligible for committee chairmanship fees and transatlantic attendance allowance
plus any committee membership fees.
c
Committee chairmen do not receive an additional membership fee for the committee they chair.
d
For members of the audit, SEEAC and remuneration committees.

BP Annual Report and Accounts 2008
Directors’ remuneration report

Remuneration of non-executive directors in 2008a

A Burgmans
Sir William Castell
C B Carroll
G Davidb
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Sir Ian Prosser
P D Sutherland

Director leaving the board in 2008
Dr W E Masseyc

aThis information has been subject to audit.

bAppointed on 11 February 2008.

cAlso received a superannuation gratuity of £23,000.

£ thousand

2008
90
108
93
100
105
90
110
95
170
600

2007
86
87
43
n/a
107
86
106
87
137
517

133

No share or share option awards were made to any non-executive
director in respect of service on the board during 2008.

Non-executive directors have letters of appointment, which
recognize that, subject to the Articles of Association, their service is at the
discretion of shareholders. All directors stand for re-election at each AGM.

Review of chairman and non-executive director remuneration
The new process for the determination of non-executive remuneration,
as described earlier, was operated during the year and recommendations
were made. However, the chairman and the non-executive directors
informed the board that, in the current economic circumstances, they
did not wish to receive any increase in remuneration for the coming
year 2009.

The board, therefore, decided after review to maintain fees for
2009 at the 2008 level set out in the fee structure table, save that the
committee membership fee would no longer be paid to members of
the nomination committee.

Superannuation gratuities
Until 2002, BP maintained a long-standing practice whereby non-
executive directors who retired from the board after at least six years’
service were eligible for consideration for a superannuation gratuity.
The board was, and continues to be, authorized to make such payments
under the company’s Articles of Association and 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

superannuation gratuities so that:
• Non-executive directors appointed to the board after 1 July 2002

would not be eligible for consideration for such a payment.

• 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 a superannuation gratuity of £23,000 during the year to
Dr Walter Massey, who retired in April 2008. This payment was in line
with the policy arrangements agreed in 2002 and outlined above.

Non-executive directors of Amoco Corporation
Non-executive directors who were formerly non-executive directors of
Amoco Corporation have residual entitlements under the Amoco Non-
Employee Directors’ Restricted Stock Plan. Directors were allocated
restricted stock in 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. The
restricted stock will vest on the retirement of the non-executive director
at the age of 70 (or earlier at the discretion of the board). Since the
merger, no further entitlements have accrued to any director under the
plan. The residual interests, as interests in a long-term incentive scheme,
are set out in the table below, in accordance with the Directors’
Remuneration Report Regulations 2002.

E B Davis, Jr

Interest in BP ADSs
at 1 Jan 2008 and
31 Dec 2008a
4,490

Date on
which director
reaches age 70b
5 Aug 2014

Director leaving the board in 2008
Dr W E Masseyc

3,346

5 April 2008

aNo awards were granted and no awards lapsed during the year. 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.
bFor 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.
cDr Massey retired from the board on 17 April 2008. He had received awards of Amoco shares
under the plan between 22 June 1993 and 28 April 1998 prior to the merger. These interests had
been converted into BP ADSs at the time of the merger. In accordance with the terms of the
plan, the board exercised its discretion over this award on 16 May 2008 and the shares vested on
that date (when the BP ADS market price was $74.57) without payment by him.

Past directors
Mr Miles (who was a non-executive director of BP until April 2006) was
appointed as a director and non-executive chairman of BP Pension
Trustees Limited in October 2006 for a term of three years. During 2008,
he received £150,000 for this role.

Dr Walter Massey (who retired as a non-executive director of BP

in April 2008) remained a member of the nomination committee during

the year to assist in the search for a successor to BP’s chairman.

Dr Massey received a total fee of £15,000 for this role in 2008.

Dr Massey was also appointed to the BP America board in April 2008 for

a term of two years. During 2008, he received US$93,500 for this role.

This directors’ remuneration report was approved by the board and

signed on its behalf by David J Jackson, company secretary, on

24 February 2009.

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Additional information
for shareholders

90 Share ownership

91 Major shareholders and related

party transactions

92 Dividends

92 Legal proceedings

93 The offer and listing

95 Memorandum and Articles

of Association

96 Exchange controls

96 Taxation

98 Documents on display

99 Purchases of equity securities by

the issuer and affiliated purchasers

100 Called-up share capital

100 Annual general meeting

100 Administration

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BP Annual Report and Accounts 2008

Additional information for shareholders

Share ownership

Directors and senior management
As at 18 February 2009, the following directors of BP p.l.c. held interests in BP ordinary shares of 25 cents each or their calculated equivalent as set
out below:

I C Conn
Dr B E Grote
Dr A B Hayward
A G Inglis
A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Sir Ian Prosser
P D Sutherland

279,937
1,261,664
527,607
255,424
10,000
–
82,500
9,000
73,185
15,000
15,000
20,000
16,301
30,906

1,815,940a
266,904c
–
2,066,316a
–
2,734,170a
1,759,435a b 266,904c
–
–
–
–
–
–
–
–
–
–

–
–
–
–
–
–
–
–
–
–

a
Performance shares awarded under the BP Executive Directors Incentive Plan. These figures represent the maximum possible vesting levels. The actual number of shares/ADSs that vest will depend on
the extent to which performance conditions have been satisfied over a three-year period.
bAlso includes 325,750 performance shares awarded under the BP Medium Term Performance Plan, which represents the maximum possible vesting level. The actual number of shares that vest will
depend on the extent to which performance conditions have been satisfied over a three-year period.
c
Restricted share award under the BP Executive Directors Incentive Plan. These shares will vest in two equal tranches after three and five years, subject to the directors’ continued service and
satisfactory performance.

As at 18 February 2009, the following directors of BP p.l.c. held options under the BP group share option schemes for ordinary shares or their
calculated equivalent as set out below:

I C Conn
Dr B E Grote
Dr A B Hayward
A G Inglis

205,551
1,186,098
769,620
410,750

There are no directors or members of senior management who own more than 1% of the ordinary shares outstanding. At 18 February 2009, all
directors and senior management as a group held interests in 4,308,712 ordinary shares or their calculated equivalent, 11,163,994 performance
shares or their calculated equivalent and 3,281,964 options for ordinary shares or their calculated equivalent under the BP group share options
schemes.

Additional details regarding the options granted and performance shares awarded can be found in the directors’ remuneration report on

pages 83 and 84.

Employee share plans
The following table shows employee share options granted.

Employee share options granted during the yeara

2008
8,063

options thousands

2007
6,004

2006
53,977

aFor the options outstanding at 31 December 2008, the exercise price ranges and weighted average remaining contractual lives are shown in Financial statements – Note 41 on page 168.

BP offers most of its employees the opportunity to acquire a
shareholding in the company through savings-related and/or matching
share plan arrangements. BP also uses long-term performance plans
(see Financial statements – Note 41 on page 168) and the granting of
share options as elements of remuneration for executive directors and
senior employees.

Shares acquired through the company’s employee share plans

rank pari passu with shares in issue and have no special rights, save as
described below. For legal and practical reasons, the rules of these plans
set out the consequences of a change of control of the company, and
generally provide for options and conditional awards to vest on an
accelerated basis.

Savings and matching plans
BP ShareSave Plan
This is a savings-related share option plan, under which employees save
on a monthly basis over a three-year or five-year period towards the
purchase of shares at a fixed price determined when the option is
granted. This 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 options are granted annually, usually in June. Participants
leaving for a qualifying reason will have six months in which to use their
savings to exercise their options on a pro rated basis.

BP Annual Report and Accounts 2008
Additional information for shareholders

BP ShareMatch plans
These are matching share plans, under which BP matches employees’
own contributions of shares up to a predetermined limit. The plans are
run in the UK and in more than 70 other countries. The UK plan is run on
a monthly basis with shares being held in trust for five years before they
can be released free of any income tax and national insurance liability.
In other countries, the plan is run on an annual basis, with shares being
held in trust for three years. The plan is operated on a cash basis in
those countries where there are regulatory restrictions preventing
the holding of BP shares. When the employee leaves BP, all shares
must be removed from trust and units under the plan operated on a
cash basis must be encashed.

Once shares have been awarded to an employee under the plan,

the employee may instruct the trustee how to vote their shares.

Local plans
In some countries, BP provides local scheme benefits, the rules and
qualifications for which vary according to local circumstances.

The above share plans are indicated as being equity-settled.

In certain countries, however, it is not possible to award shares to
employees owing to local legislation. In these instances, the award will
be settled in cash, calculated as the cash equivalent of the value to the
employee of an equity-settled plan.

Employee share ownership plans (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards
made to participants under the Executive Directors’ Incentive Plan, the
Medium-Term Performance Plan, the Long-Term Performance Plan, the
Deferred Annual Bonus Plan and the BP ShareMatch plans. The ESOPs
have waived their rights to dividends on shares held for future awards
and are funded by the group. Pending vesting, the ESOPs have
independent trustees that have the discretion in relation to the voting of
such shares. 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’ equity (see Financial
statements – Note 40 on page 166). Assets and liabilities of the ESOPs
are recognized as assets and liabilities of the group.

At 31 December 2008, the ESOPs held 29,051,082 shares (2007

6,448,838 shares and 2006 12,795,887 shares) for potential future
awards, which had a market value of $220 million (2007 $79 million and
2006 $142 million).

Pursuant to the various BP group share option schemes, the
following options for ordinary shares of the company were outstanding at
18 February 2009:

Options outstanding (shares)
323,378,846

Expiry dates
of options
2009-2016

Exercise price
per share
5.7050-11.9210

More details on share options appear in Financial statements – Note 41
on page 168.

Major shareholders and related party
transactions

Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000a
Totals

Number of
ordinary
shareholders
57,617
120,017
124,970
11,837
1,089
790
316,320

Percentage of Percentage of
total ordinary
total ordinary
share capital
shareholders
0.01
18.22
0.31
37.94
1.83
39.51
1.17
3.74
1.95
0.34
94.73
0.25
100.00
100.00

aIncludes JP Morgan Chase Bank holding 27.48% of the total ordinary issued share capital
(excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which
is shown in the table below.

31 December 2008a

Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000b
Totals

Number of
ADS holders
73,569
38,781
22,656
1,505
23
2
136,536

Percentage of

total ADS Percentage of
total ADSs
0.50
2.16
7.12
3.04
0.47
86.71
100.00

holders
53.88
28.40
16.59
1.10
0.02
0.01
100.00

aOne ADS represents six 25 cent ordinary shares.

bOne of the holders of ADSs represents some 818,000 underlying shareholders.

As at 31 December 2008, there were also 1,622 preference

shareholders. Preference shareholders represented 0.44% and ordinary

shareholders represented 99.56% of the total issued nominal share

capital of the company as at that date.

Substantial shareholdings
The disclosure of certain major interests in the share capital of the
company is governed by the Disclosure and Transparency Rules (DTR)
made by the UK Financial Services Authority. Under DTR 5, we have
received notification that Legal and General Group Plc hold 4.34% of the
voting rights of the issued share capital of the company.

Related-party transactions
Transactions between the group and its significant jointly controlled
entities and associates are summarized in Financial statements – Note 26
on page 140 and Financial statements – Note 27 on page 141. In the
ordinary course of its business, the group enters into transactions with
various organizations with which certain of its directors or executive
officers are associated. Except as described in this report, the group did
not have material transactions or transactions of an unusual nature with,
and did not make loans to, related parties in the period commencing
1 January 2008 to 18 February 2009.

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BP Annual Report and Accounts 2008
Additional information for shareholders

Dividends
BP has paid dividends on its ordinary shares in each year since 1917. In
2000 and thereafter, dividends were, and are expected to continue to be,
paid quarterly in March, June, September and December. Former Amoco
Corporation and Atlantic Richfield Company shareholders will not be able
to receive dividends, or proxy material, until they send in their Amoco
Corporation or Atlantic Richfield Company common shares for exchange.
BP currently announces dividends for ordinary shares in US

dollars and states an equivalent pounds sterling dividend. Dividends on
BP ordinary shares will be paid in pounds sterling and on BP ADSs in US
dollars. The rate of exchange used to determine the sterling amount
equivalent is the average of the forward exchange rate in London over the
five business days prior to the announcement date. The directors may

choose to declare dividends in any currency provided that a sterling
equivalent is announced, but it is not the company’s intention to
change its current policy of announcing dividends on ordinary shares
in US dollars.

The following table shows dividends announced and paid by the

company per ADS for each of the past five years. In the case of dividends
paid before 1 May 2004, the dividends shown are before the deemed
credit allowed to shareholders resident in the US under the former
income tax convention between the US and the UK and the associated
withholding tax in respect thereof equal to the amount of such credit.
(This deemed credit and associated withholding tax do not apply to
dividends paid after 30 April 2004 to shareholders resident in the US.)

March

June

September

December

Total

Dividends per American depositary share
2004

2005

2006

2007

2008

UK pence
US cents
Canadian cents
UK pence
US cents
Canadian cents
UK pence
US cents
Canadian cents
UK pence
US cents
Canadian cents
UK pence
US cents
Canadian cents

22.0
40.5
53.7
27.1
51.0
64.0
31.7
56.25
64.5
31.5
61.95
73.3
40.9
81.15
80.8

22.8
40.5
54.8
26.7
51.0
63.2
31.5
56.25
64.1
30.9
61.95
69.5
41.0
81.15
82.5

23.2
42.6
56.7
30.7
53.55
65.3
31.9
58.95
67.4
31.7
64.95
67.8
42.2
84.00
85.8

23.5
42.6
52.2
30.4
53.55
63.7
31.4
58.95
66.5
31.8
64.95
63.6
52.2
84.00
108.6

91.5
166.2
217.4
114.9
209.1
256.2
126.5
230.40
262.5
125.9
253.8
274.2
176.3
330.3
357.7

A dividend reinvestment plan is in place whereby holders of BP ordinary shares can elect to reinvest the net cash dividend in shares purchased on the
London Stock Exchange. This plan is not available to any person resident in the US or Canada or in any jurisdiction outside the UK where such an offer
requires compliance by the company with any governmental or regulatory procedures or any similar formalities. A dividend reinvestment plan is,
however, available for holders of ADSs through JPMorgan Chase Bank.

Future dividends will be dependent on future earnings, the financial condition of the group, the Risk factors set out on pages 12-14 and other

matters that may affect the business of the group set out in Financial and operating performance on page 50 and in Liquidity and capital resources on
page 58.
Legal proceedings
Save as disclosed in the following paragraphs, no member of the group is
a party to, and no property of a member of the group is subject to, any
pending legal proceedings that are significant to the group.

BP America Inc. (BP America) continues to be subject to oversight

by an independent monitor, who has authority to investigate and report
alleged violations of the US Commodity Exchange Act or US Commodity
Futures Trading Commission (CFTC) regulations and to recommend
corrective action. The appointment of the independent monitor was a
condition of the deferred prosecution agreement (DPA) entered into with
the US Department of Justice (DOJ) on 25 October 2007 relating to
allegations that BP America manipulated the price of February 2004 TET
physical propane and attempted to manipulate the price of TET propane
in April 2003 and the companion consent order with the CFTC, entered
the same day, resolving all criminal and civil enforcement matters
pending at that time concerning propane trading by BP Products North
America Inc. (BP Products). The DPA requires BP America’s and certain of
its affiliates’ continued co-operation with the US government
investigations of the trades in question, as well as other trading matters
that may arise. The DPA has a term of three years but can be extended
by two additional one-year periods, and contemplates dismissal of all
charges at the end of the term following the DOJ’s determination that BP
America has complied with the terms of the DPA. Investigations into BP’s
trading activities continue to be conducted from time to time.

Private complaints, including class actions, have also been filed against
BP Products alleging propane price manipulation. The complaints contain
allegations similar to those in the CFTC action as well as of violations of
federal and state antitrust and unfair competition laws and state
consumer protection statutes and unjust enrichment. The complaints
seek actual and punitive damages and injunctive relief. Settlement with
one group of the class actions has received preliminary approval from the
court and final approval is expected in 2009.

On 23 March 2005, an explosion and fire occurred in the

isomerization unit of BP Products’ Texas City refinery as the unit was
coming out of planned maintenance. Fifteen workers died in the incident
and many others were injured. BP Products has resolved all civil claims
arising from the incident, except for a small number of claims that remain
on appeal following dismissal in the trial court.

In March 2007, the US Chemical Safety and Hazard Investigation
Board (CSB) issued its final report on the incident. The report contained
recommendations to the Texas City refinery and to the board of the
company. In May 2007, BP responded to the CSB’s recommendations.
BP and the CSB continue to discuss BP’s responses with the objective of
the CSB agreeing to close-out its recommendations.

BP Annual Report and Accounts 2008
Additional information for shareholders

On 25 October 2007, the DOJ announced that it had entered into a
criminal plea agreement with BP Products related to the March 2005
explosion and fire. Following BP Products’ guilty plea on 4 February 2008,
pursuant to the plea agreement, to one felony violation of the risk
management planning regulations promulgated under the US federal
Clean Air Act, a series of appeals were taken by victims of the incident,
who alleged that the plea agreement did not fully take into account the
victims’ injuries. On 7 October 2008, after resolution of those appeals,
BP Products returned to court to argue for acceptance of the guilty plea.
At the plea hearing, the court advised that it would take the matter under
review and decide whether to accept or reject the plea. If the court
accepts the agreement, BP Products will pay a $50 million criminal fine
and serve three years’ probation. Compliance with a 2005 OSHA
settlement agreement and an agreed order entered into by BP Products
with the Texas Commission on Environmental Quality (TCEQ) are
conditions of probation. The TCEQ and the DOJ continue to investigate
certain matters arising from the March 2005 explosion and fire.

On 29 November 2007, BP Exploration (Alaska) Inc. (BPXA)
entered into a criminal plea agreement with the DOJ relating to leaks of
crude oil in March and August 2006. BPXA’s guilty plea, to a
misdemeanour violation of the US Federal Water Pollution Control Act,
included a term of three years’ probation. BPXA is eligible to petition the
court for termination of the probation term if it meets certain benchmarks
relating to replacement of the transit lines, upgrades to its leak detection
system and improvements to its integrity management programme. BPXA
continues to co-operate with a parallel State of Alaska civil investigation
into the March and August 2006 spills, including three separate
subpoenas issued to BPXA by the Alaska Department of Environmental
Conservation. BPXA is also engaged in discussions with the DOJ, the EPA
and the US Department of Transportation concerning a civil enforcement
action relating to the 2006 Prudhoe Bay oil transit line incidents.

Shareholder derivative lawsuits alleging breach of fiduciary duty

that were filed in US federal and state courts against the directors of the
company and others, nominally the company and certain US subsidiaries,
following the events relating to, inter alia, Prudhoe Bay, Texas City and the
trading cases, have been settled (following court approval of the
settlement terms) and the claims have been dismissed.

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 46.9%
interest (reduced during 2001 from 50% by a sale of 3.1% 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. 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 that 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 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 against Atlantic
Richfield. Atlantic Richfield is named in these lawsuits as alleged
successor to International Smelting and Refining and another company
that 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 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 of 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 nor has Atlantic Richfield been subject to a final adverse
judgment in any proceeding. 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 that the
incurrence of liability 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.

In January 2009, the TNK-BP shareholders resolved, or agreed

a process for resolving, all outstanding claims between them, including
those relating to Russian back taxes. The suit filed in Russia by a
minority shareholder in TNK-BP Holding, alleging that an agreement
by BP specialists to provide services to the TNK-BP group is invalid
and demanding repayment of sums paid to BP for such services, has
been withdrawn.

For certain information regarding environmental proceedings,

see Environment – US regional review on page 46.

The offer and listing
Markets and market prices
The primary market for BP’s ordinary shares is the London Stock
Exchange (LSE). BP’s ordinary shares are a constituent element of the
Financial Times Stock Exchange 100 Index. BP’s ordinary shares are also
traded on stock exchanges in France and Germany.

Trading of BP’s shares on the LSE is primarily through the use of

the Stock Exchange Electronic Trading Service (SETS), introduced in 1997
for the largest companies in terms of market capitalization whose
primary listing is the LSE. Under SETS, buy and sell orders at specific
prices may be sent to the exchange electronically by any firm that is a
member of the LSE, on behalf of a client or on behalf of itself acting as a
principal. The orders are then anonymously displayed in the order book.
When there is a match on a buy and a sell order, the trade is executed
and automatically reported to the LSE. Trading is continuous from
8.00 a.m. to 4.30 p.m. UK time but, in the event of a 20% movement in
the share price either way, the LSE may impose a temporary halt in the
trading of that company’s shares in the order book to allow the market to
re-establish equilibrium. Dealings in ordinary shares may also take place
between an investor and a market-maker, via a member firm, outside the
electronic order book.

In the US, the company’s securities are traded in the form of
ADSs, for which JPMorgan Chase Bank is the depositary (the Depositary)
and transfer agent. The Depositary’s principal office is 4 New York Plaza,
Floor 13, New York, NY 10004, US. Each ADS represents six ordinary
shares. ADSs are listed on the New York Stock Exchange. ADSs are
evidenced by American depositary receipts (ADRs), which may be issued
in either certificated or book entry form.

The following table sets forth for the periods indicated the highest

and lowest middle market quotations for BP’s ordinary shares for the
periods shown. These are derived from the Daily Official List of the LSE
and the highest and lowest sales prices of ADSs as reported on the New
York Stock Exchange (NYSE) composite tape.

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Ordinary shares

High

Low

High

Dollars

American
depositary
sharesa
Low

561.00
686.00
723.00
640.00
657.25

574.50
606.50
617.00
640.00
648.00
657.25
583.00
541.25
566.50

536.00
518.75
540.00
541.25
566.50
518.00

407.75
499.00
558.50
504.50
370.00

504.50
542.50
516.00
548.00
495.00
501.34
446.00
370.00
461.50

446.00
370.00
450.25
476.00
470.50
461.50

62.10
72.75
76.85
79.77
77.69

67.27
72.49
75.25
79.77
75.87
77.69
69.10
51.49
49.83

58.13
50.96
51.49
50.10
49.83
46.07

46.65
56.60
63.52
58.62
37.57

58.62
64.42
61.10
67.24
57.87
60.25
48.35
37.57
39.45

48.35
37.57
39.45
41.55
39.45
39.91

BP Annual Report and Accounts 2008
Additional information for shareholders

Year ended 31 December
2004
2005
2006
2007
2008
Year ended 31 December
2007: First quarter

Second quarter
Third quarter
Fourth quarter

2008: First quarter

Second quarter
Third quarter
Fourth quarter

2009: First quarter (to 18 February)
Month of
September 2008
October 2008
November 2008
December 2008
January 2009
February 2009 (to 18 February)

aAn ADS is equivalent to six 25 cent ordinary shares.

Market prices for the ordinary shares on the LSE and in after-hours
trading off the LSE, in each case while the NYSE is open, and the market
prices for ADSs on the NYSE are closely related due to arbitrage among
the various markets, although differences may exist from time to time
due to various factors, including UK stamp duty reserve tax.

On 18 February 2009, 864,042,084 ADSs (equivalent to

5,184,252,501 ordinary shares or some 27.51% of the total issued share
capital, excluding treasury shares) were outstanding and were held by
approximately 136,213 ADS holders. Of these, about 134,710 had
registered addresses in the US at that date. One of the registered
holders of ADSs represents some 818,000 underlying holders.

On 18 February 2009, there were approximately 317,409 holders

of record of ordinary shares. Of these holders, around 1,504 had
registered addresses in the US and held a total of some 4,236,569
ordinary shares.

Since certain of the ordinary shares and ADSs were held by

brokers and other nominees, the number of holders of record in the US
may not be representative of the number of beneficial holders or of their
country of residence.

BP Annual Report and Accounts 2008
Additional information for shareholders

Memorandum and Articles
of Association

The following summarizes certain provisions of the company’s
Memorandum and Articles of Association and applicable English law. This
summary is qualified in its entirety by reference to the UK Companies Act
and the company’s Memorandum and Articles of Association. Information
on where investors can obtain copies of the Memorandum and Articles
of Association is described under the heading ‘Documents on display’ on
page 98.

On 24 April 2003, the shareholders of BP voted at the AGM to

adopt new Articles of Association to consolidate amendments that had
been necessary to implement legislative changes since the previous
Articles of Association were adopted in 1983.

At the AGM held on 15 April 2004, shareholders approved an

amendment to the Articles of Association such that, at each AGM held
after 31 December 2004, all directors shall retire from office and may
offer themselves for re-election.

At the AGM held on 17 April 2008, shareholders voted to adopt

new Articles of Association, largely to take account of changes in UK
company law brought about by the Companies Act 2006. Further
amendments to the Articles of Association are likely to be required at
our AGM in 2010, to reflect the full implementation of the Companies
Act 2006.

Objects and purposes
BP is incorporated under the name BP p.l.c. and is registered in
England and Wales with registered number 102498. Clause 4 of BP’s
Memorandum of Association provides that its objects include the
acquisition of petroleum-bearing lands; the carrying on of refining and
dealing businesses in the petroleum, manufacturing, metallurgical or
chemicals businesses; the purchase and operation of ships and all other
vehicles and other conveyances; and the carrying on of any other
businesses calculated to benefit BP. The memorandum grants BP
a range of corporate capabilities to effect these objects.

Directors
The business and affairs of BP shall be managed by the directors.
The Articles of Association place a general prohibition on a
director voting in respect of any contract or arrangement in which he has
a material interest other than by virtue of his interest in shares in the
company. However, in the absence of some other material interest not
indicated below, a director is entitled to vote and to be counted in a
quorum for the purpose of any vote relating to a resolution concerning
the following matters:
• The giving of security or indemnity with respect to any money

lent or obligation taken by the director at the request or benefit of
the company.

• Any proposal in which he is interested concerning the underwriting of

company securities or debentures.

• Any proposal concerning any other company in which he is

interested, directly or indirectly (whether as an officer or shareholder
or otherwise) provided that he and persons connected with him are
not the holder or holders of 1% or more of the voting interest in the
shares of such company.

• Proposals concerning the modification of certain retirement benefits
schemes under which he may benefit and that have been approved
by either the UK Board of Inland Revenue or by the shareholders.

• Any proposal concerning the purchase or maintenance of any

insurance policy under which he may benefit.

The UK Companies Act requires a director of a company who is in any
way interested in a contract or proposed contract with the company to
declare the nature of his interest at a meeting of the directors of the
company. The definition of ‘interest’ includes the interests of spouses,
children, companies and trusts. The UK Companies Act also requires that
a director must avoid a situation where a director has, or could have, a
direct or indirect interest that conflicts, or possibly may conflict, with the
company’s interests. The Act allows directors of public companies to
authorize such conflicts where appropriate, if a company’s Articles
of Association so permit. BP’s Articles of Association permit the
authorization of such conflicts. The directors may exercise all the powers
of the company to borrow money, except that the amount remaining
undischarged of all moneys borrowed by the company shall not, without
approval of the shareholders, exceed the amount paid up on the share
capital plus the aggregate of the amount of the capital and revenue
reserves of the company. Variation of the borrowing power of the board
may only be effected by amending the Articles of Association.

Remuneration of non-executive directors shall be determined in

the aggregate by resolution of the shareholders. Remuneration of
executive directors is determined by the remuneration committee. This
committee is made up of non-executive directors only. There is no
requirement of share ownership for a director’s qualification.

Dividend rights; other rights to share in company profits;
capital calls
If recommended by the directors of BP, BP shareholders may, by
resolution, declare dividends but no such dividend may be declared in
excess of the amount recommended by the directors. The directors may
also pay interim dividends without obtaining shareholder approval. No
dividend may be paid other than out of profits available for distribution,
as determined under IFRS and the UK Companies Act. Dividends on
ordinary shares are payable only after payment of dividends on BP
preference shares. Any dividend unclaimed after a period of 12 years
from the date of declaration of such dividend shall be forfeited and
reverts to BP.

The directors have the power to declare and pay dividends in

any currency provided that a sterling equivalent is announced. It is not
the company’s intention to change its current policy of paying dividends
in US dollars.

Apart from shareholders’ rights to share in BP’s profits by dividend

(if any is declared), the Articles of Association provide that the directors
may set aside:
• A special reserve fund out of the balance of profits each year to make
up any deficit of cumulative dividend on the BP preference shares.
• A general reserve out of the balance of profits each year, which shall
be applicable for any purpose to which the profits of the company
may properly be applied. This may include capitalization of such sum,
pursuant to an ordinary shareholders’ resolution, and distribution to
shareholders as if it were distributed by way of a dividend on the
ordinary shares or in paying up in full unissued ordinary shares for
allotment and distribution as bonus shares.

Any such sums so deposited may be distributed in accordance with the
manner of distribution of dividends as described above.

Holders of shares are not subject to calls on capital by the
company, provided that the amounts required to be paid on issue have
been paid off. All shares are fully paid.

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BP Annual Report and Accounts 2008
Additional information for shareholders

Voting rights
The Articles of Association of the company provide that voting on
resolutions at a shareholders’ meeting will be decided on a poll other
than resolutions of a procedural nature, which may be decided on a show
of hands. If voting is on a poll, every shareholder who is present in
person or by proxy has one vote for every ordinary share held and two
votes for every £5 in nominal amount of BP preference shares held. If
voting is on a show of hands, each shareholder who is present at the
meeting in person or whose duly appointed proxy is present in person
will have one vote, regardless of the number of shares held, unless a poll
is requested. Shareholders do not have cumulative voting rights.
Holders of record of ordinary shares may appoint a proxy,
including a beneficial owner of those shares, to attend, speak and vote
on their behalf at any shareholders’ meeting.

Record holders of BP ADSs are also entitled to attend, speak and

vote at any shareholders’ meeting of BP by the appointment by the
approved depositary, JPMorgan Chase Bank, of them as proxies in
respect of the ordinary shares represented by their ADSs. Each such
proxy may also appoint a proxy. Alternatively, holders of BP ADSs are
entitled to vote by supplying their voting instructions to the depositary,
who will vote the ordinary shares represented by their ADSs in
accordance with their instructions.

Proxies may be delivered electronically.
Matters are transacted at shareholders’ meetings by the
proposing and passing of resolutions, of which there are three types:
ordinary, special or extraordinary. An annual general meeting must be
held once in every year and all other general meetings will be called
extraordinary general meetings.

An ordinary resolution requires the affirmative vote of a majority

of the votes of those persons voting at a meeting at which there is a
quorum. Special and extraordinary resolutions require the affirmative vote
of not less than three-fourths of the persons voting at a meeting at which
there is a quorum. Any AGM requires 21 days’ notice. The notice period
for an extraordinary general meeting is 14 days. With the implementation
of the EU Shareholder Rights Directive into UK law expected later this
year, reliance on this notice period of 14 days will require annual
shareholder approval, failing which, a 21-day notice period will apply.

Liquidation rights; redemption provisions
In the event of a liquidation of BP, after payment of all liabilities and
applicable deductions under UK laws and subject to the payment of
secured creditors, the holders of BP preference shares would be entitled
to the sum of (i) the capital paid up on such shares plus, (ii) accrued and
unpaid dividends and (iii) a premium equal to the higher of (a) 10% of the
capital paid up on the BP preference shares and (b) the excess of the
average market price over par value of such shares on the LSE during the
previous six months. The remaining assets (if any) would be divided pro
rata among the holders of ordinary shares.

Without prejudice to any special rights previously conferred on the

holders of any class of shares, BP may issue any share with such
preferred, deferred or other special rights, or subject to such restrictions
as the shareholders by resolution determine (or, in the absence of any
such resolutions, by determination of the directors), and may issue
shares that are to be or may be redeemed.

Variation of rights
The rights attached to any class of shares may be varied with the consent
in writing of holders of 75% of the shares of that class or on the adoption
of an extraordinary resolution passed at a separate meeting of the
holders of the shares of that class. At every such separate meeting, all of
the provisions of the Articles of Association relating to proceedings at a
general meeting apply, except that the quorum with respect to a meeting
to change the rights attached to the preference shares is 10% or more of
the shares of that class, and the quorum to change the rights attached to
the ordinary shares is one-third or more of the shares of that class.

Shareholders’ meetings and notices
Shareholders must provide BP with a postal or electronic address in the
UK in order to be entitled to receive notice of shareholders’ meetings. In
certain circumstances, BP may give notices to shareholders by
advertisement in UK newspapers. Holders of BP ADSs are entitled to
receive notices under the terms of the deposit agreement relating to BP
ADSs. The substance and timing of notices is described above under the
heading Voting Rights.

Under the Articles of Association, the AGM of shareholders will

be held within the six-month period from the first day of BP’s accounting
period. All general meetings shall be held at a time and place determined
by the directors within the UK. If any shareholders’ meeting is adjourned
for lack of quorum, notice of the time and place of the meeting may be
given in any lawful manner, including electronically. Powers exist for
action to be taken either before or at the meeting by authorized officers
to ensure its orderly conduct and safety of those attending.

Limitations on voting and shareholding
There are no limitations imposed by English law or the company’s
Memorandum or Articles of Association on the right of non-residents or
foreign persons to hold or vote the company’s ordinary shares or ADSs,
other than limitations that would generally apply to all of the shareholders.

Disclosure of interests in shares
The UK Companies Act permits a public company, on written notice, to
require any person whom the company believes to be or, at any time
during the previous three years prior to the issue of the notice, to have
been interested in its voting shares, to disclose certain information with
respect to those interests. Failure to supply the information required may
lead to disenfranchisement of the relevant shares and a prohibition on
their transfer and receipt of dividends and other payments in respect of
those shares. In this context the term ‘interest’ is widely defined and will
generally include an interest of any kind whatsoever in voting shares,
including any interest of a holder of BP ADSs.

Exchange controls
There are currently no UK foreign exchange controls or restrictions on
remittances of dividends on the ordinary shares or on the conduct of
the company’s operations.

There are no limitations, either under the laws of the UK or
under the company’s Articles of Association, restricting the right of
non-resident or foreign owners to hold or vote BP ordinary or preference
shares in the company.

Taxation
This section describes the material US federal income tax and UK
taxation consequences of owning ordinary shares or ADSs to a US holder
who holds the ordinary shares or ADSs as capital assets for tax
purposes. It does not apply, however, to members of special classes of
holders subject to special rules and holders that, directly or indirectly,
hold 10% or more of the company’s voting stock.

A US holder is any beneficial owner of ordinary shares or ADSs
that is for US federal income tax purposes (i) a citizen or resident of the
US, (ii) a US domestic corporation, (iii) an estate whose income is subject
to US federal income taxation regardless of its source, or (iv) a trust if a
US court can exercise primary supervision over the trust’s administration
and one or more US persons are authorized to control all substantial
decisions of the trust.

This section is based on the Internal Revenue Code of 1986, as

amended, its legislative history, existing and proposed regulations
thereunder, published rulings and court decisions, and the taxation laws
of the UK, all as currently in effect, as well as the income tax convention

BP Annual Report and Accounts 2008
Additional information for shareholders

between the US and the UK that entered into force on 31 March 2003
(the Treaty). These laws are subject to change, possibly on a retroactive
basis. This section is further based in part on the representations of the
Depositary and assumes that each obligation in the Deposit Agreement
and any related agreement will be performed in accordance with its terms.
For purposes of the Treaty and the estate and gift tax Convention

(the ‘Estate Tax Convention’), and for US federal income tax and UK
taxation purposes, a holder of ADRs evidencing ADSs will be treated as
the owner of the company’s ordinary shares represented by those ADRs.
Exchanges of ordinary shares for ADRs and ADRs for ordinary shares
generally will not be subject to US federal income tax or to UK taxation
other than stamp duty or stamp duty reserve tax, as described below.
Investors should consult their own tax adviser regarding the US
federal, state and local, the UK and other tax consequences of owning
and disposing of ordinary shares and ADSs in their particular
circumstances, and in particular whether they are eligible for the
benefits of the Treaty.

Taxation of dividends
UK taxation
Under current UK taxation law, no withholding tax will be deducted from
dividends paid by the company, including dividends paid to US holders.
A shareholder that is a company resident for tax purposes in the UK or
trading in the UK through a permanent establishment generally will not
be taxable in the UK on a dividend it receives from the company. A
shareholder who is an individual resident for tax purposes in the UK is
subject to UK tax but entitled to a tax credit on cash dividends paid on
ordinary shares or ADSs of the company equal to one-ninth of the
cash dividend.

US federal income taxation
A US holder is subject to US federal income taxation on the gross
amount of any dividend paid by the company out of its current or
accumulated earnings and profits (as determined for US federal income
tax purposes). Dividends paid to a non-corporate US holder in taxable
years beginning before 1 January 2011 that constitute qualified dividend
income will be taxable to the holder at a maximum tax rate of 15%,
provided that the holder has a holding period in the ordinary shares or
ADSs of more than 60 days during the 121-day period beginning 60 days
before the ex-dividend date and meets other holding period
requirements. Dividends paid by the company with respect to the
shares or ADSs will generally be qualified dividend income.

As noted above in UK taxation, a US holder will not be subject to

UK withholding tax. A US holder will include in gross income for US
federal income tax purposes the amount of the dividend actually
received from the company and the receipt of a dividend will not entitle
the US holder to a foreign tax credit.

For US federal income tax purposes, a dividend must be included

in income when the US holder, in the case of ordinary shares, or the
Depositary, in the case of ADSs, actually or constructively receives the
dividend, and will not be eligible for the dividends-received deduction
generally allowed to US corporations in respect of dividends received
from other US corporations. Dividends will be income from sources
outside the US, and generally will be ‘passive category income’ or, in
the case of certain US holders, ‘general category income,’ each of which
is treated separately for purposes of computing the allowable foreign
tax credit.

The amount of the dividend distribution on the ordinary shares or

ADSs that is paid in pounds sterling will be the US dollar value of the
pounds sterling payments made, determined at the spot pounds
sterling/US dollar rate on the date the dividend distribution is includible
in income, regardless of whether the payment is in fact converted into
US dollars. Generally, any gain or loss resulting from currency exchange
fluctuations during the period from the date the pounds sterling dividend
payment is includible in income to the date the payment is converted

into US dollars will be treated as ordinary income or loss and will not be
eligible for the 15% tax rate on qualified dividend income. The gain or
loss generally will be income or loss from sources within the US for
foreign tax credit limitation purposes.

Distributions in excess of the company’s earnings and profits,
as determined for US federal income tax purposes, will be treated as
a return of capital to the extent of the US holder’s basis in the ordinary
shares or ADSs and thereafter as capital gain, subject to taxation as
described in Taxation of capital gains – US federal income taxation.

Taxation of capital gains
UK taxation
A US holder may be liable for both UK and US tax in respect of a gain on
the disposal of ordinary shares or ADSs if the US holder is (i) a citizen of
the US resident or ordinarily resident in the UK, (ii) a US domestic
corporation resident in the UK by reason of its business being managed
or controlled in the UK or (iii) a citizen of the US or a corporation that
carries on a trade or profession or vocation in the UK through a branch or
agency or, in respect of corporations for accounting periods beginning on
or after 1 January 2003, through a permanent establishment, and that
have used, held, or acquired the ordinary shares or ADSs for the
purposes of such trade, profession or vocation of such branch, agency or
permanent establishment. However, such persons may be entitled to a
tax credit against their US federal income tax liability for the amount of
UK capital gains tax or UK corporation tax on chargeable gains (as the
case may be) that is paid in respect of such gain.

Under the Treaty, capital gains on dispositions of ordinary shares

or ADSs generally will be subject to tax only in the jurisdiction of
residence of the relevant holder as determined under both the laws of
the UK and the US and as required by the terms of the Treaty.

Under the Treaty, individuals who are residents of either the UK

or the US and who have been residents of the other jurisdiction (the US
or the UK, as the case may be) at any time during the six years
immediately preceding the relevant disposal of ordinary shares or ADSs
may be subject to tax with respect to capital gains arising from a
disposition of ordinary shares or ADSs of the company not only in the
jurisdiction of which the holder is resident at the time of the disposition
but also in the other jurisdiction.

US federal income taxation
A US holder that sells or otherwise disposes of ordinary shares or ADSs
will recognize a capital gain or loss for US federal income tax purposes
equal to the difference between the US dollar value of the amount
realized and the holder’s tax basis, determined in US dollars, in the
ordinary shares or ADSs. Capital gain of a non-corporate US holder that
is recognized in taxable years beginning before 1 January 2011 is
generally taxed at a maximum rate of 15% if the holder’s holding period
for such ordinary shares or ADSs exceeds one year. The gain or loss will
generally be income or loss from sources within the US for foreign tax
credit limitation purposes. The deductibility of capital losses is subject
to limitations.

We do not believe that ordinary shares or ADSs will be treated as

stock of a passive foreign investment company, or PFIC, for US federal
income tax purposes, but this conclusion is a factual determination that
is made annually and thus is subject to change. If we are treated as a
PFIC, unless a US holder elects to be taxed annually on a mark-to-mark
basis with respect to ordinary shares or ADSs, gain realized on the sale
or other disposition of ordinary shares or ADSs would in general not be
treated as capital gain. Instead a US holder would be treated as if he or
she had realized such gain and certain ‘excess distributions’ ratably over
the holding period for ordinary shares or ADSs and would be taxed at
the highest tax rate in effect for each such year to which the gain was
allocated, in addition to which an interest charge in respect of the tax
attributable to each such year would apply.

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BP Annual Report and Accounts 2008
Additional information for shareholders

Additional tax considerations
UK inheritance tax
The Estate Tax Convention applies to inheritance tax. ADSs held by an
individual who is domiciled for the purposes of the Estate Tax Convention
in the US and is not for the purposes of the Estate Tax Convention a
national of the UK will not be subject to UK inheritance tax on the
individual’s death or on transfer during the individual’s lifetime unless,
among other things, the ADSs are part of the business property of a
permanent establishment situated in the UK used for the performance of
independent personal services. In the exceptional case where ADSs are
subject both to inheritance tax and to US federal gift or estate tax, the
Estate Tax Convention generally provides for tax payable in the US to be
credited against tax payable in the UK or for tax paid in the UK to be
credited against tax payable in the US, based on priority rules set forth in
the Estate Tax Convention.

UK stamp duty and stamp duty reserve tax
The statements below relate to what is understood to be the current
practice of HM Revenue & Customs in the UK under existing law.

Provided that any instrument of transfer is not executed in the UK

and remains at all times outside the UK and the transfer does not relate
to any matter or thing done or to be done in the UK, no UK stamp duty is
payable on the acquisition or transfer of ADSs. Neither will an agreement
to transfer ADSs in the form of ADRs give rise to a liability to stamp duty
reserve tax.

Purchases of ordinary shares, as opposed to ADSs, through the

CREST system of paperless share transfers will be subject to stamp duty
reserve tax at 0.5%. The charge will arise as soon as there is an
agreement for the transfer of the shares (or, in the case of a conditional
agreement, when the condition is fulfilled). The stamp duty reserve tax
will apply to agreements to transfer ordinary shares even if the
agreement is made outside the UK between two non-residents.
Purchases of ordinary shares outside the CREST system are subject
either to stamp duty at a rate of £5 per £1,000 (or part, unless the stamp
duty is less than £5, when no stamp duty is charged), or stamp duty
reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are
generally the liability of the purchaser.

A subsequent transfer of ordinary shares to the Depositary’s
nominee will give rise to further stamp duty at the rate of £1.50 per £100
(or part) or stamp duty reserve tax at the rate of 1.5% of the value of the
ordinary shares at the time of the transfer.

An ADR holder electing to receive ADSs instead of a cash dividend will
be responsible for the stamp duty reserve tax due on issue of shares to
the Depositary’s nominee and calculated at the rate of 1.5% on the issue
price of the shares. It is understood that HM Revenue & Customs
practice is to calculate the issue price by reference to the total cash
receipt to which a US holder would have been entitled had the election to
receive ADSs instead of a cash dividend not been made. ADR holders
electing to receive ADSs instead of the cash dividend authorize the
Depositary to sell sufficient shares to cover this liability.

Documents on display
BP’s Annual Report and Accounts is also available online at
www.bp.com/annualreport. Shareholders may obtain a hard copy of BP’s
complete audited financial statements, free of charge, by contacting BP
Distribution Services at +44 (0)870 241 3269 or through an email request
addressed to bpdistributionservices@bp.com, or BP’s US Shareholder
Services office in Warrenville, Illinois at +1 800 638 5672 or through an
email request addressed to shareholderus@bp.com.

The company is subject to the information requirements of the US

Securities Exchange Act of 1934 applicable to foreign private issuers. In
accordance with these requirements, the company files its Annual
Report on Form 20-F and other related documents with the SEC. It is
possible to read and copy documents that have been filed with the SEC
at the SEC’s public reference room located at 100 F Street NE,
Washington, DC 20549, US. You may also call the SEC at +1 800-SEC
0330 or log on to www.sec.gov. In addition, BP’s SEC filings are available
to the public at the SEC’s website www.sec.gov. BP discloses on its
website at www.bp.com/NYSEcorporategovernancerules, and in its
Annual Report on Form 20-F (Item 16G) significant ways (if any) in which
its corporate governance practices differ from those mandated for US
companies under NYSE listing standards.

Details of some of BP’s other publications are listed on the inside

back cover.

BP Annual Report and Accounts 2008
Additional information for shareholders

Purchases of equity securities by the issuer and affiliated purchasers

The following table provides details of ordinary shares repurchased.

Total number of
shares purchased a b

$
Average price
paid per share

Total number of shares
purchased as part of
publicly announced
programmes

Maximum number of
shares that may yet
be purchased under
the programme c

2008
January
February
March
April
May
June
July
August
September
October
November
December
2009
January
February (to 18 February)

41,187,000
24,314,706
25,494,193
28,537,196
27,570,000
29,793,000
32,285,000
33,006,764
27,569,329
–
–
–

–
–

11.26
10.90
10.60
11.02
12.34
11.58
10.67
9.86
8.92
–
–
–

–
–

41,187,000
24,314,706
25,494,193
28,537,196
27,570,000
29,793,000
32,285,000
33,006,764
27,569,329
–
–
–

–
–

aAll share purchases were open market transactions.
bAll shares were repurchased for cancellation.
cAt the AGM on 17 April 2008, authorization was given to repurchase up to 1.9 billion ordinary shares in the period to the next AGM in 2009 or 16 July 2009, the latest date by which an AGM must be held.
This authorization is renewed annually at the AGM.

The following table provides details of share purchases made by ESOP trusts.

2008
January
February
March
April
May
June
July
August
September
October
November
December
2009
January
February (to 18 February)

Total number of
shares purchased

–
–
30,000,000
680
–
–
63
1,500,000
81,694
1,000,772
166
59,049

–
126

$
Average price
paid per share

Total number of shares
purchased as part of
publicly announced
programmes

Maximum number of
shares that may yet
be purchased under
the programmea

–
–
11.41
11.53
–
–
11.08
9.49
8.73
7.39
10.09
8.09

–
7.65

aNo shares were repurchased pursuant to a publicly announced plan. Transactions represent the purchase of ordinary shares by ESOP trusts to satisfy future requirements of employee share schemes.

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BP Annual Report and Accounts 2008
Additional information for shareholders

Called-up share capital

Administration

Details of the allotted, called up and fully paid share capital at
31 December 2008 are set out in Financial statements – Note 39 on
page 165.

At the AGM on 17 April 2008, authorization was given to the
directors to allot shares up to an aggregate nominal amount equal to
$1,586 million. Authority was also given to the directors to allot shares for
cash and to dispose of treasury shares, other than by way of rights issue,
up to a maximum of $238 million, without having to offer such shares to
existing shareholders. These authorities are given for the period until the
next AGM in 2009 or 16 July 2009, whichever is the earlier. These
authorities are renewed annually at the AGM.

Annual general meeting

The 2009 AGM will be held on Thursday 16 April 2009 at 11.30 a.m.
at ExCeL London, One Western Gateway, Royal Victoria Dock, London
E16 1XL. A separate notice convening the meeting is distributed to
shareholders, which includes an explanation of the items of 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
Notice of BP Annual General Meeting 2009.

If you have any queries about the administration of shareholdings, such
as change of address, change of ownership, dividend payments, the
dividend reinvestment plan or the ADS direct access plan, or to change
the way you receive your company documents (such as the Annual
Report and Accounts, Annual Review and Notice of Meeting) please
contact the BP Registrar or ADS Depositary.

UK – Registrar’s Office
The BP Registrar, Equiniti
Aspect House, Spencer Road, Lancing, West Sussex BN99 6DA
Freephone in UK 0800 701107; Tel +44 (0)121 415 7005
Textphone 0871 384 2255; Fax +44 (0)871 384 2100

Please note that any numbers quoted with the prefix 0871 will be
charged at 8p per minute from a BT landline. Other network providers’
costs may vary.

US – ADS Depositary
JPMorgan Chase Bank, N.A.
PO Box 64504, St. Paul, MN 55164-0504
Toll-free in US and Canada +1 877 638 5672; Tel +1 651 306 4383
For the hearing impaired +1 651 453 2133

By order of the board
David J Jackson
Secretary
24 February 2009

100

Financial statements

102 Consolidated financial statements

of the BP group
Statement of directors’ responsibilities in respect of the
consolidated financial statements
Independent auditor’s report to the members of BP p.l.c.
Group income statement
Group balance sheet
Group cash flow statement
Group statement of recognized income and expense

108 Notes on financial statements

1. Significant accounting policies
2. Resegmentation
3. Acquisitions
4. Non-current assets held for sale and discontinued

operations
5. Disposals
6. Segmental analysis
7. Interest and other revenues
8. Gains on sale of businesses and fixed assets
9. Production and similar taxes
10. Depreciation, depletion and amortization
11. Impairment and losses on sale of businesses and

fixed assets

12. Impairment review of goodwill
13. Distribution and administration expenses
14. Currency exchange gains and losses
15. Research and development
16. Operating leases
17. Exploration for and evaluation of oil and

natural gas resources
18. Auditor’s remuneration
19. Finance costs
20. Taxation
21. Dividends
22. Earnings per ordinary share
23. Property, plant and equipment
24. Goodwill
25. Intangible assets
26. Investments in jointly controlled entities
27. Investments in associates
28. Financial instruments and financial risk factors
29. Other investments
30. Inventories
31. Trade and other receivables
32. Cash and cash equivalents
33. Trade and other payables

102
103
104
105
106
107

108
116
117

117
118
120
126
126
127
127
128

129
132
132
132
132
133

134
134
135
136
137
138
139
139
140
141
142
148
148
148
149
149

34. Derivative financial instruments
35. Finance debt
36. Capital disclosures and analysis of changes in net debt
37. Provisions
38. Pensions and other post-retirement benefits
39. Called-up share capital
40. Capital and reserves
41. Share-based payments
42. Employee costs and numbers
43. Remuneration of directors and senior management
44. Contingent liabilities
45. Capital commitments
46. Subsidiaries, jointly controlled entities and associates
47. Oil and natural gas exploration and production activities

180 Additional information for

US reporting
48. Auditor’s remuneration for US reporting
49. Valuation and qualifying accounts
50. Computation of ratio of earnings to fixed charges

150
155
157
158
159
165
166
168
172
173
174
174
175
177

180
181
181

182 Supplementary information on oil

and natural gas

191 Parent company financial

statements of BP p.l.c.
Statement of directors’ responsibilities in respect of the
parent company financial statements
Independent auditor’s report to the members of BP p.l.c.
Company balance sheet
Company cash flow statement
Statement of total recognized gains and losses
Notes on financial statements
1. Accounting policies
2. Taxation
3. Fixed assets – investments
4. Debtors
5. Creditors
6. Pensions
7. Called-up share capital
8. Capital and reserves
9. Cash flow
10. Contingent liabilities
11. Share-based payments
12. Auditor’s remuneration
13. Directors’ remuneration

191

192
193
194
194
195
195
196
197
197
198
198
201
201
202
202
203
206
207

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Consolidated financial statements
of the BP group

Statement of directors’ responsibilities in respect of the consolidated
financial statements

The directors are responsible for preparing the Annual Report and the consolidated financial statements in accordance with applicable United Kingdom
law, International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board and IFRS as adopted by the
European Union.

The directors are required to prepare financial statements for each financial year that present fairly the financial position of the group and

the financial performance and cash flows of the group for that period. In preparing those financial statements, the directors are required to:
• Select suitable accounting policies and then apply them consistently.
• Present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information.
• Provide additional disclosure when compliance with the specific requirements of IFRS is insufficient to enable users to understand the impact

of particular transactions, other events and conditions on the group’s financial position and financial performance.

• State that the company has complied with IFRS, subject to any material departures disclosed and explained in the financial statements.
The directors are 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 financial statements comply with the Companies Act 1985 and Article 4 of the IAS Regulation. They
are also responsible for safeguarding the assets of the group and hence for taking reasonable steps for the prevention and detection of fraud and
other irregularities.

The group’s business activities, performance, position and risks are set out in this report. The financial position of the group, its cash flows,

liquidity position and borrowing facilities are detailed in Liquidity and capital resources on pages 58 to 60 and elsewhere in the notes on financial
statements. The report also includes details of the group’s risk mitigation and management. The group has considerable financial resources, and the
directors believe that the group is well placed to manage its business risks successfully despite the current uncertain economic outlook. After making
enquiries, the directors have a reasonable expectation that the group has adequate resources to continue in operational existence for the foreseeable
future. Accordingly, they continue to adopt the going concern basis in preparing the financial statements.

Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 234ZA

of the Companies Act 1985) of which the group’s auditors are unaware, and the directors have taken all the steps they ought to have taken to make
themselves aware of any relevant audit information and to establish that the group’s auditors are aware of that information.

The directors confirm that to the best of their knowledge:

• The consolidated financial statements, prepared in accordance with IFRS as issued by the International Accounting Standards Board, IFRS as

adopted by the European Union and in accordance with the provisions of the Companies Act 1985, give a true and fair view of the assets, liabilities,
financial position and profit of the group; and

• The management report, which is incorporated in the directors’ report, includes a fair review of the development and performance of the business

and the position of the group, together with a description of the principal risks and uncertainties.

102

BP Annual Report and Accounts 2008
Consolidated financial statements of the BP group

Independent auditor’s report to the members of BP p.l.c.

We have audited the consolidated financial statements of BP p.l.c. for the year ended 31 December 2008 which comprise the group income
statement, the group balance sheet, the group cash flow statement, the group statement of recognized income and expense and the related notes 1
to 47. These consolidated financial statements have been prepared under the accounting policies set out therein.

We have reported separately on the parent company financial statements of BP p.l.c. for the year ended 31 December 2008 and on the

information in the Directors’ Remuneration Report that is described as having been audited.

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 the consolidated financial statements in accordance with applicable United Kingdom
law and International Financial Reporting Standards (IFRS) as adopted by the European Union as set out in the Statement of directors’ responsibilities
in respect of the consolidated financial statements.

Our responsibility is to audit the consolidated financial statements in accordance with relevant legal and regulatory requirements and

International Standards on Auditing (UK and Ireland).

We report to you our opinion as to whether the consolidated financial statements give a true and fair view and whether the consolidated

financial statements have been properly prepared in accordance with the Companies Act 1985 and Article 4 of the IAS Regulation. We also report
to you whether in our opinion the information given in the directors’ report, including the business review, is consistent with the financial statements.

In addition we report to you if, in our opinion, we have not received all the information and explanations we require for our audit, or if

information specified by law regarding directors’ remuneration and other transactions is not disclosed.

We review whether the BP board performance report reflects the company’s compliance with the nine provisions of the 2006 Combined Code

Principles of Good Governance and Code of Best Practice 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 the Annual Report and consider whether it is consistent with the audited consolidated financial

statements. The other information comprises the Additional information for US reporting, the Supplementary information on oil and natural gas and
the BP board performance report. We consider the implications for our report if we become aware of any apparent misstatements or material
inconsistencies with the consolidated financial statements. Our responsibilities do not extend to any other information.

Basis of audit opinion
We conducted our audit in accordance with International Standards on Auditing (UK and Ireland) issued by the Auditing Practices Board. An audit
includes examination, on a test basis, of evidence relevant to the amounts and disclosures in the consolidated financial statements. It also includes
an assessment of the significant estimates and judgements made by the directors in the preparation of the consolidated financial statements, 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 consolidated financial statements 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
consolidated financial statements.

Opinion
In our opinion:
• The consolidated financial statements give a true and fair view, in accordance with IFRS as adopted by the European Union, of the state

of the group’s affairs as at 31 December 2008 and of its profit for the year then ended.

• The consolidated financial statements have been properly prepared in accordance with the Companies Act 1985 and Article 4 of the

IAS Regulation.

• The information given in the directors’ report is consistent with the consolidated financial statements.

Separate opinion in relation to IFRS as issued by the International Accounting Standards Board
As explained in Note 1 to the consolidated financial statements, the group, in addition to complying with its legal obligation to comply with IFRS as
adopted by the European Union, has also complied with IFRS as issued by the International Accounting Standards Board.

In our opinion the consolidated financial statements give a true and fair view, in accordance with IFRS as issued by the International Accounting

Standards Board, of the state of the group’s affairs as at 31 December 2008 and of its profit for the year then ended.

Ernst & Young LLP
Registered auditor
London
24 February 2009

The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not involve
consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial
statements since they were initially presented on the website.

Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

103

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Consolidated financial statements of the BP group

Group income statement

For the year ended 31 December

Sales and other operating revenues
Earnings from jointly controlled entities – after interest and tax
Earnings from associates – after interest and tax
Interest and other revenues
Total revenues
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
Fair value (gain) loss on embedded derivatives
Profit before interest and taxation from continuing operations
Finance costs
Net finance income relating to pensions and other post-retirement benefits
Profit before taxation from continuing operations
Taxation
Profit from continuing operations
Loss from Innovene operations
Profit for the year
Attributable to

BP shareholders
Minority interest

Earnings per share – cents
Profit for the year attributable to BP shareholders

Basic
Diluted

Profit from continuing operations attributable to BP shareholders

Basic
Diluted

Note

7
6
8

9
10
11
17
13
34

19
38

2008
361,143
3,023
798
736
365,700
1,353
367,053
266,982
29,183
6,526
10,985
1,733
882
15,412
111
35,239
1,547
(591)
34,283
12,617
21,666
–
21,666

21,157
509
21,666

2007
284,365
3,135
697
754
288,951
2,487
291,438
200,766
25,915
4,013
10,579
1,679
756
15,371
7
32,352
1,393
(652)
31,611
10,442
21,169
–
21,169

$ million

2006
265,906
3,553
442
701
270,602
3,714
274,316
187,183
23,793
3,621
9,128
549
1,045
14,447
(608)
35,158
986
(470)
34,642
12,331
22,311
(25)
22,286

20,845
324
21,169

22,000
286
22,286

22
22

112.59
111.56

108.76
107.84

109.84
109.00

112.59
111.56

108.76
107.84

109.97
109.12

104

BP Annual Report and Accounts 2008
Consolidated financial statements of the BP group

Group balance sheet

At 31 December

Non-current assets

Property, plant and equipment
Goodwill
Intangible assets
Investments in jointly controlled entities
Investments in associates
Other investments
Fixed assets
Loans
Other receivables
Derivative financial instruments
Prepayments
Defined benefit pension plan surpluses

Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Cash and cash equivalents

Assets classified as held for sale

Total assets
Current liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions

Liabilities directly associated with the assets classified as held for sale

Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits

Total liabilities
Net assets
Equity

Share capital
Reserves

BP shareholders’ equity
Minority interest
Total equity

P D Sutherland Chairman
Dr A B Hayward Group Chief Executive

Note

2008

23
24
25
26
27
29

31
34

30
31
34

33
34

35
20
37
38

40
40
40

103,200
9,878
10,260
23,826
4,000
855
152,019
995
710
5,054
1,338
1,738
161,854

168
16,821
29,261
8,510
3,050
377
8,197
66,384
–
66,384
228,238

33,644
8,977
6,743
15,740
3,144
1,545
69,793
–
69,793

3,080
6,271
784
17,464
16,198
12,108
10,431
66,336
136,129
92,109

5,176
86,127
91,303
806
92,109

$ million

2007

97,989
11,006
6,652
18,113
4,579
1,830
140,169
999
968
3,741
1,083
8,914
155,874

165
26,554
38,020
6,321
3,589
705
3,562
78,916
1,286
80,202
236,076

43,152
6,405
6,640
15,394
3,282
2,195
77,068

163
77,231

1,251
5,002
959
15,651
19,215
12,900
9,215
64,193
141,424
94,652

5,237
88,453
93,690
962
94,652

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BP Annual Report and Accounts 2008
Consolidated financial statements of the BP group

Group cash flow statement

For the year ended 31 December

Operating activities

Profit before taxation

Adjustments to reconcile profit before taxation to net cash provided by operating activities

Exploration expenditure written off
Depreciation, depletion and amortization
Impairment and (gain) loss on sale of businesses and fixed assets
Earnings from jointly controlled entities and associates
Dividends received from jointly controlled entities and associates
Interest receivable
Interest received
Finance costs
Interest paid
Net finance income relating to pensions and other post-retirement benefits
Share-based payments
Net operating charge for pensions and other post-retirement benefits, less

contributions and benefit payments for unfunded plans

Net charge for provisions, less payments
(Increase) decrease in inventories
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Income taxes paid
Net cash provided by operating activities
Investing activities

Capital expenditure
Acquisitions, net of cash acquired
Investment in jointly controlled entities
Investment in associates
Proceeds from disposal of fixed assets
Proceeds from disposal of businesses, net of cash disposed
Proceeds from loan repayments
Other

Net cash used in investing activities
Financing activities

Net repurchase of shares
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
Dividends paid

BP shareholders
Minority interest

Net cash used in financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year

Note

2008

2007

$ million

2006

34,283

31,611

34,642

17
10
8,11

5
5

385
10,985
380
(3,821)
3,728
(407)
385
1,547
(1,291)
(591)
459

(173)
(298)
9,010
2,439
(6,101)
(12,824)
38,095

(22,658)
(395)
(1,009)
(81)
918
11
647
(200)
(22,767)

(2,567)
7,961
(3,821)
(1,315)

(10,342)
(425)
(10,509)
(184)
4,635
3,562
8,197

347
10,579
(808)
(3,832)
2,473
(489)
500
1,393
(1,363)
(652)
420

(404)
(92)
(7,255)
5,210
(3,857)
(9,072)
24,709

(17,830)
(1,225)
(428)
(187)
1,749
2,518
192
374
(14,837)

(7,113)
8,109
(3,192)
1,494

(8,106)
(227)
(9,035)
135
972
2,590
3,562

624
9,128
(3,165)
(3,995)
4,495
(473)
500
986
(1,242)
(470)
416

(261)
340
995
3,596
(4,211)
(13,733)
28,172

(15,125)
(229)
(37)
(570)
5,963
291
189
–
(9,518)

(15,151)
3,831
(3,655)
3,873

(7,686)
(283)
(19,071)
47
(370)
2,960
2,590

106

BP Annual Report and Accounts 2008
Consolidated financial statements of the BP group

Group statement of recognized income and expense

For the year ended 31 December

Currency translation differences
Exchange gain on translation of foreign operations transferred to gain or loss on sale of

businesses and fixed assets

Actuarial (loss) gain relating to pensions and other post-retirement benefits
Available-for-sale investments marked to market
Available-for-sale investments – recycled to the income statement
Cash flow hedges marked to market
Cash flow hedges – recycled to the income statement
Cash flow hedges – recycled to the balance sheet
Tax on currency translation differences
Tax on actuarial (loss) gain relating to pensions and other post-retirement benefits
Tax on available-for-sale investments
Tax on cash flow hedges
Tax on share-based payments
Net (expense) income recognized directly in equity
Profit for the year
Total recognized income and expense for the year
Attributable to

BP shareholders
Minority interest

2008
(4,362)

–
(8,430)
(994)
526
(1,173)
45
(38)
100
2,602
50
194
(190)
(11,670)
21,666
9,996

9,562
434
9,996

2007
1,887

(147)
1,717
200
(91)
155
(74)
(40)
139
(427)
(14)
26
213
3,544
21,169
24,713

24,365
348
24,713

$ million

2006
2,025

–
2,615
561
(695)
413
(93)
(6)
(201)
(820)
108
(47)
26
3,886
22,286
26,172

25,837
335
26,172

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BP Annual Report and Accounts 2008

Notes on financial statements

1. Significant accounting policies

Authorization of financial statements and statement of compliance
with International Financial Reporting Standards
The consolidated financial statements of the BP group for the year ended
31 December 2008 were authorized for issue by the board of directors
on 24 February 2009 and the balance sheet was signed on the board’s
behalf by P D Sutherland and Dr A B Hayward. BP p.l.c. is a public limited
company incorporated and domiciled in England and Wales. The
company’s ordinary shares are traded on the London Stock Exchange.
The consolidated financial statements have been prepared in accordance
with International Financial Reporting Standards (IFRS) as issued by the
International Accounting Standards Board (IASB), IFRS as adopted by the
European Union (EU) and in accordance with the provisions of the
Companies Act 1985. IFRS as adopted by the EU differs in certain
respects from IFRS as issued by the IASB, however, the differences
have no impact on the group’s consolidated financial statements for
the years presented. The significant accounting policies of the group
are set out below.

Basis of preparation
The consolidated financial statements have been prepared in accordance
with IFRS and International Financial Reporting Interpretations
Committee (IFRIC) interpretations issued and effective for the year ended
31 December 2008, or issued and early adopted.

Standards and interpretations adopted in the year had no

significant impact on the financial statements.

Subsequent to releasing our preliminary announcement of the

fourth quarter 2008 results on 3 February 2009, an adjustment has been
made to correct for a $560 million overstatement of the deferred tax
liability in the balance sheet as at 31 December 2008 with a
corresponding adjustment to the foreign currency translation reserve in
equity. There was no impact on profit for the year.

The accounting policies that follow have been consistently applied

to all years presented.

The consolidated financial statements are presented in US dollars
and all values are rounded to the nearest million dollars ($ million), except
where otherwise indicated.

For further information regarding the key judgements and

estimates made by management in applying the group’s accounting
policies, refer to Critical accounting policies on pages 61 to 63, which
forms part of these financial statements.

Basis of consolidation
The group financial statements consolidate the financial statements
of BP p.l.c. and the entities it controls (its subsidiaries) drawn up to
31 December each year. Control comprises the power to govern the
financial and operating policies of the investee so as to obtain benefit
from its activities and is achieved through direct and indirect ownership
of voting rights; currently exercisable or convertible potential voting
rights; or by way of contractual agreement. Subsidiaries are consolidated
from the date of their acquisition, being the date on which the group
obtains control, and continue to be consolidated until the date that such
control ceases. The financial statements of subsidiaries are prepared for
the same reporting year as the parent company, using consistent
accounting policies. All intercompany balances and transactions, including
unrealized profits arising from intragroup transactions, have been
eliminated in full. Unrealized losses are eliminated unless the transaction
provides evidence of an impairment of the asset transferred. Minority
interests represent the portion of profit or loss and net assets in
subsidiaries that is not held by the group.

108

Interests in joint ventures
A joint venture is a contractual arrangement whereby two or more parties
(venturers) undertake an economic activity that is subject to joint control.
Joint control exists only when the strategic financial and operating
decisions relating to the activity require the unanimous consent of the
venturers. A jointly controlled entity is a joint venture that involves the
establishment of a company, partnership or other entity to engage in
economic activity that the group jointly controls with its fellow venturers.

The results, assets and liabilities of a jointly controlled entity are

incorporated in these financial statements using the equity method of
accounting. Under the equity method, the investment in a jointly
controlled entity is carried in the balance sheet at cost, plus post-
acquisition changes in the group’s share of net assets of the jointly
controlled entity, less distributions received and less any impairment in
value of the investment. Loans advanced to jointly controlled entities are
also included in the investment on the group balance sheet. The group
income statement reflects the group’s share of the results after tax of
the jointly controlled entity. The group statement of recognized income
and expense reflects the group’s share of any income and expense
recognized by the jointly controlled entity outside profit and loss.

Financial statements of jointly controlled entities are prepared for
the same reporting year as the group. Where necessary, adjustments are
made to those financial statements to bring the accounting policies used
into line with those of the group.

Unrealized gains on transactions between the group and its
jointly controlled entities are eliminated to the extent of the group’s
interest in the jointly controlled entities. Unrealized losses are also
eliminated unless the transaction provides evidence of an impairment
of the asset transferred.

The group assesses investments in jointly controlled entities

for impairment whenever events or changes in circumstances indicate
that the carrying value may not be recoverable. If any such indication
of impairment exists, the carrying amount of the investment is
compared with its recoverable amount, being the higher of its fair value
less costs to sell and value in use. Where the carrying amount exceeds
the recoverable amount, the investment is written down to its
recoverable amount.

The group ceases to use the equity method of accounting on the
date from which it no longer has joint control or significant influence over
the joint venture, or when the interest becomes held for sale.

Certain of the group’s activities, particularly in the Exploration and

Production segment, are conducted through joint ventures where the
venturers have a direct ownership interest in and jointly control the
assets of the venture. The income, expenses, assets and liabilities of
these jointly controlled assets are included in the consolidated financial
statements in proportion to the group’s interest.

Interests in associates
An associate is an entity over which the group is in a position to exercise
significant influence through participation in the financial and operating
policy decisions of the investee, but that is not a subsidiary or a jointly
controlled entity.

The results, assets and liabilities of an associate are incorporated

in these financial statements using the equity method of accounting
as described above for jointly controlled entities.

BP Annual Report and Accounts 2008
Notes on financial statements

1. Significant accounting policies continued

Foreign currency translation
Functional currency is the currency of the primary economic environment
in which an entity operates and is normally the currency in which the
entity primarily generates and expends cash.

In individual companies, transactions in foreign currencies are

initially recorded in the functional currency by applying the rate of
exchange ruling at the date of the transaction. Monetary assets and
liabilities denominated in foreign currencies are retranslated into the
functional currency at the rate of exchange ruling at the balance sheet
date. Any resulting exchange differences are included in the income
statement. Non-monetary assets and liabilities that are measured at
historical cost and denominated in a foreign currency are translated into
the functional currency using the rates of exchange as at the dates of the
initial transactions. Non-monetary assets and liabilities measured at fair
value in a foreign currency are translated into the functional currency
using the rate of exchange at the date the fair value was determined.

Impairment is determined by assessing the recoverable amount of
the cash-generating unit to which the goodwill relates. Where the
recoverable amount of the cash-generating unit is less than the carrying
amount, an impairment loss is recognized.

Goodwill arising on business combinations prior to 1 January

2003 is stated at the previous carrying amount under UK generally
accepted accounting practice.

Goodwill may also arise upon investments in jointly controlled

entities and associates, being the surplus of the cost of investment
over the group’s share of the net fair value of the identifiable assets. Such
goodwill is recorded within investments in jointly controlled entities
and associates, and any impairment of the goodwill is included within
the earnings from jointly controlled entities and associates.

Non-current assets held for sale
Non-current assets and disposal groups classified as held for sale
are measured at the lower of carrying amount and fair value less
costs to sell.

In the consolidated financial statements, the assets and liabilities

Non-current assets and disposal groups are classified as held

for sale if their carrying amounts will be recovered through a sale
transaction rather than through continuing use. This condition is regarded
as met only when the sale is highly probable and the asset or disposal
group is available for immediate sale in its present condition.
Management must be committed to the sale, which should be expected
to qualify for recognition as a completed sale within one year from the
date of classification.

Property, plant and equipment and intangible assets once

classified as held for sale are not depreciated.

Intangible assets
Intangible assets, other than goodwill, include expenditure on the
exploration for and evaluation of oil and natural gas resources, computer
software, patents, licences and trademarks and are stated at the amount
initially recognized, less accumulated amortization and accumulated
impairment losses.

Intangible assets acquired separately from a business are carried
initially at cost. The initial cost is the aggregate amount paid and the fair
value of any other consideration given to acquire the asset. An intangible
asset acquired as part of a business combination is measured at fair
value at the date of acquisition and is recognized separately from
goodwill if the asset is separable or arises from contractual or other legal
rights and its fair value can be measured reliably.

Intangible assets with a finite life are amortized on a straight-line

basis over their expected useful lives. For patents, licences and
trademarks, expected useful life is the shorter of the duration of the legal
agreement and economic useful life, which can range from three to 15
years. Computer software costs have a useful life of three to five years.
The expected useful lives of assets are reviewed on an
annual basis and, if necessary, changes in useful lives are accounted
for prospectively.

The carrying value of intangible assets is reviewed for impairment
whenever events or changes in circumstances indicate the carrying value
may not be recoverable.

of non-US dollar functional currency subsidiaries, jointly controlled entities
and associates, including related goodwill, are translated into US dollars at
the rate of exchange ruling at the balance sheet date. The results and cash
flows of non-US dollar functional currency subsidiaries, jointly controlled
entities and associates 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 non-US dollar functional currency
subsidiaries, jointly controlled entities and associates are translated into
US dollars are taken to a separate component of equity and reported in
the statement of recognized income and expense. Exchange gains and
losses arising on long-term intragroup foreign currency borrowings used
to finance the group’s non-US dollar investments are also taken to equity.
On disposal of a non-US dollar functional currency subsidiary, jointly
controlled entity or associate, the deferred cumulative amount recognized
in equity relating to that particular non-US dollar operation is recognized in
the income statement.

Business combinations and goodwill
Business combinations are accounted for using the purchase method of
accounting. The cost of an acquisition is measured as the cash paid and
the fair value of other assets given, equity instruments issued and
liabilities incurred or assumed at the date of exchange, plus costs directly
attributable to the acquisition. The acquired identifiable assets, liabilities
and contingent liabilities are measured at their fair values at the date of
acquisition. Any excess of the cost of acquisition over the net fair value
of the identifiable assets, liabilities and contingent liabilities acquired is
recognized as goodwill. Any deficiency of the cost of acquisition below
the fair values of the identifiable net assets acquired (i.e. discount on
acquisition) is credited to the income statement in the period of
acquisition. Where the group does not acquire 100% ownership of
the acquired company, the interest of minority shareholders is stated at
the minority’s proportion of the fair values of the assets and liabilities
recognized. Subsequently, any losses applicable to the minority
shareholders in excess of the minority interest on the group balance
sheet are allocated against the interests of the parent.

At the acquisition date, any goodwill acquired is allocated to each
of the cash-generating units expected to benefit from the combination’s
synergies. For this purpose, cash-generating units are set at one level
below a business segment.

Following initial recognition, goodwill is measured at cost less any

accumulated impairment losses. Goodwill is reviewed for impairment
annually or more frequently if events or changes in circumstances
indicate that the carrying value may be impaired.

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Notes on financial statements

1. Significant accounting policies continued

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 licence and leasehold property acquisition costs are
capitalized within intangible assets and are reviewed at each reporting
date to confirm that there is no indication that the carrying amount
exceeds the recoverable amount. This review includes confirming that
exploration drilling is still under way or firmly planned or that it has been
determined, or work is under way to determine, that the discovery is
economically viable based on a range of technical and commercial
considerations and sufficient progress is being made on establishing
development plans and timing. If no future activity is planned, the
remaining balance of the licence and property acquisition costs is written
off. Lower value licences are pooled and amortized on a straight-line
basis over the estimated period of exploration. Upon recognition of
proved reserves and internal approval for development, the relevant
expenditure is transferred to property, plant and equipment.

Exploration expenditure
Geological and geophysical exploration costs are charged against income
as incurred. Costs directly associated with an exploration well are initially
capitalized as an intangible asset until the drilling of the well is complete
and the results have been evaluated. These costs include employee
remuneration, materials and fuel used, rig costs, delay rentals and
payments made to contractors. 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, which may include the
drilling of further wells (exploration or exploratory-type stratigraphic test
wells), are likely to be capable of commercial development, the costs
continue to be carried as an asset. All such carried costs are subject to
technical, commercial and management review at least once a year 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
property, plant and equipment.

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 property, plant and equipment and is
depreciated from the commencement of production as described below
in the accounting policy for Property, plant and equipment.

Property, plant and equipment
Property, plant and equipment is stated at cost, less accumulated
depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or

construction cost, any costs directly attributable to bringing the asset
into operation, the initial estimate of any decommissioning obligation, if
any, and, for qualifying assets, borrowing costs. The purchase price or
construction cost is the aggregate amount paid and the fair value of
any other consideration given to acquire the asset. The capitalized value
of a finance lease is also included within property, plant and equipment.

110

Exchanges of assets are measured at fair value unless the exchange
transaction lacks commercial substance or the fair value of neither the
asset received nor the asset given up is reliably measurable. The cost
of the acquired asset is measured at the fair value of the asset given up,
unless the fair value of the asset received is more clearly evident. Where
fair value is not used, the cost of the acquired asset is measured at the
carrying amount of the asset given up. The gain or loss on derecognition
of the asset given up is recognized in profit or loss.

Expenditure on major maintenance refits or repairs comprises the

cost of replacement assets or parts of assets, inspection costs and
overhaul costs. Where an asset or part of an asset that was separately
depreciated is replaced and it is probable that future economic benefits
associated with the item will flow to the group, the expenditure is
capitalized and the carrying amount of the replaced asset is
derecognized. Inspection costs associated with major maintenance
programmes are capitalized and amortized over the period to the next
inspection. Overhaul costs for major maintenance programmes are
expensed as incurred. All other maintenance costs are expensed
as incurred.

Oil and natural gas properties, including related pipelines, are
depreciated using a unit-of-production method. The cost of producing
wells is amortized over proved developed reserves. Licence acquisition,
field development and future decommissioning costs are amortized over
total proved reserves. The unit-of-production rate for the amortization of
field development costs takes into account expenditures incurred to date,
together with approved future development expenditure required to
develop reserves.

Other property, plant and equipment is depreciated on a straight-

line basis over its expected useful life.

The useful lives of the group’s other property, plant and

equipment are as follows:

Land improvements
Buildings
Refineries
Petrochemicals plants
Pipelines
Service stations
Office equipment
Fixtures and fittings

15 to 25 years
20 to 50 years
20 to 30 years
20 to 30 years
10 to 50 years
15 years
3 to 7 years
5 to 15 years

The expected useful lives of property, plant and equipment are reviewed
on an annual basis and, if necessary, changes in useful lives are
accounted for prospectively.

The carrying value of property, plant and equipment is reviewed
for impairment whenever events or changes in circumstances indicate
the carrying value may not be recoverable.

An item of property, plant and equipment is derecognized upon

disposal or when no future economic benefits are expected to arise from
the continued use of the asset. Any gain or loss arising on derecognition
of the asset (calculated as the difference between the net disposal
proceeds and the carrying amount of the item) is included in the income
statement in the period the item is derecognized.

BP Annual Report and Accounts 2008
Notes on financial statements

1. Significant accounting policies continued

Impairment of intangible assets and property, plant and equipment
The group assesses assets or groups of assets for impairment whenever
events or changes in circumstances indicate that the carrying value of an
asset may not be recoverable, for example, low prices or margins for an
extended period or for oil and gas assets significant downward revisions
of estimated volumes or increases in estimated future development
expenditure. If any such indication of impairment exists, the group makes
an estimate of its recoverable amount. Individual assets are grouped for
impairment assessment purposes at the lowest level at which there are
identifiable cash flows that are largely independent of the cash flows of
other groups of assets. An asset group’s recoverable amount is the
higher of its fair value less costs to sell and its value in use. Where the
carrying amount of an asset group exceeds its recoverable amount, the
asset group is considered impaired and is written down to its recoverable
amount. In assessing value in use, the estimated future cash flows are
adjusted for the risks specific to the asset group and are discounted to
their present value using a pre-tax discount rate that reflects current
market assessments of the time value of money.

An assessment is made at each reporting date as to whether

there is any indication that previously recognized impairment losses may
no longer exist or may have decreased. If such indication exists, the
recoverable amount is estimated. A previously recognized impairment
loss is reversed only if there has been a change in the estimates used to
determine the asset’s recoverable amount since the last impairment loss
was recognized. If that is the case, the carrying amount of the asset is
increased to its recoverable amount. That increased amount cannot
exceed the carrying amount that would have been determined, net of
depreciation, had no impairment loss been recognized for the asset in
prior years. Such reversal is recognized in profit or loss. After such a
reversal, the depreciation charge is adjusted in future periods to allocate
the asset’s revised carrying amount, less any residual value, on a
systematic basis over its remaining useful life.

Financial assets
Financial assets are classified as loans and receivables; available-for-sale
financial assets; financial assets at fair value through profit or loss; or as
derivatives designated as hedging instruments in an effective hedge, as
appropriate. Financial assets include cash and cash equivalents, trade
receivables, other receivables, loans, other investments, and derivative
financial instruments. The group determines the classification of its
financial assets at initial recognition. Financial assets are recognized
initially at fair value, normally being the transaction price plus, in the case
of financial assets not at fair value through profit or loss, directly
attributable transaction costs.

The subsequent measurement of financial assets depends on

their classification, as follows:

Loans and receivables
Loans and receivables are non-derivative financial assets with fixed or
determinable payments that are not quoted in an active market. Such
assets are carried at amortized cost using the effective interest method if
the time value of money is significant. Gains and losses are recognized in
income when the loans and receivables are derecognized or impaired, as
well as through the amortization process. This category of financial
assets includes trade and other receivables.

Available-for-sale financial assets
Available-for-sale financial assets are those non-derivative financial assets
that are not classified as loans and receivables. After initial recognition,
available-for-sale financial assets are measured at fair value, with gains or
losses recognized as a separate component of equity until the
investment is derecognized or impaired.

The fair value of quoted investments is determined by reference
to bid prices at the close of business on the balance sheet date. Where
there is no active market, fair value is determined using valuation
techniques. Where fair value cannot be reliably measured, assets are
carried at cost.

Financial assets at fair value through profit or loss
Derivatives, other than those designated as effective hedging
instruments, are classified as held for trading and are included in this
category. These assets are carried on the balance sheet at fair value with
gains or losses recognized in the income statement.

Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value. The
treatment of gains and losses arising from revaluation is described
below in the accounting policy for Derivative financial instruments and
hedging activities.

Impairment of financial assets
The group assesses at each balance sheet date whether a financial
asset or group of financial assets is impaired.

Loans and receivables
If there is objective evidence that an impairment loss on loans and
receivables carried at amortized cost has been incurred, the amount
of the loss is measured as the difference between the asset’s carrying
amount and the present value of estimated future cash flows discounted
at the financial asset’s original effective interest rate. The carrying amount
of the asset is reduced, with the amount of the loss recognized in profit
or loss.

Available-for-sale financial assets
If an available-for-sale financial asset is impaired, the cumulative
gain or loss previously recognized in equity is transferred to the
income statement.

If there is objective evidence that an impairment loss on an

unquoted equity instrument that is carried at cost has been incurred,
the amount of the loss is measured as the difference between the
asset’s carrying amount and the present value of estimated future cash
flows discounted at the current market rate of return for a similar
financial asset.

Inventories
Inventories, other than inventory held for trading purposes, are stated
at the lower of cost and net realizable value. Cost is determined by the
first-in first-out method and comprises direct purchase costs, cost of
production, transportation and manufacturing expenses. Net realizable
value is determined by reference to prices existing at the balance
sheet date.

Inventories held for trading purposes are stated at fair value
less costs to sell and any changes in net realizable value are recognized in
the income statement.

Supplies are valued at cost to the group mainly using the average

method or net realizable value, whichever is the lower.

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Notes on financial statements

1. Significant accounting policies continued

Financial liabilities
Financial liabilities are classified as financial liabilities at fair value through
profit or loss; derivatives designated as hedging instruments in an
effective hedge; or as financial liabilities measured at amortized cost, as
appropriate. Financial liabilities include trade and other payables, accruals,
finance debt and derivative financial instruments. The group determines
the classification of its financial liabilities at initial recognition. The
measurement of financial liabilities depends on their classification,
as follows:

Financial liabilities at fair value through profit or loss
Derivatives, other than those designated as effective hedging
instruments, are classified as held for trading and are included in
this category. These liabilities are carried on the balance sheet at fair
value with gains or losses recognized in the income statement.

Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value, the
treatment of gains and losses arising from revaluation are described
below in the accounting policy for Derivative financial instruments
and hedging activities.

Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value. For
interest-bearing loans and borrowings this is the fair value of the
proceeds received net of issue costs associated with the borrowing.

Contracts to buy or sell a non-financial item that can be settled net in
cash or another financial instrument, or by exchanging financial
instruments, as if the contracts were financial instruments, with the
exception of contracts that were entered into and continue to be held
for the purpose of the receipt or delivery of a non-financial item in
accordance with the group’s expected purchase, sale or usage
requirements, are accounted for as financial instruments.

Gains or losses arising from changes in the fair value of
derivatives that are not designated as effective hedging instruments
are recognized in the income statement.

For the purpose of hedge accounting, hedges are classified as:

• Fair value hedges when hedging exposure to changes in the fair value

of a recognized asset or liability.

• Cash flow hedges when hedging exposure to variability in cash flows

that is either attributable to a particular risk associated with a
recognized asset or liability or a highly probable forecast transaction.

• Hedges of a net investment in a foreign operation.
At the inception of a hedge relationship the group formally designates
and documents the hedge relationship for which the group wishes to
claim hedge accounting, together with the risk management objective
and strategy for undertaking the hedge. The documentation includes
identification of the hedging instrument, the hedged item or transaction,
the nature of the risk being hedged, and how the entity will assess the
hedging instrument effectiveness in offsetting the exposure to changes
in the hedged item’s fair value or cash flows attributable to the hedged
item. Such hedges are expected at inception to be highly effective in
achieving offsetting changes in fair value or cash flows.

Hedges meeting the criteria for hedge accounting are accounted

After initial recognition, other financial liabilities are subsequently

for as follows:

measured at amortized cost using the effective interest method.
Amortized cost is calculated by taking into account any issue costs,
and any discount or premium on settlement. Gains and losses arising on
the repurchase, settlement or cancellation of liabilities are recognized
respectively in interest and other revenues and finance costs.

This category of financial liabilities includes trade and other

payables and finance debt.

Leases
Finance leases, which transfer to the group substantially all the risks and
benefits incidental to ownership of the leased item, are capitalized at the
commencement of the lease term at the fair value of the leased property
or, if lower, at the present value of the minimum lease payments. Finance
charges are allocated to each period so as to achieve a constant rate of
interest on the remaining balance of the liability and are charged directly
against income.

Capitalized leased assets are depreciated over the shorter of

the estimated useful life of the asset or the lease term.

Operating lease payments are recognized as an expense in
the income statement on a straight-line basis over the lease term.
For both finance and operating leases, contingent rents are

recognized in the income statement in the period in which they
are incurred.

Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain
exposures to fluctuations in foreign currency exchange rates, interest
rates and commodity prices as well as for trading purposes. Such
derivative financial instruments are initially recognized at fair value
on the date on which a derivative contract is entered into and are
subsequently remeasured at fair value. Derivatives are carried as
assets when the fair value is positive and as liabilities when the fair
value is negative.

Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or
loss. The change in the fair value of the hedged item attributable to the
risk being hedged is recorded as part of the carrying value of the hedged
item and is also recognized in profit or loss.

The group applies fair value hedge accounting for hedging fixed

interest rate risk on borrowings. The gain or loss relating to the effective
portion of the interest rate swap is recognized in the income statement
within finance costs, offsetting the amortization of the interest on the
underlying borrowings.

If the criteria for hedge accounting are no longer met, or if the
group revokes the designation, the adjustment to the carrying amount
of a hedged item for which the effective interest rate method is used
is amortized to profit or loss over the period to maturity.

Cash flow hedges
For cash flow hedges, the effective portion of the gain or loss on the
hedging instrument is recognized directly in equity, while the ineffective
portion is recognized in profit or loss. Amounts taken to equity are
transferred to the income statement when the hedged transaction affects
profit or loss. The gain or loss relating to the effective portion of interest
rate swaps hedging variable rate borrowings is recognized in the income
statement within finance costs.

Where the hedged item is the cost of a non-financial asset or

liability, such as a forecast transaction for the purchase of property, plant
and equipment, the amounts taken to equity are transferred to the initial
carrying amount of the non-financial asset or liability.

If the hedging instrument expires or is sold, terminated or
exercised without replacement or rollover, or if its designation as a hedge
is revoked, amounts previously recognized in equity remain in equity until
the forecast transaction occurs and are transferred to the income
statement or to the initial carrying amount of a non-financial asset or
liability as above. If a forecast transaction is no longer expected to occur,
amounts previously recognized in equity are transferred to profit or loss.

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BP Annual Report and Accounts 2008
Notes on financial statements

1. Significant accounting policies continued

Hedges of a net investment in a foreign operation
For hedges of a net investment in a foreign operation, the effective
portion of the gain or loss on the hedging instrument is recognized
directly in equity, while the ineffective portion is recognized in profit or
loss. Amounts taken to equity are transferred to the income statement
when the foreign operation is sold or partially disposed.

Embedded derivatives
Derivatives embedded in other financial instruments or other host
contracts are treated as separate derivatives when their risks and
characteristics are not closely related to those of the host contract.
Contracts are assessed for embedded derivatives when the group
becomes a party to them, including at the date of a business
combination. Embedded derivatives are measured at fair value at
each balance sheet date. Any gains or losses arising from changes in
fair value are taken directly to profit or loss.

Provisions and contingencies
Provisions are recognized when the group has a present obligation (legal
or constructive) as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the
obligation and a reliable estimate can be made of the amount of the
obligation. Where appropriate, the future cash flow estimates are adjusted
to reflect risks specific to the liability.

If the effect of the time value of money is material, provisions are

determined by discounting the expected future cash flows at a pre-tax
rate that reflects current market assessments of the time value of
money. Where discounting is used, the increase in the provision due to
the passage of time is recognized within finance costs.

A contingent liability is disclosed where the existence of an

obligation will only be confirmed by future events or where the amount
of the obligation cannot be measured reliably. Contingent assets are
not recognized, but are disclosed where an inflow of economic
benefits is probable.

Decommissioning
Liabilities for decommissioning costs are recognized when the group has
an obligation to dismantle and remove a facility or an item of plant and to
restore the site on which it is located, and when a reliable estimate of that
liability can be made. Where an obligation exists for a new facility, such as
oil and natural gas production or transportation facilities, this will be on
construction or installation. An obligation for decommissioning may also
crystallize during the period of operation of a facility through a change in
legislation or through a decision to terminate operations. The amount
recognized is the present value of the estimated future expenditure
determined in accordance with local conditions and requirements.

A corresponding item of property, plant and equipment of an

amount equivalent to the provision is also created. This is subsequently
depreciated as part of the asset.

Other than the unwinding discount on the provision, any change

in the present value of the estimated expenditure is reflected as an
adjustment to the provision and the corresponding item of property,
plant and equipment.

Environmental expenditures and 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 do not contribute to
current or future earnings are expensed.

Liabilities for environmental costs are recognized when a clean-up
is probable and the associated costs can be reliably estimated. Generally,
the timing of recognition 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.

Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave
and sick leave are accrued in the period in which the associated services
are rendered by employees of the group. Deferred bonus arrangements
that have a vesting date more than 12 months after the period end are
valued on an actuarial basis using the projected unit credit method and
amortized on a straight-line basis over the service period until the award
vests. The accounting policy for pensions and other post-retirement
benefits is described below.

Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by
reference to the fair value at the date at which equity instruments are
granted and is recognized as an expense over the vesting period, which
ends on the date on which the relevant employees become fully entitled
to the award. Fair value is determined by using an appropriate valuation
model. In valuing equity-settled transactions, no account is taken of any
vesting conditions, other than conditions linked to the price of the shares
of the company (market conditions).

No expense is recognized for awards that do not ultimately vest,
except for awards where vesting is conditional upon a market condition,
which are treated as vesting irrespective of whether or not the market
condition is satisfied, provided that all other performance conditions
are satisfied.

At each balance sheet date before vesting, the cumulative

expense is calculated, representing the extent to which the vesting
period has expired and management’s best estimate of the achievement
or otherwise of non-market conditions and the number of equity
instruments that will ultimately vest or, in the case of an instrument
subject to a market condition, be treated as vesting as described above.
The movement in cumulative expense since the previous balance sheet
date is recognized in the income statement, with a corresponding entry
in equity.

Where the terms of an equity-settled award are modified or a

new award is designated as replacing a cancelled or settled award, the
cost based on the original award terms continues to be recognized over
the original vesting period. In addition, an expense is recognized over
the remainder of the new vesting period for the incremental fair value of
any modification, based on the difference between the fair value of the
original award and the fair value of the modified award, both as measured
on the date of the modification. No reduction is recognized if this
difference is negative.

Where an equity-settled award is cancelled, it is treated as if it
had vested on the date of cancellation and any cost not yet recognized
in the income statement for the award is expensed immediately. Any
compensation paid up to the fair value of the award at the cancellation
or settlement date is deducted from equity, with any excess over fair
value being treated as an expense in the income statement.

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Notes on financial statements

1. Significant accounting policies continued

Cash-settled transactions
The cost of cash-settled transactions is measured at fair value and
recognized as an expense over the vesting period, with a corresponding
liability recognized on the balance sheet.

Pensions and other post-retirement benefits
The cost of providing benefits under the defined benefit plans is
determined separately for each plan using the projected unit credit
method, which attributes entitlement to benefits to the current period
(to determine current service cost) and to the current and prior periods
(to determine the present value of the defined benefit obligation).
Past service costs are recognized immediately when the company
becomes committed to a change in pension plan design. When a
settlement (eliminating all obligations for benefits already accrued) or
a curtailment (reducing future obligations as a result of a material
reduction in the scheme membership or a reduction in future
entitlement) occurs, the obligation and related plan assets are
remeasured using current actuarial assumptions and the resultant gain
or loss is recognized in the income statement during the period in which
the settlement or curtailment occurs.

Deferred tax liabilities are recognized for all taxable temporary
differences:
• Except where the deferred tax liability arises on goodwill that is not
tax deductible or the initial recognition of an asset or liability in a
transaction that is not a business combination and, at the time of the
transaction, affects neither the accounting profit nor taxable profit
or loss.

• In respect of taxable temporary differences associated with

investments in subsidiaries, jointly controlled entities and associates,
except where the group is able to control the timing of the reversal of
the temporary differences and it is probable that the temporary
differences will not reverse in the foreseeable future.

Deferred tax assets are recognized for all deductible temporary
differences, carry-forward of unused tax assets and unused tax losses, to
the extent that it is probable that taxable profit will be available against
which the deductible temporary differences and the carry-forward of
unused tax assets and unused tax losses can be utilized:
• Except where the deferred income tax asset relating to the

deductible temporary difference arises from the initial recognition of
an asset or liability in a transaction that is not a business combination
and, at the time of the transaction, affects neither the accounting
profit nor taxable profit or loss.

The interest element of the defined benefit cost represents the

• In respect of deductible temporary differences associated with

change in present value of scheme obligations resulting from the
passage of time, and is determined by applying the discount rate to the
opening present value of the benefit obligation, taking into account
material changes in the obligation during the year. The expected return on
plan assets is based on an assessment made at the beginning of the year
of long-term market returns on scheme assets, adjusted for the effect on
the fair value of plan assets of contributions received and benefits paid
during the year. The difference between the expected return on plan
assets and the interest cost is recognized in the income statement as
other finance income or expense.

Actuarial gains and losses are recognized in full in the group
statement of recognized income and expense in the period in which
they occur.

investments in subsidiaries, jointly controlled entities and associates,
deferred tax assets are only recognized to the extent that it is
probable that the temporary differences will reverse in the
foreseeable future and taxable profit will be available against
which the temporary differences can be utilized.

The carrying amount of deferred tax assets is reviewed at each balance
sheet date and reduced to the extent that it is no longer probable that
sufficient taxable profit will be available to allow all or part of the deferred
income tax asset to be utilized.

Deferred tax assets and liabilities are measured at the tax rates
that are expected to apply to the year when the asset is realized or the
liability is settled, based on tax rates (and tax laws) that have been
enacted or substantively enacted at the balance sheet date.

The defined benefit pension plan surplus or deficit in the balance

Tax relating to items recognized directly in equity is recognized in

sheet comprises the total for each plan of the present value of the
defined benefit obligation (using a discount rate based on high quality
corporate bonds), less the fair value of plan assets out of which the
obligations are to be settled directly. Fair value is based on market price
information and, in the case of quoted securities, is the published
bid price.

Contributions to defined contribution schemes are recognized in

the income statement in the period in which they become payable.

Corporate taxes
Income tax expense represents the sum of the tax currently payable and
deferred tax. Interest and penalties relating to tax are also included in
income tax expense.

The tax currently payable is based on the taxable profits for the

period. Taxable profit differs from net profit as reported in the income
statement because it excludes items of income or expense that are
taxable or deductible in other periods and it further excludes items that
are never taxable or deductible. The group’s liability for current tax is
calculated using tax rates that have been enacted or substantively
enacted by the balance sheet date.

Deferred tax is provided, using the liability method, on all

temporary differences at the balance sheet date between the tax
bases of assets and liabilities and their carrying amounts for financial
reporting purposes.

equity and not in the income statement.

Customs duties and sales taxes
Revenues, expenses and assets are recognized net of the amount of
customs duties or sales tax except:
• Where the customs duty or sales tax incurred on a purchase of

goods and services is not recoverable from the taxation authority,
in which case the customs duty or sales tax is recognized as part
of the cost of acquisition of the asset or as part of the expense
item as applicable.

• Receivables and payables are stated with the amount of customs

duty or sales tax included.

The net amount of sales tax recoverable from, or payable to, the taxation
authority is included as part of receivables or payables in the balance sheet.

Own equity instruments
The group’s holdings in its own equity instruments, including ordinary
shares held by Employee Share Ownership Plans (ESOPs), are classified
as ‘treasury shares’, or ‘own shares’ for the ESOPs, and are shown as
deductions from shareholders’ equity at cost. Consideration received for
the sale of such shares is also recognized in equity, with any difference
between the proceeds from sale and the original cost being taken to
the profit and loss account reserve. No gain or loss is recognized in
the income statement on the purchase, sale, issue or cancellation
of equity shares.

Revenue
Revenue arising from the sale of goods is recognized when the

114

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Notes on financial statements

1. Significant accounting policies continued

significant risks and rewards of ownership have passed to the buyer and
it can be reliably measured.

Revenue is measured at the fair value of the consideration

received or receivable and represents amounts receivable for goods
provided in the normal course of business, net of discounts, customs
duties and sales taxes.

Revenues associated with the sale of oil, natural gas, natural gas

liquids, liquefied natural gas, petroleum and chemicals products and all
other items are recognized when the title passes to the customer.
Physical exchanges are reported net, as are sales and purchases made
with a common counterparty, as part of an arrangement similar to a
physical exchange. Similarly, where the group acts as agent on behalf of a
third party to procure or market energy commodities, any associated fee
income is recognized but no purchase or sale is recorded. Additionally,
where forward sale and purchase contracts for oil, natural gas or power
have been determined to be for trading purposes, the associated sales
and purchases are reported net within sales and other operating
revenues whether or not physical delivery has occurred.

Generally, revenues from the production of oil and natural gas

properties in which the group has an interest with joint venture partners
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.

Interest income is recognized as the interest accrues (using the

effective interest rate that is the rate that exactly discounts estimated
future cash receipts through the expected life of the financial instrument)
to the net carrying amount of the financial asset.

Dividend income from investments is recognized when the

shareholders’ right to receive the payment is established.

Research
Research costs are expensed as incurred.

Finance costs
Finance costs directly attributable to the acquisition, construction or
production of qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use, are added
to the cost of those assets, until such time as the assets are substantially
ready for their intended use.

All other finance costs are recognized in the income statement in

the period in which they are incurred.

Use of estimates
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets
and liabilities as well as the disclosure of contingent assets and liabilities
at the balance sheet date and the reported amounts of revenues and
expenses during the reporting period. Actual outcomes could differ from
those estimates.

Impact of new International Financial Reporting Standards
Adopted for 2008
Standards and interpretations adopted in the year had no significant
impact on the financial statements.

Not yet adopted
The following pronouncements from the IASB will become effective
for future financial reporting periods and have not yet been adopted
by the group.

IFRS 8 ‘Operating Segments’ was issued in October 2006 and
defines operating segments as components of an entity about which
separate financial information is available and is evaluated regularly by the
chief operating decision maker in deciding how to allocate resources and
in assessing performance. The new standard sets out the required
disclosures for operating segments and is effective for annual periods
beginning on or after 1 January 2009. BP will adopt the new standard
with effect from 1 January 2009 and expects no change to its segments
that are separately reported but anticipates that its segmental analysis
will be based on non-GAAP measures as used by the chief operating
decision maker. There will be no effect on the group’s reported income or
net assets. IFRS 8 has been adopted by the EU.

In September 2007, the IASB issued Amendments to IAS 1

‘Presentation of Financial Statements’ – A Revised Presentation, which
requires separate presentation of owner and non-owner changes in equity
by introducing the statement of comprehensive income. The statement of
recognized income and expense will no longer be presented. Whenever
there is a restatement or reclassification, an additional balance sheet, as at
the beginning of the earliest period presented, will be required to be
published. The revised standard is effective for annual periods beginning
on or after 1 January 2009 and BP will adopt it from that date. There will
be no effect on the group’s reported income or net assets. IAS 1 Revised
has been adopted by the EU.

In January 2008, the IASB issued a revised version of IFRS 3

‘Business Combinations’. The revised standard still requires the purchase
method of accounting to be applied to business combinations but will
introduce some changes to existing accounting treatment. For example,
contingent consideration is measured at fair value at the date of acquisition
and subsequently remeasured to fair value with changes recognized in
profit or loss. Goodwill may be calculated based on the parent’s share of
net assets or it may include goodwill related to the minority interest. All
transaction costs are expensed. The standard is applicable to business
combinations occurring in accounting periods beginning on or after 1 July
2009 and BP plans to adopt it with effect from 1 January 2010. Assets and
liabilities arising from business combinations occurring before the date of
adoption by the group will not be restated and thus there will be no effect
on the group’s reported income or net assets on adoption. The revised
standard has not yet been adopted by the EU.

Also in January 2008, the IASB issued an amended version of IAS

27 ‘Consolidated and Separate Financial Statements’. This requires the
effects of all transactions with non-controlling interests to be recorded in
equity if there is no change in control. Such transactions will no longer
result in goodwill or gains or losses. When control is lost, any remaining
interest in the entity is remeasured to fair value and a gain or loss
recognized in profit or loss. The amendment is effective for annual
periods beginning on or after 1 July 2009 and is to be applied
retrospectively, with certain exceptions. BP plans to adopt the
amendment with effect from 1 January 2010 and has not yet completed
its evaluation of the effect of adoption. The revised standard has not yet
been adopted by the EU.

In addition, IFRIC 18 ‘Transfers of Assets from Customers’ was
issued in January 2009 and is effective prospectively from 1 July 2009.
BP has not yet completed its evaluation of the effect of adopting this
interpretation.

There are no other standards and interpretations in issue but not

yet adopted that the directors anticipate will have a material effect on the
reported income or net assets of the group.

115

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Notes on financial statements

2. Resegmentation

With effect from 1 January 2008 the organizational structure of BP has been simplified into two business segments – Exploration and Production and
Refining and Marketing. A separate business, Alternative Energy, handles BP’s low-carbon businesses and future growth options outside oil and gas,
including solar, wind, gas-fired power, hydrogen, biofuels and coal conversion.

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

(cid:129) The Gas, Power and Renewables segment ceased to report separately.
(cid:129) The natural gas liquids (NGLs), liquefied natural gas and gas and power marketing and trading businesses were transferred from the Gas, Power

and Renewables segment to the Exploration and Production segment.

(cid:129) The Alternative Energy business was transferred from the Gas, Power and Renewables segment to Other businesses and corporate.
(cid:129) The Emerging Consumers Marketing Unit was transferred from Refining and Marketing to Alternative Energy.
(cid:129) The Biofuels business was transferred from Refining and Marketing to Alternative Energy.
(cid:129) The Shipping business was transferred from Refining and Marketing to Other businesses and corporate.
As a result of the transfers identified above, Other businesses and corporate has been redefined. It now consists of the Alternative Energy business,
Shipping, the group’s aluminium asset, Treasury (which includes interest income on the group’s cash and cash equivalents) and corporate activities
worldwide.

Comparative amounts have been restated to reflect the resegmentation, as shown below.

By business – as reported

Revenues

Total revenues
Less: sales between businesses
Total third party revenues

Segment results

Profit (loss) before interest and tax

Segment assets and liabilities

Segment assets
Segment liabilities

By business – as restated

Revenues

Total revenues
Less: sales between businesses
Total third party revenues

Segment results

Profit (loss) before interest and tax

Segment assets and liabilities

Segment assets
Segment liabilities

By business – as reported

Revenues

Total revenues
Less: sales between businesses
Total third party revenues

Segment results

Exploration
and
Production

Refining
and
Marketing

Gas,
Power
and
Renewables

Other Consolidation
adjustment
and
eliminations

businesses
and
corporate

$ million

2007

Total
group

57,941
(38,803)
19,138

251,538
(2,024)
249,514

21,725
(2,436)
19,289

1,010
–
1,010

(43,263)
43,263
–

288,951
–
288,951

26,938

6,072

674

(1,128)

(204)

32,352

108,874
(23,792)

95,691
(41,053)

19,889
(13,439)

17,188
(14,940)

(6,271)
5,342

235,371
(87,882)

69,376
(32,083)
37,293

250,897
(1,914)
248,983

27,729

6,076

125,736
(37,741)

95,311
(41,409)

–
–
–

–

–
–

3,972
(1,297)
2,675

(35,294)
35,294
–

288,951
–
288,951

(1,233)

(220)

32,352

20,595
(14,074)

(6,271)
5,342

235,371
(87,882)

Exploration
and
Production

Refining
and
Marketing

Gas,
Power
and
Renewables

Other Consolidation
adjustment
and
eliminations

businesses
and
corporate

Total
group

Innovene
operations

$ million

2006

Total
continuing
operations

56,400
(36,171)
20,229

233,302
(4,076)
229,226

23,923
(4,019)
19,904

1,243
–
1,243

(44,266)
44,266
–

270,602
–
270,602

–
–
–

270,602
–
270,602

Profit (loss) before interest and tax

29,629

5,041

1,321

(1,069)

34,974

184

35,158

By business – as restated

Revenues

Total revenues
Less: sales between businesses
Total third party revenues

Segment results

71,868
(32,608)
39,260

232,833
(3,935)
228,898

Profit (loss) before interest and tax

30,953

4,919

116

–
–
–

–

3,703
(1,259)
2,444

(37,802)
37,802
–

270,602
–
270,602

–
–
–

270,602
–
270,602

(963)

34,974

184

35,158

BP Annual Report and Accounts 2008
Notes on financial statements

3. Acquisitions

Acquisitions in 2008
BP made a number of acquisitions in 2008 for a total consideration of $403 million. These business combinations were in the Exploration and
Production segment and Other businesses and corporate and the most significant was the acquisition of Whiting Clean Energy, a cogeneration power
plant. Fair value adjustments have been made on a provisional basis to the acquired assets and liabilities. Goodwill of $1 million has been recognized
on these acquisitions.

Acquisitions in 2007
BP made a number of acquisitions in 2007 for a total consideration of $1,200 million. These business combinations were predominantly in the Refining
and Marketing segment, the most significant of which was the acquisition of Chevron’s Netherlands manufacturing company, Texaco Raffiniderij Pernis
B.V. The acquisition included Chevron’s 31% minority shareholding in Nerefco, its 31% shareholding in the 22.5 MW wind farm co-located at the
refinery as well as a 22.8% shareholding in the TEAM joint venture terminal and shareholdings in two local pipelines linking the TEAM terminal to the
refinery. Fair value adjustments were made to the acquired assets and liabilities. Goodwill of $270 million arose on these acquisitions.

Acquisitions in 2006
BP made a number of acquisitions in 2006 for a total consideration of $256 million. All these business combinations were in Other businesses and
corporate. Fair value adjustments were made to the acquired assets and liabilities and goodwill of $64 million arose on these acquisitions.

4. Non-current assets held for sale and discontinued operations

Non-current assets held for sale
In December 2007, BP signed a memorandum of understanding with Husky Energy Inc. to form an integrated North American oil sands business.
The transaction was completed on 31 March 2008, with BP contributing its Toledo refinery to a US jointly controlled entity to which Husky contributed
$250 million cash and a payable of $2,588 million. The Toledo refinery assets and associated liabilities were classified as a disposal group held for sale
at 31 December 2007. No impairment loss was recognized at the time of reclassification of the Toledo disposal group as held for sale nor
at 31 December 2007. For further information see Notes 5 and 26.

The major classes of assets and liabilities of the Toledo disposal group, reported within the Refining and Marketing segment, classified as held

for sale at 31 December 2007, are set out below.

Assets

Property, plant and equipment
Goodwill
Inventories

Assets classified as held for sale
Liabilities

Current liabilities

Liabilities directly associated with assets classified as held for sale

$ million

2007

635
90
561
1,286

163
163

Discontinued operations
The sale of Innovene, BP’s olefins, derivatives and refining group, to INEOS was completed on 16 December 2005. In 2006 a loss before taxation of
$184 million was incurred which related to post-closing adjustments. These adjustments also reduced disposal proceeds by $34 million.

Financial information for the Innovene operations after group eliminations is presented below.

Loss recognized on the remeasurement to fair value less costs to sell and on disposal
Loss before taxation from Innovene operations
Tax (charge) credit

on loss before loss recognized on remeasurement to fair value less costs to sell and on disposal
on loss recognized on the remeasurement to fair value less costs to sell and on disposal

Loss from Innovene operations
Loss per share from Innovene operations – cents

Basic
Diluted

Further information is contained in Note 5.

$ million

2006
(184)
(184)

166
(7)
(25)

(0.13)
(0.12)

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BP Annual Report and Accounts 2008
Notes on financial statements

5. Disposals

Proceeds from the sale of Innovene operations
Proceeds from the sale of other businesses
Proceeds from the sale of businesses
Proceeds from disposal of fixed assets

By business

Exploration and Production
Refining and Marketing
Other businesses and corporate

2008
–
11
11
918
929

19
813
97
929

2007
–
2,518
2,518
1,749
4,267

1,280
2,953
34
4,267

$ million

2006
(34)
325
291
5,963
6,254

4,302
1,784
168
6,254

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. The group may also dispose of other assets, such as refineries, when this meets strategic objectives.

Cash received during the year from disposals amounted to $929 million (2007 $4.3 billion and 2006 $6.3 billion).
The major transactions in 2008 were the disposal of our Toledo refinery to an entity which we jointly control in the US and our continued

disposal of company-owned and company-operated retail sites in the US.

The major transactions in 2007 were the disposals of our Coryton refinery, our exploration and production and gas infrastructure business

in the Netherlands, our interest in non-core Permian assets in the US and our interest in the Entrada field in the Gulf of Mexico.

The major transactions in 2006 were the disposals of our interests in the Gulf of Mexico Shelf and our interest in the Shenzi discovery in the

Gulf of Mexico. The principal transactions for each business segment are described below.

Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. There were no significant disposals in 2008.

During 2007, the major transactions were the disposal of an exploration and production and gas infrastructure business in the Netherlands and

the divestments of our interests in non-core Permian assets in the US and in the Entrada field in the Gulf of Mexico. We also sold our interests in a
number of fields in Egypt, Canada and the US.

During 2006, the major transactions were disposals of our interests in the Gulf of Mexico Shelf, in the Shenzi discovery in the Gulf of Mexico,

in the Statfjord oil and gas field and in the Luva gas field in the North Sea. We also divested our interests in a number of onshore fields in South
Louisiana, interests in fields in the North Sea, the Gulf of Suez and Venezuela, part of an interest in Colombia and our shareholding in Enagas, the
Spanish gas transport grid operator.

Refining and Marketing
The churn of retail assets represents a significant element of the total in all three years and in particular, in 2008, our continued disposal of sites in the
US. In addition, in 2008 we contributed our Toledo refinery to a US jointly controlled entity in an exchange transaction with Husky Energy and disposed
of our interest in the Dixie Pipeline in the US, certain assets at our Acetyls plant in Hull, UK, and other interests in the UK and Europe.

During 2007, we disposed of the Coryton refinery in the UK, our interest in the West Texas Pipeline in the US, our interest in the Samsung

Petrochemical Company in South Korea and other interests in France, Brazil and Africa.

During 2006, we disposed of our interests in Zhenhai Refining and Chemicals Company in China and in Eiffage, the French-based construction

company. We also exited the retail market in the Czech Republic and disposed of our interests in a number of pipelines.

118

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Notes on financial statements

5. Disposals continued
Other businesses and corporate
In 2008, the group disposed of miscellaneous non-core assets.

There were no significant disposals in 2007. During 2006, the group disposed of miscellaneous non-core businesses and assets.

Summarized financial information for the sale of businesses is shown below.

The disposals comprise the following

Non-current assets
Current assets
Non-current liabilities
Current liabilities

Total carrying amount of net assets disposed
Recycling of foreign exchange on disposal
Costs on disposal

Profit (loss) on sale of businessesa
Total consideration
Fair value of interest received in a jointly controlled entity
Consideration received (receivable)b
Closing adjustments associated with the sale of Innovene
Proceeds from the sale of businessesc

2008

2007

$ million

2006

759
485
–
(134)
1,110
–
7
1,117
1,721
2,838
(2,838)
11
–
11

753
587
(64)
(27)
1,249
(147)
22
1,124
1,384
2,508
–
10
–
2,518

143
169
(10)
(70)
232
–
–
232
167
399
–
(74)
(34)
291

aOf which $929 million gain has not been recognized in the income statement in 2008 as it represents an unrealized gain on the transfer of the Toledo refinery into a jointly controlled entity.

bConsideration received from prior year disposals or not yet received from current year disposals.

cNet of cash and cash equivalents disposed of nil (2007 $115 million and 2006 $2 million).

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Notes on financial statements

6. Segmental analysis

The group’s primary format for segment reporting is business segments and the secondary format is geographical segments. The risks and returns of
the group’s operations are primarily determined by the nature of the different activities that the group engages in, rather than the geographical location
of these operations. This is reflected by the group’s organizational structure and internal financial reporting systems.

In 2008, BP had two reportable operating segments: Exploration and Production and Refining and Marketing. Exploration and Production’s

activities include oil and natural gas exploration, development and production (upstream activities), together with related pipeline, transportation and
processing activities (midstream activities), as well as the marketing and trading of natural gas (including LNG), power and natural gas liquids (NGLs).
The activities of Refining and Marketing include the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum
and chemicals products and related services. The group is managed on an integrated basis.

Other businesses and corporate comprises the Alternative Energy business, Shipping, the group’s aluminium asset, Treasury (which in the

segmental analysis includes all of the group’s cash, cash equivalents and associated interest income), and corporate activities worldwide.

The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues
and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on
consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred.

The group’s geographical segments are based on the location of the group’s assets. The UK and the US are significant countries of activity

for the group; the other geographical segments are groupings of countries determined by geographical location.

Sales to external customers are based on the location of the seller, which in most circumstances is not materially different from the location

of the customer. Crude oil and LNG are commodities for which there is an international market and buyers and sellers can be widely separated
geographically. The UK segment includes the UK-based international activities of Refining and Marketing.

By business

Sales and other operating revenues

Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Equity-accounted earnings
Interest and other revenues
Total revenues

Segment results

Profit (loss) before interest and taxation
Finance costs and net finance income relating to pensions

and other post-retirement benefits

Profit (loss) before taxation
Taxation
Profit (loss) for the year

Assets and liabilities
Segment assets
Current tax receivable
Total assets
Includes

Equity-accounted investments

Segment liabilities
Current tax payable

Finance debt

Deferred tax liabilities

Total liabilities

Other segment information

Capital expenditure and acquisitions

Goodwill and other intangible assets
Property, plant and equipment
Other

Total
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Losses on sale of businesses and fixed assets
Gains on sale of businesses and fixed assets

120

Exploration
and
Production

Refining
and
Marketing

Other Consolidation
adjustment
and
eliminations

businesses
and
corporate

$ million

2008

Total
group

86,170
(45,931)
40,239
3,565
167
43,971

320,039
(1,918)
318,121
131
288
318,540

4,634
(1,851)
2,783
125
281
3,189

(49,700)
49,700
–
–
–
–

361,143
–
361,143
3,821
736
365,700

37,915

(1,884)

(1,258)

466

35,239

–
37,915
–
37,915

–
(1,884)
–
(1,884)

–
(1,258)
–
(1,258)

(956)
(490)
(12,617)
(13,107)

(956)

34,283
(12,617)
21,666

136,665
–
136,665

75,329
–
75,329

19,079
–
19,079

(3,212)
377
(2,835)

227,861
377
228,238

20,131

6,622

1,073

–

27,826

(39,611)
–
–
–
(39,611)

(28,668)
–
–
–
(28,668)

(18,218)
–
–
–
(18,218)

2,914
(3,144)
(33,204)
(16,198)
(49,632)

(83,583)

(3,144)

(33,204)

(16,198)

(136,129)

4,940
14,117
3,170
22,227
8,440
1,186
155
18
34

145
4,417
2,072
6,634
2,208
159
–
297
1,258

89
959
791
1,839
337
227
–
1
61

–
–
–
–
–
–
–
–
–

5,174
19,493
6,033
30,700
10,985
1,572
155
316
1,353

BP Annual Report and Accounts 2008
Notes on financial statements

6. Segmental analysis continued

By business

Sales and other operating revenues

Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Equity-accounted earnings
Interest and other revenues
Total revenues

Segment results

Profit (loss) before interest and taxation
Finance costs and net finance income relating to pensions and

other post-retirement benefits

Profit (loss) before taxation
Taxation
Profit (loss) for the year

Assets and liabilities

Segment assets
Current tax receivable
Total assets
Includes

Exploration
and
Production

Refining
and
Marketing

Other
businesses
and
corporate

Consolidation
adjustment
and
eliminations

$ million

2007

Total
group

65,740
(32,083)
33,657
3,199
437
37,293

250,221
(1,914)
248,307
542
134
248,983

3,698
(1,297)
2,401
91
183
2,675

(35,294)
35,294
–
–
–
–

284,365
–
284,365
3,832
754
288,951

27,729

6,076

(1,233)

(220)

32,352

–
27,729
–
27,729

–
6,076
–
6,076

125,736
–
125,736

95,311
–
95,311

–
(1,233)
–
(1,233)

20,595
–
20,595

(741)
(961)
(10,442)
(11,403)

(741)
31,611
(10,442)
21,169

(6,271)
705
(5,566)

235,371
705
236,076

Equity-accounted investments

16,770

5,268

654

–

22,692

Segment liabilities
Current tax payable
Finance debt
Deferred tax liabilities
Total liabilities

Other segment information

Capital expenditure and acquisitions

Goodwill and other intangible assets
Property, plant and equipment
Other

Total
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Losses on sale of businesses and fixed assets
Gains on sale of businesses and fixed assets

(37,741)
–
–
–
(37,741)

(41,409)
–
–
–
(41,409)

(14,074)
–
–
–
(14,074)

5,342
(3,282)
(31,045)
(19,215)
(48,200)

(87,882)
(3,282)
(31,045)
(19,215)
(141,424)

2,245
11,539
423
14,207
7,856
292
237
42
954

581
4,474
440
5,495
2,421
1,186
–
313
1,464

27
874
38
939
302
83
–
–
69

–
–
–
–
–
–
–
–
–

2,853
16,887
901
20,641
10,579
1,561
237
355
2,487

121

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$ million

2006

Total
continuing
operations

265,906
–
265,906
3,995
701
270,602

Exploration
and
Production

Refining
and
Marketing

Other
businesses
and
corporate

Consolidation
adjustment
and
eliminations

Total
group

Innovene
operations

67,950
(32,608)
35,342
3,568
350
39,260

232,386
(3,935)
228,451
341
106
228,898

30,953

4,919

–
30,953
–
30,953

6,689
237
340

–
195
2,502

–
4,919
–
4,919

2,239
155
–

–
228
1,109

3,372
(1,259)
2,113
86
245
2,444

(37,802)
37,802
–
–
–
–

265,906
–
265,906
3,995
701
270,602

–
–
–
–
–
–

(963)

–
(963)
–
(963)

200
69
–

184
5
103

34,974

184

35,158

(516)
(451)
(12,172)
(12,623)

(516)
34,458
(12,172)
22,286

–
–
–

9,128
461
340

184
428
3,714

–
184
(159)
25

–
–
–

(184)
–
–

(516)
34,642
(12,331)
22,311

9,128
461
340

–
428
3,714

BP Annual Report and Accounts 2008
Notes on financial statements

6. Segmental analysis continued

By business

Sales and other operating revenues

Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Equity-accounted earnings
Interest and other revenues
Total revenues

Segment results

Profit (loss) before interest and taxation
Finance costs and net finance income relating to pensions

and other post-retirement benefits

Profit (loss) before taxation
Taxation
Profit (loss) for the year

Other segment information

Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Loss on remeasurement to fair value less costs to sell and on

disposal of Innovene operations

Losses on sale of businesses and fixed assets
Gains on sale of businesses and fixed assets

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6. Segmental analysis continued

By geographical area

Sales and other operating revenues

Segment sales and other operating revenues
Less: sales between areas
Third party sales
Equity-accounted earnings
Interest and other revenues
Total revenues

Segment results

Profit before interest and taxation
Finance costs and net finance income relating to pensions and

other post-retirement benefits

Profit before taxation
Taxation
Profit for the year

Assets and liabilities

Segment assets
Current tax receivable
Total assets
Includes

Rest of
Europe

Rest of
World

Consolidation
adjustment
and
eliminations

150,133
(68,360)
81,773
(4)
55
81,824

93,303
(11,272)
82,031
74
226
82,331

130,142
(6,778)
123,364
(14)
193
123,543

105,911
(31,936)
73,975
3,765
262
78,002

5,808

1,541

7,831

20,059

(22)
5,786
(2,867)
2,919

(316)
1,225
(576)
649

(411)
7,420
(2,336)
5,084

(207)
19,852
(6,838)
13,014

–
–
–
–
–
–

–

–
–
–
–

$ million

2008

Total

479,489
(118,346)
361,143
3,821
736
365,700

35,239

(956)

34,283
(12,617)
21,666

40,693
1
40,694

27,999
187
28,186

87,364
125
87,489

80,090
64
80,154

(8,285)
–
(8,285)

227,861
377
228,238

Equity-accounted investments

1,873

3,790

22,071

–

27,826

Segment liabilities
Current tax payable
Finance debt

Deferred tax liabilities

Total liabilities

Other segment information

Capital expenditure and acquisitions

Goodwill and other intangible assets
Property, plant and equipment
Other

Total
Depreciation, depletion and amortization
Exploration expense
Impairment losses
Impairment reversals
Losses on sale of businesses and fixed assets
Gains on sale of businesses and fixed assets

(23,767)
(438)
(22,621)
(2,031)
(48,857)

(14,319)
(399)
(201)
(862)
(15,781)

(33,099)
(881)
(7,659)
(8,916)
(50,555)

(20,683)
(1,426)
(2,723)
(4,389)
(29,221)

8,285
–
–
–
8,285

(83,583)
(3,144)
(33,204)

(16,198)

(136,129)

277
1,279
52
1,608
1,610
121
97
–
1
74

19
2,043
125
2,187
997
1
104
–
23
49

3,794
9,655
2,597
16,046
3,969
306
392
9
259
1,209

1,084
6,516
3,259
10,859
4,409
454
979
146
33
21

–
–
–
–
–
–
–
–
–
–

5,174
19,493
6,033
30,700
10,985
882
1,572
155
316
1,353

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Notes on financial statements

6. Segmental analysis continued

By geographical area

Sales and other operating revenues

Segment sales and other operating revenues
Less: sales between areas
Third party sales
Equity-accounted earnings
Interest and other revenues
Total revenues

Segment results

Profit before interest and taxation
Finance costs and net finance income relating to pensions and

other post-retirement benefits

Profit before taxation
Taxation
Profit for the year

Assets and liabilities

Segment assets
Current tax receivable
Total assets
Includes

Rest of
Europe

Rest of
World

Consolidation
adjustment
and
eliminations

109,800
(48,651)
61,149
1
222
61,372

78,366
(12,024)
66,342
55
78
66,475

105,120
(2,801)
102,319
144
142
102,605

74,462
(19,907)
54,555
3,632
312
58,499

4,613

4,164

7,439

16,136

(17)
4,596
(2,027)
2,569

(287)
3,877
(949)
2,928

(524)
6,915
(2,593)
4,322

87
16,223
(4,873)
11,350

–
–
–
–
–
–

–

–
–
–
–

$ million

2007

Total

367,748
(83,383)
284,365
3,832
754
288,951

32,352

(741)
31,611
(10,442)
21,169

53,065
3
53,068

34,658
27
34,685

81,911
468
82,379

76,504
207
76,711

(10,767)
–
(10,767)

235,371
705
236,076

Equity-accounted investments

142

1,970

1,659

18,921

–

22,692

Segment liabilities
Current tax payable
Finance debt
Deferred tax liabilities
Total liabilities

Other segment information

Capital expenditure and acquisitions

Goodwill and other intangible assets
Property, plant and equipment
Other

Total
Depreciation, depletion and amortization
Exploration expense
Impairment losses
Impairment reversals
Losses on sale of businesses and fixed assets
Gains on sale of businesses and fixed assets

(30,043)
(963)
(20,085)
(3,397)
(54,488)

(18,985)
(658)
(200)
(1,124)
(20,967)

(31,314)
(104)
(8,238)
(10,656)
(50,312)

(18,307)
(1,557)
(2,522)
(4,038)
(26,424)

10,767
–
–
–
10,767

(87,882)
(3,282)
(31,045)
(19,215)
(141,424)

453
1,141
78
1,672
2,133
46
315
–
2
893

298
2,489
253
3,040
959
–
136
–
77
655

817
6,516
154
7,487
3,558
252
723
237
233
770

1,285
6,741
416
8,442
3,929
458
387
–
43
169

–
–
–
–
–
–
–
–
–
–

2,853
16,887
901
20,641
10,579
756
1,561
237
355
2,487

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Notes on financial statements

6. Segmental analysis continued

By geographical area

Sales and other operating revenues

Segment sales and other operating revenues
Less: sales between areas
Third party sales
Equity-accounted earnings
Interest and other revenues
Total revenues

Segment results

Profit before interest and taxation from continuing operations
Finance costs and net finance income relating to pensions and

other post-retirement benefits

Profit before taxation from continuing operations
Taxation
Profit for the year from continuing operations
Profit (loss) from Innovene operations
Profit for the year

Other segment information

Depreciation, depletion and amortization
Exploration expense
Impairment losses
Impairment reversals
Loss on remeasurement to fair value less costs to sell and on

disposal of Innovene operations

Losses on sale of businesses and fixed assets
Gains on sale of businesses and fixed assets

$ million

2006

Rest of
Europe

Rest of
World

Total

105,518
(50,942)
54,576
5
258
54,839

76,768
(14,821)
61,947
13
7
61,967

99,935
(5,032)
94,903
127
107
95,137

71,547
(17,067)
54,480
3,850
329
58,659

353,768
(87,862)
265,906
3,995
701
270,602

5,897

3,282

11,164

14,815

35,158

43
5,940
(3,158)
2,782
31
2,813

2,139
20
–
176

185
12
337

(262)
3,020
(1,176)
1,844
(76)
1,768

840
–
171
–

36
96
577

(331)
10,833
(3,553)
7,280
(2)
7,278

3,459
633
114
90

(16)
217
2,530

34
14,849
(4,444)
10,405
22
10,427

(516)
34,642
(12,331)
22,311
(25)

22,286

2,690
392
176
74

(21)
103
270

9,128
1,045
461
340

184
428
3,714

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Notes on financial statements

7. Interest and other revenues

Related to financial instruments

Interest income from available-for-sale financial assets
Dividend income from available-for-sale financial assets
Interest income from loans and receivables

Not related to financial instruments

Interest from loans to equity-accounted entities
Other interest
Other income

8. Gains on sale of businesses and fixed assets

Gains on sale of businesses

Exploration and Production
Refining and Marketing
Other businesses and corporate

Gains on sale of fixed assets

Exploration and Production
Refining and Marketing
Other businesses and corporate

2008

2007

$ million

2006

32
37
163
232

115
59
330
504
736

2008

–
792
–
792

34
466
61
561
1,353

5
29
175
209

172
97
276
545
754

2007

527
850
7
1,384

427
614
62
1,103
2,487

13
32
186
231

176
62
232
470
701

$ million

2006

–
101
66
167

2,502
1,008
37
3,547
3,714

The principal transactions giving rise to these gains for each business segment are described below.

Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. There were no significant divestments during 2008.

The major divestments during 2007 that resulted in gains were the disposal of an exploration and production and gas infrastructure business

in the Netherlands and the divestments of our interests in non-core Permian assets in the US and in the Entrada field in the Gulf of Mexico.

The major divestments during 2006 that resulted in gains were the sales of our interest in the Shenzi discovery in the Gulf of Mexico in

the US, interests in the North Sea and our shareholding in Enagas.

Refining and Marketing
During 2008, the major divestments that resulted in gains were the disposal of US retail assets, the contribution of Toledo refinery to a jointly
controlled entity with Husky Energy and the disposal of our interest in the Dixie Pipeline.

During 2007, the major transactions that resulted in gains were the divestment of Coryton refinery in the UK, the interest in the West Texas

Pipeline in the US and the interest in the Samsung Petrochemical Company in South Korea.

During 2006, the major transactions that resulted in gains were the divestment of the retail business in the Czech Republic and fixed assets

including the shareholding in Zhenhai Refining and Chemicals Company in China, the shareholding in Eiffage, the French-based construction company,
and pipeline assets.

Other businesses and corporate
There were no significant disposals in 2008 and 2007.

During 2006, the group disposed of its ethylene oxide business.

Additional information on the sale of businesses and fixed assets is given in Note 5.

126

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Notes on financial statements

9. Production and similar taxes

UK
Overseas

10. Depreciation, depletion and amortization

By business
Exploration and Productiona

UK
Rest of Europe
US
Rest of World

Refining and Marketing

UKb
Rest of Europe
US
Rest of World

Other businesses and corporate

UK
Rest of Europe
US
Rest of World

By geographical area

UKb
Rest of Europe
US
Rest of World

2008
370
6,156
6,526

2007
197
3,816
4,013

2008

2007

1,168
203
3,012
4,057
8,440

288
761
825
334
2,208

154
33
132
18
337

1,698
213
2,365
3,580
7,856

278
729
1,076
338
2,421

157
17
117
11
302

1,610
997
3,969
4,409
10,985

2,133
959
3,558
3,929
10,579

$ million

2006
260
3,361
3,621

$ million

2006

1,735
225
2,336
2,393
6,689

299
603
1,047
290
2,239

105
12
76
7
200

2,139
840
3,459
2,690
9,128

aAt the end of 2006, BP adopted the US Securities and Exchange Commission (SEC) rules for estimating oil and natural gas reserves instead of the UK accounting rules contained in the Statement of
Recommended Practice ‘Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities’ (UK SORP). This change in accounting estimate had a direct impact on the
amount of depreciation, depletion and amortization (DD&A) charged in the income statement in respect of oil and natural gas properties which are depreciated on a unit-of-production basis as described
in Note 1. The change in estimate was applied prospectively, with no restatement of prior periods’ results. The group’s actual DD&A charge for 2006 was $9,128 million, whereas the charge based on UK
SORP reserves would have been $9,057 million, i.e. an increase of $71 million due to the change in reserves estimates that was used to calculate DD&A for the last three months of 2006. For 2007, it
was estimated that the DD&A charge would have increased by approximately $400 million to $500 million as a result of the change. No estimate has been made in respect of 2008. Over the life of a
field, this change has no overall effect on DD&A. The main differences between the UK SORP and SEC rules relate to the SEC requirement to use year-end prices and costs, the application of 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) within proved reserves. Consequently, reserves quantities under SEC rules differ from those that would be reported under application of the UK SORP. The change to SEC reserves in 2006
represented a simplification of the group’s reserves reporting, as only one set of reserves estimates is disclosed. In addition, the use of SEC reserves for accounting purposes makes our results more
comparable with those of our major competitors.
bUK area includes the UK-based international activities of Refining and Marketing.

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Notes on financial statements

11. Impairment and losses on sale of businesses and fixed assets

Impairment losses

Exploration and Production
Refining and Marketing
Other businesses and corporate

Impairment reversals

Exploration and Production

Loss on sale of fixed assets

Exploration and Production
Refining and Marketing
Other businesses and corporate

Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations

Innovene operations
Continuing operations

2008

2007

$ million

2006

1,186
159
227
1,572

(155)
(155)

18
297
1
316
—
1,733
—
1,733

292
1,186
83
1,561

(237)
(237)

42
313
–
355
–
1,679
–
1,679

237
155
69
461

(340)
(340)

195
228
5
428
184
733
(184)
549

Impairment
In assessing whether a write-down is required in the carrying value of a potentially impaired intangible asset, item of property, plant and equipment or
an equity-accounted investment, its carrying value is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair
value less costs to sell and value in use. Given the nature of the group’s activities, information on the fair value of an asset is usually difficult to obtain
unless negotiations with potential purchasers are taking place. Consequently, unless indicated otherwise, the recoverable amount used in assessing
the impairment charges described below is value in use. The group estimates value in use using a discounted cash flow model. The future cash flows
are adjusted for risks specific to the asset and are discounted using a pre-tax discount rate. This discount rate is derived from the group’s post-tax
weighted average cost of capital and is adjusted where applicable to take into account any specific risks relating to the country where the
cash-generating unit is located. Typically rates of 11% or 13% are used (2007 11% or 13%). The rate to be applied for each country is reassessed each
year. For impairments of available-for-sale financial assets that are quoted investments, the fair value is determined by reference to bid prices at the
close of business at the balance sheet date. Any cumulative gain or loss previously recognized in equity is transferred to the income statement.

Exploration and Production
During 2008, the Exploration and Production segment recognized impairment losses of $1,186 million. The main elements were the writing down of
our investment in Rosneft by $517 million to its fair value determined by reference to an active market, due to a significant decline
in the market value of the investment, impairment of oil and gas properties in the Gulf of Mexico of $270 million triggered by downward revisions of
reserves, an impairment of exploration assets in Vietnam of $210 million following BP’s decision to withdraw from activities in the area concerned,
impairment of oil and gas properties in Egypt of $85 million triggered by cost increases and several other individually insignificant impairment charges
amounting to $104 million.

These charges were partly offset by reversals of previously recognized impairment charges amounting to $155 million. Of this total,

$122 million resulted from a reassessment of the economics of Rhourde El Baguel in Algeria.

During 2007, the Exploration and Production segment recognized impairment losses of $292 million. The main elements were a charge of

$112 million relating to the cancellation of the DF1 project in Scotland, a $103 million partner loan write-off as a result of unsuccessful drilling in the
West Shmidt licence block in Sakhalin and a $52 million write-off of the Whitney Canyon gas plant in US Lower 48 driven by management’s decision to
abandon this facility. In addition, there were several individually insignificant impairment charges, triggered by downward reserves revisions, amounting
to $25 million in total.

These charges were largely offset by reversals of previously recognized impairment charges amounting to $237 million. Of this total,

$208 million resulted from a reassessment of the decommissioning liability for damaged platforms in the Gulf of Mexico Shelf. The remaining
$29 million related to other individually insignificant impairment reversals, resulting from favourable revisions to the estimates used in determining the
assets’ recoverable amounts.

During 2006, Exploration and Production recognized a net gain on impairment. The main element was a $340 million credit for reversals of
previously booked impairments relating to the UK North Sea, US Lower 48 and China. These reversals resulted from a positive change in the estimates
used to determine the assets’ recoverable amount since the impairment losses were recognized. This was partially offset by impairment losses
totalling $237 million. The major element was a charge of $109 million against intangible assets relating to properties in Alaska. The trigger for the
impairment test was the decision of the Alaska Department of Natural Resources to terminate the Point Thompson Unit Agreement. We are defending
our right through the appeal process. In addition, there was a charge of $100 million relating to certain North American pipeline assets. The trigger for
impairment testing was the reduction in future pipeline tariff revenues and increased ongoing operational costs. The remaining $28 million relates to
other individually insignificant impairments, the impairment tests for which were triggered by downward reserves revisions and increased tax burden.

128

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Notes on financial statements

11. Impairment and losses on sale of businesses and fixed assets continued
Refining and Marketing
During 2008, the Refining and Marketing segment recognized impairment losses on a number of assets which in total amounted to $159 million.

The main component of the 2007 impairment charge of $1,186 million arose because of a decision to sell our company-owned and company-
operated sites in the US resulting in a $610 million write-down of the carrying amount of the sites to fair value less costs to sell. Following a decision
to sell certain assets at our Acetyls plant in Hull, UK, we wrote down the carrying amount of these assets to fair value less costs to sell leading to an
impairment charge of $186 million. Changing marketing conditions led to impairments in Samsung Petrochemical Company, to fair value less costs to
sell, and in China American Petrochemical Company amounting in total to $165 million. The balance relates principally to the write-downs of assets
elsewhere in the segment portfolio.

During 2006, certain assets in our Retail and Aromatics & Acetyls businesses were written down to fair value less costs to sell.

Other businesses and corporate
During 2008, Other businesses and corporate recognized impairment losses totalling $227 million primarily related to various assets in the Alternative
Energy business.

There were no significant impairments in 2007.
The impairment charge for 2006 relates to remaining chemical assets after the sale of Innovene.

Loss on sale of fixed assets
The principal transactions that give rise to the losses for each business segment are described below.

Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. For 2006, the largest component of the loss is attributed
to the sale of properties in the Gulf of Mexico Shelf, which included increases in decommissioning liability estimates associated with the hurricane-
damaged fields that were divested during the year.

Refining and Marketing
For 2008, the principal transactions contributing to the loss were disposals of retail sites in the US and Europe.

For 2007, the principal transactions contributing to the loss were related to the decision to withdraw from the company-owned and company-

operated channel of trade in the US and retail churn. Retail churn is the overall process of acquiring and disposing of retail sites by which the group
aims to improve the quality and mix of its portfolio of service stations.

For 2006, the principal transactions contributing to the loss were retail churn.

12. Impairment review of goodwill

Goodwill at 31 December

Exploration and Production
Refining and Marketing
Other businesses and corporate

2008

4,297
5,462
119
9,878

$ million

2007

4,296
6,626
84
11,006

Goodwill acquired through business combinations has been allocated to groups of cash-generating units (cash-generating units) that are expected to
benefit from the synergies of the acquisition. For Exploration and Production, goodwill has been allocated to each geographic region, that is UK, Rest
of Europe, US and Rest of World, and for Refining and Marketing, goodwill has been allocated to the Rhine Fuels Value Chain (FVC), US West Coast
FVC, Lubricants and Other.

In assessing whether goodwill has been impaired, the carrying amount of the cash-generating unit (including goodwill) is compared with the
recoverable amount of the cash-generating unit. The recoverable amount is the higher of fair value less costs to sell and value in use. In the absence
of any information about the fair value of a cash-generating unit, the recoverable amount is deemed to be the value in use.

The group calculates the recoverable amount as the value in use using a discounted cash flow model. The future cash flows are adjusted

for risks specific to the cash-generating unit and are discounted using a pre-tax discount rate. The discount rate is derived from the group’s post-tax
weighted average cost of capital and is adjusted where applicable to take into account any specific risks relating to the country where the
cash-generating unit is located. Typically rates of 11% or 13% are used (2007 11% or 13%). The rate to be applied to each country is reassessed
each year. A discount rate of 11% has been used for all goodwill impairment calculations performed in 2008 (2007 11%).

The three-year or four-year business segment plans, which are approved on an annual basis by senior management, are the primary source

of information for the determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for
various types of refined products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step in the preparation of these
plans, various environmental assumptions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates, are
set by senior management. These environmental assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas,
other macroeconomic factors and historical trends and variability.

For the purposes of impairment testing, the group’s Brent oil price assumption is an average $49 per barrel in 2009, $59 per barrel in 2010,
$65 per barrel in 2011, $68 per barrel in 2012, $70 per barrel in 2013 and $75 per barrel in 2014 and beyond (2007 average $90 per barrel in 2008,
$86 per barrel in 2009, $84 per barrel in 2010, $84 per barrel in 2011, $84 per barrel in 2012 and $60 per barrel in 2013 and beyond). Similarly, the

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Notes on financial statements

12. Impairment review of goodwill continued
group’s assumption for Henry Hub natural gas prices is an average of $6.16/mmBtu in 2009, $7.15/mmBtu in 2010, $7.34/mmBtu in 2011,
$7.62/mmBtu in 2012, $7.60/mmBtu in 2013 and $7.50/mmBtu in 2014 and beyond (2007 average of $7.87/mmBtu in 2008, $8.33/mmBtu in 2009,
$8.26/mmBtu in 2010, $8.12/mmBtu in 2011, $8.00/mmBtu in 2012 and $7.50/mmBtu in 2013 and beyond). The prices for the first five years are
derived from forward price curves at the year-end. Prices in 2014 and beyond are determined using long-term views of global supply and demand,
building upon past experience of the industry and consistent with a number of external economic forecasts. These prices are adjusted to arrive at
appropriate consistent price assumptions for different qualities of oil and gas.

Exploration and Production
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates
of cessation of production of each producing field. Management believes that the cash flows generated over the estimated life of field is the
appropriate basis upon which to assess goodwill and individual assets for impairment, as the production profile and related cash flows can be
estimated from the company’s past experience. The date of cessation of production depends on the interaction of a number of variables, such as the
recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to
recover the hydrocarbons, the production costs, the contractual duration of the production concession and the selling price of the hydrocarbons
produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using
appropriate individual economic models and key assumptions agreed by BP’s management for the purpose. Capital expenditure and operating costs
for the first four years and expected hydrocarbon production profiles up to 2020 are derived from the business segment plan. Estimated production
quantities and cash flows up to the date of cessation of production on a field-by-field basis are developed to be consistent with this. The production
profiles used are consistent with the resource volumes approved as part of BP’s centrally-controlled process for the estimation of proved reserves and
total resources.

Consistent with prior years, the 2008 review for impairment was carried out during the fourth quarter. Detailed calculations were performed for

the US and the UK. As permitted by IAS 36, the detailed calculations performed in 2005 were used for the 2008 impairment test on the goodwill for
the Rest of World as the criteria of IAS 36 were considered to be satisfied: the excess of the recoverable amount over the carrying amount was
substantial in 2005; there had been no significant change in the assets and liabilities; and the likelihood that the recoverable amount would be less than
the carrying amount at the time of the test was remote.

The following table shows the carrying amount of the goodwill allocated to each of the regions of the Exploration and Production segment and,
for the US and the UK, the amount by which the recoverable amount (value in use) exceeds the carrying amount of the goodwill and other non-current
assets in the cash-generating units to which the goodwill has been allocated. No impairment charge is required.

The key assumptions required for the value-in-use estimation are the oil and natural gas prices, production volumes and the discount rate.

To test the sensitivity of the excess of the recoverable amount over the carrying amount of goodwill and other non-current assets (the headroom) to
changes in production volumes and oil and natural gas prices, management has developed ‘rules of thumb’ for key assumptions. Applying these gives
an indication of the impact on the headroom of possible changes in the key assumptions.

It is estimated that the long-term price of oil that would cause the total recoverable amount to be equal to the total carrying amount for each

cash-generating unit would be of the order of $38 per barrel for the UK and $50 per barrel for the US. It was estimated that the long-term price of gas
that would cause the total recoverable amount to be equal to the total carrying amount of goodwill and related non-current assets for the US
cash-generating unit would be of the order of $4/mmBtu (Henry Hub). As a significant amount of gas from the North Sea is sold under fixed-price
contracts, or contracts priced using non-gas indices, it is estimated that no reasonably possible change in gas prices would cause the UK headroom to
be reduced to zero. It was estimated that no reasonably possible change in oil and gas prices would cause the headroom in Rest of World to be
reduced to zero.

Estimated production volumes are based on detailed data for the fields and take into account development plans for the fields agreed by
management as part of the long-term planning process. It is estimated that, if all our production were to be reduced by 10% for the whole of the next
15 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amounts of each cash-generating unit to zero.
Consequently, management believes no reasonably possible change in the production assumption would cause the carrying amounts to exceed the
recoverable amounts.

Management also believes that currently there is no reasonably possible change in discount rate that would cause the carrying amounts in the

UK, US or Rest of World to exceed the recoverable amounts.

Goodwill
Excess of recoverable amount over carrying amount

Goodwill

130

UK
341
7,972

US
3,441
16,692

UK
341

US
3,440

$ million

2008

Total
4,297
n/a

$ million

2007

Total
4,296

Rest of
World
515
n/a

Rest of
World
515

BP Annual Report and Accounts 2008
Notes on financial statements

12. Impairment review of goodwill continued
Refining and Marketing
In previous years, Refining and Marketing goodwill has been allocated to the following cash-generating units: Refining, Retail, Lubricants, and Other.
In 2008, the Refining and Retail units were largely integrated into geographically-based Fuels Value Chain units (FVC) and consequently the cash-
generating units to which goodwill is allocated have been redefined. The goodwill previously allocated to the global Refining and Retail units has
been aggregated and reallocated to the FVC units that are expected to benefit from the synergies of the business combinations that gave rise to the
goodwill. As part of this reallocation a small amount of goodwill was also allocated to business units included in ‘Other’. Goodwill is now allocated
to the following cash-generating units: Rhine FVC, US West Coast FVC, Lubricants and Other.

For all cash-generating units, the cash flows for the first three years are derived from the three-year business segment plan. For determining

the value in use for each of the cash-generating units, cash flows for a period of 10 years have been discounted and aggregated with a terminal value.
A key assumption for the FVCs is the Global Indicator Margin (GIM). Each regional GIM is based on a single representative crude with product yields
characteristic of the typical level of upgrading complexity.

Rhine FVC
Cash flows beyond the three-year period are extrapolated using a 1.2% growth rate.

The key assumptions to which the calculation of value in use for the Rhine FVC unit is most sensitive are refinery gross margins, refinery

production volumes and discount rate. The average value assigned to the refinery gross margin during the plan period is based on a $5.50 per barrel
GIM. The average value assigned to the refinery production volume is 250mmbbl a year over the plan period. These key assumptions reflect past
experience and are consistent with external sources.

The Rhine FVC’s recoverable amount exceeds its carrying amount by $3.6 billion. Based on sensitivity analysis, it is estimated that: (i) if the GIM

changes by $1 per barrel, the Rhine FVC’s value in use changes by $2.1 billion and, if there was an adverse change in the GIM of $1.70 per barrel, the
recoverable amount of the Rhine FVC would equal its carrying amount; (ii) if the volume assumption changes by 13mmbbl a year, the Rhine FVC’s value
in use changes by $1.2 billion and, if there is an adverse change in refinery volumes of 36mmbbl a year, the recoverable amount of the Rhine FVC
would equal its carrying amount; and (iii) a change of 1% in the discount rate would change the Rhine FVC’s value in use by $0.8 billion and, if the
discount rate increases to 17% the value in use of the Rhine FVC would equal its carrying amount.

US West Coast FVC
Cash flows beyond the three-year period are extrapolated using a 2% growth rate.

The key assumptions to which the calculation of value in use for the West Coast FVC unit is most sensitive are refinery gross margins, refinery

production volumes and discount rate. The average value assigned to the refinery gross margin during the plan period is based on a $7.60 per barrel
GIM. The average value assigned to the refinery production volume is 170mmbbl a year over the plan period. These key assumptions reflect past
experience and are consistent with external sources.

The West Coast FVC’s recoverable amount exceeds its carrying amount by $1.6 billion. Based on sensitivity analysis, it is estimated that: (i) if the

GIM changes by $1 per barrel, the West Coast FVC’s value in use changes by $1.5 billion and, if there was an adverse change in the GIM of $1.10 per
barrel, the recoverable amount of the West Coast FVC would equal its carrying amount; (ii) if the volume assumption changes by 8mmbbl a year, the
West Coast FVC’s value in use changes by $1.1 billion and, if there is an adverse change in refinery volumes of 12mmbbl a year, the recoverable
amount of the West Coast FVC would equal its carrying amount; and (iii) a change of 1% in the discount rate would change the West Coast FVC’s value
in use by $0.6 billion and, if the discount rate increases to 14% the value in use of the West Coast FVC would equal its carrying amount.

Lubricants
Cash flows beyond the three-year period are extrapolated using a 3% growth rate (2007 3%).

For the Lubricants unit, the key assumptions to which the calculation of value in use is most sensitive are operating margin, sales volumes and

discount rate. The average values assigned to the operating margin and sales volumes over the plan period are 70 cents per litre (2007 65 cents per
litre) and 3.4 billion litres a year (2007 3.3 billion litres a year) respectively. These key assumptions reflect past experience.

The Lubricants unit’s recoverable amount exceeds its carrying amount by $5.4 billion. Based on sensitivity analysis, it is estimated that: (i) if

there is an adverse change in the operating margin of 14 cents per litre, the recoverable amount of the Lubricants unit would equal its carrying amount;
(ii) if the sales volume assumption changes by 200 million litres a year, the Lubricants unit’s value in use changes by $1.4 billion and, if there is an
adverse change in Lubricants sales volumes of 700 million litres a year, the recoverable amount of the Lubricants unit would equal its carrying amount;
and (iii) a change of 1% in the discount rate would change the Lubricants unit’s value in use by $1.4 billion and, management believes no reasonably
possible change in the discount rate would lead to the Lubricants unit’s value in use being equal to its carrying amount.

Goodwill
Excess of recoverable amount over carrying amount

Rhine FVC
637
3,603

US West
Coast FVC
1,579
1,629

Lubricants
3,043
5,445

Refining
1,515
11,443

Retail
827
4,062

Lubricants
4,175
5,028

$ million

2008

Total
5,462
n/a

$ million

2007

Total
6,626

n/a

Other
203
n/a

Other
109
n/a

Comparative narrative information is not generally shown because, due to the reorganization of the Refining and Marketing business in 2008, the
information is not relevant to an understanding of the current year’s financial statements.

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BP Annual Report and Accounts 2008
Notes on financial statements

13. Distribution and administration expenses

Distribution
Administration

14. Currency exchange gains and losses

Currency exchange (gains) losses (credited) charged to income relating to embedded

derivatives measured at fair value through profit or loss

Other currency exchange (gains) losses (credited) charged to income

15. Research and development

Expenditure on research and development

16. Operating leases

2008

14,075
1,337
15,412

2007

14,028
1,343
15,371

2008

2007

(496)
156
(340)

12
(201)
(189)

2008
595

2007
566

$ million

2006

13,174
1,273
14,447

$ million

2006

179
43
222

$ million

2006
395

The table below shows the expense for the year in respect of operating leases. Where an operating lease is entered into solely by the group as the
operator of a jointly controlled asset, the total cost is included in this analysis, irrespective of any amounts that have been or will be reimbursed by joint
venture partners. Where BP is not the operator of a jointly controlled asset, and has not co-signed the lease, operating lease costs and future minimum
lease payments are excluded from the information given below. However, where BP has co-signed the lease, BP’s share of the lease costs and future
minimum lease payments are included.

Minimum lease payments
Contingent rentals
Sub-lease rentals

2008

4,870
134
(201)
4,803

2007

4,152
105
(191)
4,066

$ million

2006

3,647
13
(131)
3,529

The future minimum lease payments at 31 December, before deducting related rental income from operating sub-leases of $557 million (2007
$618 million), are shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor,
the future minimum lease payments are based on the factor as at inception of the lease.

Future minimum lease payments
Payable within
1 year
2 to 5 years
Thereafter

Of which, future minimum operating lease commitments relating to drilling rigs are $7,730 million (2007 $5,688 million).

2008

4,135
9,140
5,520
18,795

$ million

2007

3,780
7,660
5,498
16,938

132

BP Annual Report and Accounts 2008
Notes on financial statements

16. Operating leases continued
The following additional disclosures represent the net operating lease expense and net future minimum lease payments, after deducting amounts
reimbursed, or to be reimbursed, by joint venture partners.

Where BP is not the operator of a jointly controlled asset, and has not co-signed the lease, operating lease costs and future minimum lease

payments are excluded from the information given below. However, where BP has co-signed the lease, BP’s share of the lease costs and future
minimum lease payments are included.

Minimum lease payments
Contingent rentals
Sub-lease rentals

Future minimum lease payments

Payable within
1 year
2 to 5 years
Thereafter

2008

3,693
97
(197)
3,593

2007

3,100
80
(183)
2,997

2008

3,165
7,135
4,820
15,120

$ million

2006

2,924

(131)
2,806

$ million

2007

2,826
6,519
5,050
14,395

Of which, future minimum operating lease commitments relating to drilling rigs are $4,660 million (2007 $3,736 million).

The group enters into operating leases of ships, plant and machinery, commercial vehicles and land and buildings. Typical durations of the

leases are as follows:

Ships
Plant and machinery
Commercial vehicles
Land and buildings

Years

up to 15
up to 10
up to 15
up to 40

The group has entered into a number of structured operating leases for ships and in most cases the lease rental payments vary with market interest
rates. The variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is
treated as contingent rental expense. The group also routinely enters into bareboat charters, time-charters and spot-charters for ships on standard
industry terms.

The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Exploration and Production
segment. In some cases, drilling rig lease rental rates are adjusted periodically to market rates that are influenced by oil prices and may be significantly
different from the rates at the inception of the lease. Differences between the rate paid and the rate at inception of the lease are treated as contingent
rental expense.

Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main

items in the land and buildings category.

The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases

of ships and buildings allow for renewals at BP’s option.

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17. Exploration for and evaluation of oil and natural gas resources

The following financial information represents the amounts included within the group totals relating to activity associated with the exploration
for and evaluation of oil and natural gas resources. All such activity is recorded within the Exploration and Production segment.

Exploration and evaluation costs

Exploration expenditure written off
Other exploration costs
Exploration expense for the yeara
Intangible assets – exploration expenditure
Net assets
Capital expenditure and acquisitions
Net cash used in operating activities
Net cash used in investing activities

2008

2007

385
497
882
9,031
9,031
4,780
497
4,163

347
409
756
5,252
5,252
2,000
409
2,000

$ million

2006

624
421
1,045
4,110
4,110
1,537
421
1,498

aIn addition to these amounts, an impairment charge of $210 million was recognized in 2008 relating to exploration assets in Vietnam following BP’s decision to withdraw from activities in the area
concerned.

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Notes on financial statements

18. Auditor’s remuneration

Fees – Ernst & Young
Fees payable to the company’s auditors for the audit of the company’s accountsa
Fees payable to the company’s auditors and its associates for other services

Audit of the company’s subsidiaries pursuant to legislation
Other services pursuant to legislation

Tax services
Services relating to corporate finance transactions
All other services

Audit fees in respect of the BP pension plans

2008
16

2007
18

$ million

2006
15

28
13
57
2
2
5
1
67

31
14
63
2
1
8
1
75

31
15
61
1
2
9
–
73

aFees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.

Total fees for 2008 include $3 million of additional fees for 2007 (2007 includes $7 million of additional fees for 2006 and 2006 includes $5 million of
additional fees for 2005). Auditor’s remuneration is included in the income statement within distribution and administration expenses.

The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services.
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 compared with that of other potential service providers. These services are for a fixed term.

19. Finance costs

Interest payable
Capitalized at 4.00% (2007 5.70% and 2006 5.25%)a
Unwinding of discount on provisions
Unwinding of discount on other payables

aTax relief on capitalized interest is $42 million (2007 $81 million and 2006 $182 million).

Revised income statement presentation

2008
1,319
(162)
287
103
1,547

2007
1,433
(323)
283
–
1,393

$ million

2006
1,196
(478)
245
23
986

With effect from 1 January 2008, the unwinding of the discount on provisions and on other payables is now included within finance costs. Previously,
it was included within other finance income or expense. This line item has now been renamed net finance income or expense relating to pensions
and other post-retirement benefits. This change does not affect profit before interest and taxation, profit before taxation or profit for the period in the
group income statement. For 2007 $283 million was reclassified from other finance income to finance costs (2006 $268 million).

134

BP Annual Report and Accounts 2008
Notes on financial statements

20. Taxation

Tax on profit

Current tax

Charge for the year
Adjustment in respect of prior years

Innovene operations
Continuing operations
Deferred tax

Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years

Tax on profit from continuing operations

Tax included in the statement of recognized income and expense

Current tax
Deferred tax

This comprises:
Currency translation differences
Actuarial gain (loss) relating to pensions and other post-retirement benefits
Share-based payments
Cash flow hedges
Available-for-sale investments

2008

2007

13,468
(85)
13,383
–
13,383

(324)
(442)
(766)
12,617

2008
(264)
(2,492)
(2,756)

(100)
(2,602)
190
(194)
(50)
(2,756)

10,006
(171)
9,835
–
9,835

671
(64)
607
10,442

2007
(178)
241
63

(139)
427
(213)
(26)
14
63

$ million

2006

11,199
442
11,641
159
11,800

1,771
(1,240)
531
12,331

$ million

2006
(51)
985
934

201
820
(26)
47
(108)
934

Reconciliation of the effective tax rate

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

Profit before taxation from continuing operations
Tax on profit from continuing operations
Effective tax rate

UK statutory corporation tax rate
Increase (decrease) resulting from

UK supplementary and overseas taxes at higher rates
Tax reported in equity-accounted entities
Adjustments in respect of prior years
Current year losses unrelieved (prior year losses utilized)
Other

Effective tax rate

2008
34,283
12,617
37%

2007
31,611
10,442
33%

$ million

2006
34,642
12,331
36%

14
(2)
(2)
(1)
–
37

% of profit before taxation
from continuing operations
30

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7
(2)
(1)
(1)
–
33

11
(3)
(2)
(1)
1
36

135

BP Annual Report and Accounts 2008
Notes on financial statements

20. Taxation continued
Deferred tax

Deferred tax liability
Depreciation
Pension plan surpluses
Other taxable temporary differences

Deferred tax asset

Petroleum revenue tax
Pension plan and other post-retirement benefit plan deficits
Decommissioning, environmental and other provisions
Derivative financial instruments
Tax credit and loss carry forward
Other deductible temporary differences

2008

1,248
108
(2,471)
(1,115)

121
104
(333)
228
118
111
349
(766)

125
127
1,371
1,623

139
(72)
(1,069)
450
(466)
2
(1,016)
607

Income statement
2006a

2007a

$ million

Balance sheet
2007a

2008

1,423
173
417
2,013

4
71
(754)
(115)
220
(908)
(1,482)
531

23,342
412
3,626
27,380

(192)
(2,414)
(4,860)
(331)
(1,821)
(1,564)
(11,182)
16,198

2008
19,215
(67)
(766)
(2,492)
–
308
16,198

22,338
2,136
5,998
30,472

(325)
(1,545)
(5,107)
(541)
(1,822)
(1,917)
(11,257)
19,215

$ million

2007
18,116
42
607
241
199
10
19,215

Net deferred tax (credit) charge and net deferred tax liability
aA minor amendment has been made to the comparative amounts shown in the analysis of deferred tax by category of temporary difference.

Analysis of movements during the year
At 1 January
Exchange adjustments
Charge (credit) for the year on ordinary activities
Charge (credit) for the year in the statement of recognized income and expense
Acquisitions
Other movements
At 31 December

In 2008, there have been no changes in the statutory tax rates that have materially impacted the group’s tax charge. The enactment, in 2007, of a 2%
reduction in the rate of UK corporation tax on profits arising from activities outside the North Sea reduced the deferred tax charge by $189 million in
that year.

Deferred tax assets are recognized to the extent that it is probable that taxable profit will be available against which the deductible temporary

differences and the carry-forward of unused tax assets and unused tax losses can be utilized.

At 31 December 2008, the group had around $6.3 billion (2007 $5.0 billion) of carry-forward tax losses, predominantly in Europe, that would be

available to offset against future taxable profit. A deferred tax asset has been recognized in respect of $4.2 billion of losses (2007 $3.2 billion). No
deferred tax asset has been recognized in respect of $2.1 billion of losses (2007 $1.8 billion). Substantially all the tax losses have no fixed expiry date.

At 31 December 2008, the group had around $3.4 billion (2007 $4.1 billion) of unused tax credits in the UK and US. A deferred tax asset of

$0.5 billion has been recognized in 2008 for these credits (2007 $0.8 billion), which is offset by a deferred tax liability associated with unremitted
profits from overseas entities in jurisdictions with a lower tax rate than the UK. No deferred tax asset has been recognized in respect of $2.9 billion of
tax credits (2007 $3.2 billion). The UK tax credits do not have a fixed expiry date. The US tax credits, amounting to $1.8 billion, expire ten years after
generation, and substantially all expire in the period 2014-2018.

The major components of temporary differences at the end of 2008 are tax depreciation, US inventory holding gains (classified as other taxable

temporary differences), provisions, and pension plan and other post-retirement benefit plan deficits.

The group profit and loss account reserve includes $18,347 million (2007 $16,335 million) of earnings retained by subsidiaries and equity-accounted

entities.

21. Dividends

2008

2007

2006

2008

2007

2006

2008

2007

pence per share

cents per share

$ million

2006

Dividends announced and paid

Preference shares
Ordinary shares
March
June
September
December

Dividend announced per ordinary
share, payable in March 2009

6.813
6.830
7.039
8.705
29.387

9.818

5.258
5.151
5.278
5.308
20.995

5.288
5.251
5.324
5.241
21.104

13.525
13.525
14.000
14.000
55.050

10.325
10.325
10.825
10.825
42.300

9.375
9.375
9.825
9.825
38.400

2,553
2,545
2,623
2,619
10,342

2,000
1,983
2,065
2,056
8,106

1,922
1,893
1,943
1,926
7,686

–

14.000

–

2,626

–

The group does not account for dividends until they are paid. The accounts for the year ended 31 December 2008 do not reflect the dividend
announced on 3 February 2009 and payable in March 2009; this will be treated as an appropriation of profit in the year ended 31 December 2009.

136

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Notes on financial statements

22. Earnings per ordinary share

Basic earnings per share
Diluted earnings per share

2008
112.59
111.56

cents per share

2007
108.76
107.84

2006
109.84
109.00

Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to ordinary shareholders by the weighted
average number of ordinary shares outstanding during the year. The average number of shares outstanding excludes treasury shares and the shares
held by the Employee Share Ownership Plans (ESOPs) and includes certain shares that will be issuable in the future under employee share plans.

For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the number
of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method. In addition, for 2006
the profit attributable to ordinary shareholders has been adjusted for the unwinding of the discount on the deferred consideration for the acquisition of
our interest in TNK-BP and the weighted average number of shares outstanding during the year has been adjusted for the number of shares to be
issued for the deferred consideration for the acquisition of our interest in TNK-BP.

Profit from continuing operations attributable to BP shareholders
Less dividend requirements on preference shares
Profit from continuing operations attributable to BP ordinary shareholders
Loss from discontinued operations

Unwinding of discount on deferred consideration for acquisition of

investment in TNK-BP (net of tax)

Diluted profit for the year attributable to BP ordinary shareholders

Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share schemes
Potential dilutive effect of ordinary shares issuable as consideration for BP’s interest in

the TNK-BP joint venture

2008
21,157
2
21,155
–
21,155

–
21,155

2007
20,845
2
20,843
–
20,843

–
20,843

$ million

2006
22,025
2
22,023
(25)
21,998

16
22,014

shares thousand

2008

2006
18,789,827 19,163,389 20,027,527
109,813

163,486

172,690

2007

58,118
18,962,517 19,326,875 20,195,458

–

The number of ordinary shares outstanding at 31 December 2008, excluding treasury shares and the shares held by the ESOPs, and including certain
shares that will be issuable in the future under employee share plans was 18,716,098,258. Between 31 December 2008 and 18 February 2009, the
latest practicable date before the completion of these financial statements, there has been an increase of 4,867,626 in the number of ordinary shares
outstanding as a result of share issues related to employee share plans. The number of potential ordinary shares issuable through the exercise of
options related to employee share plans was 191,340,183 at 31 December 2008. There has been a decrease of 42,722,753 in the number of potential
ordinary shares between 31 December 2008 and 18 February 2009.

Loss per share for the discontinued operations in 2006 is derived from the net loss attributable to ordinary shareholders from discontinued

operations of $25 million, divided by the weighted average number of ordinary shares for both basic and diluted amounts as shown above.

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BP Annual Report and Accounts 2008
Notes on financial statements

23. Property, plant and equipment

Cost

At 1 January 2008
Exchange adjustments
Acquisitions
Additions
Transfersa
Deletions

At 31 December 2008
Depreciation

At 1 January 2008
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Transfersb
Deletions

At 31 December 2008
Net book amount at 31 December 2008
Cost

At 1 January 2007
Exchange adjustments
Acquisitions
Additions
Transfers
Reclassified as assets held for sale
Deletions

At 31 December 2007
Depreciation

At 1 January 2007
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Reclassified as assets held for sale
Deletions

At 31 December 2007
Net book amount at 31 December 2007
Net book amount at 1 January 2007

Assets held under finance leases at net book amount
included above
At 31 December 2008
At 31 December 2007

Decommissioning asset at net book amount included above

At 31 December 2008
At 31 December 2007

Assets under construction included above

At 31 December 2008
At 31 December 2007

Land
and land
improve-
ments

Buildings

4,516
(320)
–
64
–
(296)
3,964

718
(30)
32
21
–
–
(143)
598
3,366

4,442
271
–
78
–
(16)
(259)
4,516

675
25
52
86
–
(9)
(111)
718
3,798
3,767

3,150
(287)
–
161
–
(282)
2,742

1,533
(118)
79
33
–
–
(214)
1,313
1,429

3,129
148
–
171
–
–
(298)
3,150

1,470
89
98
62
–
–
(186)
1,533
1,617
1,659

Oil and
gas
properties

134,615
(1)
136
12,571
(454)
(54)
146,813

72,486
–
7,490
469
(122)
(352)
(16)
79,955
66,858

123,493
22
–
12,107
422
–
(1,429)
134,615

66,189
19
7,370
189
(237)
–
(1,044)
72,486
62,129
57,304

Plant,
machinery
and
equipment

Fixtures,
fittings and
office
equipment

Transport-
ation

Oil depots,
storage
tanks and
service
stations

36,365
(1,655)
212
4,118
79
(1,214)
37,905

17,417
(917)
1,697
131
–
4
(1,034)
17,298
20,607

32,203
1,182
910
3,662
–
(1,114)
(478)
36,365

16,189
556
1,266
236
–
(486)
(344)
17,417
18,948
16,014

3,169
(237)
–
530
(1)
(416)
3,045

1,820
(147)
313
1
–
(1)
(290)
1,696
1,349

3,006
73
–
466
–
–
(376)
3,169

1,762
45
341
9
–
–
(337)
1,820
1,349
1,244

11,866
(98)
–
243
454
(170)
12,295

7,126
(41)
296
–
–
274
(113)
7,542
4,753

11,930
32
–
181
–
–
(277)
11,866

6,876
16
373
14
–
–
(153)
7,126
4,740
5,054

11,410
(1,047)
–

842

–
(860)
10,345

6,002
(502)
709
19
–
–
(721)
5,507
4,838

11,076
733
–
643
–
–
(1,042)
11,410

5,119
299
741
643
–
–
(800)
6,002
5,408
5,957

–
–

12
17

237
155

107
185

–
–

8
11

18
24

Cost

Depreciation

7,140
7,851

3,659
3,328

$ million

Total

205,091
(3,645)
348
18,529
78
(3,292)
217,109

107,102
(1,755)
10,616
674
(122)
(75)
(2,531)
113,909
103,200

189,279
2,461
910
17,308
422
(1,130)
(4,159)
205,091

98,280
1,049
10,241
1,239
(237)
(495)
(2,975)
107,102
97,989
90,999

382
392

Net

3,481
4,523

17,213
18,658

aIncludes $337 million transferred to equity-accounted investments and $415 million transferred from intangible assets.
bIncludes $75 million transferred to equity-accounted investments.

138

BP Annual Report and Accounts 2008
Notes on financial statements

24. Goodwill

Cost and net book amount

At 1 January
Exchange adjustments
Acquisitions
Additions
Reclassified as assets held for sale
Deletions
At 31 December

25. Intangible assets

Cost

At 1 January
Exchange adjustments
Acquisitions
Additionsa
Transfersb
Deletions
At 31 December
Amortization

At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January

2008

11,006
(1,112)
1
39
–
(56)
9,878

$ million

2007

10,780
126
270
–
(90)
(80)
11,006

Exploration
expenditure

Other
intangibles

5,637
(1)
42
4,738
(415)
(576)
9,425

385
–
385
200
(576)
394
9,031
5,252

2,898
(175)
–
354
–
(150)
2,927

1,498
(60)
369
–
(109)
1,698
1,229
1,400

2008

Total

8,535
(176)
42
5,092
(415)
(726)
12,352

1,883
(60)
754
200
(685)
2,092
10,260
6,652

Exploration
expenditure

Other
intangibles

4,590
3
–
2,000
(506)
(450)
5,637

480
–
347
–
(442)
385
5,252
4,110

2,396
49
35
548
–
(130)
2,898

1,260
25
338
–
(125)
1,498
1,400
1,136

$ million

2007

Total

6,986
52
35
2,548
(506)
(580)
8,535

1,740
25
685
–
(567)
1,883
6,652
5,246

aIncluded in additions to exploration expenditure in 2008 is $2,331 million in relation to BP’s purchase of interests in shale gas assets in the US.
bIncluded in transfers of exploration expenditure in 2007 is $84 million transferred to equity-accounted investments.

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139

BP Annual Report and Accounts 2008
Notes on financial statements

26. Investments in jointly controlled entities

The significant jointly controlled entities of the BP group at 31 December 2008 are shown in Note 46. The principal joint venture is the TNK-BP joint
venture. Summarized financial information for the group’s share of jointly controlled entities is shown below.

Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Minority interest
Profit for the yeara
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Minority interest

Group investment in jointly controlled entities
Group share of net assets (as above)
Loans made by group companies
to jointly controlled entities

TNK-BP
25,936
3,588
275
3,313
882
169
2,262
13,874
3,760
17,634
3,287
4,820
8,107
588
8,939

Other
10,796
1,343
185
1,158
397
–
761
15,584
3,687
19,271
1,998
3,973
5,971
–
13,300

2008

Total
36,732
4,931
460
4,471
1,279
169
3,023
29,458
7,447
36,905
5,285
8,793
14,078
588
22,239

TNK-BP
19,463
3,743
264
3,479
993
215
2,271
12,433
6,073
18,506
3,547
5,562
9,109
580
8,817

Other
7,245
1,299
176
1,123
259
–
864
9,841
2,642
12,483
1,552
3,620
5,172
–
7,311

2007

Total
26,708
5,042
440
4,602
1,252
215
3,135
22,274
8,715
30,989
5,099
9,182
14,281
580
16,128

8,939

13,300

22,239

8,817

7,311

16,128

–
8,939

1,587
14,887

1,587
23,826

–
8,817

1,985
9,296

1,985
18,113

TNK-BP
17,863
4,616
192
4,424
1,467
193
2,764

Other
6,119
1,218
169
1,049
260
–
789

$ million

2006

Total
23,982
5,834
361
5,473
1,727
193
3,553

aBP’s share of the profit of TNK-BP in 2006 includes a net gain of $892 million on the disposal of certain assets.

In December 2007, BP signed a memorandum of understanding with Husky Energy Inc. (Husky) to form an integrated North American oil sands
business. The transaction was completed on 31 March 2008, with BP contributing its Toledo refinery to a US jointly controlled entity to which Husky
contributed $250 million cash and a payable of $2,588 million. In Canada, Husky contributed its Sunrise field to a second jointly controlled entity, with
BP contributing $250 million in cash and a payable of $2,264 million. Both jointly controlled entities are owned 50:50 by BP and Husky and are
accounted for using the equity method. During the year, equity-accounted earnings from these jointly controlled entities amounted to a loss of $70 million.

BP purchased refined products from the Toledo jointly controlled entity during the year amounting to $3,440 million. In addition, BP purchased
crude oil from third parties which it sold to the Toledo jointly controlled entity under an agency agreement. The fees earned by BP for this service, and
the total amounts receivable and payable at 31 December 2008 under these arrangements, were not significant. BP will also purchase refinery
feedstocks from the Sunrise jointly controlled entity once production commences, which is expected in 2013. During 2008 the unwinding of discount
on the payable to the Sunrise jointly controlled entity, included within finance costs in the group income statement, amounted to $103 million.

Our investment in TNK-BP will be reclassified from a jointly controlled entity to an associate with effect from 9 January 2009, the date that BP

finalized a revised shareholder agreement with its Russian partners in TNK-BP, Alfa Access-Renova (AAR). The formerly evenly-balanced main board
structure is replaced by one with four representatives each from BP and AAR, plus three independent directors. The change in accounting classification
from a jointly controlled entity to an associate reflects the ability of the independent directors of TNK-BP to decide on certain matters in the event of
disagreement between the shareholder representatives on the board. The group's investment will continue to be accounted for using the equity method.

Transactions between the group and its jointly controlled entities are summarized below.

Sales to jointly controlled entities

Product
LNG, crude oil and oil products, natural gas, employee services

Purchases from jointly controlled entities

Product
Crude oil and oil products, natural gas, refinery operating costs,

plant processing fees

2008

Amount
receivable at
31 December
1,036

Sales
2,971

Sales
2,336

2008

Amount
payable at
31 Decembera

Purchases

2007

Amount
receivable at
31 December
888

2007

Amount
payable at
31 December

$ million

2006

Amount
receivable at
31 December
830

$ million

2006

Amount
payable at
31 December

Sales
2,258

Purchases

9,115

2,547

2,067

3,678

119

aIncludes $110 million current payable and $2,255 million non-current payable to the Sunrise Oil Sands jointly controlled entity relating to BP’s contribution on the establishment of the joint venture.

The terms of the outstanding balances receivable from jointly controlled entities are typically 30 to 45 days, except for a receivable from Ruhr Oel
of $386 million, which will be paid over several years as it relates to pension payments. The balances are unsecured and will be settled in cash. There
are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of
bad or doubtful debts.
140

BP Annual Report and Accounts 2008
Notes on financial statements

27. Investment in associates

The significant associates of the group are shown in Note 46. Summarized financial information for the group’s share of associates is set out below.

Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Profit for the year
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities

Group investment in associates

Group share of net assets (as above)
Loans made by group companies to associates

2008
11,709
1,065
33
1,032
234
798
4,292
1,912
6,204
1,669
1,852
3,521
2,683

2,683
1,317
4,000

Transactions between the group and its associates are summarized below.

Sales to associates

Product
LNG, crude oil and oil products, natural gas, employee services

2008

Amount
receivable at
31 December
219

Sales
3,248

2007

Amount
receivable at
31 December
60

Sales
697

2007
9,855
947
57
890
193
697
5,012
2,308
7,320
1,801
2,423
4,224
3,096

3,096
1,483
4,579

Sales
747

Purchases from associates

Product
Crude oil, natural gas, transportation tariff

2008

Amount
payable at
31 December
295

2007

Amount
payable at
31 December
574

Purchases
2,905

Purchases
4,635

Purchases
2,568

$ million

2006
8,792
669
63
606
164
442

$ million

2006

Amount
receivable at
31 December
66

$ million

2006

Amount
payable at
31 December
236

The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash.
There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in
respect of bad or doubtful debts.

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BP Annual Report and Accounts 2008
Notes on financial statements

28. Financial instruments and financial risk factors

The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.

At 31 December

Financial assets

Other investments – listed
Other investments – unlisted
Loans
Trade and other receivables
Derivative financial instruments
Cash at bank and in hand
Cash equivalents – listed
Cash equivalents – unlisted

Financial liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt

At 31 December

Financial assets

Financial liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt

$ million

2008

Total
carrying
amount

592
263
1,163
29,489
13,564
4,001
4,060
136

$ million

2007

Total
carrying
amount

1,617
213
1,164
38,710
10,062
2,996
3
563

Note

Loans and
receivables

Available-for-
sale financial
assets

At fair value
through profit
and loss

Derivative

Financial
liabilities
hedging measured at
instruments amortized cost

29
29

31
34
32
32
32

33
34

–
–
1,163
29,489
–
4,001
–
–

–
–
–
–
34,653

592
263
–
–
–
–
4,060
136

–
–
–
–
5,051

–
–
–
–
12,501
–
–
–

–
(13,173)
–
–
(672)

–
–
–
–
1,063
–
–
–

–
–
–
–
–
–
–
–

–
(2,075)
–
–
(1,012)

(33,140)
–
(7,527)
(33,204)
(73,871)

(33,140)
(15,248)
(7,527)
(33,204)
(35,851)

Note

Loans and
receivables

Available-for-
sale financial
assets

At fair value
through profit
and loss

Derivative
hedging
instruments

Financial
liabilities
measured at
amortized cost

29
29

31
34
32
32
32

33
34

–
–
1,164
38,710
–
2,996
–
–

–
–
–
–
42,870

1,617
213
–
–
–
–
3
563

–
–
–
–
2,396

–
–
–
–
9,155
–
–
–

–
(11,284)
–
–
(2,129)

–
–
–
–
907
–
–
–

–
(123)
–
–
784

–
–
–
–
–
–
–
–

(40,062)
–
(7,599)
(31,045)
(78,706)

(40,062)
(11,407)
(7,599)
(31,045)
(34,785)

The fair value of finance debt is shown in Note 35. For all other financial instruments, the carrying amount is either the fair value, or approximates
the fair value.

Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments
including market risks relating to commodity prices, foreign currency exchange rates, interest rates and equity prices, credit risk and liquidity risk.

The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The

GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the finance, tax and the
integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance
framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the
group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed
in accordance with group policies and group risk appetite.

142

BP Annual Report and Accounts 2008
Notes on financial statements

28. Financial instruments and financial risk factors continued
The group’s trading activities in the oil, natural gas and power markets are managed within the integrated supply and trading function, while activities
in the financial markets are managed by the treasury function. All derivative activity is carried out by specialist teams that have the appropriate skills,
experience and supervision.These teams are subject to close financial and management control.

The integrated supply and trading function maintains formal governance processes that provide oversight of market risk associated with trading

activity. These processes meet generally accepted industry practice and reflect the principles of the Group of Thirty Global Derivatives Study
recommendations. A policy and risk committee monitors and validates limits and risk exposures, reviews incidents and validates risk-related policies,
methodologies and procedures. A commitments committee approves value-at-risk delegations, the trading of new products, instruments and
strategies and material commitments.

In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a separate control

framework as described more fully below.

(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The
market price movements that the group is exposed to include oil, natural gas and power prices (commodity price risk), foreign currency exchange
rates, interest rates, equity prices and other indices that could adversely affect the value of the group’s financial assets, liabilities or expected future
cash flows. The group enters into derivatives in a well established entrepreneurial trading operation. In addition, the group has developed a control
framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with this control framework the group
enters into various transactions using derivatives for risk management purposes.

During recent periods of increased volatility in financial markets the group’s policies in relation to managing market risk continue to be

appropriate and are outlined in further detail below. The group measures market risk exposure arising from its trading positions 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 prices 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, together with the correlation of these price movements.
The value-at-risk measure is supplemented by stress testing and tail risk analysis.

The trading value-at-risk model is used for derivative financial instrument types 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 forwards, futures, swap agreements and options. Additionally, where physical commodities or non-derivative forward contracts are held as part
of a trading position, they are also reflected in the value-at-risk model. For options, a linear approximation is included in the value-at-risk models when
full revaluation is not possible.

The value-at-risk table does not incorporate any of the group’s natural business exposures or any derivatives entered into to risk manage those

exposures. Market risk exposure in respect of embedded derivatives is also not included in the value-at-risk table. Instead separate sensitivity analyses
are disclosed below.

Value-at-risk limits are in place for each trading activity and for the group’s trading activity in total. The board has delegated an overall limit of

$100 million value at risk in support of this trading activity. The high and low values at risk indicated in the table below for each type of activity are
independent of each other. Through the portfolio effect the high value at risk for the group as a whole is lower than the sum of the highs for the
constituent parts. The potential movement in fair values is expressed to a 95% confidence interval. This means that, in statistical terms, one would
expect to see a decrease in fair values greater than the trading value at risk on one occasion per month if the portfolio were left unchanged.

Value at risk for 1 day at 95% confidence interval

2008

$ million

2007

Group trading
Oil price trading
Natural gas price trading
Power price trading
Currency trading
Interest rate trading
Other trading

High

Low

Average

Year end

High

Low

Average

Year end

76
69
50
14
4
7
5

20
12
12
3
–
–
1

37
25
24
7
2
2
2

69
63
23
4
–
1
2

50
46
32
6
6
11
7

24
16
9
1
1
–
–

35
26
16
3
3
5
2

38
34
15
5
2
2
1

(i) Commodity price risk
The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes available in the related
commodity markets. Natural gas swaps, options and futures are used to mitigate price risk. Power trading is undertaken using a combination of
over-the-counter forward contracts and other derivative contracts, including options and futures. This activity is on both a standalone basis and in
conjunction with gas derivatives in relation to gas-generated power margin. In addition, NGLs are traded around certain US inventory locations using
over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories. Trading value-at-risk information in
relation to these activities is shown in the table above.

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Notes on financial statements

28. Financial instruments and financial risk factors continued
As described above, the group also carries out risk management of certain short-term natural business exposures using over-the-counter swaps and
exchange futures contracts with a duration of less than three years. In past periods commodity price risk relating to this activity has been managed
using value-at-risk measures. For 2008 a separate control framework is now used as described under market risk above. For these derivative contracts
the sensitivity of the net fair value to an immediate 10% increase or decrease in all reference prices would have been $90 million at 31 December
2008. This figure does not include any corresponding economic benefit or disbenefit that would arise from the natural business exposure which would
be expected to largely offset the gain or loss on the derivatives.

In addition, the group has embedded derivatives relating to certain natural gas and crude oil contracts. The net fair value of these embedded

derivatives was a liability of $1,867 million at 31 December 2008 (2007 liability of $2,085 million). Key information on the natural gas contracts is
given below.

At 31 December
Remaining contract terms
Contractual/notional amount
Discount rate – nominal risk free

2008
1 year 9 months to 9 years 9 months
3,585 million therms
2.5%

2007
9 months to 11 years
3,889 million therms
4.5%

For these embedded derivatives the sensitivity of the net fair value to an immediate 10% favourable or unfavourable change in the key assumptions is
as follows.

At 31 December

Favourable 10% change
Unfavourable 10% change

Gas price

Oil price

Power price

291
(289)

81
(81)

27
(27)

2008

Discount
rate

16
(16)

Gas price

Oil price

Power price

317
(368)

72
(84)

37
(34)

$ million

2007

Discount
rate

31
(32)

The sensitivities for risk management activity and embedded derivatives are hypothetical and should not be considered to be predictive of future
performance. In addition, for the purposes of this analysis, in the above table, the effect of a variation in a particular assumption on the fair value of the
embedded derivatives is calculated independently of any change in another assumption. In reality, changes in one factor may contribute to changes in
another, which may magnify or counteract the sensitivities. Furthermore, the estimated fair values as disclosed should not be considered indicative of
future earnings on these contracts.

(ii) Foreign currency exchange risk
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-
risk techniques as explained above. This activity is described as currency trading in the value-at-risk table above.

Since BP has global operations, fluctuations in foreign currency exchange rates can have significant effects on the group’s reported results.

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 results. The main underlying economic currency of the group’s cash flows is the US
dollar. This is because BP’s major product, oil, is priced internationally in US dollars. BP’s foreign currency exchange management policy is to minimize
economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign
currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible, and then dealing with any material residual
foreign currency exchange risks.

The group manages these exposures by constantly reviewing the foreign currency economic value at risk and managing such risk to keep

the 12-month foreign currency value at risk below $200 million. At 31 December 2008, the foreign currency value at risk was $70 million (2007
$60 million). At no point over the past three years did the value at risk exceed the maximum risk limit. The most significant exposures relate to capital
expenditure commitments and other UK and European operational requirements, for which a hedging programme is in place and hedge accounting
is claimed as outlined in Note 34.

For highly probable forecast capital expenditures the group locks in the US-dollar cost of non-US dollar supplies by using currency forwards
and futures. The main exposures are sterling, euro, Norwegian krone, Australian dollar, Korean won and Canadian dollar, and at 31 December 2008
open contracts were in place for $949 million sterling, $553 million euro, $392 million Norwegian krone, $303 million Australian dollar, $187 million
Korean won and $712 million Canadian dollar capital expenditures maturing within seven years, with over 65% of the deals maturing within two years
(2007 $732 million sterling, $931 million euro, $479 million Norwegian krone, $38 million Australian dollar, $243 million Korean won and $7 million
Canadian dollar capital expenditures maturing within eight years with over 80% of the deals maturing within two years).

For other UK, European, Canadian and Australian operational requirements the group uses cylinders and currency forwards to hedge the

estimated exposures on a 12-month rolling basis. At 31 December 2008, the open positions relating to cylinders consisted of receive sterling, pay
US dollar, purchased call and sold put options (cylinders) for $1,660 million (2007 $2,800 million); receive euro, pay US dollar cylinders for $1,612 million
(2007 $1,400 million); receive Canadian dollar, pay US dollar cylinders for $250 million (2007 nil); and receive Australian dollar, pay US dollar cylinders for
$455 million (2007 $382 million). At 31 December 2008, the open positions relating to currency forwards consisted of buy sterling, sell US dollar,
currency forwards for $816 million (2007 nil); buy euro, sell US dollar currency forwards for $141 million (2007 nil); buy Canadian dollar, sell US dollar,
currency forwards for $50 million (2007 nil); and buy Australian dollar, sell US dollar, currency forwards for $90 million (2007 nil).

In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2008, the total

foreign currency net borrowings not swapped into US dollars amounted to $1,037 million (2007 $1,045 million). Of this total, $92 million was
denominated in currencies other than the functional currency of the individual operating unit being entirely Canadian dollars (2007 $268 million, being
$191 million in Canadian dollars and $77 million in Trinidad & Tobago dollars). It is estimated that a 10% change in the corresponding exchange rates
would result in an exchange gain or loss in the income statement of $9 million (2007 $27 million).

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Notes on financial statements

28. Financial instruments and financial risk factors continued
(iii) Interest rate risk
Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques
as described above. This activity is described as interest rate trading in the value-at-risk table above.

BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of

its financial instruments, principally finance debt.

While the group issues debt in a variety of currencies based on market opportunities, it uses derivatives to swap the debt to a US dollar floating

rate exposure but in certain defined circumstances maintains a fixed rate exposure for a proportion of debt. The proportion of floating rate debt net of
interest rate swaps at 31 December 2008 was 72% of total finance debt outstanding (2007 68%). The weighted average interest rate on finance debt
at 31 December 2008 is 3% (2007 5%) and the weighted average maturity of fixed rate debt is three years (2007 two years).

The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates

applicable to floating rate instruments were to have increased by 1% on 1 January 2009, it is estimated that the group’s profit before taxation for 2009
would decrease by approximately $239 million (2007 $168 million decrease in 2008). This assumes that the amount and mix of fixed and floating rate
debt, including finance leases, remains unchanged from that in place at 31 December 2008 and that the change in interest rates is effective from the
beginning of the year. Where the interest rate applicable to an instrument is reset during a quarter it is assumed that this occurs at the beginning of the
quarter and remains unchanged for the rest of the year. In reality, the fixed/floating rate mix will fluctuate over the year and interest rates will change
continually. Furthermore, the effect on earnings shown by this analysis does not consider the effect of any other changes in general economic activity
that may accompany such an increase in interest rates.

(iv) Equity price risk
The group holds equity investments, typically made for strategic purposes, that are classified as non-current available-for-sale financial assets and are
measured initially at fair value with changes in fair value recognized directly in equity. Accumulated fair value changes are recycled to the income
statement on disposal, or when the investment is impaired. Impairment losses of $546 million have been recognized in 2008 relating to listed non-
current available-for-sale investments. For further information see Note 29.

At 31 December 2008, it is estimated that an increase of 10% in quoted equity prices would result in an immediate credit to equity of
$59 million (2007 $162 million credit to equity), whilst a decrease of 10% in quoted equity prices would result in an immediate charge to profit or loss
of $48 million and a charge to equity of $11 million (2007 $162 million charge to equity).

At 31 December 2008, 56% (2007 70%) of the carrying amount of non-current available-for-sale financial assets represented the group’s stake

in Rosneft, thus the group’s exposure is concentrated on changes in the share price of this equity in particular.

(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to
the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit
exposures to customers relating to outstanding receivables.

The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to
measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract
the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy are formal delegated authorities
to the sales and marketing teams to incur credit risk and to a specialized credit function to set counterparty limits; the establishment of credit systems
and processes to ensure that counterparties are rated and limits set; and systems to monitor exposure against limits and report regularly on those
exposures, and immediately on any excesses, and to track and report credit losses. The treasury function provides a similar credit risk management
activity with respect to group-wide exposures to banks and other financial institutions.

In the current economic environment the group has placed increased emphasis on the management of credit risk. Policies and processes have
been reviewed during the year and credit exposures with banks and others have been reduced through netting and collateral arrangements, or reduced
activity where appropriate.

Before trading with a new counterparty can start, its creditworthiness is assessed and a credit rating is allocated that indicates the probability

of default, along with a credit exposure limit. The assessment process takes into account all available qualitative and quantitative information about the
counterparty and the group, if any, to which the counterparty belongs. The counterparty’s business activities, financial resources and business risk
management processes are taken into account in the assessment, to the extent that this information is publicly available or otherwise disclosed to the
group by the counterparty, together with external credit ratings, if any, including ratings prepared by Moody’s Investor Service and Standard & Poor’s.
Creditworthiness continues to be evaluated after transactions have been initiated and a watchlist of higher-risk counterparties is maintained. Once
assigned a credit rating, each counterparty is allocated a maximum exposure limit.

The group does not aim to remove credit risk but expects to experience a certain level of credit losses. The group attempts to mitigate credit
risk by entering into contracts that permit netting and allow for termination of the contract on the occurrence of certain events of default. Depending
on the creditworthiness of the counterparty, the group may require collateral or other credit enhancements such as cash deposits or letters of credit
and parent company guarantees. Trade and other derivative assets and liabilities are presented on a net basis where unconditional netting
arrangements are in place with counterparties and where there is an intent to settle amounts due on a net basis. The maximum credit exposure
associated with financial assets is equal to the carrying amount. At 31 December 2008, the maximum credit exposure was $52,413 million (2007
$53,498 million). Collateral received and recognized in the balance sheet at the year-end was $1,121 million (2007 $39 million) and collateral held off
balance sheet was $203 million (2007 $474 million). Credit exposure exists in relation to guarantees issued by group companies under which amounts
outstanding at 31 December 2008 were $223 million (2007 $443 million) in respect of liabilities of jointly controlled entities and associates and
$613 million (2007 $601 million) in respect of liabilities of other third parties.

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Notes on financial statements

28. Financial instruments and financial risk factors continued
Notwithstanding the processes described above, significant unexpected credit losses can occasionally occur. Exposure to unexpected losses
increases with concentrations of credit risk that exist when a number of counterparties are involved in similar activities or operate in the same industry
sector or geographical area, which may result in their ability to meet contractual obligations being impacted by changes in economic, political or other
conditions. The group’s principal customers, suppliers and financial institutions with which it conducts business are located throughout the world. In
addition, these risks are managed by maintaining a group watchlist and aggregating multi-segment exposures to ensure that a material credit risk
is not missed.

Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure

by segment, and overall quality of the portfolio. The reports also include details of the largest counterparties by exposure level and expected loss,
and details of counterparties on the group watchlist.

It is estimated that over 80% (2007 80%) of the counterparties to the contracts comprising the derivative financial instruments in an asset

position are of investment grade credit quality.

Trade and other receivables of the group are analysed in the table below. By comparing the BP credit ratings to the equivalent external credit

ratings, it is estimated that approximately 60-65% (2007 65-70%) of the trade receivables portfolio exposure are of investment grade quality. With
respect to the trade and other receivables that are neither impaired nor past due, there are no indications as of the reporting date that the debtors will
not meet their payment obligations.

The group does not typically renegotiate the terms of trade receivables; however, if a renegotiation does take place, the outstanding balance is

included in the analysis based on the original payment terms. There were no significant renegotiated balances outstanding at 31 December 2008 or
31 December 2007.

Trade and other receivables at 31 December
Neither impaired nor past due
Impaired (net of valuation allowance)
Not impaired and past due in the following periods

within 30 days
31 to 60 days
61 to 90 days
over 90 days

The movement in the valuation allowance for trade receivables is set out below.

At 1 January
Exchange adjustments
Charge for the year
Utilization
At 31 December

2008
25,838
73

1,323
489
596
1,170
29,489

2008
406
(32)
191
(174)
391

$ million

2007
35,167
145

2,350
273
311
464
38,710

$ million

2007
421
34
175
(224)
406

(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed
centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations,
subsidiaries pool their cash surpluses to treasury, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the
market or arrange for necessary external borrowings, while managing the group’s overall net currency positions.

In managing its liquidity risk, the group has access to a wide range of funding at competitive rates through capital markets and banks. The

group’s treasury function centrally co-ordinates relationships with banks, borrowing requirements, foreign exchange requirements and cash
management. The group believes it has access to sufficient funding through the commercial paper markets and by using undrawn committed
borrowing facilities to meet foreseeable borrowing requirements. At 31 December 2008, the group had substantial amounts of undrawn borrowing
facilities available, including committed facilities of $4,950 million, of which $4,550 million are in place until at least the fourth quarter of 2011 (2007
$4,950 million, of which $4,550 million are in place until at least the fourth quarter of 2011). These facilities are with a number of international banks
and borrowings under them would be at pre-agreed rates.

The group has in place a European Debt Issuance Programme (DIP) under which the group may raise $20 billion of debt for maturities of one
month or longer. At 31 December 2008, the amount drawn down against the DIP was $10,334 million (2007 $10,438 million). In addition, the group
has in place a US Shelf Registration under which it may raise $10 billion of debt with maturities of one month or longer. At 31 December 2008, the
amount drawn down under the US Shelf was $6,500 million (2007 $2,500 million).

The group has long-term debt ratings of Aa1 (stable outlook) and AA (stable outlook), (2007 Aa1 (stable outlook) and AA+ (negative outlook))

assigned respectively by Moody’s and Standard and Poor’s.

Despite current uncertainty in the financial market including a lack of liquidity for some borrowers, we have been able to issue $5 billion of

long-term debt in the fourth quarter of 2008. In addition, we have been able to issue short-term commercial paper at competitive rates. In the context
of unforeseen market volatility, we have however, increased the cash and cash equivalents held by the group to $8.2 billion at the end of 2008
compared with $3.6 billion at the end of 2007.

The amounts shown for finance debt in the table below include expected interest payments on borrowings and the future minimum lease

payments with respect to finance leases.

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Notes on financial statements

28. Financial instruments and financial risk factors continued
There are amounts included within finance debt that we show in the table below as due within one year to reflect the earliest contractual repayment
dates but that are expected to be repaid over the maximum long-term maturity profiles of the contracts as described in Note 35. US Industrial
Revenue/Municipal Bonds of $3,166 million (2007 $2,880 million) with earliest contractual repayment dates within one year have expected repayment
dates ranging from 1 to 40 years (2007 1 to 35 years). The bondholders typically have the option to tender these bonds for repayment on interest reset
dates; however, 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 internally assessing the maturity profile of its finance debt. Similar treatment is applied for loans
associated with long-term gas supply contracts totalling $1,806 million (2007 $1,899 million) that mature within nine years.

The table also shows the timing of cash outflows relating to trade and other payables and accruals.

At 31 December

Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years

Trade and
other
payables
30,598
402
898
902
223
53
64
33,140

Accruals
6,743
359
77
72
67
164
45
7,527

2008

Finance
debt
16,670
5,934
3,419
2,647
5,072
1,316
1,050
36,108

Trade and
other
payables
39,576
147
62
26
30
197
24
40,062

$ million

2007

Finance
debt
16,561
8,011
3,515
1,447
2,352
1,100
1,447
34,433

Accruals
6,640
351
245
78
49
200
36
7,599

The group manages liquidity risk associated with derivative contracts on a portfolio basis, considering both physical commodity sale and purchase
contracts together with financially-settled derivative assets and liabilities.

The held-for-trading derivatives amounts in the table below represent the total contractual cash outflows by period for the purchases of physical

commodities under derivative contracts and the estimated cash outflows of financially-settled derivative liabilities. The group also holds derivative
contracts for the sale of physical commodities and financially-settled derivative assets that are expected to generate cash inflows that will be available
to the group to meet cash outflows on purchases and liabilities. These contracts are excluded from the table below. The amounts disclosed for
embedded derivatives represent the contractual cash outflows of purchase contracts some of which have embedded derivatives associated with them
which are financial assets.

At 31 December

Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years

2008

Held-for-
trading
derivatives
60,270
8,189
2,437
1,111
841
2,087
553
75,488

Embedded
derivatives
562
403
470
509
535
1,538
–
4,017

Embedded
derivatives
699
659
641
627
624
2,342
–
5,592

$ million

2007

Held-for-
trading
derivatives
82,465
8,541
2,906
707
338
592
447
95,996

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The table below shows cash outflows for derivative hedging instruments based upon contractual payment dates. The amounts reflect the maturity
profile of the fair value liability where the instruments will be settled net, and the gross settlement amount where the pay leg of a derivative will be
settled separately to the receive leg, as in the case of cross-currency interest rate swaps hedging non-US dollar finance debt. The swaps are with high
investment-grade counterparties and therefore the settlement day risk exposure is considered to be negligible.

At 31 December
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years

2008
3,426
3,024
1,037
1,731
1,389
129
10,736

$ million

2007
1,708
1,220
3,759
365
1,650
105
8,807

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Notes on financial statements

29. Other investments

Listed
Unlisted

2008
592
263
855

$ million

2007
1,617
213
1,830

Other investments comprise equity investments that have no fixed maturity date or coupon rate. These investments are classified as available-for-sale
financial assets and as such are recorded at fair value with the gain or loss arising as a result of changes in fair value recorded directly in equity.
Accumulated fair value changes are recycled to the income statement on disposal, or when the investment is impaired.

The fair value of listed investments has been determined by reference to quoted market bid prices. Unlisted investments are stated at cost less

accumulated impairment losses.

The most significant investment is the group’s stake in Rosneft which had a fair value of $483 million at 31 December 2008 (2007 $1,285
million). During 2008, an impairment loss of $517 million was recognized relating to the Rosneft investment (see Note 11), $29 million relating to other
listed investments and $17 million relating to unlisted investments (2007 $80 million relating to unlisted investments).

30. Inventories

Crude oil
Natural gas
Refined petroleum and petrochemical products

Supplies

Trading inventories

Cost of inventories expensed in the income statement

2008
4,396
107
9,318
13,821
1,588
15,409
1,412
16,821
266,982

$ million

2007
8,157
160
14,723
23,040
1,517
24,557
1,997
26,554
200,766

The inventory valuation at 31 December 2008 is stated net of a provision of $1,412 million (2007 $117 million) to write inventories down to their net
realizable value. The net movement in the provision during the year was a charge of $1,295 million (2007 $86 million credit).

31. Trade and other receivables

Financial assets

Trade receivables
Amounts receivable from jointly controlled entities
Amounts receivable from associates
Other receivables

Non-financial assets

Other receivables

Trade and other receivables are predominantly non-interest bearing.

2008

$ million

2007

Current Non-current

Current

Non-current

22,869
1,035
219
4,656
28,779

482
29,261

–
–
–
710
710

–
710

33,012
888
380
3,462
37,742

278
38,020

–
–
–
968
968

–
968

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Notes on financial statements

32. Cash and cash equivalents

Cash at bank and in hand
Cash equivalents

Listed
Unlisted

2008
4,001

4,060
136
8,197

$ million

2007
2,996

3
563
3,562

Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; and short-term highly liquid investments that
are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from
the date of acquisition.

Cash and cash equivalents at 31 December 2008 includes $2,133 million (2007 $1,294 million) that is restricted. This relates principally to

amounts on deposit to cover initial margins on trading exchanges.

33. Trade and other payables

Financial liabilities
Trade payables
Amounts payable to jointly controlled entities
Amounts payable to associates
Other payables

Non-financial liabilities

Production and similar taxes
Other payables

Trade and other payables are predominantly interest free.

2008

$ million

2007

Current Non-current

Current

Non-current

20,129
292
295
9,882
30,598

445
2,601
3,046
33,644

–
2,255
–
287
2,542

538
–
538
3,080

30,735
66
650
8,125
39,576

803
2,773
3,576
43,152

–
–
–
486
486

765
–
765
1,251

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Notes on financial statements

34. Derivative financial instruments

An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 28.

IAS 39 prescribes strict criteria for hedge accounting, whether as a cash flow or fair value hedge or a hedge of a net investment in a foreign

operation, and requires that any derivative that does not meet these criteria should be classified as held for trading and fair valued, with gains and
losses recognized in profit or loss.

In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in
relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed
rate debt, consistent with risk management policies and objectives. Additionally, the group has a well-established entrepreneurial trading operation that
is undertaken in conjunction with these activities using a similar range of contracts.

The fair values of derivative financial instruments at 31 December are set out below.

Derivatives held for trading
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives

Embedded derivatives

Commodity contracts
Interest rate contracts

Cash flow hedges

Currency forwards, futures and cylinders
Cross-currency interest rate swaps

Fair value hedges

Cross-currency interest rate swaps
Interest rate swaps

Hedges of net investments in foreign operations

Of which – current

– non-current

Fair
value
asset

278
3,813
6,945
978
90
12,104

397
–
397

120
109
229

465
367
832
2
13,564
8,510
5,054

2008

Fair
value
liability

(273)
(3,523)
(6,113)
(904)
(96)
(10,909)

(2,264)
–
(2,264)

(1,175)
(558)
(1,733)

(342)
–
(342)
–
(15,248)
(8,977)
(6,271)

$ million

2007

Fair
value
liability

(317)
(3,432)
(4,022)
(1,140)
–
(8,911)

(2,340)
(33)
(2,373)

(45)
(52)
(97)

Fair
value
asset

147
3,214
4,388
1,121
30
8,900

255
–
255

226
122
348

430
89
519
40
10,062
6,321
3,741

(9)
(17)
(26)
–
(11,407)
(6,405)
(5,002)

Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy
supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective,
and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of
contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these
exposures is monitored using market value-at-risk techniques as described in Note 28.

The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Changes during the year in the net fair value of derivatives held for trading purposes were as follows.

Fair value of contracts at 1 January 2008
Contracts realized or settled in the year
Fair value of options at inception
Fair value of other new contracts entered into during the year
Changes in fair values relating to price
Exchange adjustments
Fair value of contracts at 31 December 2008

Currency

(170)
24
–
–
151
–
5

Oil
price

(218)
190
(216)
66
468
–
290

Natural gas
price

Power
price

366
(216)
(201)
49
881
(47)
832

(19)
3
34
–
60
(4)
74

$ million

Total

(11)
(14)
(383)
115
1,539
(51)
1,195

Other

30
(15)
–
–
(21)
–
(6)

150

BP Annual Report and Accounts 2008
Notes on financial statements

34. Derivative financial instruments continued

Fair value of contracts at 1 January 2007
Contracts realized or settled in the year
Fair value of options at inception
Fair value of other new contracts entered into during the year
Changes in fair values relating to price
Exchange adjustments
Fair value of contracts at 31 December 2007

Oil
price

296
(289)
28
–
(253)
–
(218)

Natural gas
price

Power
price

Other

Total

$ million

855
(602)
168
1
(58)
2
366

42
(68)
36
–
(20)
(9)
(19)

113
(83)
–
–
–
–
30

1,411
(1,151)
232
1
(498)
(6)
(11)

Currency

105
(109)
–
–
(167)
1
(170)

If at inception of a contract the valuation cannot be supported by observable market data, any gain determined by the valuation methodology is not
recognized in the income statement but is deferred on the balance sheet and is commonly known as ‘day-one profit’. This deferred gain is recognized
in the income statement over the life of the contract until substantially all of the remaining contract term can be valued using observable market data
at which point any remaining deferred gain is recognized in income. Changes in valuation from this initial valuation are recognized immediately
through income.

The following table shows the changes in the day-one profits deferred on the balance sheet.

Fair value of contracts not recognized through the income statement at 1 January
Fair value of new contracts at inception not recognized in the income statement
Fair value recognized in the income statement
Fair value of contracts not recognized through profit at 31 December

Derivative assets held for trading have the following fair values and maturities.

2008

Natural
gas price

36
49
(2)
83

Oil price

–
66
(34)
32

Oil price

–
–
–
–

Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives

Less than
1 year

53
3,368
3,940
688
90
8,139

Less than
1 year

123
2,545
2,170
819
12
5,669

1-2 years

2-3 years

3-4 years

4-5 years

90
353
1,090
256
–
1,789

67
61
545
31
–
704

37
11
436
1
–
485

20
11
271
2
–
304

1-2 years

2-3 years

3-4 years

4-5 years

10
471
677
250
18
1,426

6
113
333
52
–
504

5
39
283
–
–
327

1
26
216
–
–
243

Derivative liabilities held for trading have the following fair values and maturities.

Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives

Less than
1 year

(257)
(3,001)
(3,484)
(722)
(95)
(7,559)

1-2 years

2-3 years

3-4 years

4-5 years

–
(458)
(987)
(159)
(1)
(1,605)

(2)
(36)
(438)
(18)
–
(494)

(1)
(18)
(310)
(4)
–
(333)

(13)
(9)
(283)
(1)
–
(306)

Over
5 years

11
9
663
–
–
683

Over
5 years

2
20
709
–
–
731

Over
5 years

–
(1)
(611)
–
–
(612)

$ million

2007

Natural
gas price

36
1
(1)
36

$ million

2008

Total

278
3,813
6,945
978
90
12,104

$ million

2007

Total

147
3,214
4,388
1,121
30
8,900

$ million

2008

Total

(273)
(3,523)
(6,113)
(904)
(96)
(10,909)

151

s
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t
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s

a
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F

BP Annual Report and Accounts 2008
Notes on financial statements

34. Derivative financial instruments continued

Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives

Less than
1 year

(145)
(2,735)
(2,089)
(832)
(5,801)

1-2 years

2-3 years

3-4 years

4-5 years

(99)
(512)
(527)
(246)
(1,384)

(32)
(135)
(298)
(61)
(526)

(16)
(25)
(219)
(1)
(261)

(15)
(22)
(185)
–
(222)

$ million

2007

Total

(317)
(3,432)
(4,022)
(1,140)
(8,911)

Over
5 years

(10)
(3)
(704)
–
(717)

The following table shows the fair value of derivative assets held for trading, analysed by maturity period and by methodology of fair value estimation.

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

Less than
1 year

40
7,628
471
8,139

Less than
1 year

169
5,417
83
5,669

1-2 years

2-3 years

3-4 years

4-5 years

43
1,614
132
1,789

30
553
121
704

7
361
117
485

6
190
108
304

1-2 years

2-3 years

3-4 years

4-5 years

53
1,174
199
1,426

49
363
92
504

3
225
99
327

–
140
103
243

$ million

2008

Total

128
10,402
1,574
12,104

$ million

2007

Total

276
7,319
1,305
8,900

Over
5 years

2
56
625
683

Over
5 years

2
–
729
731

The following table shows the fair value of derivative liabilities held for trading, analysed by maturity period and by methodology of fair value estimation.

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

Less than
1 year

(227)
(6,997)
(335)
(7,559)

Less than
1 year

(50)
(5,629)
(122)
(5,801)

1-2 years

2-3 years

3-4 years

4-5 years

–
(1,482)
(123)
(1,605)

(2)
(365)
(127)
(494)

–
(209)
(124)
(333)

(13)
(182)
(111)
(306)

1-2 years

2-3 years

3-4 years

4-5 years

(50)
(1,116)
(218)
(1,384)

–
(420)
(106)
(526)

(1)
(143)
(117)
(261)

(9)
(103)
(110)
(222)

$ million

2008

Total

(242)
(9,262)
(1,405)
(10,909)

$ million

2007

Total

(111)
(7,411)
(1,389)
(8,911)

Over
5 years

–
(27)
(585)
(612)

Over
5 years

(1)
–
(716)
(717)

Prices actively quoted refers to the fair value of contracts valued solely using quoted prices in an active market. Prices sourced from observable data or
market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data, for
example, swaps and physical forward contracts. Prices based on models and other valuation methods refers to the fair value of a contract valued in
part using internal models due to the absence of quoted prices, including over-the-counter options. The net change in fair value of contracts based on
models and other valuation methods during the year was a gain of $253 million (2007 $94 million loss and 2006 $117 million loss).

Gains and losses relating to derivative contracts are included either within sales and other operating revenues or within purchases in the

income statement depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures,
options, swaps and certain forward sales and forward purchases contracts. Gains or losses arise on contracts entered into for risk management
purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal procurement or sales activity for the
group but that are required to be fair valued under accounting standards. Also included within sales and other operating revenues are gains and losses
on inventory held for trading purposes. The total amount relating to all of these items was a gain of $6,721 million (2007 $376 million gain and 2006
$2,842 million gain).

152

BP Annual Report and Accounts 2008
Notes on financial statements

34. Derivative financial instruments continued
Embedded derivatives
Prior to the development of an active gas trading market, UK gas contracts were priced using a basket of available price indices, primarily relating to oil
products, power and inflation. After the development of an active UK gas market, certain contracts were entered into or renegotiated using pricing
formulae not directly related to gas prices, for example, oil product and power prices. In these circumstances, pricing formulae have been determined
to be derivatives, embedded within the overall contractual arrangements that are not clearly and closely related to the underlying commodity. The
resulting fair value relating to these contracts is recognized on the balance sheet with gains or losses recognized in the income statement.

All the embedded derivatives are valued using inputs that include price curves for each of the different products that are built up from active
market pricing data. Where necessary, these are extrapolated to the expiry of the contracts (the last of which is in 2018) using all available external
pricing information. Additionally, where limited data exists for certain products, prices are interpolated using historic and long-term pricing relationships.

The following table shows the changes during the year in the net fair value of embedded derivatives.

Fair value of contracts at 1 January
Contracts realized or settled in the year
Changes in valuation techniques or key assumptions
Changes in fair values relating to price
Exchange adjustments
Fair value of contracts at 31 December

Embedded derivative assets have the following fair values and maturities.

Commodity
price

Interest
rate

(2,085)
294
–
(928)
852
(1,867)

(33)
38
–
(5)
–
–

2008

Total

(2,118)
332
–
(933)
852
(1,867)

(2,064)
449
130
(567)
(33)
(2,085)

Commodity
price

Interest
rate

Commodity price embedded derivatives

116

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Commodity price embedded derivatives

Less than
1 year

193

1-2 years

2-3 years

3-4 years

4-5 years

Embedded derivative liabilities have the following fair values and maturities.

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

s
t
n
e
m
e
t
a
t
s

a
c
n
a
n
F

Commodity price embedded derivatives

(404)

(322)

(365)

(303)

(271)

(599)

(2,264)

Commodity price embedded derivatives
Interest rate embedded derivatives

Less than
1 year

(554)
(33)
(587)

1-2 years

2-3 years

3-4 years

4-5 years

(437)
–
(437)

(299)
–
(299)

(244)
–
(244)

(219)
–
(219)

$ million

2007

Total

(2,340)
(33)
(2,373)

Over
5 years

(587)
–
(587)

153

$ million

2007

Total

(2,090)
449
130
(574)
(33)
(2,118)

$ million

2008

Total

397

$ million

2007

Total

255

$ million

2008

Total

(26)
–
–
(7)
–
(33)

Over
5 years

BP Annual Report and Accounts 2008
Notes on financial statements

34. Derivative financial instruments continued
Embedded derivative assets have the following fair values when analysed by maturity period and by methodology of fair value estimation.

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

Less than
1 year

–
35
15
50

Less than
1 year

–
61
132
193

1-2 years

2-3 years

3-4 years

4-5 years

–
–
116
116

–
–
75
75

–
–
45
45

–
–
36
36

1-2 years

2-3 years

3-4 years

4-5 years

–
–
18
18

–
–
15
15

–
–
7
7

–
–
10
10

Over
5 years

–
–
75
75

Over
5 years

–
–
12
12

Embedded derivative liabilities have the following fair values when analysed by maturity period and by methodology of fair value estimation.

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

Less than
1 year

–
(10)
(394)
(404)

Less than
1 year

–
–
(587)
(587)

1-2 years

2-3 years

3-4 years

4-5 years

–
–
(322)
(322)

–
–
(365)
(365)

–
–
(303)
(303)

–
–
(271)
(271)

1-2 years

2-3 years

3-4 years

4-5 years

–
–
(437)
(437)

–
–
(299)
(299)

–
–
(244)
(244)

–
–
(219)
(219)

Over
5 years

–
–
(599)
(599)

Over
5 years

–
–
(587)
(587)

The net change in fair value of contracts based on models and other valuation methods during the year is a gain of $287 million (2007 gain of
$18 million and 2006 gain of $423 million).

The fair value gain (loss) on embedded derivatives is shown below.

$ million

2008

Total

–
35
362
397

$ million

2007

Total

–
61
194
255

$ million

2008

Total

–
(10)
(2,254)
(2,264)

$ million

2007

Total

–
–
(2,373)
(2,373)

Commodity price embedded derivatives
Interest rate embedded derivatives
Fair value (loss) gain

2008
(106)
(5)
(111)

2007
–
(7)
(7)

$ million

2006
604
4
608

The fair value gain (loss) in the above table includes $496 million of exchange gains (2007 $12 million of exchange losses and 2006 $179 million of
exchange losses) arising on contracts that are denominated in a currency other than the functional currency of the individual operating unit.

154

BP Annual Report and Accounts 2008
Notes on financial statements

34. Derivative financial instruments continued
Cash flow hedges
At 31 December 2008, the group held currency forwards and futures contracts and cylinders that were being used to hedge the foreign currency risk
of highly probable forecast transactions, as well as cross-currency interest rate swaps to fix the US dollar interest rate and US dollar redemption value,
with matching critical terms on the currency leg of the swap with the underlying non-US dollar debt issuance. Note 28 outlines the management of
risk aspects for currency and interest rate risk. For cash flow hedges the group only claims for the intrinsic value on the currency with any fair value
attributable to time value taken immediately to profit or loss. There were no highly probable transactions for which hedge accounting has been claimed
that have not occurred and no significant element of hedge ineffectiveness requiring recognition in the income statement. For cash flow hedges the
pre-tax amount removed from equity during the period and included in the income statement is a loss of $45 million (2007 gain of $74 million and 2006
gain of $93 million). Of this, a loss of $1 million is included in production and manufacturing expenses (2007 $143 million gain and 2006 $162 million
gain) and a loss of $44 million is included in finance costs (2007 $69 million loss and 2006 $69 million loss). The amount removed from equity during
the year and included in the carrying amount of non-financial assets was a gain of $38 million (2007 $40 million gain and 2006 $6 million gain).

The amounts retained in equity at 31 December 2008 are expected to mature and affect the income statement by a $826 million loss in 2009, a

loss of $92 million in 2010 and a loss of $182 million in 2011 and beyond.

Fair value hedges
At 31 December 2008, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk on
fixed rate debt issued by the group. The effectiveness of each hedge relationship is quantitatively assessed and demonstrated to continue to be highly
effective. The gain on the hedging derivative instruments taken to the income statement in 2008 was $2 million (2007 $334 million gain and 2006 $257
million gain) offset by a loss on the fair value of the finance debt of $20 million (2007 $327 million loss and 2006 $257 million loss).

The interest rate and cross-currency interest rate swaps have an average maturity of three to four years, (2007 one to two years) and are used

to convert sterling, euro, Swiss franc and Australian dollar denominated borrowings into US dollar floating rate debt. Note 28 outlines the group’s
approach to interest rate risk management.

Hedges of net investments in foreign operations
The group holds currency swap contracts as a hedge of a long-term investment in a UK subsidiary expiring in 2009. At 31 December 2008, the hedge
had a fair value of $2 million (2007 $40 million) and the loss on the hedge recognized in equity in 2008 was $38 million (2007 $67 million loss and 2006
$105 million gain). US dollars have been sold forward for sterling purchased and match the underlying liability with no significant ineffectiveness
reflected in the income statement.

35. Finance debt

Borrowings
Net obligations under finance leases

Within
1 year a

15,647
93
15,740

After
1 year

16,937
527
17,464

2008

Total

32,584
620
33,204

Within
1 year a

15,149
245
15,394

After
1 year

15,004
647
15,651

$ million

2007

Total

30,153
892
31,045

aAmounts due within one year include current maturities of long-term debt and borrowings that are expected to be repaid later than the earliest contractual repayment dates of within one year.
US Industrial Revenue/Municipal Bonds of $3,166 million (2007 $2,880 million) with earliest contractual repayment dates within one year have expected repayment dates ranging from 1 to 40 years (2007
1 to 35 years). The bondholders typically have the option to tender these bonds for repayment on interest reset dates; however, 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 internally assessing the maturity profile of its finance debt. Similar treatment is applied for loans
associated with long-term gas supply contracts totalling $1,806 million (2007 $1,899 million) that mature within nine years.

s
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e
m
e
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a
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s

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155

BP Annual Report and Accounts 2008
Notes on financial statements

35. Finance debt continued
The following table shows, by major currency, the group’s finance debt at 31 December and the weighted average interest rates achieved at those
dates through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures.

US dollar
Sterling
Euro
Other currencies

Fixed rate debt

Floating rate debt

Weighted
average
interest
rate
%

Weighted
average
time for
which rate
is fixed
Years

5
–
4
7

3
–
3
10

2
–
4
13

Weighted
average
interest
rate
%

2
6
4
7

5
6
5
7

Amount
$ million

9,005
–
74
216
9,295

9,541
–
81
268
9,890

Amount
$ million

22,116
21
1,330
442
23,909

20,460
35
107
553
21,155

Total
$ million

2008

31,121
21
1,404
658
33,204

2007
30,001
35
188
821
31,045

Finance leases
The group uses finance leases to acquire property, plant and equipment. These leases have terms of renewal but no purchase options and escalation
clauses. Renewals are at the option of the lessee. Future minimum lease payments under finance leases are set out below.

Future minimum lease payments payable within

1 year
2 to 5 years
Thereafter

Less finance charges
Net obligations
Of which – payable within 1 year

– payable within 2 to 5 years
– payable thereafter

2008

116
361
439
916
296
620
93
234
293

$ million

2007

268
393
630
1,291
399
892
245
217
430

Fair values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.

Long-term borrowings in the table below include the portion of debt that matures in the year from 31 December 2008, whereas in the balance

sheet the amount would be reported within current liabilities.

The carrying amount of the group’s short-term borrowings, comprising mainly commercial paper, bank loans, overdrafts and US Industrial

Revenue/Municipal Bonds, 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.

Short-term borrowings
Long-term borrowings
Net obligations under finance leases
Total finance debt

156

2008

Carrying
amount

9,913
22,671
620
33,204

Fair value

9,913
23,239
638
33,790

Fair value

11,212
19,094
908
31,214

$ million

2007

Carrying
amount

11,212
18,941
892
31,045

BP Annual Report and Accounts 2008
Notes on financial statements

36. Capital disclosures and analysis of changes in net debt

The group defines capital as the total equity of the group. The group’s objective for managing capital is to deliver competitive, secure and sustainable
returns to maximize long-term shareholder value. BP is not subject to any externally-imposed capital requirements.

The group’s approach to managing capital is set out in its financial framework. The group aims to balance returns to shareholders between

long-term growth and current returns via the dividend whilst maintaining capital discipline in relation to investing activities and taking action on costs
to respond to the current environment. At the beginning of 2008, the group rebalanced returns to shareholders by increasing the dividend component.
As a result, the share buyback programme was curtailed and then suspended in September in light of the uncertain environment.

The group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross

finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange
and interest rate risks relating to finance debt, for which hedge accounting is claimed, less cash and cash equivalents. Net debt and net debt ratio are
non-GAAP measures. BP uses these measures to provide useful information to investors. Net debt enables investors to see the economic effect of
gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to
equity from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. All components of
equity are included in the denominator of the calculation. We believe that a net debt ratio in the range 20-30% provides an efficient capital structure
and an appropriate level of financial flexibility.

At 31 December 2008 the net debt ratio was 21% (2007 22%).

At 31 December

Gross debt
Less: Cash and cash equivalents
Less: Fair value (liability) asset of hedges related to finance debt
Net debt
Equity
Net debt ratio

An analysis of changes in net debt is provided below.

Movement in net debt

At 1 January
Exchange adjustments
Net cash flow
Other movements
At 31 December

aIncluding fair value of associated derivative financial instruments.

2008

33,204
8,197
(34)
25,041
92,109
21%

Finance
debt a

(30,379)
102
(2,825)
(136)
(33,238)

Cash and
cash
equivalents

3,562
(184)
4,819
–
8,197

2008

Net
debt

(26,817)
(82)
1,994
(136)
(25,041)

Finance
debta

(23,712)
(122)
(6,411)
(134)
(30,379)

Cash and
cash
equivalents

2,590
135
837
–
3,562

$ million

2007

31,045
3,562
666
26,817
94,652
22%

$ million

2007

Net
debt

(21,122)
13
(5,574)
(134)
(26,817)

Revised definition of net debt
Net debt has been redefined to include the fair value of associated derivative financial instruments that are used to hedge foreign exchange and
interest rate risks relating to finance debt, for which hedge accounting is claimed. The derivatives are reported on the balance sheet within the
headings ‘Derivative financial instruments’. Amounts for comparative periods are presented on a consistent basis.

Net debt
Equity
Ratio of net debt to net debt plus equity

$ million

2007

As amended

As reported

26,817
94,652
22%

27,483
94,652
23%

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BP Annual Report and Accounts 2008
Notes on financial statements

37. Provisions

At 1 January 2008
Exchange adjustments
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Utilization
Deletions
At 31 December 2008
Of which – expected to be incurred within 1 year

– expected to be incurred in more than 1 year

At 1 January 2007
Exchange adjustments
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Utilization
Deletions
At 31 December 2007
Of which – expected to be incurred within 1 year

– expected to be incurred in more than 1 year

Decommissioning Environmental

9,501
(1,208)
327
–
202
(402)
(2)
8,418
322
8,096

2,107
(45)
270
(107)
43
(512)
(65)
1,691
418
1,273

Decommissioning Environmental

8,365
168
1,163
–
195
(297)
(93)
9,501
447
9,054

2,127
19
373
(151)
44
(305)
–
2,107
431
1,676

Litigation
and other

3,487
(107)
2,059
(513)
42
(1,424)
–
3,544
805
2,739

Litigation
and other

3,152
11
1,376
(196)
44
(899)
(1)
3,487
1,317
2,170

$ million

Total

15,095
(1,360)
2,656
(620)
287
(2,338)
(67)
13,653
1,545
12,108

$ million

Total

13,644
198
2,912
(347)
283
(1,501)
(94)
15,095
2,195
12,900

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. The provision for the costs of decommissioning these production facilities and pipelines at the end of their
economic lives has been estimated using existing technology, at current prices or long-term assumptions, depending on the expected timing of the
activity, and discounted using a real discount rate of 2.0% (2007 2.0%). These costs are generally 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. Where BP has entered into a contract for the execution of decommissioning activity, these
amounts are generally reported within accruals or other payables.

Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be reliably estimated.

Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provision for
environmental liabilities has been estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2007 2.0%).
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 the
liability.

Included within the litigation and other category at 31 December 2008 are provisions for litigation of $1,446 million (2007 $1,737 million), for
deferred employee compensation of $792 million (2007 $761 million) and for expected rental shortfalls on surplus properties of $251 million (2007
$320 million). 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 2.5% (2007 4.5%) or a real discount rate of 2.0% (2007 2.0%), as appropriate. No additional provisions were made during
2008 in respect of the Texas City incident (in 2007 the provision was increased by $500 million). Disbursements to claimants in 2008 were $410 million
(2007 $314 million) and the provision at 31 December 2008 was $46 million (2007 $456 million).

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Notes on financial statements

38. Pensions and other post-retirement benefits

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.

In particular, the primary pension arrangement in the UK is a funded final salary pension plan that remains open to new employees. Retired

employees draw the majority of their benefit as an annuity.

In the US, a range of retirement arrangements is provided. These include a funded final salary pension plan for certain heritage employees

and a cash balance arrangement for new hires. Retired US employees typically take their pension benefit in the form of a lump sum payment.
US employees are also eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company
contributions.

The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as
they fall due. During 2008, contributions of $6 million (2007 $524 million and 2006 $438 million) and $362 million (2007 $97 million and 2006 $181
million) were made to the UK plans and US plans respectively. In addition, contributions of $130 million (2007 $127 million and 2006 $136 million)
were made to other funded defined benefit plans. The aggregate level of contributions in all countries in 2009 is expected to be approximately
$500 million, and includes contributions that we expect to be required to make by law or under contractual agreements as well as an allowance
for discretionary funding.

Certain group companies, principally 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 obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method.

The date of the most recent actuarial review was 31 December 2008.

The material financial assumptions used for estimating the benefit obligations of the various plans are set out below. The assumptions are
reviewed by management at the end of each year, and are used to evaluate accrued pension and other post-retirement benefits at 31 December.
The same assumptions are used to determine pension and other post-retirement benefit expense for the following year, that is, the assumptions
at 31 December 2008 are used to determine the pension liabilities at that date and the pension expense for 2009.

Financial assumptions

Discount rate for pension

plan liabilities

Discount rate for post-retirement

benefit plans

Rate of increase in salaries
Rate of increase for pensions

in payment

Rate of increase in deferred

pensions

Inflation

2008

6.3

n/a
4.9

3.0

3.0
3.0

2007

5.7

n/a
5.1

3.2

3.2
3.2

2006

5.1

n/a
4.7

2.8

2.8
2.8

2008

2007

6.3

6.2
2.2

–

–
0.4

6.1

6.4
4.2

–

–
2.4

2006

5.7

5.9
4.2

–

–
2.4

2008

5.7

n/a
3.5

1.7

1.0
2.0

2007

5.6

n/a
3.7

1.8

1.2
2.2

Other

2006

4.8

n/a
3.6

1.8

1.1
2.2

Our discount rate assumptions are based on third-party AA corporate bond indices and for our largest schemes in the UK and US we use yields which
reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US schemes are based on the difference
between the yields on index-linked and fixed-interest long-term government bonds. In other countries we use either this approach, or the central bank
inflation target, or advice from the local actuary depending on the information that is available to us. The inflation assumptions are used to determine
the rate of increase for pensions in payment and the rate of increase for deferred pensions where there is such an increase.

Our assumptions for the rate of increase in salaries are based on our inflation assumption plus an allowance for expected long-term real salary

growth. These include allowance for promotion-related salary growth, of between 0.3% and 0.4% depending on country. In addition to the financial
assumptions, we regularly review the demographic and mortality assumptions.

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BP Annual Report and Accounts 2008
Notes on financial statements

38. Pensions and other post-retirement benefits continued
Mortality assumptions reflect best practice in the countries in which we provide pensions, and have been chosen with regard to the latest available
published tables adjusted where appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future.
As part of the triannual valuation of our UK pensions funds, our UK mortality assumption was reviewed and updated at end-2008 resulting in an
increase in the liability of around $900 million. BP’s most substantial pension liabilities are in the UK, the US and Germany where our mortality
assumptions are as follows:

Mortality assumptions

Life expectancy at age 60 for a
male currently aged 60
Life expectancy at age 60 for a
male currently aged 40
Life expectancy at age 60 for a
female currently aged 60
Life expectancy at age 60 for a
female currently aged 40

2008

2007

25.9

28.9

28.5

31.4

24.0

25.1

26.9

27.9

2006

23.9

25.0

26.8

27.8

2008

2007

24.4

25.9

26.1

27.0

24.3

25.8

26.1

27.0

2006

24.2

25.8

26.0

26.9

2008

2007

23.0

25.9

27.6

30.3

22.4

25.3

27.0

29.7

Years

Germany

2006

22.2

25.2

26.9

29.6

Our assumptions for future US healthcare cost trend rate reflect the rate of actual cost increases seen in recent years for the initial trend rate, and the
ultimate trend rate reflects our long-term expectations based on past medical inflation seen over a longer period of time. The assumed future US
healthcare cost trend rate is as follows:

Initial US healthcare cost trend rate
Ultimate US healthcare cost trend rate
Year in which ultimate trend rate is reached

2008
8.6
5.0
2015

2007
9.0
5.0
2013

2006
9.3
5.0
2013

Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligation of
the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in
portfolio management.

A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term with an acceptable level

of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the
investment portfolios are highly diversified. The long-term asset allocation policy for the major plans is as follows:

Asset category
Total equity
Bonds/cash
Property/real estate

Policy range
%
45-75
17.5-50
0-10

Some of the group’s pension plans use derivative financial instruments as part of their asset mix and to manage the level of risk. The group’s main
pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.

Return on asset assumptions reflect the group’s expectations built up by asset class and by plan. The group’s expectation is derived from

a combination of historical returns over the long term and the forecasts of market professionals. Our assumption for return on equities is based on
a long-term view, and the size of the resulting equity risk premium over government bond yields is reviewed each year for reasonableness. Our
assumption for return on bonds reflects the portfolio mix of government fixed-interest, index-linked and corporate bonds.

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Notes on financial statements

38. Pensions and other post-retirement benefits continued
The expected long-term rates of return and market values of the various categories of asset held by the defined benefit plans at 31 December are set
out below. The market values shown include the effects of derivative financial instruments. The amounts classified as equities include investments
in companies listed on stock exchanges as well as unlisted investments. The market value of unlisted investments at 31 December 2008 was
$2,819 million (2007 $2,491 million and 2006 $1,506 million). The market value of pension assets at the end of 2008 is lower than at the end of 2007
due to a fall in the market value of investments when expressed in their local currencies and a reduction in value that arises from changes in exchange
rates (reducing the reported value of investments when expressed in US dollars). Movements in the value of plan assets during the year are shown in
detail in the table on page 162.

UK pension plans
Equities
Bonds
Property
Cash

US pension plans
Equities
Bonds
Property
Cash

US other post-retirement benefit plans

Equities
Bonds

Other plans
Equities
Bonds
Property
Cash

Expected
long-term
rate of
return

2008

Market
value

Expected
long-term
rate of
return

2007

Market
value

Expected
long-term
rate of
return

2006

Market
value

$ million

8.0
6.1
6.5
2.9
7.4

8.5
3.7
8.0
1.9
8.0

8.5
3.7
7.3

8.4
4.2
6.3
3.1
5.8

13,704
3,258
978
299
18,239

3,991
1,247
8
131
5,377

9
4
13

799
1,481
127
118
2,525

8.0
4.4
6.5
5.6
7.3

8.5
5.0
8.0
3.6
8.0

8.5
5.0
7.6

8.1
5.0
5.7
4.2
6.4

24,106
5,279
1,259
977
31,621

6,610
1,347
16
72
8,045

17
6
23

1,260
1,491
145
214
3,110

7.5
4.7
6.5
3.8
7.0

8.5
5.0
8.0
3.2
8.0

8.5
5.0
7.5

7.6
4.6
4.7
3.0
5.8

23,631
3,881
1,370
379
29,261

6,528
1,371
15
41
7,955

19
7
26

1,158
1,199
120
191
2,668

The assumed rate of investment return, discount rate, inflation and the assumed US healthcare cost trend rate all 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:

Investment return

Effect on pension and other post-retirement benefit expense in 2009

Discount rate

Effect on pension and other post-retirement benefit expense in 2009
Effect on pension and other post-retirement benefit obligation at 31 December 2008

Inflation rate

Effect on pension and other post-retirement benefit expense in 2009
Effect on pension and other post-retirement benefit obligation at 31 December 2008

US healthcare cost trend rate

Effect on US other post-retirement benefit expense in 2009
Effect on US other post-retirement obligation at 31 December 2008

$ million

One-percentage point

Increase

Decrease

(256)

258

(88)
(3,783)

129
4,818

375
3,407

(286)
(2,783)

29
335

(23)
(277)

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BP Annual Report and Accounts 2008
Notes on financial statements

38. Pensions and other post-retirement benefits continued

Expected return on plan assets
Interest on plan liabilities
Other finance income (expense)
Analysis of the amount recognized in the statement of recognized income and expense
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial (loss) gain recognized in statement of recognized income and expense
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Current service costa
Past service cost
Interest cost
Curtailment
Settlement
Special termination benefitsc
Contributions by plan participants
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Actuarial (gain) loss on obligation
Benefit obligation at 31 Decembera
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Expected return on plan assetsa e
Contributions by plan participants
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Actuarial loss on plan assetse
Fair value of plan assets at 31 December
Surplus (deficit) at 31 December
Represented by

Asset recognized
Liability recognized

The surplus (deficit) may be analysed between funded and unfunded plans as follows

Funded
Unfunded

The defined benefit obligation may be analysed between funded and unfunded

plans as follows
Funded
Unfunded

UK
pension
plans

448
7
30
–
485

2,094
(1,239)
855

(6,946)
1,570
(73)
(5,449)

23,927
(6,408)
448
7
1,239
–
(3)
33
42
(1,131)
(2)
(1,497)
16,655

31,621
(7,447)
2,094
42
6
(1,131)
(6,946)
18,239
1,584

1,682
(98)

1,584

1,682
(98)

1,584

US
pension
plans

US other post-
retirement
benefit
plans

235
74
–
170
479

632
(444)
188

(2,895)
3
(194)
(3,086)

7,409
–
235
74
444
–
–
–
–
(767)
(52)
191
7,534

8,045
–
632
–
362
(767)
(2,895)
5,377
(2,157)

–
(2,157)

(2,157)

(1,734)
(423)

(2,157)

40
–
–
–
40

2
(198)
(196)

(8)
215
18
225

3,178
–
40
–
198
–
–
–
–
(4)
(176)
(233)
3,003

23
–
2
–
–
(4)
(8)
13
(2,990)

–
(2,990)

(2,990)

(31)
(2,959)

(2,990)

$ million

2008

Total

851
82
42
195
1,170

2,922
(2,331)
591

(10,253)
2,002
(179)
(8,430)

43,100
(7,036)
851
82
2,331
(3)
(6)
51
54
(2,105)
(649)
(1,823)
34,847

42,799
(7,761)
2,922
54
498
(2,105)
(10,253)
26,154
(8,693)

1,738
(10,431)

(8,693)

(437)
(8,256)

(8,693)

Other
plans

128
1
12
25
166

194
(450)
(256)

(404)
214
70
(120)

8,586
(628)
128
1
450
(3)
(3)
18
12
(203)
(419)
(284)
7,655

3,110
(314)
194
12
130
(203)
(404)
2,525
(5,130)

56
(5,186)

(5,130)

(354)
(4,776)

(5,130)

(16,557)
(98)
(16,655)

(7,111)
(423)
(7,534)

(44)
(2,959)
(3,003)

(2,879)
(4,776)
(7,655)

(26,591)
(8,256)
(34,847)

aThe costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are generally included in current service cost and
the costs of administering our other post-retirement benefit plans are included in the benefit obligation.
blncluded within production and manufacturing expenses and distribution and administration expenses.
cThe charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
dThe benefit payments amount shown above comprises $2,697 million benefits plus $57 million of plan expenses incurred in the administration of the benefit.
eThe actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial loss on plan assets as disclosed above.

At 31 December 2008 reimbursement balances due from or to other companies in respect of pensions amounted to $455 million reimbursement
assets (2007 $496 million) and $61 million reimbursement liabilities (2007 $72 million). These balances are not included as part of the pension
liability, but are reflected elsewhere in the group balance sheet.
162

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Notes on financial statements

38. Pensions and other post-retirement benefits continued

Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service cost
Settlement, curtailment and special termination benefits
Payments to defined contribution plans
Total operating chargeb
Analysis of the amount credited (charged) to other finance expense
Expected return on plan assets
Interest on plan liabilities
Other finance income (expense)
Analysis of the amount recognized in the statement of recognized income and expense
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial gain recognized in statement of recognized income and expense
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Current service costa
Past service cost
Interest cost
Curtailment
Settlement
Special termination benefitsc
Contributions by plan participants
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Acquisitions
Disposals
Actuarial gain on obligation
Benefit obligation at 31 Decembera
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Expected return on plan assetsa e
Contributions by plan participants
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Acquisitions
Disposals
Actuarial gain (loss) on plan assetse
Fair value of plan assets at 31 December
Surplus (deficit) at 31 December
Represented by

Asset recognized
Liability recognized

The surplus (deficit) may be analysed between funded and unfunded plans as follows

Funded
Unfunded

UK
pension
plans

492
5
36
–
533

2,075
(1,198)
877

406
513
(162)
757

23,289
394
492
5
1,198
(7)
(3)
46
43
(1,085)
(3)
–
(91)
(351)
23,927

29,261
488
2,075
43
524
(1,085)
–
(91)
406
31,621
7,694

7,818
(124)
7,694

US
pension
plans

US other post-
retirement
benefit
plans

227
10
–
184
421

613
(425)
188

(28)
358
(27)
303

7,695
–
227
10
425
–
–
–
–
(580)
(37)
–
–
(331)
7,409

7,955
–
613
–
97
(580)
–
(12)
(28)
8,045
636

989
(353)
636

978
(342)
636

43
–
–
–
43

2
(190)
(188)

–
137
29
166

3,300
–
43
–
190
–
–
–
–
(5)
(184)
–
–
(166)
3,178

26
–
2
–
–
(5)
–
–
–
23
(3,155)

–
(3,155)
(3,155)

(29)
(3,126)
(3,155)

(52)
(3,126)
(3,178)

$ million

2007

Total

894
15
38
209
1,156

2,855
(2,203)
652

302
1,615
(200)
1,717

42,433
1,311
894
15
2,203
(7)
(3)
48
55
(1,852)
(603)
141
(120)
(1,415)
43,100

39,910
804
2,855
55
748
(1,852)
101
(124)
302
42,799
(301)

8,914
(9,215)
(301)

8,504
(8,805)
(301)

(34,295)
(8,805)
(43,100)

Other
plans

132
–
2
25
159

165
(390)
(225)

(76)
607
(40)
491

8,149
917
132
–
390
–
–
2
12
(182)
(379)
141
(29)
(567)
8,586

2,668
316
165
12
127
(182)
101
(21)
(76)
3,110
(5,476)

107
(5,583)
(5,476)

(263)
(5,213)
(5,476)

(3,373)
(5,213)
(8,586)

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s

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F

The defined benefit obligation may be analysed between funded and unfunded plans as follows

Funded
Unfunded

(23,803)
(124)
(23,927)

(7,067)
(342)
(7,409)

aThe costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are generally included in current service cost and
the costs of administering our other post-retirement benefit plans are included in the benefit obligation.
bIncluded within production and manufacturing expenses and distribution and administration expenses.
cThe charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of a restructuring programme in the UK.
dThe benefit payments amount shown above comprises $2,398 million benefits plus $57 million of plan expenses incurred in the administration of the benefit.
eThe actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain on plan assets as disclosed above.

163

BP Annual Report and Accounts 2008
Notes on financial statements

38. Pensions and other post-retirement benefits continued

Expected return on plan assets
Interest on plan liabilities
Other finance income (expense)

Analysis of the amount recognized in the statement of recognized income

and expense

Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial gain recognized in statement of recognized income and expense

UK
pension
plans

US
pension
plans

US other
post-
retirement
benefit
plans

432
(74)
4
–
362

1,711
(1,006)
705

1,305
114
(24)
1,395

216
38
–
161
415

564
(423)
141

521
195
17
733

42
–
–
–
42

2
(186)
(184)

–
111
80
191

$ million

2006

Total

829
3
231
177
1,240

2,410
(1,940)
470

1,967
772
(124)
2,615

Other
plans

139
39
227
16
421

133
(325)
(192)

141
352
(197)
296

History of surplus (deficit) and of experience gains and losses

Benefit obligation at 31 December
Fair value of plan assets at 31 December
Deficit

Experience losses on plan liabilities
Actual return less expected return on pension plan assets
Actual return on plan assets
Actuarial (loss) gain recognized in statement of recognized income and expense
Cumulative amount recognized in statement of recognized income and expense

2008

2007

2006

2005

34,847
26,154
(8,693)

(178)
(10,253)
(7,331)
(8,430)
(2,940)

43,100
42,799
(301)

(200)
302
3,157
1,717
5,490

42,433
39,910
(2,523)

(124)
1,967
4,377
2,615
3,773

38,855
32,907
(5,948)

(212)
3,364
5,502
975
1,158

Estimated future benefit payments
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2018 are as follows: