BP Annual Report 2009 | Quarterlytics

← All annual reports

FY2009 Annual Report · BP

Loading PDF…

beyond petroleum®

Annual Report
and Accounts
2009

B
P
A
n
n
u
a

R
e
p
o
r
t
a
n
d
A
c
c
o
u
n
t
s
2
0
0
9

bp.com/annualreport

What’s inside?

3 Business review

93 Additional information for

Chairman’s letter
Group chief executive’s review
Our performance

4
6
8
10 Group overview
22 Exploration and Production
36 Reﬁ ning and Marketing
42 Other businesses and corporate
44 Research and technology
46 Corporate responsibility
s
52 Relationships with suppliers and contractor
52 Regulation of the group’s business
52 Organizational structure
53 Financial performance
61

Liquidity and capital resources

65 Board performance and biographies

66 Directors and senior management
69 Board performance report

81 Directors’ remuneration report

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

shareholders
94 Critical accounting policies
96 Property, plants and equipment
96 Share ownership
98 Major shareholders and related party transactions
98 Dividends
99 Legal proceedings
100 Share prices and listings
101 Memorandum and Articles of Association
103 Exchange controls
103 Taxation
105 Documents on display
105 Controls and procedures
106 Code of ethics
106 Principal accountants’ fees and services
106 Corporate governance practices
107 Purchases of equity securities by the issuer

and afﬁ liated purchasers

107 Fees and charges payable by a holder of ADSs
108 Fees and payments made by the Depositary

to the issuer

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

109 Financial statements

110 Consolidated ﬁ nancial statements of the BP group
116 Notes on ﬁ nancial statements
179 S upplementary information on oil and

natural gas (unaudited)

193 Parent company ﬁ nancial statements of BP p.l.c.

BP Annual Report and Accounts 2009

Information for shareholders

Reports and publications

You can order BP’s printed publications,
free of charge, from:

US and Canada
Precision IR
Toll-free +1 888 301 2505
Fax +1 804 327 7549
bpreports@precisionir.com

UK and Rest of World
BP Distribution Services
Tel +44 (0)870 241 3269
Fax +44 (0)870 240 5753
bpdistributionservices@bp.com

BP’s reports and publications are available to view online
or download from www.bp.com/annualreport.

Annual Review
Read a summary of our ﬁ nancial
and operating performance in
BP Annual Review 2009 in print
or online.
www.bp.com/annualreview

Sustainability Review
Read the summary
BP Sustainability Review
2009 in print or read more
online from April 2010.
www.bp.com/sustainability

Acknowledgements
Design sasdesign.co.uk
Typesetting Bowne, London
Printing St Ives Westerham Press Ltd, UK,
ISO 14001, FSC-certiﬁ ed and CarbonNeutral®
Photography Stuart Conway, Graham Trott

Paper
This Annual Report and Accounts is
printed on FSC-certiﬁ ed Revive Pure
White Uncoated (cover) and Revive
Pure White Offset (text pages).
This paper has been independently
certiﬁ ed according to the rules of the
Forest Stewardship Council (FSC) and
was manufactured at a mill that holds
ISO 14001 accreditation. The inks
used are all vegetable oil based.

209

BP Annual Report and Accounts 2009

Information about this report

This document constitutes the Annual Report and Accounts of BP p.l.c. for the year ended 31 December 2009 in accordance with UK requirements
and is dated 26 February 2010. This document also contains information that will be included in the company’s Annual Report on Form 20-F 2009 in
accordance with the requirements of the US Securities and Exchange Commission (SEC). Such information will be supplemented and may be updated
at the time of filing that document with the SEC, or later amended, if necessary.

The Annual Report and Accounts for the year ended 31 December 2009 contains the Directors’ Report, including the Business Review and

Management Report, on pages 3-80 and 93-108, 110 and 193. The Directors’ Remuneration Report is on pages 81-92. The consolidated financial
statements are on pages 109-192. The report of the auditor is on page 111 for the group and page 194 for the company.

BP Annual Report and Accounts 2009 and BP Annual Review 2009 may be downloaded from www.bp.com/annualreport. No material on the

BP website, other than the items identified as BP Annual Report and Accounts 2009 and BP Annual Review 2009, forms any part of those documents.

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

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

Profit for the year attributable to BP shareholders
Replacement cost profit

Dividends paid per ordinary share – cents
– pence

Dividends paid per American depositary share (ADS) – dollars

2009
26,426
(1,302)
(8,365)
(181)
16,578
(2,623)
13,955
24,800
743
(2,322)
(717)
22,504
(1,302)
(7,066)
(181)
13,955

88.49
74.49
56.00
36.417
3.360

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

112.59
136.20
55.05
29.387
3.303

$ million

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

108.76
95.85
42.30
20.995
2.538

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

On pages 4-9, references within BP Annual Report and Accounts 2009 to ‘profits’, ‘results’ and ‘return on average capital employed’ are to those
measures on a replacement cost basis unless otherwise indicated.

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

and operations of the parent company and those of its subsidiaries.

The term ‘shareholder’ in this Annual Report and Accounts means, unless the context otherwise requires, investors in the equity capital of
BP p.l.c., both direct and/or indirect. As BP shares, in the form of ADSs, are listed on the New York Stock Exchange (NYSE), an Annual Report on
Form 20-F will be filed with the SEC in accordance with the US Securities Exchange Act of 1934. When filed, copies may be obtained free of charge
(see page 108).

Cautionary statement
BP Annual Report and Accounts 2009 contains certain forward-looking statements within the meaning of the US Private Securities Litigation Reform
Act of 1995 with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with
respect to these items. For more details, please see Forward-looking statements on page 21.

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

BP Annual Report and Accounts 2009

Miscellaneous terms

In this document, unless the context
otherwise requires, the following terms
shall have the meaning set out below.

ADR
American depositary receipt.

ADS
American depositary share.

AGM
Annual general meeting.

Amoco
The former Amoco Corporation
and its subsidiaries.

Atlantic Richfield
Atlantic Richfield Company
and its subsidiaries.

Associate
An entity, including an unincorporated
entity such as a partnership, over which
the group has significant influence and
that is neither a subsidiary nor a joint
venture. Significant influence is the
power to participate in the financial and
operating policy decisions of an entity
but is not control or joint control over
those policies.

Barrel
42 US gallons.

b/d
barrels per day.

boe
barrels of oil equivalent.

BP, BP group or the group
BP p.l.c. and its subsidiaries.

Burmah Castrol
Burmah Castrol PLC and its
subsidiaries.

Cent or c
One-hundredth of the US dollar.

The company
BP p.l.c.

Dollar or $
The US dollar.

EU
European Union.

Gas
Natural gas.

Hydrocarbons
Crude oil and natural gas.

IFRS
International Financial Reporting
Standards.

Joint control
Joint control is the contractually agreed
sharing of control over an economic
activity, and exists only when the
strategic financial and operating
decisions relating to the activity require
the unanimous consent of the parties
sharing control (the venturers).

Joint venture
A contractual arrangement whereby
two or more parties undertake an
economic activity that is subject to
joint control.

Jointly controlled asset
A joint venture where the venturers
jointly control, and often have a direct
ownership interest in the assets of the
venture. The assets are used to obtain
benefits for the venturers. Each
venturer may take a share of the output
from the assets and each bears an
agreed share of the expenses incurred.

Jointly controlled entity
A joint venture that involves the
establishment of a corporation,
partnership or other entity in which
each venturer has an interest. A
contractual arrangement between the
venturers establishes joint control over
the economic activity of the entity.

Liquids
Crude oil, condensate and natural
gas liquids.

LNG
Liquefied natural gas.

London Stock Exchange or LSE
London Stock Exchange plc.

LPG
Liquefied petroleum gas.

mb/d
thousand barrels per day.

mboe/d
thousand barrels of oil equivalent
per day.

mmBtu
million British thermal units.

mmboe
million barrels of oil equivalent.

mmcf
million cubic feet.

mmcf/d
million cubic feet per day.

MTBE
Methyl tertiary butyl ether.

MW
Megawatt.

NGLs
Natural gas liquids.

OPEC
Organization of Petroleum Exporting
Countries.

Ordinary shares
Ordinary fully paid shares in BP p.l.c. of
25c each.

Pence or p
One-hundredth of a pound sterling.

Pound, sterling or £
The pound sterling.

Preference shares
Cumulative First Preference Shares and
Cumulative Second Preference Shares
in BP p.l.c. of £1 each.

PSA
A production-sharing agreement (PSA)
is an arrangement through which an oil
company bears the risks and costs of
exploration, development and
production. In return, if exploration is
successful, the oil company receives
entitlement to variable physical
volumes of hydrocarbons, representing
recovery of the costs incurred and a
stipulated share of the production
remaining after such cost recovery.

SEC
The United States Securities and
Exchange Commission.

Subsidiary
An entity that is controlled by the BP
group. Control is the power to govern
the financial and operating policies of
an entity so as to obtain the benefits
from its activities.

Tonne
2,204.6 pounds.

UK
United Kingdom of Great Britain and
Northern Ireland.

US
United States of America.

Business review

4 Chairman’s letter

52 Relationships with suppliers and

contractors

6 Group chief executive’s review

52 Regulation of the group’s business

52 Organizational structure

53 Financial performance

61 Liquidity and capital resources

8 Our performance

10 Group overview

22 Exploration and Production

36 Refining and Marketing

42 Other businesses and corporate

44 Research and technology

46 Corporate responsibility

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

I have joined BP at an exciting and testing
time for the energy industry and the wider
world. Crisis in the global economy has
asked tough questions of everyone.
Meanwhile, two long-term issues require
our continued attention – the high growth
in energy demand expected over coming
years, and the complex challenges created
by climate change.

Naturally, more and more people
want to improve their quality of life, and
a reliable supply of affordable energy
is central to meeting their needs and
aspirations. Sharing the beneﬁ ts of energy
with communities around the world
represents important human progress,
but this must be achieved with care.

Such pressing matters place BP at
the heart of what is important to society.
While many of the group’s operations are
conducted far from our towns and cities,
what we produce is essential to everyday
life. I have been here only a short time, but
I have already seen in action the remarkable
skills and technology that ﬁ nd and extract
raw materials and turn them into much-
needed energy products. I am particularly
impressed by the professionalism and
sheer tenacity of the BP people I have
met. There is a powerful spirit here.

This spirit can be seen clearly within

the executive team, under the leadership
of Tony Hayward. Their focus on safety,
operational performance and culture has
produced great results across the group,
despite tough market conditions. There
is still more to do, and I look forward
to working with them as BP moves
forward. Our employees have also shown
considerable determination over the
past 12 months. They have helped to
drive a notable and continuing business
transformation and I thank them for
their commitment.

BP Annual Report and Accounts 2009
Business review

Chairman’s letter

A revitalized
BP

Carl-Henric Svanberg Chairman
26 February 2010

Highlights

• BP playing key role in addressing the

energy challenge.

• Strong board enhanced by new appointments.

• Powerful spirit among BP people.

The success of BP today is, in many ways,
testament to Peter Sutherland’s unique
style in leading the board. As chairman for
12 years and non-executive board director
for 14 years, Peter steered the group through
many challenges. He leaves a strong BP that
is well positioned for further success. As
a board, we thank him for his exceptional
contribution. We also thank those non-
executives who are to leave after the annual
general meeting. Sir Ian Prosser departs
after 12 years of outstanding service,
including 10 years as deputy chairman.
Erroll Davis, Jr joined in 1998 and played
an important role in key non-executive
committees. Sir Tom McKillop joined in
2004 and chose to retire this year, having
made a strong impression. I know my
fellow board members greatly appreciate
their contributions.

We are now in the process of
appointing experienced and talented
newcomers to the board. I have worked
closely with colleagues on the nominations
committee to select individuals whose
skills match the needs of the business
while ensuring appropriate independence.
As part of our continuing refreshment of
the board, I am delighted that Paul Anderson
has recently joined the board and that Ian
Davis will join in April 2010. Our clear
objective as a board is to sustain the success
of the group and I can tell you that we will
not lack ambition. BP has driven itself back
to competitive ﬁ tness; we must ensure we
build on the hard work of the past three
years and continue to grow a successful
and enduring company. We now have the
opportunity to plot the group’s future position
within a changing energy landscape.

The ﬁ nancial crisis has highlighted concerns
about the way in which companies operate.
In some cases, levels of trust between
boards of directors and shareholders have
been impacted. From my early contact with
BP shareholders, I understand that the BP
board has long been actively engaged in
dialogue. I strongly endorse and encourage
this and intend to build on such good
practice. BP is respected for its leadership
on governance and we will keep looking
for ways to enhance how we govern and
report on the group.

Risk remains a key issue for every

business, but at BP it is fundamental to
what we do. We operate at the frontiers
of the energy industry, in an environment
where attitude to risk is key. The countries
we work in, the technical and physical
challenges we take on and the investments
we make – these all demand a sharp focus
on how we manage risk. We must never
shrink from taking on difﬁ cult challenges,
but the board will strive to set high
expectations of how risk is managed
and remain vigilant on oversight.

As is well known, BP responded
early to the issue of climate change. The
group has made substantial investments
in alternative energies and in lower-carbon
fossil fuels such as natural gas. We support
the low-carbon evolution, but must also
continue to produce the high-quality
hydrocarbons required by a world with
a growing population, growing economies
and greater mobility.

BP has driven itself back to competitive

ﬁ tness; we must ensure we build on the hard
work of the past three years and continue to
grow a successful and enduring company.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

We will continue to contribute to debate
around public policy, and intend to help
shape and lead the energy industry of
tomorrow. People need BP to keep doing
what it does best.

I recognize that many institutions and
individuals rely on BP for a consistent return
on their investment and the board takes
seriously its responsibilities in this regard.
Our task is to achieve the best balance
of our sources and uses of cash, making
investments to generate long-term business
momentum while managing debt and
realizing steady rewards for shareholders.
Over the past year we have demonstrated
our ability to achieve this despite a very
volatile business environment. While we
cannot control the price of oil we can control
the efﬁ ciency of our own operations, and the
improving performance within the group will
help us to balance ﬁ nancial priorities. The
quarterly dividend, to be paid in March, is
14 cents per share ($0.84 per ADS), the
same as a year ago. In sterling terms, the
quarterly dividend is 8.679 pence per share,
compared with 9.818 pence a year ago.

We are now proposing to introduce

a scrip dividend programme. For those
shareholders who choose to take their
dividend in shares, rather than cash,
the issuing of scrip shares is an
attractive alternative.

So, I thank shareholders for their

continued support. The group has recently
celebrated its centenary and I relish the
opportunity to lead the board as we move
into a second century. We operate in a
fast-moving world full of profound challenges
and opportunities, but I see no reason why
a ﬁ t and determined BP cannot thrive in
this environment and remain at the heart
of society for many years to come.

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

BP Annual Report and Accounts 2009
Business review

Group chief
executive’s review

Efﬁ ciency,
momentum
and growth

Tony Hayward Group Chief Executive
26 February 2010

Highlights

• Progress on safe and reliable operations.

• Real momentum in growing our businesses.

• Continued focus on efﬁ ciency and improvement.

2009 saw the continuation of difﬁ cult
economic conditions and a volatile energy
market, with rising demand for oil in
non-OECD countries failing to offset lower
levels of consumption in OECD countries.
Oil prices began the year at $36.55 per
barrel and recovered to $77.67 per barrel
in December. Reﬁ ning margins and gas
prices fell sharply. Despite these difﬁ cult
conditions, a revitalized BP kept up its
momentum and delivered strong operating
and ﬁ nancial results while continuing to
focus on safe and reliable operations.
Replacement cost proﬁ t for the year was
$14 billion, with a return on average capital
employeda of 11%.
a The return on average capital employed on a replacement
basis is the ratio of replacement cost proﬁ t before interest
expense and minority interest but after tax, to the average
of opening and closing capital employed. Capital employed
is BP shareholders’ interest, plus ﬁ nance debt and minority
interest.

Performance has been restored and
the group is competitive with the
industry once again, so what
priorities have you now set for BP?

Our priorities have remained absolutely
consistent – safety, people and performance
– and you can see the results of this focus
with improvements on all three fronts.
This year we have increased emphasis on
operational efﬁ ciency, with a particular focus
on compliance and continuous improvement.
Achieving safe, reliable and compliant
operations is our number one priority and
the foundation stone for good business.
This year we achieved a reported recordable
injury frequency of 0.34, an improvement of
20% over 2008. In Reﬁ ning and Marketing
reported major incidents have been reduced
by 90% since 2005. All our operated
reﬁ neries and petrochemicals plants now
operate on the BP operating management
system (OMS), which governs how BP’s
operations, sites, projects and facilities are
managed. In Exploration and Production 47
of our 54 sites completed the transition to
OMS by the end of 2009, and I expect all BP
operations to be on OMS by the end of 2010.
This represents good progress and we must
remain absolutely vigilant.

Why are you putting such strong
emphasis on operational efﬁ ciency?

In 2009 we invested $20 billion in our
businesses and realized more than $4 billion
in cash costb savings, of which approximately
40% related to foreign exchange beneﬁ ts
and lower fuel costs. Within an organization
of our scale, putting a long-term commitment
to efﬁ ciency at the heart of the group is
essential to improving earnings, year after
year. Our challenge is to maintain a relentless
focus on continuous improvement, making
today better than yesterday, so that we
continue to drive the business forward
whatever the market conditions.

What does the focus on efﬁ ciency
and continuous improvement mean
for your people?

Better performance starts and ends with the
actions of individuals and I want to thank our
employees for the commitment they showed
in 2009. Our performance speaks volumes
b

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

about their motivation and skills. The results
from our 2009 employee survey conﬁ rm
that employee morale is improving as our
operational performance improves.

We have placed greater emphasis on
organizational quality, which is about driving
continuous improvement in our leadership
and culture, skills and capability, and systems
and processes. We have redesigned the way
we manage and reward people to incentivize
performance. We are simplifying the
organization and freeing people to do their
jobs. We are placing particular value on deep
specialist skills and technical expertise, and
are developing and recruiting the excellent
professionals we need to ensure a
sustainable future for the group.

How is this focus translating into
performance in Exploration and
Production?

2009 was an outstanding year. Reported
production grew by 4% and unit production
costs were down by 12%. We are now the
largest producer in deepwater ﬁ elds globally.
In the Gulf of Mexico we ramped up
production at Thunder Horse to more than
300,000 barrels of oil equivalent per day.
Production started from Atlantis Phase 2,
Dorado and King South. And in September
we announced the Tiber discovery, the
deepest oil and gas discovery well ever
drilled. These successes make us the largest
producer and leading resource holder in the
deepwater Gulf of Mexico.

During the year we also shipped

the ﬁ rst cargo of liqueﬁ ed natural gas (LNG)
from the Tangguh project in Indonesia, and
we brought ﬁ rst gas onstream at Savonette,
Trinidad & Tobago, in record time. We also
gained access to new resource opportunities
in Iraq, Egypt, the Gulf of Mexico, Indonesia,
Jordan and onshore US. We entered Iraq
through a contract to expand production
from the Rumaila ﬁ eld near Basra, one of the
largest oil ﬁ elds in the world. Working with
partners China National Petroleum Company
(CNPC) and the Iraqi State Oil Marketing
Organization (SOMO), we intend to grow
production in Rumaila from approximately
1 million barrels per day to 2.85 million
barrels per day.

Overall, 2009 was the 17th

consecutive year of delivering reported
reserves replacement of more than
100%. Our success in adding reserves
and resources gives us conﬁ dence in our
ability to grow oil and gas production.

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

B
u
s
i
n
e
s
s
r
e
v
i
e
w

greenhouse gases of 80% or more relative
to conventional transport fuels. We have
focused our wind business on the US, where
we now have more than one gigawatta of
spinning power generation capacity. In solar,
we are repositioning our manufacturing
footprint to lower-cost locations, principally
India and China. And in carbon capture and
storage, we are investing in two major
projects – one in California, the other in
Abu Dhabi.

In 2009 we saw further challenges
for international oil companies in
terms of generating growth and
achieving access, together with
the continued strong emergence
of national oil companies. How is
BP responding?

BP has always operated at the frontiers of
the energy industry and our core strengths
are more relevant and valuable than ever.
BP’s experience, skills, capability, technology
and access to markets enable resource
holders to maximize returns over the long
term. We continue to show our ability to take
on and manage risk, doing the difﬁ cult things
that others either can’t do or choose not to
do. This is why we are able to form such
strong relationships with governments and
national oil companies and why we continue
to have a critical role to play in supplying the
world with its future energy needs.

In a world of increasing energy
demand and growing technical challenges,
I believe BP will continue to set itself apart
by operating and succeeding at the frontiers
of the energy industry.
a O n a gross joint-venture basis (which includes 100% of the
capacity of equity-accounted entities where BP has partial
ownership). Including BP’s share of joint ventures on a net
basis, the capacity was 711 megawatts.

Speeches by Tony Hayward
bp.com/speeches

What progress are you making
in Reﬁ ning and Marketing?
The transition to full OMS status across all
our operated reﬁ neries and petrochemicals
plants is a major milestone, and oil spills and
recordable injuries are at the lowest levels for
10 years. So, I’m pleased with the progress
made on safety and we have made very
strong progress on operational performance
in a year when reﬁ ning margins were hit
hard by recession. Reﬁ ning availability is
up around 5% on 2008 and we have restored
our performance so that it is once again
competitive with our supermajor peers.

We saw a really competitive
performance from our international
businesses in 2009. We are building strong
positions in the petrochemicals market in
China and we are continuing to enhance
our six integrated fuels value chains around
the world to maximize efﬁ ciency and
proﬁ tability. It is critical that we keep driving
efﬁ ciencies through the businesses while
growing our positions in the most valuable
and attractive markets.

The world must meet growing
demand for energy in a sustainable
way; what role will BP play in this
energy evolution?

We are looking to build a future energy
industry that provides energy that is
available, sustainable, secure and affordable.
For BP, supporting the transition to a low-
carbon economy has several dimensions.
First, we are improving energy efﬁ ciency
in BP’s own operations through close
performance monitoring. We are also
developing more efﬁ cient products such
as BP Ultimate fuels and Castrol lubricants.
Second, we are promoting a greater

role for natural gas as a key part of the
energy future. Gas is easily the cleanest
burning fossil fuel and is efﬁ cient, versatile
and abundantly available. We are also
including a cost of carbon in investment
appraisals for all new major projects to allow
informed investment in fossil fuels and to
encourage development of the technology
needed to reduce their carbon footprint.

And ﬁ nally, we are investing in our

low-carbon businesses. Since 2005 we have
invested more than $4 billion in Alternative
Energy, with our activity focused on four
key areas. We are investing in advanced
biofuels, which are low cost, scalable and
sustainable, and can provide reductions in

BP Annual Report and Accounts 2009
Business review

Our performance

Pr ogress in 2009

Safety

People

Personal safety – reported recordable injury frequency

Employee satisfactiona (%)

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

Safety is BP’s number one priority
and we constantly seek to improve our
performance through our procedures,
processes and training programmes.
Our workforce RIF, which includes
employees and contractors combined,
was 0.34 in 2009 – signiﬁ cantly lower
than 0.43 in 2008 and 0.48 in 2007.

Employees
Contractors

0.35
2007

0.59
2007

0.35
2008

0.50
2008

0.23
2009

0.43
2009

0.75

0.60

0.45

0.30

0.15

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

The improved performance in 2009

was underpinned by increases in the
categories of ‘trust in management’
and ‘perceptions that BP is being
effectively managed and well run’. This
reﬂ ects our clear, simple and consistent
communication to employees of BP’s
business performance and progress
against corporate goals.

100

66
2006

59
2008

65
2009

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

Process safety – oil spills

Number of employeesa

We report all spills of hydrocarbons
greater than or equal to one barrel
(159 litres, 42 US gallons).

The reduction in the number of oil
spills in 2009 follows several years of
focus across BP on procedures such as
‘integrity management’ and ‘control of
work’, which are core elements of BP’s
operating management system.

340
2007

335
2008

234
2009

500

400

300

200

100

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

In 2009 BP total headcount fell
by 11,700, reﬂ ecting the transfer of
our US convenience retail sites to
a franchise model and the progress
we have made in making BP a
simpler, more efﬁ cient organization.

98,100
2007

92,000
2008

80,300
2009

a As at 31 December.

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

We report greenhouse gas (GHG)
emissions, and emission reductions,
on a CO2-equivalent basis including
CO2 and methane. This represents all
consolidated entities and BP’s share
of equity-accounted entities except
TNK-BP .

The increase in GHG emissions in
2009 was driven primarily by increases
in operational activity, in particular higher
throughput from our US reﬁ neries, the
start-up of our Tangguh LNG project in
Indonesia and increased production
from deepwater platforms in the Gulf
of Mexico.

100

65.0
2009

61.4
2008

63.5
2007
a See BP Sustainability Review 2009 for more
information on how we derive our sustainable
GHG reductions.

Diversity and inclusion (%)

Each year we record the percentage of
women and individuals from countries
other than the UK and US among BP’s
top 492 leaders (2008 583, 2007 624).

BP has maintained the percentage

of female and ‘most-of-world’ leaders
in 2009 and remains focused on
building a more sustainable pipeline
of diverse talent for the future.

Women
Non-UK/US

16
2007

19
2007

14
2008

19
2008

14
2009

21
2009

125

100

Operating cash ﬂ ow ($ billion)

Operating cash ﬂ ow is net cash
ﬂ ow provided by operating activities,
from the group cash ﬂ ow statement.
Operating activities are the principal
revenue-generating activities of the
group and other activities that are
not investing or ﬁ nancing activities.
Lower operating cash ﬂ ow in
2009 primarily reﬂ ected lower group
proﬁ ts, movements in working capital
and a decrease in dividends from jointly
controlled entities and associates.
These effects were partly offset by
decreases in income taxes paid.

24.7
2007

38.1
2008

27.7
2009

Performance

Production (thousand barrels of oil equivalent per day)

Replacement cost proﬁ t per ordinary share (cents)

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

Reported production increased

by 4% compared with 2008. This
reﬂ ected strong performance from
our existing assets, the continued
ramp-up of production following the
start-up of major projects in 2008 and
the start-up of a further seven major
projects in 2009.

4,250

4,000

3,750

3,500

3,250

Replacement cost proﬁ t reﬂ ects the
replacement cost of supplies. It is
arrived at by excluding from proﬁ t
inventory holding gains and losses
and their associated tax effect.
(See footnote a on page 1.)
Our 2009 results were impacted
by lower oil and gas realizations and
lower reﬁ ning margins, partly offset by
higher production, stronger operational
performance and lower costs.

95.85
2007

136.20
2008

74.49
2009

3,818
2007

3,838
2008

3,998
2009

Reserves replacement ratioa b (%)

Dividends paid per ordinary share

150

120

100

112
2007

121
2008

129
2009

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

82.9
2007

88.8
2008

93.6
2009

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

In 2009 we extended our track

record for reported reserves
replacement of more than 100% to
17 consecutive years. We continue
to drive renewal through new access,
exploration, targeted acquisitions and a
strategic focus on increasing resources
from ﬁ elds we currently operate.

Reﬁ ning availability (%)

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

Reﬁ ning availability has increased

signiﬁ cantly each year from 2007 to
2009 and is now at the highest level
since 2005. This has been a key
element in our drive to restore missing
revenues in our operations, with the
biggest contributor being the restoration
of our Texas City reﬁ nery.

This measure shows the total dividend
per share paid to ordinary shareholders
in the year.

The total dividend paid per share in
2009 increased by 2% compared with
2008. We determine the dividend in US
dollars as it is the economic currency of
BP. In sterling terms, our 2009 dividend
was 24% higher than in 2008 due to
the strengthening of the dollar relative
to sterling.

Cents
Pence

42.30
2007

20.995
2007

55.05
2008

29.387
2008

56.00
2009

36.417
2009

Total shareholder returna (%)

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

Total shareholder return scores

in 2009 reﬂ ect BP’s improving
competitive performance as well
as a general recovery of global stock
markets compared with the low
levels seen at the end of 2008.

ADS basis
Ordinary share basis

14.1
2007

6.8
2007

33.0
2009

27.6
2009

2008
-34.6

2008
-15.1

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

B
u
s
i
n
e
s
s
r
e
v
i
e
w

200

160

120

-20

Our group functions and regions support the work of our segments and
businesses. Their key objectives are to establish and monitor fit-for-
purpose functional standards across the group; to act as centres of deep
functional expertise; to access significant leverage with third-party
suppliers; and to establish and maintain capabilities among the
functional staff employed within our operating businesses. In addition,
the head of each region provides the required integration and
co-ordination of group activities in a particular geographic area and
represents BP to external parties.

Where we operate
BP’s worldwide headquarters is in London. The UK is a centre for
trading, legal, finance and other business functions as well as three
of BP’s major global research and technology groups.

We have well-established operations in Europe, the US, Canada,

Russia, South America, Australasia, Asia and parts of Africa. Currently,
around 67% of the group’s capital is invested in Organisation for
Economic Co-operation and Development (OECD) countries, with
around 40% of our fixed assets located in the US and around 20%
in Europe.

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

BP Annual Report and Accounts 2009
Business review

Group overview

Our organization
BP is one of the world’s leading international oil
and gas companiesa. We operate in more than
80 countries, providing our customers with fuel
for transportation, energy for heat and light,
retail services and petrochemicals products for
everyday items.

As a global group, our interests and activities are held or operated
through subsidiaries, jointly controlled entities or associates established
in – and subject to the laws and regulations of – many different
jurisdictions. These interests and activities covered two business
segments in 2009: Exploration and Production and Refining and
Marketing. BP’s activities in low-carbon energy are managed through our
Alternative Energy business, which is reported within Other businesses
and corporate.

Exploration and Production’s activities cover three key areas.

Upstream activities include oil and natural gas exploration, field
development and production. Midstream activities include pipeline,
transportation and processing activities related to our upstream
activities. Marketing and trading activities include the marketing and
trading of natural gas, including liquefied natural gas (LNG), together
with power and natural gas liquids (NGLs).

Refining and Marketing’s activities include the supply and
trading, refining, manufacturing, marketing and transportation of crude
oil, petroleum and petrochemicals products and related services.
The two business segments each comprise a number of

strategic performance units (SPUs), which are organized along either
geographic or activity-related lines. The role of the SPU includes the
development of local capability and the fostering of external stakeholder
relationships. Each SPU is of a scale that allows for a close focus on
performance delivery by its respective segment, which includes the
appropriate management of costs.

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

Unless otherwise indicated, information in this document reflects 100% of the
assets and operations of the company and its subsidiaries that were consolidated
at the date or for the periods indicated, including minority interests. The company was
incorporated in 1909 in England and Wales and changed its name to BP p.l.c. in 2001.
BP’s primary share listing is the London Stock Exchange. Ordinary shares are also traded
on the Frankfurt Stock Exchange in Germany and, in the US, the company’s securities
are traded in the form of ADSs. (See pages 100 to 101 for more details.)

(cid:129) BP subsidiary
(cid:129) Equity-accounted entity

Our worldwide headquarters is located at:
1 St James’s Square,
London SW1Y 4PD, UK.
Tel +44 (0)20 7496 4000.

Our agent in the US is BP America Inc.,
501 Westlake Park Boulevard, Houston, Texas 77079.
Tel +1 281 366 2000.

BP Annual Report and Accounts 2009
Business review

Our Exploration and Production segment conducts upstream and
midstream activities in 30 countries and we are the largest producer of
oil and gas in North America. The segment’s geographical coverage in
these activities currently includes Angola, Azerbaijan, Canada, Egypt,
Russia, Trinidad & Tobago (Trinidad), Norway, the UK, the US and
locations within Asia Pacific, Latin America, North Africa and the Middle
East. Our Exploration and Production segment also includes gas
marketing and trading activities, primarily in Canada, Europe and
the US. In Russia, we have an important associate through our 50%
shareholding in TNK-BP, a major oil company with exploration assets,
refineries and other downstream infrastructure.

In Refining and Marketing, we market our products in more than
80 countries, with a particularly strong presence in the US and Europe,
as well as major activities in Australia, Southern Africa, India and China.
In the US, we own or have a share in five refineries and market primarily
under the Amoco, ARCO, BP and Castrol brands. We are one of the
largest gasoline retailers in that country. In Europe, we own or have a
share in seven refineries and we market extensively across the region,
primarily under the Aral, BP and Castrol brands. Our long-established
supply and trading activity is responsible for delivering value across the
crude and oil products supply chain. Our petrochemicals business
maintains a manufacturing position globally, with an emphasis on growth
in Asia. We continue to seek opportunities to broaden our activities in
growth markets such as China and India.

Refining and Marketing
BP’s global presencea

(cid:129) BP refinery (wholly or partly owned)
(cid:129) Petrochemicals site (s)

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

Our market
Energy markets remained volatile in 2009,
reflecting the dramatic drop in world economic
activity early in the year and indications of
economic recovery in the second half. Looking
ahead, the long-term outlook is one of growing
demand for energya, particularly in Asia,
alongside challenges for the industry in meeting
this demand. Rising incomes and expanding
urban populations are expected to drive
demand, while the evolution towards a lower-
carbon economy will require technology,
innovation and investment.

World oil consumption declined for a second successive year during
2009, with growing demand in non-OECD countries once again more
than offset by falling consumption in OECD countries. Average crude
oil prices for 2009 were lower than in the previous year, breaking an
unprecedented string of seven consecutive annual increases. Natural
gas prices also weakened in 2009 and were highly volatile. Refining
margins fell sharply as oil demand contracted and substantial amounts
of new refining capacity came onstream.

Economic context
The world economy began to show signs of recovery in the latter part
of 2009 and this is expected to continue through 2010, but economic
growth in 2010 is likely to be muted in the OECD countries. Growth in
global oil consumption is expected to resume as the world economy
recovers from recession.

In 2009, concerns about the volatility of commodity and financial
markets, combined with renewed focus on climate change and the early
experiences with efforts to reduce CO2 emissions in the EU and
elsewhere, led to an increased focus on the appropriate role for markets,
government oversight and other policy measures relating to the supply
and consumption of energy.

The concept of peak oil – the time after which less oil is available

to the world – continues to hold the interest of some commentators,
although global proved reserves have tended to rise over time and
remain sufficient to support higher levels of production. Meanwhile, the
consumer response to higher prices and an increased focus on energy
efficiency have served to constrain demand. We expect regulation and
taxation of the energy industry and energy users to increase in many
areas over the short to medium term.

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

B
u
s
i
n
e
s
s
r
e
v
i
e
w
–
G
r
o
u
p
o
v
e
r
v
w
i
e
e
w
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Crude oil and gas prices, and refining margins
($ per barrel of oil equivalent)

Dated Brent oil price
Henry Hub gas price (First of Month Index)
Global indicator refining margin (GIM)a

150

120

2004

2005

2006

2007

2008

2009

Source: Platts/BP.

Crude oil prices
Dated Brent for the year averaged $61.67 per barrel, about 37% below
2008’s record average of $97.26 per barrel. Prices began the year at their
lowest point as the world economy grappled with the sharpest downturn
in modern economic history.

Global oil consumption reflected the economic slowdown, falling
by roughly 1.3 million b/d for the year (1.5%)b, the largest annual decline
since 1982. The biggest reductions were early in the year, with OECD
countries accounting for the entire global decline. Crude oil prices rose
sharply in the second quarter in response to sustained OPEC production
cuts and emerging signs of stabilization in the world economy, despite
very high commercial oil inventories in the OECD. OPEC members
sustained roughly 2.5 million b/d of production cutsb implemented in late
2008 and throughout 2009. Additional price increases later in the year
were sustained by further positive economic news and signs that the
inventory overhang was beginning to correct.

In 2008, the average dated Brent price of $97.26 per barrel was

34% higher than the $72.39 per barrel average seen in 2007. Daily prices
began 2008 at $96.02 per barrel, peaked at $144.22 per barrel on 3 July
2008, and fell to $36.55 per barrel at the end of the year. The sharp drop
in prices was due to falling demand in the second half of the year, caused
by the OECD falling into recession and the lagged effect on demand of
high prices in the first half of the year. OPEC had increased production
significantly through the first three quarters and, as a result of falling
consumption and rising OPEC production, inventories rose. As prices
continued to decline, OPEC responded with successive announcements
of production cuts in September, October and December.

Looking ahead, in 2010 we expect oil price movements to

continue to be driven by the extent of global economic growth and its
resulting implications for oil consumption, and by OPEC production
decisions.

a See footnote d on page 37.
b Adapted from Oil Market Report (February 2009). ©OECD/IEA 2009.

Natural gas prices
Natural gas prices weakened in 2009 and were volatile. The average US
Henry Hub First of Month Index fell to $3.99/mmBtu in 2009, a 56%
decrease from the record $9.04/mmBtu average seen in 2008.
Recession-induced demand declines and strong production caused prices
to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in
September. However, over the course of the year, the impact was partly
offset as US regional gas price differentials narrowed, driven partly by the
Rockies Express Pipeline extension allowing the transportation of larger
quantities of gas out of the Rockies area. Reduced imports from Canada,
slowing US production growth and cooler temperatures allowed prices to
recover to $4.49/mmBtu by the end of the year. Prices at the UK National
Balancing Point similarly fell to an average of 30.85 pence per therm,
47% below the 2008 average price of 58.12 pence per therm. In 2009,
there was a switch of uncontracted LNG cargoes from Asia to Europe,
reflecting a shift in relative spot prices. LNG imports to Europe have
competed with pipeline imports, where the gas price is often indexed to
oil prices, as well as with marginal European gas production. Gas prices
were often at or below parity with coal, when translated into the cost of
generating power, which led to gas displacing coal in power generation in
Europe and the US.

In 2008, average natural gas prices in the US and the UK were

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

Looking ahead, gas markets in 2010 are expected to follow
developments in the global economy, but any price movements are likely
to be impacted by significant new LNG capacity as it becomes available.

Refining margins
Refining margins fell sharply in 2009 as demand for oil products reduced
in the wake of the global economic recession and new refining capacity
came onstream, mostly in Asia Pacific. The BP global indicator refining
margin (GIM)a averaged $4 per barrel last year, down $2.50 per barrel
compared with 2008. Margins in the Far East were particularly badly hit –
averaging close to zero in Singapore – because new refining capacity has
been added in the region.

Margins in Europe were about half the 2008 level as the reduction

in economic activity meant weaker demand for commercial transport
and therefore lower middle distillate consumption. In the US, where
refining is more highly upgraded and the transport market more
gasoline-orientated, margins were stronger than in Europe.

Refining margins in 2008 were lower than in 2007, with the BP

GIM decreasing to an average of $6.50 per barrel from $9.94 per barrel in
2007. The premium for light products above fuel oils remained high,
reflecting a continuing shortage of upgrading capacity and the favouring
of fully upgraded refineries over less complex sites.

Looking ahead, refining margins are likely to remain under

pressure through 2010, with capacity already exceeding demand and
additional new capacity expected to come onstream during the year.

BP Annual Report and Accounts 2009
Business review

Global energy demand by type
(million tonnes of oil equivalent)

Other renewables
Biomass and waste
Coal
Hydroelectricity
Nuclear energy
Natural gas
Oil

2007

1990
2015
Source: World Energy Outlook 2009. © OECD/IEA 2009, page 622: ‘Reference
Scenario, World’.

2030

Long-term outlook
Recent economic conditions have weakened global demand for primary
energy, but a number of forecasts predict a return to growth in the
medium term. This is underpinned by continuing population growth and
by generally rising living standards in the developing world, including the
expansion of urban populations.

Under the International Energy Agency’s (IEA) reference scenario,

global energy demand is projected to increase by around 40% between
2007 and 2030a. That scenario also projects that fossil fuels will still be
satisfying as much as 80% of the world’s energy needs in 2030. At
current rates of consumption, the world has enough proved reserves of
fossil fuels to meet these requirementsb if investment is permitted to
turn those reserves into production capacity. However, to meet the
potential growth in demand, continued investment in new technology will
be required in order to boost recovery from declining fields and
commercialize currently inaccessible resources. For example, in oil alone,
where we believe there are reserves in place to satisfy approximately
40 years’ demand at current rates of consumptionb, we estimate that our
industry will need to bring nearly 50 million barrels per day of new
capacity onstream by 2030 if it is to meet the increased demand. To play
their part in achieving this, energy companies such as BP will need
secure and reliable access to as-yet undeveloped resources. We estimate
that more than 80% of the world’s oil resources are held by Russia,
Mexico and members of OPEC – areas where international oil companies
are frequently limited or prohibited from applying their technology and
expertise to produce additional supply. New partnerships will be required
to transform latent resources into much-needed proved reserves.

A more diverse mix of energy will also be required to meet this
increased demand. Such a mix is likely to include both unconventional
fossil fuel resources – such as oil sands, coalbed methane and natural
gas produced from shale formations – and renewable energy sources
such as wind, biofuels and solar power. Beyond simply meeting growth
in overall demand, a diverse mix would also help to provide enhanced
national and global energy security while supporting the transition to a
lower-carbon economy. Improving the efficiency of energy use will also
play a key role in maintaining energy market balance in the future.

Along with increasing supply, we believe the energy industry will be
required to make hydrocarbons cleaner and more efficient to use –
particularly in the critical area of power generation, for which the key
hydrocarbons are currently coal and gas. The world has reserves of coal
for around 120 years at current consumption ratesb, but coal produces
more carbon than any other fossil fuel. Carbon capture and storage (CCS)
may help to provide a path to cleaner coal, and BP is investing in this
area, but CCS technologies still face significant technical and economic
issues and are unlikely to be in operation at scale for at least a decade.

In contrast, we believe that in many countries natural gas has the
potential to provide the most significant reductions in carbon emissions
from power generation in the shortest time and at the lowest cost. These
reductions can be achieved using technology available today. Combined-
cycle turbines, fuelled by natural gas, produce around half the CO2
emissions of coal-fired power, and are cheaper and quicker to build. It is
estimated that there are reserves of natural gas in place equivalent to
60 years’ consumption at current ratesb and they are rising as new skills
and technology unlock new unconventional gas resources. For these
reasons, gas is looking to be an increasingly attractive resource in
meeting the growing demand for energy, playing a greater role as a key
part of the energy future.

At the same time, alternative energies also have the potential to

make a substantial contribution to the transition to a lower-carbon
economy, but this will require investment, innovation and time. Currently,
wind, solar, wave, tide and geothermal energy account for only around
1% of total global consumptionc. Even in the most aggressive scenario
put forward by the IEA, these forms of energy are estimated to meet no
more than 5% of total demand in 2030d.

If industry and the market are to meet the world’s growing
demand for energy in a sustainable way, governments will be required to
set a stable and enduring framework. As part of this, governments will
need to provide secure access for exploration and development of fossil
fuel resources, define mutual benefits for resource owners and
development partners, and establish and maintain an appropriate legal
and regulatory environment, including a mechanism for recognizing and
incorporating the cost of reducing carbon emissions.

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

B
u
s
i
n
e
s
s
r
e
v
i
e
w
–
G
r
o
u
p
o
v
e
r
v
w
i
e
e
w
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Our strategy
The priorities that drove our success in 2009 –
safety, people and performance – remain the
foundation of our agenda as we build on our
momentum and work to further enhance our
competitive position.

Our strategy is to invest competitively to grow oil and gas production
while working to drive performance across the group through enhanced
operating efficiency, capital efficiency and cost efficiency.

Enhanced performance and efficiency
Our strategy aims to create value for shareholders by investing to deliver
growth in our Exploration and Production business together with
enhanced efficiency and high-quality earnings and returns throughout
our operations.

In Exploration and Production, our strategy is to invest to grow
production safely, reliably and efficiently. We intend to achieve this by
strengthening our portfolio of leadership positions in the world’s most
prolific hydrocarbon basins, enabled by the development and application
of technology and the building of strong relationships based on mutual
advantage. We also intend to sustainably drive cost and capital efficiency
in accessing, finding, developing and producing resources, enabled by
deep technical capability and a culture of continuous improvement.

To meet growing world demand, BP is committed to exploring,

In Refining and Marketing, our strategic focus is on enhancing

developing and producing more fossil fuel resources; manufacturing,
processing and delivering better and more advanced products; and
enabling the transition to a lower-carbon future. We aim to do this while
operating safely, reliably and in compliance with the law. We strive to run
our business within the discipline of a clear financial framework.

In 2009, we improved our overall competitive performance by
enhancing operating performance and reducing complexity and costs.
We believe we can continue to compete successfully through our ability
to access resources and deliver high-quality products and service to our
customers. We intend to remain focused on the application of technology
and developing relationships based on a commitment to long-term
partnerships and mutual advantage. Our intention is to generate and
sustain business momentum and growth through a rigorous process
of continuous improvement and an ongoing focus on safety, people
and performance.

Safety, reliability, compliance and continuous improvement
Safe, reliable and compliant operations remain the group’s first priority.
A key enabler for this is the BP operating management system (OMS),
which provides a common framework for all BP operations, designed to
achieve consistency and continuous improvement in safety and
efficiency. OMS includes mandatory practices, such as integrity
management and incident investigation, which are designed to address
particular risks. In addition, it enables each site to focus on the most
important risks in its own operations and sets out procedures on how to
manage them in accordance with the group-wide framework. Further
information on our safety priorities and performance can be found on
page 46.

The right people, skills and capability
It is vital that we develop and deploy people with the skills, capability
and behaviours required to meet our objectives. Despite a tight global
recruitment market for some of our core technical disciplines, we have
been successful in building capacity and getting the right people with the
right skills in the right place. We are now going further, strengthening the
culture within BP through a commitment to continuous improvement in
operations and enhancing the capabilities, technical expertise and
organizational quality needed to drive performance.

Our people strategy has already resulted in refreshed group
leadership and senior management teams, recruitment focused on
individuals with strong operational and technical expertise, and
appropriate reward for performance at all levels.

portfolio quality, integrating activities across value chains and
performance efficiency. We expect to continue building our business
around advantaged assets in material and significant energy markets
while improving the safety and reliability of our operations. Our objective
is to achieve sector-leading levels of performance on a sustainable basis.
To achieve this, we need to continue upgrading the manufacturing
capabilities within our integrated fuels value chains to achieve the best
capacity utilization and margin capture. We continue to explore
appropriate opportunities to deploy downstream capital into faster-
growing non-OECD markets. We also intend to continue our selective
investment in our international businesses, which include
petrochemicals and lubricants, where we see potential to deliver strong
and sustainable returns.

In Alternative Energy, we have focused our investments in the

areas where we believe we can create the greatest competitive
advantage. We have substantial businesses in wind and solar power and
are developing advanced biofuels and low-carbon energy technologies
such as hydrogen power and carbon capture and storage.

Our determination to drive efficiency through our businesses has

proved vital to our performance during a period of recession and we
believe that it will remain critical to our future prospects as the global
economy recovers and evolves.

Looking further ahead
As discussed in the ‘Our market’ section of this Annual Report and
Accounts (see pages 11 to 13), we expect that the world will require a
more diverse energy mix as the basis for a secure supply of energy over
time. We intend to play a central role in meeting the world’s continued
need for hydrocarbons, with our Exploration and Production and Refining
and Marketing activities remaining at the core of our strategy. We are
also creating long-term options for the future in new energy technology
and low-carbon energy businesses. Current investment is focused on
wind, solar and biofuels as potential sources of resource diversification
for the world, and we are investing in carbon capture and storage as an
enabling technology. We believe that this focused portfolio has the
potential to be a material source of value creation for BP in the longer
term (see pages 42 to 43). We are also enhancing our capabilities in
natural gas, which is likely to play a greater role as a key part of the
energy future. We intend to lead and shape this transition, including
through the application of advanced technology to unlock sources of
unconventional gas, while working to achieve sector-leading levels of
return for our shareholders.

BP Annual Report and Accounts 2009
Business review

Our performance
2009 has been a successful year for BP, with
positive financial and operational momentum
despite an extremely turbulent global financial
environment.

Safety
Good progress has been made on underpinning improved safety
performance in 2009. Throughout the year, we continued to focus on
training and enhancing procedures across the organization. Significantly,
2009 was an important year in the development of OMS. By the end
of 2009, around 80% of our operating sites were using the system,
including all our operated refineries and petrochemicals plants. (See
Safety on page 46 for more information on OMS.)

In 2009, a third-party-operated helicopter carrying contractors

from BP’s Miller platform crashed in the North Sea, resulting in the tragic
loss of 16 lives. In addition, BP sustained two fatalities within our own
operations. We deeply regret the loss of these lives.

Recordable injury frequency (RIF, a measure of the number of

reported injuries per 200,000 hours worked) was 0.34, significantly below
2008 and 2007 levels of 0.43 and 0.48, respectively. Reported oil spills
greater than one barrel were 234 in 2009 compared with 335 in 2008 and
340 in 2007. Our environmental measure that tracks greenhouse gas
(GHG) emissionsa increased in 2009 to 65.0 million tonnes of carbon
dioxide equivalent, compared with 61.4 million tonnes in 2008. The
primary reason for this increase is the growth of our business, including
the significant increase in our US refining throughputs, the start-up of our
Tangguh LNG project in Indonesia and the continued success of our Gulf
of Mexico deepwater operations, including Thunder Horse.

People
During 2009 we made further significant progress in generating
a stronger performance focus and in fostering a culture that attributes
more value to deep specialist skills and expertise. At the same time, we
continued to improve operational efficiency and reduce overheads.

Non-retail headcount was reduced by 4,400 (6%) in 2009. Overall,

the number of employees (including retail staff) was reduced by 11,700
in 2009.

Performance
Against the backdrop of the global recession, we delivered a strong
performance in 2009. Profit and cash flow were lower than in 2008, due
primarily to a much weaker price environment, although the impact was
partially offset by better operational performance and lower costs across
the group as we implemented our efficiency programmes. Notable
achievements include:

Exploration and Production
(cid:129)

Replacing 129% of our proved reserves, on a combined basis of
subsidiaries and equity-accounted entities.

(cid:129) Delivering a 5% underlying growth in productionb.
(cid:129) Reducing unit production costs by 12%.
(cid:129) Achieving a strong gas marketing and trading performance.
(cid:129) Accessing new resources in Egypt, the Gulf of Mexico, Indonesia,

Iraq and Jordan.

(cid:129) Making the Tiber discovery in the Gulf of Mexico at a depth of over
35,000 feet, the deepest oil and gas discovery well ever drilled.

(cid:129) Making three further discoveries in Block 31, Angola.
(cid:129) Starting up Tangguh in Indonesia and six other major projects in the

Gulf of Mexico, Trinidad and Russia.

Refining and Marketing
(cid:129) Restoring our overall performance so that it is once again competitive

with our supermajor peers.

(cid:129) Achieving a Solomon refining availabilityc of 93.6%, which is an
increase of almost five percentage points compared with 2008.

(cid:129) Reducing costs across the segment by more than 15%d.
(cid:129) Delivering a strong supply and trading performance.
(cid:129) Performing strongly in our international businesses, despite the weak

environment.

(cid:129) Delivering simplification and lower costs through integration in the

fuels value chains.

(cid:129) Simplifying the segment’s footprint in aviation and lubricants and

completing the transfer of our US convenience retail business to a
franchise operation.

(cid:129) Successfully exiting from our ground fuels marketing business in

Greece.

a See footnote a in Environment on page 47.
b Underlying production growth excludes the effect of entitlement changes in our production-sharing
agreements (driven by changes in oil and gas prices) and the effect of OPEC quota restrictions.
c Refining availability represents Solomon Associates’ operational availability, which is defined as the
percentage of the year that a unit is available for processing after subtracting the annualized time
lost due to turnaround activity and all planned mechanical, process and regulatory maintenance
downtime.
d Based on Refining and Marketing’s share of production and manufacturing expenses plus
distribution and administration expenses.

B
u
s
i
n
e
s
s
r
e
v
i
e
w
–
G
r
o
u
p
o
v
e
r
v
w
i
e
e
w
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Selected financial and operating
information
This information, insofar as it relates to 2009, has been extracted or
derived from the audited consolidated financial statements of the BP
group presented on pages 109 to 178. Note 1 to the financial

statements includes details on the basis of preparation of these financial
statements. The selected information should be read in conjunction with
the audited financial statements and related notes elsewhere herein.

Income statement data
Sales and other operating revenues from continuing operationsa
Profit before interest and taxation from continuing operationsa
Profit from continuing operationsa
Profit for the year
Profit for the year attributable to BP shareholders
Capital expenditure and acquisitionsb
Per ordinary share – cents

Profit for the year attributable to BP shareholders

Basic
Diluted

Profit from continuing operations attributable to BP shareholdersa

Basic
Diluted

Dividends paid per share – cents
– pence

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

Balance sheet data

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

2009

2008

2007

2006

2005

$ million except per share amounts

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

88.49
87.54

88.49
87.54
56.00
36.417

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

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

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

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

112.59
111.56

112.59
111.56
55.05
29.387

108.76
107.84

108.76
107.84
42.30
20.995

109.84
109.00

109.97
109.12
38.40
21.104

105.74
104.52

104.87
103.66
34.85
19.152

18,732
18,936

18,790
18,963

19,163
19,327

20,028
20,195

21,126
21,411

235,968
102,113
5,179
101,613
25,518
20%

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%

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

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

Profit attributable to BP shareholders for the year ended

31 December 2008 was $21,157 million, including inventory holding
losses, net of tax, of $4,436 million and a net charge for non-operating
items, after tax, of $796 million. In addition, fair value accounting effects
had a favourable impact, net of tax, of $146 million relative to
management’s measure of performance.

Profit attributable to BP shareholders for the year ended 31 December
2007 was $20,845 million, including inventory holding gains, net of tax,
of $2,475 million and a net charge for non-operating items, after tax, of
$373 million. In addition, fair value accounting effects had an
unfavourable impact, net of tax, of $198 million relative to
management’s measure of performance.

The primary additional factors affecting profit for 2009, compared
with 2008, were lower realizations and refining margins, partly offset by
higher production, stronger operational performance and lower costs.
The primary additional factors reflected in profit for 2008,

compared with 2007, were higher realizations, a higher contribution
from the gas marketing and trading business, improved oil supply and
trading performance, improved marketing performance and strong cost
management; however, these positive effects were partly offset by
weaker refining margins, particularly in the US, higher production taxes,
higher depreciation, and adverse foreign exchange impacts.

BP Annual Report and Accounts 2009
Business review

B
u
s
i
n
e
s
s
r
e
v
i
e
w
–
G
r
o
u
p
o
v
e
r
v
w
i
e
e
w
i
v
e
r
s
s
e
n
i
s
u
B

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

2009f
1,400
1,135
7,450
1,035
5,658
4,853
40,388

2008
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

(billion cubic feet)e

4,742

5,203

3,770

3,763

3,856

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

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

10,511

Liquidsc
Natural gas

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

7,781

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

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

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

Our total hydrocarbon production during 2009 averaged 3,998mboe/d
(2,684mboe/d for subsidiaries and 1,314mboe/d for equity-accounted
entities). This represents an increase of 4% (an increase of 6% for
liquids and an increase of 2% for gas) when compared with 2008.
In aggregate, after adjusting for entitlement impacts in our production-
sharing agreements (PSAs) and the effect of OPEC quota restrictions,
production was 5% higher than 2008. Our total hydrocarbon production
during 2008 averaged 3,838mboe/d (2,517mboe/d for subsidiaries and
1,321mboe/d for equity accounted-entities). This represented an
increase of 0.5% (a decrease of 0.5% for liquids and an increase of 2%
for gas) when compared with 2007. In aggregate, after adjusting for
entitlement impacts in our PSAs, 2008 production was 5% higher
than 2007.

Acquisitions and disposals
There were no significant acquisitions in 2009. Disposal proceeds in
2009 were $2,681 million, principally from the sale of our interests in BP
West Java Limited, Kazakhstan Pipeline Ventures LLC and LukArco, and
the sale of our ground fuels marketing business in Greece and retail
churn in the US, Europe and Australasia. Further proceeds from the
sale of LukArco are receivable in the next two years. See Financial
statements – Note 3 on page 124.

In 2008, we completed an asset exchange with Husky Energy

Inc., and asset purchases from Chesapeake Energy Corporation as
described on page 53.

In 2007, BP acquired Chevron’s Netherlands manufacturing

company, Texaco Raffiniderij Pernis B.V. The acquisition included
Chevron’s 31% minority shareholding in Nerefco and certain associated
assets. Disposal proceeds were $4,267 million, which included $1,903
million from the sale of the Coryton refinery and $605 million from the
sale of our exploration and production gas infrastructure business in
the Netherlands.

BP Annual Report and Accounts 2009
Business review

Risk factors
We urge you to consider carefully the risks described below. If any of
these risks occur, we might fail to deliver on our strategic priorities, which
are expressed in terms of safety, people and performance (see page 14).
Our business, financial condition and results of operations could suffer
and the trading price and liquidity of our securities could decline.

In the current uncertain financial and economic environment, certain risks
may gain more prominence either individually or when taken together. Oil
and gas prices are likely to remain volatile with average prices and
margins influenced by changes in supply and demand. This is likely to
exacerbate competition in all businesses, which may impact costs and
margins. At the same time, governments are facing greater pressure on
public finances, which may increase their motivation to intervene in the
fiscal and regulatory frameworks for the oil and gas industry, including
the risk of increased taxation. The financial and economic situation may
have a negative impact on third parties with whom we do, or may do,
business. Any of these factors may affect our results of operations,
financial condition and liquidity.

Capital markets have regained some confidence after the recent

crisis but if there are extended periods of constraints in these markets, at
a time when cash flows from our business operations may be under
pressure, our ability to maintain our long-term investment programme
may be impacted with a consequent effect on our growth rate, and may
impact shareholder returns, including dividends and share buybacks, or
share price. Decreases in the funded levels of our pension plans may also
increase our pension funding requirements.

Our system of risk management identifies and provides the

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

The risks are categorized against the following areas: strategic;

compliance and control; and operational.

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

Prices and markets
Oil, gas and product prices are subject to international supply and
demand. Political developments and the outcome of meetings of OPEC
can particularly affect world supply and oil prices. Previous oil price
increases have resulted in increased fiscal take, cost inflation and more
onerous terms for access to resources. As a result, increased oil prices
may not improve margin performance. In addition to the adverse effect
on revenues, margins and profitability from any fall in oil and natural gas
prices, a prolonged period of low prices or other indicators would lead to

further reviews for impairment of the group’s oil and natural gas
properties. Such reviews would reflect management’s view of long-term
oil and natural gas prices and could result in a charge for impairment that
could have a significant effect on the group’s results of operations in the
period in which it occurs. Rapid material and/or sustained change in oil,
gas and product prices can impact the validity of the assumptions on
which strategic decisions are based and, as a result, the ensuing actions
derived from those decisions may no longer be appropriate. A prolonged
period of low oil prices may impact our ability to maintain our long-term
investment programme with a consequent effect on our growth rate and
may impact shareholder returns, including dividends and share buybacks,
or share price. Periods of global recession could impact the demand for
our products, the prices at which they can be sold and affect the viability
of the markets in which we operate.

Refining profitability can be volatile, with both periodic oversupply

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

Climate change and carbon pricing
Compliance with changes in laws, regulations and obligations relating to
climate change could result in substantial capital expenditure, taxes,
reduced profitability from changes in operating costs, and revenue
generation and strategic growth opportunities being impacted. Our
commitment to the transition to a lower-carbon economy may create
expectations for our activities, and the level of participation in alternative
energies carries reputational, economic and technology risks.

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

We set ourselves high standards of corporate citizenship and

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

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

BP Annual Report and Accounts 2009
Business review

B
u
s
i
n
e
s
s
r
e
v
i
e
w
–
G
r
o
u
p
o
v
e
r
v
w
i
e
e
w
i
v
e
r
s
s
e
n
i
s
u
B

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.

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.

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

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.

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

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

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

For more information on financial instruments and financial risk

factors see Financial statements – Note 24 on page 144.

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

For more information on environmental regulation, see

Environment on pages 47-49.

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

For certain legal proceedings involving the group, see Legal

proceedings on pages 99-100.

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

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

Environmental
If we do not apply our resources to overcome the perceived trade-off
between global access to energy and the protection or improvement of
the natural environment, we could fail to live up to our aspirations of no or
minimal damage to the environment and contributing to human progress.
Failure to comply with environmental laws, regulations and permits could
lead to damage to the environment and could result in regulatory action,
legal liability and damage to our reputation.

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

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

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

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

BP Annual Report and Accounts 2009
Business review

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

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

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

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

People and capability
Successful recruitment of new staff, employee training, development and
long-term renewal of skills, in particular technical capabilities such as
petroleum engineers and scientists, are key to implementing our plans.
Inability to develop the human capacity and capability across the
organization could jeopardize performance delivery.

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

Our systems of control
The board is responsible for the direction and oversight of BP. The board
has set an overall goal for BP, which is to maximize long-term shareholder
value through the allocation of its resources to activities in the oil, natural
gas, petrochemicals and energy businesses. The board delegates
authority for achieving this goal to the group chief executive (GCE).

The board maintains five permanent committees that are

composed entirely of non-executives. The board and its committees
monitor, among other things, the identification and management of the
group’s risks – both financial and non-financial. During the year, the
board’s committees engaged with executive management, the general
auditor and other monitoring and assurance providers (such as the group
compliance and ethics officer and the external auditor) on a regular basis
as part of their oversight of the group’s risks. Significant incidents that
occurred and management’s response to them were considered by the
appropriate committee and reported to the board. (See Board
performance report on pages 69 to 80.)

The GCE maintains a comprehensive system of internal control.
This comprises the holistic set of management systems, organizational
structures, processes, standards and behaviours that are employed to
conduct our business and deliver returns for shareholders. The system is
designed to meet the expectations of internal control of the Combined
Code in the UK and of COSO (committee of the sponsoring organizations
for the Treadway Commission) in the US. It addresses risks and how we
should respond to them as well as the overall control environment. Each
component of the system has been designed to respond to a particular
type or collection of risks. Material risks are described within the Risk
factors section (see pages 18 to 20).

Key elements of our system of internal control are: the control

environment; the management of risk and operational performance
(including in relation to financial reporting); and the management of
people and individual performance. Controls include the BP code of
conduct, our leadership framework and our principles for delegation of
authority, which are designed to make sure employees understand what
is expected of them.

As part of the control system, the GCE’s senior team – known

as the executive team – is supported by sub-committees that are
responsible for and monitor specific group risks. These include the group
operations risk committee (GORC), the group financial risk committee
(GFRC), the group people committee (GPC), and the group disclosures
committee (GDC), which reviews the disclosures, controls and
procedures over reporting.

Operations and investments are conducted and reported in

accordance with, and associated risks are thereby managed through,
relevant standards and processes. These range from group standards,
which set out processes for major areas such as safety and integrity,
through to detailed administrative instructions on issues such as fraud
reporting. The GCE conducts regular performance reviews with the
segments and key functions to monitor performance and the
management of risk and to intervene if necessary. People management
is based on performance objectives, through which individuals are
accountable for delivering specific elements of the group plan within
agreed boundaries.

BP Annual Report and Accounts 2009
Business review

Forward-looking statements
In order to utilize the ‘Safe Harbor’ provisions of the United States Private
Securities Litigation Reform Act of 1995, BP is providing the following
cautionary statement. This document contains certain forward-looking
statements with respect to the financial condition, results of operations
and businesses of BP and certain of the plans and objectives of BP with
respect to these items. These statements may generally, but not always,
be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’,
‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’,
‘we see’ or similar expressions. In particular, among other statements,
(i) certain statements in Business review (pages 10-63), including under
the headings ‘Outlook’, with regard to strategy, management aims and
objectives, future capital expenditure, the future scrip dividend
programme, future hydrocarbon production volume and the group’s ability
to satisfy its long-term sales commitments from future supplies available
to the group, date(s) or period(s) in which production is scheduled or
expected to come onstream or a project or action is scheduled or
expected to begin or be completed, capacity of planned plants or facilities
and impact of health, safety and environmental regulations; (ii) the
statements in Business review (pages 10-52) with regard to anticipated
energy demand and consumption, global economic recovery, oil and gas
prices, global reserves, expected future energy mix and the potential for
cleaner and more efficient sources of energy, management aims and
objectives, strategy, production, petrochemical and refining margins,
anticipated investment in Alternative Energy, anticipated future project
developments, growth of the international businesses, Refining and
Marketing investments, reserves increases through technological
developments, with regard to planned investment or other projects,
timing and ability to complete announced transactions and future
regulatory actions; and (iii) the statements in Business review (pages 53-
63) with regard to the plans of the group, the cost of and provision for
future remediation programmes and environmental operating and capital
expenditures, taxation, liquidity and costs for providing pension and other
post-retirement benefits; and including under ‘Liquidity and capital
resources’ – Trend Information, with regard to global economic recovery,
oil and gas prices, petrochemical and refining margins, production,
demand for petrochemicals, production and production growth,
depreciation, underlying average quarterly charge from Other businesses
and corporate, costs, foreign exchange and energy costs, capital
expenditure, timing and proceeds of divestments, balance of cash
inflows and outflows, dividend and optional scrip dividend, cash flows,
shareholder distributions, gearing, working capital, guarantees, expected
payments under contractual and commercial commitments and purchase
obligations; are all forward-looking in nature.

By their nature, forward-looking statements involve risk and
uncertainty because they relate to events and depend on circumstances
that will or may occur in the future and are outside the control of BP.
Actual results may differ materially from those expressed in such
statements, depending on a variety of factors, including the specific
factors identified in the discussions accompanying such forward-looking
statements; the timing of bringing new fields onstream; future levels of
industry product supply, demand and pricing; operational problems;
general economic conditions; political stability and economic growth in
relevant areas of the world; changes in laws and governmental
regulations; actions by regulators; exchange rate fluctuations;
development and use of new technology; the success or otherwise of
partnering; the actions of competitors; natural disasters and adverse
weather conditions; changes in public expectations and other changes to
business conditions; wars and acts of terrorism or sabotage; and other
factors discussed elsewhere in this report including under ‘Risk factors’
on pages 18-20. In addition to factors set forth elsewhere in this report,
those set out above are important factors, although not exhaustive, that
may cause actual results and developments to differ materially from
those expressed or implied by these forward-looking statements.

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

Further note on certain activities
During the period covered by this report, non-US subsidiaries or other
non-US entities of BP, conducted limited activities in, or with persons
from, certain countries identified by the US Department of State as State
Sponsors of Terrorism (‘Sanctioned Countries’). These activities continue
to be insignificant to the group’s financial condition and results of
operations.

BP has interests in, and is the operator of, two fields and a

pipeline located outside Iran in which the National Iranian Oil Company
(NIOC) and an affiliated entity have interests. BP buys crude oil, refinery
and petrochemicals feedstocks, blending components and LPG of Iranian
origin or from Iranian counterparties primarily for sale to third parties in
Europe and a small portion is used by BP in its own facilities in South
Africa and Europe. Until recently BP held an equity interest in an Iranian
joint venture that has a blending facility and markets lubricants for sale to
domestic consumers. In January 2010, BP restructured its interest in the
joint venture and currently maintains its involvement through certain
contractual arrangements, which it keeps under review in light of pending
legislative developments in the US. BP does not seek to obtain from the
government of Iran licences or agreements for oil and gas projects in
Iran, is not conducting any technical studies in Iran and does not own or
operate any refineries or petrochemicals plants in Iran.

BP sells lubricants in Cuba through a 50:50 joint venture there and

in 2009 purchased a cargo of naphtha from a non-Cuban counterparty
that was loaded in Cuba. In Syria, lubricants are sold through a distributor
and BP obtains crude oil and refinery feedstocks for sale to third parties
in Europe. In addition, BP sells crude oil and refined products into Syria.
BP supplies fuels and lubricants to airlines and shipping

companies from Sanctioned Countries at airports and ports located
outside these countries.

BP monitors its activities with Sanctioned Countries and keeps

them under review to ensure compliance with applicable laws and
regulations of the US and other countries where BP operates.

B
u
s
i
n
e
s
s
r
e
v
i
e
w
–
G
r
o
u
p
o
v
e
r
v
w
i
e
e
w
i
v
e
r
s
s
e
n
i
s
u
B

Recession-induced demand declines and strong production caused prices
to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in
September. However, over the course of the year, the impact was partly
offset as US regional gas price differentials narrowed, driven partly by the
Rockies Express Pipeline extension allowing the transportation of larger
quantities of gas out of the Rockies area. Reduced imports from Canada,
slowing US production growth and cooler temperatures allowed prices to
recover to $4.49/mmBtu by the end of the year. Prices at the UK National
Balancing Point similarly fell to an average of 30.85 pence per therm,
47% below the 2008 average price of 58.12 pence per therm.

In 2009, there was a switch of uncontracted LNG cargoes from
Asia to Europe, reflecting a shift in relative spot prices. LNG imports to
Europe have competed with pipeline imports, where the gas price is
often indexed to oil prices, as well as with marginal European gas
production. On an energy equivalent basis, gas prices were often at
or below parity with coal, which led to gas displacing coal in power
generation in Europe and the US.

In the event of any recovery in the economy in 2010, both the US
and UK gas markets are expected to benefit although the price upside is
likely to be constrained as a result of a record amount of LNG expected
to become available globally.

Our strategy
Our strategy is to invest to grow production safely, reliably and efficiently
by:
(cid:129) Strengthening our portfolio of leadership positions in the world’s

most prolific hydrocarbon basins, enabled by the development and
application of technology and strong relationships based on mutual
advantage.

(cid:129) Sustainably driving cost and capital efficiency in accessing, finding,
developing and producing resources, enabled by deep technical
capability and a culture of continuous improvement.

Our performance
In Exploration and Production, safety, both personal and process, remains
our highest priority. 2009 brought further improvements in personal
safety with our reported recordable injury frequency improving from 0.43
in 2008 to 0.39 in 2009. We also achieved improvements in the number
of reported process safety-related incidents and a significant reduction in
the number of reported spills.

BP’s operating management system (OMS) provides us with

a systematic framework for safe, reliable and efficient operations.
Throughout 2009, OMS helped us to deliver continuous improvement in
the way we manage our people, processes, plant and performance.

From onshore production facilities to offshore platforms, a total
of 47 exploration and production sites had completed their transition to
OMS by the end of 2009. The remaining seven sites are on track to
transition to OMS in 2010.

BP Annual Report and Accounts 2009
Business review

Exploration and Production
Our Exploration and Production segment includes upstream and
midstream activities in 30 countries, including Angola, Azerbaijan,
Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), Norway, the UK, the
US and locations within Asia Pacific, Latin America, North Africa and the
Middle East, as well as gas marketing and trading activities, primarily in
Canada, Europe and the US. Upstream activities involve oil and natural
gas exploration and field development and production. Our exploration
programme is currently focused around Angola, Egypt, the deepwater
Gulf of Mexico, Libya, the North Sea, Oman and onshore US. Major
development areas include Algeria, Angola, Asia Pacific, Azerbaijan, Egypt
and the deepwater Gulf of Mexico. During 2009, production came from
21 countries. The principal areas of production are Angola, Asia Pacific,
Azerbaijan, Egypt, Latin America, the Middle East, Russia, Trinidad, the
UK and the US.

Midstream activities involve the ownership and management of

crude oil and natural gas pipelines, processing facilities and export
terminals, LNG processing facilities and transportation, and our NGL
extraction businesses in the US, the UK, Canada and Indonesia. Our
most significant midstream pipeline interests are the Trans-Alaska
Pipeline System in the US, the Forties Pipeline System and the Central
Area Transmission System pipeline, both in the UK sector of the North
Sea, the South Caucasus Pipeline (SCP), which takes gas from Azerbaijan
through Georgia to the Turkish border and the Baku-Tbilisi-Ceyhan
pipeline, running through Azerbaijan, Georgia and Turkey. Major LNG
activities are located in Trinidad, Indonesia and Australia. BP is also
investing in the LNG business in Angola.

Additionally, our activities include the marketing and trading of

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

Our oil and natural gas production assets are located onshore and

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

Upstream operations in Argentina, Bolivia, Chile, Abu Dhabi,

Kazakhstan, Venezuela and Russia, as well as some of our operations in
Angola, Canada and Indonesia, are conducted through equity-accounted
entities.

Our market
The market environment in which we operate was particularly challenging
during 2009, with crude oil and natural gas prices at lower levels than we
have experienced in recent history.

The annual average crude oil price declined in 2009 for the first

time since 2001, breaking an unprecedented string of seven consecutive
annual increases. Dated Brent for the year averaged $61.67 per barrel,
about 37% below 2008’s record average of $97.26 per barrel. Prices
were lowest at the beginning of the year as the world economy grappled
with the sharpest downturn in modern economic history.

In 2010, we expect oil market movements to continue to be

driven by developments in the world economy, by their resulting
implications for oil consumption, and by OPEC production decisions.

Natural gas prices weakened in 2009 and were volatile. The
average US Henry Hub First of Month Index fell to $3.99/mmBtu in 2009,
a 56% decrease from the record $9.04/mmBtu average seen in 2008.

BP Annual Report and Accounts 2009
Business review

We continually seek to access resources and in 2009 this included Iraq,
where, together with China National Petroleum Corporation (CNPC), we
entered into a contract with the state-owned South Oil Company (SOC)
to expand production from the Rumaila field; Jordan, where on 3 January
2010, we received approval from the Government of Jordan to join the
state-owned National Petroleum Company (NPC) to exploit the onshore
Risha concession in the north east of the country; further access in
Egypt, where we were awarded two blocks in an offshore area of the
Nile Delta; Indonesia, where we signed a production-sharing agreement
(PSA) for the exploration and development of coalbed methane in the
Sanga-Sanga block, supplying gas to Indonesia’s largest LNG export
facility and, subject to Government of Indonesia approval, farmed into
Chevron’s West Papua I & III blocks; and the Gulf of Mexico, where we
were awarded 61 blocks through the Outer Continental Shelf Lease Sales
208 and 210.

In 2009, we were involved in a number of discoveries. The most
significant of these were in the deepwater Gulf of Mexico with the Tiber
well; Angola, where we made three further discoveries in the ultra
deepwater Block 31; and Canada, where we discovered natural gas with
the Ellice J27 well.

Seven major projects came onstream. We continue to grow our
position and leverage our experience as the largest producer in the Gulf
of Mexico, starting up three projects ahead of schedule, including the
second phase of Atlantis. In addition, production commenced at our
Savonette field in Trinidad, at our Tangguh LNG project in Indonesia and,
through TNK-BP, we saw the start-up of a further two projects, in the
northern hub of Kamennoye, and the Urna and Ust-Tegus fields in the
Uvat area.

Production from our established centres – including the North

Sea, Alaska, North America Gas and Trinidad – was on plan, with
improved operating efficiency for the segment as a whole, and we had
strong production growth in the Gulf of Mexico, including excellent
performance from Thunder Horse. Production from Egypt and TNK-BP
also made a strong contribution to our growth.

Production for the year was up more than 4% from last year. After
adjusting for the effect of entitlement changes in our PSAs and the effect
of OPEC quota restrictions, underlying production growtha was 5%
higher than 2008.

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

We also reduced unit production costs through a combination of high-
grading activity, improving execution efficiency, capturing the benefits
of the deflationary cost environment at the beginning of the year and
favourable foreign exchange effects. During 2009 we improved the
quality of our procurement and supply chain management organization,
systems and processes, which we expect will help deliver sustained cos
t
efficiency in the future.

The replacement cost profit before interest and tax was
$24.8 billion, a 35% decrease compared with the record level in 2008.
This result was primarily driven by lower oil and gas realizations, lower
income from equity-accounted entities and higher depreciation, partly
offset by strong underlying production growth and improved cost
management, which contributed to a 12% reduction in unit production
costs. Our financial results are discussed in more detail on pages 55-56.
Total capital expenditure including acquisitions and asset
exchanges in 2009 was $14.9 billion (2008 $22.2 billion and 2007
$14.2 billion). In 2009, capital expenditure included $306 million relating
to the award of the contract to redevelop the Rumaila field in Iraq.
Development expenditure of subsidiaries incurred in 2009,

excluding midstream activities, was $10,396 million, compared with
$11,767 million in 2008 and $10,153 million in 2007.

Key statistics

Sales and other operating revenuesa
Replacement cost profit before

interest and taxb

Total assets
Capital expenditure and acquisitions

2009
57,626

2008
86,170

24,800
140,149
14,896

38,308
136,665
22,227

$ million

2007
65,740

27,602
125,736
14,207

$ per barrel

Average BP liquids realizationsc d

56.26

90.20

67.45

$ per thousand cubic feet

verage BP natural gas realizationsc

3.25

6.00

4.53

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

The table below presents our average sales price per unit of production.

Europe

North
America

South
America

Africa

Asia

Australasia

Total group
average

$ per unit of productiona

Average sales priceb
2009
Liquidsc
Gas

2008
Liquidsc
Gas

2007
Liquidsc
Gas

Rest of
Europe

62.19
4.68

89.82
8.41

69.17
6.40

60.73
7.62

93.77
6.96

70.41
5.84

53.68
3.07

89.22
6.77

64.18
5.43

Rest of
North
America

30.77
3.53

64.42
7.87

48.24
6.24

Russia

Rest of
Asia

52.48
2.50

91.61
4.90

65.54
3.25

57.40
3.61

89.44
4.46

67.81
3.93

–
–

61.27
3.30

97.20
3.63

73.00
3.05

57.22
5.25

86.33
9.22

70.56
5.96

a Units of production are barrels for liquids and thousands of cubic feet for gas.
b Realizations are based on sales of consolidated subsidiaries only (including transfers between businesses), which excludes equity-accounted entities.
c Crude oil and natural gas liquids.

56.26
3.25

90.20
6.00

67.45
4.53

BP Annual Report and Accounts 2009
Business review

The table below presents our average production cost per unit of production.

Europe

North
America

South
America

Africa

Asia

Australasia

Total group
average

$ per unit of productiona

The average production cost per
unit of productiona
2009
2008
2007

Rest of
Europe

12.38
12.19
14.00

10.72
8.74
7.17

Rest of
North
America

14.45
15.35
14.04

7.26
9.02
9.03

Russia

Rest of
Asia

2.20
2.34
2.69

6.05
6.72
6.43

–
–
–

4.35
5.24
3.81

1.60
1.74
1.75

6.39
7.24
7.14

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

Outlook
Our priorities remain the same – safety, people and performance,
focusing on the delivery of safe, reliable and efficient operations.

In 2010, we aim to use the momentum generated in 2009 to

continue to improve operational, cost and capital efficiency, while
ensuring we maintain our priorities of safe, reliable and efficient
operations. We intend to continue to focus on building personnel and
technological capability for the future. We believe our portfolio of assets
is strong and well positioned to compete and grow in a range of external
conditions. Also in 2010, we intend to create a centralized developments
organization to deliver our major projects. By bringing our project
expertise into one team, we expect to continue our drive for improved
capital efficiency by fully optimizing our project designs and improving
project execution.

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

Our exploration and appraisal costs, excluding lease acquisitions,
in 2009 were $2,805 million, compared with $2,290 million in 2008 and
$1,892 million in 2007. These costs include exploration and appraisal
drilling expenditures, which are capitalized within intangible fixed assets,
and geological and geophysical exploration costs, which are charged to
income as incurred. Approximately 68% of 2009 exploration and appraisal
costs were directed towards appraisal activity. In 2009, we participated in
503 gross (107 net) exploration and appraisal wells in 12 countries.
The principal areas of exploration and appraisal activity were Angola,
Egypt, the deepwater Gulf of Mexico, Libya, the North Sea, Oman
and onshore US.

Total exploration expense in 2009 of $1,116 million (2008
$882 million and 2007 $756 million) included the write-off of expenses
related to unsuccessful drilling activities in the deepwater Gulf of Mexico
($391 million), India ($31 million), Angola ($28 million), Egypt ($27 million),
and others ($31 million).

In most cases, reserves booking from new discoveries will
depend on the results of ongoing technical and commercial evaluations,
including appraisal drilling.

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

At the point of final investment decision, most proved reserves

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

Contingent resources in a field will only be recategorized as
proved reserves when all the criteria for attribution of proved status have
been met and the proved reserves are included in the business plan and
scheduled for development, typically within five years. Where, on
occasion, the group decides to book proved reserves where
development is scheduled to commence after five years, these proved
reserves will be booked only where they satisfy the SEC’s criteria for
attribution of proved status. There are material volumes of proved
undeveloped reserves in Angola, Trinidad, the US, and Canada which are
part of ongoing development activities for which BP has a historical track
record of completing comparable projects. In all cases, the volumes are
being progressed as part of an adopted development plan which calls for
drilling of wells over an extended period of time given the magnitude of
the development.

In 2009, we converted approximately 2,061mmboe proved

undeveloped reserves to proved developed reserves through ongoing
investment in our upstream development activities. Total development
expenditure in Exploration and Production, excluding midstream
activities, was $12,392 million in 2009 ($10,396 million for subsidiaries
and $1,996 million for equity-accounted entities). The major areas
converted in 2009 were Azerbaijan, Indonesia, Russia, Trinidad and
the US.

BP Annual Report and Accounts 2009
Business review

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

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:
(cid:129) 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.

(cid:129) Capital allocation processes, whereby delegated authority is

(cid:129)

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.
(cid:129) Approval hierarchy, whereby proved reserves changes above certain
threshold volumes require central authorization and periodic reviews.
The frequency of review is determined according to field size and
ensures that more than 80% of the BP proved reserves base
undergoes central review every two years and more than 90% is
reviewed centrally every four years.

BP’s segment resources authority is the petroleum engineer primarily
responsible for overseeing the preparation of the reserves estimate.
He has over 35 years of diversified industry experience with the past 10
spent as the head of the reservoir management function within BP. He is
a member of the Society of Petroleum Engineers (SPE) and the Institute
of Materials, Minerals and Mining. On the retirement of the current

segment resources authority in 2010, his responsibilities for reserves
estimation, governance and compliance will be taken by the current vice
president of segment reserves. The current vice president of segment
reserves has over 25 years of diversified industry experience with the
past seven spent managing the governance and compliance of BP’s
reserves estimation. He is a sitting member of the SPE Oil and Gas
Reserves Committee and the United Nations Economic Commission
for Europe Expert Group on Resource Classification.

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

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

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

Proved reserves replacement
Total hydrocarbon proved reserves, on an oil equivalent basis including
equity-accounted entities, comprised 18,292mmboe (12,621mmboe for
subsidiaries and 5,671mmboe for equity-accounted entities) at
31 December 2009, an increase of 0.8% (increase of 0.5% for
subsidiaries and increase of 1.5% for equity-accounted entities)
compared with 31 December 2008. Natural gas represents about 43%
(55% for subsidiaries and 14% for equity-accounted entities) of these
reserves. The increase includes a net decrease from acquisitions and
divestments of 282mmboe, (59mmboe net decrease for subsidiaries
and 223mmboe net decrease for equity-accounted entities) largely
comprising a number of assets in Bolivia, Indonesia, Kazakhstan, Pakistan
and the UK.

The proved reserves replacement ratio is the extent to which

production is replaced by proved reserves additions. This ratio is
expressed in oil equivalent terms and includes changes resulting from
revisions to previous estimates, improved recovery and extensions and
discoveries, and may be expressed as a replacement ratio excluding
acquisitions and divestments or as a total replacement ratio including
acquisitions and divestments. For 2009 the proved reserves replacement
ratio excluding acquisitions and divestments was 129% (121% in 2008
and 112% in 2007) for subsidiaries and equity-accounted entities, 112%
for subsidiaries alone and 164% for equity-accounted entities alone.

In 2009, net additions to the group’s proved reserves (excluding

production, sales and purchases of reserves-in-place and equity-
accounted entities) amounted to 1,113mmboe (795mmboe for equity-
accounted entities), principally through improved recovery from, and
extensions to, existing fields and discoveries of new fields. Of our
subsidiary reserves additions through improved recovery from, and
extensions to, existing fields and discoveries of new fields, approximately
55% are associated with new projects and are proved undeveloped
reserves additions. Volumes added in 2009 principally relied on the
application of conventional technologies. The remaining additions are in
existing developments where they represent a mixture of proved
developed and proved undeveloped reserves. The principal reserves
additions in our subsidiaries were in the US (Arkoma, Mad Dog, Prudhoe
Bay, Thunder Horse), the UK (Clair), Trinidad (Kapok), Angola (Pazflor) and
Australia (Jansz-Io). The principal reserves additions in our equity-
accounted entities were in Argentina (Cerro Dragon, Cuenca Marina
Austral) and in Russia (Kamennoye, Samatlor).

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Compliance
International Financial Reporting Standards (IFRSs) do not provide
specific guidance on reserves disclosures. BP estimates proved reserves
in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant
Compliance and Disclosure Interpretations (C&DI) and Staff Accounting
Bulletins as issued by the SEC staff. On 31 December 2008, the SEC
published a revision of Rule 4-10 (a) of Regulation S-X for the estimation
of reserves. These revised rules form the basis of the 2009 year-end
estimation of proved reserves and the application of the technical aspects
resulted in an immaterial increase of less than 1% to BP’s total proved
reserves. The reasons for the increase are primarily due to the application
of reliable technologies and inclusion of proved reserves more than one
spacing away from existing penetrations as discussed below.

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

development and production of proved reserves, including, but not
limited to, final regulatory approval, the installation of new or additional
infrastructure as well as changes in oil and gas prices, changes in
operating and development costs and the continued availability of
additional development capital. All the group’s proved reserves held in
subsidiaries and equity-accounted entities are estimated by the group’s
petroleum engineers.

Our proved reserves are associated with both concessions (tax

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

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

Production
Our total hydrocarbon production during 2009 averaged 3,998 thousand
barrels of oil equivalent per day (mboe/d). This comprised 2,684mboe/d
for subsidiaries and 1,314mboe/d for equity-accounted entities, an
increase of 6.6% and a decrease of 0.5% respectively compared with
2008. For subsidiaries, 40% of our production was in the US, 17% in
Trinidad and 10% in the UK. For equity-accounted entities, 71% of
production was from Russia, 14% in the United Arab Emirates and 11%
in Argentina.

The strong growth in production in 2009 benefited by about

40mboe/d on an annual basis from a combination of the absence of a
significant hurricane season and from the make-up of a prior period
underlift. As a result, we expect production in 2010 to be slightly lower
than in 2009. The actual growth rate will depend on a number of factors,
including our pace of capital spending, the efficiency of that spend, the
oil price and its impact on PSAs, as well as OPEC quota restrictions.

The group and its equity-accounted entities have numerous long-
term sales commitments in their various business activities, all of which
are expected to be sourced from supplies available to the group which
are not subject to priorities, curtailments or other restrictions. No single
contract or group of related contracts is material to the group.

The following tables show BP’s estimated net proved reserves as at
31 December 2009.

Estimated net proved reserves of liquids at 31 December 2009a b

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

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

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

million barrels

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

Estimated net proved reserves of natural gas at 31 December 2009a b

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

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

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

billion cubic feet

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

Net proved reserves on an oil equivalent basis

Subsidiaries
Equity-accounted entities
Total

million barrels of oil equivalent

Developed
6,696
3,644
10,340

Undeveloped
5,925
2,027
7,952

Total
12,621
5,671
18,292

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 jointly controlled entities and associates that
are accounted for by the equity method although we do not control these entities or the assets
held by such entities.
b The 2009 marker prices used were Brent $59.91/bbl (2008 $36.55/bbl and 2007 $96.02/bbl) and
Henry Hub $3.82/mmBtu (2008 $5.63/mmBtu and 2007 $7.10/mmBtu).
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 68 million barrels on which
a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay
Royalty Trust.
d Includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and
Tobago LLC.
e Includes 243 million barrels of crude oil in respect of the 6.86% minority interest in TNK-BP.
f Includes 3,068 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad
and Tobago LLC.
g Includes 131 billion cubic feet of natural gas in respect of the 5.79% minority interest in TNK-BP.

BP Annual Report and Accounts 2009
Business review

The following tables show BP’s net production by major field for 2009, 2008 and 2007.

Liquids

UKb

Total UK
Norway
Total Rest of Europe
Total Europe
Alaska

Total Alaska
Lower 48 onshoreb
Gulf of Mexico deepwater

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

Total Angola
Egypt

Total Egypt
Algeria
Total Africa
Azerbaijan

Field or area
ETAPc
Foinavend
Other

Various

Prudhoe Bayd
Kuparuk
Milne Pointd
Other

Various
Thunder Horsed
Atlantisd
Mad Dogd
Mars
Na Kikad
Horn Mountaind
Kingd
Other

Variousd

Variousd
Variousd
Various

Greater Plutoniod
Kizomba C Dev
Dalia
Girassol FPSO
Other

Gupco
Other

Various

Azeri-Chirag-Gunashlid
Other

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

Various
Various

Various

Various
Various

Various
Various
Various

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

thousand barrels per day
BP net share of productiona
2007
32
37
132
201
51
51
252
74
52
28
55
209
108
–
2
25
30
32
18
22
67
196
513
8
8
521
28
30
16
74
12
–
31
20
77
140
36
7
43
12
195
200
5
205
7
16
228
228
34
34
1,304

2008
27
26
120
173
43
43
216
72
48
27
50
197
97
24
42
31
28
29
18
23
49
244
538
9
9
547
24
38
4
66
69
30
34
22
46
201
41
16
57
19
277
97
8
105
7
16
128
128
29
29
1,263

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

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

2009
34
29
105
168
40
40
208
69
45
24
43
181
97
133
54
35
29
27
25
22
62
387
665
8
8
673
23
38
–
61
70
43
32
22
44
211
55
16
71
22
304
94
7
101
5
17
123
123
31
31
1,400

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

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

BP Annual Report and Accounts 2009
Business review

Natural gas

UKb

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

Total Lower 48 onshore
Gulf of Mexico deepwater

Total Gulf of Mexico deepwater
Alaska
Total US
Canadab

Total Canada
Total Rest of North America
Total North America
Trinidad & Tobago

Total Trinidad
Colombia
Venezuelab
Total South America
Egypt

Total Egypt
Algeria
Total Africa
Pakistanb
Azerbaijan
Western Indonesiab

Total Western Indonesia
China
Vietnam
Sharjah
Total Rest of Asia
Total Asia
Australia

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

Field or area
Bruce/Rhumc
Brae East
Other

Various
Various

San Juanc
Jonahc
Arkomac
Wamsutterc
Hugotonc
Tuscaloosac
Other

Thunder Horsec
Other

Various

West Central
Otherc

Mangoc
Cashima/NEQBc
Kapokc
Cannonballc
Amherstiac
Otherc

Various
Various

Temsah
Ha’pyc
Taurtc
Other

Various

Variousc
Variousc
Sanga-Sanga
Other

Yacheng
Variousc
Variousc

Perseus/Athena
Goodwyn
Angel
Other

Tangguhc

Various

Various
Various

Various
Various
Various

million cubic feet per day
BP net share of productiona
2007
161
60
547
768
3
26
29
797
694
173
204
120
123
78
458
1,850
–
269
269
55
2,174
63
192
255
255
2,429
22
6
984
628
155
638
2,433
104
6
2,543
118
108
–
89
315
153
468
121
73
75
81
156
85
82
92
609
609
193
107
–
76
376
–
376
7,222

2008
165
71
523
759
–
23
23
782
682
221
240
136
91
65
451
1,886
11
219
230
41
2,157
63
182
245
245
2,402
471
375
619
336
288
357
2,446
84
2
2,532
109
94
24
145
372
112
484
162
143
69
97
166
91
61
73
696
696
229
74
6
71
380
1
381
7,277

564
564
31
8
39
603
385
63
6
454
1,057
8,334

451
451
33
8
41
492
369
60
–
429
921
8,143

2009
110
62
446
618
–
16
16
634
659
227
194
146
102
65
562
1,955
83
220
303
58
2,316
69
194
263
263
2,579
664
571
540
225
197
233
2,430
62
–
2,492
118
94
73
177
462
159
621
173
126
71
35
106
83
63
59
610
610
142
139
120
39
440
74
514
7,450

601
601
31
11
42
643
378
11
3
392
1,035
8,485

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

BP Annual Report and Accounts 2009
Business review

The following narrative reviews operations in our Exploration and
Production business by continent and country, and lists associated
significant events that occurred in 2009. Where relevant, BP’s percentage
working interest in oil and gas assets is shown in brackets. Working
interest is the cost-bearing ownership share of an oil or gas lease. The
percentages disclosed for certain agreements do not necessarily reflect
the percentage interests in reserves and production.

(cid:129)

North America
United States
Our activities within the US take place in three main areas: deepwater
Gulf of Mexico, Lower 48 states and Alaska.

Deepwater Gulf of Mexico:
Deepwater Gulf of Mexico is our largest area of growth in the US.
In addition, we are the largest producer and acreage holder in the region.

(cid:129)

Significant events were:

In May 2009, BP announced it had begun production from the Dorado
(BP 75% and operator) and King South (BP 100%) projects. Both
projects are subsea tiebacks to the existing BP Marlin Tension Leg
Platform (TLP) infrastructure. Dorado comprises three new subsea
wells located about two miles from the Marlin TLP. King South
comprises a single subsea well located 18 miles from the Marlin TLP.
Both projects leverage existing subsea and topsides infrastructure
and the latest subsea and drilling technology to enable the efficient
development of the fields. Dorado utilizes dual completion technology
enabling production from five Miocene zones and King South is
produced through the existing King subsea pump.
In June 2009, the Atlantis Phase 2 (BP 56%) project achieved first oil
ahead of schedule, signalling the official start-up.
In July 2009, BP announced the drilling of a successful appraisal well
in a previously untested southern segment of the Mad Dog field (BP
60.5% and operator). The 826-5 well is located in the Green Canyon
block 826, approximately 100 miles south of Grand Isle, Louisiana,
in about 5,100 feet of water. The results from this well continue the
successful phased development of the Mad Dog field and build upon
the success from 2008.
In September 2009, BP announced the Tiber discovery in the
deepwater Gulf of Mexico (BP 62% and operator). The discovery well,
located in Keathley Canyon block 102, approximately 250 miles south-
east of Houston, is in 4,132 feet of water. It was drilled to a total
depth of approximately 35,055 feet making it the deepest oil and gas
discovery well ever drilled. The well found oil in multiple Lower
Tertiary reservoirs. Appraisal will be required to determine the size
and commerciality of the discovery.

Lower 48 states:
Our North America Gas business operates onshore in the Lower 48
states producing natural gas, natural gas liquids and coalbed methane
across 14 states. In 2009, we drilled almost 300 wells as operator and
continued to maintain a stable programme of drilling activity throughout
the year. Shale gas assets are becoming an increasingly important part of
our North America Gas business:

Significant events were:

(cid:129)

In the fourth quarter of 2009, BP further expanded its shale gas
portfolio by securing new access in the Eagle Ford Shale in South
Texas. Combined with our 2008 acquisitions of interests in
Chesapeake Energy Corporation’s Woodford and Fayetteville Shale
assets in the Arkoma Basin and our incumbent position in the
Haynesville Shale in East Texas, BP now has a material shale gas
position in the Lower 48 states.

(cid:129) Since taking over operations of the Woodford shale properties,
BP gross operated production has increased from 60mmcf/d in
November 2008 to over 100mmcf/d by the end of 2009, a 67%
increase. BP delivered 23 wells by the end of the year with an

average 30-day rate of 4.6mmcf/d per well, approximately 50% higher
than initial expectations.
In 2009, BP net production from the Fayetteville shale properties has
grown from approximately 55mmcf/d to 87mmcf/d at the end of the
year, an increase of approximately 60%. Individual well performance
continues to exceed expectations by approximately 25%.
In 2009, BP drilled four wells appraising the Haynesville Shale asset
and plans to increase horizontal well drilling in 2010. BP’s position in
the Haynesville Shale in North Louisiana and East Texas covers an
area of approximately 150,000 net acres.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

(cid:129) The business has made good progress in restructuring its activity and
driving down costs to a level that is consistent with the economic
environment.

Alaska:
BP operates 15 North Slope oil fields (including Prudhoe Bay, Endicott,
Northstar, and Milne Point) and four North Slope pipelines, and owns a
significant interest in six other producing fields.

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

(cid:129)

Significant events were:

In 2009, we progressed the previously announced development
activities for the Liberty oilfield, which is located on federal leases
about six miles offshore in the Beaufort Sea, and east of the Prudhoe
Bay oilfield. The planned development includes up to six ultra-
extended reach wells, including four producers and two injectors, to
be drilled from existing infrastructure in the BP-operated Endicott field
to minimize the onshore and offshore environmental footprint. These
wells are expected to be the longest horizontal wells ever drilled and
completed in the industry, extending two miles deep and as far as
eight miles horizontally. A specialized rig for drilling in the Arctic has
been built for the project, and it is the world’s largest and most
powerful onshore drilling rig. Key project milestones achieved during
2009 include expansion of the BP-operated Endicott field satellite
drilling island (SDI) in April; and sealift delivery of the ultra-extended
reach drilling rig to the Endicott SDI in August. Drilling is expected to
start in 2010, with first oil expected in 2011. BP drilled the Liberty
discovery well in 1997, and is the operator and sole owner of the field.

(cid:129) On 27 January 2009, the Commissioner of the State of Alaska

Department of Natural Resources (DNR) issued a ‘Conditional Interim
Decision’ in connection with the appeal of the Point Thomson area
lease terminations. The Point Thomson Unit (PTU) was terminated by
administrative decision of the DNR in November 2006 (BP 32%). In
February 2007, the DNR notified the PTU owners of its decision to
terminate the Point Thomson area leases as well. ExxonMobil,
operator, and the other unit owners including BP, are pursuing an
appeal of the unit termination in the Alaska Superior Court; and the
lease terminations are under administrative appeal with the DNR. The
27 January 2009 Conditional Interim Decision permitted ExxonMobil
to conduct drilling operations on two of the 31 terminated leases
comprising the former PTU. The DNR’s interim decision provided that
the two leases would be reinstated if certain conditions were met.
On 11 January 2010, the Alaska Superior Court reversed the DNR
Commissioner’s administrative decision to terminate the PTU. The
parties have been ordered to provide the Court further briefing
regarding whether the Court should again remand the matter for an
administrative proceeding with DNR, or retain jurisdiction with the
Alaska Superior Court and conduct a de novo proceeding.

BP Annual Report and Accounts 2009
Business review

Canada
In Canada, BP operates in five provinces and two territories, exploring for,
developing, producing and processing natural gas and heavy crude oil.
We also hold an interest in an oil sands joint venture with Husky Energy
Inc., we market natural gas and we are the largest marketer of natural
gas liquids.
(cid:129)

In 2009, BP conducted a successful 3D seismic programme over the
primary area of interest on the exploration licences acquired in 2008
in the Canadian Beaufort Sea. The programme was the most
northerly 3D seismic programme ever conducted, with approximately
1,600 square kilometres of 3D data acquired. The project also had the
largest array of towed marine streamers deployed in the high Arctic.
BP has 2,392,101 acres (968,049 hectares) of significant discovery
licences and exploration licences in the Beaufort Sea.

South America
Venezuela
BP has been in Venezuela since 1994 and currently participates in three
equity-accounted entities.
(cid:129)

In 2009, production cuts due to OPEC quota restrictions were
assigned to the Petromonagas and Petroperija entities.
Petromonagas’s OPEC quota restrictions resulted in a complete
production shutdown until 12 July 2009. There is uncertainty
regarding the duration of the quota restrictions in Petroperija.

Colombia
Our main activity in Colombia is concentrated on operating a producing
field complex in the Casanare region. In addition, we operate four
principal processing plants and own pipeline interests. BP also holds
exploration rights over two blocks off Colombia’s northern coast in the
Caribbean Sea.
(cid:129) During 2009, seismic data processing and interpretation was carried
out at the RC4 and RC5 Caribbean offshore blocks (BP 40.6%) in
order to determine potential prospects. A decision whether to drill a
well is expected to be taken in 2010.

(cid:129) During 2009, the strategy and detailed plan for the termination of the

Santiago de las Atalayas field contract by June 2010, and its
subsequent operation by Ecopetrol, was designed and implemented.

Argentina, Bolivia and Chile
BP conducts activity in the Southern Cone region of South America
(Argentina, Bolivia and Chile) through Pan American Energy (PAE), a joint
venture company in which BP holds a 60% interest. As the venture is
jointly controlled with Bridas Corporation, it is accounted for using the
equity method of accounting. Most of the PAE production comes from
the Cerro Dragon field in the provinces of Chubut and Santa Cruz.
(cid:129) The Cerro Dragon field is now producing at its highest level since the
licence was granted in 1958, and further expansion programmes are
planned. PAE also has other gas and liquids producing assets in the
Argentine provinces of Salta, Neuquen and Tierra del Fuego, and in
Bolivia. PAE also has interests in exploration areas, pipelines, and
other midstream infrastructure assets, primarily in Argentina.

(cid:129) On 26 November 2008, the Argentine government issued a decree by
which a new regime on oil and by-products exports, called Petróleo
Plus was put in place. This programme provides fiscal relief in the
form of fiscal credit certificates, which can be used to offset export
tariffs on oil, LPG and by-products. The goal is to incentivize
investment to increase oil production and reserves. As PAE achieved
the targets for both reserves replacement and production growth
stipulated in the programme, it has obtained and applied fiscal credit
certificates since January 2009.

(cid:129) On 23 January 2009, the president of Bolivia issued a decree

nationalizing PAE’s investment in 8,049,660 shares of Chaco. The
decree establishes a compensation value per share, which represents
a total amount of $233 million (BP share $140 million), subject to
eventual adjustments. The partners assert that this is not an adequate
compensation for the nationalized shares. PAE will pursue an
adequate compensation for the nationalized assets.

(cid:129) On 28 January and 22 May 2009, PAE entered into two agreements

with the Neuquen province in Argentina that provide for the extension
of concession terms related to the exploration and development of
the Aguada Pichana and San Roque blocks and of the Lindero
Atravesado block, respectively.

Trinidad & Tobago
BP holds exploration and production licences covering 904,000 acres
offshore of the east coast. Facilities include 12 offshore platforms and
one onshore processing facility. Production is comprised of oil, gas and
NGLs.
(cid:129) On 27 October 2009, the Savonette offshore field development

began production on a normally unmanned installation platform (NUI).
Savonette is located in 290 feet (88 metres) of water approximately
50 miles off Trinidad’s south-east coast. Production from the platform
is tied in to BP Trinidad and Tobago’s Mahogany B platform and will
supply the Trinidad domestic market as well as Atlantic LNG’s
liquefaction plant for export as LNG to international markets. The
Savonette platform, installed in February 2009, is the fourth in a
series of NUIs designed and constructed locally in Trinidad using a
standardized ‘clone’ concept. The first three NUIs were Cannonball,
Mango and Cashima.

Europe
United Kingdom
We are the largest producer of oil, the second largest producer of gas
and the largest overall producer of hydrocarbons in the UK. Key aspects
of our activities in the North Sea include a focus on in-field drilling and
selected new field developments. Our development expenditure
(excluding midstream) in the UK was $751 million in 2009, compared
with $907 million in 2008 and $804 million in 2007. BP operates one NGL
plant in the UK.

Significant events were:

(cid:129) On 31 August 2009, the exchange of assets between BP and BG
Group was formally completed. The exchange is expected to
strengthen BP’s position as a major operator in the southern North
Sea and to facilitate development activity and investment in the UK
Continental Shelf. BP acquired BG’s 24.2% interest in the BP-
operated Amethyst field and all its interests in the Easington
Catchment Area fields, including a 73.3% interest in the Mercury
field, a 79% interest in the Neptune field, a 65% interest in the
Minerva, Apollo and Artemis fields and BG’s 30.8% interest in the
BP-operated Whittle and Wollaston fields. In return, BG Group
acquired BP’s interest and operatorship in the Everest (BP 21.1%)
and Lomond (BP 22.2%) fields, BP’s 18.2% interest in the BG-
operated Armada field and 32% of the Chevron-operated Erskine field
(BP retained 18% equity in Erskine).

(cid:129) Drilling performance moved from fourth quartile in 2007 to first

quartile in 2008a, and generated additional drilling capital efficiencies
in 2009.

a Source: BP Drilling and Completions Global Benchmarking.

BP Annual Report and Accounts 2009
Business review

Rest of Europe
Our activities in the Rest of Europe are in Norway.
(cid:129) Development expenditure (excluding midstream) in the Rest of

Europe was $1,054 million, compared with $695 million in 2008 and
$443 million in 2007. Progress continued on the Skarv and Valhall
redevelopment projects.

Africa
Angola
BP is present in four major deepwater licences offshore Angola (Blocks
15, 17, 18 and 31) and is operator in Blocks 18 and 31. In addition, BP
holds a 13.6% equity share in the first Angolan LNG project. Technical
skills developed in similar deepwater basins around the world have been
applied extensively in BP’s operations in Angola.
(cid:129) On 29 December 2008, BP began a comprehensive seismic survey
on Block 31 (BP 26.67% and operator) using a wide azimuth towed
streamer (WATS) to gain improved imaging quality of sub-salt strata.
WATS seismic is an acquisition configuration developed by BP to
image areas of complex geology below salt. The WATS survey will
significantly improve the imaging and understanding of the fields, and
more significantly, the data acquired will also support the definition of
hubs which will form part of BP’s development programme. This is
the first such survey to be conducted by BP outside the Gulf of
Mexico, and is the first WATS survey conducted in Angola.
In 2009, BP announced its seventeenth through nineteenth
discoveries in the ultra deepwater Block 31. On 3 March 2009, BP
announced the discovery of the Leda field. Leda was drilled in a water
depth of 2,070 metres and reached a total depth of nearly 6
kilometres below sea level. It is located in the central northern portion
of Block 31, some 415 kilometres north-west of Luanda. This is the
fifth discovery in Block 31 in which the exploration well has been
drilled through salt to access the oil-bearing sandstone reservoir
beneath. On 27 May 2009, BP announced the Oberon oil discovery.
Oberon-1 was drilled in a water depth of 1,624 metres and reached a
total depth of 3,622 metres below sea level. On 1 October 2009, BP
announced the Tebe oil discovery. The Tebe well was drilled in a water
depth of 1,752 metres and a total depth of 3,325 metres below sea
level.

(cid:129)

Algeria
BP is a partner with Sonatrach and Statoil in the In Salah (BP 33.15%)
and In Amenas (BP 45.89%) projects, which supply gas to the domestic
and European markets. BP is also in partnership with Sonatrach in the
Rhourde El Baguel (REB) oilfield (BP 60%), an enhanced oil recovery
project 75 kilometres east of the Hassi Messaoud oilfield. In addition, BP
is in partnership with Sonatrach in the Bourarhet Sud block, located to the
south-west of In Amenas.
(cid:129)

In 2008, Sonatrach and BP announced a discovery with the Tin
Zaouatene-1 (TZN-1) exploration well. BP is currently in the second
prospecting period, which runs until September 2010. Seismic
operations started in February 2009 and were completed in October
2009. Drilling activities commenced in December 2009.

Libya
In Libya, BP is in partnership with the Libyan Investment Corporation
(LIC) to explore the onshore Ghadames and offshore Sirt basins.
(cid:129)

In 2009, BP continued the onshore and offshore seismic operations
started in 2008 on the acreage covered under the exploration and
production sharing agreement ratified in December 2007 (BP 85%).
In October 2009, BP completed a large offshore 3D survey in the
deepwaters of the Libyan Gulf of Sirt. The programme, started in
September 2008, was conducted by the seismic vessel Geowave
Endeavour (operated by CGGV-Wavefield Inseis), and covered 17,000
square kilometres, 60% of BP’s Sirt exploration acreage.

(cid:129)

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

(cid:129) BP is also progressing its onshore seismic operations in the deserts
of Libya’s Ghadames basin. This is the first full application of a new,
cutting-edge seismic technique developed by BP, known as
Independent Simultaneous Sweeping (ISS): the technology allows
greater acquisition (in excess of 10,000 vibration points per day
compared with conventional technology of 1,500 per day) and cost
efficiency. Exploration drilling is scheduled to commence during 2010
in both onshore and offshore blocks.

Egypt
BP is the single largest foreign investor in Egypt, with investments close
to $15 billion to date. With its partners, BP has produced almost 40% of
Egypt’s entire oil production and close to 30% of its gas production. The
Gulf of Suez Petroleum Company (GUPCO), BP’s joint venture with the
Egyptian General Petroleum Corporation, has been an industry leader in
Egypt and the entire region and covers operations in the Gulf of Suez and
the Western Desert.
(cid:129) During the second quarter of 2009, BP was awarded two blocks in
the Egyptian Offshore Nile Delta. BP has a 100% working interest
and is the operator of Block 2, North Tineh, which is in a deepwater
area of the Eastern Nile Delta. BP will also be the operator of Block 3,
North Damietta Offshore, which is adjacent to Block 2, with Shell and
Petronas as partners with a one-third working interest each. These
awards build on the existing portfolio in Egypt, providing an additional
platform for growth. BP’s expertise in exploring deepwater, high-
pressure and high-temperature deep targets maximizes the chances
of unlocking the potential in this area.

(cid:129) During the third quarter of 2009, the Egyptian parliament approved
the amendments to two Gulf of Suez (GOS) concessions: South
Belayim (BP 100%) and South Ghara (BP 75%). The amendments
provide BP with enhanced commercial structure and extend the term
of both concessions by 20 years in return for increased investment
levels. This marks a significant step in the development of the
Southern GOS assets.

Asia
Western Indonesia
BP has a joint interest in Virginia Indonesia Company LLC (VICO), the
operator of the Sanga-Sanga PSA (BP 38%) supplying gas to Indonesia’s
largest LNG export facility, the Bontang LNG plant in Kalimantan.
(cid:129) During 2009, VICO successfully completed a joint evaluation of the
coalbed methane (CBM) opportunities in the Sanga-Sanga area. In
November, VICO signed a PSA with the Government of Indonesia, for
the exploration and development of these CBM resources.

(cid:129) On 1 July 2009, BP divested its entire 46% holding in the Offshore
Northwest Java (ONWJ) PSA to Indonesia’s national oil company,
Pertamina.

Vietnam
Our upstream business in Vietnam is concentrated on the Block 6.1
offshore gas field. BP participates in one of the country’s largest foreign
investment projects, the Nam Con Son gas project. This is an integrated
resource and infrastructure project, which includes offshore gas
production, a pipeline transportation system and a power plant.
(cid:129) BP Block 6.1 Lan Do development project was sanctioned in

December 2009, with first gas scheduled in 2012.

(cid:129) BP’s withdrawal from Blocks 5.2 (BP 55.9% and operator) and 5.3

(BP 75% and operator) was completed in December 2009.

China
BP’s upstream asset in the country is the Yacheng offshore gas field (BP
34.3%) in the South China Sea, one of the biggest offshore gas fields in
China. Yacheng supplies the Castle Peak Power Company gas for up to
70% of Hong Kong’s gas-fired electricity generation. Additional gas is
also sold to the Hainan Holdings Fuel & Chemical Corporation Limited.

BP Annual Report and Accounts 2009
Business review

(cid:129) The Platform A development project approved at the end of 2008 is

on track to deliver first gas in 2010.

Azerbaijan
BP is the largest foreign investor in the country. BP operates two PSAs,
Azeri-Chirag-Gunashli (ACG) and Shah Deniz, and also holds other
exploration leases.
(cid:129) A comprehensive review of the subsurface gas release that occurred

beneath the Central Azeri platform in September 2008, and
subsequent remedial works, have resulted in bringing the level of
production from the platform to over 220mboe/d from 12 wells.
Further minor remedial work is planned during 2010.

(cid:129) On 13 July 2009, BP and the State Oil Company of the Republic of

Azerbaijan (SOCAR) signed a memorandum of understanding (MOU)
to jointly explore and develop the Shafag and Asiman structures in
the Azerbaijan sector of the Caspian Sea. The MOU gives BP the
exclusive right to negotiate the PSA. The block covers an area of
some 1,100 square kilometres and has never been explored before.
It is located in a deepwater section of about 650-800 metres with
reservoir depth of about 7,000 metres.

Russia
TNK-BP
TNK-BP, an associate owned by BP (50%) and Alfa Group and Access-
Renova (AAR) (50%), is an integrated oil company operating in Russia and
the Ukraine. BP’s investment in TNK-BP is reported in the Exploration and
Production segment. The TNK-BP group’s major assets are held in OAO
TNK-BP Holding. Other assets include the BP-branded retail sites in the
Moscow region and interests in OAO Rusia Petroleum and the OAO
Slavneft group. The workforce comprises more than 52,000 people.
(cid:129) Downstream, TNK-BP has interests in six refineries in Russia and the
Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl
refinery), with throughput of approximately 683 thousand barrels per
day. TNK-BP supplies approximately 1,400 branded filling stations in
Russia and the Ukraine and has more than 20% market share of the
Moscow retail market.

(cid:129) On 9 January 2009, BP reached final agreement on amendments to
the shareholder agreement with its Russian partners in TNK-BP. The
revised agreement is aimed at improving the balance of interests
between the company’s owners, and focusing the business more
explicitly on value growth. The former evenly balanced main board
structure has been replaced by one with four representatives each
from BP and AAR, plus three independent directors. Unanimous
board support is required for certain matters including substantial
acquisitions, divestments and contracts, and projects outside the
business plan, together with approval of key changes to the TNK-BP
group’s financial framework and related-party transactions. A number
of other matters will be decided by approval of a majority of the
board, so that the independent directors will have the ability to
decide in the event of disagreement between the shareholder
representatives on the board. BP will continue to nominate the chief
executive officer (CEO), subject to main board approval, and AAR will
continue to appoint the chairman. The three independent directors
appointed to the restructured main board are Gerhard Schroeder,
former chancellor of the Federal Republic of Germany, James Leng,
former chairman of Corus Steel and Alexander Shokhin, president of
the Russian Union of Industrialists and Entrepreneurs. In addition,
significant TNK-BP subsidiaries will have directors appointed by BP
and AAR on their boards. Our investment was reclassified from a
jointly controlled entity to an associate with effect from 9 January
2009; however, the results of TNK-BP continue to be accounted for
under the equity method. On 6 August 2009, TNK-BP announced that
William Schrader was appointed chief operating officer. Mr. Schrader
took office during the fourth quarter of 2009, replacing Tim Summers.
In November, the TNK-BP board of directors unanimously agreed to

appoint Maxim Barsky, TNK-BP executive vice president for strategy
and business development, as the TNK-BP group’s future CEO,
effective 1 January 2011. Until that time, Mikhail Fridman has agreed
to continue to act as interim CEO, in addition to his role as executive
chairman of the board of directors of TNK-BP Limited.

(cid:129) On 16 February 2009, TNK-BP announced that the company had

launched commercial production from the Urna and Ust-Tegus fields
in the Uvat area of the Tyumen region, Russia. Urna and Ust-Tegus are
located in the eastern part of Uvat. TNK-BP completed construction of
a 264-kilometre pipeline and a central crude oil gathering facility,
which facilitate transportation of oil from the fields westwards to
enter the Transneft pipeline system. Investment in field development
and construction of the infrastructure is expected to amount to over
$1.5 billion.

(cid:129) On 2 June 2009, TNK-BP announced that the company had launched
commercial production in the Northern Hub of the Kamennoye field,
one month earlier than planned. The Kamennoye field, in the Khanty-
Mansiisk region of West Siberia, is one of the largest greenfield
projects developed by TNK-BP. Aitor and Poima form the Northern
Hub of the producing Kamennoye field. Thirty-five wells were drilled
and completed in Aitor and, going forward, the primary focus is on
drilling 194 wells in Poima. Infrastructure construction includes
upgrading of the gathering and treatment facilities, construction and
upgrade of the pipeline and water flood systems as well as the power
supply system. This strategy and development plan is aimed at
maximizing the use of existing facilities and minimizing the impact
on the ecologically sensitive territory. Between 2004 and 2009,
investment in the Kamennoye project amounted to over $800 million.

(cid:129) On 29 July 2009, TNK-BP and Weatherford International Ltd

(Weatherford) announced that TNK-BP completed the sale of its Oil
Field Services (OFS) enterprises to Weatherford pursuant to the sales
and purchase agreement signed on 29 May 2009. Via this transaction,
Weatherford acquired 10 OFS companies providing drilling, well work-
over and cementing services operating in West Siberia, East Siberia
and the Volga-Urals region.
In 2007, BP and TNK-BP signed heads of agreement to create
strategic business alliances with OAO Gazprom. Under the terms of
this agreement, TNK-BP agreed to sell to Gazprom its stake in OAO
Rusia Petroleum, the company that owns the licence for the Kovykta
gas condensate field in East Siberia and its interest in East Siberia
Gas Company. Discussions to conclude this disposal continue.

(cid:129)

Sakhalin
(cid:129) BP has material interests in Sakhalin through two joint venture

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

BP Annual Report and Accounts 2009
Business review

Kazakhstan
(cid:129) On 11 December 2009, BP announced that it has divested its interest
in Kazakhstan’s Tengiz oil field and the Caspian Pipeline Consortium
(CPC) pipeline, carrying oil between Kazakhstan and Russia, by selling
its 46% stake in LukArco to Russia’s Lukoil. Lukoil, which already
owns 54% of LukArco, will pay $1.6 billion in cash in three
instalments over two years from December 2009.

Middle East and Pakistan
Production in the Middle East consists principally of the production
entitlement of associates in Abu Dhabi, where we have equity interests
of 9.5% and 14.67% in onshore and offshore concessions respectively.
In Sharjah, the joint agreement between BP, the Government of
(cid:129)
Sharjah, Itochu and Tokyo Beki, for the operation and maintenance of
LPG facilities and the production and marketing of LPG products,
expired on 22 March 2009 after a period of 25 years. BP relinquished
its 25% ownership, in accordance with the joint venture agreement,
and negotiated terms that retain BP as the operator of the facilities
through an operating fee structure.
In Block 61 in Oman, the challenges posed by the world’s largest
onshore wide-azimuth 3D seismic survey led the BP Oman team to
use a ground-breaking new technique known as distance separated
simultaneous sweeping (DS3). BP’s appraisal programme continues
to make good progress evaluating the resources in place in the
Khazzan/Makarem gas fields. Five appraisal wells have been drilled
in 2009. Fracture stimulation and testing of these wells continues.
Infrastructure to facilitate long-term wells tests is under construction
and expected to be ready for service in the second half of 2010.
(cid:129) On 3 January 2010, we received approval from the Government of
Jordan to join the state-owned National Petroleum Company to
exploit the onshore Risha concession in the north-east of the country.

(cid:129)

(cid:129) With effect from 1 January 2009 BP assumed operatorship of the

(cid:129)

Mirpurkhas and Khipro onshore blocks in the southern Sindh province
of Pakistan.
In the third quarter of 2009, BP won bids for two new exploration
blocks, Digri and Sanghar South, in Pakistan. These blocks are
adjacent to BP’s Mirpurkhas and Khipro concession areas and add
another 5,000 square kilometres to the group’s existing portfolio of
5,300 square kilometres. BP has committed to invest approximately
$30 million in these blocks for seismic and wells over the next three
years.

Iraq
(cid:129)

In November 2009, BP and China National Petroleum Company
(CNPC) entered into a contract with the state-owned Southern Oil
Company of Iraq to expand production from the Rumaila oilfield near
Basra in southern Iraq. This followed a successful bid for the contract
in Baghdad in June 2009. The Rumaila field currently produces
approximately one million barrels of oil per day. BP and CNPC plan to
invest approximately $15 billion over the next 20 years to enhance the
Rumaila production to a plateau rate of 2.85mmb/d, around 3% of
global oil production. BP will hold a 38% working interest, CNPC will
hold 37% and the remaining 25% will be held by the State Oil
Marketing Organisation (SOMO) representing the Iraqi government.

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

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

(cid:129) The North Rankin 2 project linking a second platform to the existing
North Rankin A platform sanctioned in 2008, is on schedule. On
completion, the North Rankin A and North Rankin B platforms will
operate as a single integrated facility and recover low pressure gas
from the North Rankin and Perseus gas fields.

(cid:129) The joint venture partners (Chevron, ExxonMobil and Shell) approved

the Greater Gorgon project on 14 September 2009 with the Australian
Government also awarding production licences for the Jansz-Io field
(BP 5.375%). The Jansz-Io field will be developed as part of the
Greater Gorgon project, which will comprise three LNG trains, each
with a capacity of 5 million tonnes per annum (mtpa), on Barrow
Island with first gas expected in 2014. As part of this, a unitization
and unit operating agreement has been executed with the joint
venture partners and sales and purchase agreements for the wellhead
sale of raw gas and repurchase of LNG ex-Barrow Island have been
executed between BP and Shell.

Midstream activities
Oil and natural gas transportation
The group has direct or indirect interests in certain crude oil and natural
gas transportation systems. The following narrative details the significant
events that occurred during 2009 by country.

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

transportation assets are included under Refining and Marketing (see
page 36).

Alaska
BP owns a 46.9% interest in the Trans-Alaska Pipeline System (TAPS),
with the balance owned by four other companies. BP also owns a 50%
interest in a joint venture company called ‘Denali – The Alaska Gas
Pipeline’ (Denali). Denali has begun work on an Alaska gas pipeline
project, consisting of a gas treatment plant on Alaska’s North Slope,
a large diameter pipeline that is intended to pass through Alaska into
Canada, and should it be required, a large-diameter pipeline from Alberta
to the Lower 48 states. When completed, the pipeline is expected to
transport approximately 4 billion cubic feet of natural gas per day to
market. Following a successful open season, Denali will seek certification
from the Federal Energy Regulatory Commission (FERC) of the US and
the National Energy Board (NEB) of Canada to move forward with project
construction. Denali will manage the project, and will own and operate
the pipeline when completed. BP may consider other equity partners,
including pipeline companies, who can add value to the project and help
manage the risks involved.

Significant events were:

(cid:129) Work on the strategic reconfiguration project to upgrade and

automate four TAPS pump stations continued to progress in 2009.
This project involves installing electrically driven pumps at four critical
pump stations, along with increased automation and upgraded
control systems. Two of the reconfigured pump stations came online
during 2007 and a third reconfigured pump station came online in
May 2009. Reconfiguration of the remaining pump station in the
programme plan will commence in 2010, with installation currently
planned for 2012.

BP Annual Report and Accounts 2009
Business review

(cid:129) On 16 April 2009, the US FERC issued an initial ruling on shipper

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

North Sea
In the UK sector of the North Sea, BP operates the Forties Pipeline
System (FPS) (BP 100%), an integrated oil and NGLs transportation and
processing system that handles production from more than 50 fields in
the Central North Sea. The system has a capacity of more than one
million barrels per day, with average throughput in 2009 of 671mb/d. BP
also operates and has a 29.5% interest in the Central Area Transmission
System (CATS), a 400-kilometre natural gas pipeline system in the central
UK sector of the North Sea. The pipeline has a transportation capacity of
1,700mmcf/d to a natural gas terminal at Teesside in north-east England.
CATS offers natural gas transportation and processing services. In
addition, BP operates the Dimlington/Easington gas processing
terminal (BP 100%) on Humberside and the Sullom Voe oil and gas
terminal in Shetland.

Asia
BP, as operator, manages and holds a 30.1% interest in the
Baku-Tbilisi-Ceyhan (BTC) oil pipeline. The 1,768-kilometre pipeline
transports oil from the BP-operated ACG oil field in the Caspian Sea to
the eastern Mediterranean port of Ceyhan. BP is technical operator of,
and holds a 25.5% interest in, the 693-kilometre South Caucasus Pipeline
(SCP), which takes gas from Azerbaijan through Georgia to the Turkish
border. In addition, BP operates the Azerbaijan section of the Western
Export Route Pipeline between Azerbaijan and the Black Sea coast of
Georgia (as operator of Azerbaijan International Operating Company).

Significant events were:

(cid:129) On 23 April 2009, BP completed the sale of its 49.9% interest in

Kazakhstan Pipeline Ventures (KPV) to Kazakhstan state oil and gas
company KazMunayGas (KMG) for $250 million. KPV holds a 1.75%
interest in the Caspian Pipeline Consortium (CPC) that carries crude
oil from Kazakhstan’s largest producing oil field, Tengiz, to the Russian
port of Novorossiysk on the Black Sea.

(cid:129) On 11 December 2009, BP also divested its interest in the CPC

pipeline (held through LukArco) by selling its 46% stake in LukArco to
Lukoil.

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

Assets and significant events included:

(cid:129)

In Trinidad, BP’s net share of the capacity of Atlantic LNG Trains 1, 2, 3
and 4 is 6 million tonnes of LNG per year (369 billion cubic feet
equivalent regasified), with the Atlantic LNG Train 4 (BP 37.8%)
designed to produce 5.2mtpa (294 billion cubic feet per annum) of
LNG. All of the LNG from Atlantic Train 1 and most of the LNG from
Trains 2 and 3 is sold to third parties in the US and Spain under 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.

(cid:129) We have a 10% equity shareholding in the Abu Dhabi Gas

Liquefaction Company, which in 2009 supplied 5.4 million tonnes
(279,000mmcf) of LNG.

(cid:129) BP has a 13.6% share in the Angola LNG project, which is expected
to receive approximately one billion cubic feet of associated gas per
day from offshore producing blocks and to produce 5.2 million tonnes
per year of LNG (gross), as well as related gas liquids products.
Construction and implementation of the project is proceeding and
is expected to start up in 2012.
In Indonesia, BP is involved in two of the three LNG centres in the
country. BP participates in Indonesia’s LNG exports through its
holdings in the Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently
delivers around 13% of the total gas feed to Bontang, one of the
world’s largest LNG plants. The Bontang plant produced more than
17 million tonnes of LNG in 2009.

(cid:129)

(cid:129) Also in Indonesia, the Tangguh project (BP 37.16% and operator) in
Papua Barat, Indonesia, started LNG production in June 2009,
delivering its first commercial LNG delivery in July. Tangguh is BP’s
first operated LNG plant. The first phase of Tangguh comprises two
offshore platforms, two pipelines and an LNG plant with two
production trains with a total capacity of 7.6mtpa. Tangguh adopted
a fully integrated approach to development and its impact on local
communities. The Tangguh project has five long-term contracts in
place to supply LNG to purchasers in China, South Korea, Mexico
and Japan.
In Australia, we are one of seven partners in the North West Shelf
(NWS) venture. The joint venture operation covers offshore
production platforms, trunklines, onshore gas and LNG processing
plants and LNG carriers. BP’s net share of the capacity of NWS LNG
Trains 1-5 is 2.7mtpa of LNG.

(cid:129)

(cid:129) BP has a 30% equity stake in the 7mtpa capacity Guangdong LNG
regasification and pipeline project in south-east China, making it the
only foreign partner in China’s LNG import business. The terminal is
also supplied under a long-term contract with Australia’s NWS
project.
In both the Atlantic and Asian regions, BP is marketing LNG using BP
LNG shipping and contractual rights to access import terminal
capacity in the liquid markets of the US (via Cove Point and Elba
Island), the UK (via the Isle of Grain) and Italy (Rovigo), and is
supplying Asian customers in Japan, South Korea and Taiwan.

(cid:129)

BP Annual Report and Accounts 2009
Business review

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

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

commodity derivative contracts and storage and transport contracts.
These include commodity derivatives such as futures, swaps and options
to manage price risk and forward contracts used to buy and sell gas and
power in the marketplace. Using these contracts, in combination with
rights to access storage and transportation capacity, allows the group to
access advantageous pricing differences between locations, time periods
and arbitrage between markets. Natural gas futures and options are
traded through exchanges, while over-the-counter (OTC) options and
swaps are used for both gas and power transactions through bilateral
and/or centrally cleared arrangements. Futures and options are primarily
used to trade the key index prices such as Henry Hub, while swaps can
be tailored to price with reference to specific delivery locations where
gas and power can be bought and sold. OTC forward contracts have
evolved in both the US and UK markets, enabling gas and power to be
sold forward in a variety of locations and future periods. These contracts
are used both to sell production into the wholesale markets and as
trading instruments to buy and sell gas and power in future periods.
Storage and transportation contracts allow the group to store and
transport gas, and transmit power between these locations. The group
has developed a risk governance framework to manage and oversee the
financial risks associated with this trading activity, which is described in
Note 24 to the Financial statements on pages 144-149.

The range of contracts that the group enters into is described

below in more detail.

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

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 sales
and other operating 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 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. For accounting purposes, spot and term sales are included
in sales and other operating revenues, when title passes. Similarly, spot
and term purchases are included in purchases for accounting purposes.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business 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, petrochemicals products and related services to
wholesale and retail customers. BP markets its products in more than
80 countries. We have significant operations 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.

Our organization is managed through 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 the geographic nature of the
markets in which we compete. This provides the opportunity to optimize
our activities from crude oil purchases to end-consumer sales through our
physical assets (refineries, terminals, pipelines and retail stations). The
IBs include the manufacturing, supply and marketing of lubricants,
petrochemicals, aviation fuels and liquefied petroleum gas (LPG).

Our market
The 2009 operating environment was again challenging. Global oil
demand contracted by approximately 1.3 million barrels per day with
demand in the OECD falling for the fourth consecutive year. Crude oil
prices more than doubled during the course of the year, from a dated
Brent price of $36.55 per barrel on 1 January 2009 to $77.67 per barrel at
the end of 2009, contributing to margin volatility.

Refining margins fell sharply in 2009 as demand for oil products
reduced in the wake of the global economic recession and new refining
capacity came onstream, mostly in Asia. During 2009, distillate
inventories were consistently above the top of the range of the past five
years. Gasoline inventories grew steadily and were generally at or slightly
above the average level of the past five years. As a result, the BP global
indicator refining margin (GIM) averaged $4 per barrel in 2009, down
$2.50 per barrel compared with 2008, with the average for the fourth-
quarter of 2009 at only $1.49 per barrel, the lowest for almost 15 years.
This margin decline had a significant adverse impact on the financial
performance of the segment.

In Europe, where diesel accounts for a large proportion of regional
demand, refining margins were hit by reduced demand from commercial
transport because of the economic recession. In the US, where refining is
more highly upgraded and the transport market is more gasoline oriented,
margins deteriorated less. Refining margins in Asia Pacific were the
hardest hit due to substantial additions to refining capacity in the region.

During 2009, upgrading margins were particularly poor due to

stronger relative fuel oil prices and narrow light-heavy crude spreads. This
adversely impacted our highly upgraded refineries and had an adverse
impact on our financial performance in 2009 compared with 2008.

The end of 2008 and the first quarter of 2009 saw unprecedented

levels of market volatility, driven by turmoil in the financial sector and
disruptions in the supply chain resulting from the economic downturn.
This high level of volatility, combined with our proprietary asset base and
trading skills, enabled us to deliver a particularly strong supply and trading
result in the first quarter of 2009. Subsequent to the first quarter,
volatility returned to more normal levels.

In our IBs, we saw a decline in demand for lubricants due to the
financial crisis. During the year we saw a partial recovery in the demand
for our petrochemicals products.

Our strategy
Our purpose is to be the product- and service-led arm of BP, focused on
fuels, lubricants, petrochemicals products and related services. We aim
to be excellent in the markets we choose to be in – those that allow BP
to serve the major energy markets of the world. We are in pursuit of
competitive returns and enduring growth, as we serve customers and
promote BP and our brands through quality products.

We believe that key to our continued success in Refining and

Marketing is holding a portfolio of quality, integrated, efficient positions
and accessing available market growth in emerging markets. We intend
to do this through holding positions in advantaged integrated FVCs where
we will invest to strengthen our established positions. We also intend to
retain and grow our IBs.

In 2007, we identified that the segment’s financial performance

lagged that of our competitors, based on our analysis of our position
compared with our supermajor peers, and we launched a programme to
restore our financial performance. Our objective was to restore our
performance over a period of three to four years by focusing on achieving
safe, reliable and compliant operations, restoring missing revenues and
delivering sustainable competitive returns and cash flows.

We believe our overall performance has now returned to being

competitive with our supermajor peers, but that there is significant
potential for further performance improvements. In the future, we intend
to build on this by focusing on further improvements in operations, asset
quality and overall efficiency, in order to be a leading player in each of the
markets in which we choose to participate.

Our performance
Our 2009 performance has benefited from the fundamental
improvements we have been 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 replacement cost profit
before interest and tax was $0.7 billion for 2009, compared with
$4.2 billion in 2008. The result was heavily impacted by non-operating
items, which included a significant level of restructuring charges and a
$1.6 billion one-off charge to write off all the segment’s goodwill in the
US West Coast FVC relating to our 2000 ARCO acquisition. This resulted
from our annual review of goodwill as required under IFRS and reflects
the prevailing weak refining environment that, together with a review of
future margin expectations in the FVC, has led to a reduction in the
expected future cash flows. The decrease in profit was also driven by the
very significantly weaker environment, where refining margins fell by
almost 40%. This was partly offset by significantly stronger operational
performance in the fuels value chains, with 93.6% Solomon refining
availability, lower costs and improved performance in the international
businesses. Our financial results are discussed in more detail on
pages 56-57.

Safety, both process and personal, remains our top priority. During

2009, we continued the migration to the BP operating management
system (OMS) with a continuing focus on process safety. The OMS is
described in further detail in Safety (see page 46). At the end of 2009, all
our operated refineries and petrochemicals plants were using the OMS.
Within our US refineries, we continued to implement the
recommendations of the BP US Refineries Independent Safety Review
Panel and regulatory bodies (further information can be found in Safety
on page 46 and in Legal proceedings on page 99). The focus on
operational integrity continues to yield positive results across the
segment. Since 2005, when we started identifying incidents by type, we
have reduced the overall number of major incidents by 90%. None of the
major incidents reported in 2009 was integrity-management related. We
have also reduced the number of reported oil spills and the recordable
injury frequency in our workforce to the lowest level for 10 years. In
2009, there were no reported workforce fatalities associated with our
refining and marketing operations.

BP Annual Report and Accounts 2009
Business review

In 2009, despite the impact on our overall results of the weak refining
environment, our focus on operations delivered significant performance
improvements, both financial and operational. Solomon availability for the
year was around five percentage points higher than in 2008. Average
throughputs were up by over 130,000b/d compared with 2008, an
increase of more than 6%. In addition, 2009 has seen further
improvements at our Texas City refinery. Production has ramped up
steadily during the year and availability has increased each quarter. During
April 2009, the site’s Solomon availability exceeded 90% for the first time
in four years.

Our financial performance also benefited from lower non-
feedstock costs. In 2009, our total costs were over 15%a lower than in
2008. In addition we reduced our headcount, excluding retail store staff,
by over 2,600 (see Financial statements – Note 39 on page 174).

a Based on Refining and Marketing’s share of production and manufacturing expenses plus
distribution and administration expenses.

Key statistics

Sales and other operating revenuesa
Replacement cost profit before

interest and taxb

Total assets
Capital expenditure and acquisitions

Total refinery throughputs

Total chemicals productionc

Global indicator refining margind
Refining availabilitye

2009
213,050

2008
320,039

$ million

2007
250,221

743
82,224
4,114

2,287

12,391

4.00
93.6%

2,621
4,176
95,311
75,329
5,495
6,634
thousand barrels per day
2,127
2,155
thousand tonnes
14,028
$ per barrel
9.94
82.9%

6.50
88.8%

12,518

a Includes sales between businesses.
b Includes profit after interest and tax of equity-accounted entities.
c A minor amendment has been made to comparative periods.
d The global indicator refining margin (GIM) is the average of regional industry indicator margins
weighted 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 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.
e 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.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

Sales and other operating revenues are analysed in more detail below.

2009

2008

$ million

2007

Sale of crude oil through spot and

term contracts

35,625

54,901

43,004

Marketing, spot and term sales

of refined products

Other sales and operating revenues

166,088
11,337
213,050

248,561
16,577
320,039

194,979
12,238
250,221

Oil sales volumes

Refined products
US
Europe
Rest of World
Total marketing salesa
Trading/supply salesb
Total refined product sales
Crude oil
Total oil sales

2009
1,426
1,504
630
3,560
2,327
5,887
1,824
7,711

thousand barrels per day

2008
1,460
1,566
685
3,711
1,987
5,698
1,689
7,387

2007
1,533
1,633
640
3,806
1,818
5,624
1,885
7,509

Marketing 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).
Trading/supply sales are sales to large unbranded resellers and other oil companies.

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

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

2009
495
1,444
1,012
418
191
3,560

thousand barrels per day

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

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

Marketing volumes were 3,560mb/d, slightly lower than last year,
reflecting the impact of slowing global economies on demand for fuel
and the volume effects of our business simplification.

Outlook
For 2010, although demand has stabilized, the overall economic
environment is expected to continue to be very challenging with
continuing pressure on the demand for our products and on margins.

In response, our priorities in 2010 remain consistent with those
in 2009 and we intend to build on the momentum we have established
around improving financial performance and operations. We will continue
to focus on delivering safe, reliable and compliant operations, improving
the performance of our integrated FVCs, in particular in the US, and
driving further cost efficiencies across all our businesses. We intend
to maintain investment at 2009 levels, focused on key safety and
operational integrity priorities, maintaining our quality manufacturing
and marketing portfolio, strengthening our US Mid-West FVC business
through the Whiting refinery modernization project and continuing
to grow our advantaged petrochemicals business in China.

BP Annual Report and Accounts 2009
Business review

Fuels value chains
We have six regionally organized integrated FVCs, 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 marketing and sales to our
customers. The Texas City refinery is not part of an integrated FVC but is
operated as a standalone, predominantly merchant, refining business that
also supports our marketing operations on the east and Gulf coasts of
the US.

We also have a number of regionally focused fuels marketing
businesses that are not integrated into a refinery, covering the UK, France
and Turkey.

In 2009, the FVCs accounted for roughly three-quarters of the

operating capital employeda in Refining and Marketing and generated just
under half of the profit, after adjusting for non-operating items and fair
value accounting effects. Without these adjustments, the result for the
FVCs was a significant loss in 2009, with the most significant factor being
the impairment charge to write off all the segment’s goodwill in the
West Coast fuels value chain.

Significant events in the FVCs in 2009 were as follows:

(cid:129)

In February 2009, a new 20,000b/d coker was commissioned at our
Castellón refinery in Spain. This was the culmination of a four-year
project to convert the Castellón refinery to one capable of upgrading
all fuel oil to higher value products. This will allow the refinery to
produce about 50% more diesel than it did before, for sale to the
local Spanish market and will also improve the ability of the refinery
to process higher-margin heavy crude oils.

Refineries
BP’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 synergies with other parts of
the group’s business. Our refining focus is to maintain and improve our
competitive position through sustainable, safe, reliable, compliant 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.

(cid:129)

(cid:129) The Whiting refinery modernization project is more than one year into
construction. The engineering design is now almost complete and
many of the large foundations are in place. For further details on
permit issues relating to our planned upgrades see Environment
on page 49.
In July 2009, BP announced that it would not be progressing with the
project with Irving Oil to build a refinery at Eider Rock in Saint John,
New Brunswick, Canada as a result of global economic and industry
conditions.
In December 2009, BP completed the sale of our ground fuels
marketing business in Greece, to Hellenic Petroleum for $0.5 billion.
The sale included a BP brand licence agreement for at least
three years.
In November 2007, BP announced that it would sell all of its
company-owned and company-operated convenience sites in the US.
The sites will be supplied with BP or ARCO branded fuels under a
20-year contract and will continue to market BP-branded fuels in the
eastern US and ARCO-branded fuels in the western US. By the end
of 2009, we were no longer operating any of these sites and had
completed the sale of all but around 30.
In the fourth quarter of 2009, we announced that we would explore
options to divest a number of non-strategic pipelines and terminals in
the US Mid-West, Gulf Coast and West Coast during 2010 and 2011.
In February 2010, we announced that we had received an offer from
Delek Europe B.V. for the retail fuels and convenience business and
selected fuels terminals in France. As a result, BP has agreed a period
of exclusivity with Delek Europe B.V. to negotiate the terms for the
sale and to allow consultation with the relevant works councils. Any
transaction will be subject to regulatory approval. Any transaction is
expected to include a BP brand licence agreement.

(cid:129)

aOperating capital employed is total assets (excluding goodwill) less total liabilities, excluding finance
debt and current and deferred taxation.

BP Annual Report and Accounts 2009
Business review

The following table summarizes the BP group’s interests in refineries and average daily crude distillation capacities at 31 December 2009. In July
2009, BP disposed of its 17.1% interest in Kenya Petroleum Refineries Ltd to Essar Energy Overseas Ltd.

Refinery

Fuels value chain

Group interestb

thousand barrels per day
Crude distillation capacitiesa
BP
share

Total

Europe
Germany

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

New Zealand
South Africa
Total Rest of World
Total

Bayernoil
Gelsenkirchenc
Karlsruhe
Lingenc
Schwedt
Rotterdamc
Castellónc

Carsonc
Cherry Pointc
Whitingc
Toledoc
Texas Cityc

Bulwerc
Kwinanac
Whangerei
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

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%
50.0%

215
266
323
93
226
386
110
1,619

265
234
405
160
475
1,539

102
137
112
180
531
3,689

48
133
39
93
42
386
110
851

265
234
405
80
475
1,459

102
137
27
90
356
2,666

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

a Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
b BP share of equity, which is not necessarily the same as BP share of processing entitlements.
c Indicates refineries operated by BP.

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

US
Europe
Rest of World

2009
1,238
755
294
2,287

2,666
86%
85%
89%
83%

thousand barrels per day

2008
1,121
739
295
2,155

2,678
81%
77%
87%
80%

2007
1,064
758
305
2,127

2,769
77%
69%
88%
83%

a Refinery throughputs reflect crude oil and other feedstock volumes.
b Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
c Refinery utilization is annual throughput divided by crude distillation capacity, expressed as a percentage. The measure has been redefined in 2009 to be more consistent with industry standards.
Prior periods have been restated.

BP Annual Report and Accounts 2009
Business review

Refining throughputs in 2009 increased by 6% relative to 2008, driven
principally by improved operational performance in the US. Higher US
throughputs were largely attributable to the recovery at the Texas City
refinery, partially offset by the reduced equity interest in the Toledo
refinery stemming from the Husky joint venture.

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 the optimization of BP’s FVCs to
maintain a single interface with the oil trading markets and to operate
with a single set of trading compliance processes, systems and controls.
The business is organized along global commodity lines and with trading
offices in Europe, the US and Asia, the function is able to maintain a
presence in the regionally connected global markets. The supply and
trading function has supported the Refining and Marketing segment
through a period of higher volatility of crude and oil product prices and
increased credit risk following the global financial crisis.

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.

Along with 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 24 on
pages 144-149.

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 sales and other operating 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 or 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 sales and
other operating revenues, when title passes. Similarly, spot and term
purchases are included in purchases for accounting purposes.

Fuels marketing and logistics
Our fuels strategy focuses on optimizing the integrated value of each FVC
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.

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 transport and industrial
sectors.

Our retail network is largely concentrated in Europe and the US
but also has established operations in Australasia, 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
US
Europe
Rest of World
Total

Number of retail sites operated under a BP brand

2009
11,500
8,600
2,300
22,400

2008
11,700
8,600
2,300
22,600

2007
12,200
8,600
2,500
23,300

a The number of retail sites includes sites not operated by BP but instead operated by dealers,
jobbers, franchisees or brand licensees that operate under a BP brand. These may move to or from
the BP brand as their fuel supply or brand licence agreements expire and are renegotiated in the
normal course of business.
b Excludes our interest in equity-accounted entities which are dual-branded.

BP Annual Report and Accounts 2009
Business review

At 31 December 2009, BP’s worldwide network consisted of some
22,400 sites 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 2009, we sold over 600 company-owned sites to
dealers, jobbers and franchisees who continue to operate these sites
under the BP brand. In addition we sold around 1,200 sites in Greece
to Hellenic Petroleum, which will continue to be operated under the BP
brand through a brand licensing agreement. We also divested around
100 company-owned sites to third parties.

Our retail convenience operations offer consumers a range of

food, drink and other consumables and services on the fuel forecourt in a
convenient and innovative manner. The convenience offer includes brands
such as ampm, Wild Bean Café and Petit Bistro.

During 2009, we continued the implementation of our ampm

convenience retail franchise model in the US. We expect this model to
provide a reliable, long-term sales outlet for transport fuels from our
refinery systems, together with reduced costs and lower levels of capital
investment. Overall in the US, by the end of 2009 there were 11,500
branded retail sites of which 1,200 were branded ampm, compared with
11,700 and 1,100 respectively at the beginning of 2009.

In Europe, we are one of the largest forecourt convenience
retailers, with about 2,500 convenience retail sites 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 addition, at the end of 2009, we had approximately 500
sites outside Europe and the US in countries such as Australia, New
Zealand and South Africa.

International businesses
Our IBs provide quality products and offers to customers in more than 80
countries worldwide with a significant focus on Europe, North America
and Asia. Our products include aviation 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. 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 outperform its competitors.

In 2009, the IBs accounted for just under a quarter of the
segment’s operating capital employeda and just over half the profit, after
adjusting for non-operating items and fair value accounting effects.
Without these adjustments, the profit for the IBs more than offset the
loss for the FVCs.

Significant events in the international businesses in 2009 were:

(cid:129) Our expanded purified terephthalic acid (PTA) facility in Geel, Belgium
was successfully commissioned in the first quarter of 2009. The
expansion, which has a design capacity of 350 thousand tonnes per
annum (ktepa), has improved operating costs and by the end of 2009
had already increased the site’s PTA capacity by 255ktepa.

(cid:129) SECCO completed its first major turnaround in the third quarter of
2009 and at the same time expanded production capacity, creating
China’s largest ethylene cracker capable of producing 1.3mtpa of
ethylene per year, an increase of 25%.

a Operating capital employed is total assets (excluding goodwill) less total liabilities, excluding
finance debt and current and deferred taxation.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

(cid:129) Construction of the new 500ktepa acetic acid plant in Jiangsu
province, China by BP YPC Acetyls Company (Nanjing) Limited
(BYACO) was completed. This is a BP joint venture with Yangzi
Petrochemical Co. Ltd (a subsidiary of Sinopec). Commercial
production is expected to begin in the second quarter of 2010.

(cid:129) BP and Sinopec continued to progress the project 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 is under review due to current market conditions. When
complete, total production at the YARACO site is expected to be in
excess of one million tonnes per annum, making this one of the
largest acetic acid production locations in the world.

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 46 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,

and also 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. In 2009, more than 30% of pre-tax operating income
was generated from emerging markets.

BP marine lubricants is one of the largest global suppliers of

lubricants to the marine industry. We supply many types of vessels from
bulkers to container ships to dredgers and cruise ships, with global
presence in over 850 ports. 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.

Petrochemicals
Our petrochemicals operations comprise 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
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 polyethylene terephthalate (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 acid markets with a major manufacturing presence in Asia,
particularly China. PX is a feedstock for PTA production. In addition to
these three main products, we produce a number of other speciality
petrochemicals products. We have a total of 14 manufacturing sites
operating in the UK, the US, Belgium, China, Indonesia, Korea, Malaysia
and Taiwan, including our joint ventures.

In O&D, we crack naptha and ethane as feedstocks to produce
ethylene and other products and derivatives, within equity-accounted
entities.

BP Annual Report and Accounts 2009
Business review

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 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, butadiene 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. BP also owns one other naphtha cracker
site outside of Asia, which is integrated with our Gelsenkirchen
refinery in Germany.

The following table shows BP’s petrochemicals production
capacity at 31 December 2009. This production capacity is based on the
original design capacity of the plants plus expansions.

BP share of petrochemicals production capacitya b

Other businesses and corporate
Other businesses and corporate comprises 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.

The financial results of Other businesses and corporate are

discussed on page 57.

Key statistics

Sales and other operating revenuesa
Replacement cost profit (loss) before

interest and taxb

Total assets
Capital expenditure and acquisitions

2009
2,843

(2,322)
17,954
1,299

2008
4,634

(1,223)
19,079
1,839

$ million

2007
3,698

(1,209)
20,595
939

thousand tonnes per year

a Includes sales between businesses.
b Includes profit after interest and tax of equity-accounted entities.

Geographic area
US
Europe
Rest of World

PTA

Acetic
acid
PX
583
2,385 2,373
532
1,330
624
3,704
– 1,035
7,419 2,997 2,150

Total
O&D
Other
5,492
151
–
4,273
158 1,629
108 3,217
8,064
417 4,846 17,829

a Petrochemicals capacity is the maximum proven sustainable daily rate (msdr) multiplied by the
number of days in the respective period, where msdr is the highest average daily rate ever achieved
over a sustained period.
b Includes BP share of equity-accounted entities.

Global fuels
The supply of aviation fuels and LPG is run globally in the global fuels SPU.
Air BP is one of the world’s largest and best known aviation fuels

suppliers, serving many of the major commercial airlines as well as the
general aviation and military sectors. During 2009, which was another
tough year for the aviation industry, we continued to simplify our
geographical footprint by exiting non-core countries and we now supply
customers in 64 countries. This has allowed us to reduce working capital
and improve returns on operating capital employed.

We have annual marketing sales in excess of 25 billion litres. 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.

The LPG business sells bulk, bottled, automotive and wholesale
LPG products to a wide range of customers in 12 countries. During the
past few years, our LPG business has consolidated its position and
introduced new consumer offers in established markets, developed
opportunities in growth markets and pursued new demand such as the
German Autogas market. In 2009, we have divested non-core operations
and focused our asset base around sustainable marketing operations.
Annual sales are in excess of 2 million tonnes per annum.

Alternative Energy
Alternative Energy comprises BP’s low-carbon businesses and future
growth options outside oil and gas. Alternative Energy is focused on four
key businesses, which we believe have the potential to be a material
source of low-carbon energy and are aligned with BP’s core capabilities.
These are biofuels, wind, solar, and hydrogen power and carbon capture
and storage (CCS).

Our market
It is now well accepted that a more diverse mix of energy will be required
to meet future demand. The International Energy Association (IEA)a
estimates that world energy demand could be 40% higher than at
present by 2030, driven largely by China and India. The IEA also projects
that higher fossil-fuel prices, as well as increasing concerns over energy
security and climate change, could boost the share of wind and solar
electricity generation from 1% in 2007 to 6% in 2030, and the biofuels
share of transport fuels from 1% in 2007 to 4% in 2030b.

Our performance
Alternative Energy made good progress in 2009. Our wind business has
added 279MW of capacity including the construction of two wind farms
in the US – Fowler Ridge II in Indiana and Titan I in South Dakota – taking
the total capacity in commercial operation to 711MW (1,237MW gross)
at the end of 2009. In our solar business, we completed the restructuring
of our manufacturing facilities and increased unit sales 25% over 2008.
Our biofuels business is investing in advanced technologies. We have our
first joint-venture ethanol refinery in Brazil and another joint-venture
facility is under construction in the UK.

Since 2005, we have invested more than $4 billionc in Alternative

Energy, in line with our commitment to invest $8 billion by 2015.

a Adapted from World Energy Outlook 2009. ©OECD/IEA 2009, page 73.
bWorld Energy Outlook 2009. ©OECD/IEA 2009, pages 622-623: ‘Reference Scenario, World’.
c The majority of costs have been capitalized, some were expensed under IFRS.

Wind – net rated capacity at year-end

(megawatts)a

Solar – module sales (megawatts)b

2009

711
203

2008

432
162

2007

172
115

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 1,237MW in 2009, 785MW in 2008 and 373MW in 2007. This includes
32MW of capacity in the Netherlands that is managed by our Refining and Marketing segment.
b Solar sales are the total sales of solar modules to third-party customers, expressed in MW.
Previously we reported the theoretical cell production capacity of our in-house solar manufacturing
facilities. Reporting sales volumes operating data brings us into line with the broader solar industry.

BP Annual Report and Accounts 2009
Business review

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. 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. BP continues to invest throughout
the entire biofuels value chain from sustainable feedstocks that minimize
pressure on food supplies through to the development of the advantaged
fuel molecule biobutanol. BP has production facilities operating, or in the
planning and construction phases, in the US, Brazil and the UK.

In 2009, we announced a $45-million investment in a joint

venture with Verenium which plans to construct a facility to produce
lignocellulosic bioethanol in Florida, US. This investment builds on the
$90-million investment made by BP in 2008 to further develop existing
Verenium technical work and develop a demonstration plant at
commercial scale. In August, BP also announced a $10-million multi-year
agreement with Martek Biosciences Corporation to establish proof of
concept for large-scale microbial biodiesel production through the
fermentation of sugars.

The blending and distribution of biofuels continues to be carried

out by our Refining and Marketing segment, in line with regulation. BP is
one of the largest blenders and marketers of biofuels in the world.

Wind
In wind power, BP has focused its portfolio in the US, where we believe
the most attractive opportunities exist and where we have developed
one of the leading wind portfolios.

During 2009, we announced the completion of phase I of the

100MW Flat Ridge Wind Farm in Barber County, Kansas. BP and Westar
Energy, Inc. each own 50% of phase 1 of the wind farm. BP sells its
share of the output to Westar. In addition, commercial operations
commenced at the Fowler Ridge Wind Farm in Benton County, Indiana,
the largest wind farm in the US Midwest at 600MW, where BP and
Dominion are equal partners in 300MW. BP and Sempra Generation are
equal partners in 200MW, and 100MW is wholly-owned by BP. Full
commercial operation also began at our wholly-owned 25MW Titan I
Wind Farm in South Dakota.

As a result, BP has increased its net wind generation capacity to

711MW during 2009, an increase of 65% over the prior year. This net
increase in capacity includes the disposal of 78MW of our wind interests
in India as part of our focus on US wind.

Solar
2009 was quite challenging in the solar market due to weak demand in
the first half year and a significant decrease in module sales prices of
about 40%. However, BP Solar was successful in increasing unit sales
by 41MW to 203MW, an increase of 25% over 2008.

BP Solar’s organization, with over 1,700 employees worldwide,

is headquartered in San Francisco, California, in the US. BP Solar is
structured to serve the residential, commercial, and utility markets with
sales and marketing offices in major markets around the world. Our
manufacturing facilities are located in Frederick, Maryland, US; and joint
venture manufacturing is located in Xi’an, China and Bangalore, Indiaa.

During 2009, BP Solar continued to restructure manufacturing to

reduce costs and, as part of this programme, module assembly was
phased out in Maryland and our cell manufacture and module assembly
facilities in Madrid, Spain, were closed. Wafer and cell manufacturing
facilities in Maryland and joint venture manufacturing sites in China and
India continue to supply BP Solar.

a Our Indian manufacturing operations are accounted for as a consolidated subsidiary.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

Hydrogen power and CCS
BP has played a leading role in the CCS industry for more than 10 years,
and today focuses on both full-scale projects and a continuing
programme of research and technology development. The Hydrogen
Energy International Limited joint venture, which was formed to develop
hydrogen power projects in 2007, is now wholly owned by BP following
an agreement with Rio Tinto to sell its 50% share.

The two companies are continuing to develop the Hydrogen

Energy California 250MW power project with CCS through the
Hydrogen Energy International LLC joint venture, which secured
$308 million of Department of Energy (DoE) funding during 2009.
The funding award was made to California as part of the American
Recovery Reinvestment Act of 2009 and is part of the third round of
the DoE’s Clean Coal Power Initiative.

Separately, the 400MW Hydrogen Power Abu Dhabi project with
CCS reached an important milestone, with the Abu Dhabi environmental
regulator’s approval of the environment and social impact assessment.
The project is a joint venture between BP (40%) and Masdar (60%).

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. The
primary purpose of our shipping and chartering activities is the
transportation of our hydrocarbon products. In addition, we may use
surplus capacity to transport third-party products.

International fleet
The size of our managed international fleet has not changed since 2008.
At the end of 2009, we had 54 international 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, we retain a fleet of four double-hulled vessels. Outside the
US, we had 14 specialist vessels (two double-hulled lubricants oil barges
and 12 offshore support vessels).

Time-charter vessels
BP has 104 hydrocarbon-carrying vessels above 600 deadweight tonnes
on time-charter, of which 102 are double-hulled. 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.

BP Annual Report and Accounts 2009
Business review

Maritime security issues
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 these areas,
subject to the adoption of heightened security measures.

2009 has seen continuing pirate activity in the Gulf of Aden,
extending into the Indian Ocean (from the east coast of Somalia to
beyond the Seychelles) and a significant increase in the number of
international shipping incidents. The number of vessels actually
hijacked has remained roughly the same as 2008, as a result of
heightened awareness to the threat, and protective measures adopted by
transiting ships.

At present, we follow available military and government agency
advice and are participating in protective group transits through the Gulf
of Aden Maritime Security Patrol Area transit corridor. BP supports the
protective measures recommended in the international shipping industry
guide Best Management Practices to Deter Piracy in the Gulf of Adena.

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.

Treasury
Treasury manages the financing of the group centrally, ensuring liquidity
sufficient to meet group requirements and manages key financial risks
including interest rate, foreign exchange, pension and financial institution
credit risk. From locations in the UK, the US and the Asia Pacific region,
Treasury provides the interface between BP and the international
financial markets and supports the financing of BP’s projects around the
world. Treasury trades foreign exchange and interest rate products in the
financial markets, hedging group exposures and generating incremental
value through optimizing and managing flows. Trading activities are
underpinned by the compliance, control, and risk management
infrastructure common to all BP trading activities.

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.

a Jointly published and supported by Industry bodies, including OCIMF.

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. BP’s model is one of selective technology leadership,
where we have chosen 20 major technology programmes – 10 in
Exploration and Production, seven in Refining and Marketing and three
focused on lower-carbon value chains.

Inside the business segments, the full breadth of these activities

is carried out in service of competitive business performance and new
business development, through research and development (R&D) or
acquisition of new technologies. The central R&T group provides
leadership and assurance for scientific and technological activities across
BP with a focus on having the right capability in critical areas, overseeing
the quality of BP’s major technology programmes, and illuminating the
potential of emerging science. External assurance is achieved through
the Technology Advisory Council, which advises the board and executive
management on the state of research and technology within BP. The
Council comprises typically eight to 10 world-leading and eminent
industrialists and academics.

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 and the leverage of our spend.

Across the group, expenditure on R&D for 2009 was $587 million,

compared with $595 million in 2008 and $566 million in 2007. See
Financial statements – Note 11 on page 134. Despite the economic
downturn of 2009, R&D spending remained roughly flat. In addition we
increased our focus on value realization from the application of
technology (including field trials), and capability development, which are
not included in the headline R&D expenditure.

In our Exploration and Production segment, we selectively focus

on 10 ‘flagship’ technology programmes which have the greatest
business impact. We consider that each has the potential to add more
than one billion boe to reserves through their development and
deployment in our assets worldwide. These technologies continue to
contribute to exploration and production success in Alaska, Angola,
Azerbaijan, Egypt, North Africa, the North Sea, Trinidad and the
deepwater Gulf of Mexico. 2009 highlights from four of these flagships
include:
(cid:129) Advanced seismic imaging – BP’s expertise leads the industry, with
cutting-edge ‘simultaneous sweeping’ techniques being successfully
applied in onshore seismic surveys in Libya and Oman. Offshore, BP
completed its largest ever 3D surveys in Libya’s deepwater, carried
out the most northerly 3D seismic programme ever conducted (in the
Canadian Beaufort Sea), and deployed a wide azimuth towed
streamer in Angola – an acquisition configuration developed by
BP to image areas of complex geology below salt. These imaging
techniques significantly reduce time and costs needed to acquire
seismic data over vast areas.

(cid:129) Enhanced oil recovery (EOR) technologies are pushing recovery

factors to new limits. By increasing the overall recovery factor from
our fields by 1%, we believe we can add 2 billion boe to our reserves.
At the Endicott field in Alaska, BP completed a field trial of its LoSalTM
EOR technology, which uses injection water with a much lower than
usual salt content to flush out or displace extra oil from the reservoir.
Following the success of this trial, the technology is now being
actively considered for application in several new projects. BP has
now performed 38 Bright Water™ treatments in Alaska, Argentina
and Pakistan, which have delivered an increase of more than 9 million
barrels to our recoverable volumes at a development cost of less than
$6 per barrel.

BP Annual Report and Accounts 2009
Business review

(cid:129) Field-of-the-FutureTM (FotF) exploits digital technologies to improve

performance and optimize production. For example, ISIS, a
proprietary system designed by BP engineers, gathers subsurface
information from wells in real time using field sensors that measure
parameters such as pressures and temperatures. ISIS has now
been deployed as a virtual flow meter and has improved production
rates at Thunder Horse and other fields. BP has deployed FotF to 35
operations using a common platform, leading the industry in this
area.
Inherently reliable facilities – BP conducted a high reliability
chemical injection skid field trial at Wytch Farm in the UK, as part of
this flagship’s objectives of improving corrosion inhibition, extending
the life of BP’s assets and ensuring safe, reliable and efficient
operations.

(cid:129)

In our Refining and Marketing segment, technology is delivering
performance improvements across all businesses. For example:
(cid:129) Refining technology advances are enabling better understanding and
processing of feedstocks of varying quality and optimization of our
assets in real time, enhancing the flexibility and reliability of our
refineries and improving margins. The reconfiguration at Whiting
refinery to process heavier crudes is on track, incorporating
technologically advanced coking operations. BP’s Refinery-of-the-
Future programme develops and deploys state-of-the-art
measurement, monitoring and predictive technologies to improve
refinery safety, integrity, availability and utilization, and to optimize
feedstock selection and blending. For example, BP has completed
large-scale field trials of wireless, online, sensors for remote
corrosion monitoring, and deployment across our refineries is now
under way.

(cid:129) 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. In 2009, BP completed the launch of
Castrol EDGE Sport, a range of highly advanced synthetic engine oils
that outperform conventional, high mileage, part synthetic and
benchmark synthetic motor oils. BP’s strong relationship with Ford
has contributed to important technological advances in fuel and
lubricants products, including a joint UK Government-backed project
to improve fuel efficiency, which has achieved reductions in friction
and a significant overall reduction in fuel usage for next generation
engines.

(cid:129) 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 in purified terephthalic acid (PTA) and acetic acid. Learning
from successful project implementations in Asia, continuous
improvement of our CATIVA® technology for manufacture of acetic
acid maintains BP’s world-class capital and conversion cost position.
In the field of conversion technology, our Fischer-Tropsch
demonstration plant programme in Nikiski, Alaska, has been
completed, proving the performance of BP’s fixed-bed process. This
technology is now ready for commercial deployment and available for
third-party licensing. The process is particularly well suited for the
chemical conversion of biomass-derived feedstocks to liquids.

(cid:129)

BP’s Alternative Energy portfolio covers a wide range of renewable and
low-carbon energy technologies.
(cid:129)

In 2009, our biofuels business extended its reach and capability
through joint ventures with Dupont (to develop, produce and market
next-generation biofuels from biobutanol), Verenium (two 50:50 JVs
accelerating the development and commercialization of biofuels from
lignocellulosic feedstocks), and Martek Biosciences (developing
technology to convert sugars into diesel).

(cid:129)

In our solar business, BP has joined forces with Interuniversity
Microelectronics Centre (IMEC) and other partners to demonstrate
high-efficiency, low-cost silicon Mono2TM solar cells. This new
technology is producing cells ranging up to 18% efficiency, compared
with multicrystalline cells that are typically around 15%-15.8%
efficiency. Mono2 cells are fabricated using BP Solar’s proprietary
casting technique to produce monocrystalline wafers. BP Solar has
also developed and is in the process of commercializing a full
portfolio of module technology. This uses advanced heat
management and internal microcircuits to optimize energy
production, safety, and ease of operation and maintenance.
(cid:129) Our carbon capture and storage projects in Abu Dhabi and

California are making progress, with environmental regulator approval
for the former and Department of Energy funding for the latter.

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:
(cid:129) 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 2009, we
established an EOR exploratory research programme with three
European universities to improve our understanding, foster innovation
and provide a ‘springboard’ for new technologies.

(cid:129) At our Energy Biosciences Institute at Berkeley, we have located
BP researchers at the institute to collaborate with the academic
researchers. Several foundational research platforms have been
established (including second-generation biofuel technologies and
microbially-enhanced oil and gas recovery) and the first patents and
inventions have started to emerge.

(cid:129) BP is an industry member of the UK’s Energy Technologies

(cid:129)

Institute (ETI) – a public/private partnership to accelerate low-carbon
technology development. In 2009, the ETI commissioned over
£50 million ($80 million) of work covering 10 projects across a wide
range of technologies. The ETI has also developed a model of the UK
energy system which projects out to 2050.
In 2009, BP launched the Energy Sustainability Challenge, a three-
year study into how changes in availability of and demand for natural
resources and ecosystem services will affect future energy supply
and demand, the technologies that could enable more efficient use
of natural resources, and the policies that will be necessary to bring
these into effect.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Corporate responsibility
Safety
Safety, people and performance are BP’s top priorities. We constantly
seek to improve our safety performance through the procedures,
processes and training programmes that we implement in pursuit of
our goal of ‘no accidents, no harm to people and no damage to the
environment’.

In 2009, a third-party-operated helicopter carrying contractors

from BP’s Miller platform crashed in the North Sea resulting in the tragic
loss of 16 lives. In addition, BP sustained two fatalities within our own
operations, one, when a rig worker was lost overboard during drilling
operations in Azerbaijan and a second, in a crush injury on a well pad
in Alaska.

We deeply regret the loss of these lives.

Safety and operational performance
In 2009, BP’s safety record continued to improve, as indicated by
measures of personal safety including reported recordable injury
frequency (RIF) and days away from work case frequency (DAFWC).
Our overall RIF of 0.34 was significantly lower than the rate of

0.43 in 2008 and 0.48 in 2007. Our DAFWCF was 0.069, an improvement
on the level of 0.080 in 2008.

In 2009, eight work-related major incidents were reported,
compared with 21 in 2008. Major incidents include incidents resulting in
fatalities, significant property damage or significant environmental
impacts. All fatalities and other major incidents and many that have the
potential to become major incidents, are discussed by the group
operations risk committee (GORC), chaired by the group chief executive.
Our mandatory internal requirement to undertake incident investigations
seeks to ensure that we learn as much as possible from each incident
and take action to prevent re-occurrence.

There were 234 oil spills of one barrel or more reported in 2009, a
significant reduction on the 335 spills that occurred in 2008. The reported
volume of oil spilled in 2009 was approximately 1,191 million litres, a
reduction of 65% compared with 2008.

This performance follows several years of intense focus on

training and procedures across BP. BP’s operating management
system (OMS), which provides a single operating framework for all BP
operations, is a key part of continuing to drive a rigorous approach
to safe operations. 2009 marked an important year in the continuing
implementation of OMS.

Safe, reliable and responsible operations
Having been introduced at eight operating sites in 2008, implementation
of the OMS gathered pace in 2009. The system was up and running at
70 operations across the business by the end of the year, including all our
operated refineries and petrochemicals plants. This represents around
80% of the operations for which OMS implementation is planned, with
the remainder scheduled to be live by the end of 2010.

Taking a systematic approach is integral to improving safety and
operating performance in every BP site. Our OMS covers all areas from
process safety, to personal health, to environmental performance. By
applying consistent principles and processes across the BP group’s
operations, the system provides for an integrated and consistent way of
working. These principles and processes are designed to simplify the
organization, improve productivity, enable consistent execution and focus
BP on performance.

Capability development
Having built a safety and operations learning framework to enhance the
capability of our staff to deliver safe, reliable, responsible and efficient
operations, we defined target populations for these programmes more
accurately in 2009.

More than 2,700 front-line operational leaders across our global

operations have started one or more of the modules within the Operating
Essentials programme which seeks to embed the BP way of operating
as defined by OMS. Our Operations Academy (OA), a partnership with
the Massachusetts Institute of Technology (MIT), is also now well
established. Seven cadres of senior operations staff have already
attended this academy and three of these have graduated: all are
applying their learning and having a deep influence in the operations
community. We also have an Executive Operations Programme which
has continued to support the executive team and senior business leaders
in the development of their unique operations capability requirements.

Process safety management
We continued to implement the 2007 recommendations made by the BP
US Refineries Independent Safety Review Panel (Panel), which following
the incident at Texas City in 2005, reviewed process safety management
at our US refineries and our safety management culture.

In accordance with those recommendations, we appointed an

Independent Expert for a five-year term to monitor their implementation.
We again co-operated closely with the Independent Expert in 2009,
providing him access to our sites, personnel and documentation and
routinely supplying him with progress reports. In the Independent
Expert’s second annual report, published in 2009, he acknowledged BP’s
sustained focus on its safety and operations agenda and the priority
given by executive management and the board to safe, reliable and
responsible operations. The report identified areas for continued focus
and highlighted the progress made in several areas, including the
development of capability programmes, OMS implementation, safety and
operations auditing, and the improvement of metrics to monitor process
safety performance. During the course of 2009, we also provided regular
progress updates to the Safety, Ethics and Environment Assurance
Committee of the board.

See Legal proceedings on pages 99-100 in respect of ongoing

Texas City refinery matters.

By the end of 2009 our safety and operations audit team had

audited a total of 94 BP businesses, including all major operating sites,
within a three-year period. The audits, which in 2009 included pilot audits
for analysis against the requirements of the OMS, have provided a
rigorous process for assessing our businesses against BP’s relevant
standards and requirements.

We also participated in industry-wide forums on process safety.
We chaired the API/ANSI multi-stakeholder group developing a standard
for public reporting of leading and lagging process safety indicators.
Through this and other bodies, we shared our learning with other
organizations within and outside the oil and gas industry.

‘Six-point plan’
Our efforts on process safety included taking action to close out our
six-point plan for process safety, which was launched in 2006 to address
immediate priorities for improving process safety and minimizing risk at
our operations worldwide. We have either completed the required actions
or integrated the few continuing requirements within the OMS, for
tracking to completion. We established a clear approach for future
monitoring of these within the internal HSE & Operations Integrity
Report. This report, which is the key source of management information
relating to safety and operations in BP, is prepared quarterly for the
GORC.

BP Annual Report and Accounts 2009
Business review

Environment

Climate change
BP recognizes that climate change is a global concern representing a
significant challenge for society, the energy industry, and BP.

We monitor and report on greenhouse gas (GHG) emissionsa, and

we manage our GHG emissions through a focus on operational energy
efficiency. Each year since 2002, we have estimated the reduction in our
reported annual emissions due to efficiency projects and the running
total of these estimated reductions is now 7.9 million tonnes (Mte),
including 0.3Mte estimated for the last year.

However, last year’s sustainable reductions have been more

than offset by additional emissions from increased operational activity.
As such, we are reporting 65.0Mte of GHG emissions for the year 2009,
3.6Mte higher than the 61.4Mte reported for 2008. Increased throughput
from US refineries, the start-up of our Tangguh LNG project in Indonesia
and deepwater production platforms in the Gulf of Mexico account for
much of this increase.

We expect that additional regulation of GHG emissions in the
future and international accords aimed at addressing climate change
will have an increasing impact on our businesses, operating costs and
strategic planning, but may also offer opportunities in the development of
low-carbon technologies and businesses. See Regulation – Greenhouse
gas regulation on page 48.

To address this expectation, we factor a carbon cost into our

investment appraisals and the engineering design of new projects. We
do this by requiring projects to make realistic assumptions about the likely
carbon price during the lifetime of the project. This is used as a basis for
assessing the economic value of the investment, and for assessing
options to optimize the way the project is engineered. This is our way of
evaluating investments to ensure they are competitive not only in today’s
world but in a future where carbon has a more robust price.

Environmental management
During 2009, we began integrating our environmental management
systems into our operating management system (OMS) and piloted an
integrated approach to identify potential environmental and social
impacts in new projects. These are intended to improve our consistency
and effectiveness in identifying and mitigating the environmental and
social impacts of our operations. Our major operating sites are all
certified under the international environmental management system
standard ISO 14001, with the exception of the Texas City petrochemicals
plant which is seeking certification in 2010.

None of our new projects entered a protected area in 2009.

Our protected areas classification includes the International Union for
the Conservation of Nature (IUCN) I-IV, Ramsar and World Heritage
designations.

We continue to strengthen our processes for managing
compliance with environmental regulations in each of the countries in
which we operate. In addition, each employee is required to comply with
the health, safety and environmental requirements of the BP code of
conduct. We expect our partners, suppliers and contractors to comply
with legal requirements and operate consistently with the principles of
our code of conduct.

Information on the environmental impact of our operations and

our efforts to manage resources responsibly are discussed in our annual
BP Sustainability Report which is available on our website at
www.bp.com/sustainability.

a We report greenhouse gas (GHG) emissions, and emission reductions, on a CO2-equivalent basis
including CO2 and methane. This represents all consolidated entities and BP’s share of equity-
accounted entities except TNK-BP.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

Technology development
BP invests in, or jointly funds, research and development seeking
opportunities to reduce our potential environmental impacts, for example,
sound and marine life research, a range of water management projects
and advanced drill cuttings treatment. BP also participates in public and
private partnerships to develop new technologies. These include:
(cid:129)

the Energy Biosciences Institute (EBI) in the US, which conducts
research into biofuel technologies, improved oil and gas recovery and
carbon sequestration;
the Energy Technologies Institute (ETI) in the UK, which seeks to
accelerate the development of energy technologies to reduce GHG
emissions including offshore wind and for marine, tidal and wave
energy; and
the Carbon Mitigation Initiative at Princeton University, to research
the fundamental environmental, and technological issues in carbon
management.

(cid:129)

Regulation
BP operates in more than 80 countries and is subject to a wide variety
of 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 may have a significant effect on the production, sale
and profitability of many of our products.

There also are environmental laws that require us to remediate

and restore areas damaged by the accidental or unauthorized release of
hazardous materials or petroleum associated with our operations. These
laws may apply to sites that BP currently owns or operates, sites that it
previously owned or operated, or sites used for the disposal of its and
other parties’ waste. Provisions for environmental restoration and
remediation are made when a clean-up is probable and the amount
of BP’s legal obligation can be reliably estimated. The cost of future
environmental remediation obligations is often inherently difficult to
estimate. Uncertainties can include the extent of contamination, the
appropriate corrective actions, technological feasibility and BP’s share of
liability. See Financial statements – Note 34 on page 160 for the amounts
provided in respect of environmental remediation and decommissioning.

A number of pending or anticipated governmental proceedings

against BP and certain subsidiaries under environmental laws could result
in monetary sanctions of $100,000 or more. We are also subject to
environmental claims for personal injury and property damage alleging
the release or exposure to hazardous substances. The costs associated
with such future environmental remediation obligations, governmental
proceedings and claims could be significant and may be material to the
results of operations in the period in which they are recognized, but it is
not expected that such costs will be material to the group’s overall
results of operations, our financial position or liquidity. However, we
cannot accurately predict the effects of future developments on the
group, such as stricter environmental laws or enforcement policies or
future events at our facilities, and there can be no assurance that material
liabilities and costs will not be incurred in the future. For a discussion of
the group’s environmental expenditure see page 60.

BP Annual Report and Accounts 2009
Business review

Greenhouse gas regulation
Increasing concerns about climate change have led to a number of
international, national and regional measures to limit greenhouse gas
emissions; additional stricter measures can be expected in the future.
Current measures and developments affecting our businesses include
the following:
(cid:129) The Kyoto Protocol currently commits 38 ratified parties to meet
emissions targets in the commitment period 2008 to 2012.

(cid:129) The UN summit in Copenhagen in December 2009 where Parties to
the UN Framework Convention on Climate Change (UNFCCC) took
note of the Copenhagen Accord. The Accord recognizes the scientific
view that the increase in global temperature should be below 2°C.
Signatories to the Accord are to append to it their emissions targets
for 2020 or their proposed GHG mitigation measures. By the end of
January 2010 the UNFCCC had received submissions of national
pledges to cut and limit greenhouse gases by 2020 from 55
countries. According to the UNFCCC, these countries together
account for 78% of global emissions from energy use.

(cid:129) The European Union (EU) Climate Action and Renewable Energy
Package which requires increased greenhouse gas reductions,
improvements in energy efficiency and increased renewable energy
use by 2020 as well as including the Revision of the EU Emissions
Trading Scheme (EU ETS) directive. This regulates approximately
one-fifth of our reported 2009 global CO2 emissions and can be
expected to require additional expenditure from 2013 when the
revision of the scheme (EU ETS Phase 3) comes into effect.

(cid:129) Australia has committed to reduce its GHG emissions by between
5-25% below 2000 levels by 2020, depending on the extent of
international action. Australia has also developed an emissions trading
scheme. If passed in law, it will cover around 70% of the nation’s
GHG emissions including stationary energy and transport emissions.

(cid:129) New Zealand has agreed to cut GHG emissions by 10-20% from

(cid:129)

1990 levels by 2020, subject to certain conditions. New Zealand is
extending the scope of its Emission Trading Scheme in July 2010.
In the US, recent national legislation has imposed stricter automobile
fuel emissions standards and biofuel mandates and legislative
proposals would impose GHG emission limits through cap-and-trade
programmes as well as mandates for alternative energy and
increases in energy efficiency.
(cid:129) The US Environmental Protection Agency (EPA) released a GHG
endangerment finding in late 2009 giving it authority to regulate
GHG emissions under the Clean Air Act; it has also issued a GHG
reporting rule covering major stationary emission sources and
upstream fuel suppliers.

(cid:129) A number of additional state and regional initiatives in the US will
affect our operations including regulation in California seeking to
reduce GHG emissions to 1990 levels by 2020, including
reductions in the carbon intensity of transport fuel sold in the
state.

(cid:129) Canada has adopted an action plan to reduce emissions to 20%
below 2006 levels by 2020 and the national government seeks a
coordinated approach with the US on environmental and energy
objectives, such as a North America-wide cap-and-trade system.

Each of these measures can increase our production costs for certain
products, increase demand for competing energy alternatives or products
with lower-carbon intensity and affect the sales of many of our products.

US and EU regulations
Approximately 60% of our fixed assets are located in the US and the EU.
US and EU environment and health and safety regulations significantly
affect BP’s exploration and production, refining, marketing, transportation
and shipping operations. Significant legislation in the US and the EU
affecting our businesses and profitability includes the following:

United States
(cid:129) The Clean Air Act (CAA) regulates air emissions, permitting, fuel

specifications and other aspects of our production, distribution and
marketing activities. Stricter limits on sulphur and benzene in fuels
will affect us going forward. Additionally, many states have separate
laws similar to the CAA.

(cid:129) The Energy Policy Act of 2005 and The Energy Independence and
Security Act of 2007 affect our US fuel markets by, among other
things, imposing renewable fuel mandate and imposing GHG
emission thresholds for certain renewable fuels. States such as
California also impose additional carbon fuel standards.

(cid:129) The Clean Water Act (CWA) regulates wastewater and other effluent
discharges from BP’s facilities, and BP is required to obtain discharge
permits, install control equipment and implement operational controls
and preventative measures.

(cid:129) The Resource Conservation and Recovery Act (RCRA) regulates the
generation, handling, and disposal of wastes associated with our
operations and can require corrective action at locations where such
wastes have released.

(cid:129) The Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA), can, in certain circumstances, impose the
entire cost of investigation and remediation on a party who owned or
operated a contaminated site or arranged for waste disposal at the
site. BP has incurred, or expects to incur, liability under CERCLA or
similar state laws, including costs attributed to insolvent or
unidentified parties. BP is also subject to claims for remediation costs
under other federal and state laws, and to claims for natural resource
damages (NRD) under CERCLA, the OPA 90 and other federal and
state laws.

(cid:129) The Toxic Substances Control Act regulates BP’s import, export and

sale of new chemical products.

(cid:129) The Occupational Safety and Health Act (OSHA), imposes workplace

safety and health requirements on our operations along with
significant process safety management obligations.

(cid:129) The Emergency Planning and Community Right-to-Know Act, requires
emergency planning and hazardous substance release notification as
well as public disclosure of our chemical usage and emissions.
(cid:129) The US Department of Transportation (DOT) regulates the transport

of BP’s petroleum products such as crude oil, gasoline and
petrochemicals.

(cid:129) The Marine Transportation Security Act and the DOT Hazardous
Materials (HAZMAT) and the Chemical Facility Anti-Terrorism
Standard (CFATS) regulations impose security compliance regulations
on BP and require security vulnerability assessments, security
mitigation plans and require security upgrades that increase our cost
of operations.

BP Annual Report and Accounts 2009
Business review

The US refineries of BP Products North America Inc (BP Products) are
subject to a consent decree with the EPA to resolve alleged violations of
the CAA and implementation of the decree’s requirements continues. A
2009 amendment to the decree resolves remaining alleged air violations
at the Texas City refinery through the payment of a $12 million civil fine, a
$6 million supplemental environmental project and enhanced CAA
compliance measures estimated to cost approximately $150 million. The
fine has been paid and BP Products is implementing the other provisions.
For further disclosures relating to Texas City refinery, please see Legal
proceedings on pages 99-100.

Various environmental groups and the EPA have challenged
certain aspects of the operating permit issued by the Indiana Department
of Environmental Management (IDEM) for our upgrades to the Whiting
refinery. In response to these challenges, IDEM has reviewed the
permits and responded formally to the EPA. The EPA either through
IDEM or directly can cause the permit to be modified, reissued or in
extremis terminated or revoked. BP is in discussions with the EPA and
IDEM over these issues and clean air act violations at the Whiting, Toledo,
Carson and Cherry Point refineries. Settlement negotiations continue in
an effort to resolve these matters.

European Union
BP’s operations in the EU are subject to a number of current and
proposed regulatory requirements that affect our operations and
profitability. These include:
(cid:129) The EU Climate Action and Renewable Energy Package and the
Emissions Trading Scheme (ETS) Directive (see Greenhouse gas
regulation above).

(cid:129) The EU European Integrated Pollution Prevention and Control (IPPC)

Directive imposes a unified environmental permit requirement on our
major European sites including refineries and chemical facilities and
requires assessments and some upgrades to our facilities. A
proposed Industrial Emission Directive would replace the IPPC
Directive. It would merge several existing industrial emission
directives, impose tighter emission standards for large combustion
plants and be more prescriptive as to the Best Available Techniques
(BAT) to be used to achieve emission limits. This may result in
requirements for further emission reductions at our EU sites.
(cid:129) The EC Thematic Strategy on Air Pollution and the related work on

revisions to the Gothenburg Protocol and National Emissions Ceiling
Directive (NECD). This will establish national ceilings for emissions of
a variety of air pollutants in order to achieve EU-wide health and
environmental improvement targets. The EC is also considering the
use of a NOX and SO2 trading scheme as a tool to achieve emission
reductions. This may result in requirements for further emission
reductions at our EU sites.

(cid:129) The EU Regulation on ozone depleting substances (ODS), which

implements the Montreal Protocol on ODS was most recently revised
in 2009 requires BP to reduce the use of ozone depleting substances
(ODS) and phase out certain ODS substances. BP continues to
replace ODS in refrigerants and/or equipment, in the EU and
elsewhere, in accordance with the Protocol and related legislation.
Methyl bromide (an ODS) is a minor byproduct in the production by
our petrochemicals operations of purified terephthalic acid and the
progressive phase out of methyl bromide uses may result in future
pressure to reduce our emissions of methyl bromide.

(cid:129) The EU Fuel Quality Directive affects our production and marketing of
fuels. Proposed changes to this directive would require BP to achieve
life cycle GHG emission reductions in fuels we sell and would also
facilitate the introduction of biofuels into gasoline and diesel.

(cid:129) The EU Registration, Evaluation and Authorization of Chemicals

(REACH) legislation requires that we register chemical substances we
manufacture or import into the EU with a complete set of hazard and
risk data. Existing manufactured and imported substances were all
preregistered by 1 December 2008 and qualified for a timed phase-in
for full registration during the period 2010-2018. Crude oil and natural
gas are exempt from registration requirements, while fuels are
exempt from authorization but not registration. REACH affects our
refining, petrochemicals and other manufacturing operations.
International marine fuel regulations under International Maritime
Organisation (IMO) and International Convention for the Prevention of
Pollution from Ships (Marpol) regimes impose stricter sulphur
emission restrictions on ships in EU ports and inland waterways and
the North and Baltic seas beginning in 2010 and with a stricter global
cap on marine sulphur emissions beginning in 2012. Further
reductions are to be phased in thereafter. These restrictions require
the use of compliant heavy fuel oil (HFO) or distillate, or the
installation of abatement technologies on ships. These regulations will
place additional costs on refineries producing marine fuel, including
costs to dispose of sulphur, as well as increased CO2 emissions and
energy costs for additional refining.
In the UK, significant health and safety legislation affecting BP
includes the Health and Safety at Work Act and regulations and the
Control of Major Accident Hazards Regulations.

(cid:129)

Maritime regulations
BP Shipping’s operations are subject to extensive national and
international regulations governing liability, operations, training,
spill prevention and insurance. These include:
(cid:129)

In US waters, the Oil Pollution Act of 1990 (OPA 90) imposes liability
and spill prevention and planning requirements governing, amongst
others, tankers, barges and offshore facilities and mandates a levy
on oil imported and produced domestically to fund oil spill response.
Some states, including Alaska, Washington, Oregon and California,
impose additional liability for oil spills.

(cid:129) Outside US territorial waters, BP Shipping tankers are subject to
international liability, spill response and preparedness regulations
under the UN’s International Maritime Organization, including the
International Convention on Civil Liability for Oil Pollution, the
International Convention for the Prevention of Pollution from Ships,
the International Convention on Oil Pollution, Preparedness,
Response and Co-operation and the International Convention
on Civil Liability for Bunker Oil Pollution Damage.

To meet its financial responsibility requirements, BP Shipping maintains
marine liability pollution insurance to a maximum limit of $1 billion for
each occurrence through mutual insurance associations (P&I Clubs) but
there can be no assurance that a spill will necessarily be adequately
covered by insurance or that liabilities will not exceed insurance
recoveries.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Employees
Number of employees at 31 December
2009
Exploration and Production
Refining and Marketinga
Other businesses and corporate

2008
Exploration and Production
Refining and Marketinga
Other businesses and corporate

2007
Exploration and Production
Refining and Marketinga
Other businesses and corporate

Non-US

Total

8,000
12,700
2,100
22,800

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

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

13,500
38,900
5,100
57,500

13,700
42,500
6,500
62,700

14,000
44,500
6,600
65,100

21,500
51,600
7,200
80,300

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

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

a Includes 13,900 (2008 21,200 and 2007 24,500) service station staff.

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.

We had approximately 80,300 employees at 31 December 2009,

compared with approximately 92,000 at 31 December 2008. This
reduction principally reflects the transfer of our convenience retail sites
to a franchise model and the progress we have made in making BP a
simpler, more efficient organization.

Our focus in 2009 has been on ensuring we have the right people
in the right roles including renewal of the group leader population. We are
seeking to promote continuous improvement by embedding the BP
leadership framework throughout the organization. This framework sets
out how BP leaders are expected to behave in delivering our strategy and
achieving sustained high performance. We are striving for deeper skills
development and continuing to align reward frameworks to promote
our desired behaviours and outcomes. Diversity and inclusion (D&I) is
an important part of all our people processes in BP and involves
acknowledging, valuing and leveraging our similarities and differences
for business success.

We have made significant progress in changing the culture of the
group to one with a stronger performance focus and which places more
value on deep specialist skills and expertise. Creating this culture has
required us to enhance our approach to performance management
at the business, team and individual level and to align performance and
reward outcomes.

We have completed the second cycle of our redesigned
performance management and reward process to ensure that there is a
direct link between performance and incentive reward. Throughout the
organization we have also achieved greater differentiation of
performance ratings and, as a result, in incentive compensation spend.
We believe this will continue to improve the performance focus of
businesses and individuals.

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 1,400 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 whose
skills are in high demand.

We aim 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.

We have revitalized our approach to D&I. In 2009, the focus

has been to re-establish D&I as a corporate priority. There is now
clear ownership by the business of D&I plans which are the direct
responsibility of the relevant SPU or function. Each SPU and function has
a D&I plan against which progress is measured. In addition the group
chief executive chairs the global D&I council. This council is supported by
a North American regional council and segment councils. We are creating
momentum which we expect will lead to sustainable progress on D&I.
The group people committee, formed in 2007, continues to take
overall responsibility for policy decisions relating to employees. In 2009,
this included senior level talent review and succession planning,
embedding of D&I 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 proportion is around
85%. 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.

At the end of 2009, 14% of our top 492 group leaders were

female and 21% 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 leaders’ awareness of D&I, and further training is planned
in 2010.

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 2009, we appointed 40 people
to positions in the group leadership population. Of these, 20 were
internal candidates.

BP Annual Report and Accounts 2009
Business review

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

The Leadership Framework is being embedded through access to
management development programmes and progress will be measured
by a new 360° feedback tool. The group-wide management development
programme, Managing Essentials – Effective Performance
Conversations, has now run in 41 countries. A further five programmes
have been developed in 2009 which address particular leadership
challenges faced by the group leader, senior level leader and first level
leader populations.

We provide development opportunities for all our employees,
including external and on-the-job training, international assignments,
mentoring, team development days, workshops, seminars and online
learning. We encourage all employees to take five training days per year.

Through our ShareMatch plan, run in around 65 countries, we

match BP shares purchased by employees.

Communications with employees include magazines, intranet

sites, DVDs, targeted emails and face-to-face communication. Team
meetings are the core of our employee engagement, 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.

In 2008, we received feedback through our employee engagement

surveys that, while there was still very high loyalty to BP as a company,
employee engagement was declining as we worked through the difficult
actions needed to turn around our performance. In response, we have
made it a priority to ensure that BP’s group leaders are better equipped
to tell our story and engage their staff in supporting our strategy.

The progress we have made in employee engagement is evident

from the results from our 2009 employee survey. The response rate for
the survey improved year on year with 57% of people completing the
survey, up from 42% in 2008. The Employee Satisfaction Index and our
Pulse survey scores for Performance culture and Safety and Compliance
culture all improved year on year.

We continue to make significant efforts to communicate the

intent and progress of our ongoing cost-efficiency programmes, to
minimize any potential negative perceptions within the business. We
have moved quickly to manage these people and performance changes
while keeping the focus on safety, continuous improvement and
sustainable change. These improvements are expected to continue in
2010, but we have already delivered material reductions in complexity,
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 2009 was 874, compared with 925 in 2008.

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 2009, 524 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. Specifically, BP made no donations to UK or other EU
political parties or organizations in 2009.

Social and community issues

Contributing to communities
We seek to make a positive difference wherever we operate. To do this,
we take action that is relevant to local circumstances, mutually beneficial
and designed to create enduring, as opposed to short-term, solutions.
Our investments in education and local enterprise development aim to
build local capability as part of our business agenda, either through our
local employees or through the provision of goods and services.

As a global energy company, BP operates in a diverse range
of countries and in a variety of environmental and social conditions.
A common feature of these operations is the lifespan of our projects
– some BP projects might last as long as 30-40 years. This longevity
requires that BP seeks to cultivate and maintain enduring relationships
with the communities and governments in these areas. To do this, BP is
committed to finding solutions that create mutual benefit: work with local
communities, agencies and organizations on finding solutions to issues
that can bring benefit to both the local operations as well as help to meet
community development needs over a project’s lifespan.

We always seek solutions that are aligned to the strategy of our

local businesses. For example, in education we support projects that
contribute to the wider sustainable development agenda of the particular
country but also develop skills and capabilities that are relevant to BP.
In doing this, we involve ourselves, as appropriate, in supporting the
enhancement of the availability, quality and relevance of education
offerings, particularly technical education. This can range from the
development of new geo-science and petro-technical offerings at
universities, to the support for English language-based technical
training, to the support for a broader understanding of the legal aspects
of oil and gas management for policy makers, to the basics of the oil
industry for journalists.

In some instances we get involved in supporting elements of

macro-economic planning to ensure that issues such as good revenue
management practices can enable wider national development. In doing
this we usually facilitate access to world class policy thinkers on a
range of issues through BP’s global relationships with leading
education institutions.

We also seek to support the development of the local supply

chain as a way of deepening the involvement of local enterprise in BP
business activities. The way we do this depends on local conditions
but can include training, business advisory services or financing
programmes that aim to help develop existing business products and
services, improve internal standards and practices, or create new
small enterprises.

We support various voluntary, multi-stakeholder initiatives aimed
at sharing best practice and improving industry-wide management of key
social and economic challenges. We are 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. We are also members of
the Voluntary Principles on Security and Human Rights through which we
have developed a robust internal process designed to ensure that the
security of our operations around the world is maintained in a manner
consistent with our group stance on human rights.

We make direct contributions to communities through community

programmes. Our total contribution in 2009 was $106.8 million, which
included $1.3 million to UK charities. The majority of our community
expenditure was directed towards education and technical
training projects.

BP Annual Report and Accounts 2009
Business review

In 2009, we spent $55 million promoting education, with investment
in three broad areas: tertiary and post secondary level support for
engineering; energy industry-related areas such as geo-science and
business leadership skills; and supporting the improvement of science
and technology teaching within basic education.

Relationships with suppliers
and contractors
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.

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 our 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 2006 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.

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 (PSAs). 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 ventures 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 PSAs). 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 Abu Dhabi, Angola, Egypt,
Norway, the UK, the US, Russia, South America and Trinidad & Tobago.
For a discussion of environmental and certain health and safety

regulations and environmental proceedings, see Environment on
pages 47-49. See also Legal proceedings on pages 99-100.

Organizational structure
The significant subsidiaries of the group at 31 December 2009 and the
group percentage of ordinary share capital (to the nearest whole number)
are set out in Financial statements – Note 43 on pages 177-178. See
Financial statements – Notes 22 and 23 on pages 142 and 143
respectively for information on significant jointly controlled entities
and associates of the group.

BP Annual Report and Accounts 2009
Business review

Financial performance
Group results
The following summarizes the group’s results.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

Sales and other operating revenues
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

For a discussion of the business environment in 2007-2009, see Group overview on page 12.

$ million except per share amounts

2009
239,272
16,759
16,578
88.49
56.00

2008
361,143
21,666
21,157
112.59
55.05

2007
284,365
21,169
20,845
108.76
42.30

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

Profit attributable to BP shareholders for the year ended

31 December 2007 was $20,845 million, including inventory holding
gains, net of tax, of $2,475 million and a net charge for non-operating
items, after tax, of $373 million. In addition, fair value accounting effects
had an unfavourable impact, net of tax, of $198 million relative to
management’s measure of performance. Further information on non-
operating items and fair value accounting effects can be found on
pages 58-59.

The primary additional factors reflected in profit for 2009,
compared with 2008, were lower realizations and refining margins and
higher depreciation, partly offset by higher production, stronger
operational performance and lower costs.

The primary additional factors reflected in profit for 2008,
compared with 2007, were higher realizations, a higher contribution from
the gas marketing and trading business, improved oil supply and trading
performance, improved marketing performance and strong cost
management; however, these positive effects were partly offset by
weaker refining margins, particularly in the US, higher production taxes,
higher depreciation, and adverse foreign exchange impacts.

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 80,300 at 31 December 2009,
92,000 at 31 December 2008 and 98,100 at 31 December 2007.

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.

Capital expenditure and acquisitions

Exploration and Production
Refining and Marketing
Other businesses and corporate
Capital expenditure
Acquisitions and asset exchanges

Disposals
Net investment

2009
14,696
4,114
1,191
20,001
308
20,309
(2,681)
17,628

2008
22,026
4,710
1,450
28,186
2,514
30,700
(929)
29,771

$ million

2007
13,904
4,356
934
19,194
1,447
20,641
(4,267)
16,374

Capital expenditure and acquisitions in 2009, 2008 and 2007 amounted
to $20,309 million, $30,700 million and $20,641 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 of
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 2009 was $20,001 million compared with $28,186 million in 2008 and
$19,194 million in 2007.

BP Annual Report and Accounts 2009
Business review

Finance costs and net finance expense relating to pensions and
other post-retirement benefits
Finance costs comprise interest payable less amounts capitalized, and
interest accretion on provisions and long-term other payables. Finance
costs in 2009 were $1,110 million compared with $1,547 million in 2008
and $1,393 million in 2007. The decrease in 2009, when compared with
2008, is largely attributable to the reduction in interest rates. The increase
in 2008, when compared with 2007, is largely the outcome of reductions
in capitalized interest as capital construction projects concluded.
Net finance expense relating to pensions and other post-
retirement benefits in 2009 was $192 million compared with net finance
income of $591 million and $652 million in 2008 and 2007 respectively.
The expected return on assets decreased significantly in 2009 as the
pension asset base reduced, consistent with falls in equity markets
during 2008.

Taxation
The charge for corporate taxes in 2009 was $8,365 million, compared
with $12,617 million in 2008 and $10,442 million in 2007. The effective
tax rate was 33% in 2009, 37% in 2008 and 33% in 2007. The group
earns income in many countries and, on average, pays taxes at rates
higher than the UK statutory rate of 28%. The decrease in the effective
tax rate in 2009 compared with 2008 primarily reflects a higher
proportion of income from associates and jointly controlled entities
where tax is included in the pre-tax operating result, foreign exchange
effects and changes to the geographical mix of the group’s income.
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.

Segment results
Profit before interest and taxation, which is before finance costs, net
finance income or expense, taxation and minority interests, was
$26,426 million in 2009, $35,239 million in 2008 and $32,352 million
in 2007.

Analysis of replacement cost profit before interest and tax and reconciliation to profit before taxationa

By business
Exploration and Production

US
Non-US

Refining and Marketing

US
Non-US

Other businesses and corporate

US
Non-US

Consolidation adjustment
Replacement cost profit before interest and taxb
Inventory holding gains (losses)
Exploration and Production
Refining and Marketing
Other businesses and corporate

Profit before interest and tax
Finance costs
Net finance expense (income) relating to

pensions and other post-retirement benefits

Profit before taxation
Replacement cost profit before interest and tax
By geographical area

US
Non-US

2009

2008

6,685
18,115
24,800

(2,578)
3,321
743

(728)
(1,594)
(2,322)
23,221
(717)
22,504

142
3,774
6
26,426
1,110

192
25,124

11,724
26,584
38,308

(644)
4,820
4,176

(902)
(321)
(1,223)
41,261
466
41,727

(393)
(6,060)
(35)
35,239
1,547

(591)
34,283

$ million

2007

7,929
19,673
27,602

(1,232)
3,853
2,621

(960)
(249)
(1,209)
29,014
(220)
28,794

127
3,455
(24)
32,352
1,393

(652)
31,611

2,806
19,698
22,504

10,678
31,049
41,727

5,581
23,213
28,794

a IFRS requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for the purposes of performance
assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit before interest and tax. In addition, a reconciliation is required between the total of the operating
segments’ measures of profit or loss and the group profit or loss before taxation.
b Replacement cost profit reflects the replacement cost of supplies. The replacement cost profit for the period is arrived at by excluding from profit inventory holding gains and losses and their associated
tax effect. Replacement cost profit for the group is not a recognized GAAP measure. Further information on inventory holding gains and losses is provided on page 53.

BP Annual Report and Accounts 2009
Business review

Exploration and Production

For the year ended 31 December

Sales and other operating revenuesa
Replacement cost profit before interest and taxb

Net proved reserves for subsidiaries
Net proved reserves for equity-accounted entities
Total of subsidiaries and equity-accounted entities

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

Average BP natural gas realizationsc
Average BP US natural gas realizationsc

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
Total of subsidiaries and equity-accounted entitiesd f

Natural gas production for subsidiariesf
Natural gas production for equity-accounted entitiesf
Total of subsidiaries and equity-accounted entitiesf

Total production for subsidiariesf g
Total production for equity-accounted entitiesf g
Total of subsidiaries and equity-accounted entitiesf g

a Includes sales between businesses.
b Includes profit after interest and tax of equity-accounted entities.
c Realizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities.
d Crude oil and natural gas liquids.
e Henry Hub First of Month Index.
f Net of royalties.
g Expressed 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.

2009
57,626
24,800

12,621
5,671
18,292

59.86
29.60
56.26
61.92
61.67

3.25
3.07

2008
86,170
38,308

$ million

2007
65,740
27,602

million barrels of oil equivalent

12,562
5,585
18,147

95.43
52.30
90.20
100.06
97.26

12,583
5,231
17,814

$ per barrel

69.98
46.20
67.45
72.20
72.39

$ per thousand cubic feet

6.00
6.77

4.53
5.43

$ per million British thermal units
6.86

9.04

3.99

30.85

1,400
1,135
2,535

7,450
1,035
8,485

pence per therm
29.95

58.12

thousand barrels per day

1,263
1,138
2,401

1,304
1,110
2,414

million cubic feet per day

7,277
1,057
8,334

7,222
921
8,143

thousand barrels of oil equivalent per day

2,684
1,314
3,998

2,517
1,321
3,838

2,549
1,269
3,818

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Sales and other operating revenues for 2009 were $58 billion, compared
with $86 billion in 2008 and $66 billion in 2007. The decrease in 2009
primarily reflected lower oil and gas realizations. The increase in 2008
compared with 2007 primarily reflected higher oil and gas realizations;
gas marketing sales also increased primarily as a result of higher prices.

The replacement cost profit before interest and tax for the year

ended 31 December 2009 was $24,800 million. This included a net credit
for non-operating items of $2,265 million (see page 58), with the most
significant items being gains on the sale of operations (primarily from the
disposal of our 46% stake in LukArco, the sale of our 49.9% interest in
Kazakhstan Pipeline Ventures LLC and the sale of BP West Java Limited
in Indonesia) and fair value gains on embedded derivatives. In addition,
fair value accounting effects had a favourable impact of $919 million
relative to management’s measure of performance (see page 59).

The replacement cost profit before interest and tax for the year

ended 31 December 2008 was $38,308 million. This included a net
charge for non-operating items of $990 million (see page 58), with the
most significant items being net impairment charges and net fair value
losses on embedded derivatives, partly offset by the reversal of certain
provisions. The impairment charge included 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 59).

The replacement cost profit before interest and tax for the year

ended 31 December 2007 was $27,602 million. This included a net credit
from non-operating items of $491 million (see page 58), 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 59).

The primary additional factor contributing to the 35% decrease in the
replacement cost profit before interest and tax for the year ended
31 December 2009 compared with the year ended 31 December 2008
was lower realizations. In addition, the result was impacted by lower
income from equity-accounted entities and higher depreciation but the
result benefited from higher production and lower costs, as a result of
our continued focus on cost management.

The primary additional factor contributing to the 39% increase in

the replacement cost 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.

Reported production for 2009 was 3,998mboe/d (2,684mboe/d for

subsidiaries and 1,314mboe/d for equity-accounted entities) compared
with 3,838mboe/d in 2008 (2,517mboe/d for subsidiaries and
1,321mboe/d for equity-accounted entities), an increase of 4%. After
adjusting for entitlement impacts in our PSAs and the effect of OPEC
quota restrictions, the increase was 5%. This reflected continued strong
operational performance and the start-up of seven major projects in
2009.

Reported production for 2008 was 3,838mboe/d (2,517mboe/d

for subsidiaries and 1,321mboe/d for equity-accounted entities),
compared with 3,818mboe/d in 2007 (2,549mboe/d for subsidiaries and
1,269mboe/d for equity-accounted entities). In aggregate, after adjusting
for the effect of lower entitlement in our PSAs, 2008 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 nine major projects
in 2008.

Refining and Marketing

Sales and other operating revenuesa
Replacement cost profit before interest and taxb

Global indicator refining margin (GIM)c

Northwest Europe
US Gulf Coast
Midwest
US West Coast
Singapore
BP average

Refining availabilityd

Refinery throughputs

2009
213,050
743

2008
320,039
4,176

$ million

2007
250,221
2,621
$ per barrel

3.26
4.63
5.43
5.88
0.21
4.00

93.6

2,287

6.72
6.78
5.17
7.42
6.30
6.50

4.99
13.48
12.81
15.05
5.29
9.94
%
82.9
thousand barrels per day
2,127
2,155

88.8

a Includes sales between businesses.
b Includes profit after interest and tax of equity-accounted entities.
c The global indicator refining margin (GIM) is the average of regional indicator margins weighted 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 regional indicator margins may not be representative of the margins achieved by BP in any period
because of BP’s particular refinery configurations and crude and product slate.
d 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.

BP Annual Report and Accounts 2009
Business review

Sales and other operating 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

Sale of crude oil through spot and term contracts
Marketing, spot and term sales of refined products

Sales and other operating revenues for 2009 were $213 billion, compared
with $320 billion in 2008 and $250 billion in 2007. The decrease in 2009
compared with 2008 primarily reflected a decrease in prices. The increase
in 2008 compared with 2007 primarily reflected an increase in revenues
from marketing, spot and term sales of refined products, mainly driven by
higher prices. Additionally, revenues from sales of crude oil through spot
and term contracts increased as a result of higher prices, partly offset by
lower volumes.

The replacement cost profit before interest and tax for the year
ended 31 December 2009 was $743 million. This included a net charge
for non-operating items of $2,603 million (see page 58). The most
significant non-operating items were restructuring charges and a
$1.6 billion one-off, non-cash, loss to impair all the segment’s goodwill in
the US West Coast fuels value chain relating to our 2000 ARCO
acquisition. In addition, fair value accounting effects had an unfavourable
impact of $261 million relative to management’s measure of
performance (see page 59).

The replacement cost profit before interest and tax for the year

ended 31 December 2008 was $4,176 million. This included a net credit
for non-operating items of $347 million (see page 58). 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
to 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 59).

The replacement cost profit before interest and tax for the year

ended 31 December 2007 was $2,621 million. This included a net charge
for non-operating items of $952 million (see page 58). 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 in the UK and a
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 59).

During 2009, our performance was also driven by the significantly

weaker environment, where refining margins fell by almost 40%. This
was partly offset by significantly stronger operational performance in the
fuels value chains, with 93.6% refining availability; lower costs and
improved performance in the international businesses.

2009
35,625
166,088
11,337
213,050

1,824
5,887

2008
54,901
248,561
16,577
320,039

$ million

2007
43,004
194,979
12,238
250,221

thousand barrels per day

1,689
5,698

1,885
5,624

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

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 were 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 compared with 2007, 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.
Refining throughputs in 2009 were 2,287mb/d, 132mb/d higher

than in 2008. Refining availability was 93.6%, 4.8 percentage points
higher than in 2008, the increase being driven primarily by the restoration
of availability at our Texas City refinery. Marketing volumes at 3,560mb/d
were around 4.1% lower than in 2008.

Other businesses and corporate

Sales and other operating revenuesa
Replacement cost profit (loss) before

2009
2,843

2008
4,634

$ million

2007
3,698

interest and taxb

(2,322)

(1,223)

(1,209)

a Includes sales between businesses.
b Includes 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 interest income on the group’s cash, cash equivalents), and
corporate activities worldwide.

The replacement cost loss before interest and tax for the year

ended 31 December 2009 was $2,322 million and included a net charge
for non-operating items of $489 million (see page 58).

The primary additional factors affecting 2009’s result compared
with that of 2008 were a weaker margin environment for Shipping and
our BP Solar business and adverse foreign exchange effects.

The replacement cost loss before interest and tax for the year

ended 31 December 2008 was $1,223 million and included a net charge
for non-operating items of $633 million (see page 58).

The replacement cost loss before interest and tax for the year

ended 31 December 2007 was $1,209 million and included a net charge
for non-operating items of $262 million (see page 58).

BP Annual Report and Accounts 2009
Business review

Non-operating items
Non-operating items are charges and credits arising in consolidated
entities 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 costs; 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.
These items are not separately recognized under IFRS. An analysis of
non-operating items is shown in the table below.

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 assetsa
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
Taxation credit (charge)b
Total after taxation

2009

2008

$ million

2007

1,574
3
(10)
664
34
2,265

(1,604)
(219)
(907)
(57)
184
(2,603)

(130)
(75)
(183)
–
(101)
(489)
(827)
(240)
(1,067)

(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)

a Includes $1,579 million in relation to the impairment of goodwill allocated to the US West Coast fuels value chain.
b The amounts shown for taxation are based upon the effective tax rate on group profit. In 2009, no tax credit has been calculated on the goodwill impairment in Refining and Marketing because the
charge is not tax deductible.

BP Annual Report and Accounts 2009
Business review

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 which 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 for
consolidated entities 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. A reconciliation to GAAP
information is set out below.

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

Taxation credit (charge)a

By region
Exploration and Production
US
Non-US

Refining and Marketing
US
Non-US

a The amounts shown for taxation are based upon the effective tax rate on group profit.

Reconciliation of non-GAAP information

Exploration and Production
Replacement cost profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Replacement cost profit before interest and tax
Refining and Marketing
Replacement cost profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Replacement cost profit before interest and tax

2009

389
530
919

(82)
(179)
(261)
658
(213)
445

687
232
919

16
(277)
(261)

2008

107
(389)
(282)

429
82
511
229
(83)
146

(231)
(51)
(282)

231
280
511

2009

2008

23,881
919
24,800

1,004
(261)
743

38,590
(282)
38,308

3,665
511
4,176

$ million

2007

155
(107)
48

72
(429)
(357)
(309)
111
(198)

(77)
125
48

(165)
(192)
(357)

$ million

2007

27,554
48
27,602

2,978
(357)
2,621

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Environmental expenditure

Operating expenditure
Clean-ups
Capital expenditure
Additions to environmental remediation provision
Additions to decommissioning provision

2009
701
70
955
588
169

2008
755
64
1,104
270
327

$ million

2007
662
62
1,033
373
1,163

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 may form 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 $701 million in 2009

was lower than in 2008, due to a reduction in new projects undertaken.
In addition, there was a significant reduction in the sulphur oil premium
paid due to a greater use of low-sulphur fuel.

Environmental operating expenditure of $755 million in 2008 was

higher than in 2007 and reflected continuing integrity management
activity. There were no individually significant factors driving the increase.

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 normally occurs in
subsequent periods and is not included in environmental operating
expenditure reported for such periods. The charge for environmental
remediation provisions in 2009 included $582 million resulting from a
reassessment of existing site obligations and $6 million in respect of
provisions for new sites.

Provisions for environmental remediation are recognized when
a clean-up is probable and the amount of the obligation can be reliably
estimated. Generally, this coincides with the commitment to a formal
plan of action or, if earlier, on divestment or on closure of inactive sites.

The extent and cost of future environmental restoration, remediation and
abatement programmes are 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.
In addition, we recognize 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 recognized 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 34 on page 160. See also
Environment on pages 47-49.

BP Annual Report and Accounts 2009
Business 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 2009 was $27,716 million compared with $38,095 million
for 2008 reflecting a decrease in profit before taxation of $9,159 million,
an increase in working capital requirements of $8,944 million and a
decrease in dividends from jointly controlled entities and associates of
$725 million; these were partly offset by a decrease in income taxes
paid of $6,500 million, higher depreciation, depletion, amortization and
impairment charges of $1,329 million and an increase in charges for
provisions of $948 million.

Net cash provided by operating activities for the year ended

31 December 2008 was $38,095 million compared with $24,709 million
for 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 used in investing activities was $18,133 million in 2009,

compared with $22,767 million and $14,837 million in 2008 and 2007
respectively. The decrease in 2009 reflected a decrease in capital
expenditure and acquisitions of $2,356 million and an increase in disposal
proceeds of $1,752 million. The increase in 2008 reflected a reduction in
disposal proceeds of $3,338 million and an increase in capital expenditure
of $5,303 million.

Net cash used in financing activities was $9,551 million in 2009
compared with $10,509 million in 2008 and $9,035 million in 2007. The
decrease in 2009 reflects a $2,774 million decrease in the net repurchase
of shares and an increase in net proceeds from long-term financing of
$1,406 million; these were partly offset by an increase in net repayments
of short-term debt of $3,090 million. 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 group has had significant levels of capital investment for

many years. Cash flow in respect of capital investment, excluding
acquisitions, was $21.4 billion in 2009, $23.7 billion in 2008 and
$18.4 billion in 2007. 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 $26.2 billion at the end
of 2009, $25.0 billion at the end of 2008 and was $26.8 billion at the end
of 2007.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

2009
27,716
(18,133)
(9,551)
110
142
8,197
8,339

2008
38,095
(22,767)
(10,509)
(184)
4,635
3,562
8,197

$ million

2007
24,709
(14,837)
(9,035)
135
972
2,590
3,562

During the period 2007 to 2009, our total sources of cash amounted
to $100 billion, whilst our total uses of cash amounted to $105 billion.
The net cash usage of $5 billion was financed by an increase in finance
debt of $11 billion over the three-year period, offset by an increase in our
balance of cash and cash equivalents of $6 billion. During this period,
the price of Brent has averaged $77.11 per barrel. The following table
summarizes the three-year sources and uses of cash.

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

$ billion

91
9
100

64
2
9
29
1
105
(5)

(11)
6
(5)

Acquisitions made for cash were more than offset by divestment
proceeds received during the three-year period. Net investment during
the same period averaged $19 billion per year. Dividends to BP
shareholders, which grew on average by 14% per year in dollar terms,
used $29 billion. Net repurchase of shares was $9 billion, which included
$11 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.

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.

The group’s finance debt is almost entirely in US dollars and at

31 December 2009 amounted to $34,627 million (2008 $33,204 million)
of which $9,109 million (2008 $15,740 million) was short term.

Net debt was $26,161 million at the end of 2009, an increase of

$1,120 million compared with 2008. 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 20% at the end of 2009 and 21% at the end of 2008, 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 24 on
page 144 and Note 32 on page 158.

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 2009, the amount drawn down
against the DIP was $11,403 million (2008 $10,334 million).

In addition, the group has in place an unlimited US Shelf
Registration under which it may raise debt with maturities of one month
or longer.

Commercial paper markets in the US and Europe are a primary

source of liquidity for the group. At 31 December 2009, the outstanding
commercial paper amounted to $398 million (2008 $4,268 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 2009, the group had available undrawn
committed borrowing facilities of $4,950 million (2008 $4,950 million).

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 2009, the group’s share of third-party finance debt of
equity-accounted entities was $6,483 million (2008 $6,675 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 2009 are $319 million (2008 $223
million) in respect of liabilities of jointly controlled entities and associates
and $667 million (2008 $613 million) in respect of liabilities of other third
parties. Of these amounts, $286 million (2008 $215 million) of the jointly
controlled entities and associates guarantees relate to borrowings and for
other third-party guarantees, $633 million (2008 $582 million) relates to
guarantees of borrowings.

BP Annual Report and Accounts 2009
Business review

Trend information
In the US and the major economies of Europe, we expect recovery from
the recession to be slow and gradual. The oil markets look well supported
by OPEC, but we expect gas markets to remain volatile. Demand for
petrochemicals products is recovering only slowly, and there is significant
refining over-capacity particularly in the Atlantic Basin. As a consequence,
refining margins are likely to remain depressed for the foreseeable future.
In Exploration and Production, production growth was very strong

in 2009, benefiting by about 40mboe/d on an annual basis from a
combination of the absence of a significant hurricane season and the
make-up of a prior-period underlift. As a result, we expect production in
2010 to be slightly lower than in 2009.

In Refining and Marketing, we expect refining margins to remain

weak in 2010.

We expect the quarterly loss in Other businesses and corporate,

excluding non-operating items, to average around $400 million in 2010. This
will, as in previous years, remain volatile on an individual quarterly basis.
We expect capital expenditure, excluding acquisitions and asset

exchanges, to be around $20 billion in 2010, and we expect divestments
to be between $2 and $3 billion.

In 2009 the cash inflows and outflows of the group were broadly

in balance despite much weaker than expected refining margins and
North American gas prices. Looking forward we expect to be able to
continue to balance cash inflows and outflows even if conditions are
equally challenging.

Dividends and other distributions to shareholders
The total dividend paid to BP shareholders in 2009 was $10,483 million,
compared with $10,342 million for 2008. The dividend paid per share was
56 cents, an increase of 2% compared with 2008. In sterling terms, the
dividend increased 24% due to the strengthening of the dollar relative to
sterling. We determine the dividend in US dollars, the economic currency
of BP.

During 2009, the company did not repurchase any of its own

shares.

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.

Subject to shareholder approval at the Annual General Meeting on
15 April, an optional scrip dividend programme, allowing shareholders to
choose to receive dividends in the form of new fully paid ordinary shares
in BP p.l.c. instead of cash, will be available for future dividends. This
would replace the company’s current dividend reinvestment plans.

The discussion above and following contains forward-looking

statements particularly those regarding global economic recovery and
outlook for oil and gas markets, oil and gas prices, refining margins,
production, demand for petrochemicals products, underlying average
quarterly loss from Other businesses and corporate, effective tax rate,
operating and capital expenditure, timing and proceeds of divestments,
contractual commitments, balance of cash inflows and outflows and
dividend and optional scrip dividend. 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 21 and ‘Risk factors’ on pages 18-20, 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.

BP Annual Report and Accounts 2009
Business review

Contractual commitments
The following table summarizes the group’s principal contractual obligations at 31 December 2009. Further information on borrowings and finance
leases is given in Financial statements – Note 32 on page 158 and more information on operating leases is given in Financial statements – Note 12 on
page 134.

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
Unconditional purchase obligationsd
Total

$ million

Payments due by period

Total
36,717
845
14,716
13,261
1,860
26,855
155,356
249,610

2010
9,681
109
3,251
364
385
1,647
92,536
107,973

2011
6,740
121
2,513
261
256
1,890
16,189
27,970

2012
5,282
77
1,977
356
193
1,887
10,420
20,192

2013
5,463
65
1,604
428
152
1,884
6,677
16,273

2014
3,085
66
1,240
389
117
1,491
5,350
11,738

2015 and
thereafter
6,466
407
4,131
11,463
757
18,056
24,184
65,464

a Expected payments include interest payments on borrowings totalling $2,679 million ($662 million in 2010, $508 million in 2011, $379 million in 2012, $262 million in 2013, $168 million in 2014 and
$700 million thereafter).
b The future minimum lease payments are before deducting related rental income from operating sub-leases. In the case of an operating lease entered into solely by BP as the operator of a jointly
controlled asset, the amounts shown in the table represent the 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 BP’s share of the future minimum lease payments are included in the amounts shown, whether BP has co-signed the lease or not. 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.
c Represents 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.
d Represents 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 2010 include purchase commitments existing at 31 December 2009 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 24 on page 144.

The following table summarizes the nature of the group’s unconditional purchase obligations.

Unconditional purchase obligations
Crude oil and oil products
Natural gas
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total

Total
80,991
41,680
10,939
3,846
718
8,923
8,259
155,356

2010
62,794
21,038
2,909
2,969
112
1,005
1,709
92,536

2011
6,352
5,598
1,521
591
111
858
1,158
16,189

2012
3,894
3,150
1,183
236
93
806
1,058
10,420

2013
1,787
2,386
849
36
69
766
784
6,677

$ million

Payments due by period

2014
1,001
1,957
824
14
59
723
772
5,350

2015 and
thereafter
5,163
7,551
3,653
–
274
4,765
2,778
24,184

The group expects its total capital expenditure, excluding acquisitions and asset exchanges, to be around $20 billion in 2010. The following table
summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2009 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
29,451
9,812

2010
13,406
6,611

2011
7,071
1,713

2012
3,091
748

2013
1,624
320

2014
1,618
195

$ million

2015 and
thereafter
2,641
225

In addition, at 31 December 2009, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to
$1,038 million. Contracts were in place for $792 million of this total.

B
u
s
i
n
e
s
s
r
e
v
i
e
w

w
e
i
v
e
r
s
s
e
n
i
s
u
B

BP Annual Report and Accounts 2009
Business review

Board performance
and biographies

66 Directors and

senior management

69 Board performance report

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

BP Annual Report and Accounts 2009
Board performance and biographies

Directors and senior management

The following lists the company’s directors and senior management as at 18 February 2010.

Name
C-H Svanberg

Chairman

Sir Ian Prosser

Non-Executive Deputy Chairman

P Anderson
A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
Dr D S Julius
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
R W Dudley
Dr B E Grote
A G Inglis
R Bondy
S Bott
H L McKay
S Westwell

Executive Director (Chief Executive, Refining and Marketing)
Executive Director (Managing Director)
Executive Director (Chief Financial Officer)
Executive Director (Chief Executive, Exploration and Production)
Group General Counsel
Executive Vice President, Human Resources
Executive Vice President (Chairman and President of BP America Inc.)
Executive Vice President (Group Chief of Staff)

Initially elected or appointed
Chairman since January 2010
Director since September 2009
Deputy chairman since February 1999
Director since May 1997
February 2010
February 2004
June 2007
July 2006
February 2008
December 1998
January 2005
November 2001
Group Chief Executive since May 2007
Director since February 2003
July 2004
April 2009
August 2000
February 2007
May 2008
March 2005
June 2008
January 2008

Mr C-H Svanberg was appointed as a director and chairman designate on 1 September 2009 and appointed chairman on 1 January 2010 on the
retirement of Mr P D Sutherland. Mr P Anderson was appointed as a director on 1 February 2010. Sir Tom McKillop resigned as a director on 16 April
2009.

At the company’s 2009 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 R W Dudley; Mr D J Flint;
Dr B E Grote; Dr A B Hayward; Mr A G Inglis; Dr D S Julius; Sir Ian Prosser and Mr P D Sutherland.

Mr I E L Davis has been appointed as a director with effect from 2 April 2010. All of the directors, including Mr Davis, will offer themselves for
election/re-election at the company’s 2010 AGM.

David Jackson (57) 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 2009
Board performance and biographies

Directors
C-H Svanberg
Chairman of the chairman’s and the nomination committees and attends
meetings of the remuneration committee
Carl-Henric Svanberg (57) was appointed a non-executive director of BP
on 1 September 2009 and, in succession to Mr Sutherland, became
chairman of BP on 1 January 2010. From 2003 until 31 December 2009,
he was president and chief executive officer of Ericsson, also serving as
s
the chairman of Sony Ericsson Mobile Communications AB. He continue
to be a non-executive director of Ericsson.

Sir Ian Prosser
Member of the chairman’s, the nomination and the remuneration
committees and chairman of the audit committee
Sir Ian (66) 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 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 GlaxoSmithKline plc, The Boots Company
PLC and Lloyds TSB PLC.

P Anderson
Member of the chairman’s and the safety, ethics and environment
assurance committees
Paul Anderson (64) was appointed a non-executive director of BP on
1 February 2010. He is a non-executive director of BAE Systems PLC and
of Spectra Energy Corp. He was formerly chief executive at BHP Billiton
and Duke Energy where he also served as a non-executive director.
Having previously been chief executive officer and managing director of
BHP Limited and then BHP Billiton Limited and BHP Billiton Plc, he
rejoined these latter boards in 2006 as a non-executive director, retiring
on 31 January 2010.

A Burgmans, KBE
Member of the chairman’s, the remuneration and the safety, ethics and
environment assurance committees
Antony Burgmans (63) 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-executiv
chairman of Unilever PLC and Unilever NV, retiring from these
appointments in 2007. He is also a member of the supervisory boards of
Akzo Nobel NV, Aegon NV and SHV Holdings NV.

C B Carroll
Member of the chairman’s and the safety, ethics and environment
assurance committees
Cynthia Carroll (53) joined BP’s board in 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 2007. She is also a director of
De Beers s.a. and Anglo Platinum Ltd.

Sir William Castell, LVO
Member of the chairman’s and the nomination committees and chairman
of the safety, ethics and environment assurance committee
Sir William (62) 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, the audit and the remuneration committees
George David (67) joined BP’s board in February 2008. He has spent
his career with United Technologies Corporation (UTC), as its chief
executive officer between 1994 and 2008 and chairman from 1997
until his retirement on 31 December 2009. He is a former director of
Citigroup Inc.

E B Davis, Jr
Member of the chairman’s, the audit and the safety, ethics and
environment assurance committees
Erroll B Davis, Jr (65) 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 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 (54) joined BP’s board in 2005. He trained as a chartered
accountant and was made a partner at KPMG in 1988. In 1995, he was
appointed group finance director of HSBC Holdings plc and in 2009 his
role was broadened to chief financial officer, executive director risk and
regulation. 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 (60) 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.

Dr A B Hayward
Tony Hayward (52) 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 2007. He became an
executive director of BP in 2003 and was appointed as group chief
executive in 2007.

I C Conn
Iain Conn (47) 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 2007. He is a non-executive director and senior independent
director of Rolls-Royce Group plc.

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

BP Annual Report and Accounts 2009
Board performance and biographies

R W Dudley
Robert Dudley (54) joined the Amoco Corporation in 1979 for whom he
worked until its merger with BP in 1998. Following a variety of posts in
the US, the UK, the South China Sea and Moscow, in 2001 he became
group vice president responsible for BP’s upstream businesses in Russia,
the Caspian Region, Angola, Algeria and Egypt. From 2003 to 2008,
Mr Dudley was president and chief executive officer of TNK-BP in
Moscow. He was appointed an executive director on 6 April 2009 and is
an executive vice president with responsibility for broad oversight of the
company’s activities in the Americas and Asia.

Senior management
R Bondy
Rupert Bondy (48) 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.

Dr B E Grote
Byron Grote (61) 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 (50) 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 2007. He is a non-executive director of BAE
Systems plc.

S Bott
Sally Bott (60) joined BP in 2005 as an executive vice president
responsible for global human resources. Sally joined Citibank in 1970 and
was in the economics department and the finance function before joining
human resources. She was appointed human resources vice president in
1979. 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.

H L McKay
Lamar McKay (51) was appointed chairman and president of BP America,
Inc. in February 2009. He joined Amoco Production Company as a
petroleum engineer in 1980. He held a variety of roles before becoming
group vice president for Russia & Kazakhstan in 2003, also being
appointed to the board of TNK-BP in 2004. In 2007, he was named
executive vice-president of BP America and COO. In early 2008, he
became executive vice president of BP plc special projects, focusing
on Russia, subsequently joining the group executive management team
in June 2008.

S Westwell
Steve Westwell (51) 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 in January 2008.

BP Annual Report and Accounts 2009
Board performance and biographies

Board performance report

I am pleased to have this opportunity to report to you on the work of the
BP board over the last year.

I joined the board as a non-executive director in September 2009

and took the chair on 1 January 2010 upon the retirement of Peter
Sutherland. Peter has reviewed this letter and I, of course, have had the
benefit of the views of my board colleagues on its content.

This is a particularly interesting time for me to take the chair at BP.
In the past months we have seen the reports of Sir David Walker and the
Financial Reporting Council (FRC), to which we have contributed. The way
in which boards work has again been in the spotlight. There are a number
of lessons that all boards can learn from the events of 2008 and 2009.
Both these reports have focused on the need for appropriate behaviours
around the board table and for governance not to be regarded as solely
relating to compliance. This is a view which BP has taken for some time
and which I fully endorse.

I have been impressed by BP’s commitment to the highest
standards of corporate governance. Governance describes all that a board
does – a point which has been reinforced by the FRC’s draft revised
Combined Code. It is vital that a board balances the time that it spends
between strategy and oversight. From early indications, I believe that the
BP board achieves this balance well.

The board is responsible for the direction and oversight of

BP p.l.c. on behalf of shareholders; it is accountable to them,
as owners, for all aspects of BP’s business. It sets the tone from the top.
In conducting its business, BP needs to be responsive to other
constituencies with whom it comes into contact.

Governance framework
Clarity of roles and responsibilities, and the proper utilization of distinct
skills and processes lie at the heart of the board’s role. The BP board
governance principles (‘principles’) are the framework within which the
board operates.

This framework sets out the role of the board, its processes,
its relationship with executive management and the main tasks and
requirements of the board committees. The board’s core activities
include:
(cid:129) The active consideration of long-term strategy.
(cid:129) The monitoring of executive action and the performance of BP.
(cid:129) Obtaining assurance that the material risks to BP are identified and

that systems of risk management and control are in place to mitigate
such risks.

(cid:129) Ongoing board and executive management succession.
The principles can be seen on BP’s website at www.bp.com/governance.

The board delegates authority for executive management of the company
to the group chief executive. This delegation is subject to a clearly defined
set of executive limitations which are monitored by the board. The
executive limitations require the group chief executive to take into
consideration specific issues in the course of business – these include
key risk areas such as health, safety and environmental matters and
generally ensuring that BP’s reputation is maintained. The group chief
executive is also responsible for ensuring there is a comprehensive
system of controls to identify and manage the risks that are material
to BP.

The board keeps this framework under regular review and tests

its effectiveness through the annual board evaluation.

Board activities in 2009
The board’s work reflects the tasks described above, namely strategy,
risk and the oversight of the company’s performance and operation of
the system of delegation.

The board endeavours to balance its work so that these tasks are
achieved either through the work of the board or its committees. At the
start of each year, the board reviews and agrees a forward workplan
based upon:
(cid:129) The need for the board to be involved in strategy development and

the oversight of risk.

(cid:129) Annual reviews of the two business segments and of the corporate

business and functions which includes Alternative Energy.
(cid:129) Oversight of risk generally and specifically those risks identified

through the annual plan (the board will decide which risk issues will
be considered by the whole board and which will be delegated to the
committees with appropriate reporting to the board).
(cid:129) Consideration of quarterly and annual corporate reporting

documentation.

In determining its programme the board has to allow sufficient time for
urgent issues to be accommodated. The board will meet by telephone
should circumstances dictate.

The board now holds one of its meetings at the company’s
offices in Washington and will meet at other locations when appropriate.
In 2009, the board met in Long Beach, California and used this
opportunity to visit the company’s businesses in the West Coast fuels
value chain and to learn about the research taking place into biofuels.

An analysis of the time spent by the board during 2009 is shown below:

Board activities
Approximate allocation of agenda time in 2009*

20%

11%

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

41%

GCE and executive director updates,
business reviews (including safety)
Strategy and risk
Country specific reports (including safety)
Functional reviews
Financial and corporate reporting
Other matters

*Excludes time spent on site visits.

Strategy and risk
While strategic issues are normally discussed at the two dedicated away
day sessions, the development of the group’s business over the year has
meant that strategic issues have been actively considered at a number of
meetings. Strategic and geopolitical challenges, together with the
associated risks are at the core of the group’s business.

The business and competitive environment, the global economic
outlook, the impact of the price of oil, the issues raised by carbon policy,
the technological challenges and strengths of the group were all matters
which the board kept under review.

BP Annual Report and Accounts 2009
Board performance and biographies

BP governance framework

D
e
l
e
g
a
t
i
o
n

Owners/shareholders

Board

Nomination
Nomination
committee
committee

Remuneration Chairman’s
Chairman’s
Remuneration
committee
committee
committee
committee

SEEAC

Audit
Audit
committee
committee

Annual plan / Group risks / Strategy

Group chief executive

GCE’s delegations

Executive management

RCM
Resource
commitments
meeting

GPC
Group people
committee

GDC
Group
disclosures
committee

GFRC
Group
ﬁnancial risk
committee

GORC
Group
operations risk
committee

BP Board Governance
Principles

• BP goal
• Governance process
• Delegation model
• Executive limitations

Delegation

Delegation of authority
through policy with
monitoring

Accountability

Assurance through
monitoring and reporting

Monitoring,
Information and
Assurance

Ernst & Young

Internal audit

Finance function

Safety & Operations
function

General counsel

Group compliance
ofﬁ cer

External market
and reputation
research

Independent expert

Independent advice
(if requested)

A
c
c
o
u
n
t
a
b

i
l
i
t
y

GCE update and business reviews
The group chief executive provides a written report to each meeting of
the board which gives an update on key issues relating to safety and
integrity, operations, financial performance and the market in which
BP’s businesses operate. These are complemented by verbal updates
given by executive directors on material matters which have arisen in
their business.

Periodic reviews of the business are scheduled throughout the
year. During 2009, reviews were held with both segments (Exploration
and Production and Refining and Marketing) and with Alternative Energy.

Country specific reports
Separate to the business specific reports, the board discussed the
performance, political landscape and market outlook relating to BP’s
operations, particularly in the US and Russia.

Functional reviews
The work of the group technology function was reviewed and discussions
were held on issues relating to information technology and services.

Financial and corporate reporting
The board considered the group’s statutory reports and the broader
aspects of corporate reporting. It also received regular updates on the
group’s financial outlook as well as discussing the financial results.

An annual review of the group’s process for sanctioning capital

investment is undertaken by the board. This includes examining case
studies of BP projects with different levels of complexity and
understanding the effectiveness of project delivery against original
sanction.

Other matters
Other matters discussed by the board included the BP brand and
corporate advertising, the results of the group-wide employee
satisfaction survey and an annual report evaluating BP’s external
reputation in the UK and US.

The board also received a presentation from the independent expert
appointed to provide an objective assessment of the BP US Refineries
Independent Safety Review Panel (the panel). Further details on the
activities of the independent expert are outlined in the report of the
safety, ethics and environment assurance committee below.

Risk management and internal control
The board and its committees monitor the identification and
management of the group’s risks and the board reviews how group-level
risks and their mitigations are embedded in the c ompany’s annual plan.
Geopolitical and reputational risks are considered by all the board which
also receives reports from the committees to whom specific risk
oversight has been allocated. The audit committee monitors financial risk
whilst the safety, ethics and environment assurance committee (SEEAC)
monitors non-financial risk; the audit committee and SEEAC hold an
annual joint meeting to assess the effectiveness of the company’s
internal controls and risk management. Like BP’s other board
committees, the audit committee and SEEAC are composed entirely
of independent non-executive directors.

The audit committee and SEEAC maintain a forward-looking

approach to risk exposure. A high level work programme for the board
and its committees is set on the basis of an agenda that reflects the
board’s core tasks and the key group risks.

The group chief executive and his senior team are supported by

executive-level sub-committees which monitor specific group risks: these
committees comprise the group operations risk committee (GORC), the
group financial risk committee (GFRC), the group people committee
(GPC), the resource commitments meeting (RCM) and the group
disclosures committee (GDC). They provide input and data to the risk
oversight process by the executive, as well as external and internal audit,
the group’s compliance and ethics officer, safety and operations audit
and group controls.

Further information about our internal control systems is set out

on pages 20, 74 and 105.

BP Annual Report and Accounts 2009
Board performance and biographies

BP’s general auditor (head of the internal audit function) reports on the
design and operation of risk management activities across the group and
attends meetings of both the audit committee and SEEAC. The general
auditor has direct access to the chairs of both committees and holds
regular meetings with them outside formal meetings.

The chairman is tasked with setting the agenda for the board in
consultation with the group chief executive and with the support of the
company secretary. The chairman ensures that systems are in place to
provide directors with accurate, timely and clear information concerning
the business of the board and the company.

Within the company, BP has an annual certification process in

Between board meetings, the chairman has authority to act

which team leaders are asked to discuss with their teams and then
submit a certificate regarding their and their team’s understanding of and
adherence to BP’s code of conduct and the reporting of any breaches or
risk of non-compliance. The certification system enables the risk of non-
compliance to be assessed and reported alongside other business risks.

Board meetings and attendance
The board met 12 times during the year, of which two meetings were
two-day strategy sessions and three meetings were by telephone.

P D Sutherland
Sir Ian Prosser
A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
D S Julius
Sir Tom McKillopa
C-H Svanbergb
I C Conn
R W Dudleyc
B E Grote
A B Hayward
A G Inglis

Board meetings
eligible to attend
12
12
12
12
12
12
12
12
12
5
4
12
8
12
12
12

Board meetings
attended
10
12
12
11
11
12
10
10
12
3
3
12
8
12
12
11

a Retired from the board on 16 April 2009.
b Joined the board on 1 September 2009.
c Joined the board on 6 April 2009.

International advisory board
In 2009, BP formed an international advisory board whose purpose is
to advise the chairman, group chief executive and board of BP plc on
strategic and geopolitical issues relating to the long-term development
of the company. The international advisory board met twice in 2009.

The chairman, senior independent director and
non-executive directors
Neither the chairman nor the senior independent director is employed as
an executive of the group. The board is required to develop and maintain
a plan for the succession of both the chairman and senior independent
director. During 2009, these posts were held by Peter Sutherland and
Sir Ian Prosser respectively. Sir Ian Prosser also held the post of deputy
chairman during the year – a role which will cease on his retirement.

The chairman
Upon Peter’s retirement, I took the chair on 1 January 2010. The process
for my appointment and induction programme is outlined below.
I stepped down as CEO of Ericsson on 31 December 2009, but will
remain on the Ericsson board as a non-executive director. I had no other
significant commitments at the time of my appointment as chairman.
The chairman’s role is to provide leadership of the board, act

as facilitator for meetings, maintain the integrity of the governance
framework and have overall responsibility for ensuring the board’s
effectiveness. Other responsibilities include leading the board’s
performance evaluation and overseeing the board learning and
induction programme.

and speak for the board on all matters relating to the role of the board.
He also has responsibility for ensuring the relationship with executive
management is working well.

The chairman represents the views of the board to shareholders

on key issues, in particular those relating to the work of the board
including succession planning. He keeps the board briefed on those
views. In November I was able to meet a number of our institutional
shareholders as part of my induction. I found these to be productive
meetings and comment on them, and on the board engagement which
has taken place during the year, in further detail below.

The senior independent director
The senior independent director acts for the chairman in his absence or
at his request, and is available to shareholders if they request a meeting
or have concerns which contact through the normal channels has failed
to resolve or where such contact is inappropriate.

The senior independent director is available to act as a

communication channel between the chairman and other board
members and, when necessary, to provide a sounding board for the
chairman. He also has responsibility for leading the annual performance
review of the chairman.

Sir Ian Prosser will retire from the BP board at the AGM in April

2010. Sir William Castell will become the senior independent director
from that date.

Sessions of the non-executive directors
The chairman and all non-executive directors meet periodically without
the presence of executive management as the chairman’s committee.
The work of the committee during the year is outlined in the report
below.

Board composition
During the year, the number on the board has fluctuated. As at
26 February 2010, the board is composed of the chairman, nine non-
executive directors and five executive directors; over half the board is
therefore made up of independent non-executive directors. We state
that the number of directors should not normally exceed 16.

This is a large board, however, given the scale and scope of BP’s
business we believe that it is appropriate. We need to have a broad and
experienced group of directors who are able to contribute to a discussion
on strategy and risk whilst having the right skills to work on the
committees. We believe it is important to have a strong group of
executive directors who recognize their board responsibilities as directors
and not solely to represent the activity in the company for which they are
responsible. This adds to open and constructive debate and
demonstrates one of the strengths of a unitary board.

Sir Tom McKillop retired from the board on 16 April 2009 and Peter
Sutherland retired on 31 December 2009. Bob Dudley joined the board as
an executive director on 6 April 2009 and I became a BP non-executive
director and chairman designate on 1 September 2009. Paul Anderson
joined the board on 1 February 2010 and Ian Davis will join the board on
2 April 2010. Finally, two of our longest serving directors will be retiring at
the AGM in April 2010: Sir Ian Prosser and Erroll Davis, Jr.

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

BP Annual Report and Accounts 2009
Board performance and biographies

Appointments to the board
The board is actively involved in succession planning for both executive
and non-executive directors. It is assisted in this task of the progressive
refreshing of the board by the nomination committee. The nomination
committee keeps under review the composition, skills, independence,
knowledge and diversity of directors to ensure that the board and its
committees remains effective and appropriate to the work they
undertake. This review is undertaken at regular intervals and forms
the basis of criteria to evaluate potential board candidates.

Due to the size of the BP board and the wish to achieve a steady

refreshment of board appointments the nomination committee is
developing a longer-term pipeline of potential non-executive talent on
which it hopes to draw as new appointments arise. The committee
believes that given BP’s scale and breadth of operations, a broad mix of
skills, experience and knowledge is required for its board members. The
committee has identified deep operational and industry experience, as
well as insight into key technologies, health and safety, emerging
markets and financial knowledge as particularly relevant to future
board appointments. An understanding of geopolitical influence is also a
key skill.

A report on the work of the nomination committee is set

out below.

Terms of appointment
The chairman and non-executive directors of BP serve on the basis of
letters of appointment. Non-executive directors ordinarily retire at the
AGM following their 70th birthday. Executive directors have service
contracts with the company, which are expressed to retire at a normal
retirement age of 60 (subject to age discrimination).

Board independence
Non-executive directors are required to be independent in character and
judgement and free from any business or other relationship which could
materially interfere with the exercise of their judgement. The board has
determined that non-executive directors who served during 2009 fulfilled
this requirement and were independent. Upon appointment as chairman,
the board was satisfied that I met the criteria of independence outlined
above in the principles and in the UK Combined Code.

The board is also satisfied that there is no compromise to the

independence or conflicts of interest of those directors who serve
together as directors on the boards of outside entities or who have
other appointments in outside entities. These issues are considered
on a regular basis at board meetings.

Serving as a director
Induction and board learning
All directors receive a full induction programme when they join the board,
including a core element covering BP’s system of governance, the legal
duties of directors of a listed company and the regulatory systems in the
UK and US. The programme for non-executive directors has wider
content which covers the business of the group and is tailored according
to a director’s own interests and needs and takes into account the tasks
of the committees on which they will serve. Non-executive directors will
receive presentations from senior management, have in-depth briefings
on the company’s strategy, plan and financial performance and be given
the opportunity to visit BP’s operations and meet employees at BP sites.

Prior to assuming the role of chairman, I received an extensive

induction programme which covered:
(cid:129) Board matters, including directors’ duties, board issues and board

Details of all payments to directors appear in the directors’

committees.

remuneration report.

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
2009. During the year, a review of the terms and scope of the policy
was undertaken. The policy has been renewed for 2010. 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. UK company law permits the company
to advance costs to directors for their defence in investigations or legal
actions.

Tenure and director elections
BP does not place a term limit on a director’s service as the board
considers this unnecessary in light of the company’s long-established
practice of proposing all directors for annual re-election by shareholders.
The chairman and the nomination committee keep the tenure of the
directors under review as part of the wider consideration of board skills
and balance.

New board members are subject to election by shareholders

at the first AGM following their appointment, with all existing directors
standing for re-election each year. The notice of meeting contains a
biography of each of the directors and a description of the skills and
experience which the company feels is relevant to shareholders in
taking an informed decision on their election.

(cid:129) The business environment for BP.
(cid:129) BP’s core businesses: Exploration and Production, and Refining and

Marketing.

(cid:129) Reviews of Alternative Energy and Group Technology.
(cid:129) Overviews of BP’s functions – including Finance, Safety and

Operations, HR, Internal Audit, Legal, and Information Technology
and Services.

(cid:129) BP’s regional presence and key markets.
(cid:129) BP’s strategic approach and financial framework.
(cid:129) BP’s approach to risk management.
(cid:129) A review with the company’s external auditor.
I had one-to-one meetings with each member of the board and
undertook site visits to the Thunder Horse platform in the Gulf of Mexico
and BP’s fuels value chain in the western US. I attended meetings of the
audit, remuneration, nomination and chairman’s committees. I also met
with a number of BP’s largest shareholders. It was a lot of ground to
cover and the process is still continuing.

As the chairman, I am responsible for ensuring that induction
and training programmes are provided to all directors, and look at this
provision on an individual basis. The company secretary assists in this
and ensures that the programme to familiarize board members with BP’s
business is developed and updated in response to the needs of directors.
During 2009, the board received briefings on biosciences, carbon policy
and the economic outlook for the US, in addition to training at separate
committees. Written updates were given on legal and regulatory issues.

All non-executive directors are required to participate in at least

one site visit per year. During the year, site visits were made to the
Projects and Operations Academies at the Massachusetts Institute of
Technology, and to BP’s fuels value chain in California, involving visits
to a marine terminal, Carson Refinery, an inland distribution facility and
a retail service station.

The effectiveness and relevance of the board’s induction and
training programmes are tested through their inclusion in the annual
board evaluation. Feedback from the evaluation indicated that directors
would welcome more deep-dive coverage of BP’s business and more
learning content on risk and the context for evaluating risk.

BP Annual Report and Accounts 2009
Board performance and biographies

Board evaluation
BP undertakes an annual evaluation of the performance and
effectiveness of the board, including the work of its committees.
Evaluation of individual directors is undertaken by the chairman, with the
chairman’s committee evaluating the performance of the chairman.

By building on the results of the previous year’s evaluation, the
board tries to achieve a continuous cycle of evaluation, targeted actions
arising from the review and performance improvement. Actions taken by
the board during the year in response to the outcome of the 2008 review
included greater focus on key areas of board learning, the undertaking of
an investor audit to obtain feedback on BP’s performance and expanded
presentation of capital investment effectiveness.

For the 2009 evaluation, an external facilitator was engaged to

provide me with an understanding of the dynamics and performance of
the board as part of my induction as chairman.

Following a review of different providers, Boardroom Review was

selected as external facilitator and it was determined that they had no
other connection with the company. Boardroom Review undertook one-
to-one interviews with each board member plus those who provide
advice and support to the board and its committees. This was followed
by observation of the board and each committee meeting in session. The
evaluation report prepared by Boardroom Review was presented and
discussed by the board in January 2010. The evaluation identified several
areas of significant strength, including:
(cid:129) Strategic involvement: including the detailed and dynamic

examination of information on the external environment and the
impact and penetration of the work of the committees.

(cid:129) Board dynamics: examples cited include the breadth and depth of

executive and non-executive experience and the open and
transparent culture of the board.

(cid:129) Executive leadership: in particular the operational and performance
focus of the executive team and their commitment to develop the
board’s understanding of future options, strategic partnerships and
operational excellence.

Issues identified in the evaluation for the board to consider further
included:
(cid:129) Strategy and risk: while the way in which the board dealt with

strategy was seen to be a strength, the enhanced focus on risk
meant the board was seeking ways to further improve its
conversations on this.

(cid:129) The balance of formal and informal time: the time pressure on the

board to balance workload coupled with the increasing expectations
and responsibilities placed on board members. As a result, the board
is considering how best to maximize its time together, including
options such as scheduling more informal sessions outside board
meetings whilst still encouraging board members to observe
committee meetings of which they are not members in order to
better understand the issues.

(cid:129) Board and committee tenure: with the retirement of several board
members and the planned refreshment of the board, it was noted
that board committees would be faced with turnover. Going forward,
the board will examine ways of ensuring that committees do not face
members retiring within the same timeframe and that there is
appropriate cross membership between related committees.

(cid:129) Discussion of people and culture: with the ongoing process of change

within the company, there is challenge for the board to maintain
oversight on issues such as long-term retention, cultural values and
practices across the group. The board is looking at how its
committees can maintain a holistic view of these issues and how
employee engagement, staff morale and retention strategy is
monitored and influenced.

Time commitment and outside appointments
Letters of appointment to the BP board do not set out fixed time
commitments for board duties as the company believes that the time
required may change depending upon the demands of business.
Membership of the board represents a significant time commitment and
it is expected that directors will allocate sufficient time to the company to
perform their responsibilities effectively. The nomination committee
keeps this under review.

The company recognizes that executive directors may be invited

to become non-executive directors of other companies. Such
appointments can broaden their knowledge and experience, to the
benefit of both the individual and the group. BP permits executive
directors to take up one external board appointment, subject to the
agreement of the chairman which is then 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 support and external advice
The chairman, assisted by the company secretary, ensures that board
members receive timely and clear information on all matters relevant
to the work and tasks of the board. Support to the board and its
committees is provided through the company secretary’s office, which
reports to the chairman. The company secretary has no executive
functions, with his appointment determined by the nomination
committee and his remuneration determined by the remuneration
committee.

Any BP director is entitled to obtain independent, professional
advice relating to their own responsibilities and the affairs of BP; this
advice will be at the expense of the company and facilitated through the
company secretary’s office. No BP directors sought such advice in 2009.

Board communication
Engagement with shareholders
The board represents the interests of all shareholders and seeks to act
fairly between them. It is accountable to shareholders for the
performance and activities of BP and engages in regular dialogue to
understand their views and preferences.

The chairman, the group chief executive, other executive and non-

executive directors and senior management, the company secretary’s
office, investor relations and other teams within BP engage with a range
of shareholders on issues relating to the group. 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
interest to shareholders made by the group chief executive and other
senior management.

Peter Sutherland held a number of one-to-one meetings with

investors over the course of the year to discuss issues relating to
governance, succession, strategy and performance. The chair of the
remuneration committee had meetings with institutional investors to
discuss executive director remuneration.

A meeting was held in March 2009 for BP’s largest shareholders

with the chairman and the chairs of the board committees. Each chair
gave a short presentation on his or her committee’s work and the key
challenges the committee faced in the year ahead, before opening the
session up to questions. The meeting was aimed at providing our largest
investors with an overview of the board’s activities in advance of the
AGM in April. Following positive feedback from both committee chairs
and investors, a similar event will be held in 2010.

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

BP Annual Report and Accounts 2009
Board performance and biographies

I met a number of BP’s largest shareholders in November to hear their
views on the company and the activities of the board and its committees
in advance of becoming chairman in January 2010.

Written and verbal feedback from shareholder meetings is shared

with the wider board. During the year, the investor relations team
engaged an external consultant to undertake an investor audit to solicit
the views of major shareholders. The results of this audit were presented
to the board in July. The board also receives regular reports on the
company’s share register, including explanations for movements in price
and holdings of the company’s ADRs and ordinary shares.

AGM
The AGM is an opportunity for BP’s shareholders to ask questions and
hear the resulting discussion about the company’s performance and the
directors’ stewardship of the company. Given the size and geographical
distribution of the company’s shareholder base BP recognizes that
attendance may not be practical; therefore 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 and chairs of the board committees were present
during the 2009 AGM and met shareholders on an informal basis after
main business of the meeting. In 2009, voting levels at the AGM
decreased slightly to 61%, compared with 63% in 2008. As in previous
years the AGM was webcast, with the number of webcast downloads
increasing over 2008 levels. The webcast, speeches and presentations
given at the AGM are available on the BP website after the event,
together with the outcome of voting on the resolutions.

Combined Code compliance
BP complied throughout 2009 with the provisions of the Combined Code
on Corporate Governance, 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 not set by the remuneration
committee. Instead the chairman’s remuneration 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.

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 are reviewed periodically by the board and are
consistent with the requirements of the Combined Code including
principle C.2.

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.

A joint meeting of the audit and safety, ethics and environment

assurance committees in January 2010 reviewed reports from the
general auditor as part of the board’s annual review of the system of
internal control. The chairman of the board and the chairman of the
remuneration committee also attended the meeting. 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 which responds to such risks. The
reports also highlighted the results of audit work conducted during the
year and the remedial actions taken by management in response to
significant failings and weaknesses identified.

During the year, these committees engaged with 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.

On behalf of the board,

Carl-Henric Svanberg
Chairman
26 February 2010

Audit committee report
The report that follows outlines the principal responsibilities and method
of operation of the audit committee, and highlights some of the specific
activities it undertook during 2009.

The committee’s main tasks include:
(cid:129) Reviewing the effectiveness of BP’s internal financial controls and its

systems of internal control and risk management.

(cid:129) Monitoring and obtaining assurance that the management and
mitigation of significant risks of a financial nature facing BP are
appropriately addressed.

(cid:129) Monitoring the integrity of BP’s financial statements and making

The board has an established process by which the effectiveness

recommendations to the board about their adoption and publication.

of this system of internal control is reviewed as required by provision
C.2.1 of the Combined Code. This process enables the board and its
committees to consider the system of internal controls being operated
for managing significant risks, including social, environmental, safety,
ethical and compliance risks, throughout the year. The process does 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.

(cid:129) Monitoring and reviewing the effectiveness of BP’s internal audit

function.

(cid:129) Keeping under review the external auditor’s independence and

objectivity, and overseeing the effectiveness of the audit process.

(cid:129) Making recommendations to the board on the appointment,

re-appointment or removal of the external auditor and regarding
the approval of their remuneration and terms of engagement.
(cid:129) Monitoring the policy and its application on the engagement of the

external auditor to supply non-audit services to BP.

(cid:129) Reviewing the systems in place (including OpenTalk) to enable those
who work for BP to raise, in confidence, any concerns about possible
improprieties in matters of financial reporting or other financial issues
and for those matters to be appropriately investigated.

BP Annual Report and Accounts 2009
Board performance and biographies

The full list of the tasks and requirements of the audit committee
is set out in BP’s board governance principles and can be found at
www.bp.com/governance. The committee keeps these tasks under
review to determine whether they remain fit for purpose. In 2009, the
evaluation of the committee’s work was conducted as an integral part of
the external evaluation undertaken by the board. Following this
evaluation, the board concluded that the committee had fulfilled its
responsibilities as defined under the principles and that its tasks and
requirements remained appropriate.

Committee structure
The audit committee comprises four independent non-executive directors
selected to provide a wide range of financial, international and
commercial expertise appropriate to fulfil the committee’s duties. During
2009 the members, in addition to myself as chairman included George
David, Erroll Davis, Jr and Douglas Flint. The secretary of the committee
is David Pearl, deputy company secretary of BP.

The committee met 12 times in 2009, with an additional joint

meeting between the audit committee and the safety, ethics and
environment assurance committee (SEEAC) to review the general
auditor’s report on internal controls and risk management for the
previous year. Each meeting was attended by the group chief financial
officer, the deputy group chief financial officer, the group controller, the
general auditor (head of internal audit) and the chief accounting officer.
The lead partner of the external auditors (Ernst & Young) was also
present. Other senior management are invited to attend when the
business of the committee requires. During the year the committee held
private sessions, usually at the end of each full meeting, without the
presence of executive management. It also held separate sessions with
only the external auditors present and only the general auditor present.
Carl-Henric Svanberg attended two meetings of the audit

committee during the year as part of his board induction programme.

The board determined that Douglas Flint is the audit committee
member with recent and relevant financial experience as defined by the
Combined Code guidance.

The board also determined that Douglas Flint meets the

independence criteria provisions of Rule 10A-3 of the US Securities
Exchange Act of 1934 and that Mr Flint may be regarded as an audit
committee financial expert as defined in Item 16A of the Annual Report
on Form 20-F. Mr Flint is group finance director of HSBC Holdings plc and
a former member of the Accounting Standards Board and the Standards
Advisory Council of the International Accounting Standards Board.

Information and external advice
The committee receives information and reports directly from
accountable functional and business managers and from relevant external
sources. BP’s board governance principles are explicit that the board and
its committees can access independent advice and counsel when
needed on an unrestricted basis. Further support is provided by the
company secretary’s office and during 2009 external specialist legal and
regulatory advice was provided to the audit committee in the normal
course of carrying out its responsibilities by Sullivan & Cromwell LLP. In
addition to the lead partner for Ernst & Young, other external audit staff
also attended meetings where appropriate to a particular review of a
business or function.

As part of its annual evaluation process, the audit committee
looked at whether it has received sufficient and timely information to
enable it to undertake its tasks effectively. It was concluded that the
processes surrounding the reliability and timeliness of information
was robust.

The board was kept updated and informed of the audit
committee’s activities and any issues that had arisen both through the
committee minutes and also more immediately through verbal updates
given by myself as committee chair as part of the board’s regular agenda.

Training and visits
The composition of the committee was unchanged from the previous
year, so training was focused on deepening knowledge rather than
induction.

During the year the committee received briefings on financial

reporting developments, governance changes affecting audit
committees, new SEC regulations for oil and gas reserves accounting
and tax reform.

In addition to the site visits made by the board as a whole, the

audit committee visited BP’s UK trading operations for an in-depth
briefing on the fundamentals of oil and gas trading. This was
supplemented by visits by myself and the secretary of the committee to
BP’s oil and gas trading operations in Houston and Chicago. These visits
also provided an opportunity to meet staff of the independent monitor
appointed for BP’s US trading business. Two members of the committee
also joined the SEEAC visit to BP’s Projects and Operations Academies
at MIT in March. I found that visit, and the one I made to the company’s
accounting, reporting and control course, provided valuable insight into
training deep within the organization.

After l retire from the BP board at the AGM in April 2010, it has

Committee activities in 2009

been agreed that Douglas Flint will become chairman of the audit
committee.

Attendance

Sir Ian Prosser (chair)
E B Davis, Jr
D J Flint
G David

Audit
committee
meetings eligible
to attend
13
13
13
13

Audit
committee
meetings
attended
13
11
12
13

Audit committee activities
Approximate allocation of agenda time in 2009*

5% 31%

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

28%

36%

Financial reporting
Monitoring business risks
Internal controls and audit
Other agenda items

*Excludes time spent on site visits.

BP Annual Report and Accounts 2009
Board performance and biographies

Financial reporting
During the year, the committee reviewed the group’s quarterly financial
reports, the annual report and accounts, the annual review and the 20-F
before recommending their publication to the board. The committee also
discussed with management the critical accounting policies and
judgements applied in the preparation of those financial reports. This
included key assumptions regarding significant provisions, including
those for decommissioning and environmental remediation and those
used for impairment testing. (See Financial statements – Note 3 on page
124.)

Monitoring business risk
The committee reviewed reports on the inherent risks within selected
areas of BP’s businesses and supporting functions. This together with
the related controls and assurance processes is designed to manage and
mitigate such risks. On top of reviewing the major business areas and
functions within BP, this year specific focus was additionally given to
Treasury activities, including debt and liquidity management, to
information technology and to the group’s oil and gas trading activities.
The committee also reviewed risk management and investment strategy
related to pensions and other post-retirement benefits, the management
of taxation and litigation exposures and the management of BP’s
approach to insurance.

The work and scope of the executive-level Group Financial Risk

Committee (which provides assurance to the executive on the
management of BP’s financial risk) was reported to the committee
during the year by the chief financial officer.

Internal control and audit
The committee holds an annual joint meeting at the start of each year
with the safety, ethics and environment assurance committee to review
the general auditor’s report on internal controls and risk management for
the previous year. This provides important input into the board’s review of
the company’s system of internal control.

The committee’s agenda includes standing items addressing
internal control and these included in 2009 the quarterly internal audit
findings report and the annual assessment of BP’s enterprise level
controls.

Further detail on risk management and internal control in BP is

outlined in the governance section of this board performance report
above.

External auditors
The committee held two private meetings during the year with the
external auditors. These provided additional opportunity for open dialogue
and feedback from both the committee and the auditors without the
presence of BP management. At these meetings, topics covered
included the quality of interaction with executive management, the
strength of the financial team and the effectiveness of the internal audit
function. I also meet on my own with the external auditors prior to each
audit committee to discuss the forthcoming agenda.

The committee undertakes regular reviews of the performance,

effectiveness and viability of the external auditors. As part of its 2009
review, senior partners at Ernst & Young who were independent of the
audit team responsible for BP undertook an evaluation process, which
involved 22 face-to-face interviews with those BP board members and
senior management who have key interactions with the external auditors.
In addition, there was a web-based survey of 185 people representing a
cross section of BP’s global finance organization, covering both group
reporting and statutory locations. The results of the interviews and
surveys were presented to the committee by the independent senior
partners in July and the auditors were asked to develop an action plan to
address a small number of areas identified for improvement.

The external auditor followed up these findings with a report to the
committee in November which outlined its responses to these areas.
The external auditors will perform an assessment of service quality in
2010 to review the progress against the development areas outlined in
the feedback.

Fees paid to the external auditor for the year (see Financial
statements – Note 14 on page 136) were $54 million, of which 15% 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 previous
years reflecting a joint approach to raising efficiency in audit processes as
well as a reduction in tax services and services related to corporate
finance transactions. All non-audit work is subject to the committee’s
advance approval policy and is monitored on a quarterly basis.

The audit committee has considered the proposed fee structure

and audit engagement terms for 2010 and has recommended to the
board that the reappointment of the external auditors be proposed to
shareholders at the 2010 AGM.

Internal audit
The general auditor attends all committee meetings but also meets
regularly on a one-to-one basis with myself as committee chairman.
In July the general auditor met privately with the committee without the
presence of executive management or the external auditors. In reviewing
the effectiveness and quality of the internal audit, the committee also
sought input from external auditors.

The committee receives a quarterly update on the progress of

internal audit against its schedule of audits, is notified of their key
findings and tracks any material actions that are overdue or have been
rescheduled. The proposed internal audit work programme for the year
was agreed by the committee in January. The committee was satisfied
that it appropriately responded to the key risks facing the company and
that the function had sufficient staff and resources to complete its work.

Other activities
The committee receives quarterly reports from the group compliance and
ethics function which examine areas of potential non-compliance with
the company’s Code of Conduct and remedial actions that are being
undertaken. The committee also receives an annual certification report
which is signed by the group chief executive. The committee reviews
quarterly reports on financial issues and concerns that have been
raised through the group-wide employee concerns programme, OpenTalk
and quarterly updates from internal audit on instances of actual or
potential fraud.

Committee evaluation
The committee conducts an annual review of its performance and
effectiveness. For 2009, this review was facilitated externally as part of
the wider review of the board and its committees. The external facilitator
undertook one-to-one interviews with each committee member, plus
those who provide support to the committee and the external auditor.
The review concluded that the audit committee was effective in carrying
out its duties.

On behalf of the audit committee,

Sir Ian Prosser
Audit committee chairman

BP Annual Report and Accounts 2009
Board performance and biographies

Safety, ethics and environment assurance committee report
This report describes the role of the safety, ethics and environment
assurance committee (SEEAC) and notes particular activities undertaken
in 2009.

The role of the SEEAC requires us to look at the processes
adopted by the executive management to identify and mitigate significant
non-financial risks and receive assurance that they are appropriate in
design and effective in implementation. Following the tragic incident at
the Texas City refinery in 2005 the committee has observed a number of
key developments, including: the establishment of a safety & operations
(S&O) function with the highest calibre of staff; development of a group-
wide operating management system (OMS) which is being progressively
adopted by all operating sites; the establishment of training programmes
in conjunction with MIT that are teaching project management and
operational excellence; the dissemination of standard engineering
practices throughout the group; and the formation of a highly
experienced S&O audit team formed to assess the safety and efficiency
of operations and recommend improvements. Throughout this time
the group chief executive has made safety the number one priority.
The committee’s focus in S&O will now be to monitor how these
advances are interpreted into the culture of day-to-day operations.

As in all years the committee has not focused solely on S&O. Our main
tasks include:
(cid:129) Monitoring and obtaining assurance that the management or
mitigation of significant BP risks of a non-financial nature is
appropriately addressed.

(cid:129) Reviewing material to be placed before shareholders which address
BP’s environmental, safety and ethical performance and making
recommendations to the board about their adoption and publication.

(cid:129) Reviewing BP’s internal control systems as they relate to non-

financial risk.

(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.

The full list of the tasks and requirements of the SEEAC are set out in
BP’s board governance principles, at www.bp.com/governance. The
committee reviews its tasks and processes on a regular basis and seeks
to learn from the challenges and issues of the previous year when setting
its future agenda. Following the committee evaluation in 2009, which
was an integral part of the external evaluation undertaken by the board,
it was concluded that the SEEAC’s tasks and requirements remained
appropriate.

Committee structure
The SEEAC comprises four non-executive directors. Sir Tom McKillop left
the committee when he retired from the board in April. Erroll Davis, Jr
joined the SEEAC in May 2009 and will continue until his retirement in
April 2010. Paul Anderson joined in February 2010. Both bring broad
experience of the international energy industry. The committee
membership is completed by Antony Burgmans, Cynthia Carroll and
myself as chairman. Support is provided by the committee secretary,
David Pearl, BP’s deputy company secretary.

In addition to its non-executive members, the committee invites
the lead partner of the external auditors, the BP general auditor (head of
internal audit) and the group head of safety and operations to attend each
meeting. Meetings are also attended by relevant senior executive
managers. Tony Hayward was the principal executive liaison with the
committee in 2009 and led the management reporting at all seven
meetings of the SEEAC. The chief executives of Refining and Marketing,
and Exploration and Production, Iain Conn and Andy Inglis, attended to
report on topics specific to their businesses. As outlined in the report of
the audit committee, one of SEEAC’s meetings each year is held jointly
with the audit committee to review BP’s system of internal control and
discuss the forward programme of the internal audit function.

The committee holds private sessions without the presence of

executive management at the end of each meeting. This provides an
opportunity to reflect on the effectiveness of each meeting and confirm
actions to be pursued. Updating the wider board on the committee’s
activities and key issues is achieved through the circulation of minutes
and through the verbal reports I provide as committee chairman to the
board meetings.

Attendance

Sir William Castell (chair)
A Burgmans
C B Carroll
E B Davis, Jr
Sir Tom McKillop

SEEAC meetings
eligible to attend
7
7
7
4
3

SEEAC meetings
attended
7
7
5
3
3

Information and external advice
SEEAC receives information from external and internal sources, including
directly from the business segments and supporting functions such as
group compliance and ethics, safety and operations and internal audit.
During 2009 the committee’s principal external input has been provided
by Duane Wilson, the independent expert (see the Independent expert
section on the following page). SEEAC can access any other independent
advice and counsel if it requires, on an unrestricted basis.

Training and visits
The committee participated in the board’s visit to the US west coast
fuels value chain in September which enabled members to discuss
safety, operational integrity and environmental matters first hand at a
marine terminal, a refinery, an inland distribution terminal and a retail site.

The committee also visited the Projects and Operations

Academies at MIT (described in the board report above), and participated
in working sessions with course participants. In October the committee
secretary and I visited the company’s international centre for business
and technology at Sunbury. We were briefed by the group head of
engineering and group head of operations and their teams on OMS
and the standard operating and engineering practices applied within
the businesses.

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

BP Annual Report and Accounts 2009
Board performance and biographies

Committee activities in 2009

SEEAC 2009 activities
Approximate allocation of agenda time*

51%

12%

13%

24%

Safety, operations and environment, including
reports from the independent expert
Regional and functional reports
Internal audit and compliance and ethics
Other topics

*Excludes time spent on site visits.

Safety and operations
The committee received regular reports from the group operations risk
committee (GORC) including data on company-wide safety and
operational integrity performance, and was briefed on significant
compliance issues including those arising with OSHA and other US
regulatory agencies. We continued to monitor progress made in
developing robust leading and lagging indicators in process safety. Other
topics covered by the GORC and reviewed with the committee included
improving corporate learning from safety incidents, strengthening the
group-wide safety culture, and capability training programmes across the
company. The committee also received a detailed briefing on the work of
the safety and operations audit function.

North Sea helicopter incident
Following the tragic accident in April when a helicopter operated by
Bond Offshore Helicopters carrying BP sub-contractors came down in
the North Sea, Andy Inglis reviewed with the committee BP’s response
and the information emerging in interim reports from the UK Air Accident
Investigation Branch (AAIB). Although the AAIB is yet to publish its final
report, it is our understanding that the accident was caused by a gearbox
failure. The impact of such an incident was deeply felt by the committee.

Independent expert
The committee spent considerable time with Mr Duane Wilson who was
appointed in 2007 by the board as an independent expert to provide an
objective assessment of BP’s progress in implementing the
recommendations of the BP US Refineries Independent Safety Review
Panel (aimed at improving process safety performance at BP’s five US
refineries). Mr Wilson, who was previously a member of the panel and is
independently funded through the company secretary’s office, reported
to us at five of our meetings. The committee was advised of evident
progress against defined programmes to improve process safety
performance at our US refineries. However it was also recognized that
the journey requires investment not only in engineering but in sustaining
cultural change and this will take many years to complete.

Mr Wilson’s updates to the committee reflected the workplan

which we agree with him annually and the outcomes of his visits to BP’s

US refining sites. In March 2009, he published his second annual report
which assessed BP’s progress against the 10 panel recommendations.
Mr Wilson concluded that good progress was being made, in particular
that BP’s ‘tone at the top’ was reinforcing valuable positive messages on
the importance of process safety, that the panel’s recommendations had
become embedded in the planning and resource allocation processes at
all US refineries and that BP’s Safety and Operations audit programme
had matured into a comprehensive, high-quality programme. Areas
where Mr Wilson believed more attention was warranted included
further reduction in overtime, for the small percentage of individuals
where this practice remained, in order to reduce the potential for fatigue,
improvements to the investigation reports associated with incident
investigations and development of comprehensive plans for safety
instrumented systems (SIS) for the refineries in the US.

Mr Wilson’s report was made available on BP’s website.

Regional and functional reports
In the past year we have reviewed the company’s approach to corporate
social responsibility by taking BP’s operations in Azerbaijan as a case
study.

With BP operating one of the largest tanker fleets in the world we

have sought and received assurance from its chief executive regarding
fleet integrity and operating standards.

During 2009 we also reviewed reports on the identification and

management of the group’s security risks and the progress made in HSE
at TNK-BP.

Internal audit and compliance and ethics
The committee received and discussed quarterly reports from the group
compliance and ethics officer. Each year we review compliance with the
company’s code of conduct and the attention devoted to enforcing a
standard of acceptable behaviour on a global basis. The group chief
executive’s own certification is provided to the committee. The
compliance and ethics officer also reports to the committee on the
operation of the employee concerns programme OpenTalk and the
work of the US ombudsman. We are looking for further improvement
in OpenTalk to be made in the coming year.

We also reviewed reports from internal audit addressing the

programme of audits undertaken throughout the year, key audit findings
and management’s responses. These findings help focus our agendas to
areas that require more attention. The committee was also briefed on the
enhanced co-ordination between internal audit and other audit functions
in the group, including Safety and Operations.

Other topics
During the year the committee was regularly updated on the company’s
plans in response to a potential pandemic and in May received a report
on health risk management in the workplace. In October the committee
reviewed risk evaluation and mitigation related to potential loss of
containment in Refining and Marketing’s logistics operations.

The committee believes, given the scale and diversity of this

company and recognizing that it operates primarily in hydrocarbon
businesses, that it receives information in sufficient depth to provide
overall assurance of the management’s commitment to achieve world
class levels of safe, reliable and compliant operations.

On behalf of the safety, ethics and environment assurance committee,

Sir William Castell
SEEAC chairman

BP Annual Report and Accounts 2009
Board performance and biographies

Remuneration committee report
Structure of the committee
Members of the remuneration committee during the year were
Dr DeAnne Julius (chairman) and Sir Ian Prosser. Sir Tom McKillop
stepped down from the committee when he retired from the board in
April 2009 and Erroll Davis, Jr left the committee at the end of April 2009.
Antony Burgmans and George David joined the committee in May 2009.
The chairman of the board attends meetings of the committee and
Carl-Henric Svanberg attended meetings prior to becoming chairman on
1 January 2010.

Attendance
The committee met eight times during 2009:

Nomination committee report
This has been a very active year for the committee which has met
15 times.

The main tasks of the committee are:
(cid:129)

Identifying, evaluating and recommending candidates for the
appointment or re-appointment as directors.
Identifying, evaluating and recommending candidates for
appointment as company secretary.

(cid:129)

(cid:129) Keeping under review the mix of knowledge, skills and experience of

the board to ensure an orderly succession of directors.

(cid:129) Reviewing the outside directorships and broader commitments of the

non-executive directors.

Dr D S Julius (Chair)
A Burgmans
G David
E B Davis, Jr
Sir Tom McKillop
Sir Ian Prosser

Remuneration committee
meetings eligible to attend
8
6
6
2
2
8

Remuneration committee
meetings attended
8
5
6
2
2
8

Committee structure
The committee is comprised of the chairman and the chairs of the SEEAC,
audit and remuneration committees. During the year, Peter Sutherland,
Sir William Castell, Sir Ian Prosser and Dr DeAnne Julius were members.
After his appointment on 1 September, Carl-Henric Svanberg has attended
meetings of the committee. Dr Hayward has also attended certain
meetings of the committee during the year.

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 and
executive directors and reports on these to shareholders. It also
makes recommendations to the board regarding the chairman’s
remuneration. 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 2010 AGM.

On behalf of the remuneration committee,

Dr DeAnne Julius
Remuneration committee chairman

Attendance

P D Sutherland
Sir William Castell
Sir Ian Prosser
D S Julius

Nomination committee meetings
eligible to attend
15
15
15
15

Nomination committee
meetings attended
12
14
15
14

The work of the committee during the year has been focused on
two areas:

1. The completion of the process for the selection of a successor to

Peter Sutherland as chairman.
Sir Ian Prosser chaired the committee in this activity. After an
intensive process involving two external search consultants,
Carl-Henric Svanberg was selected as the next chairman in June
2009. He became a non-executive director on 1 September 2009 and
took the chair on 1 January 2010.

2. The continuing refreshment of the board.

During the year the committee has reviewed the skills needed for
the board against the competences and experience of the current
directors. Sir Tom McKillop retired from the board in April and Sir Ian
Prosser and Erroll Davis, Jr will retire at the next AGM. In the second
half of the year, the focus has been on refreshing the board and
identifying a number of candidates available to join the board in the
short and medium term. Two non-executive director appointments
were made in early 2010 following this process: Paul Anderson in
February and Ian Davis in March to take effect in April. This work will
continue as Dr Julius retires in 2011.

On behalf of the nomination committee,

Carl-Henric Svanberg
Chairman

B
o
a
r
d
p
e
r
f
o
r
m
a
n
c
e
a
n
d
b
o
g
r
a
p
h
i
e
s

BP Annual Report and Accounts 2009
Board performance and biographies

Chairman’s committee report
The committee met five times in 2009.

Committee structure
The chairman’s committee consists of the chairman and all the non-
executive directors.

Attendance

P D Sutherland
Sir Ian Prosser
A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
D S Julius
Sir Tom McKillop
C-H Svanberg

Chairman’s committee meetings
eligible to attend
5
5
5
5
5
5
5
5
5
1
2

Chairman’s committee
meetings attended
3
5
5
5
4
5
5
5
5
1
2

The main tasks of the committee are:
(cid:129) Evaluating the performance and effectiveness of the group chief

executive.

(cid:129) Reviewing the structure and effectiveness of the business

organization of BP.

(cid:129) 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.

(cid:129) Determining any other matter which is appropriate to be considered

by all of the non-executive directors.

(cid:129) Opining on any matter referred to it by the chairman of any
committee comprised solely of non-executive directors.

Committee activities
During the year, the committee reviewed:
(cid:129) The performance of the group chief executive and with him, the

performance of the other executive directors.

(cid:129) The performance of the chairman.
(cid:129) The succession plan for the executive team and any development issues.
Dr Hayward attended a number of meetings of the committee and
considered with the committee his response to the strategic and
operational challenges facing the group and their implication for the
evaluation of the senior management team. Corporate culture and ‘tone
from the top’ also remain an area of active discussion.

On behalf of the chairman’s committee,

Carl-Henric Svanberg
Chairman

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 Ian Prosser
Directors leaving the board
Sir Tom McKillop
P D Sutherland

Directors joining the board
P Anderson
R W Dudley
C-H Svanberg

At 31 Dec 2009
10,156
10,500b
82,500
293,216a
39,000b
76,497b
15,000

Change from
31 Dec 2009
At 1 Jan 2009 to 18 Feb 2010
–
–
–
56,604
–
–
–
59,886
87,424
49,476
–
–

10,000
–
82,500
240,789a
9,000b
73,185b
15,000
1,291,643c 1,214,330c
488,459
226,175d
15,000
16,301
At 1 Jan 2009
20,000
30,906

535,383
259,163d
15,000
16,301
At resignation/retirement
20,000e
30,906f

At 31 Dec 2009 On appointment

–
276,846
–

6,000b g
269,746b h

–i

Change from
31 Dec 2009
to 18 Feb 2010
–
–
750,000

a Includes 47,320 shares held as ADSs at 31 December 2009 and 44,158 shares held as
ADSs at 1 January 2009.
b Held as ADSs.
c Held as ADSs, except for 94 shares held as ordinary shares.
d Includes 34,962 shares held as ADSs.
e On retirement at 16 April 2009.
f On retirement at 31 December 2009.
g On appointment at 1 February 2010.
h On appointment at 6 April 2009.
i On appointment at 1 September 2009.

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 as at the applicable dates.

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

82 Part 1 Summary

84 Part 2 Executive directors’

remuneration

91 Part 3 Non-executive directors’

remuneration

D
i
r
e
c
t
o
r
s
’

r
e
m
u
n
e
r
a
t
i
o
n
r
e
p
o
r
t

BP Annual Report and Accounts 2009

Directors’ remuneration report

Part 1 Summary

In a volatile year for the world economy, the BP executive team produced
excellent results. While salaries were frozen for all directors in 2009, the
variable performance-related pay reflected the impressive achievements
of the year and the turnaround of performance over the past three years.
The details of executive director remuneration are set out in the table on
the opposite page.

The remuneration committee sets the measures and targets for

the annual bonus element of variable pay at the beginning of the year,
based on the strategy and annual plan accepted by the board. The
strategy is built around safety, people and performance. The measures
included key safety measures (15% of bonus), staff numbers and survey
results to reflect the people priorities (15%) and a set of financial and
operational targets to measure performance (70%). Nearly all targets
were exceeded, some substantially, with particularly strong performance
on cost reduction, exploration success, production start-ups and refining
performance. This overall excellent performance was also reflected in the
market, where BP shareholders recorded the highest total shareholder
return (TSR) of all the oil majors for the year.

The other element of variable pay is awarded in shares based on
BP’s performance over three years, compared with the other oil majors.
Following the process approved by shareholders in the Executive
Directors’ Incentive Plan (EDIP), the committee first reviews the three-
year TSR of BP compared with its peers and then considers a set of
underlying business metrics, again in comparison with peers. When there
is a difference between the two comparisons, the committee decides
which level of vesting best represents BP’s relative three-year
performance. This year the TSR result was tightly clustered and sensitive
to calculation methodology. For example, based on a three-month
averaging of endpoints, BP came fourth whereas on a one-month
averaging it came second. On underlying metrics, BP ranked first on four
of the six reviewed (production growth, earnings per share growth,
change in return on average capital employed and free cash flow) and
second or third on the others (Refining and Marketing earnings per barrel

and net income growth). Following the process set out in the EDIP, the
committee judged BP to be tied for third place and thus shared the
vesting outcome for third and fourth place to result in a vesting of 17.5%
of the maximum award.

During the year the committee conducted a full review of BP’s

remuneration policy, and particularly the EDIP, which is being put before
shareholders for renewal this year. We consulted with a number of our
shareholders, reviewed the actual experience with applying EDIP rules
over the past five years and considered recent developments in the
marketplace. Overall we concluded that the basic structure of the EDIP
remains appropriate, but that some rebalancing of elements is warranted.
The key change we propose is to require a portion of the annual bonus to
be deferred, paid in shares and matched after three years subject to an
assessment of safety and environmental sustainability over the three-
year period. This change would place more focus on the long term,
highlight the importance of safety and build a larger equity stake for
executives that we believe aligns their interests well with shareholders.
To balance this additional bonus element, we propose to reduce the
maximum award of performance shares in the renewed EDIP so as to
maintain the current quantum of total remuneration. These changes are
summarized in the table below.

It has been an excellent year for BP and its shareholders. In
determining annual and long-term awards, the committee has recognized
the very real achievements of the executive team. For the future, we
believe our revised EDIP provides a sound framework with which to
competitively reward our top executives for continued success in this
long-term business.

Dr DeAnne S Julius
Chairman, Remuneration Committee
26 February 2010

Summary of future remuneration components
Salary

(cid:129) Normally reviewed mid-year (no increases in 2009). Current salaries: Dr Hayward £1,045,000, Mr Conn £690,000,

Mr Dudley $1,000,000, Dr Grote $1,380,000, Mr Inglis £690,000.

Bonus

(cid:129) On-target bonus of 150% of salary and maximum of 225% of salary based on performance relative to targets set at

Deferred bonus and
match

start of year relating to financial and operational metrics.

(cid:129) One-third of actual bonus awarded as shares with three-year deferral, with ability to voluntarily defer an additional

one-third.

(cid:129) All deferred shares matched one-for-one, both subject to an assessment of safety and environmental performance over

the three-year period.

Performance shares

(cid:129) Following EDIP renewal, award of shares of up to 5.5 times salary for group chief executive, 4.75 times for the chief

executive of Exploration and Production, and 4 times for other executive directors.

(cid:129) Vesting after three years based on performance relative to other oil majors.
(cid:129) Three-year retention period after vesting before release of shares.
(cid:129) Final salary scheme appropriate to home country of executive.

Pension

BP Annual Report and Accounts 2009
Directors’ remuneration report

Summary of remuneration of executive directors in 2009a

Annual remuneration

Long-term remuneration

Share element of EDIP

2006-2008 plan
(vested in Feb 2009)

2007-2009 plan
(vested in Feb 2010)

2009-2011
plan

Salaryb
(thousand)
2009
£1,045
£690
$750
$1,380
£690

2008

Annual
performance bonus
(thousand)
2009
£1,496 £2,090
£871 £1,104
n/a $1,125
$1,742 $2,070
£1,173 £1,311

2008
£998
£670
n/a
$1,340
£670

Dr A B Hayward
I C Conn
R W Dudleyg h
Dr B E Groteg
A G Inglis

Non-cash benefits and
other emoluments
(thousand)
2009
£23
£46
$304i
$8

2008
£15
£45
n/a
$8
£212

2008
£2,509
£1,586
n/a
$3,090
£216j i £2,055

Total
(thousand)
2009
£3,158
£1,840
$2,179
$3,458
£2,217

Actualc
Valued
shares
vested (thousand)

Actualc
shares
vested (thousand)
£852
£551
n/a
$933
£483

Potential
maximum
Valuee performance
sharesf
1,182,540
780,816
539,634
992,928
780,816

£336 147,985
£336 95,697
n/a
$603 101,502e
£279 83,859

n/a

66,136
66,136
n/a
80,231
54,994

Amounts shown are in the currency received by executive directors. Annual bonuses are shown in the year they were earned.

a This information has been subject to audit.
b Figures show the total salary received during the calendar year. The last salary increase was in July 2008.
c Includes shares representing reinvested dividends received on the shares that vested at the end of the performance period.
d Based on market price on vesting date (£5.08 per share/$45.13 per ADS).
e Based on market price on vesting date (£5.76 per share/$55.17 per ADS).
f Maximum potential shares that could vest at the end of the three-year period depending on performance.
g Dr Grote and Mr Dudley hold shares in the form of ADSs. The above number reflects calculated equivalent in ordinary shares.
h Reflects remuneration received by Mr Dudley since appointment as executive director on 6 April 2009.
i This amount includes costs of London accommodation and any tax liability thereon.
j In addition to this amount, under a tax equalization arrangement, BP discharged a US tax liability arising from the participation by Mr Inglis in the UK pension scheme amounting to $90,314.

Historical TSR performance

FTSE 100
BP

250

200

150

100

g
n
d
o
h

0
0
1
£

a
c
i
t
e
h
t
o
p
y
h

f
o

e
u
a
V

Remuneration of non-executive directors in 2009a

P D Sutherland
A Burgmans
Sir William Castell
C B Carroll
G Davidb
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Ian Prosser
C-H Svanbergc
Directors leaving the board in 2009

Sir Tom McKillop

£ thousand

2009
600
93
115
90
118
105
85
105
165
30

2008
600
90
108
93
100
105
90
110
170
n/a

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 £141.75 and
£134.58 respectively.

a This information has been subject to audit.
b Also received £4,166 for serving as a member of BP’s technology advisory committee.
c Appointed on 1 September 2009.

While fees were held at 2008 levels, in 2009 actual fees paid to
non-executive directors were affected by changes in committee
membership and the number of transatlantic meetings for which an
attendance allowance was paid.

In 2009 the chairman reviewed non-executive director

remuneration taking into account the review completed in 2008.
The chairman made a recommendation to the board (which was
agreed) to maintain the 2008 structure until a further review in 2010.

D
i
r
e
c
t
o
r
s
’

r
e
m
u
n
e
r
a
t
i
o
n
r
e
p
o
r
t

BP Annual Report and Accounts 2009
Directors’ remuneration report

Part 2 Executive directors’ remuneration

2009 remuneration

Salary
Executive directors have had no salary increases since July 2008, with
the exception of Mr Dudley who was appointed to the board in April
2009. Dr Hayward’s salary remains £1,045,000, Mr Conn’s £690,000,
Mr Dudley’s $1,000,000, Dr Grote’s $1,380,000, and Mr Inglis’s
£690,000.

Annual bonus
The annual bonus awards for 2009 reflect the excellent performance
achieved across the business and are set out in the table on page 83.

Performance measures and targets were set at the beginning of

the year based on the group’s annual plan. Group results formed the
basis for Dr Hayward’s, Mr Dudley’s and Dr Grote’s annual bonus and
were weighted 70% on financial and operating results (including profit,
cash flow, cash costs, production, reserves replacement, Refining and
Marketing profitability, refining availability, and installed wind capacity),
15% on safety (both metrics and progress on plans), and 15% on people
(including organizational changes and employee attitudes). Mr Conn’s and
Mr Inglis’s annual bonuses were based 50% on the group results as
above, and 50% on their respective business unit results (also a mix of
financial, operating, safety and people measures). The target level of
bonus for executive directors was 120% of salary with committee
judgement to award up to 150% for exceeding targets and above that
level to recognize exceptional performance.

Targets were exceeded on virtually all key measures during 2009,

a number by a substantial margin and resulting in bonuses averaging
170% of salary.

All key safety and operating metrics (including days away from
work case frequency (DAFWCF), recordable injury frequency (RIF), oil
spills, loss of primary containment, and process safety high potential
incidents) showed good results and significant improvements in all cases
from 2008. Implementation of the operating management system (OMS)
progressed ahead of plan and is now successfully installed at
70 operating entities including all major downstream sites. People
metrics were also exceeded. Major organizational restructuring was
completed including reducing the number of group leaders and senior
level leaders in excess of plan. The employee survey results showed
significant improvement in key aspects such as safety and compliance
and performance culture, as well as overall employee satisfaction.

Exceptional results were achieved on financial and operating

measures. Replacement cost profit was some $5 billion above plan after
adjusting for the oil price and other environmental factors. Cash costs
were reduced substantially. Production increased by more than 4% while
unit production costs reduced by 12%. The reserves replacement ratio
was 129%, continuing an industry-leading peformance. Refining and
Marketing cash costs were reduced by 15%, and refining availability
increased to 94%. Refining and Marketing profitability exceeded plan
after adjusting for a dramatically weaker industry environment.
Exploration and Production achieved major project start-ups in the Gulf of
Mexico, Indonesia and Trinidad & Tobago. Exploration successes included
the Tiber discovery in the Gulf of Mexico and new access for future
growth was secured in Iraq, Indonesia and Jordan as well as new
acreage in the Gulf of Mexico.

The excellent results achieved during 2009 reflect the strong

leadership of the executive team and their continuing focus on safety,
people and performance.

2007-2009 share element
This momentum of improvement is also apparent over the three-year
performance period covered by the 2007-2009 share element under the
EDIP. Performance for the share element is assessed relative to the
other oil majors – ExxonMobil, Shell, Total and Chevron. The committee
follows the assessment process approved by shareholders in
determining the vesting of shares that had been awarded at the start of
2007. It first compares the total shareholder return (TSR) of each of the
majors and then reviews underlying performance metrics across the
same group. Given the small peer group, similarity of their businesses,
and general imperfections in measurement, there will be occasions when
results of some or all of the companies are tightly clustered. In such
circumstances, a small difference in TSR performance or calculation
methodology could produce a large, and inappropriate, difference in
vesting level. To counter this the committee has the obligation to review
both relative TSR and underlying performance to ensure a balanced
judgement is made. Such was the case with regard to the 2007-2009
metrics.

The TSR result was tightly clustered for 2007-2009 with BP

coming fourth based on our established methodology but very close to
third place. As required by the plan, the committee reviewed a number of
financial and operating metrics to assess relative underlying
performance. These included the average change over the three years of
EPS, ROACE, free cash flow, net income, production growth and Refining
and Marketing profitability. The review of underlying performance showed
BP in a strong relative position. BP came first on change in EPS growth,
ROACE, free cash flow and production, on adjusted net income BP
ranked second and on Refining and Marketing profitability it came third.
Based on the full review and combining both the TSR and underlying
analysis, the committee judged BP to be tied for third place and thus
shared the vesting outcome for third and fourth place (35% and 0%
respectively) as set out in the plan rules. The resulting 17.5% vesting for
eligible participants is also shown in the table on page 83.

Remuneration policy review

During 2009 the committee carried out a comprehensive review of its
remuneration policy for executive directors. The review covered all
components of remuneration, both fixed and variable, short term and
long term. It focused especially on the EDIP which provides the
framework for long-term, variable pay. The current EDIP was approved by
shareholders in 2005 and will expire in April 2010, when a renewal will be
put to shareholder vote. As part of its review the committee met with
key shareholders to assess the current pay structure and test areas for
change.

The basic principles that guide remuneration policy for executive

directors in BP formed the starting point for the review. These include:
(cid:129) A substantial portion of executive remuneration should be linked to
success in implementing the company’s business strategy to
maximize long-term shareholder value.

(cid:129) Executives should develop and be required to hold a significant

shareholding as this represents the best way to align their interests
with those of shareholders.

(cid:129) The structure of pay should reflect the long-term nature of BP’s
business and the significance of safety and environmental risks.
(cid:129) Performance conditions for variable pay should be set independently
by the committee at the outset of each year and assessed by the
committee both quantitatively and qualitatively at the end of each
performance period.

(cid:129) Performance assessment should take into account material changes

in the market environment (predominantly oil prices) and BP’s
competitive position (primarily vis-à-vis other oil majors).

BP Annual Report and Accounts 2009
Directors’ remuneration report

(cid:129) Salaries should be reviewed annually, in the context of the total

quantum of pay, and taking into account both external market and
internal company conditions.

(cid:129) The remuneration committee will actively seek to understand
shareholder preferences and be as transparent as possible in
explaining its remuneration policy and practices.

The committee’s review concluded that the basic structure of fixed and
variable pay remains appropriate. The EDIP gives the committee a range
of tools, within an overall framework approved by shareholders, with
which to construct remuneration packages that are tailored to the
company’s business objectives each year and are calibrated to achieve
the desired linkage between performance and pay.

While the basic structure of the EDIP remains appropriate, the

committee concluded that three of its features should be revised. First,
with respect to the annual bonus, a new element should be added to
require one-third of the bonus to be deferred for three years and paid in
shares rather than cash. At the end of this three-year period, subject to
an assessment of safety and environmental sustainability, the deferred
bonus would be matched with additional shares on a one-for-one basis.
Executives would also have the opportunity to defer an additional one-
third of their annual bonus on this basis.

Second, with respect to the long-term performance share
element, the maximum number of shares should be reduced to offset
the more generous annual bonus and deferred element in the revised
EDIP and thereby keep the total quantum of remuneration roughly
constant.

Third, the current EDIP includes a provision for discretionary cash
payments which has never been used. This provision will be omitted from
the revised EDIP.

Detail of elements of remuneration
The majority of total remuneration is long term and varies with
performance, with the largest elements share based, further aligning
interests with shareholders.

Salary
The committee normally reviews salaries annually, taking into account
other large Europe-based global companies as well as relevant US
companies. These groups are each defined and analysed by the
committee’s independent remuneration advisers.

Annual bonus
The committee sets bonus targets and levels of eligibility each year for all
executive directors. For the 2010 bonus, the committee has adjusted
bonus levels and structure of payment, as part of the wider rebalancing
of the remuneration mix.

The on-target bonus level for 2010 is 150% of salary with the

maximum of 225% of salary. This was changed from the target for 2009
referred to earlier.

Group results will be determined based on six metrics comprising

safety, people and four performance-related measures including:

(cid:129) Group replacement cost profits.
(cid:129) Cash costs.
(cid:129) Production and reserves replacement.
(cid:129) Refining and Marketing income per barrel.

Dr Hayward’s and Mr Dudley’s bonus will be based on group results.

Mr Conn, Dr Grote and Mr Inglis will have 70% of their bonus based
on the above group results and 30% on the results of their respective
business segments as measured by key performance 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 Finance, they focus on specific
business and cost targets. For Refining and Marketing, they include
refining availability, earnings and cash costs, as well as safety and
work simplification.

The 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.

The committee can decide to reduce bonuses where this is

warranted and, in exceptional circumstances, bonuses can be reduced
to zero.

Deferred bonus
One-third of the annual bonus will be deferred into shares for three years
and matched by the company on a one-for-one basis. Both deferred and
matched shares will vest contingent on an assessment of safety and
environmental sustainability over the three-year deferral period. If the
committee assesses that there has been a material deterioration in
safety and environmental metrics, or there have been major incidents
revealing underlying weaknesses in safety and environmental
management, then it may conclude that shares should vest in part, or not
at all. In reaching its conclusion, the committee will obtain advice from
the safety, ethics and environment assurance committee (SEEAC).

Executive directors may voluntarily defer a further one-third of
their annual bonus into shares, which will be capable of vesting, and
will qualify for matching, on the same basis as set out above.

Where shares vest, the executive director will receive additional

shares representing the value of the reinvested dividends.

This structure of deferred bonuses, paid in shares, places
increased focus on long-term alignment and reinforces the critical
importance of maintaining high safety and environmental standards.

Performance shares
The share element of the EDIP has been a feature of the plan, with some
modifications, since its inception in 2000. To reflect the introduction of
the deferred matching element, the maximum number of shares that can
be awarded will be reduced from 7.5 times salary to 5.5 times salary for
the group chief executive and from 5.5 times salary to 4.75 times salary
for the chief executive of Exploration and Production, and to four times
salary for the other executive directors.

Performance shares will only vest to the extent that a
performance condition is met, as described below. In addition, the
committee will have an overriding discretion, in exceptional
circumstances (relating to either the company or a particular
participant) to reduce the number of shares that vest (or to provide 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, which is designed to ensure their interests are aligned with
those of shareholders.

Where shares vest, the executive director will receive additional

shares representing the value of the reinvested dividends.

The committee’s policy, reflected in the EDIP, continues to be
that each executive director builds a significant personal shareholding,
with a target of shares equivalent in value to five times salary, within a
reasonable time from appointment as an executive director.

D
i
r
e
c
t
o
r
s
’

r
e
m
u
n
e
r
a
t
i
o
n
r
e
p
o
r
t

BP Annual Report and Accounts 2009
Directors’ remuneration report

Performance conditions
Performance conditions for the 2010-12 share element will continue the
structure used in the 2009-2011 plan.

Vesting of shares will be based, as to one-third, on BP’s TSR

compared with other oil majors over a three-year period and as to
two-thirds, on a balanced scorecard of underlying performance. BP’s
TSR performance will be compared with the other oil majors –
ExxonMobil, Shell, Total, ConocoPhillips and Chevron. This comparison
group can be altered if circumstances change, for example, if there is
significant consolidation or change in the industry. While this comparison
group is narrow, it is used by both management and shareholders in
assessing BP’s comparative TSR performance.

The inclusion of relative TSR is an appropriate way of measuring

performance for the purposes of a long-term incentive for executive
directors as it reflects the creation of shareholder value while minimizing
the impact of sector specific events such as the oil price. TSR is
calculated as share price performance over the relevant period, assuming
dividends are reinvested. All share prices are averaged over the three-
month period before the beginning and end of the performance period.
They are measured in US dollars.

Pensions
Executive directors are eligible to participate in the appropriate pension
schemes applying in their home countries. Details are set out in the table
on page 87.

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.

The balanced scorecard will be assessed by the committee on

Although Mr Inglis is, like other UK directors, a member of the BP

three measures reflecting key priorities in BP’s strategy, production
growth, Refining and Marketing profitability and group underlying net
income. Both production growth and Refining and Marketing profitability
are key strategic objectives for the group and key drivers of value for
shareholders. Group underlying net income acts as a holistic measure of
success reflecting revenues, costs and complexity as well as safe and
reliable operations. The three underlying measures will be averaged to
form the balanced scorecard component.

All the above measures will be compared with the 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. 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. 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.

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 may exercise its discretion, in a reasonable and informed
manner, to adjust vesting levels upwards or downwards if it concludes
the 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.

In exceptional recruitment circumstances, the committee may

award performance shares that are subject to a requirement of continued
service over a specified period, rather than a corporate performance
condition.

Pension Scheme, he is currently based in Houston, US. His participation
in the BP Pension Scheme gives rise to a US tax liability. During 2009, the
committee approved the discharge of this US tax liability under a tax
equalization arrangement amounting to $90,314.

US directors
Dr Grote and Mr Dudley participate 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 and Mr Dudley are eligible to participate under

the supplemental plan. Their pension accrual for 2009, 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 applying in
their home countries. Benefits in kind are not pensionable. BP provides
accommodation in London for both Mr Inglis and Mr Dudley.

BP Annual Report and Accounts 2009
Directors’ remuneration report

Pensionsa

Dr A B Hayward (UK)
I C Conn (UK)
R W Dudley (US)d
Dr B E Grote (US)
A G Inglis (UK)

Service at
31 Dec 2009
28 years
24 years
30 years
30 years
29 years

Accrued pension
entitlement
at 31 Dec 2009
£584
£276
$406
$1,011
£337

Additional pension
earned during the
year ended
31 Dec 2009b
£23
£12
$106
$143
£12

Transfer value of
accrued benefitc
at 31 Dec 2008 (A)
£8,045
£3,161
$2,994
$11,220
£4,399

Transfer value of
accrued benefitc
at 31 Dec 2009 (B)
£10,840
£4,508
$4,353
$12,047
£6,000

Amount of B-A less
contributions made by
the director in 2009
£2,743
£1,347
$1,358
$827
£1,601

thousand

a This information has been subject to audit.
b Additional pension earned during the year includes an inflation increase of 0.9% for UK directors and 0% for US directors.
c Transfer values have been calculated in accordance with guidance issued by the actuarial profession.
d Figures represent period after joining the board on 6 April 2009.

D
i
r
e
c
t
o
r
s
’

r
e
m
u
n
e
r
a
t
i
o
n
r
e
p
o
r
t

BP Annual Report and Accounts 2009
Directors’ remuneration report

Performance share element of EDIPa

Performance
period
2006-2008
2007-2009
2008-2010
2009-2011
2006-2008
2007-2009
2008-2010
2008-2011d
2008-2013d
2009-2011
2009-2011
2006-2008
2007-2009
2008-2010
2009-2011
2006-2008
2007-2009
2008-2010
2008-2011d
2008-2013d
2009-2011

Date of
award of
performance
shares
16 Feb 2006
06 Mar 2007
13 Feb 2008
11 Feb 2009
16 Feb 2006
06 Mar 2007
13 Feb 2008
13 Feb 2008
13 Feb 2008
11 Feb 2009
6 May 2009
16 Feb 2006
06 Mar 2007
13 Feb 2008
11 Feb 2009
27 Mar 2006
06 Mar 2007
13 Feb 2008
13 Feb 2008
13 Feb 2008
11 Feb 2009

Market price
of each share
at date of award
of performance
shares
£
6.54
5.12
5.61
5.10
6.54
5.12
5.61
5.61
5.61
5.10
5.00
6.54
5.12
5.61
5.10
6.59
5.12
5.61
5.61
5.61
5.10

Share element interests
Potential maximum performance sharesb

Interests vested in 2009 and 2010

At 1 Jan
2009
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
–

Awarded
2009
–
–
–
– 1,182,540
–
–
–
–
–
780,816
539,634
–
–
–
992,928
–
–
–
–
–
780,816

At 31 Dec
2009
–
706,311
845,319
1,182,540
–
456,748
578,376
133,452
133,452
780,816
539,634
–
491,640
581,748
992,928
–
400,243
578,376
133,452
133,452
780,816

Number of
ordinary
shares
vestedc
66,136
147,985
–
–
66,136
95,697
–
–
–
–
–
80,231
101,502
–
–
54,994
83,859
–
–
–
–

Vesting
date
6 Feb 2009
3 Feb 2010
–
–
6 Feb 2009
3 Feb 2010
–
–
–
–
–
6 Feb 2009
3 Feb 2010
–
–
6 Feb 2009
3 Feb 2010
–
–
–
–

Market price
of each share
at vesting
£
5.08
5.76
–
–
5.08
5.76
–
–
–
–
–
5.08
5.76
–
–
5.08
5.76
–
–
–
–

2006-2008
2007-2009

16 Feb 2006
06 Mar 2007

6.54
5.12

383,200
456,748

–
–

–
456,748

34,518
47,848

6 Feb 2009
3 Feb 2010

5.08
5.76

Dr A B Hayward

I C Conn

R W Dudleye
Dr B E Grotee

A G Inglis

Former directors

Dr D C Allen

a This information is subject to audit.
b BP’s performance is measured against the oil sector. For awards under the 2006-2008 through 2008-2010 plans, the performance condition is TSR measured against ExxonMobil, Shell, Total and Chevron.
For awards under the 2009-2011 plan, performance conditions are measured 50% on TSR against ExxonMobil, Shell, Total, ConocoPhillips and Chevron and 50% on a balanced scorecard of underlying
performance. Each performance period ends on 31 December of the third year.
c Represents 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 and Mr Dudley receive awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares.

BP Annual Report and Accounts 2009
Directors’ remuneration report

Share optionsa

Dr A B Hayward

I C Conn

R W Dudleyb c

Dr B E Groteb

A G Inglis

Option
type
SAYE
EXEC
EXEC
EXEC
EDIP
EDIP
SAYE
SAYE
SAYE
SAYE
EXEC
EXEC
BP SOP
BP SOP
BP SOP
BP SOP
BP SOP
BPA
BPA
EDIP
EDIP
EDIP
SAYE
EXEC
EXEC
EXEC
EXEC

At 1 Jan 2009
3,220
34,000
77,400
160,000
220,000
275,000
1,186
1,498
617
–
72,250
130,000
1,800
6,460
1,073
17,835
17,835
10,404
12,600
58,173
58,173
58,333
4,550
72,250
119,000
119,000
100,500

Granted
–
–
–
–
–
–
–
–
–
605
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–

Exercised
–
–
–
–
220,000
–
1,186
–
–
–
–
–
–
–
–
–
–
–
–
–
45,000
–
4,550
–
–
–
–

At 31 Dec
2009
3,220
34,000
77,400
160,000
–
275,000
–
1,498
617
605
72,250
130,000
1,800
6,460
1,073
17,835
17,835
–d
12,600
–d
13,173e
58,333
–
72,250
119,000
119,000
100,500

Option
price
£5.00
£5.99
£5.67
£5.72
£3.88
£4.22
£3.86
£4.41
£4.87
£4.20
£5.67
£5.72
$48.94
$49.65
$43.82
$48.99
$38.10
$53.90
$48.94
$48.82
$37.76
$48.53
£3.50
£5.67
£5.72
£3.88
£4.22

Market price
at date of
exercise

Date from
which first
exercisable

£5.88

Expiry date
01 Sep 2011 29 Feb 2012
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
£5.74 01 Sep 2009 28 Feb 2010
01 Sep 2010 28 Feb 2011
01 Sep 2011 01 Feb 2012
01 Sep 2012 28 Feb 2013
23 Feb 2004 23 Feb 2011
18 Feb 2005 18 Feb 2012
28 Mar 2003 27 Mar 2010
23 Feb 2004 22 Feb 2011
17 Dec 2004 16 Dec 2011
18 Feb 2005 17 Feb 2012
17 Feb 2006 16 Feb 2013
15 Mar 2000 14 Mar 2009
28 Mar 2001 27 Mar 2010
18 Feb 2003 18 Feb 2009
17 Feb 2004 17 Feb 2010
25 Feb 2005 25 Feb 2011
£4.86 01 Sep 2008 28 Feb 2009
23 Feb 2004 22 Feb 2011
18 Feb 2005 17 Feb 2012
17 Feb 2006 16 Feb 2013
25 Feb 2007 24 Feb 2014

$57.28-$59.50

The closing market prices of an ordinary share and of an ADS on 31 December 2009 were £6.00 and $57.97 respectively.
During 2009, the highest market prices were £6.09 and $59.93 respectively and the lowest market prices were £4.05 and $34.14 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 84.
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.
BP SOP = BP Share Option Plan. These options were granted to Mr Dudley prior to his appointment as a director and are not subject to performance conditions.

a This information has been subject to audit.
b Numbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.
c On appointment to the board.
d Options lapsed.
e Options exercised on 12 February 2010 at a market price of $54.36 per ADS.

D
i
r
e
c
t
o
r
s
’

r
e
m
u
n
e
r
a
t
i
o
n
r
e
p
o
r
t

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 Steela

Additional position
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
£29,000

£65,000

Unilever PLC
£36,000
Unilever NV
Z52,250
£90,000

Member of Tata Steel Europe board until 1 April 2009 and Tata Steel Ltd board until
18 September 2009.

Remuneration committee
All the members of the committee are independent non-executive
directors. Throughout the year, Dr Julius (chairman), and Sir Ian Prosser
were members. Mr Davis and Sir Tom McKillop served on the committee
until April 2009 and were succeeded by Mr Burgmans and Mr David in
May 2009. 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.

The remuneration committee’s tasks, as set out in the board governance
principles, are:
(cid:129) 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.

(cid:129) 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.

(cid:129) To nominate, on behalf of the board, any trustees (or directors of

corporate trustees) of the scheme.

(cid:129) To review the policies being applied by the group chief executive in
remunerating senior executives other than executive directors to
ensure alignment and proportionality.

(cid:129) To recommend to the board the quantum and structure of

remuneration for the chairman.

BP Annual Report and Accounts 2009
Directors’ remuneration report

Service contracts
Director

Dr A B Hayward
I C Conn
Mr R Dudley
Dr B E Grote
A G Inglis

Contract
date

Salary as at
31 Dec 2009
29 Jan 2003 £1,045,000
22 Jul 2004
£690,000
6 Apr 2009 $1,000,000
7 Aug 2000 $1,380,000
£690,000
1 Feb 2007

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 at the date of the 2011 Annual General Meeting.
Mr Dudley’s contract is with BP Corporation North America Inc. He is
seconded to BP p.l.c. under a secondment agreement of 15 April 2009
which expires on 15 April 2012. Both secondments can be terminated by
one month’s notice by either party and terminate automatically on the
termination of their service contracts.

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.

All 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.

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.

BP Annual Report and Accounts 2009
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 72).

They have no personal financial interest, other than as

shareholders, in the committee’s decisions.

The committee met eight times in the period under review.
The chairman of the board attends meetings of the committee and
Mr Svanberg attended meetings prior to becoming chairman on
1 January 2010.

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
Mr Aronson, an independent consultant, is the committee’s secretary
and independent adviser. Advice was also received from Mr Jackson, the
company secretary, and from the company secretary’s office, which is
independent of executive management and reports to the chairman of
the board.

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 2009, the committee continued to engage Towers Watson

as its principal external adviser. Towers Watson also provided other
remuneration and benefits advice to parts of the group.

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 83, 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

The board sets the level of remuneration for all non-executive directors
within a limit approved from time to time by shareholders. Key elements
of BP’s policy on non-executive director remuneration include:
(cid:129) Remuneration should be sufficient to attract and retain world-class

non-executive talent.

(cid:129) Remuneration of non-executive directors is proposed by the chairman

and agreed by the board.

(cid:129) Remuneration practice should be consistent with recognized best
practice standards for non-executive directors’ remuneration.

(cid:129) Remuneration should be in the form of cash fees, payable monthly.
(cid:129) Non-executive directors should not receive share options from the

company.

(cid:129) Non-executive directors are encouraged to establish a holding in BP

shares of the equivalent value of one year’s base fee.

Process
BP reviews the quantum and structure of chairman and non-executive
remuneration on an annual basis. The chairman’s remuneration is
reviewed by the remuneration committee, which makes a
recommendation to the board; the chairman does not vote on his own
remuneration. Non-executive director remuneration is reviewed by the
chairman, who makes a recommendation to the board; non-executive
directors do not vote on their own remuneration.

2009 review of chairman and non-executive director remuneration
In 2009, the chairman reviewed non-executive director remuneration
taking into account the review completed in 2008. The chairman made a
recommendation to the board (which was agreed) to maintain the 2008
structure until a further review in 2010.

Carl-Henric Svanberg was appointed to the board in September

2009. At the time of his appointment, the remuneration committee
looked at a comparison of remuneration for FTSE and international
chairmen in determining his fee. The committee determined that in
common with the previous chairman, he should receive the use of a
chauffeured car, a maintained office for company business and security
advice. In addition, the committee recognized that the appointment was
to be Mr Svanberg’s main commitment and as he would be performing a
proportion of his duties from Sweden, limited but appropriate secretarial
support in Sweden would be provided. Mr Svanberg is also eligible for a
single relocation allowance of up to £100,000 to cover expenses incurred
in relocating to London from Sweden.

Mr Svanberg received the basic non-executive director fee and

transatlantic attendance allowance for the period between his
appointment and his assumption of the role of chairman on 1 January
2010. On his appointment as chairman in 2010, the chairman’s fee
increased to £750,000.

D
i
r
e
c
t
o
r
s
’

r
e
m
u
n
e
r
a
t
i
o
n
r
e
p
o
r
t

The amount of the superannuation gratuity is calculated according to
the following:
(cid:129) Service on the board is taken up to 1 July 2002.
(cid:129) Payment is calculated as 10% of the total remuneration received in

either the year to 1 July 2002 or calendar year 2001 (whichever is the
greater) multiplied by the number of years a non-executive director
served on the board until 1 July 2002.

(cid:129) There is a limit on the payment equivalent to a maximum of 10 years’

service.

Peter Sutherland, who retired on 31 December 2009, is entitled to a
superannuation gratuity of £280,000 in line with the policy arrangements
agreed in 2002 and outlined above. Mr Sutherland has asked that the full
balance of the gratuity be donated to an educational foundation.

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:

E B Davis, Jr

Interest in BP ADSs
at 1 Jan 2009 and
31 Dec 2009a
4,490

Date on
which director
reaches age 70b
5 Aug 2014

a No 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.
b For the purposes of the regulations, the date on which the director retires from the board at or after
the age of 70 is the end of the qualifying period. If the director retires prior to this date, the board
may waive the restrictions.

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. During 2009, he received £150,000
for this role.

Dr Walter Massey (who retired as a non-executive director of BP

in April 2008) was appointed to the BP America External Advisory Council
in April 2008 for a period of two years. During 2009, he received
US$93,750 for this role.

This directors’ remuneration report was approved by the board and
signed on its behalf by David J Jackson, company secretary, on
26 February 2010.

BP Annual Report and Accounts 2009
Directors’ remuneration report

Fee structure
The table below shows the fee structure for non-executive directors on
1 January 2010:

Chairmana
Senior independent director b
Board member
Audit committee and SEEAC chairmanship feesc
Remuneration committee chairmanship feec
Committee membership feed
Transatlantic attendance allowance

£ thousand

Fee level
750
120
75
30
20
5
5

a The chairman remains ineligible for committee chairmanship and membership fees or transatlantic
attendance allowance.
b The senior independent director is 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 SEEAC, audit and remuneration committees.

Remuneration of non-executive directors in 2009a

P D Sutherland
A Burgmans
Sir William Castell
C B Carroll
G Davidb
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Ian Prosser
C-H Svanbergc
Directors leaving the board in 2009

Sir Tom McKillop

£ thousand

2009
600
93
115
90
118
105
85
105
165
30

2008
600
90
108
93
100
105
90
110
170
n/a

a This information has been subject to audit.
b Also received £4,166 for serving as a member of BP’s technology advisory committee.
c Appointed on 1 September 2009.

While fees were held at 2008 levels, in 2009 actual fees paid to non-
executive directors were affected by changes in committee membership
and the number of transatlantic meetings to which an attendance
allowance was paid.

No share or share option awards were made to any non-executive

director in respect of service to the board during 2009.

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.

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. In 2002, the board revised
its policy so that non-executive directors appointed to the board after
1 July 2002 would not be eligible for a superannuation gratuity, and that
directors in service at that date would remain eligible but service past
1 July 2002 would not be taken into account by the board in considering
the amount of the superannuation gratuity.

Additional information
for shareholders

94 Critical accounting policies

107 Purchases of equity securities by

96 Property, plants and equipment

96 Share ownership

98 Major shareholders and related

party transactions

the issuer and affiliated purchasers

107 Fees and charges payable by

a holder of ADSs

108 Fees and payments made by the

Depositary to the issuer

108 Called-up share capital

108 Administration

108 Annual general meeting

98 Dividends

99 Legal proceedings

100 Share prices and listings

101 Memorandum and Articles

of Association

103 Exchange controls

103 Taxation

105 Documents on display

105 Controls and procedures

106 Code of ethics

106 Principal accountants’ fees

and services

106 Corporate governance practices

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

Critical accounting policies
The significant accounting policies of the group are summarized in
Financial statements – Note 1 on page 116.

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 principles of 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 natural 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 natural 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 natural 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:
(cid:129) Producing wells – proved developed reserves.
(cid:129) 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).

On 31 December 2008, the SEC published a revision of Rule

4-10 (a) of Regulation S-X for the estimation of reserves. These revised
rules form the basis of the 2009 year-end estimation of proved reserves
and the application of the technical aspects resulted in an immaterial
increase of less than 1% to BP’s total proved reserves. The 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 24, which is unaudited. 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 2009 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
(unaudited) on pages 179 to 192.

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 natural 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 asset or 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.

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

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 natural 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 2009, the group’s long-term
planning assumptions were $75 per barrel for Brent and $7.50/mmBtu
for Henry Hub (2008 $75 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, although other rates may be used if appropriate to the specific
circumstances. In 2009 the rates ranged from 9% to 13% (2008 11%
to 13%). The rate applied in each country is re-assessed each year by
analysing 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
$8.6 billion on its balance sheet (2008 $9.9 billion), 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. In 2009,
an impairment loss of $1.6 billion was recognized to write off all of the
goodwill allocated to the US West Coast fuels value chain. The prevailing
weak refining environment, together with a review of future margin
expectations in the FVC, led to a reduction in the expected future
cash flows.

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 16 on page 137 and
Note 41 on page 176.

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 embedded derivatives. These are
primarily long-term UK gas contracts that use pricing formulas 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 31 on
page 152. An analysis of the sensitivity of the fair value of the embedded
derivatives to changes in the key assumptions is provided in Financial
statements – Note 24 on page 144.

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 2009 was 1.75% (2008 2%). The interest rate represents
the real rate (i.e. excluding the impacts of inflation) on long-dated
government bonds.

BP Annual Report and Accounts 2009
Additional information for shareholders

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 and quantification of the
liability require 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 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 is estimated 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 2009 was 1.75% (2008 2%).

As further described in Financial statements – Note 41 on

page 176, 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

December 2009, 2008 and 2007 are provided in Financial statements –
Note 35 on page 161.

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 35 on page 161.

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. A sensitivity
analysis of the impact of changes in the mortality assumptions on the
benefit expense and obligation is provided in Financial statements –
Note 35 on page 161.

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 22 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.

Share ownership
Directors and senior management
As at 18 February 2010, 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
R W Dudley
Dr B E Grote
Dr A B Hayward
A G Inglis
P Anderson
A Burgmans
C B Carroll
Sir William Castell
G David
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Ian Prosser
C-H Svanberg

349,820
276,846
1,351,529
622,807
308,639
6,000
10,156
10,500
82,500
39,000
76,497
15,000
15,000
16,301
750,000

2,016,005a
1,120,716a
2,376,570a
3,022,598a
2,016,005a
–
–
–
–
–
–
–
–
–
–

266,904b
–
–
–
266,904b
–
–
–
–
–
–
–
–
–
–

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.

b 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.

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

As at 18 February 2010, 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
R W Dudley
Dr B E Grote
Dr A B Hayward
A G Inglis

204,970
270,018
425,598
549,620
410,750

There are no directors or members of senior management who own more than 1% of the ordinary shares outstanding. At 18 February 2010, all
directors and senior management as a group held interests in 5,649,017 ordinary shares or their calculated equivalent, 12,173,702 performance
shares or their calculated equivalent and 2,113,316 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 88 and 89.

Employee share plans
The following table shows employee share options granted.

Employee share options granted during the yeara

2009
9,680

options thousands

2008
8,063

2007
6,004

a For the options outstanding at 31 December 2009, the exercise price ranges and weighted average remaining contractual lives are shown in Financial statements – Note 38 on page 172.

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 performance plans (see Financial
statements – Note 38 on page 172) 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- 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 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.

Cash-settled share-based payments
Grants are settled in cash where participants are located in a country
whose regulatory environment prohibits the holding of BP shares.

Employee share ownership plans (ESOPs)
ESOPs have been established to hold BP shares to satisfy any releases
made to participants under the Executive Directors’ Incentive Plan, the
Long-Term Performance Plan and the Share Option 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 37 on page 168). Assets and liabilities of the ESOPs
are recognized as assets and liabilities of the group.

At 31 December 2009, the ESOPs held 18,062,246 shares (2008

29,051,082 shares and 2007 6,448,838 shares) for potential future
awards, which had a market value of $174 million (2008 $220 million and
2007 $79 million).

Pursuant to the various BP group share option schemes, the
following options for ordinary shares of the company were outstanding at
18 February 2010:

Options outstanding (shares)
285,364,691

Expiry dates
of options
2010-2016

Exercise price
per share
$6.18-$11.92

More details on share options appear in Financial statements – Note 38
on page 172.

At the date of this report the company has also been notified of the
following interests in preference shares: The National Farmers Union
Mutual Insurance Society Limited holds interests in 945,000 8%
cumulative first preference shares (13.07% of that class) and 987,000
9% cumulative second preference shares (18.03% of that class).
M & G Investment Management Ltd. holds interests in 528,150
8% cumulative first preference shares (7.30% of that class) and 644,450
9% cumulative second preference shares (11.77% of that class).
Gartmore Investment Management Limited holds interests in 394,538
8% cumulative first preference shares (5.45% of that class) and 500,000
9% cumulative second preference shares (9.14% of that class). Duncan
Lawrie Ltd. holds interests in 461,876 8% cumulative first preference
shares (6.39% of that class). Ruffer LLP holds interests in 587,000 9%
cumulative second preference shares (10.72% of that class). Lazard
Asset Management Ltd. (U.K.) holds interests in 328,500 9% cumulative
second preference shares (6.0% of that class).

The total preference shares in issue comprise only 0.4%

of the company’s total issued nominal share capital, the rest being
ordinary shares.

Related-party transactions
Transactions between the group and its significant jointly controlled
entities and associates are summarized in Financial statements – Note 22
on page 142 and Financial statements – Note 23 on page 143. 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 2009 to 18 February 2010.

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.

BP Annual Report and Accounts 2009
Additional information for shareholders

Major shareholders and related
party transactions
Register of members holding BP ordinary shares as at
31 December 2009

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
57,927
116,624
126,034
11,867
1,065
777
314,294

Percentage of Percentage of
total ordinary
total ordinary
share capital
shareholders
0.02
18.43
0.30
37.11
1.83
40.10
1.17
3.77
1.85
0.34
94.83
0.25
100.00
100.00

a Includes JPMorgan Chase Bank holding 27.74% 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.

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
72,272
37,695
21,893
1,417
22
1
133,300

Percentage of

total ADS Percentage of
total ADSs
0.48
2.08
6.80
2.81
0.43
87.4
100.00

holders
54.22
28.28
16.42
1.06
0.02
0.00
100.00

a One ADS represents six 25 cent ordinary shares.
b One of the holders of ADSs represents some 698,373 underlying shareholders.

As at 31 December 2009, there were also 1,660 preference shareholders.
Preference shareholders represented 0.4% and ordinary shareholders
represented 99.6% 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 and the US Securities
Exchange Act of 1934. Under DTR 5, we have received notification that
BlackRock, Inc. holds 5.93% of the voting rights of the issued share
capital of the company; and Legal and General Group Plc holds 4.18% of
the voting rights of the issued share capital of the company.

As at the date of this report, the company had been notified that

JPMorgan Chase Bank, as depositary for American depositary shares
(ADSs) holds interests through its nominee, Guaranty Nominees Limited,
in 5,318,457,873 ordinary shares (28.34% of the company’s ordinary
share capital excluding shares held in Treasury and shares bought back
for cancellation). During 2009, BlackRock, Inc. acquired Barclays Global
Investors, resulting in an increase in the share interest of BlackRock, Inc.
BlackRock, Inc. holds interests in 1,112,967,596 ordinary shares (5.93%
of the ordinary share capital excluding shares held in treasury and shares
bought back for cancellation). Legal & General Group plc hold interests in
783,820,456 ordinary shares (4.18% of the company’s ordinary share
capital excluding shares held in treasury and shares bought back for
cancellation). The company’s major shareholders do not have different
voting rights.

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

The following table shows dividends announced and paid by the company per ADS for each of the past five years.

Dividends per American depositary share
2005

2006

2007

2008

2009

March

June

September

December

Total

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 centsa

27.1
51.0
64.0
31.7
56.25
64.5
31.5
61.95
73.3
40.9
81.15
80.8
58.91
84
n/a

26.7
51.0
63.2
31.5
56.25
64.1
30.9
61.95
69.5
41.0
81.15
82.5
57.50
84
n/a

30.7
53.55
65.3
31.9
58.95
67.4
31.7
64.95
67.8
42.2
84.0
85.8
51.02
84
n/a

30.4
53.55
63.7
31.4
58.95
66.5
31.8
64.95
63.6
52.2
84.0
108.6
51.07
84
n/a

114.9
209.1
256.2
126.5
230.4
262.5
125.9
253.8
274.2
176.3
330.3
357.7
218.5
336
n/a

a BP shares were de-listed from the Toronto Stock Exchange on 15 August 2008 and the last dividend payment in Canadian dollars was made on 8 December 2008.

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. Subject to shareholder approval at
the Annual General Meeting, the company is seeking to replace these
plans with an optional Scrip Dividend Programme. If approved, the
requirements of the programme mean that there will be certain
changes to our current dividend timetable.

Future dividends will be dependent on future earnings, the
financial condition of the group, the Risk factors set out on pages 18-20
and other matters that may affect the business of the group set out in
Financial performance on page 53 and in Liquidity and capital resources
on page 61.

Legal proceedings
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 in both
groups of the class actions (the direct and indirect purchasers) have
received final court approval. Two independent lawsuits from class
members who opted out of the direct purchaser settlement are also
pending. In addition, state actions alleging manipulation of propane and
other energy commodity prices and seeking a variety of remedies have
been filed against BP Products and other BP subsidiaries.

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 injury
claims arising from the March 2005 incident.

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 will continue to discuss BP’s responses with the
objective of the CSB agreeing to close-out its recommendations.

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. On 4 February 2008, BP Products pleaded guilty,
pursuant to the plea agreement, to one felony violation of the risk
management planning regulations promulgated under the US federal
Clean Air Act and on 12 March 2009, the court accepted the plea
agreement. In connection with the plea agreement, BP Products paid
a $50 million criminal fine and was sentenced to three years’ probation.
Compliance with a 2005 US Occupational Safety and Health
Administration (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 DOJ
continues to investigate certain other matters arising from the March
2005 explosion and fire.

BP Annual Report and Accounts 2009
Additional information for shareholders

The Texas Office of Attorney General, on behalf of the TCEQ, has filed a
petition against BP Products asserting certain air emission and reporting
violations at the Texas City refinery from 2005 to 2009, including in
relation to the March 2005 explosion and fire. BP is contesting the
petition in a pending civil proceeding.

In September 2009, BP Products filed a petition to clarify specific

required actions and deadlines under the 2005 Settlement Agreement
with OSHA. That agreement resolved citations issued in connection with
the March 2005 Texas City refinery explosion. OSHA has denied BP
Products’ petition. This matter is scheduled for review by the
Occupational Safety and Health (OSH) Review Commission. In October
2009 OSHA issued the Texas City Refinery citations seeking a total of
$87.4 million civil penalty for alleged violations of the 2005 Agreement
and alleged process safety management violations. BP Products has
contested the citations so this will also be reviewed by the OSH Review
Commission and possibly the federal courts. Settlement negotiations
continue between BP Products and OSHA in an attempt to settle the
citations for alleged violations of the 2005 settlement agreement.

BP has received a shareholder derivative action against various of

its current and former officers and directors based on alleged violations
of the US Clean Air Act and OSHA regulations at the Texas City refinery
subsequent to the March 2005 explosion and fire.

BP is also defending civil personal injury claims by Texas City

refinery workers or their families from incidents or releases since 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.
On 31 March 2009, the DOJ filed a complaint against BPXA seeking
civil penalties and injunctive relief relating to the 2006 oil releases.
The complaint alleges that BPXA violated various federal environmental
and pipeline safety statutes and associated regulations in connection
with the two releases and its maintenance and operation of North Slope
pipelines. The State of Alaska also filed a complaint on 31 March 2009
against BPXA seeking civil penalties and damages relating to these
events. The complaint alleges that the two releases and BPXA’s
corrosion management practices violated various statutory, contractual
and common law duties to the State, resulting in penalty liability, damages
for lost royalties and taxes, and liability for punitive damages.

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
judgement 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.

For certain information regarding environmental proceedings, see

Environment – United States on page 48.

Share prices and listings
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 the Frankfurt stock exchange in 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.

100

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

Year ended 31 December
2005
2006
2007
2008
2009
Year ended 31 December
2008: First quarter

Second quarter
Third quarter
Fourth quarter

2009: First quarter

Second quarter
Third quarter
Fourth quarter

2010: First quarter (to 18 February)
Month of
September 2009
October 2009
November 2009
December 2009
January 2010
February 2010 (to 18 February)

a An ADS is equivalent to six 25 cent ordinary shares.

Pence

Ordinary shares

High

Low

High

Dollars

American
depositary
sharesa
Low

686.00
723.00
640.00
657.25
613.40

648.00
657.25
583.00
541.25
566.50
543.75
568.50
613.40
639.00

568.50
598.00
599.30
613.40
639.00
595.00

499.00
558.50
504.50
370.00
400.00

495.00
501.34
446.00
370.00
400.00
426.50
459.25
528.00
552.30

514.80
528.00
562.50
572.00
585.10
552.30

72.75
76.85
79.77
77.69
60.00

75.87
77.69
69.10
51.49
49.83
53.24
55.61
60.00
62.38

55.61
58.69
60.00
58.99
62.38
57.26

56.60
63.52
58.62
37.57
33.71

57.87
60.25
48.35
37.57
33.71
38.50
44.63
50.60
52.11

50.30
50.60
56.22
55.77
55.87
52.11

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 being proposed at our AGM in 2010, to
reflect the full implementation of the Companies Act 2006, among other
matters.

Under the Companies Act 2006 the Memorandum serves a
more limited role as historical evidence of the formation of the company.
Since October 2009 the provisions of the company’s Memorandum are
deemed to form part of BP’s Articles of Association.

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.

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 2010, 886,409,646 ADSs (equivalent to

5,318,457,873 ordinary shares or some 28.34% of the total issued
share capital, excluding treasury shares and shares bought back for
cancellation) were outstanding and were held by approximately 132,684
ADS holders. Of these, about 131,204 had registered addresses in the
US at that date. One of the registered holders of ADSs represents some
698,373 underlying holders.

On 18 February 2010, there were approximately 314,028 holders

of record of ordinary shares. Of these holders, around 1,540 had
registered addresses in the US and held a total of some 4,343,899
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.

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 105.

101

BP Annual Report and Accounts 2009
Additional information for shareholders

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:
(cid:129) 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.

(cid:129) Any proposal in which he is interested concerning the underwriting of

company securities or debentures.

(cid:129) 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.

(cid:129) 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.

(cid:129) 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.

102

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:
(cid:129) 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.
(cid:129) 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.

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, reliance on this
notice period of 14 days requires annual shareholder approval, failing
which, a 21-day notice period will apply.

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

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. In addition, if a
partnership holds the shares or ADSs, the United States federal income
tax treatment of a partner will generally depend on the status of the
partner and the tax treatment of the partnership, and may not be
described fully below.

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
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.

103

BP Annual Report and Accounts 2009
Additional information for shareholders

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 a US holder’s foreign tax
credit limitation.

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.

In addition, the taxation of dividends may be subject to the rules

for passive foreign investment companies, described below under
‘Capital Gains – US federal income taxation’. Distributions made by a
PFIC do not constitute qualified dividend income and are not eligible for
the 15% tax rate.

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.

104

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-market 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 rateably 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. Certain ‘excess distributions’ would be similarly treated if we were
treated as a PFIC.

Additional tax considerations
Proposed scrip dividend programme
Subject to shareholder approval at the Annual General Meeting on
15 April, the company is planning to introduce an optional scrip dividend
programme, wherein holders of ordinary shares or ADSs may elect to
receive their dividends in the form of new fully paid ordinary shares or
ADSs of the company, instead of cash. Please consult your tax adviser
for the consequences to you.

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.

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

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 (UK and Rest of World) or
from Precision IR at + 1 888 301 2505 or through an email request
addressed to bpreports@precisionir.com (US and Canada).

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.

Controls and procedures
Evaluation of disclosure controls and procedures
The company maintains ‘disclosure controls and procedures’ as such
term is defined in Exchange Act Rule 13a-15(e), that are designed to
ensure that information required to be disclosed in reports the company

files or submits under the Exchange Act is recorded, processed,
summarized and reported within the time periods specified in the
Securities and Exchange Commission rules and forms, and that such
information is accumulated and communicated to management, including
the company’s group chief executive and chief financial officer, as
appropriate, to allow timely decisions regarding required disclosure.
In designing and evaluating our disclosure controls and
procedures, our management, including the group chief executive and
chief financial officer, recognize that any controls and procedures, no
matter how well designed and operated, can provide only reasonable, not
absolute, assurance that the objectives of the disclosure controls and
procedures are met. Because of the inherent limitations in all control
systems, no evaluation of controls can provide absolute assurance that
all control issues and instances of fraud, if any, within the company have
been detected. Further, in the design and evaluation of our disclosure
controls and procedures our management necessarily was required to
apply its judgement in evaluating the cost-benefit relationship of possible
controls and procedures. Also, we have investments in certain
unconsolidated entities. As we do not control these entities, our
disclosure controls and procedures with respect to such entities are
necessarily substantially more limited than those we maintain with
respect to our consolidated subsidiaries. Because of the inherent
limitations in a cost-effective control system, misstatements due to error
or fraud may occur and not be detected. The company’s disclosure
controls and procedures have been designed to meet, and management
believe that they meet, reasonable assurance standards.

The company’s management, with the participation of the
company’s group chief executive and chief financial officer, has evaluated
the effectiveness of the company’s disclosure controls and procedures
pursuant to Exchange Act Rule 13a-15(b) as of the end of the period
covered by this annual report. Based on that evaluation, the group chief
executive and chief financial officer have concluded that the company’s
disclosure controls and procedures were effective at a reasonable
assurance level.

Changes in internal controls over financial reporting
There were no changes in the group’s internal controls over financial
reporting that occurred during the period covered by the Form 20-F that
have materially affected or are reasonably likely to materially affect, our
internal controls over financial reporting.

Management’s report on internal control over financial reporting
Management of BP is responsible for establishing and maintaining
adequate internal control over financial reporting. BP’s internal control
over financial reporting is a process designed under the supervision
of the principal executive and principal financial officers to provide
reasonable assurance regarding the reliability of financial reporting and
the preparation of BP’s financial statements for external reporting
purposes in accordance with IFRS.

As of the end of the 2009 fiscal year, management conducted an

assessment of the effectiveness of internal control over financial
reporting in accordance with the Internal Control Revised Guidance for
Directors on the Combined Code (Turnbull). Based on this assessment,
management has determined that BP’s internal control over financial
reporting as of 31 December 2009 was effective.

The company’s internal control over financial reporting includes

policies and procedures that pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect transactions and
dispositions of assets; provide reasonable assurances that transactions
are recorded as necessary to permit preparation of financial statements
in accordance with IFRS and that receipts and expenditures are being
made only in accordance with authorizations of management and the
directors of BP; and provide reasonable assurance regarding prevention
or timely detection of unauthorized acquisition, use or disposition of BP’s
assets that could have a material effect on our financial statements.

105

BP Annual Report and Accounts 2009
Additional information for shareholders

BP’s internal control over financial reporting as of 31 December 2009 has
been audited by Ernst & Young LLP, an independent registered public
accounting firm, as stated in their report appearing in our Annual Report
on Form 20-F 2009.

Code of ethics
The company has adopted a code of ethics for its group chief executive,
chief financial officer, deputy chief financial officer, group controller,
general auditors and chief accounting officer as required by the provisions
of Section 406 of the Sarbanes-Oxley Act of 2002 and the rules issued by
the SEC. There have been no waivers from the code of ethics relating to
any officers. The code has been amended to reflect changes to the titles
and posts of certain senior officers. The amended code of ethics has
been filed as an exhibit to our Annual Report on Form 20-F.

In June 2005, BP published a code of conduct, which is applicable

to all employees.

Principal accountants’ fees and services
The audit committee has established policies and procedures for the
engagement of the independent registered public accounting firm, Ernst
& Young LLP, to render audit and certain assurance and tax services. The
policies provide for pre-approval by the audit committee of specifically
defined audit, audit-related, tax and other services that are not prohibited
by regulatory or other professional requirements. Ernst & Young is
engaged for these services when its expertise and experience of BP are
important. Most of this work is of an audit nature. Tax services were
awarded either through a full competitive tender process or following an
assessment of the expertise of Ernst & Young relative to that of other
potential service providers. These services are for a fixed term.

Under the policy, pre-approval is given for specific services within

the following categories: advice on accounting, auditing and financial
reporting matters; internal accounting and risk management control
reviews (excluding any services relating to information systems design
and implementation); non-statutory audit; project assurance and advice
on business and accounting process improvement (excluding any
services relating to information systems design and implementation
relating to BP’s financial statements or accounting records); due diligence
in connection with acquisitions, disposals and joint ventures (excluding
valuation or involvement in prospective financial information); income tax
and indirect tax compliance and advisory services; and employee tax
services (excluding tax services that could impair independence);
provision of, or access to, Ernst & Young publications, workshops,
seminars and other training materials; provision of reports from data
gathered on non-financial policies and information; and assistance with
understanding non-financial regulatory requirements. Additionally, any
proposed service not included in the pre-approved services, must be
approved in advance prior to commencement of the engagement. The
audit committee has delegated to the chairman of the audit committee
authority to approve permitted services provided that the chairman
reports any decisions to the committee at its next scheduled meeting.
The audit committee evaluates the performance of the auditors

each year. The audit fees payable to Ernst & Young are reviewed by
the committee in the context of other global companies for cost
effectiveness. The committee keeps under review the scope and results
of audit work and the independence and objectivity of the auditors.
External regulation and BP policy requires the auditors to rotate their lead
audit partner every five years.

(See Financial statements – Note 14 on page 136 and Audit

committee report on page 74 for details of audit fees.)

106

Corporate governance practices
In the US, BP ADSs are listed on the New York Stock Exchange (NYSE).
The significant differences between BP’s corporate governance practices
as a UK company and those required by NYSE listing standards for US
companies are listed as follows:

Independence
BP has adopted a robust set of board governance principles, which
reflect the UK’s Combined Code and its principles-based approach to
corporate governance. As such, the way in which BP makes
determinations of directors’ independence differs from the NYSE rules.
BP’s board governance principles require that all non-executive

directors be determined by the board to be ‘independent in character and
judgement and free from any business or other relationship which could
materially interfere with the exercise of their judgement’. The BP board
has determined that, in its judgement, all of the non-executive directors
are independent. In doing so, however, the board did not explicitly take
into consideration the independence requirements outlined in the NYSE’s
listing standards.

Committees
BP has a number of board committees which are broadly comparable in
purpose and composition to those required by NYSE rules for domestic
US companies. For instance, BP has a chairman’s (rather than executive)
committee, nomination (rather than nominating/corporate governance)
committee and remuneration (rather than compensation) committee.
BP also has an audit committee, which NYSE rules require for both US
companies and foreign private issuers. These committees are composed
solely of non-executive directors whom the board has determined to be
independent, in the manner described above.

The BP board governance principles prescribe the composition,
main tasks and requirements of each of the committees (see the board
committees on pages 74-80). BP has not, therefore, adopted separate
charters for each committee.

Under US securities law and the listing standards of the NYSE, BP

is required to have an audit committee which satisfies the requirements
of Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE
Listed Company Manual. BP’s audit committee complies with these
requirements.

One of the NYSE’s additional requirements for the audit
committee states that at least one member of the audit committee is to
have ‘accounting or related financial management expertise’. As reported
in BP Annual Report on Form 20-F 2008, the board determined that
Douglas Flint possessed such expertise and also possesses the financial
and audit committee experiences set forth in both the Combined Code
and SEC rules (see Audit committee report on page 74).

Shareholder approval of equity compensation plans
The NYSE rules for US companies require that shareholders must be
given the opportunity to vote on all equity-compensation plans and
material revisions to those plans. BP complies with UK requirements
which are similar to the NYSE rules. The board, however, does not
explicitly take into consideration the NYSE’s detailed definition of what
are considered ‘material revisions’.

Code of ethics
The NYSE rules require that US companies adopt and disclose a code of
business conduct and ethics for directors, officers and employees. BP has
adopted a code of conduct, which applies to all employees, and has board
governance principles which address the conduct of directors. In addition
BP has adopted a code of ethics for senior financial officers as required by
the SEC. The code has been amended to reflect changes to the titles and
posts of certain senior officers. BP considers that these codes and policies
address the matters specified in the NYSE rules for US companies.

A
d
d
i
t
i
o
n
a
l

n
f
o
r
m
a
t
i
o
n
f
o
r
s
h
a
r
e
h
o
d
e
r
s

BP Annual Report and Accounts 2009
Additional information for shareholders

Purchases of equity securities by the issuer and affiliated purchasers
At the AGM on 16 April 2009, authorization was given to repurchase up to 1.8 billion ordinary shares in the period to the next AGM in 2010 or 15 July
2010, the latest date by which an AGM must be held. This authorization is renewed annually at the AGM. No repurchases of shares were made in the
period 1 January 2009 to 18 February 2010.

The following table provides details of share purchases made by ESOP trusts.

2009
January
February
March
April
May
June
July
August
September
October
November
December
2010
January
February (to 18 February)

Total number of
shares purchased

–
126
118
–
–
553
1,090,018
54
134
713
1,265,242
58

51
144,523

$
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 a

–
7.48
6.35
–
–
7.46
8.35
8.16
8.36
8.42
11.41
8.82

10.36
11.41

a No 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.

Fees and charges payable by a holder of ADSs
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of
withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the
amounts distributed or by selling a portion of the distributable property to pay the fees.

The charges of the Depositary payable by investors are as follows:

Type of service

Depositary actions

Fee

Depositing or substituting the
underlying shares

Selling or exercising rights

Issuance of ADSs against the deposit of shares,
including deposits and issuances in respect of:
(cid:129) Share distributions, stock splits, rights, merger
(cid:129) Exchange of securities or other transactions or

event or other distribution affecting the ADSs or
deposited securities

Distribution or sale of securities, the fee being in an
amount equal to the fee for the execution and delivery
of ADSs which would have been charged as a result of
the deposit of such securities

Withdrawing an underlying
share

Acceptance of ADSs surrendered for withdrawal of
deposited securities

Expenses of the Depositary

Expenses incurred on behalf of holders in connection with:
(cid:129) Stock transfer or other taxes and governmental

charges

(cid:129) Cable, telex, electronic and facsimile

transmission/delivery

(cid:129) Transfer or registration fees, if applicable, for the
registration of transfers of underlying shares

(cid:129) Expenses of the Depositary in connection with the
conversion of foreign currency into US dollars
(which are paid out of such foreign currency)

$5.00 per 100 ADSs (or portion thereof)
evidenced by the new ADSs delivered

$5.00 per 100 ADSs (or portion thereof)

$5.00 for each 100 ADSs (or portion
thereof) evidenced by the ADSs
surrendered

Expenses payable at the sole discretion
of the Depositary by billing holders or
by deducting charges from one or by
deducting charges from one or more
cash dividends or other cash
distributions

107

BP Annual Report and Accounts 2009
Additional information for shareholders

Fees and payments made by the
Depositary to the issuer
The Depositary has agreed to reimburse certain company expenses
related to the company’s ADS programme and incurred by the company
in connection with the programme. The Depositary reimbursed to the
company, or paid amounts on the company’s behalf to third parties, or
waived its fees and expenses, of $4,565,411 for the year ended
31 December 2009.

The table below sets forth the types of expenses that the
Depositary has agreed to reimburse, and the invoices relating to the year
ended 31 December 2009 that were reimbursed:

Called-up share capital
Details of the allotted, called up and fully paid share capital at
31 December 2009 are set out in Financial statements – Note 36 on
page 167.

At the AGM on 16 April 2009, authorization was given to the
directors to allot shares up to an aggregate nominal amount equal to
$1,561 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 $234 million, without having to offer such shares to
existing shareholders. These authorities are given for the period until the
next AGM in 2010 or 15 July 2010, whichever is the earlier. These
authorities are renewed annually at the AGM.

Category of expense reimbursed
to the company
NYSE listing feesa
Printing costs in connection with US
shareholder communications and AGM
related expenses in connection with
the ADR programme
Total

Amount reimbursed for the year
ended 31 December 2009
$500,000

$140,226
$640,226

Administration
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.

a During 2009 the company received a payment of $500,000 from the Depositary in respect of NYSE
listing fee for 2008.

The Depositary has also agreed to waive fees for standard costs
associated with the administration of the ADS programme and has paid
certain expenses directly to third parties on behalf of the company. The
table below sets forth those expenses that the Depositary waived or paid
directly to third parties relating to the year ended 31 December 2009:

Amount reimbursed for the year
ended 31 December 2009

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.

Category of expense waived or paid
directly to third partiesa
Service fees and out of pocket expenses
waivedb
Broker reimbursementsc
Other third-party mailing costsd
Transfer agency fees in Canadae
Other third-party expenses paid directly
Total

$2,706,973
$1,070,408
$132,435
$10,441
$4,928
$3,925,185

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

a In addition to the reimbursed and waived fees for the year ended 31 December 2009, the
Depositary also reimbursed, waived or paid directly to third parties $2,656,148 that related to the
year ended 31 December 2008.
b Includes fees in relation to transfer agent costs and operation of BP Direct Access Plan by
JPMorgan Chase.
c Broker reimbursements are fees payable to Broadridge and other service providers for the
distribution of hard copy material to ADR beneficial holders in the Depositary Trust Company.
Corporate materials include information related to shareholders’ meetings and related voting
instructions. These fees are SEC approved.
d Reimbursement of fees to UPS Mail innovations, Precision IR and Bank of New York Mellon for
distribution of hard copy materials to ADR beneficial holders and proxy solicitation.
e Fees payable to CIBC as co-transfer agent for Canadian ADR holders.

Under certain circumstances, including removal of the Depositary or
termination of the ADR programme by the company, the company is
required to repay the Depositary amounts reimbursed and/or expenses
paid to or on behalf of the company during the 12-month period prior to
notice of removal or termination.

Annual general meeting
The 2010 AGM will be held on Thursday, 15 April 2010 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 2010.

By order of the board
David J Jackson
Secretary
26 February 2010

BP p.l.c.
Registered in England and Wales No. 102498

108

Financial statements

110 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 statement of comprehensive income
Group statement of changes in equity
Group balance sheet
Group cash flow statement

110
111
112
113
113
114
115

116 Notes on financial statements

116
1 Significant accounting policies
124
2 Acquisitions
124
3 Disposals and impairment
126
4 Segmental analysis
131
5 Interest and other income
131
6 Production and similar taxes
131
7 Depreciation, depletion and amortization
132
8 Impairment review of goodwill
134
9 Distribution and administration expenses
134
10 Currency exchange gains and losses
134
11 Research and development
134
12 Operating leases
13 Exploration for and evaluation of oil and natural gas resources 135
136
14 Auditor's remuneration
136
15 Finance costs
137
16 Taxation
139
17 Dividends
139
18 Earnings per ordinary share
140
19 Property, plant and equipment
141
20 Goodwill
141
21 Intangible assets
142
22 Investments in jointly controlled entities
143
23 Investments in associates
144
24 Financial instruments and financial risk factors
150
25 Other investments
150
26 Inventories
150
27 Trade and other receivables
151
28 Cash and cash equivalents
151
29 Valuation and qualifying accounts
151
30 Trade and other payables
152
31 Derivative financial instruments
158
32 Finance debt
159
33 Capital disclosures and analysis of changes in net debt

34 Provisions
35 Pensions and other post-retirement benefits
36 Called up share capital
37 Capital and reserves
38 Share-based payments
39 Employee costs and numbers
40 Remuneration of directors and senior management
41 Contingent liabilities
42 Capital commitments
43 Subsidiaries, jointly controlled entities and associates

179 Supplementary information on

oil and natural gas (unaudited)

193 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
Company 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

160
161
167
168
172
174
175
176
176
177

193
194
195
196
196

197
198
199
199
200
200
203
203
204
204
205
208
208

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009

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:
(cid:129) Select suitable accounting policies and then apply them consistently.
(cid:129) Present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information.
(cid:129) 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.

(cid:129) 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 2006 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 the appropriate sections on pages 61 to 63 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. After making enquiries, the directors have a reasonable expectation that
the company and the group have adequate resources to continue in operational existence for the foreseeable future. Accordingly, they continue to
adopt the going concern basis in preparing the annual report and accounts.

Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 418(3) of the

Companies Act 2006) 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:

(cid:129) 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 2006, give a true and fair view of the assets, liabilities,
financial position and profit of the group; and

(cid:129) 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.

110

BP Annual Report and Accounts 2009
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 2009 which comprise the group income
statement, the group statement of comprehensive income, the group statement of changes in equity, the group balance sheet, the group cash flow
statement and the related notes 1 to 43. The financial reporting framework that has been applied in their preparation is applicable law and International
Financial Reporting Standards (IFRS) as adopted by the European Union.

This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. 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 auditor’s
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
As explained more fully in the Statement of directors’ responsibilities in respect of the consolidated financial statements set out on page 110, the
directors are responsible for the preparation of the consolidated financial statements and for being satisfied that they give a true and fair view. Our
responsibility is to audit the consolidated financial statements in accordance with applicable law and International Standards on Auditing (UK and
Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.

Scope of the audit of the financial statements
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the
financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting
policies are appropriate to the group’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant
accounting estimates made by the directors; and the overall presentation of the financial statements.

Opinion on financial statements
In our opinion the consolidated financial statements:
(cid:129) give a true and fair view of the state of the group’s affairs as at 31 December 2009 and of its profit for the year then ended;
(cid:129) have been properly prepared in accordance with IFRS as adopted by the European Union; and
(cid:129) have been prepared in accordance with the requirements of the Companies Act 2006 and Article 4 of the IAS Regulation.

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 apply IFRS as adopted by
the European Union, has also applied IFRS as issued by the International Accounting Standards Board (IASB).
In our opinion the consolidated financial statements comply with IFRS as issued by the IASB.

Opinion on other matter prescribed by the Companies Act 2006
In our opinion the information given in the Directors’ Report for the financial year for which the consolidated financial statements are prepared is
consistent with the consolidated financial statements.

Matters on which we are required to report by exception
We have nothing to report in respect of the following:
Under the Companies Act 2006 we are required to report to you if, in our opinion:
(cid:129)
certain disclosures of directors’ remuneration specified by law are not made; or
(cid:129) we have not received all the information and explanations we require for our audit.

Under the Listing Rules we are required to review:
(cid:129)
(cid:129)

the directors’ statement, set out on page 110, in relation to going concern; and
the part of the BP board performance report relating to the company’s compliance with the nine provisions of the June 2008 Combined Code
specified for our review.

Other matter
We have reported separately on the parent company financial statements of BP p.l.c. for the year ended 31 December 2009 and on the information in
the Directors’ remuneration report that is described as having been audited.

F
F
i
i
n
n
a
a
n
n
c
c
i
i
a
a
l
l
s
s
t
t
a
a
t
t
e
e
m
m
e
e
n
n
t
t
s
s

Ernst & Young LLP
Allister Wilson (Senior statutory auditor)
for and on behalf of Ernst & Young LLP, Statutory auditor
London
26 February 2010

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.

111

BP Annual Report and Accounts 2009
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 income
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
Finance costs
Net finance expense (income) relating to pensions and other post-retirement benefits
Profit before taxation
Taxation
Profit for the year
Attributable to

BP shareholders
Minority interest

Earnings per share – cents
Profit for the year attributable to BP shareholders

Basic
Diluted

Note
4

5
3

6
6
7
3
13
9
31

15
35

2009
239,272
1,286
2,615
792
2,173
246,138
163,772
23,202
3,752
12,106
2,333
1,116
14,038
(607)
26,426
1,110
192
25,124
8,365
16,759

16,578
181
16,759

2008
361,143
3,023
798
736
1,353
367,053
266,982
26,756
8,953
10,985
1,733
882
15,412
111
35,239
1,547
(591)
34,283
12,617
21,666

$ million

2007
284,365
3,135
697
754
2,487
291,438
200,766
24,225
5,703
10,579
1,679
756
15,371
7
32,352
1,393
(652)
31,611
10,442
21,169

21,157
509
21,666

20,845
324
21,169

18
18

88.49
87.54

112.59
111.56

108.76
107.84

112

BP Annual Report and Accounts 2009
Consolidated financial statements of the BP group

Group statement of comprehensive income

For the year ended 31 December

Profit for the year
Currency translation differences
Exchange gains 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
Taxation
Other comprehensive income
Total comprehensive income
Attributable to

BP shareholders
Minority interest

Group statement of changes in equity

Note

3
35

2009
16,759
1,826

(27)
(682)
705
2
652
366
136
525
3,503
20,262

20,137
125
20,262

2008
21,666
(4,362)

–
(8,430)
(994)
526
(1,173)
45
(38)
2,946
(11,480)
10,186

9,752
434
10,186

At 1 January
Total comprehensive income
Dividends
Repurchase of ordinary

share capital

Share-based payments

(net of tax)

Changes in associates’ equity
Minority interest buyout
At 31 December

BP
shareholders’
equity
91,303
20,137
(10,483)

–

721
(43)
(22)
101,613

Minority
interest
806
125
(416)

–

–
–
(15)
500

$ million

2007
21,169
1,887

(147)
1,717
200
(91)
155
(74)
(40)
(276)
3,331
24,500

24,152
348
24,500

$ million

2007

Total
equity
85,465
24,500
(8,333)

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

2009

Total
equity
92,109
20,262
(10,899)

BP
shareholders’
equity
93,690
9,752
(10,342)

2008

Total
equity
94,652
10,186
(10,767)

BP
shareholders’
equity
84,624
24,152
(8,106)

Minority
interest
962
434
(425)

Minority
interest
841
348
(227)

–

(2,414)

–

(2,414)

(7,997)

–

(7,997)

721
(43)
(37)
102,113

617
–
–
91,303

–
–
(165)
806

617
–
(165)
92,109

1,017
–
–
93,690

–
–
–
962

1,017
–
–
94,652

113

BP Annual Report and Accounts 2009
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
Deferred tax assets
Defined benefit pension plan surpluses

Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Cash and cash equivalents

Total assets
Current liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions

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

C-H Svanberg Chairman
Dr A B Hayward Group Chief Executive
26 February 2010

114

Note

2009

$ million

2008

19
20
21
22
23
25

27
31

16
35

26
27
31

30
31

32
16
34
35

37
37
37

108,275
8,620
11,548
15,296
12,963
1,567
158,269
1,039
1,729
3,965
1,407
516
1,390
168,315

249
22,605
29,531
4,967
1,753
209
8,339
67,653
235,968

35,204
4,681
6,202
9,109
2,464
1,660
59,320

3,198
3,474
703
25,518
18,662
12,970
10,010
74,535
133,855
102,113

5,179
96,434
101,613
500
102,113

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
228,238

33,644
8,977
6,743
15,740
3,144
1,545
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

BP Annual Report and Accounts 2009
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 expense (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
Decrease in other current and non-current assets
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 disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposed
Proceeds from loan repayments
Other

Net cash used in investing activities
Financing activities

Net issue (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 in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year

Note

2009

2008

$ million

2007

25,124

34,283

31,611

13
7
3

3
3

593
12,106
160
(3,901)
3,003
(258)
203
1,110
(909)
192
450

(887)
650
(5,363)
7,595
(5,828)
(6,324)
27,716

(20,650)
1
(578)
(164)
1,715
966
530
47
(18,133)

207
11,567
(6,021)
(4,405)

(10,483)
(416)
(9,551)
110
142
8,197
8,339

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

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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

115

BP Annual Report and Accounts 2009

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 2009 were approved and signed by the chairman
and group chief executive on 26 February 2010 having been duly
authorized to do so by the board of directors. BP p.l.c. is a public limited
company incorporated and domiciled in England and Wales. 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 2006. 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
2009, or issued and early adopted. The standards and interpretations
adopted in the year are described further on page 123.

The accounting policies that follow have been consistently applied

to all years presented. The group balance sheet as at 1 January 2008 is
not presented as it is not affected by the retrospective adoption of any
new accounting policies during the year, nor any other retrospective
restatements or reclassifications.

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 94 to 96, 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.

116

Segmental reporting
The group’s operating segments are established on the basis of those
components of the group that are evaluated regularly by the chief
operating decision maker in deciding how to allocate resources and in
assessing performance. The accounting policies of the operating
segments are the same as the group’s accounting policies described in
this note, except that IFRS requires that the measure of profit or loss
disclosed for each operating segment is the measure that is provided
regularly to the chief operating decision maker. For BP, this measure of
profit or loss is replacement cost profit before interest and tax which
reflects the replacement cost of supplies by excluding from profit
inventory holding gains and losses. Replacement cost profit for the
group is not a recognized measure under generally accepted accounting
practice (GAAP). For further information see Note 4.

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.

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. BP recognizes, on a line-by-line basis in the
consolidated financial statements, its share of the assets, liabilities and
expenses of these jointly controlled assets, along with the group’s
income from the sale of its share of the output and any liabilities and
expenses incurred in relation to the venture.

BP Annual Report and Accounts 2009
Notes on financial statements

1. Significant accounting policies continued

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 which 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.

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, other than
those measured at fair value, are not retranslated subsequent to
initial recognition.

In the consolidated financial statements, the assets and
liabilities 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
comprehensive income. 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 of exchange gains and losses
recognized in equity relating to that particular non-US dollar operation is
reclassified to 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. 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.

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. 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.

The cost of 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 investment 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.

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. The group ceases to use
the equity method of accounting on the date from which an interest in
a joint venture or an interest in an associate becomes held for sale.

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, and 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.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

117

BP Annual Report and Accounts 2009
Notes on financial statements

1. Significant accounting policies continued

Oil and natural gas exploration, appraisal and development
expenditure
Oil and natural gas exploration, appraisal and development expenditure
is accounted for using the principles of 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 and appraisal 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 potentially commercial quantities of
hydrocarbons are not found, the exploration expenditure is written off as
a dry hole. If hydrocarbons are found and, subject to further appraisal
activity, are likely to be capable of commercial development, the costs
continue to be carried as an asset.

Costs directly associated with appraisal activity, undertaken
to determine the size, characteristics and commercial potential of a
reservoir following the initial discovery of hydrocarbons, including the
costs of appraisal wells where hydrocarbons were not found, are initially
capitalized as an intangible 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 approved by
management, 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 service and 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.

118

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.
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 in which the item is derecognized.

BP Annual Report and Accounts 2009
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 the asset’s 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 within other comprehensive income. Accumulated
changes in fair value are recorded 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 the
income statement.

Available-for-sale financial assets
If an available-for-sale financial asset is impaired, the cumulative loss
previously recognized in equity is transferred to the income statement.
Any subsequent recovery in the fair value of the asset is recognized
within other comprehensive income.

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.

119

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
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.

After initial recognition, other financial liabilities are subsequently

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.

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:

(cid:129) Fair value hedges when hedging exposure to changes in the fair value

of a recognized asset or liability.

(cid:129) 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.

(cid:129) 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 for as follows:

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.

This category of financial liabilities includes trade and other

The group applies fair value hedge accounting for hedging fixed

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
e
or, if lower, at the present value of the minimum lease payments. Financ
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.

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 within other comprehensive income,
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 recognized within other comprehensive
income 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 within other comprehensive
income 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
reclassified to the income statement.

120

BP Annual Report and Accounts 2009
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 within
other comprehensive income, 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 of.

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 the income statement.

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.

Contingent liabilities are possible obligations whose existence will

only be confirmed by future events not wholly within the control of the
group. Contingent liabilities are not recognized in the financial statements
but are disclosed unless the possibility of an outflow of economic
resources is considered remote.

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 recognized. 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. Such changes include foreign exchange gains
and losses arising on the retranslation of the liability into the functional
currency of the reporting entity, when it is known that the liability will
be settled in a foreign currency.

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). Non-vesting conditions, such as the
condition that employees contribute to a savings-related plan, are taken
into account in the grant-date fair value, and failure to meet a non-vesting
condition is treated as a cancellation, where this is within the control of
the employee.

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.

When 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.

When 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.

121

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
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.
The interest element of the defined benefit cost represents

the 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 plan 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 within other

comprehensive income in the period in which they occur.

The defined benefit pension plan surplus or deficit in the balance

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.

Deferred tax liabilities are recognized for all taxable temporary
differences:
(cid:129) Except where the deferred tax liability arises on goodwill that is

(cid:129)

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 credits 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 credits and unused tax losses can be utilized:
(cid:129) Except where the deferred income tax asset relating to the

(cid:129)

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.
In respect of deductible temporary differences associated with
investments in subsidiaries, jointly controlled entities and associates,
deferred tax assets are recognized only 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.

Tax relating to items recognized directly in equity is recognized in

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:
(cid:129) Where the customs duty or sales tax incurred on a purchase of

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.

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.

The tax currently payable is based on the taxable profits for the

(cid:129) Receivables and payables are stated with the amount of customs

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.

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.

122

BP Annual Report and Accounts 2009
Notes on financial statements

1. Significant accounting policies continued

Revenue
Revenue arising from the sale of goods is recognized when the
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 2009
The following new IFRS, and revised or amended IFRSs were adopted
by the group with effect from 1 January 2009, IFRS 8 ‘Operating
Segments’ was issued in November 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. BP’s operating segments did not change as a result of
adopting the new standard and there was no effect on the group’s
reported income or net assets. The disclosures required by the standard
are included in this report, including the measures as used by the chief
operating decision maker.

In September 2007, the IASB issued a revised version of IAS 1
‘Presentation of Financial Statements’, 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 is no longer 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. There was no effect on the group’s reported income or net
assets as a result of the adoption of this revised standard.

In March 2009, the IASB issued Amendments to IFRS 7

‘Financial Instruments: Disclosures – Improving Disclosures about
Financial Instruments’, which requires enhanced disclosures about fair
value measurements and liquidity risk. There was no effect on the
group’s reported income or net assets. The disclosures required by the
standard are included in this report.

In addition, several other standards and interpretations

were adopted in the year which 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.

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 the 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 will adopt it with effect from
1 January 2010. Assets and liabilities arising from business combinations
that occurred 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 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. 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 will adopt the amendment
with effect from 1 January 2010 and there will be no effect on the
group’s reported income or net assets on adoption. The revised standard
has been adopted by the EU.

In November 2009, the IASB issued IFRS 9 ‘Financial
Instruments’ which deals with the classification and measurement of
financial assets. This new standard represents the first phase of the
IASB’s project to replace IAS 39 ‘Financial Instruments: Recognition and
Measurement’. The new standard is effective for annual periods
beginning on or after 1 January 2013 with transitional arrangements
depending upon the date of initial application. BP has not yet decided the
date of initial application for the group and has not yet completed its
evaluation of the effect of adoption. The new standard has not yet been
adopted by the EU.

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.

123

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
Notes on financial statements

2. Acquisitions

Acquisitions in 2009
BP made no significant acquisitions in 2009.

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 were made to the acquired assets and liabilities.

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 22.5MW 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. Fair value adjustments were made to the acquired assets and liabilities. Goodwill of $270 million arose on these acquisitions.

3. Disposals and impairment

Proceeds from disposal of businesses, net of cash disposed of
Proceeds from disposal of fixed assets

By business

Exploration and Production
Refining and Marketing
Other businesses and corporate

2009
966
1,715
2,681

940
1,294
447
2,681

2008
11
918
929

19
813
97
929

$ million

2007
2,518
1,749
4,267

1,280
2,953
34
4,267

Deferred consideration relating to disposals of businesses and fixed assets at 31 December 2009 amounted to $807 million receivable within one year
(2008 $15 million and 2007 $22 million) and $691 million receivable after one year (2008 $64 million and 2007 $84 million).

Gains on sale of businesses and fixed assets

Exploration and Production
Refining and Marketing
Other businesses and corporate

Losses on sale of businesses and fixed assets

Exploration and Production
Refining and Marketing
Other businesses and corporate

Impairment losses

Exploration and Production
Refining and Marketing
Other businesses and corporate

Impairment reversals

Exploration and Production
Other businesses and corporate

Impairment and losses on sale of businesses and fixed assets

124

2009

2008

1,717
384
72
2,173

2009

28
154
21
203

118
1,834
189
2,141

(3)
(8)
(11)
2,333

34
1,258
61
1,353

2008

18
297
1
316

1,186
159
227
1,572

(155)
–
(155)
1,733

$ million

2007

954
1,464
69
2,487

$ million

2007

42
313
–
355

292
1,186
83
1,561

(237)
–
(237)
1,679

BP Annual Report and Accounts 2009
Notes on financial statements

3. Disposals and impairment continued
Disposals
As part of the strategy to upgrade the quality of its asset portfolio, the group has an active programme to dispose of non-strategic assets. In the
normal course of business in any particular year, the group may sell interests in exploration and production properties, service stations and pipeline
interests as well as non-core businesses. The group may also dispose of other assets, such as refineries, when this meets strategic objectives.

Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. In 2009, the major transactions were the sale of BP West
Java Limited in Indonesia, the sale of our 49.9% interest in Kazakhstan Pipeline Ventures LLC and the sale of our 46% stake in LukArco, all of which
resulted in gains. We also exchanged interests in a number of fields in the North Sea with BG Group plc.

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, all of which resulted in gains. We
also sold our interests in a number of fields in Egypt, Canada and the US.

Refining and Marketing
In 2009, gains on disposal mainly resulted from the disposal of our ground fuels marketing business in Greece and retail churn in the US, Europe and
Australasia. Losses resulted from the continued disposal of company-owned and company-operated retail sites in the US, retail churn and disposals of
assets elsewhere in the segment portfolio. 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.

In 2008, the major transactions resulting in gains were the contribution of our Toledo refinery to a US jointly controlled entity in an exchange

transaction with Husky Energy and the disposals of our interest in the Dixie Pipeline and certain retail assets in the US. The losses on sale related
mainly to the disposal of retail assets in the US and Europe. In addition, certain assets at our Acetyls plant in Hull, UK, and other interests in the UK
and Europe were sold.

During 2007, we disposed of the Coryton refinery in the UK, our interest in the West Texas Pipeline in the US, and our interest in the Samsung

Petrochemical Company in South Korea, all of which resulted in gains. Losses were incurred related to the decision to withdraw from the company-
owned and company-operated channel of trade in the US and retail churn.

Other businesses and corporate
During 2009, we disposed of our wind energy business in India and contributed our Fowler II wind energy development asset in exchange for a 50%
equity interest in a jointly controlled entity, Fowler II Holdings LLC. In addition, there was a return of capital in the jointly controlled entity Fowler Ridge
Wind Farm LLC which did not change our percentage interest in the entity.

Summarized financial information for the sale of businesses is shown below.

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
Proceeds from the sale of businessesc

2009
536
444
(146)
(152)
682
(27)
3
658
314
972
–
(6)
966

2008
759
485
–
(134)
1,110
–
7
1,117
1,721
2,838
(2,838)
11
11

$ million

2007
753
587
(64)
(27)
1,249
(147)
22
1,124
1,384
2,508
–
10
2,518

a Of which $929 million gain was not recognized in the income statement in 2008 as it represented an unrealized gain on the transfer of the Toledo refinery into a jointly controlled entity.
b Consideration received from prior year business disposals or not yet received from current year disposals.
c Net of cash and cash equivalents disposed of $91 million (2008 nil and 2007 $115 million).

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

125

BP Annual Report and Accounts 2009
Notes on financial statements

3. Disposals and impairment continued
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, the asset’s 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. 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,
although other rates may be used if appropriate to the specific circumstances. In 2009 the rates ranged from 9% to 13% (2008 11% to 13%). The rate
applied in each country is re-assessed each year. In certain circumstances the fair value less costs to sell may be available for an asset. On occasion,
an impairment assessment may be carried out using fair value less costs to sell as the recoverable amount when, for example, a recent market
transaction for a similar asset has taken place. 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 loss previously recognized in other
comprehensive income is transferred to the income statement.

Exploration and Production
During 2009, the Exploration and Production segment recognized impairment losses of $118 million. The main elements were the write-down of our
$42 million investment in the East Shmidt interest in Russia, triggered by a decision to not proceed to development; a $62 million charge associated
with our nErgize gas scheduling system; and several other individually insignificant impairment charges amounting to $14 million.

During 2008, the Exploration and Production segment recognized impairment losses of $1,186 million. The main elements were the write-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 (see Note 25), 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,
impaiment 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 losses 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.

Refining and Marketing
During 2009, an impairment loss of $1,579 million was recognized against the goodwill allocated to the US West Coast fuels value chain (FVC). The
goodwill was originally recognized at the time of the ARCO acquisition in 2000. The prevailing weak refining environment, together with a review of
future margin expectations in the FVC, has led to a reduction in the expected future cash flows. Further information, including details of the group’s
approach to impairment reviews of goodwill, is given in Note 8. Other impairment losses were also recognized by the segment on a number of assets
which amounted to $255 million.

During 2008, the Refining and Marketing segment recognized impairment losses on a number of assets which 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 to $165 million. The balance relates principally to the write-downs of assets elsewhere
in the segment portfolio.

Other businesses and corporate
During 2009 and 2008, Other businesses and corporate recognized impairment losses totalling $189 million and $227 million respectively related to
various assets in the Alternative Energy business. The impairment loss of $83 million in 2007 related to various individually insignificant write-downs.

4. Segmental analysis

The group’s organizational structure reflects the different activities in which BP is engaged. In 2009, BP had two reportable segments: Exploration and
Production and Refining and Marketing. BP’s activities in low-carbon energy are managed through our Alternative Energy business, which is reported
in Other businesses and corporate. The group is managed on an integrated basis.

Exploration and Production’s activities cover three key areas. Upstream activities include oil and natural gas exploration, field development and

production. Midstream activities include pipeline, transportation and processing activities related to our upstream activities. Marketing and trading
activities include the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs).

Refining and Marketing’s activities include the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum

and petrochemicals products and related services.

126

BP Annual Report and Accounts 2009
Notes on financial statements

4. Segmental analysis continued
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 Alternative Energy
business is an operating segment that has been aggregated with the other activities within Other businesses and corporate as it does not meet the
materiality thresholds for separate segment reporting.

The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS
requires that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating
decision maker for the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit
before interest and tax which reflects the replacement cost of supplies by excluding from profit inventory holding gains and lossesa. Replacement cost
profit for the group is not a recognized GAAP measure.

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. Sales to external customers are based on the
location of the seller. The UK region includes the UK-based international activities of Refining and Marketing.

All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to
Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the other operating segments based upon the
business in which the employees work.

Certain financial information is provided separately for the US as this is an individually material country for BP, and for the UK as this is BP’s

country of domicile.

By business
Segment revenues
Sales and other operating revenues
Less: sales between businesses
Third party sales and other operating revenues
Equity-accounted earnings
Interest revenues
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gainsa
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Fair value (gain) loss on embedded derivatives
Charges for provisions, net of write-back of unused provisions,

including change in discount rate

Segment assets
Segment assets
Current tax receivable
Deferred tax assets
Total assets
Includes

Equity-accounted investments

Additions to non-current assets

Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset

Exploration
and
Production

Refining
and
Marketing

Other Consolidation
adjustment
and
eliminations

businesses
and
corporate

57,626
(32,540)
25,086
3,309
98

24,800
142
24,942

213,050
(821)
212,229
558
32

743
3,774
4,517

2,843
(886)
1,957
34
95

(2,322)
6
(2,316)

(34,247)
34,247
–
–
–

(717)
–
(717)

9,557
118
3
(664)

2,236
1,834
–
57

307

756

313
189
8
–

488

–
–
–
–

–

140,149

82,224

17,954

(5,084)

20,289
15,855

6,882
4,083

1,088
1,297

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

$ million

2009

Total
group

239,272
–
239,272
3,901
225

22,504
3,922
26,426
(1,110)
(192)
25,124

12,106
2,141
11
(607)

1,551

235,243
209
516
235,968

28,259
21,235
19
(7)
(938)
20,309

–
–

–

Capital expenditure and acquisitions

14,896

4,114

1,299

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 period 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.

127

BP Annual Report and Accounts 2009
Notes on financial statements

4. Segmental analysis continued

By business
Segment revenues
Sales and other operating revenues
Less: sales between businesses
Third party sales and other operating revenues
Equity-accounted earnings
Interest revenues
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding lossesa
Profit (loss) before interest and taxation
Finance costs
Net finance income relating to pensions and other post-retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Fair value (gain) loss on embedded derivatives
Charges for provisions, net of write-back of unused provisions
Segment assets
Segment assets
Current tax receivable
Total assets
Includes

Equity-accounted investments

Additions to non-current assets

Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset

Exploration
and
Production

Refining
and
Marketing

Other
businesses
and
corporate

Consolidation
adjustment
and
eliminations

$ million

2008

Total
group

86,170
(45,931)
40,239
3,565
114

38,308
(393)
37,915

320,039
(1,918)
318,121
131
35

4,176
(6,060)
(1,884)

4,634
(1,851)
2,783
125
220

(1,223)
(35)
(1,258)

8,440
1,186
155
163
573

2,208
159
–
(57)
479

337
227
–
5
657

20,131

21,584

6,622

6,636

1,073

1,802

(49,700)
49,700
–
–
–

361,143
–
361,143
3,821
369

466
–
466

–
–
–
–
–

–

41,727
(6,488)
35,239
(1,547)
591
34,283

10,985
1,572
155
111
1,709

227,861
377
228,238

27,826

30,022
52
11
615
30,700

136,665

75,329

19,079

(3,212)

Capital expenditure and acquisitions

22,227

6,634

1,839

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 period 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.

128

BP Annual Report and Accounts 2009
Notes on financial statements

4. Segmental analysis continued

B
y business
egment revenues
S
ales and other operating revenues
S
ess: sales between businesses
L
hird party sales and other operating revenues
T
E
quity-accounted earnings
nterest revenues
I
S
egment results
R
eplacement cost profit (loss) before interest and taxation
nventory holding gains (losses)a
I
P
rofit (loss) before interest and taxation
F
inance costs
N
et finance income relating to pensions and other post-retirement benefits
P
rofit before taxation
O
ther income statement items
D
epreciation, depletion and amortization
I
mpairment losses
I
mpairment reversals
F
air value loss on embedded derivatives
C
harges for provisions, net of write-back of unused provisions
S
egment assets
S
egment assets
C
urrent tax receivable
otal assets
T
ncludes
I

Equity-accounted investments

dditions to non-current assets

Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset

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
202

27,602
127
27,729

250,221
(1,914)
248,307
542
30

2,621
3,455
6,076

3,698
(1,297)
2,401
91
217

(1,209)
(24)
(1,233)

7,856
292
237
–
484

2,421
1,186
–
–
638

302
83
–
7
280

16,770

15,535

5,268

5,437

654

916

(35,294)
35,294
–
–
–

284,365
–
284,365
3,832
449

(220)
–
(220)

–
–
–
–
–

–

28,794
3,558
32,352
(1,393)
652
31,611

10,579
1,561
237
7
1,402

235,371
705
236,076

22,692

21,888
23
56
(1,326)
20,641

125,736

95,311

20,595

(6,271)

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

apital expenditure and acquisitions

14,207

5,495

939

a I
nventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies incurred during the period and the cost of sales calculated
n 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,
o
he 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
t
s
ignificant 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
ealizable 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
r
d
ividing 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
djustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.
a

129

BP Annual Report and Accounts 2009
Notes on financial statements

4. Segmental analysis continued

By geographical area
Revenues
Third party sales and other operating revenuesa
Results
Replacement cost profit before interest and taxation
Non-current assets
Other non-current assetsb c
Other investments
Loans
Other receivables
Derivative financial instruments
Deferred tax assets
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions

a Non-US region includes UK $51,172 million.
b
Non-US region includes UK $16,713 million.
c Excluding financial instruments, deferred tax assets and post-employment benefit plan surpluses.

By geographical area
Revenues
Third party sales and other operating revenuesa
Results
Replacement cost profit before interest and taxation
Non-current assets
Other non-current assetsb c
Other investments
Loans
Other receivables
Derivative financial instruments
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions

a Non-US region includes UK $81,773 million.
b Non-US region includes UK $15,990 million.
c Excluding financial instruments, and post-employment benefit plan surpluses.

By geographical area
Revenues

Third party sales and other operating revenuesa

Results

Replacement cost profit before interest and taxation

Non-current assets

Other non-current assetsb c
Other investments
Loans
Other receivables
Derivative financial instruments
Defined benefit pension plan surplus
Total non-current assets
Capital expenditure and acquisitions

a Non-US region includes UK $61,149 million.
b Non-US region includes UK $19,302 million.
c Excluding financial instruments and post-employment benefit plan surpluses.

130

Non-US

$ million

2009

Total

83,982

155,290

239,272

2,806

19,698

22,504

64,529

93,580

9,865

10,444

Non-US

158,109
1,567
1,039
1,729
3,965
516
1,390
168,315
20,309

$ million

2008

Total

123,364

237,779

361,143

10,678

31,049

41,727

62,679

89,823

16,046

14,654

Non-US

152,502
855
995
710
5,054
1,738
161,854
30,700

$ million

2007

Total

102,319

182,046

284,365

5,581

23,213

28,794

51,840

87,582

7,487

13,154

139,422
1,830
999
968
3,741
8,914
155,874
20,641

BP Annual Report and Accounts 2009
Notes on financial statements

5. Interest and other income

Interest income

Interest income from available-for-sale financial assetsa
Interest income from loans and receivablesa
Interest from loans to equity-accounted entities
Other interest

Other income

Dividend income from available-for-sale financial assetsa
Other income

aTotal interest and other income related to financial instruments amounted to $116 million (2008 $232 million and 2007 $209 million).

6. Production and similar taxes

US
Non-US

2009

2008

$ million

2007

15
69
53
88
225

32
535
567
792

32
163
115
59
369

37
330
367
736

5
175
172
97
449

29
276
305
754

2009
649
3,103
3,752

2008
2,602
6,351
8,953

$ million

2007
1,260
4,443
5,703

Comparative figures have been restated to include amounts previously reported as production and manufacturing expenses amounting to $2,427 million
for 2008 and $1,690 million for 2007 which we believe are more appropriately classified as production taxes. There was no effect on the group profit or
the group balance sheet.

7. Depreciation, depletion and amortization

By business
Exploration and Production

US
Non-US

Refining and Marketing

US
Non-USa

Other businesses and corporate

US
Non-US

By geographical area

US
Non-USa

a Non-US area includes the UK-based international activities of Refining and Marketing.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

2009

2008

4,150
5,407
9,557

919
1,317
2,236

136
177
313

3,012
5,428
8,440

825
1,383
2,208

132
205
337

$ million

2007

2,365
5,491
7,856

1,076
1,345
2,421

117
185
302

5,205
6,901
12,106

3,969
7,016
10,985

3,558
7,021
10,579

131

BP Annual Report and Accounts 2009
Notes on financial statements

8. Impairment review of goodwill

Goodwill at 31 December
Exploration and Production
Refining and Marketing
Other businesses and corporate

2009
4,297
4,245
78
8,620

$ million

2008
4,297
5,462
119
9,878

Goodwill acquired through business combinations has been allocated to groups of 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. 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 2009 (2008 11%).

The 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.

Exploration and Production

Goodwill
Excess of recoverable amount over carrying amount

UK
341
7,721

US
3,441
15,528

Rest of
World
515
n/a

2009

Total
4,297
n/a

UK
341
7,972

US
3,441
16,692

Rest of
World
515
n/a

$ million

2008

Total
4,297
n/a

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. As the production profile and related cash flows can be estimated from the company’s past
experience, 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. 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 2009 review for impairment was carried out during the fourth quarter. As permitted by IAS 36, the detailed

calculations of recoverable amount performed in 2008 for the US and the UK, and calculations performed in 2005 for the Rest of World, were used for
the 2009 impairment test as the criteria of IAS 36 were considered to be satisfied: the excess of the recoverable amount over the carrying amount (the
headroom) was substantial in 2008 (for the US and the UK) and 2005 (for the Rest of World); 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 table above shows the carrying amount of the goodwill allocated to each of the regions of the Exploration and Production segment and,

where required, the headroom in the cash-generating units to which the goodwill has been allocated. The estimates of headroom at 31 December
2009 for the UK and the US are based on recoverable amounts determined in 2008 and carrying amounts at 31 December 2009. No impairment
charge is required.

For 2008, the Brent oil price assumption was 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. The Henry Hub natural gas price assumption was 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. The prices for
the first five years were derived from forward price curves at the year-end. Prices in 2014 and beyond were 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
were adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas.

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 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.

132

BP Annual Report and Accounts 2009
Notes on financial statements

8. Impairment review of goodwill continued
In the prior year it was estimated that the long-term price of oil that would cause the recoverable amount to be equal to the 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 was 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. In 2008, it was 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.

Refining and Marketing

Goodwill
Excess of recoverable amount

over carrying amount

Rhine FVC
655

Lubricants
3,416

Other
174

2009

Total
4,245

Rhine FVC
637

US West
Coast FVC
1,579

Lubricants
3,043

2,034

n/a

3,603

1,629

5,445

$ million

2008

Total
5,462

n/a

Other
203

n/a

For all cash-generating units, the cash flows for the first two or five years are derived from the 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.

Rhine FVC
As a result of the continuing integration of our businesses into fuels value chains, convenience retail operations in the Rhine region were incorporated
into the Rhine FVC from the beginning of 2009. The key assumptions to which the calculation of value in use for the Rhine FVC is most sensitive are
refinery gross margins, production volumes, and discount rate. Refinery gross margins used in the plan are derived from assumptions that are
consistent with those used to develop the regional Global Indicator Margin (GIM). The regional GIM is based on a single representative crude with
product yields characteristic of the typical level of upgrading complexity available in the region. The average values assigned to the regional GIM and
refinery production volume over the plan period are $4.05 per barrel and 254mmbbl a year (2008 $5.50 per barrel and 250mmbbl a year). The values
reflect past experience and are consistent with external sources. Cash flows beyond the five-year plan period are extrapolated using a 2.4% growth rate
(2008 cash flows beyond the three-year plan period were extrapolated using a 1.2% growth rate).

Sensitivity analysis

Sensitivity of value in use to a change in refinery margins of $1 per barrel ($ billion)
Adverse change in refinery margins to reduce recoverable amount to carrying amount ($ per barrel)
Sensitivity of value in use to a 5% change in production volume ($ billion)
Adverse change in production volume to reduce recoverable amount to carrying amount (mmbbl per year)
Sensitivity of value in use to a change in the discount rate of 1% ($ billion)
Discount rate to reduce recoverable amount to carrying amount

2009

2.2
0.9
0.8
31
0.8
14%

Lubricants
The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and
discount rate. The values assigned to these key assumptions reflect past experience. No reasonably possible change in any of these key assumptions
would cause the unit’s carrying amount to exceed its recoverable amount. For 2008 the average values assigned to the operating margin and sales
volumes over the plan period were 70 cents per litre and 3.4 billion litres per year, respectively. Cash flows beyond the two-year plan period are
extrapolated using a 3% growth rate (2008 cash flows beyond the three-year plan period were extrapolated using a 3% growth rate).

US West Coast FVC
As disclosed in Note 3, the impairment review of goodwill allocated to the US West Coast FVC resulted in the recognition of an impairment loss in
2009 to write off the entire balance of $1,579 million. The key assumptions to which the calculation of value in use for the US West Coast FVC was
most sensitive in 2008 were refinery gross margins, production volumes and discount rates. The average value assigned to the refinery gross
margin during the plan period was based on a $7.60 per barrel regional GIM. The average value assigned to the production volume was 170mmbbl a
year over the plan period. Cash flows beyond the three-year plan period were extrapolated using a 2% growth rate. These assumptions reflected
past experience and were consistent with external sources.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

133

BP Annual Report and Accounts 2009
Notes on financial statements

9. Distribution and administration expenses

Distribution
Administration

10. Currency exchange gains and losses

Currency exchange (gains) losses (credited) charged to incomea

aExcludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.

11. Research and development

Expenditure on research and development

12. Operating leases

2009

2008

12,798
1,240
14,038

14,075
1,337
15,412

$ million

2007

14,028
1,343
15,371

2009
193

2008
156

$ million

2007
(201)

2009
587

2008
595

$ million

2007
566

The presentation of operating lease expense and future minimum lease payments has been revised in 2009 in order to provide more meaningful
information about the costs incurred by BP under these arrangements, and the associated future commitments. The comparative information has been
amended to conform to the revised presentation.

In the case of an operating lease entered into by BP as the operator of a jointly controlled asset, the amounts shown in the tables below

represent the net operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or
to be reimbursed, by joint venture partners, whether the joint venture partners have co-signed the lease or not. Where BP is not the operator of a
jointly controlled asset, BP’s share of the lease expense and future minimum lease payments is included in the amounts shown, whether BP has
co-signed the lease or not.

The table below shows the expense for the year in respect of operating leases.

Minimum lease payments
Contingent rentals
Sub-lease rentals

2009

4,109
(9)
(133)
3,967

2008

4,114
97
(194)
4,017

$ million

2007

3,522
80
(183)
3,419

The future minimum lease payments at 31 December, before deducting related rental income from operating sub-leases of $379 million (2008 $547 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

134

2009

3,251
7,334
4,131
14,716

$ million

2008

3,659
7,628
4,864
16,151

BP Annual Report and Accounts 2009
Notes on financial statements

12. Operating leases continued
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.

At 31 December 2009 the future minimum lease payments relating to drilling rigs amounted to $4,919 million (2008 $5,531 million). 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 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.

13. 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
Net cash used in operating activities
Net cash used in investing activities

2009

2008

593
523
1,116
10,388
10,388
2,715
523
3,306

385
497
882
9,031
9,031
4,780
497
4,163

$ million

2007

347
409
756
5,252
5,252
2,000
409
2,000

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

a In 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.

135

BP Annual Report and Accounts 2009
Notes on financial statements

14. 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

2009
13

2008
16

$ million

2007
18

22
11
46
1
–
6
1
54

28
13
57
2
2
5
1
67

31
14
63
2
1
8
1
75

a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.

2008 includes $3 million of additional fees for 2007 and 2007 includes $7 million of additional fees for 2006. Auditors’ 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.

Under SEC regulations, the remuneration of the auditor of $54 million (2008 $67 million and 2007 $75 million) is required to be presented as

follows: audit services $46 million (2008 $57 million and 2007 $63 million); other audit related services $2 million (2008 $1 million and 2007 $3 million);
tax services $1 million (2008 $2 million and 2007 $2 million); and fees for all other services $5 million (2008 $7 million and 2007 $7 million).

15. Finance costs

Interest payable
Capitalized at 2.75% (2008 4.00% and 2007 5.70%)a
Unwinding of discount on provisions
Unwinding of discount on other payables

a Tax relief on capitalized interest is $63 million (2008 $42 million and 2007 $81 million).

2009
906
(188)
247
145
1,110

2008
1,319
(162)
287
103
1,547

$ million

2007
1,433
(323)
283
–
1,393

136

BP Annual Report and Accounts 2009
Notes on financial statements

16. Taxation

Tax on profit

Current tax

Charge for the year
Adjustment in respect of prior years

Deferred tax

Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years

Tax on profit
Tax included in other comprehensive income

Current tax
Deferred tax

Tax included directly in equity

Deferred tax

2009

2008

6,045
(300)
5,745

2,131
489
2,620
8,365

2009
–
(525)
(525)

2009
(65)

13,468
(85)
13,383

(324)
(442)
(766)
12,617

2008
(264)
(2,682)
(2,946)

2008
190

$ million

2007

10,006
(171)
9,835

671
(64)
607
10,442

$ million

2007
(178)
454
276

$ million

2007
(213)

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.

Profit before taxation
Tax on profit
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)
Goodwill impairment
Tax incentives for investment
Other

Effective tax rate

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

2009
25,124
8,365
33%

2008
34,283
12,617
37%

$ million

2007
31,611
10,442
33%

8
(3)
1
–
2
(2)
(1)
33

% of profit before taxation
30

14
(2)
(2)
(1)
–
(1)
1
37

8
(2)
(1)
(1)
–
–
(1)
33

137

BP Annual Report and Accounts 2009
Notes on financial statements

16. 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 credits
Loss carry forward
Other deductible temporary differences

Net deferred tax (credit) charge and net deferred tax liability
Of which – deferred tax liabilities

– deferred tax assets

Analysis of movements during the year
At 1 January
Exchange adjustments
Charge (credit) for the year on profit
Charge (credit) for the year in other comprehensive income
Charge (credit) for the year in equity
Deletions
Other movements
At 31 December

Income statement

$ million

Balance sheet

2009

2008

2007

2009

2008

1,983
(6)
978
2,955

44
180
86
80
(516)
402
(611)
(335)
2,620

1,248
108
(2,471)
(1,115)

121
104
(333)
228
330
(212)
111
349
(766)

125
127
1,371
1,623

139
(72)
(1,069)
450
(384)
(82)
2
(1,016)
607

25,398
271
4,307
29,976

(142)
(2,269)
(4,930)
(243)
(1,034)
(1,014)
(2,198)
(11,830)
18,146
18,662
516

2009
16,198
(7)
2,620
(525)
(65)
(75)
–
18,146

23,342
412
3,626
27,380

(192)
(2,414)
(4,860)
(331)
(519)
(1,302)
(1,564)
(11,182)
16,198
16,198
–

$ million

2008
19,215
(67)
(766)
(2,682)
190
–
308
16,198

In 2009 and 2008, there have been no changes in the statutory tax rates that have materially impacted the group’s tax charge. In 2007 the enactment
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 credits and unused tax losses can be utilized.

At 31 December 2009, the group had approximately $4.2 billion (2008 $6.3 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 $3.2 billion of losses (2008
$4.2 billion). No deferred tax asset has been recognized in respect of $1.0 billion of losses (2008 $2.1 billion). In 2009 the group has been able to utilize
$1.1 billion of the losses, previously unrecognized, through other comprehensive income. Of the $1.0 billion losses with no deferred tax asset,
$0.2 billion expire in three years and $0.8 billion have no fixed expiry date.

At 31 December 2009, the group had approximately $3.0 billion of unused tax credits predominantly in the US (2008 $3.4 billion in the UK and
US). Due to legislative changes in the UK that repealed double taxation relief in relation to foreign dividends, onshore pooling and utilization of eligible
unrelieved foreign tax, there are now no UK tax credits carried forward at 31 December 2009. A deferred tax asset of $1.0 billion has been recognized
in 2009 in respect of unused tax credits (2008 $0.5 billion). No deferred tax asset has been recognized in respect of $2.0 billion of tax credits (2008
$2.9 billion). The US tax credits with no deferred tax asset, amounting to $2.0 billion (2008 $1.8 billion) expire 10 years after generation, and
substantially all expire in the period 2014-2019.

The major components of temporary differences at the end of 2009 are tax depreciation, US inventory holding gains (classified as other taxable

temporary differences), provisions and pension plan and other post-retirement benefit plan deficits.

In 2009 there are no material temporary differences associated with investments in subsidiaries and equity-accounted entities for which

deferred tax liabilities have not been recognized.

138

BP Annual Report and Accounts 2009
Notes on financial statements

17. Dividends

2009

2008

2007

2009

2008

2007

2009

2008

pence per share

cents per share

$ million

2007

Dividends announced and paid

Preference shares
Ordinary shares
March
June
September
December

Dividend announced per ordinary
share, payable in March 2010

9.818
9.584
8.503
8.512
36.417

8.679

6.813
6.830
7.039
8.705
29.387

5.258
5.151
5.278
5.308
20.995

14.000
14.000
14.000
14.000
56.000

13.525
13.525
14.000
14.000
55.050

10.325
10.325
10.825
10.825
42.300

2,619
2,619
2,620
2,623
10,483

2,553
2,545
2,623
2,619
10,342

2,000
1,983
2,065
2,056
8,106

–

14.000

–

2,626

–

The group does not account for dividends until they are paid. The accounts for the year ended 31 December 2009 do not reflect the dividend
announced on 2 February 2010 and payable in March 2010; this will be treated as an appropriation of profit in the year ended 31 December 2010.

18. Earnings per ordinary share

Basic earnings per share
Diluted earnings per share

2009
88.49
87.54

cents per share

2008
112.59
111.56

2007
108.76
107.84

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.

Profit attributable to BP shareholders
Less dividend requirements on preference shares
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

2009
16,578
2
16,576

2008
21,157
2
21,155

$ million

2007
20,845
2
20,843

shares thousand

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

2009

2008

2007
18,732,459 18,789,827 19,163,389
163,486
18,935,691 18,962,517 19,326,875

172,690

203,232

The number of ordinary shares outstanding at 31 December 2009, 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 18,755,378,211. Between 31 December 2009 and 18 February 2010, the
latest practicable date before the completion of these financial statements, there has been a net increase of 12,018,689 in the number of ordinary
shares outstanding as a result of share issues in relation to employee share schemes. The number of potential ordinary shares issuable through the
exercise of employee share schemes was 215,123,696 at 31 December 2009. There has been an increase of 264,627 in the number of potential
ordinary shares between 31 December 2009 and 18 February 2010.

139

BP Annual Report and Accounts 2009
Notes on financial statements

19. Property, plant and equipment

Cost

At 1 January 2009
Exchange adjustments
Additions
Transfers
Deletions

At 31 December 2009
Depreciation

At 1 January 2009
Exchange adjustments
Charge for the year
Impairment losses
Deletions

At 31 December 2009
Net book amount at 31 December 2009
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
Net book amount at 1 January 2008

Assets held under finance leases at net book amount
included above
At 31 December 2009
At 31 December 2008

Decommissioning asset at net book amount included above

At 31 December 2009
At 31 December 2008

Assets under construction included above

At 31 December 2009
At 31 December 2008

Land
and land
improve-
ments

Buildings

3,964
148
59
–
(385)
3,786

598
19
31
88
(165)
571
3,215

4,516
(320)
–
64
–
(296)
3,964

718
(30)
32
21
–
–
(143)
598
3,366
3,798

2,742
85
313
–
(222)
2,918

1,313
38
102
53
(117)
1,389
1,529

3,150
(287)
–
161
–
(282)
2,742

1,533
(118)
79
33
–
–
(214)
1,313
1,429
1,617

Oil and
gas
properties

146,813
2
11,928
745
(2,291)
157,197

79,955
–
8,951
10
(1,941)
86,975
70,222

134,615
(1)
136
12,571
(454)
(54)
146,813

72,486
–
7,490
469
(122)
(352)
(16)
79,955
66,858
62,129

Plant,
machinery
and
equipment

Fixtures,
fittings and
office
equipment

37,905
877
3,743
–
(926)
41,599

17,298
446
1,372
185
(398)
18,903
22,696

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
18,948

3,045
83
145
–
(251)
3,022

1,696
54
302
10
(169)
1,893
1,129

3,169
(237)
–
530
(1)
(416)
3,045

1,820
(147)
313
1
–
(1)
(290)
1,696
1,349
1,349

Oil depots,
storage
tanks and
service
stations

10,345
546
739
–
(1,335)
10,295

5,507
272
618
52
(1,049)
5,400
4,895

11,410
(1,047)
–
842
–
(860)
10,345

6,002
(502)
709
19
–
–
(721)
5,507
4,838
5,408

$ million

Total

217,109
1,807
17,042
745
(5,445)
231,258

113,909
859
11,665
406
(3,856)
122,983
108,275

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
97,989

Transport-
ation

12,295
66
115
–
(35)
12,441

7,542
30
289
8
(17)
7,852
4,589

11,866
(98)
–
243
454
(170)
12,295

7,126
(41)
296
–
–
274
(113)
7,542
4,753
4,740

–
–

14
12

225
237

110
107

–
–

7
8

19
18

375
382

Cost

Depreciation

Net

7,968
7,140

4,129
3,659

3,839
3,481

19,120
17,213

a Includes $337 million transferred to equity-accounted investments and $415 million transferred from intangible assets.
b Includes $75 million transferred to equity-accounted investments.

140

BP Annual Report and Accounts 2009
Notes on financial statements

20. Goodwill

Cost

At 1 January
Exchange adjustments
Acquisitions
Additions
Deletions
At 31 December
Impairment losses
At 1 January
Impairment losses for the year

At 31 December
Net book amount at 31 December

21. Intangible assets

Cost

At 1 January
Exchange adjustments
Acquisitions
Additionsa
Transfers
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

2009

9,878
350
–
–
(29)
10,199

–
(1,579)
(1,579)
8,620

Exploration
and appraisal
expenditure

Other
intangibles

9,425
8
–
2,715
(745)
(690)
10,713

394
–
593
–
(662)
325
10,388
9,031

2,927
75
–
441
–
(159)
3,284

1,698
32
441
90
(137)
2,124
1,160
1,229

2009

Total

12,352
83
–
3,156
(745)
(849)
13,997

2,092
32
1,034
90
(799)
2,449
11,548
10,260

Exploration
and appraisal
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

a Included in additions to exploration and appraisal expenditure in 2008 is $2,331 million in relation to BP's purchase of interests in shale gas assets in the US.

$ million

2008

11,006
(1,112)
1
39
(56)
9,878

–
–
–

9,878

$ million

2008

Total

8,535
(176)
42
5,092
(415)
(726)
12,352

1,883
(60)
754
200
(685)
2,092
10,260
6,652

141

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
Notes on financial statements

22. Investments in jointly controlled entities

The significant jointly controlled entities of the BP group at 31 December 2009 are shown in Note 43. 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 year
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
19,463
3,743
264
3,479
993
215
2,271

Other
7,245
1,299
176
1,123
259
–
864

$ million

2007

Total
26,708
5,042
440
4,602
1,252
215
3,135

2009

9,396
1,815
155
1,660
374
–
1,286
15,857
4,124
19,981
2,276
3,768
6,044
–
13,937

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

13,937

8,939

13,300

22,239

1,359
15,296

–
8,939

1,587
14,887

1,587
23,826

Our investment in TNK-BP was 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 has
been 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 reflected 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 continues to be accounted for using the equity method.
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.

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

2009

Amount
receivable at
31 December
1,328

Sales
2,182

Sales
2,971

Purchases from jointly controlled entities

Product
LNG, crude oil and oil products, natural gas, refinery operating costs,

Purchases

2009

Amount
payable at
31 Decembera

Purchases

2008

Amount
receivable at
31 December
1,036

2008

Amount
payable at
31 Decembera

$ million

2007

Amount
receivable at
31 December
888

$ million

2007

Amount
payable at
31 December

Sales
2,336

Purchases

plant processing fees

5,377

214

9,115

182

2,067

a Amounts payable to jointly controlled entities shown above exclude payables relating to BP’s contribution on the establishment of the Sunrise Oil Sands 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
$419 million, which will be paid over several years as it relates partly 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. Dividends receivable are not included in the above balances.

142

BP Annual Report and Accounts 2009
Notes on financial statements

23. Investments in associates

The significant associates of the group are shown in Note 43. The principal associate in 2009 is TNK-BP. Summarized financial information for the
group’s share of associates is set out below.

Group investment in associates

Group share of net assets (as above)
Loans made by group companies to associates

$ million

2007

9,855
947
57
890
193
–
697

TNK-BP
17,377
3,178
220
2,958
871
139
1,948
13,437
4,205
17,642
3,122
4,797
7,919
582
9,141

9,141
–
9,141

Other
8,301
811
19
792
125
–
667
4,573
1,887
6,460
1,640
2,277
3,917
–
2,543

2,543
1,279
3,822

2009

Total
25,678
3,989
239
3,750
996
139
2,615
18,010
6,092
24,102
4,762
7,074
11,836
582
11,684

11,684
1,279
12,963

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

Our investment in TNK-BP was reclassified from a jointly controlled entity to an associate with effect from 9 January 2009. See Note 22 for
further information.

Transactions between the group and its associates are summarized below.

Sales to associates

Product
LNG, crude oil and oil products, natural gas, employee services

Sales
2,801

Purchases from associates

Product
Crude oil and oil products, natural gas, transportation tariff

Purchases
5,110

2009

Amount
receivable at
31 December
320

2009

Amount
payable at
31 December
614

2008

Amount
receivable at
31 December
219

2008

Amount
payable at
31 December
295

Sales
3,248

Purchases
4,635

$ million

2007

Amount
receivable at
31 December
60

2007

Amount
payable at
31 December
574

Sales
697

Purchases
2,905

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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.

The amounts receivable and payable at 31 December 2009, as shown in the table above, exclude $376 million due from and due to an
intermediate associate which provides funding for our associate The Baku-Tbilisi-Ceyhan Pipeline Company. These balances are expected to be settled
in cash throughout the period to 2015.

Dividends receivable at 31 December 2009 of $19 million are also excluded from the table above.

143

BP Annual Report and Accounts 2009
Notes on financial statements

24. 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
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents

Financial liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt

At 31 December

Financial assets

Other investments
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents

Financial liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt

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

27
31
28

30
31

–
1,288
31,016
–
6,570

–
–
–
–
38,874

1,567
–
–
–
1,769

–
–
–
–
3,336

–
–
–
7,960
–

–
(7,389)
–
–
571

–
–
–
972
–

–
(766)
–
–
206

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

27
31
28

30
31

–
1,163
29,489
–
5,609

–
–
–
–
36,261

855
–
–
–
2,588

–
–
–
–
3,443

–
–
–
12,501
–

–
(13,173)
–
–
(672)

–
–
–
1,063
–

–
(2,075)
–
–
(1,012)

(34,325)
–
(6,905)
(34,627)
(75,857)

(34,325)
(8,155)
(6,905)
(34,627)
(32,870)

$ million

2009

Total
carrying
amount

1,567
1,288
31,016
8,932
8,339

$ million

2008

Total
carrying
amount

855
1,163
29,489
13,564
8,197

–
–
–
–
–

(33,140)
–
(7,527)
(33,204)
(73,871)

(33,140)
(15,248)
(7,527)
(33,204)
(35,851)

The fair value of finance debt is shown in Note 32. 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.

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.

144

BP Annual Report and Accounts 2009
Notes on financial statements

24. Financial instruments and financial risk factors continued
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.

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

2009

$ million

2008

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

79
75
70
14
4
7
4

24
9
15
3
–
–
1

45
29
33
5
2
3
2

30
12
31
5
2
3
3

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

The major components of market risk are commodity price risk, foreign currency exchange risk, interest rate risk and equity price risk, each of which is
discussed below.

(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. Oil and 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.

As described above, the group also carries out risk management of certain natural business exposures using over-the-counter swaps and
exchange futures contracts. Together with certain physical supply contracts that are classified as derivatives, these contracts fall outside of the value-at-
risk framework. 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 $73 million at 31 December 2009 (2008 $90 million). This figure does not include any corresponding economic benefit or disbenefit
that would arise from the natural business exposure which would be expected to offset the gain or loss on the over-the-counter swaps and exchange
futures contracts mentioned above.

In addition, the group has embedded derivatives relating to certain natural gas contracts. The net fair value of these contracts was a liability of

$1,331 million at 31 December 2009 (2008 liability of $1,867 million). Key information on the natural gas contracts is given below.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

At 31 December
Remaining contract terms
Contractual/notional amount
Discount rate – nominal risk free

2008
9 months to 8 years 9 months 1 year 9 months to 9 years 9 months
3,585 million therms
2.5%

2,460 million therms
4.0%

2009

145

BP Annual Report and Accounts 2009
Notes on financial statements

24. Financial instruments and financial risk factors continued
For these embedded derivatives the sensitivity of the net fair value to an immediate 10% favourable or adverse change in the key assumptions is as follows.

At 31 December

Favourable 10% change
Unfavourable 10% change

Gas price

Oil price

Power price

175
(215)

26
(43)

23
(19)

2009

Discount
rate

20
(20)

Gas price

Oil price

Power price

291
(289)

81
(81)

27
(27)

$ million

2008

Discount
rate

16
(16)

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 2009, the foreign currency value at risk was $140 million (2008
$70 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 31.

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, Canadian dollar, euro, Norwegian krone, Australian dollar, Korean won, and at
31 December 2009 open contracts were in place for $800 million sterling, $491 million Canadian dollar, $299 million euro, $240 million
Norwegian krone, $215 million Australian dollar, $51 million Korean won and $41 million Singapore dollar capital expenditures maturing within
six years, with over 65% of the deals maturing within two years (2008 $949 million sterling, $712 million Canadian dollar, $553 million euro,
$392 million Norwegian krone, $303 million Australian dollar and $187 million Korean won capital expenditures maturing within seven years
with over 65% 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 2009, the open positions relating to cylinders consisted of receive
sterling, pay US dollar, purchased call and sold put options (cylinders) for $1,887 million (2008 $1,660 million); receive euro, pay US dollar
cylinders for $1,716 million (2008 $1,612 million); receive Canadian dollar, pay US dollar cylinders for $300 million (2008 $250 million); and
receive Australian dollar, pay US dollar cylinders for $297 million (2008 $455 million). At 31 December 2009 there were no open positions
relating to currency forwards (2008 buy sterling, sell US dollar currency forwards for $816 million; buy euro, sell US dollar currency forwards
for $141 million; buy Canadian dollar, sell US dollar, currency forwards for $50 million; and buy Australian dollar, sell US dollar currency
forwards for $90 million).

In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2009, the total

foreign currency net borrowings not swapped into US dollars amounted to $465 million (2008 $1,037 million). Of this total, $113 million was
denominated in currencies other than the functional currency of the individual operating unit being entirely Canadian dollars (2008 $92 million, being
entirely Canadian 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 $11 million (2008 $9 million).

(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 2009 was 63% of total finance debt outstanding (2008 72%). The weighted average
interest rate on finance debt at 31 December 2009 is 2% (2008 3%) and the weighted average maturity of fixed rate debt is four years
(2008 three years).

146

BP Annual Report and Accounts 2009
Notes on financial statements

24. Financial instruments and financial risk factors continued
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 2010, it is estimated that the group’s profit before taxation for
2010 would decrease by approximately $219 million (2008 $239 million decrease in 2009). 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 2009 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 in other comprehensive income. Accumulated fair value changes are recycled
to the income statement on disposal, or when the investment is impaired. No impairment losses have been recognized in 2009 (2008 $546 million
and 2007 nil) relating to listed non-current available-for-sale investments. For further information see Note 25.

At 31 December 2009, it is estimated that an increase of 10% in quoted equity prices would result in an immediate credit to other
comprehensive income of $130 million (2008 $59 million credit to other comprehensive income), whilst a decrease of 10% in quoted equity prices
would result in an immediate charge to other comprehensive income of $130 million (2008 $48 million charge to profit or loss and $11 million charge
to other comprehensive income).

At 31 December 2009, 73% (2008 56%) 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 procedures

were reviewed in 2008 and credit exposures arising from physical commodity and derivative transactions with banks and other counterparties have
been reduced in 2008 and 2009, mainly through netting and collateral arrangements.

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 BP 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.

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 receivables and payables, and 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
2009, the maximum credit exposure was $49,575 million (2008 $52,413 million). Collateral received and recognized in the balance sheet at
the year-end was $549 million (2008 $1,121 million) and collateral held off balance sheet was $48 million (2008 $203 million). Credit exposure
exists in relation to guarantees issued by group companies under which amounts outstanding at 31 December 2009 were $319 million (2008
$223 million) in respect of liabilities of jointly controlled entities and associates and $667 million (2008 $613 million) in respect of liabilities of
other third parties.

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.

147

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
Notes on financial statements

24. Financial instruments and financial risk factors continued
Some mitigation of credit exposure is achieved by: netting arrangements; credit support agreements which require the counterparty to provide
collateral or other credit risk mitigation; and credit insurance and other risk transfer instruments.

For the contracts comprising derivative financial instruments in an asset position at 31 December 2009, it is estimated that over 80% (2008

over 80%) of the unmitigated credit exposure is to counterparties 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 55-60% (2008 approximately 60-65%) of the unmitigated trade receivables portfolio exposure is of
investment grade credit 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 2009 or
31 December 2008.

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.

Trade and other receivables at 31 December
At 1 January
Exchange adjustments
Charge for the year
Utilization
At 31 December

2009
29,426
91

808
151
76
464
31,016

2009
391
12
157
(130)
430

$ million

2008
25,838
73

1,323
489
596
1,170
29,489

$ million

2008
406
(32)
191
(174)
391

(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 2009, 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 through to the fourth quarter of 2011,
unchanged from the position as at 31 December 2008. 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 2009, the amount drawn down against the DIP was $11,403 million (2008 $10,334 million). In addition, the group
has in place an unlimited US Shelf Registration under which it may raise debt with maturities of one month or longer.

The group has long-term debt ratings of Aa1 (stable outlook) and AA (stable outlook), assigned respectively by Moody’s and Standard and

Poor’s, unchanged from 2008.

Despite recent increased uncertainty in the financial markets, including a lack of liquidity for some borrowers, we have been able to issue

$11 billion of long-term debt during 2009 and issue short-term commercial paper at competitive rates, as and when required. As an additional
precautionary measure, we have increased and maintained the cash and cash equivalents held by the group to $8.3 billion at the end of 2009 and
$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.

148

BP Annual Report and Accounts 2009
Notes on financial statements

24. 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 32.
US Industrial Revenue/Municipal Bonds of $2,895 million (2008 $3,166 million) with earliest contractual repayment dates within one year
have expected repayment dates ranging from 1 to 33 years (2008 1 to 40 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 $1,622 million (2008 $1,806 million) that
mature within eight years.

The table also shows the timing of cash outflows relating to trade and other payables and accruals.

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
31,413
1,059
1,089
566
67
85
46
34,325

Accruals
6,202
231
106
78
49
163
76
6,905

2009

Finance
debt
9,790
6,861
5,359
5,528
3,151
5,723
1,150
37,562

Trade and
other
payables
30,598
402
898
902
223
53
64
33,140

$ million

2008

Finance
debt
16,670
5,934
3,419
2,647
5,072
1,316
1,050
36,108

Accruals
6,743
359
77
72
67
164
45
7,527

The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of
both derivative assets and liabilities as indicated in Note 31. Management does not currently anticipate any cash flows that could be of a significantly
different amount, or could occur earlier than the expected maturity analysis provided.

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 from 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. Not shown
in the table are the gross settlement amounts for the receive leg of derivatives that are settled separately from the pay leg, which amount to $7,999
million at 31 December 2009 (2008 $8,545 million) to be received on the same day as the related cash outflows.

Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years

2009
2,826
1,395
1,669
1,349
1,104
322
8,665

$ million

2008
3,426
3,024
1,037
1,731
1,389
129
10,736

The group has issued third-party guarantees, as described above under credit risk. These amounts represent the maximum exposure of the group,
substantially all of which could be called within one year.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

149

BP Annual Report and Accounts 2009
Notes on financial statements

25. Other investments

Listed
Unlisted

2009
1,296
271
1,567

$ million

2008
592
263
855

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 and as such are in level 1 of the fair value

hierarchy. Unlisted investments are stated at cost less accumulated impairment losses and are in level 3 of the fair value hierarchy.

The most significant investment is the group’s stake in Rosneft which had a fair value of $1,138 million at 31 December 2009 (2008

$483 million). The fair value gain arising on revaluation of this investment during 2009 has been recorded within other comprehensive income.
In 2008, an impairment loss of $517 million was recognized in the income statement relating to the Rosneft investment (see Note 3). In 2009,
impairment losses were incurred of $13 million (2008 $17 million) relating to unlisted investments and nil (2008 $29 million) relating to other
listed investments.

26. Inventories

Crude oil
Natural gas
Refined petroleum and petrochemical products

Supplies

Trading inventories

Cost of inventories expensed in the income statement

2009
6,237
105
12,337
18,679
1,661
20,340
2,265
22,605
163,772

$ million

2008
4,396
107
9,318
13,821
1,588
15,409
1,412
16,821
266,982

The inventory valuation at 31 December 2009 is stated net of a provision of $46 million (2008 $1,412 million) to write inventories down to their net
realizable value. The net movement in the year in respect of inventory net realizable value provisions was $1,366 million credit (2008 $1,295 million charge).

27. 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. See Note 24 for further information.

2009

$ million

2008

Current Non-current

Current

Non-current

22,604
1,317
417
4,949
29,287

244
29,531

–
11
298
1,420
1,729

–
1,729

22,869
1,035
219
4,656
28,779

482
29,261

–
–
–
710
710

–
710

150

BP Annual Report and Accounts 2009
Notes on financial statements

28. Cash and cash equivalents

Cash at bank and in hand
Term bank deposits
Other cash equivalents

2009
3,359
3,211
1,769
8,339

$ million

2008
3,442
2,167
2,588
8,197

Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; term deposits of three months or less 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. The carrying amounts of cash at bank
and in hand and term bank deposits approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the
fair value hierarchy.

Cash and cash equivalents at 31 December 2009 includes $1,095 million (2008 $2,133 million) that is restricted. This relates principally to

amounts required to cover initial margins on trading exchanges.

See Note 24 for further information.

29. Valuation and qualifying accounts

At 1 January
Charged to costs and expenses
Charged to other accountsa
Deductions
At 31 December

a Principally exchange adjustments.

2009

2008

Doubtful Fixed assets –
investments
935
66
6
(658)
349

debts
391
157
12
(130)
430

Doubtful Fixed assets –
investments
146
647
143
(1)
935

debts
406
191
(32)
(174)
391

$ million

2007

Doubtful Fixed assets –
investments
151
158
2
(165)
146

debts
421
175
34
(224)
406

Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply.

30. 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. See Note 24 for further information.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

2009

$ million

2008

Current Non-current

Current

Non-current

22,886
304
692
7,531
31,413

757
3,034
3,791
35,204

–
2,419
298
195
2,912

286
–
286
3,198

20,129
292
295
9,882
30,598

445
2,601
3,046
33,644

–
2,255
–
287
2,542

538
–
538
3,080

151

BP Annual Report and Accounts 2009
Notes on financial statements

31. 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 24.

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.

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 the income statement.

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 derivative commodity contracts

Cash flow hedges

Currency forwards, futures and cylinders
Cross-currency interest rate swaps

Fair value hedges

Currency forwards, futures and swaps
Interest rate swaps

Hedges of net investments in foreign operations

Of which – current

– non-current

2009

Fair
value
liability

(226)
(1,191)
(3,960)
(497)
(47)
(5,921)

(1,468)

(114)
(298)
(412)

(232)
(122)
(354)
–
(8,155)
(4,681)
(3,474)

$ million

2008

Fair
value
liability

(273)
(3,523)
(6,113)
(904)
(96)
(10,909)

Fair
value
asset

278
3,813
6,945
978
90
12,104

397

(2,264)

120
109
229

(1,175)
(558)
(1,733)

465
367
832
2
13,564
8,510
5,054

(342)
–
(342)
–
(15,248)
(8,977)
(6,271)

Fair
value
asset

318
1,140
5,636
682
47
7,823

137

182
44
226

490
256
746
–
8,932
4,967
3,965

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 24.

The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Derivative assets held for trading have the following fair values and maturities.

Less than
1 year

162
814
2,958
496
47
4,477

1-2 years

2-3 years

3-4 years

4-5 years

83
136
1,059
139
–
1,417

33
69
582
32
–
716

22
59
354
12
–
447

16
44
186
3
–
249

$ million

2009

Total

318
1,140
5,636
682
47
7,823

Over
5 years

2
18
497
–
–
517

Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives

152

BP Annual Report and Accounts 2009
Notes on financial statements

31. Derivative financial instruments continued

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

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

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

(110)
(1,083)
(2,381)
(335)
(47)
(3,956)

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

(58)
(67)
(607)
(109)
–
(841)

(20)
(29)
(248)
(39)
–
(336)

(32)
(11)
(222)
(11)
–
(276)

(4)
(1)
(78)
(3)
–
(86)

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)

$ million

2008

Total

278
3,813
6,945
978
90
12,104

$ million

2009

Total

(226)
(1,191)
(3,960)
(497)
(47)
(5,921)

$ million

2008

Total

(273)
(3,523)
(6,113)
(904)
(96)
(10,909)

Over
5 years

11
9
663
–
–
683

Over
5 years

(2)
–
(424)
–
–
(426)

Over
5 years

–
(1)
(611)
–
–
(612)

If at inception of a contract the valuation cannot be supported by observable market data, any gain or loss 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 or loss’. This deferred gain or loss 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 or loss is recognized in the income statement. Changes in valuation from this initial valuation are
recognized immediately through the income statement.

The following table shows the changes in the day-one profits and losses 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 the income statement at 31 December

2009

Natural
gas price

83
(14)
(36)
33

Oil price

32
–
(11)
21

Oil price

–
66
(34)
32

$ million

2008

Natural
gas price

36
49
(2)
83

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

153

BP Annual Report and Accounts 2009
Notes on financial statements

31. Derivative financial instruments continued
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by
methodology of fair value estimation.

IFRS 7 ‘Financial Instruments: Disclosures’ sets out a fair value hierarchy which consists of three levels that describe the methodology of

estimation as follows:
– Level 1 – using quoted prices in active markets for identical assets or liabilities.
– Level 2 – using inputs for the asset or liability, other than quoted prices, that are observable either directly (i.e. as prices) or indirectly (i.e. derived

from prices).

– Level 3 – using inputs for the asset or liability that are not based on observable market data such as prices based on internal models or other

valuation methods.

This information is presented on a gross basis, that is, before netting by counterparty.

Less than
1 year

163
9,544
264
9,971
(5,494)
4,477

(95)
(9,086)
(269)
(9,450)
5,494
(3,956)
521

Less than
1 year

40
19,737
687
20,464
(12,325)
8,139

(227)
(19,106)
(551)
(19,884)
12,325
(7,559)
580

1-2 years

2-3 years

3-4 years

4-5 years

76
2,182
188
2,446
(1,029)
1,417

(39)
(1,681)
(150)
(1,870)
1,029
(841)
576

23
915
162
1,100
(384)
716

(14)
(597)
(109)
(720)
384
(336)
380

17
357
148
522
(75)
447

(24)
(234)
(93)
(351)
75
(276)
171

10
146
128
284
(35)
249

–
(47)
(74)
(121)
35
(86)
163

1-2 years

2-3 years

3-4 years

4-5 years

43
3,477
196
3,716
(1,927)
1,789

–
(3,345)
(187)
(3,532)
1,927
(1,605)
184

30
871
148
1,049
(345)
704

(2)
(683)
(154)
(839)
345
(494)
210

7
508
140
655
(170)
485

–
(356)
(147)
(503)
170
(333)
152

6
225
137
368
(64)
304

(13)
(217)
(140)
(370)
64
(306)
(2)

$ million

2009

Total

290
13,144
1,417
14,851
(7,028)
7,823

(173)
(11,645)
(1,131)
(12,949)
7,028
(5,921)
1,902

$ million

2008

Total

128
24,874
1,980
26,982
(14,878)
12,104

(242)
(23,734)
(1,811)
(25,787)
14,878
(10,909)
1,195

Over
5 years

1
–
527
528
(11)
517

(1)
–
(436)
(437)
11
(426)
91

Over
5 years

2
56
672
730
(47)
683

–
(27)
(632)
(659)
47
(612)
71

Fair value of derivative assets

Level 1
Level 2
Level 3

Less: netting by counterparty

Fair value of derivative liabilities

Level 1
Level 2
Level 3

Less: netting by counterparty

Net fair value

Fair value of derivative assets

Level 1
Level 2
Level 3

Less: netting by counterparty

Fair value of derivative liabilities

Level 1
Level 2
Level 3

Less: netting by counterparty

Net fair value

154

BP Annual Report and Accounts 2009
Notes on financial statements

31. Derivative financial instruments continued
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value
hierarchy.

Net fair value of contracts at 1 January 2009
Gains (losses) recognized in the income statement
Settlements
Purchases
Sales
Transfers out of level 3
Transfers in to level 3
Exchange adjustments
Net fair value of contracts at 31 December 2009

Net fair value of contracts at 1 January 2008
Gains recognized in the income statement
Settlements
Transfers out of level 3
Transfers in to level 3
Exchange adjustments
Net fair value of contracts at 31 December 2008

Currency

3
(1)
–
–
–
(2)
–
–
–

Currency

(17)
8
–
12
–
–
3

Oil
price

149
205
(91)
–
–
(50)
2
–
215

Oil
price

1
148
18
(25)
7
–
149

Natural gas
price

Power
price

Other

17
91
(5)
–
–
(4)
(25)
(2)
72

–
–
–
1
(2)
–
–
–
(1)

–
(1)
–
–
1
–
–
–
–

Natural gas
price

Power
price

Other

(67)
160
3
(79)
3
(3)
17

(1)
–
1
–
–
–
–

–
–
–
–
–
–
–

$ million

Total

169
294
(96)
1
(1)
(56)
(23)
(2)
286

$ million

Total

(84)
316
22
(92)
10
(3)
169

The amount recognized in the income statement for the year relating to level 3 derivatives still held at 31 December 2009 was a $278 million gain
(2008 $199 million gain relating to derivatives still held at 31 December 2008).

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 net gain of $3,735 million (2008 $6,721 million net gain and 2007 $376 million net
gain).

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.

Embedded derivative assets have the following fair values and maturities.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Commodity price embedded derivatives

Less than
1 year

134

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

–

1-2 years

2-3 years

3-4 years

4-5 years

Commodity price embedded derivatives

116

Over
5 years

$ million

2009

Total

137

$ million

2008

Total

397

155

BP Annual Report and Accounts 2009
Notes on financial statements

31. Derivative financial instruments continued
Embedded derivative liabilities have the following fair values and maturities.

Commodity price embedded derivatives

(154)

(236)

(231)

(227)

(232)

(388)

(1,468)

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

$ million

2009

Total

Over
5 years

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

$ million

2008

Total

Over
5 years

Commodity price embedded derivatives

(404)

(322)

(365)

(303)

(271)

(599)

(2,264)

The following table shows the fair value of embedded derivative assets and liabilities analysed by maturity period and by methodology of fair value
estimation.

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

–
–
134
134

–
–
(154)
(154)
(20)

Less than
1 year

–
35
15
50

–
(10)
(394)
(404)
(354)

–
–
–
–

–
–
(236)
(236)
(236)

–
–
–
–

–
–
(231)
(231)
(231)

–
–
–
–

–
–
(227)
(227)
(227)

–
–
–
–

–
–
(232)
(232)
(232)

1-2 years

2-3 years

3-4 years

4-5 years

–
–
116
116

–
–
(322)
(322)
(206)

–
–
75
75

–
–
(365)
(365)
(290)

–
–
45
45

–
–
(303)
(303)
(258)

–
–
36
36

–
–
(271)
(271)
(235)

$ million

2009

Total

–
–
137
137

–
–
(1,468)
(1,468)
(1,331)

$ million

2008

Total

–
35
362
397

–
(10)
(2,254)
(2,264)
(1,867)

Over
5 years

–
–
3
3

–
–
(388)
(388)
(385)

Over
5 years

–
–
75
75

–
–
(599)
(599)
(524)

Fair value of embedded derivative assets

Level 1
Level 2
Level 3

Fair value of embedded derivative liabilities

Level 1
Level 2
Level 3

Net fair value

Fair value of embedded derivative assets

Level 1
Level 2
Level 3

Fair value of embedded derivative liabilities

Level 1
Level 2
Level 3

Net fair value

156

BP Annual Report and Accounts 2009
Notes on financial statements

31. Derivative financial instruments continued
The following table shows the changes during the year in the net fair value of embedded derivatives within level 3 of the fair value hierarchy.

Net fair value of contracts at 1 January
Settlements
Gains (losses) recognized in the income statementa
Exchange adjustments
Net fair value of contracts at 31 December

2009

Commodity
price

Interest
rate

(1,892)
221
535
(195)
(1,331)

(2,146)
414
(1,011)
851
(1,892)

(33)
38
(5)
–
–

$ million

2008

Total

(2,179)
452
(1,016)
851
(1,892)

a The amount for gains (losses) recognized in the income statement for 2009 includes a loss of $224 million arising as a result of refinements in the modelling and valuation methods used for these
contracts.

The amount recognized in the income statement for the year relating to level 3 embedded derivatives still held at 31 December 2009 was a
$347 million gain (2008 $985 million loss relating to embedded derivatives still held at 31 December 2008).

The fair value gain (loss) on embedded derivatives is shown below.

Commodity price embedded derivatives
Interest rate embedded derivatives
Fair value gain (loss)

2009
607
–
607

2008
(106)
(5)
(111)

$ million

2007
–
(7)
(7)

Cash flow hedges
At 31 December 2009, 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 24 outlines the management of risk
aspects for currency and interest rate risk. For cash flow hedges the group only claims hedge accounting for the intrinsic value on the currency with
any fair value attributable to time value taken immediately to the income statement. 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
$366 million (2008 loss of $45 million and 2007 gain of $74 million). Of this, a loss of $332 million is included in production and manufacturing
expenses (2008 $1 million loss and 2007 $143 million gain) and a loss of $34 million is included in finance costs (2008 $44 million loss and 2007
$69 million loss). The amount removed from equity during the period and included in the carrying amount of non-financial assets was a loss of
$136 million (2008 $38 million gain and 2007 $40 million gain).

The amounts retained in equity at 31 December 2009 are expected to mature and affect the income statement by a $146 million gain in 2010,

a loss of $26 million in 2011 and a loss of $65 million in 2012 and beyond.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Fair value hedges
At 31 December 2009, 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 loss on the hedging derivative instruments taken to the income statement in 2009 was $98 million (2008 $2 million gain and 2007
$334 million gain) offset by a gain on the fair value of the finance debt of $117 million (2008 $20 million loss and 2007 $327 million loss).

The interest rate and cross-currency interest rate swaps have an average maturity of four to five years, (2008 three to four years) and are used
to convert sterling, euro, Swiss franc, Australian dollar, Japanese yen and Hong Kong dollar denominated borrowings into US dollar floating rate debt.
Note 24 outlines the group’s approach to interest rate risk management.

Hedges of net investments in foreign operations
The group held currency swap contracts as a hedge of a long-term investment in a UK subsidiary that expired in 2009. At 31 December 2008, the
hedge had a fair value of $2 million and the loss on the hedge recognized in equity in 2008 was $38 million (2007 $67 million loss). US dollars had been
sold forward for sterling purchased and matched the underlying liability with no significant ineffectiveness reflected in the income statement.

157

BP Annual Report and Accounts 2009
Notes on financial statements

32. Finance debt

Borrowings
Net obligations under finance leases

Within
1 year a

9,018
91
9,109

After
1 year

25,020
498
25,518

2009

Total

34,038
589
34,627

Within
1 year a

15,647
93
15,740

After
1 year

16,937
527
17,464

$ million

2008

Total

32,584
620
33,204

a Amounts 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 $2,895 million (2008 $3,166 million) with earliest contractual repayment dates within one year have expected repayment dates ranging from 1 to 33 years (2008
1 to 40 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 $1,622 million (2008 $1,806 million) that mature within eight years.

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
Euro
Other currencies

US dollar
Sterling
Euro
Other currencies

Fixed rate debt

Floating rate debt

Total

Weighted
average
interest
rate
%

Weighted
average
time for
which rate
is fixed
Years

4
4
6

5
–
4
7

4
2
14

3
–
3
10

Weighted
average
interest
rate
%

1
2
3

2
6
4
7

Amount
$ million

12,525
63
171
12,759

9,005
–
74
216
9,295

Amount
$ million

20,566
1,199
103
21,868

22,116
21
1,330
442
23,909

Amount
$ million

2009

33,091
1,262
274
34,627

2008
31,121
21
1,404
658
33,204

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.

2009

109
329
407
845
256
589
91
202
296

$ million

2008

116
361
439
916
296
620
93
234
293

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

158

BP Annual Report and Accounts 2009
Notes on financial statements

32. Finance debt continued
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 2009, 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

See Note 24 for further information.

2009

Carrying
amount

5,144
28,894
589
34,627

Fair value

9,913
23,239
638
33,790

Fair value

5,144
29,918
599
35,661

$ million

2008

Carrying
amount

9,913
22,671
620
33,204

33. 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 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, the group rebalanced distributions away from share buybacks in favour of dividends. During 2009, the company did not repurchase any of its
own shares.

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 2009 the net debt ratio was 20% (2008 21%).

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

At 31 December

Gross debt
Less: Cash and cash equivalents
Less: Fair value asset (liability) 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

a Including fair value of associated derivative financial instruments.

2009

34,627
8,339
127
26,161
102,113
20%

Finance
debt a

(33,238)
(60)
(1,141)
(61)
(34,500)

Cash and
cash
equivalents

8,197
110
32
–
8,339

2009

Net
debt

(25,041)
50
(1,109)
(61)
(26,161)

Finance
debta

(30,379)
102
(2,825)
(136)
(33,238)

Cash and
cash
equivalents

3,562
(184)
4,819
–
8,197

$ million

2008

33,204
8,197
(34)
25,041
92,109
21%

$ million

2008

Net
debt

(26,817)
(82)
1,994
(136)
(25,041)

159

BP Annual Report and Accounts 2009
Notes on financial statements

34. Provisions

At 1 January 2009
Exchange adjustments
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Change in discount rate
Utilization
Deletions
At 31 December 2009
Of which – expected to be incurred within 1 year

– expected to be incurred in more than 1 year

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

Decommissioning Environmental

Litigation

8,418
398
169
–
184
324
(383)
(90)
9,020
287
8,733

1,691
15
588
(259)
32
18
(308)
(58)
1,719
368
1,351

1,446
22
302
(99)
15
(35)
(574)
(1)
1,076
433
643

Decommissioning

Environmental

Litigation

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

1,737
(1)
886
(383)
22
(815)
–
1,446
521
925

Other

2,098
29
1,256
(228)
16
8
(361)
(3)
2,815
572
2,243

Other

1,750
(106)
1,173
(130)
20
(609)
–
2,098
284
1,814

$ million

Total

13,653
464
2,315
(586)
247
315
(1,626)
(152)
14,630
1,660
12,970

$ million

Total

15,095
(1,360)
2,656
(620)
287
(2,338)
(67)
13,653
1,545
12,108

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 1.75% (2008 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.

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 1.75% (2008
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.

The litigation category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of
exposures of third parties to toxic substances. Included within the other category at 31 December 2009 are provisions for deferred employee
compensation of $789 million (2008 $792 million) and for expected rental shortfalls on surplus properties of $246 million (2008 $251 million). These
provisions are discounted using either a nominal discount rate of 4.0% (2008 2.5%) or a real discount rate of 1.75% (2008 2.0%), as appropriate.

160

BP Annual Report and Accounts 2009
Notes on financial statements

35. 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 under which retired employees draw the majority

of their benefit as an annuity. During 2009, BP announced that, with effect from 1 April 2010, it will close its UK plan to new joiners other than some of
those joining the North Sea SPU. The plan will remain open to those employees who joined BP on or before 31 March 2010.

In the US, a range of retirement arrangements are 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 2009, contributions of $9 million (2008 $6 million and 2007 $524 million) and $795 million (2008 $362 million and 2007 $97 million) were
made to the UK plans and US plans respectively. In addition, contributions of $204 million (2008 $130 million and 2007 $127 million) were made to other
funded defined benefit plans. The aggregate level of contributions in 2010 is expected to be approximately $1,000 million, and includes contributions in all
countries 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 2009. The group’s principal plans are subject to a formal actuarial valuation every three
years in the UK, with valuations being required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension
plans was as at 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
2009 are used to determine the pension liabilities at that date and the pension expense for 2010.

Financial assumptions

Discount rate for pension

plan liabilities

Discount rate for other post-
retirement benefit plans
Rate of increase in salaries
Rate of increase for pensions

in payment

Rate of increase in deferred

pensions

Inflation

2009

5.8

n/a
5.3

3.4

3.4
3.4

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

2009

2008

5.4

5.8
4.2

–

–
2.4

6.3

6.2
2.2

–

–
0.4

2007

6.1

6.4
4.2

–

–
2.4

2009

5.8

n/a
3.8

1.8

1.2
2.3

2008

5.7

n/a
3.5

1.7

1.0
2.0

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Other

2007

5.6

n/a
3.7

1.8

1.2
2.2

Our discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and Germany we use yields
that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans 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 in 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.

161

BP Annual Report and Accounts 2009
Notes on financial statements

35. Pensions and other post-retirement benefits continued
The 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, 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

2009

2008

26.0

29.0

28.6

31.5

25.9

28.9

28.5

31.4

2007

24.0

25.1

26.9

27.9

2009

2008

24.6

26.1

26.3

27.2

24.4

25.9

26.1

27.0

2007

24.3

25.8

26.1

27.0

2009

2008

23.2

26.1

27.8

30.4

23.0

25.9

27.6

30.3

Years

Germany

2007

22.4

25.3

27.0

29.7

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 healthcare cost 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

2009
8.2
5.0
2017

2008
8.6
5.0
2015

2007
9.0
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 obligations
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.

162

BP Annual Report and Accounts 2009
Notes on financial statements

35. 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 2009 was $2,956 million
(2008 $2,819 million and 2007 $2,491 million). The market value of pension assets at the end of 2009 is higher than at the end of 2008 due to a rise in the
market value of investments when expressed in their local currencies and an increase in value that arises from changes in exchange rates (increasing 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 164.

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

2009

Market
value

Expected
long-term
rate of
return

2008

Market
value

Expected
long-term
rate of
return

2007

Market
value

$ million

8.0
5.3
6.5
1.1
7.3

8.5
4.8
8.0
0.9
8.0

8.5
4.8
7.6

8.6
4.4
6.5
2.0
5.9

16,945
3,701
1,269
634
22,549

4,326
1,218
8
271
5,823

8
4
12

1,091
1,651
82
245
3,069

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

The assumed rate of investment return, discount rate, inflation, US healthcare cost trend rate and the mortality assumptions all have a significant
effect on the amounts reported.

A one-percentage point change in the following assumptions for the group’s plans would have had the effects shown in the table below. The

effects shown for the expense in 2010 include current service cost and interest on plan liabilities.

Investment return

Effect on pension and other post-retirement benefit expense in 2010

Discount rate

Effect on pension and other post-retirement benefit expense in 2010
Effect on pension and other post-retirement benefit obligation at 31 December 2009

Inflation rate

Effect on pension and other post-retirement benefit expense in 2010
Effect on pension and other post-retirement benefit obligation at 31 December 2009

US healthcare cost trend rate

Effect on US other post-retirement benefit expense in 2010
Effect on US other post-retirement obligation at 31 December 2009

$ million

One-percentage point

Increase

Decrease

(313)

313

(75)
(4,778)

98
6,084

424
4,394

(343)
(3,706)

31
339

(28)
(304)

One additional year of longevity in the mortality assumptions would have the effects shown in the table below. The effect shown for the expense in
2010 includes current service cost and interest on plan liabilities.

One additional year’s longevity

Effect on pension and other post-retirement benefit expense in 2010
Effect on pension and other post-retirement benefit obligation at 31 December 2009

UK
pension
plans

39
528

US
pension
plans

US other post-
retirement
benefit
plans

5
90

4
62

$ million

German
pension
plans

9
149

163

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
Notes on financial statements

35. 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 other comprehensive income
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 other comprehensive income
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
Disposals
Actuarial (gain) loss on obligation
Benefit obligation at 31 Decembera e
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 f
Contributions by plan participants
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Disposals
Actuarial gain on plan assetsf
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

311
–
37
–
348

1,426
(1,112)
314

1,761
(2,217)
(141)
(597)

16,655
1,896
311
–
1,112
–
–
37
37
(977)
(4)
–
2,358
21,425

18,239
2,054
1,426
37
9
(977)
–
1,761
22,549
1,124

1,290
(166)

1,124

1,287
(163)

1,124

(21,262)
(163)
(21,425)

US
pension
plans

US other post-
retirement
benefit
plans

243
–
–
205
448

405
(456)
(51)

617
(501)
(229)
(113)

7,534
–
243
–
456
–
–
–
–
(1,371)
(73)
–
730
7,519

5,377
–
405
–
795
(1,371)
–
617
5,823
(1,696)

–
(1,696)

(1,696)

(1,280)
(416)

(1,696)

(7,103)
(416)
(7,519)

48
(22)
–
–
26

1
(183)
(182)

2
(50)
71
23

3,003
–
48
(22)
183
–
–
–
–
(4)
(191)
–
(21)
2,996

13
–
1
–
–
(4)
–
2
12
(2,984)

–
(2,984)

(2,984)

(33)
(2,951)

(2,984)

(45)
(2,951)
(2,996)

$ million

2009

Total

719
(21)
90
233
1,021

1,979
(2,171)
(192)

2,549
(2,810)
(421)
(682)

34,847
2,259
719
(21)
2,171
11
(3)
82
47
(2,561)
(667)
(42)
3,231
40,073

26,154
2,296
1,979
47
1,008
(2,561)
(19)
2,549
31,453
(8,620)

1,390
(10,010)

(8,620)

(190)
(8,430)

(8,620)

Other
plans

117
1
53
28
199

147
(420)
(273)

169
(42)
(122)
5

7,655
363
117
1
420
11
(3)
45
10
(209)
(399)
(42)
164
8,133

2,525
242
147
10
204
(209)
(19)
169
3,069
(5,064)

100
(5,164)

(5,064)

(164)
(4,900)

(5,064)

(3,233)
(4,900)
(8,133)

(31,643)
(8,430)
(40,073)

The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pension 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.
b
Included within production and manufacturing expenses and distribution and administration expenses.
c
The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
d
The benefit payments amount shown above comprises $3,174 million benefits plus $54 million of plan expenses incurred in the administration of the benefit.
e
The benefit obligation for other plans includes $3,880 million for the German plan, which is largely unfunded.
f The 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.

At 31 December 2009, reimbursement balances due from or to other companies in respect of pensions amounted to $443 million reimbursement
assets (2008 $455 million) and $14 million reimbursement liabilities (2008 $61 million). These balances are not included as part of the pension liability,
but are reflected elsewhere in the group balance sheet.
164

BP Annual Report and Accounts 2009
Notes on financial statements

35. 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 other comprehensive income

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 other comprehensive income
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 e
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 f
Contributions by plan participants
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Actuarial loss on plan assetsf
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

US
pension
plans

US other post-
retirement
benefit
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

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)

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

a The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pension 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.
b Included within production and manufacturing expenses and distribution and administration expenses.
c The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
d The benefit payments amount shown above comprises $2,697 million benefits plus $57 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for other plans includes $3,837 million for the German plan, which is largely unfunded.
f The 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.

165

BP Annual Report and Accounts 2009
Notes on financial statements

35. 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 other comprehensive income

UK
pension
plans

US
pension
plans

US other
post-
retirement
benefit
plans

492
5
36
–
533

2,075
(1,198)
877

406
513
(162)
757

227
10
–
184
421

613
(425)
188

(28)
358
(27)
303

43
–
–
–
43

2
(190)
(188)

–
137
29
166

$ million

2007

Total

894
15
38
209
1,156

2,855
(2,203)
652

302
1,615
(200)
1,717

Other
plans

132
–
2
25
159

165
(390)
(225)

(76)
607
(40)
491

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 other comprehensive income
Cumulative amount recognized in other comprehensive income

2009

2008

2007

2006

40,073
31,453
(8,620)
(421)
2,549
4,528
(682)
(3,622)

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

Estimated future benefit payments
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2019 are as follows:

US
other post-
retirement
benefit
plans

201
206
208
213
218
1,123

US
pension
plans

618
637
679
677
672
3,275

UK
pension
plans

1,003
1,019
1,061
1,095
1,148
6,496

Other
plans

612
587
581
578
584
2,835

2010
2011
2012
2013
2014
2015-2019

166

$ million

2005

38,855
32,907
(5,948)
(212)
3,364
5,502
975
1,158

$ million

Total

2,434
2,449
2,529
2,563
2,622
13,729

BP Annual Report and Accounts 2009
Notes on financial statements

36. Called-up share capital

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

Issued

8% cumulative first preference shares of £1 each
9% cumulative second preference shares of £1 each

Ordinary shares of 25 cents each

At 1 January
Issue of new shares for employee share schemesa
Repurchase of ordinary share capitalb

At 31 December

Authorized
8% cumulative first preference shares of £1 each
9% cumulative second preference shares of £1 each
Ordinary shares of 25 cents each

Shares
(thousand)

7,233
5,473

20,618,458
11,207
–
20,629,665

2009

$ million

12
9
21

Shares
(thousand)

7,233
5,473

2008

$ million

12
9
21

Shares
(thousand)

7,233
5,473

3
–

5,155 20,863,424
24,791
(269,757)
5,158 20,618,458
5,179

6
(67)

5,216 21,457,301
69,273
(663,150)
5,155 20,863,424
5,176

7,250
5,500
36,000,000

12
9

7,250
5,500
9,000 36,000,000

12
9

7,250
5,500
9,000 36,000,000

2007

$ million

12
9
21

5,364
18
(166)
5,216
5,237

12
9
9,000

a Consideration received relating to the issue of new shares for employee share schemes amounted to $84 million (2008 $180 million and 2007 $492 million).
b Purchased for a total consideration of nil (2008 $2,914 million and 2007 $7,497 million), all of which were for cancellation. At 31 December 2009, 112,803,287 (2008 150,444,408 and 2007
150,966,096) ordinary shares bought back were awaiting cancellation. These shares have been excluded from ordinary shares in issue shown above. Transaction costs of share repurchases amounted
to nil (2008 $16 million and 2007 $40 million).

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

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

Treasury shares

At 1 January
Shares gifted to the Employee Share Ownership Plans
Shares transferred at market price to the Employee Share

Ownership Plans

Shares re-issued to employee share schemes
At 31 December

2009

2008

2007

Shares Nominal value
$ million

(thousand)

Shares Nominal value
$ million

(thousand)

Shares Nominal value
$ million

(thousand)

1,888,151
(1,265)

–
(17,109)
1,869,777

472
(1)

1,940,639
(10,000)

485 1,946,805
(1,700)

(2)

–
(4)
467

(20,000)
(22,488)
1,888,151

(5)
(6)

–
(4,466)
472 1,940,639

487
–

–
(2)
485

For each year presented, the balance at 1 January represents the maximum number of shares held in treasury during the year, representing 9.2%
(2008 9.3% and 2007 9.1%) of the called-up ordinary share capital of the company.

During 2009, the movement in treasury shares represented less than 0.1% (2008 0.25% and 2007 less than 0.1%) of the ordinary share capital

of the company.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

167

BP Annual Report and Accounts 2009
Notes on financial statements

37. Capital and reserves

At 1 January 2009

Currency translation differences (including recycling)
Actuarial gain relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Profit for the year
Total comprehensive income
Dividends
Share-based paymentsa
Changes in associates’ equity
Minority interest buyout
At 31 December 2009

At 1 January 2008

Currency translation differences (including recycling)
Actuarial gain relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Profit for the year
Total comprehensive income
Dividends
Repurchase of ordinary share capital
Share-based paymentsa
Minority interest buyout
At 31 December 2008

At 1 January 2007

Currency translation differences (including recycling)
Actuarial gain relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Profit for the year
Total comprehensive income
Dividends
Repurchase of ordinary share capital
Share-based paymentsa
At 31 December 2007

a Includes new share issues and movements in own shares and treasury shares where these relate to share-based payment plans.

168

Share
capital

5,176

–
–
–
–
–
–
–
3
–
–
5,179

Share
capital

5,237

–
–
–
–
–
–
–
(67)
6
–
5,176

Share
capital

5,385

–
–
–
–
–
–
–
(166)
18
5,237

Capital
premium redemption
reserve

account

9,763

–
–
–
–
–
–
–
84
–
–
9,847

1,072

–
–
–
–
–
–
–
–
–
–
1,072

Share
premium
account

Capital
redemption
reserve

9,581

–
–
–
–
–
–
–
–
182
–
9,763

1,005

–
–
–
–
–
–
–
67
–
–
1,072

Share
premium
account

Capital
redemption
reserve

9,074

–
–
–
–
–
–
–
–
507
9,581

839

–
–
–
–
–
–
–
166
–
1,005

BP Annual Report and Accounts 2009
Notes on financial statements

Merger
reserve

27,206

–
–
–
–
–
–
–
–
–
–
27,206

Merger
reserve

27,206

–
–
–
–
–
–
–
–
–
–
27,206

Merger
reserve

27,201

–
–
–
–
–
–
–
–
5
27,206

Other
reserve

Own
shares

–

–
–
–
–
–
–
–
–
–
–
–

Other
reserve

–

–
–
–
–
–
–
–
–
–
–
–

(326)

–
–
–
–
–
–
–
112
–
–
(214)

Own
shares

(60)

–
–
–
–
–
–
–
–
(266)
–
(326)

Treasury
shares

(21,513)

–
–
–
–
–
–
–
210
–
–
(21,303)

Treasury
shares

(22,112)

–
–
–
–
–
–
–
–
599
–
(21,513)

Other
reserve

Own
shares

Treasury
shares

–
–
–
–
–
–
–
–
(5)
–

(154)

(22,182)

–
–
–
–
–
–
–
–
94
(60)

–
–
–
–
–
–
–
–
70
(22,112)

Foreign
currency
translation
reserve

Available-
for-sale
investments

Cash flow
hedges

(866)

(37)
–
–
925
–
888
–
–
–
–
22

(2)
–
693
–
–
691
–
–
–
–
754

Available-
for-sale
investments

Cash flow
hedges

481

–
–
(418)
–
–
(418)
–
–
–
–
63

106

–
–
–
(972)
–
(972)
–
–
–
–
(866)

Available-
for-sale
investments

Cash flow
hedges

386

–
–
95
–
–
95
–
–
–
481

–
–
–
67
–
67
–
–
–
106

2,353

2,458
–
–
–
–
2,458
–
–
–
–
4,811

Foreign
currency
translation
reserve

6,540

(4,187)
–
–
–
–
(4,187)
–
–
–
–
2,353

Foreign
currency
translation
reserve

4,685

1,855
–
–
–
–
1,855
–
–
–
6,540

Share-
based
payment
reserve

1,295

–
–
–
–
–
–
–
289
–
–
1,584

Share-
based
payment
reserve

1,196

–
–
–
–
–
–
–
–
99
–
1,295

Share-
based
payment
reserve

859

–
–
–
–
–
–
–
–
337
1,196

$ million

BP
shareholders’
equity

Minority
interest

Total
equity

91,303

2,419
(478)
693
925
16,578
20,137
(10,483)
721
(43)
(22)
101,613

806

(56)
–
–
–
181
125
(416)
–
–
(15)
500

92,109

2,363
(478)
693
925
16,759
20,262
(10,899)
721
(43)
(37)
102,113

Profit
and loss
account

67,080

–
(478)
–
–
16,578
16,100
(10,483)
23
(43)
(22)
72,655

Profit
and loss
account

BP
shareholders’
equity

Minority
interest

64,510

–
(5,828)
–
–
21,157
15,329
(10,342)
(2,414)
(3)
–
67,080

93,690

(4,187)
(5,828)
(418)
(972)
21,157
9,752
(10,342)
(2,414)
617
–
91,303

962

(75)
–
–
–
509
434
(425)
–
–
(165)
806

Profit
and loss
account

BP
shareholders’
equity

Minority
interest

58,487

–
1,290
–
–
20,845
22,135
(8,106)
(7,997)
(9)
64,510

84,624

1,855
1,290
95
67
20,845
24,152
(8,106)
(7,997)
1,017
93,690

841

24
–
–
–
324
348
(227)
–
–
962

Total
equity

94,652

(4,262)
(5,828)
(418)
(972)
21,666
10,186
(10,767)
(2,414)
617
(165)
92,109

Total
equity

85,465

1,879
1,290
95
67
21,169
24,500
(8,333)
(7,997)
1,017
94,652

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

169

BP Annual Report and Accounts 2009
Notes on financial statements

37. Capital and reserves continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including
treasury shares.

Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.

Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.

Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in
an acquisition made by the issue of shares.

Other reserve
The balance on the other reserve represented the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in
the ARCO acquisition on the exercise of ARCO share options.

Own shares
Own shares represent BP shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based
payment plans.

Treasury shares
Treasury shares represent BP shares repurchased and available for re-issue.

Foreign currency translation reserve
The foreign currency translation reserve is used to record exchange differences arising from the translation of the financial statements of foreign
operations. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement. This reserve is
also used to record the effect of hedging net investments in foreign operations.

Available-for-sale investments
This reserve records the changes in fair value of available-for-sale investments. On disposal or impairment, the cumulative changes in fair value are
recycled to the income statement.

Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. When
the hedged transaction occurs, the gain or loss on the hedging instrument is transferred out of equity to either profit or loss or the carrying value of
assets, as appropriate. If the forecast transaction is no longer expected to occur the gain or loss recognized in equity is transferred to profit or loss.

Share-based payment reserve
This reserve represents cumulative amounts charged to profit in respect of employee share-based payment plans where the scheme has not yet been
settled by means of an award of shares to an individual.

Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.

170

BP Annual Report and Accounts 2009
Notes on financial statements

37. Capital and reserves continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.

Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Other comprehensive income

$ million

2009

Net of tax
2,363
(478)
693
925
3,503

$ million

2008

Net of tax
(4,262)
(5,828)
(418)
(972)
(11,480)

$ million

2007

Net of tax
1,879
1,290
95
67
3,331

Tax
564
204
(14)
(229)
525

Tax
100
2,602
50
194
2,946

Tax
139
(427)
(14)
26
(276)

Pre-tax
1,799
(682)
707
1,154
2,978

Pre-tax
(4,362)
(8,430)
(468)
(1,166)
(14,426)

Pre-tax
1,740
1,717
109
41
3,607

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

171

BP Annual Report and Accounts 2009
Notes on financial statements

38. Share-based payments

Effect of share-based payment transactions on the group’s result and financial position

Total expense recognized for equity-settled share-based payment transactions
Total expense (credit) recognized for cash-settled share-based payment transactions
Total expense recognized for share-based payment transactions
Closing balance of liability for cash-settled share-based payment transactions
Total intrinsic value for vested cash-settled share-based payments

2009
506
15
521
32
7

2008
524
(16)
508
21
2

$ million

2007
412
16
428
40
22

For ease of presentation, option and share holdings detailed in the tables within this note are stated as UK ordinary share equivalents in US dollars. US
employees are granted American Depositary Shares (ADSs) or options over the company’s ADSs (one ADS is equivalent to six ordinary shares). The
share-based payment plans that existed during the year are detailed below. All plans are ongoing unless otherwise stated.

Plans for executive directors
Executive Directors’ Incentive Plan (EDIP) – share element
An equity-settled incentive plan for executive directors with a three-year performance period. For share plan performance periods 2007-2009 and 2008-2010
the award of shares is determined by comparing BP’s total shareholder return (TSR) against the other oil majors (ExxonMobil, Shell, Total and Chevron). For
the performance period 2009-2011 the award of shares is determined 50% on TSR versus a competitor group of oil majors (which in this period also included
ConocoPhillips) and 50% on a balanced scorecard (BSC) of three underlying performance measures versus the same competitor group. After the
performance period, the shares that vest (net of tax) are then subject to a three-year retention period. The directors’ remuneration report on pages 81 to 92
includes full details of the plan.

Executive Directors’ Incentive Plan (EDIP) – share option element
An equity-settled share option plan for executive directors that permits options to be granted at an exercise price no lower than the market price of a
share on the date that the option is granted. The options are exercisable up to the seventh anniversary of the grant date and the last grants were made
in 2004. From 2005 onwards the remuneration committee’s policy is not to make further grants of share options to executive directors.

Plans for senior employees
The group operates a number of equity-settled share plans under which share units are granted to its senior leaders and certain employees. These
plans typically have a three-year performance or restricted period during which the units accrue net notional dividends which are treated as having
been reinvested. Leaving employment during the three-year period will normally preclude the conversion of units into shares, but special arrangements
apply where the participant leaves for a qualifying reason.

Grants are settled in cash where participants are located in a country whose regulatory environment prohibits the holding of BP shares.

Performance unit plans
The number of units granted is made by reference to level of seniority of the employees. The number of units converted to shares is determined by
reference to performance measures over the three-year performance period. The main performance measure used is BP’s TSR compared against the
other oil majors. In addition, free cash flow (FCF) is used as a performance measure for one of the performance plans. Plans included in this category
are the Competitive Performance Plan (CPP), the Medium Term Performance Plan (MTPP) and, in part, the Performance Share Plan (PSP).

Restricted share unit plans
Share unit grants under BP’s restricted plans typically take into account the employee’s performance in either the current or the prior year, track record
of delivery, business and leadership skills and long-term potential. One restricted share unit plan used in special circumstances for senior employees,
such as recruitment and retention, normally has no performance conditions. Plans included in this category are the Executive Performance Plan (EPP),
the Restricted Share Plan (RSP), the Deferred Annual Bonus Plan (DAB) and, in part, the Performance Share Plan (PSP).

BP Share Option Plan (BPSOP)
Share options with an exercise price equivalent to the market price of a share immediately preceding the date of grant were granted to participants
annually until 2006. There were no performance conditions and the options are exercisable between the third and tenth anniversaries of the grant date.

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- 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 have six months in which to use their savings to exercise their options on a pro-
rated basis.

172

BP Annual Report and Accounts 2009
Notes on financial statements

38. Share-based payments continued
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.

Local plans
In some countries BP provides local scheme benefits, the rules and qualifications for which vary according to local circumstances.

Employee Share Ownership Plans (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards made to participants under the BP share plans as required. The ESOPs have
waived their rights to dividends on shares held for future awards and are funded by the group. Until such time as the company’s own shares held by
the ESOP trusts vest unconditionally to employees, the amount paid for those shares is deducted in arriving at shareholders’ equity (see Note 37).
Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.

At 31 December 2009 the ESOPs held 18,062,246 shares (2008 29,051,082 shares and 2007 6,448,838 shares) for potential future awards,

which had a market value of $174 million (2008 $220 million and 2007 $79 million).

Share option transactions

2009

Outstanding at 1 January
Granted
Forfeited
Exercised
Expired
Outstanding at 31 December
Exercisable at 31 December

Number

Weighted
average
of exercise price
$
8.70
6.55
8.81
7.53
8.01
8.73
8.80

options
326,254,599
9,679,836
(5,954,325)
(21,293,871)
(12,790,882)
295,895,357
274,685,068

2008

Weighted
average
exercise price
$
8.51
8.96
8.50
6.97
7.00
8.70
8.22

Number
of
options
358,094,243
8,062,899
(2,502,784)
(37,277,895)
(121,864)
326,254,599
260,178,938

2007

Weighted
average
exercise price
$
8.25
9.11
9.10
6.94
8.68
8.51
7.70

Number
of
options
426,471,462
6,004,025
(3,924,714)
(69,715,558)
(740,972)
358,094,243
238,707,055

As share options are exercised continuously throughout the year, the weighted average share price during the year of $9.10 (2008 $10.87 and 2007
$11.72) is representative of the weighted average share price at the date of exercise. For the options outstanding at 31 December 2009, the exercise
price ranges and weighted average remaining contractual lives are shown below.

Options outstanding

Options exercisable

Range of exercise prices
$6.18 – $7.61
$7.62 – $9.05
$9.06 – $10.48
$10.49 – $11.92

Number
of
shares
53,511,852
143,736,259
27,046,156
71,601,090
295,895,357

Weighted
average

Weighted
average
remaining life exercise price
$
6.43
8.18
9.83
11.14
8.73

Years
3.31
2.48
4.10
5.81
3.58

Number

Weighted
average
of exercise price
$
6.40
8.16
10.01
11.14
8.80

shares
43,956,777
137,625,273
21,501,928
71,601,090
274,685,068

Fair values and associated details for options and shares granted

Option pricing model used
Weighted average fair value
Weighted average share price
Weighted average exercise price
Expected volatility
Option life
Expected dividends
Risk free interest rate
Expected exercise behaviour

2009

ShareSave
3 year
Binomial
$1.07
$7.87
$6.92
32%
3.5 years
7.40%
3.00%

ShareSave
5 year
Binomial
$1.07
$7.87
$6.92
32%
5.5 years
7.40%
3.75%
100% year 4 100% year 6

ShareSave
3 year
Binomial
$1.82
$11.26
$9.70
23%
3.5 years
4.60%
5.00%
100% year 4

2008

ShareSave
5 year
Binomial
$1.74
$11.26
$9.70
23%
5.5 years
4.60%
5.00%
100% year 6

ShareSave
3 year
Binomial
$3.57
$12.10
$9.13
21%
3.5 years
3.48%
5.75%
100% year 4

2007

ShareSave
5 year
Binomial
$3.79
$12.10
$9.13
21%
5.5 years
3.48%
5.75%
100% year 6

The group uses a valuation model to determine the fair value of options granted. The model uses the implied volatility of ordinary share price for the
quarter within which the grant date of the relevant plan falls. The fair value is adjusted for the expected rates of early cancellation. Management is
responsible for all inputs and assumptions in relation to the model, including the determination of expected volatility.

173

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
Notes on financial statements

38. Share-based payments continued

Shares granted in 2009
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

Shares granted in 2008
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

Shares granted in 2007
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

a EDIP – retention element.
b EDIP – long-term leadership element.

CPP
1.4
$9.76
Monte
Carlo

MTPP-
TSR
9.1
$5.07
Monte
Carlo

MTPP-
TSR
9.4
$4.73
Monte
Carlo

EPP
7.6
$6.56
Market
value

MTPP-
FCF
9.1
$10.34
Market
value

MTPP-
FCF
8.5
$10.02
Market
value

EDIP-
TSR
2.1
$2.74
Monte
Carlo

EDIP-
TSR
2.6
$4.55
Monte
Carlo

EDIP-
TSR
4.5
$2.81
Monte
Carlo

EDIP-
BSC
2.1
$7.27
Market
value

EDIP-
RETa
0.5
$11.13
Market
value

EDIP-
LTLb
0.5
$9.92
Market
value

RSP
2.4
$8.76
Market
value

DAB
38.9
$6.56
Market
value

RSP
7.7
$8.83
Market
value

RSP
7.7
$11.93
Market
value

DAB
5.8
$10.34
Market
value

DAB
4.4
$10.02
Market
value

PSP
16.5
$8.32
Monte
Carlo

PSP
16.7
$12.89
Monte
Carlo

PSP
14.8
$12.37
Monte
Carlo

The group used a Monte Carlo simulation to determine the fair value of the TSR element of the 2009, 2008 and 2007 CPP, PSP, MTPP and EDIP plans.
In accordance with the rules of the plans the model simulates BP’s TSR and compares it against our principal strategic competitors over the three-year
period of the plans. The model takes into account the historic dividends, share price volatilities and covariances of BP and each comparator company to
produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the TSR element.

Accounting expense does not necessarily represent the actual value of share-based payments made to recipients, which are determined by the

remuneration committee according to established criteria.

39. Employee costs and numbers

Employee costs

Wages and salariesa
Social security costs
Share-based payments
Pension and other post-retirement benefit costs

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

By geographical area
US
Non-USb

Average number of employees
Exploration and Production
Refining and Marketing
Other businesses and corporate

a Includes termination payments of $945 million (2008 $669 million and 2007 $422 million).
b Includes 13,900 (2008 21,200 and 2007 24,500) service station staff.

174

2009

9,702
780
521
1,213
12,216

2009
21,500
51,600
7,200
80,300

22,800
57,500
80,300

2008

10,388
805
508
579
12,280

2008
21,400
61,500
9,100
92,000

29,300
62,700
92,000

$ million

2007

9,808
771
428
504
11,511

2007
21,800
67,200
9,100
98,100

33,000
65,100
98,100

2007

Total
21,500
67,300
8,400
97,200

US
7,900
14,700
2,300
24,900

Non-US
13,800
40,700
5,800
60,300

2009

Total
21,700
55,400
8,100
85,200

US
7,800
21,600
2,600
32,000

Non-US
13,800
43,400
6,500
63,700

2008

Total
21,600
65,000
9,100
95,700

US
7,700
23,400
2,500
33,600

Non-US
13,800
43,900
5,900
63,600

BP Annual Report and Accounts 2009
Notes on financial statements

40. Remuneration of directors and senior management

Remuneration of directors

Total for all directors
Emoluments
Gains made on the exercise of share options
Amounts awarded under incentive schemes

2009

2008

19
2
2

19
1
–

$ million

2007

26
2
10

Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits
earned during the relevant financial year, plus bonuses awarded for the year. Ex gratia superannuation payments of $3 million were included in 2007.
Also included was compensation for loss of office of $1 million in 2008 and $1 million in 2007.

Pension contributions
Three executive directors participated in a non-contributory pension scheme established for UK employees by a separate trust fund to which
contributions are made by BP based on actuarial advice. Two US executive directors participated in the US BP Retirement Accumulation Plan during 2009.

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

Further information
Full details of individual directors’ remuneration are given in the directors’ remuneration report on pages 81 to 92.

Remuneration of directors and senior management

Total for all senior management

Short-term employee benefits
Post-retirement benefits
Share-based payments

2009

2008

36
3
20

34
4
20

$ million

2007

35
6
22

Senior management, in addition to executive and non-executive directors, includes other senior managers who are members of the executive
management team.

Short-term employee benefits
In addition to fees paid to the non-executive chairman and non-executive directors, these amounts comprise, for executive directors and senior
managers, salary and benefits earned during the year, plus cash bonuses awarded for the year. Deferred annual bonus awards, to be settled in shares,
are included in share-based payments. Short-term employee benefits includes an ex gratia superannuation payment of nil (2008 nil and 2007
$3 million) and compensation for loss of office of $6 million (2008 $3 million and 2007 $1 million).

Post-retirement benefits
The amounts represent the estimated cost to the group of providing defined benefit pensions and other post-retirement benefits to senior
management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.

Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares
granted accounted for in accordance with IFRS 2 ‘Share-based Payments’. The main plans in which senior management have participated are the EDIP
and MTPP. For details of these plans refer to Note 38.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

175

BP Annual Report and Accounts 2009
Notes on financial statements

41. Contingent liabilities

There were contingent liabilities at 31 December 2009 in respect of guarantees and indemnities entered into as part of the ordinary course of the
group’s business. No material losses are likely to arise from such contingent liabilities. Further information is included in Note 24.

Lawsuits arising out of the Exxon Valdez oil spill in Prince William Sound, Alaska, in March 1989 were filed against 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 Company (Atlantic Richfield). Alyeska and its owners have settled all the claims against them under these lawsuits. Exxon has
indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages that Exxon has incurred. BP will defend any
such claims vigorously. It is not possible to estimate any financial effect.

In the normal course of the group’s business, legal proceedings are pending or may be brought against BP group entities arising out of current

and past operations, including matters related to commercial disputes, product liability, antitrust, premises-liability claims, general environmental claims
and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals. BP believes that the
impact of these legal proceedings on the group’s results of operations, liquidity or financial position will not be material.

With respect to lead pigment in paint in particular, 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. Although it is not possible to predict the outcome of the legal proceedings, Atlantic
Richfield believes it has valid defences that render the incurrence of a liability remote; however, the amounts claimed and the costs of implementing
the remedies sought in the various cases could be substantial. The majority of the lawsuits have been abandoned or dismissed against Atlantic
Richfield. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding.
Atlantic Richfield intends to defend such actions vigorously.

The group files income tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group’s

income tax returns. Tax returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the
resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is
difficult to predict the ultimate outcome in some cases, the group does not anticipate that there will be any material impact upon the group’s results
of operations, financial position or liquidity.

The group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities.

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

The group also has obligations to decommission oil and natural gas production facilities and related pipelines. Provision is made for the
estimated costs of these activities, however there is uncertainty regarding both the amount and timing of these costs, given the long-term nature of
these obligations. BP believes that the impact of any reasonably foreseeable changes to these provisions on the group’s results of operations, financial
position or liquidity will not be material.

The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because

external insurance is not considered an economic means of financing losses for the group. Losses will therefore be borne as they arise rather than
being spread over time through insurance premiums with attendant transaction costs. The position is reviewed periodically.

42. Capital commitments

Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been placed at 31 December
2009 amounted to $9,812 million (2008 $14,062 million). In addition, at 31 December 2009, the group had contracts in place for future capital
expenditure relating to investments in jointly controlled entities of $622 million (2008 $644 million) and investments in associates of $170 million
(2008 $160 million).

BP’s share of capital commitments of jointly controlled entities amounted to $926 million (2008 $1,540 million).

176

BP Annual Report and Accounts 2009
Notes on financial statements

43. Subsidiaries, jointly controlled entities and associates

The more important subsidiaries, jointly controlled entities and associates of the group at 31 December 2009 and the group percentage of ordinary
share capital or joint venture interest (to nearest whole number) are set out below. The principal country of operation is generally indicated by the
company’s country of incorporation or by its name. Those held directly by the parent company are marked with an asterisk (*), the percentage owned
being that of the group unless otherwise indicated. A complete list of investments in subsidiaries, jointly controlled entities and associates will be
attached to the parent company’s annual return made to the Registrar of Companies.

Country of

% incorporation

Principal activities

Subsidiaries

% incorporation

Principal activities

Subsidiaries
International

*BP Corporate Holdings
BP Exploration Op. Co.
*BP Global Investments
*BP International

BP Oil International

*BP Shipping
*Burmah Castrol
Jupiter Insurance

100 England
100 England
100 England
100 England
100 England
100 England
100 Scotland
100 Guernsey

Investment holding
Exploration and production
Investment holding
Integrated oil operations
Integrated oil operations
Shipping
Lubricants
Insurance

Netherlands

BP Capital
BP Nederland

New Zealand

100 Netherlands
100 Netherlands Refining and marketing

Finance

BP Oil New Zealand

100 New Zealand Marketing

Norway

BP Norge

Spain

100 Norway

Exploration and production

100 Scotland

Exploration and production

100 Bahamas

Exploration and production

BP España

100 Spain

Refining and marketing

South Africa

*BP Southern Africa

75 South Africa Refining and marketing

BP Exploration (Angola)

100 England

Exploration and production

Trinidad & Tobago

BP Trinidad and

Tobago

70 US

Exploration and production

Algeria

BP Amoco Exploration
(In Amenas)

BP Exploration (El
Djazair)

Angola

Australia

BP Oil Australia
BP Australia Capital
Markets
BP Developments
Australia

BP Finance Australia

Azerbaijan

Amoco Caspian Sea
Petroleum
BP Exploration

100 Australia

Integrated oil operations

100 Australia

Finance

100 Australia
100 Australia

Exploration and production
Finance

British Virgin Exploration and production

100 Islands

(Caspian Sea)

100 England

Exploration and production

Canada

BP Canada Energy
BP Canada Finance

100 Canada
100 Canada

Exploration and production
Finance

Egypt

BP Egypt Co.

100 US

Exploration and production

Germany

Deutsche BP

Indonesia

BP Berau

100 Germany

Refining and marketing
and petrochemicals

100 US

Exploration and production

BP Capital Markets
BP Oil UK
Britoil

100 England
100 England
100 Scotland

Finance
Marketing
Exploration and production

*BP Holdings North

America

100 England

Investment holding

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Atlantic Richfield Co.
BP America
BP America
Production
Company

BP Amoco Chemical

Company
BP Company

North America

BP Corporation

North America

BP Exploration
(Alaska) Inc.
BP Products

North America

BP West Coast

Products

Standard Oil Co.
BP Capital Markets

America

100 US

Exploration and production,
refining and marketing,
pipelines and
petrochemicals

Finance

177

BP Annual Report and Accounts 2009
Notes on financial statements

43. Subsidiaries, jointly controlled entities and associates continued

Jointly controlled entities
Angola LNG Supply Services
Atlantic 4 Holdings
Atlantic LNG 2/3 Company of Trinidad and Tobago
BP-Husky Refining
Elvary Neftegaz Holdings BV
Pan American Energya
Petromonagas
Ruhr Oel
Shanghai SECCO Petrochemical Co.
Sunrise Oil Sands
United Gas Derivatives Company
Watson Cogenerationa

%
14
38
43
50
49
60
17
50
50
50
33
51

Country of incorporation
or registration
US
US
Trinidad & Tobago
US
Netherlands
US
Venezuela
Germany
China
Canada
Egypt
US

Principal activities
LNG processing and transportation
LNG manufacture
LNG manufacture
Refining
Exploration and appraisal
Exploration and production
Exploration and production
Refining and marketing and petrochemicals
Petrochemicals
Exploration and production
LNG manufacture
Power generation

a The entity is not controlled by BP as certain key business decisions require joint approval of both BP and the minority partner. It is therefore classified as a jointly controlled entity rather than a subsidiary.

Associates
Abu Dhabi

Abu Dhabi Marine Areas
Abu Dhabi Petroleum Co.

Azerbaijan

The Baku-Tbilisi-Ceyhan Pipeline Co.
South Caucasus Pipeline Co.

Russia

TNK-BP
Trinidad & Tobago

Atlantic LNG Company of Trinidad and Tobago

Country of incorporation

Principal activities

37
24

30
26

England
England

Crude oil production
Crude oil production

Cayman Islands
Cayman Islands

Pipelines
Pipelines

British Virgin Islands

Integrated oil operations

Trinidad & Tobago

LNG manufacture

178

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Supplementary information on oil and natural gas (unaudited)
The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved
reserves (for subsidiaries plus equity-accounted entities), in accordance with revised SEC and FASB requirements. The comparative information for
2008 and 2007 is also presented on this basis. For 2009, where relevant, information for equity-accounted entities is provided in the same level of
detail as for subsidiaries. Also for 2009, proved reserves are based on revised SEC definitions.

For details on BP’s proved reserves and production compliance and governance processes, see pages 24 to 26.

Oil and natural gas exploration and production activities

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2009

Total

Subsidiariesa
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation
Net capitalized costs

35,096
752
35,848
26,794
9,054

6,644
–
6,644
3,306
3,338

64,366
5,464
69,830
31,728
38,102

3,967
147
4,114
2,309
1,805

8,346
198
8,544
4,837
3,707

24,476
2,377
26,853
12,492
14,361

Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc

Proved
Unproved

Exploration and appraisal costsd
Development
Total costs

179
(1)
178
183
751
1,112

–
–
–
–
1,054
1,054

(17)
370
353
1,377
4,208
5,938

Results of operations for the year ended 31 December
Sales and other operating revenuese

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and amortization
Impairments and (gains) losses on sale
of businesses and fixed assets

Profit before taxationg
Allocable taxes
Results of operations

2,239
2,482
4,721
59
1,243
(3)
(1,259)
1,148

(122)
1,066
3,655
1,568
2,087

68
809
877
–
164
–
51
185

(7)
393
484
76
408

4,759
11,313
16,072
663
2,821
649
2,353
3,857

(208)
10,135
5,937
1,902
4,035

–
1
1
79
386
466

99
484
583
80
284
1
145
170

–
680
(97)
(58)
(39)

–
–
–
78
453
531

1,525
1,409
2,934
16
395
220
184
697

(11)
1,501
1,433
916
517

–
18
18
712
2,707
3,437

1,846
5,313
7,159
219
908
–
144
2,041

(1)
3,311
3,848
1,517
2,331

–
–
–
–
–

–
–
–
8
–
8

–
–
–
8
15
–
76
–

–
99
(99)
(25)
(74)

10,900
733
11,633
4,798
6,835

2,894 156,689
10,710
1,039
3,933 167,399
87,302
1,038
80,097
2,895

306
–
306
315
560
1,181

636
6,257
6,893
49
361
2,854
967
757

(702)j
4,286
2,607
682
1,925

–
10
10
53
277
340

468
398
866
2,805
10,396
14,067

785
726
1,511
22
70
72
178
96

–
438
1,073
2
1,071

11,957
28,793
40,750
1,116
6,261
3,793
2,839
8,951

(1,051)
21,909
18,841
6,580
12,261

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Exploration and Production segment replacement cost profit before interest and tax
Exploration and production activities –

subsidiaries (as above)

Midstream activities – subsidiariesh
Equity-accounted entitiesi
Total replacement cost profit before

3,655
925
–

484
17
5

5,937
719
29

(97)
833
134

1,433
17
630

3,848
(27)
56

(99)
(37)
1,924

2,607
518
531

1,073
(315)
–

18,841
2,650
3,309

interest and tax

4,580

506

6,685

870

2,080

3,877

1,788

3,656

758

24,800

a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. Midstream activities relating to the management and ownership of crude oil and natural
gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGL’s
in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission
System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business
in Angola.
bDecommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
dIncludes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
ePresented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $663 million. The UK region includes a $783 million gain offset by corresponding charges primarily in
the US, relating to the group self-insurance programme.
g Excludes the unwinding of the discount on provisions and payables amounting to $308 million which is included in finance costs in the group income statement.
hMidstream activities exclude inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and tax.
j Includes the gain on disposal of upstream assets associated with our sale of our 46% stake in LukArco (see Note 3).

179

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Oil and natural gas exploration and production activities continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Equity-accounted entities (BP share)a
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation
Net capitalized costs

Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc

Proved
Unproved

Exploration and appraisal costsd
Development
Total costs

–
–
–
–
–

–
–
–
–
–
–

Results of operations for the year ended 31 December
Sales and other operating revenuese

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Impairments and (gains) losses on sale
of businesses and fixed assets

Profit before taxation
Allocable taxes
Results of operations

Exploration and production activities –

equity-accounted entities (as above)
Midstream and other activities after taxf
Total replacement cost profit after

interest and tax

–
–
–
–
–
–
–
–

–
–
–
–
–

–
–

–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–
–

–
–
–
–
–

–
5

Russia

Rest of
Asia

13,266
737
14,003
5,550
8,453

2,259
–
2,259
1,739
520

–
10
10
77
1,182
1,269

4,919
2,838
7,757
37
1,428
2,597
12
1,073

72
5,219
2,538
501
2,037

–
–
–
3
246
249

351
–
351
–
159
–
(2)
274

–
431
(80)
–
(80)

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–
–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–
–

–
–
–
–
–

–
1,378
1,378
–
1,378

5,789
197
5,986
2,084
3,902

–
–
–
–
30
30

–
–
–
–
–
–
–
–

–
–
–
–
–

–
31
31
21
538
590

1,977
–
1,977
23
354
702
(69)
281

–
1,291
686
270
416

–
29

–
134

134

416
214

630

–
56

2,037
(113)

(80)
611

1,924

531

$ million

2009

Total

21,314
2,312
23,626
9,373
14,253

–
41
41
101
1,996
2,138

7,247
2,838
10,085
60
1,941
3,299
(59)
1,628

72
6,941
3,144
771
2,373

2,373
936

3,309

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–
–

–
–
–
–
–

–
–

–

a These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Midstream activities relating to the management and ownership of crude
oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream activities of TNK-BP are excluded. The amounts reported for equity-
accounted entities exclude the corresponding amounts for their equity-accounted entities.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes.
f Includes interest, minority interest and the net results of equity-accounted entities of equity-accounted entities.

180

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Oil and natural gas exploration and production activities continued

Europe

North
America

South
America

Rest of
Europe

Rest of
North
America

Africa

Asia

Australasia

$ million

2008

Total

Russia

Rest of
Asia

34,614
626
35,240
26,564
8,676

5,507
–
5,507
3,125
2,382

59,918
5,006
64,924
28,511
36,413

3,517
165
3,682
2,141
1,541

7,934
134
8,068
4,217
3,851

21,563
2,011
23,574
10,451
13,123

–
–
–
–
–

10,689
465
11,154
4,395
6,759

2,581 146,323
1,018
9,425
3,599 155,748
80,349
75,399

945
2,654

Subsidiariesa
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation
Net capitalized costs

The group’s share of equity-accounted entities’ net capitalized costs at 31 December 2008 was $13,393 million.

Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc

Proved
Unproved

Exploration and appraisal costsd
Development
Total costs

–
4
4
137
907
1,048

–
–
–
–
695
695

1,374
2,942
4,316
862
4,914
10,092

2
–
2
33
309
344

–
–
–
90
768
858

–
–
–
838
2,966
3,804

–
–
–
12
–
12

136
41
177
269
859
1,305

–
–
–
49
349
398

1,512
2,987
4,499
2,290
11,767
18,556

The group’s share of equity-accounted entities’ costs incurred in 2008 was $3,259 million: in Russia $1,921 million, South America $1,039 million, and
Rest of Asia $299 million.

Results of operations for the year ended 31 December
Sales and other operating revenuese

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxesf
Other costs (income)f g
Depreciation, depletion and amortization
Impairments and (gains) losses on sale
of businesses and fixed assets

Profit before taxationh
Allocable taxes
Results of operations

3,865
4,374
8,239
121
1,357
503
(28)
1,049

–
3,002
5,237
2,280
2,957

105
1,416
1,521
1
150
–
(43)
199

–
307
1,214
883
331

8,010
15,610
23,620
305
3,002
2,603
3,440
2,729

308
12,387
11,233
3,857
7,376

147
1,237
1,384
32
289
2
343
181

2
849
535
205
330

3,339
2,605
5,944
30
429
358
198
730

4
1,749
4,195
2,218
1,977

3,745
6,022
9,767
213
875
–
(122)k
2,120

8
3,094
6,673
2,672
4,001

–
–
–
14
18
–
196
–

–
228
(228)
(36)
(192)

1,186
11,249
12,435
140
485
5,510
2,064
788

219
9,206
3,229
984
2,245

860
1,171
2,031
26
62
110
226
87

–
511
1,520
513
1,007

21,257
43,684
64,941
882
6,667
9,086
6,274
7,883

541
31,333
33,608
13,576
20,032

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

The group’s share of equity-accounted entities’ results of operations (including the group’s share of total TNK-BP results) in 2008 was a profit of $2,793
million after deducting interest of $355 million, taxation of $1,217 million and minority interest of $169 million.

Exploration and Production segment replacement cost profit before interest and tax
Exploration and production activities

Subsidiaries (as above)
Equity-accounted entities

Midstream activitiesi j
Total replacement cost profit
before interest and tax

5,237
(1)
743

1,214
–
16

11,233
1
490

535
40
673

4,195
304
274

6,673
(1)
112

(228)
2,259
–

3,229
191
(272)

1,520
–
(129)

33,608
2,793
1,907

5,979

1,230

11,724

1,248

4,773

6,784

2,031

3,148

1,391

38,308

b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d
Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e
Presented net of transportation costs, purchases and sales taxes.
f Comparative figures have been restated to include in Production taxes amounts previously reported within Other costs (income) amounting to $2,427 million.
g
Includes property taxes, other government take and the fair value loss on embedded derivatives of $102 million. The UK region includes a $499 million gain offset by corresponding charges primarily
in the US, relating to the group self-insurance programme.
h
Excludes the unwinding of the discount on provisions and payables amounting to $285 million which is included in finance costs in the group income statement.
i Includes a $517 million write-down of our investment in Rosneft based on its quoted market price at the end of the year.
j Midstream activities exclude inventory holding gains and losses.
k
Includes $367 million previously reported within the ‘Other’ region.

181

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Oil and natural gas exploration and production activities continued

Europe

North
America

South
America

Rest of
Europe

Rest of
North
America

Africa

Asia

Australasia

$ million

2007

Total

Russia

Rest of
Asia

34,774
606
35,380
25,515
9,865

4,925
–
4,925
2,925
2,000

53,079
1,660
54,739
25,500
29,239

3,261
182
3,443
1,968
1,475

7,366
115
7,481
3,560
3,921

18,333
1,533
19,866
8,315
11,551

–
4
4
–
4

9,629
536
10,165
3,638
6,527

1,495 132,862
1,001
5,637
2,496 138,499
71,844
66,655

423
2,073

Subsidiariesa
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation
Net capitalized costs

The group’s share of equity-accounted entities’ net capitalized costs at 31 December 2007 was $11,787 million.

Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc

Proved
Unproved

Exploration and appraisal costsd
Development
Total costs

–
–
–
209
804
1,013

–
–
–
16
443
459

245
54
299
646
3,861
4,806

–
16
16
40
240
296

–
–
–
32
817
849

–
321
321
677
2,634
3,632

–
–
–
119
–
119

232
126
358
118
1,109
1,585

–
–
–
35
245
280

477
517
994
1,892
10,153
13,039

The group’s share of equity-accounted entities’ costs incurred in 2007 was $2,552 million: in Russia $1,787 million, South America $569 million, and
Rest of Asia $196 million.

Results of operations for the year ended 31 December
Sales and other operating revenuese

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxesf
Other costs (income)f g
Depreciation, depletion and amortization
Impairments and (gains) losses on sale
of businesses and fixed assets

Profit before taxationh
Allocable taxes
Results of operations

4,503
2,260
6,763
46
1,658
227
(419)
1,569

112
3,193
3,570
1,664
1,906

434
902
1,336
–
147
3
123
207

(534)
(54)
1,390
611
779

1,436
14,353
15,789
252
2,782
1,260
2,505
2,118

(413)
8,504
7,285
2,560
4,725

147
868
1,015
57
267
1
237
169

(38)
693
322
35
287

1,995
2,274
4,269
77
503
272
158
653

(5)
1,658
2,611
1,167
1,444

2,219
3,223
5,442
183
637
–
224j
1,372

(76)
2,340
3,102
1,462
1,640

–
–
–
116
2
–
169
–

–
287
(287)
3
(290)

1,388
10,137
11,525
18
470
3,914
1,316
1,148

–
6,866
4,659
1,133
3,526

681
816
1,497
7
64
56
366
52

–
545
952
267
685

12,803
34,833
47,636
756
6,530
5,733
4,679
7,288

(954)
24,032
23,604
8,902
14,702

The group’s share of equity-accounted entities’ results of operations (including the group’s share of total TNK-BP results) in 2007 was a profit of $2,704
million after deducting interest of $401 million, taxation of $1,355 million and minority interest of $215 million.

Exploration and Production segment replacement cost profit before interest and tax
Exploration and production activities

Subsidiaries (as above)
Equity-accounted entities

Midstream activitiesi
Total replacement cost profit
before interest and tax

3,570
–
15

1,390
–
12

7,285
1
643

322
(33)
626

2,611
414
13

3,102
–
96

(287)
2,292
(112)

4,659
30
38

952
–
(37)

23,604
2,704
1,294

3,585

1,402

7,929

915

3,038

3,198

1,893

4,727

915

27,602

a These tables contain information relating to oil and natural gas exploration and production activities. Midstream activities relating to the management and ownership of crude oil and natural gas
pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and
NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area
Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia. The group’s share of equity-
accounted entities’ activities are excluded from the tables and included in the footnotes with the exception of the Abu Dhabi operations which are included in the results of operations above.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes.
f Comparative figures have been restated to include in Production taxes amounts previously reported within Other costs (income) amounting to $1,690 million.
g Includes property taxes, other government take and the fair value gain on embedded derivatives of $47 million. The UK region includes a $409 million gain offset by corresponding charges primarily in

the US, relating to the group self-insurance programme.

h Excludes the unwinding of the discount on provisions and payables amounting to $179 million which is included in finance costs in the group income statement.
i Midstream activities exclude inventory holding gains and losses.
j Includes $24 million previously reported within the ‘Other’ region.

182

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Movements in estimated net proved reserves

million barrels

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USe

Rest of
North
America

Russia

Rest of
Asia

Crude oila

Subsidiaries
At 1 January 2009
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2009c

Developed
Undeveloped

Equity-accounted entities (BP share)f
At 1 January 2009
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place

At 31 December 2009d

Developed
Undeveloped

410
119
529

7
42
1
184
(61)
(8)
165

403
291
694

–
–
–

–
–
–
–
–
–
–

–
–
–

81
194
275

(1)
7
–
–
(14)
–
(8)

83
184
267

–
–
–

–
–
–
–
–
–
–

–
–
–

1,717
1,273
2,990

165
82
–
73
(237)
–
83

1,862
1,211
3,073

–
–
–

–
–
–
–
–
–
–

–
–
–

Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2009
Developed
Undeveloped

410
119
529

At 31 December 2009

Developed
Undeveloped

403
291
694

81
194
275

83
184
267

1,717
1,273
2,990

1,862
1,211
3,073

2009

Total

2,981
2,684
5,665

(55)
203
2
378
(501)
(34)
(7)

3,070
2,588
5,658

3,125
1,563
4,688

562
58
–
90
(415)
(130)
165

3,121
1,732
4,853

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

195
488
683

(128)
31
1
–
(45)
(26)
(167)

182
334
516

499
199
698

(28)
–
–
–
(71)
(116)
(215)

363
120
483

56
58
114

3
2
–
7
(11)
–
1

58
57
115

–
–
–

–
–
–
–
–
–
–

–
–
–

694
687
1,381

545
454
999

56
58
114

58
57
115

6,106
4,247
10,353

6,191
4,320
10,511

11
1
12

2
–
–
–
(2)
–
–

11
1
12

–
–
–

–
–
–
–
–
–
–

–
–
–

11
1
12

47
55
102

18
7
–
–
(22)
–
3

49
56
105

399
409
808

2
50
–
3
(37)
(14)
4

407
405
812

446
464
910

456
461
917

464
496
960

(121)
32
–
114
(109)
–
(84)

422
454
876

–
11
11

(2)
–
–
–
–
–
(2)

–
9
9

464
507
971

422
463
885

–
–
–

–
–
–
–
–
–
–

–
–
–

2,227
944
3,171

590
8
–
87
(307)
–
378

2,351
1,198
3,549

2,227
944
3,171

2,351
1,198
3,549

183

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Movements in estimated net proved reserves continued

Natural gasa

Subsidiaries
At 1 January 2009
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2009c

Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January 2009
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2009d

Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

2009

Total

billion cubic feet

1,822
582
2,404

(114)
34
159
150
(243)
(118)
(132)

1,602
670
2,272

–
–
–

–
–
–
–
–
–
–

–
–
–

61
402
463

(8)
–
–
–
(9)
–
(17)

49
397
446

–
–
–

–
–
–
–
–
–
–

–
–
–

9,059
5,473
14,532

659
468
1,127

3,316
7,434
10,750

1,050
1,382
2,432

549
550
–
496
(907)
(4)
684

43
5
–
94
(100)
–
42

322
322
–
105
(929)
–
(180)

270
49
–
59
(249)
–
129

9,583
5,633
15,216

716
453
1,169

3,177
7,393
10,570

1,107
1,454
2,561

–
–
–

–
–
–
–
–
–
–

–
–
–

1,102
1,308
2,410

1,887
4,000
5,887

18,956
21,049
40,005

(231)
82
31
–
(241)
(223)
(582)

22
75
–
531
(189)
–
439

853
1,117
190
1,435
(2,867)
(345)
383

1,579
249
1,828

3,219
3,107
6,326

21,032
19,356
40,388

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

1,498
1,023
2,521

(26)
314
–
6
(165)
(388)
(259)

1,252
1,010
2,262

–
182
182

(17)
–
–
–
–
–
(17)

–
165
165

1,560
653
2,213

204
1
–
23
(219)
–
9

1,703
519
2,222

1,560
653
2,213

1,703
519
2,222

176
111
287

(19)
4
–
–
(25)
(154)
(194)

80
13
93

1,278
1,419
2,697

1,659
262
1,921

–
–
–

–
–
–
–
–
–
–

–
–
–

3,234
1,969
5,203

142
319
–
29
(409)
(542)
(461)

3,035
1,707
4,742

1,887
4,000
5,887

3,219
3,107
6,326

22,190
23,018
45,208

24,067
21,063
45,130

Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2009
Developed
Undeveloped

1,822
582
2,404

At 31 December 2009

Developed
Undeveloped

1,602
670
2,272

61
402
463

49
397
446

9,059
5,473
14,532

9,583
5,633
15,216

659
468
1,127

716
453
1,169

4,814
8,457
13,271

4,429
8,403
12,832

1,050
1,564
2,614

1,107
1,619
2,726

184

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Movements in estimated net proved reserves continued

Crude oila

Subsidiaries
At 1 January 2008
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2008c

Developed
Undeveloped

Equity-accounted entities (BP share)f
At 1 January 2008
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place

At 31 December 2008d

Developed
Undeveloped

Europe

North
America

South
America

Rest of
Europe

USe

Rest of
North
America

Africa

Asia

Australasia

million barrels

2008

Total

Russia

Rest of
Asia

414
123
537

16
39
–
–
(63)
–
(8)

410
119
529

–
–
–

–
–
–
–
–
–
–

–
–
–

105
169
274

(11)
28
–
–
(16)
–
1

81
194
275

–
–
–

–
–
–
–
–
–
–

–
–
–

1,882
1,265
3,147

(212)
182
–
64
(191)
–
(157)

1,717
1,273
2,990

–
–
–

–
–
–
–
–
–
–

–
–
–

13
1
14

1
–
–
–
(3)
–
(2)

11
1
12

–
–
–

–
–
–
–
–
–
–

–
–
–

13
1
14

11
1
12

102
202
304

7
8
–
5
(23)
(199)
(202)

47
55
102

328
243
571

(3)
62
199
13
(34)
–
237

399
409
808

430
445
875

446
464
910

256
350
606

264
18
–
173
(101)
–
354

464
496
960

–
–
–

11
–
–
–
–
–
11

–
11
11

256
350
606

464
507
971

–
–
–

–
–
–
–
–
–
–

–
–
–

2,094
1,137
3,231

217
–
–
26
(302)
(1)
(60)

2,227
944
3,171

2,094
1,137
3,231

2,227
944
3,171

121
372
493

194
43
–
–
(47)
–
190

195
488
683

574
205
779

(1)
–
–
–
(80)
–
(81)

499
199
698

44
73
117

5
3
–
–
(11)
–
(3)

56
58
114

–
–
–

–
–
–
–
–
–
–

–
–
–

2,937
2,555
5,492

264
321
–
242
(455)
(199)
173

2,981
2,684
5,665

2,996
1,585
4,581

224
62
199
39
(416)
(1)
107

3,125
1,563
4,688

695
577
1,272

694
687
1,381

44
73
117

56
58
114

5,933
4,140
10,073

6,106
4,247
10,353

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2008
Developed
Undeveloped

414
123
537

At 31 December 2008

Developed
Undeveloped

410
119
529

105
169
274

81
194
275

1,882
1,265
3,147

1,717
1,273
2,990

185

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Movements in estimated net proved reserves continued

Natural gasa

Subsidiaries
At 1 January 2008
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2008c

Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January 2008
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2008d

Developed
Undeveloped

2,049
553
2,602

23
77
–
–
(298)
–
(198)

1,822
582
2,404

–
–
–

–
–
–
–
–
–
–

–
–
–

Europe

North
America

South
America

Rest of
Europe

Rest of
North
America

Africa

Asia

Australasia

2008

Total

billion cubic feet

Russia

Rest of
Asia

63
410
473

(8)
9
–
–
(11)
–
(10)

61
402
463

10,670
4,705
15,375

(2,063)
1,322
183
549
(834)
–
(843)

9,059
5,473
14,532

608
421
1,029

3,075
7,973
11,048

990
1,410
2,400

51
16
–
125
(94)
–
98

(456)
159
–
948
(946)
(3)
(298)

142
6
–
82
(198)
–
32

659
468
1,127

3,316
7,434
10,750

1,050
1,382
2,432

–
–
–

–
–
–
–
–
–
–

–
–
–

1,270
1,269
2,539

1,135
4,529
5,664

19,860
21,270
41,130

–
108
–
37
(274)
–
(129)

361
2
–
–
(140)
–
223

(1,950)
1,699
183
1,741
(2,795)
(3)
(1,125)

1,102
1,308
2,410

1,887
4,000
5,887

18,956
21,049
40,005

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

1,478
831
2,309

(96)
301
3
192
(188)
–
212

1,498
1,023
2,521

–
–
–

182
–
–
–
–
–
182

–
182
182

808
353
1,161

1,273
–
–
–
(221)
–
1,052

1,560
653
2,213

808
353
1,161

1,560
653
2,213

187
113
300

(2)
11
–
–
(22)
–
(13)

176
111
287

–
–
–

–
–
–
–
–
–
–

–
–
–

2,473
1,297
3,770

1,357
312
3
192
(431)
–
1,433

3,234
1,969
5,203

1,457
1,382
2,839

1,278
1,419
2,697

1,135
4,529
5,664

1,887
4,000
5,887

22,333
22,567
44,900

22,190
23,018
45,208

Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2008
Developed
Undeveloped

2,049
553
2,602

At 31 December 2008

Developed
Undeveloped

1,822
582
2,404

63
410
473

61
402
463

10,670
4,705
15,375

9,059
5,473
14,532

608
421
1,029

659
468
1,127

4,553
8,804
13,357

4,814
8,457
13,271

990
1,410
2,400

1,050
1,564
2,614

186

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Movements in estimated net proved reserves continued

Crude oila

Subsidiaries
At 1 January 2007
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2007c

Developed
Undeveloped

Equity-accounted entities (BP share)d g
At 1 January 2007
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place

At 31 December 2007e

Developed
Undeveloped

Europe

North
America

South
America

Rest of
Europe

USf

Rest of
North
America

Africa

Asia

Australasia

million barrels

2007

Total

Russia

Rest of
Asia

458
146
604

(1)
7
–
–
(73)
–
(67)

414
123
537

–
–
–

–
–
–
–
–
–
–

–
–
–

189
97
286

(25)
1
–
31
(19)
–
(12)

105
169
274

–
–
–

–
–
–
–
–
–
–

–
–
–

1,916
1,292
3,208

18
99
25
60
(169)
(94)
(61)

1,882
1,265
3,147

–
–
–

–
–
–
–
–
–
–

–
–
–

15
2
17

–
–
–
–
(3)
–
(3)

13
1
14

–
–
–

–
–
–
–
–
–
–

–
–
–

15
2
17

13
1
14

115
235
350

(29)
6
–
1
(24)
–
(46)

102
202
304

221
139
360

178
59
–
2
(28)
–
211

328
243
571

336
374
710

430
445
875

193
512
705

(133)
12
–
93
(71)
–
(99)

256
350
606

–
–
–

–
–
–
–
–
–
–

–
–
–

193
512
705

256
350
606

–
–
–

–
–
–
–
–
–
–

–
–
–

2,200
644
2,844

413
–
16
283
(304)
(21)
387

2,094
1,137
3,231

2,200
644
2,844

2,094
1,137
3,231

104
487
591

(29)
6
8
–
(83)
–
(98)

121
372
493

521
163
684

167
1
–
–
(73)
–
95

574
205
779

51
81
132

(5)
–
–
2
(12)
–
(15)

44
73
117

–
–
–

–
–
–
–
–
–
–

–
–
–

3,041
2,852
5,893

(204)
131
33
187
(454)
(94)
(401)

2,937
2,555
5,492

2,942
946
3,888

758
60
16
285
(405)
(21)
693

2,996
1,585
4,581

625
650
1,275

695
577
1,272

51
81
132

44
73
117

5,983
3,798
9,781

5,933
4,140
10,073

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2007
Developed
Undeveloped

458
146
604

At 31 December 2007

Developed
Undeveloped

414
123
537

189
97
286

105
169
274

1,916
1,292
3,208

1,882
1,265
3,147

a Crude oil includes NGLs and condensate. 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.
b Excludes NGLs from processing plants in which an interest is held of 54 thousand barrels a day.
c Includes 739 million barrels of NGLs. Also includes 20 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d The BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. During the second quarter of 2007, we updated our
reporting policy in Abu Dhabi to be consistent with general industry practice and as a result have started reporting production and reserves there gross of production taxes. This change resulted in an
increase in our reserves of 153 million barrels and in our production of 33mb/d.
e Includes 26 million barrels of NGLs. Also includes 210 million barrels of crude oil in respect of the 6.51% minority interest in TNK-BP.
f Proved reserves in the Prudhoe Bay field in Alaska include an estimated 98 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe
Bay Royalty Trust.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.

187

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Movements in estimated net proved reserves continued

Natural gasa

Subsidiaries
At 1 January 2007
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2007c

Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January 2007
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place

At 31 December 2007d

Developed
Undeveloped

Europe

North
America

South
America

Rest of
Europe

Rest of
North
America

Africa

Asia

Australasia

2007

Total

billion cubic feet

Russia

Rest of
Asia

1,968
825
2,793

93
15
–
–
(299)
–
(191)

2,049
553
2,602

–
–
–

–
–
–
–
–
–
–

–
–
–

242
56
298

(37)
1
–
293
(14)
(68)
175

63
410
473

–
–
–

–
–
–
–
–
–
–

–
–
–

10,438
4,660
15,098

744
326
23
95
(879)
(32)
277

627
310
937

(72)
32
–
237
(98)
(7)
92

3,305
8,884
12,189

(204)
–
–
12
(949)
–
(1,141)

1,032
1,675
2,707

(146)
9
–
17
(187)
–
(307)

10,670
4,705
15,375

608
421
1,029

3,075
7,973
11,048

990
1,410
2,400

–
–
–

–
–
–
–
–
–
–

–
–
–

808
1,781
2,589

882
4,675
5,557

19,302
22,866
42,168

(21)
100
109
–
(238)
–
(50)

140
16
–
88
(137)
–
107

497
499
132
742
(2,801)
(107)
(1,038)

1,270
1,269
2,539

1,135
4,529
5,664

19,860
21,270
41,130

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

1,460
735
2,195

73
195
–
22
(176)
–
114

1,478
831
2,309

–
–
–

–
–
–
–
–
–
–

–
–
–

1,087
184
1,271

61
–
8
–
(179)
–
(110)

808
353
1,161

1,087
184
1,271

808
353
1,161

222
75
297

9
16
–
–
(22)
–
3

187
113
300

–
–
–

–
–
–
–
–
–
–

–
–
–

2,769
994
3,763

143
211
8
22
(377)
–
7

2,473
1,297
3,770

1,030
1,856
2,886

1,457
1,382
2,839

882
4,675
5,557

1,135
4,529
5,664

22,071
23,860
45,931

22,333
22,567
44,900

Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2007
Developed
Undeveloped

1,968
825
2,793

At 31 December 2007

Developed
Undeveloped

2,049
553
2,602

242
56
298

63
410
473

10,438
4,660
15,098

10,670
4,705
15,375

627
310
937

608
421
1,029

4,765
9,619
14,384

4,553
8,804
13,357

1,032
1,675
2,707

990
1,410
2,400

188

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves

The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural gas
production from the group’s estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures requirements.

Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing of

future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange rates
from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical
information becomes available and economic conditions change. BP cautions against relying on the information presented because of the highly arbitrary
nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2009

Total

At 31 December 2009
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted

50,800
20,000
5,000
12,900
12,900
5,800

17,700 204,000
91,300
24,900
27,300
60,500
29,500

8,000
2,500
3,700
3,500
1,600

4,900
2,700
1,000
200
1,000
500

26,400
6,700
5,600
5,800
8,300
3,200

58,400
12,000
12,200
11,300
22,900
9,800

future net cash flowse

7,100

1,900

31,000

500

5,100

13,100

–
–
–
–
–
–

–

36,100
9,200
6,400
4,700
15,800
6,300

3,100
4,500

32,500 430,800
11,000 160,900
60,700
70,400
13,900 138,800
64,000

7,300

9,500

6,600

74,800

Equity-accounted entities (BP share)f
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted

future net cash flowsg h

Total subsidiaries and equity-accounted entities
Standardized measure of discounted

–
–
–
–
–
–

–

–
–
–
–
–
–

–

–
–
–
–
–
–

–

–
–
–
–
–
–

–

37,700
17,000
4,000
5,200
11,500
6,800

4,700

–
–
–
–
–
–

–

96,700
65,200
10,200
4,300
17,000
7,900

30,000
25,200
3,100
100
1,600
800

9,100

800

–
–
–
–
–
–

–

164,400
107,400
17,300
9,600
30,100
15,500

14,600

future net cash flows

7,100

1,900

31,000

500

9,800

13,100

9,100

10,300

6,600

89,400

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Sales and transfers of oil and gas produced, net of production costs
Previously estimated development costs incurred during the year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeari

Subsidiaries
(18,900)
11,700
8,500
37,200
(4,300)
(10,600)
(600)
(100)
4,700
27,600

Equity-accounted
entities (BP share)
(3,400)
2,100
1,600
5,900
(200)
(1,600)
900
(900)
900
5,300

$ million

Total subsidiaries and

equity-accounted entities

(22,300)
13,800
10,100
43,100
(4,500)
(12,200)
300
(1,000)
5,600
32,900

aThe marker prices used were Brent $59.91/bbl, Henry Hub $3.82/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
cTaxation is computed using appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e Minority interest in BP Trinidad and Tobago LLC amounted to $1,300 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
gMinority interest in TNK-BP amounted to $600 million.
hNo equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements.

189

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves continued

Europe

North
America

South
America

Africa

Asia

Australasia

$ million

Total

At 31 December 2008
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted

Rest of
Europe

36,400
18,100
3,300
7,300
7,700
2,200

13,800 165,800
80,400
25,600
17,500
42,300
21,000

6,300
2,900
2,300
2,300
1,200

Rest of
North
America

6,400
2,700
1,300
500
1,900
1,000

26,300
7,200
7,200
5,500
6,400
2,900

40,400
11,600
10,900
6,600
11,300
5,500

future net cash flowse

5,500

1,100

21,300

900

3,500

5,800

Equity-accounted entities (BP share)g
Standardized measure of discounted

Russia

Rest of
Asia

–
–
–
–
–
–

–

31,400
11,800
7,500
2,400
9,700
4,200

24,200 344,700
10,700 148,800
61,900
44,900
89,100
41,900

3,200
2,800
7,500
3,900

5,500

3,600

47,200

future net cash flowsh

–

3,600

–

4,800

900

–

9,300

Total subsidiaries and equity-accounted entities
Standardized measure of discounted

future net cash flowse

5,500

1,100

21,300

900

7,100

5,800

4,800

6,400

3,600

56,500

At 31 December 2007
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted

72,100
27,500
4,000
20,200
20,400
6,500

29,500 350,100
7,500 109,800
21,900
3,300
71,600
13,000
5,700 146,800
76,000
2,800

7,500
3,000
700
900
2,900
1,300

60,200
14,900
5,800
20,800
18,700
8,200

63,300
9,900
8,300
17,100
28,000
9,400

future net cash flowse

13,900

2,900

70,800

1,600

10,500

18,600

Equity-accounted entities (BP share)g
Standardized measure of discounted

–
–
–
–
–
–

–

55,100
9,700
3,900
9,800
31,700
12,600

41,900 679,700
11,600 193,900
3,700
51,600
8,600 162,000
18,000 272,200
9,200 126,000

19,100

8,800 146,200

future net cash flowsh

–

5,000

–

21,700

3,000

–

29,700

Total subsidiaries and equity-accounted entities
Standardized measure of discounted

future net cash flowse

13,900

2,900

70,800

1,600

15,500

18,600

21,700

22,100

8,800 175,900

The following are the principal sources of change in the standardized measure of discounted future net cash flows for subsidiaries:

2008

$ million

2007

(43,600)
9,400
4,400

(28,300)
9,400
12,300
(146,800) 102,100
(12,200)
(28,300)
(7,800)
(700)
9,100
55,600

1,200
69,400
(7,400)
(200)
14,600
(99,000)

a The year-end marker prices used were 2008 Brent $36.55/bbl, Henry Hub $5.63/mmBtu and 2007 Brent $96.02/bbl, Henry Hub $7.10/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on year-end cost levels and assume continuation of existing
economic conditions. Future decommissioning costs are included.
c Taxation is computed using appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e Minority interest in BP Trinidad and Tobago LLC amounted to $900 million at 31 December 2008 and $2,300 million at 31 December 2007.
f Total change in the standardized measure during the year includes the effect of exchange rate movements.
g The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-acccounted investments of
those entities.
h Minority interest in TNK-BP amounted to $300 million at 31 December 2008 and $1,400 million at 31 December 2007.

190

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Operational and statistical information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage.

Crude oil and natural gas production
The following table shows crude oil and natural gas production for the years ended 31 December 2009, 2008 and 2007.

Production for the yeara

Subsidiaries
Crude oilb
2009
2008
2007
Natural gasc
2009
2008
2007
Equity-accounted entities (BP share)
Crude oilb
2009
2008
2007
Natural gasc
2009
2008
2007

Europe

North
America

South
America

Africa

Asia

Australasia

Total

Rest of
Europe

168
173
201

618
759
768

–
–
–

40
43
51

16
23
29

–
–
–

Rest of
North
America

8
9
8

263
245
255

–
–
–

665
538
513

2,316
2,157
2,174

–
–
–

Russia

Rest of
Asia

–
–
–

840
826
832

601
564
451

123
128
228

610
696
609

194
220
201

42
39
41

61
66
74

2,492
2,532
2,543

101
92
77

392
454
429

304
277
195

621
484
468

–
–
–

31
29
34

thousand barrels per day
1,400
1,263
1,304
million cubic feet per day
7,450
7,277
7,222

514
381
376

–
–
–

thousand barrels per day
1,135
1,138
1,110
million cubic feet per day
1,035
1,057
921

–
–
–

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.
bCrude oil includes natural gas liquids and condensate.
cNatural gas production excludes gas consumed in operations.

Productive oil and gas wells and acreage
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped oil and
natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2009. A ‘gross’ well or acre is one in which a
whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or fractional working interests in gross
wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is the acreage within the boundary of a field,
on which development wells have been drilled, which could produce the reserves; while undeveloped acres are those on which wells have not been
drilled or completed to a point that would permit the production of commercial quantities, whether or not such acres contain proved reserves. These
tables do not include any information relating to our recent entry into Iraq.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Europe

North
America

South
America

Africa

Asia

Australasia

Total

UK
Number of productive wells at 31 December 2009
Oil wellsa

Gas wellsb

– gross
– net
– gross
– net

Rest of
Europe

83
26
–
–

5,793
2,090
21,974
12,359

Rest of
North
America

197
76
1,852
1,236

Russia

3,650
2,045
487
171

668
529
104
47

20,593
8,750
46
23

Rest of
Asia

1,657
303
563
258

13
2
68
15

32,936
13,972
25,373
14,242

282
151
279
133

a Includes approximately 3,982 gross (1,750 net) multiple completion wells (more than one formation producing into the same well bore).
b Includes approximately 2,834 gross (1,841 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.

Europe

North
America

South
America

Africa

Asia

Australasia

Total

Oil and natural gas acreage at 31 December 2009
Developed

– gross
– net

Undevelopeda – gross

– net

aUndeveloped acreage includes leases and concessions.

Rest of
Europe

366
201
1,602
919

65
19
486
226

Rest of
North
America

1,186
850
6,967
5,009

7,587
4,609
7,985
4,979

Russia

Rest of
Asia

1,740
470

539
222
7,361 105,512
33,341
3,471

4,123
1,794
10,357
4,683

2,191
842
15,191
6,597

Thousands of acres
17,997
200
9,046
39
4,109 159,570
60,136

911

191

BP Annual Report and Accounts 2009
Supplementary information on oil and natural gas (unaudited)

Net oil and gas wells completed or abandoned
The following table shows the number of net productive and dry exploratory and development oil and natural gas wells completed or abandoned in the
years indicated by the group and its equity-accounted entities. Productive wells include wells in which hydrocarbons were encountered and the drilling
or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be
incapable of producing hydrocarbons in sufficient quantities to justify completion.

Europe

North
America

South
America

Africa

Asia

Australasia

Total

2009
Exploratory
Productive
Dry
Development
Productive
Dry
2008
Exploratory
Productive
Dry

Development
Productive
Dry
2007
Exploratory
Productive
Dry

Development
Productive
Dry

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

–
–

1.5
–

–
0.5

0.5
–

–
–

0.8
–

47.2
4.2

403.8
3.3

2.4
0.9

379.8
1.1

4.1
0.7

401.2
4.2

–
–

17.9
–

–
0.1

28.3
0.9

0.5
0.5

36.0
8.8

3.0
–

135.4
–

4.4
0.4

112.5
2.9

–
–

10.0
–

4.5
1.4

20.8
0.5

4.3
2.6

18.6
1.5

6.1
1.6

15.3
–

7.0
4.5

293.0
4.0

12.5
23.0

10.0
19.5

16.0
9.0

246.0
9.5

5.3
6.0

45.8
0.4

0.5
0.5

45.4
2.1

1.7
1.4

27.5
–

0.6
0.2

1.6
0.6

0.6
0.4

4.5
–

1.1
–

2.1
–

67.7
16.5

929.1
8.8

25.5
28.4

606.2
28.2

31.1
13.2

739.3
23.1

0.1
0.2

9.3
–

0.8
–

6.6
0.2

1.6
–

0.4
0.6

Drilling and production activities in progress
The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its equity-
accounted entities as at 31 December 2009. Suspended development wells and long-term suspended exploratory wells are also included in the table.

Europe

North
America

South
America

Africa

Asia

Australasia

Total

At 31 December 2009
Exploratory
Gross
Net
Development
Gross
Net

–
–

4.0
2.7

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

–
–

1.0
0.3

112.0
30.2

366.0
176.9

4.0
1.8

30.0
19.8

–
–

15.0
9.2

5.0
2.6

23.0
7.5

8.0
4.0

45.0
20.0

3.0
2.0

16.0
3.4

–
–

132.0
40.6

500.0
239.8

192

BP Annual Report and Accounts 2009

Parent company financial statements of BP p.l.c.

Statement of directors’ responsibilities in respect of the parent company
financial statements

The directors are responsible for preparing the financial statements in accordance with applicable United Kingdom law and United Kingdom generally
accepted accounting practice.

Company law requires the directors to prepare financial statements for each financial year that give a true and fair view of the state of affairs of

the company. In preparing these financial statements, the directors are required:
(cid:129) To select suitable accounting policies and then apply them consistently.
(cid:129) To make judgements and estimates that are reasonable and prudent.
(cid:129) To state whether applicable accounting standards have been followed, subject to any material departures disclosed and explained in the

financial statements.

(cid:129) To prepare the financial statements on the going concern basis unless it is inappropriate to presume that the company will continue in business.
The directors are also responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the financial position of the
company and enable them to ensure that the financial statements comply with the Companies Act 2006. They are also responsible for safeguarding
the assets of the company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.

Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 418(3) of the

Companies Act 2006) of which the company’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 company’s auditors are aware of that information.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

193

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

Independent auditor’s report to the members of BP p.l.c.

We have audited the parent company financial statements of BP p.l.c. for the year ended 31 December 2009 which comprise the company balance
sheet, the company cash flow statement, the company statement of total recognized gains and losses and the related notes 1 to 13. The financial
reporting framework that has been applied in their preparation is applicable law and United Kingdom accounting standards (United Kingdom generally
accepted accounting practice).

Respective responsibilities of directors and auditors
As explained more fully in the Statement of directors’ responsibilities in respect of the parent company financial statements set out on page 193, the
directors are responsible for the preparation of the parent company financial statements and for being satisfied that they give a true and fair view. Our
responsibility is to audit the parent company financial statements in accordance with applicable law and International Standards on Auditing (UK and
Ireland). Those standards require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.

Scope of the audit of the financial statements
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the
financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting
policies are appropriate to the parent company’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of
significant accounting estimates made by the directors; and the overall presentation of the financial statements.

Opinion on financial statements
In our opinion the parent company financial statements:
(cid:129) give a true and fair view of the state of the company’s affairs as at 31 December 2009;
(cid:129) have been properly prepared in accordance with United Kingdom generally accepted accounting practice; and
(cid:129) have been prepared in accordance with the requirements of the Companies Act 2006.

Opinion on other matters prescribed by the Companies Act 2006
In our opinion:
(cid:129)
(cid:129)

the part of the Directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006; and
the information given in the Directors’ Report for the financial year for which the parent company financial statements are prepared is consistent
with the parent company financial statements.

Matters on which we are required to report by exception
We have nothing to report in respect of the following matters where the Companies Act 2006 requires us to report to you if, in our opinion:
(cid:129)

adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not been received from branches
not visited by us; or
the parent company financial statements and the part of the Directors’ remuneration report to be audited are not in agreement with the accounting
records and returns; or
(cid:129)
certain disclosures of directors’ remuneration specified by law are not made; or
(cid:129) we have not received all the information and explanations we require for our audit.

(cid:129)

Other matter
We have reported separately on the consolidated financial statements of BP p.l.c. for the year ended 31 December 2009.

Ernst & Young LLP
Allister Wilson (Senior statutory auditor)
for and on behalf of Ernst & Young LLP, Statutory auditor
London
26 February 2010

Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

194

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

Company balance sheet

At 31 December

Fixed assets

Investments

Subsidiary undertakings
Associated undertakings

Total fixed assets
Current assets

Debtors – amounts falling due:

Within one year
After more than one year

Deferred taxation
Cash at bank and in hand

Creditors – amounts falling due within one year
Net current assets
Total assets less current liabilities
Creditors – amounts falling due after more than one year
Net assets excluding pension plan surplus and deficit
Defined benefit pension plan surplus
Defined benefit pension plan deficit
Net assets

Represented by
Capital and reserves

Called-up share capital
Share premium account
Capital redemption reserve
Merger reserve
Own shares
Treasury shares
Share-based payment reserve
Profit and loss account

Note

2009

$ million

2008

3
3

4
4
2

6
6

7
8
8
8
8
8
8
8

93,063
2
93,065

88,971
2
88,973

30,709
1,178
130
28
32,045
2,401
29,644
122,709
4,328
118,381
912
(120)
119,173

5,179
9,847
1,072
26,509
(214)
(21,303)
1,519
96,564
119,173

6,129
1,174
77
11
7,391
2,609
4,782
93,755
80
93,675
1,185
(68)
94,792

5,176
9,763
1,072
26,509
(326)
(21,513)
1,271
72,840
94,792

The financial statements on pages 195-208 were approved and signed by the chairman and group chief executive on 26 February 2010 having been
duly authorized to do so by the board of directors.

C-H Svanberg Chairman
Dr A B Hayward Group Chief Executive

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

195

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

Company cash flow statement

For the year ended 31 December

Net cash (outflow) inflow from operating activities
Servicing of finance and returns on investments

Interest received
Interest paid
Dividends received

Net cash inflow from servicing of finance and returns on investments
Tax paid
Capital expenditure and financial investment
Payments for fixed assets – investments
Proceeds from sale of fixed assets – investments

Net cash (outflow) inflow for capital expenditure and financial investment
Equity dividends paid
Net cash (outflow) inflow before financing
Financing

Other share-based payment movements
Repurchase of ordinary share capital
Net cash inflow (outflow) from financing
Increase (decrease) in cash

Company statement of total recognized gains and losses

For the year ended 31 December

Profit for the year
Currency translation differences
Actuarial (loss) gain relating to pensions
Tax on actuarial loss (gain) relating to pensions
Total recognized gains and losses relating to the year

Note
9

2009
(20,773)

2008
(4,399)

137
(26)
35,187
35,298
(11)

(4,236)
9
(4,227)
(10,483)
(196)

213
–
213
17

167
(167)
17,066
17,066
(2)

–
–
–
(10,342)
2,323

358
(2,914)
(2,556)
(233)

2009
34,524
104
(585)
164
34,207

2008
17,715
(710)
(5,122)
1,434
13,317

6
2

$ million

2007
(833)

202
(381)
16,416
16,237
(1)

(7)
8
1
(8,106)
7,298

464
(7,497)
(7,033)
265

$ million

2007
16,013
89
698
(195)
16,605

196

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

Notes on financial statements

1. Accounting policies

Accounting standards
These financial statements are prepared in accordance with applicable UK accounting standards.

Accounting convention
The financial statements are prepared under the historical cost convention.

Foreign currency transactions
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. 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 profit for the year. Exchange
adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency branches are translated into
US dollars are taken to a separate component of equity and reported in the statement of total recognized gains and losses.

Investments
Investments in subsidiaries and associated undertakings are recorded at cost. The company assesses investments for impairment whenever events or
changes in circumstances indicate that the carrying value of an investment may not be recoverable. If any such indication of impairment exists, the
company makes an estimate of its recoverable amount. Where the carrying amount of an investment exceeds its recoverable amount, the investment
is considered impaired and is written down to its recoverable amount.

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). Non-vesting conditions, such as the condition that employees
contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition is treated as a
cancellation, where this is within the control of the employee.

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.

When 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.

When 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.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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
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.

The interest element of the defined benefit cost represents the 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 plan 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 within the statement of total recognized gains and losses in the period in which they occur.

197

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

1. Accounting policies continued
The defined benefit pension plan surplus or deficit in the balance 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. The surplus or deficit, net of
taxation thereon, is presented separately above the total for net assets on the face of the balance sheet.

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

Deferred tax assets are recognized only to the extent that it is considered more likely than not that there will be suitable taxable profits from

which the underlying timing differences can be deducted.

Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which timing differences

reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date.

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

2. Taxation

Tax included in the statement of total recognized gains and losses
Deferred tax

Origination and reversal of timing differences in the current year

This comprises:
Actuarial (loss) gain relating to pensions

Deferred tax

Deferred tax liability

Pensions
Deferred tax asset

Other taxable timing differences

Net deferred tax liability
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 total recognized gains and losses

At 31 December

2009

2008

(164)

(1,434)

(164)

(1,434)

279

130
149

322
47
(56)
(164)
149

399

77
322

1,885
(276)
147
(1,434)
322

$ million

2007

195

2,008

123
1,885

1,506
1
183
195
1,885

198

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

3. Fixed assets – investments

Cost

At 1 January 2009
Adjustment
Additions

At 31 December 2009
Amounts provided

At 1 January 2009
At 31 December 2009
Cost

At 1 January 2008
Additions

At 31 December 2008
Amounts provided

At 1 January 2008
At 31 December 2008
Net book amount

At 31 December 2009
At 31 December 2008

Subsidiary
undertakings
Shares

Associated
undertakings

Loans

Total

$ million

89,045
(116)
4,208
93,137

74
74

89,036
9
89,045

74
74

93,063
88,971

2
–
–
2

–
–

2
–
2

–
–

2
2

2
–
–
2

2
2

2
–
2

2
2

–
–

89,049
(116)
4,208
93,141

76
76

89,040
9
89,049

76
76

93,065
88,973

The more important subsidiary undertakings of the company at 31 December 2009 and the percentage holding of ordinary share capital (to the
nearest whole number) are set out below. The principal country of operation is generally indicated by the company’s country of incorporation or by its
name. A complete list of investments in subsidiary undertakings, joint ventures and associated undertakings will be attached to the company’s annual
return made to the Registrar of Companies.

Subsidiary undertakings
International

BP Global Investments
BP International
BP Holdings North America
BP Shipping
BP Corporate Holdings
Burmah Castrol

100
100
100
100
100
100

Country of
incorporation

England
England
England
England
England
Scotland

Principal activities

Investment holding
Integrated oil operations
Investment holding
Shipping
Investment holding
Lubricants

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

The carrying value of BP International Ltd in the accounts of the company at 31 December 2009 was $30.25 billion (2008 $30.25 billion and 2007
$30.25 billion).

4. Debtors

Group undertakings
Other

The carrying amounts of debtors approximate their fair value.

Within
1 year
30,704
5
30,709

2009

After
1 year
1,150
28
1,178

Within
1 year
6,126
3
6,129

$ million

2008

After
1 year
1,146
28
1,174

199

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

5. Creditors

Group undertakings
Accruals and deferred income
Dividends
Other

Within
1 year
2,343
27
1
30
2,401

2009

After
1 year
4,236
74
–
18
4,328

$ million

2008

After
1 year
–
47
–
33
80

Within
1 year
2,581
7
1
20
2,609

The carrying amounts of creditors approximate their fair value.

The maturity profile of the financial liabilities included in the balance sheet at 31 December is shown in the table below. These amounts are

included within Creditors – amounts falling due after more than one year, and are denominated in US dollars.

Amounts falling due after one year include $4,236 million payable to a group undertaking. This amount is subject to interest payable quarterly at

LIBOR plus 55 basis points.

Due within

1 to 2 years
2 to 5 years
More than 5 years

2009

33
51
4,244
4,328

$ million

2008

21
35
24
80

6. Pensions
The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as
an annuity. During 2009, BP announced that, with effect from 1 April 2010, it will close its UK plan to new joiners other than some of those joining the
North Sea SPU. The plan will remain open to those employees who joined BP on or before 31 March 2010.

The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most
recent actuarial review was 31 December 2009. The principal plans are subject to a formal actuarial valuation every three years in the UK. The most
recent formal actuarial valuation of the main UK pension plan was as at 31 December 2008.

The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions used to evaluate

accrued pension at 31 December in any year are used to determine pension expense for the following year, that is, the assumptions at 31 December
2009 are used to determine the pension liabilities at that date and the pension cost for 2010.

Financial assumptions

Expected long-term rate of return
Discount rate for plan liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inflation

2009
7.4
5.8
5.3
3.4
3.4
3.4

2008
7.5
6.3
4.9
3.0
3.0
3.0

2007
7.4
5.7
5.1
3.2
3.2
3.2

Our discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the expected benefit
payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long-term government bonds.
The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions.

Our assumption for the rate of increase in salaries is based on our inflation assumption plus an allowance for expected long-term real salary

growth. This includes allowance for promotion-related salary growth of 0.4%. In addition to the financial assumptions, we regularly review the
demographic and mortality assumptions. The mortality assumptions reflect best practice in the UK, 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.

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

200

2009
26.0
29.0
28.6
31.5

2008
25.9
28.9
28.5
31.4

Years

2007
24.0
25.1
26.9
27.9

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

6. Pensions continued
The market values of the various categories of asset held by the pension plan at 31 December are set out below.

The market value of pension assets at the end of 2009 is higher when compared with 2008 due to an increase in the market value of investments

when expressed in their local currencies and a further increase in value that arises from changes in exchange rates (increasing the reported value of
investments on consolidation when expressed in US dollars). Movements in the value of plan assets during the year are shown in detail below.

Equities
Bonds
Property
Cash

Present value of plan liabilities
Surplus in the plan

Expected
long-term
rate of
return %
8.0
5.4
6.5
1.1
7.4

2009

Market
value
$ million
16,148
2,989
1,221
595
20,953
19,882
1,071

Expected
long-term
rate of
return %
8.0
6.3
6.5
2.9
7.5

2008

Market
value
$ million
13,106
2,610
932
282
16,930
15,414
1,516

Expected
long-term
rate of
return %
8.0
4.4
6.5
5.6
7.4

Analysis of the amount charged to operating profit
Current service costa
Past service cost
Settlement, curtailment and special termination benefitsc
Total operating chargeb
Analysis of the amount credited (charged) to other finance income
Expected return on pension plan assets
Interest on pension plan liabilities
Other finance income
Analysis of the amount recognized in the statement of total recognized gains and losses
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 total recognized gains and losses

2009

2008

300
–
34
334

1,339
(1,029)
310

1,634
(2,073)
(146)
(585)

434
7
29
470

1,969
(1,146)
823

(6,533)
1,476
(65)
(5,122)

$ million

2007

Market
value
$ million
22,869
4,456
1,173
913
29,411
22,146
7,265

$ million

2007

473
5
35
513

1,927
(1,108)
819

404
751
(457)
698

2009

2008

Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustment
Current service costa
Past service cost
Interest cost
Settlement
Special termination benefits
Contributions by plan participants
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Actuarial loss (gain) on obligation
Benefit obligation at 31 December
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustment
Expected return on plan assetsa e
Contributions by plan participants
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Actuarial gain (loss) on plan assetse
Fair value of plan assets at 31 Decemberf
Surplus at 31 December

15,414
1,756
300
–
1,029
–
34
36
(902)
(4)
2,219
19,882

16,930
1,907
1,339
36
9
(902)
1,634
20,953
1,071

a The 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 included in current service cost.
b Included within production and manufacturing expenses and distribution and administration expenses.
c The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
d The benefit payments amount shown above comprises $890 million benefits plus $16 million of plan expenses incurred in the administration of the benefit.
e The 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.
f Reflects $20,895 million of assets held in the BP Pension Fund (2008 $16,887 million) and $58 million held in the BP Global Pension Trust (2008 $43 million).

22,146
(5,929)
434
7
1,147
(3)
32
41
(1,048)
(2)
(1,411)
15,414

29,411
(6,916)
1,969
41
6
(1,048)
(6,533)
16,930
1,516

201

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

6. Pensions continued

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

Fundeda
Unfunded

a Reflects $19,661 million of liabilities of the BP Pension Fund (2008 $15,280 million) and $61 million of liabilities of the BP Global Pension Trust (2008 $42 million).

Reconciliation of plan surplus to balance sheet
Surplus at 31 December
Deferred tax

Represented by

Asset recognized on balance sheet
Liability recognized on balance sheet

2009

1,234
(163)
1,071

1,231
(160)
1,071

$ million

2008

1,608
(92)
1,516

(19,722)
(160)
(19,882)

(15,322)
(92)
(15,414)

2009

1,071
(279)
792

912
(120)
792

$ million

2008

1,516
(399)
1,117

1,185
(68)
1,117

The aggregate level of employer contributions into the BP Pension Fund in 2010 is expected to be $419 million.

History of surplus and of experience gains and losses
Benefit obligation at 31 December
Fair value of plan assets at 31 December
Surplus
Experience gains and losses on plan liabilities

Amount ($ million)
Percentage of benefit obligation

Actual return less expected return on pension plan assets

Amount ($ million)
Percentage of plan assets

Actuarial (loss) gain recognized in statement of total recognized gains and losses

Amount ($ million)
Percentage of benefit obligation

2009

2008

2007

2006

19,882
20,953
1,071

15,414
16,930
1,516

22,146
29,411
7,265

21,507
27,169
5,662

$ million

2005

18,316
21,542
3,226

(146)

(1)%

(65)

(155)

(1)%

(211)

(1)%

(66)

1,634

(6,533)

(39)%

(585)

(5,122)

(3)%

(33)%

404

698

1,252

2,946

14%

1,120

1,159

Cumulative amount recognized in statement of total recognized gains and losses

(1,692)

(1,107)

4,015

3,317

2,197

202

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

7. Called-up share capital

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

Issued
8% cumulative first preference shares of £1 each
9% cumulative second preference shares of £1 each

Ordinary shares of 25 cents each

At 1 January
Issue of new shares for employee share schemes
Repurchase of ordinary share capital

At 31 December

Authorized
8% cumulative first preference shares of £1 each
9% cumulative second preference shares of £1 each
Ordinary shares of 25 cents each

Shares
(thousand)
7,233
5,473

20,618,458
11,207
–
20,629,665

2009

$ million
12
9
21

Shares
(thousand)
7,233
5,473

3
–

5,155 20,863,424
24,791
(269,757)
5,158 20,618,458
5,179

7,250
5,500
36,000,000

12
9

7,250
5,500
9,000 36,000,000

2008

$ million
12
9
21

5,216
6
(67)
5,155
5,176

12
9
9,000

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

Repurchase of ordinary share capital
The company did not purchase any ordinary shares in 2009 (2008 269,757,188 ordinary shares were purchased for total consideration of $2,914 million
and 2007 663,149,528 ordinary shares were purchased for total consideration of $7,497 million of which all were for cancellation). At 31 December 2009,
1,869,777,323 shares of nominal value $467 million were held in treasury (2008 1,888,151,157 shares of nominal value $472 million and 2007
1,940,638,808 shares of nominal value $485 million). There were no transaction costs for share purchases in 2009 (2008 $16 million and 2007 $40 million).

8. Capital and reserves

At 1 January 2009
Currency translation
differences

Actuarial loss on pensions

(net of tax)

Share-based payments
Profit for the year
Dividends
At 31 December 2009

Share
capital
5,176

Capital
premium redemption
reserve
1,072

account
9,763

Merger
reserve
26,509

Own
shares
(326)

Treasury
shares
(21,513)

Share-based
payment
reserve
1,271

Profit
and loss
account
72,840

$ million

Total
94,792

–

104

–
3
–
–
5,179

–
84
–
–
9,847

–
–
–
–
1,072

–
–
–
–
26,509

–
112
–
–
(214)

–
210
–
–
(21,303)

–
248
–
–
1,519

(421)
–
34,524
(10,483)
96,564

(421)
657
34,524
(10,483)
119,173

203

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

8. Capital and reserves continued

At 1 January 2008
Currency translation
differences

Actuarial loss on pensions

(net of tax)

Repurchase of ordinary

share capital

Share-based payments
Profit for the year
Dividends
At 31 December 2008

Share
premium
account
9,581

Capital
redemption
reserve
1,005

Merger
reserve
26,509

Own
shares
(60)

Treasury
shares
(22,112)

Share-based
payment
reserve
982

Profit
and loss
account
72,282

$ million

Total
93,424

–

–
182
–
–
9,763

–

67
–
–
–
1,072

–

–
–
–
–
26,509

–

–
(266)
–
–
(326)

–

–
599
–
–
(21,513)

–

–
289
–
–
1,271

(710)

(3,688)

(2,414)
(3)
17,715
(10,342)
72,840

(2,414)
807
17,715
(10,342)
94,792

Share
capital
5,237

–

(67)
6
–
–
5,176

As a consolidated income statement is presented for the group, a separate income statement for the parent company is not required to be published.
The profit and loss account reserve includes $24,107 million (2008 $24,107 million and 2007 $27,428 million), the distribution of which is

limited by statutory or other restrictions.

The company does not account for dividends until they have been paid. The accounts for the year ended 31 December 2009 do not reflect the

dividend announced on 2 February 2010 and payable in March 2010; this will be treated as an appropriation of profit in the year ended 31 December 2010.

Managing Capital
The company defines capital as the total equity of the company. The company’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 company’s approach to managing capital is set out in its financial framework. The company aims 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, the company rebalanced distributions away from share buybacks in favour of dividends. During 2009, the company did not
repurchase any of its own shares.

9. Cash flow

Reconciliation of net cash flow to movement of funds
Increase (decrease) in cash
Movement of funds
Net cash at 1 January
Net cash at 31 December

Notes on cash flow statement
(a) Reconciliation of operating profit to net cash (outflow) inflow from operating activities
Operating profit
Net operating charge for pensions, less contributions
Dividends, interest and other income
Share-based payments
(Increase) decrease in debtors
Increase (decrease) in creditors
Net cash outflow from operating activities

(b) Analysis of movements of funds
Cash at bank

10. Contingent liabilities

2009

2008

(233)
(233)
244
11

2008
17,211
461
(17,239)
446
(5,271)
(7)
(4,399)

$ million

2007

265
265
(21)
244

2007
15,699
7
(16,624)
338
2,238
(2,491)
(833)

$ million

At
Cash 31 December
2009
flow
28
17

17
17
11
28

2009
34,195
321
(35,189)
444
(24,584)
4,040
(20,773)

At
1 January
2009
11

The parent company has issued guarantees under which amounts outstanding at 31 December 2009 were $30,158 million (2008 $30,063 million and
2007 $27,665 million), including $30,126 million (2008 $30,008 million and 2007 $27,610 million) in respect of borrowings by its subsidiary
undertakings and $32 million (2008 $55 million and 2007 $55 million) in respect of liabilities of other third parties.

204

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

11. Share-based payments

Effect of share-based payment transactions on the company’s result and financial position

2009

506
15
521
32
7

2008

524
(16)
508
21
2

$ million

2007

412
16
428
40
22

For ease of presentation, option and share holdings detailed in the tables within this note are stated as UK ordinary share equivalents in US dollars.
US employees are granted American Depositary Shares (ADSs) or options over the company’s ADSs (one ADS is equivalent to six ordinary shares).
The share-based payment plans that existed during the year are detailed below. All plans are ongoing unless otherwise stated.

Plans for executive directors
Executive Directors’ Incentive Plan (EDIP) – share element
An equity-settled incentive plan for executive directors with a three-year performance period. For share plan performance periods 2007-2009 and
2008-2010 the award of shares is determined by comparing BP’s total shareholder return (TSR) against the other oil majors (ExxonMobil, Shell, Total
and Chevron). For the performance period 2009-2011 the award of shares is determined 50% on TSR versus a competitor group of oil majors (which in
this period also included ConocoPhillips) and 50% on a balanced scorecard (BSC) of three underlying performance measures versus the same
competitor group. After the performance period, the shares that vest (net of tax) are then subject to a three-year retention period. The directors’
remuneration report on pages 81 to 92 includes full details of the plan.

Grants are settled in cash where participants are located in a country whose regulatory environment prohibits the holding of BP shares.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

205

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

11. Share-based payments continued
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-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 have six months in which to use their savings to exercise their options on a pro-
rated basis.

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.

Local plans
In some countries BP provides local scheme benefits, the rules and qualifications for which vary according to local circumstances.

Employee Share Ownership Plans (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards made to participants under the BP share plans as required. The ESOPs have
waived their rights to dividends on shares held for future awards and are funded by the group. Until such time as the company’s own shares held by
the ESOP trusts vest unconditionally to employees, the amount paid for those shares is deducted in arriving at shareholders’ equity (see Note 8).
Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.

At December 2009 the ESOPs held 18,062,246 shares (2008 29,051,082 shares and 2007 6,448,838 shares) for potential future awards, which

had a market value of $174 million (2008 $220 million and 2007 $79 million).

Share option transactions

Outstanding at 1 January
Granted
Forfeited
Exercised
Expired
Outstanding at 31 December
Exercisable at 31 December

2009

Weighted
average
exercise
price
$
8.70
6.55
8.81
7.53
8.01
8.73
8.80

Number
of
options
326,254,599
9,679,836
(5,954,325)
(21,293,871)
(12,790,882)
295,895,357
274,685,068

2008

Weighted
average
exercise
price
$
8.51
8.96
8.50
6.97
7.00
8.70
8.22

Number
of
options
358,094,243
8,062,899
(2,502,784)
(37,277,895)
(121,864)
326,254,599
260,178,938

2007

Weighted
average
exercise
price
$
8.25
9.11
9.10
6.94
8.68
8.51
7.70

Number
of
options
426,471,462
6,004,025
(3,924,714)
(69,715,558)
(740,972)
358,094,243
238,707,055

Options outstanding

Options exercisable

Number
of
shares
53,511,852
143,736,259
27,046,156
71,601,090
295,895,357

Weighted
average
remaining
life
years
3.31
2.48
4.10
5.81
3.58

Weighted
average
exercise
price
$
6.43
8.18
9.83
11.14
8.73

Number
of
shares
43,956,777
137,625,273
21,501,928
71,601,090
274,685,068

Weighted
average
exercise
price
$
6.40
8.16
10.01
11.14
8.80

Range of exercise prices
$6.18 – $7.61
$7.62 – $9.05
$9.06 – $10.48
$10.49 – $11.92

206

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

11. Share-based payments continued
Fair values and associated details for options and shares granted

2009

ShareSave
3 year
Binomial
$1.07
$7.87
$6.92
32%
3.5 years
7.40%
3.00%

ShareSave
5 year
Binomial
$1.07
$7.87
$6.92
32%
5.5 years
7.40%
3.75%
100% year 4 100% year 6

ShareSave
3 year
Binomial
$1.82
$11.26
$9.70
23%
3.5 years
4.60%
5.00%
100% year 4

2008

ShareSave
5 year
Binomial
$1.74
$11.26
$9.70
23%
5.5 years
4.60%
5.00%
100% year 6

ShareSave
3 year
Binomial
$3.57
$12.10
$9.13
21%
3.5 years
3.48%
5.75%
100% year 4

2007

ShareSave
5 year
Binomial
$3.79
$12.10
$9.13
21%
5.5 years
3.48%
5.75%
100% year 6

Shares granted in 2009
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

Shares granted in 2008
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

Shares granted in 2007
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

a EDIP – retention element.
b EDIP – long-term leadership element.

CPP
1.4
$9.76
Monte
Carlo

MTPP-
TSR
9.1
$5.07
Monte
Carlo

MTPP-
TSR
9.4
$4.73
Monte
Carlo

EPP
7.6
$6.56
Market
value

MTPP-
FCF
9.1
$10.34
Market
value

MTPP-
FCF
8.5
$10.02
Market
value

EDIP-
TSR
2.1
$2.74
Monte
Carlo

EDIP-
TSR
2.6
$4.55
Monte
Carlo

EDIP-
TSR
4.5
$2.81
Monte
Carlo

EDIP-
BSC
2.1
$7.27
Market
value

EDIP-
RETa
0.5
$11.13
Market
value

EDIP-
LTLb
0.5
$9.92
Market
value

RSP
2.4
$8.76
Market
value

DAB
38.9
$6.56
Market
value

PSP
16.5
$8.32
Monte
Carlo

RSP
7.7
$8.83
Market
value

RSP
7.7
$11.93
Market
value

DAB
5.8
$10.34
Market
value

DAB
4.4
$10.02
Market
value

PSP
16.7
$12.89
Monte
Carlo

PSP
14.8
$12.37
Monte
Carlo

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

The group used a Monte Carlo simulation to determine the fair value of the TSR element of the 2009, 2008 and 2007 CPP, PSP, MTPP and EDIP plans.
In accordance with the rules of the plans the model simulates BP’s TSR and compares it against our principal strategic competitors over the three-year
period of the plans. The model takes into account the historic dividends, share price volatilities and covariances of BP and each comparator company
to produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the TSR element.
Accounting expense does not necessarily represent the actual value of share-based payments made to recipients, which are determined by

the remuneration committee according to established criteria.

207

BP Annual Report and Accounts 2009
Parent company financial statements of BP p.l.c.

12. Auditor’s remuneration

Fees payable to the company’s auditors for the audit of the company’s accounts were $13 million (2008 $16 million and 2007 $18 million).

Remuneration receivable by the company’s auditors for the supply of other services to the company is not presented in the parent company

financial statements as this information is provided in the consolidated financial statements.

13. Directors’ remuneration

Remuneration of directors

Total for all directors
Emoluments
Gains made on the exercise of share options
Amounts awarded under incentive schemes

2009

2008

19
2
2

19
1
–

$ million

2007

26
2
10

Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits
earned during the relevant financial year, plus bonuses awarded for the year. Ex gratia superannuation payments of $3 million were included in 2007.
Compensation for loss of office was $1 million in 2008 and $1 million in 2007.

Pension contributions
Three executive directors participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which contributions
are made by BP based on actuarial advice. Two US executive directors participated in the US BP Retirement Accumulation Plan during 2009.

Further information
Full details of individual directors’ remuneration are given in the directors’ remuneration report on pages 81 to 92.

208

BP Annual Report and Accounts 2009

Information for shareholders

Reports and publications

You can order BP’s printed publications
free of charge, from:

US and Canada
Precision IR
Toll-free +1 888 301 2505
Fax +1 804 327 7549
bpreports@precisionir.com

UK and Rest of World
BP Distribution Services
Tel +44 (0)870 241 3269
Fax +44 (0)870 240 5753
bpdistributionservices@bp.com

BP’s reports and publications are available to view online
or download from www.bp.com/annualreport.

Annual Review
Read a summary of our ﬁ nancial
and operating performance in
BP Annual Review 2009 in print
or online.
www.bp.com/annualreview

Sustainability Review
Read the summary
BP Sustainability Review
2009 in print or read more
online from April 2010.
www.bp.com/sustainability

Acknowledgements
Design sasdesign.co.uk
Typesetting Bowne, London
Printing St Ives Westerham Press Ltd, UK,
ISO 14001, FSC-certiﬁ ed and CarbonNeutral®
Photography Stuart Conway, Graham Trott

209

beyond petroleum®

Annual Report
and Accounts
2009

B
P
A
n
n
u
a

R
e
p
o
r
t
a
n
d
A
c
c
o
u
n
t
s
2
0
0
9

bp.com/annualreport

What’s inside?

3 Business review

93 Additional information for

Chairman’s letter
Group chief executive’s review
Our performance

4
6
8
10 Group overview
22 Exploration and Production
36 Reﬁ ning and Marketing
42 Other businesses and corporate
44 Research and technology
46 Corporate responsibility
52 Relationships with suppliers and contractors
52 Regulation of the group’s business
52 Organizational structure
53 Financial performance
61

Liquidity and capital resources

65 Board performance and biographies

66 Directors and senior management
69 Board performance report

81 Directors’ remuneration report

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

and afﬁ liated purchasers

107 Fees and charges payable by a holder of ADSs
108 Fees and payments made by the Depositary

to the issuer

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

109 Financial statements

110 Consolidated ﬁ nancial statements of the BP group
116 Notes on ﬁ nancial statements
179

Supplementary information on oil and
natural gas (unaudited)

193 Parent company ﬁ nancial statements of BP p.l.c.