BP Annual Report 2006 | Quarterlytics

FY2006 Annual Report · BP
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Annual Report and Accounts 2006

www.bp.com

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These and other BP publications may be obtained, free of charge, from the following sources:

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www.bp.com/annualreview
11 www.bp.com/annualreview
BP Annual Review 2006 summarizes our 
financial and operating performance.

22 www.bp.com/financialandoperating 
 www.bp.com/financialandoperating 
BP Financial and Operating Information 
2002-2006 includes five-year financial 
and operating data.

 www.bp.com/sustainabilityreport
33 www.bp.com/sustainabilityreport
BP Sustainability Report 2006, published 
in May 2007, gives details of our 
environmental and social commitments 
and performance. 

44 www.bp.com/statisticalreview
 www.bp.com/statisticalreview
BP Statistical Review of World Energy, 
published in June each year, reports on 
key global energy trends. 

Acknowledgements
Design  VSA Partners, Chicago
Typesetting  St Ives Financial, UK
Printing  St Ives Financial, UK
Paper  This Annual Report and Accounts is printed on ReGen paper, 
which is manufactured from 100% de-inked post-consumer waste 
at a mill with IS0 14001 certification.

© BP p.l.c. 2007

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Information about this report

This document constitutes the Annual Report and Accounts of BP p.l.c.
for the year ended 31 December 2006 in accordance with UK
requirements and is dated 23 February 2007. This document also contains
information set out within the company’s Annual Report on Form 20-F
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.

Reﬁning and Marketing following the sale of Innovene; (b) the transfer
of certain mid-stream assets and activities from Reﬁning and Marketing
and Exploration and Production to Gas, Power and Renewables; (c) the
transfer of Hydrogen for Transport activities from Gas, Power and
Renewables to Reﬁning and Marketing; and (d) a change to the basis
of accounting for certain over-the-counter forward sale and purchase
contracts for oil, natural gas, natural gas liquids and power. (See Financial
statements – Note 2 on page 109 for further details.)

The ﬁnancial information for 2005 and 2004 has been restated to reﬂect
the following, all with effect from 1 January 2006: (a) the transfer of three
equity-accounted entities from Other businesses and corporate to

On pages 4-9, references within BP Annual Report and Accounts 2006
to ‘proﬁts’, ‘results’ and ‘return on average capital employed’ are to those
measures on a replacement cost basis unless otherwise indicated.

Reconciliation of proﬁt for the year to replacement cost proﬁt

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Proﬁt before interest and tax from continuing operations
Finance costs and other ﬁnance expense
Taxation
Minority interest
Proﬁt for the year from continuing operations attributable to BP shareholders
Proﬁt (loss) for the year from Innovene operations
Inventory holding (gains) losses
Replacement cost proﬁta
Replacement cost proﬁt from continuing operations attributable to BP shareholders
Replacement cost loss from Innovene operations
Replacement cost proﬁt
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate
Consolidation adjustments

Unrealized proﬁt in inventory
Net proﬁt on transactions between continuing operations and Innovene operations

Replacement cost proﬁt before interest and tax
Finance costs and other ﬁnance expense
Taxation
Minority interest
Replacement cost proﬁt from continuing operations attributable to BP shareholders
Per ordinary share – cents

Proﬁt for the year attributable to BP shareholders
Replacement cost proﬁt

Dividends per ordinary share – cents
– pence

Dividends paid per American depositary share (ADS) – dollars

2006
35,158
(516)
(12,331)
(286)
22,025
(25)
253
22,253
22,278
(25)
22,253
29,647
5,283
1,376
(947)

52
–
35,411
(516)
(12,331)
(286)
22,278

109.84
111.10
38.40
21.104
2.304

2005
32,682
(761)
(9,473)
(291)
22,157
184
(3,027)
19,314
19,513
(199)
19,314
25,485
4,394
1,077
(1,237)

(208)
527
30,038
(761)
(9,473)
(291)
19,513

105.74
91.41
34.85
19.152
2.091

2004
25,746
(780)
(7,082)
(187)
17,697
(622)
(1,643)
15,432
16,336
(904)
15,432
18,075
5,194
964
155

(191)
188
24,385
(780)
(7,082)
(187)
16,336

78.24
70.71
27.70
15.251
1.662

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

a Replacement cost profit reflects the current cost of supplies. The replacement cost profit for the year is determined by excluding from profit inventory holding gains and
losses. BP uses this measure to assist investors to assess BP’s performance from period to period.

The Annual Report and Accounts for the year ended 31 December 2006
contains the Directors’ Report, including the Business Review, on pages 4-67,
83-91, 94 and 205. The Directors’ Remuneration Report is on pages 68-75.
The consolidated ﬁnancial statements are on pages 93-175. The reports of
the auditor are on page 95 for the group and page 206 for the company.
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 the 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.

BP Annual Report and Accounts 2006 and BP Annual Review 2006
may be downloaded from www.bp.com/annualreview. No material on
the BP website, other than the items identiﬁed as BP Annual Report
and Accounts 2006 and BP Annual Review 2006, forms any part
of those documents.

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 90). BP discloses
on its website at www.bp.com/NYSEcorporategovernancerules signiﬁcant
ways (if any) in which its corporate governance practices differ from those
mandated for US companies under NYSE listing standards.

Cautionary statement
BP Annual Report and Accounts 2006 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 further details, please see
Forward-looking statements on page 13.

The registered ofﬁce of BP p.l.c. is 1 St James’s Square, London
SW1Y 4PD, UK. Telephone: +44 (0)207 496 4000.
Registered in England and Wales No. 102498.
Stock exchange symbol ‘BP’.

BP Annual Report and Accounts 2006

1

Miscellaneous terms

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

------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

ADR American depositary receipt.

LNG Liqueﬁed natural gas.

ADS American depositary share.

London Stock Exchange or LSE London Stock Exchange plc.

Amoco The former Amoco Corporation and its subsidiaries.

LPG Liqueﬁed petroleum gas.

Atlantic Richﬁeld Atlantic Richﬁeld Company and its subsidiaries.

mb/d thousand barrels per day.

Associate An entity 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 without having control or joint control over those policies.

Barrel 42 US gallons.

b/d Barrels per day.

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.

mboe/d thousand barrels of oil equivalent per day.

mmBtu million British thermal units.

mmcf/d million cubic feet per day.

MTBE Methyl tertiary butyl ether.

NGLs Natural gas liquids.

OPEC Organisation 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 Production-sharing agreement.

Hydrocarbons Crude oil and natural gas.

SEC The United States Securities and Exchange Commission.

IFRS International Financial Reporting Standards.

Joint venture A contractual arrangement between the group and other
venturers that undertake an economic activity that is subject to joint
control. Joint control exists only where the strategic ﬁnancial and
operating decisions relating to the activity require the unanimous consent
of the venturers.

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.

Jointly controlled asset A joint venture where the venturers have a
direct ownership interest in and jointly control the assets of the venture.

UK GAAP Generally Accepted Accounting Practice in the UK.

Jointly controlled entity 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 fellow venturers.

Liquids Crude oil, condensate and natural gas liquids.

US or USA United States of America.

US GAAP Generally Accepted Accounting Principles in the US.

2

Contents

4 Chairman’s letter

6 Group chief executive’s review

9 Measuring our progress

10 Performance review

65 Directors, senior management and employees

68 Directors’ remuneration report

76 Governance: board performance report

83 Additional information for shareholders

93

Financial statements

BP Annual Report and Accounts 2006

3

Dear Shareholder BP’s performance in 2006 can be best
described as mixed. A great portfolio of assets and excellent
people who are executing a consistent strategy remained as
our core strength. However, results could and should have
been better. The ability to beneﬁt from higher oil prices was
impaired by some of our major assets not being available.
For many years, BP has been a greatly admired group,
reﬂecting its strategic vision, determined execution and high
aspirations in areas such as safety, the environment and the
community – and I believe it still is. However, a number of
events in the US, starting with the tragic incident at the Texas
City reﬁnery in March 2005, have deeply shocked the group,
led to increased public scrutiny and had an effect on BP’s
reputation as a responsible operator. We must ensure that the
lessons we have learned will enable us to demonstrate rapidly
that we are again in the forefront of our industry in all respects.
Our aspirations remain unchanged and, in the vast majority
of our activities, we continue to be justly proud of our safety
record, our environmental initiatives and our high ethical
standards. However, it is quite clear to your board that the
group’s record in some areas has not met the standards
to which we aspire. Above all, we must ensure that, at all
locations, those who work for us do so safely.

The board’s governance system has long balanced support

for the executive team in the development of the group’s
strategy with the need to ensure effective monitoring of its
implementation. In this context, both the full board and its
committees have considered the signiﬁcant events of the
year and their impact on BP’s business and reputation.

The work of each of the committees is described in more
detail in the governance: board performance report on pages
36-43 of Notice of BP Annual General Meeting 2007 and also
on pages 76-82 of BP Annual Report and Accounts 2006.
The safety, ethics and environment assurance committee,
chaired by Dr Walter Massey, has played a particularly
important role during the year. The audit committee, chaired
by Sir Ian Prosser, has similarly had important work. I remain
conﬁdent in the work of all the committees and our overall
system of governance.

There have been a number of inquiries into the events at

Texas City and other aspects of the group’s operations. In
particular, on the recommendation of the US Chemical Safety
and Hazard Investigation Board, which was investigating the
Texas City incident, an independent panel was commissioned
by BP to examine the safety culture of our US reﬁneries. The
panel was chaired by former US Secretary of State James A
Baker, III and reported to us in early January. It found that,
while the focus of the group had been on personal safety
performance, where signiﬁcant improvement had been
achieved, there was insufﬁcient emphasis on process safety.
The panel further found that, by concentrating on improving
personal safety statistics, the group had developed a false
sense of conﬁdence in its safety culture. In essence, the panel

concluded that BP had fallen short in its approach to process
safety at its ﬁve US reﬁneries. It made a number of
recommendations, all of which we have considered and
will implement. One recommendation was that the board,
for at least ﬁve years, should engage an outside expert,
independent of the executive, to report to it on the progress
of the implementation of the panel’s recommendations.

Your board will keep you fully advised on the implementation

of those recommendations to which we, and the group’s
executives and employees, are fully committed. Indeed, we
have long had a tradition of emphasizing safety and, in nearly
20 years of reporting, we have seen a signiﬁcant improvement
in our safety performance.

It is important to stress that we have a clear strategy and
an underlying business that remains robust. BP has a set of
world-class assets that will ensure the continued success of
the group into the medium term. Our cash ﬂow has remained
strong during the year. The board has therefore been able
to continue its policy of returning value to our shareholders
through both increased dividends and buybacks. I am pleased
to conﬁrm a dividend, to be paid in March, of 10.325 cents per
share. The annual dividend paid of 38.40 cents or 21.104 pence
represents an increase of 10% in both dollar and sterling
terms. During 2006, we repurchased some $15.5 billion
of shares. Of these, 27% were for cancellation and the
remainder placed in treasury. Your board will continue to
keep its distribution policy under review.

I would like to pay tribute to John Browne, his executive

team and all our employees for their contributions to the
creation and maintenance of a robust, cash-generative
business. It has been a major task for the executive team
to respond to the pressing issues of 2006 while diligently
managing and guiding the business forward in a challenging
market. Although oil prices have remained high, we are in a
softening market and prices are some way from their peak;
costs of capital equipment and services, however, have risen
faster than inﬂation.

This year, the board, like many companies whose shares
are traded on both sides of the Atlantic, has streamlined the
company’s reporting process by using a common document
as the basis for both our Annual Report and Accounts and
our Annual Report on Form 20-F. As a result, the Annual
Report and Accounts now contains information that, in the
past, would only have appeared in our US reporting. The
short-form Annual Review continues to give a summary
of the group’s operations for the majority of our private
shareholders. We will keep our reporting process under
review, including a greater use of electronic communication
wherever we are able to do so.

In the summer of 2006, John and I agreed that he would
stay as chief executive until the end of 2008. Early in 2007,
we both decided that it would be in the group’s interest to
name a successor in order to provide a short orderly transition

Chairman’s letter

4

BP Annual Report and Accounts 2006

over a period of six months. The chairman’s committee was in
a position to identify a succession candidate in Tony Hayward,
then chief executive of the exploration and production
segment. Accordingly, John will retire on 31 July 2007 and
Tony has been appointed by the board to succeed him.

Tony has had an outstanding career at BP and the board

believes he has the intellect, skills and personal qualities to take
your company through the coming challenges and changes.

John Browne is one of the great businessmen of his

generation and has led the transformation of BP into one of
the biggest energy groups in the world. His performance over
the past 12 years has been extraordinary. He has consistently
been identiﬁed by his fellow chief executives as the most
impressive businessman in Britain.

I would like to thank John on behalf of the board for his
great achievement in leading the transformation of BP from
a mid-ranking regional oil company to what it is today.

Following Tony Hayward’s appointment as group chief
executive designate, Tony has passed his responsibilities as
chief executive of exploration and production to Andy Inglis,
who was appointed to the board on 1 February 2007. Andy
was previously deputy chief executive of exploration and
production and has held a number of posts in that segment
during his career with the group, which started in 1980.

Michael Wilson stood down as a director last year to take up
the post of Canada’s ambassador to Washington. He had joined
the BP board in 1998 at the time of the Amoco merger after
a distinguished political and business career. He had a keen
interest in corporate governance matters, being the chairman
of the Canadian Coalition of Good Governance. He had brought
all these strengths from his political and business background
to our board and committee deliberations.

John Bryan will stand down at the forthcoming AGM. John

also joined the BP board at the time of the Amoco merger
and has made signiﬁcant contributions to both the audit and
remuneration committees. His experience as a former CEO
in the US has been invaluable to the board over the years.
We shall miss his contribution at the board and his
commitment to board and committee work.

I was pleased to welcome Sir William Castell as a new
non-executive director in July. Bill is chairman of the board of
governors of the Wellcome Trust and is a non-executive director
of the General Electric Company, having been chief executive
of Amersham plc and subsequently president and chief
executive ofﬁcer of GE Healthcare. Bill is a member of the
chairman’s, the audit and the safety, ethics and environment
assurance committees.

I believe that the board has the right mix of skills and

experience to address the issues that we face. I will keep this
under review as we refresh the board over time. There remain
signiﬁcant challenges for the group in securing its business into
the medium and the longer term. The board will be focusing on
these in the coming year. On behalf of the board, I would like
to thank you for your support.

Peter Sutherland
Chairman
23 February 2007

Group chief
executive’s
review

Dear Shareholder BP’s purpose is a progressive one. That
means we aim to generate returns for our investors by
providing the energy for basic human needs such as light,
heat and mobility and to do so in a safe, sustainable and
environmentally responsible way. Our ﬁnancial results were
very strong in 2006. However, we fell short of our expectations
in certain areas, notably with two oil spills in Alaska and the
inability to start up the Thunder Horse platform as soon as
we had hoped.

We are headed in the right strategic direction and we should

not allow recent setbacks to obscure that. We have been
urgently addressing operational issues and matters related to
our safety performance. And I believe that, from the lessons
we have learned, the fresh investment and priorities we are
putting in place and the determined reafﬁrmation of our core
values, BP will emerge a stronger company.

Our staff across the world have responded to the tough

challenges of the year in an exemplary fashion. I am
immensely proud of their resilience and would like to thank
them. They are as determined as my successor, Tony Hayward,
and I are to restore BP’s performance and reputation.

The trading environment has been extremely volatile. The
oil price hit a high of $78 per barrel in August before falling back
to end the year at about $59 per barrel. The Henry Hub price for
gas fell signiﬁcantly during the year to close at around $5.50 per
million British thermal units. Reﬁning margins widened over the
summer before narrowing towards normal levels in the winter.
These movements are characteristic of an industry that is not
only cyclical but also affected by trends such as rising
concerns about energy security and climate change.

Safety Before addressing our ﬁnancial performance, let me
talk about the things that did not go so well, for these have
absorbed much of my and the team’s attention. Safety has
always been one of our core priorities. Scrutiny of the group
has inevitably been dominated by the investigations into the
March 2005 explosion at the Texas City reﬁnery, in which 15
of our co-workers tragically lost their lives, and into the pipeline
corrosion at Prudhoe Bay in Alaska.

It is an unavoidable fact that we operate in a hazardous
industry. But accidents of any kind cause people to question
the values that underpin our company. They also cast a shadow
over our many successes – and the fact that, around the world,
hundreds of thousands of employees and contractors work
safely for BP, with dedication and integrity.

BP aspires to be an industry leader in the three dimensions

of safety – personal safety, process safety and the
environment. We have had a strong track record in the day-
to-day personal safety of our people. In 2006, our recordable
injury frequency rate, the standard industry measure, fell to
0.47 per 200,000 hours worked, the lowest in our history.
There were also seven fatalities. Every death is a tragedy, but
we should recognize that this number has reduced signiﬁcantly,
to the lowest level in nearly 20 years of reporting. I am
particularly pleased with the large drop in driving-related
fatalities, from 14 in 2003 to two in 2006, following the
implementation of our new driving safety standard. On
the environment, we continue to make progress in reducing
greenhouse gas emissions and the environmental impact
of our products.

Our response to the Baker report In January, former US
Secretary of State James A Baker, III and his panel published
a candid and thorough report into process safety management
at our US reﬁneries. The panel was established by BP on
the recommendation of the US Chemical Safety and Hazard
Investigation Board in the wake of the Texas City tragedy and
was intended to provide lessons not just for us but for the
entire industry.

BP will implement the Baker panel’s recommendations and
we are now consulting with the panel on how best to do that.
Many of the recommendations are consistent with our own
internal reviews and our aim now is to develop a timely and
intelligent plan of action in order to transform BP into an
industry leader in process safety management.

Importantly, the panel did not conclude that BP intentionally

withheld resources on any safety-related assets or projects
for budgetary or cost reasons. The panel interviewed hundreds
of employees in the course of its work and observed that it
had seen no information to suggest that anyone – from BP’s
board members to its hourly-paid workers – acted in anything
other than good faith.

Our response to the Baker report comes alongside what
we were already doing to embed consistently high standards
of safety and operational integrity throughout BP. This includes
an ambitious four-year programme of investment in safety
and operational integrity right across the group and the
creation of an advisory board of external experts to assist
and advise BP America Inc. in monitoring the operations of
the US businesses, with particular focus on compliance, safety
and regulatory affairs. At Texas City itself, a new leadership
team has introduced world-class training programmes,
increased the number of safety inspectors, renovated major
units and relocated hundreds of employees. We expect Texas

City to be processing about 400,000 barrels per day of crude
oil by the end of 2007.

We are also implementing lessons from the two oil spills
and the cases of corrosion that occurred at Prudhoe Bay in
2006. When corrosion was found in August, we rapidly shut
down production as a precaution. Nearly 27,000 individual
radiographic or ultrasonic inspections of the pipeline system
have since been carried out and output was restored to its
full level in late 2006. We are replacing 16 miles of transit
lines, increasing spending on major maintenance and retaining
a team of independent corrosion experts as advisers.

We took similar precautionary action to replace subsea

components for the Thunder Horse platform in the Gulf
of Mexico. The components had passed industry tests and
met regulatory requirements but a metallurgical failure was
revealed when our engineers tested compliance with BP’s
own, more stringent, standards. We are now replacing the
equipment in question and expect Thunder Horse to start
production by the end of 2008.

Integrity We are also taking action to ensure that people
across BP behave with consistent integrity. During the year,
there were allegations of market manipulation in our US trading
operations. We have responded to these serious allegations
by making internal improvements and instituting a thorough
internal review by independent auditors.

Performance In terms of ﬁnancial performance, the year
was a record one, with replacement cost proﬁt rising 15%
to $22.3 billion, representing a return on average capital
employed of 22%. Thanks to our share buyback programme,
earnings per share rose faster than proﬁts, by 22%, to
111.1 cents per share.

Our role as a leading international oil company is to build

strong and sustainable supply chains between producing
countries and markets around the world. In emerging economies
such as Algeria, Angola, Azerbaijan, Egypt, Indonesia and
Trinidad & Tobago, our investments help to increase the ﬂow
of supplies to world markets as well as strengthening local
economies and contributing to economic development.

Our joint venture in Russia, TNK-BP, brings together BP’s

experience with local assets, capabilities and resources to
help increase production. Our experience in working in the
Russian Federation is to act with caution, respect and genuine
reciprocity. The agreement we concluded with Gazprom
during the year to provide liqueﬁed natural gas (LNG) cargoes
indicates the scope for co-operation to build new supply
chains in the international marketplace. We also deepened
our strategic relationship with Rosneft, Russia’s second largest
oil company, investing $1 billion in a stake at its initial public
offering in July. That investment has risen by about 25% in
value. We are also exploring the Sakhalin IV and V licence areas
in a joint venture with Rosneft and have signed a protocol with
them to carry out joint studies in the basins of the Russian
arctic region.

In 2006, capital investment in our exploration and production

segment totalled $12.1 billion, excluding our investment in
Rosneft. We added 1.4 billion barrels of oil and 1.3 trillion cubic
feet of natural gas to our booked reserves for subsidiaries and
equity-accounted entities. We have decided to move solely to
the US Securities and Exchange Commission (SEC) basis of
reserves reporting to simplify disclosures and allow for easier
comparison with competitors. Our reserves replacement ratio,

BP Annual Report and Accounts 2006

7

using reserves calculated in accordance with SEC guidance,
was 113% on a combined basis of subsidiaries and equity-
accounted entities, excluding acquisitions and disposals –
an excellent result.

We produced more than 3.9 million barrels of oil equivalent
per day and continued to build our presence as a producer and
supplier of natural gas. The production level was affected by
strategic divestments but, excluding the historic impact of
these, our production continues to grow. Since the year-end,
we have signed a signiﬁcant gas production-sharing agreement
with the Sultanate of Oman. In reﬁning and marketing, we
continued to develop strong positions in areas of fast-growing
demand, supplying millions of customers every day. Our low-
carbon power business, BP Alternative Energy, made a strong
start, with signiﬁcant additions in wind and solar capacity.

Speciﬁc highlights of the year included the start of production

in the East and West Azeri oil ﬁelds in the Caspian Sea and
the start of operations for the Baku-Tbilisi-Ceyhan pipeline,
which links the Caspian Sea to the Mediterranean. There
were discoveries in Angola and the Gulf of Mexico. We saw
our ﬁrst gas produced from the Cannonball platform in Trinidad
& Tobago and from In Amenas in Algeria. With our partners,
we commissioned a new LNG regasiﬁcation terminal in China.
We announced a major investment at our Whiting reﬁnery
in the US to process Canadian heavy crude, providing a new
source of supply for the North American market.

2006 was also a year when environmental issues, chieﬂy

climate change, remained at the top of the public agenda.
BP Alternative Energy, launched in 2005, is a rapidly growing
business devoted to providing low-carbon power from solar,
wind, hydrogen and natural gas sources. The business
developed strongly in 2006, doubling its solar manufacturing
capacity since 2004, acquiring wind power interests with a
potential total generating capacity of some 15,000 megawatts
and increasing gas-ﬁred capacity. It also further developed its
ground-breaking plans for hydrogen power stations fed by
fossil fuel feedstocks from which carbon dioxide is extracted
and stored underground, minimizing the environmental impact.
In the transport sector, we took new steps towards providing

more sustainable energy by announcing the forthcoming
establishment of a university-based Energy Biosciences
Institute, seeking to mirror in energy the beneﬁts that biological
sciences have brought to medicine. We also set up a dedicated
biofuels business and entered into a partnership with DuPont
to produce a new generation of biofuels.

Our guiding principle remains that of mutual advantage –
creating beneﬁts for others as well as for ourselves. I hope
this year has shown that, when we fail in that respect, we
will work relentlessly and transparently to solve the problems.

The future This is my last letter to shareholders as I am
soon to retire as group chief executive. I have devoted my
working life to BP and I would like to thank shareholders,
the board and our employees for their support over the
past 12 years.

I believe that, although our journey has not always been
smooth, the fundamentals of the company – its assets, its
strategy and its people – are very sound. BP has certainly
changed dramatically since 1995. By most measures it has
doubled or tripled in size and has grown from being a regional
player, based principally around the North Sea and Alaska,
to a truly international company. We now produce more
than 100,000 barrels of oil equivalent per day from eight
different countries, up from three countries in 1995. And
long-term investors should gain comfort from our creditable
reserves position.

BP is widely recognized as a pioneer in the oil and gas
industry for both reducing greenhouse gas emissions and
investing substantially in alternative and renewable energy
businesses. Shareholders have beneﬁted too and, from
mid-1995 until the end of 2006, total returns were 278%
in dollars and 203% in sterling.

Our ﬁnancial framework is robust. We aim to invest in our
operations; to pursue a progressive dividend policy; to maintain
our gearing within a range of 20-30%; and to return any surplus
cash to shareholders, circumstances permitting. During the
year, we bought back 1.3 billion of our shares, of which
358 million were for cancellation, with the remainder being
held in treasury. We also paid total dividends of 38.40 cents,
or 21.104 pence, a share, an increase of 10% on 2005.

BP’s strategic priorities are enduring: to build production

in some of the world’s largest oil and gas ﬁelds; to focus
on advantaged reﬁneries and retail markets; to capture world-
scale gas market positions; and to participate in fast-growing
markets for gas and low-carbon power.

We are emerging from 2006 with our basic values tested,

but reafﬁrmed. My successor as group chief executive,
Tony Hayward, is a wonderful choice and I wish him and
the company every good fortune. The best is yet to come.

The Lord Browne of Madingley
Group Chief Executive
23 February 2007

8

BP Annual Report and Accounts 2006

Measuring
our progress

BP Annual Report and Accounts 2006

9

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Performance review

Selected ﬁnancial and operating information

This information, insofar as it relates to 2006, has been extracted or
derived from the audited ﬁnancial statements of the BP group presented
on pages 93-175. The selected information should be read in conjunction
with the audited ﬁnancial statements and related Notes elsewhere herein.
The ﬁnancial information for 2005 and 2004 has been restated to reﬂect
the following, all with effect from 1 January 2006: (a) the transfer of three
equity-accounted entities from Other businesses and corporate to
Reﬁning and Marketing following the sale of Innovene; (b) the transfer of
certain mid-stream assets and activities from Reﬁning and Marketing and
Exploration and Production to Gas, Power and Renewables; (c) the
transfer of Hydrogen for Transport activities from Gas, Power and
Renewables to Reﬁning and Marketing; and (d) a change to the basis of
accounting for certain over-the-counter forward sale and purchase
contracts for oil, natural gas, NGLs and power. (See Financial statements
– Note 2 on page 109 for further details.)

BP sold its Innovene operations in December 2005. In the

circumstances of discontinued operations, IFRS require that the proﬁts
earned by the discontinued operations, in this case the Innovene
operations, on sales to the continuing operations be eliminated on
consolidation from the discontinued operations and attributed to the
continuing operations and vice versa. This adjustment has two offsetting
elements: the net margin on crude reﬁned by Innovene, as substantially
all crude for its reﬁneries was supplied by BP and most of the reﬁned
products manufactured by Innovene were taken by BP; and the margin on
sales of feedstock from BP’s US reﬁneries to Innovene’s manufacturing
plants. The proﬁts attributable to individual segments are not affected by
this adjustment. This representation does not indicate the proﬁts earned
by continuing or Innovene operations, as if they were standalone entities,
for past periods or those likely to be earned in future periods. Under US
GAAP, Innovene operations would not be classiﬁed as discontinued
operations due to BP’s continuing customer/supplier arrangements with
Innovene. For a full description of the differences between IFRS and
US GAAP, see Financial statements – Note 53 on page 179.

IFRS

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

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 shareholders

Basic
Diluted

Dividends per share – cents
Dividends per share – 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 equity

$ million except per share amounts

2006

2005

2004

2003

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

109.84
109.00

109.97
109.12
38.40
21.104

20,028
20,195

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

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

105.74
104.52

104.87
103.66
34.85
19.152

21,126
21,411

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

192,024
25,746
17,884
17,262
17,075
16,651

78.24
76.87

81.09
79.66
27.70
15.251

21,821
22,293

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

164,653
18,776
12,681
12,618
12,448
19,623

56.14
55.61

56.42
55.89
25.50
15.658

22,171
22,424

172,491
70,264
5,552
69,139
12,869
22%

Selected historical ﬁnancial data is based on ﬁnancial statements prepared in accordance with IFRS and accordingly is shown for the four years
subsequent to the date of transition to IFRS.

10

US GAAP

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Income statement data
Revenuesd
Proﬁt for the year attributable to BP shareholdersd
Comprehensive income
Proﬁt per ordinary share – cents

Basic
Diluted

Proﬁt per American depositary share – cents

Basic
Diluted

Balance sheet data
Total assets
Net assets
BP shareholders’ equity

2006

2005

2004

2003

2002

$ million except per share amounts

265,906
21,116
23,125

252,168
19,642
17,053

203,303
17,090
17,371

173,615
12,941
19,689

145,991
8,109
10,256

105.42
104.63

632.52
627.78

92.96
91.91

78.31
76.88

58.36
57.79

36.20
36.02

557.76
551.46

469.86
461.28

350.16
346.74

217.20
216.12

219,288
87,358
86,517

213,722
85,936
85,147

206,139
86,435
85,092

186,576
80,292
79,167

164,103
67,274
66,636

a Excludes Innovene which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’. (See Financial
statements – Note 5 on page 111). Under US GAAP, Innovene is not treated as a discontinued operation.
b There were no significant acquisitions in 2006 or in 2005. Capital expenditure in 2006 includes $1 billion in respect of our investment in Rosneft. Capital expenditure and
acquisitions for 2004 includes $1,354 million for including TNK’s interest in Slavneft within TNK-BP and $1,355 million for the acquisition of Solvay’s interests in BP Solvay
Polyethylene Europe and BP Solvay Polyethylene North America. With the exception of the shares issued to Alfa Group and Access-Renova (AAR) in connection with TNK-BP
(2004-2006), all capital expenditure and acquisitions during the last five years have been financed from cash flow from operations, disposal proceeds and external financing.
c The number of ordinary shares shown have been used to calculate per share amounts for both IFRS and US GAAP.
d Under US GAAP, Innovene is not treated as a discontinued operation. (See Financial statements – Note 5 on page 111). As such, the results of Innovene are included within
revenues and profit for the year, as adjusted to accord with US GAAP.

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

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

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)a b
Estimated net proved crude oil reserves for equity-accounted entities (million barrels)a c
Estimated net proved natural gas reserves for subsidiaries (billion cubic feet)a d
Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet)a e

2006

2005

2004

2003

2002

1,351
1,124
7,412
1,005
5,893
3,888
42,168
3,763

1,423
1,139
7,512
912
6,360
3,205
44,448
3,856

1,480
1,051
7,624
879
6,755
3,179
45,650
2,857

1,615
506
8,092
521
7,214
2,867
45,155
2,869

1,766
252
8,324
383
7,762
1,403
45,844
2,945

a Net proved reserves of crude oil and natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.
b Includes 23 million barrels (29 million barrels at 31 December 2005 and 40 million barrels at 31 December 2004) in respect of the 30% minority interest in BP Trinidad and
Tobago LLC.
c Includes 179 million barrels (95 million barrels at 31 December 2005 and 127 million barrels at 31 December 2004) in respect of the 6.29% minority interest in TNK-BP
(4.47% at 31 December 2005 and 5.9% at 31 December 2004).
d Includes 3,537 billion cubic feet of natural gas (3,812 billion cubic feet at 31 December 2005 and 4,064 billion cubic feet at 31 December 2004) in respect of the 30% minority
interest in BP Trinidad and Tobago LLC.
e Includes 99 billion cubic feet (57 billion cubic feet at 31 December 2005 and 13 billion cubic feet at 31 December 2004) in respect of the 7.77% minority interest in TNK-BP
(4.47% at 31 December 2005 and 5.9% at 31 December 2004).

During 2006, 329 million barrels of oil and natural gas, on an oil equivalent* basis (mmboe), were added to BP’s proved reserves for subsidiaries

(excluding purchases and sales). After allowing for production, which amounted to 963mmboe, BP’s proved reserves for subsidiaries were
13,163mmboe at 31 December 2006. These proved reserves are mainly located in the US (44%), Rest of Americas (20%), Asia Paciﬁc (10%), Africa
(9%) and the UK (8%).

For equity-accounted entities, 1,306mmboe were added to proved reserves (excluding purchases and sales), production was 479mmboe and proved

reserves were 4,537mmboe at 31 December 2006.

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

BP Annual Report and Accounts 2006

11

Risk factors

We urge you to consider carefully the risks described below. If any
of these risks occur, our business, ﬁnancial condition and results of
operations could suffer and the trading price and liquidity of our securities
could decline, in which case you could lose all or part of your investment.
Our system of risk management provides the response to enduring
risks of group signiﬁcance through the establishment of standards and
other controls. Inability to identify, assess and respond to risks through
this and other controls could lead to inability to capture opportunities,
threats materializing, inefﬁciency and legal non-compliance.

The risks are categorized against the following areas: Strategy,

Compliance and ethics, Financial control and operations.

Strategic risks
Access and renewal
Successful execution of our group plan depends critically on implementing
activities to renew and reposition our portfolio. The challenges to renewal
of our upstream portfolio are growing due to increasing competition for
access to opportunities globally. Inability to complete planned disposals
and/or lack of material positions in new markets could result in an inability
to capture above-average market growth.

Prices and markets
Oil, gas and product prices are subject to international supply and
demand. Political developments (especially in the Middle East) and the
outcome of meetings of OPEC can particularly affect world supply and
oil prices. In addition to the adverse effect on revenues, margins and
proﬁtability from any future fall in oil and natural gas prices, a prolonged
period of low prices or other indicators would lead to a review for
impairment of the group’s oil and natural gas properties. This review
would reﬂect management’s view of long-term oil and natural gas prices.
Such a review could result in a charge for impairment that could have a
signiﬁcant effect on the group’s results of operations in the period in
which it occurs.

Reﬁning proﬁtability can be volatile, with both periodic oversupply and

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

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

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

Competition
The oil, gas and petrochemicals industries are highly competitive. There
is strong competition, both within the oil and gas industry and with other
industries, in supplying the fuel needs of commerce, industry and the
home. Competition puts pressure on product prices, affects oil products
marketing and requires continuous management focus on reducing unit
costs and improving efﬁciency.

Compliance and ethics risks
Regulatory
The oil industry is subject to regulation and intervention by governments
throughout the world in such matters as the award of exploration and
production interests, the imposition of speciﬁc drilling obligations,
environmental protection controls, controls over the development and
decommissioning of a ﬁeld (including restrictions on production) and,

12

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

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

Financial control risks
Liquidity, ﬁnancial capacity and ﬁnancial exposure
The group has established a ﬁnancial framework to ensure that it is able
to maintain an appropriate level of liquidity and ﬁnancial capacity and to
constrain the level of assessed capital at risk for the purposes of positions
taken in ﬁnancial instruments. Failure to operate within our ﬁnancial
framework could lead to the group becoming ﬁnancially distressed leading
to a loss of shareholder value. Commercial credit risk is measured and
controlled to determine the group’s total credit risk. Inability adequately to
determine our credit exposure could lead to ﬁnancial loss. Crude oil prices
are generally set in US dollars, while sales of reﬁned products may be in
a variety of currencies. Fluctuations in exchange rates can therefore give
rise to foreign exchange exposures, with a consequent impact on
underlying costs.

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

Operations risks
Operations — safety and operations
Process safety
Inherent in our operations are hazards that require continual oversight
and control. There are risks of technical integrity failure and loss of
containment of hydrocarbons and other hazardous material at operating
sites or pipelines. Failure to manage these risks could result in injury or
loss of life, environmental damage and/or loss of production.

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

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

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

Drilling and production
Exploration and production require high levels of investment and are
subject to natural hazards and other uncertainties, including those relating
to the physical characteristics of an oil or natural gas ﬁeld. The cost of
drilling, completing or operating wells is often uncertain. We may be
required to curtail, delay or cancel drilling operations because of a

variety of factors, including unexpected drilling conditions, pressure
or irregularities in geological formations, equipment failures or
accidents, adverse weather conditions and compliance with
governmental requirements.

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

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

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

Reserves replacement
Successful execution of our group plan (see page 14) depends critically on
sustaining long-term reserves replacement. If upstream resources are not
progressed to proved reserves in a timely and efﬁcient manner, we will
be unable to sustain long-term replacement of reserves.

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

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

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

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

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

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’,
‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we
see’ or similar expressions. In particular, among other statements, (i)
certain statements in Performance review (pages 10-60) with regard to
management aims and objectives, future capital expenditure, future
hydrocarbon production volume, date or period(s) in which production is
scheduled or expected to come on stream or a project or action is
scheduled or expected to be completed, capacity of planned plants or
facilities, the timing of divestments and impact of health, safety and
environmental regulations; (ii) the statements in Performance review
(pages 14-47) with regard to planned expansion, investment or other
projects and future regulatory actions; and (iii) the statements in
Performance review (pages 47-60) with regard to the plans of the group,
cash ﬂows, opportunities for material acquisitions, the cost of future
remediation programmes, liquidity and costs for providing pension and
other post-retirement beneﬁts; and including under ‘Liquidity and Capital
Resources’ with regard to future cash ﬂows, future levels of capital
expenditure and divestments, working capital, future production volumes,
the renewal of borrowing facilities, shareholder distributions and share
buybacks and expected payments under contractual and commercial
commitments; are all forward-looking in nature.

By their nature, forward-looking statements involve risk and uncertainty

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

Statements regarding competitive position

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

BP Annual Report and Accounts 2006

13

Information on the company

General
Unless otherwise indicated, information in this document reﬂects 100%
of the assets and operations of the company and its subsidiaries that
were consolidated at the date or for the periods indicated, including
minority interests. Also, unless otherwise indicated, ﬁgures for business
sales and other operating revenues include sales between BP businesses.
The British Petroleum Company p.l.c., incorporated in 1909 in England
and Wales, became known as BP Amoco p.l.c. following the merger with
Amoco Corporation (incorporated in Indiana, US, in 1889). The company
subsequently changed its name to BP p.l.c.

BP is one of the world’s leading oil companies on the basis of market
capitalization and proved reserves. Our worldwide headquarters is located
at 1 St James’s Square, London SW1Y 4PD, UK. Telephone +44 (0)20
7496 4000. Our agent in the US is BP America Inc., 4101 Winﬁeld Road,
Warrenville, Illinois 60555. Telephone +1 630 821 2222.

Overview of the group
BP is a global group, with interests and activities held or operated through
subsidiaries, jointly controlled entities or associates established in, and
subject to the laws and regulations of, many different jurisdictions. These
interests and activities cover three business segments, supported by a
number of organizational elements comprising group functions or regions.
The three business segments are Exploration and Production, Reﬁning

and Marketing and Gas, Power and Renewables. Exploration and
Production’s activities include oil and natural gas exploration, development
and production (upstream activities), together with related pipeline,
transportation and processing activities (midstream activities). The
activities of Reﬁning and Marketing include oil supply and trading and the
manufacture and marketing of petroleum products, including aromatics
and acetyls, as well as reﬁning and marketing. Gas, Power and
Renewables activities include marketing and trading of gas and power;
marketing of liqueﬁed natural gas (LNG); natural gas liquids (NGLs); and
low-carbon power generation through our Alternative Energy business.
The group provides high-quality technological support for all its businesses
through its research and engineering activities.

Group functions serve the business segments, aiming to achieve

coherence across the group, manage risks effectively and achieve
economies of scale. Each head of region ensures regional consistency of
the activities of business segments and group functions and represents
BP to external parties.

The group’s system of internal control is described in the BP

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

The group strategy describes the group’s strategic objectives and the
presumptions made by BP about the future. It describes strategic risks
that arise from making such presumptions and the actions to be taken
to manage or mitigate the risks. The board delegates to the group chief
executive responsibility for developing BP’s strategy and its
implementation through ﬁve-year and annual plans (the group plan) that
determine the setting of priorities and allocation of resources. The group
chief executive is obliged to discuss with the board, on the basis of the
strategy and group plan, all material matters currently or prospectively
affecting BP’s performance.

As the group’s business segments are managed on a global, not on a
regional, basis, geographical information for the group and segments is
given to provide additional information for investors but does not reﬂect
the way BP manages its activities.

We have well-established operations in Europe, the US, Canada,
Russia, South America, Australasia, Asia and parts of Africa. Currently,
around 70% of the group’s capital is invested in Organisation for

14

Economic Co-operation and Development (OECD) countries, with just
under 40% of our ﬁxed assets located in the US and around 25% located
in the UK and the Rest of Europe.

We believe that BP has a strong portfolio of assets in each of its main

segments:
– In Exploration and Production, we have upstream interests in 26

countries. In addition to our drive to maximize the value of our existing
portfolio, we are continuing to develop new proﬁt centres. Exploration
and Production activities are managed through operating units that
are accountable for the day-to-day management of the segment’s
activities. An operating unit is accountable for one or more ﬁelds. Proﬁt
centres comprise one or more operating units. Proﬁt centres are, or
are expected to become, areas that provide signiﬁcant production and
income for the segment. Our new proﬁt centres are in Asia Paciﬁc
(Australia, Vietnam, Indonesia and China), Azerbaijan, North Africa
(Algeria), Angola, Trinidad & Tobago and the deepwater Gulf of Mexico;
and in Russia/Kazakhstan (including our operations in TNK-BP, Sakhalin
and LukArco), where we believe we have competitive advantage and
which we believe provide the foundation for volume growth and
improved margins in the future. We also have signiﬁcant midstream
activities to support our upstream interests.

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

– In Gas, Power and Renewables, we have a growing marketing and

trading business in the US, Canada, UK and continental Europe. Our
marketing and trading activities include natural gas, power and NGLs.
Our international natural gas monetization activities identify and capture
worldwide opportunities for our upstream natural gas resources and
are focused on growing natural gas markets, including the US, Canada,
Spain and many of the emerging markets of the Asia Paciﬁc region,
notably China. We have a signiﬁcant NGLs processing and marketing
business in North America. In 2005, we established BP Alternative
Energy, which aims to extend signiﬁcantly our capabilities in solar,
wind, hydrogen power and gas-ﬁred power generation. Alternative
Energy has solar production facilities in US, Spain and India and
Australia, wind farms in the Netherlands and a substantial portfolio of
development projects in the US. We are advancing development of
hydrogen power plants and are involved in power projects in the US,
UK, Spain and South Korea.
Through non-US subsidiaries or other entities, BP conducts or has

conducted limited marketing, licensing and trading activities and technical
studies in certain countries subject to US sanctions, in particular in Iran
and with Iranian counterparties, including the National Iranian Oil
Company (NIOC) and afﬁliated entities, and has a small representative
ofﬁce in Iran. BP believes that these activities are immaterial to the group.
In addition, BP has interests in, and is the operator of, two ﬁelds outside
Iran in which NIOC and an afﬁliated entity have interests. However, BP
does not seek to obtain from the government of Iran licences or
agreements for oil and gas projects in Iran and does not own or operate
any reﬁneries or chemicals plants in Iran.

Acquisitions and disposals
In 2006, there were no signiﬁcant acquisitions. BP purchased 9.6% of
the shares issued under Rosneft’s IPO for a consideration of $1 billion
(included in capital expenditure). This represents an interest of around
1.4% in Rosneft. Disposal proceeds were $6,254 million, which included
$2.1 billion on the sale of our interest in the Shenzi discovery and around
$1.3 billion from the sale of our producing properties on the Outer
Continental Shelf of the Gulf of Mexico to Apache Corporation.

In 2005, there were no signiﬁcant acquisitions. Disposal proceeds
were $11,200 million, which included net cash proceeds from the sale
of Innovene to INEOS of $8,304 million after selling costs, closing
adjustments and liabilities. Innovene represented the majority of the
Oleﬁns and Derivatives business. Additionally, disposal proceeds included
proceeds from the sale of the group’s interest in the Ormen Lange ﬁeld
in Norway.

On 2 November 2004, Solvay exercised its option to sell its interests

in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North
America to BP. Solvay held 50% of BP Solvay Polyethylene Europe and
51% of BP Solvay Polyethylene North America. On completion, the two
entities, which manufactured and marketed high-density polyethylene,
became wholly owned subsidiaries of BP. The total consideration for the
acquisition was $1,391 million. These two entities were subsequently
included as part of the sale of Innovene to INEOS (see above).

During 2004, BP China and Sinopec announced the establishment
of the BP-Sinopec (Zhejiang) Petroleum Co. Ltd, a retail joint venture

between BP and Sinopec. Based on the existing service station network
of Sinopec, the 30-year dual-branded joint venture has plans to build,
operate and manage a network of 500 service stations in Hangzhou,
Ningbo and Shaoxing. Also during 2004, BP China and PetroChina
announced the establishment of BP-PetroChina Petroleum Company
Limited. Located in Guangdong, one of the most developed provinces in
China, the 30-year dual-branded joint venture is intended to acquire, build,
operate and manage 500 service stations in the province within three
years of establishment. The initial investment in both joint ventures
amounted to $106 million. (See Reﬁning and Marketing on page 31 for
further details.)

Disposal proceeds in 2004 were $4,961 million, which included

$2.3 billion from the sale of the group’s investments in PetroChina and
Sinopec. Additionally, it included proceeds from the sale of various oil and
gas properties, the sale of our interest in Singapore Reﬁning Company
Private Limited, the sale of our specialty intermediate chemicals and
Fabrics and Fibres businesses and the sale of two NGLs plants.

BP Annual Report and Accounts 2006

15

Exploration and production

Our Exploration and Production business includes upstream and
midstream activities in 26 countries, including the US, the UK, Angola,
Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad) and
locations within Asia Paciﬁc, Latin America and the Middle East.
Upstream activities involve oil and natural gas exploration and ﬁeld
development and production. Our exploration programme is currently
focused around the deepwater Gulf of Mexico, Angola, Egypt, Russia and
Algeria. Major development areas include the deepwater Gulf of Mexico,
Azerbaijan, Algeria, Angola, Egypt and Asia Paciﬁc. During 2006,
production came from 22 countries. The principal areas of production are
Russia, the US, Trinidad, the UK, Latin America, the Middle East, Asia
Paciﬁc, Azerbaijan, Angola and Egypt.

Midstream activities involve the ownership and management of crude

oil and natural gas pipelines, processing and export terminals and LNG
processing facilities and transportation. Our most signiﬁcant midstream
pipeline interests include the Trans Alaska Pipeline System, the Forties
Pipeline System and the Central Area Transmission System pipeline, both
in the UK sector of the North Sea, and the Baku-Tbilisi-Ceyhan pipeline,
running through Azerbaijan, Georgia and Turkey. Major LNG activities are
located in Trinidad, Indonesia and Australia. Further LNG businesses with
BP involvement are being built up in Egypt and Angola.

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

Key statistics

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

2005a

$ million
2004a

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Sales and other operating revenues

from continuing operations
Proﬁt before interest and tax from

continuing operations

Total assets
Capital expenditure and acquisitions

52,600

47,210

34,700

29,629
99,310
13,118

25,502
93,447
10,237

18,085
85,808
11,002

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Average BP crude oil realizationsb
Average BP NGL realizationsb
Average BP liquids realizationsb c
Average West Texas Intermediate

oil price

Average Brent oil price

$ per barrel

61.91
37.17
59.23

66.02
65.14

50.27
33.23
48.51

56.58
54.48

36.45
26.75
35.39

41.49
38.27

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Average BP natural gas realizationsb
Average BP US natural gas realizationsb

4.72
5.74

4.90
6.78

3.86
5.11

$ per thousand cubic feet

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Average Henry Hub gas priced

7.24

8.65

6.13

$ per mmBtu

Profit before interest and tax from continuing operations includes profit after interest
and tax of equity-accounted entities.

a With effect from 1 January 2006, we transferred the Phu My Phase 3 combined
cycle gas turbine plant in Vietnam to the Gas, Power and Renewables segment.
The 2005 and 2004 data above has been restated to reflect this transfer.
b The Exploration and Production business does not undertake any hedging activity.
Consequently, realizations reflect the market price achieved. Realizations are based
on sales of consolidated subsidiaries only – this excludes equity-accounted entities.
c Crude oil and natural gas liquids.
d Henry Hub First of Month Index.

Our activities are divided among existing proﬁt centres – our operations in
Alaska, Egypt, Latin America (including Argentina, Bolivia, Colombia
and Venezuela), Middle East (including Abu Dhabi, India, Sharjah and
Pakistan), North America Gas (onshore US and Canada) and the North Sea
(UK, Netherlands and Norway); and new proﬁt centres – our operations in
Asia Paciﬁc (Australia, Vietnam, Indonesia and China), Azerbaijan, North
Africa (Algeria), Angola, Trinidad and the deepwater Gulf of Mexico; and
Russia/Kazakhstan (this includes our operations in TNK-BP, Sakhalin
and LukArco).

16

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

The Exploration and Production strategy is to build production with

improving returns by:
– Focusing on ﬁnding the largest ﬁelds, concentrating our involvement
in a limited number of the world’s most proliﬁc hydrocarbon basins.

– Building leadership positions in these areas.
– Managing the decline of existing producing assets and divesting assets

when they no longer compete in our portfolio.
This strategy is underpinned by a focused exploration strategy in
areas with the potential for large oil and natural gas ﬁelds as new proﬁt
centres. Through the application of advanced technology and signiﬁcant
investment, we have gained a strong position in many of these areas.
Within our existing proﬁt centres, we seek to manage the decline through
the application of technology, reservoir management, maintaining
operating efﬁciency and investing in new projects. We also continually
review our existing assets and dispose of them when the opportunities
for future investment are no longer competitive compared with other
opportunities within our portfolio and offer greater value to another
operator.

In support of growth, total capital expenditure and acquisitions in 2006

was $13.1 billion (2005 $10.2 billion and 2004 $11.0 billion). Capital
expenditure in 2006 included our investment in Rosneft’s IPO of $1 billion.
There were no signiﬁcant acquisitions in 2006 or 2005. Acquisitions in
2004 included some $1.4 billion of additional investment in TNK-BP.
Capital expenditure in 2007 is planned to be around $13 billion. This
reﬂects our project programme, managed within the context of our
disciplined approach to capital investment and taking into account sector-
speciﬁc inﬂation.

Development expenditure incurred in 2006, excluding midstream
activities, was $9,109 million, compared with $7,678 million in 2005 and
$7,270 million in 2004. This increase reﬂects the investment we have
been making in our new proﬁt centres and the development phase of
many of our major projects.

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

Our exploration and appraisal costs in 2006 were $1,765 million,

compared with $1,266 million in 2005 and $1,039 million in 2004. 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. About 41%
of 2006 exploration and appraisal costs were directed towards appraisal
activity. In 2006, we participated in 85 gross (37 net) exploration and
appraisal wells in 14 countries. The principal areas of activity were
deepwater Gulf of Mexico, Angola, Egypt, the UK North Sea, Trinidad and
Russia (outside TNK-BP).

Total exploration expense in 2006 of $1,045 million (2005 $684 million

and 2004 $637 million) included the write-off of unsuccessful drilling
activity in the deepwater Gulf of Mexico ($343 million), in Trinidad
($85 million), in Turkey ($80 million), onshore North America ($44 million)
and others ($16 million).

In 2006, we obtained upstream rights in several new tracts, which

include the following:
– In the Gulf of Mexico, we were awarded 101 blocks (BP 100%)
through the Outer Continental Shelf Lease Sales 198 and 200.
– In India, we were awarded (BP 100%) the Coal Bed Methane block
BB-CBM-2005/III located in the Birbhum district of West Bengal.

– In Pakistan, we were awarded three new blocks (BP 100%), covering

approximately 20,000 km2 of the offshore Indus delta.
In early 2007:

– In Oman, we signed a production-sharing agreement to appraise and

develop the Khazzan/Makarem gas ﬁelds.
In 2006, we were involved in a number of discoveries. In most cases,
reserves bookings from these ﬁelds will depend on the results of ongoing

technical and commercial evaluations, including appraisal drilling. Our
most signiﬁcant discoveries in 2006 included the following:
– In Angola, we made further discoveries in the ‘ultra deepwater’

(greater than 1,500 metres) in Block 31 (BP 26.7% and operator) with
Urano, Titania and Terra wells, bringing the total number of discoveries
in Block 31 to 12.

– In the deepwater Gulf of Mexico, we made a discovery with the

Kaskida well.

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

Resources in a ﬁeld will only be categorized as proved reserves when

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

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

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

The ﬁrst element is the accountabilities of certain ofﬁcers of the
company to ensure that there are effective controls in the proved
reserves veriﬁcation and approval process of the group’s reserves
estimates and the timely reporting of the related ﬁnancial impacts of
proved reserves changes. These ofﬁcers of the company are responsible
for carrying out veriﬁcation of proved reserves estimates and are
independent of the operating business unit to ensure integrity and
accuracy of reporting.

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

The third element is Internal Audit, whose role includes systematically

examining the effectiveness of the group’s ﬁnancial controls designed
to assure the reliability of reporting and safeguarding of assets and
examining the group’s compliance with laws, regulations and internal
standards.

reserves base undergoes central review every two years and more than
90% is reviewed every four years.

For the executive directors and senior management, no speciﬁc portion

of compensation bonuses is directly related to oil and gas reserves
targets. Additions to proved reserves is one of several indicators by which
the performance of the Exploration and Production business segment
is assessed by the remuneration committee for the purposes of
determining compensation bonuses for the executive directors and senior
management. 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 business segment is based on individual
performance contracts. Individual performance contracts are based on
agreed items from the business performance plan, one of which, if they
choose, could relate to oil and gas reserves.

Details of our net proved reserves of crude oil, condensate, natural
gas liquids and natural gas at 31 December 2006, 2005 and 2004 and
reserves changes for each of the three years then ended are set out in
the Supplementary information on oil and natural gas section beginning on
page 196. We separately disclose our share of reserves held in equity-
accounted companies (jointly controlled entities and associates), although
we do not control these entities or the assets held by such entities.

All the group’s oil and gas reserves held in consolidated companies

have been estimated by the group’s petroleum engineers. Of the
equity-accounted volumes in 2006, 17% were based on estimates
prepared by group petroleum engineers and 83% were based on
estimates prepared by independent engineering consultants, although
all the group’s oil and gas reserves held in equity-accounted companies
are reviewed by the group’s petroleum engineers before making the
assessment of volumes to be booked by BP.

Our proved reserves are associated with both concessions (tax and

royalty arrangements) and production-sharing agreements (PSAs). In
a concession, the consortium of which we are a part is entitled to the
reserves that can be produced over the licence period, which may be the
life of the ﬁeld. In a PSA, we are entitled to recover volumes that equate
to costs incurred to develop and produce the reserves and an agreed
share of the remaining volumes or the economic equivalent. As part
of our entitlement is driven by the monetary amount of costs to be
recovered, price ﬂuctuations will have an impact on both production
volumes and reserves. Fifteen per cent of our proved reserves are
associated with PSAs. The main countries in which we operate under
PSAs are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam.

At the end of 2006, BP adopted the SEC rules for estimating reserves
for all accounting and reporting purposes. Previously, BP applied the UK
accounting rules contained in the Statement of Recommended Practice
‘Accounting for Oil and Gas Exploration, Development, Production and
Decommissioning Activities’ (UK SORP). These changes are explained in
Financial statements – Note 3 on page 110. The company’s proved
reserves estimates for the year ended 31 December 2006 reﬂect
year-end prices and application of SEC interpretations of SEC regulations
relating to the use of technology (mainly seismic) to estimate reserves in
the reservoir away from wellbores and the reporting of fuel gas (i.e. gas
used for fuel in operations on the lease) within proved reserves.
Consequently, these reserves quantities differ from those that would
be reported under application of the UK SORP. The 2006 year-end
marker prices used were Brent $58.93/bbl (2005 $58.21/bbl and 2004
$40.24/bbl) and Henry Hub $5.52/mmBtu (2005 $9.52/mmBtu and
2004 $6.01/mmBtu). The other 2006 movements in proved reserves
are reﬂected in the tables showing movements in oil and gas reserves
by region in Financial statements – Supplementary information on oil
and natural gas on pages 196-197.

The fourth element is a quarterly due diligence review, which is

Total hydrocarbon proved reserves, on an oil equivalent basis and

separate and independent from the operating business units, of proved
reserves associated with properties where technical, operational or
commercial issues have arisen.

The ﬁfth element is the established criteria whereby proved

reserves changes above certain thresholds require central authorization.
Furthermore, the volumes booked under these authorization levels are
reviewed on a periodic basis. The frequency of review is determined
according to ﬁeld size and ensures that more than 80% of the BP

excluding equity-accounted entities, comprised 13,163mmboe at
31 December 2006, a decrease of 6.1% compared with 31 December
2005. Natural gas represents about 55% of these reserves. This reduction
includes net sales of 227mmboe, largely comprising a number of assets
in Latin America, the UK and the US.

The proved reserves replacement ratio, excluding equity-accounted

entities, was 34% (2005 68% and 2004 78%). The proved reserves
replacement ratio (also known as the production replacement ratio) is the
extent to which production is replaced by proved reserves additions. This

BP Annual Report and Accounts 2006

17

ratio is expressed in oil equivalent terms and includes changes resulting
from revisions to previous estimates, improved recovery, extensions,
discoveries and other additions, excluding the impact of sales and
purchases of reserves-in-place and excluding reserves related to
equity-accounted entities. The proved reserves replacement ratio,
including sales and purchases of reserves-in-place but excluding
equity-accounted entities, was 11% (2005 40% and 2004 64%). By their
nature, there is always some risk involved in the ultimate development
and production of reserves, including but not limited to ﬁnal regulatory
approval, the installation of new or additional infrastructure as well as
changes in oil and gas prices and the continued availability of additional
development capital.

In 2006, net additions to the group’s proved reserves (excluding
sales and purchases of reserves-in-place and equity-accounted entities)
amounted to 329mmboe, principally through improved recovery from
existing ﬁelds. Of the reserves additions through improved recovery from,
and extensions to, existing ﬁelds and discoveries of new ﬁelds,
approximately half are associated with new projects and are proved
undeveloped reserves additions. The remainder are in existing
developments where they represent a mixture of proved developed and
proved undeveloped reserves. Major new development projects typically
take one to four years from the time of initial booking to the start of
production. The principal reserves additions were in the UK (Devenick,
Foinaven), the US (San Juan, Seminole, Great White, Horn Mountain,
Mars) and Angola (Rosa, Greater Plutonio).

Total hydrocarbon proved reserves, on an oil equivalent basis
for equity-accounted entities alone, comprised 4,537mmboe at 31
December 2006, an increase of 17.2% compared with 31 December
2005. Natural gas represents about 14% of these reserves. The proved
reserves replacement ratio for equity-accounted entities alone was 272%
(2005 151% and 2004 114%) and the proved reserves replacement ratio
for equity-accounted entities alone but including sales and purchases of
reserves-in-place was 239% (2005 141% and 2004 170%).

Additions to proved developed reserves in 2006 for subsidiaries were
675mmboe, including sales and purchases. This included some reserves
that were previously classiﬁed as proved undeveloped. The proved

developed reserves replacement ratio (including both sales and purchases
of reserves-in-place) was 70% (2005 63% and 2004 70%).

Additions to proved developed reserves in 2006 for equity-accounted

entities were 936mmboe. This included some reserves that were
previously classiﬁed as proved undeveloped. The proved developed
reserves replacement ratio (including both sales and purchases of
reserves-in-place) was 195% (2005 99% and 2004 180%).

Our total hydrocarbon production during 2006 averaged 2,629 thousand
barrels of oil equivalent per day (mboe/d) for subsidiaries and 1,297mboe/d
for equity-accounted entities, a decrease of 3.3% and an increase of 0.1%
respectively compared with 2005. For subsidiaries, 36% of our production
was in the US and 16% in the UK. For equity-accounted entities, 75% of
production was from TNK-BP.

Total production for 2007 is expected to remain broadly the same as

in 2006 after allowing for the impact on 2007 of divestments made in
2006. This estimate is based on the group’s asset portfolio at 1 January
2007, expected start-ups in 2007 and Brent at $60/bbl, before any 2007
disposal effects and before any effects of prices above $60/bbl on
volumes in PSAs.

The anticipated decline in production volumes from subsidiaries in
our existing proﬁt centres is partly mitigated by the development of
new projects and the investment in incremental reserves in and around
existing ﬁelds. We expect that this overall decline in production from
subsidiaries in our existing proﬁt centres will be more than compensated
for by strong increases in production from subsidiaries in our new proﬁt
centres over the next few years. Production in our equity-accounted joint
venture TNK-BP is expected to remain broadly constant to 2009.

The most important determinants of cash ﬂows in relation to our oil and

natural gas production are the prices of these commodities. At constant
prices, cash ﬂows from currently developed proved reserves are expected
to decline in a manner consistent with anticipated production decline
rates. Development activities associated with recent discoveries, as well
as continued investment in these producing ﬁelds, are expected to more
than offset this decline, resulting in increased operating cash ﬂows over
the next few years. Cash ﬂows from equity-accounted entities are
expected to be in the form of dividend payments. (See Liquidity and
capital resources on page 54.)

18

The following tables show BP’s estimated net proved reserves as at 31 December 2006.

Estimated net proved reserves of liquids at 31 December 2006a b

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Developed

Undeveloped

million barrels

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Estimated net proved reserves of natural gas at 31 December 2006a b

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Developed

Undeveloped

billion cubic feet

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

458
189
1,916
130
67
193
–
88
3,041

1,968
242
10,438
3,932
1,359
1,032
–
331
19,302

146
97
1,292
237
86
512
–
482
2,852

825
56
4,660
9,194
5,202
1,675
–
1,254
22,866

Total

604
286
3,208
367c
153
705
–
570
5,893
3,888d

Total

2,793
298
15,098
13,126e
6,561
2,707
–
1,585
42,168
3,763f

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

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

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Net proved reserves on an oil equivalent basis (mmboe)
– Group
– Equity-accounted entities

13,163
4,537

a Net proved reserves of crude oil and natural gas, stated as at 31 December 2006, exclude production royalties due to others, whether payable in cash or in kind, and include
minority interests in consolidated operations. We disclose our share of reserves held in joint ventures and associates that are accounted for by the equity method although
we do not control these entities or the assets held by such entities.
b In certain deepwater fields, such as fields in the Gulf of Mexico, BP has claimed proved reserves before production flow tests are conducted, in part because of the
significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring
and delineating reservoir properties without the need for flow tests. The general method of reserves assessment to determine reasonable certainty of commercial recovery
that BP employs relies on the integration of three types of data: (1) well data used to assess the local characteristics and conditions of reservoirs and fluids; (2) field scale
seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control; and (3) data from relevant analogous
fields. Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. BP considers the integration of this data in certain cases to be
superior to a flow test in providing a better understanding of the overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures
and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be determined over a greater volume than the localized volume of
investigation associated with a short term flow test. Historically, proved reserves recorded using these methods have been validated by actual production levels. As at the
end of 2006, BP had proved reserves in 22 fields in the deepwater Gulf of Mexico that had been initially booked prior to production flow testing. Of these fields, 18 have
been in production and two, Atlantis and Thunder Horse, are expected to begin production by the end of 2007 and by the end of 2008 respectively. Two other fields are in the
early stages of development.
c Includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 179 million barrels of crude oil in respect of the 6.29% minority interest in TNK-BP.
e Includes 3,537 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
f Includes 99 billion cubic feet of natural gas in respect of the 7.77% minority interest in TNK-BP.

BP Annual Report and Accounts 2006

19

The following tables show BP’s production by major ﬁeld for 2006, 2005 and 2004.

Liquids

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

%

thousand barrels per day

BP net share of productiona

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Field or Area
Production
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Prudhoe Bayb
Alaska
Kuparuk
Northstarb
Milne Pointb
Other

26.4
39.2
98.6
100.0
Various

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

71
57
38
31
27

Interest

2004

2006

2005

Total Alaska
Lower 48 onshorec
Gulf of Mexico deepwaterc

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Various
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Na Kikab
Horn Mountainb
Kingb
Mars
Ursa
Other
Other

Various
50.0
66.6
100.0
28.5
22.7
Various
Various

41
23
28
19
21
63
3

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

125

224

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

ETAPd
Foinavenb
Magnusb
Schiehallion/Loyalb
Hardingb
Andrewb
Other

Wytch Farmb

Various
Valhallb
Draugen
Ulab
Other

Various
Various
85.0
Various
70.0
62.8
Various

67.8

Various
28.1
18.4
80.0
Various

Gulf of Mexico Shelfc
Total Gulf of Mexico
Total USA
UK offshorec

Total UK offshore
Onshore
Total UK
Netherlands
Norway

Total Rest of Europe
Angola

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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Kizomba A
Girassol
Xikomba
Other
Various
Azeri-Chirag-Gunashlib
Various
Variousb
Various
Variousb
Various
Various
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

26.7
16.7
26.7
Various
15.8
34.1
Various
Various
Various
100.0
Various
Various

54
17
4
58
34
145
8
34
42
40
26
28

Various
Various
Various
Various
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Various
Various
Various
Various

163
69
876
16

a Net of royalty, whether payable in cash or in kind.
b BP-operated.
c In 2006, BP divested its producing properties on the Outer Continental Shelf of the Gulf of Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in
the Boqueron, Desarollo Zulia Occidental (DZO) and Jusepin projects in Venezuela were reduced following a decision by the Venezuelan government. TNK-BP disposed of its
non-core interests in the Urdmurtneft assets. In 2005, BP divested the Teak, Samaan and Poui assets in Trinidad and sold interests in certain properties in the Gulf of Mexico.
In addition, BP exchanged the Gulf of Mexico deepwater Blind Faith prospect for Kerr McGee’s interest in the Arkoma Red Oak and Williburton fields. TNK-BP disposed of
non-core producing assets in the Saratov region. In 2004, BP agreed with AAR to incorporate their 50% interest in Slavneft into TNK-BP, an equity-accounted entity. BP also
acquired minor additional working interests in Canada and the US. BP diluted its working interests in King’s Peak and divested the Swordfish assets in the deepwater Gulf
of Mexico. Additionally, BP sold various properties including its interest in the South Pass 60 in the Gulf of Mexico Shelf, various assets in Alberta, Canada and the Kangean
PSA in Indonesia.
d Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields which are operated by Shell.
e Includes 55 thousand net barrels of oil equivalent per day (mboe/d) of NGLs from processing plants in which BP has an interest (2005 58mboe/d and 2004 67mboe/d).
f The BP group holds proportionate interests, through associates, in onshore and offshore concessions in Abu Dhabi expiring in 2014 and 2018, respectively.

20

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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-
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-
-
-
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-
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-
-
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-
-
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-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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-
-
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-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

198

547

49
37
30
26
17
7
69

235

18

253

1
21
15
14
10

61

490

1,351

1,124

89
62
46
37
34
268
130
44
26
24
21
19
64
16
214
612
49
39
30
28
22
12
75
255
22
277
1
25
20
17
12
75
56
34
10
28
36
76
10
41
47
40
55
26
459
1,423

148
67
911
13
1,139

97
68
49
44
37
295
142
27
41
26
35
29
47
24
229
666
55
48
34
39
27
12
89
304
26
330
1
25
27
16
8
77
16
31
18
6
36
39
11
48
57
59
55
31
407
1,480

142
64
831
14
1,051

50.0
78.2
Various
Various

Various
37.0
100.0
62.0
9.0
27.5
18.2
Various

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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-
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-
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-
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-
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-
-
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-
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-
-
-
-
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-
-

1,920

2,376

97
16
210
66

389

101
107
56
42
42
31
28
529

936

91

4,009

7,412

1,005

753
198
151
111
110
97
465
1,885
133
52
235
160
580
81
2,546
165
161
55
47
46
37
30
549
1,090
25
37
46
108
367
307
98
106
83
110
128
113
10
1,005
303
289
154
132
83
21
459
3,768
7,512

343
482
87
912

772
183
158
96
105
114
514
1,942
133
43
313
240
729
78
2,749
147
163
67
70
54
76
50
547
1,174
34
46
45
125
308
349
99
80
115
137
144
103
14
553
453
408
137
172
85
111
308
3,576
7,624

317
458
104
879

Natural gas

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

%

million cubic feet per day

BP net share of productiona

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Field or Area
Production
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
San Juanc
Lower 48 onshoreb
Arkomac
Hugotonc
Tuscaloosac
Wamsutterc
Jonahc
Other

Various
Various
Various
Various
70.5
65.0
Various

765
225
137
86
113
133
461

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Interest

2005

2006

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Various
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Various

67

Total Lower 48 onshore
Gulf of Mexico deepwaterb

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

Na Kikac
Marlinc
Other
Other

Braesd
Brucec
West Solec
Marnockc
Britannia
Shearwater
Armada
Other

Total UK
Netherlands

Norway
Total Rest of Europe
Australia
Canadab
China
Egypt

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

P/18-2c
Other
Various
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

48.7
Various
Various

23
33
35

Sharjah

Indonesiab

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

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

364
282
102
99
172
84
80
111
9
946
321
176
120
219
30
453
441

Trinidad & Tobagob

Otherb
Total Rest of World
Total groupe
Equity-accounted entities (BP share)
Argentina – Pan American Energy
Russia – TNK-BPb
Otherb
Total equity-accounted entitiesb

Various
Various
Various
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Various
Various
Various

362
544
99

a Net of royalty, whether payable in cash or in kind.
b In 2006, BP divested its producing properties on the Outer Continental Shelf of the Gulf of Mexico and its interest in the Statfjord oil and gas field in the UK. Our interests in
the Boqueron, Desarollo Zulia Occidental (DZO) and Jusepin projects in Venezuela were reduced following a decision by the Venezuelan government. TNK-BP disposed of its
non-core interests in the Urdmurtneft assets. In 2005, BP divested the Teak, Samaan and Poui assets in Trinidad and sold interests in certain properties in the Gulf of Mexico.
In addition, BP exchanged the Gulf of Mexico deepwater Blind Faith prospect for Kerr McGee’s interest in the Arkoma Red Oak and Williburton fields. TNK-BP disposed of
non-core producing assets in the Saratov region. In 2004, BP agreed with AAR to incorporate their 50% interest in Slavneft into TNK-BP, an equity-accounted entity. BP also
acquired minor additional working interests in Canada and the US. BP diluted its working interests in King’s Peak and divested the Swordfish assets in the deepwater Gulf
of Mexico. Additionally, BP sold various properties including its interest in the South Pass 60 in the Gulf of Mexico Shelf, various assets in Alberta, Canada and the Kangean
PSA in Indonesia.
c BP-operated.
d Includes 4 million and 7 million cubic feet a day of natural gas received as in-kind tariff payments in 2005 and 2004 respectively.
e 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 2006

21

United States
2006 liquids production at 547 thousand barrels per day (mb/d) decreased
11% from 2005, while natural gas production at 2,376 million cubic feet
per day (mmcf/d) decreased 7% compared with 2005.

fracturing techniques, we are achieving well rates up to 10 times
higher than more conventional techniques and per-well recoveries
some ﬁve times higher.
Signiﬁcant events were:

Crude oil production decreased 63mb/d from 2005, with production

– Drilling continued during 2006 on the Wamsutter natural gas expansion

from new projects being offset by divestments and natural reservoir
decline. The NGLs component of liquids production remained essentially
ﬂat compared with 2005, with a slight decline of 2mb/d. Gas production
was lower (170mmcf/d) because of divestments and natural reservoir
decline.

Development expenditure in the US (excluding midstream) during
2006 was $3,579 million, compared with $2,965 million in 2005 and
$3,247 million in 2004. The annual increase is the result of various
development projects in progress.

project. The multi-year drilling programme is expected to increase
production signiﬁcantly by the end of 2010. We are currently testing
horizontal fracturing technology and carrying out wireless seismic
studies on the reservoir.

– In January 2007, we announced our investment of up to $2.4 billion
over the next 13 years in the Coal Bed Methane Field development
project in the San Juan Basin of Colorado. The project includes the
drilling of more than 700 wells, nearly all from existing well sites, and
the installation of associated ﬁeld facilities.

On 19 April 2006, BP announced the sale of its producing properties on

– In October 2006, we completed the sale of ﬁve onshore properties in

the Outer Continental Shelf of the Gulf of Mexico to Apache Corporation
for $1.3 billion. The major part of the sale was completed in June 2006
after receiving regulatory approval. In the third quarter of 2006, we
completed the sale of our remaining Gulf of Mexico Shelf assets that
were subject to pre-emption rights. BP retained certain decommissioning
obligations related to the disposed assets.

South Louisiana to Swift Energy for approximately $160 million.

Alaska
In Alaska, BP net crude oil production in 2006 was 224mb/d, a decrease
of 16% from 2005, due to mature ﬁeld decline and operational issues
associated with transit pipelines described below.

Our activities within the US take place in three main areas. Signiﬁcant

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

events during 2006 within each of these are indicated below.

Deepwater Gulf of Mexico
Deepwater Gulf of Mexico is one of our new proﬁt centres and our largest
area of growth in the US. In 2006, our deepwater Gulf of Mexico crude oil
production was 195mb/d and gas production was 323mmcf/d.

and Milne Point) and four North Slope pipelines and owns a signiﬁcant
interest in six other producing ﬁelds. Our 26.4% interest in the Prudhoe
Bay natural gas resource is a large undeveloped source of natural gas.

Developing viscous oil is an important part of the Alaska business. We
are continually looking to develop viscous oil production in various ﬁelds
through the application of advanced technology.

Signiﬁcant events were:

Signiﬁcant events were:

– Offshore repair work on the Thunder Horse platform (BP 75% and
operator) was completed during 2006. However, tests conducted
during the commissioning of the platform revealed metallurgical
failure in components of the subsea system. In September 2006, we
announced our plan to retrieve and replace all the subsea components
we believed could be at risk. We currently estimate that this will cost
around $650 million (BP net). Production is expected to start up by the
end of 2008.

– The Mars platform (BP 28.5%) suffered heavy damage from Hurricane
Katrina in August 2005. Production resumed in May 2006 and was
190mboe/d gross by September 2006, a 20% increase over pre-
Katrina rates.

– Expansion of the Mars and Na Kika ﬁelds also continued during 2006

and ﬁrst production from these projects is expected in 2007.
– Progress continued on the Atlantis project (BP 56% and operator)
during 2006. The semi-submersible platform will be the deepest
moored ﬂoating production facility in the world in approximately
7,100 feet of water. First oil is expected by the end of 2007.
– On 31 August 2006, we announced a signiﬁcant oil exploration

discovery on the Kaskida prospect in approximately 5,900 feet of water.

– Development of the King Subsea Pump project (BP 100% and

operator) continued during 2006, with ﬁrst production expected by the
end of 2007. This is the ﬁrst subsea multi-phase pump application in
water depths greater than 3,000 feet.

– In July 2006, we completed the sale of our 28% interest in the Shenzi

discovery to Repsol for $2,145 million.

Lower 48 states
In the Lower 48 states (Onshore), our 2006 natural gas production was
1,920mmcf/d, which was up 2% compared with 2005. Liquids production
was 125mb/d, down 4% compared with 2005 as a result of normal ﬁeld
decline. In 2006, we drilled approximately 330 wells as operator and
continued to maintain a level programme of drilling activity throughout
the year.

Production is derived primarily from two main areas:

– In the Western Basins (Colorado, New Mexico and Wyoming), our

assets produced 218mboe/d in 2006.

– In the Gulf Coast and Mid-Continental basins (Kansas, Louisiana,
Oklahoma and Texas), our assets produced 183mboe/d in 2006.

– The development of recovery technology continues to be a

fundamental strategy in accessing our North America tight gas
resources. Through the use of horizontal drilling and advanced hydraulic

– BP, along with ExxonMobil, ConocoPhillips and the Executive Branch
of the State of Alaska, reached agreement on a gas pipeline ﬁscal
contract. Two special sessions of the legislature called by the former
governor ended without legislative ratiﬁcation of the contract. The
change of governor, which took place in December 2006, has
temporarily delayed continued negotiations with the State of Alaska
until a clear process leading to ratiﬁcation of the gas pipeline ﬁscal
contract is deﬁned by the new administration. BP stands ready to
execute a modiﬁed ﬁscal contract that is agreeable to all the parties.

– The State of Alaska signiﬁcantly increased production taxes by

adopting a new Petroleum Production Tax (PPT) bill on 19 August
2006, effective from 1 April 2006. The key terms of the PPT include a
22.5% oil tax rate with capital credits and a clause whereby the oil tax
rate increases as the net margin rises above $40/bbl.

– On 27 November 2006, the State of Alaska Department of Natural

Resources (DNR) issued a decision regarding the Plan of Development
(POD) submitted by ExxonMobil on behalf of the Point Thompson Unit
owners (BP 32%) on 18 October 2006. The DNR decision was to reject
the modiﬁed POD, deny the proposed settlement of the expansion
lease acreage and terminate the Point Thompson Unit. BP, along with
the other owners, is studying options available in response to this
decision. BP intends to pursue vigorously the retention of its interest in
the Point Thompson Unit and remains committed to its development in
conjunction with our broader gas strategy and the proposal to construct
a gas pipeline from Alaska, through Canada, to the Midwest US.

– Alaska viscous and heavy oil assets produced their 100 millionth barrel
(gross) in November 2006. West Sak 1J Phase 1 viscous project has
drilled more than half the planned 31 development wells, Milne Point
is planning the NW Schrader Bluff winter appraisal programme and
the Orion Phase II sanction in Prudhoe Bay is expected in the ﬁrst
quarter of 2007. Orion Phase II completes GC-2 viscous oil facility
modiﬁcations and develops eight additional producer wells and 22
injector wells; ﬁrst oil is planned for 2009.

– On 2 March 2006, a transit pipeline in the Western operating area of
the Prudhoe Bay ﬁeld was discovered to have spilled approximately
4,800 barrels of crude oil over approximately two acres. The processing
facility that feeds into the transit line was immediately shut down. An
investigation team determined that the leak was caused by internal
corrosion. Spill clean-up was completed and business operations
resumed in April 2006 using a separate bypass line. (See also
Environmental Protection – Health, Safety and Environmental
Regulation on page 42.)

22

– On 7 August 2006, an orderly and phased shutdown of the Eastern
Operating Area of the Prudhoe Bay oil ﬁeld began following the
discovery of unexpected corrosion and a small spill from a Prudhoe
Bay oil transit line. In September, we determined that the oil
transit lines in the Eastern Operating Area of Prudhoe Bay could be
returned to service for the purposes of in-line inspection. By the end of
October we had returned to service all three ﬂow stations previously
shut down.

– Current production from Prudhoe Bay is more than 400,000 barrels of
oil and natural gas liquids per day (gross). BP has a 26.4% interest in
the Prudhoe Bay ﬁeld.

– In response to the recent corrosion discoveries, BP has decided to
replace the main oil transit lines (16 miles) in both the Eastern and
Western Operating Areas of Prudhoe Bay. In addition, BP plans to
spend over $550 million (net) over the next two years on integrity
management in Alaska. BP has retained three eminent corrosion
experts to evaluate independently and make recommendations for
improving the corrosion programme in Alaska. BP has also asked an
independent ombudsman to undertake a review of worker allegations
raised on the North Slope of Alaska since the acquisition of ARCO
in 2000 to determine whether the problems have been addressed
and rectiﬁed.

– In February 2007, BP temporarily shut down its Northstar production
facility to repair welds in the low pressure gas piping system. BP is
currently ﬁnalising inspections and has begun repairs.

United Kingdom
We are the largest producer of oil and second largest producer of gas in
the UK. BP remains the largest overall producer of hydrocarbons in the
UK. In 2006, total liquids production was 253mb/d, a 9% decrease on
2005, and gas production was 936mmcf/d, a 14% decrease on 2005. This
decrease in production was driven by the natural decline, operational
issues and lower seasonal gas demand. Our activities in the North Sea
are focused on safe operations, efﬁcient delivery of production
and midstream operations, in-ﬁeld drilling and selected new ﬁeld
developments. Our development expenditure (excluding
midstream) in the UK was $794 million in 2006, compared with $790
million in 2005 and $679 million in 2004.

Signiﬁcant events were:

– Drilling continued during 2006 on the Clair Phase 1 development (BP

28.6% and operator) programme and is scheduled to continue through
2008.

– In September 2006, BP reached an agreement, subject to Department
of Trade and Industry (DTI) approval, to acquire acreage in the UK
Central North Sea that contains two discovered ﬁelds and further
exploration potential.

– BP and its partner approved the front end engineering and design for
the Harding Area Gas Project (BP 70% and operator) in July 2006.
This represents the ﬁrst stage of a development project to allow the
production of gas from the Harding area and prolong the life of the ﬁeld
beyond 2015.

– Progress continued during the year on the Magnus Expansion Project

(BP 85% and operator), with ﬁrst oil achieved in October 2006.

– The UK government approved the North West Hutton

decommissioning programme in April 2006. BP, on behalf of the
owners of North West Hutton (BP 26% and operator), awarded a
contract in October 2006 for the offshore removal and onshore
recycling of the installation. Detailed engineering work for removal
has begun. Platform removal is expected to start in 2008 and to be
completed by the end of 2009.

– In December 2005, the UK government announced a 10%

supplemental tax increase on North Sea oil proﬁts, taking the total
corporate tax rate to 50%. This tax increase became law in July 2006,
with effect from 1 January 2006.

– In March 2006, we reached agreement for the sale of our 4.84%
interest in the Statfjord oil and gas ﬁeld. This sale was completed
in June 2006.

Rest of Europe
Development expenditure, excluding midstream, in the Rest of Europe
was $214 million, compared with $188 million in 2005 and $262 million
in 2004.

Norway
In 2006, our total production in Norway was 66mboe/d, a 20% decrease
on 2005. This decrease in production was driven by natural decline.

Signiﬁcant activities were:

– Progress on the Valhall (BP 28.1% and operator) redevelopment

project continued during 2006. A new platform is scheduled to become
operational in 2010, with expected oil production capacity of 150mb/d
and gas handling capacity of 175mmcf/d.

– Drilling continued through 2006 on the Valhall ﬂank development
and water injection projects. The ﬂank drilling programme was
completed in September 2006 and water injection drilling will continue
during 2007.

– In March 2006, we reached agreement for the sale of our interest in
the Luva gas discovery, in the North Sea. This sale was completed in
the second quarter of 2006.

Netherlands
In May 2006, we announced our intention to sell our exploration and
production and gas infrastructure business in the Netherlands. This
includes onshore and offshore production assets and the onshore gas
supply facility, Piek Gas Installatie, at Alkmaar. The sale was completed
on 1 February 2007 to the Abu Dhabi National Energy Company, TAQA.

Rest of World
Development expenditure, excluding midstream, in Rest of World
was $4,522 million in 2006, compared with $3,735 million in 2005
and $3,082 million in 2004.

Rest of Americas
Canada
– In Canada, our natural gas and liquids production was 57mboe/d in
2006, a decrease of 10% compared with 2005. The year-on-year
decrease in production is mainly due to natural ﬁeld decline.

– BP has been successful in obtaining new licences in British Columbia
and Alberta land sales. The acquired acreage will form part of the Noel
tight gas development project in north-eastern British Columbia. The
project will involve drilling up to 180 horizontal wells and innovative
fracturing technology to develop the remainder of the resources.

Trinidad
– In Trinidad, natural gas production volumes increased by 14% to

2,265mmcf/d in 2006. The increase was driven by higher demand due
to the ramp-up of Atlantic LNG Train 4. Liquids production declined by
2mb/d (5%) to 38mb/d in 2006.

– Cannonball (BP 100%), Trinidad’s ﬁrst major offshore construction

project executed locally, started production in March 2006. Production
increased during the year and the asset is currently providing gas for
the Atlantic LNG trains.

– BP sanctioned the development projects for Red Mango (BP 100%) in
April 2006 and for Cashima (BP 100%) in August 2006. First production
is expected by the end of 2007 and in 2008 respectively.

Venezuela
– In Venezuela, our 2006 liquids production reduced by 25mb/d

compared with 2005, mainly as a result of the enforced reduction of our
interests in the non-BP-operated Jusepin property and the Boqueron
and Desarollo Zulia Occidental (DZO) reactivation projects, which BP
operated until 31 March 2006 under operating service agreements on
behalf of the state oil company, Petroleos de Venezuela S.A. (PDVSA).
– In August 2006, BP signed conversion agreements to co-operate with

PDVSA in setting up incorporated joint ventures in which PDVSA would
be the majority shareholder. The structures for the incorporated joint
ventures were established in December 2006 and these are now the
operators of the Boqueron and DZO properties.

BP Annual Report and Accounts 2006

23

– In December 2006, BP, in common with the other partners in the

Jusepin property, reached agreement with PDVSA for compensation
in return for the relinquishment of our interest in the property.

December 2006. Development on the Rosa project, a tie-back to the
Girassol hub, continued, with ﬁrst production expected by the end
of 2007.

– Cerro Negro is a non-BP-operated property that is a heavy oil project

– In Block 18 (BP 50% and operator), work has continued on the Greater

from which production is sold directly by BP. The Venezuelan
government has communicated its intention of converting this strategic
association to an incorporated joint venture. It is too early to determine
the effect of this.

– In 2005, changes were made by the Venezuelan government to
increase corporate income taxes from 34% to 50% on those
companies operating under operating service agreements. Changes
were also made in 2006 to the taxation of oil extraction companies,
such as Cerro Negro. From 1 June 2006, a new extraction tax at a
maximum rate of 33.33% was introduced (the existing royalty of
16.67% can be offset against the new extraction tax) and, on
25 September 2006, the corporate income tax rate was raised from
34% to 50% with effect from 1 January 2007.

Colombia
– In Colombia, BP’s net production averaged 50mboe/d. The main part of
the production comes from the Cusiana, Cupiagua and Cupiagua South
Fields, with increasing new production from the Cupiagua extension
into the Recetor Association Contract and the Floren˜ a and Pauto ﬁelds
in the Piedemonte Association Contract. In March 2006, cumulative
production from the BP-operated ﬁelds reached 1 billion barrels gross
since operations began in 1992.

– In December 2006, the corporate income tax rate was reduced from

its current rate of 35% to 34% from 1 January 2007 and to 33% from
1 January 2008.

Argentina and Bolivia
– In Argentina and Bolivia, activity is conducted through Pan American

Energy (PAE), in which BP holds a 60% interest, and which is
accounted for by the equity method since it is jointly controlled. In
2006, total production of 145mboe/d represented an increase of 7%
over 2005, with oil increasing by 4% and gas by 10%. The main
increase in oil production came from the continued focus on drilling and
waterﬂoods in Golfo San Jorge in Argentina, where oil production was
60mb/d, compared with 58mb/d in 2005. The ﬁeld is now producing
at its highest level since inception in 1958 and further expansion
programmes are planned. PAE also has interests in gas pipelines,
electricity generation plants and other midstream infrastructure assets.

– In November 2006, PAE and all other oil and gas companies with

operations in Bolivia entered into agreements with the state-owned
oil company Yacimientos Petrolı´feros Fiscales Bolivianos (YPFB) that
establish governmental control over the country’s hydrocarbon
resources. The agreements have been approved by the Bolivian
Congress. YPFB will be responsible for marketing all hydrocarbons
produced in Bolivia and for determining the terms of sales contracts.

Africa
Algeria
– BP, through its joint operatorship of In Salah Gas with Statoil and the
Algerian state company, Sonatrach, supplied 300bcf (gross) of gas
to markets in Algeria and southern Europe during 2006. The carbon
dioxide (CO2) capture system, part of the In Salah project (BP 33.15%),
is one of the world’s largest CO2 capture projects.

– BP, through its joint operatorship of In Amenas with Statoil and

Sonatrach, completed the development of the In Amenas project
(BP 12.5%). First production was achieved in June 2006.

– From 1 August 2006, a windfall proﬁt tax was announced that applies
to certain producers when the monthly average price of a barrel of oil
exceeds $30. At present, the only asset of BP affected by this is the
In Amenas project.

Angola
– In Block 15 (BP 26.7%), development of Kizomba C commenced in the
ﬁrst quarter of 2006. Development of Kizomba A Phase II continued,
with ﬁrst production planned for the end of 2007.

– In Block 17 (BP 16.7%), development activities were completed and

the FPSO moored on the Dalia project. First production commenced in

24

Plutonio development in line with expectations to commence
production by the end of 2007.

– In Block 31 (BP 26.7% and operator), three additional discoveries were
made in 2006. There have been a total of 12 discoveries that are at
various stages of assessment of commercial viability.

– We are participating in the Angola LNG project (BP 13.6%).

Egypt
– In Egypt, the Gulf of Suez Petroleum Company (GUPCO) (BP 50%), a

joint venture operating company between BP and the Egyptian General
Petroleum Corporation, carries out our operated oil and gas production
operations. GUPCO operates eight PSAs in the Gulf of Suez and
Western Desert and one PSA in the Mediterranean Sea, encompassing
more than 40 ﬁelds.

– The Temsah redevelopment project was completed and production

achieved in the second quarter of 2006.

– Progress continued on the Saqqara ﬁeld (BP 100%) development
project, with ﬁrst production expected in the ﬁrst quarter of 2008.
– In June 2006, the Egyptian Natural Gas Holding Corporation (EGAS),
BP, SEGAS and Eni signed a framework agreement marking a major
step forward for the development of the second liqueﬁed natural
gas (LNG) export train at the Damietta site on the Egyptian
Mediterranean coast.

Asia Paciﬁc
Indonesia
– BP produces crude oil and supplies natural gas to the island of Java

through its holding in the Offshore Northwest Java Production Sharing
Agreement (BP 46%).

– During 2006, progress continued on the Tangguh LNG project (BP
37.2% and operator). The project development includes offshore
platforms, pipelines and an LNG plant with two production trains.
First LNG is expected by the end of 2008.

Vietnam
– BP participates in the country’s largest project with foreign investment,

the Nam Con Son gas project. This is an integrated resource and
infrastructure project, including offshore gas production, pipeline
transportation system and power plant. In 2006, natural gas production
was 392mmcf/d gross, an increase of 13% over 2005. This increase
was mainly due to higher demand resulting from continuing growth
in the economy. Gas sales from Block 6.1 (BP 35% and operator) are
made under a long-term agreement for electricity generation in
Vietnam, including the Phu My Phase 3 power plant (BP 33.33%).

China
– The Yacheng offshore gas ﬁeld (BP 34.3%) supplies, under a long-term
contract, 100% of the natural gas requirement of Castle Peak Power
Company, which provides around 50% of Hong Kong’s electricity.
Some natural gas is also piped to Hainan Island, where it is sold
to the Fuel and Chemical Company of Hainan, also under a long-
term contract.

Australia
– We are one of six equal partners in the North West Shelf (NWS)

venture. Each partner holds a 16.7% interest in the infrastructure and
oil reserves and a 15.8% interest in the gas reserves and condensate.
The operation covers offshore production platforms, a ﬂoating
production and storage vessel, trunklines and onshore gas processing
plants. The NWS Venture is currently the principal supplier to the
domestic market in Western Australia. During 2006, progress
continued on the construction of a ﬁfth LNG train (4.7 million tonnes
a year design capacity), with ﬁrst throughput expected in 2008.

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

Other
– In July 2006, BP purchased 9.6% of the shares issued in Rosneft’s IPO
for $1 billion. This represents an interest of around 1.4% in Rosneft.

Access-Renova (AAR) (50%), is an integrated oil company operating in
Russia and the Ukraine. The TNK-BP group’s major assets are held in
OAO TNK-BP Holding. Other assets include the BP-branded retail sites
in Moscow and the Moscow region, OAO Rusia Petroleum and the
OAO Slavneft group. The workforce is about 70,000 people.

– BP’s investment in TNK-BP is held by the Exploration and Production

business and the results of TNK-BP are accounted for under the equity
method in this segment.

– TNK-BP has proved reserves of 6.1 billion boe (including its 49.9%

equity share of Slavneft), of which 4.8 billion are developed. In 2006,
average liquids production was 1.9mmboe/d, a decrease of just over
2% compared with 2005, reﬂecting the disposal of the Urdmurt and
Saratov assets in 2006 and 2005. The production base is largely
centred in West Siberia (Samotlor, Nyagan and Megion), which
contributes about 1.4mmboe/d, together with Volga Urals (Orenburg)
contributing some 0.4mmboe/d. About 50% of total oil production is
currently exported as crude oil and 20% as reﬁned product.

– Downstream, TNK-BP owns ﬁve reﬁneries in Russia and the Ukraine

(including Ryazan and Lisichansk), with throughput of 0.6 million barrels
a day (28 million tonnes a year). In retail, TNK-BP operates more than
1,600 ﬁlling stations in Russia and the Ukraine, with a share of the
Moscow retail market in excess of 20%.

– During 2006, four of TNK-BP’s licences were extended by 25 years,

including two key licences covering the Samotlor ﬁeld and the
Khokhryakovskoye and Permyakovskoye licences.

– In October, TNK-BP’s subsidiary Rusia Petroleum received a letter from
the Russian authorities alleging a number of violations of the conditions
related to a licence covering part of the Kovykta ﬁeld in East Siberia.
In February 2007, the status of the licence was reviewed by the
authorities, who we anticipate will issue formal ﬁndings shortly. Rusia
Petroleum continues to discuss this matter with the authorities in order
to address any outstanding concerns.

– In November, following a review of the results of an inspection by
the licensing authorities, regional prosecutors made a request for
revocation of the two licences held by TNK-BP subsidiary Rospan
International on grounds of violation of licence conditions and
applicable legislation. Following discussion with the licensing
authorities, renewal was granted of certain documents associated
with the licences for which TNK-BP had previously applied. In addition,
Rospan presented a plan to rectify the licence non-compliances,
following which the licensing authorities have granted a six-month
period to fulﬁl this plan.

– On 23 October 2006, TNK-BP received decisions from the Russian
tax authorities in relation to the tax audits of certain TNK-BP group
companies for the years 2002 and 2003, resulting in a payment by
TNK-BP of approximately $1.4 billion in settlement of these claims.
At the present time, BP believes that its provisions are adequate for
its share of any liabilities arising from these and other outstanding tax
decisions not covered by the indemnities provided by our co-venturers
in respect of historical tax liabilities related to assets contributed to the
joint venture.

– In August 2006, TNK-BP completed the sale of its interest in OAO

Udmurtneft to Sinopec.

– In January 2007, TNK-BP announced the acquisition of Occidental

Petroleum’s 50% interest in the West Siberian joint venture,
Vanyoganneft, for $485 million. The transaction is expected to close
during the ﬁrst quarter of 2007, subject to Russian regulatory
approvals. On completion of the purchase, TNK-BP will own 100%
of the Vanyoganneft asset.

Sakhalin
– BP participates in exploration activity through Elvaryneftegas (BP 49%),

an equity-accounted joint venture with Rosneft in Sakhalin, where
three discoveries have been made. Exploratory drilling continued in
2006 and preliminary work is under way to prepare for development
if commercial reserves are discovered. Further drilling is planned
during 2007.

Other
Azerbaijan
– BP, as operator of the Azerbaijan International Operating Company

(AIOC), manages and has a 34.1% interest in the Azeri-Chirag-Gunashli
(ACG) oil ﬁelds in the Caspian Sea, offshore Azerbaijan. Phase 2 of
the Azeri project delivered ﬁrst oil from the West Azeri platform to
Sangachal terminal on 3 January 2006 and was completed on
21 October 2006 with the delivery of ﬁrst oil from the East Azeri
platform to Sangachal, four months ahead of schedule. Phase 3 of the
project, which will develop the deepwater Gunashli area of ACG,
remains on schedule to begin production in 2008.

– Construction and the Stage 1 pre-drill programme of the project to

develop the Shah Deniz natural gas ﬁeld (BP 25.5% and operator) were
completed in 2006, with ﬁrst gas in December 2006.

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 14.7% in onshore and offshore concessions
respectively. In 2006, production in Abu Dhabi was 164mb/d, up 11%
from 2005 as a result of capacity enhancements.

– In Pakistan, BP is one of the leading foreign operators, producing 22%
of the country’s oil and 6% of its natural gas on a gross basis in 2006.

– In July 2006, BP was awarded three offshore blocks in Pakistan’s
offshore Indus Delta. The blocks cover an area of approximately
20,000km2 and include the right to operate any commercially
viable discoveries.

– In January 2007, we were awarded development rights to the Khazzan/
Makarem ﬁelds in Oman. These provide access to a signiﬁcant volume
of tight gas resource in place, which we believe can be developed
using the same technology as we are currently deploying at our
Wamsutter ﬁeld in the US.

India
– In November 2006, BP signed a PSA with the Indian government to

explore for coal bed methane in the Birbhun district of India’s eastern
West Bengal state.

Midstream activities
Oil and natural gas transportation
The group has direct or indirect interests in certain crude oil transportation
systems, the principal ones being the Trans Alaska Pipeline System
(TAPS) in the US and the Forties Pipelines System (FPS) in the UK sector
of the North Sea. We also operate the Central Area Transmission System
(CATS) for natural gas in the UK sector of the North Sea.

BP, as operator, manages and holds a 30.1% interest in the

Baku-Tbilisi-Ceyhan (BTC) oil pipeline, which was fully commissioned in
July 2006. BP, as operator of AIOC, also operates the Western Export
Route Pipeline between Azerbaijan and the Black Sea coast of Georgia
and the Azeri leg of the Northern Export Route Pipeline between
Azerbaijan and Russia.

Our onshore US crude oil and product pipelines and related

transportation assets are included under Reﬁning and Marketing (see
page 27). Revenue is earned on pipelines through charging tariffs. Our
gas marketing business is included in our Gas, Power and Renewables
segment (see page 35).

Activity in oil and natural gas transportation during 2006 included:

Alaska
– BP owns a 46.9% interest in TAPS, with the balance owned by four
other companies. Production transported by TAPS from Alaska North
Slope ﬁelds averaged 748mb/d during 2006.

– The use of US-built and US-ﬂagged ships is required when transporting
Alaskan oil to markets in the US. In September 2006, BP completed
the replacement of its US-ﬂagged ﬂeet with the delivery of its fourth
ship, the Alaska Legend. BP had contracted for the delivery of four
1.3 million-barrel-capacity double-hulled tankers for use in transporting

BP Annual Report and Accounts 2006

25

North Slope oil to West Coast reﬁneries. BP took delivery of the ﬁrst
three tankers between August 2004 and November 2005. As existing
ships were retired, the replacements were constructed in accordance
with the Oil Pollution Act of 1990. For discussion of the Oil Pollution
Act of 1990, see Environmental Protection – Maritime oil spill
regulations on page 44.

– Work progressed during 2006 on the strategic reconﬁguration project
to upgrade and automate four pump stations. This project will install
electrically driven pumps at four critical pump stations, combined with
increased automation and upgraded control systems. Start-up of the
ﬁrst pump station is expected to occur in the ﬁrst quarter of 2007, with
the second expected to be online by the end of 2007. The remaining
two reconﬁgured pump stations are expected to come online
sequentially after 2007.

– There are a number of unresolved protests regarding intrastate tariffs
charged for shipping oil through TAPS. These protests were ﬁled
between 1986 and 2003 with the Regulatory Commission of Alaska
(RCA). These matters are proceeding through the Alaska judicial and
regulatory systems. Pending the resolution of these matters, the RCA
has imposed intrastate rates effective 1 July 2003 that are consistent
with its 2002 Order requiring refunds to be made to TAPS shippers of
intrastate crude oil.

– Tariffs for interstate and intrastate transportation on TAPS are

calculated utilizing the Federal Energy Regulatory Commission (FERC)
endorsed TAPS Settlement Methodology (TSM) entered into with
the State of Alaska in 1985. In February 2006, FERC combined and
consolidated all 2005 and 2006 rate complaints ﬁled by the State,
Anadarko, Tesoro and Tesoro Alaska. The complaints were ﬁled on a
variety of grounds. We are conﬁdent that the rates are in accordance
with the TSM and are continuing to evaluate the disputes. BP will
continue to collect its TSM-based interstate tariffs; however, our tariffs
are subject to refund depending on the outcome of the challenges.
Interstate transport makes up roughly 93% of total TAPS throughput.

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

processing system that handles production from more than 50 ﬁelds
in the Central North Sea. The system has a capacity of more than
1mmb/d, with average throughput in 2006 at 545mb/d. In January
2007, FPS completed the tying in of the Buzzard ﬁeld, which is
expected to be a signiﬁcant user of FPS capacity.

– BP operates and has a 29.5% interest in CATS, a 400-kilometre natural
gas pipeline system in the central UK sector of the North Sea. The
pipeline has a transportation capacity of 1.7bcf/d to a natural gas
terminal at Teesside in north-east England. CATS offers natural gas
transportation and processing services. In 2006, throughput was
1.1bcf/d (gross), 326mmcf/d (net).

– In addition, BP operates the Dimlington/Easington gas processing

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

Asia (including the former Soviet Union)
– BP, as operator, manages and holds a 30.1% interest in the BTC oil
pipeline. The 1,768-kilometre pipeline is expected to carry 750,000
barrels of oil a day by the end of 2007 from the BP-operated ACG oil
ﬁeld in the Caspian Sea to the eastern Mediterranean port of Ceyhan.
Loading of the ﬁrst tanker at Ceyhan occurred in June 2006 and the
ofﬁcial inauguration of the Turkish section of the BTC oil export
pipeline, the new Ceyhan marine export terminal and the full BTC
pipeline export system was held on 13 July 2006.

– The South Caucasus Pipeline for the transport of gas from Shah

Deniz in Azerbaijan to the Turkish border was ready for operation in
November 2006. BP is the operator and holds a 25.5% interest.
– Through the LukArco joint venture, BP holds a 5.75% interest (with
a 25% funding obligation) in the Caspian Pipeline Consortium (CPC)

pipeline. CPC is a 1,510-kilometre pipeline from Kazakhstan to the
Russian port of Novorossiysk and carries crude oil from the Tengiz ﬁeld
(BP 2.3%). In addition to our interest in LukArco, we hold a separate
0.87% interest (3.5% funding obligation) in CPC through a 49%
holding in Kazakhstan Pipeline Ventures. In 2006, CPC total throughput
reached 31.2 million tonnes. During 2006, negotiations continued
between the CPC shareholders towards the approval of an expansion
plan. The expansion would require the construction of 10 additional
pump stations, additional storage facilities and a third offshore
mooring point.

Liqueﬁed natural gas
Within BP, Exploration and Production is responsible for the supply of
LNG and the Gas, Power and Renewables business is responsible for
the subsequent marketing and distribution of LNG. (See details under
Gas, Power and Renewables – Liqueﬁed natural gas on page 36). BP’s
Exploration and Production segment has interests in four major LNG
plants: the Atlantic LNG plant in Trinidad (BP 34% in Train 1, 42.5% in
each of Trains 2 and 3 and 37.8% in Train 4); in Indonesia, through our
interests in the Sanga-Sanga PSA (BP 38%), which supplies natural gas
to the Bontang LNG plant, and Tangguh (PSA, BP 37.2%), which is under
construction; and in Australia through our share of LNG from the NWS
natural gas development (BP 16.7% infrastructure and oil reserves/15.8%
gas and condensate reserves).

Assets and activities:

– We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction
Company, which in 2006 supplied 5.6 million tonnes (290bcf) of LNG,
up 3.6% on 2005.

– In Australia, we are one of six equal partners in the NWS Venture.
Each partner holds a 16.7% interest in the infrastructure and oil
reserves and a 15.8% interest in the gas reserves and condensate. The
joint venture operation covers offshore production platforms, a ﬂoating
production and storage vessel, trunklines, onshore gas processing
plants and LNG carriers. Construction continued during 2006 on a ﬁfth
LNG train that is expected to process 4.7 million tonnes of LNG a year
and will increase the plant’s capacity to 16.6 million tonnes a year. The
train is expected to be commissioned during the second half of 2008.
NWS produced 12.0 million tonnes (544bcf) of LNG, an increase of 2%
on 2005.

– 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 15.5% of the total gas feed to Bontang, one of the
world’s largest LNG plants. The Bontang plant produced 19.5 million
tonnes (886bcf) of LNG in 2006, compared with 19.4 million tonnes
in 2005.

– Also in Indonesia, BP has interests in the Tangguh LNG joint venture
(BP 37.2% and operator) and in each of the Wiriagar (BP 38% and
operator), Berau (BP 48% and operator) and Muturi (BP 1%) PSAs in
north-west Papua that are expected to supply feed gas to the Tangguh
LNG plant. During 2006, construction continued on two trains, with
start-up planned late in 2008. Tangguh is expected to be the third
LNG centre in Indonesia, with an initial capacity of 7.6 million tonnes
(388bcf) a year. Tangguh has signed sales contracts for delivery to
China, Korea and North America’s West Coast.

– In Trinidad, construction of the Atlantic LNG Train 4 (BP 37.8%) was
completed in December 2005, with the ﬁrst LNG cargo delivered in
January 2006. Train 4 is now the largest producing LNG train in the
world and is designed to produce 5.2 million tonnes (253bcf) a year of
LNG. BP expects to supply at least two-thirds of the gas to the train.
The facilities will be operated under a tolling arrangement, with the
equity owners retaining ownership of their respective gas. The LNG
is expected to be sold in the US, Dominican Republic and other
destinations. BP’s net share of the capacity of Atlantic LNG Trains 1, 2,
3 and 4 is 6.5 million tonnes (305bcf) of LNG a year.

26

Reﬁning and Marketing

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

Key statistics

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

2005a

$ million
2004a

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Sales and other operating revenues

for continuing operations

232,855

213,326

170,639

Proﬁt before interest and tax from

continuing operations

Total assets
Capital expenditure and acquisitions

5,041
80,964
3,144

6,926
77,485
2,860

6,506
73,582
2,989

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Global Indicator Reﬁning Marginb

8.39

8.60

6.31

$ per barrel

Profit before interest and tax from continuing operations includes profit after interest
and tax of equity-accounted entities.

a With effect from 1 January 2006, the following assets were transferred to or from
the Refining and Marketing segment:
– Three equity-accounted entities were transferred from Other businesses and

corporate following the sale of Innovene;

– The South Houston Green Power co-generation facility (in the Texas City refinery)
and the Watson co-generation facility (in the Carson refinery) were transferred to
Gas, Power and Renewables as a result of the formation of BP Alternative Energy;
and

– Hydrogen for Transport activities were transferred from Gas, Power and

Renewables.
The 2005 and 2004 data above has been restated to reflect these transfers.
b The Global Indicator Refining Margin (GIM) is the average of regional industry
indicator margins, which we weight for BP’s crude refining capacity in each region.
Each regional indicator margin is based on a single representative crude with product
yields characteristic of the typical level of upgrading complexity. The refining margins
are industry-specific rather than BP-specific measures, which we believe are useful
to investors in analysing trends in the industry and their impact on our results.
The margins are calculated by BP based on published crude oil and product prices
and take account of fuel utilization and catalyst costs. No account is taken of BP’s
other cash and non-cash costs of refining, such as wages and salaries and plant
depreciation. The indicator margin may not be representative of the margins
achieved by BP in any period because of BP’s particular refining configurations and
crude and product slate.

The changes in sales and other operating revenues are explained in more
detail below.

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

$ million

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

2005

2004

Sale of crude oil through spot and

term contracts

38,577

36,992

21,989

Marketing, spot and term sales of

reﬁned products

177,995

155,098

124,458

Other sales including non-oil and to

other segments

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

16,283

232,855

21,236
213,326

24,192
170,639

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Sale of crude oil through spot and

mb/d

term contracts

Marketing, spot and term sales of

reﬁned products

2,110

2,464

2,312

5,801

5,888

6,398

portfolio will be upgraded further through the construction of a new coker
at the Castello´ n reﬁnery, an increase in the Whiting reﬁnery’s ability to
process Canadian heavy crude, upgrades to diesel and gasoline
desulphurization capability at the Nerefco reﬁnery in the Netherlands,
completion of a major upgrade to the oleﬁn cracker at the Gelsenkirchen
reﬁnery in Germany and the site reconﬁguration and installation of a new
hydrocracker at the Bayernoil reﬁnery, also in Germany. In addition, the
portfolio will be improved through upgrades implemented during the
recommissioning of the Texas City reﬁnery in the US.

Our marketing businesses, underpinned by world-class manufacturing

such as our Aromatics and Acetyls portfolio, generate customer value
by providing quality products and offers. Our retail strategy provides
differentiated fuel and convenience offers to some of the most attractive
markets. Our lubricants brands offer customers beneﬁts through
technology and relationships and we focus on increasing brand
and product loyalty in Castrol lubricants. We continue to build deep
customer relationships and strategic partnerships in the business-to-
business sector.

Reﬁning and Marketing manages a portfolio of assets that we believe
are competitively advantaged across the chain of downstream activities.
Such advantage derives from several factors, including location (such as
the proximity of manufacturing assets to markets), operating cost and
physical asset quality.

We are one of the major reﬁners of gasoline and hydrocarbon products

in the US, Europe and Australia. We have signiﬁcant retail and business-
to-business market positions in the US, UK, Germany and the rest of
Europe, Australasia, Africa and Asia. We are enhancing our presence in
China and exploring opportunities in India. Reﬁning and Marketing also
includes the Aromatics and Acetyls business, which maintains
manufacturing positions globally, with an emphasis on Asia growth,
particularly in China.

During 2006, signiﬁcant events were:

– BP announced that it had entered the ﬁnal planning stage of a $3-billion

investment in Canadian heavy crude oil processing capability at its
Whiting, US, reﬁnery. This project is expected to reposition Whiting
competitively as a top-tier reﬁnery by increasing its Canadian heavy
crude processing capability by 260,000 barrels per day and modernizing
it with equipment of signiﬁcant size and scale. Reconﬁguring the
reﬁnery also has the potential to increase its production of motor fuels
by about 15%, which is about 1.7 million additional gallons of gasoline
and diesel per day. Construction is tentatively scheduled to begin in
2007, pending regulatory approval.

– BP also announced plans to invest $500 million over the next 10 years
to establish a dedicated bioscience research laboratory. The BP Energy
Biosciences Institute (EBI) is planned to be the ﬁrst of its kind in the
world and to be attached to a major academic centre. On 1 February
2007, BP announced that it had selected the University of California,
Berkeley, and its partners the University of Illinois at Urbana–
Champaign and the Lawrence Berkeley National Laboratory for the
research programme. Further, BP and DuPont announced the creation
of a partnership to develop, produce and market a next generation of
biofuels. The companies’ joint strategy is to deliver advantaged biofuels
that will provide improved options for expanding energy supplies and
accelerate the move to renewable transportation fuels that lower
overall greenhouse gas emissions. The ﬁrst product to market is
expected to be biobutanol, an improved biocomponent for gasoline.
Initial introduction activities are currently targeted on the UK market.

– In 2006, plans for a second puriﬁed terephthalic acid (PTA) plant at

the BP Zhuhai Chemical Company Limited site in Guangdong province,
China, were approved by the Chinese government and the plant is
expected to come on stream at the end of 2007.

The Reﬁning and Marketing segment includes a portfolio of businesses,

– BP continues to develop its retailing business in both new markets

namely Reﬁning, Retail, Lubricants, Business-to-Business Marketing
and Aromatics and Acetyls. Our strategy is to continue our focused
investment in key assets and market positions. We aim to improve the
quality and capability of our manufacturing portfolio. Over the past ﬁve
years, this has been taking place through upgrades of existing conversion
units at several of our facilities and investment in new clean fuels units
at the Castello´ n reﬁnery in Spain, the Kwinana reﬁnery in Australia and all
our US reﬁneries (excluding the Carson reﬁnery, which was already
producing a full slate of clean fuels). Over the next ﬁve years, our reﬁning

and new business models. In 2006, developments included:
r The roll-out of the BP Connect Wild Bean Cafe´ brands to its dealer
network in a franchise agreement. We are expecting to develop a
network of 150 Connect franchise sites along with a further 100
company-owned Connect sites in the UK by the end of 2010.
r The successful piloting of a Marks & Spencer store partnership
in the UK, with the intention of rolling this out to a further 200
stores in 2007.

BP Annual Report and Accounts 2006

27

r

In a study by Corporate Research International, US consumers
ranked BP’s convenience chain in the US as the best for
customer service.

– BP completed the disposal of its shareholding in Zhenhai Reﬁning and
Chemicals Company to Sinopec, sold its shareholding in Eiffage, the
French-based construction company, and completed the disposal of its
network of 70 retail sites in the Czech Republic.

– BP also announced its intention to sell the Coryton reﬁnery in the
UK, which processes 172,000 barrels of crude oil per day. On
1 February 2007, we announced that the sale of the reﬁnery to
Petroplus Holdings AG had been agreed, subject to required regulatory
approvals. The sale includes the adjacent bulk terminal and BP’s UK
bitumen business which is closely integrated with the reﬁnery.
Completion of the sale is expected in mid-2007.

Texas city reﬁnery
Summary
Throughout 2006, BP continued to respond to the 23 March 2005 incident
at its Texas City reﬁnery. BP addressed a number of the factors that
contributed to the incident, including the announcement of a new policy
for the siting of occupied portable buildings and the removal from service
at Texas City of all blow-down stacks handling heavier-than-air light
hydrocarbons. BP also implemented a number of actions relating to
safety and operations, not only at US reﬁneries but also at other facilities
worldwide. These actions include a decision to increase spending to an
average of $1.7 billion a year over the next four years to improve the
integrity and reliability of US reﬁning assets, the formation of a safety and
operations function to focus on operations and process safety across the
group, the appointment of a new chairman and president of BP America
Inc. and the creation of an advisory board to assist BP America Inc.’s
management in monitoring and assessing BP’s US operations (see Action
on process safety across BP on page 40). Also in 2006, BP settled a large
number of civil suits arising from the Texas City incident. BP established
a $1.625 billion provision related to the incident and reached settlements
with all the relatives of those who were killed and with hundreds of other
persons who ﬁled injury claims. Trials have been scheduled for a number
of unresolved claims in mid-2007, although to date all claims scheduled
for trial have been resolved in advance of trial.

In 2006, BP continued its co-operation with the governmental entities
investigating the incident, including the US Department of Justice (DOJ),
the US Environmental Protection Agency (EPA), the US Occupational
Safety & Health Administration (OSHA), the US Chemical Safety and
Hazard Investigation Board (CSB) and the Texas Commission on
Environmental Quality (TCEQ). During 2006, BP also devoted signiﬁcant
time and effort to co-operate with the BP US Reﬁneries Independent
Safety Review Panel (the panel), which it chartered in 2005 on the
recommendation of the CSB, to assess the effectiveness of corporate
oversight of safety management systems at BP’s US reﬁneries and the
corporate safety culture. The panel published its report in January 2007
and BP has committed to implement its recommendations
(see Report of the BP US Reﬁneries Independent Safety Review Panel on
page 29).

Background
The March 2005 explosion and ﬁre at BP Products North America Inc.’s
Texas City reﬁnery occurred in the isomerization unit of the reﬁnery as the
unit was starting up after routine planned maintenance. The incident
claimed the lives of 15 workers and injured many others.

An internal BP incident investigation determined that the rafﬁnate
splitter at the isomerization unit was overﬁlled and overheated, causing
the relief valves to open into the blow-down system and resulting
in an overﬂow of liquid hydrocarbon from the blow-down stack. The
resulting vapour cloud was ignited by a source that has not been
deﬁnitively identiﬁed.

BP’s incident investigation team found that the critical factors leading to

the incident included over-pressurization of the rafﬁnate splitter, resulting
in loss of containment, the failure to follow procedures during the start-up,
the placement of temporary trailers too close to the blow-down stack and
the design and operation of the blow-down stack. The investigation team
issued a comprehensive ﬁnal report, which is available in full on the BP
internet site, www.bpresponse.org. The ﬁnal report identiﬁed a number

28

of underlying causes related to the working environment, process safety
and other management and operational behaviours and processes at the
Texas City reﬁnery.

The investigation team recommended numerous changes relating

to people, procedures, control of work and trailer siting, design and
engineering, underlying systems and investigation and reporting of
incidents. The Texas City reﬁnery established a programme ofﬁce to
implement the recommendations from this report and to address other
projects needed to enhance the safety and performance of the reﬁnery.
In addition, in the immediate wake of the incident, a new Texas City site
manager was appointed in May 2005. That manager has been succeeded
by a permanent replacement, whose tenure at the reﬁnery began in
the ﬁrst quarter of 2007. Steps were taken following the incident to
strengthen the leadership team, clarify responsibilities and introduce
systems to improve communication and compliance. All occupied
trailers have been removed from speciﬁed areas, an enhanced training
programme is under way and the site has committed to restarting
process units without any blow-down stacks in heavier-than-air light
hydrocarbons.

The incident prompted a number of investigations by other state and

federal agencies. The TCEQ and OSHA investigations of the incident
resulted in settlement agreements between BP and the agencies. In the
third quarter of 2005, BP reached a settlement with OSHA that resulted
in the payment of a $21.4 million penalty, an agreement to correct all
alleged safety violations and the retention of experts to assess the
reﬁnery’s organization and process safety systems. In the second
quarter of 2006, BP settled with the TCEQ, resolving 27 alleged violations
by paying a $0.3 million ﬁne and agreeing, among other things, to upgrade
its ﬂare system.

In August 2005, the CSB issued an urgent recommendation to BP to
establish an independent panel to assess and make recommendations
regarding BP’s corporate oversight of safety management systems at
its ﬁve US reﬁneries and its corporate safety culture. BP established
the panel in October 2005, chaired by former US Secretary of State
James A Baker, III, and co-operated fully with the panel. In order to
make a thorough and credible assessment, the panel visited all BP’s US
reﬁneries, commissioned independent process safety audits, interviewed
staff at all levels, including operators and reﬁnery managers and
leadership teams, conducted an extensive process safety cultural survey
and reviewed tens of thousands of documents.

BP expects the CSB to issue its ﬁnal report in March 2007,

supplementing two interim reports of ﬁndings. At a news conference
on 31 October 2006, the CSB issued an update on the status of its own
20-month investigation into the causes of the incident and also issued
recommendations to the American Petroleum Institute (API) to amend its
guidance relating to atmospheric relief systems and to OSHA to establish
a national emphasis programme promoting the elimination of unsafe
systems in favour of safer alternatives.

The DOJ is investigating whether the Texas City incident involved
any criminal conduct. The DOJ has issued Grand Jury subpoenas for
documents and testimony. The investigation, with which BP is
co-operating, is ongoing.

The reﬁnery was entirely shut down in September 2005 in anticipation

of Hurricane Rita. The hurricane caused the loss of steam and power to
the reﬁnery and these services were not fully restored until December
2005. The site-wide shut-down of the Texas City reﬁnery also affected the
Aromatics and Acetyls business, which has a co-located manufacturing
capacity of paraxylene (PX) and metaxylene. The PX unit resumed
production in March and the metaxylene unit resumed in April 2006.
The remaining PX capacity at Texas City has been restarted in line with
the ongoing phased recommissioning of the reﬁning units.

Throughout the period from September 2005 to the end of the ﬁrst
quarter of 2006, BP worked to understand the extent of the damage
the hurricane and loss of power had caused and put into place detailed
plans to effect repair and safe restart of the process units. This was a
considerable task, involving the entire workforce at the site plus
signiﬁcant external engineering resources.

At the end of the ﬁrst quarter of 2006, the reﬁnery restarted

production and reached an average throughput of 248,000 barrels per day
in the fourth quarter of 2006. The site started up smoothly and

safely and is producing gasoline, diesel and chemicals products for
the US market.

In parallel, reﬁnery personnel have continued to work to effect the
repair and the safe restart of the remaining process units. Additional
processing facilities were commissioned in the second and third quarters
of 2006. Additional conversion capacity is expected to be brought online
in 2007. BP’s plan is to bring additional sour crude processing facilities
back on-stream in the second half of 2007; these facilities will allow the
processing of additional high-sulphur crude. We expect crude throughputs
to be approximately 400,000 barrels per day by the end of 2007.

The following milestones have been achieved in returning the reﬁnery

to operation with sequenced reconditioning of a multitude of units:
– Major site commissioning involving more than 15 million worker hours

to date.

– Refurbishment and safe start-up of 27-mile steam system.
– Extensive mechanical renovation and the installation of a new

ﬂare system.

– Creation of a new command centre with interactive audio/visual links

to the units, manned 24 hours a day during unit start-up.

– Implementation of a holistic commissioning plan deﬁning behaviours

and accountabilities to deliver safe and successful start-up.

– Implementation of a comprehensive systems training programme,

coupled with safety accountability roll-out plans.
Several other improvements are either complete or under way:

– A new ofﬁce building for more than 400 Texas City workers

was opened to relocate workers who can work outside our plant
fence line.

– A new ﬂue gas scrubber is being added to the FCC unit. This

$80-million investment will reduce emissions of sulphur and nitrogen
oxide from the reﬁnery.

– A new Employee Services Building (ESB) is under construction. The

ESB will include facilities for learning and development and operations
training departments, including unit training simulators and nine training
rooms, the medical department, some of the site’s security team, the
Incident Management Team and site union ofﬁcial ofﬁces.
Construction has started on a new 250 megawatt (MW) steam turbine

power generating plant that will reduce emissions and improve both
energy and operational efﬁciency. The $100-million unit will be located
next to the existing South Houston Green Power LP co-generation facility
and is expected to boost the total electricity generating capacity located at
the Texas City reﬁnery site to 1,000MW.

Report of the BP US Reﬁneries Independent Safety Review Panel
On 16 January 2007, having completed its review, the panel issued its
report. The report identiﬁed deﬁciencies in process safety performance
at BP’s US reﬁneries and called on BP to give process safety the same
priority that it had historically given to personal safety and environmental
performance. In making its ﬁndings and recommendations, the panel
stated its objective was excellence in process safety performance, not
simply legal compliance. The panel speciﬁcally noted that, ‘during the

course of its review, it saw no information to suggest that anyone – from
BP’s board members to its hourly workers – acted in anything other than
good faith.’

The panel made 10 recommendations relating to: process safety
leadership; integrated and comprehensive process safety management
system; process safety knowledge and expertise; process safety culture;
clearly deﬁned expectations and accountability for process safety; support
for line management; leading and lagging performance indicators for
process safety; process safety auditing; board monitoring; and industry
leader. The panel’s report in its entirety can be found at www.bp.com/
bakerpanelreport.

The panel acknowledged the measures BP had taken since the Texas

City incident, including dedicating signiﬁcant resources and personnel
intended to improve the process safety performance at BP’s US
reﬁneries. BP has committed to implement the panel’s recommendations
and will consult with the panel on how best to do this across the US
reﬁneries and to apply the lessons learned elsewhere in its global
operations.

Other reﬁnery investigations
As a result of its investigation of the Texas City reﬁnery, OSHA conducted
an inspection of BP Products North America Inc.’s Toledo reﬁnery,
beginning in October 2005. On 24 April 2006, OSHA issued citations with
a total penalty of $2.4 million, alleging 39 separate violations of two
different OSHA standards. BP and OSHA have reached a settlement in
principle and are working towards ﬁnalizing the documentation.

On 15 November 2006, the Indiana Occupational Safety and Health
Administration (IOSHA) issued the Whiting reﬁnery with three Safety
Orders and Notiﬁcations of Penalty alleging 14 separate violations of
the OSHA regulations. The total proposed penalty was $0.4 million. On
7 December 2006, BP and IOSHA met to discuss resolution of the
matter. Discussions to reach a settlement agreement are ongoing.

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

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

and conﬁguration to produce fuels from low-cost feedstocks in line with
the demand of the region. Efﬁcient operations are measured primarily
using regional reﬁning surveys conducted by third parties. The surveys
assess our competitive position against benchmarked industry measures
for margin, energy efﬁciency and costs per barrel. Investments in our
reﬁneries are focused on maintaining and improving our competitive
position and developing the capability to produce the cleaner fuels that
meet the requirements of our customers and their communities.

BP Annual Report and Accounts 2006

29

The following table summarizes the BP group’s interests in reﬁneries and crude distillation capacities at 31 December 2006.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

mb/d
Crude distillation capacitiesa
BP
share

Total

Group interestb
%

100.0%

UK
Total UK
Rest of Europe
Germanyd

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

New Zealand
Kenya
South Africa
Total Rest of World
Total

Reﬁnery
Coryton*c

Bayernoil
Gelsenkirchen*
Karlsruhe
Lingen*
Schwedt
Nerefco*
Castello´ n*

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

Bulwer*
Kwinana*
Whangerei
Mombasa
Durban

22.5%
50.0%
12.0%
100.0%
18.8%
69.0%
100.0%

100.0%
100.0%
100.0%
100.0%
100.0%

100.0%
100.0%
23.7%
17.1%
50.0%

172
172

272
268
302
91
226
400
110
1,669

265
232
405
155
475
1,532

101
137
101
94
182
615
3,988

172
172

61
134
36
91
42
276
110
750

265
232
405
155
475
1,532

101
137
24
16
91
369
2,823

2006

165
648
1,110
275

2,198

2,823
76%
70%
87%
78%

thousand barrels per day

2005

180
667
1,255
297
2,399

2004

208
684
1,373
342
2,607

2,832
87%
82%
90%
88%

2,823
93%
95%
90%
87%

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

* Indicates refineries operated by BP.
a Crude distillation capacity is gross rated capacity, which is defined as the maximum achievable utilization of capacity (24-hour assessment) based on standard feed.
b BP share of equity, which is not necessarily the same as BP share of processing entitlements.
c BP has announced the sale of its Coryton refinery, subject to required regulatory approvals.
d BP’s share of the Reichstett refinery in Germany was sold in December 2006.

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

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

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

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

BP’s 2006 reﬁnery throughput declined as a result of increased turnaround activity during the year. In the US, the year-on-year decline was as a result
of the full shutdown of the Texas City reﬁnery in September 2005 and the subsequent maintenance programme that led to a partial and phased start-up
during 2006.

30

Sales of reﬁned productsa
Marketing sales

UKb
Rest of Europe
USA
Rest of World

Total marketing salesc
Trading/supply salesd
Total reﬁned products

Marketing
Marketing comprises four business areas: Retail, Lubricants, Business-
to-Business Marketing and Aromatics and Acetyls. We market a
comprehensive range of reﬁned products, including gasoline, gasoil,
marine and aviation fuels, heating fuels, LPG, lubricants and bitumen.
We also manufacture and market puriﬁed terephthalic acid, paraxylene
and acetic acid through our Aromatics and Acetyls business.

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

thousand barrels per day

2006

2005

2004

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Each of these brands carries a very strong offer and we also aim to share
best practices between them. Since 2003, we upgraded our fuel offer
with the introduction of Ultimate gasoline and diesel products. In 2006,
we launched Utimate in South Africa and Russia and now market
Ultimate in 15 countries.

We continue to focus on operational efﬁciencies through targeted
portfolio upgrades to drive increases in our fuel throughput per site and
our store sales per square metre. In 2006, across the network, same-
store sales growth at 4% exceeded estimated market growth of 2%.

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

2006

647
2,821
1,755
591

5,814

2,528
3,286
–

5,814

2005

628
3,069
1,776
610
6,083
2,489
3,533
61
6,083

$ million

2004

655
3,090
1,715
601
6,061
2,319
3,623
119
6,061

356
1,340
1,595
581

3,872
1,929

5,801

355
1,354
1,634
599
3,942
1,946
5,888

322
1,360
1,682
638
4,002
2,396
6,398

$ million

Store salesa
UK
Rest of Europe
USA
Rest of World
Total
Direct-managed
Franchise
Store alliances
Total

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Proceeds from sale of reﬁned

products

177,995

155,098

124,458

a Excludes sales to other BP businesses and the sale of Aromatics and Acetyls
products.
b UK area includes the UK-based international activities of Refining and Marketing.
c 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).
d Trading/supply sales are sales to large unbranded resellers and other oil companies.

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

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

a Store sales reported are sales through direct-managed stations, franchisees and the
BP share of store alliances and joint ventures. Sales figures exclude sales taxes and
lottery sales but include quick-service restaurant sales. Fuel sales are not included in
these figures. Not all retail sites include a BP convenience store.

Our retail network is largely concentrated in Europe and the US, with

established operations in Australasia and southern and eastern Africa.
We are developing networks in China with joint venture partners.

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

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

2006

488
1,603
1,170
388
223

3,872

thousand barrels per day

2005

499
1,603
1,185
379
276
3,942

2004

494
1,675
1,255
343
235
4,002

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

Number of retail sites

2006

1,300
7,700
2,700
9,600
3,300

24,600

2005

1,300
7,900
3,100
9,700
3,200
25,200

2004

1,300
8,000
3,900
10,300
3,300
26,800

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

Our aim is to increase total margin by focusing on both volumes and

margin per unit. We do this by growing our customer base, both in
existing and new markets, by attracting new customers and by covering
a wider geographic area. We also work to improve the efﬁciency of our
operations through upgrading our transactional and operational processes,
reducing costs and improving our product mix. In addition, we recognize
that our customers are demanding a wider choice of fuels, particularly
fuels that are cleaner and more efﬁcient. Through our integrated reﬁning
and marketing operations, we believe we are better able to meet these
customer demands.

Marketing sales of reﬁned products were 3,872mb/d in 2006,
compared with 3,942mb/d in the previous year. The decrease was
due mainly to the effects of the high price environment in certain retail
markets and of BP reducing volumes in less proﬁtable business-to-
business markets.

BP enjoys a strong market share and leading technologies in the

Aromatics and Acetyls business. In Asia, we continue to develop a strong
position in PTA and acetic acid. Our investment is biased towards this
high-growth region, especially China.

Retail
Our retail strategy focuses on investment in high-growth metropolitan
markets and the upgrading of our retail offers, while driving operational
efﬁciencies through portfolio optimization.

There are two components of our retail offer: convenience and

fuels. The convenience offer comprises sales of convenience items to
customers from advantaged locations in metropolitan areas, while our
fuels offer is deployed at locations in all our markets, in many cases
without the convenience offer. We execute our convenience offer
through a quality store format in each of our key markets, whether it
is the BP Connect offer in Europe and the eastern US, the am/pm offer
west of the Rocky Mountains in the US or the Aral offer in Germany.

a Retail sites includes all sites operated under a BP brand.

At 31 December 2006, BP’s worldwide network consisted of more
than 24,000 locations branded BP, Amoco, ARCO and Aral, compared
with approximately 25,000 in the previous year. We continue to improve
the efﬁciency of our retail asset network and increase the consistency of
our site offer through a process of regular review. In 2006, we sold 513
company-owned sites to dealers and jobbers who continue to operate
these sites under the BP brand. We also divested an additional 301
company-owned sites (including all company-owned sites in the Czech
Republic) to third parties.

In 2006, we continued the rollout of the BP Connect offer at sites
in the UK and US, consistent with our retail strategy of building on our
advantaged locations, strong market positions and brand. The BP
Connect sites include a distinctive food offer, large convenience store and
cleaner fuels. The BP Connect sites include both those that are new and
those where extensive upgrading and remodelling have taken place.
At 31 December 2006, more than 760 BP Connect stations were
open worldwide.

Through regular review and execution of business opportunities,
we continue to concentrate our ownership of real estate in markets
designated for development of the convenience offer. At 31 December
2006, BP’s retail network in the US comprised approximately 12,300
sites, of which approximately 9,600 were owned by jobbers. BP’s
network comprised about 9,000 sites in the UK and the Rest of Europe
and 3,300 sites in the Rest of World.

The joint venture between BP and PetroChina (BP-PetroChina

Petroleum Company Ltd) started operation in 2004. Located in
Guangdong, one of the most developed provinces in China, 387 sites
were operational at 31 December 2006. The joint venture plans to operate
and manage a total network of 500 locations in the province. A joint
venture with Sinopec, approved in the fourth quarter of 2004 with the
establishment of BP-Sinopec (Zhejiang) Petroleum Co. Ltd, commenced

BP Annual Report and Accounts 2006

31

operations with 151 sites in Ningbo in 2005, with a further 72 sites in
Shaoxing being transferred into the joint venture in 2006. The joint
venture plans to build, operate and manage a network of 500 sites in
Hangzhou, Ningbo and Shaoxing within Zhejiang province.

Lubricants
We manufacture and market lubricants products and also supply related
products and services to business customers and end-consumers in over
60 countries directly and to the rest of the world through local distributors.
Our business is concentrated on the higher-margin sectors of automotive
lubricants, especially in the consumer sector, and also has a strong
presence in business markets such as commercial vehicle ﬂeets, aviation,
marine and specialized industrial segments. Customer focus, distinctive
brands and superior technology remain the cornerstones of our long-term
strategy. BP markets through its two major brands, Castrol and BP, and
several secondary brands, including Duckhams, Veedol and Aral.
In the consumer sector of the automotive segment, we supply

lubricants, other products and related business services to intermediate
customers such as retailers and workshops, who in turn serve end-
consumers (e.g. car, motorcycle and leisure craft owners) in the mature
markets of western Europe and North America and also in the fast-
growing markets of the developing world such as Russia, China,
India, the Middle East, South America and Africa. The Castrol brand is
recognized worldwide and we believe it provides us with a signiﬁcant
competitive advantage.

In commercial vehicle and general industrial markets, we supply
lubricants and lubricant-related services to the transportation industry
and to automotive manufacturers.

Business-to-business marketing
Business Marketing markets a comprehensive range of reﬁnery and
lubricants products focused on business customers in the aviation
fuel, marine fuel, marine and industrial lubricants, LPG and the ground
fuels sectors.

Air BP is one of the world’s largest aviation businesses, supplying
aviation fuel and lubricants to the airline, military and general aviation
sectors. It supplies customers in approximately 100 countries, has
annual marketing sales of around 26,854 million litres (approximately
463 thousand barrels per day) and has relationships with many of the
major commercial airlines. Air BP’s strategic aim is to strengthen its
position in existing markets (Europe/US/Asia Paciﬁc), while creating
opportunities in emerging economies such as South America and China.

The LPG business sells bulk, bottled, automotive and wholesale
products to a wide range of customers in 14 countries. During the past
few years, our LPG business has consolidated its position in established
markets and pursued opportunities in new and emerging markets. BP is

one of the leading importers of LPG into the Chinese market, where we
continued to grow our retail LPG business. LPG Marketing Product sales
in 2006 were approximately 71 thousand barrels per day.

Marine comprises three global businesses: Marine Fuels, Marine

Lubricants, and Power Generation and Offshore, which supplies specialist
lubricants to the power generation and offshore industry. Under the BP
and Castrol brands, the business is the marine lubricants market leader
and has a strong presence in the marine fuels sector. The business has
ofﬁces in 90 countries and operates in more than 1,150 ports.

The Commercial Fuels business has activities in approximately 14
European countries and marketing sales of approximately 596 thousand
barrels per day. The business markets fuels and heating oil, mostly as
pick-up business at reﬁneries, terminals and depots.

Our Business Marketing activities also include Industrial Lubricants,
selling industrial lubricants and services to manufacturing companies in
approximately 40 countries, and the supply of bitumen to the road and
rooﬁng industries. The businesses seek to increase value by building from
the technology, marketing and sales capabilities of a business to business
operation.

BP supports its businesses through a dedicated Strategic Accounts
organization. Strategic Accounts develops strategic relationships with
carefully selected leading organizations in targeted markets, where mutual
strategic and ﬁnancial value can be created. Its operating model manages
each relationship in a disciplined manner to achieve growth and efﬁciency
for BP and its partners through focused offer development and capability
building. Relationships are held across organizations and involve many
senior leaders in the partners’ organizations.

Aromatics and acetyls
The Aromatics and Acetyls business is managed along three main
products lines: PTA, PX and acetic acid. PTA is a raw material for the
manufacture of polyesters used in textiles, plastic bottles, ﬁbres and
ﬁlms. PX is feedstock for the production of PTA. Acetic acid is a versatile
intermediate chemical used in a variety of products such as paints,
adhesives and solvents. It is also used in the production of PTA. In
addition to these three main products, we are involved in a number
of other petrochemicals products, namely Dimethyl 2, 6 Naphthalene
dicarboxylate (NDC), which is used for optical ﬁlm and specialized
packaging, and acetic anhydride, ethyl acetate and vinyl acetate
monomer (VAM), which are used in cellulose acetate, paints, adhesives
and solvents.

Our Aromatics and Acetyls strategy is to invest to maintain our

advantaged manufacturing positions globally, with an emphasis on Asia
growth, particularly in China. We are also investing in maintaining and
developing our technology leadership position to deliver both operating
and capital cost advantages.

32

The following table shows BP’s Aromatics and Acetyls production capacity at 31 December 2006. This production capacity is based on the original
design capacity of the plants plus expansions.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

thousand tonnes per year

Acetic
acid

Total – BP
share of
capacity

PX

PTA

Other

529

633

1,076

Geographic area
------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
UK
Hull
Rest of Europe
Belgium
Geel
USA
Cooper River
Decatur
Texas City
Rest of World
China
Chongqing
Zhuhai
Indonesia
Merak
Korea
Ulsan

(51% of YARACO)b

1,309
2,217
1,975

(50% of PT Ami)

1,145
1,309

1,309
1,043

254
582

29
123

1,162

1,628

242d

202b

553c

543a

57e

252

582

252

852

552

52

(47% of SPC)c
(34% of ASACCO)e
(51% of SS-BP)d
(47% of SPC)c

545

353

545
699

153g
2,214

894

822
457
153
13,260

(61% of CAPCO)f
(61% of CAPCO)f
(50% of FBPC)g

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Seosan
Malaysia
Kertih
Kuantan
Taiwan
Kaohsiung
Taichung
Mai Liao

353c

699

822f
457f

7,146

3,006

a Sterling Chemicals plant, the output of which is marketed by BP.
b Yangtze River Acetyls Company.
c Samsung-Petrochemicals Company Ltd.
d Samsung-BP Chemicals Ltd.
e Asian Acetyls Company Ltd.
f China American Petrochemical Company Ltd.
g Formosa BP Chemicals Corporation.

In addition to the plans for a second PTA plant at the BP Zhuhai Chemical
Company Limited site in Guandong province, China, described previously,
the following portfolio activity took place in the Aromatics and Acetyls
business during the year:
– In the third quarter of 2006, BP announced its intent to sell its 47.41%
equity interest in Samsung Petrochemical Co. Ltd (SPC), a PTA joint
venture with Samsung in South Korea.

– In 2004, BP announced the phased closure of two acetic acid plants at
Hull, UK. The ﬁrst plant was shut down in the second quarter of 2005
and the remaining plant was shut down in the third quarter of 2006.
– The development of a 350 thousand tonnes per annum (ktepa) PTA

expansion at Geel, Belgium, is expected to be operational in early 2008
and to increase the site’s PTA capacity to 1,426ktepa.

Supply and trading
The group has a long-established supply and trading activity responsible
for delivering value across the overall crude and oil products supply chain.
This activity identiﬁes the best markets and prices for our crude oil,
sources optimal feedstock to our reﬁning assets and sources marketing
activities with ﬂexible and competitive supply. Additionally, the function
creates incremental trading gains through holding commodity derivative
contracts and trading inventory. To achieve these objectives in a liquid and
volatile international market, the group enters into a range of commodity
derivative contracts, including exchange traded futures and options, over-
the-counter options, swaps and forward contracts as well as physical
term and spot contracts.

Exchange traded contracts are traded on liquid regulated markets that
transact in key crude grades, such as Brent and West Texas Intermediate,
and the main product grades, such as gasoline and gasoil. These
exchanges exist in each of the key markets in the US, western Europe

and the Far East. Over-the-counter contracts include a variety of options,
forwards and swaps. These swaps price in relation to a wider set of
grades than those traded through the exchanges, where counterparties
contract for differences between, for example, ﬁxed and ﬂoating prices.
The contracts we use are described in more detail below. Additionally,
physical crude can be traded forward by using speciﬁc over-the-counter
contracts pricing in reference to Brent and West Texas Intermediate
grades. Over-the-counter crude forward sales contracts are used by BP to
buy and sell the underlying physical commodity, as well as to act as a risk
management and trading instrument.

Risk management is undertaken when the group is exposed to market
risk, primarily due to the timing of sales and purchases, which may occur
for both commercial and operational reasons. For example, if the group
has delayed a purchase and has a lower than normal inventory level, the
associated price exposure may be limited by taking an offsetting position
in the most suitable commodity derivative contract described above.
Where trading is undertaken, the group actively combines a range of
derivative contracts and physical positions to create incremental trading
gains by arbitraging prices, typically between locations and time periods.
This range of contract types includes futures, swaps, options and forward
sale and purchase contracts, which are described further below. The
volume of activity in 2006 was similar to 2005.

Through these transactions, the group sells crude production into the

market, allowing more suitable higher-margin crude to be supplied to
our reﬁneries. The group may also actively buy and sell crude on a spot
and term basis to improve selections of crude for reﬁneries further. In
addition, where reﬁnery production is surplus to marketing requirements
or can be sourced more competitively, it is sold into the market. This
latter activity also encompasses opportunities to maximize the value
of the whole supply chain through the optimization of storage and pipeline

BP Annual Report and Accounts 2006

33

assets, including the purchase of product components that are blended
into ﬁnished products. The group also owns and contracts for storage and
transport capacity to facilitate this activity.

The range of transactions that the group enters into is described below

Transportation
Our Reﬁning and Marketing business owns, operates or has an interest
in extensive transportation facilities for crude oil, reﬁned products and
petrochemicals feedstock.

in more detail:
– Exchange-traded commodity derivatives

These contracts are typically in the form of futures and options traded
on a recognized exchange, such as Nymex, Simex, 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 gas
oil. 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. These
contracts are used for the trading and risk management of both crude
and products. Realized and unrealized gains and losses on exchange
traded commodity derivatives are included in sales and other operating
revenues for accounting purposes.

– Over-the-counter (OTC) contracts

These contracts are typically in the form of forwards, swaps and
options. OTC contracts are negotiated between two parties and are not
traded on an exchange. These contracts can be used both as part of
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.
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 – BFO). Although the contracts
specify physical delivery terms for each crude blend, a signiﬁcant
volume are not settled physically. The contracts 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 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
crude or oil products at a speciﬁed price on or before a speciﬁc future
date. Amounts under these derivative ﬁnancial instruments are settled
at expiry, typically through netting agreements, to limit credit exposure
and support liquidity.
– Spot and term contracts

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

Trading investigations
See Legal proceedings on page 85 for further details regarding
investigations into various aspects of BP’s trading activities.

The independent review, commissioned by BP, of the current

compliance approach in the group’s US trading organization has been
completed. A number of recommendations have been made in regard
to the design and effectiveness of the compliance processes and
procedures. BP is fully implementing these recommendations.

We transport crude oil to our reﬁneries principally by ship and through

pipelines from our import terminals. We have interests in crude oil
pipelines in Europe and the US.

Bulk products are transported between reﬁneries and storage terminals
by pipeline, ship, barge and rail. Onward delivery to customers is primarily
by road. We have interests in major product pipelines in the UK, the Rest
of Europe and the US.

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 on BP business are subject to our health,
safety, security and environmental requirements. In 2006, we continued
to expand our operated and time-chartered ﬂeet in order to provide more
protection against the risk of a major oil spill. This ﬂeet transformation
is ahead of the international requirements for phase-out of single-
hulled vessels.

International ﬂeet
In 2005 we managed an international ﬂeet of 52 vessels (44 oil tankers
and eight LNG carriers). At the end of 2006, we had 57 international
vessels (42 medium-size crude and product carriers, four very large crude
carriers, one North Sea shuttle tanker, seven LNG carriers and three new
LPG carriers). All these ships are double-hulled.

Of the seven LNG carriers, BP manages four on behalf of joint ventures

in which it is a participant and operates three LNG carriers, with a further
four on order for delivery in 2007 and 2008.

Regional and specialist vessels
In Alaska, we took delivery of the fourth and ﬁnal ship in a series of new-
build double-hulled tankers and redelivered one of our time-chartered
vessels back to the owner. The entire Alaskan ﬂeet of six vessels is
double-hulled.

In the Lower 48, two of the four heritage Amoco barges remain in
service, one of which is due to be phased out of BP’s service in 2007.
We now intend to retain the other, which is double-hulled, until 2009.

Outside the US, the specialist ﬂeet has grown from six ships in 2005
to 16 in 2006 (three tugs, two double-hulled lubricants oil barges and 11
offshore support vessels).

Time charter vessels
BP has 100 hydrocarbon-carrying vessels above 600 deadweight
tonnes on time charter, of which 83 are double-hulled and three are
double-bottomed. All these vessels are enrolled in BP’s Time Charter
Assurance Programme.

Spot charter vessels
To transport the remainder of the group’s products, BP spot charters
vessels, typically for single voyages. These vessels are always vetted
prior to use.

Other vessels
BP uses miscellaneous 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.

34

Gas, Power and Renewables

The Gas, Power and Renewables segment includes four main activities:
marketing and trading of gas and power; marketing of liqueﬁed natural
gas (LNG); natural gas liquids (NGLs); and low-carbon power generation
through our Alternative Energy business.

The strategic purpose of the segment comprises four elements:
– Develop a leading low-carbon power generation business across the

value chain.

– Access cost competitive supply.
– Capture distinctive world-scale gas market positions by accessing

key pieces of infrastructure.

– Expand gross margin by providing distinctive energy products and

services to selected customer segments and by optimizing the gas
and power value chains.

Key statistics

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

2005a

$ million
2004a

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Sales and other operating revenues

from continuing operations
Proﬁt before interest and tax from

continuing operations

Total assets
Capital expenditure and acquisitions

23,708

25,696

23,969

1,321
27,398
688

1,172
28,952
235

1,003
17,753
530

Profit before interest and tax from continuing operations includes profit after tax of
equity-accounted entities.

a On 1 January 2006, following the formation of the Alternative Energy business, certain
mid-stream assets and activities were transferred into Gas, Power and Renewables
and the 2005 and 2004 data above has been restated to reflect these transfers:
– South Houston Green Power co-generation facility (in the Texas City refinery) from

Refining and Marketing.

– Watson co-generation facility (in the Carson refinery) from Refining and Marketing.
– Phu My Phase 3 combined cycle gas turbine (CCGT) plant in Vietnam from

Exploration and Production.

The changes in sales and other operating revenues are explained in more
detail below.

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

$ million

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Gas marketing sales
Other sales (including NGLs

marketing)

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

2005

2004

11,428

15,222

13,532

12,280

23,708

10,474
25,696

10,437
23,969

mmcf/d

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

3,685

5,096

5,244

Gas marketing sales volumes
Natural gas sales by Exploration

and Production

5,152

4,747

3,670

We seek to maximize the value of our gas by targeting high-value
customer segments in selected markets and to optimize supply around
our physical and contractual rights to assets. Marketing and trading
activities are focused on the relatively open and deregulated natural gas
and power markets of North America, the UK and the most liquid trading
locations in continental Europe. Some long-term natural gas contracting
activity is included within the Exploration and Production business
segment because of the nature of the gas markets when the long-term
sales contracts were agreed.

Our LNG business develops opportunities to capture sales for our
upstream natural gas resources, working in close collaboration with the
Exploration and Production business. For sales into non-liquid markets
such as Japan and Korea, we aim to secure contracts with high-value
customers. For the majority of sales into liquid wholesale markets such
as the US and UK, we are building integrated supply chains covering
production, liquefaction, shipping, regasiﬁcation and access to the
wholesale transmission grid. Our strategy is to capture a growing share
of the internationally traded gas market. We are focusing on markets that
offer signiﬁcant prospects for growth. Our LNG activities involve the
marketing of third-party LNG as well as BP equity volumes, where this
allows us to optimize our existing asset and contractual positions.

Our NGLs business is engaged in the processing, fractionation and
marketing of ethane, propane, butanes and pentanes extracted from
natural gas. We have a signiﬁcant NGLs processing and marketing
business in North America. Our NGLs activity is underpinned by our
upstream resources and serves third-party markets for chemicals and
clean fuels as well as supplying BP’s reﬁning activities.

Globally, the power sector is the largest source of greenhouse gas
(GHG) emissions, which are responsible for about twice the emissions
from transport. Creating low-carbon power is therefore critical in the effort
to stabilize global GHG emissions. BP is focused on power generation
activities with low-carbon emissions. In 2005, we announced our plans
to invest in a new business called BP Alternative Energy, which aims to
extend signiﬁcantly our capabilities in solar, wind power, hydrogen power
and gas-ﬁred power generation.

Capital expenditure and acquisitions for 2006 was $688 million,
compared with $235 million in 2005 and $530 million in 2004. In 2006,
this included the acquisitions of Orion Energy, LLC, and Greenlight
Energy, Inc. In 2005 and 2004, there were no acquisitions. Capital
expenditure excluding acquisitions for 2007 is planned to be around
$900 million. The increase over the 2006 level primarily reﬂects our
project programme, including continuing investment in the Alternative
Energy business.

Marketing and trading activities
Gas and power marketing and trading activity is undertaken primarily in
the US, Canada, the UK and continental Europe to market BP’s gas and
power production and manage market price risk as well as to create
incremental trading gains 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
and the group enters into these transactions on a large scale to meet
these objectives.

The group also has an NGLs trading activity in the US for delivering
value across the overall NGLs supply chain, sourcing optimal feedstock to
our processing assets and securing access to markets with ﬂexible and
competitive supply.

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. Gas futures and options are traded
through exchanges, while over-the-counter options and swaps are used
for both gas and power transactions through bilateral 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.
Over-the-counter 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. Capacity contracts allow
the group to store, transport gas and transmit power between these
locations. Additionally, activity is undertaken to risk manage power
generation margins related to the Texas City co-generation plant using
a range of gas and power commodity derivatives.

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.

– Over-the-counter (OTC) contracts

These contracts are typically in the form of forwards, swaps and
options. OTC contracts are negotiated between two parties and are not

BP Annual Report and Accounts 2006

35

traded on an exchange. These contracts can be used both as part of
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. Although these contracts specify delivery terms for
the underlying commodity, in practice a signiﬁcant volume 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 is the main variable term.
Swaps are 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 prevailing on the delivery date when title to the inventory
passes. Term contracts are contracts to purchase or sell a commodity
at regular intervals over an agreed term. Though spot and term
contracts may have a standard form, there is no offsetting mechanism
in place. These transactions result in physical delivery with operational
and price risk. Spot and term contracts relate typically to purchases of
third-party gas and sales of the group’s gas production to third parties.
Spot and term sales are included in sales and other operating
revenues, when title passes. Similarly, spot and term purchases are
included in purchases for accounting purposes.
See Financial and operating performance – Gas, Power and

Renewables on page 53.

Trading investigations
See Legal proceedings on page 85 for details regarding investigations
into various aspects of BP’s trading activities.

The independent review, commissioned by BP, of the current

compliance approach in the group’s US trading organization has been
completed. A number of recommendations have been made in regard
to the design and effectiveness of the compliance processes and
procedures. BP is fully implementing these recommendations.

North America
BP is one of the leading wholesale marketers and traders of natural gas in
North America, the world’s largest natural gas market. Our business has
been built on the foundation of our position as the continent’s leading
producer of gas based on volumes. Our gas activity in the US and Canada
has grown as the group increased its scale through both organic growth
of operations and the acquisition of smaller marketing and trading
companies, increasing reach into additional markets. At the same time,
the overall volumes in these markets have also increased. The group also
trades power, in addition to selling and risk managing production from the
Texas City co-generation facility in the US.

The scale of our gas and power businesses in North America grew
over the period 2004-2006 because of a number of factors: (i) increased
access to transport rights; (ii) increase in our trading activities; and (iii)
growth from the acquisition of small regional marketing businesses. The
OTC market for NGLs also developed during this period but the scale of
activity was not signiﬁcant in the context of the group’s overall marketing
and trading activity.

Our North American natural gas marketing and trading strategy seeks to

provide unconstrained market access for BP’s equity gas. Our marketing
strategy targets high-value customer segments through fully utilizing our
rights to store and transport gas. These assets include those owned by

36

BP and those contractually accessed through agreements with third
parties such as pipelines and terminals.

Europe
The natural gas market in the UK is signiﬁcant in size and is one of the
most progressive in terms of deregulation when compared with other
European markets. BP is one of the largest producers of natural gas in
the UK based on volumes. The majority of natural gas sales are to power-
generation companies and to other gas wholesalers via long-term supply
deals. Some of the natural gas continues to be sold under long-term
supply contracts that were entered into prior to market deregulation. In
addition to the marketing of BP gas, commodity derivative contracts are
used actively in combination with assets and rights to store and transport
gas to generate trading gains. This may include storing physical gas to sell
in future periods or moving gas between markets to access higher prices.
Commodity contracts such as over-the-counter forward contracts can be
used to achieve this, while other commodity contracts such as futures
and options can be used to manage the market risk relating to changes
in prices.

As UK gas markets become increasingly connected to continental
Europe, it is important that we maintain our understanding of how wider
European gas markets work. We therefore trade in continental Europe.
In Europe, our main marketing activities are currently in Spain. The

Spanish natural gas market has continued to grow and is now deregulated
ahead of the deadlines set by European law. Since April 2000, we have
built a market position that currently places us as one of the leading
foreign entrants into the Spanish gas market.

Following Spanish deregulation, our 5% shareholding in Enagas, the
Spanish gas transport grid operator, was no longer considered strategic
and in November 2006 we divested these shares.

Liqueﬁed natural gas
Our LNG and new market development activities are focused on
establishing international market positions to create maximum value
from our upstream natural gas resources and on capturing third-party
LNG supply to complement our equity ﬂows.

BP Exploration and Production has interests in major existing LNG
projects in Trinidad, ADGAS in Abu Dhabi, Bontang in Indonesia and the
North West Shelf in Australia. Additional LNG supplies are being pursued
through an expansion of the existing LNG facilities at the North West
Shelf project in Australia and greenﬁeld developments in Indonesia
(Tangguh) and Angola. BP has no proved reserves associated with its
interests in LNG projects in Abu Dhabi and Angola.

We continue to access major growth markets for the group’s equity
gas. In Asia Paciﬁc, agreements for the supply of LNG from the Tangguh
project (BP 37.2%) have been signed with POSCO and K-Power for
supply to South Korea and with Sempra for supply to the Mexican and
US markets. Together with an earlier agreement to supply LNG to China,
these agreements mean that markets for more than 7 million tonnes
a year (380bcf) of Tangguh LNG have been secured. In March 2005,
Tangguh received key government approvals for the two-train launch and
the project consortium is now executing the major construction contracts,
with start-up planned in late 2008. During 2006, further progress was
made in securing contracts for LNG to be derived from the remaining
uncontracted reserves at the North West Shelf project.

In the Atlantic and Mediterranean regions, signiﬁcant progress has also
been made in creating opportunities to supply LNG to North American and
European gas markets. The fourth LNG train at Atlantic LNG in Trinidad,
with a capacity of 5.2 million tonnes per annum (mtpa) (253bcf), began
operations in late 2005. BP is marketing its LNG entitlement directly,
utilizing BP-controlled LNG shipping and contractual rights to access
import terminal capacity in the liquid markets of the US (Cove Point and
Elba Island) and the UK (Isle of Grain). These BP-marketed volumes
supplement a 2005 long-term agreement with Egyptian Natural Gas
Holding Company (EGAS) of Egypt to purchase 1.45 billion cubic metres
per year of LNG from the Spanish Egyptian Gas Company (SEGAS) plant
at Damietta, short-term contracts to purchase LNG from Oman and Qatar
and periodic ‘spot’ purchases of LNG. We have signed a memorandum of
understanding with Brass River LNG in Nigeria to purchase around
2 million tonnes a year of LNG, starting in 2010 for 20 years, which will be
supplied to multiple markets in the Atlantic basin.

In south-east China, the Dapeng LNG import and regasiﬁcation terminal

and Trunkline Project (BP 30%) in Guangdong province received its ﬁrst
commissioning cargo during May 2006 and commenced commercial
operations in September. LNG for the terminal is supplied under a long-
term contract signed with Australia LNG in October 2002 that involves
deliveries from the North West Shelf project (BP 16.7% infrastructure and
oil reserves/15.8% gas and condensate reserves).

BP continues to progress options for new terminal development in
the US. The proposed 1.2 billion cubic feet per day (bcf/d) Crown Landing
terminal is to be located on the Delaware River in New Jersey. The
Federal Energy Regulatory Commission (FERC) granted its approval for
the siting, construction and operation of this project during 2006. BP
continues to work with the State agencies in New Jersey to complete
State permitting requirements and with the relevant federal, state and
local authorities to put in place security plans for the facility and
associated shipping activities. BP is also monitoring the progress of a
proceeding ﬁled by the State of New Jersey against the State of
Delaware in the US Supreme Court concerning New Jersey’s jurisdiction
over developments on its shores, including the project’s loading jetty that
extends into the Delaware River. The court has agreed to hear the case.

Natural gas liquids
With global demand for NGLs, both as a chemicals feedstock and as a
cleaner fuel, forecast to grow in excess of 3% a year, this business is
expected to offer potential for further growth. Based on sales volumes,
we are one of the leading producers and marketers of NGLs in North
America and hold interests for NGL volumes in the UK and Egypt.

NGLs produced in North America from gas chieﬂy sourced out of
Alberta, Canada, and the US onshore and Gulf Coast, are used as a
heating fuel and as a feedstock for reﬁneries and chemicals plants. NGLs
are sold to petrochemicals plants and reﬁneries, including our own. In
addition, a signiﬁcant amount of NGLs are marketed on a wholesale basis
under annual supply contracts that provide for price redetermination
based on prevailing market prices.

We operate natural gas processing facilities across North America, with
a total capacity of 6.4bcf/d. These facilities, which we own or in which we
have an interest, are located in major production areas across North
America, including Alberta, Canada, the US Rockies, the San Juan basin
and the Gulf of Mexico. We also own or have an interest in fractionation
plants (that process the natural gas liquids stream into its separate
component products) in Canada and the US, and own or lease storage
capacity in Alberta, eastern Canada, and the US Gulf Coast, as well as the
US West Coast and mid-continent regions. Our North American NGL
processing capacity utilization in 2006 was 75%. In addition, we have
entered into a long-term supply contract with Aux Sable Liquid Products
to secure additional NGLs to supply our customers in the US Midwest.
BP operates one plant in the UK (capacity 1.2bcf/d) and we are a
partner (33.33%) in a gas processing plant in Egypt with 1.1bcf/d of gas
processing capacity. We have also secured access to the Abibes LPG
terminal in Cremona, northern Italy. During the ﬁrst quarter of 2006, a
memorandum of understanding was signed with EGAS for a feasibility
study covering construction of a greenﬁeld NGLs plant in the West Nile
Delta, Egypt, that would process gas from future BP equity and third-party
production offshore.

Alternative energy
BP Alternative Energy is focused on the power generation sector – the
largest single source of emissions from the use of fossil fuels – and aims
to extend BP’s capabilities in solar, wind, hydrogen and gas-ﬁred power
generation to produce low-carbon power. Its activities include the
production and marketing of solar panels; development of wind farms;
generation of electricity from hydrogen power using sequestration in
which carbon is captured and stored; and gas-ﬁred power generation,
which typically emits only half as much CO2 as a conventional coal-ﬁred
station. The business brings together the group’s existing activities in
these technologies with our power marketing and trading capabilities
to form a single business.

In 2005, BP Alternative Energy announced its plans to invest up to

$8 billion over 10 years. This investment is expected to be spread
in broadly equal proportions between solar, wind, hydrogen and high-
efﬁciency gas-ﬁred power generation.

Solar
BP Solar’s main production facilities are located in Frederick, Maryland,
US; Madrid, Spain; Sydney, Australia; and Bangalore, India. During 2006,
the expansion of our manufacturing facilities in India and Spain doubled
our production capacity from 100MW in 2004 to 200MW, keeping us on
track to triple capacity from 2005 levels by 2008. During 2007, expansion
of cell capacity will continue at our Madrid and Bangalore facilities,
alongside a $70-million project to expand casting capacity at Frederick.
BP Solar achieved sales of 93MW (2005 105MW and 2004 99MW).

We made good use of technology to manage the current silicon supply
issue last year: developing a new silicon growth process named Mono2,
which signiﬁcantly increases cell efﬁciency over traditional multi-
crystalline-based solar cells. Solar cells made with these wafers, in
combination with other BP Solar advances in cell process technology, are
expected to be able to produce between 5% and 8% more power than
solar cells made with conventional processes. We also teamed up with
the California Institute of Technology to launch a multi-million dollar
research programme to explore a radically new way of producing solar
cells, based on the growth of silicon on ‘nanorods’, which could improve
efﬁciency and make solar electricity much more competitive. In Germany,
we signed a co-operation agreement with the Institute of Crystal Growth
(IKZ) to develop a process for depositing silicon on glass that has the
potential to reduce the amount of silicon feedstock used in cell
production. In Spain, BP Solar and Banco Santander have formed an
alliance that will allow for the construction of up to 278 photovoltaic solar
power installations in Spain, with total capacity of 18-25 megawatts peak.

Wind
We are building expertise in wind energy and implementing projects. We
operate two wind farms in the Netherlands, 9MW at our oil terminal in
Amsterdam and 22.5MW at the Nerefco oil reﬁnery (both the reﬁnery and
wind farm are jointly owned with Chevron (BP 69%)), providing electricity
to the local grid.

In the US, we entered into a long-term supply agreement with Clipper

Windpower plc with options to purchase Clipper turbines, with a total
capacity of 2,250MW. During 2007, we plan to begin construction of ﬁve
wind power generation projects, located in four states – California,
Colorado, North Dakota and Texas. The projects are expected to deliver a
combined generation capacity of some 550MW.

During 2006, BP Alternative Energy also acquired Orion Energy, LLC,
and Greenlight Energy, Inc. With the acquisition of these large-scale wind
energy developers, our North American wind portfolio includes
opportunities to develop almost 100 projects with potential total
generating capacity of some 15,000MW.

Gas-ﬁred power
Gas-ﬁred power stations typically emit around half as much CO2 as
conventional coal-ﬁred plants.

We operate a 776MW gas-ﬁred power generation facility and an
associated LNG regasiﬁcation facility at Bilbao, Spain (BP 25% share in
each) and a 750MW co-generation plant at Texas City, US (50:50 joint
venture with Cinergy Solutions, Inc.), which supplies power and steam to
BP’s largest reﬁning and petrochemicals complex. BP supplies natural gas
to the Texas City plant and will use excess generation capacity to support
power marketing and trading activities. Also, a 50MW co-generation plant
near Southampton, UK (BP 100%), has been in operation since the ﬁrst
half of 2005. The construction of K-Power’s (BP 35%) 1,074MW gas-ﬁred
combined cycle power plant at Kwangyang, Korea, was completed and
full commercial operations started in the second quarter of 2006.

We have started construction of a new 250MW steam turbine power
generating plant at the Texas City reﬁnery site, which is expected to bring
the total capacity of the site to 1,000MW when completed in 2008. We
also plan to construct a 520MW co-generation facility at Cherry Point,
Washington, US.

Hydrogen power
During 2006, we announced a new strategic relationship with General
Electric to accelerate the development of hydrogen power technology and
the deployment of the concept. Progress on our proposed hydrogen plant
at Carson, California, US, continued and we were awarded $90 million in
US Federal Investment credits.

BP Annual Report and Accounts 2006

37

Other businesses and corporate

Technology

Other businesses and corporate comprises Finance, the group’s
aluminium asset, its investments in PetroChina and Sinopec (both
divested in early 2004), interest income and costs relating to corporate
activities worldwide. Following the sale of Innovene to INEOS in 2005,
three equity-accounted entities (Shanghai SECCO Petrochemical
Company Limited in China and Polyethylene Malaysia Sdn Bhd and
Ethylene Malaysia Sdn Bhd, both in Malaysia) previously reported in Other
businesses and corporate were transferred to Reﬁning and Marketing,
effective 1 January 2006. The 2005 and 2004 data below has been
restated to reﬂect these transfers.

Key statistics

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

2005

$ million

2004

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Sales and other operating revenues

for continuing operations

1,009

668

546

Proﬁt (loss) before interest and tax
from continuing operationsa

Total assets
Capital expenditure and acquisitions

(885)
14,184
281

(1,237)
12,144
817

155
21,795
2,130

a Includes profit after interest and tax of equity-accounted entities.

Finance
Finance co-ordinates the management of the group’s major ﬁnancial
assets and liabilities. From locations in the UK, the US and the Asia Paciﬁc
region, it provides the link between BP and the international ﬁnancial
markets and makes available a range of ﬁnancial services to the group,
including supporting the ﬁnancing of BP’s projects around the world.

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.

Research, technology and engineering
Research, technology and engineering activities are carried out by each
of the major business segments on the basis of a distributed programme
co-ordinated by a technology co-ordination group. This body provides
leadership for scientiﬁc, technical and engineering activities throughout
the group and in particular promotes cross-business initiatives and the
transfer of best practice between businesses. In addition, a group of
eminent industrialists and academics forms the Technology Advisory
Council, which advises senior management on the state of technology
within the group and helps to identify current trends and future
developments in technology.

Research and development 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
technology solutions to be considered and implemented, improving
the productivity of research and development activities.

Across the group, expenditure on research for 2006 was $395 million,

compared with $502 million in 2005 and $439 million in 2004.

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

38

The realization of technological advancements is pivotal to our strategic
progress and business performance. It is also the key to ﬁnding and
developing solutions that meet the energy and climate challenges of the
21st century.

The sheer range and complexity of technologies that can affect our

businesses and the wide variety of sources for these technologies –
proprietary, energy service sector, universities and research institutions
and other industries – mean that no single approach can meet all
our needs.

The following guiding principles underpin our approach to technology:
– Deliver technology leadership in a select few areas of distinctiveness.
– Develop innovative and sustainable technology-based solutions for

corporate renewal.

– Drive rapid take-up of proprietary and commercially available

technologies.

– Innovate and test technology at material scale.
– Develop and access world-class skills and collaborate internally and

externally.

These principles are reﬂected in how we deﬁne technology investment.
Whereas research and development is an externally reported number,
internally we use a broader but very speciﬁc deﬁnition for technology
investment. This consists of four elements: technology development for
incremental improvement of our base businesses; technology leadership
areas to create and sustain material, advantaged business positions;
long-term technology investments to secure our future; and application
and propagation of technology through formalized technology networks
and knowledge management processes.

Our ﬁve-year technology plan provides for sustained investment in our

core technologies and increasing investment in long-term technologies.
As we have deepened our current areas of leadership, extended their
application in the ﬁeld and broadened our long-term technology portfolio,
our technology investment has grown at an average of 15% a year
between 2003 and 2006. In 2006, total technology investment was
around $890 million.

During 2006, we continued to advance and employ new technologies

in drilling and well construction, unconventional gas development,
enhanced oil recovery and seismic imaging. These technologies have
enabled discoveries in the deepwater Gulf of Mexico and Angola,
increased production from tight gas ﬁelds in the continental US and
increased recoveries from our ﬁelds in maturing basins, such as
Alaska and the North Sea.

Technology advancements are also broadening our reﬁning capability to
understand and process ever-lower quality crudes and optimize our assets
in real time, enhancing the ﬂexibility and reliability of our reﬁneries. Our
proprietary technologies in PTA have continued to reduce manufacturing
costs and environmental impact.

Our long-term technology priorities ﬁt into three categories of activity:

technologies that enhance our capability to identify new hydrocarbon
resources and better exploit those we have; technologies that convert
hydrocarbon feedstocks into efﬁcient fuels and chemicals; and
selected low-carbon technologies for power and transport to minimize
CO2 emissions.

During 2006, we announced plans to establish a dedicated biosciences
energy research laboratory and invest $500 million over the next 10 years.
On 1 February 2007, BP announced that it had selected the University of
California, Berkeley, and its partners the University of Illinois at Urbana-
Champaign and the Lawrence Berkeley National Laboratory, for the
research programme. The Energy Biosciences Institute’s aim will be to
explore the application of bioscience and the production of new and
cleaner energy, initially focusing on renewable biofuels for road transport.
It will also pursue bioscience-based research in three other key areas: the
conversion of heavy hydrocarbons to clean fuels; improved recovery from
existing oil and gas reservoirs; and carbon sequestration.

Regulation of the group’s business

Safety, environmental and social performance

BP’s exploration and production activities are conducted in many different
countries and are therefore subject to a broad range of legislation and
regulations. These cover virtually all aspects of exploration and production
activities, including matters such as licence acquisition, production rates,
royalties, pricing, environmental protection, export, taxes and foreign
exchange. The terms and conditions of the leases, licences and contract
under which these oil and gas interests are held vary from country to
country. These leases, licences and contracts are generally granted by
or entered into with a government entity or state company and are
sometimes entered into with private property owners. These
arrangements with governmental or state entities usually take the
form of licences or production-sharing agreements. Arrangements with
private property owners are usually in the form of leases.

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

Production-sharing agreements entered into with a government entity

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

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

Frequently, BP conducts its exploration and production activities in
joint venture with other international oil companies, state companies or
private companies.

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

BP’s other activities, including its interests in pipelines and its
commodities and trading activities, are also subject to a broad range
of legislation and regulations in various countries in which it operates.
Health, safety and environmental regulations are discussed in more

detail in Environmental protection on page 42.

For certain information regarding environmental proceedings, see

Environmental protection – US regional review on page 45.

This section reviews BP’s 2006 performance with respect to safety,
the environment, employees and relations with communities. A more
comprehensive report on our non-ﬁnancial performance will be found
in BP Sustainability Report 2006.

BP’s approach to being a responsible business has three levels. At the

ﬁrst level, we work to comply with local laws and regulations. At the
second level, we seek to go further than regulations require, setting our
own standards and designing processes to help us meet them. At the
third level – beyond our own operations and our direct control – we have a
role to play in addressing issues that are relevant to our work, such as
climate change and sustainable development.

BP’s operations
Safety
During 2006, we took action to address a number of speciﬁc safety issues
as well as building more comprehensive systems for managing them,
including speciﬁc investments and targeted programmes in response to
the March 2005 explosion and ﬁre at the Texas City reﬁnery.

As a group, we aspire to be an industry leader in the three dimensions
of safety – personal safety, process safety and the environment. BP has a
strong track record in personal safety and on the environment but we
have more to do to move towards process safety excellence.

In total, there were seven workforce fatalities in the course of BP’s
operations during 2006, compared with 27 fatalities in 2005. We deeply
regret the loss of these lives. The 2006 ﬁgure has reduced signiﬁcantly to
the lowest level in nearly 20 years of reporting. This includes a reduction
in driving-related fatalities, which were 14 in 2003, to two in 2006, after
we implemented our new driving safety standard. Our reported
recordable injury frequency fell to 0.47 per 200,000 hours worked, the
lowest in our recorded history.

For many years, we have operated using a management system called

getting HSE right (gHSEr) and we are building on this foundation to
strengthen our approach to safety, particularly process safety. To help
sustain and reinforce this momentum, we have formalized our approach
by establishing a group operations risk committee (GORC) as a
subcommittee of the group chief executive’s meeting (GCEM). Its
membership consists of heads of operating segments, the group
managing director responsible for safety, the deputy chief executive of
exploration and production, the head of the safety and operations function
and the group engineering director. The role of this committee is to
provide assurance that group operational risks are being identiﬁed
and managed in accordance with approved policy and to guide BP’s
overall approach.

The main focus for GORC is management systems, particularly
for process safety, across the group. The immediate priority for this
committee is to monitor the implementation of a six-point plan to apply
lessons learned from the Texas City incident and other priorities (see
below). GORC is overseeing a detailed review of process safety
measures and practices across BP’s operations to identify improvements.

Over time, we will consolidate these management system

improvements into a sustainable, integrated framework incorporating
strengthened standards and based on a commitment to continuous
improvement. This will form part of a new operating management system
(OMS) that will incorporate and expand on gHSEr, underpinned by a
consistent set of standards and processes covering health, safety,
operational integrity and environmental issues. The ﬁrst wave of
implementation of the OMS began in January 2007 in all our US
reﬁneries and other selected locations across our worldwide operations.

BP Annual Report and Accounts 2006

39

Continuing response to Texas City incident and inquiries
During 2006, investigations continued into the March 2005 Texas
City explosion. There was also ongoing action on our part to apply the
lessons learned. BP settled a large number of civil suits arising from, and
established a $1.625-billion provision related to, the incident. In terms of
action at the reﬁnery itself, having concluded our own inquiry during 2005
and reached a settlement with OSHA, we have launched a programme in
which we expect to invest an estimated $1 billion from 2006 to 2010 to
improve and maintain the site. At the end of 2006, changes made at
Texas City included: restarting the operations after the shutdown for
Hurricane Rita; extensive mechanical renovation; installing a new ﬂare
system; moving temporary buildings away from speciﬁed areas; relocating
more than 400 Texas City workers into a new ofﬁce building outside the
fence line; commissioning of plant, involving more than 15 million worker
hours to date, refurbishment and safe start-up of a 27-mile steam system;
and implementation of an enhanced total systems training programme.

In January 2007, the company received the report of the BP US
Reﬁneries Independent Safety Review Panel (the panel), which was
chaired by former US Secretary of State James A Baker, III (see Report of
the BP US Reﬁneries Independent Safety Review Panel on page 29). The
panel was established on the recommendation of the US Chemical Safety
and Hazard Investigation Board. Throughout 2006, the panel assessed the
effectiveness of corporate oversight of safety management systems at
BP’s US reﬁneries and the corporate safety culture.

The panel’s report identiﬁed deﬁciencies in process safety performance

at BP’s US reﬁneries and called on BP to give process safety the same
priority that it had historically given to personal safety and the reduction of
GHGs and promotion of alternative forms of energy. In making its ﬁndings
and recommendations, the panel’s objective was excellence in process
safety performance, not simply legal compliance. The panel speciﬁcally
noted that ‘during the course of its review, it saw no information to
suggest that anyone – from BP’s board members to its hourly workers –
acted in anything other than good faith’.

The panel made 10 recommendations relating to: process safety
leadership; integrated and comprehensive process safety management
system; process safety knowledge and expertise; process safety culture;
clearly deﬁned expectations and accountability for process safety; support
for line management; leading and lagging performance indicators for
process safety; process safety auditing; board monitoring; and industry
leader. The panel’s report in its entirety can be found at
www.bp.com/bakerpanelreport.

The panel acknowledged the measures BP had taken since the Texas

City incident, including dedicating signiﬁcant resources and personnel
intended to improve the process safety performance at BP’s US
reﬁneries. BP has committed to implement the panel’s recommendations
and will consult with the panel on how best to do this across the US
reﬁneries and to apply the lessons learned elsewhere in its global
operations. As announced in July 2006, there was an increase in spending
at the ﬁve US reﬁneries, from $1.2 billion to $1.5 billion a year, with
further increases to $1.7 billion a year for the period 2007 to 2010,
representing a step-up in scale as well as pace.

Alaska spills
During 2006, two incidents occurred in our operations at Prudhoe Bay,
Alaska. In March, an undetected leak led to a spill of approximately 4,800
barrels. In August, the eastern part of the ﬁeld was shut down as a
precaution following the discovery of isolated pitting corrosion that
resulted in a spill of 199 barrels of oil from an oil transit in a pipeline.
Following inspection of the transit lines, production restarted in the
eastern part of the ﬁeld in 44 days.

Using smart pigs, devices that are run through the inside of the pipeline

to inspect the pipe walls, we have now conﬁrmed sufﬁcient integrity for
current operations. Nonetheless, we have decided to replace the main oil
transit lines (16 miles) in both the eastern and western operating areas of
Prudhoe Bay. In addition, we plan to spend over $550 million (net) over
the next two years on integrity management in Alaska. We have retained
three of the world’s foremost corrosion experts, who will independently
review these programmes.

40

Action on process safety across BP
Throughout 2006, we continued to implement the improvements initiated
following the Texas City incident and supplemented them with new
measures as necessary. These included inspecting and investing in our
plants; training and development to ensure people have the right skills and
behaviours; and working to ensure we have clear, consistent and rigorous
processes for managing safety. We have earmarked $7 billion for safety
investments over four years to upgrade our US reﬁneries and to repair
and replace pipelines in Alaska. We also appointed a new chairman and
president for BP America Inc. and announced the creation of an external
advisory board to provide expert advice in the US on compliance, safety
and regulatory affairs.

In particular, during 2006 a group-wide programme was introduced

known as the six-point plan to address the following points:
– Removing blow-down stacks and moving temporary buildings away

from potential hazards.

– Conducting major accident risk assessments at plants and acting on

their ﬁndings.

– Implementing new group standards that set detailed requirements

on control of work and integrity management.

– Ensuring compliance with applicable laws and regulations.
– Rapidly addressing ﬁndings from past audits.
– Building competence in safety and operations through training

and development.
During 2006, the total number of oil spills of one barrel or more from all
of our operations was 417, compared with 541 in 2005 and 1,098 in 1999.
The difference between the reported number of spills in 2005 and 2006 is
principally due to boundary changes, including the disposal of Innovene.
During 2006, we continued to expand our shipping ﬂeet of operated
and time-chartered vessels in order to provide more protection against the
risk of a major oil spill. All vessels on BP business are subject to our
health, safety, security and environmental (HSSE) requirements. The ﬂeet
transformation is ahead of the international requirements for phase-out of
single-hulled vessels. Our international ﬂeet has grown from 52 vessels in
2005 to 57 in December 2006, all of which are double-hulled. We also
have 100 vessels on time charter, of which 83 are double-hulled and three
double-bottomed. In addition, we use spot charter, regional, specialist and
miscellaneous craft. In 2006, we launched SafeShips, an education and
information programme highlighting safety for our seafarers and shore
staff. It covers a wide range of safety-related topics, including risk
assessments, operations safety, best practice and safety by design.

Our operations and the environment
During 2006, we continued working to reduce the environmental impact
of our operations, primarily by reducing our emissions of greenhouse
gases (GHGs) and by implementing processes to drive continuous
improvements in a wide range of other environmental issues. In our
operations since 2001, we have been aiming to offset half of the
underlying GHG emission increases that result from our growing business
through operational efﬁciency projects. After ﬁve years, we estimate that
emissions growth of some 11 million tonnes has been offset by around
6 million tonnes of sustainable reductions.

Our 2006 operational GHG emissions were 64.4 million tonnes (Mte)

of carbon dioxide equivalent on a direct equity basis compared with a
reported ﬁgure of 78.0Mte in 2005, of which 11.2Mte related to Innovene
assets divested late in 2005. Our 2006 emissions were therefore some
2.4Mte lower than the comparable 2005 emissions of 66.8Mte (excluding
Innovene’s 2005 contribution).

Our track record of improvement from our ongoing efﬁciency

programme continues, with reductions of 1.2Mte. The remaining 1.2Mte
decrease comes from the balance of the growth of our business (1.3Mte),
the effect of acquisitions and divestments, temporary operational
variations and reporting protocol changes.

We have taken part in the EU Emissions Trading Scheme since its
launch in January 2005. We began 2006 with 18 participating installations
and, during the year, our BP Solar facility in Madrid also began
participating in the scheme. These 19 installations account for around one-
ﬁfth of our reported 2006 global GHG emissions.

2006 saw the culmination of two years’ work with the launch in

November of a new group practice called the Environmental
Requirements for New Projects. Work on this practice began in 2004

after we were challenged by some investors over our processes for
working in environmentally sensitive areas. We acknowledged the scope
for improvement and designed the new requirements to include
processes for early project screening, environmental impact assessments
throughout the entire project life cycle, external consultation and
operational performance requirements. These requirements cover a
wide range of environmental impacts, ranging from GHG emissions and
water management to impacts on communities and wildlife.

In 2006, no new decisions were taken by BP to explore or develop
in World Conservation Union (IUCN) category I-IV areas. We constantly
try to limit the environmental impact of our operations by using natural
resources responsibly and reducing waste and emissions. All our major
sites, except two, are certiﬁed to the ISO 14001 international standard on
environmental management. The Texas City reﬁnery intends to recertify
after completing planned work to strengthen its HSE management
systems, while an acetyls plant in Malaysia was only recently added to our
reporting boundary for ISO 14001.

People
We seek to attract, develop and retain highly talented people, using
appropriate incentives, in order to maintain the capability of the group
to deliver our strategy and plans. As a global group, we believe our
workforce, leadership and recruitment should reﬂect the communities in
which we operate. We therefore run programmes designed to ensure that
we increase the number of local leaders and employees in our operations.

Our policy is to ensure equal opportunity in recruitment, career

development, promotion, training and reward for all employees,
including those with disabilities. Where existing employees become
disabled, our policy is to provide continuing employment and training
wherever practicable.

We now have a number of programmes in place to help raise our senior

level leaders’ awareness of diversity and inclusion (D&I). Our ‘Managing
Inclusion’ programme is recommended for all senior level leaders in the
US. We have also developed a web-based resource that uses interactive
tools to present the business case for D&I, give guidance on D&I
leadership and provide a gateway to other learning opportunities.

At the end of 2006, 17% of our top 622 leaders were female and 20%

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 recruit people in the
hope that they will spend a signiﬁcant portion of their careers with BP.
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 2006, we appointed 70 people to
positions in the 622-strong group leadership. Of these, 50 were internal
candidates. We provide development opportunities for our employees,
including training courses, international assignments, mentoring, team
development days, workshops, seminars and online learning. We
encourage everyone to take ﬁve training days a year. In our two-yearly
People Assurance Survey of employees, conducted in 2006 and
completed by 73% of those eligible, the level of satisfaction was 66%.
We had approximately 97,000 employees as at 31 December 2006,
compared with approximately 96,200 at 31 December 2005. We continue
to support employee share ownership. Through our award-winning
ShareMatch plan, run in more than 70 countries, we match BP shares
purchased by employees.

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

The code of conduct
We have a code of conduct, launched in 2005, designed to ensure that all
employees comply with legal requirements and our own standards. The
code deﬁnes what BP expects of its people, providing expectations in key
areas such as safety, workplace behaviour and use of IT. It also provides
references to show employees where they can ﬁnd more detailed

guidance on speciﬁc areas. Our strict anti-corruption policy includes a
prohibition on making facilitation payments and is incorporated in the
code of conduct.

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 was 1,064 in 2006, compared with 634 in 2005.
Another avenue for raising concerns was opened in the US in

September 2006 when BP America’s president and chairman appointed
former US District Court Judge Stanley Sporkin to be BP America’s
ombudsperson. This followed concerns raised in Alaska and elsewhere.
His role is to serve as a neutral and supportive adviser whom employees
and contractors can conﬁdentially contact at any time 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 2006, this included the reported
dismissal of 642 people for non-compliance or unethical behaviour. (This
number excludes some dismissals from the retail business including
those for minor or immaterial incidents.) BP has taken a number of steps
to improve compliance performance within its supply and trading function.
The independent review, commissioned by BP, of the current compliance
approach in the group’s US trading organization has been completed.
A number of recommendations have been made in regard to the design
and effectiveness of the compliance processes and procedures. BP is
fully implementing these recommendations. The existing supply and
trading compliance function is being integrated into the group’s
Compliance and Ethics function to provide more independent oversight
over trading activities.

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

in party political activity or make any political contributions, whether in
cash or in kind. BP speciﬁcally made no contributions to UK or other EU
political parties or organizations in 2006.

Suppliers and contractors
Our processes are designed to enable us to choose suppliers carefully
on merit, avoiding conﬂicts of interest and inappropriate gifts and
entertainment. We expect suppliers to comply with legal requirements
and we seek to do business with suppliers who act in line with
BP’s commitments to compliance and ethics, as outlined in the code
of conduct.

We engage with suppliers in a variety of ways, including performance

review meetings to identify mutual improvements in performance.

We seek to have a positive inﬂuence on major issues beyond our own
operations. The two main areas where we seek to do so are climate
change and development.

BP and climate change
During 2006, we made further investments to increase the supply of low-
carbon energy, both for power and transport. Our activities came against
a background of intensifying public concern and debate over the issue.
As well as international negotiations on climate change in Nairobi, world
leaders at the G8 summit in St Petersburg recommitted themselves
to address the issue. In the US, a funding package was announced for
research into renewable and alternative technologies and, in the UK,
a government-commissioned report argued that the cost of failing to
act to avert climate change would outweigh the cost of acting to stabilize
GHG levels.

These developments reinforced our own support for taking

precautionary action as well as demonstrating the business opportunity
that is created by the growth of markets for low-carbon power. In our
view, the goal must be to take urgent but informed measures that will
stabilize GHG concentrations by delivering sustainable and cost-efﬁcient
long-term emission reductions. We must address the fact that fossil
fuels currently supply most of the energy people use and are projected
to remain fundamental to global energy supply for at least the next 20-30
years. Innovation to reduce CO2 emissions from the use of fossil
fuels will therefore be a major contributor to stabilization during this
period, alongside growing renewable energy industries. We believe that
governments and businesses must work together to develop appropriate

BP Annual Report and Accounts 2006

41

policy responses, recognizing the existence of different starting points,
perspectives, priorities and solutions and including the many potential
contributors to the common goal of addressing climate change. BP’s
actions focus on our own business activities and engaging in informed
external dialogue to inﬂuence policy, regulation and research. We support
the use of market mechanisms such as emissions trading to bring about
the most efﬁcient forms of emissions reduction.

BP Alternative Energy
In 2006, we made further progress in building BP Alternative Energy,
launched in 2005, into a substantial business providing cleaner low-
carbon power from solar, wind, hydrogen and natural gas. In 2005, we
announced that we are investing $8 billion over 10 years in BP Alternative
Energy to address the major opportunity presented by the low-carbon
power market. Globally, the power sector is the biggest source of GHG
emissions – responsible for around twice the emissions of transport – so
creating low-carbon power is critical in the effort to stabilize global GHG
levels. During 2006, BP Alternative Energy doubled its production capacity
of solar cells and modules from the capacity produced in 2004, entered
into research partnerships in the US and Germany to improve the
performance of solar technology, acquired US wind energy developers
Orion Energy, LLC, and Greenlight Energy, Inc., and signed an agreement
with Clipper Windpower plc for the supply of wind turbines and the joint
development of two gigawatts of wind capacity in the US. Our joint
venture with SK Corporation in South Korea saw operations start at the
combined cycle gas turbine power station, the Kwangyang plant, in which
BP has a 35% stake, and we have started construction of a new 250MW
steam turbine power generating plant at the Texas City reﬁnery site.
Looking ahead, we also plan to construct a 520MW co-generation facility
at Cherry Point in the US. During 2006, we announced a new strategic
relationship with General Electric to accelerate the development of
hydrogen power technology and the deployment of the concept. The
US government showed support for our proposed hydrogen plant at
Carson, California, by awarding the project $90 million in Federal
Investment credits.

Sustainable transport
In 2006, we increased our involvement in biofuels – fuels made from
crops, which limit GHG emissions from transport over their full life cycle
because they absorb CO2 as the crops grow. We launched a dedicated
biofuels business and announced that we would be investing $500 million
over 10 years in a university-based Energy Biosciences Institute at which
specialist researchers will apply their biotechnology expertise to energy.
On 1 February 2007, BP announced that it had selected the University of
California, Berkeley, and its partners the University of Illinois at Urbana-
Champaign and the Lawrence Berkeley National Laboratory for the
research programme. Our ambition is that bioscience will deliver
comparable beneﬁts in the energy sector to those achieved in medicine.
These new biofuels activities build upon our existing operations to
blend biocomponents into transport fuels in the US, Germany, Austria
and France.

We continued the roll-out of BP Ultimate, launched in 2003, in two
new markets, South Africa and Russia. This fuel delivers reductions in
emissions such as carbon monoxide and nitrogen oxide compared with
standard fuels.

We worked with several partners to develop lubricants that support
improvements in engine construction and emissions systems that are
intended to improve fuel efﬁciency and reduce pollution. We have also
developed longer-lasting driveline ﬂuids that reduce total oil volumes over
a vehicle’s lifetime and improve fuel efﬁciency by up to 1.5%. Closer
co-operation between lubricants development and manufacturing
processes have resulted in signiﬁcant energy and resource savings during
the blending of lubricants.

BP is also supporting a project at Tsinghua University in China to
investigate the challenges presented by the rapid growth of cities,
especially in Asia. The ﬁrst phase, completed in March 2006,
demonstrated the need for an integrated approach across
many disciplines.

42

BP and development
We wish to make a positive contribution to social and economic
development wherever we operate. Our aim is to be a ‘local energy
company’ – an accepted member of the community, but one that
contributes global resources, standards and capabilities.

Following this approach, we seek to bring local people into our

leadership and workforce and to bring local companies into our supply
chains. Consequently, as well as increasing the number of our leaders
who are from beyond the US and UK, we have also invested in training
and support for local companies in many countries. In 2006, we invested
$10.7 million in support of enterprise development. In countries such
as Azerbaijan, where we and our co-venturers have invested in local
enterprise development through the Regional Development Initiative, and
in Angola, BP has worked with the US NGO Citizens Development Corp
to set up the Centro De Apoio Empresarial business support centre.
We support micro-ﬁnance systems to make loans to small businesses
in Angola, Azerbaijan, Colombia, Georgia and Trinidad & Tobago.

During 2006, we acted as a member of the International Advisory
Group for the Extractive Industries Transparency Initiative (EITI), and we
remain represented on the board, which has replaced the International
Advisory Group. EITI provides guidelines for publicly disclosing the
amount of revenue governments receive from energy companies, so
people can see how much is available for public spending. BP continues
to support the implementation of the EITI in Azerbaijan.

In 2006, Professor Tony Venables was appointed as the ﬁrst BP

professor in the economics department of the University of Oxford, UK.
The chair was endowed in 2005, together with funding for the Oxford
Centre for the Analysis of Resource-Rich Economies, also in the
economics department of Oxford, to conduct research on resource-rich
economies and share best practice in managing energy revenues
effectively.

We also make direct contributions to communities through community

programmes. Our total contribution in 2006 was $106.7 million. This
includes $0.6 million contributed by BP to UK charities. The growing
focus of this is on education, the development of local enterprise and
providing access to energy in remote locations. We plan to spend around
$500 million in each ﬁve-year cycle focusing on these areas, with
enough ﬂexibility to respond to local needs as appropriate.

In 2006, we spent $63.9 million promoting education, with investment

in three broad areas: energy and the environment; business leadership
skills; and basic education in developing countries where we operate
large projects.

We also help to promote development by assisting in providing access

to various forms of energy in many countries, working alongside
governments, NGOs and aid agencies. For example, we provide solar
power for rural communities in countries such as Algeria, Sri Lanka and
the Philippines and we have set up a new business in India to provide
access to energy. Our ﬁrst offer is a biomass cooking stove to help
provide cleaner energy for cooking. Almost 13,000 customers have
purchased our biomass stove that signiﬁcantly reduces emissions
compared with traditional wood-burning stoves made of mud.

Environmental protection

Health, safety and environmental regulation
The group is subject to numerous national and local environmental
laws and regulations concerning its products, operations and activities.
Current and proposed fuel and product speciﬁcations under a number of
environmental laws will have a signiﬁcant effect on the production,
sale and proﬁtability of many of our products. Environmental laws and
regulations also require the group to remediate or otherwise redress 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, chemicals plants, natural
gas processing plants, oil and natural gas ﬁelds, service stations, terminals
and waste disposal sites. In addition, the group may have obligations
relating to prior asset sales or closed facilities. Provisions for
environmental restoration and remediation are made when a clean-up
is probable and the amount is reasonably determinable. Generally, their
timing coincides with the commitment to a formal plan of action or, if

earlier, on divestment or on closure of inactive sites. The provisions made
are considered by management to be sufﬁcient for known requirements.
The extent and cost of future environmental restoration, remediation

and abatement programmes are often inherently difﬁcult to estimate.
They depend on the magnitude of any possible contamination, the timing
and extent of the corrective actions required, technological feasibility and
BP’s share of liability relative to that of other solvent responsible parties.
Though the costs of future restoration and remediation 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.
See Financial statements – Note 40 on page 152 for the amounts
provided in respect of environmental remediation and decommissioning.
The group’s operations are also subject to environmental and common
law claims for personal injury and property damage caused by the release
of chemicals, hazardous materials or petroleum substances by the group
or others. Nineteen proceedings involving governmental authorities are
pending or known to be contemplated against BP and certain of its
subsidiaries under federal, state or local environmental laws, each of
which could result in monetary sanctions of $100,000 or more. No
individual proceeding is, nor are the proceedings in aggregate, expected
to be material to the group’s results of operations or ﬁnancial position.

On 23 March 2005, an explosion and ﬁre occurred in the isomerization

unit of BP Products North America Inc.’s Texas City reﬁnery as the unit
was coming out of planned maintenance. Fifteen workers died in the
incident and many others were injured. In 2005 and 2006, BP agreed
settlements in respect of all the fatalities and many of the personal injury
claims arising from the incident. Trials have been scheduled for a number
of unresolved claims in mid-2007, although to date all claims scheduled
for trial have been resolved in advance of trial. In 2006, BP continued its
co-operation with the governmental entities investigating the incident,
including the US Department of Justice (DOJ), the US Environmental
Protection Agency (EPA), the US Occupational Safety & Health
Administration (OSHA), the US Chemical Safety and Hazard Investigation
Board (CSB) and the Texas Commission on Environmental Quality (TCEQ).
During 2006, BP also devoted signiﬁcant time and effort to co-operate
with the BP US Reﬁneries Independent Safety Review Panel (the panel),
which it chartered in 2005 on the recommendation of the CSB to assess
the effectiveness of corporate oversight of safety management systems
at BP’s US reﬁneries and the corporate safety culture. The panel
published its report in January 2007 and BP has publicly committed to
implement its recommendations (see Report of the BP US Reﬁneries
Independent Safety Review Panel on page 29).

The incident prompted a number of investigations by other state and

federal agencies. The TCEQ and OSHA investigations of the incident
resulted in settlement agreements between BP and the agencies. In the
third quarter of 2005, BP reached a settlement with OSHA that resulted in
the payment of a $21.4 million penalty, an agreement to correct all alleged
safety violations and the retention of experts to assess the reﬁnery’s
organization and process safety systems. In the second quarter of 2006,
BP settled with the TCEQ, resolving 27 alleged violations by paying
a $0.3 million ﬁne and agreeing, among other things, to upgrade its
ﬂare system.

The CSB report is expected to be issued in March 2007.
As a result of its investigation of the Texas City reﬁnery, OSHA
conducted an inspection of BP Products North America Inc.’s Toledo
reﬁnery beginning in October 2005. On 24 April 2006, OSHA issued
citations with a total penalty of $2.4 million, alleging 39 separate
violations of two different OSHA standards. BP and OSHA have reached
a settlement in principle and are working towards ﬁnalizing
the documentation.

On 15 November 2006, the Indiana Occupational Safety and Health
Administration (IOSHA) issued the Whiting reﬁnery with three Safety
Orders and Notiﬁcations of Penalty alleging 14 separate violations of
the OSHA regulations. The total proposed penalty was $0.4 million. On
7 December 2006, BP and IOSHA met to discuss resolution of the
matter. Discussions to reach a settlement agreement are ongoing.
On 2 March 2006, a crude oil spill of approximately 4,800 barrels

occurred on a low-pressure transit line on the Alaskan North Slope in the
Western Operating Area of the Prudhoe Bay ﬁeld operated by BP. The
spill was reported to all the appropriate government agencies as soon as

it was discovered and the portion of the line with the leak was shut down.
The pipeline leak was caused by internal corrosion. The spill affected
approximately two acres of frozen tundra. Clean-up and rehabilitation of
the area are complete and environmental damage to the tundra is
expected to be minimal. On 15 March 2006, the US Department of
Transportation (DOT) issued a Corrective Action Order (CAO) that
required, among other items, that BP develop a plan to run maintenance
pipeline inspection tools (pigs) and smart pigs through the three Prudhoe
Bay oil transit lines. The DOT has since issued two amendments to the
CAO. Combined, the three orders have required 34 corrective actions.
On 6 August 2006, BP Exploration Alaska ordered a phased shutdown of
the Prudhoe Bay oil ﬁeld following the discovery of unexpectedly severe
corrosion and a spill of 199 barrels from the oil transit line in the Eastern
Operating Area of Prudhoe Bay. The decision was based on the receipt
of data from a smart pig run and follow-up inspections where corrosion-
related wall thinning appeared to exceed BP criteria for continued
operation. It was during these follow-up inspections that BP personnel
discovered a leak and a small spill to the tundra. The spill was contained
and clean-up began. US and State of Alaska investigations of the incident
have been initiated and subpoenas have been issued, including a Federal
Grand Jury subpoena. BP continues its discussions with the DOT to
assure compliance with the corrective actions outlined in the CADs.
In September 2006, BP executives testiﬁed before the US House of
Representatives and the US Senate.

Management cannot predict future developments, such as increasingly

strict requirements of environmental laws and resulting enforcement
policies, that might affect the group’s operations or affect the exploration
for new reserves or the products sold by the group. A risk of increased
environmental costs and impacts is inherent in particular operations
and products of the group and there can be no assurance that material
liabilities and costs will not be incurred in the future. In general, the group
does not expect that it will be affected differently from other companies
with comparable assets engaged in similar businesses. Management
believes that the group’s activities are in compliance in all material
respects with applicable environmental laws and regulations.

For a discussion of the group’s environmental expenditure see

Environmental expenditure on page 54.

BP operates in more than 100 countries worldwide. In all regions of the

world, BP has processes designed to ensure compliance with applicable
regulations. In addition, each individual in the group is required to comply
with BP health, safety and environmental (HSE) policies as embedded
in the BP code of conduct. Our partners, suppliers and contractors are
also encouraged to adopt them. The group is working with the equity-
accounted entity TNK-BP to develop management information to allow
for the assessment and measurement of their activities in relation to HSE
regulations and obligations.

This Environmental protection section focuses primarily on the US and
the EU, where approximately 70% of our property, plant and equipment
is located, and on two issues of a global nature: climate change
programmes and maritime oil spills regulations.

Climate change programmes
In December 1997, at the Third Conference of the Parties to the United
Nations Framework Convention on Climate Change (UNFCCC) in Kyoto,
Japan, the participants agreed on a system of differentiated internationally
legally binding targets for the ﬁrst commitment period of 2008-2012. In
2005, the Kyoto protocol came into force, committing the 156
participating countries to emissions targets and the EU Emissions Trading
Scheme (ETS) came into operation. However, Kyoto was only designed
as a ﬁrst step and policymakers continue to discuss what new agreement
might follow it in 2012 and how all signiﬁcant countries can be involved.
This was discussed further by the G8 group of world leaders at their
St Petersburg summit in 2006 and at the UNFCC conference in Nairobi,
where progress was made on climate impacts adaptation and vulnerability
and there was agreement to review the Kyoto protocol by 2008.

Market mechanisms to allow optimum utilization of resources to
meet the national Kyoto targets are being considered, developed or
implemented by individual countries and also internationally through the
EU. The relative success of these systems will determine the extent to
which alternative ﬁscal or regulatory measures may be applied.

BP Annual Report and Accounts 2006

43

In July 2003, ﬁnal agreement was reached on a European Directive
establishing a scheme for GHG emission allowance trading within the EU
and, in January 2005, the scheme came into force, capping the CO2
emissions of major industrial emitters. BP was well prepared for the EU
ETS, building on experiences from our own internal emissions trading
system (operated between 1999 and 2001) and participation in the UK’s
own pilot ETS. The EU ETS launched in 2005 covers all BP installations
with combustion facilities greater than 20MW thermal input. The ﬁrst
phase of EU ETS will come to completion at the end of 2007, with EU
ETS phase II running from 2008 to 2012. By 31 December 2006, member
states should have submitted their ﬁnal national allocation plan (NAP)
versions. These are in the process of receiving ﬁnal approval from the
Commission. In 2006, our 18 EU ETS participating installations submitted
their veriﬁed 2005 CO2 emission reports, balanced their EU ETS
allowance positions using BP’s trading resources in London and
surrendered the required number of allowances, equal to their 2005
veriﬁed annual emissions.

In September 2006, California governor Arnold Schwarzenegger signed

the California Global Warming Solutions Act of 2006 (AB 32) into law.
AB 32 requires the California Air Resources Board (CARB) to develop
regulations that will ultimately reduce California’s GHG emissions to 1990
levels by 2020 (an approximately 25% reduction from current levels).
Mandatory caps will begin in 2012 for signiﬁcant sources and will ratchet
down over time to meet the 2020 goals. The law speciﬁcally targets
‘sources or categories that contribute the most to statewide emissions’
for action. The California Climate Action Team, which the law designates
to co-ordinate overall climate policy, has identiﬁed transportation as the
largest GHG-emitting sector in California, and electricity generation and
the oil and gas industry are the two largest GHG-emitting industrial
sectors in the state.

The US congressional mid-term elections in November 2006 resulted in a

change in control of the US Congress that may increase the prospects for
more aggressive federal regulation of GHG emissions. Such future regulation
could include stricter Corporate Average Fuel Emissions for automobiles sold
in the US, changes in fuel speciﬁcations, the promotion of alternative fuels,
stricter emissions limits on large GHG sources and/or the introduction of a
cap and trade programme on CO2 or other GHG emissions.

Since 1997, BP has been actively involved in policy debate. We also
ran a global programme that reduced our operational GHG emissions by
10% between 1998 and 2001. We continue to look at two principal kinds
of emissions: operational emissions, which are generated from our
operations such as reﬁneries, chemicals plants and production facilities,
and product emissions, generated by our customers when they use the
fuels and products that we sell. Since 2001, we have been aiming to
offset, through energy efﬁciency projects, half the underlying operational
GHG emission increases that result from our growing business. After ﬁve
years, we estimate that emissions growth of some 12 million tonnes has
been offset by around 6 million tonnes of sustainable reductions. With
regard to our products, our commitment to low-carbon businesses
increased in 2006 with the internal establishment of a separate biofuels
business and the announcement to establish a dedicated biosciences
energy research facility attached to a major academic centre and invest
$500 million over the next 10 years. Our low-carbon power business, BP
Alternative Energy, continued to expand its activities with the purchase of
US wind developers Orion Energy, LLC, and Greenlight Energy Inc. and
the formation of a strategic alliance with Clipper Windpower, to develop
jointly more than 2 gigawatts of wind projects in the US.

Maritime oil spill regulations
Within the US, the Oil Pollution Act of 1990 (OPA 90) imposes oil spill
prevention requirements, spill response planning obligations and spill
liability for tankers and barges transporting oil and for offshore facilities
such as platforms and onshore terminals. To ensure adequate funding
for response to oil spills and compensation for damages, when not fully
covered by a responsible party, OPA 90 created a $1-billion fund that is
ﬁnanced by a tax on imported and domestic oil. This has recently been
amended by the Coast Guard and Marine Transportation Act 2006 to
increase the size of the fund from $1 billion to $2.7 billion, through the
previously mentioned tax, together with an increase in the liability of
double-hulled tankers from $1,200 per gross ton to $1,900 per gross ton.
In addition to federal law (OPA 90), which imposes liability for oil spills

44

on the owners and operators of the carrying vessel, some states
implemented statutes also imposing liability on the shippers or owners of
oil spilled from such vessels. Alaska, Washington, Oregon and California
are among these states. The exposure of BP to such liability is mitigated
by the vessels’ marine liability insurance, which has a maximum limit of
$1 billion for each accident or occurrence. OPA 90 also provides that all
new tank vessels operating in US waters must have double hulls and
existing tank vessels without double hulls must be phased out by 2015.
BP contracted with National Steel and Ship Building Company (NASSCO)
for the construction of four double-hulled tankers in San Diego, California.
The ﬁrst of these new vessels began service in 2004, demise chartered
to and operated by Alaska Tanker Company (ATC), which transports BP
Alaskan crude oil from Valdez. NASSCO delivered two more in 2005
and the fourth was delivered in 2006. At the end of 2006, the ATC ﬂeet
consisted of six tankers, all double-hulled.

Outside the US, the BP-operated ﬂeet of tankers is subject to

international spill response and preparedness regulations that are typically
promulgated through the International Maritime Organization (IMO) and
implemented by the relevant ﬂag state authorities. The International
Convention for the Prevention of Pollution from Ships (Marpol 73/78)
requires vessels to have detailed ship-board emergency and spill
prevention plans. The International Convention on Oil Pollution,
Preparedness, Response and Co-operation requires vessels to have
adequate spill response plans and resources for response anywhere the
vessel travels. These conventions and separate Marine Environmental
Protection Circulars also stipulate the relevant state authorities around
the globe that require engagement in the event of a spill. All these
requirements together are addressed by the vessel owners in Shipboard
Oil Pollution Emergency Plans. BP Shipping’s liabilities for oil pollution
damage under the OPA 90 and outside the US under the 1969/1992
International Convention on Civil Liability for Oil Pollution Damage are
covered by marine liability insurance, having a maximum limit of $1 billion
for each accident or occurrence. This insurance cover is provided by three
mutual insurance associations (P&I Clubs): The United Kingdom Steam
Ship Assurance Association (Bermuda) Limited, The Britannia Steam Ship
Insurance Association Limited and The Standard Steamship Owners’
Protection and Indemnity Association (Bermuda) Limited. With effect
from 20 February 2006, two new complementary voluntary oil pollution
compensation schemes were introduced by tanker owners, supported by
their P&I Clubs, with the agreement of the International Oil Pollution
Compensation Fund at the IMO. Pursuant to both these schemes, tanker
owners will voluntarily assume a greater liability for oil pollution
compensation in the event of a spill of persistent oil than is provided for in
CLC. The ﬁrst scheme, The Small Tanker Owners’ Pollution
Indemniﬁcation Agreement (STOPIA), provides for a minimum liability of
20 million Special Drawing Rights (around $29 million) for a ship at or
below 29,548 gross tons, while the second scheme, The Tanker Owners’
Pollution Indemniﬁcation Agreement (TOPIA), provides for the tanker
owner to take a 50% stake in the 2003 Supplementary Fund, i.e. an
additional liability of up to 273.5 million Special Drawing Rights (around
$406 million). Both STOPIA and TOPIA will only apply to tankers whose
owners are party to these agreements and who have entered their ships
with P&I Clubs in the International Group of P&I Clubs, so beneﬁting
from those Clubs’ pooling and reinsurance arrangements. All BP
Shipping’s managed and time-chartered vessels will participate in
STOPIA and TOPIA.

At the end of 2006, the international ﬂeet we managed numbered 47
oil and product carriers, all double-hulled with an average age of less than
three years, seven LNG ships with an average age of nine years and three
LPG ships, which are all less than one year old. The international ﬂeet
renewal programme will continue and is expected to see one more LPG
ship being delivered in mid-2007 and four new LNG ships being delivered
between mid-2007 and the end of 2008. In addition to its own ﬂeet, BP
will continue to charter quality ships; currently these vessels include both
single- and double-hulled designs, but BP Shipping is accelerating the
phase-in of only double-hulled vessels by 2008; all vessels will continue
to be vetted prior to each use in accordance with the BP group ship
vetting policy.

US regional review
The following is a summary of signiﬁcant US environmental issues and
legislation affecting the group.

The Clean Air Act and its regulations require, among other things,
stringent air emission limits and operating permits for chemicals plants,
reﬁneries, marine and distribution terminals; stricter fuel speciﬁcations
and sulphur reductions; enhanced monitoring of major sources
of speciﬁed pollutants; and risk management plans for storage of
hazardous substances. This law affects BP facilities producing, reﬁning,
manufacturing and distributing oil and products as well as the fuels
themselves. Federal and state controls on ozone, particulate matter,
carbon monoxide, benzene, sulphur, MTBE, nitrogen dioxide, oxygenates
and Reid Vapor Pressure affect BP’s activities and products in the US. BP
is continually adapting its business to these rules and has the know-how
to produce quality and competitive products in compliance with their
requirements. Beginning January 2006, all gasoline produced by BP was
subject to the EPA’s stringent low-sulphur standards. Furthermore, by
June 2006, at least 80% of the highway diesel fuel produced each year by
BP was required to meet a sulphur cap of 15 parts per million (ppm) and
then 100% beginning January 2010. By June 2007, all non-road diesel fuel
production will have to meet a sulphur cap of 500ppm and then 15ppm by
June 2012.

The Energy Policy Act of 2005 also required several changes to the
US fuels market with the following fuel provisions: elimination of the
Federal Reformulated Gasoline (RFG) oxygen requirement in May 2006;
establishment of a renewable fuels mandate – 4 billion gallons in 2006,
increasing to 7.5 billion in 2012; consolidation of the summertime RFG
Volatile organic compound (VOC) standards for Region 1 and 2; provision
to allow the Ozone Transport Commission states on the east coast to opt
any area into RFG; and a provision to allow states to repeal the 1psi Reid
Vapor Pressure waiver for 10% ethanol blends.

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

The Clean Water Act is designed to protect and enhance the quality of

US surface waters by regulating the discharge of wastewater and other
discharges from both onshore and offshore operations. Facilities are
required to obtain permits for most surface water discharges, install
control equipment and implement operational controls and preventative
measures, including spill prevention and control plans. Requirements
under the Clean Water Act have become more stringent in recent years,
including coverage of storm and surface water discharges at many more
facilities and increased control of toxic discharges. New regulations are
expected over the next several years that could require, for example,
additional wastewater treatment systems at some facilities.

The Resource Conservation and Recovery Act (RCRA) regulates the
storage, handling, treatment, transportation and disposal of hazardous and
non-hazardous wastes. It also requires the investigation and remediation
of certain locations at a facility where such wastes have been handled,
released or disposed of. BP facilities generate and handle a number
of wastes regulated by RCRA and have units that have been used for
the storage, handling or disposal of RCRA wastes that are subject to
investigation and corrective action.

Under the Comprehensive Environmental Response, Compensation,
and Liability Act (also known as CERCLA or Superfund), waste generators,
site owners, facility operators and certain other parties are strictly liable
for part or all of the cost of addressing sites contaminated by spills or
waste disposal regardless of fault or the amount of waste sent to a site.
Additionally, each state has laws similar to CERCLA.

BP has been identiﬁed as a Potentially Responsible Party (PRP)
under CERCLA or otherwise named under similar state statutes at
approximately 800 sites. A PRP or named party can incur joint and several
liability for site remediation costs under some of these statutes and so
BP may be required to assume, among other costs, the share attributed
to insolvent, unidentiﬁed or other parties. BP has the most signiﬁcant
exposure for remediation costs at 60 of these sites. For the remaining
sites, the number of parties can range up to 200 or more. BP expects its
share of remediation costs at these sites to be small in comparison with
the major sites. BP has estimated its potential exposure at all sites where
it has been identiﬁed as a PRP or is otherwise named and has established

provisions accordingly. BP does not anticipate that its ultimate exposure
at these sites individually, or in aggregate, will be signiﬁcant, except as
reported for Atlantic Richﬁeld Company in the matters below.

The US and the State of Montana seek to hold Atlantic Richﬁeld

Company liable for environmental remediation, related costs and natural
resource damages arising out of mining-related activities by Atlantic
Richﬁeld’s predecessors in the upper Clark Fork River Basin (the basin).
The estimated future cost of performing selected and proposed remedies
in certain areas in the basin are likely to exceed $350 million. Federal and
state trustees also seek to recover damages for alleged injuries to natural
resources in the basin. In 1999, Atlantic Richﬁeld settled most of the
State’s claims for damages, as well as all natural resource damage claims
asserted by a local Native American tribe. However, the parties have not
resolved the claims for natural resource damages on certain federal land
or the State’s remaining claims for restoration damages. Past settlements
among the parties, including consent decree settlements providing for
combined remediation and restoration projects in limited areas of the
basin, may provide a framework for future settlement of the remaining
claims. Atlantic Richﬁeld Company has asserted defences to the
remaining claims and has asserted counterclaims.

The group is also subject to other claims for natural resource damages

(NRD) under CERCLA, OPA 90, and other federal and state laws. NRD
claims have been asserted by government trustees against a number of
group operations. This is a developing area of the law that could affect the
cost of addressing environmental conditions at some sites in the future.

In the US, many environmental clean-ups are the result of strict
groundwater protection standards at both the state and federal level.
Contamination or the threat of contamination of current or potential
drinking water resources can result in stringent clean-up requirements
even if the water is not being used for drinking water. Some states have
even addressed contamination of non-potable water resources using
similarly strict standards. BP has encouraged risk-based approaches to
these issues and seeks to tailor remedies at its facilities to match the
level of risk presented by the contamination.

Other signiﬁcant legislation includes the Toxic Substances Control Act,
which regulates the development, testing, import, export and introduction
of new chemical products into commerce; the Occupational Safety and
Health Act, which imposes workplace safety and health, training and
process requirements to reduce the risks of physical and chemical
hazards and injury to employees; and the Emergency Planning and
Community Right-to-Know Act, which requires emergency planning
and spill notiﬁcation as well as public disclosure of chemical usage and
emissions. In addition, the US Department of Transportation, through
the Pipeline and Hazardous Materials Safety Administration, regulates in
a comprehensive manner the transportation of the group’s petroleum
products such as crude oil, gasoline and chemicals to protect the health
and safety of the public.

BP is subject to the Marine Transportation Security Act and the

Department of Transportation Hazardous Materials security compliance
regulations in the US. These regulations require many of our US
businesses to conduct security vulnerability assessments and prepare
security mitigation plans that require the implementation of upgrades to
security measures, the appointment and training of designated security
personnel and the submission of plans for approval and inspection by
government agencies.

BP has a national spill response team, the BP Americas Response

Team (BART), consisting of approximately 250 trained emergency
responders at group locations throughout North America. Supporting
the BART are ﬁve Regional Response Incident Management Teams
and seven HAZMAT Strike Teams. Collectively, these teams are
ready to assist in a response to a major incident.

See also Legal proceedings on page 85.

European Union regional review
Within the EU, European Community directives are proposed by the
European Commission (EC) and usually adopted jointly by the European
Parliament and the Council of Ministers. They must then be implemented
by each EU member state. Less frequently in the ﬁeld of environment,
EC regulations are adopted that apply directly throughout the EU without
the need for member state implementation. When implementing EU
legislation, member states must ensure that penalties for non-compliance

BP Annual Report and Accounts 2006

45

are effective, proportionate and dissuasive, and must usually designate a
‘competent authority’ (regulatory body) for implementation. Where the
EC believes that a member state has failed fully and correctly to
transpose and implement EU legislation, it can take the member state to
the European Court of Justice, which can order the member state to
comply and in certain cases can impose monetary penalties on the
member state. A few non-EU states may also agree to apply EU
environmental legislation, in particular under the framework of the
European Economic Area agreement.

An EC directive for a system of integrated pollution prevention
and control (IPPC) was adopted in 1996. This system requires certain
industrial installations – including most activities and processes
undertaken by the oil and petrochemicals industry within the EU –
to obtain an IPPC permit, which is designed to address an installation’s
environmental impacts, air emissions, water discharges and waste in a
comprehensive fashion. The permit requires, among other things, the
application of Best Available Techniques (BAT), taking into account the
costs and beneﬁts, unless an applicable environmental quality standard
requires more stringent restrictions, and an assessment of existing
environmental impacts and future site closure obligations. All such plants
must apply for and obtain such a permit by November 2007. Compliance
requires capital and revenue expenditure across BP sites. The EC has
embarked upon a process of review that is likely to report in 2007 and to
result in recommendations for amendments to the IPPC directive.

The EC Large Combustion Plant Directive was adopted in 1988 and

subsequently replaced by a new Large Combustion Plant Directive
in 2001. The current LCPD imposes a complex range of controls on
emissions of sulphur dioxide, nitrogen oxides and particulates from large
combustion plants. The nature and stringency of these controls for a
particular plant depend principally on its age. Plants permitted between
1987 and 2002 had a requirement for speciﬁc emission limit values
by 27 November 2002. Plants permitted since then must meet more
stringent emission limit values. Plants permitted prior to 1987 must also
meet emission limit values unless they have ‘opted out’ (in which case
they must now close after 20,000 hours of further operation starting
from 1 January 2008 and ending no later than 31 December 2015) or will
participate in a National Emission Reduction Plan designed to deliver
equivalent aggregate emission reductions.

The second important set of air quality-related legislation affecting BP
European operations is the Air Quality Framework Directive on ambient air
quality assessment and management and its daughter Directives, which
prescribe, among other things, ambient limit values for sulphur dioxide,
oxides of nitrogen, particulate matter, lead, carbon monoxide, ozone,
cadmium, arsenic, nickel, mercury and polyaromatic hydrocarbons. If the
concentration of a pollutant exceeds air quality limit values plus a margin
of tolerance set under a daughter Directive (or there is a risk of such
exceedance), a member state is required to take action to reduce
emissions. This may affect any BP operations whose emissions
contribute to such exceedances.

In 2005, the EC published its Thematic Strategy on Air Pollution – a key

part of the ‘Clean Air for Europe’ (CAFE´ ) programme – and an
accompanying proposed directive to consolidate the existing ambient air
quality legislation referred to above and to introduce new controls on the
concentration of ﬁne particles (PM 2.5 – particulate matter less than 2.5
microns diameter) in ambient air. The Thematic Strategy outlines EU-wide
objectives to reduce the health and environmental impacts of air quality
and a wide range of measures to be taken. These measures include: the
ambient air quality proposal mentioned above; revisions to the National
Emissions Ceilings Directive; new emission limits for light and heavy duty
diesel vehicles; new controls on smaller combustion plant; and further
control of evaporative losses from vehicle refuelling at service stations.

The EU has set stringent objectives to control exhaust emissions from

vehicles, which are being implemented in stages. Maximum sulphur
levels for gasoline and diesel of 50ppm and a 35% maximum aromatic
content for gasoline were both agreed to apply from 2005. Agreement
was reached in December 2002 on a further directive to make petrol and
diesel with a maximum sulphur content of 10ppm mandatory throughout
the EU from January 2009, and from 2005, member states will also have
to supply low-sulphur fuel at enough locations to allow the circulation of
new low-emission engines requiring the cleaner fuel. Further measures
on sulphur levels of shipping fuels and/or reduction of emissions using

46

such fuels started to take effect during 2006. Restrictions and measures
include sulphur levels in fuels of 0.1% for inland vessels by January 2010
and 1.5% for passenger ships by 19 August 2006. The chief impact on BP
is likely to arise from installation of ﬂue gas desulphurization on ships and
higher cost fuel. The overall impact is not expected to be material to the
group’s results of operations or ﬁnancial position.

A new EC programme for European chemical regulation – REACH
(Registration, Evaluation and Authorization of Chemicals) will come into
force on 1 June 2007. All chemical substances manufactured or imported
in the EU above 1 tonne per annum (about 30,000) will require a new pre-
registration within the following 18 months and a registration within a 3-
to 11-year time-phased period from adoption. The actual date depends on
volume bands or classiﬁcation with high volumes and hazardous
substances ﬁrst. Only time-limited authorizations will be given to
substances of ‘high concern’. A new European Chemical Agency will be
established in Helsinki by mid-2008. Crude oil and natural gas are exempt.
Fuels will be exempted from authorization but not registration. For BP,
REACH will affect all reﬁning petroleum products, petrochemicals,
lubricants and other chemicals. An initial estimate suggests costs of about
$60,000 each for the internal preparation, pre-registration and registration
of nearly 1,000 entities representing manufactured or imported
substances or imported preparations for all BP individual entities obligated
under REACH. Additional costs for further submission to authorization for
relevant substances and the modiﬁcation of safety data sheets will have
to be assessed as further costs once the ﬁnal regulation is known.

The EC adopted a Directive on Environmental Liability on 21 April 2004.
From 30 April 2007, member states must usually require the operators of
activities that cause signiﬁcant damage to water, ecological resources or
land after that date to undertake restoration of that damage. Provision is
also made for reporting and tackling imminent threats of such damage.
The regime is more stringent for operators of speciﬁed higher-risk
activities, including IPPC-permitted operations. Member states are
considering how to implement the regime.

During 2007, the commission is expected to release a communication

on Carbon Capture and Storage (CCS), setting out guidelines for the
technology and its regulation. The intention of the communication is in
part to identify regulatory barriers that may restrict CCS technologies,
so that those barriers can be appropriately addressed, and to identify
common methodologies to be implemented across EU member states.

Other environment-related existing regulations that may have an impact

on BP’s operations include: the Major Hazards Directive which, for the
sites to which it applies, requires emergency planning, public disclosure
of emergency plans and ensuring that hazards are assessed and effective
emergency management systems are in place; the Water Framework
Directive, which includes protection of surface waters and groundwater;
and the Waste Framework Directive.

The Water Framework Directive requires member states to develop
‘programmes of measures’ and start implementing them by 2012, the
principal objective being to ensure that all water bodies covered by the
directive attain at least ‘good quality’ by 2015. For an individual plant
which, for instance, abstracts water or discharges efﬂuent into water, the
implications of the directive will depend on local circumstances (including
the extent to which the activity might prejudice attaining ‘good quality’
for a water body) and on the individual member state’s approach to
developing and implementing the relevant programme of measures.
The Water Framework Directive also draws together and provides for
the replacement (with new directives) of a number of other directives
relating to water quality, such as those on groundwater and discharge of
dangerous substances.

The Waste Framework Directive requires member states to operate
a permitting regime for waste disposal and recovery and to ensure that
waste is recovered or disposed without endangering human health and
without using processes or methods that could harm the environment.
A European Court of Justice ruling in 2004 (Van de Walle) interpreted
these requirements widely, in a way that raised potentially signiﬁcant
implications for soil and groundwater contamination; however, a proposed
revision to the directive that is currently making its way through the EU
legislative process would, if adopted in its current form, potentially pave
the way for mitigating this position by excluding from the directive
unexcavated soil covered by other EU legislation.

In 2005, the EC published a proposed EC Marine Strategy Directive,

which would adopt an approach akin to that in the Water Framework
Directive by requiring achievement of ‘good environmental status’ for
marine waters by 2021 through the implementation of programmes of
measures.

In 2006, the EC published a proposed Soil Framework Directive that, as
currently drafted, would encompass all soils, not just those for agricultural
uses. If adopted in its current form, the directive would require member
states to develop, over time, a register of ‘contaminated sites’ and to
require their remediation so that they do not pose signiﬁcant risks to
human health or the environment. Unlike the Environmental Liability
Directive, this is intended to apply to historic as well as new
contamination. Member states may well need to carry out or require
intrusive site investigations in order to establish whether particular sites
are ‘contaminated sites’; coupled with a requirement (which will be new
for some member states) for site investigations to be carried out on any
sale of land that may be contaminated, this could lead to the crystallization
of liabilities for BP in respect of its current or former operational and other
land holdings, if any such land is found to be contaminated.

Property, plants and equipment

BP has freehold and leasehold interests in real estate in numerous countries
throughout the world, but no individual property is signiﬁcant to the group as
a whole. See Exploration and Production on page 16 for a description of the
group’s signiﬁcant reserves and sources of crude oil and natural gas.
Signiﬁcant plans to construct, expand or improve speciﬁc facilities are
described under each of the business headings within this section.

Organizational structure

The signiﬁcant subsidiaries of the group at 31 December 2006 and the
group percentage of ordinary share capital (to nearest whole number) are
set out in Financial statements – Note 50 on page 171. See Financial
statements – Notes 29, 30 and 55 on pages 136, 137 and 195
respectively for information on signiﬁcant jointly controlled entities and
associates of the group.

Financial and operating performance

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

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million except per share amounts

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Sales and other operating revenues from continuing operationsa
Proﬁt from continuing operationsa
Proﬁt for the year
Proﬁt for the year attributable to BP shareholders
Proﬁt attributable to BP shareholders per ordinary share – cents
Dividends paid per ordinary share – cents

2006

2005

2004

265,906
22,311
22,286
22,000
109.84
38.40

239,792
22,448
22,632
22,341
105.74
34.85

192,024
17,884
17,262
17,075
78.24
27.70

a Excludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’. See Financial
statements – Note 5 on page 111.

Business environment
The business environment in 2006 was mixed compared with 2005,
but still robust in comparison with historical averages. Crude oil and
UK natural gas prices increased, while US natural gas prices and global
reﬁning margins fell.

In 2005, the dated Brent price averaged $54.48 per barrel, an increase

of more than $16 per barrel above the $38.27 per barrel average seen
in 2004, and varied between $38.21 and $67.33 per barrel. Hurricanes
Katrina and Rita severely disrupted oil and gas production in the Gulf of
Mexico for an extended period but supply availability was maintained.

Crude oil prices reached record highs in 2006 in nominal terms, driven

Natural gas prices in the US were also higher during 2005 than in 2004

by low surplus oil production capacity, continued demand growth and
concern about vulnerability of supply. The dated Brent price averaged
$65.14 per barrel, an increase of more than $10 per barrel over the
$54.48 per barrel average seen in 2005, and varied between $78.69 and
$55.89 per barrel. Prices peaked in early August before retreating in the
face of a mild hurricane season and rising inventories. OPEC action late
in the year helped support prices.

Natural gas prices in the US declined in 2006 but remained well above

historical averages. The Henry Hub First of the Month Index averaged
$7.24 per mmBtu, $1.41 per mmBtu below the 2005 average of $8.65
per mmBtu. Rising production and weak consumption resulted in above-
average inventories, depressing gas prices relative to crude oil. UK gas
prices rose slightly in 2006, averaging 42.19 pence per therm at the
National Balancing Point, compared with a 2005 average of 40.71 pence
per therm.

Reﬁning margins were only slightly lower in 2006, with the BP Global
Indicator Margin (GIM) averaging $8.39 per barrel. This reﬂected further
oil demand growth, lingering effects on US reﬁnery production from the
2005 hurricanes and gasoline formulation changes in several US states.
The premium for light products over fuel oils remained exceptionally high,
favouring upgraded reﬁneries over less complex sites.

Retail margins improved slightly in 2006, beneﬁting from a decline in the

cost of product during the second half of the year, despite
intense competition.

The business environment in 2005 was stronger than in 2004, with
higher oil and gas realizations and higher reﬁning and oleﬁns margins
but lower retail marketing margins.

in the face of rising oil prices and hurricane-induced production losses.
In 2005, the Henry Hub First of the Month Index averaged $8.65 per
mmBtu, up by around $2.50 per mmBtu compared with the 2004 average
of $6.13 per mmBtu. High gas prices in 2005 stimulated a fall in demand,
especially in the industrial sector. UK gas prices were up strongly in
2005, averaging 40.71 pence per therm at the National Balancing Point,
compared with a 2004 average of 24.39 pence per therm.

Reﬁning margins also reached record highs in 2005, with the BP GIM
averaging $8.60 per barrel. This reﬂected further oil demand growth and
the loss of reﬁning capacity as a result of the US hurricanes. The premium
for light products above fuel oils remained exceptionally high, favouring
upgraded reﬁneries over less complex sites.

Retail margins weakened in 2005 as rising product prices and price

volatility made their impact felt in a competitive marketplace.

Hydrocarbon production
Hydrocarbon production for subsidiaries decreased by 3.3% in 2006
reﬂecting a decrease of 5.1% for liquids and a decrease of 1.3% for
natural gas. Increases in production in our new proﬁt centres were offset
by anticipated decline in our existing proﬁt centres and the effect of
disposals. Hydrocarbon production for equity-accounted entities increased
by 0.1%, reﬂecting a decrease of 1.3% for liquids and an increase of
10.2% for natural gas.

Hydrocarbon production for subsidiaries decreased by 2.8% in 2005

compared with 2004, reﬂecting a decrease of 3.9% for liquids and a
decrease of 1.5% for natural gas. Increases in production in our new
proﬁt centres were more than offset by the effect of hurricanes, higher

BP Annual Report and Accounts 2006

47

planned maintenance shutdowns and anticipated decline in our existing
proﬁt centres. Hydrocarbon production for equity-accounted entities
increased by 7.8%, reﬂecting an increase of 8.4% for liquids and an
increase of 3.8% for natural gas. This increase primarily reﬂects increased
production from TNK-BP.

Sales and other operating revenues
The increase in sales and other operating revenues (before the elimination
of sales between businesses) for 2006 included approximately $39 billion
from higher prices related to marketing and other sales (spot and term
contracts, oil and gas realizations and other sales), partially offset by a net
decrease of approximately $15 billion from lower volumes of marketing
and other sales and a decrease of around $1 billion related to lower
production volumes of subsidiaries.

The increase in sales and other operating revenues (before the

elimination of sales between businesses) for 2005 included approximately
$67 billion from higher prices related to marketing and other sales (spot
and term contracts, oil and gas realizations and other sales) and $1 billion
from foreign exchange movements due to sales in local currencies being
translated into the US dollar. This was partially offset by a net decrease
of approximately $11 billion from lower volumes of marketing and other
sales and a decrease of around $1 billion related to lower production
volumes of subsidiaries.

Proﬁt attributable to BP shareholders
Proﬁt attributable to BP shareholders for the year ended 31 December
2006 was $22,000 million, after inventory holding losses of $253 million.
Inventory holding gains or losses represent the difference between
the cost of sales calculated using the average cost of supplies incurred
during the year and the cost of sales calculated using the ﬁrst-in ﬁrst-out
method. Proﬁt attributable to BP shareholders for the year ended
31 December 2005 was $22,341 million, including inventory holding gains
of $3,027 million, and proﬁt attributable to BP shareholders for the year
ended 31 December 2004 was $17,075 million, including inventory
holdings gains of $1,643 million.

The proﬁt attributable to BP shareholders for the year ended
31 December 2006 included losses from Innovene operations of
$25 million, compared with a proﬁt of $184 million and a loss of
$622 million in the years ended 31 December 2005 and 31 December 2004
respectively. The loss/proﬁt from Innovene for the years 2006 and 2005
included losses on remeasurement to fair value of $184 million and
$591 million respectively. Financial statements – Note 5 on page 111
provides further ﬁnancial information for Innovene.

Proﬁt attributable to BP shareholders for the year ended
31 December 2006:
– Included net gains of $2,114 million on the sales of assets, net fair

value gains of $515 million on embedded derivatives (these embedded
derivatives are fair valued at each period end with the resulting gains or
losses taken to the income statement) and a net impairment credit of
$203 million and was after charges for legal provisions of $335 million
in Exploration and Production;

– Included net disposal gains of $884 million and was after a charge of
$925 million as a result of the ongoing review of fatality and personal
injury compensation claims associated with the March 2005 incident at
the Texas City reﬁnery, an impairment charge of $155 million, a charge
of $155 million in respect of a donation to the BP Foundation and a
charge of $33 million relating to new, and revisions to existing,
environmental and other provisions in Reﬁning and Marketing;

– Included net disposal gains of $193 million and net fair value gains of

$88 million on embedded derivatives and was after a charge
$100 million for the impairment of a North American NGLs asset in the
Gas, Power and Renewables segment; and

– Included a credit of $94 million in relation to new, and revisions to

existing, environmental and other provisions, a net gain on disposal
of $95 million and net fair value gains of $5 million on embedded
derivatives, and was after a charge of $200 million relating to the
reassessment of certain provisions and an impairment charge of
$69 million in Other businesses and corporate.

48

Proﬁt attributable to BP shareholders for the year ended
31 December 2005:
– Included net gains of $1,159 million on the sales of assets, primarily

from our interest in the Ormen Lange ﬁeld, and was after net fair value
losses of $1,688 million on embedded derivatives, an impairment
charge of $226 million in respect of ﬁelds in the Gulf of Mexico and a
charge for impairment of $40 million relating to ﬁelds in the UK North
Sea in Exploration and Production;

– Included net gains of $177 million, principally on the divestment of a

number of regional retail networks in the US and was after a charge of
$700 million in respect of fatality and personal injury compensation
claims associated with the March 2005 incident at the Texas City
reﬁnery a charge of $140 million relating to new, and revisions to
existing, environmental and other provisions, an impairment charge of
$93 million and a charge of $33 million for the impairment of an equity-
accounted entity in Reﬁning and Marketing;

– Included net gains of $55 million primarily on the disposal of BP’s

interest in the Interconnector pipeline and a power plant in the UK and
was after net fair value losses of $346 million on embedded derivatives
and a credit of $6 million related to new, and revisions to existing,
environmental and other provisions in the Gas, Power and Renewables
segment; and

– Included net gains on disposal of $38 million, and was after a net
charge of $278 million related to new, and revisions to existing,
environmental and other provisions and the reversal of environmental
provisions no longer required, a charge of $134 million relating to the
separation of the Oleﬁns and Derivatives business and net fair value
losses of $13 million on embedded derivatives in Other businesses
and corporate.

Proﬁt attributable to BP shareholders for the year ended
31 December 2004:
– Was after an impairment charge of $267 million in respect of ﬁelds in
the deepwater Gulf of Mexico and US onshore, an impairment charge
of $108 million in respect of a gas processing plant in the US and a
ﬁeld in the Gulf of Mexico Shelf, an impairment charge of $60 million in
respect of the partner-operated Temsah platform in Egypt following a
blow-out, a net loss on disposal of $65 million, a charge of $35 million
in respect of Alaskan tankers that were no longer required and, in
addition, following the lapse of the sale agreement for oil and gas
properties in Venezuela, $31 million of the previously booked
impairment was reversed in Exploration and Production;

– Was after net losses on disposal of $267 million, a charge of $206
million related to new, and revisions to existing, environmental and
other provisions, a charge of $195 million for the impairment of the
petrochemicals facilities at Hull, UK, and a charge of $32 million for
restructuring, integration and rationalization in Reﬁning and Marketing;

– Included net gains on disposal of $56 million in the Gas, Power and

Renewables segment; and

– Included net gains on disposal of $949 million primarily related to
the sale of our interests in PetroChina and Sinopec and a credit of
$66 million primarily resulting from the reversal of vacant space
provisions in the UK and the US, and was after a charge of $283 million
related to new, and revisions to existing, environmental and other
provisions and a charge of $102 million relating to the separation of the
Oleﬁns and Derivatives business in Other businesses and corporate.

(See Environmental expenditure on page 54 for more information on
environmental charges.)

The primary additional factors reﬂected in proﬁt attributable to BP
shareholders for the year ended 31 December 2006 compared with a
year ago were higher oil realizations, higher retail margins (although this
was partially offset by a deterioration in other marketing margins), higher
reﬁning margins, including the beneﬁt of supply optimization, and higher
contributions from the operating businesses in the Gas, Power and
Renewables segment, offset by the ongoing impact following the Texas
City reﬁnery shutdown, lower gas realizations, lower production volumes,
higher costs and volatility arising under IFRS fair value accounting.

The primary additional factors reﬂected in proﬁt attributable to BP

shareholders for the year ended 31 December 2005 compared with 2004

were higher liquids and gas realizations, higher reﬁning margins and
higher contributions from the operating business within the Gas, Power
and Renewables segment, partially offset by lower retail marketing
margins, higher costs (including the Thunder Horse incident, the Texas
City reﬁnery shutdown and planned restructuring actions) and signiﬁcant
volatility arising under IFRS fair value accounting.

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 97,000 at 31 December 2006,

96,200 at 31 December 2005 and 102,900 at 31 December 2004. The
decrease in 2005 resulted primarily from the sale of Innovene.

Capital expenditure and acquisitions

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

$ million

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2005

2004

Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate
Capital expenditure
Acquisitions and asset exchanges

Disposals
Net investment

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

13,075
3,122
432
281

16,910
321

17,231
(6,254)

10,977

10,149
2,757
235
797
13,938
211
14,149
(11,200)
2,949

9,648
2,862
530
770
13,810
2,841
16,651
(4,961)
11,690

Capital expenditure and acquisitions in 2006, 2005 and 2004 amounted to
$17,231 million, $14,149 million and $16,651 million respectively. There
were no signiﬁcant acquisitions in 2006 or 2005. Acquisitions during 2004
included $1,354 million for including TNK’s interest in Slavneft within
TNK-BP and $1,355 million for the acquisition of Solvay’s interests in BP
Solvay Polyethylene Europe and BP Solvay Polyethylene North America.
Excluding acquisitions and asset exchanges, capital expenditure for
2006 was $16,910 million compared with $13,938 million in 2005 and

$13,810 million in 2004. In 2006, this included $1 billion in respect of
our investment in Rosneft.

Finance costs and other ﬁnance expense
Finance costs comprises group interest less amounts capitalized. Finance
costs for continuing operations in 2006 were $718 million compared with
$616 million in 2005 and $440 million in 2004. These amounts included a
charge of $57 million arising from early redemption of ﬁnance leases in
2005. The charge in 2006 reﬂected higher interest rates and costs, offset
by an increase in capitalized interest compared with 2005. Compared with
2004, the charge for 2005 also reﬂected higher interest rates and costs
offset by an increase in capitalized interest.

Other ﬁnance expense included net pension ﬁnance costs, the interest

accretion on provisions and the interest accretion on the deferred
consideration for the acquisition of our investment in TNK-BP. Other
ﬁnance expense for continuing operations in 2006 was a credit of
$202 million compared with charges of $145 million in 2005 and
$340 million in 2004. The decrease in 2006 compared with 2005 primarily
reﬂected a reduction in net pension ﬁnance costs owing to a higher return
on pension assets due to the increased market value of the pension asset
base. The decrease in 2005 compared with 2004 primarily reﬂected a
reduction in net pension ﬁnance costs. This was primarily due to a higher
expected return on investment driven by a higher pension fund asset
value at the start of 2005 compared with the start of 2004, while the
expected long-term rate of return was similar.

Taxation
The charge for corporate taxes for continuing operations in 2006 was
$12,331 million, compared with $9,473 million in 2005 and $7,082 million
in 2004. The effective rate was 36% in 2006, 30% in 2005 and 28% in
2004. The increase in the effective rate in 2006 compared with 2005
primarily reﬂected the impact of the increase in the North Sea tax rate
enacted by the UK government in July 2006 and the absence of
non-recurring beneﬁts that were present in 2005. The increase in
the effective rate in 2005 compared with 2004 was primarily due to a
higher proportion of income in countries bearing higher tax rates,
and other factors.

BP Annual Report and Accounts 2006

49

Business results
Proﬁt before interest and taxation from continuing operations, which is before ﬁnance costs, other ﬁnance expense, taxation and minority interests, was
$35,158 million in 2006, $32,682 million in 2005 and $25,746 million in 2004.

Exploration and Production

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

2006

2005

2004

52,600
29,629

1,045
624

47,210
25,502

684
305

34,700
18,085

637
274

$ per barrel

Sales and other operating revenues from continuing operations
Proﬁt before interest and tax from continuing operationsa
Results include

Exploration expense
Of which: Exploration expenditure written off

Key statistics
Average BP crude oil realizationsb

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

UK
USA
Rest of World
BP average

Average BP NGL realizationsb

UK
USA
Rest of World
BP average

Average BP liquids realizationsb c

UK
USA
Rest of World
BP average

62.45
62.03
61.11
61.91

47.21
36.13
36.03
37.17

61.67
57.25
59.54
59.23

51.22
50.98
48.32
50.27

37.95
31.94
35.11
33.23

50.45
47.83
47.56
48.51

36.11
37.40
34.99
36.45

31.79
25.67
27.76
26.75

35.87
35.41
34.51
35.39

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ per thousand cubic feet

Average BP natural gas realizationsb

UK
USA
Rest of World
BP average

6.33
5.74
3.70
4.72

5.53
6.78
3.46
4.90

4.32
5.11
2.74
3.86

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ per barrel

66.02
63.57
65.14

56.58
53.55
54.48

41.49
38.96
38.27

7.24

8.65

6.13

$/mmBtu

mb/d

mmcf/d

mboe/d

1,351
1,124

1,423
1,139

1,480
1,051

7,412
1,005

7,512
912

7,624
879

2,629
1,297

2,718
1,296

2,795
1,202

Average West Texas Intermediate oil price
Alaska North Slope US West Coast
Average Brent oil price

Average Henry Hub gas priced

Total liquids production for subsidiariesc e
Total liquids production for equity-accounted entitiesc e

Natural gas production for subsidiariese
Natural gas production for equity-accounted entitiese

Total production for subsidiariese f
Total production for equity-accounted entitiese f

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

a Includes profit after interest and tax of equity-accounted entities.
b The Exploration and Production business does not undertake any hedging activity. Consequently, realizations reflect the market price achieved.
c Crude oil and natural gas liquids.
d Henry Hub First of Month Index.
e Net of royalties.
f 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.

Sales and other operating revenues for 2006 were $53 billion, compared
with $47 billion in 2005 and $35 billion in 2004. The increase in 2006
primarily reﬂected an increase of around $6 billion related to higher liquids
and gas realizations, partially offset by a decrease of around $1 billion due
to lower volumes of subsidiaries. The increase in 2005 primarily reﬂected
an increase of around $13 billion related to higher liquids and gas
realizations, partially offset by a decrease of around $1 billion due to
slightly lower volumes of subsidiaries.

Proﬁt before interest and tax for the year ended 31 December 2006
was $29,629 million, including net gains of $2,114 million on the sales

of assets (primarily gains from the sales of our interest in the Shenzi
discovery in the Gulf of Mexico in the US and interests in the North Sea
offset by a loss on the sale of properties in the Gulf of Mexico shelf),
net fair value gains of $515 million on embedded derivatives (these
embedded derivatives are fair valued at each period end with the resulting
gains or losses taken to the income statement) and a net impairment
credit of $203 million (comprised of a $340 million credit for reversals of
previously booked impairments partially offset by a charge of $109 million
against intangible assets relating to properties in Alaska, and other

50

individually insigniﬁcant impairments), and was after inventory holding
losses of $18 million and charges for legal provisions of $335 million.

Proﬁt before interest and tax for the year ended 31 December 2005
was $25,502 million, including inventory holding gains of $17 million and
net gains of $1,159 million on the sales of assets, primarily from our
interest in the Ormen Lange ﬁeld in Norway, and was after net fair value
losses of $1,688 million on embedded derivatives, an impairment charge
of $226 million in respect of ﬁelds in the Gulf of Mexico, a charge for
impairment of $40 million relating to ﬁelds in the UK North Sea and
a charge of $265 million on the cancellation of an intra-group gas
supply contract.

Proﬁt before interest and tax for the year ended 31 December 2004
was $18,085 million, including inventory holding gains of $10 million, and
was after an impairment charge of $267 million in respect of ﬁelds in the
deepwater Gulf of Mexico and US onshore, an impairment charge of $108
million in respect of a gas processing plant in the US and a ﬁeld in the
Gulf of Mexico shelf, an impairment charge of $60 million in respect of
the partner-operated Temsah platform in Egypt following a blow-out, a net
loss on disposal of $65 million and a charge of $35 million in respect of
Alaskan tankers that were no longer required. In addition, following the
lapse of the sale agreement for oil and gas properties in Venezuela,
$31 million of the previously booked impairment was reversed.

The primary additional factors reﬂected in proﬁt before interest and tax

for the year ended 31 December 2006 compared with the year ended
31 December 2005 were higher overall realizations contributing around
$5,050 million (liquids realizations were higher and gas realizations were
lower), partially offset by decreases of around $1,825 million due to
lower reported volumes, $350 million due to higher production taxes and

$1,950 million due higher costs, reﬂecting the impacts of sector-speciﬁc
inﬂation, increased integrity spend and revenue investments. Additionally,
BP’s share of the TNK-BP result was higher by around $500 million,
primarily reﬂecting higher disposal gains.

The primary additional factors reﬂected in proﬁt before interest and tax
for the year ended 31 December 2005 compared with the year ended 31
December 2004 were higher liquids and gas realizations contributing
around $10,100 million and around $400 million from higher volumes (in
areas not affected by hurricanes), partially offset by a decrease of around
$900 million due to the hurricane impact on volumes, costs associated
with hurricane repairs and Thunder Horse of around $200 million and
higher operating and revenue investment costs of around $1,700 million.

Total production for 2006 was 2,629mboe/d for subsidiaries and

1,297mboe/d for equity-accounted entities, compared with 2,718mboe/d
and 1,296mboe/d respectively in 2005. For subsidiaries, increases in
production in our new proﬁt centres were offset by anticipated decline in
our existing proﬁt centres and the effect of disposals.

Actual production for subsidiaries and equity-accounted entities in
2006 of 2,629mboe/d and 1,297mboe/d respectively, compared with
2,649mboe/d and 1,301mboe/d previously indicated at the time of our
third-quarter results.

Total production for 2005 was 2,718mboe/d for subsidiaries and

1,296mboe/d for equity-accounted entities, compared with 2,795mboe/d
and 1,202mboe/d respectively in 2004. For subsidiaries, increases in
production in our new proﬁt centres were more than offset by the effect
of the hurricanes, higher planned maintenance shutdowns and anticipated
decline in our existing proﬁt centres. For equity-accounted entities, this
primarily reﬂects growth from TNK-BP.

Reﬁning and Marketing

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Sales and other operating revenues from continuing operations
Proﬁt before interest and tax from continuing operationsa

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Global Indicator Reﬁning Margin (GIM)b
Northwest Europe
US Gulf Coast
Midwest
US West Coast
Singapore
BP average

Reﬁning availabilityc

Reﬁnery throughputs

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

a Includes profit after interest and tax of equity-accounted entities.
b The GIM is the average of regional industry indicator margins that we weight for BP’s crude refining capacity in each region. Each regional indicator margin is based on a
single representative crude with product yields characteristic of the typical level of upgrading complexity. The refining margins are industry-specific rather than BP-specific
measures, which we believe are useful to investors in analysing trends in the industry and their impact on our results. The margins are calculated by BP based on published
crude oil and product prices and take account of fuel utilization and catalyst costs. No account is taken of BP’s other cash and non-cash costs of refining, such as wages and
salaries and plant depreciation. The indicator margin may not be representative of the margins achieved by BP in any period because of BP’s particular refining configurations
and crude and product slate.
c Refining availability is defined as the ratio of units that are available for processing, regardless of whether they are actually being used, to total capacity. Where there is
planned maintenance, such capacity is not regarded as being available. During 2006, there was planned maintenance of a substantial part of the Texas City refinery.

BP Annual Report and Accounts 2006

51

2006

2005

2004

232,855
5,041

213,326
6,926

170,639
6,506

$/bbl

%

mb/d

3.92
12.00
9.14
14.84
4.22
8.39

5.47
11.40
8.19
13.49
5.56
8.60

4.28
7.15
5.08
11.27
4.94
6.31

82.5

92.9

95.4

2,198

2,399

2,607

The changes in sales and other operating revenues are explained in more detail below.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

2006

38,577
177,995
16,283

232,855

2005

36,992
155,098
21,236
213,326

2004

21,989
124,458
24,192
170,639

mb/d

2,110
5,801

2,464
5,888

2,312
6,398

The primary additional factors reﬂected in proﬁt before interest and

tax for the year ended 31 December 2006 compared with the year
ended 31 December 2005 were a positive impact from IFRS fair value
accounting (compared with a negative impact in 2005), contributing
around $500 million, and lower costs associated with rationalization
programmes of around $320 million. In addition, reﬁning margins,
including the beneﬁts of supply optimization, were higher by some $400
million and retail margins were higher by around $600 million, although
this was partially offset by a deterioration of around $150 million in other
marketing margins. These factors were offset by a reduction of around
$1.1 billion due to the impact of the progressive recommissioning of
Texas City during the year. Efﬁciency programmes delivered lower
operating costs although the savings have been offset by higher
turnaround and integrity management spend.

The primary additional factors reﬂected in proﬁt before interest and
tax for the year ended 31 December 2005, compared with the year ended
31 December 2004, were improved reﬁning margins, contributing
approximately $2,000 million, offset by lower retail marketing margins,
reducing proﬁts by approximately $720 million, a reduction of around
$870 million due to the shutdown of the Texas City reﬁnery, along with
other storm-related supply disruptions to a number of our US-based
businesses, an adverse impact of around $400 million due to fair value
accounting for derivatives (see explanation below), a reduction of around
$430 million due to rationalization and efﬁciency programme charges,
mainly across our marketing activities in Europe.

Where derivative instruments are used to manage certain economic

exposures that cannot themselves be fair valued or accounted for as
hedges, timing differences in relation to the recognition of gains and
losses occur. These economic exposures primarily relate to inventories
held in excess of normal operating requirements that are not designated
as held for trading and fair valued and forecast transactions to replenish
inventory. Gains and losses on derivative commodity contracts are
recognized immediately through the income statement while gains and
losses on the related physical transaction are recognized when the
commodity is sold.

Additionally, IFRS requires that inventory designated as held for trading

is fair valued using period end spot prices while the related derivative
instruments are valued using 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 quarterly
timing differences.

The average reﬁning Global Indicator Margin (GIM) in 2006 was lower
than in 2005. Retail margins improved, but this improvement was partially
negated by deterioration in other marketing margins.

Reﬁning throughputs in 2006 were 2,198mb/d, 201mb/d lower than in
2005. Reﬁning availability, excluding the Texas City reﬁnery, was 95.7%,
broadly consistent with 2005. Marketing volumes at 3,872mb/d were
around 2% lower than in 2005.

Sale of crude oil through spot and term contracts
Marketing, spot and term sales of reﬁned products
Other sales including non-oil and to other segments

Sale of crude oil through spot and term contracts
Marketing, spot and term sales of reﬁned products

Sales and other operating revenues for 2006 was $233 billion, compared
with $213 billion in 2005 and $171 billion in 2004. The increase in 2006
compared with 2005 was principally due to an increase of around
$23 billion in marketing, spot and term sales of reﬁned products. This
was due to higher prices of $25 billion, partially offset by lower volumes
of $2 billion. Additionally, sales of crude oil, spot and term contracts
increased by $2 billion, reﬂecting higher prices of $6 billion and lower
volumes of $4 billion, and other sales decreased by $5 billion, primarily
due to lower volumes. The increase in 2005 compared with 2004 was
principally due to an increase of around $31 billion in marketing, spot and
term sales of reﬁned products. This reﬂected higher prices of $39 billion
and a positive foreign exchange impact due to a weaker dollar of $1 billion,
partially offset by lower volumes of $9 billion. Additionally, sales of crude
oil, spot and term contracts increased by $15 billion due to higher prices
of $13 billion and higher volumes of $2 billion and other sales decreased
by $3 billion, primarily due to lower volumes.

Proﬁt before interest and tax for the year ended 31 December 2006
was $5,041 million, including net disposal gains of $884 million (related
primarily to the sale of BP’s Czech Republic retail business, the disposal
of BP’s shareholding in Zhenhai Reﬁning and Chemicals Company, the
sale of BP’s shareholding in Eiffage, the French-based construction
company, and pipelines assets), and was after inventory holding losses of
$242 million, a charge of $925 million as a result of the ongoing review
of fatality and personal injury compensation claims associated with the
March 2005 incident at the Texas City reﬁnery, an impairment charge of
$155 million, a charge of $155 million in respect of a donation to the BP
Foundation and a charge of $33 million relating to new, and revisions to
existing, environmental and other provisions.

Proﬁt before interest and tax for the year ended 31 December 2005
was $6,926 million, including inventory holding gains of $2,532 million
and net gains of $177 million principally on the divestment of a number of
regional retail networks in the US, and is after a charge of $700 million
in respect of fatality and personal injury compensation claims associated
with the incident at the Texas City reﬁnery, a charge of $140 million
relating to new, and revisions to existing, environmental and other
provisions, an impairment charge of $93 million and a charge of $33 million
for the impairment of an equity-accounted entity.

Proﬁt before interest and tax for the year ended 31 December 2004
was $6,506 million, including inventory holding gains of $1,312 million,
and is after net losses on disposal of $267 million (principally related to
the closure of two manufacturing plants at Hull, UK, the disposal of our
European speciality intermediate chemicals business, the disposal of our
interest in the Singapore Reﬁning Company Private Limited, the closure of
the lubricants operation of the Coryton reﬁnery in the UK and of reﬁning
operations at the ATAS reﬁnery in Mersin, Turkey, and the sale of the
Cushing and other pipeline interests in the US), a charge of $206 million
related to new, and revisions to existing, environmental and other
provisions, a charge of $195 million for the impairment of the
petrochemicals facilities at Hull, UK, and a charge of $32 million for
restructuring, integration and rationalization.

52

2006

11,428
12,280

23,708

2005

15,222
10,474
25,696

2004

13,532
10,437
23,969

2006

2005

2004

3,685
5,152

5,096
4,747

5,244
3,670

Gas, Power and Renewables

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Sales and other operating revenues from continuing operations
Proﬁt before interest and tax from continuing operationsa

2006

2005

2004

23,708
1,321

25,696
1,172

23,969
1,003

a Includes profit after interest and tax of equity-accounted entities.

The changes in sales and other operating revenues are explained in more detail below.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Gas marketing sales
Other sales (including NGLs marketing)

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

mmcf/d

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Gas marketing sales volumes
Natural gas sales by Exploration and Production

Sales and other operating revenues for 2006 was $24 billion, compared
with $26 billion in 2005. Gas marketing sales declined by $3.8 billion,
reﬂecting a decrease of $4.2 billion related to lower volumes, partially
offset by an increase of $0.4 billion related to higher prices. Other sales
(including NGLs marketing) increased by $1.8 billion due to higher prices.
Sales and other operating revenues were $26 billion in 2005, compared
with $24 billion in 2004. Gas marketing sales increased by $1.7 billion
as price increases of $2.1 billion more than offset lower volumes of
$0.4 billion. Other sales (including NGLs marketing) remained ﬂat,
reﬂecting $0.1 billion related to higher prices and $0.1 billion to lower
volumes. Gas marketing sales volumes declined in 2005 and 2006
primarily due to customer portfolio changes and, in 2005, production loss
caused by hurricanes in the Gulf of Mexico.

Proﬁt before interest and tax for the year ended 31 December 2006
was $1,321 million, including net gains of $193 million, primarily on the
disposal of our interest in Enagas, and net fair value gains of $88 million
on embedded derivatives, and was after inventory holding losses of $55
million and a charge $100 million for the impairment of a North American
NGLs asset.

Other businesses and corporate

Proﬁt before interest and tax for the year ended 31 December 2005

was $1,172 million, including inventory holding gains of $95 million,
compensation of $265 million received on the cancellation of an
intra-group gas supply contract and net gains of $55 million primarily on
the disposal of BP’s interest in the Interconnector pipeline and a power
plant in the UK, and was after net fair value losses of $346 million on
embedded derivatives and a credit of $6 million related to new, and
revisions to existing, environmental and other provisions.

Proﬁt before interest and tax for the year ended 31 December 2004
was $1,003 million, including inventory holding gains of $39 million and
a net gain on disposal of $56 million.

The primary additional factors reﬂected in proﬁt before interest and tax

for the year ended 31 December 2006, compared with the equivalent
period in 2005, were higher contributions from the operating businesses
of around $160 million partially offset by higher IFRS fair value accounting
charges reducing the result by around $60 million.

The primary additional factors reﬂected in proﬁt before interest and tax

for the year ended 31 December 2005, compared with the equivalent
period in 2004 were higher contributions from the operating businesses
of around $170 million.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Sales and other operating revenues from continuing operations
Proﬁt (loss) before interest and tax from continuing operationsa

a Includes profit after interest and tax of equity-accounted entities.

Other businesses and corporate comprises Finance, the group’s
aluminium asset, its investments in PetroChina and Sinopec (both
divested in early 2004), interest income and costs relating to corporate
activities worldwide. Following the sale of Innovene to INEOS in 2005,
three equity-accounted entities (Shanghai SECCO Petrochemical
Company Limited in China and Polyethylene Malaysia Sdn Bhd and
Ethylene Malaysia Sdn Bhd, both in Malaysia) previously reported in
Other businesses and corporate were transferred to Reﬁning and
Marketing, effective 1 January 2006.

The loss before interest and tax for the year ended 31 December 2006
was $885 million, including inventory holding gains of $62 million, a credit
of $94 million in relation to new, and revisions to existing, environmental
and other provisions, a net gain on disposal of $95 million and a net fair
value gain of $5 million on embedded derivatives, and was after a charge
of $200 million relating to the reassessment of certain provisions and an
impairment charge of $69 million.

2006

2005

2004

1,009
(885)

668
(1,237)

546
155

The loss before interest and tax for the year ended 31 December 2005

was $1,237 million, including a net gain on disposal of $38 million, and
was after a net charge of $278 million relating to new, and revisions to
existing, environmental and other provisions and the reversal of
environmental provisions no longer required, a charge of $134 million in
respect of the separation of the Oleﬁns and Derivatives business and net
fair value losses of $13 million on embedded derivatives.

The proﬁt before interest and tax for the year ended 31 December
2004 was $155 million, including net gains on disposals of $949 million,
primarily related to the sale of our interests in PetroChina and Sinopec,
and a credit of $66 million primarily resulting from the reversal of vacant
space provisions in the UK and the US, and was after a charge of $283
million related to new, and revisions to existing, environmental and other
provisions, and a charge of $102 million relating to the separation of the
Oleﬁns and the Derivatives business.

BP Annual Report and Accounts 2006

53

Environmental expenditure

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

$ million

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Operating expenditure
Clean-ups
Capital expenditure
Additions to environmental
remediation provision

Additions to decommissioning

provision

2006

2005

2004

596
59
806

423

494
43
789

565

2,142

1,023

526
25
524

587

286

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

The increase in environmental operating expenditure in 2006 is largely
related to expenditure incurred on reducing air emissions at US reﬁneries.
The increase in capital expenditure in 2005 compared with 2004 is largely
related to clean fuels investment. Similar levels of operating and capital
expenditures are expected in the foreseeable future. In addition to
operating and capital expenditures, we also create provisions for future
environmental remediation. Expenditure against such provisions is
normally in subsequent periods and is not included in environmental
operating expenditure reported for such periods. The charge for
environmental remediation provisions in 2006 includes $378 million
resulting from a reassessment of existing site obligations and $45 million
in respect of provisions for new sites.

Liquidity and capital resources

Cash ﬂow
The following table summarizes the group’s cash ﬂows.

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

The extent and cost of future remediation programmes are inherently

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

In addition, we make provisions 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 which 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 on stream in a particular year and the outcome of the periodic
reviews.

Provisions for environmental remediation and decommissioning are
usually set up on a discounted basis, as required by IAS 37 ‘Provisions,
Contingent Liabilities and Contingent Assets’.

Further details of decommissioning and environmental provisions

appear in Financial statements – Note 40 on page 152. See also
Environmental protection on page 42.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Net cash provided by operating activities of continuing operations
Net cash provided by (used in) operating activities of Innovene operations
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 2006 was $28,172 million, compared with $26,721 million
for the equivalent period of 2005, reﬂecting a decrease in working capital
requirements of $4,817 million, an increase in proﬁt before taxation from
continuing operations of $2,721 million and an increase in dividends from
jointly controlled entities and associates of $1,662 million, partially offset
by an increase in income taxes paid of $4,705 million and a higher net
credit for impairment and gain/loss on sale of businesses and ﬁxed assets
of $2,095 million.

Net cash provided by operating activities for the year ended

31 December 2005 was $26,721 million compared with $23,378 million
for the equivalent period of 2004, reﬂecting an increase in proﬁt before
taxation from continuing operations of $6,955 million, an increase in
net cash provided by operating activities of Innovene of $1,639 million,
a lower charge for provisions, less payments of $710 million and an
increase in dividends received from jointly controlled entities and

associates of $634 million. This was partially offset by an increase in
income taxes paid of $2,640 million, an increase of $1,320 million in
working capital requirements, an increase in earnings from jointly
controlled entities and associates of $1,263 million, a higher net credit for
impairment and gain/loss on sale of businesses and ﬁxed assets of
$775 million, an increase in interest paid of $429 million and an increase in
the net operating charge for pensions and other post-retirement beneﬁts,
less contributions of $351 million.

Net cash used in investing activities was $9,518 million in 2006,
compared with $1,729 million and $11,331 in 2005 and 2004. The
increase in 2006 reﬂected a reduction in disposal proceeds of
$4,946 million and an increase in capital expenditure of $2,844 million.
The reduction in 2005 compared with 2004 reﬂected an increase in
disposal proceeds of $6,239 million, primarily from the sale of Innovene,
and a decrease in spending on acquisitions of $2,693 million.

54

2006

28,172
–

28,172
(9,518)
(19,071)
47

(370)
2,960

2,590

2005

2004

25,751
970
26,721
(1,729)
(23,303)
(88)
1,601
1,359
2,960

24,047
(669)
23,378
(11,331)
(12,835)
91
(697)
2,056
1,359

Net cash used in ﬁnancing activities was $19,071 million in 2006
compared with $23,303 million in 2005 and $12,835 million in 2004.
The lower outﬂow in 2006 reﬂects a net increase in short term debt
of $5,330 million, a decrease in repayments of long-term ﬁnancing
of $1,165 million and higher proceeds from long-term ﬁnancing of
$1,356 million, partially offset by an increase in the net repurchase of
share of $3,836 million. The higher outﬂow in 2005 compared with 2004
reﬂects an increase in the net repurchase of ordinary share capital of
$4,107, higher repayments of long-term ﬁnancing of $2,616 million,
a net decrease of $1,433 million in short-term debt, and increases in
equity dividends paid to BP shareholders of $1,318 million and to
minority interest of $794 million.

The group has had signiﬁcant levels of capital investment for many
years. Capital investment, excluding acquisitions, was $16.9 billion in
2006, $13.9 billion in 2005 and $13.8 billion in 2004. 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 $21.7 billion at the end of 2004, $16.2 billion at the end
of 2005 and was $21.4 billion at the end of 2006. The lower level of debt
at the end of 2005 reﬂects the receipt of the Innovene disposal proceeds
in December 2005.

Over the period 2004 to 2006 our cash inﬂows and outﬂows were
balanced, with sources and uses both totalling $101 billion. During that
period, the price of Brent has averaged $52.63/bbl. The following table
summarizes the three-year sources and uses of cash.

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Sources
Net cash provided by operating activities
Divestments
Movement in net debt

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Uses
Capital expenditure
Acquisitions
Net repurchase of shares
Dividends to BP shareholders
Dividends to Minority Interest

$ billion

$ billion

78
22
1
101

42
3
34
21
1
101

Acquisitions made for cash were more than offset by divestments. Net
investment over the same period has averaged $7.7 billion per year.
Dividends to BP shareholders, which grew on average by 14.9% per year
in dollar terms, used $21 billion. Net repurchase of shares was $34 billion,
which includes $35 billion in respect of our share buyback programme
less proceeds from share issues. Finally, cash was used to strengthen the
ﬁnancial condition of certain of our pension funds. In the last three years,
$1.9 billion has been contributed to funded pension plans.

Trend information
We expect to grow cash ﬂows underpinned by the following:
– We expect to grow production even in a $60/bbl price environment.
– We aim to control cost increases below inﬂation.
– We expect capital expenditure to be around $18 billion in 2007.
– We expect to continue to high-grade our portfolio consistent with

our strategy.

As noted above, we expect capital expenditure, excluding acquisitions, to
be around $18 billion in 2007; the exact level will depend on a number of
things including: the actual level of sector inﬂation that we will experience
in the year; time-critical and material one-off investment opportunities
which further our strategy; and any acquisition opportunities that
may arise.

In 2006, the UK supplementary tax charge was raised to 20%,
increasing the group’s effective tax rate by 2%. The impact of the
additional one-off deferred tax adjustment relating to this rate change was
largely offset by relieving measures speciﬁcally provided in the legislation.

Total production for 2007 is expected to remain broadly the same as in
2006 after allowing for the impact on 2007 of divestments made in 2006.
This estimate is based on the group’s asset portfolio at 1January 2007,
expected start-ups in 2007 and Brent at $60/bbl, before any 2007 disposal
effects and before any effects of prices above $60/bbl on volumes
in PSAs.

The anticipated decline in production volumes from subsidiaries in
our existing proﬁt centres is partly mitigated by the development of
new projects and the investment in incremental reserves in and around
existing ﬁelds. We expect that this overall decline in production from
subsidiaries in our existing proﬁt centres will be more than compensated
for by strong increases in production from subsidiaries in our new proﬁt
centres over the next few years. Production growth in our equity-
accounted joint venture, TNK-BP, is expected to remain broadly constant
to 2009.

The most important determinants of cash ﬂows in relation to our oil

and natural gas production are the prices of these commodities. In a
stable price environment, cash ﬂows from currently developed proved
reserves are expected to decline in a manner consistent with anticipated
production decline rates. Development activities associated with recent
discoveries, as well as continued investment in these producing ﬁelds, are
expected to more than offset this decline, resulting in increased operating
cash ﬂows over the next few years. Cash ﬂows from equity-accounted
entities are expected to be in the form of dividend payments.

Dividends and other distributions to shareholders and gearing
The total dividend paid in 2006 was $7,686 million, compared with
$7,359 million in 2005 and $6,041 million in 2004. The dividend per
share was 38.40 cents, compared with 34.85 cents per share in 2005
(an increase of 10%) and 27.70 cents per share in 2004 (an increase
of 26% between 2005 and 2004). In sterling terms, the dividend paid
in 2006 was also 10% higher than 2005.

Our dividend policy is to grow the dividend per share progressively.

In pursuing this policy and in setting the levels of dividends we are
guided by several considerations, including:
– The prevailing circumstances of the group.
– The future investment patterns and sustainability of the group.
– The trading environment.
We determine the dividend in US dollars, the economic currency of BP.
BP intends to continue the operation of the Dividend Reinvestment
Plan (DRIP) for shareholders who wish to receive their dividend in the
form of shares rather than cash. The BP Direct Access Plan for US and
Canadian shareholders also includes a dividend reinvestment feature.
We remain committed to returning the excess of net cash provided
by operating activities less net cash used in investing activities to our
investors where this is in excess of investment and dividend needs.

During 2006, the company repurchased 1,334 million of its own shares

at a cost of $15,481 million. Of these, 358 million were purchased for
cancellation and the remainder are held in treasury. The repurchased
shares had a nominal value of $333 million and represented 6.5% of
ordinary shares in issue, net of treasury shares, at the end of 2005.
Since the inception of the share repurchase programme in 2000 until
the end of 2006 we have repurchased some 3,996 million shares at a
cost of $40.7 billion. We plan to continue our programme of share
buybacks, subject to market conditions and constraints and to renewed
authority at the April 2007 annual general meeting.

Our ﬁnancial framework includes a gearing band of 20-30% which is
intended to provide an efﬁcient capital structure and the appropriate level
of ﬁnancial ﬂexibility. Our aim is to maintain gearing within this range.
At 31 December 2006, gearing was 20%, at the bottom of the
targeted band.

The discussion above and following contains forward-looking

statements with regard to future cash ﬂows, future levels of
capital expenditure and divestments, future production volumes, working
capital, the renewal of borrowing facilities, shareholder distributions and
share buybacks and expected payments under contractual and
commercial commitments. 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

BP Annual Report and Accounts 2006

55

on page 13 and Risk factors on pages 12-13, 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.

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 2006 amounted to $24,010 million (2005 $19,162 million)
of which $12,924 million (2005 $8,932 million) was short term.

or longer. At 31 December 2006, the amount drawn down against the DIP
was $7,893 million.

In addition, the group has in place a US Shelf Registration under which
it may raise $10 billion of debt with maturities of one month or longer. At
31 December there had not been any draw-down.

Commercial paper markets in the US and Europe are a primary source

of liquidity for the group. At 31 December 2006, the outstanding
commercial paper amounted to $4,167 million (2005 $1,911million).

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 2006, the group had available undrawn committed
borrowing facilities of $4,700 million ($4,500 million at 31 December
2005).

BP believes that, taking into account the substantial amounts of
undrawn borrowing facilities available, the group has sufﬁcient working
capital for foreseeable requirements.

Net debt was $21,420 million at the end of 2006, an increase of

In addition to reported debt, BP uses conventional off balance sheet

$5,218 million compared with 2005. The ratio of net debt to net debt plus
equity was 20% at the end of 2006 and 17% at the end of 2005. The ratio
of 20% at 31 December 2006 takes into account seasonal impacts.

The maturity proﬁle and ﬁxed/ﬂoating rate characteristics of the group’s

debt are described in Financial statements – Note 38 on page 149.

We have in place a European Debt Issuance Programme (DIP) under
which the group may raise $10 billion of debt for maturities of one month

arrangements such as operating leases and borrowings in jointly
controlled entities and associates. At 31 December 2006, the group’s
share of third-party ﬁnance debt of jointly controlled entities and
associates was $4,942 million (2005 $3,266 million) and $1,143 million
(2005 $970 million) respectively. 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 2006 are summarized below. Some guarantees
outstanding are in respect of borrowings of jointly controlled entities and associates noted above.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Guarantees expiring by period

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Total

2007

2008

2009

2010

2011

Guarantees issued in respect of

2012 and
thereafter

Borrowings of jointly controlled entities and associates
Liabilities of other third parties

1,123
789

91
480

223
7

118
8

114
19

116
29

461
246

At 31 December 2006, contracts had been placed for authorized future capital expenditure estimated at $9,773 million. Such expenditure is expected to
be ﬁnanced largely by cash ﬂow from operating activities.

Contractual commitments
The following table summarizes the group’s principal contractual obligations at 31 December 2006. Further information on borrowings and ﬁnance
leases is given in Financial statements – Note 38 on page 149 and further information on operating leases is given in Financial statements – Note 18 on
page 127.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Total

2007

2008

2009

2010

2011

Payments due by period

2012 and
thereafter

Expected payments by period under contractual
obligations and commercial commitments
Borrowingsa
Finance lease minimum future lease payments
Operating leasesb
Decommissioning liabilities
Environmental liabilities
Pensions and other post-retirement beneﬁtsc
Purchase obligationsd

28,680
1,331
17,408
12,064
2,298
22,793
139,020

9,164
82
3,355
337
445
1,353
86,954

4,403
92
3,031
292
414
1,350
16,723

4,663
93
2,403
255
309
1,066
7,573

1,022
94
1,686
346
288
668
4,948

1,106
97
1,191
273
215
615
4,500

8,322
873
5,742
10,561
627
17,741
18,322

a Expected payments include interest payments on borrowings totalling $5,485 million ($917 million in 2007, $750 million in 2008, $554 million in 2009, $335 million in 2010,
$301 million in 2011 and $2,628 million thereafter).
b The minimum future lease payments including executory costs and after deducting related rental income from operating subleases. Where an operating lease is entered into
solely by the group as the operator of a jointly controlled asset, the total cost is included irrespective of any amounts that will be reimbursed by joint venture partners. Where
operating lease costs are incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital
cost of the project.
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 2007 include purchase
commitments existing at 31 December 2006 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 Quantitative and qualitative disclosures about market risk on page 61.

56

The following table summarizes the nature of the group’s unconditional purchase obligations.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Payments due by period

Total

Purchase obligations – payments due by period
Crude oil and oil products
Natural gas
Chemicals and other reﬁnery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
47,247
18,070
5,162
14,464
197
830
984
------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
86,954

58,036
37,923
12,906
20,148
1,618
3,704
4,685
139,020

1,912
8,836
3,660
–
922
1,269
1,723
18,322

4,865
4,622
1,541
4,407
156
530
602
16,723

1,518
1,549
590
–
106
299
438
4,500

1,368
2,954
956
1,270
131
407
487
7,573

1,126
1,892
997
7
106
369
451
4,948

2008

2009

2011

2007

2010

2012 and
thereafter

The following table summarizes the group’s capital expenditure commitments at 31 December 2006 and the proportion of that expenditure for which
contracts have been placed. For jointly controlled assets, the net BP share is included in the amounts shown. The group expects its total capital
expenditure excluding acquisitions to be around $18 billion in 2007.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Capital expenditure commitments including
amounts for which contracts have been placed
Committed on major projects
Amounts for which contracts have been placed

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
11,175
5,782

22,273
9,773

5,607
2,127

2,812
1,171

1,659
435

597
191

423
67

Total

2007

2008

2009

2010

2011

$ million

2012 and
thereafter

Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s
business activities may not be available. The group has long-term debt
ratings of Aa1 and AA+, assigned respectively by Moody’s and Standard
& Poor’s.

The group has access to a wide range of funding at competitive rates
through the capital markets and banks. It co-ordinates relationships with
banks, borrowing requirements, foreign exchange requirements and cash
management centrally. The group believes it has access to sufﬁcient
funding, including through the commercial paper markets, and also has
undrawn committed borrowing facilities to meet currently foreseeable
borrowing requirements. At 31 December 2006, the group had substantial
amounts of undrawn borrowing facilities available, including committed
facilities of $4,700 million, of which $4,300 million are in place for at least
ﬁve years (2005 $4,500 million expiring in 2006 and 2004 $4,500 million
expiring in 2005). These facilities are with a number of international banks
and borrowings under them would be at pre-agreed rates. Certain of
these facilities support the group’s commercial paper programme.

Critical accounting policies

The signiﬁcant accounting policies of the group are summarized
in Financial statements – Note 1 on page 100.

Inherent in the application of many of the accounting policies used

in the preparation of the ﬁnancial statements is the need for BP
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities at the date of the 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 further information about the
critical accounting policies that could have a signiﬁcant impact on the
results of the group and should be read in conjunction with the Notes
on ﬁnancial statements.

The accounting policies and areas that require the most signiﬁcant

judgements and estimates to be used in the preparation of the
consolidated ﬁnancial statements are in relation to oil and natural gas
accounting, including the estimation of reserves, the recoverability of
asset carrying values, deferred taxation, provisions and contingencies,
and pensions and other post-retirement beneﬁts.

Oil and natural gas accounting

The group follows the successful efforts method of accounting for its

oil and natural gas exploration and production activities.

The acquisition of geological and geophysical seismic information, prior

to the discovery of proved reserves, is expensed as incurred, similar to
the accounting for research and development costs.

Licence and property acquisition costs are initially capitalized within
intangible assets. These costs are amortized on a straight-line basis until
such time as either exploration drilling is determined to be successful or it
is unsuccessful and all costs are written off. Each property is reviewed on
an annual basis to conﬁrm that drilling activity is planned and that it is not
impaired. If no future activity is planned, the remaining balance of the
licence and property acquisition costs is written off.

For exploration wells and exploratory-type stratigraphic test wells, costs

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

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

Once a project is sanctioned for development, the carrying values of
licence and property acquisition costs and exploration and appraisal costs
are transferred to production assets within property, plant and equipment.
Field development costs subject to depreciation are expenditures incurred
to date, together with sanctioned future development expenditure
approved by the group.

BP Annual Report and Accounts 2006

57

The capitalized exploration and development costs for proved oil and

gas properties (which include the costs of drilling unsuccessful wells)
are amortized on the basis of oil-equivalent barrels that are produced
in a period as a percentage of the estimated proved reserves.

The estimated proved reserves used in these unit-of-production
calculations vary with the nature of the capitalized expenditure. The
reserves used in the calculation of the unit-of-production amortization
are as follows:
– Proved developed reserves for producing wells.
– Total proved reserves for development costs.
– Total proved reserves for licence and property acquisition costs.
– Total proved reserves for future decommissioning costs.
The impact of changes in estimated proved reserves is dealt with
prospectively by amortizing the remaining book value of the asset over
the expected future production. If proved reserves estimates are revised
downwards, earnings could be affected by higher depreciation expense or
an immediate write-down of the property’s book value (see discussion
of recoverability of asset carrying values below).

Given the large number of producing ﬁelds in the group’s portfolio, it is
unlikely that any changes in reserves estimates for individual ﬁelds, either
individually or in aggregate, year on year, will have a signiﬁcant effect on
the group’s prospective charges for depreciation.

At the end of 2006, BP adopted the Securities and Exchange
Commission (SEC) rules for estimating reserves for accounting and
reporting purposes instead of the UK accounting rules contained in the
UK SORP. These changes are explained in Financial statements – Note 3
on page 110.

Oil and natural gas reserves
Commencing in 2006, BP has estimated its proved reserves on the basis
of the requirements of the SEC. The 2006 year-end marker prices used to
determine reserves volumes were Brent $58.93/bbl ($58.21/bbl) and
Henry Hub $5.52/mmBtu ($9.52/mmbtu). Prior to this date, BP used
guidance contained in the UK SORP to estimate reserves. In estimating
its reserves under UK SORP, BP used long-term planning prices.
The group manages its hydrocarbon resources in three major
categories: prospect inventory, non-proved resources and proved
reserves. When a discovery is made, volumes usually transfer from the
prospect inventory to the non-proved resource category. The resources
move through various non-proved resource sub-categories as their
technical and commercial maturity increases through appraisal activity.

Resources in a ﬁeld will only be categorized as proved reserves when

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

At the point of sanction, all booked reserves will be categorized as
proved undeveloped (PUD). Volumes will subsequently be recategorized
from PUD to proved developed (PD) as a consequence of development
activity. When part of a well’s reserves depends on a later phase of
activity, only that portion of reserves associated with existing, available
facilities and infrastructure moves to PD. The ﬁrst PD bookings will occur
at the point of ﬁrst oil or gas production. Major development projects
typically take one to four years from the time of initial booking to the
start of production. Changes to reserves bookings may be made due
to analysis of new or existing data concerning production, reservoir
performance, commercial factors, acquisition and divestment activity and
additional reservoir development activity. Proved reserves do not include
reserves that are dependent on the renewal of exploration and production

licences, unless there is strong evidence to support the assumption of
such renewal.

BP has an internal process to control the quality of reserves bookings
that forms part of a holistic and integrated system of internal control. As
discussed in the oil and natural gas accounting section and below, oil and
natural gas reserves have a direct impact on certain amounts reported in
the ﬁnancial statements.

The 2006 movements in proved reserves are reﬂected in the tables

showing movements in oil and gas reserves by region in Financial
statements – Supplementary information on oil and natural gas on pages
196-197.

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. Such indicators include
changes in the group’s business plans, changes in commodity prices
leading to unproﬁtable performance and, for oil and gas properties,
signiﬁcant downward revisions of estimated proved reserves quantities.
The assessment for impairment entails comparing the carrying value of
the cash generating unit and associated goodwill with the recoverable
amount of the asset, that is, the higher of net realizable value and value
in use. Value in use is usually determined on the basis of discounted
estimated future net cash ﬂows.

Determination as to whether and how much an asset is impaired

involves management estimates on highly uncertain matters such
as future commodity prices, the effects of inﬂation and technology
improvements on operating expenses, production proﬁles and the outlook
for global or regional market supply-and-demand conditions for crude oil,
natural gas 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 and associated risk-adjusted probable and possible reserves.
Expected future cash ﬂows from the sale or production of reserves
are calculated based on the group’s best estimate of future oil and gas
prices. For 2006, 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
2006, the group’s long-term planning assumptions were $40 per barrel for
Brent and $5.50 per mmBtu for Henry Hub. Previously, prices for oil and
natural gas used in future cash ﬂow calculations were assumed to decline
from the existing levels in equal steps during the following three years
to the long-term planning assumptions, which were $25 per barrel and
$4.0 per mmBtu for Brent and Henry Hub respectively. These long-term
planning assumptions are subject to periodic review and modiﬁcation.
The estimated future level of production is based on assumptions about
future commodity prices, lifting and development costs, ﬁeld decline
rates, market demand and supply, economic regulatory climates
and other factors.

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

Irrespective of whether there is any indication of impairment, BP is

required to test for impairment any goodwill acquired in a business
combination. The group carries goodwill of approximately $10.8 billion on
its balance sheet, principally relating to the Atlantic Richﬁeld and Burmah
Castrol acquisitions. In testing goodwill for impairment, the group uses a
similar approach to that described above. The cash-generating units for
impairment testing in this case are one level below business segments.
As noted 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.

58

Deferred taxation
The group has around $4.7 billion of carry-forward tax losses in the UK
and Germany, which would be available to offset against future taxable
income. At the end of 2006, $216 million of deferred tax assets were
recognized on these losses as this is the extent to which it is judged that
suitable taxable income will arise. No material carry-forward tax losses in
other taxing jurisdictions have been recognized as deferred tax assets and
these are unlikely to have a signiﬁcant effect on the group’s tax rate in
future years.

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 tangible 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 to be used in discounting the cash ﬂows.
The interest rate used to determine the balance sheet obligation at the
end of 2006 was 2%, unchanged from the end of 2005. The interest rate
represents the real rate (i.e. adjusted for inﬂation) on long-dated
government bonds.

Other provisions and liabilities are recognized in the period when it
becomes probable that there will be a future outﬂow of funds resulting
from past operations or events that can be reasonably estimated. The
timing of recognition requires the application of judgement to existing
facts and circumstances, which can be subject to change. Since the

actual cash outﬂows can take place many years in the future, the carrying
amounts of provisions and liabilities are reviewed regularly and adjusted
to take account of changing facts and circumstances.

A change in estimate of a recognized provision or liability would
result in a charge or credit to net income in the period in which the
change occurs (with the exception of decommissioning costs as
described above).

In particular, provisions for environmental clean-up and remediation

costs are based on current legal and constructive requirements,
technology, price levels and expected plans for remediation. Actual costs
and cash outﬂows can differ from estimates because of changes in laws
and regulations, public expectations, prices, discovery and analysis of site
conditions and changes in clean-up technology.

The provision for environmental liabilities is reviewed at least annually.

The interest rate used to determine the balance sheet obligation at
31 December 2006 was 2%, the same rate as at the previous balance
sheet date.

As further described in Financial statements – Note 47 on page 168 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 other post-retirement plans is important to the
recorded amounts for such obligations on the balance sheet and to the
amount of beneﬁt expense in the income statement. The assumptions
used may vary from year to year, which will affect future results of
operations. Any differences between these assumptions and the actual
outcome also affect future results of operations.

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

The pension assumptions at 31 December 2006 and 2005 are summarized below.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

%

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

2006

2006

2006

USA

2005

Other

2005

UK

2005

7.0
5.1
4.7
2.8
2.8

7.00
4.75
4.25
2.50
2.50

8.0
5.7
4.2
nil
2.4

8.00
5.50
4.25
nil
2.50

5.8
4.8
3.6
1.8
2.2

5.50
4.00
3.25
1.75
2.00

Rate of return on pension plan assets
Discount rate for pension plan liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Inﬂation

The assumptions used in calculating the charge for US other post-retirement beneﬁts are consistent with those shown above for US pension plans
except for the discount rate for plan liabilities which is 5.9% (2005 5.5%).

BP Annual Report and Accounts 2006

59

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

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

One-percentage-point

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Increase

Decrease

Investment return

Effect on pension and other post-retirement beneﬁt expense in 2007

Discount rate

Effect on pension and other post-retirement beneﬁt expense in 2007
Effect on pension and other post-retirement beneﬁt obligation at 31 December 2006

The assumed future US healthcare cost trend rate is shown below.

(383)

383

(52)
(5,013)

75
6,433

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

%

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

2007

2008

2009

2010

2011

2012

Beneﬁciaries aged under 65
Beneﬁciaries aged over 65

8.0
10.0

7.5
9.5

7.0
8.5

6.5
7.5

6.0
6.5

5.5
5.5

5.0
5.0

2013 and
subsequent
years

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

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

One-percentage-point

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Effect on US other post-retirement beneﬁt expense in 2007
Effect on US other post-retirement obligation at 31 December 2006

Increase

Decrease

31
349

(25)
(289)

In addition to the ﬁnancial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reﬂect best practice
in the countries in which we provide pensions and have been chosen with regard to the latest available published tables adjusted where appropriate
to reﬂect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension liabilities
are in the UK, the US and Germany, where our assumptions are as follows.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Mortality assumptions

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

UK

2005

USA

2005

2006

2006

2006

23.9
26.8
25.0
27.8

23.0
26.0
23.9
26.9

24.2
26.0
25.8
26.9

21.9
25.6
21.9
25.6

22.2
26.9
25.2
29.6

22.1
26.7
25.0
29.4

Years

Germany

2005

Life expectancy at age 60 for a male currently aged 60
Life expectancy at age 60 for a female currently aged 60
Life expectancy at age 60 for a male currently aged 40
Life expectancy at age 60 for a female currently aged 40

Adoption of International Financial Reporting Standards
For all periods up to and including the year ended 31 December 2004,
BP prepared its ﬁnancial statements in accordance with UK generally
accepted accounting practice (UK GAAP). BP, together with all other EU
companies listed on an EU stock exchange, was required to prepare
consolidated ﬁnancial statements in accordance with International
Financial Reporting Standards (IFRS) as adopted by the EU with effect
from 1 January 2005. The Annual Report and Accounts for the year ended
31 December 2005 comprised BP’s ﬁrst consolidated ﬁnancial statements
prepared under IFRS.

The general principle for ﬁrst-time adoption of IFRS is that standards in

force at the ﬁrst reporting date (for BP, 31 December 2005) are applied
retrospectively. However, IFRS 1 ‘First-time Adoption of International
Financial Reporting Standards’ contains a number of exemptions that
companies are permitted to apply. BP elected to take the exemption
allowing comparative information on ﬁnancial instruments to be prepared
in accordance with UK GAAP and the group adopted IAS 32 ‘Financial
Instruments: Disclosure and Presentation’ (IAS 32) and IAS 39 ‘Financial
Instruments: Recognition and Measurement’ (IAS 39) from 1 January
2005. Had IAS 32 and IAS 39 been applied from 1 January 2003, BP’s

date of transition for all other IFRS in force at the ﬁrst reporting date,
the following are the most signiﬁcant adjustments that would have
been necessary in the ﬁnancial statements for the year ended
31 December 2004:
– All derivatives, including embedded derivatives, would have been

brought on to the balance sheet at fair value and changes in fair value
would have been recognized in the income statement.

– Available-for-sale investments would have been carried at fair value

rather than at cost and changes in fair value would have been
recognized directly in equity.

Further information regarding the impact of adopting IAS 32 and IAS 39
is shown in Financial statements – Note 49 on page 168.

US generally accepted accounting principles
The consolidated ﬁnancial statements of the BP group are prepared in
accordance with IFRS, which differs in certain respects from US GAAP.
The principal differences between US GAAP and IFRS for BP group
reporting are discussed in Financial statements – Note 53 on page 179.
The impact of new US accounting standards is also disclosed in that note.

60

Quantitative and qualitative disclosures
about market risk

The group is exposed to a number of different market risks arising from
its normal business activities. Market risk is the possibility that changes
in foreign currency exchange rates, interest rates, or oil and natural gas
or power prices will adversely affect the value of the group’s ﬁnancial
assets, liabilities or expected future cash ﬂows. The group has developed
policies aimed at managing the volatility inherent in certain of these
natural business exposures and in accordance with these policies the
group enters into various transactions using derivative ﬁnancial and
commodity instruments (derivatives). Derivatives are contracts whose
value is derived from one or more underlying ﬁnancial or commodity
instruments, indices or prices which are deﬁned in the contract.
The group also trades derivatives in conjunction with its risk
management activities.

All derivative activity, whether for risk management or trading, is carried

out by specialist teams that have the appropriate skills, experience and
supervision. These teams are subject to close ﬁnancial and management
control, meeting generally accepted industry practice and reﬂecting
the principles of the group of Thirty Global Derivatives Study
recommendations. Independent control functions monitor compliance
with the group’s policies. A Trading Risk Management Committee has
oversight of the quality of internal control in the group’s trading function.
The control framework includes prescribed trading limits that are
reviewed regularly by senior management, daily monitoring of risk
exposure using value-at-risk principles, marking trading exposures to
market and stress testing to assess the exposure to potentially extreme
market situations. The group’s operational, risk management and trading
activities in oil, natural gas, power and ﬁnancial markets are managed
within a single integrated function that has the responsibility for ensuring
high and consistent standards of control, making investments in the
necessary systems and supporting infrastructure and providing
professional management oversight.

In market risk management and trading, conventional exchange-

traded derivatives such as futures and options are used, as well as non-
exchange-traded instruments such as ‘over-the-counter’ swaps, options
and forward contracts.

IAS 39 ‘Financial Instruments: Recognition and Measurement’ (IAS 39)

prescribes strict criteria for hedge accounting, whether as a cash ﬂow
or fair value hedge, and requires that any derivative that does not meet
these criteria should be classiﬁed as held for trading purposes and fair
valued. BP adopted IAS 32 and IAS 39 with effect from 1 January 2005
without restating prior periods. Consequently, the group’s accounting
policy under UK GAAP has been used for 2004. The policy under UK
GAAP and the disclosures required by UK GAAP for derivative ﬁnancial
instruments are shown in Financial statements – Note 37 on page 148.
Where derivatives constitute a fair value hedge, the group’s exposure
to market risk created by the derivative is offset by the opposite exposure
arising from the asset, liability or transaction being hedged. Gains and
losses relating to derivatives designated as part of a cash ﬂow hedge are
taken to reserves and recycled through income or to the carrying value of
assets, as appropriate as the hedged item is recognized. By contrast,
where derivatives are held for trading purposes, realized and unrealized
gains and losses are recognized in the period in which they occur.

The group also has embedded derivatives classiﬁed as held for trading.

not related directly 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.

Further information about BP’s use of derivatives, their characteristics

and the IFRS accounting treatment thereof is given in Financial
statements – Note 1 and Note 36 on pages 100 and 141.

There are minor differences in the criteria for hedge accounting under

IFRS and SFAS No. 133 ‘Accounting for Derivative Instruments and
Hedging Activities’. Prior to 1 January 2005, the group did not designate
any of its derivative ﬁnancial instruments as part of hedged transactions
under SFAS 133. As a result, all changes in fair value were recognized
through earnings. See Financial statements – Note 53 on page 179 for
further information.

Foreign currency exchange rate risk
Fluctuations in 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 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 exchange risks centrally, by netting off naturally
occurring opposite exposures wherever possible, to reduce the risks,
and then dealing with any material residual foreign exchange risks. The
most signiﬁcant residual exposures are capital expenditure and UK and
European operational requirements. In addition, most of the group’s
borrowings are in US dollars or are hedged with respect to the US dollar.
At 31 December 2006, the total of foreign currency borrowings not
swapped into US dollars amounted to $957 million. The principal elements
of this are $195 million of borrowings in euros, $179 million in Australian
dollars, $114 million in Chinese renminbi, $78 million in South African
rand, $35 million in sterling, $224 million in Canadian dollars and
$76 million in Trinidad & Tobago dollars.

The following table provides information about the group’s foreign
currency derivative ﬁnancial instruments. These include foreign currency
forward exchange agreements (forwards), cylinder option contracts
(cylinders) and purchased call options that are sensitive to changes in
the sterling/US dollar and euro/US dollar exchange rates. Where foreign
currency denominated borrowings are swapped into US dollars using
forwards or cross-currency swaps such that currency risk is completely
eliminated, neither the borrowing nor the derivative is included in
the table.

For forwards, the tables present the notional amounts and weighted

average contractual exchange rates by contractual maturity dates and
exclude forwards that have offsetting positions. Only signiﬁcant forward
positions are included in the tables. The notional amounts of forwards are
translated into US dollars at the exchange rate included in the contract at
inception. The fair value represents an estimate of the gain or loss that
would be realized if the contracts were settled at the balance sheet date.

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. Post the development of an active UK gas market,
certain contracts were entered into or renegotiated using pricing formulae

Cylinders consist of purchased call option and written put option
contracts. For cylinders and purchased call options, the tables present
the notional amounts of the option contracts at 31 December and the
weighted average strike rates.

BP Annual Report and Accounts 2006

61

The fair values for the foreign exchange contracts in the table below are based on market prices of comparable instruments (forwards) and pricing
models that take into account relevant market data (options). These derivative contracts constitute a hedge; changes in the fair value or expected cash
ﬂows are offset by an opposite change in the market value or expected cash ﬂows of the asset, liability or transaction being hedged.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

2007

2008

2009

2010

2011

Total

Notional amount by expected maturity date
At 31 December 2006
Forwards

Beyond
2011

Fair value
asset/
(liability)

16

733

82

–

–

–

9

–

–

–

–

1,113

102

1,685

14

1,685

992

992

–

–

–

Receive sterling/pay US dollars

Contract amount
Weighted average contractual exchange rate

Receive sterling/pay euro

Contract amount
Weighted average contractual exchange rate

Receive euro/pay US dollars

Contract amount
Weighted average contractual exchange rate

Cylinders

Receive sterling/pay US dollars

Purchased call

Contract amount
Weighted average strike price

Sold put

Contract amount
Weighted average strike price

Receive euro/pay US dollars

Purchased call

Contract amount
Weighted average strike price

Sold put

Contract amount
Weighted average strike price

630
1.76

–

957
1.24

1,685
1.97

1,685
1.89

992
1.35

992
1.27

66

–

136

–

–

–

–

9

–

5

–

–

–

–

6

–

3

–

–

–

–

6

–

3

–

–

–

–

Weighted average contractual exchange rates are expressed as US dollars per non-US dollar currency unit.

62

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

2006

2007

2008

2009

2010

Total

Beyond
2010

Fair value
asset/
liability

Notional amount by expected maturity date
At 31 December 2005
Forwards

Receive sterling/pay US dollars

Contract amount
Weighted average contractual exchange rate

Receive sterling/pay euro

Contract amount
Weighted average contractual exchange rate

Receive euro/pay US dollars

Contract amount
Weighted average contractual exchange rate

Cylinders

Receive sterling/pay US dollars

Purchased call

Contract amount
Weighted average strike price

Sold put

Contract amount
Weighted average strike price

Receive Euro/pay US dollars

Purchased call

Contract amount
Weighted average strike price

Sold put

Contract amount
Weighted average strike price

Purchased call options

Receive sterling/pay US dollars

Contract amount
Weighted average strike price

Receive euro/pay US dollars

Contract amount
Weighted average strike price

1,749
1.78

67
£0.70

1,253
1.22

717
1.84

717
1.77

706
1.29

706
1.21

533
1.97

207
1.42

128

1

102

–

–

–

–

–

–

25

–

26

–

–

–

–

–

–

6

–

11

–

–

–

–

–

–

5

–

8

–

–

–

–

–

–

22

1,935

(66)

–

68

1

30

1,430

(13)

–

–

–

–

–

–

717

3

717

(27)

706

3

706

(23)

533

207

0

0

Weighted average contractual exchange rates are expressed as US dollars per non-US dollar currency unit.

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

and ﬂoating rate debt, the group enters into interest rate and cross-
currency swaps in which the group agrees to exchange, at speciﬁed
intervals, the difference between ﬁxed and variable rate interest amounts
calculated by reference to an agreed notional principal amount. The
proportion of ﬂoating rate debt at 31 December 2006 was 73% of total
ﬁnance debt outstanding.

BP Annual Report and Accounts 2006

63

The following table shows, by major currency, the group’s ﬁnance debt at 31 December 2006 and 2005 and the weighted average interest
rates achieved at those dates through a combination of borrowings and other derivative instruments entered into to manage interest rate
and currency exposures.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

%

years

$ million

%

$ million

$ million

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Fixed rate debt

Floating rate debt

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Weighted
average
interest
rate

Weighted
average time
for which
rate is ﬁxed

Weighted
average
interest
rate

Amount

Amount

Total

5
–
3
7

7
–
–
9

3
–
8
8

11
–
–
14

5,998
–
61
299
6,358

665
–
–
157
822

6
5
4
8

5
6
3
12

17,055
35
134
428
17,652

18,073
76
150
41
18,340

23,053
35
195
727
24,010

18,738
76
150
198
19,162

At 31 December 2006
US dollar
Sterling
Euro
Other currencies
Total loans

At 31 December 2005
US dollar
Sterling
Euro
Other currencies
Total loans

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

The group’s earnings are sensitive to changes in interest rates over the
forthcoming year as a result of the ﬂoating rate instruments included in
the group’s ﬁnance debt at 31 December 2006. These include the effect
of interest rate and currency swaps and forwards utilized to manage
interest rate risk. If the interest rates applicable to ﬂoating rate
instruments were to have increased by 1% on 1 January 2007, the
group’s 2007 earnings before taxes would decrease by approximately
$180 million. 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 2006 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 an overall
reduction in economic activity which could accompany such an increase
in interest rates.

Derivatives held for trading
In conjunction with the risk management activities discussed above, the
group also trades interest rate and foreign exchange rate derivatives and,
in addition, undertakes trading and risk management of certain speciﬁed
commodities. In order to disclose a complete picture of activities in
relation to commodity derivatives, all activity (trading and risk

management) is included in aggregate in Financial statements – Note 36
on page 141.

The group’s operational, risk management and trading activities in oil,

natural gas, power and ﬁnancial markets are managed within a single
integrated function. The group’s risk management policy requires the
management of only certain short-term exposures in respect of its equity
share of production and certain of its reﬁnery and marketing activities.
These risks are managed in combination with the group’s supply and
trading activities.

To this end, the group’s supply and trading function uses the full range

of conventional ﬁnancial and commodity derivatives available in the
related commodity markets. Natural gas swaps, options and futures are
used to convert speciﬁc sale and purchase contracts from ﬁxed prices to
market prices. Swaps are also used to manage exposures to gas price
differentials between locations. The group’s oil supply and trading
activities undertake the full range of conventional derivative ﬁnancial and
commodity instruments and physical cargoes available in the commodity
markets. 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.

64

Directors, senior management and employees

Directors and senior management

The following lists the company’s directors and senior management as at 20 February 2007.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
Name
------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
P D Sutherland

Non-Executive Chairman

Sir Ian Prosser

Non-Executive Deputy Chairman

The Lord Browne of Madingley Executive Director (Group Chief Executive)
Dr A B Hayward
Dr D C Allen
P B P Bevan
S Bott
I C Conn
V Cox
Dr B E Grote
A G Inglis
R A Malone
J A Manzoni
J H Bryan
A Burgmans
Sir William Castell
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Dr W E Massey

Executive Director (Group Chief Executive designate)
Executive Director (Group Chief of Staff)
Group General Counsel
Executive Vice President, Human Resources
Executive Director (Group Executive Ofﬁcer, Strategic Resources)
Executive Vice President, Gas, Power & Renewables
Executive Director (Chief Financial Ofﬁcer)
Executive Director (Chief Executive, Exploration and Production)
Executive Vice President (Chairman and President of BP America Inc.)
Executive Director (Chief Executive, Reﬁning and Marketing)
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director

Initially elected or appointed
Chairman since May 1997
Director since July 1995
Deputy chairman since February 1999
Director since May 1997
September 1991
February 2003
February 2003
September 1992
March 2005
July 2004
July 2004
August 2000
February 2007
July 2006
February 2003
December 1998
February 2004
July 2006
December 1998
January 2005
November 2001
July 2004
December 1998

On 12 January 2007, BP announced that Lord Browne of Madingley
would retire as group chief executive at the end of July 2007 and that
Dr A B Hayward, currently head of BP’s exploration and production
business, would succeed him at that time.

Mr M H Wilson resigned as a director on 28 February 2006 and

Mr H M P Miles retired as a director on 20 April 2006. Sir William Castell
was appointed a non-executive director on 20 July 2006 and Mr A G Inglis
was appointed an executive director on 1 February 2007. At the
company’s 2006 annual general meeting (AGM), the following directors
retired, offered themselves for re-election and were duly re-elected:
Dr D C Allen, The Lord Browne of Madingley, Mr J H Bryan,
Mr A Burgmans, Mr I C Conn, Mr E B Davis, Jr, Mr D J Flint, Dr B E
Grote, Dr A B Hayward, Dr D S Julius, Sir Tom McKillop, Mr J A Manzoni,
Dr W E Massey, Sir Ian Prosser and Mr P D Sutherland.

David Jackson (54) was appointed company secretary in 2003. A solicitor,
he is a director of BP Pension Trustees Limited, a director of Business
in the Community and a member of the Listing Authorities Advisory
Committee.

P D Sutherland, KCMG
Peter Sutherland (60) rejoined BP’s board in 1995, having been a non-
executive director from 1990 to 1993, and was appointed chairman in 1997.
He is non-executive chairman of Goldman Sachs International and a
non-executive director of Investor AB and The Royal Bank of
Scotland Group.
Chairman of the chairman’s and nomination committees

Sir Ian Prosser
Sir Ian (63) joined BP’s board in 1997 and was appointed non-executive
deputy chairman in 1999. He is the senior non-executive director. He
retired as chairman of InterContinental Hotels Group PLC, previously
Bass PLC, in 2003. He is the senior independent non-executive director
of GlaxoSmithKline plc and a non-executive director of the Sara Lee
Corporation. He was previously on the boards of The Boots Company PLC
and Lloyds TSB PLC.
Member of the chairman’s, nomination and remuneration committees and
chairman of the audit committee

The Lord Browne of Madingley, FRS, FREng
John Browne (59) joined BP in 1966 and subsequently held a variety of
exploration and production and ﬁnance posts in the US, UK and Canada.
He was appointed an executive director in 1991 and group chief executive
in 1995. He will retire as group chief executive at the end of July 2007. He
is a non-executive director of Goldman Sachs Group Inc. He was knighted
in 1998 and made a life peer in 2001.

Dr A B Hayward
Tony Hayward (49) 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 1 February 2007, becoming
an executive director in 2003. He has been appointed to succeed Lord
Browne as group chief executive following Lord Browne’s retirement
in July. Dr Hayward is a non-executive director of Corus Group plc.

Dr D C Allen
David Allen (52) joined BP in 1978 and subsequently undertook a number
of corporate and exploration and production roles in London and New
York. He moved to BP’s corporate planning function in 1986, becoming
group vice president in 1999. He was appointed executive vice president
and group chief of staff in 2000 and an executive director of BP in 2003.
He is a director of BP Pension Trustees Limited.

P B P Bevan
Peter Bevan (62) joined BP in 1970 after qualifying as a solicitor with a
City of London ﬁrm. He worked initially in the law department of BP’s
chemicals business. He became group general counsel in 1992 following
roles as manager of the legal function of BP Exploration, assistant
company secretary and deputy group legal adviser. He was appointed
an executive vice president of BP p.l.c. in 1998.

S Bott
Sally Bott (57) joined BP in March 2005 as an executive vice president
responsible for global human resources management. She joined Citibank
in 1970 and, following a variety of roles, was appointed a vice president in

BP Annual Report and Accounts 2006

65

human resources in 1979 and subsequently held a series of positions as a
human resources director to sectors of Citibank. In 1994, she joined BZW,
an investment bank, as head of human resources and in 1996 became
group human resources director of Barclays Group. From 2000 to early
2005, she was managing director and head of global human resources at
insurance brokers Marsh Inc.

I C Conn
Iain Conn (44) 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 is a non-executive director of Rolls-Royce Group plc.

V Cox
Vivienne Cox (47) joined BP in 1981. Following a series of commercial
roles, she was appointed chief executive of Air BP in 1998. From 1999
until 2001, she was group vice president of BP Oil, responsible for
business-to-business marketing and oil supply and trading. From 2001 to
2004, she was group vice president for integrated supply and trading. In
2004, she was appointed an executive vice president, responsible for gas,
power and renewables in addition to the supply and trading businesses
and, in late 2005, also became responsible for BP Alternative Energy.
She is a non-executive director of Rio Tinto plc.

Dr B E Grote
Byron Grote (58) 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 (47) 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 on 1 February 2007.

R A Malone
Bob Malone (54) was appointed chairman and president of BP America
Inc. and an executive vice president in mid-2006. He started his career
in 1974 at Kennecott Copper Corporation, holding various roles in
environmental engineering, operations and safety. From 1981 until 1988,
he was director of health, safety and environment for Kennecott and later
for BP America. In 1993, he became president of BP Pipelines Alaska and,
in 1996, president and chief operating ofﬁcer of Alyeska Pipeline Service
Company. In 2000, he became western regional president for BP America
and from 2002 until 2006 he was chief executive of BP Shipping Limited.

J A Manzoni
John Manzoni (47) joined BP in 1983. He became group vice president
for European marketing in 1999 and BP regional president for the eastern
US in 2000. In 2001, he became an executive vice president and chief
executive for gas and power. He was appointed chief executive of
reﬁning and marketing in 2002 and an executive director of BP in 2003.
He is a non-executive director of SABMiller plc.

J H Bryan
John Bryan (70) joined BP’s board in 1998, having previously been a director
of Amoco. He serves on the boards of General Motors Corporation and
Goldman Sachs Group Inc. He retired as the chairman of Sara Lee Corporation
in 2001. He is chairman of Millennium Park Inc. in Chicago.
Member of the chairman’s, audit and remuneration committees

66

A Burgmans
Antony Burgmans (60) joined BP’s board in 2004. He was appointed to
the board of Unilever in 1991. In 1999, he became chairman of Unilever
NV and vice chairman of Unilever PLC. He was appointed chairman
of Unilever NV and Unilever PLC in 2005. He is also a member of the
supervisory board of Akzo Nobel NV.
Member of the chairman’s and safety, ethics and environment assurance
committees

Sir William Castell, LVO
Sir William (59) joined BP’s board in July 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 and is a trustee of London’s Natural
History Museum.
Member of the chairman’s, audit and safety, ethics and environment
assurance committees

E B Davis, Jr
Erroll B Davis, Jr (62) joined BP’s board in 1998, having previously been
a director of Amoco. He was chairman and chief executive ofﬁcer of
Alliant Energy, relinquishing this dual appointment in 2005. He continued
as chairman of Alliant Energy until February 2006, leaving to become
chancellor of the University System of Georgia. He is a non-executive
director of PPG Industries, Union Paciﬁc Corporation and the US
Olympic Committee.
Member of the chairman’s, audit and remuneration committees

D J Flint, CBE
Douglas Flint (51) joined BP’s board in 2005. He trained as a chartered
accountant and became a partner at KPMG in 1988. In 1995, he was
appointed group ﬁnance director of HSBC Holdings plc. He was chairman
of the Financial Reporting Council’s review of the Turnbull Guidance on
Internal Control. Between 2001 and 2004, he served on the Accounting
Standards Board and the Standards Advisory Council of the International
Accounting Standards Board.
Member of the chairman’s and audit committees

Dr D S Julius, CBE
DeAnne Julius (57) 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 an
independent member of the Monetary Policy Committee of the Bank of
England. She is chairman of the Royal Institute of International Affairs and
a non-executive director of Lloyds TSB Group PLC, Roche Holdings SA
and Serco Group plc.
Member of the chairman’s and nomination committees and chairman
of the remuneration committee

Sir Tom McKillop
Sir Tom (63) joined BP’s board in 2004. Sir Tom was chief executive of
AstraZeneca PLC from the merger of Astra AB and Zeneca Group PLC
in 1999 until December 2005. He was a non-executive director of Lloyds
TSB Group PLC until 2004 and is chairman of The Royal Bank of
Scotland Group.
Member of the chairman’s, remuneration and safety, ethics and
environment assurance committees

Dr W E Massey
Walter Massey (68) joined BP’s board in 1998, having previously been
a director of Amoco. He is president of Morehouse College, a non-
executive director of Bank of America and McDonald’s Corporation
and a member of President Bush’s Council of Advisors on Science
and Technology.
Member of the chairman’s and nomination committees and chairman
of the safety, ethics and environment assurance committee

Employees

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

UK

Rest of
Europe

3,500
11,300
300
1,800
16,900

3,100
11,300
200
1,900
16,500

2,900
10,400
200
4,000
17,500

700
18,600
700
200
20,200

700
19,700
700
200
21,300

600
19,500
800
5,000
25,900

USA

6,200
23,900
1,800
1,800
33,700

5,600
25,200
1,500
2,100
34,400

5,000
26,500
1,400
4,000
36,900

Rest of
World

8,600
15,700
1,700
200
26,200

7,600
14,600
1,700
100
24,000

7,100
13,400
1,600
500
22,600

Total

19,000
69,500
4,500
4,000
97,000

17,000
70,800
4,100
4,300
96,200

15,600
69,800
4,000
13,500
102,900

Number of employees at 31 December
2006
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

2005
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

2004
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Employee numbers decreased in 2005 compared with 2004, primarily due to the sale of Innovene. The company seeks to maintain constructive
relationships with labour unions.

BP Annual Report and Accounts 2006

67

Directors’ remuneration report

This is the board’s report to shareholders on directors’ remuneration.
It covers both executive directors and non-executive directors. The ﬁrst
and third parts were prepared by the remuneration committee. The
second part was prepared by the company secretary on behalf of the
board. The report has been approved by the board and signed on its
behalf by the company secretary. The report is subject to the approval
of shareholders at the annual general meeting (AGM).

Contents

Part 1 Executive directors’ remuneration

68

Letter to shareholders
2006 remuneration
Remuneration policy

Salary
Annual bonus
Long-term incentives
Pensions

Service contracts

Part 2 Non-executive directors

Part 3 Additional statutory and other disclosures

Historical TSR performance graph
Pensions table
Share element of EDIP and LTPPs table
Share options table

72

73

Part 1 – Executive directors’ remuneration

Dear Shareholder
Executive directors’ remuneration for 2006 reﬂects a clear set of principles, set out in the pages that follow. At their heart is the importance of matching
reward to performance, in a way that both reﬂects shareholders’ interests and provides fair and competitive compensation to the executives.

As described elsewhere, 2006 was a year of strong ﬁnancial performance for the group. A number of strategic and operational milestones were
attained. However, the year also brought serious challenges and in key operational and safety areas company performance fell short of expectations.
The remuneration committee has carefully evaluated performance against the quantitative measures set at the beginning of the year. We also
made a qualitative assessment of the effect on the company and its reputation of adverse events and developments in the year. The executive team
responded to these challenges with determination and a sincere commitment to implement the lessons learned. However, taking a balanced judgement
on the year, the remuneration committee halved the bonuses that would have resulted directly from their quantitative assessment. This, and all other
remuneration received, is shown on the following page.

We have made some changes to the style and format of the remuneration report this year in order to make it easier to read and understand. Our aim

has been to set out clearly the principles and policy on which we base executive directors’ remuneration, as well as the ﬁgures for 2006. In addition,
full details of arrangements agreed for Lord Browne’s retirement later in 2007 and information on recent changes in remuneration for Dr Hayward and
Mr Inglis are included in the relevant sections.

Dr D S Julius
Chairman, Remuneration Committee
23 February 2007

68

2006 remuneration
All remuneration paid to executive directors in 2006 is summarized in the table below. The annual bonuses are shown in the year they were earned.
The remuneration committee reviewed base salaries in 2006 and awarded increases between 5% and 10% of base salary from 1 July for each

director. These increases are reﬂected in the numbers below and their current base salary is shown on page 71.

All executive directors are part of a ﬁnal salary pension scheme, the details of which are set out later in this report. Accrued annual pension
earned as of 31 December 2006 is £1,050,000 for Lord Browne, £228,000 for Dr Allen, £170,000 for Mr Conn, $675,000 for Dr Grote, £239,000
for Dr Hayward and £188,000 for Mr Manzoni. Service and transfer value detail is shown on page 74.

Summary of remuneration of executive directors in 2006a

------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------

Annual remuneration

------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------

Long-term remuneration
Share element of EDIP/LTPPsb

2003-2005 plan

2004-2006 plan

2006-2008 plan

(vested in
Feb 2006)

(vested in
Feb 2007)

(awarded in
Feb 2006)

------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------
Potential
maximum
performance
sharesf

Non-cash beneﬁts
and other emoluments
(thousand)
2005

Annual
performance bonus
(thousand)

Valuee
(thousand)

Valuec
(thousand)

Actual
shares
vestedd

Total
(thousand)

Salary
(thousand)

Actual
shares
vested

2005

2006

2005

2006

2006

2005

2006

------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------
1,761,249
Lord Browne

380,668

474,384

£3,067

£1,451

£1,531

£3,291

£2,044

£1,750

£2,526

£900

£90

£95

Dr A B Hayward

Dr D C Allen

I C Conn

Dr B E Grote

J A Manzoni

£431

£431

£421

$923

£431

£463

£463

£463

$973

£463

£460

£480

£450

$1,100

£440

£250

£250

£250

$525

£250

£14

£12

£43

$0

£47

£20

£13

£42

$1

£45

£905

£923

£914

£733

£726

£755

$2,023

$1,499

£918

£758

147,783

147,783

68,250

175,229

147,783

£955

£955

£441

$1,979

£955

112,941

112,941

54,600

127,601

112,941

£606

£606

£293

$1,338

£606

383,200

383,200

383,200

470,432

383,200

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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 Long Term Performance Plans.
c Based on market price on vesting date (£6.465 per share/$67.76 per ADS).
d Gross award of shares based on a performance assessment by the remuneration committee and on the other terms of the plan. Sufficient shares are sold to pay
for tax applicable. Remaining shares are held in trust for current directors until 2010, when they are released to the individual.
e Based on market price on vesting date (£5.37 per share/$62.91 per ADS).
f Maximum potential shares that could vest at the end of the three-year period depending on performance.

Annual bonus result
The 2006 annual bonus was based on performance relative to measures
and targets set at the beginning of the year, as well as other factors
the remuneration committee determined were relevant. Financial and
operational metrics from the annual plan carried a 50% weighting and
focused on earnings before interest, taxes, depreciation and amortization
(EBITDA), return on average capital employed (ROACE) and safety,
environment and production targets. Strategic milestones, including those
relating to technology, operations and business development, accounted
for 30%. Individual performance, including both leadership objectives and
living the values of the group, accounted for 20%.

On the ﬁnancial side, underlying EBITDA was marginally below target.
There were negative effects from US operating issues and positive effects
from improvements in operating performance. ROACE was marginally
above target. Cash costs and capital expenditure came in around target
levels. Planned divestments of non-strategic assets achieved premium
prices. Targets were met for personal safety, greenhouse gas emissions,
oil and gas discovered volumes and proved reserves. Average production
rate was below target.

With respect to milestones, seven of nine major projects were

completed as planned. However, the Thunder Horse development was
delayed. Good progress was achieved to deﬁne and sanction a further
18 major projects. The alternative energy business exceeded its
objectives. Good progress was made in developing and implementing
a major six-point plan for improving safety and operational integrity.

In terms of individual performance, in a period of signiﬁcant challenges,

the executive directors demonstrated commitment, determination and
unity to address issues and improve performance.

While the quantitative assessment generated a near-target score,

the remuneration committee also considered broader qualitative
factors. These included the ﬁndings of internal and external reports
on operational and safety issues in the US business. On balance, the
committee judged that bonus levels should be reduced by 50% from the
level they would otherwise have been. The resulting annual bonuses are
set out in the table above.

2004-2006 share element result
For the 2004-2006 share element of the Executive Directors’ Incentive
Plan (EDIP), BP’s performance was assessed in terms of shareholder
return against the market (SHRAM), ROACE and earnings per share (EPS)
growth. BP’s three-year SHRAM was measured against the companies
in the FTSE All World Oil & Gas Index. Companies within the index are
weighted according to their market capitalization at the beginning of the
three-year period in order to give greatest emphasis to oil majors. BP’s
ROACE and EPS growth were measured against ExxonMobil, Shell, Total
and Chevron. Based on a performance assessment of 60 points out of
200 (0 for SHRAM, 50 for ROACE and 10 for EPS growth), the committee
made awards of shares to executive directors as shown in the 2004-2006
columns in the table above.

BP Annual Report and Accounts 2006

69

Remuneration policy
Our remuneration policy for executive directors aims to ensure there
is a clear link between the company’s purpose, the business plans and
executive reward, with pay varying with performance. In order to achieve
this, the policy is based on these key principles:
– The remuneration structure will support BP’s aim to maximize long-term

shareholder value.

– The structure will reﬂect a fair system of reward for all the participants.
– The remuneration committee will determine the overall amount of each
component of remuneration, taking into account the success of BP and
the competitive environment.

– The majority of executive remuneration will be linked to the

achievement of demanding performance targets, independently
set to support the creation of long-term shareholder value.

– There will be a quantitative and qualitative assessment of performance,

with the remuneration committee making an informed judgement
within a framework approved by shareholders.

– Pay and employment conditions elsewhere in the group will be taken

into account, especially in setting annual salary increases.

– Executives will develop a signiﬁcant personal shareholding in order to

align their interests with those of shareholders.

– The remuneration policy for executive directors will be reviewed

regularly, independently of executive management, and will set the
tone for the remuneration of other senior executives.

– The remuneration committee will actively seek to understand

shareholder preferences.

– Remuneration policy and practice will be as transparent as possible.

Executive directors’ total remuneration consists of salary, annual bonus,

long-term incentives, pensions and other beneﬁts. The remuneration
committee reviews this structure regularly to ensure it is achieving its
aims. In 2006, well over three-quarters of executive directors’ total
potential remuneration was performance-related, in line with the target.
The same will be true for potential remuneration in 2007.

Salary
The remuneration committee reviews salaries annually, taking into
account other large Europe-based global companies and companies in the
US oil and gas sector. These groups are each deﬁned and analysed by the
committee’s independent remuneration advisers. The committee makes a
judgement on salary levels based on its assessment of market conditions
and the external advice.

Annual bonus
All executive directors are eligible to take part in an annual performance-
based bonus scheme. The remuneration committee sets bonus targets
and levels of eligibility each year.

The target level for 2007 is 120% of base salary. In normal

circumstances, the maximum payment for substantially exceeding
performance targets will continue to be 150% of base salary.

Annual bonus awards for 2007 will be based on a mix of demanding
ﬁnancial targets, based on the annual plan and the leadership objectives
set at the beginning of the year. The weightings on annual bonus
targets are:
– 50% Financial metrics from the annual plan, principally EBITDA,

cash costs and capital expenditure.

– 30% Non-ﬁnancial measures focusing on health, safety and the

environment; growth; and reputation.

– 20% Individual performance against leadership objectives and against
living the values of the group (incorporating BP’s code of conduct).

The remuneration committee will also review carefully the underlying
performance of the group in the light of the ﬁve-year business plan and
will look at competitors’ results, analysts’ reports and the views of the
chairmen of other BP board committees when assessing results.

In exceptional circumstances, the remuneration committee can decide
to award bonuses moderately above the maximum level. The committee
can also decide to reduce bonuses where this is warranted, and in
exceptional circumstances bonuses could be reduced to zero. We
have a duty to shareholders to use our discretion in a reasonable
and informed manner, acting in the best interests of the company,

70

and also to be accountable and transparent in our decisions. Any
signiﬁcant exercise of discretion will be explained in the subsequent
directors’ remuneration report.

Group chief executive
As for previous years, the target level for 2007 for Lord Browne is 130%
of base salary, with a maximum payment for substantially exceeding
performance targets of 165% of base salary. Lord Browne will retire on
31 July 2007. His annual bonus award for 2007 will be pro-rated to reﬂect
his service during the ﬁnancial year up to his retirement in July.

Long-term incentives
Each executive director participates in the EDIP. It has three elements:
shares, share options and cash. The remuneration committee did not use
either share option or cash elements in 2006 and would only do so in
2007 in exceptional circumstances. This section describes the share
element. We intend that executive directors will continue to receive
performance shares under the EDIP, barring unforeseen circumstances,
until it expires or is renewed in 2010.

Policy
The remuneration committee can award shares to executive directors that
will only vest to the extent that demanding performance conditions are
satisﬁed at the end of a three-year period. The maximum number of these
performance shares that can be awarded to an executive director in any
year is at the discretion of the remuneration committee, but will not
normally exceed 5.5 times base salary (7.5 times base salary in the case
of the group chief executive).

In exceptional circumstances, the committee also has an overriding
discretion to reduce the number of shares that vest or to decide that no
shares vest.

The compulsory retention period will also be decided by the committee

and will not normally be less than three years. Together with the
performance period, this gives executive directors a six-year incentive
structure, as shown in the timeline below, which is designed to ensure
their interests are aligned with those of shareholders.

--------------- -------------- -------------- --------------- -------------- -------------- -------------- --------------- -------------- -------------- ---

TIMELINE FOR 2007-2009 EDIP SHARE ELEMENT
--------------------------------------------------------------------------------------------------------------------------------------

Performance period

Retention period

Award

Vesting

Release

2007

2008

2009

2010

2011

2012

2013

--------------- -------------- -------------- --------------- -------------- -------------- -------------- --------------- -------------- -------------- ---

Where shares vest under awards made in 2007 and future years, the

executive director will receive additional shares representing the value
of the reinvested dividends.

The committee’s policy continues to be that each executive director
should hold shares equivalent in value to ﬁve times his or her base salary
within ﬁve years of appointment as an executive director. This policy is
reﬂected in the terms of the EDIP, as shares awarded will only be
released at the end of the three-year retention period, described below,
if these minimum shareholding guidelines are met.

Performance conditions
For performance share awards in 2007, the performance conditions will
continue to relate to BP’s total shareholder return (TSR) compared with
other oil majors – ExxonMobil, Shell, Total and Chevron – over a three-
year period. We have the discretion to alter this comparison group if
circumstances change, for example, if there are signiﬁcant consolidations
in the industry.

We consider this relative TSR to be the most appropriate measure
of performance for the purpose of long-term incentives for executive
directors. It best reﬂects the creation of shareholder value while
minimizing the impact of sector-speciﬁc effects 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 months before the beginning and end of the performance period.
They are measured in US dollars. At the end of the performance period,
the companies’ TSRs will be ranked. Executive directors’ performance
shares will vest at 100%, 70% and 35% if BP is ranked ﬁrst, second
or third respectively; none will vest if BP is in fourth or ﬁfth place.

As the comparator group is small and as the oil majors’ underlying
businesses are broadly similar, a simple ranking could sometimes distort
BP’s underlying business performance relative to the comparators.

The committee is therefore able to exercise discretion in a reasonable
and informed manner to adjust the vesting level upwards or downwards
to reﬂect better the underlying health of BP’s business. This would be
judged by reference to a range of measures including ROACE, growth
in EPS, reserves replacement and cash ﬂow. The need to exercise
discretion is most likely to arise when the TSR of some companies is
clustered, so that a relatively small difference in TSR performance would
produce a major difference in vesting levels.

The remuneration committee will explain any adjustments in the

next directors’ remuneration report following the vesting, in line with its
commitment to transparency.

Group chief executive
As noted above, as group chief executive, Lord Browne is eligible for
performance share awards of up to 7.5 times his base salary. While the
largest part of this is related to TSR, the committee has decided that
up to two times base salary should be based on long-term leadership
measures. These focus on sustaining BP’s ﬁnancial, strategic and
organizational health. They include, among other measures, maintenance
of BP’s performance culture and the continued development of BP’s
business strategy, executive talent and internal organization. As with
the TSR element, this element will be assessed over a three-year
performance period.

The remuneration committee has agreed that Lord Browne will be
granted a share award under the 2007-2009 plan on the above basis.
The performance targets for this award (and those granted to him on
the same basis in 2005 and 2006) will be assessed by the remuneration
committee at the end of the three-year performance period that applies
to each award. The actual number of shares received will depend on the
extent to which relevant performance conditions are satisﬁed.

Pensions
Executive directors are eligible to participate in the appropriate pension
schemes applying in their home countries. Additional details are given
on page 74.

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 have recently been amended
such that the normal retirement age is 65. Scheme members can 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.

In April 2006, the UK government made important changes to the

operation and taxation of pensions. The remuneration committee decided
to deliver pension beneﬁts in excess of the new lifetime allowance of
£1.5 million set by the legislation via an unapproved, unfunded pension
arrangement paid by the company direct.

US directors
Dr Grote participates in the US BP Retirement Accumulation Plan (US
plan), which features a cash balance formula. The US plan took its current
form on 1 July 2000. Pension beneﬁts are provided through a combination
of tax-qualiﬁed and non-qualiﬁed beneﬁt restoration plans, consistent with
US tax regulations as applicable.

The Supplemental Executive Retirement Beneﬁt (supplemental plan) is

a non-qualiﬁed top-up arrangement that became effective on 1 January
2002 for US employees above a speciﬁed salary level. The beneﬁt formula
is 1.3% of ﬁnal average earnings, which comprise base salary and bonus
in accordance with standard US practice (and as speciﬁed under the
qualiﬁed arrangement), multiplied by years of service. There is an
offset for beneﬁts payable under all other BP qualiﬁed and non-qualiﬁed
pension arrangements. This beneﬁt is unfunded and therefore paid from
corporate assets.

Dr Grote is eligible to participate under the supplemental plan. His
pension accrual for 2006, shown in the table on page 74, includes the
total amount that could become payable under all plans.

Other beneﬁts
Executive directors are eligible to participate in regular employee beneﬁt
plans and in all-employee share saving schemes and savings plans
applying in their home countries. Beneﬁts in kind are not pensionable.
Expatriates may receive a resettlement allowance for a limited period.

Service contracts

Directora

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

Contract date

Salary as at 31 Dec 2006

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----
Lord Browne

11 Nov 1993

£1,575,000

Dr A B Hayward

Dr D C Allen

I C Conn

Dr B E Grote

J A Manzoni

29 Jan 2003

29 Jan 2003

22 Jul 2004

7 Aug 2000

29 Jan 2003

£485,000

£485,000

£485,000

$1,000,000

£485,000

a Subsequent to 31 December 2006, Dr Hayward’s salary was increased to £750,000
and Mr Inglis’ salary, on appointment to the board, to £425,000.

When Lord Browne retires on 31 July 2007, he will become entitled to a
payment equal to the aggregate of 12 months’ base salary at that date, his
target annual bonus level (130% of base salary) and £90,000 in respect of
fringe beneﬁts. In accordance with the committee’s policy, the payment will
be made in four quarterly instalments (the ﬁrst payable in November 2007)
and each instalment will be reduced by an amount equal to any of Lord
Browne’s replacement earnings for the quarter in question, to the extent
that such earnings exceed one-third of the relevant quarterly instalment.
Service contracts are expressed to expire at a normal retirement age
of 60 (subject to age discrimination). The contracts have a notice period
of one year.

The service contracts of Dr Allen, Mr Conn, Dr Hayward and
Mr Manzoni 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 terminated on the expiry of the remainder of the notice period.

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 had
an unexpired term of one year on 31 December 2006. The secondment
can be terminated by one month’s notice by either party and terminates
automatically on the termination of Dr Grote’s service contract.

There are no other provisions for compensation payable on early

termination of the above contracts. In the event of the early termination
of any of the contracts by the company, other than for cause (or under a
speciﬁc termination payment provision), the relevant director’s then-current
salary and beneﬁts would be taken into account in calculating any liability of
the company.

Since January 2003, new service contracts have included 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.

BP Annual Report and Accounts 2006

71

Remuneration of non-executive directors in 2006a

------------------------------------------------------------- -------------------------------------------------------------
£ thousand
------------------------------------------------------------- -------------------------------------------------------------
Current directors
2005
------------------------------------------------------------- -------------------------------------------------------------
110
J H Bryan

110

2006

A Burgmans
Sir William Castellb
E B Davis, Jr

D J Flint

Dr D S Julius

Sir Tom McKillop

Dr W E Massey

Sir Ian Prosser

P D Sutherland

85

38.5

100

100

105

85

130

130

500

90

n/a

110

90

107

90

130

135

500

Directors leaving the board in 2006
------------------------------------------------------------- -------------------------------------------------------------
H M P Milesc d
90
M H Wilsone

22.5

105

30

a This information has been subject to audit.
b Appointed on 20 July 2006.
c Also received a superannuation gratuity of £46,000.
d Also received £37,500 for serving as a director and non-executive chairman of BP
Pension Trustees Limited.
e Also received a superannuation gratuity of £21,000.

Based on the current fee structure, the table above shows the 2006

remuneration of each non-executive director.

Non-executive directors have letters of appointment that 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.

Non-executive directors of Amoco Corporation
Non-executive directors who were formerly non-executive directors of
Amoco Corporation have residual entitlements under the Amoco Non-
Employee Directors’ Restricted Stock Plan. Directors were allocated
restricted stock in remuneration for their service on the board of Amoco
Corporation prior to its merger with BP in 1998. On merger, interests in
Amoco shares in the plan were converted into interests in BP ADSs. The
restricted stock will vest on the retirement of the non-executive director
at the age of 70 (or earlier at the discretion of the board). Since the
merger, no further entitlements have accrued to any director under
the plan. The residual interests, as interests in a long-term incentive
scheme, are set out in the table below, in accordance with the Directors’
Remuneration Report Regulations 2002.

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----

Interest in BP ADSs
at 1 Jan 2006 and
31 Dec 2006a

Date on
which director
reaches age 70b

--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----
J H Bryan

5 Oct 2006

5,546

E B Davis, Jr

Dr W E Massey

4,490

3,346

5 Aug 2014

5 Apr 2008

Director leaving the board in 2006
--------- -------- -------- --------- -------- -------- --------- -------- ------ -- -------- --------- -------- -------- --------- -------- -- ------ --------- ----
M H Wilsonc

4 Nov 2007

3,170

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.
c Mr Wilson resigned from the board on 28 February 2006. Mr Wilson had received
awards of Amoco shares under the plan between 1 November 1993 and 28 April
1998 prior to the merger. These interests had been converted into BP ADSs at the
time of the merger. In accordance with the terms of the plan, the board exercised its
discretion over this award on 11 May 2006 and the shares vested on that date
(when the BP ADS market price was $76.07) without payment by him.

Part 2 – Non-executive directors’ remuneration

Policy
The board sets the level of remuneration for all non-executive directors
within the limit approved from time to time by shareholders. The
remuneration of the chairman is set by the board rather than the
remuneration committee, in line with BP’s governance policies, as we
believe the performance of the chairman is a matter for the board as a
whole rather than any one committee. The board’s policy is that non-
executive remuneration should be consistent with recognized
best-practice standards. Non-executive directors are encouraged to
establish a holding in BP shares broadly related to one year’s base fee.

Annual fee structure
Non-executive directors’ remuneration consists of the following elements:
– Cash fees, paid monthly, with increments for positions of additional

responsibility, reﬂecting workload and potential liability.

– A ﬁxed allowance, currently £5,000, for transatlantic or equivalent

inter-continental travel to attend a board or board committee meeting
(excluding the chairman).

– Reasonable travel and related business expenses.

No share or share option awards are made to any non-executive

director in respect of service on the board.

The fees were reviewed in 2005 by an ad hoc board committee and
were increased with effect from 1 January 2005 to reﬂect the change
in workload and global market rates for independent or non-executive
directors since the previous review in 2002. There was no increase
in 2006.

Current fee structure
----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

£ thousand

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Chairmana
Deputy chairmanb
Board member

Committee chairmanship fee
Transatlantic attendance allowancec

500

100

75

20

5

a The chairman is not eligible for committee chairmanship fees or transatlantic
attendance allowance but has the use of a fully maintained office for company
business, a chauffeured car and security advice.
b The deputy chairman receives a £25,000 increment on top of the standard board
fee. In addition, he is eligible for committee chairmanship fees and the transatlantic
attendance allowance. The deputy chairman is currently chairman of the audit
committee.
c This allowance is payable to non-executive directors undertaking transatlantic or
equivalent intercontinental travel for the purpose of attending a board meeting or
board committee meeting.

Superannuation gratuities
In accordance with the company’s long-standing practice, non-executive
directors who retired from the board after at least six years’ service are, at
the time of their retirement, eligible for consideration for a superannuation
gratuity. The board is authorized to make such payments under the
company’s Articles of Association. The amount of the payment is
determined at the board’s discretion (having regard to the director’s
period of service as a director and other relevant factors).

In 2002, the board revised its policy with respect to superannuation
gratuities so that: (i) non-executive directors appointed to the board after
1 July 2002 would not be eligible for consideration for such a payment;
and (ii) while non-executive directors in service at 1 July 2002 would
remain eligible for consideration for a payment, service after that date
would not be taken into account by the board in considering the amount
of any such payment.

The board made superannuation gratuity payments during the year

to the following former directors: Mr Miles £46,000 (who retired in
April 2006) and Mr Wilson £21,000 (who resigned from the board in
February 2006). These payments were in line with the policy
arrangements agreed in 2002 (outlined above).

72

Part 3 – Additional statutory
and other disclosures

Remuneration committee
All the members of the committee are independent non-executive
directors. Throughout this year, Dr Julius (chairman), Mr Bryan, Mr Davis,
Sir Tom McKillop and Sir Ian Prosser were members. Lord Browne was
consulted on matters relating to the other executive directors who report
to him and on matters relating to the performance of the company;
he was not present when matters affecting his own remuneration
were discussed.

Tasks
The remuneration committee’s tasks are:
– To determine, on behalf of the board, the terms of engagement and

remuneration of the group chief executive and the executive directors
and to report on these to the shareholders.

– To determine, on behalf of the board, matters of policy over which

the company has authority regarding the establishment or operation
of the company’s pension scheme of which the executive directors
are members.

– To nominate, on behalf of the board, any trustees (or directors of

corporate trustees) of the scheme.

– To monitor the policies being applied by the group chief executive in
remunerating senior executives who are not executive directors.

Constitution and operation
Each member of the remuneration committee (named on page 80) is
subject to annual re-election as a director of the company. The board
considers all committee members to be independent (see page 77).
They have no personal ﬁnancial interest, other than as shareholders, in the
committee’s decisions.

The committee met ﬁve times in the period under review. There was
a full attendance record except for Mr Davis, who was unable to attend
one meeting. Mr Sutherland, as chairman of the board, attended all the
committee meetings.

The committee is accountable to shareholders through its annual

report on executive directors’ remuneration. It will consider the outcome
of the vote at the AGM on the directors’ remuneration report and take
into account the views of shareholders in its future decisions. The
committee values its dialogue with major shareholders on remuneration
matters.

Advice
Advice is provided to the committee by the company secretary’s ofﬁce,
which is independent of executive management and reports to the
chairman of the board. Mr Aronson, an independent consultant, is the
committee’s secretary and special adviser. Advice was also received
from Mr Jackson, the company secretary.

The committee also appoints external advisers to provide specialist

advice and services on particular remuneration matters. The
independence of the advice is subject to annual review.

In 2006, the committee continued to engage Towers Perrin as its
principal external adviser. Towers Perrin also provided limited ad hoc
remuneration and beneﬁts advice to parts of the group, principally
changes in employee share plans and some market information
on pay structures. The committee continued to engage Kepler Associates
to advise on performance measurement. Kepler Associates also
provided performance data and limited ad hoc advice on performance
measurement to the group.

Freshﬁelds Bruckhaus Derringer 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 69,
to ensure they met an independent, objective standard. They also
provided audit, audit-related and taxation services for the group.

Historical TSR performancea
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 and to
the FTSE All World Oil & Gas Index. BP is a constituent of both indices,
which are the most relevant broad equity market indices for this purpose.

FTSE All World Oil & Gas Index

a This information has been subject to audit.

Past directors
Until 30 September 2006, Mr Olver acted as a consultant to BP in
relation to its activities in Russia and served as a BP-nominated director
of TNK-BP Limited, a joint venture company owned 50% by BP.
Under the consultancy agreement, he received £225,000 in fees in
2006 as well as reimbursement of costs and support for his role. He
was also entitled to retain fees paid to him by TNK-BP up to a maximum
of $120,000 a year for his role as a director, deputy chairman and
chairman of the audit committee of TNK-BP Limited.

Mr Miles (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. This position is for a term of three years and he receives
£150,000 per annum.

BP Annual Report and Accounts 2006

73

Pensionsa

thousand

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Additional pension
earned during the
year ended
31 Dec 2006b

Amount of B-A less
contributions made by
the director in 2006

Transfer value of
accrued beneﬁtc
at 31 Dec 2005 (A)

Transfer value of
accrued beneﬁtc
at 31 Dec 2006 (B)

Accrued pension
entitlement
at 31 Dec 2006

Service at
31 Dec 2006

40 years

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Lord Browne (UK)
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Dr A B Hayward (UK)
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Dr D C Allen (UK)
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
I C Conn (UK)
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Dr B E Grote (US)
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
J A Manzoni (UK)

28 years

21 years

25 years

27 years

23 years

£19,979

£21,700

£1,721

£3,408

£4,006

£2,510

$6,681

£2,518

£1,050

£4,017

£3,433

£2,124

$7,591

£2,961

£573

£386

$910

£609

£443

£228

£170

$105

£239

$675

£188

£28

£23

£59

£31

£24

a This information has been subject to audit.
b Additional pension earned during the year includes an inflation increase of 2.2% for UK directors and 3.3% for US directors.
c Transfer values have been calculated in accordance with version 8.1 of guidance note GN11 issued by the actuarial profession.

Group chief executive
As stated in previous years’ reports, Lord Browne is eligible for consideration for an ex-gratia lump sum superannuation payment equivalent to one
year’s base salary. This is in line with the company’s past practice for directors retiring on or after age 55 having accrued at least 30 years’ service. The
remuneration committee has approved the payment of this sum to Lord Browne immediately following his retirement. This payment will be in addition
to his pension entitlements under the scheme described above. No other executive director is eligible for consideration for an ex-gratia payment on
retirement because in 1996 the remuneration committee decided that appointees to the board after that time should cease to be eligible.

Share element of EDIP and LTPPsa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Share element/LTPP interests
Potential maximum performance sharesb

Interests vested in 2006

Performance
period

Date of
award of
performance
shares

Market price
of each share
at date of award
of performance
shares
£

At 1 Jan
2006

Awarded
2006

At 31 Dec
2006

Number of
ordinary
shares
vestedc

Market price
of each share
at vesting
date
£

Vesting
date

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Lord Browne

13 Feb 2006

17 Feb 2003

2003-2005

1,265,024

474,384

6.47

3.96

–

–

2004-2006

25 Feb 2004

2005-2007

28 April 2005

2006-2008

16 Feb 2006

4.25

5.33

6.54

1,268,894

2,006,767

–

–

–

1,761,249

1,268,894

2,006,767

1,761,249

380,668

15 Feb 2007

–

–

–

–

5.37

–

–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Dr A B Hayward

13 Feb 2006

17 Feb 2003

2003-2005

147,783

394,088

6.47

3.96

–

–

2004-2006

25 Feb 2004

2005-2007

28 Apr 2005

2006-2008

16 Feb 2006

4.25

5.33

6.54

376,470

436,623

–

–

–

383,200

376,470

436,623

383,200

112,941

15 Feb 2007

–

–

–

–

5.37

–

–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Dr D C Allen

13 Feb 2006

17 Feb 2003

2003-2005

394,088

147,783

6.47

3.96

–

–

2004-2006

25 Feb 2004

2005-2007

28 Apr 2005

2006-2008

16 Feb 2006

4.25

5.33

6.54

376,470

436,623

–

–

–

383,200

376,470

436,623

383,200

112,941

15 Feb 2007

–

–

–

–

5.37

–

–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
I C Conn

13 Feb 2006

17 Feb 2003

2003-2005

182,000

68,250

6.47

3.96

–

–

2004-2006

25 Feb 2004

2005-2007

28 Apr 2005

2006-2008

16 Feb 2006

4.25

5.33

6.54

182,000

415,832

–

–

–

383,200

182,000

415,832

383,200

54,600

15 Feb 2007

–

–

–

–

5.37

–

–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Dr B E Grote

13 Feb 2006

17 Feb 2003

2003-2005

467,276

175,229

6.47

3.96

–

–

2004-2006

25 Feb 2004

2005-2007

28 Apr 2005

2006-2008

16 Feb 2006

4.25

5.33

6.54

425,338

501,782

–

–

–

470,432

425,338

501,782

470,432

127,601

15 Feb 2007

–

–

–

–

5.37

–

–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
J A Manzoni

13 Feb 2006

17 Feb 2003

2003-2005

147,783

394,088

6.47

3.96

–

–

2004-2006

25 Feb 2004

2005-2007

28 Apr 2005

2006-2008

16 Feb 2006

4.25

5.33

6.54

376,470

436,623

–

–

–

383,200

376,470

436,623

383,200

112,941

15 Feb 2007

–

–

–

–

5.37

–

–

-
-
-
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a This information has been subject to audit.
b BP’s performance is measured against the oil sector. For the periods 2003-2005 and 2004-2006, the performance measure is SHRAM, which is measured against the FTSE
All World Oil & Gas Index, and ROACE and EPS growth, which are measured against ExxonMobil, Shell, Total and Chevron. For periods 2005-2007 onward, the performance
condition is TSR measured against ExxonMobil, Shell, Total and Chevron. 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.

74

Share optionsa

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Option type

At 1 Jan 2006

Granted

Exercised

At 31 Dec 2006

Option price

Market price
at date of
exercise

Date from
which ﬁrst
exercisable

Expiry date

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
Lord Browne

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
Dr A B Hayward

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
I C Conn

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
Dr D C Allen

SAYE
EDIP
EDIP
EDIP
EDIP
EDIP

SAYE
SAYE
EXEC
EXEC
EXEC
EDIP
EDIP

EXEC
EXEC
EXEC
EDIP
EDIP

SAYE
SAYE
SAYE
EXEC
EXEC
EXEC
EXEC

SAYE
SAYE
SAYE
EXEC
EXEC
EXEC
EDIP
EDIP

4,550
408,522
1,269,843
1,348,032
1,348,032
1,500,000

3,302
–
34,000
77,400
160,000
220,000
275,000

37,000
87,950
175,000
220,000
275,000

1,456
1,186
1,498
72,250
130,000
160,000
126,000

878
2,548
847
34,000
72,250
175,000
220,000
275,000

–
3,220
–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–

–
–
–
–
–
–
–

–
–
–
–
–
–
–
–

–
–
1,269,843
–
1,348,032
–

–
–
160,000
–

–
–
–
–
–
–
–

–
–
–
–
–

–
–

–
–
–
–
–
–
–
–

4,550
408,522
–
1,348,032
–
1,500,000

3,302
3,220
34,000
77,400
160,000
220,000
275,000

37,000
87,950
175,000
220,000
275,000

1,456
1,186
1,498
72,250
130,000
–
126,000

878
2,548
847
34,000
72,250
175,000
220,000
275,000

£3.50
£5.99
£5.67
£5.72
£3.88
£4.22

£5.11
£5.00
£5.99
£5.67
£5.72
£3.88
£4.22

£5.99
£5.67
£5.72
£3.88
£4.22

£3.50
£3.86
£4.41
£5.67
£5.72
£3.88
£4.22

£4.52
£3.50
£3.86
£5.99
£5.67
£5.72
£3.88
£4.22

£6.67

£6.67

£6.55

1 Sep 2008
15 May 2001
19 Feb 2002
18 Feb 2003
17 Feb 2004
25 Feb 2005

1 Sep 2006
1 Sep 2011
15 May 2003
23 Feb 2004
18 Feb 2005
17 Feb 2004
25 Feb 2005

15 May 2003
23 Feb 2004
18 Feb 2005
17 Feb 2004
25 Feb 2005

1 Sep 2008
1 Sep 2009
1 Sep 2010
23 Feb 2004
18 Feb 2005
17 Feb 2006
25 Feb 2007

28 Feb 2009
15 May 2007
19 Feb 2008
18 Feb 2009
17 Feb 2010
25 Feb 2011

28 Feb 2007
29 Feb 2012
15 May 2010
23 Feb 2011
18 Feb 2012
17 Feb 2010
25 Feb 2011

15 May 2010
23 Feb 2011
18 Feb 2012
17 Feb 2010
25 Feb 2011

28 Feb 2009
28 Feb 2010
28 Feb 2011
23 Feb 2011
18 Feb 2012
17 Feb 2013
25 Feb 2014

1 Sep 2007
1 Sep 2008
1 Sep 2009
15 May 2003
23 Feb 2004
18 Feb 2005
17 Feb 2004
25 Feb 2005

28 Feb 2008
28 Feb 2009
28 Feb 2010
15 May 2010
23 Feb 2011
18 Feb 2012
17 Feb 2010
25 Feb 2011

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Dr B E Groteb

SAR
SAR
BPA
BPA
EDIP
EDIP
EDIP
EDIP

35,200
40,000
10,404
12,600
40,182
58,173
58,173
58,333

–
–
–
–
–
–
–
–

35,200
–
–
–
–
–
–
–

–
40,000
10,404
12,600
40,182
58,173
58,173
58,333

$25.27
$33.34
$53.90
$48.94
$49.65
$48.82
$37.76
$48.53

$66.96

6 Mar 1999
28 Feb 2000
15 Mar 2000
28 Mar 2001
19 Feb 2002
18 Feb 2003
17 Feb 2004
25 Feb 2005

6 Mar 2006
28 Feb 2007
14 Mar 2009
27 Mar 2010
19 Feb 2008
18 Feb 2009
17 Feb 2010
25 Feb 2011

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------
J A Manzoni

The closing market prices of an ordinary share and of an ADS on 31 December 2006 were £5.68 and $67.10 respectively.
During 2006, the highest market prices were £7.12 and $76.47 respectively and the lowest market prices were £5.64 and $63.72 respectively.

EDIP = Executive Directors’ Incentive Plan adopted by shareholders in April 2005 as described on page 70.
BPA = BP Amoco share option plan, which applied to US executive directors prior to the adoption of the EDIP.
SAR = Stock Appreciation Rights under BP America Inc. Share Appreciation Plan.
SAYE = Save As You Earn employee share scheme.
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.

a This information has been subject to audit.
b Numbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.

This directors’ remuneration report was approved by the board
and signed on its behalf by David J Jackson, company secretary,
on 23 February 2007.

BP Annual Report and Accounts 2006

75

Governance: board performance report

Governance and the role of our board

Governance is the system by which the company’s owners and their
representatives on the board ensure that the company pursues its deﬁned
purpose and only allocates resources to that purpose. It is neither a
process of compliance nor an additional level of management. The
board’s activity is focused on this task as the representative of BP’s
owners and it discharges this through actions that promote long-term
shareholder interest.

BP’s approach to governance is based on the connection between

good governance and maximizing shareholder value. We believe that good
governance involves both clarity of roles and distinct skills and processes.
The BP board governs the company on behalf of shareholders, while
management is delegated to the group chief executive through the board
governance policies. These policies use a coherent, principles-based
approach that ensures our board and management operate within a clear
and efﬁcient governance framework that places long-term shareholder
interest at the centre of everything the company does.

In maximizing long-term shareholder interest, the board exercises

judgement when carrying out its work in policy-making, monitoring
executive action and active consideration of group strategy. While being
responsible to shareholders, the board also recognizes the need to be
responsive to the interests of those with whom the company interacts.

Shareholders

Accountability
The board, principally through the AGM, is accountable to shareholders
for the performance and activities of the entire BP group. The board
takes steps to understand shareholder preferences and to evaluate
systematically the ﬁnancial, social, environmental and ethical matters
that may inﬂuence or affect the interests of our shareholders.

Dialogue
Throughout the year, the chairman has regular meetings with institutional
shareholders to discuss issues of governance and high-level strategy.
Shareholder dialogue is also undertaken by the group chief executive and
other directors, the company secretary’s ofﬁce, investor relations and
other teams within BP on wider issues relating to the operation and
ﬁnancial performance of the company. Presentations given by the
company to the investment community are available on the ‘Investor’
section of www.bp.com.

Reporting
BP uses a number of different reporting channels to provide feedback
and accountability on the company’s performance to shareholders. These
include the Annual Report and Accounts (which now includes a business
review), Annual Review, Annual Report on Form 20-F and announcements
made through stock exchanges on which BP shares are listed, as well as
the AGM. BP seeks to promote the use of electronic communications
within its reporting methods, so all these documents are available via our
website at www.bp.com.

AGM and voting
Shareholders are encouraged to attend the AGM and use the opportunity
to ask questions and hear the resulting discussion about BP’s
performance. However, given the size and geographical diversity of the
company’s shareholder base, we recognize that this may not always be
practical and shareholders who are unable to attend are encouraged to
use proxy voting on the resolutions put forward. Every vote cast, whether
in person or by proxy at shareholder meetings, is counted, because votes
on all matters except procedural issues are taken by a poll. The company
has introduced a ‘vote withheld’ option on the proxy form in order to
comply with the revised UK Combined Code. A ‘vote withheld’ is not a
vote in law and will not be counted in the calculation of the proportion of
votes ‘for’ and ‘against’ a resolution.

76

After the event, copies of speeches and presentations given at the

AGM are available to download via www.bp.com, together with the
outcome of voting on the resolutions.

The chairman and the board committee chairmen were present during

the 2006 AGM. Board members also met shareholders informally after
the main business of the AGM. In 2006, voting levels at the AGM
increased to 64%, up from 62% in 2005.

Election of directors
All directors stand for re-election each year, with new directors being
subject to election at the ﬁrst opportunity following their appointment.
All the names submitted to shareholders for election are accompanied
by a biography and an outline of the skills and experience that the
company feels are relevant in proposing them for the ofﬁce of director.
Voting levels from the 2006 AGM demonstrated continued support

for all our directors.

How the board governs the company

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

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

The board focuses on those tasks that are unique to it as a board,
reserving to itself the making of broad policy decisions. It delegates
detailed consideration to either board committees and ofﬁcers (for board
processes) or to the group chief executive (in the case of management of
the company’s business activities). The board governs BP through setting
general policy for the conduct of business (and, critically, by clearly
articulating its goals) and by monitoring its implementation by the group
chief executive.

To discharge its governance function effectively, the board has laid

down rules for its own activities in a governance process policy.
Responsibility for implementing this policy is placed on the chairman.
This policy covers:
– The conduct of members at meetings.
– The cycle of board activities and the setting of agendas.
– The provision of timely information to the board.
– Board ofﬁcers and their roles.
– Board committees, their tasks and composition.
– Qualiﬁcations for board membership and the process of the

nomination committee.

– The evaluation and assessment of board performance.
– The remuneration of non-executive directors.
– The process for directors to obtain independent advice.
– The appointment and role of the company secretary.

The delegation of authority from the board to the group chief executive
and the expectations and limitations on that authority are set out in three
separate board governance policies, which enables the board to shape
BP’s values and standards:
1. Board-executive linkage policy, which outlines how the board delegates
authority to the group chief executive and the extent of that authority.
It also sets out how the performance of the group chief executive will
be monitored.

2. Board goals policy, which clariﬁes what the board expects the group

chief executive to deliver.

3. Executive limitations policy, which deﬁnes the boundaries on how the
group chief executive can achieve these results and requires that any
executive action taken in the course of business considers internal
controls, risk preferences, ﬁnancing, ethical behaviour, health, safety,
the environment, treatment of employees and political considerations.

Accountability in our business

The group chief executive describes to the board how the expected
outcome and goals are intended to be delivered through regular business
plans, which also encompass an assessment of the group’s risks.
During the year, the board receives updates on progress towards these
outcomes through actual and forecasted results.

The group chief executive is obliged to review and discuss with the

board all strategic projects or developments and all material matters
currently or prospectively affecting the company and its performance.
This key dialogue speciﬁcally includes any materially under-performing
business activities, actions that breach the executive limitations policy
and material matters of a social responsibility, environmental or
ethical nature.

The board-executive linkage policy also sets out how the group chief
executive’s performance will be monitored and recognizes that, in the
multitude of changing circumstances, judgement will always be involved.
The systems set out in the board-executive linkage policy are designed to
manage, rather than to eliminate, the risk of failure to achieve the goals or
observe the executive limitations policy. They provide reasonable, rather
than absolute, assurance against material misstatement or loss.

The board: structure and skills

The board is composed of the chairman, nine non-executive and seven
executive directors. In total, four nationalities are represented on the
board. The names and biographical details of the directors are provided
on pages 65-66.

The board is actively engaged in orderly succession planning for both
executive and non-executive roles, to enable the board’s composition to
be renewed without compromising its continued effectiveness.

Lord Browne will retire as group chief executive and from the board
on 31 July 2007. Dr Tony Hayward will become group chief executive on
1 August 2007. Mr Michael Wilson stepped down from the board at
the end of February 2006 and Mr Michael Miles retired in April 2006.
Sir William Castell joined the board in July 2006. Mr Andy Inglis joined
the board on 1 February 2007 as chief executive of the exploration and
production segment in succession to Dr Hayward. At the 2007 AGM,
Mr John Bryan will retire from the board.

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

We believe that our non-executive directors bring a broad range

of relevant skills and experience to the work of the board and its
committees. Not only do they contribute international and operational
experience, but they also provide an understanding of the economies and
world capital markets in which the group operates and an appreciation of
the health, safety and environmental and sustainability issues the group
faces. Our executive directors bring a further perspective to the work of
the board through their deep comprehension of the company’s business.

Board independence

Part of the qualiﬁcation for board membership of BP is the requirement
that non-executive directors be free from any relationship with the
company’s executive management that could materially interfere with the
exercise of their independent judgement. In the board’s view, the non-
executive directors fulﬁl this requirement and the board has determined
that those who served during 2006 were independent. All non-executive
directors are now subject to annual election and to date have received
overwhelming endorsement at successive AGMs.

Sir Ian Prosser joined the board in 1997. It is the view of the board that,
despite having served for more than nine years, he remains independent.
His experience and long-term perspective on BP’s business have provided
a valuable contribution to the board, given the long-term nature of our
business. The board has speciﬁcally requested that he remain chairman
of the audit committee for the time being through the retirement of
Dr Byron Grote.

Those directors who joined the BP board in 1998 after service on the

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

The board has satisﬁed itself that there is no compromise to the

independence of those directors who serve together as directors on the
boards of outside entities (or who have other appointments in outside
entities). Where necessary, our board ensures appropriate processes are
in place to manage any possible conﬂict of interest.

Board directors: terms of appointment

The chairman and directors of BP stand for re-election each year and,
subject to BP’s Articles of Association, serve on the basis of letters
of appointment. Executive directors of BP have service contracts with
the company. Details of all payments to directors are reviewed in the
directors’ remuneration report on pages 68-75.

BP’s policy on directors’ retirement is as follows: the service contracts
of executive directors are expressed to expire at a normal retirement age
of 60 (subject to age discrimination), while non-executive directors
ordinarily retire at the AGM following their 70th birthday. It is the board’s
policy that non-executive directors are not generally expected to hold
ofﬁce for more than 10 years.

In accordance with BP’s Articles of Association, directors are granted
an indemnity from the company 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 2006. This
policy has been renewed for 2007. 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.

Board and committees:
meetings and attendance

The board requires all members to devote sufﬁcient time to the work
of the board to discharge the ofﬁce of director and to use their best
endeavours to attend meetings.

In addition to the AGM (which 14 directors attended), the board met
nine times during 2006: six times in the UK, twice in the US and once
in Turkey. Two of these meetings were two-day strategy discussions.
A number of board committee meetings were held during the year;
for details of these and their attendance by board members please
see the following table.

BP Annual Report and Accounts 2006

77

Directors’ attendance

- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----- ------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------
SEEAC
meetings
- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----- ------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------
Possible
- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----- ------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------

Remuneration
committee meetings

Chairman’s
committee meetings

Nomination
committee meetings

Audit committee
meetings

Board
meetings

Attended

Attended

Attended

Attended

Attended

Attended

Possible

Possible

Possible

Possible

Possible

P D Sutherland
J H Bryan
A Burgmans
Sir William Castell
E B Davis, Jr
D J Flint
Dr D S Julius
Sir Tom McKillop
Dr W E Massey
H M P Miles
Sir Ian Prosser
M H Wilson
Lord Browne
Dr A B Hayward
Dr D C Allen
I C Conn
Dr B E Grote
J A Manzoni

9
9
9
3
7
9
8
9
9
4
9
2
9
9
9
9
9
9

9
9
9
3
9
9
9
9
9
4
9
2
9
9
9
9
9
9

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
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–
10
–
1
11
11
–
–
–
3
11
3
–
–
–
–
–
–

–
12
–
2
12
12
–
–
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4
12
3
–
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–

-
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–
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-
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5
5
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5
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5
5
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5
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6
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6
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6
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6
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6
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6
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–

Serving as a director:
induction, training and evaluation

Induction
Following their appointment to the board, new directors undertake
an induction programme that is tailored to their speciﬁc needs. This
programme covers matters such as the operation and activities of the
group (including key ﬁnancial, business, social and environmental risks to
the group’s activities), the role of the board and the matters reserved for
its decision, the tasks and membership of the principal board committees,
the powers delegated to those committees, the board’s governance
policies and practices and the latest ﬁnancial information about the group.
The chairman is accountable for the induction of new board members and
is assisted by the company secretary’s ofﬁce in this role.

Training
On appointment, our directors are advised of the legal and other duties
and obligations they have as directors of a listed company. The board
regularly considers the implications of these duties under the board
governance policies. In addition, non-executive directors also receive
ongoing training speciﬁc to the tasks of the particular board committees
on which they serve in order to update their skills and knowledge and
enhance their effectiveness during their tenure.

Our directors are updated on BP’s business, the environment in which

it operates and other matters throughout their period in ofﬁce.

Outside appointments
As part of their ongoing development, our executive directors are
permitted to take up an external board appointment, subject to the
agreement of the BP board. Generally, outside appointments for
executive directors are limited to a single company board only, although
our current group chief executive, by exception, serves on two outside
company boards. Our board is satisﬁed that these appointments do not
conﬂict with his duties and commitments to BP. Executive directors retain
any fees received in respect of such external appointments.

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
the extent of directors’ other interests under review to ensure that the
efﬁcacy of our board is not compromised.

Evaluation
The board continued its ongoing evaluation processes to assess its
performance and identify areas in which its effectiveness, policies and
processes might be enhanced. The board evaluated its performance

78

during the year through the use of a questionnaire aimed at building
on the outcome of the previous year’s evaluation and endeavouring to
assess the manner in which the board had responded to the issues
that occurred during 2006. The board is considering the output from
the evaluation.

Separate evaluations of the audit and the safety, ethics and

environment assurance committees took place during the year and are
reported in the committee reports on pages 79-81. The remuneration
committee will be reviewing its 2006 performance in the ﬁrst half of 2007.
The potential use of external providers in the context of board evaluation
is being kept under review.

The chairman and the senior
independent director

BP’s board governance policies require that neither the chairman nor the
deputy chairman is employed as an executive of the group. During 2006,
the posts were held by Mr Sutherland and Sir Ian Prosser, respectively.
Sir Ian also acts as our senior independent director and is available to
shareholders who have concerns that cannot be addressed through
normal channels.

The chairman is responsible for leading the board and facilitating
its work. He ensures that the governance principles and processes of
the board are maintained and encourages debate and discussion. The
chairman also leads board and individual director performance appraisals.
He represents the views of the board to shareholders on key issues,
not least in succession planning for both executive and non-executive
appointments. Shareholders’ views are fed back to the board by
the chairman.

The company secretary reports to the chairman and has no

executive functions. His remuneration is determined by the
remuneration committee.

Between board meetings, the chairman has responsibility for ensuring

the integrity and effectiveness of the board/executive relationship.
This requires his interaction with the group chief executive between
board meetings, as well as his contact with other board members
and shareholders.

The chairman and all the non-executive directors meet periodically as
the chairman’s committee (reported on page 81). The performance of the
chairman is evaluated each year, with the evaluation discussion taking
place when the chairman is not present.

Board committees

The governance process policy allocates the tasks of monitoring executive
actions and assessing performance to certain board committees. These
tasks prescribe the authority and role of the board committees.

Reports for each of the committees for 2006 follow. In common with
the board, each committee has access to independent advice and counsel
as required and each is supported by the company secretary’s ofﬁce,
which is demonstrably independent of the executive management of
the group.

Audit committee report
Membership and meeting schedule
The audit committee consists solely of independent non-executive
directors. Its membership is selected to provide a broad set of
ﬁnancial, international and commercial expertise appropriate to fulﬁl
the committee’s duties.

Members of the audit committee include Sir Ian Prosser (chairman),
Mr D J Flint, Mr E B Davis, Jr and Mr J H Bryan. During 2006, Mr M H
Wilson and Mr H M P Miles retired from the committee and Sir William
Castell joined as a new member. The company secretary’s ofﬁce ensures
new committee members receive brieﬁngs on the committee’s tasks and
process before taking up their roles.

The board has determined that Mr Flint possesses the ﬁnancial and
audit committee experience as deﬁned by the Combined Code guidance
and the US Securities and Exchange Commission and has nominated him
as the audit committee’s ﬁnancial expert.

At the request of the audit committee chairman, each meeting is

attended by the lead partner of the external auditors (Ernst & Young), the
BP general auditor (head of internal audit), the group chief ﬁnancial ofﬁcer,
the chief accounting ofﬁcer and the group controller.
The audit committee met 12 times during 2006.

Role of audit committee
The tasks of the audit committee include gaining assurance on the
ﬁnancial processes of the group and the integrity of its reports and
accounts. On behalf of the board, it monitors observance of the executive
limitations policy relating to ﬁnancial matters. The committee reviews the
management of ﬁnancial risks and the internal controls designed to
address them.

The activities of the audit committee and any issues that have arisen

are reported back to the main board by the audit committee chairman
following each meeting.

Committee activities in 2006
Financial reports
During the year, the committee reviewed all annual and quarterly
ﬁnancial reports before recommending their publication to the board.
The committee also examined the application of new ﬁnancial
standards, critical accounting policies and judgements.

Internal controls and risk management
In the course of 2006, the audit committee reviewed reports on risks,
control and assurance for all the BP business segments (exploration
and production, reﬁning and marketing and gas, power and renewables),
together with BP’s trading function. Reviews were also carried out on
BP’s long-term contractual commitments and the manner in which the
risks and control systems for these contracts were being managed.
Key regulatory issues are discussed throughout the year by the

committee as part of its standing agenda items. These include a quarterly
review of the company’s evaluation of its internal controls systems as
part of the requirement of Section 404 of the Sarbanes-Oxley Act. The
committee also examines the effectiveness of BP’s enterprise level
controls through the annual assessment undertaken by the company’s
internal audit function.

In addition to the recurring items on the agenda, the audit committee

considered a range of other speciﬁc topics during the year, including a
review of tax planning and provisions, an evaluation of the company’s
pension and post-retirement beneﬁt assumptions and an assessment
of BP’s oil and gas reserves methodology.

Relationship with external auditors
As outlined above, the lead audit partner from Ernst & Young attends
all meetings of the audit committee at the request of the committee
chairman. Other audit partners are also invited to attend meetings to
participate in discussions relating to their areas of expertise, for example,
during business segment reviews.

During the year, the committee held two private meetings with the
external auditors without the presence of executive management, in order
to discuss any issues or concerns on the part of both the committee and
the auditors.

The committee believes that it meets each of the tasks that are

The performance of the external auditors is evaluated by the audit

outlined in the Combined Code as falling within the remit of an
audit committee.

Agenda and information
Central to the operation of the audit committee is the meeting agenda.
Forward agendas are set at the start of each year to determine a high-
level work programme for the committee. Agendas are constructed from
regular items, including those that are required by regulation, and items
reﬂecting the board’s desire to review group risks. Between committee
meetings, the chairman reviews any issues that arise with the group
chief ﬁnancial ofﬁcer, the external auditors and the BP general auditor
and items may be added to the next committee meeting agenda
as appropriate.

The committee receives information on agenda items from both
internal and external sources, including the chief ﬁnancial ofﬁcer, the
internal auditor and BP’s external auditors. Presentations are made by
a wide cross-section of the group’s business and ﬁnancial control
management. Where relevant to a particular business or functional
review, additional Ernst & Young audit staff attend and contribute.
In addition, the committee meets both the external auditors and BP
general auditor in private sessions where the executive management are
not present.

In common with other BP board committees, the audit committee can

access independent advice and counsel if it requires, on an unrestricted
basis. Further support is provided to the committee by the company
secretary’s ofﬁce and, during 2006, external specialist legal and regulatory
advice was provided to the committee by Sullivan & Cromwell LLP.

committee each year. Central to this evaluation is scrutiny of the
external auditors’ independence, objectivity and viability. To maintain the
independence of the external auditors, the provision of non-audit services
is limited to tax and audit-related work that fall within speciﬁc categories.
This work is pre-approved by the audit committee and all non-audit
services are monitored quarterly. Fees paid to the external auditors
during the year for audit and other services were $73 million, of which
16% was for non-audit work (see Financial statements – Note 20 on
page 128). Non-audit services provided by Ernst & Young have been
signiﬁcantly reduced over recent years but, reﬂecting regulatory and
reporting developments in the UK and US, audit fees have increased
substantially.

In addition to the restrictions on non-audit work, the objectivity and
independence of the external auditors are augmented by the rotation of
audit staff on a regular basis. A new lead audit partner is appointed every
ﬁve years and other senior audit staff are moved every seven years. It is
the policy of the company that no partners or senior staff connected with
the BP audit may transfer to BP.

After considering both the proposed fee structure and the audit
engagement terms for 2007, the audit committee has recommended
to the board that the reappointment of the auditors be proposed to
shareholders at the 2007 AGM.

Internal audit
BP’s internal audit function advises the committee on the company’s
identiﬁcation and control of risk. The general auditor contributes widely
to the committee’s discussion of the company’s framework of internal
controls and the effectiveness of their application. The audit committee
agreed the work programme to be undertaken by internal audit during the

BP Annual Report and Accounts 2006

79

year and obtained satisfaction that the proposed work plan appropriately
responded to the key risks facing the company and that internal audit had
adequate staff and resources to complete its work.

forward agenda at the beginning of each year, the committee pays
particular attention to the review of group risks conducted by the general
auditor and risks identiﬁed in the company’s business plans.

In addition to regular observations and updates at each committee
meeting, internal audit made two written reports of its ﬁndings to the
committee in 2006. These reports contributed to the committee’s view
on how effective the company’s system of internal controls had been
and formed the basis of its recommendations to the board.

During the year, the committee met privately with the head of internal

audit (the BP general auditor), without the presence of executive
management. It also evaluated the performance of the internal
audit function.

Fraud reporting and employee concerns/whistleblowing
The committee received a quarterly report from internal audit on instances
of actual or potential fraud or concerns relating to the ﬁnancial accounting
of the company. In addition, the group compliance and ethics function
reported on issues raised via the employee concerns programme,
OpenTalk, together with other topics arising from the company’s annual
certiﬁcation process.

Performance evaluation
The audit committee conducts a yearly evaluation of its performance.
The review for 2006 involved a survey of committee members and other
individuals who had regularly attended the committee. The results of
the review were fed back to the committee in November. No signiﬁcant
process changes were identiﬁed but the committee did determine to take
additional time in private session at the end of each meeting and to hold
a joint meeting with the safety, ethics and environment assurance
committee each year to review the general auditor’s internal controls and
risk management report. These adjustments were incorporated in the
forward agenda and work plan for 2007.

The audit committee plans to meet 12 times during 2007.

Safety, ethics and environment assurance committee report
Membership and meeting schedule
The committee’s members consist solely of independent non-executive
directors and include Dr W E Massey (chairman) and Mr A Burgmans.
During 2006, Mr M H Wilson and Mr H M P Miles retired from the
committee and Sir William Castell and Sir Tom McKillop joined as new
members. The company secretary’s ofﬁce ensures new committee
members receive brieﬁngs on the committee’s tasks and process before
taking up their roles.

In addition to the members above, each meeting is attended by the
lead partner of the external auditors (Ernst & Young) and the BP general
auditor (head of internal audit) at the invitation of the committee chairman.
Reports and presentation to the committee are led by the executive

director with functional accountability for safety and the environment
(Mr Iain Conn) and the committee’s dialogue includes meeting with the
relevant senior managers and functional experts for each of its agenda
topics. In 2006, the group chief executive attended one meeting.

The safety, ethics and environment assurance committee, created in
1997, has increased the frequency of its meetings in recent years from
four per year in 2003 to seven in 2006. This has reﬂected both the
increased breadth of the company’s business (for example, expansion into
new geographies such as Russia) and the committee’s additional work in
monitoring the executive management’s response to incidents (including
the Texas City ﬁre and explosion and the oil spills in Alaska).

Role of the committee
On behalf of the board, the committee monitors observance of the
executive limitations policy that relates to the environmental, health and
safety, security and ethical performance and compliance of the company.
During 2006, the committee’s name was amended. Having reviewed
its agendas over the past few years, it was considered by the board that
the addition of ‘safety’ to ethics and environment assurance provided a
better reﬂection of the committee’s work.

Agenda and information
The tasks of the safety, ethics and environment assurance committee are
particularly broad as they cover all non-ﬁnancial risks. In constructing its

80

Forward agendas also include regular or standing agenda items.

Standing agenda items are those that enable the committee to monitor
and assess how the executive limitations policy is being observed (for
example, compliance and ethics and health, safety and environment
reports) and review the speciﬁc non-ﬁnancial risks that are identiﬁed in the
company’s annual plan (for example, in performing regional risk reviews).
The chairman of the committee will also review the forward agenda
against any emerging issues or developments that may arise during
the year and amend as necessary.

The committee receives information relating to agenda items from
both internal and external sources, including internal audit, BP’s external
auditors, the group compliance and ethics function and external market
and reputation research. In common with other BP board committees,
the safety, ethics and environment assurance committee can access
independent advice and counsel if it requires, on an unrestricted basis.

The activities of the safety, ethics and environment assurance
committee and any issues that have arisen are reported back to the
main board by the committee chairman following each meeting.

Committee activities in 2006
HSE performance
The committee received reports on both the company’s overall HSE
performance, including an examination of key metrics, and on individual
topics such as human resources capability, employee health and HSE in
TNK-BP. Progress in safety and operations management since the
incident at the Texas City reﬁnery has been reviewed regularly.

Regional risk reviews
While most of the board-level monitoring is undertaken through business
segments or functions, risks that require management at a country or
regional level are also scrutinized by the committee. During the year, risk
reviews were carried out for North America, Russia and the Caspian.

Compliance and ethics
The group compliance and ethics function reports to the committee
on a quarterly basis. During 2006, the compliance and ethics reports
covered the results of the 2005 certiﬁcation process, progress on the
implementation of the company’s code of conduct and the operation
of OpenTalk.

Performance evaluation
The committee conducts an annual review of its process and
performance. This year’s review was discussed at the committee’s
November meeting and has led to enhancements in the committee
process going forward, including the incorporation of reports from the
new group operations risk committee and an increase in time allotted to
agenda items to enable further in-depth discussion.

The safety, ethics and environment assurance committee plans to

meet seven times during 2007.

Remuneration committee report
Membership and meeting schedule
The remuneration committee consists solely of non-executive directors,
who are considered by the board to be independent. Committee
members include Dr D S Julius (chairman), Mr J H Bryan, Mr E B Davis,
Jr, Sir Tom McKillop and Sir Ian Prosser. The chairman of the board also
attends meetings of the committee.

The committee met ﬁve times during 2006 and is independently

advised.

Role of remuneration committee
The committee’s main task is to determine the terms of engagement and
remuneration of the executive directors.

Further details of the committee’s role, authority and activities during
the year are set out in the directors’ remuneration report on pages 68-75,
which is the subject of a vote by shareholders at the 2007 AGM.

Chairman’s committee report
Membership and meeting schedule
The chairman’s committee comprises all the non-executive directors and
is chaired by the board chairman.

B.1.4

B.2.2

The committee met four times during the year.

Role of chairman’s committee
The task of the committee is to consider broad issues of governance,
including the performance of the chairman and the group chief executive,
succession planning, the organization of the group and any matters
referred to it for an opinion from another board committee.

The amount of fees received by executive directors in respect
of their service on outside boards is not disclosed since this
information is not considered relevant to BP.
The remuneration of the chairman is ﬁxed by the board as a
whole (rather than the remuneration committee) within the
limits set by shareholders, since the chairman’s performance
is a matter for the whole board.

Internal control review

Committee activities in 2006
The main focus of the committee was on the task of ensuring an orderly
succession plan for the group chief executive role. In that respect, the
committee formed a working group comprised of the chairmen of each of
the board’s standing committees, which has taken forward the detailed
work necessary to ensure a best-practice process to identify a new group
chief executive. The working group met six times during the year.

The board, through its governance policies, has established a process by
which the effectiveness of the system of internal control can be regularly
reviewed as required by provision C.2.1 of the Combined Code.

The process enables the board and its committees to assess the

system of internal controls being operated for managing signiﬁcant risks,
including social, environmental, safety and ethical risks, throughout the
year. The process did not extend to joint ventures or associates.

The committee took external advice as appropriate and benchmarked

As part of this process, the board and the audit and safety, ethics and

all the candidates against the external market.

The committee concluded its work by making a unanimous

recommendation to the board that Dr A B Hayward be appointed as
the next group chief executive.

Nomination committee report
Membership and meeting schedule
The nomination committee consists of non-executive directors. Its
members include Dr D S Julius, Sir Ian Prosser and Dr W E Massey
and the committee is chaired by the board chairman, Mr P D Sutherland.
All members of the nomination committee are considered by the board
to be independent.

The committee met six times during the year.

Role of nomination committee
The task of the nomination committee is to identify and evaluate
candidates for appointment and reappointment as director or company
secretary of BP.

Committee activities in 2006
As a result of the committee’s processes, Sir William Castell joined
the board in 2006.

The committee continues to keep under review the skills and
background that the board requires to perform its various tasks. The
committee recognizes that, with the forthcoming retirements of directors,
at least one new non-executive director will need to be appointed to the
board each year for the next three years. The committee is currently
evaluating candidates with a North American background.

Combined Code compliance

BP complied throughout 2006 with the provisions of the Combined Code
Principles of Good Governance and Code of Best Practice, except in the
following aspects:
A.4.4

Letters of appointment do not set out ﬁxed time commitments
since the schedule of board and committee meetings is subject
to change according to the exigencies of the business. All
directors are expected to demonstrate their commitment to
the work of the board on an ongoing basis. This is reviewed
by the nomination committee in recommending candidates
for annual re-election.

environment assurance committees requested, received and reviewed
reports from executive management, including management of the
business segments, 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.

The BP general auditor presented reports to a joint meeting of
the committees in January 2007 to support the board in its annual
assessment of internal control. The reports described how signiﬁcant
risks were identiﬁed and embedded within business segment and
function plans across the group; the effectiveness of executive controls;
and the continuing development of the systems in place to identify and
manage risks.

The reports also highlighted future risks of potential signiﬁcance

that had been reviewed by the board as part of the company’s
planning process.

The committees engage with executive management during the
year on a regular basis to monitor the management of risks. Signiﬁcant
incidents that occurred and management’s response to them were
considered by the committees during the year.

As is disclosed elsewhere in BP Annual Report and Accounts 2006,

the company has recently received reports that were previously
commissioned relating to the US reﬁnery system and trading operations.
The company has accepted the recommendations of those reports
and is in the process of determining the appropriate actions required
to implement those recommendations. The committees will monitor
management’s actions in respect of these reports over the coming year.
Subject to this, the board is satisﬁed that, where signiﬁcant failings or
weaknesses in internal controls were identiﬁed, appropriate remedial
actions were taken or are being taken.

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).

BP Annual Report and Accounts 2006

81

Directors’ interests

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Change from
31 Dec 2006
to 20 Feb 2007

At 1 Jan 2006

Current directors
At 31 Dec 2006
----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------
530,933a
Dr D C Allen
2,525,313b
Lord Browne
158,760c
J H Bryan
10,000
A Burgmans
209,449d
I C Conn
68,992c
E B Davis, Jr
D J Flint
15,000
1,105,825e
Dr B E Grote
407,021
Dr A B Hayward
193,022f
A G lnglis
15,000
Dr D S Julius
20,000
Sir Tom McKillop
376,213
J A Manzoni
49,722c
Dr W E Massey
16,301
Sir Ian Prosser
30,079
P D Sutherland
–
Sir W M Castell

443,742
2,242,954
158,760
10,000
156,349
67,610
15,000
988,812
305,543
–
15,000
20,000
275,743
49,722
16,301
30,079
–

66,635
224,594
–
–
32,348
–
–
75,288
70,071
30,090
–
–
66,769
–
–
–
–

Directors leaving
the board in 2006
At retirement
----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------
H M P Miles
M H Wilson

22,145
60,000c

22,145
60,000

At 1 Jan 2006

a Includes 25,368 shares held as ADSs.
b Includes 61,186 shares held as ADSs.
c Held as ADSs.
d Includes 40,155 shares held as ADSs.
e Held as ADSs, except for 94 that are held as ordinary shares.
f Interest as at 1 February 2007 on appointment as a director.

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 Companies Act 1985 as at the applicable dates. In making these
disclosures, the directors did not distinguish their beneﬁcial and
non-beneﬁcial interests.

Executive directors are also deemed to have an interest in such shares

of the company held from time to time by 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.

82

Additional information for shareholders

Share ownership

Directors and senior management
As at 20 February 2007, 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:

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

597,568

819,823a
2,749,907 3,768,016a
799,032a
972,212a
819,823a
–
819,823a
–
–
–
–
–
–
–
–
–
–

241,797
1,181,113
477,092
223,112
442,982
158,760
10,000
–
68,992
15,000
15,000
49,722
20,000
16,301
30,079

794,950
3,261,104
332,390
1,427,190b
769,620
415,300
780,523

Dr D C Allen
The Lord Browne of Madingley
I C Conn
Dr B E Grote
Dr A B Hayward
A G Inglis
J A Manzoni
J H Bryan
A Burgmans
Sir William Castell
E B Davis, Jr
D J Flint
Dr D S Julius
Dr W E Massey
Sir Tom McKillop
Sir Ian Prosser
P D Sutherland

Dr D C Allen
The Lord Browne of Madingley
I C Conn
Dr B E Grote
Dr A B Hayward
A G Inglis
J A Manzoni

As at 20 February 2007, 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:

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

a Performance shares awarded under the BP Executive Directors Incentive Plan.
These 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 In addition to the above, Dr Grote holds 40,000 Stock Appreciation Rights
(equivalent to 240,000 ordinary shares).

There are no directors or members of senior management who own
more than 1% of the ordinary shares outstanding. At 20 February 2007,
all directors and senior management as a group held interests in
15,488,669 ordinary shares or their calculated equivalent and 8,584,526
options for ordinary shares or their calculated equivalent under the BP
group share options schemes.

Additional details regarding the options granted, including exercise
price and expiry dates, are found in the directors’ remuneration report
on page 75.

Employee share plans
The following table shows employee share options granted.

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

options thousands

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

2006

2005

2004

Employee share options

granted during the yeara

53,978

54,482

80,395

a For the options outstanding at 31 December 2006, the exercise price ranges and
weighted average remaining contractual lives are shown in Financial statements –
Note 44 on page 163.

BP offers most of its employees the opportunity to acquire a shareholding
in the company through savings-related and/or matching share plan
arrangements. BP also uses long-term performance plans (see Financial

statements – Note 44 on page 163) and the granting of share options as
elements of remuneration for executive directors and senior employees.

Savings and matching plans
BP ShareSave Plan
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 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. Until 2003, a three-year savings plan
was also run in a small number of other countries. Options will remain
outstanding in respect of these countries until the end of June 2007.
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
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 over 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.

The above share plans are indicated as being equity-settled. However in
certain countries it is not possible to award shares to employees owing to
local legislation. In these instances the award will be settled in cash,
calculated as the cash equivalent of the value to the employee of an
equity-settled plan.

Cash plans
Cash Options/Stock Appreciation Rights (SARs)
These are cash-settled share-based payments available to certain
employees that require the group to pay the intrinsic value of the
cash option/SAR to the employee at the date of exercise. There are
no performance conditions; however, participants must continue in
employment with BP for the ﬁrst three calendar years of the plan for
the options/SARs to vest. Special arrangements may apply for qualifying
leavers. The options/SARs are exercisable between the third and 10th
anniversaries of the grant date.

Employee Share Ownership Plans (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards
made to participants under the Executive Directors’ Incentive Plan, the
Medium Term Performance Plan, the Long Term Performance Plan, the
Deferred Annual Bonus Plan and the BP ShareMatch Plans. The ESOPs
have waived their rights to dividends on shares held for future awards and
are funded by the group. 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 43 on page 160. Assets and liabilities of the
ESOPs are recognized as assets and liabilities of the group.)

At 31 December 2006, the ESOPs held 12,795,887 shares (2005
14,560,003 shares and 2004 8,621,219 shares) for potential future
awards, which had a market value of $142 million (2005 $156 million and
2004 $84 million).

BP Annual Report and Accounts 2006

83

Pursuant to the various BP group share option schemes, the following

options for ordinary shares of the company were outstanding at
20 February 2007:

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------
Options outstanding (shares)
----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------
422,119,465

Exercise price per share
$5.0967-$11.921

Expiry dates of options
2007-2016

Major shareholders and
related party transactions

Register of members holding BP ordinary shares
as at 31 December 2006

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Number of
shareholders

Percentage of total
shareholders

Percentage of total
share capital

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

61,108
126,141
128,717
12,366
1,087
822
----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------
330,241

18.50
38.20
38.98
3.74
0.33
0.25
100.00

0.01
0.30
1.81
1.18
1.83
94.87
100.00

a Includes JP Morgan Chase Bank, holding 26.46% of the total share capital as the
approved depositary for ADSs, a breakdown of which is shown in the table below.

Register of holders of American depositary shares as at
31 December 2006a

----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------

Number of
ADS holders

Percentage of total
ADS holders

Percentage of total
ADS holders

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

37,265
36,140
58,388
16,708
600
12
----- -------- -------- --------- -------- -------- --------- -------- -------- -- ------ -------- --------- -------- -------- --------- ------ -- -------- ---------
149,113

0.05
0.34
3.63
7.60
1.91
86.47
100.00

24.99
24.24
39.16
11.20
0.40
0.01
100.00

a One ADS represents six 25 cent ordinary shares.
b One of the holders of ADSs represents some 751,000 underlying shareholders.

As at 31 December 2006, there were also 1,534 preference shareholders.

Substantial shareholdings
Following implementation of the EU Transparency Directive effected by
the new Disclosure and Transparency Rules (DTR) made by the Financial

Services Authority, there has been a change in the basis on which we
disclose certain major interests in the share capital of the company. Under
DTR 5, we have received notiﬁcation that Legal & General Group Plc hold
3.77% of the voting rights of the issued share capital of the company.

Related party transactions
The group had no material transactions with jointly controlled entities and
associates during the period commencing 1 January 2006 to the date of
this report. Transactions between the group and its signiﬁcant jointly
controlled entities and associates are summarized in Financial statements
– Note 29 on page 136 and Financial statements – Note 30 on page 137.
In the ordinary course of its business, the group has transactions with

various organizations with which certain of its directors are associated
but, except as described in this report, no material transactions
responsive to this item have been entered into in the period commencing
1 January 2006 to 20 February 2007.

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. Until their
shares have been exchanged for BP ADSs, Amoco and Atlantic Richﬁeld
shareholders do not have the right to receive dividends.

BP currently announces dividends for ordinary shares in US dollars and

states an equivalent pounds sterling dividend. Dividends on BP ordinary
shares will be paid in pounds sterling and on BP ADSs in US dollars. The
rate of exchange used to determine the sterling amount equivalent is the
average of the forward exchange rate in London over the ﬁve business
days prior to the announcement date. The directors may choose to
declare dividends in any currency provided that a sterling equivalent is
announced, but it is not the company’s intention to change its current
policy of announcing dividends on ordinary shares in US dollars.

The following table shows dividends announced and paid by the
company per ADS for each of the past ﬁve years before the ‘refund’
and deduction of withholding taxes as described in Taxation on page 88.
Refund means an amount equal to the tax credit available to individual
shareholders resident in the UK in respect of such dividend, less a
withholding tax equal to 15% (but limited to the amount of the tax credit)
of the aggregate of such tax credit and such dividend.

For dividends paid after 30 April 2004, there is no refund available

to shareholders resident in the US. See Taxation on page 88 for
more information.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

March

June

September

December

Total

Dividends per American depositary share

2002

2003

2004

2005

2006

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

UK pence
US cents
Can. cents
UK pence
US cents
Can. cents
UK pence
US cents
Can. cents
UK pence
US cents
Can. cents
UK pence
US cents
Can. cents

24.3
34.5
54.9
22.9
37.5
57.4
22.0
40.5
53.7
27.1
51.0
64.0
31.7
56.25
64.5

24.3
34.5
54.1
23.7
37.5
54.3
22.8
40.5
54.8
26.7
51.0
63.2
31.5
56.25
64.1

23.3
36.0
56.7
24.2
39.0
54.0
23.2
42.6
56.7
30.7
53.55
65.3
31.9
58.95
67.4

23.4
36.0
56.1
23.1
39.0
51.1
23.5
42.6
52.2
30.4
53.55
63.7
31.4
58.95
66.5

95.3
141.0
221.8
93.9
153.0
216.8
91.5
166.2
217.4
114.9
209.1
256.2
126.5
230.4
262.5

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

A dividend reinvestment plan is in place whereby holders of BP ordinary shares can elect to reinvest the net cash dividend in shares purchased on
the London Stock Exchange. This plan is not available to any person resident in the US or Canada or in any jurisdiction outside the UK where such an
offer requires compliance by the company with any governmental or regulatory procedures or any similar formalities. A dividend reinvestment plan is,
however, available for holders of ADSs through JPMorgan Chase Bank.

Future dividends will be dependent on future earnings, the ﬁnancial condition of the group, the Risk factors set out on pages 12-13 and other matters

that may affect the business of the group set out in Financial and operating performance on page 47.

84

Legal proceedings

Save as disclosed in the following paragraphs, no member of the group
is a party to, and no property of a member of the group is subject to,
any pending legal proceedings that are signiﬁcant to the group.

On 28 June 2006, the US Commodity Futures Trading Commission
(CFTC) ﬁled a civil enforcement action in the US District Court for the
Northern District of Illinois against BP Products North America Inc. (BP
Products), a wholly owned subsidiary of BP, alleging that BP Products
manipulated the price of February 2004 TET physical propane. The CFTC
also charged BP Products with attempting to manipulate the price of
February 2004 and April 2003 TET physical propane. The CFTC is seeking
permanent injunctive relief, disgorgement, restitution and payment of
civil monetary penalties. On 28 June 2006, the US Department of Justice
ﬁled a criminal charge against a former BP Products propane trader, who
entered a guilty plea. Proceedings in the CFTC’s civil enforcement action
have been stayed by the District Court pending the further investigation of
these matters by the Department of Justice. BP Products believes that it
has co-operated fully with the CFTC in its investigation of this matter and
is assisting the Department of Justice in its ongoing investigation. Private
class action complaints have also been ﬁled against BP Products that
have been consolidated in the US District Court for the Northern District
of Illinois. 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.

The CFTC is currently investigating various aspects of BP Products’
crude oil trading and storage activities in the US since 2003 and has made
various formal and informal requests for information. BP has provided,
and continues to provide, responsive data and other information to these
requests. The CFTC is also conducting an investigation into BP Products’
trading of unleaded gasoline futures contracts on 31 October 2002.
The CFTC staff notiﬁed BP on 21 November 2006 that they intend to
recommend to the CFTC that a civil enforcement action be brought
against BP Corporation North America Inc. alleging violations of Sections
6(c), 6(d) and 9(a)(2) of the Commodity Exchange Act in connection with
its trading of unleaded gasoline futures contracts on 31 October 2002.
BP has provided, and continues to provide, responsive documents and
witness testimony. The US Attorney for the Northern District of Illinois is
also conducting an investigation into BP Products’ trading of unleaded
gasoline futures contracts on 31 October 2002.

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 reached more than 1,000
settlements in respect of all the fatalities and many of the personal injury
claims arising from the incident. Trials have been scheduled for a number
of unresolved claims in mid-2007, although to date all claims scheduled
for trial have been resolved in advance of trial. The US Occupational
Safety and Health Administration (OSHA), the US Chemical Safety and
Hazard Investigation Board (CSB), the US Environmental Protection
Agency and the Texas Commission on Environmental Quality, among
other agencies, have conducted or are conducting investigations. At the
conclusion of their investigation, OSHA issued citations that BP Products
agreed not to contest. BP Products settled that matter with OSHA on

22 September 2005, paying a $21.4 million penalty and undertaking a
number of corrective actions designed to make the reﬁnery safer.
OSHA referred the matter to the US Department of Justice for criminal
investigation, and the Department of Justice has opened an investigation.
At the recommendation of the CSB, BP appointed an independent safety
panel, the BP US Reﬁneries Independent Safety Review Panel, under
the chairmanship of former US Secretary of State James A Baker, III.
See Report of the BP US Reﬁneries Safety Review Panel on page 29
for a discussion of the Baker Panel’s report, which was published on
16 January 2007. Other government legal actions related to this matter
are pending.

Shareholder derivative lawsuits have been ﬁled in US federal and state

courts against the directors of the company and others, nominally the
company and certain US subsidiaries following the events relating to,
inter alia, Prudhoe Bay, Texas City and the trading cases, alleging breach
of ﬁduciary duty.

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

Since 1987, Atlantic Richﬁeld Company, 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 as against
Atlantic Richﬁeld. Atlantic Richﬁeld is named in these lawsuits as alleged
successor to International Smelting and Reﬁning which, along with a
predecessor company, manufactured lead pigment during the period
1920-1946. Plaintiffs include individuals and governmental entities.
Several of the lawsuits purport to be class actions. The lawsuits seek
various remedies including: compensation to lead-poisoned children; cost
to ﬁnd and remove lead paint from buildings; medical monitoring and
screening programmes; public warning and education of lead hazards;
reimbursement of government healthcare costs and special education for
lead-poisoned citizens; and punitive damages. No lawsuit against Atlantic
Richﬁeld has been settled nor has Atlantic Richﬁeld been subject to a ﬁnal
adverse judgment in any proceeding. The amounts claimed and, if such
suits were successful, the costs of implementing the remedies sought in
the various cases could be substantial. While it is not possible to predict
the outcome of these legal actions, Atlantic Richﬁeld believes that it has
valid defences and it intends to defend such actions vigorously and that
the incurrence of liability is remote. Consequently, BP believes that the
impact of these lawsuits on the group’s results of operations, ﬁnancial
position or liquidity will not be material.

For certain information regarding environmental proceedings, see

Environmental protection – US regional review on page 45.

BP Annual Report and Accounts 2006

85

The offer and listing

Markets and market prices
The primary market for BP’s ordinary shares is the London Stock
Exchange (LSE). BP’s ordinary shares are a constituent element of the
Financial Times Stock Exchange 100 Index. BP’s ordinary shares are also
traded on stock exchanges in France, Germany, Japan and Switzerland.
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 and Canada, 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 and are
also traded on the Chicago, Paciﬁc and Toronto Stock Exchanges. ADSs
are evidenced by American depositary receipts, or 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 composite tape.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Pence

Ordinary shares

Dollars

American
depositary
sharesa

High

Low

High

Low

625.00
458.00
561.00
686.00
723.00

579.50
600.00
686.00
679.00
693.00
723.00
653.00
619.00
574.50

387.00
348.75
407.75
499.00
558.50

499.00
516.00
580.50
599.00
623.00
581.00
560.00
558.50
527.50

53.98
49.59
62.10
72.75
76.85

66.65
64.94
72.75
71.25
72.88
76.85
73.28
69.49
64.03

36.25
34.67
46.65
56.60
63.52

56.60
57.95
62.84
63.26
65.35
64.19
63.81
63.52
61.29

605.50
619.00
606.50
587.50
574.50
544.00

560.00
558.50
566.00
563.00
527.50
527.50

68.60
69.49
69.11
66.88
62.27
64.03

63.81
63.52
65.75
66.20
61.29
61.90

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Year ended 31 December
2002
2003
2004
2005
2006
Year ended 31 December
2005:

2006:

First quarter
Second quarter
Third quarter
Fourth quarter
First quarter
Second quarter
Third quarter
Fourth quarter
First quarter (through 20 February)

2007:
Month of
September 2006
October 2006
November 2006
December 2006
January 2007
February 2007 (through 20 February)

a An ADS is equivalent to six 25 cent ordinary shares.

86

Market prices for the ordinary shares on the LSE and in after-hours trading
off the LSE, in each case while the New York Stock Exchange is open,
and the market prices for ADSs on the New York Stock Exchange and
other North American stock exchanges 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. Trading
in ADSs began on the LSE on 3 August 1987.

On 20 February 2007, 945,592,180 ADSs (equivalent to 5,673,553,084
ordinary shares or some 29.08% of the total) were outstanding and were
held by approximately 148,268 ADR holders. Of these, about 146,556 had
registered addresses in the US at that date. One of the registered holders
of ADSs represents some 759,659 underlying holders.

On 20 February 2007, there were approximately 332,034 holders of
record of ordinary shares. Of these holders, around 1,471 had registered
addresses in the US and held a total of some 4,201,229 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 BP’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 BP’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 90.

On 24 April 2003, the shareholders of BP voted at the AGM to adopt
new Articles of Association to consolidate amendments which had been
necessary to implement legislative changes since the previous Articles of
Association were adopted in 1983.

At the AGM held on 15 April 2004, shareholders approved an

amendment to the Articles of Association such that, at each AGM held
after 31 December 2004, all directors shall retire from ofﬁce and may
offer themselves for re-election. There have been no further amendments
to the 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.

Directors
The business and affairs of BP shall be managed by the directors.

The Articles of Association place a general prohibition on a director

voting in respect of any contract or arrangement in which he has a
material interest other than by virtue of his interest in shares in the
company. However, in the absence of some other material interest not
indicated below, a director is entitled to vote and to be counted in a
quorum for the purpose of any vote relating to a resolution concerning
the following matters:
– The giving of security or indemnity with respect to any money

lent or obligation taken by the director at the request or beneﬁt of
the company.

– Any proposal in which he is interested concerning the underwriting of

company securities or debentures.

– Any proposal concerning any other company in which he is interested,
directly or indirectly (whether as an ofﬁcer or shareholder or otherwise)
provided that he and persons connected with him are not the holder
or holders of 1% or more of the voting interest in the shares of
such company.

– Proposals concerning the modiﬁcation of certain retirement beneﬁts

schemes under which he may beneﬁt and which have been approved
by either the UK Board of Inland Revenue or by the shareholders.

– Any proposal concerning the purchase or maintenance of any

insurance policy under which he may beneﬁt.
The UK Companies Act requires a director of a company who is in any

way interested in a contract or proposed contract with the company to
declare the nature of his interest at a meeting of the directors of the
company. The deﬁnition of ‘interest’ now includes the interests of
spouses, children, companies and trusts. 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. Any director attaining the age
of 70 shall retire at the next AGM. There is no requirement of share
ownership for a director’s qualiﬁcation.

Dividend rights; other rights to share in company proﬁts;
capital calls
If recommended by the directors of BP, BP shareholders may, by
resolution, declare dividends but no such dividend may be declared in
excess of the amount recommended by the directors. The directors may
also pay interim dividends without obtaining shareholder approval. No
dividend may be paid other than out of proﬁts available for distribution, as
determined under IFRS and the UK Companies Act. Dividends on ordinary
shares are payable only after payment of dividends on BP preference
shares. Any dividend unclaimed after a period of 12 years from the date
of declaration of such dividend shall be forfeited and reverts to BP.
The directors have the power to declare and pay dividends in any
currency provided that a sterling equivalent is announced. It is not the
company’s intention to change its current policy of paying dividends in
US dollars.

Apart from shareholders’ rights to share in BP’s proﬁts by dividend
(if any is declared), the Articles of Association provide that the directors
may set aside:
– A special reserve fund out of the balance of proﬁts each year to make
up any deﬁcit of cumulative dividend on the BP preference shares.
– A general reserve out of the balance of proﬁts each year, which shall

be applicable for any purpose to which the proﬁts of the company may
properly be applied. This may include capitalization of such sum,
pursuant to an ordinary shareholders’ resolution, and distribution to
shareholders as if it were distributed by way of a dividend on the
ordinary shares or in paying up in full unissued ordinary shares for
allotment and distribution as bonus shares.

Any such sums so deposited may be distributed in accordance with the
manner of distribution of dividends as described above.

Holders of shares are not subject to calls on capital by the company,
provided that the amounts required to be paid on issue have been paid
off. All shares are fully paid.

Voting rights
The Articles of Association of BP 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.

BP Annual Report and Accounts 2006

87

Record holders of BP ADSs also are 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 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 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 at which it is proposed to put a special or ordinary
resolution requires 21 days’ notice. An extraordinary resolution put to the
AGM requires no notice period. Any extraordinary general meeting at
which it is proposed to put a special resolution requires 21 days’ notice;
otherwise, the notice period for an extraordinary general meeting is
14 days.

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 upon 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 15 months after the preceding AGM. All other general meetings of
shareholders shall be called extraordinary general meetings and 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 BP’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 BP’s

Articles of Association, restricting the right of non-resident or foreign
owners to hold or vote BP ordinary or preference shares in the company.

Taxation

This section describes the material US federal income tax and UK taxation
consequences of owning ordinary shares or ADSs to a US holder who
holds the ordinary shares or ADSs as capital assets for tax purposes.
It does not apply, however, to members of special classes of holders
subject to special rules and holders that, directly or indirectly, hold 10%
or more of the company’s voting stock.

A US holder is any beneﬁcial owner of ordinary shares or ADSs that
is for US federal income tax purposes (i) a citizen or resident of the US,
(ii) a US domestic corporation, (iii) an estate whose income is subject to
US federal income taxation regardless of its source, or (iv) a trust if a
US court can exercise primary supervision over the trust’s administration
and one or more US persons are authorized to control all substantial
decisions of the trust.

This section is based on the Internal Revenue Code of 1986, as
amended, its legislative history, existing and proposed regulations
thereunder, published rulings and court decisions, and the taxation laws
of the UK, all as currently in effect, as well as the income tax convention
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.

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.

This section is further based in part upon 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.
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.

88

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 United
Kingdom generally will not be taxable on a dividend it receives from the
company. A shareholder who is an individual resident for tax purposes
in the United Kingdom is entitled to a tax credit on cash dividends paid
on ordinary shares or ADSs of the company equal to one-ninth of the
cash dividend.

US federal income taxation
A US holder is subject to US federal income taxation on the gross amount
of any dividend paid by the company out of its current or accumulated
earnings and proﬁts (as determined for US federal income tax purposes).
Dividends paid to a non-corporate US holder in taxable years beginning
before 1 January 2011 that constitute qualiﬁed dividend income will be
taxable to the holder at a maximum tax rate of 15%, provided that the
holder has a holding period in the ordinary shares or ADSs of more than
60 days during the 121-day period beginning 60 days before the ex-
dividend date and meets other holding period requirements. Dividends
paid by the company with respect to the shares or ADSs will generally
be qualiﬁed dividend income.

As noted above in UK taxation, a US holder will not be subject to UK
withholding tax. A US holder will include in gross income for US federal
income tax purposes the amount of the dividend actually received from
the company and the receipt of a dividend will not entitle the US holder
to a foreign tax credit.

For US federal income tax purposes, a dividend must be included in

income when the US holder, in the case of ordinary shares, or the
Depositary, in the case of ADSs, actually or constructively receives the
dividend, and will not be eligible for the dividends-received deduction
generally allowed to US corporations in respect of dividends received
from other US corporations. Dividends will be income from sources
outside the US, and generally will be ‘passive income’ or, in the case of
certain US holders, ‘ﬁnancial services income’ (or, for tax years beginning
after 31 December 2006, ‘general category income’), which is treated
separately from other types of income for purposes of computing the
allowable foreign tax credit.

The amount of the dividend distribution on the ordinary shares or ADSs

that is paid in pounds sterling will be the US dollar value of the pounds
sterling payments made, determined at the spot pounds sterling/US
dollar rate on the date the dividend distribution is includible in income,
regardless of whether the payment is in fact converted into US dollars.
Generally, any gain or loss resulting from currency exchange ﬂuctuations
during the period from the date the pounds sterling dividend payment is
includible in income to the date the payment is converted into US
dollars will be treated as ordinary income or loss. The gain or loss
generally will be income or loss from sources within the US for foreign tax
credit limitation purposes.

Distributions in excess of the company’s earnings and proﬁts, as
determined for US federal income tax purposes, will be treated as a
return of capital to the extent of the US holder’s basis in the ordinary
shares or ADSs and thereafter as capital gain, subject to taxation as
described in Taxation of capital gains – US federal income taxation.

Taxation of capital gains
UK taxation
A US holder may be liable for both UK and US tax in respect of a gain on
the disposal of ordinary shares or ADSs if the US holder is (i) a citizen of
the US resident or ordinarily resident in the UK, (ii) a US domestic
corporation resident in the UK by reason of its business being managed or
controlled in the UK or (iii) a citizen of the US or a corporation that carries
on a trade or profession or vocation in the UK through a branch or agency
or, in respect of corporations for accounting periods beginning on or after
1 January 2003, through a permanent establishment, and that have used,
held, or acquired the ordinary shares or ADSs for the purposes of such
trade, profession or vocation of such branch, agency or permanent
establishment. However, such persons may be entitled to a tax credit
against their US federal income tax liability for the amount of UK capital

gains tax or UK corporation tax on chargeable gains (as the case may be)
which is paid in respect of such gain.

Under the Treaty, capital gains on dispositions of ordinary shares or
ADSs generally will be subject to tax only in the jurisdiction of residence
of the relevant holder as determined under both the laws of the UK and
the US and as required by the terms of the Treaty.

Under the Treaty, individuals who are residents of either the UK or the
US and who have been residents of the other jurisdiction (the US or the
UK, as the case may be) at any time during the six years immediately
preceding the relevant disposal of ordinary shares or ADSs may be
subject to tax with respect to capital gains arising from a disposition of
ordinary shares or ADSs of the company not only in the jurisdiction of
which the holder is resident at the time of the disposition but also in the
other jurisdiction.

US federal income taxation
A US holder that sells or otherwise disposes of ordinary shares or ADSs
will recognize a capital gain or loss for US federal income tax purposes
equal to the difference between the US dollar value of the amount
realized and the holder’s tax basis, determined in US dollars, in the
ordinary shares or ADSs. Capital gain of a non-corporate US holder
that is recognized in taxable years beginning before 1 January 2011 is
generally taxed at a maximum rate of 15% if the holder’s holding period
for such ordinary shares or ADSs exceeds one year. The gain or loss
will generally be income or loss from sources within the US for foreign
tax credit limitation purposes. The deductibility of capital losses is
subject to limitations.

Additional tax considerations
UK inheritance tax
The Estate Tax Convention applies to inheritance tax. ADSs held by an
individual who is domiciled for the purposes of the Estate Tax Convention
in the US and is not for the purposes of the Estate Tax Convention a
national of the UK will not be subject to UK inheritance tax on the
individual’s death or on transfer during the individual’s lifetime unless,
among other things, the ADSs are part of the business property of a
permanent establishment situated in the UK used for the performance of
independent personal services. In the exceptional case where ADSs are
subject both to inheritance tax and to US federal gift or estate tax, the
Estate Tax Convention generally provides for tax payable in the US to
be credited against tax payable in the UK or for tax paid in the UK to be
credited against tax payable in the US, based on priority rules set forth
in the Estate Tax Convention.

UK stamp duty and stamp duty reserve tax
The statements below relate to what is understood to be the current
practice of the UK Inland Revenue under existing law.

Provided that the 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
50 pence per £100 (or part), 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.

A transfer of the underlying ordinary shares to an ADR holder on

cancellation of the ADSs without transfer of beneﬁcial ownership will give
rise to UK stamp duty at the rate of £5 per transfer.

BP Annual Report and Accounts 2006

89

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. Current UK Inland Revenue practice is to calculate the
issue price by reference to the total cash receipt (i.e., cash dividend plus
the Refund if any) 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 available online at www.bp.com.
Shareholders have the ability to receive 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 e-mail request addressed
to bpdistributionservices@bp.com, or BP’s US Shareholder Services ofﬁce
in Warrenville, Illinois at 1 800 638 5672 or through an e-mail request
addressed to shareholderus@bp.com.

The company is subject to the information requirements of the US
Securities and 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. Please 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 web site at www.sec.gov.

Details of some of BP’s other publications are listed on the inside back

cover.

Purchases of equity securities by the issuer and afﬁliated purchasers

The following table provides details of ordinary shares repurchased.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Total number of shares

purchaseda c

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 programmeb

2006
January
February
March
April
May
June
July
August
September
October
November
December
2007
January
February (through 20 February)

2006
January
February
March
April
May
June
July
August
September
October
November
December
2007
January
February (through 20 February)

70,000,000
139,785,200
139,294,200
107,608,638
149,312,153
118,823,000
159,261,259
91,904,300
47,989,000
171,740,000
113,255,000
25,390,000

73,361,264
61,797,871

11.67
11.41
11.41
12.22
12.33
11.31
11.82
11.87
10.95
11.15
11.28
11.42

10.80
10.55

70,000,000
139,785,200
139,294,200
107,608,638
149,312,153
118,823,000
159,261,259
91,904,300
47,989,000
171,740,000
113,255,000
25,390,000

73,361,264
61,797,871

41,068
1,638,669
6,198,758
–
13,829
10,001,371
–
–
13,606
10,231
–
–

71,643
1,700,000

11.24
11.33
11.47
–
12.11
10.70
–
–
11.15
11.00
–
–

10.93
11.46

a All share purchases were open market transactions.
b At the AGM on 20 April 2006, authorization was given to repurchase up to 2 billion ordinary shares in the period to the next AGM or 19 July 2007, the latest date by which an
AGM must be held. This authorization is renewed annually at the AGM.
c Made up of 493,533,135 shares repurchased for cancellation and 975,988,750 shares held in treasury.

The following table provides details of share purchases made by ESOP trusts.

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------------------------------------------

Total number of shares
purchased

Average price paid
per share

$

Total number of shares
purchased as part of publicly
announced programmesa

Maximum number of shares
that may yet be purchased
under the programmea

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.

90

Annual general meeting

Administration

The 2007 annual general meeting will be held on Thursday 12 April 2007
at 11.30 a.m. at ExCeL London, One Western Gateway, Royal Victoria
Dock, London E16 1XL. A separate notice convening the meeting is sent
to shareholders with this Report, together with an explanation of the
items of special business to be considered at the meeting.

All resolutions of which notice has been given will be decided on

a poll.

Ernst & Young LLP have expressed their willingness to continue in
ofﬁce as auditors and a resolution for their reappointment is included in
Notice of BP Annual General Meeting 2007.

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, please contact the
Registrar or ADS Depositary.

To elect to receive the Directors’ Report and Annual Accounts in place
of summary ﬁnancial statements for all future ﬁnancial years, please write
to the Registrar.

To elect to receive your company documents (such as the Annual

Report and Accounts, Annual Review and Notice of Meeting)
electronically, please register at www.bp.com/edelivery.

By order of the board
David J Jackson
Secretary
23 February 2007

UK – Registrar’s Ofﬁce
The BP Registrar, Lloyds TSB Registrars
The Causeway, Worthing, West Sussex BN99 6DA
Telephone: +44 (0)121 415 7005; Freephone in UK: 0800 701107
Textphone: 0870 600 3950; Fax: +44 (0)1903 833371

US – ADS Administration
JPMorgan Chase Bank
PO Box 3408, South Hackensack, NJ 07606-3408
Telephone: +1 201 680 6630
Toll-free in US and Canada: +1 877 638 5672

BP Annual Report and Accounts 2006

91

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92

Financial statements contents

Consolidated ﬁnancial statements of the BP group
Statement of directors’ responsibilities in respect

of the consolidated ﬁnancial statements

Independent auditor’s report

Group income statement
Group balance sheet

Group cash ﬂow statement

Group statement of recognized income and expense

Notes on ﬁnancial statements
1 Signiﬁcant accounting policies
2 Resegmentation and other changes to comparatives
3 Oil and natural gas reserves estimates

4 Acquisitions

5 Non-current assets held for sale and discontinued operations

6 Disposals

7 Segmental analysis

8 Earnings from jointly controlled entities and associates

9 Interest and other revenues

10 Gains on sale of businesses and ﬁxed assets
11 Production and similar taxes

12 Depreciation, depletion and amortization

13 Impairment and losses on sale of businesses and ﬁxed assets

14 Impairment of goodwill

15 Distribution and administration expenses

16 Currency exchange gains and losses

17 Research

18 Operating leases
19 Exploration for and evaluation of oil and natural gas resources

20 Auditors’ remuneration

21 Finance costs

22 Other ﬁnance income and expense

23 Taxation

24 Dividends

25 Earnings per ordinary share

26 Property, plant and equipment
27 Goodwill

28 Intangible assets

29 Investments in jointly controlled entities

30 Investments in associates

31 Other investments

32 Inventories

33 Trade and other receivables

34 Cash and cash equivalents
35 Trade and other payables

36 Derivative ﬁnancial instruments

37 Derivative ﬁnancial instruments (UK GAAP)

38 Finance debt

94

95

96
97

98

99

100

109

110

111

111

112

113

120

120

121

121

122

123

124

126

126

127

127

128

128

129

129

130

132

133

134

135

135

136

137

138

138

139

139

140

141

148

149

39 Analysis of changes in net debt

40 Provisions
41 Pensions and other post-retirement beneﬁts

42 Called up share capital

43 Capital and reserves

44 Share-based payments

45 Employee costs and numbers

46 Remuneration of directors and key management

47 Contingent liabilities

48 Capital commitments
49 First-time adoption of International Financial Reporting Standards

50 Subsidiaries, jointly controlled entities and associates

51 Oil and natural gas exploration and production activities

Additional information for US reporting
52 Suspended exploration well costs

53 US GAAP reconciliation
54 Auditors’ remuneration for US reporting

55 Summarized ﬁnancial information on jointly controlled entities

and associates

56 Valuation and qualifying accounts

57 Computation of ratio of earnings to ﬁxed charges

Supplementary information on oil and natural gas

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

Company balance sheet

Company cash ﬂow statement

Statement of total recognized gains and losses
Notes on ﬁnancial statements

1 Accounting policies
2 Taxation

3 Fixed assets – investments

4 Debtors

5 Creditors

6 Pensions

7 Called up share capital
8 Capital and reserves

9 Cash ﬂow

10 Contingent liabilities

11 Share-based payments

12 Auditors’ remuneration

13 Directors’ remuneration

151

152

152

158

160

163

166

167

168

168

168

171

173

176

179

194

195

195

195

196

205

206

207

208

208

209

210

211

211

211

212

214

215

215

216

216

220

220

BP Annual Report and Accounts 2006

93

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 UK law and those
International Financial Reporting Standards (IFRS) adopted by the EU.

The directors are required to prepare ﬁnancial statements for each ﬁnancial year which present fairly the ﬁnancial position of the group and the

ﬁnancial performance and cash ﬂows of the group for that period. In preparing those ﬁnancial statements, the directors are required to:
– Select suitable accounting policies and then apply them consistently.
– Present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information.
– Provide additional disclosure when compliance with the speciﬁc requirements of IFRS is insufﬁcient to enable users to understand the impact of

particular transactions, other events and conditions on the group’s ﬁnancial position and ﬁnancial performance.

– State that the company has complied with IFRS, subject to any material departures disclosed and explained in the ﬁnancial statements.

The directors are responsible for keeping proper accounting records which disclose with reasonable accuracy at any time the ﬁnancial position of the
group and enable them to ensure that the ﬁnancial statements comply with the Companies Act 1985 and Article 4 of the IAS Regulation. They are also
responsible for safeguarding the assets of the group and hence for taking reasonable steps for the prevention and detection of fraud and other
irregularities.

The directors conﬁrm that they have complied with these requirements and, having a reasonable expectation that the group has adequate resources

to continue in operational existence for the foreseeable future, continue to adopt the going concern basis in preparing the ﬁnancial statements.

Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as deﬁned by Section 234ZA of the

Companies Act 1985) of which the group’s auditors are unaware, and the directors have taken all the steps they ought to have taken to make
themselves aware of any relevant audit information and to establish that the group’s auditors are aware of that information.

94

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 2006 which comprise the group income statement,
the group balance sheet, the group cash ﬂow statement, the group statement of recognized income and expense and the related notes 1 to 51. These
consolidated ﬁnancial statements have been prepared under the accounting policies set out therein.

We have reported separately on the parent company ﬁnancial statements of BP p.l.c. for the year ended 31 December 2006 and on the information in

the Directors’ Remuneration Report that is described as having been audited.

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

Respective responsibilities of directors and auditors
The directors are responsible for preparing the Annual Report and the consolidated ﬁnancial statements in accordance with applicable United Kingdom
law and International Financial Reporting Standards (IFRS) as adopted by the European Union as set out in the Statement of directors’ responsibilities in
respect of the consolidated ﬁnancial statements.

Our responsibility is to audit the consolidated ﬁnancial statements in accordance with relevant legal and regulatory requirements and International

Standards on Auditing (UK and Ireland).

We report to you our opinion as to whether the consolidated ﬁnancial statements give a true and fair view and whether the consolidated ﬁnancial

statements have been properly prepared in accordance with the Companies Act 1985 and Article 4 of the IAS Regulation. We also report to you
whether in our opinion the information given in the directors’ report, including the business review, is consistent with the ﬁnancial statements.

In addition we report to you if, in our opinion, we have not received all the information and explanations we require for our audit, or if information

speciﬁed by law regarding directors’ remuneration and other transactions is not disclosed.

We review whether the governance board performance report reﬂects the company’s compliance with the nine provisions of the 2006 Combined
Code Principles of Good Governance and Code of Best Practice speciﬁed for our review by the Listing Rules of the Financial Services Authority, and we
report if it does not. We are not required to consider whether the board’s statements on internal control cover all risks and controls, or form an opinion
on the effectiveness of the group’s corporate governance procedures or its risk and control procedures.

We read other information contained in the Annual Report and consider whether it is consistent with the audited consolidated ﬁnancial statements.
The other information comprises the Additional information for US reporting, the Supplementary information on oil and natural gas, the Directors’ Report
and the Governance: Board performance report. We consider the implications for our report if we become aware of any apparent misstatements or
material inconsistencies with the consolidated ﬁnancial statements. Our responsibilities do not extend to any other information.

Basis of audit opinion
We conducted our audit in accordance with International Standards on Auditing (UK and Ireland) issued by the Auditing Practices Board. An audit
includes examination, on a test basis, of evidence relevant to the amounts and disclosures in the consolidated ﬁnancial statements. It also includes an
assessment of the signiﬁcant estimates and judgements made by the directors in the preparation of the consolidated ﬁnancial statements, and of
whether the accounting policies are appropriate to the group’s circumstances, consistently applied and adequately disclosed.

We planned and performed our audit so as to obtain all the information and explanations which we considered necessary in order to provide us with

sufﬁcient evidence to give reasonable assurance that the consolidated ﬁnancial statements are free from material misstatement, whether caused by
fraud or other irregularity or error. In forming our opinion we also evaluated the overall adequacy of the presentation of information in the consolidated
ﬁnancial statements.

Opinion
In our opinion:
– The consolidated ﬁnancial statements give a true and fair view, in accordance with IFRS as adopted by the European Union, of the state of the

group’s affairs as at 31 December 2006 and of its proﬁt for the year then ended.

– The group ﬁnancial statements have been properly prepared in accordance with the Companies Act 1985 and Article 4 of the IAS Regulation.
– The information given in the directors’ report is consistent with the consolidated ﬁnancial statements.

Separate opinion in relation to IFRS
As explained in Note 1 to the consolidated ﬁnancial statements, the group, in addition to complying with its legal obligation to comply with IFRS as
adopted by the European Union, has also complied with IFRS as issued by the International Accounting Standards Board.

In our opinion the consolidated ﬁnancial statements give a true and fair view, in accordance with IFRS, of the state of the group’s affairs as at 31

December 2006 and of its proﬁt for the year then ended.

Ernst & Young LLP
Registered auditor
London
23 February 2007

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 occured to the ﬁnancial statements
since they were initially presented on the website or any other website they are presented on.

Legislation in the United Kingdom governing the preparation and dissemination of ﬁnancial statements may differ from legislation in other

jurisdictions.

BP Annual Report and Accounts 2006

95

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Note

2006

2005

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

7
8
8
9

10

11
12
13
19
15
36

21
22

23

5

265,906
3,553
442
701

270,602
3,714

274,316
187,183
23,793
3,621
9,128
549
1,045
14,447
(608)

35,158
718
(202)

34,642
12,331

22,311
(25)

22,286

22,000
286

239,792
3,083
460
613
243,948
1,538
245,486
163,026
21,092
3,010
8,771
468
684
13,706
2,047
32,682
616
145
31,921
9,473
22,448
184
22,632

22,341
291
22,632

$ million

192,024
1,818
462
615
194,919
1,685
196,604
128,055
17,330
2,149
8,529
1,390
637
12,768
–
25,746
440
340
24,966
7,082
17,884
(622)
17,262

17,075
187
17,262

25
25

109.84
109.00

105.74
104.52

78.24
76.87

Group income statement

For the year ended 31 December

Sales and other operating revenues
Earnings from jointly controlled entities – after interest and tax
Earnings from associates – after interest and tax
Interest and other revenues
Total revenues
Gains on sale of businesses and ﬁxed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and ﬁxed assets
Exploration expense
Distribution and administration expenses
Fair value (gain) loss on embedded derivatives
Proﬁt before interest and taxation from continuing operations
Finance costs
Other ﬁnance (income) expense
Proﬁt before taxation from continuing operations
Taxation
Proﬁt from continuing operations
Proﬁt (loss) from Innovene operations
Proﬁt for the year
Attributable to

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BP shareholders
Minority interest

Basic
Diluted

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Earnings per share – cents
Proﬁt for the year attributable to BP shareholders

22,286

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt from continuing operations attributable to BP shareholders

Basic
Diluted

109.97
109.12

104.87
103.66

81.09
79.66

96

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Note

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Current assets

142,262

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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 and accrued income
Deﬁned beneﬁt pension plan surplus

Loans
Inventories
Trade and other receivables
Derivative ﬁnancial instruments
Prepayments and accrued income
Current tax receivable
Cash and cash equivalents

Assets classiﬁed as held for sale

Total assets
Current liabilities

Trade and other payables
Derivative ﬁnancial instruments
Accruals and deferred income
Finance debt
Current tax payable
Provisions

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Liabilities directly associated with the assets classiﬁed as held for sale

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Non-current liabilities
Other payables
Derivative ﬁnancial instruments
Accruals and deferred income
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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Peter Sutherland Chairman
The Lord Browne of Madingley Group Chief Executive

BP Annual Report and Accounts 2006

97

$ million

2005

85,947
10,371
4,772
13,556
6,217
967
121,830
821
770
3,909
1,012
3,282
131,624

132
19,760
40,902
10,056
1,268
212
2,960
75,290
–
75,290
206,914

42,136
10,036
5,017
8,932
4,274
1,102
71,497
–
71,497

1,935
5,871
989
10,230
16,443
9,954
9,230
54,652
126,149
80,765

5,185
74,791
79,976
789
80,765

26
27
28
29
30
31

33
36

41

32
33
36

34

5

35
36

38

40

5

35
36

38
23
40
41

42

43
43
43

90,999
10,780
5,246
15,074
5,975
1,697

129,771
817
862
3,025
1,034
6,753

141
18,915
38,692
10,373
3,006
544
2,590

74,261
1,078

75,339

217,601

42,236
9,424
6,147
12,924
2,635
1,932

75,298
54

75,352

1,430
4,203
961
11,086
18,116
11,712
9,276

56,784

132,136

85,465

5,385
79,239

84,624
841

85,465

Group cash ﬂow statement

For the year ended 31 December

Operating activities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Note

2006

2005

2004

Proﬁt before taxation from continuing operations

Adjustments to reconcile proﬁt before taxation to net cash provided by operating activities

34,642

31,921

24,966

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
Other ﬁnance (income) expense
Share-based payments
Net operating charge for pensions and other post-retirement beneﬁts, less contributions
Net charge for provisions, less payments
(Increase) decrease in inventories
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Income taxes paid

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Net cash provided by operating activities of continuing operations
Net cash provided by (used in) operating activities of Innovene operations
Net cash provided by operating activities
Investing activities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Capital expenditures
Acquisitions, net of cash acquired
Investment in jointly controlled entities
Investment in associates
Proceeds from disposal of ﬁxed assets
Proceeds from disposal of businesses
Proceeds from loan repayments
Other

Net cash used in investing activities
Financing activities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Net repurchase of shares
Proceeds from long-term ﬁnancing
Repayments of long-term ﬁnancing
Net increase (decrease) in short-term debt
Dividends paid

(15,151)
3,831
(3,655)
3,873

(11,315)
2,475
(4,820)
(1,457)

(7,208)
2,675
(2,204)
(24)

BP shareholders
Minority interest

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Net cash used in ﬁnancing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(7,686)
(283)

(19,071)

47

(370)
2,960

2,590

(7,359)
(827)
(23,303)
(88)
1,601
1,359
2,960

(6,041)
(33)
(12,835)
91
(697)
2,056
1,359

$ million

274
8,529
(295)
(2,280)
2,199
(284)
331
440
(698)
340
224
(84)
(110)
(3,182)
(10,225)
10,290
(6,388)
24,047
(669)
23,378

(12,286)
(1,503)
(1,648)
(942)
4,236
725
87
–
(11,331)

624
9,128
(3,165)
(3,995)
4,495
(473)
500
718
(1,242)
(202)
416
(261)
340
995
3,596
(4,211)
(13,733)

28,172
–

28,172

(15,125)
(229)
(37)
(570)
5,963
291
189
–

(9,518)

305
8,771
(1,070)
(3,543)
2,833
(479)
401
616
(1,127)
145
278
(435)
600
(6,638)
(16,427)
18,628
(9,028)
25,751
970
26,721

(12,281)
(60)
(185)
(619)
2,803
8,397
123
93
(1,729)

19
12
10, 13
8

21

22

5

6
6

24

98

Group statement of recognized income and expense

For the year ended 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Note

2006

2005

2004

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Currency translation differences
Exchange gain on translation of foreign operations transferred to gain or loss on sale of businesses

and ﬁxed assets

Actuarial 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
Unrealized gain on acquisition of further investment in equity-accounted investments
Tax on currency translation differences
Tax on exchange gain on translation of foreign operations transferred to gain or loss on sale of

businesses and ﬁxed assets

Tax on actuarial gain relating to pensions and other post-retirement beneﬁts
Tax on available-for-sale investments
Tax on cash ﬂow hedges
Tax on share-based payments
Net income (expense) recognized directly in equity
Proﬁt for the year
Total recognized income and expense for the year
Attributable to

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BP shareholders
Minority interest

BP shareholders
Minority interest

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Effect of change in accounting policy – adoption of IAS 32 and IAS 39 on 1 January 2005

26,172

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2,025

(2,502)

2,283

–
2,615
561
(695)
413
(93)
(6)
–
(201)

(315)
975
322
(60)
(212)
36
–
–
11

(78)
107
–
–
–
–
–
94
(208)

–
(820)
108
(47)
26

3,886
22,286

26,172

25,837
335

95
(356)
(72)
63
–
(2,015)
22,632
20,617

20,326
291
20,617

(243)
–
(243)

–
96
–
–
39
2,333
17,262
19,595

19,408
187
19,595

–
–
–

–
–

49

–

BP Annual Report and Accounts 2006

99

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 2006 were authorized for issue by the board of directors on
23 February 2007 and the balance sheet was signed on the board’s behalf by Peter Sutherland and The Lord Browne of Madingley. BP p.l.c. is a public
limited company incorporated and domiciled in England and Wales. The company’s ordinary shares are traded on the London Stock Exchange. The
consolidated ﬁnancial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European
Union (EU) and in accordance with the provisions of the Companies Act 1985. IFRS as adopted by the EU differs in certain respects from IFRS as issued
by the International Accounting Standards Board (IASB). However, the consolidated ﬁnancial statements for the years presented would be no different
had the group applied IFRS as issued by the IASB. 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 2006, or issued and early adopted.

In preparing the consolidated ﬁnancial statements for the current year, the group has adopted the following amendments to IFRS and IFRIC

interpretations:
– Amendment to IAS 21 ‘The Effects of Changes in Foreign Exchange Rates’ – ‘Net Investment in a Foreign Operation’.
– Amendment to IAS 39 ‘Financial Instruments: Recognition and Measurement’ – ‘The Fair Value Option’.
– Amendments to IAS 39 ‘Financial Instruments: Recognition and Measurement’ and IFRS 4 ‘Insurance Contracts’ – ‘Financial Guarantee Contracts’.
– IFRIC 5 ‘Rights to Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds’.
– IFRIC 6 ‘Liabilities Arising from Participating in a Speciﬁc Market – Waste Electrical and Electronic Equipment’.
– IFRIC 7 ‘Applying IAS 29 for the First Time’.
– IFRIC 8 ‘Scope of IFRS 2 – Share-based payment’.
– IFRIC 9 ‘Reassessment of embedded derivatives’.

Further information regarding the impact of adoption is given below.
The accounting policies that follow have been consistently applied to all years presented with the exception of those relating to ﬁnancial instruments
under IAS 32 ‘Financial Instruments: Disclosure and Presentation’ (IAS 32) and IAS 39 ‘Financial Instruments: Recognition and Measurement’ (IAS 39)
which have been applied with effect from 1 January 2005. For the year ended 31 December 2004 ﬁnancial instruments have been accounted for in
accordance with the group’s previous accounting policies under UK generally accepted accounting practice (UK GAAP). For further information see
Note 49.

The consolidated ﬁnancial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where

otherwise indicated.

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 and is presented
separately within equity in the consolidated balance sheet.

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. The group income
statement reﬂects the group’s share of the results after tax of the jointly controlled entity. The group statement of recognized income and expense
reﬂects the group’s share of any income and expense recognized by the jointly controlled entity outside proﬁt and loss.

Financial statements of jointly controlled entities are prepared for the same reporting year as the group. Where necessary, adjustments are made to

those ﬁnancial statements to bring the accounting policies used into line with those of the group.

Unrealized gains on transactions between the group and its jointly controlled entities are eliminated to the extent of the group’s interest in the jointly

controlled entities. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.

The group assesses at each balance sheet date whether an investment in a jointly controlled entity is impaired. If there is objective evidence that an

impairment loss has been incurred, 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 over, or signiﬁcant inﬂuence in the

joint venture, or when the interest becomes held for sale.

Certain of the group’s activities, particularly in the Exploration and Production segment, are conducted through joint ventures where the venturers
have a direct ownership interest in and jointly control the assets of the venture. The income, expenses, assets and liabilities of these jointly controlled
assets are included in the consolidated ﬁnancial statements in proportion to the group’s interest.

100

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 a company operates and is normally the currency in which the
company 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 translated into the functional currency at the rate of
exchange ruling at the balance sheet date. Any resulting exchange differences are included in the income statement. Non-monetary assets and liabilities
that are measured in terms of historical cost in a foreign currency are translated into the functional currency using the rates of exchange as at the dates
of the initial transactions. Non-monetary assets and liabilities measured at fair value in a foreign currency are translated into the functional currency using
the rate of exchange at the date the fair value was determined.

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 recognized
income and expense. Exchange gains and losses arising on long-term intragroup foreign currency borrowings used to ﬁnance the group’s non-US dollar
investments are also taken to equity. On disposal of a non-US dollar functional currency subsidiary, jointly controlled entity or associate, the deferred
cumulative amount recognized in equity relating to that particular non-US dollar operation is recognized in the income statement.

Business combinations and goodwill
Business combinations are accounted for using the acquisition method of accounting. The cost of an acquisition is measured as the cash paid and the
fair value of other assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange, plus costs directly attributable to
the acquisition. The acquired identiﬁable assets, liabilities and contingent liabilities are measured at their fair values at the date of acquisition. Any excess
of the cost of acquisition over the net fair value of the identiﬁable assets, liabilities and contingent liabilities acquired is recognized as goodwill. Any
deﬁciency of the cost of acquisition below the fair values of the identiﬁable net assets acquired (i.e. discount on acquisition) is credited to the income
statement in the period of acquisition. Where the group does not acquire 100% ownership of the acquired company, the interest of minority
shareholders is stated at the minority’s proportion of the fair values of the assets and liabilities recognized. Subsequently, any losses applicable to the
minority shareholders in excess of the minority interest are allocated against the interests of the parent.

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.

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. Impairment is determined by assessing the recoverable amount
of the cash-generating unit to which the goodwill relates. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an
impairment loss is recognized.

Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous UK GAAP carrying amount.
Goodwill may also arise upon investments in jointly controlled entities and associates, being the surplus of the cost of investment over the group’s
share of the net fair value of the identiﬁable assets. Such goodwill is recorded within investments in jointly controlled entities and associates, and any
impairment of the goodwill is included within the earnings from jointly controlled entities and associates.

Non-current assets held for sale
Non-current assets and disposal groups classiﬁed as held for sale are measured at the lower of carrying amount and fair value less costs to sell.

Non-current assets and disposal groups are classiﬁed as held for sale if their carrying amounts will be recovered through a sale transaction rather than

through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for
immediate sale in its present condition. Management must be committed to the sale, which should be expected to qualify for recognition as a
completed sale within one year from the date of classiﬁcation.

Property, plant and equipment and intangible assets once classiﬁed as held for sale are not depreciated.

Intangible assets
Intangible assets are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses. Intangible assets
include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software, patents, licences and trademarks.

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 recognized separately from goodwill if
the asset is separable or arises from contractual or other legal rights and its fair value can be measured reliably.

Intangible assets with a ﬁnite life are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks,

expected useful life is the shorter of the duration of the legal agreement and economic useful life, which can range from three to 15 years. Computer
software costs have a useful life of three to ﬁve years.

The expected useful lives of assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
The carrying value of intangible assets is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not

be recoverable.

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

BP Annual Report and Accounts 2006

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1 Signiﬁcant accounting policies continued

Licence and property acquisition costs
Exploration and property leasehold acquisition costs are capitalized within intangible ﬁxed assets and amortized on a straight-line basis over the
estimated period of exploration. Each property is reviewed on an annual basis to conﬁrm that drilling activity is planned and it is not impaired. If no future
activity is planned, the remaining balance of the licence and property acquisition costs is written off. Upon determination of economically recoverable
reserves (‘proved reserves’ or ‘commercial reserves’), amortization ceases and the remaining costs are aggregated with exploration expenditure and
held on a ﬁeld-by-ﬁeld basis as proved properties awaiting approval within other intangible assets. When development is approved internally, the
relevant expenditure is transferred to property, plant and equipment.

Exploration expenditure
Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are capitalized
as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee remuneration,
materials and fuel used, rig costs, delay rentals and payments made to contractors. If hydrocarbons are not found, the exploration expenditure is written
off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, which may include the drilling of further wells (exploration or
exploratory-type stratigraphic test wells), are likely to be capable of commercial development, the costs continue to be carried as an asset. All such
carried costs are subject to technical, commercial and management review at least once a year to conﬁrm the continued intent to develop or otherwise
extract value from the discovery. When this is no longer the case, the costs are written off. When proved reserves of oil and natural gas are determined
and development is sanctioned, the relevant expenditure is transferred to property, plant and equipment.

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

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 the fair value of the asset given up unless the exchange transaction lacks commercial substance or the fair

value of neither the asset received nor the asset given up is reliably measurable.

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 and is now written off is replaced and it is probable that future economic beneﬁts
associated with the item will ﬂow to the group, the expenditure is capitalized. 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, decommissioning and ﬁeld development 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 sanctioned future
development expenditure.

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 40 years
20 to 30 years
20 to 30 years
10 to 50 years
15 years
3 to 7 years
5 to 15 years

The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted

for prospectively.

The carrying value of property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate the carrying

value may not be recoverable.

An item of property, plant and equipment is derecognized upon disposal or when no future economic beneﬁts are expected to arise from the

continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and
the carrying amount of the item) is included in the income statement in the period the item is derecognized.

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. 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. If any such indication of impairment exists, the group makes an
estimate of its recoverable amount. 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.

102

1 Signiﬁcant accounting policies continued

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. When ﬁnancial assets are recognized initially, they are measured at fair value, normally being the transaction price plus, in
the case ﬁnancial assets not at fair value through proﬁt or loss, directly attributable transaction costs. As explained in Note 49, the group has not
restated comparative amounts on ﬁrst applying IAS 32 and IAS 39, as permitted in IFRS 1 ‘First-time Adoption of International Financial Reporting
Standards’.

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.

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 being recognized as a separate component of equity until the
investment is derecognized or until the investment is determined to be impaired, at which time the cumulative gain or loss previously reported in equity
is included in the income statement.

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. These include using recent arm’s-length market transactions; reference to the current
market value of another instrument which is substantially the same; discounted cash ﬂow analysis; and pricing models. Where fair value cannot be
reliably estimated, assets are carried at cost.

Financial assets at fair value through proﬁt or loss
Derivatives, other than those designated as 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 are described below in the
accounting policy for Derivative ﬁnancial instruments.

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 administration costs.

Available-for-sale ﬁnancial assets
If an available-for-sale ﬁnancial asset is impaired, an amount comprising the difference between its cost (net of any principal payment and amortization)
and its fair value is transferred from equity to the income statement.

If there is objective evidence that an impairment loss on an unquoted equity instrument that is not carried at fair value because its fair value cannot be

reliably measured, or on a derivative asset that is linked to and must be settled by delivery of such an unquoted equity instrument, 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.

Financial assets are derecognized on sale or settlement.

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.

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.

Trade and other receivables
Trade and other receivables are carried at the original invoice amount, less allowances made for doubtful receivables. Where the time value of money is
material, receivables are carried at amortized cost. Provision is made when there is objective evidence that the group will be unable to recover balances
in full. Balances are written off when the probability of recovery is assessed as being remote.

BP Annual Report and Accounts 2006

103

1 Signiﬁcant accounting policies continued

Cash and cash equivalents
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; and short-term highly liquid investments that are
readily convertible to known amounts of cash, are subject to insigniﬁcant risk of changes in value and have a maturity of three months or less from the
date of acquisition.

For the purpose of the group cash ﬂow statement, cash and cash equivalents consist of cash and cash equivalents as deﬁned above, net of

outstanding bank overdrafts.

Trade and other payables
Trade and other payables are carried at payment or settlement amounts. Where the time value of money is material, payables are carried at amortized
cost.

Interest-bearing loans and borrowings
All loans and borrowings are initially recognized at fair value, being the fair value of the proceeds received net of issue costs associated with the
borrowing.

After initial recognition, interest-bearing loans and borrowings 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

other ﬁnance expense.

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
inception of the lease at the fair value of the leased property or, if lower, at the present value of the minimum lease payments. Lease payments are
apportioned between the ﬁnance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the
liability. Finance charges 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.

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. From 1 January 2005, 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.

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.

For those derivatives designated as hedges and for which hedge accounting is desired, the hedging relationship is documented at its inception. This

documentation identiﬁes the hedging instrument, the hedged item or transaction, the nature of the risk being hedged and how effectiveness will be
measured throughout its duration. Such hedges are expected at inception to be highly effective.
For the purpose of hedge accounting, hedges are classiﬁed as:
– Fair value hedges when hedging the exposure to changes in the fair value of a recognized asset or liability.
– Cash ﬂow hedges when hedging exposure to variability in cash ﬂows that is either attributable to a particular risk associated with a recognized asset

or liability or a highly probable forecast transaction, including intragroup transactions.

– Hedges of the net investment in a foreign entity.

Any gains or losses arising from changes in the fair value of all other derivatives, which are classiﬁed as held for trading, are taken to the income
statement. These may arise from derivatives for which hedge accounting is not applied because they are either not designated or not effective as
hedging instruments or from derivatives that are acquired for trading purposes.

The treatment of gains and losses arising from revaluing derivatives designated as hedging instruments depends on the nature of the hedging

relationship, as follows:

Fair value hedges
For fair value hedges, the carrying amount of the hedged item is adjusted for gains and losses attributable to the risk being hedged; the derivative is
remeasured at fair value and gains and losses from both are taken to proﬁt or loss. For hedged items carried at amortized cost, the adjustment is
amortized through the income statement such that it is fully amortized by maturity. When an unrecognized ﬁrm commitment is designated as a hedged
item, this gives rise to an asset or liability in the balance sheet, representing the cumulative change in the fair value of the ﬁrm commitment attributable
to the hedged risk.

The group discontinues fair value hedge accounting if the hedging instrument expires or is sold, terminated or exercised, the hedge no longer meets

the criteria for hedge accounting or the group revokes the designation.

Cash ﬂow hedges
For cash ﬂow hedges, the effective portion of the gain or loss on the hedging instrument is recognized directly in equity, while the ineffective portion is
recognized in proﬁt or loss. Amounts taken to equity are transferred to the income statement when the hedged transaction affects proﬁt or loss. Where
the hedged item is the cost of a non-ﬁnancial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the non-
ﬁnancial asset or liability.

If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked,
amounts previously recognized in equity remain in equity until the forecast transaction occurs and are transferred to the income statement or to the
initial carrying amount of a non-ﬁnancial asset or liability as above. If a forecast transaction is no longer expected to occur, amounts previously
recognized in equity are transferred to proﬁt or loss.

104

1 Signiﬁcant accounting policies continued

Hedges of the net investment in a foreign entity
For hedges of the net investment in a foreign entity, the effective portion of the gain or loss on the hedging instrument is recognized directly in
equity, while the ineffective portion is recognized in proﬁt or loss. Amounts taken to equity are transferred to the income statement when the foreign
entity is sold.

Embedded derivatives
Derivatives embedded in other ﬁnancial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are
not closely related to those of the host contract. Contracts are assessed for embedded derivatives when the group becomes a party to them, including
at the date of a business combination. Embedded derivatives are measured at fair value at each balance sheet date. Any gains or losses arising from
changes in fair value are taken directly to proﬁt or loss.

Provisions and contingencies
Provisions are recognized when the group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outﬂow of
resources embodying economic beneﬁts will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
Where the group expects some or all of a provision to be reimbursed, for example, under an insurance contract, the reimbursement is recognized as a
separate asset, but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of
any reimbursement. 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 and, where appropriate, the risks speciﬁc to the liability. Where
discounting is used, the increase in the provision due to the passage of time is recognized as other ﬁnance expense. Any change in the amount
recognized for environmental and litigation and other provisions arising through changes in discount rates is included within other ﬁnance expense.

A contingent liability is disclosed where the existence of an obligation will only be conﬁrmed by future events or where the amount of the
obligation cannot be measured with reasonable reliability. Contingent assets are not recognized, but are disclosed where an inﬂow of economic
beneﬁts is probable.

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 environmental assessments or clean-ups are probable and the associated costs can be

reasonably estimated. Generally, the timing of these provisions coincides with the commitment to a formal plan of action or, if earlier, on divestment or
on closure of inactive sites.

The amount recognized is the best estimate of the expenditure required. Where the liability will not be settled for a number of years, the amount

recognized is the present value of the estimated future expenditure.

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 reasonable estimate of that liability can be made. Where an obligation exists for a new facility, such
as oil and natural gas production or transportation facilities, this will be on construction or installation. An obligation for decommissioning may also
crystallize during the period of operation of a facility through a change in legislation or through a decision to terminate operations. The amount
recognized is the present value of the estimated future expenditure determined in accordance with local conditions and requirements.

A corresponding item of property, plant and equipment of an amount equivalent to the provision is also created. This is subsequently depreciated as

part of the capital costs of the facility or item of plant.

Any change in the present value of the estimated expenditure is reﬂected as an adjustment to the provision and the corresponding property, plant

and equipment.

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 they are granted and is
recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award. Fair
value is determined by using an appropriate valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other
than conditions linked to the price of the shares of the company (market conditions).

No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which are

treated as vesting irrespective of whether or not the market condition is satisﬁed, provided that all other performance conditions are satisﬁed.

At each balance sheet date before vesting, the cumulative expense is calculated, representing the extent to which the vesting period has expired and

management’s best estimate of the achievement or otherwise of non-market conditions and the number of equity instruments that will ultimately vest
or, in the case of an instrument subject to a market condition, be treated as vesting as described above. The movement in cumulative expense since
the previous balance sheet date is recognized in the income statement, with a corresponding entry in equity.

Where the terms of an equity-settled award are modiﬁed or a new award is designated as replacing a cancelled or settled award, the cost based on

the original award terms continues to be recognized over the original vesting period. In addition, an expense is recognized over the remainder of the
new vesting period for the incremental fair value of any modiﬁcation, based on the difference between the fair value of the original award and the fair
value of the modiﬁed award, both as measured on the date of the modiﬁcation. No reduction is recognized if this difference is negative.

Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation and any cost not yet recognized in the income

statement for the award is expensed immediately. Any compensation paid up to the fair value of the award at the cancellation or settlement date is
deducted from equity, with any excess over fair value being treated as an expense in the income statement.

BP Annual Report and Accounts 2006

105

1 Signiﬁcant accounting policies continued

Cash-settled transactions
The cost of cash-settled transactions is measured at fair value using an appropriate option valuation model. Fair value is established initially at the grant
date and at each balance sheet date thereafter until the awards are settled. During the vesting period, a liability is recognized representing the product
of the fair value of the award and the portion of the vesting period expired as at the balance sheet date. From the end of the vesting period until
settlement, the liability represents the full fair value of the award as at the balance sheet date. Changes in the carrying amount for the liability are
recognized in proﬁt or loss for the period.

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 deﬁned beneﬁt obligation) and is based on actuarial advice. 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 scheme assets, adjusted for the effect on the fair value of plan assets of contributions received and beneﬁts paid during the year. The
difference between the expected return on plan assets and the interest cost is recognized in the income statement as other ﬁnance income or expense.

Actuarial gains and losses are recognized in full in the group statement of recognized income and expense in the period in which they occur.
The deﬁned beneﬁt pension asset or liability 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.

Corporate taxes
Income tax expense represents the sum of the tax currently payable and deferred tax.

The tax currently payable is based on the taxable proﬁts for the period. Taxable proﬁt differs from net proﬁt as reported in the income statement
because it excludes items of income or expense that are taxable or deductible in other periods and it further excludes items that are never taxable or
deductible. The group’s liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on all temporary differences at the balance sheet date between the tax bases of assets and

liabilities and their carrying amounts for ﬁnancial reporting purposes.

Deferred tax liabilities are recognized for all taxable temporary differences:

– Except where the deferred tax liability arises on goodwill that is not tax deductible or the initial recognition of an asset or liability in a transaction that

is not a business combination and, at the time of the transaction, affects neither the accounting proﬁt nor taxable proﬁt or loss.

– In respect of taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where the

timing of the reversal of the temporary differences can be controlled by the group and it is probable that the temporary differences will not reverse in
the foreseeable future.
Deferred tax assets are recognized for all deductible temporary differences, carry-forward of unused tax assets and unused tax losses, to the extent
that it is probable that taxable proﬁt will be available against which the deductible temporary differences and the carry-forward of unused tax assets and
unused tax losses can be utilized:
– Except where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in

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 only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable proﬁt will
be available against which the temporary differences can be utilized.
The carrying amount of deferred income 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:
– Where the customs duty or sales tax incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the

customs duty or sales tax is recognized as part of the cost of acquisition of the asset or as part of the expense item as applicable.

– Receivables and payables are stated with the amount of customs duty or sales tax included.

The net amount of sales tax recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the balance sheet.

Own equity instruments
The group’s holding in its own equity instruments, including ordinary shares held by Employee Share Ownership Plans (ESOPs), are classiﬁed as
‘treasury shares’, and 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 revenue reserves. No gain or loss is recognized in the
performance statements on the purchase, sale, issue or cancellation of equity shares.

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.

106

1 Signiﬁcant accounting policies continued

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 method 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 2006
The following amendments to IFRS and IFRIC interpretations have been adopted by the group with effect from 1 January 2006.

Amendment to IAS 21 ‘The Effects of Changes in Foreign Exchange Rates’– ‘Net Investment in a Foreign Operation’ was issued in December 2005.
The amendment clariﬁes the requirements of IAS 21 regarding an entity’s investment in foreign operations. This amendment was adopted by the EU in
May 2006. There was no material impact on the group’s reported income or net assets as a result of adoption of this amendment.

The IASB issued an amendment to the fair value option in IAS 39 in June 2005. The option to irrevocably designate, on initial recognition, any ﬁnancial

instruments as ones to be measured at fair value with gains and losses recognized in proﬁt and loss has now been restricted to those ﬁnancial
instruments meeting certain criteria. The criteria are where such designation eliminates or signiﬁcantly reduces an accounting mismatch, when a group
of ﬁnancial assets, ﬁnancial liabilities or both are managed and their performance is evaluated on a fair value basis in accordance with a documented risk
management or investment strategy, and when an instrument contains an embedded derivative that meets particular conditions. The group has not
designated any ﬁnancial instruments as being at-fair-value-through-proﬁt-and-loss, thus there was no effect on the group’s reported income or net
assets as a result of adoption of this amendment.

In August 2005, the IASB issued amendments to IAS 39 and IFRS 4 ‘Insurance Contracts’ regarding ﬁnancial guarantee contracts. These

amendments require the issuer of ﬁnancial guarantee contracts to account for them under IAS 39 as opposed to IFRS 4 unless an issuer has previously
asserted explicitly that it regards such contracts as insurance contracts and has used accounting applicable to insurance contracts. In these instances
the issuer may elect to apply either IAS 39 or IFRS 4. Under the amended IAS 39, a ﬁnancial guarantee contract is initially recognized at fair value and is
subsequently measured at the higher of (a) the amount determined in accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’
and (b) the amount initially recognized, less, when appropriate, cumulative amortization recognized in accordance with IAS 18 ‘Revenue’. This standard
impacts guarantees given by group companies in respect of equity-accounted entities as well as in respect of other third parties; these are recorded in
the group’s ﬁnancial statements at initial fair value less cumulative amortization. The effect on the group’s reported income and net assets as a result of
adoption of this amendment was not material.

In addition, in 2006 BP has adopted IFRIC 5 ‘Rights to Interests Arising from Decommissioning, Restoration and Environmental Rehabilitation Funds’
and IFRIC 6 ‘Liabilities Arising from Participating in a Speciﬁc Market – Waste Electrical and Electronic Equipment’ and has decided to early adopt IFRIC
7 ‘Applying IAS 29 for the First Time’, IFRIC 8 ‘Scope of IFRS 2 – Share-based payment’ and IFRIC 9 ‘Reassessment of embedded derivatives’. There
were no changes in accounting policy and no restatement of ﬁnancial information consequent upon adoption of these interpretations.

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 August 2005, the IASB issued IFRS 7 ‘Financial Instruments – Disclosures’ which is effective for annual periods beginning on or after 1 January
2007. Upon adoption, the group will disclose additional information about its ﬁnancial instruments, their signiﬁcance and the nature and extent of risks to
which they give rise. More speciﬁcally, the group will be required to make speciﬁed minimum disclosures about credit risk, liquidity risk and market risk.
There will be no effect on reported income or net assets.

Also in August 2005, ‘IAS 1 Amendment – Presentation of Financial Statements: Capital Disclosures’ was issued by the IASB, which requires

disclosures of an entity’s objectives, policies and processes for managing capital, quantitative data about what the entity regards as capital, whether the
entity has complied with any capital requirements, and the consequences of any non-compliance. This is effective for annual periods beginning on or
after 1 January 2007. There will be no effect on the group’s reported income or net assets.

BP Annual Report and Accounts 2006

107

1 Signiﬁcant accounting policies continued

IFRS 8 ‘Operating Segments’ was issued in October 2006 and deﬁnes operating segments as components of an entity about which separate ﬁnancial

information is available and is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing
performance. The new standard sets out the required disclosures for operating segments and is effective for annual periods beginning on or after
1 January 2009. BP has not yet completed its evaluation of the impact on its disclosures of adopting IFRS 8. There will be no effect on the group’s
reported income or net assets. IFRS 8 has not yet been adopted by the EU.

Three further IFRIC interpretations, issued in late 2006, are not yet effective and have not yet been adopted by the EU.
IFRIC 10 ‘Interim Financial Reporting and Impairment’ prohibits the reversal of an impairment loss relating to goodwill or certain ﬁnancial assets made

in an earlier interim period in the same annual period.

IFRIC 11 ‘IFRS 2 – Group and Treasury Share Transactions’ deals with share-based payment arrangements within a group and share-based payment

arrangements satisﬁed by using treasury shares.

The directors do not anticipate that the adoption of these interpretations will have a material effect on the reported income or net assets of the group.
IFRIC 12 ‘Service Concession Arrangements’ gives guidance on the accounting by operators for public-to-private service concession arrangements.

BP has not yet completed its evaluation of the impact of adopting this interpretation.

108

2 Resegmentation and other changes to comparatives

With effect from 1 January 2006 the following changes to the business segment boundaries have been implemented:
(a) Following the sale of Innovene to INEOS in December 2005, the transfer of three equity-accounted entities (Shanghai SECCO Petrochemical

Company Limited in China and Polyethylene Malaysia Sdn Bhd and Ethylene Malaysia Sdn Bhd, both in Malaysia), previously reported in Other
businesses and corporate, to Reﬁning and Marketing.

(b) The formation of BP Alternative Energy in November 2005 has resulted in the transfer of certain mid-stream assets and activities to Gas, Power and

Renewables:

– South Houston Green Power co-generation facility (in the Texas City reﬁnery) from Reﬁning and Marketing.
– Watson Cogeneration (in the Carson reﬁnery) from Reﬁning and Marketing.
– Phu My Phase 3 CCGT plant in Vietnam from Exploration and Production.
(c) The transfer of Hydrogen for Transport activities from Gas, Power and Renewables to Reﬁning and Marketing.

Furthermore, in 2005, the basis of accounting for over-the-counter forward sale and purchase contracts for oil, natural gas, NGLs and power was
changed. Certain transactions are now reported on a net basis in sales and other operating revenues, whereas previously they had been reported gross
in sales and purchases. This change, while reducing sales and other operating revenues and purchases, had no impact on reported proﬁt, proﬁt per
ordinary share, cash ﬂow or the balance sheet.

During 2006, as part of a continuous process to review how individual contracts are accounted for, certain other minor adjustments have been
identiﬁed that should have been reﬂected in the restatement from gross to net presentation. Although these adjustments are not signiﬁcant to the
group income statement, comparatives have been amended to bring them onto a basis which is consistent with the current year.

The impact of the changes described above is shown in the tables below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

Gas,
Power
and
Renewables
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Consolidation
adjustment
and
eliminations

Consolidation
adjustment
and
eliminations

Other
businesses
and
corporate

Exploration
and
Production

Total
continuing
operations

Reﬁning
and
Marketing

Innovene
operations

Total
group

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

47,210
(32,606)
14,604

220,134
(11,407)
208,727

28,561
(3,095)
25,466

21,295
(8,251)
13,044

(55,359)
55,359
–

261,841
–
261,841

(20,627)
8,251
(12,376)

8,251
(8,251)
–

249,465
–
249,465

25,508

6,942

1,104

(523)

(208)

32,823

(668)

527

32,682

73,092

45,625

5,095

(2,602)

(40,445)

80,765

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

47,210
(32,606)
14,604

213,326
(11,407)
201,919

25,696
(3,095)
22,601

21,295
(8,251)
13,044

(55,359)
55,359
–

252,168
–
252,168

(20,627)
8,251
(12,376)

8,251
(8,251)
–

239,792
–
239,792

By business – as reported
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Segment results
Proﬁt (loss) before interest and tax
Assets and liabilities
Net assets (liabilities)
By business – as restated
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Segment results
Proﬁt (loss) before interest and tax
Assets and liabilities
Net assets (liabilities)

25,502

6,926

1,172

(569)

(208)

32,823

(668)

527

32,682

73,060

45,734

5,587

(3,171)

(40,445)

80,765

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

Gas,
Power
and
Renewables
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Consolidation
adjustment
and
eliminations

Consolidation
adjustment
and
eliminations

Other
businesses
and
corporate

Exploration
and
Production

Total
continuing
operations

Reﬁning
and
Marketing

Innovene
operations

Total
group

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

34,700
(24,756)
9,944

176,350
(10,632)
165,718

26,110
(2,442)
23,668

17,994
(6,169)
11,825

(43,999)
43,999
–

211,155
–
211,155

(17,448)
6,169
(11,279)

6,169
(6,169)
–

199,876
–
199,876

18,087

6,544

954

(362)

(191)

25,032

526

188

25,746

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

34,700
(24,756)
9,944

170,639
(10,632)
160,007

23,969
(2,442)
21,527

17,994
(6,169)
11,825

(43,999)
43,999
–

203,303
–
203,303

(17,448)
6,169
(11,279)

6,169
(6,169)
–

192,024
–
192,024

By business – as reported
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Segment results
Proﬁt (loss) before interest and tax
By business – as restated
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Segment results
Proﬁt (loss) before interest and tax

18,085

6,506

1,003

(371)

(191)

25,032

526

188

25,746

BP Annual Report and Accounts 2006

109

2 Resegmentation and other changes to comparatives continued

Sales and other operating revenues

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

By geographical area – as reported
Segment sales and other operating revenues
Less: sales attributable to Innovene operations
Segment revenues from continuing operations
Less: sales between areas
Less: sales by continuing operations to Innovene
Third party sales of continuing operations
By geographical area – as restated
Segment sales and other operating revenues
Less: sales attributable to Innovene operations
Segment revenues from continuing operations
Less: sales between areas
Less: sales by continuing operations to Innovene
Third party sales of continuing operations

By geographical area – as reported
Segment sales and other operating revenues
Less: sales attributable to Innovene operations
Segment revenues from continuing operations
Less: sales between areas
Less: sales by continuing operations to Innovene
Third party sales of continuing operations
By geographical area – as restated
Segment sales and other operating revenues
Less: sales attributable to Innovene operations
Segment revenues from continuing operations
Less: sales between areas
Less: sales by continuing operations to Innovene
Third party sales of continuing operations

Purchases

As reported
As restated

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

98,744
(2,610)
96,134
(38,081)
(5,599)
52,454

95,375
(2,610)
92,765
(38,081)
(5,599)
49,085

UK

62,516
(2,365)
60,151
(18,846)
(5,263)
36,042

59,615
(2,365)
57,250
(18,846)
(5,263)
33,141

Rest of
Europe

72,972
(8,667)
64,305
(5,013)
(4,640)
54,652

72,972
(8,667)
64,305
(5,013)
(4,640)
54,652

Rest of
Europe

52,540
(7,682)
44,858
(1,396)
(896)
42,566

52,540
(7,682)
44,858
(1,396)
(896)
42,566

USA

107,494
(4,309)
103,185
(2,362)
(1,508)
99,315

101,190
(4,309)
96,881
(2,362)
(1,508)
93,011

USA

91,309
(4,109)
87,200
(1,539)
(2,064)
83,597

86,358
(4,109)
82,249
(1,539)
(2,064)
78,646

$ million

Total

339,524
(16,272)
323,252
(61,997)
(11,790)
249,465

329,851
(16,272)
313,579
(61,997)
(11,790)
239,792

Total

254,899
(14,828)
240,071
(31,969)
(8,226)
199,876

247,047
(14,828)
232,219
(31,969)
(8,226)
192,024

$ million

2004

Rest of
World

60,314
(686)
59,628
(16,541)
(43)
43,044

60,314
(686)
59,628
(16,541)
(43)
43,044

Rest of
World

48,534
(672)
47,862
(10,188)
(3)
37,671

48,534
(672)
47,862
(10,188)
(3)
37,671

2005

172,699
163,026

135,907
128,055

3 Oil and natural gas reserves estimates

At the end of 2006, BP adopted the US Securities and Exchange Commission (SEC) rules for estimating oil and natural gas reserves for all accounting
and reporting purposes instead of the UK accounting rules contained in the Statement of Recommended Practice ‘Accounting for Oil and Gas
Exploration, Development, Production and Decommissioning Activities’ (UK SORP). The main differences relate to the SEC requirement to use year-end
prices, the application of SEC interpretations of SEC regulations relating to the use of technology (mainly seismic) to estimate reserves in the reservoir
away from wellbores and the reporting of fuel gas (i.e. gas used for fuel in operations) within proved reserves. Consequently, reserves quantities under
SEC rules differ from those that would be reported under application of the UK SORP.

The change to SEC reserves represents a simpliﬁcation of the group’s reserves reporting, as in the future only one set of reserves estimates will be

disclosed. In addition, the use of SEC reserves for accounting purposes will bring our IFRS and US GAAP reporting into closer alignment, as well as
making our results more comparable with those of our major competitors.

This change in accounting estimate has a direct impact on the amount of depreciation, depletion and amortization (DD&A) charged in the income

statement in respect of oil and natural gas properties which are depreciated on a unit-of-production basis as described in Note 1. The change in estimate
is applied prospectively, with no restatement of prior periods’ results. The group’s actual DD&A charge for the year is $9,128 million, whereas the
charge based on UK SORP reserves would have been $9,057 million, i.e. an increase of $71 million due to the change in reserves estimates which was
used to calculate DD&A for the last three months of the year. Over the life of a ﬁeld this change would have no overall effect on DD&A but the
estimated effect for 2007 is expected to be an increase of approximately $400 million to $500 million for the group.

110

4 Acquisitions

Acquisitions in 2006
BP made a number of minor acquisitions in 2006 for a total consideration of $256 million. All these business combinations were in the Gas, Power and
Renewables segment and were accounted for using the acquisition method of accounting. Fair value adjustments were made to the acquired assets
and liabilities and goodwill of $64 million arose on these acquisitions.

Acquisitions in 2005
BP made a number of minor acquisitions in 2005 for a total consideration of $84 million. All these business combinations were accounted for using the
acquisition method of accounting. No signiﬁcant fair value adjustments were made to the acquired assets and liabilities. Goodwill of $27 million arose on
these acquisitions. There was also additional goodwill on the Solvay acquisition of $59 million (see below).

Acquisitions in 2004
On 2 November 2004, Solvay exercised its option to sell its interests in BP Solvay Polyethylene Europe and BP Solvay Polyethylene North America
to BP. Solvay held 50% of BP Solvay Polyethylene Europe and 51% of BP Solvay Polyethylene North America. On completion, the two entities,
which manufacture and market high-density polyethylene, became wholly owned subsidiaries of BP. The total consideration for the acquisition was
$1,391 million, subject to ﬁnal closing adjustments. There were closing adjustments and selling costs in 2005 amounting to $59 million. These created
additional goodwill of $59 million, which was written off. Other minor acquisitions were made for a total consideration of $14 million. All business
combinations have been accounted for using the acquisition method of accounting. The fair value of the property, plant and equipment was estimated
by determining the net present value of future cash ﬂows. No signiﬁcant adjustments were made to the other assets and liabilities acquired. The assets
and liabilities acquired as part of the 2004 acquisitions are shown in aggregate in the table below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Book value
on
acquisition

Fair value
adjustments

Fair value

703
15
721
36
(329)
–
(3)
(547)
596

760
–
–
–
–
(185)
–
(94)
481

1,463
15
721
36
(329)
(185)
(3)
(641)
1,077
328
1,405

Property, plant and equipment
Intangible assets
Current assets (excluding cash)
Cash and cash equivalents
Trade and other payables
Deferred tax liabilities
Deﬁned beneﬁt pension plan deﬁcits
Net investment in equity-accounted entities transferred to full consolidation
Net assets acquired
Goodwill
Consideration

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

5 Non-current assets held for sale and discontinued operations

Non-current assets held for sale
On 27 June 2006, BP announced its intention to sell the Coryton reﬁnery in the UK, following a review of its European reﬁnery portfolio which
concluded that the group would optimise its value by focusing on a smaller, but more advantaged reﬁning portfolio in Europe. In addition, given the
integrated nature of the operations, the bitumen business in the UK is also included with the divestment, along with the Coryton bulk terminal (together
‘the Coryton disposal group’).

At 31 December 2006, negotiations for the sale were in progress and the assets and associated liabilities were classiﬁed as a disposal group held for

sale. No impairment loss was recognized at the time of reclassiﬁcation of the Coryton disposal group as held for sale nor at 31 December 2006.

The major classes of assets and liabilities of the Coryton disposal group, reported within the Reﬁning and Marketing segment, classiﬁed as held for

sale at 31 December 2006 are set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Assets

Property, plant and equipment
Goodwill
Inventories

Assets classiﬁed as held for sale
Liabilities

Current liabilities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Liabilities directly associated with assets classiﬁed as held for sale

In addition, accumulated foreign exchange gains recognized directly in equity relating to the Coryton disposal group amounted to $122 million at
31 December 2006. On disposal such foreign exchange differences are recycled to the income statement.

On 1 February 2007, it was agreed to sell the Coryton disposal group, subject to required regulatory approval, to Petroplus Holdings AG, an

independent reﬁner and wholesaler of petroleum products headquartered in Zug, Switzerland, for a sale price of $1.4 billion, plus hydrocarbons to be
valued at closing.

BP Annual Report and Accounts 2006

111

$ million

564
60
454
1,078

54
54

5 Non-current assets held for sale and discontinued operations continued

Discontinued operations
The sale of Innovene, BP’s oleﬁns, derivatives and reﬁning group, to INEOS was completed on 16 December 2005.

The Innovene operations represented a separate major line of business for BP. As a result of the sale, these operations were treated as discontinued

operations for the year ended 31 December 2005. A single amount was shown on the face of the income statement comprising the post-tax result of
discontinued operations and the post-tax loss recognized on the remeasurement to fair value less costs to sell and on disposal of the discontinued
operation. That is, the income and expenses of Innovene are reported separately from the continuing operations of the BP group. The table below
provides further detail of the amount shown in the income statement.

In the cash ﬂow statement, the cash provided by the operating activities of Innovene has been separated from that of the rest of the group and

reported as a single line item.

Gross proceeds received amounted to $8,477 million. In 2005 there were selling costs of $120 million and initial closing adjustments of $43 million. In

2006 there was a ﬁnal closing adjustment of $34 million. The remeasurement to fair value less costs to sell resulted in a loss of $775 million before tax
($184 million recognized in 2006 and $591 million in 2005).

Financial information for the Innovene operations after group eliminations is presented below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Total revenues and other income
Expenses
Proﬁt (loss) before interest and taxation
Other ﬁnance income (expense)
Proﬁt (loss) before taxation and loss recognized on remeasurement to fair value less costs to sell and on disposal
Loss recognized on the remeasurement to fair value less costs to sell and on disposal
Proﬁt (loss) before taxation from Innovene operations
Tax (charge) credit

on proﬁt (loss) before loss recognized on remeasurement to fair value less costs to sell and on disposal
on loss recognized on the remeasurement to fair value less costs to sell and on disposal

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt (loss) from Innovene operations
Earnings (loss) per share from Innovene operations – cents

Basic
Diluted

The cash ﬂows of Innovene operations are presented below

Net cash provided by (used in) operating activities
Net cash used in investing activities
Net cash provided by (used in) ﬁnancing activities

Further information is contained in Note 6.

6 Disposals

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

By business

6,254

Proceeds from the sale of Innovene operations
Proceeds from the sale of other businesses
Proceeds from the sale of businesses
Proceeds from disposal of ﬁxed assets

Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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.

Cash received during the year from disposals amounted to $6.3 billion (2005 $11.2 billion and 2004 $5.0 billion). The major transactions in 2006 were

the disposals of our interests in the Gulf of Mexico Shelf and our interest in the Shenzi discovery in the Gulf of Mexico. The divestment of Innovene
contributed $8.3 billion to the total in 2005. The major transactions in 2004 that generated over $2.3 billion of proceeds were the sale of the group’s
investments in PetroChina and Sinopec. The principal transactions generating the proceeds for each business segment are described below.

112

–
–

–
–

–
(184)

(184)

166
(7)

(25)

(0.13)
(0.12)

–
–
–

2006

(34)
325

291
5,963

4,005
1,789
297
163

6,254

12,441
11,709
732
3
735
(591)
144

(306)
346
184

11,327
12,041
(714)
(17)
(731)
–
(731)

109
–
(622)

0.87
0.86

970
(524)
(446)

(2.85)
(2.79)

(669)
(1,731)
2,400

2005

8,304
93
8,397
2,803
11,200

1,416
888
540
8,356
11,200

2004

–
725
725
4,236
4,961

914
1,007
144
2,896
4,961

6 Disposals continued

Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. During 2006 the major transactions were disposals of our
interests in the Gulf of Mexico Shelf, in the Shenzi discovery in the Gulf of Mexico, in the Statfjord oil and gas ﬁeld and in the Luva gas ﬁeld in the North
Sea. We also divested our interests in a number of onshore ﬁelds in South Louisiana, interests in ﬁelds in the North Sea, the Gulf of Suez and
Venezuela, and part of an interest in Colombia. During 2005, the major transaction was the sale of the group’s interest in the Ormen Lange ﬁeld in
Norway. In addition, the group sold interests in oil and natural gas properties in Venezuela, Canada and the Gulf of Mexico. In 2004, in the US, we sold
45% of our interest in King’s Peak in the deepwater Gulf of Mexico to Marubeni Oil & Gas, divested our interest in Swordﬁsh, and additionally sold
various properties, including our interest in the South Pass 60 property in the Gulf of Mexico Shelf. In Canada, BP sold various assets in Alberta to
Fairborne Energy. In Indonesia, we disposed of our interest in the Kangean Production Sharing Contract and our participating interest in the Muriah
Production Sharing Contract.

Reﬁning and Marketing
The churn of retail assets represents a signiﬁcant element of the total in all three years. In addition, in 2006, we disposed of our interests in Zhenhai
Reﬁning and Chemicals Company in China and in Eiffage, the French-based construction company. We also exited the retail market in the Czech
Republic and disposed of our interests in a number of pipelines. During 2005, the group sold a number of regional retail networks in the US and in
addition its retail network in Malaysia. During 2004, major transactions included the sale of the Singapore reﬁnery, the divestment of the European
speciality intermediate chemicals business and the Cushing and other pipeline interests in the US.

Gas, Power and Renewables
During 2006, we disposed of our shareholding in Enagas, the Spanish gas transport grid operator. In 2005, the group sold its interest in the
Interconnector pipeline and a power plant at Great Yarmouth in the UK. During 2004, the group sold its interest in two Canadian natural gas
liquids plants.

Other businesses and corporate
During 2006, the group disposed of miscellaneous non-core businesses and assets. 2005 includes the proceeds from the sale of Innovene. The disposal
of the group’s investments in PetroChina and Sinopec were the major transactions in 2004. In addition, the group sold its US speciality intermediate
chemicals and fabrics and ﬁbres businesses.

Summarized ﬁnancial information for the sale of businesses is shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

143
169
(10)
(70)

232
167

399
(74)
(34)

291

6,452
4,779
(364)
(2,488)
8,379
18
8,397
–
–
8,397

1,046
477
(44)
(59)
1,420
(695)
725
–
–
725

The disposals comprise the following

Non-current assets
Other current assets
Non-current liabilities
Current liabilities

Proﬁt (loss) on sale of businesses
Total consideration
Consideration not yet received
Closing adjustments associated with the sale of Innovene
Proceeds from the sale of businessesa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Includes cash and cash equivalents disposed of $2 million (2005 $15 million and 2004 $10 million).

7 Segmental analysis

The group’s primary format for segment reporting is business segments and the secondary format is geographical segments. The risks and returns of
the group’s operations are primarily determined by the nature of the different activities that the group engages in, rather than the geographical location
of these operations. This is reﬂected by the group’s organizational structure and the group’s internal ﬁnancial reporting systems.

BP has three reportable operating segments: Exploration and Production; Reﬁning and Marketing; and Gas, Power and Renewables. Exploration and
Production’s activities include oil and natural gas exploration and ﬁeld development and production, together with pipeline transportation and natural gas
processing. The activities of Reﬁning and Marketing include oil supply and trading as well as reﬁning and petrochemicals manufacturing and marketing.
Gas, Power and Renewables activities include marketing and trading of gas and power, marketing of liqueﬁed natural gas, natural gas liquids and low-
carbon power generation through the Alternative Energy business. The group is managed on an integrated basis.

Other businesses and corporate comprises Finance, the group’s aluminum asset, interest income and costs relating to corporate activities worldwide.
The accounting policies of operating segments are the same as those described in Note 1.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenue and

segment result include transactions between business segments. These transactions and any unrealized proﬁts and losses are eliminated on
consolidation.

The group’s geographical segments are based on the location of the group’s assets. The UK and the US are signiﬁcant countries of activity for the

group; the other geographical segments are determined by geographical location.

Sales to external customers are based on the location of the seller, which in most circumstances is not materially different from the location of the
customer. Crude oil and LNG are commodities for which there is an international market and buyers and sellers can be widely separated geographically.
The UK segment includes the UK-based international activities of Reﬁning and Marketing.

BP Annual Report and Accounts 2006

113

7 Segmental analysis continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration
and
Production

Reﬁning
and
Marketing

Gas,
Power
and
Renewables

Other
businessess
and
corporate

Consolidation
adjustment
and
eliminations

Total
group

Innovene
operations

Consolidation
adjustment
and
eliminationsa

Total
continuing
operations

By business
Sales and other operating revenues
Segment sales and other operating

revenues

Less: sales between businesses
Third party sales
Equity-accounted earnings
Segment revenues
Interest and other revenues
Total revenues
Segment results
Proﬁt (loss) before interest and tax
Finance costs and other ﬁnance

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

52,600
(36,171)

16,429
3,517

232,855
(4,076)

228,779
341

23,708
(4,019)

19,689
138

1,009
–

1,009
(1)

(44,266)
44,266

–
–

265,906
–

265,906
3,995

–
–

–
–

–
–

–
–

265,906
–

265,906
3,995

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

19,827
–
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

269,901
701

229,120
–

269,901
701

19,946
–

1,008
–

–
701

–
–

–
–

19,946

229,120

19,827

1,008

701

270,602

–

29,629

5,041

1,321

(1,069)

52

34,974

184

–

–

270,602

35,158

expense

–
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(516)

(516)

(516)

–

–

–

–

–

1,321
–
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(464)
(12,172)

34,458
(12,172)

34,642
(12,331)

(1,069)
–

29,629
–

5,041
–

184
(159)

–
–

29,629

5,041

1,321

(1,069)

(12,636)

22,286

25

–

22,311

27,398
–
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

217,057
544

(4,799)
544

99,310
–

80,964
–

14,184
–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

99,310

80,964

27,398

14,184

(4,255)

217,601

Equity-accounted investments

15,510

4,675

853

11

–

21,049

(21,708)
–
–
–
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(87,375)
(2,635)
(24,010)
(18,116)

4,074
(2,635)
(24,010)
(18,116)

(14,555)
–
–
–

(21,787)
–
–
–

(33,399)
–
–
–

(21,787)

(33,399)

(21,708)

(14,555)

(40,687)

(132,136)

Proﬁt (loss) before taxation
Taxation
Proﬁt (loss) for the year
Assets and liabilities
Segment assets
Tax receivable
Total assets
Includes

Segment liabilities
Current tax payable
Finance debt
Deferred tax liabilities
Total liabilities
Other segment information
Capital expenditure and acquisitions

Intangible assets
Property, plant and equipment
Other

Total
Depreciation, depletion and

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,614
10,227
1,277

13,118

253
2,733
158

3,144

192
337
159

688

43
232
6

281

–
–
–

–

2,102
13,529
1,600

17,231

amortization

Impairment losses
Impairment reversals
Loss on remeasurement to fair value
less costs to sell and on disposal of
Innovene operations

Losses on sale of businesses and ﬁxed

assets

Gains on sale of businesses and ﬁxed

6,533
137
340

–

195

2,244
155
–

–

228

192
100
–

–

–

assets

2,309

1,112

193

159
69
–

184

5

100

–
–
–

–

–

–

9,128
461
340

184

428

3,714

–
–
–

(184)

–

–

–
–
–

–

–

–

9,128
461
340

–

428

3,714

114

7 Segmental analysis continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

Gas,
Power
and
Renewables
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Consolidation
adjustment
and
eliminationsa

Consolidation
adjustment
and
eliminations

Other
businesses
and
corporate

Exploration
and
Production

Total
continuing
operations

Reﬁning
and
Marketing

Innovene
operations

Total
group

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

213,326
(11,407)
201,919
249
202,168
–
202,168

6,926
–
6,926
–
6,926

25,696
(3,095)
22,601
62
22,663
–
22,663

1,172
–
1,172
–
1,172

21,295
(8,251)
13,044
(14)
13,030
–
13,030

(569)
–
(569)
–
(569)

(55,359) 252,168
–
55,359
252,168
–
3,529
–
255,697
–
689
689
256,386
689

(208)
(758)
(966)
(9,433)
(10,399)

32,823
(758)
32,065
(9,433)
22,632

(20,627)
8,251
(12,376)
14
(12,362)
(76)
(12,438)

(668)
(3)
(671)
133
(538)

8,251
(8,251)
–
–
–
–
–

527
–
527
(173)
354

239,792
–
239,792
3,543
243,335
613
243,948

32,682
(761)
31,921
(9,473)
22,448

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

77,485
–
77,485

28,952
–
28,952

12,144
–
12,144

(5,326) 206,702
212
(5,114) 206,914

212

Equity-accounted investments

14,657

4,336

771

9

–

19,773

47,210
(32,606)
14,604
3,232
17,836
–
17,836

25,502
–
25,502
–
25,502

93,447
–
93,447

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(20,387)
–
–
–
(20,387)

(31,751)
–
–
–
(31,751)

(23,365)
–
–
–
(23,365)

(15,315)
–
–
–
(15,315)

4,548
(4,274)
(19,162)
(16,443)
(35,331)

(86,270)
(4,274)
(19,162)
(16,443)
(126,149)

989
8,751
497
10,237
6,033
266

451
2,036
373
2,860
2,382
93

31
199
5
235
235
–

10
779
28
817
533
59

–
–
–
–
–
–

1,481
11,765
903
14,149
9,183
418

–
39
1,198

–
64
241

–
–
55

591
6
47

–
–
–

591
109
1,541

(412)
(59)

(591)
–
(3)

–
–

–
–
–

8,771
359

–
109
1,538

By business
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Equity-accounted earnings
Segment revenues
Interest and other revenues
Total revenues
Segment results
Proﬁt (loss) before interest and tax
Finance costs and other ﬁnance expense
Proﬁt (loss) before taxation
Taxation
Proﬁt (loss) for the year
Assets and liabilities
Segment assets
Tax receivable
Total assets
Includes

Segment liabilities
Current tax payable
Finance debt
Deferred tax liabilities
Total liabilities
Other segment information
Capital expenditure and acquisitions

Intangible assets
Property, plant and equipment
Other

Total
Depreciation, depletion and amortization
Impairment losses
Loss on remeasurement to fair value less
costs to sell and on disposal of Innovene
operations

Losses on sale of businesses and ﬁxed assets
Gains on sale of businesses and ﬁxed assets

BP Annual Report and Accounts 2006

115

7 Segmental analysis continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

Gas,
Power
and
Renewables
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Consolidation
adjustment
and
eliminationsa

Consolidation
adjustment
and
eliminations

Other
businesses
and
corporate

Exploration
and
Production

Total
continuing
operations

Reﬁning
and
Marketing

Innovene
operations

Total
group

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

By business
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales between businesses
Third party sales
Equity-accounted earnings
Segment revenues
Interest and other revenues
Total revenues
Segment results
Proﬁt (loss) before interest and tax
Finance costs and other ﬁnance expense
Proﬁt (loss) before taxation
Taxation
Proﬁt (loss) for the year
Other segment information
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Losses on sale of businesses and ﬁxed assets
Gains on sale of businesses and ﬁxed assets

34,700
(24,756)
9,944
1,983
11,927
–
11,927

18,085
–
18,085
–
18,085

170,639
(10,632)
160,007
262
160,269
–
160,269

6,506
–
6,506
–
6,506

23,969
(2,442)
21,527
35
21,562
–
21,562

1,003
–
1,003
–
1,003

17,994
(6,169)
11,825
(12)
11,813
–
11,813

(371)
–
(371)
–
(371)

(43,999) 203,303
–
43,999
203,303
–
2,268
–
205,571
–
673
673
206,244
673

(191)
(797)
(988)
(6,973)
(7,961)

25,032
(797)
24,235
(6,973)
17,262

(17,448)
6,169
(11,279)
12
(11,267)
(58)
(11,325)

526
17
543
(53)
490

6,169
(6,169)
–
–
–
–
–

188
–
188
(56)
132

192,024
–
192,024
2,280
194,304
615
194,919

25,746
(780)
24,966
(7,082)
17,884

5,583
435
31
227
162

2,532
195
–
371
104

218
–
–
–
56

679
891
–
416
1,365

–
–
–
–
–

9,012
1,521
31
1,014
1,687

(483)
(879)
–
(235)
(2)

–
–
–
–
–

8,529
642
31
779
1,685

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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

116

7 Segmental analysis continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

54,581

61,960

95,030

58,330

–

269,901

By geographical area
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales between areas
Third party sales
Equity-accounted earnings
Segment revenues
Segment results
Proﬁt (loss) before interest and tax from continuing operations
Finance costs and other ﬁnance (expense) income
Proﬁt before taxation from continuing operations
Taxation
Proﬁt for the year from continuing operations
Proﬁt (loss) from Innovene operations
Proﬁt for the year
Assets and liabilities
Segment assets
Tax receivable
Total assets
Includes

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2,813

1,768

7,278

10,427

–

22,286

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

49,018
13

49,031

28,059
65

28,124

78,586
450

79,036

69,479
16

69,495

(8,085)
–

217,057
544

(8,085)

217,601

Equity-accounted investments

78

1,538

1,529

17,904

–

21,049

UK

Rest of
Europe

USA

Rest of
World

Consolidation
adjustment
and
eliminations

105,518
(50,942)

54,576
5

76,768
(14,821)

61,947
13

99,935
(5,032)

94,903
127

71,547
(17,067)

54,480
3,850

5,897
43

5,940
(3,158)

2,782
31

3,282
(262)

3,020
(1,176)

1,844
(76)

11,164
(331)

10,833
(3,553)

7,280
(2)

14,815
34

14,849
(4,444)

10,405
22

Total

353,768
(87,862)

265,906
3,995

35,158
(516)

34,642
(12,331)

22,311
(25)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Segment liabilities
Current tax payable
Finance debt
Deferred tax liabilities
Total liabilities
Other segment information
Capital expenditure and acquisitions

Intangible assets
Property, plant and equipment
Other

Total
Depreciation, depletion and amortization
Exploration expense
Impairment losses
Impairment reversals
Loss on remeasurement to fair value less costs to sell and on disposal of

Innovene operations

Losses on sale of businesses and ﬁxed assets
Gains on sale of businesses and ﬁxed assets

–
–

–
–

–
–

–
–

–
–

–
–
–

–

(26,048)
(757)
(12,666)
(3,335)

(18,484)
(570)
(328)
(938)

(32,979)
11
(7,201)
(9,946)

(17,949)
(1,319)
(3,815)
(3,897)

8,085
–
–
–

(87,375)
(2,635)
(24,010)
(18,116)

(42,806)

(20,320)

(50,115)

(26,980)

8,085

(132,136)

421
1,120
46

1,587

53
916
22

991

905
5,531
156

6,592

723
5,962
1,376

8,061

2,102
13,529
1,600

17,231

2,139
20
–
176

185
12
337

840
–
171
–

36
96
577

3,459
633
114
90

(16)
217
2,530

2,690
392
176
74

(21)
103
270

–
–
–
–

–
–
–

9,128
1,045
461
340

184
428
3,714

BP Annual Report and Accounts 2006

117

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

7 Segmental analysis continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Equity-accounted investments

74

1,496

1,420

16,783

–

19,773

UK

Rest of
Europe

USA

Rest of
World

Consolidation
adjustment
and
eliminations

95,375
(2,610)
92,765
(38,081)
(5,599)
49,085
(8)
49,077

1,167
(80)
1,087
(289)
798
234
1,032

44,007
2
44,009

72,972
(8,667)
64,305
(5,013)
(4,640)
54,652
18
54,670

5,206
(268)
4,938
(1,646)
3,292
109
3,401

26,560
158
26,718

101,190
(4,309)
96,881
(2,362)
(1,508)
93,011
86
93,097

13,139
(366)
12,773
(3,983)
8,790
(165)
8,625

79,838
6
79,844

60,314
(686)
59,628
(16,541)
(43)
43,044
3,447
46,491

13,170
(47)
13,123
(3,555)
9,568
6
9,574

64,129
46
64,175

Total

329,851
(16,272)
313,579
(61,997)
(11,790)
239,792
3,543
243,335

32,682
(761)
31,921
(9,473)
22,448
184
22,632

(7,832) 206,702
212
(7,832) 206,914

–

(25,079)
(798)
(9,706)
(2,223)
(37,806)

(16,824)
(1,057)
(433)
(936)
(19,250)

(33,646)
(678)
(6,159)
(9,585)
(50,068)

(18,553)
(1,741)
(2,864)
(3,699)
(26,857)

7,832
–
–
–
7,832

(86,270)
(4,274)
(19,162)
(16,443)
(126,149)

205
1,340
53
1,598
2,080
32
53

43
919
18
980
932
2
7

579
4,804
86
5,469
3,685
425
238

654
4,702
746
6,102
2,074
225
61

1,481
11,765
903
14,149
8,771
684
359

–
–
–
–
–
–
–
–

–
–
–
–
–
–
–

–
–
–
–
–
–
–

By geographical area
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales attributable to Innovene operations
Segment revenues from continuing operations
Less: sales between areas
Less: sales by continuing operations to Innovene
Third party sales of continuing operations
Equity-accounted earnings
Segment revenues
Segment results
Proﬁt before interest and tax from continuing operations
Finance costs and other ﬁnance expense
Proﬁt before taxation from continuing operations
Taxation
Proﬁt for the year from continuing operations
Proﬁt (loss) from Innovene operations
Proﬁt for the year
Assets and liabilities
Segment assets
Tax receivable
Total assets
Includes

Segment liabilities
Current tax payable
Finance debt
Deferred tax liabilities
Total liabilities
Other segment information
Capital expenditure and acquisitions

Intangible assets
Property, plant and equipment
Other

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Total
Depreciation, depletion and amortization
Exploration expense
Impairment losses
Loss on remeasurement to fair value less costs to sell and on disposal of

Innovene operations

Losses on sale of businesses and ﬁxed assets
Gains on sale of businesses and ﬁxed assets

24
–
107

273
37
1,017

262
8
282

32
64
132

–
–
–

591
109
1,538

118

7 Segmental analysis continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

By geographical area
Sales and other operating revenues
Segment sales and other operating revenues
Less: sales attributable to Innovene operations
Segment revenues from continuing operations
Less: sales between areas
Less: sales by continuing operations to Innovene
Third party sales of continuing operations
Equity-accounted income
Segment revenues
Segment results
Proﬁt before interest and tax from continuing operations
Finance costs and other ﬁnance (expense) income
Proﬁt before taxation from continuing operations
Taxation
Proﬁt for the year from continuing operations
Loss from Innovene operations
Proﬁt for the year
Other segment information
Depreciation, depletion and amortization
Exploration expense
Impairment losses
Impairment reversals
Losses on sale of businesses and ﬁxed assets
Gains on sale of businesses and ﬁxed assets

UK

Rest of
Europe

USA

Rest of
World

Total

59,615
(2,365)
57,250
(18,846)
(5,263)
33,141
9
33,150

2,875
155
3,030
(1,745)
1,285
(327)
958

52,540
(7,682)
44,858
(1,396)
(896)
42,566
17
42,583

3,121
(261)
2,860
(779)
2,081
(110)
1,971

86,358
(4,109)
82,249
(1,539)
(2,064)
78,646
92
78,738

9,725
(513)
9,212
(2,596)
6,616
(96)
6,520

48,534
(672)
47,862
(10,188)
(3)
37,671
2,162
39,833

10,025
(161)
9,864
(1,962)
7,902
(89)
7,813

247,047
(14,828)
232,219
(31,969)
(8,226)
192,024
2,280
194,304

25,746
(780)
24,966
(7,082)
17,884
(622)
17,262

2,030
26
–
–
282
–

930
25
–
–
–
–

3,906
361
570
–
177
133

1,663
225
41
31
320
1,552

8,529
637
611
31
779
1,685

BP Annual Report and Accounts 2006

119

8 Earnings from jointly controlled entities and associates

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Minority
interest

Proﬁt (loss)
for the year

Proﬁt (loss)
before
interest
and tax

5,838
487
179
(1)

5,834
669

Interest

324
79
21
–

361
63

4,813
385
77
(14)
5,261
14
5,275
4,615
660
5,275

3,244
360
44
(9)
3,639
9
3,648
3,017
631
3,648

227
55
7
–
289
–
289
232
57
289

189
19
7
3
218
(3)
215
167
48
215

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

6,503

424

1,891

193

3,995

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Includes a net gain of $892 million on the disposal of fixed assets.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

6,503

424

1,891

193

3,995

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt (loss)
before interest
and tax

Interest

Minority
interest

Proﬁt (loss)
for the year

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

b Includes a net gain of $270 million on the disposal of fixed assets.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt (loss)
before interest
and tax

Interest

Minority
interest

Proﬁt (loss)
for the year

By business

Exploration and Productiona
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

Earnings from jointly controlled entities
Earnings from associates

By business

Exploration and Productionb
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

Innovene operations
Continuing operations
Earnings from jointly controlled entities
Earnings from associates

By business

Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

Innovene operations
Continuing operations
Earnings from jointly controlled entities
Earnings from associates

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

9 Interest and other revenues

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Dividends
Interest from loans and other investments
Other interest
Miscellaneous income

Innovene operations
Continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Tax

1,804
67
20
–

1,727
164

Tax

1,250
81
8
–
1,339
–
1,339
1,196
143
1,339

Tax

1,029
79
2
–
1,110
–
1,110
989
121
1,110

2006

5
154
314
228
701
–
701

193
–
–
–

193
–

104
–
–
–
104
–
104
104
–
104

43
–
–
–
43
–
43
43
–
43

2005

52
73
324
240
689
(76)
613

3,517
341
138
(1)

3,553
442

3,232
249
62
(14)
3,529
14
3,543
3,083
460
3,543

1,983
262
35
(12)
2,268
12
2,280
1,818
462
2,280

2004

37
34
244
358
673
(58)
615

120

104
63

167

2,309
1,008
193
37

3,547

3,714
–

3,714

18
–
18

1,198
223
55
47
1,523
1,541
(3)
1,538

–
–
–

162
104
56
1,365
1,687
1,687
(2)
1,685

Gains on sale of businesses
Reﬁning and Marketing
Other businesses and corporate

Gains on sale of ﬁxed assets
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

Innovene operations
Continuing operations

10 Gains on sale of businesses and ﬁxed assets

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The principal transactions giving rise to these gains for each business segment are described below.

Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. The major divestments during 2006 that resulted in gains
were the sales of our interest in the Shenzi discovery in the Gulf of Mexico in the US and interests in the North Sea. In 2005 the major divestment was
the sale of the group’s interest in the Ormen Lange ﬁeld in Norway. BP also sold various oil and gas properties in Trinidad & Tobago, Canada and the
Gulf of Mexico. For 2004, divestments included interests in oil and natural gas properties in Australia, Canada and the Gulf of Mexico.

Reﬁning and Marketing
During 2006, the group divested its retail business in the Czech Republic and ﬁxed assets including its shareholding in Zhenhai Reﬁning and Chemicals
Company in China, its shareholding in Eiffage, the French-based construction company, and pipeline assets. In 2005, the group divested a number of
regional retail networks in the US. For 2004, divestments included the sale of the Cushing and other pipeline interests in the US and the churn of retail
assets.

Gas, Power and Renewables
In 2006, the group divested its shareholding in Enagas. In 2005, transactions included the disposal of the group’s interest in the Interconnector pipeline
and power plant at Great Yarmouth in the UK. During 2004, the group divested its interest in two natural gas liquids plants in Canada.

Other businesses and corporate
In 2006, the group disposed of its ethylene oxide business. For 2004, the major disposals were the divestment of the group’s investments in
PetroChina and Sinopec.

Additional information on the sale of businesses and ﬁxed assets is given in Note 6.

11 Production and similar taxes

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK
Overseas

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

260
3,361

3,621

2005

495
2,515
3,010

2004

335
1,814
2,149

BP Annual Report and Accounts 2006

121

12 Depreciation, depletion and amortization

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

By business
Exploration and Production

UK
Rest of Europe
USA
Rest of World

Reﬁning and Marketing

UKa
Rest of Europe
USA
Rest of World

Gas, Power and Renewables

UK
Rest of Europe
USA
Rest of World

UK
Rest of Europe
USA
Rest of World

By geographical area
UKa
Rest of Europe
USA
Rest of World

Innovene operations
Continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other businesses and corporate

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,720
223
2,236
2,354
6,533

303
603
1,048
290
2,244

18
13
117
44
192

98
1
58
2
159

2,139
840
3,459
2,690
9,128
–
9,128

1,663
228
2,426
1,716
6,033

316
687
1,082
297
2,382

47
20
109
59
235

203
130
187
13
533

2,229
1,065
3,804
2,085
9,183
(412)
8,771

1,642
184
2,407
1,350
5,583

318
645
1,238
331
2,532

37
24
88
69
218

251
204
199
25
679

2,248
1,057
3,932
1,775
9,012
(483)
8,529

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

122

13 Impairment and losses on sale of businesses and ﬁxed assets

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

137
155
100
69

461

(340)

(340)

–
–

–

195
228
5

428
184

733
(184)

549

266
93
–
59
418

–
–

–
–
–

39
64
6
109
591
1,118
(650)
468

435
195
–
891
1,521

(31)
(31)

279
416
695

227
92
–
319
–
2,504
(1,114)
1,390

Impairment losses

Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

Impairment reversals

Exploration and Production

Reﬁning and Marketing
Other businesses and corporate

Loss on sale of ﬁxed assets
Exploration and Production
Reﬁning and Marketing
Other businesses and corporate

Innovene operations
Continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Loss on sale of businesses or termination of operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Loss on remeasurement to fair value less costs to sell and on disposal of Innovene operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Impairment
In assessing whether a write-down is required in the carrying value of a potentially impaired asset, its carrying value is compared with its recoverable
amount. The recoverable amount is the higher of the asset’s fair value less costs to sell and value in use. Given the nature of the group’s activities,
information on the fair value of an asset is usually difﬁcult to obtain unless negotiations with potential purchasers are taking place. Consequently, unless
indicated otherwise, the recoverable amount used in assessing the impairment charges described below is value in use. The group generally estimates
value in use using a discounted cash ﬂow model. The future cash ﬂows are usually adjusted for risks speciﬁc to the asset and discounted using a pre-
tax discount rate of 10% (2005 10% and 2004 9%). This discount rate is derived from the group’s post-tax weighted average cost of capital. A different
pre-tax discount rate is used where the tax rate applicable to the asset is signiﬁcantly different from the average corporate tax rate applicable to the
group as a whole.

Exploration and Production
During 2006, Exploration and Production recognized a net gain on impairment. The main element was a $340 million credit for reversals of previously
booked impairments relating to the UK North Sea, US Lower 48 and China. These reversals resulted from a positive change in the estimates used to
determine the assets’ recoverable amount since the impairment losses were recognised. This was partially offset by impairment losses totalling
$137 million. The major element was a charge of $109 million against intangible assets relating to properties in Alaska. The trigger for the impairment
test was the decision of the Alaska Department of Natural Resources to terminate the Point Thompson Unit Agreement. We are defending our right
through the appeal process. The remaining $28 million relates to other individually insigniﬁcant impairments, the impairment tests for which were
triggered by downward reserves revisions and increased tax burden.

During 2005, Exploration and Production recognized total charges of $266 million for impairment in respect of producing oil and gas properties. The
major element of this was a charge of $226 million relating to ﬁelds in the Shelf and Coastal areas of the Gulf of Mexico. The triggers for the impairment
tests were primarily the effect of Hurricane Rita, which extensively damaged certain offshore and onshore production facilities, leading to repair costs
and higher estimates of the eventual cost of decommissioning the production facilities and, in addition, reduced estimates of the quantities of
hydrocarbons recoverable from some of these ﬁelds. The recoverable amount was based on management’s estimate of fair value less costs to sell
consistent with recent transactions in the area. The remainder related to ﬁelds in the UK North Sea, which were tested for impairment following a
review of the economic performance of these assets. During 2004, as a result of impairment triggers, reviews were conducted which resulted in
impairment charges of $83 million in respect of King’s Peak in the Gulf of Mexico, $20 million in respect of two ﬁelds in the Gulf of Mexico Shelf
Matagorda Island area and $184 million in respect of various US onshore ﬁelds. A charge of $88 million was reﬂected in respect of a gas processing
plant in the US and a charge of $60 million following the blow-out of the Temsah platform in Egypt. In addition, following the lapse of the sale
agreement for oil and gas properties in Venezuela, $31 million of the previously booked impairment charge was released.

Reﬁning and Marketing
During 2006, certain assets in our Retail and Aromatics and Acetyls businesses were written down to fair value less costs to sell. During 2005, certain
retail assets were written down to fair value less costs to sell. With the formation of Oleﬁns and Derivatives at the end of 2004 certain agreements and
assets were restructured to reﬂect the arm’s-length relationship that would exist in the future. This resulted in an impairment of the petrochemical
facilities at Hull, UK.

Gas, Power and Renewables
The impairment charge for 2006 relates to certain North American pipeline assets. The trigger for impairment testing was the reduction in future
pipeline tariff revenues and increased on-going operational costs.

BP Annual Report and Accounts 2006

123

13 Impairment and losses on sale of businesses and ﬁxed assets continued

Other businesses and corporate
The impairment charge for 2006 relates to remaining chemical assets after the sale of Innovene. The impairment charge for 2005 relates to the write-off
of additional goodwill on the Solvay transactions. In 2004, in connection with the Solvay transactions, the group recognized impairment charges of
$325 million for goodwill and $270 million for property, plant and equipment in BP Solvay Polyethylene Europe. As part of a restructuring of the North
American Oleﬁns and Derivatives businesses, decisions were taken to exit certain businesses and facilities, resulting in impairments and write-downs
of $294 million.

Loss on sale of businesses or termination of operations
The principal transactions that give rise to the losses for each business segment are described below.

Reﬁning and Marketing
In 2004, activities included the closure of two manufacturing plants at Hull, UK, which produced acids; the sale of the European speciality intermediate
chemicals business; the closure of the lubricants operation of the Coryton reﬁnery in the UK and of reﬁning operations at the ATAS reﬁnery in
Mersin, Turkey.

Other businesses and corporate
For 2004, activities included the sale of the US speciality intermediate chemicals business; the sale of the fabrics and ﬁbres business; and the closure of
the linear alpha-oleﬁns production facility at Pasadena, Texas.

Loss on sale of ﬁxed assets
The principal transactions that give rise to the losses for each business segment are described below.

Exploration and Production
The group divested interests in a number of oil and natural gas properties in all three years. For 2006, the largest component of the loss is attributed to
the sale of properties in the Gulf of Mexico Shelf which includes increases in decommissioning liability estimates associated with the
hurricane-damaged ﬁelds which were divested during the year. For 2004, this included interests in oil and natural gas properties in Indonesia and the
Gulf of Mexico.

Reﬁning and Marketing
For 2006, the principal transactions contributing to the loss were retail churn. For 2004, the principal transactions contributing to the loss were
divestment of the Singapore reﬁnery and retail churn.

14 Impairment of goodwill

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Goodwill at 31 December
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

4,282
6,390
108

10,780

$ million

2005

4,371
5,955
45
10,371

Goodwill acquired through business combinations has been allocated ﬁrst to business segments and then down to the next level of cash-generating unit
that is 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 strategic performance units (SPUs),
namely Reﬁning, Retail, Lubricants, Aromatics and Acetyls and Business Marketing.

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 generally estimates value in use using a discounted cash ﬂow model. The future cash ﬂows are usually adjusted for risks speciﬁc to the
asset and discounted using a pre-tax discount rate of 10% (2005 10%). This discount rate is derived from the group’s post-tax weighted average cost of
capital. A different pre-tax discount rate is used where the tax rate applicable to the region is signiﬁcantly different from the average corporate tax rate
applicable to the group as a whole.

The four or ﬁve year business segment plans, which are approved on an annual basis by senior management, are the source for information for the

determination of the various values in use. They contain implicit 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 to the preparation of these
plans, various environmental assumptions, such as oil prices, natural gas prices, reﬁning margins, reﬁned product margins and cost inﬂation rates, are
set by senior management. These environmental assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas,
other macroeconomic factors and historical trends and variability.

For the purposes of impairment testing, the group’s Brent oil price assumption is an average $65 per barrel in 2007, $68 per barrel in 2008, $67 per

barrel in 2009, $66 per barrel in 2010, $64 per barrel in 2011 and $40 per barrel in 2012 and beyond (2005 $55 per barrel in 2005 decreasing in equal
annual steps over the following three years to $25 per barrel in 2009 and beyond). Similarly, the group’s assumption for Henry Hub natural gas prices is
an average of $8.10 per mmBtu in 2007, $8.31 per mmBtu in 2008, $7.88 per mmBtu in 2009, $8.21 per mmBtu in 2010, $7.50 per mmBtu in 2011 and
$5.50 per mmBtu in 2012 and beyond (2005 $8.65 per mmBtu in 2005 decreasing in equal annual steps over the following three years to $4.00 per
mmBtu in 2009 and beyond). These prices are adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas.

124

14 Impairment of goodwill continued

Exploration and Production
The value in use is based on the cash ﬂows expected to be generated by the projected oil or natural gas production proﬁles up to the expected dates of
cessation of production of each producing ﬁeld. 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. Cash outﬂows and hydrocarbon production
quantities for the ﬁrst ﬁve years are agreed as part of the annual planning process. Thereafter, estimated production quantities and cash outﬂows up to
the date of cessation of production are developed to be consistent with this.

Consistent with prior years, the review for impairment was carried out during the fourth quarter of 2006 using data which was appropriate at that
time. As permitted by IAS 36, the detailed calculation made in 2005 was used for the 2006 impairment test on the goodwill allocated to the Rest of
World as the criteria of IAS 36 were considered to be satisﬁed in respect of this region: the excess of the recoverable amount over the carrying amount
was substantial in 2005; there had been no signiﬁcant change in the assets and liabilities; and the likelihood that the recoverable amount would be less
than the carrying amount at the time of the test was remote. Therefore, the detailed impairment test for goodwill was reperformed only on the carrying
amounts in the UK and the US.

The following table shows the carrying value of the goodwill allocated to each of the regions of the Exploration and Production segment and the

amount by which the recoverable amount (value in use) exceeds the carrying amount of the goodwill and other non-current assets in the cash-
generating units to which the goodwill has been allocated. No impairment charge is required.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Goodwill
Excess of recoverable amount over carrying amount

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Goodwill
Excess of recoverable amount over carrying amount

UK

Rest of
Europe

USA

Rest of
World

Total

341
7,886

–
n/a

3,426
28,856

515
n/a

4,282
—

UK

Rest of
Europe

USA

Rest of
World

Total

341
3,205

–
n/a

3,515
6,421

515
n/a

4,371
–

The key assumptions required for the value-in-use estimation are the oil and natural gas prices, production volumes and the discount rate. To test the
sensitivity of the excess of the recoverable amount over the carrying amount of goodwill and other non-current assets shown above (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.

On the basis of the rules of thumb using estimated 2007 production proﬁles and an assumed average 15-year production life, it is estimated that the
long-term price of Brent that would cause the total recoverable amount to be equal to the total carrying amount of the goodwill and related non-current
assets for individual cash-generating units would be of the order of $31 per barrel for the UK and $28 per barrel for the US. No reasonably possible
change in oil or gas prices would cause the headroom in the Rest of the World to be reduced to zero.

Estimated production volumes are based on detailed data for the ﬁelds and take into account development plans for the ﬁelds agreed by

management as part of the long-term planning process. It is estimated that, if all our production were to be reduced by 10% for the whole of the next
15 years, this would not be sufﬁcient to reduce the excess of recoverable amount over the carrying amounts of the individual cash generating units to
zero. Consequently, management believes no reasonably possible change in the production assumption would cause the carrying amount of goodwill
and other non-current assets to exceed their recoverable amount.

Management also believes that currently there is no reasonably possible change in discount rate which would reduce the group’s headroom to zero.

Reﬁning and Marketing
For all cash generating units, the cash ﬂows for the next four years are derived from the four-year business segment plan. The cost inﬂation rate is
assumed to be 2.5% (2005 assumption was 2.5%) throughout the period. For determining the value in use for each of the SPUs, cash ﬂows for a
period of 10 years have been discounted and aggregated with its terminal value.

Reﬁning
Cash ﬂows beyond the four-year period are extrapolated using a 2% growth rate (2005 assumption was 2%).

The key assumptions to which the calculation of value in use for the Reﬁning unit is most sensitive are gross margins, production volumes and the
terminal value. The value assigned to the gross margin is based on a $7.25 per barrel global indicator margin (GIM), which is then adjusted for speciﬁc
reﬁnery conﬁgurations. In 2005 the value assigned to the gross margin was based on a $5.25 per barrel GIM, except in the ﬁrst year of the plan period
when a GIM of $7.25 was used, reﬂecting market conditions expected in the near term. The value assigned to the production volume is 850mmbbl a
year (2005 900mmbbl) and remains constant over the plan period. The value assigned to the terminal value assumption is 6 times earnings (2005 5
times), which is indicative of similar assets in the current market. These key assumptions reﬂect past experience and are consistent with external
sources.

Management believes that no reasonably possible change in the key assumptions would lead to the Reﬁning value in use being equal to its carrying

amount.

BP Annual Report and Accounts 2006

125

14 Impairment of goodwill continued

Retail
Cash ﬂows beyond the four-year period are extrapolated using a 1.3% growth rate (2005 assumption was no growth) reﬂecting a competitive
marketplace within a growing global economy.

The key assumptions to which the calculation of value in use for the Retail unit is most sensitive are unit gross margins, branded marketing volumes,

the terminal value and discount rate. The value assigned to the unit gross margin varies between markets. For the purpose of planning, each market
develops a gross margin based upon a market-speciﬁc reference price adjusted for the different income streams within the market and other market
speciﬁc factors. The weighted average Retail reference margin used in the plan was 5.0 cents per litre (2005 5.4 cents per litre). The value assigned to
the branded marketing volume assumption is 100 billion litres a year (2005 101 billion litres a year). The unit gross margin assumptions decline on
average by 5% a year over the plan period and marketing volume assumptions grow by an average of 5% a year over the plan period. The value
assigned to the terminal value assumption is 6.5 times earnings (2005 6.5 times), which is indicative of similar assets in the current market. These key
assumptions reﬂect past experience and are consistent with external sources.

The Retail unit’s recoverable amount exceeds its carrying amount by $2.1 billion. Based on sensitivity analysis, it is estimated that if there is an
adverse change in the unit gross margin of 11%, the recoverable amount of the Retail unit would equal its carrying amount. It is estimated that, if the
volume assumption changes by 5%, the Retail unit’s value in use changes by $1 billion and, if there is an adverse change in Retail volumes of 11 billion
litres a year, the recoverable amount of the Retail unit would equal its carrying amount. If the multiple of earnings used in the terminal value changes by
1 then the Retail unit’s value in use changes by $0.7 billion and, if the multiple of earnings falls to 3 times then the Retail value in use would equal its
carrying amount. A change of 1% in the discount rate would change the Retail value in use by $0.7 billion and, if the discount rate increases to 13%, the
value in use of the Retail unit would equal its carrying amount.

Lubricants
Cash ﬂows beyond the four-year period are extrapolated using a 3% margin growth rate (2005 assumption was 3%), which is lower than the long-term
average growth rate for the ﬁrst four years. The terminal value for the Lubricants unit represents cash ﬂows discounted to perpetuity.

For the Lubricants unit, the key assumptions to which the calculation of value in use is most sensitive are operating margin, sales volumes and the
discount rate. The average values assigned to the operating margins and sales volumes over the plan period are 53 cents per litre (2005 56 cents per
litre) and 3.5 billion litres a year (2005 3.5 billion litres) respectively. These key assumptions reﬂect past experience.

The Lubricants unit’s recoverable amount exceeds its carrying amount by $2.0 billion. Based on sensitivity analysis, it is estimated that if there is an
adverse change in the operating gross margin of 5 cents per litre, the recoverable amount of the Lubricants unit would equal its carrying amount. If the
sales volume assumption changes by 5%, the Lubricants unit’s value in use changes by $1.1 billion and, if there is an adverse change in Lubricants
sales volumes of 300 million litres a year, the recoverable amount of the Lubricants unit would equal its carrying amount. A change of 1% in the
discount rate would change the Lubricants unit’s value in use by $0.6 billion and, if the discount rate increases to 14% the value in use of the Lubricants
unit would equal its carrying amount.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Reﬁning

Retail

Lubricants

Other

Total

1,328
n/a

841
2,100

4,098
2,012

123
n/a

6,390
–

Goodwill
Excess of recoverable amount over carrying amount

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Reﬁning

Retail

Lubricants

Other

Total

1,388
n/a

832
1,511

3,612
3,953

123
n/a

5,955
–

Goodwill
Excess of recoverable amount over carrying amount

15 Distribution and administration expenses

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Distribution
Administration

Innovene operations
Continuing operations

16 Currency exchange gains and losses

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Currency exchange losses charged to income
Innovene operations
Continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

13,174
1,273

14,447
–

14,447

2005

2004

13,187
1,325
14,512
(806)
13,706

12,325
1,284
13,609
(841)
12,768

2006

222
–

222

2005

94
(80)
14

2004

55
(13)
42

126

17 Research

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

395
–

395

2005

502
(128)
374

2004

439
(139)
300

Expenditure on research
Innovene operations
Continuing operations

18 Operating leases

The table below shows the expense for the year in respect of operating leases. Where an operating lease is entered into solely by the group as the
operator of a jointly controlled asset, the total cost is included in this analysis, irrespective of any amounts that have been or will be reimbursed by joint
venture partners. Where BP is not the operator of a jointly controlled asset, operating lease costs and minimum future lease payments are excluded
from the information given below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

3,660
(131)

3,529
—

3,529

2005

2,737
(114)
2,623
(49)
2,574

2004

2,442
(115)
2,327
(89)
2,238

The minimum future lease payments at 31 December (before deducting related rental income from operating sub-leases, for 2006 of $626 million,
2005 $718 million) were as follows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

Minimum lease payments
Sub-lease rentals

Innovene operations
Continuing operations

Minimum future lease payments
Payable within

1 year
2 to 5 years
Thereafter

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The following additional disclosures represent the net operating lease expense and net minimum future lease payments, after deducting amounts
reimbursed, or to be reimbursed, by joint venture partners. Where operating lease costs are incurred in relation to the hire of equipment used in
connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. For 2006, $895 million of the cost
for the year has been capitalized.

Where BP is not the operator of a jointly controlled asset, operating lease costs and minimum future lease payments are excluded from the

information given below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The group has entered into operating leases on ships, plant and machinery, commercial vehicles, land and buildings, including service station sites and
ofﬁce accommodation. The ship leases represent approximately 36% (2005 52%) of the minimum future lease payments. The typical durations of the
leases are as follows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Minimum lease payments
Sub-lease rentals

Innovene operations
Continuing operations

Minimum future lease payments
Payable within

1 year
2 to 5 years
Thereafter

Ships
Plant and machinery
Commercial vehicles
Land and buildings

3,428
8,440
5,684

17,552

2,610
6,584
4,619
13,813

2006

2,937
(131)

2,806
—

2,806

2005

1,841
(110)
1,731
(49)
1,682

2,732
7,290
5,221

15,243

1,643
4,666
4,579
10,888

$ million

2,061
4,357
3,341
9,759

2004

1,840
(109)
1,731
(89)
1,642

$ million

1,534
3,778
3,275
8,587

Years

up to 20
up to 10
up to 15
up to 40

BP Annual Report and Accounts 2006

127

18 Operating leases continued

Principal details of the leases are:

Ships: the group has entered into a number of structured operating leases for vessels, but which generally have no renewal or extension options. In

most cases rentals vary with interest rates, but the amounts of these contingent rentals are not signiﬁcant for the years presented. The group also
routinely enters into bareboat charters, time charters and spot charters for ships on standard industry terms.

Plant and machinery: this principally comprises leases for drilling rigs. Generally these leases have no renewal options. There are no ﬁnancial

restrictions placed upon the lessee by entering into these leases.

Commercial vehicles: primarily railcar leases. Generally these leases have no renewal options. There are no ﬁnancial restrictions placed upon the

lessee by entering into these leases.

Land and buildings: the majority of these leases have no renewal options. There are no ﬁnancial restrictions placed upon the lessee by entering into

these leases.

The minimum future lease payments including executory costs associated with the leases of $482 million (after deducting related rental income from

operating sub-leases of $626 million) were as follows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

19 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

17,408

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2007
2008
2009
2010
2011
Thereafter

Exploration and evaluation costs

Exploration expenditure written off
Other exploration costs

Exploration expense for the year

Intangible assets
Net assets

Capital expenditure
Net cash used in operating activities
Net cash used in investing activities

20 Auditors’ 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

Innovene operations
Continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.

Total fees for 2006 include $5 million of additional fees for 2005 (2005 includes $4 million of additional fees for 2004). Auditors’ remuneration is included
in the income statement within distribution and administration expenses.

The tax services relate to income tax and indirect tax compliance and employee tax services.

128

2006

3,355
3,031
2,403
1,686
1,191
5,742

2006

2005

2004

624
421

1,045

4,110

4,110

1,537

421
1,498

305
379
684

4,008
4,008

274
363
637

3,761
3,761

950
379
950

754
363
754

$ million

2006

2005

2004

15

19

13

31
15

61

1
2
9
–

73
–

73

34
6
59

10
3
23
1
96
(9)
87

30
7
50

14
7
9
1
81
(3)
78

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

20 Auditors’ remuneration continued

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 to that of other potential service providers. These services are for a ﬁxed term.
Fees paid to major ﬁrms of accountants other than Ernst & Young for other services amounted to $52 million (2005 $151 million and 2004 $82 million).

21 Finance costs

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Bank loans and overdrafts
Other loans
Finance leases
Interest payable
Capitalized at 5.25% (2005 4.25% and 2004 3%)a
Early redemption of borrowings and ﬁnance leases

2006

130
1,020
46

1,196
(478)
–

2005

44
828
38
910
(351)
57
616

2004

34
573
37
644
(204)
–
440

2006

1,940
(2,410)

(470)
245
23
–

(202)
–

(202)

2005

2,022
(2,138)
(116)
201
57
–
142
3
145

2004

2,012
(1,983)
29
196
91
41
357
(17)
340

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Tax relief on capitalized interest is $182 million (2005 $123 million and 2004 $73 million).

718

22 Other ﬁnance income and expense

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Interest on pension and other post-retirement beneﬁt plan liabilities
Expected return on pension and other post-retirement beneﬁt plan assets
Interest net of expected return on plan assets
Unwinding of discount on provisions
Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP
Change in discount rate for provisionsa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Innovene operations
Continuing operations

a Revaluation of environmental and litigation and other provisions at a different discount rate.

BP Annual Report and Accounts 2006

129

Deferred tax charge

UK
Overseas

UK
Overseas

Total
UK
Overseas

23 Taxation

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Tax on proﬁt
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Current tax

2004

2006

2005

$ million

Charge for the year
Adjustment in respect of prior years

Innovene operations
Continuing operations
Deferred tax

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Innovene operations
Continuing operations
Tax on proﬁt from continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Tax on proﬁt from continuing operations may be analysed as follows:
Current tax charge

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Tax included in statement of recognized income and expense
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Current tax

2004

2006

2005

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Current year tax charge

Deferred tax

Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Tax included in statement of recognized income and expense

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

This comprises:
Currency translation differences
Exchange gain on translation of foreign operations transferred to loss on sale of businesses
Actuarial gain relating to pensions and other post-retirement beneﬁts
Share-based payments
Net (gain) loss on revaluation of cash ﬂow hedges
Unrealized (gain) loss on available-for-sale ﬁnancial assets
Tax included in statement of recognized income and expense

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

11,199
442

11,641
159

11,800

1,771
(1,240)

531
–

531

12,331

2,657
9,143
11,800

500
31
531

3,157
9,174
12,331

(51)
(51)

985
–
985
934

201
–
820
(26)
47
(108)
934

10,511
(977)
9,534
(910)
8,624

349
(450)
(101)
950
849
9,473

880
7,744
8,624

(489)
1,338
849

391
9,082
9,473

45
45

309
(95)
214
259

(11)
(95)
356
–
(63)
72
259

7,217
(308)
6,909
(48)
6,861

138
(74)
64
157
221
7,082

1,839
5,022
6,861

(218)
439
221

1,621
5,461
7,082

23
23

50
–
50
73

208
–
(96)
(39)
–
–
73

130

23 Taxation continued

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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt before taxation from continuing operations
Tax on proﬁt from continuing operations
Effective tax rate

UK statutory corporation tax rate
Increase (decrease) resulting from

UK supplementary and overseas taxes at higher rates
Tax reported in equity-accounted entities
Adjustments in respect of prior years
Restructuring beneﬁts
Current year losses unrelieved (prior year losses utilized)
Other

Effective tax rate

Deferred tax liability

Depreciation
Pension plan surplus
Other taxable temporary differences

Deferred tax asset

Petroleum revenue tax
Pension plan and other post-retirement beneﬁt plan deﬁcits
Decommissioning, environmental and other provisions
Derivative ﬁnancial instruments
Tax credit and loss carry forward
Other deductible temporary differences

2006

2005

2004

34,642

12,331

31,921
9,473

24,966
7,082

36%

30%

28%

% of proﬁt before tax from continuing operations

30

30

30

11
(3)
(2)
–
(1)
1
36

9
(3)
(3)
(1)
(3)
1
30

8
(3)
(1)
(2)
(3)
(1)
28

21,463
1,733
4,439

27,635

(457)
(1,824)
(2,960)
(974)
(662)
(2,642)

(9,519)

18,116

16,701
(112)
16,589
(178)
(101)
214
(81)
16,443

18,529
957
3,864
23,350

(407)
(1,822)
(2,033)
(807)
(253)
(1,585)
(6,907)
16,443

16,051
–
16,051
358
64
50
178
16,701

16,443
–

16,443
175
531
985
(18)

18,116

1,484
173
417

2,074

4
71
(800)
(115)
220
(923)

(1,543)

531

(778)
170
887
279

121
220
(144)
(629)
(245)
297
(380)
(101)

492
10
(113)
389

77
92
106
–
6
(606)
(325)
64

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Deferred tax
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Income statement

2006

2005

2004

Balance sheet

2006

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Net deferred tax liability

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Analysis of movements during the year

At 1 January
Adoption of IAS 32 and 39

Restated
Exchange adjustments
Charge for the year on ordinary activities
Charge for the year in the statement of recognized income and expense
Other movements
At 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Factors that may affect future tax charges
The group earns income in many different countries and, on average, pays taxes at rates higher than the UK statutory rate. The overall impact of these
higher taxes, which include the supplementary charge on UK North Sea proﬁts, is subject to changes in enacted tax rates and the country mix of the
group’s income. The current high oil price environment continues to create conditions that encourage host governments to review their ﬁscal regimes.

In 2006 the UK supplementary charge was raised to 20% increasing the group’s effective tax rate by 2%. The impact of the additional one-off
deferred tax adjustment relating to this rate change ($460 million) was largely offset by utilization of relieving measures speciﬁcally provided in the
legislation.

Under IFRS, the results of equity-accounted entities are reported within the group’s proﬁt before taxation on a post-tax basis. The impact of this
treatment in 2006 has been to reduce the reported effective tax rate by around 3%. This effect is expected to continue for the foreseeable future
assuming similar income levels from the entities.

Going forward, the effective tax rate is expected to be around 37%.
At 31 December 2006, deferred tax liabilities were recognized for all taxable temporary differences:

– Except where the deferred tax liability arises on goodwill that is not tax deductible or the initial recognition of an asset or liability in a transaction that

is not a business combination and, at the time of the transaction, affects neither the accounting proﬁt nor taxable proﬁt or loss.

– In respect of taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where the

timing of the reversal of the temporary differences can be controlled by the group and it is probable that the temporary differences will not reverse in
the foreseeable future.

BP Annual Report and Accounts 2006

131

23 Taxation continued

At 31 December 2006, deferred tax assets were recognized for all deductible temporary differences, carry forward of unused tax assets and unused
tax losses, to the extent that it is probable that taxable proﬁt will be available against which the deductible temporary differences and the carry forward
of unused tax assets and unused tax losses can be utilized:
– Except where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in
a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting proﬁt nor taxable proﬁt or loss.
– In respect of deductible temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, deferred tax

assets are only recognized to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable proﬁt will
be available against which the temporary differences can be utilized.
The group has around $4.7 billion (2005 $5.1 billion and 2004 $7.7 billion) of carry-forward tax losses in the UK and Germany, which would be
available to offset against future taxable income. These tax losses do not time expire. At the end of 2006, $216 million of deferred tax assets were
recognized on these losses (2005 $176 million of assets and 2004 no tax assets were recognized). Tax assets are recognized only to the extent that it is
considered more likely than not that suitable taxable income will arise. The group has not recognized any signiﬁcant deferred tax assets in relation to
carry forwards of losses in other taxing jurisdictions and this is not expected to have a material effect on the group’s tax rate in future years.

At the end of 2006, the group had around $2.0 billion (2005 $1.5 billion) of unused tax credits in the UK and the US, in respect of which no deferred

tax assets have been recognized. In 2006, $828 million of tax credits were utilized (2005 $774 million).

The major components of temporary differences in the current year are tax depreciation, US inventory holding gains (classiﬁed under other taxable

temporary differences) and provisions.

24 Dividends

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

pence per share

cents per share

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

2006

2005

2004

2006

2005

2004

Dividends announced and paid

Preference shares
Ordinary shares

2

2

2

March
June
September
December

5.288
5.251
5.324
5.241

21.104

4.522
4.450
5.119
5.061
19.152

3.674
3.807
3.860
3.910
15.251

9.375
9.375
9.825
9.825

38.400

8.500
8.500
8.925
8.925
34.850

6.750
6.750
7.100
7.100
27.700

1,922
1,893
1,943
1,926

7,686

1,823
1,808
1,871
1,855
7,359

1,492
1,477
1,536
1,534
6,041

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Dividend announced per ordinary share,

payable in March 2007

5.258

–

–

10.325

–

–

1,999

–

–

The group does not account for dividends until they have been paid. The accounts for the year ended 31 December 2006 do not reﬂect the dividend
announced on 6 February 2007 and payable in March 2007; this will be treated as an appropriation of proﬁt in the year ended 31 December 2007.

132

25 Earnings per ordinary share

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

cents per share

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

109.84
109.00

105.74
104.52

78.24
76.87

Basic earnings per share
Diluted earnings per share

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.

For the diluted earnings per share calculation, the proﬁt attributable to ordinary shareholders is adjusted for the unwinding of the discount on the
deferred consideration for the acquisition of our interest in TNK-BP. The weighted average number of shares outstanding during the year is adjusted for
the number of shares to be issued for the deferred consideration for the acquisition of our interest in TNK-BP and the number of shares that would be
issued on conversion of outstanding share options into ordinary shares using the treasury stock method.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt from continuing operations attributable to BP shareholders
Less dividend requirements on preference shares
Proﬁt from continuing operations attributable to BP ordinary shareholders
Proﬁt (loss) from discontinued operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Unwinding of discount on deferred consideration for acquisition of investment in TNK-BP (net of tax)
Diluted proﬁt for the year attributable to BP ordinary shareholders

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

shares thousand

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share schemes
Potential dilutive effect of ordinary shares issuable as consideration for BP’s interest in the TNK-BP joint

venture

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

22,025
2

22,023
(25)

21,998
16

22,014

2005

22,157
2
22,155
184
22,339
40
22,379

2004

17,697
2
17,695
(622)
17,073
64
17,137

2006

2005

2004

20,027,527
109,813

21,125,902
87,743

21,820,535
56,985

58,118

20,195,458

197,802
21,411,447

415,016
22,292,536

The number of ordinary shares outstanding at 31 December 2006, excluding treasury shares, was 19,510,496,490. Between the reporting date and the
date of completion of these ﬁnancial statements there has been a net decrease of 128,708,405 in the number of ordinary shares outstanding as a result
of share buybacks net of share issues. The number of potential ordinary shares issuable through the exercise of employee share options was
111,029,592 at 31 December 2006. There has been a decrease of 25,627,050 in the number of potential ordinary shares between the reporting date
and the completion of the ﬁnancial statements.

Earnings (loss) per share for the discontinued operations is derived from the net proﬁt (loss) attributable to ordinary shareholders from discontinued
operations of $25 million loss (2005 $184 million proﬁt and 2004 $622 million loss), divided by the weighted average number of ordinary shares for both
basic and diluted amounts as shown above.

BP Annual Report and Accounts 2006

133

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

4,442

3,129

118,554

30,642

3,006

12,000

11,211

182,984

17,800

26 Property, plant and equipment

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Land
and land
improvements

Buildings

Plant,
machinery
and
equipment

Fixtures,
ﬁttings and
ofﬁce
equipment

Transport-
ation

Oil depots,
storage
tanks and
service
stations

Of which:
assets
under
construction

Total

Cost

At 1 January 2006
Exchange adjustments
Acquisitions
Additions
Transfersa
Reclassiﬁed as assets held for sale
Deletions

At 31 December 2006
Depreciation

At 1 January 2006
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Transfersb
Reclassiﬁed as assets held for sale
Deletions

At 31 December 2006
Net book amount at 31 December 2006
Cost

At 1 January 2005
Exchange adjustments
Acquisitions
Additions
Transfers
Deletions

At 31 December 2005
Depreciation

At 1 January 2005
Exchange adjustments
Charge for the year
Impairment losses
Transfers
Deletions

Oil and
gas
properties

113,474
72
–
11,264
(628)
–
(5,628)

61,253
54
6,214
4
(340)
(887)
–
(5,048)

107,066
(15)
–
8,773
325
(2,675)

57,111
(7)
5,696
266
6
(1,819)

2,835
239
–
381
–
(1)
(325)

1,437
147
149
5
–
–
(1)
(267)

2,846
(136)
3
191
–
(69)

1,419
(60)
143
–
–
(65)

28,780
1,028
16
2,146
–
(842)
(486)

13,417
552
1,059
98
–
–
(325)
(173)

42,302
(2,364)
–
2,451
–
(13,609)

19,556
(916)
1,691
590
–
(7,504)

4,576
255
–
81
–
(15)
(455)

709
15
52
87
–
–
–
(188)

5,471
(387)
19
41
–
(568)

863
(17)
79
–
–
(216)

2,247
138
–
841
(1)
–
(219)

1,450
107
418
–
–
(1)
–
(212)

2,827
(180)
1
383
–
(784)

1,859
(67)
399
–
–
(741)

13,266
27
–
22
–
(1)
(1,314)

7,104
12
301
1
–
–
(1)
(471)

13,588
(4)
–
133
–
(451)

7,141
(76)
309
–
–
(270)

11,235
517
–
918
–
(47)
(1,412)

176,413
2,276
16
15,653
(629)
(906)
(9,839)

16,115
137
–
11,560
(9,787)
–
(225)

5,096
154
718
9
–
–
(15)
(708)

90,466
1,041
8,911
204
(340)
(888)
(342)
(7,067)

12,421
(1,117)
–
816
–
(885)

186,521
(4,203)
23
12,788
325
(19,041)

15,038
(66)
27
10,467
(8,668)
(683)

5,480
(496)
704
42
–
(634)

93,429
(1,639)
9,021
898
6
(11,249)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

675

3,767

1,470

1,659

61,250

57,304

14,628

16,014

1,762

1,244

6,946

5,054

5,254

5,957

91,985

90,999

17,800

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

4,576

2,835

113,474

28,780

2,247

13,266

11,235

176,413

16,115

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December 2005
Net book amount at 31 December 2005
Assets held under ﬁnance leases at
net book amount included above
At 31 December 2006
At 31 December 2005

709

3,867

1,437

1,398

61,253

52,221

13,417

15,363

1,450

797

7,104

6,162

5,096

6,139

90,466

85,947

16,115

5
8

18
24

42
46

341
315

1
2

9
9

29
35

445
439

Decommissioning asset at net book

amount included above

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Cost Depreciation

Net

6,391
5,398

2,558
2,342

3,833
3,056

At 31 December 2006
At 31 December 2005

a Includes $1,087 million transferred to equity-accounted investments.
b Includes $890 million transferred to equity-accounted investments.

134

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

4,590

2,128

6,718

27 Goodwill

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

28 Intangible assets

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration
expenditure

Other
intangibles

Exploration
expenditure

Other
intangibles

2006

2005

10,371
524
64
(60)
(119)

10,780

–
–
–

–

10,780

11,182
(488)
86
–
(409)
10,371

325
59
(384)
–
10,371

Cost

At 1 January
Exchange adjustments
Acquisitions
Reclassiﬁed as assets held for sale
Deletions

At 31 December
Impairment losses

At 1 January
Impairment in the year
Deletions

At 31 December
Net book amount at 31 December

Cost

At 1 January
Exchange adjustments
Acquisitions
Additions
Transfersa
Deletions

At 31 December
Amortization

At 1 January
Exchange adjustments
Charge for the year
Transfers
Impairment losses
Deletions

2006

Total

6,401
52
187
1,915
(698)
(1,139)

1,629
20
841
(2)
109
(1,125)

4,661
2
–
1,537
(698)
(912)

653
–
624
(2)
109
(904)

1,740
50
187
378
–
(227)

976
20
217
–
–
(221)

2005

Total

5,688
(110)
–
1,481
(325)
(333)
6,401

1,483
(40)
466
(6)
–
(274)
1,629
4,772

4,311
(66)
–
950
(325)
(209)
4,661

550
(8)
305
(6)
–
(188)
653
4,008

1,377
(44)
–
531
–
(124)
1,740

933
(32)
161
–
–
(86)
976
764

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December
Net book amount at 31 December

480

4,110

992

1,136

1,472

5,246

a Included in transfers of exploration expenditure is $240 million transferred to equity-accounted investments.

BP Annual Report and Accounts 2006

135

29 Investments in jointly controlled entities

The signiﬁcant jointly controlled entities of the BP group at 31 December 2006 are shown in Note 50. The principal joint venture is the TNK-BP joint
venture. Summarized ﬁnancial information for the group’s share of jointly controlled entities is shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Sales and other operating revenues
Proﬁt before interest and taxation
Finance costs and other ﬁnance expense
Proﬁt before taxation
Taxation
Minority interest
Proﬁt for the yeara
Innovene operations
Continuing operations
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Minority interest

TNK-BP

17,863

4,616
192

4,424
1,467
193

2,764
–

11,243
5,403

16,646

3,594
4,226

7,820
473

Other

6,119

1,218
169

1,049
260
–

789
–

7,612
2,184

9,796

1,272
3,370

4,642
–

2006

Total

23,982

5,834
361

5,473
1,727
193

3,553
–

18,855
7,587

26,442

4,866
7,596

12,462
473

TNK-BP

15,122
3,817
128
3,689
976
104
2,609
–
2,609
11,564
4,278
15,842
3,617
3,553
7,170
583
8,089

Other

4,255
779
104
675
220
–
455
19
474
6,310
1,682
7,992
914
2,550
3,464
–
4,528

2005

Total

19,377
4,596
232
4,364
1,196
104
3,064
19
3,083
17,874
5,960
23,834
4,531
6,103
10,634
583
12,617

---------- ------------------ ------------------ ------------------ ------------------ ------------------ ---------------- -------- ------------------ ------------------- ------------------ ------------------ ------------------ -----------------

---------- ------------------ ------------------ ------------------ ------------------ ------------------ ---------------- -------- ------------------ ------------------- ------------------ ------------------ ------------------ -----------------

---------- ------------------ ------------------ ------------------ ------------------ ------------------ ---------------- -------- ------------------ ------------------- ------------------ ------------------ ------------------ -----------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2,764

789

3,553

TNK-BP

7,839
2,421
101
2,320
675
43
1,602
–
1,602

Other

2,225
586
69
517
314
–
203
13
216

2004

Total

10,064
3,007
170
2,837
989
43
1,805
13
1,818

---------- ------------------ ------------------ ------------------ ------------------ ------------------ ---------------- -------- ------------------ ------------------- ------------------ ------------------ ------------------ -----------------

8,353

5,154

13,507

Group investment in jointly controlled entities

Group share of net assets (as above)b
Loans made by group companies to jointly

8,353

5,154

13,507

8,089

4,528

12,617

controlled entities

---------- ------------------ ------------------ ------------------ ------------------ ------------------ ---------------- -------- ------------------ ------------------- ------------------ ------------------ ------------------ -----------------

–

1,567

1,567

8,353

6,721

15,074

–
8,089

939
5,467

939
13,556

a BP’s share of the profit of TNK-BP in 2006 includes a net gain of $892 million (2005 $270 million) on the disposal of certain assets.
b Total includes BP’s share of retained earnings of $2,752 million (2005 $2,242 million).

In 2004, BP agreed with the Alfa Group and Access-Renova (AAR), its partner in the TNK-BP joint venture, to incorporate AAR’s 50% interest in Slavneft
into TNK-BP in return for $1,418 million in cash (which was subsequently reduced by receipt of pre-acquisition dividends of $64 million to $1,354 million).
BP Solvay Polyethylene Europe became a subsidiary with effect from 2 November 2004. See Note 4 for further information. In 2005, it was sold as

part of the Innovene operations.

During 2004, BP China and Sinopec announced the establishment of the BP-Sinopec (Zhejiang) Petroleum Co. Ltd, a retail joint venture between BP

and Sinopec. Based on the existing service station network of Sinopec, the joint venture will build, operate and manage a network of 500 service
stations in Hangzhou, Ningbo and Shaoxing. Also during 2004, BP China and PetroChina announced the establishment of BP-PetroChina Petroleum
Company Ltd. Located in Guangdong, one of the most developed provinces in China, the joint venture will acquire, build, operate and manage 500
service stations in the province. The initial investment in both joint ventures amounted to $106 million.

Transactions between the signiﬁcant jointly controlled entities and the group are summarized below. In addition to the amount receivable at
31 December 2005 shown below, a further $771 million was receivable from TNK-BP in respect of dividends: there was no dividend receivable at
31 December 2006.

Sales to jointly controlled entities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Amount
receivable at
31 December

2005

Amount
receivable at
31 December

$ million

2004

Amount
receivable at
31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Product

Sales

Sales

Sales

Atlantic 4 Holdings
Atlantic LNG 2/3 Company of Trinidad and Tobago
BP Solvay Polyethylene Europea
Pan American Energy
Ruhr Oel
TNK-BP

LNG
LNG
Chemicals feedstocks
Crude oil
Employee services
Employee services

227
1,123
–
389
330
189

35
99
–
–
597
99

–
1,157
–
75
169
125

–
–
–
2
527
14

–
532
230
118
192
49

–
–
–
4
780
–

a The 2004 sales to BP Solvay Polyethylene Europe shown above relate to the period to 2 November 2004.

136

29 Investments in jointly controlled entities continued

Purchases from jointly controlled entities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

Amount
payable at

Amount
payable at

$ million

2004

Amount
payable at
31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Product

Purchases

31 December Purchases

31 December Purchases

Atlantic LNG 2/3 Company of Trinidad and Tobago

Plant processing fee/

natural gas

Crude oil
Reﬁnery operating costs
Crude oil and oil products

254
4
758
2,662

–
2
32
85

190
661
384
908

–
81
134
17

120
481
477
1,809

–
43
249
80

Pan American Energy
Ruhr Oel
TNK-BP

30 Investments in associates

The signiﬁcant associates of the group are shown in Note 50. Summarized ﬁnancial information for the group’s share of associates is set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------------------

Sales and other operating revenues
Proﬁt before interest and taxation
Finance costs and other ﬁnance expense
Proﬁt before taxation
Taxation
Proﬁt for the year
Innovene operations
Continuing operations
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Net assets
Group investment in associates

Group share of net assets (as above)a
Loans made by group companies to associates

2004

5,509
632
48
584
121
463
(1)
462

2006

8,792

669
63

606
164

442
–

442

6,573
2,294

8,867

2,029
2,600

4,629

4,238

4,238
1,737

2005

6,879
665
57
608
143
465
(5)
460
5,514
2,248
7,762
1,755
2,037
3,792
3,970

3,970
2,247
6,217

------------------------------------------------------------------------------------------------------------------------------------------- -------------------------------------------------------------------------------------------------------------------------------------------

a Includes BP’s share of retained earnings of $480 million (2005 $696 million).

5,975

BP Solvay Polyethylene North America became a subsidiary with effect from 2 November 2004. See Note 4 for further information. In 2005, it was sold
as part of the Innovene operations.

Transactions between the signiﬁcant associates and the group are summarized below.

Sales to associates

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Amount
receivable at
31 December

2005

Amount
receivable at
31 December

$ million

2004

Amount
receivable at
31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Product

Sales

Sales

Sales

Atlantic LNG Company of Trinidad and Tobago
The Baku-Tbilisi-Ceyhan Pipeline Co

BP Solvay Polyethylene North Americaa

LNG
Crude oil/employee

services

Chemicals feedstocks

635

112
–

62

579

4
–

99
–

–

3
–

414

46
217

–

3
–

Purchases from associates

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

Amount
payable at

Amount
payable at

31 December Purchases

$ million

2004

Amount
payable at
31 December

Product

Purchases

Crude oil
Crude oil
Crude oil
Chemicals feedstocks

866
1,547
155
–

31 December Purchases
1,355
2,260
–
–

91
145
–
–

164
214
–
–

866
1,547
–
9

91
145
–
–

Abu Dhabi Marine Areas
Abu Dhabi Petroleum Co.
The Baku-Tbilisi-Ceyhan Pipeline Co
BP Solvay Polyethylene North Americaa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a The 2004 BP Solvay Polyethylene North America sales and purchases shown above relate to the period to 2 November 2004.

BP Annual Report and Accounts 2006

137

31 Other investments

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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.

The fair value of listed investments has been determined by reference to quoted market bid prices. Unlisted investments are stated at cost less

accumulated impairment losses.

The table below shows other investments stated at cost.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Listed
Unlisted

At cost
Listed
Unlisted

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

During 2006, the group sold its interests in Zhenhai Reﬁning and Chemicals Company, Eiffage, the French-based construction company, and Enagas,
the Spanish gas transport grid operator, for aggregate proceeds of $0.8 billion, recognizing gains of $0.5 billion. Also in 2006, the group acquired a stake
in Rosneft for $1 billion. In 2004, the group disposed of its interests in PetroChina and Sinopec for aggregate proceeds of $2.4 billion and recognized
gains of $1.3 billion.

32 Inventories

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Crude oil
Natural gas
Reﬁned petroleum and petrochemical products

Supplies

Trading inventories

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

1,516
181

1,697

2005

830
137
967

2006

2005

1,056
219

1,275

250
173
423

2006

5,357
127
10,817

16,301
1,222

17,523
1,392

2005

5,457
164
10,700
16,321
919
17,240
2,520
19,760
163,026

Cost of inventories expensed in the income statement

18,915

187,183

138

33 Trade and other receivables

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Current Non-current

Current

Non-current

2006

–
–
–
862

32,656
635
267
5,134

38,692

862

33,565
1,345
186
5,806
40,902

2005

–
–
–
770
770

2005

Trade
Jointly controlled entities
Associates
Other

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies

US dollar

US dollar

Sterling

Sterling

Total

Euro

Total

Euro

Functional currency

Currency of denomination

2006

Currency of denomination

US dollar
Sterling
Euro
Other currencies

–
376
692
248

1,217
–
7
1

123
1,652
–
1

5,286
39
1
–

6,626
2,067
700
250

1,316

1,225

1,776

5,326

9,643

–
404
1,496
458
2,358

1,111
–
1
1
1,113

354
453
–
1
808

6,045
15
948
–
7,008

7,510
872
2,445
460
11,287

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Trade and other receivables of the group at 31 December have the maturities shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
Over 5 years

At 1 January
Exchange adjustments
Charge for the year
Utilization
At 31 December

2006

38,692
187
86
82
76
431

39,554

2005

40,902
129
82
56
51
452
41,672

2006

374
32
158
(143)

421

2005

526
(30)
67
(189)
374

2006

2005

2,052

1,594

29
509

2,590

73
1,293
2,960

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The movement in the valuation allowance for trade receivables is set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The carrying amounts of Trade and other receivables approximate their fair value. Trade and other receivables are predominantly non-interest bearing.

34 Cash and cash equivalents

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Cash at bank and in hand
Cash equivalents

Listed
Unlisted

Carrying amount at 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Cash equivalents are classiﬁed as available-for-sale ﬁnancial assets and as such are recorded at fair value. Cash and cash equivalents at 31 December
2006 includes $773 million which is restricted. This relates principally to amounts on deposit to cover trading positions on trading exchanges.

BP Annual Report and Accounts 2006

139

35 Trade and other payables

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Current Non-current

Current

Non-current

2006

–
–
–
899
–
531

28,614
251
627
763
78
11,803
42,136

28,319
87
305
852
59
12,614

42,236

1,430

2005

–
–
–
1,281
–
654
1,935

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies

US dollar

US dollar

Sterling

Sterling

Total

Euro

Total

Euro

Functional currency

Currency of denomination

2006

Currency of denomination

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

–
396
185
322

1,476
–
2
4

165
507
–
8

5,818
–
1
–

7,459
903
188
334

903

1,482

680

5,819

8,884

–
133
611
339
1,083

1,802
–
4
12
1,818

157
306
–
38
501

6,640
–
17
–
6,657

8,599
439
632
389
10,059

Trade and other payables of the group at 31 December 2006 have the maturities shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Trade
Jointly controlled entities
Associates
Production and similar taxes
Social security
Other

US dollar
Sterling
Euro
Other currencies

Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
Over 5 years

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The carrying amounts of Trade and other payables approximate their fair value. Included within Other payables for 2005 was the deferred consideration
for the acquisition of our interest in TNK-BP, which was discounted on initial recognition. The remaining Trade and other payables are predominantly
interest free.

140

2006

42,236
269
215
153
184
609

43,666

2005

42,136
276
211
182
179
1,087
44,071

36 Derivative ﬁnancial instruments

An outline of the group’s ﬁnancial risks and the policies and objectives pursued in relation to those risks is set out in the quantitative and qualitative
disclosures about market risk section on pages 61-64.

This note contains the disclosures required by IAS 32 for derivative ﬁnancial instruments. IAS 39 prescribes strict criteria for hedge accounting,

whether as a cash ﬂow or fair value hedge, and requires that any derivative that does not meet these criteria should be classiﬁed as held for trading and
fair valued. BP adopted IAS 32 and IAS 39 with effect from 1 January 2005 without restating prior periods’ ﬁnancial information. Consequently, the
group’s accounting policy under UK GAAP has been used for 2004. The policy under UK GAAP and the disclosures required by UK GAAP for derivative
ﬁnancial instruments are shown in Note 37.

In the normal course of business the group is a party to 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 trading activity that is undertaken in
conjunction with each of these activities using a similar range of contracts.

The fair value of derivative ﬁnancial instruments at 31 December are set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Contractual
or notional
amounts

Contractual
or notional
amounts

Contractual
or notional
amounts

Contractual
or notional
amounts

Fair
value
liability

Fair
value
liability

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fair
value
asset

Fair
value
asset

2006

2005

Derivatives held for trading

Currency derivatives
Oil derivatives
Natural gas derivatives
Power derivatives
Other derivatives

Embedded derivatives

Natural gas and LNG contracts
Interest rate contracts

Cash ﬂow hedges

Currency forwards, futures and swaps
Currency options
Commodity futures

Fair value hedges

Currency forwards, futures and swaps
Interest rate swaps

Of which – current

– non-current

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

137
2,664
6,558
3,232
113

12,704

6,820
57,600
139,961
22,250
499

227,130

(32)
(2,368)
(5,703)
(3,190)
–

3,923
59,524
107,145
25,859
–

(11,293)

196,451

41
2,765
6,836
3,341
–
12,983

634
56,394
148,794
25,793
–
231,615

107
–

107

205
14
–

219

228
33

261

107

219
–

219

2,223
2,677
–

4,900

3,865
1,688

5,553

394

(2,171)
(26)

(2,197)

11,810
150

11,960

(33)
–
–

(33)

(13)
(91)

(104)

–

1,274
–
–

1,274

598
4,397

4,995

–

13,398

238,196

(13,627)

214,680

10,373
3,025

(9,424)
(4,203)

4,620
–
4,620

666
693
274
1,633

2,566
324
2,890
346
241,104

587
–
587

34
–
57
91

222
19
241
63
13,965
10,056
3,909

1,687
52,524
128,330
26,618
–
209,159

8,563
150
8,713

3,100
1,470
–
4,570

1,967
7,521
9,488
–
231,930

(18)
(2,826)
(6,307)
(3,158)
–
(12,309)

(3,098)
(30)
(3,128)

(94)
(35)
–
(129)

(124)
(217)
(341)
–
(15,907)
(10,036)
(5,871)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Hedges of net investments in foreign entities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The fair values of embedded derivatives are included within non-current and current derivative ﬁnancial instruments on the group balance sheet as this
is believed to be the most appropriate presentation. Previously, these balances were reported within non-current and current prepayments and accrued
income and accruals and deferred income. The comparative ﬁgures have been restated to conform with the 2006 presentation.

Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. This activity is undertaken in conjunction with risk management activities.
Derivatives held for trading purposes are recognized at fair value and 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 described in the section on market risk exposure.

BP Annual Report and Accounts 2006

141

36 Derivative ﬁnancial instruments continued

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

Changes during the year in the net fair value of derivatives held for trading purposes were as follows.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Currency

Oil
price

Natural gas
price

Power
price

Fair value of contracts at 1 January 2006
Contracts realized or settled in the year
Fair value of options at inception
Fair value of other new contracts entered into during the year
Change in fair value due to changes in valuation techniques or key assumptions
Other changes in fair values relating to price
Exchange adjustments
Fair value of contracts at 31 December 2006

Fair value of contracts at 1 January 2005
Contracts realized or settled in the year
Fair value of options at inception
Fair value of other new contracts entered into during the year
Other changes in fair values relating to price
Fair value of contracts at 31 December 2005

23
(16)
–
–
–
98
–

(54)
23
–
–
54
23

(61)
85
36
–
1
231
4

Oil
price

(171)
175
(73)
–
8
(61)

529
(327)
247
2
–
421
(17)

558
(735)
(65)
24
747
529

183
(37)
(70)
1
–
(22)
(13)

177
76
(9)
10
(71)
183

Other

–
(106)
45
–
–
174
–

–
–
–
–
–
–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

105

296

855

42

113

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Currency

Natural gas
price

Power
price

Other

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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 commonly known as ‘day one proﬁt’. When all of the remaining
contracts can be valued using observable market data this gain or loss is recognized in income. Changes in valuation from this initial valuation are
recognized immediately through income.

The following table shows the change in the associated fair value of assets and liabilities.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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 recycled into the income statement
Fair value of contracts not recognized through proﬁt at 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

gas price Power price

Power price

Natural

(39)
(2)
5

(10)
(1)
11

Natural
gas price

(15)
(24)
–
(39)

–
(10)
–
(10)

(36)

–

Derivative assets held for trading have the following fair values, contractual or notional values and maturities.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Currency derivatives

Fair value
Notional value
Oil price derivatives

Fair value
Notional value

Natural gas price derivatives

Fair value
Notional value

Power price derivatives

Fair value
Notional value
Other derivatives

Fair value
Notional value

Total derivative assets held for trading

Fair value
Notional value

142

117
6,338

2,520
52,591

4,532
81,102

2,845
16,063

64
213

–
75

116
4,736

919
33,499

274
4,999

26
149

12
241

20
210

374
9,837

86
1,171

23
137

3
89

7
62

2
54

1
1

3
23

–
–

137
6,820

2,664
57,600

166
5,186

114
3,396

453
6,941

6,558
139,961

27
17

–
–

–
–

–
–

–
–

–
–

3,232
22,250

113
499

10,078
156,307

1,335
43,458

515
11,596

203
5,354

117
3,451

456
6,964

12,704
227,130

36 Derivative ﬁnancial instruments continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Currency derivatives

Fair value
Notional value
Oil price derivatives

Fair value
Notional value

Natural gas price derivatives

Fair value
Notional value

Power price derivatives

Fair value
Notional value

Total derivative assets held for trading

Fair value
Notional value

28
358

6
73

2,476
52,260

225
3,378

4,509
113,897

1,194
17,562

2,474
19,156

594
5,049

1
51

37
676

528
8,560

119
857

9,487
185,671

2,019
26,062

685
10,144

1
28

19
45

292
4,021

143
535

455
4,629

1
32

8
35

125
2,068

11
196

145
2,331

4
92

–
–

41
634

2,765
56,394

188
2,686

6,836
148,794

–
–

3,341
25,793

192
2,778

12,983
231,615

Derivative liabilities held for trading have the following fair values, contractual or notional values and maturities.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Currency derivatives

Fair value
Notional value
Oil price derivatives

Fair value
Notional value

Natural gas price derivatives

Fair value
Notional value

Power price derivatives

Fair value
Notional value

Total derivative liabilities held for trading

Fair value
Notional value

(8)
3,183

(7)
204

(2,230)
55,488

(89)
3,541

(3,931)
63,593

(875)
25,962

(2,777)
20,086

(289)
4,457

(8,946)
142,350

(1,260)
34,164

(12)
214

(29)
363

(273)
7,710

(98)
1,299

(412)
9,586

(2)
92

(19)
111

(2)
56

(1)
21

(1)
174

(32)
3,923

–
–

(2,368)
59,524

(109)
3,059

(86)
1,591

(429)
5,230

(5,703)
107,145

(26)
17

–
–

–
–

(3,190)
25,859

(156)
3,279

(89)
1,668

(430)
5,404

(11,293)
196,451

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Currency derivatives

Fair value
Notional value
Oil price derivatives

Fair value
Notional value

Natural gas price derivatives

Fair value
Notional value

Power price derivatives

Fair value
Notional value

Total derivative liabilities held for trading

Fair value
Notional value

(12)
1,013

(4)
177

(2,486)
49,732

(275)
2,276

(1)
119

(26)
446

(1)
170

(20)
35

–
67

(19)
35

–
141

–
–

(18)
1,687

(2,826)
52,524

(3,967)
90,916

(1,319)
25,269

(591)
6,457

(187)
2,903

(89)
1,577

(154)
1,208

(6,307)
128,330

(2,459)
20,030

(557)
4,990

(59)
778

(70)
625

(13)
195

–
–

(3,158)
26,618

(8,924)
161,691

(2,155)
32,712

(677)
7,800

(278)
3,733

(121)
1,874

(154)
1,349

(12,309)
209,159

BP Annual Report and Accounts 2006

143

36 Derivative ﬁnancial instruments continued

The following tables show the net fair value of derivatives held for trading at 31 December analysed by maturity period and by methodology of fair value
estimation.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

1-2 years

2-3 years

3-4 years

4-5 years

62
29
(14)

60
54
(12)

33
19
(6)

–
36
(8)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

1,132

77

102

46

28

26

1,411

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Over
5 years

2
4
20

Over
5 years

(8)
–
46
38

Total

348
1,053
10

Total

(73)
620
127
674

1-2 years

2-3 years

3-4 years

4-5 years

(86)
(48)
(2)
(136)

46
(41)
3
8

42
60
75
177

33
(11)
2
24

Less than
1 year

191
911
30

Less than
1 year

(100)
660
3
563

Prices actively quoted refers to the fair value of contracts valued solely using quoted prices in an active market. Prices sourced from observable data or
market corroboration refers to the fair value of contracts valued in part using active quotes and in part using observable, market-corroborated data for
example, swaps and physical forward contracts. Prices based on models and other valuation methods refers to the fair value of a contract valued in part
using internal models due to the absence of quoted prices, including over-the-counter options. The net change in fair value of contracts based on
models and other valuation methods during the year was a loss of $117 million (2005 $130 million gain).

Credit risk
Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. The primary activities of the group are oil and
natural gas exploration and production, gas and power marketing and trading, oil reﬁning and marketing and the manufacture and marketing of
petrochemicals. The group’s principal customers, suppliers and ﬁnancial institutions with which it conducts business are located throughout the world.

The group has a credit policy that governs the management of credit risk, including the establishment of counterparty credit limits and speciﬁc

transaction approvals. The group limits credit risk by assessing creditworthiness of potential counterparties before entering into transactions with them
and continuing to evaluate their creditworthiness after transactions have been initiated. Creditworthiness is assessed using Moody’s Investors Service,
Standard & Poor’s and qualitative and quantitative data. The group attempts to mitigate credit risk by entering into contracts that permit netting and
allow for termination of the contract upon the occurrence of certain events of default. Depending upon the creditworthiness of the counterparty, the
group may require collateral in the form of cash deposits or letters of credit and parent company guarantees.

The maximum exposure of the group to credit risk is represented by the balance sheet carrying amount for all ﬁnancial instruments within the scope

of IAS 32, principally derivative ﬁnancial instruments, trade and other receivables and ﬁnancial guarantees. Financial guarantees in respect of
equity-accounted entities were $1,123 million and ﬁnancial guarantees in respect of third parties were $789 million at 31 December 2006. The
maximum exposure to credit risk does not take account of collateral of $689 million.

Trade and other derivative assets and liabilities are presented on a net basis where netting arrangements are in place with counterparties are

unconditional and where there is an intent to settle amounts due on a net basis

Market risk
The group measures its market risk exposure, i.e. potential gain or loss in fair values, on its held-for-trading activity using value-at-risk techniques. These
techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from
possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a
snapshot of the end-of-day exposures and the history of one-day price movements, together with the correlation of these price movements. The group
calculates value at risk for the bulk of instruments and exposures in the held-for-trading category, other than the UK North Sea natural gas embedded
derivatives, for which a sensitivity analysis is calculated.

The potential movement in fair values is expressed to 1.65 standard deviations which is equivalent to a 95% conﬁdence level. This means that, in
broad terms, one would expect to see an increase or a decrease in fair values greater than the value at risk on one occasion per month if the portfolio
were left unchanged.

The value-at-risk model takes account of 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 futures,
swap agreements and options. Additionally, where physical commodities are held as part of a trading position, they are also included in these
calculations. For options, a linear approximation is included in the value-at-risk models, when full revaluation is not possible.

The following table shows values at risk for the held-for-trading activities described above.

Value at risk on 1.65 standard deviations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

$ million

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

High

Low

Average

Year end

High

Low

Average

Year end

1
5
56
29
11

–
–
16
10
2

1
2
29
19
6

–
–
22
15
3

1
5
80
39
16

–
1
17
6
2

–
2
33
15
7

–
1
31
17
9

Interest rate trading
Currency trading
Oil price trading
Natural gas price trading
Power price trading

144

36 Derivative ﬁnancial instruments continued

Gains and losses relating to derivative contracts are included within sales and other operating revenues in the income statement. The contract types
treated in this way include futures, options, swaps and certain forward sales and purchase contracts where delivery is routinely obviated by the
purchase or sale of offsetting contracts. Also included within sales and other operating revenues are gains and losses on inventory held for trading
purposes and the change in fair value of derivative contracts which have been determined to be not for trading purposes but are required to be fair
valued. The total amount relating to these items was a gain of $2,842 million (2005 $838 million gain and 2004 $1,216 million gain).

Derivative assets held for trading denominated in currencies other than the functional currency of individual operating units are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Currency of denomination

2005

Currency of denomination

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies

US dollar

US dollar

Sterling

Sterling

Total

Euro

Total

Euro

Functional currency

US dollar
Sterling

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

–
198

55
–

–
2,227

244
1

299
2,426

198

55

2,227

245

2,725

137
–
137

–
1,504
1,504

141
1,504
1,645

Derivative liabilities held for trading denominated in currencies other than the functional currency of individual operating units are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Currency of denomination

2005

Currency of denomination

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies

US dollar

US dollar

Sterling

Sterling

Total

Euro

Total

Euro

Functional currency

US dollar
Sterling

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

–
(18)

(59)
–

–
(2,383)

(276)
–

(335)
(2,401)

(18)

(59)

(2,383)

(276)

(2,736)

(110)
–
(110)

–
(1,523)
(1,523)

(110)
(1,523)
(1,633)

4
–
4

–
–
–

–
–
–

–
–
–

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. 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.

These contracts are valued using price curves for each of the different products that are built up from active market pricing data and extrapolated to
2018 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.

The following table shows the changes during the year in the net fair value of embedded derivatives.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fair value of contracts at 1 January
Contracts realized or settled in the year
Other changes in fair values relating to price
Exchange adjustments
Fair value of contracts at 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Embedded derivative assets have the following fair values, contractual or notional values and maturities.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Natural gas and LNG embedded derivatives

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Fair value
Notional value

49
119

58
100

–
–

–
–

–
–

–
–

107
219

BP Annual Report and Accounts 2006

145

Natural gas
and LNG
price

(2,511)
762
21
(336)

2006

Interest
rate

(30)
–
4
–

Natural gas
and LNG
price

(659)
138
(2,287)
297
(2,511)

2005

Interest
rate

(17)
–
(13)
–
(30)

(2,064)

(26)

36 Derivative ﬁnancial instruments continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Natural gas and LNG embedded derivatives

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Fair value
Notional value

330
425

176
484

76
465

5
450

–
429

–
2,367

587
4,620

Embedded derivative liabilities have the following fair values, contractual or notional values and maturities.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Natural gas and LNG embedded derivatives

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Fair value
Notional value

Interest rate embedded derivatives

Fair value
Notional value

(444)
1,352

(433)
1,229

(320)
1,279

(218)
1,278

(186)
1,249

(570)
5,423

(2,171)
11,810

–
–

(26)
150

–
–

–
–

–
–

–
–

(26)
150

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Natural gas and LNG embedded derivatives

Less than
1 year

1-2 years

2-3 years

3-4 years

4-5 years

Total

Over
5 years

Fair value
Notional value

Interest rate embedded derivatives

Fair value
Notional value

(953)
740

(703)
870

(472)
1,097

(237)
832

(180)
767

(553)
4,257

(3,098)
8,563

–
–

–
–

(30)
150

–
–

–
–

–
–

(30)
150

The following tables show the net fair value of embedded derivatives at 31 December analysed by maturity period and by methodology of fair value

estimation.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1-2 years

2-3 years

3-4 years

4-5 years

–
58
(459)

–
–
(320)

–
–
(218)

–
–
(186)

Over
5 years

–
–
(570)

Total

–
107
(2,197)

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

(395)

(401)

(320)

(218)

(186)

(570)

(2,090)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1-2 years

2-3 years

3-4 years

4-5 years

–
28
(542)
(514)

–
–
(426)
(426)

–
–
(231)
(231)

–
–
(182)
(182)

Over
5 years

–
–
(565)
(565)

Total

–
79
(2,620)
(2,541)

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

Less than
1 year

–
49
(444)

Less than
1 year

–
51
(674)
(623)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The net change in fair value of contracts based on models and other valuation methods during the year is a gain of $423 million (2005 loss of

$1,773 million).

Sensitivity analysis
Detailed below for the natural gas embedded derivatives is a sensitivity of the fair value to immediate 10% favourable and adverse changes in the key
assumptions.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December 2006

At 31 December 2005

2 to 12 years
4,968 million therms

3 to 13 years
8,220 million therms

4.5%

4.5%

$(2,171) million

$(2,590) million

Remaining contract terms
Contractual / notional amount
Discount rate – nominal risk free
Fair value asset (liability)

146

36 Derivative ﬁnancial instruments continued

The reduction in notional contract gas volumes compared to 2005 was in part due to deliveries during the year but additionally due to the termination

of a contract to supply 1,822 million therms from 2008-2018.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Gas oil and

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Gas price

fuel oil price Power price

2006

Discount
rate

Gas price

Gas oil and
fuel oil price

Power price

2005

Discount
rate

Favourable 10% change
Unfavourable 10% change

332
(341)

7
(7)

45
(41)

31
(32)

408
(427)

30
(45)

(63)
58

34
(34)

These sensitivities are hypothetical and should not be considered to be predictive of future performance. Changes in fair value generally cannot be
extrapolated because the relationship of change in assumption to change in fair value may not be linear. Also, in this 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.

The fair value gain (loss) on embedded derivatives is shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Natural gas and LNG embedded derivatives
Interest rate embedded derivatives
Fair value gain (loss)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

604
4

608

2005

(2,034)
(13)
(2,047)

The fair value gain (loss) in the above table includes $179 million of exchange losses (2005 $115 million of exchange gains) arising on transactions which
are denominated in a currency other than the functional currency of an individual operating unit.

Embedded derivative liabilities denominated in currencies other than the functional currency of individual operating units are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Currency of denomination

2005

Currency of denomination

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other
currencies

US dollar

US dollar

Sterling

Sterling

Total

Euro

Total

Euro

Functional currency

US dollar

–

(1,003)

–

–

(1,003)

–

–

–

–

–

Cash ﬂow hedges
At 31 December, the group held forward currency contracts, cylinders and options which were being used to hedge the foreign currency risk of highly
probable transactions. The effective portion of the change in fair value of the hedging instrument is recognized directly in equity, whilst the ineffective
portion is recognized in proﬁt or loss. 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 previously
recognized in equity is transferred to proﬁt or loss. The hedges were assessed to be highly effective.

An analysis of the changes in net fair value is shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fair value of cash ﬂow hedges at 1 January
Change in fair value during the year
Fair value recognized in income statement during the year
Fair value on capital expenditure hedging recycled into carrying value of assets during the year
Fair value of cash ﬂow hedges at 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

(38)
398
(168)
(6)

186

2005

198
(191)
(8)
(37)
(38)

The forward currency contracts and cylinders primarily cover the purchase of sterling and euros for US dollars, with 85% of such contracts due to

mature within the next year.

Fair value hedges
At 31 December, the group held interest rate and currency swap contracts as fair value hedges of the interest rate risk on ﬁxed rate debt issued by the
group. These hedges were assessed to be highly effective.

The interest rate and currency swaps have an average maturity of 2 to 3 years, and are used to convert sterling, euro, Swiss franc and Australian

dollar denominated borrowings into US dollar ﬂoating rate debt.

Hedges of net investments in foreign entities
At 31 December, the group held currency swap contracts as a hedge of a long-term investment in a UK subsidiary. The hedge was assessed to be
highly effective. At 31 December 2006, the hedge had a fair value of $107 million (2005 $63 million) and the gain on the hedge recognized in equity was
$105 million (2005 $58 million). US dollars have been sold forward for sterling purchased, with a maturity of 2 to 3 years.

BP Annual Report and Accounts 2006

147

37 Derivative ﬁnancial instruments (UK GAAP)

The following information for 2004 shows certain disclosures required by UK GAAP (FRS 13 ‘Derivatives and other Financial Instruments: Disclosures’).

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

The purpose for which a derivative contract is used is identiﬁed at inception. To qualify as a derivative for risk management, the contract must be in

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

The group accounts for derivatives using the following methods:

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

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

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

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

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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Unrecognized

Carried forward in the balance sheet

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Gains and losses at 1 January 2004

of which accounted for in income in 2004

Gains and losses at 31 December 2004

of which expected to be recognized in income in 2005

Gains

Losses

Total

Gains

Losses

Total

331
98
487
259

(130)
(28)
(408)
(267)

201
70
79
(8)

1,003
438
1,063
265

(425)
(75)
(364)
(77)

578
363
699
188

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

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

148

37 Derivative ﬁnancial instruments (UK GAAP) continued

The group calculates value at risk on all instruments that are held for trading purposes and that therefore give an exposure to market risk. The value-

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

The following table shows values at risk for trading activities.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Interest rate trading
Foreign exchange trading
Oil price trading
Natural gas price trading
Power price trading

Interest rate trading
Foreign exchange trading
Oil price trading
Natural gas price trading
Power price trading

High

Low

Average

Year end

1
4
55
23
10

–
1
18
6
1

–
1
29
13
4

–
1
45
10
4

Net gain (loss)

4
136
1,371
461
160
2,132

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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

38 Finance debt

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Within
1 yeara
543
12,321

12,864
60

After
1 year

806
9,525

10,331
755

2006

Total

1,349
21,846

23,195
815

Within
1 yeara
155
8,717
8,872
60
8,932

After
1 year

547
8,962
9,509
721
10,230

2005

Total

702
17,679
18,381
781
19,162

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Amounts due within one year include current maturities of long-term debt.

12,924

11,086

24,010

Bank loans
Other loans
Total borrowings
Net obligations under ﬁnance leases

Included within Other loans repayable within one year above are US Industrial Revenue/Municipal Bonds of $2,744 million (2005 $2,462 million) with
maturity periods ranging from 1 to 34 years. They are classiﬁed as repayable within one year as the bondholders typically have the option to tender
these bonds for repayment on interest reset dates. Any bonds that are tendered are usually remarketed and BP has not experienced any signiﬁcant
repurchases. BP considers these bonds to represent long-term funding when assessing the maturity proﬁle of its ﬁnance debt and they are reﬂected as
such in the borrowings repayment schedule below. Similar treatment is applied for loans associated with long-term gas supply contracts totalling
$1,976 million (2005 $992 million) that mature over 10 years.

At 31 December 2006, the group had substantial amounts of undrawn borrowing facilities available, including committed facilities of $4,700 million, of
which $4,300 million are in place for at least 5 years (2005 $4,500 million all expiring in 2006). These facilities are with a number of international banks
and borrowings under them would be at pre-agreed rates. Certain of these facilities support the group’s commercial paper programme.
At 31 December 2006, the group’s share of third-party ﬁnance debt of jointly controlled entities and associates was $4,942 million

(2005 $3,266 million) and $1,143 million (2005 $970 million) respectively. These amounts are not reﬂected in the group’s debt on the balance sheet.
We have in place a European Debt Issuance Programme (DIP) under which the group may raise $10 billion of debt for maturities of one month or
longer. At 31 December 2006 the amount drawn down against the DIP was $7,893 million. In addition, the group has in place a US Shelf Registration
under which it may raise $10 billion of debt with maturities of one month or longer. At 31 December 2006 there had not been any draw-down.

BP Annual Report and Accounts 2006

149

38 Finance debt continued

Analysis of borrowings by year of expected repayment

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Bank loans Other loans

Total

Bank loans

Other loans

2006

3,355
152
426
391
400
970
805
687
4,109
3,653

3,202
62
329
301
318
896
674
653
4,081
3,626

153
90
97
90
82
74
131
34
28
27

806
543

14,142
7,704

14,948
8,247

1,349

21,846

23,195

–
18
21
24
26
34
35
35
98
256
547
155
702

2,842
203
182
188
558
446
537
2,223
2,219
3,018
12,416
5,263
17,679

Due after 10 years
Due within 10 years
9 years
8 years
7 years
6 years
5 years
4 years
3 years
2 years

1 year

US dollar
Sterling
Euro
Other currencies

US dollar
Sterling
Euro
Other currencies

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Interest rates
The weighted average interest rate on ﬁnance debt is 5%.

The proportion of ﬂoating rate debt at 31 December 2006 was 73% of total ﬁnance debt outstanding. Aside from debt issued in the US municipal
bond markets, interest rates on ﬂoating rate debt denominated in US dollars are linked principally to the London Inter-Bank Offer Rate (LIBOR), while
rates on debt in other currencies are based on local market equivalents. The group monitors interest rate risk using a process of sensitivity analysis.
Assuming no changes to the ﬁnance debt and related hedge balances, it is estimated that a change of 1% in the general level of interest rates on
1 January 2007 would change 2007 proﬁt before tax by approximately $180 million.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fixed rate

Floating rate

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Weighted
average
interest
rate
%

Weighted
average
time for
which rate
is ﬁxed
Years

Weighted
average
interest
rate
%

Amount
$ million

Total
$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

6,358

17,652

24,010

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

A further analysis of interest rates on total borrowings, excluding ﬁnance lease obligations, at 31 December, is given below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Weighted average
interest rate
%

2006

2005

2006

Amount
$ million

5,998
–
61
299

665
–
–
157
822

3
–
8
8

11
–
–
14

5
–
3
7

7
–
–
9

6
5
4
8

5
6
3
12

5
7
5
9

4
4
7

17,055
35
134
428

18,073
76
150
41
18,340

9,888
35
177
231

10,331

3,078
4,167
2,744
2,875

12,864

6
5
4
7

5
4
6

Bank and other loans – long term

US dollar
Sterling
Euros
Other currencies

Bank and other loans – short term

Current maturities of long-term debt
Commercial paper
US Industrial Revenue/Municipal bonds
Bank loans and other borrowings

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

150

23,195

$ million

2005

Total

2,842
221
203
212
584
480
572
2,258
2,317
3,274
12,963
5,418
18,381

2006

23,053
35
195
727

2005

18,738
76
150
198
19,162

$ million

2005

9,178
29
144
158
9,509

3,007
1,911
2,462
1,492
8,872
18,381

38 Finance debt continued

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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Minimum future 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

2006

2005

82
376
873

1,331
516

815

60
164
591

78
320
838
1,236
455
781
60
133
588

Fair values
For 2006, 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 2006, whereas in the balance sheet
the amount would be reported under current liabilities. Long-term borrowings also include US Industrial Revenue/Municipal Bonds and loans associated
with long-term gas supply contracts classiﬁed on the balance sheet as current liabilities.

The carrying value of the group’s short-term borrowings, comprising mainly commercial paper, bank loans and overdrafts, approximates their fair

value. The fair value of the group’s long-term borrowings and ﬁnance lease obligations is estimated using quoted prices or, where these are not
available, discounted cash ﬂow analyses based on the group’s current incremental borrowing rates for similar types and maturities of borrowing.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Carrying
amount

7,040
16,155
815

Fair value

7,040
16,201
832

24,073

24,010

Fair value

3,297
15,313
803
19,413

2005

Carrying
amount

3,297
15,084
781
19,162

Short-term borrowings
Long-term borrowings
Net obligations under ﬁnance leases
Total ﬁnance debt

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

39 Analysis of changes in net debt

Net debt is current and non-current ﬁnance debt less cash and cash equivalents. The net debt ratio is the ratio of net debt to net debt plus total equity.
The net debt ratio at 31 December 2006 was 20% (2005 17%).

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Finance
debt

(19,162)
–

(19,162)
(172)
(13)
(4,049)
(581)
(33)

Cash and
cash
equivalents

2,960
–

2,960
47
–
(417)
–
–

2006

Net
debt

(16,202)
–

(16,202)
(125)
(13)
(4,466)
(581)
(33)

(24,010)

2,590

(21,420)

85,465

Finance
debt

(23,091)
(147)
(23,238)
(44)
–
3,803
171
146
(19,162)

Cash and
cash
equivalents

1,359
–
1,359
(88)
–
1,689
–
–
2,960

2005

Net
debt

(21,732)
(147)
(21,879)
(132)
–
5,492
171
146
(16,202)
80,765

Movement in net debt
At 1 January
Adoption of IAS 39
Restated
Exchange adjustments
Debt acquired
Net cash ﬂow
Fair value hedge adjustment
Other movements
At 31 December
Equity

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BP Annual Report and Accounts 2006

151

40 Provisions

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Decommissioning Environmental

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Decommissioning

Environmental

At 1 January 2006
Exchange adjustments
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Utilization
Deletions
At 31 December 2006
Of which – expected to be incurred within 1 year

– expected to be incurred in more than 1 year

At 1 January 2005
Exchange adjustments
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Utilization
Deletions
At 31 December 2005
Of which – expected to be incurred within 1 year

– expected to be incurred in more than 1 year

8,365

324
8,041

2,127

444
1,683

3,152

1,164
1,988

13,644

1,932
11,712

Litigation
and other

2,295
44
2,111
(270)
47
(1,068)
(7)

Litigation
and other

1,570
(35)
1,464
(86)
32
(650)
–
2,295
451
1,844

2,311
31
423
(355)
45
(324)
(4)

2,457
(32)
565
(335)
47
(366)
(25)
2,311
489
1,822

Total

11,056
88
4,676
(625)
245
(1,571)
(225)

Total

9,599
(105)
3,052
(421)
201
(1,144)
(126)
11,056
1,102
9,954

6,450
13
2,142
–
153
(179)
(214)

5,572
(38)
1,023
–
122
(128)
(101)
6,450
162
6,288

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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 and discounted using a real discount rate of 2.0% (2005 2.0%). These
costs are expected to be incurred over the next 30 years. While the provision is based on the best estimate of future costs and the economic lives of
the facilities and pipelines, there is uncertainty regarding both the amount and timing of incurring these costs.

Provisions for environmental remediation are made when a clean-up is probable and the amount reasonably determinable. Generally, this coincides
with commitment to a formal plan of action or, if earlier, on divestment or closure of inactive sites. The provision for environmental liabilities has been
estimated using existing technology, at current prices and discounted using a real discount rate of 2.0% (2005 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 liability.

The group also holds provisions for litigation, expected rental shortfalls on surplus properties, and sundry other liabilities. Included within the new

or increased provisions made for 2006 is an amount of $925 million (2005 $700 million) in respect of the Texas City incident of which a total of
$1,355 million has been disbursed to claimants ($863 million in 2006 and $492 million in 2005).

To the extent that these liabilities are not expected to be settled within the next three years, the provisions are discounted using either a nominal

discount rate of 4.5% (2005 4.5%) or a real discount rate of 2.0% (2005 2.0%), as appropriate.

41 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, in the UK the primary pension arrangement is a funded ﬁnal salary pension plan which remains open to new employees. Retired

employees draw the majority of their beneﬁt as an annuity.

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.

Contributions to funded deﬁned beneﬁt plans are based on advice from independent actuaries using actuarial methods, the objective of which is

to provide adequate funds to meet pension obligations as they fall due. During 2006, contributions of $438 million (2005 $340 million and 2004
$249 million) and $181 million (2005 $279 million and 2004 $30 million) were made to the UK plans and US plans respectively. In addition, contributions
of $136 million (2005 $140 million and 2004 $116 million) were made to other funded deﬁned beneﬁt plans. The aggregate level of contributions in 2007
is expected to be approximately $750 million.

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 cost of providing pensions and other post-retirement beneﬁts is assessed annually by independent actuaries using the projected unit credit

method. The date of the most recent actuarial review was 31 December 2006.

152

41 Pensions and other post-retirement beneﬁts continued

The material ﬁnancial assumptions used for estimating the beneﬁt obligations of the various plans are set out below. The assumptions used to
evaluate accrued pension and other post-retirement beneﬁts at 31 December in any year are used to determine pension and other post-retirement
expense for the following year, that is, the assumptions at 31 December 2006 are used to determine the pension liabilities at that date and the pension
cost for 2007.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Financial assumptions

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2006

2005

2006

2005

UK

2004

USA

2004

Discount rate for pension plan liabilities
Discount rate for post-retirement beneﬁt plans
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inﬂation

5.1
n/a
4.7
2.8
2.8
2.8

4.75
n/a
4.25
2.50
2.50
2.50

5.25
n/a
4.00
2.50
2.50
2.50

5.7
5.9
4.2
nil
nil
2.4

5.50
5.50
4.25
nil
nil
2.50

5.75
5.75
4.00
nil
nil
2.50

4.8
n/a
3.6
1.8
1.1
2.2

4.00
n/a
3.25
1.75
1.00
2.00

5.00
n/a
4.00
2.50
2.50
2.50

%

Other

2004

In addition to the ﬁnancial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reﬂect best practice in
the countries in which we provide pensions, and have been chosen with regard to the latest available published tables adjusted where appropriate to
reﬂect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension liabilities are in
the UK, the US and Germany, where our assumptions are as follows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Mortality assumptions

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

2004

USA

2004

2006

2005

2006

2005

2006

2005

2004

23.9
26.8
25.0
27.8

23.0
26.0
23.9
26.9

23.0
26.0
23.9
26.9

24.2
26.0
25.8
26.9

21.9
25.6
21.9
25.6

21.9
25.6
21.9
25.6

22.2
26.9
25.2
29.6

22.1
26.7
25.0
29.4

20.3
25.4
20.3
25.4

Life expectancy at age 60 for a male currently aged 60
Life expectancy at age 60 for a female currently aged 60
Life expectancy at age 60 for a male currently aged 40
Life expectancy at age 60 for a female currently aged 40

The assumed future US healthcare cost trend rate is as follows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Assumed future US healthcare cost trend rate
Beneﬁciaries aged under 65
Beneﬁciaries aged over 65

2007

2008

2009

2010

2011

2012

8.0
10.0

7.5
9.5

7.0
8.5

6.5
7.5

6.0
6.5

5.5
5.5

5.0
5.0

BP’s post-retirement medical plans in the US provide amongst other things prescription drug coverage for Medicare-eligible retirees. The group’s
obligation for other post-retirement beneﬁts reﬂects the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the
Act). The provisions of the Act provide for a federal subsidy for plans that provide prescription drug beneﬁts and meet certain qualiﬁcations, and
alternatively would allow prescription drug plan sponsors to co-ordinate with the Medicare beneﬁt. BP reﬂects the impact of the legislation by reducing
its actuarially determined obligation for post-retirement beneﬁts and reducing the net cost for post-retirement beneﬁts. For the year ended 31 December
2006 the reduction in net cost was $40 million (2005 $41 million).

Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufﬁcient to meet the obligation of
the various plans. The assets of the trusts are invested in a manner consistent with ﬁduciary obligations and principles that reﬂect current practices in
portfolio management.

A signiﬁcant proportion of the assets are held in equities, owing to a higher expected level of return over the long term with an acceptable level of
risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment
portfolios are highly diversiﬁed. The long-term asset allocation policy for the major plans is as follows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Years

Germany

%

2013 and
subsequent
years

Policy range
%

55 – 85
15 – 35
0 – 10

Asset category
Total equity
Fixed income/cash
Property/real estate

Some of the group’s pension funds use derivatives to manage their asset mix and the level of risk. The group’s main pension funds do not directly
invest 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.

BP Annual Report and Accounts 2006

153

41 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 signiﬁcant deﬁned beneﬁt plans at 31 December
are set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

Expected
long-term
rate of return

Market
value

Expected
long-term
rate of return

Market
value

Expected
long-term
rate of return

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

%

$ million

%

$ million

%

$ million

UK pension plans

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

US pension plans

7.0

29,261

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

US other post-retirement beneﬁt plans

8.0

7,955

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

7.5
4.7
6.5
3.8

8.5
5.0
8.0
3.2

8.5
5.0

7.6
4.6
4.7
3.0

23,631
3,881
1,370
379

6,528
1,371
15
41

19
7

1,158
1,199
120
191

7.5

26

5.8

2,668

7.50
4.25
6.50
3.50
7.00

8.50
4.75
8.00
3.00
8.00

8.50
4.75
7.25

7.50
4.00
5.75
1.50
5.50

18,465
2,719
1,097
1,001
23,282

5,961
1,079
21
256
7,317

20
8
28

991
943
130
216
2,280

7.50
4.50
6.50
4.00
7.00

8.50
4.75
8.00
3.00
8.00

8.50
4.75
7.25

8.00
4.25
5.25
3.50
6.00

2004

Market
value

17,329
2,859
1,660
459
22,307

6,043
1,057
28
55
7,183

21
9
30

933
857
114
288
2,192

Equities
Bonds
Property
Cash

Equities
Bonds
Property
Cash

Equities
Bonds

Other plans
Equities
Bonds
Property
Cash

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

One-percentage point

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase

Decrease

Investment return

Effect on pension and other post-retirement beneﬁt expense in 2007

Discount rate

Effect on pension and other post-retirement beneﬁt expense in 2007
Effect on pension and other post-retirement beneﬁt obligation at 31 December 2006

(383)

383

(52)
(5,013)

75
6,433

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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

One-percentage point

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Effect on US other post-retirement beneﬁt expense in 2007
Effect on US other post-retirement obligation at 31 December 2006

Increase

Decrease

31
349

(25)
(289)

154

41 Pensions and other post-retirement beneﬁts continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Analysis of the amount charged to proﬁt before interest and taxation
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Current service cost
Past service cost
Settlement, curtailment and special termination beneﬁts
Payments to deﬁned contribution plans
Total operating chargea

beneﬁt plans Other plans
139
39
227
16
421

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Total
829
3
231
177
1,240

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

42
–
–
–
42

UK
pension
plans
432
(74)
4
–
362

US
pension
plans
216
38
–
161
415

US
other post-
retirement

Analysis of the amount credited (charged) to other ﬁnance expense
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Expected return on plan assets
Interest on plan liabilities
Other ﬁnance income (expense)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,711
(1,006)
705

2,410
(1,940)
470

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2
(186)
(184)

133
(325)
(192)

564
(423)
141

Analysis of the amount recognized in the statement of recognized income and expense
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial gain recognized in statement of recognized income and expense

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,967
772
(124)
2,615

1,305
114
(24)
1,395

141
352
(197)
296

–
111
80
191

521
195
17
733

Movements in beneﬁt obligation during the year
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Beneﬁt obligation at 1 January
Exchange adjustments
Current service cost
Past service cost
Interest cost
Curtailment
Settlement
Special termination beneﬁtsb
Contributions by plan participants
Beneﬁt payments (funded plans)
Beneﬁt payments (unfunded plans)
Acquisitions
Disposals
Actuarial gain on obligation
Beneﬁt obligation at 31 December

38,855
3,380
829
3
1,940
(20)
(22)
273
43
(1,749)
(569)
–
118
(648)
42,433

20,063
2,748
432
(74)
1,006
(20)
(22)
46
38
(981)
–
–
143
(90)
23,289

3,478
–
42
–
186
–
–
–
–
(4)
(211)
–
–
(191)
3,300

7,414
632
139
39
325
–
–
227
5
(149)
(321)
–
(7)
(155)
8,149

7,900
–
216
38
423
–
–
–
–
(615)
(37)
–
(18)
(212)
7,695

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Movements in fair value of plan assets during the year
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Fair value of plan assets at 1 January
Exchange adjustments
Expected return on plan assetsc
Contributions by plan participants
Contributions by employers (funded plans)
Beneﬁt payments (funded plans)
Acquisitions
Disposals
Actuarial gain on plan assetsc
Fair value of plan assets at 31 December

23,282
3,325
1,711
38
438
(981)
–
143
1,305
29,261

32,907
3,447
2,410
43
755
(1,749)
–
130
1,967
39,910

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2,280
122
133
5
136
(149)
–
–
141
2,668

7,317
–
564
–
181
(615)
–
(13)
521
7,955

28
–
2
–
–
(4)
–
–
–
26

Surplus (deﬁcit) at 31 December
Represented by

5,972

260

(3,274)

(5,481)

(2,523)

Asset recognized
Liability recognized

Funded
Unfunded

Funded
Unfunded

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The surplus (deﬁcit) may be analysed between funded and unfunded plans as follows

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The deﬁned beneﬁt obligation may be analysed between funded and unfunded plans as follows

6,089
(117)
5,972

6,089
(117)
5,972

617
(357)
260

601
(341)
260

(23,172)
(117)
(23,289)

(7,354)
(341)
(7,695)

–
(3,274)
(3,274)

(30)
(3,244)
(3,274)

(56)
(3,244)
(3,300)

47
(5,528)
(5,481)

(379)
(5,102)
(5,481)

6,753
(9,276)
(2,523)

6,281
(8,804)
(2,523)

(3,047)
(5,102)
(8,149)

(33,629)
(8,804)
(42,433)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Included within production and manufacturing expenses and distribution and administration expenses.
b The charge for special termination benefits represents the increased liability arising as a result of early retirements occuring as part of a restructuring programme in the UK and Europe.
c 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 2006 reimbursement balances due from or to other companies in respect of pensions amounted to $479 million reimbursement assets
(2005 $465 million) and $71 million reimbursement liabilities (2005 $71 million). These balances are not included as part of the pension liability, but are
reﬂected elsewhere in the group balance sheet.

BP Annual Report and Accounts 2006

155

41 Pensions and other post-retirement beneﬁts continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

Analysis of the amount charged to proﬁt before interest and taxation
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Current service cost
Past service cost
Settlement, curtailment and special termination beneﬁts
Payments to deﬁned contribution plans
Total operating charge
Innovene operations
Continuing operationsa

Other plans
140
51
10
14
215
(21)
194

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Total
785
41
47
172
1,045
(86)
959

UK
pension
plans
379
5
37
–
421
(38)
383

US
pension
plans
216
(10)
–
158
364
(24)
340

US
other post-
retirement
beneﬁt plans
50
(5)
–
–
45
(3)
42

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Analysis of the amount credited (charged) to other ﬁnance expense
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Expected return on plan assets
Interest on plan liabilities
Other ﬁnance income (expense)
Innovene operations
Continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2,138
(2,022)
116
(3)
113

1,456
(1,003)
453
(10)
443

557
(444)
113
(5)
108

123
(368)
(245)
10
(235)

2
(207)
(205)
2
(203)

Analysis of the amount recognized in the statement of recognized income and expense
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial gain (loss) recognized in statement of recognized income and expense

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

3,364
(2,177)
(212)
975

3,111
(1,884)
(14)
1,213

157
(470)
16
(297)

96
(59)
(197)
(160)

–
236
(17)
219

Movements in beneﬁt obligation during the year
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Beneﬁt obligation at 1 January
Exchange adjustments
Current service cost
Past service cost
Interest cost
Special termination beneﬁts
Contributions by plan participants
Beneﬁt payments (funded plans)
Beneﬁt payments (unfunded plans)
Acquisitions
Disposals
Actuarial (gain) loss on obligation
Beneﬁt obligation at 31 December

39,945
(3,122)
785
41
2,022
47
42
(1,612)
(549)
39
(1,172)
2,389
38,855

20,399
(2,194)
379
5
1,003
37
37
(922)
(1)
–
(578)
1,898
20,063

3,676
–
50
(5)
207
–
–
(4)
(204)
16
(39)
(219)
3,478

8,044
(928)
140
51
368
10
5
(116)
(314)
3
(303)
454
7,414

7,826
–
216
(10)
444
–
–
(570)
(30)
20
(252)
256
7,900

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Movements in fair value of plan assets during the year
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Fair value of plan assets at 1 January
Exchange adjustments
Expected return on plan assetsb
Contributions by plan participants
Contributions by employers (funded plans)
Beneﬁt payments (funded plans)
Acquisitions
Disposals
Actuarial gain on plan assetsb
Fair value of plan assets at 31 December

31,712
(2,664)
2,138
42
759
(1,612)
8
(840)
3,364
32,907

22,307
(2,469)
1,456
37
340
(922)
–
(578)
3,111
23,282

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2,192
(195)
123
5
140
(116)
–
(26)
157
2,280

7,183
–
557
–
279
(570)
8
(236)
96
7,317

30
–
2
–
–
(4)
–
–
–
28

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

3,219

(583)

(3,450)

(5,134)

(5,948)

Surplus (deﬁcit) at 31 December
Represented by

Asset recognized
Liability recognized

Funded
Unfunded

Funded
Unfunded

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The surplus (deﬁcit) may be analysed between funded and unfunded plans as follows

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The deﬁned beneﬁt obligation may be analysed between funded and unfunded plans as follows

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

3,240
(21)
3,219

3,240
(21)
3,219

–
(583)
(583)

(226)
(357)
(583)

(20,042)
(21)
(20,063)

(7,543)
(357)
(7,900)

–
(3,450)
(3,450)

(32)
(3,418)
(3,450)

(60)
(3,418)
(3,478)

42
(5,176)
(5,134)

(476)
(4,658)
(5,134)

(2,756)
(4,658)
(7,414)

3,282
(9,230)
(5,948)

2,506
(8,454)
(5,948)

(30,401)
(8,454)
(38,855)

a Included within production and manufacturing expenses and distribution and administration expenses.
b 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.

156

41 Pensions and other post-retirement beneﬁts continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

Analysis of the amount charged to proﬁt before interest and taxation
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Current service cost
Past service cost
Settlement, curtailment and special termination beneﬁts
Payments to deﬁned contribution plans
Total operating charge
Innovene operations
Continuing operationsa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

757
39
64
162
1,022
(85)
937

118
38
27
12
195
(22)
173

363
5
37
–
405
(35)
370

215
–
–
150
365
(25)
340

61
(4)
–
–
57
(3)
54

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Other plans

Total

UK
pension
plans

US
pension
plans

US
other post-
retirement
beneﬁt plans

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Analysis of the amount credited (charged) to other ﬁnance expense
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Expected return on plan assets
Interest on plan liabilities
Other ﬁnance income (expense)
Innovene operations
Continuing operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,983
(2,012)
(29)
17
(12)

1,351
(981)
370
(6)
364

526
(445)
81
(3)
78

104
(346)
(242)
12
(230)

2
(240)
(238)
14
(224)

Analysis of the amount recognized in the statement of recognized income and expense
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial gain (loss) recognized in statement of recognized income and expense

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,349
(774)
(468)
107

152
(366)
(562)
(776)

379
(108)
(22)
249

818
(795)
83
106

–
495
33
528

a Included within production and manufacturing expenses and distribution and administration expenses.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
History of surplus (deﬁcit) and of experience gains and losses
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Beneﬁt obligation at 31 December
Fair value of plan assets at 31 December
Surplus (deﬁcit)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

42,433
39,910
(2,523)

35,995
27,853
(8,142)

39,945
31,712
(8,233)

38,855
32,907
(5,948)

2004

2006

2005

2003

$ million

Experience gains and losses on plan liabilities
Actual return less expected return on pension plan assets
Actual return on plan assets

Actuarial gain recognized in statement of recognized income and expense
Cumulative amount recognized in statement of recognized income and expense

(124)
1,967
4,377

2,615
3,773

(212)
3,364
5,502

975
1,158

(468)
1,349
3,332

107
183

873
2,392
3,892

76
76

Estimated future beneﬁt payments
The expected beneﬁt payments, which reﬂect expected future service, as appropriate, but excluding fund expenses, up until 2016 are as follows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2007
2008
2009
2010
2011
2012-2016

UK
pension
plans

US
pension
plans

US
other post-
retirement

beneﬁt plans Other plans

Total

1,013
1,053
1,070
1,146
1,165
6,432

619
650
673
695
714
3,621

212
213
219
224
229
1,156

509
519
513
506
496
2,271

2,353
2,435
2,475
2,571
2,604
13,480

BP Annual Report and Accounts 2006

157

Issued
8% cumulative ﬁrst preference shares of £1 each
9% cumulative second preference shares of £1 each

Ordinary shares of 25 cents each

1 January
Issue of new shares for employee share schemes
Issue of ordinary share capital for TNK-BP
Repurchase of ordinary share capital
Othera

31 December

42 Called up share capital

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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Shares (thousand)
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million Shares (thousand)

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

7,233
5,473

$ million Shares (thousand)
7,233
5,473

12
9

20,657,045
64,854
111,151
(358,374)
982,625

21,457,301

21,525,978
82,144
108,629
(1,059,706)
–
20,657,045

2006

21

5,164
16
28
(90)
246

5,364

2005

12
9
21

5,382
20
27
(265)
–
5,164
5,185

7,233
5,473

22,122,610
91,512
139,096
(827,240)
–
21,525,978

2004

12
9
21

5,531
23
35
(207)
–
5,382
5,403

7,250
5,500
36,000,000

12
9
9,000

7,250
5,500
36,000,000

12
9
9,000

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Authorized
8% cumulative ﬁrst preference shares of £1 each
9% cumulative second preference shares of £1 each
Ordinary shares of 25 cents each

a Reclassification in respect of share repurchases in 2005.

5,385

12
9
9,000

7,250
5,500
36,000,000

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.

Repurchase of ordinary share capital
The company purchased 1,334,362,750 ordinary shares (2005 1,059,706,481 and 2004 827,240,360 ordinary shares) for a total consideration of
$15,481 million (2005 $11,597 million and 2004 $7,548 million), of which 358,374,000 were for cancellation and 975,988,750 were retained in treasury.
At 31 December 2006, 1,946,804,533 shares of nominal value $487 million were held in treasury (2005 982,624,971 shares of nominal value of
$246 million). Transaction costs of share repurchases amounted to $83 million (2005 $63 million and 2004 $43 million).

158

This page is intentionally left blank.

BP Annual Report and Accounts 2006

159

43 Capital and reserves

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Share
premium
account

Capital
redemption
reserve

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a For the year ended 31 December 2006, purchases of shares by ESOP trusts amounted to $205 million (2005 $251 million and 2004 $147 million).
b At 31 December 2006, the foreign currency translation reserve includes $122 million relating to non-current assets held for sale, which will be recycled to the income
statement upon disposal of such assets.
c Reclassification in respect of share repurchases in 2005.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Share
premium
account

Capital
redemption
reserve

At 1 January 2006
Currency translation differences (net of tax)
Actuarial gain relating to pensions and other post-retirement beneﬁts (net of tax)
Issue of ordinary share capital for TNK-BP
Available-for-sale investments marked to market (net of tax)
Available-for-sale investments recycling (net of tax)
Repurchase of ordinary share capital
Share-based payments (net of tax)
Cash ﬂow hedges marked to market (net of tax)
Cash ﬂow hedges recycling (net of tax)
Proﬁt for the year
Dividends
Otherc
At 31 December 2006

At 31 December 2004
Adoption of IAS 39
At 1 January 2005
Currency translation differences (net of tax)
Exchange gain on translation of foreign operations
transferred to (proﬁt) or loss on sale (net of tax)
Actuarial gain relating to pensions and other post-retirement beneﬁts (net of tax)
Issue of ordinary share capital for TNK-BP
Available-for-sale investments marked to market (net of tax)
Available-for-sale investments recycling (net of tax)
Repurchase of ordinary share capital
Share-based payments (net of tax)
Cash ﬂow hedges marked to market (net of tax)
Cash ﬂow hedges recycling (net of tax)
Proﬁt for the year
Dividends
At 31 December 2005

At 1 January 2004
Currency translation differences (net of tax)
Exchange gain on translation of foreign operations
transferred to (proﬁt) or loss on sale (net of tax)
Actuarial gain relating to pensions and other post-retirement beneﬁts (net of tax)
Unrealized gain on acquisition of further
investment in equity-accounted investments
Issue of ordinary share capital for TNK-BP
Repurchase of ordinary share capital
Share-based payments (net of tax)
Proﬁt for the year
Dividends
At 31 December 2004

160

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Share
capital

5,185
–
–
28
–
–
(90)
16
–
–
–
–
246
5,385

Share
capital

5,403
–
5,403
–

–
–
27
–
–
(265)
20
–
–
–
–
5,185

7,371
–
–
1,222
–
–
–
481
–
–
–
–
–
9,074

5,636
–
5,636
–

–
–
1,223
–
–
–
512
–
–
–
–
7,371

Merger
reserve

27,190
–
–
–
–
–
–
11
–
–
–
–
–
27,201

Merger
reserve

27,162
–
27,162
–

–
–
–
–
–
–
28
–
–
–
–
27,190

749
–
–
–
–
–
90
–
–
–
–
–
–
839

730
–
730
–

–
–
–
–
–
19
–
–
–
–
–
749

Share
capital

Share
premium
account

Capital
redemption
reserve

Merger
reserve

5,552
–

3,957
–

–
–

–
–

523
–

–
–

27,077
–

–
–

–
35
(207)
23
–
–
5,403

–
1,215
–
464
–
–
5,636

–
–
207
–
–
–
730

–
–
–
85
–
–
27,162

----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

$ million

Cash ﬂow
hedges
----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

Treasury
shares

Minority
interest

Other
reserve

Total
equity

Available-
for-sale
investments

Share-
based
payment
reserve

BP
shareholders’
equity

----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

$ million

Cash ﬂow
hedges
----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

Treasury
shares

Other
reserve

Own
shares

Available-
for-sale
investments

----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

Proﬁt
and loss
account

46,466
–
1,795
–
–
–
(4,009)
(79)
–
–
22,000
(7,686)
–
58,487

Proﬁt
and loss
account
31,940
(355)
31,585
–

–
619
–
–
–
(750)
30
–
–
22,341
(7,359)
46,466

79,976
1,756
1,795
1,250
478
(504)
(15,481)
773
313
(46)
22,000
(7,686)
–
84,624

BP
shareholders’
equity
76,892
(243)
76,649
(2,479)

(220)
619
1,250
232
(42)
(11,597)
695
(149)
36
22,341
(7,359)
79,976

789
49
–
–
–
–
–
–
–
–
286
(283)
–
841

Minority
interest
1,343
–
1,343
(18)

–
–
–
–
–
–
–
–
–
291
(827)
789

80,765
1,805
1,795
1,250
478
(504)
(15,481)
773
313
(46)
22,286
(7,969)
–
85,465

Total
equity
78,235
(243)
77,992
(2,497)

(220)
619
1,250
232
(42)
(11,597)
695
(149)
36
22,632
(8,186)
80,765

Foreign
currency
translation
reserveb
2,943
1,742
–
–
–
–
–
–
–
–
–
–
–
4,685

Foreign
currency
translation
reserve

5,616
–
5,616
(2,453)

(220)
–
–
–
–
–
–
–
–
–
–
2,943

385
27
–
–
478
(504)
–
–
–
–
–
–
–
386

–
230
230
(35)

–
–
–
232
(42)
–
–
–
–
–
–
385

Own
sharesa
(140)
(19)
–
–
–
–
–
5
–
–
–
–
–
(154)

(10,598)
–
–
–
–
–
(11,472)
134
–
–
–
–
(246)
(22,182)

(82)
–
(82)
12

–
–
–
–
–
–
(70)
–
–
–
–
(140)

–
–
–
21
–
–
(82)

–
–
–
–
–
(10,601)
3
–
–
–
–
(10,598)

–
–
–
–

–
–
–
–
–
–
–

16
–
–
–
–
–
–
(11)
–
–
–
–
–
5

44
–
44
–

–
–
–
–
–
–
(28)
–
–
–
–
16

–
–
–
(85)
–
–
44

(234)
6
–
–
–
–
–
–
313
(46)
–
–
–
39

–
(118)
(118)
(3)

–
–
–
–
–
–
–
(149)
36
–
–
(234)

Share-
based
payment
reserve
443
–
443
–

643
–
–
–
–
–
–
216
–
–
–
–
–
859

–
–
–
–
–
–
200
–
–
–
–
643

–
–
–
231
–
–
443

----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

$ million

Cash ﬂow
hedges
----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

Treasury
shares

Minority
interest

Other
reserve

Own
shares

Total
equity

Foreign
currency
translation
reserve

Available-
for-sale
investments

Share-
based
payment
reserve

Proﬁt
and loss
account

BP
shareholders’
equity

129
–

–
–

(96)
(7)

–
–

–
–

–
–

3,619
2,075

(78)
–

–
–

–
–

–
–

–
–

212
–

–
–

28,166
–

–
203

69,139
2,068

1,125
64

(78)
203

–
–

70,264
2,132

(78)
203

----------------------------------------------------------------------------------------------------------------------------------------------- -----------------------------------------------------------------------------------------------------------------------------------------------

–
–
–
–
–
–
5,616

–
–
–
–
–
–
–

–
–
–
–
–
–
–

94
–
(7,548)
(9)
17,075
(6,041)
31,940

94
1,250
(7,548)
730
17,075
(6,041)
76,892

–
–
–
–
187
(33)
1,343

94
1,250
(7,548)
730
17,262
(6,074)
78,235

BP Annual Report and Accounts 2006

161

43 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 represents the fair value of the consideration given in excess of the nominal value of the ordinary shares to be 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 arrangements.

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 translations 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 on available-for-sale investments. On disposal, 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 arrangements 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.

162

44 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 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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

289
36
325
59
53

348
20
368
48
41

405
14

38
23

419

2005

2006

2004

$ million

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 (2005 onwards)
An equity-settled incentive share plan for executive directors driven by one performance measure over a three-year performance period. The award of
shares is determined by comparing BP’s total shareholder return (TSR) against the other oil majors. In addition, for the group chief executive, 27% of
the grant is based on long-term leadership (LTL) measures. After the performance period, the shares which vest (net of tax) are then subject to a
three-year retention period. The director’s remuneration report on pages 68-75 includes full details of this plan.

Executive Directors’ Incentive Plan (EDIP) – share element (pre-2005)
An equity-settled incentive share plan for executive directors driven by three performance measures over a three-year performance period. The primary
measure is BP’s shareholder return against the market (SHRAM) versus that of the companies within the FTSE All World Oil & Gas Index. This accounts
for nearly two-thirds of the potential total award, with the remainder being assessed on BP’s relative return on average capital employed (ROACE) and
earnings per share (EPS) growth compared with the other oil majors. After the performance period, the shares that vest (net of tax) are then subject to a
three-year retention period. The director’s remuneration report on pages 68-75 includes full details of this plan. For 2005 and subsequent years, the
share element of EDIP was amended as described above.

Executive Directors’ Incentive Plan (EDIP) – share option element (pre-2005)
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. Options vest over three years (one-third each after one, two and three years respectively) and must be
exercised within seven years of the date of grant. 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
Medium Term Performance Plan (MTPP) (2005 onwards)
An equity-settled incentive share plan for senior employees driven by two performance measures over a three-year performance period. The award of
shares is determined by comparing BP’s TSR against the other oil majors and, additionally, by comparing free cash ﬂow (FCF) against a threshold
established for the period. For a small group of particularly senior employees, only the TSR measure is applicable in determining the award. The number
of shares awarded is increased to take account of the net dividends that would have been received during the performance period, assuming that such
dividends had been reinvested. With regard to leaver provisions, the general rule is that leaving employment during the performance period will preclude
an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion
of the ﬁrst year of the performance period.

Long Term Performance Plan (LTPP) (pre-2005)
An equity-settled incentive share plan for senior employees driven by three performance measures over a three-year performance period. The primary
measure is BP’s SHRAM versus that of the companies within the FTSE All World Oil & Gas Index. This accounts for nearly two-thirds of the potential
total award, with the remainder being assessed on BP’s relative ROACE and EPS growth compared with the other oil majors. Shares are awarded at the
end of the performance period and are then subject to a three-year restriction period. With regard to leaver provisions, the general rule is that leaving
during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying
reason and employment ceases after completion of the ﬁrst year of the performance period. This plan was replaced by the MTPP for 2005 onwards.

Deferred Annual Bonus Plan (DAB)
An equity-settled restricted share plan for senior employees. The award value is equal to 50% of the annual cash bonus awarded for the preceding
performance year (the ‘performance period’). The shares are restricted for a period of three years (the ‘restriction period’). Shares accrue dividends
during the restriction period and these are reinvested. With regard to leaver provisions, if a participant ceases to be employed by BP prior to the end of
the performance period, then the general rule is that this will preclude an award of shares. However, special arrangements apply where the participant
leaves for a qualifying reason. Similarly, if a participant ceases to be employed by BP prior to the end of the restriction period, the general rule is that the
restricted shares will be forfeited. Special arrangements apply where the participant leaves for a qualifying reason.

Performance Share Plan (PSP)
An equity-settled restricted share plan for senior professionals and team leaders. The award takes into account the recipient’s performance in the prior
calendar year (the ‘performance period’). Shares, provided initially as share units, are restricted for a period of three years (the ‘restriction period’). Share
units accrue notional dividends during the restriction period and these are reinvested. At the end of the restriction period additional units may be
awarded based on BP’s TSR performance against the other oil majors. At award, share units are converted into shares. With regard to leaver provisions,
the general rule is that leaving during the performance period will preclude an award of share units. If a participant ceases to be employed by BP
prior to the end of the restriction period, the general rule is that share units will lapse. Special arrangements apply where the participant leaves for a
qualifying reason.

BP Annual Report and Accounts 2006

163

44 Share-based payments continued

Restricted Share Plan (RSP)
An equity-settled restricted share plan used predominantly for senior employees in special circumstances (such as recruitment and retention). There are
no performance conditions but the shares are subject to a three-year restriction period. During the restriction period, shares accrue dividends, which are
reinvested. With regard to leaver provisions, the general rule is that ceasing employment during the restriction period will result in the forfeit of shares.
However, special arrangements apply where the participant leaves for a qualifying reason.

BP Share Option Plan (BPSOP)
An equity-settled share option plan that applies to certain categories of employees. Participants are granted share options with an exercise price no
lower than market price of a share immediately preceding the date of grant. There are no performance conditions and the options are exercisable
between the third and 10th anniversaries of the grant date. The general rule is that the options will lapse if the participant leaves employment before the
end of the third calendar year from the date of grant (and that vested options are exercisable within 31/2 years from the date of leaving). However, special
arrangements apply where the participant leaves for a qualifying reason and employment ceases after the end of the calendar year of the date of grant.
From 2007, share options no longer form a regular element of our incentive plans.

Savings and matching plans
BP ShareSave Plan
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 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. Until 2003, a three-year savings plan was also run in a small number of other countries. Options will remain outstanding in respect of
these countries until the end of June 2007. 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
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
over 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.

The above share plans are indicated as being equity-settled. However in certain countries it is not possible to award shares to employees owing to local
legislation. In these instances the award will be settled in cash, calculated as the cash equivalent of the value to the employee of an equity-settled plan.

Cash plans
Cash Options / Stock Appreciation Rights (SARs)
These are cash-settled share-based payments available to certain employees that require the group to pay the intrinsic value of the cash option/SAR to
the employee at the date of exercise. There are no performance conditions; however, participants must continue in employment with BP for the ﬁrst
three calendar years of the plan for the options/SARs to vest. Special arrangements may apply for qualifying leavers. The options/SARs are exercisable
between the third and 10th anniversaries of the grant date.

Employee Share Ownership Plans (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards made to participants under EDIP, MTPP, LTPP, DAB and the BP ShareMatch
Plans. The ESOPs have waived their rights to dividends on shares held for future awards and are funded by the group. 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 Note 43. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.

At 31 December 2006, the ESOPs held 12,795,887 shares (2005 14,560,003 shares and 2004 8,621,219 shares) for potential future awards, which

had a market value of $142 million (2005 $156 million and 2004 $84 million).

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Share option transactions

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Weighted
average
exercise price
$

7.64
11.18
8.69
6.52
7.99

8.25

Number
of
options

450,453,502
53,977,639
(7,169,710)
(70,658,480)
(131,489)

426,471,462

236,726,966

699,535,945

7.41

Number
of
options

470,263,808
54,482,053
(4,844,827)
(68,687,976)
(759,556)
450,453,502
222,729,398
955,924,506

2005

Weighted
average
exercise price
$
7.16
10.24
8.30
6.40
6.75
7.64
7.54

Number
of
options
461,885,881
80,394,760
(7,043,911)
(62,625,182)
(2,347,740)
470,263,808
224,627,758
966,076,636

2004

Weighted
average
exercise price
$
6.76
7.93
6.77
5.18
7.55
7.16
7.00

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Outstanding at beginning of the year
Granted during the year
Forfeited during the year
Exercised during the year
Expired during the year
Outstanding at end of the year
Exercisable at the end of the year
Available for grant at 31 December

164

44 Share-based payments continued

As share options are exercised continuously throughout the year, the weighted average share price during the year of $11.85 (2005 $10.77 and 2004
$8.95) is representative of the weighted average share price at the date of exercise. For the options outstanding at 31 December 2006, the exercise
price ranges and weighted average remaining contractual lives are shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Options outstanding

Options exercisable

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Range of exercise prices
$5.10 – $6.79
$6.80 – $8.50
$8.51 – $10.21
$10.22 – $11.92

Number
of
shares

100,854,491
196,009,067
55,376,829
74,231,075

Weighted
average
remaining life
Years

Weighted
average
exercise price
$

3.92
4.93
5.79
8.81

6.02
8.01
9.30
11.14

Number
of
shares

87,474,704
122,344,799
26,907,463
–

Weighted
average
exercise price
$

6.06
8.08
8.76
–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

426,471,462

5.48

8.25

236,726,966

7.41

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fair values and associated details for options and shares granted
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Options granted in 2006
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

ShareSave 5 year
Binomial
$3.08
$11.08
$9.10
24%
5.5 years
3.40%
4.75%
100% year 6

ShareSave 3 year
Binomial
$2.88
$11.08
$9.10
24%
3.5 years
3.40%
5.00%
100% year 4

BPSOP
Binomial
$2.46
$11.07
$11.17
22%
10 years
3.23%
4.50%
5% years 4-9,
70% year 10

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Options granted in 2005
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

Options granted in 2004
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

BPSOP
Binomial
$2.34
$10.85
$10.63
18%
10 years
2.72%
4.25%
5% years 4-9,
70% year 10

BPSOP
Binomial
$1.55
$8.12
$8.09
22%
10 years
3.75%
4.00%
5% years 4-9,
70% year 10

ShareSave 3 year
Binomial
$2.76
$10.49
$7.96
18%
3.5 years
3.00%
4.00%
100% year 4

ShareSave 5 year
Binomial
$2.94
$10.49
$7.96
18%
5.5 years
3.00%
4.25%
100% year 6

ShareSave 3 year
Binomial
$1.94
$8.75
$7.00
22%
3.5 years
3.75%
3.00%
100% year 4

ShareSave 5 year
Binomial
$2.13
$8.75
$7.00
22%
5.5 years
3.75%
3.75%
100% year 6

EDIP Options
Binomial
$1.34
$8.09
$8.09
22%
7 years
3.75%
3.50%
5% years 2-6,
75% year 7

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The group uses a third party estimate of expected volatility of US ADSs for the quarter within which the grant date of the relevant plan falls. This
estimate takes into account the volatility implied by options in the market.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Shares granted in 2006
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

Shares granted in 2005
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

MTPP-
TSR
8.7
$7.28

MTPP-
FCF
7.8
$11.23
Monte Carlo Market value

EDIP-
TSR
3.3
$4.87

RSP
0.5
$11.07
Monte Carlo Market value Market value

EDIP-
LTL
0.5
$11.23

MTPP -
TSR
9.3
$5.72

MTPP -
FCF
8.4
$11.04
Monte Carlo Market value

EDIP -
TSR
3.7
$3.87

RSP
0.3
$11.04
Monte Carlo Market value Market value

EDIP -
LTL
0.5
$10.13

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BP Annual Report and Accounts 2006

165

44 Share-based payments continued

The group used a Monte Carlo simulation to fair value the TSR element of the 2006 and 2005 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Shares granted in 2004
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

LTPP-
SHRAM
6.8
$4.06

LTPP-
EPS/ROACE
4.1
$7.21
Monte Carlo Market value

EDIP-
SHRAM
0.9
$4.06

RSP
0.1
$8.12
Monte Carlo Market value Market value

EDIP-
EPS/ROACE
0.5
$7.21

The group used a Monte Carlo simulation to fair value the SHRAM element of the 2004 LTPP and EDIP plan. In accordance with the rules of the plan,
the model simulates BP’s SHRAM and compares it with the comparator companies (all companies in the FTSE All World Oil & Gas Index) over the
three-year period of the plan. The SHRAMs of the comparator companies have been determined from market data over the preceding three-year period.
The model takes into account the historic dividend yields, 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 SHRAM 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.

45 Employee costs and numbers

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Employee costs
Wages and salaries
Social security costs
Share-based payments
Pension and other post-retirement beneﬁt costs

Innovene operations
Continuing operations

Number of employees at 31 December
Exploration and Production
Reﬁning and Marketinga
Gas, Power and Renewables
Other businesses and corporate

By geographical area
UK
Rest of Europe
USA
Rest of World

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Includes 26,100 (2005 27,800 and 2004 27,900) service station staff.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Average number of employees
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

UK

3,300
11,300
300
1,900

Rest of
Europe

700
19,300
700
200

USA

6,100
24,900
1,600
1,900

Rest of
World

8,100
15,000
1,700
100

2006

Total

18,200
70,500
4,300
4,100

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

16,800

20,900

34,500

24,900

97,100

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

3,000
11,100
200
3,800
18,100

UK

2,900
10,300
200
3,700
17,100

Rest of
Europe

600
19,700
800
3,900
25,000

Rest of
Europe

700
19,200
800
4,800
25,500

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

8,411
751
419
770

10,351
–

10,351

2006

19,000
69,500
4,500
4,000
97,000

16,900
20,200
33,700
26,200
97,000

USA

5,300
26,200
1,500
3,600
36,600

USA

4,900
27,200
1,400
5,700
39,200

2005

8,695
754
368
929
10,746
(892)
9,854

2005

17,000
70,800
4,100
4,300
96,200

16,500
21,300
34,400
24,000
96,200

Rest of
World

7,300
14,000
1,400
300
23,000

Rest of
World

6,900
12,900
1,600
1,000
22,400

$ million

2004

7,922
667
325
1,051
9,965
(898)
9,067

2004

15,600
69,800
4,000
13,500
102,900

17,500
25,900
36,900
22,600
102,900

2005

Total

16,200
71,000
3,900
11,600
102,700

Total

15,400
69,600
4,000
15,200
104,200

Average number of employees
Exploration and Production
Reﬁning and Marketing
Gas, Power and Renewables
Other businesses and corporate

166

46 Remuneration of directors and key management

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

$ million

Remuneration of directors

Total for all directors

Emoluments
Gains made on the exercise of share options
Amounts awarded under incentive schemes

14
12
14

18
–
8

19
3
6

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

Pension contributions
Five executive directors participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which contributions are
made by BP based on actuarial advice. One US executive director participated in the US BP Retirement Accumulation Plan during 2006.

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 68-75.

Remuneration of key management
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

Total for all key management

Short-term employee beneﬁts
Post-retirement beneﬁts
Share-based payments

30
4
26

25
4
27

24
3
20

Key management, in addition to executive and non-executive directors, includes other senior managers who attend the Group Chief Executive’s
Meeting.

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 bonuses awarded for the year.

Post-retirement beneﬁts
The amounts represent the estimated cost to the group of providing deﬁned beneﬁt pensions and other post-retirement beneﬁts to key 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 key 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 key management have participated are the
Executive Directors’ Incentive Plan (EDIP), the Medium Term Performance Plan (MTPP) and the Long Term Performance Plan (LTPP). For details of
these plans refer to Note 44.

BP Annual Report and Accounts 2006

167

47 Contingent liabilities

There were contingent liabilities at 31 December 2006 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. Group companies have issued guarantees under which amounts
outstanding at 31 December 2006 were $1,123 million (2005 $1,228 million) in respect of borrowings of jointly controlled entities and associates and
$789 million (2005 $736 million) in respect of liabilities of other third parties.

Approximately 200 lawsuits were ﬁled in State and Federal Courts in Alaska seeking compensatory and punitive damages arising out of the Exxon

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

Since 1987, Atlantic Richﬁeld, a current subsidiary of BP, has been named as a co-defendant in numerous lawsuits brought in the US alleging injury to

persons and property caused by lead pigment in paint. The majority of the lawsuits have been abandoned or dismissed as against Atlantic Richﬁeld.
Atlantic Richﬁeld is named in these lawsuits as alleged successor to International Smelting & Reﬁning which, along with a predecessor company,
manufactured lead pigment during the period 1920-1946. Plaintiffs include individuals and governmental entities. Several of the lawsuits purport to be
class actions. The lawsuits (depending on plaintiff) seek various remedies, including: compensation to lead-poisoned children; cost to ﬁnd and remove
lead paint from buildings; medical monitoring and screening programmes; public warning and education on lead hazards; reimbursement of government
healthcare costs and special education for lead-poisoned citizens; and punitive damages. No lawsuit against Atlantic Richﬁeld has been settled nor has
Atlantic Richﬁeld been subject to a ﬁnal adverse judgment in any proceeding. The amounts claimed and, if such suits were successful, the costs of
implementing the remedies sought in the various cases could be substantial. While it is not possible to predict the outcome of these legal actions,
Atlantic Richﬁeld believes that it has valid defences and it intends to defend such actions vigorously and thus the incurrence of a liability by Atlantic
Richﬁeld is remote. Consequently, BP believes that the impact of these lawsuits on the group’s results of operations, ﬁnancial position or liquidity will
not be material.

In addition, various group companies are parties to legal actions and claims that arise in the ordinary course of the group’s business. While the

outcome of such legal proceedings cannot be readily foreseen, BP believes that they will be resolved without material effect on 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, BP does not expect these costs to have
a material effect on the group’s ﬁnancial position or liquidity.

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.

48 Capital commitments

Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been placed at 31 December 2006
amounted to $9,773 million (2005 $7,596 million). Capital commitments of jointly controlled entities amounted to $1,217 million (2005 $576 million).

49 First-time adoption of International Financial Reporting Standards

For all periods up to and including the year ended 31 December 2004, BP prepared its ﬁnancial statements in accordance with UK generally accepted
accounting practice (UK GAAP). BP, together with all other European Union (EU) companies listed on an EU stock exchange, was required to prepare
consolidated ﬁnancial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU with effect from 1 January
2005. The Annual Report and Accounts for the year ended 31 December 2005 comprised BP’s ﬁrst consolidated ﬁnancial statements prepared under
IFRS.

The general principle for ﬁrst-time adoption of IFRS is that standards in force at the ﬁrst reporting date (for BP, 31 December 2005) are applied

retrospectively. However, IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’ contains a number of exemptions that companies
are permitted to apply. BP elected to take advantage of the exemption allowing comparative information on ﬁnancial instruments to be prepared in
accordance with UK GAAP and the group adopted IAS 32 ‘Financial Instruments: Disclosure and Presentation’ (IAS 32) and IAS 39 ‘Financial
Instruments: Recognition and Measurement’ (IAS 39) from 1 January 2005.

Had IAS 32 and IAS 39 been applied from 1 January 2003, BP’s date of transition for all other IFRS in force at the ﬁrst reporting date, the following

are the most signiﬁcant adjustments that would have been necessary in the ﬁnancial statements for the year ended 31 December 2004:
– All derivatives, including embedded derivatives, would have been brought on to the balance sheet at fair value, and changes in fair value would have

been recognized in the income statement.

– Available-for-sale investments would have been carried at fair value rather than at cost and changes in fair value would have been recognized directly

in equity.

168

49 First-time adoption of International Financial Reporting Standards continued

The reconciliation set out below shows the adjustments to the group balance sheet at 1 January 2005 on the adoption of IAS 32 and IAS 39.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Group balance sheet reconcilation
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

IFRS at
31 December
2004

Fair value
hedges

Cash ﬂow
hedges

Other
non-
ﬁnancial
contracts
at fair
value

Other
non-
ﬁnancial
contracts
no longer
at fair value

Non-
qualifying
hedge
derivatives

Available-
for-sale
ﬁnancial
assets

Embedded
derivatives

Elimination
of
deferred
gains/
losses

Total
IAS 39
adjustments

IFRS at
1 January
2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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 and accrued income
Deﬁned beneﬁt pension plan surplus

Current assets

Loans
Inventories
Trade and other receivables
Derivative ﬁnancial instruments
Prepayments and accrued income
Current tax receivable
Cash and cash equivalents

Total assets
Current liabilities

Trade and other payables
Derivative ﬁnancial instruments
Accruals and deferred income
Finance debt
Current tax payable
Provisions

Non-current liabilities
Other payables
Derivative ﬁnancial instruments
Accruals and deferred income
Finance debt
Deferred tax liabilities
Provisions
Deﬁned beneﬁt pension plan and other
post-retirement beneﬁt plan deﬁcits

Total liabilities
Net assets

BP shareholders’ equity
Minority interest
Total equity

93,092
10,857
4,205
14,556
5,486
394
128,590
811
429
898
354
2,105
133,187

193
15,645
37,099
5,317
1,671
159
1,359
61,443
194,630

38,540
5,074
4,482
10,184
4,131
715
63,126

10,339
53,269
116,395
78,235

76,892
1,343
78,235

–
–
–
–
–
–
–
–
–
112
–
–
112

–
–
–
–
–
–
–
–
112

–
–
–
–
–
–
–

–
112
112
–

–
–
–

–
–
–
–
–
–
–
–
–
79
–
–
79

–
–
(2)
141
–
–
–
139
218

–
16
–
–
–
–
16

–
64
80
138

138
–
138

–
–
–
–
–
–
–
–
–
8
–
–
8

–
–
–
178
–
–
–
178
186

–
210
–
–
–
–
210

–
4
214
(28)

(28)
–
(28)

–
–
–
–
–
–
–
–
–
110
–
–
110

–
–
–
34
–
–
–
34
144

–
14
–
–
–
–
14

–
56
70
74

74
–
74

–
–
–
–
–
–
–
–
–
(34)
–
–
(34)

–
–
–
47
–
–
–
47
13

–
–
–
–
–
–
–

–
5
5
8

8
–
8

–
–
–
–
–
344
344
–
–
–
–
–
344

–
–
–
–
–
–
–
–
344

–
–
–
–
–
–
–

–
114
114
230

230
–
230

–
–
–
–
–
–
–
–
–
599
–
–
599

–
–
–
278
–
–
–
278
877

–
402
–
–
–
–
402

–
–
–
–
–
–
–
–
–
(147)
–
–
(147)

–
–
–
–
–
–
–
–
(147)

–
–
–
–
–
–
–

93,092
–
10,857
–
4,205
–
14,556
–
5,486
–
344
738
344 128,934
811
429
1,625
354
2,105
1,071 134,258

–
–
727
–
–

–
–
(2)
678
–
–
–
676

193
15,645
37,097
5,995
1,671
159
1,359
62,119
1,747 196,377

–
642
–
–
–
–
642

38,540
5,716
4,482
10,184
4,131
715
63,768

–
884
1,286
(409)

(409)
–
(409)

–
109
109
(256)

(256)
–
(256)

10,339
–
1,348
54,617
1,990 118,385
77,992

(243)

(243)
–
(243)

76,649
1,343
77,992

3,581
158
699
12,907
16,701
8,884

–
129
–
(17)
–
–

–
4
–
–
60
–

–
17
–
–
(13)
–

–
12
–
–
44
–

–
–
–
–
5
–

–
–
–
–
114
–

–
1,151
–
–
(267)
–

–
–
–
164
(55)
–

–
1,313
–
147
(112)
–

3,581
1,471
699
13,054
16,589
8,884

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The fair values of embedded derivatives are included within non-current and current derivative ﬁnancial instruments on the group balance sheet as this
is believed to be the most appropriate presentation. Previously, these balances were reported within non-current and current prepayments and accrued
income and accruals and deferred income.

BP Annual Report and Accounts 2006

169

49 First-time adoption of International Financial Reporting Standards continued

Adjustments required to the balance sheet as at 1 January 2005 for the adoption of IAS 32 and IAS 39
Under UK GAAP, all derivatives used for trading purposes were recognized on the balance sheet at fair value. However, derivative ﬁnancial instruments
used for hedging purposes were recognized by applying either the accrual method or the deferral method. Under the accrual method, which was used
for derivatives, principally swaps, used to manage interest rate risk, amounts payable or receivable in respect of derivatives are recognized ratably in
earnings over the period of the contracts. Changes in the derivative’s fair value are not recognized. Under the deferral method, gains and losses from
derivatives were deferred and recognized in earnings or as adjustments to carrying amounts as the underlying hedged transaction matured or occurred.
This method was applied for derivatives used to convert non-US dollar borrowings into US dollars, to hedge signiﬁcant non-US dollar ﬁrm commitments
or anticipated transactions, and to manage some of the group’s exposure to natural gas and power price ﬂuctuations.

For IFRS, all ﬁnancial assets and ﬁnancial liabilities are recognized initially at fair value. In subsequent periods the measurement of these ﬁnancial

instruments depends on their classiﬁcation into one of the following measurement categories: i) ﬁnancial assets or ﬁnancial liabilities at-fair-value-
through-proﬁt-and-loss (such as those used for trading purposes and all derivatives which do not qualify for hedge accounting); ii) loans and receivables;
and iii) available-for-sale ﬁnancial assets (including certain investments held for the long term).

Fair value hedges
Where fair value hedge accounting was applied to transactions that hedge the group’s exposure to the changes in the fair value of a ﬁrm commitment
or a recognized asset or liability that are attributable to a speciﬁc risk the derivatives designated as hedging instruments are recorded at their fair value in
the group’s balance sheet and changes in their fair value are recognized in the income statement. Any gain or loss on the hedged item attributable to
the hedged risk is adjusted against the carrying amount of the hedged item and recognized in the income statement.

The ‘pay ﬂoating’ interest rate swaps and currency swaps hedging the debt book in place on 1 January 2005 were highly effective and consequently

qualify as fair value hedges for hedge accounting. The full fair value of the swaps was recognized on the balance sheet and the carrying value of debt
was adjusted.

Cash ﬂow hedges
The group uses currency derivatives to hedge its exposure to variability in cash ﬂows arising either from a recognized asset or liability or a forecast
transaction. The hedged instrument is recognized at fair value on the balance sheet. At maturity of the hedged item, the element deferred in equity is
treated in accordance with the nature of the hedged exposure, for example, capitalized into the cost of an item of property, plant and equipment, or
expensed in the case of a hedge of a tax payment.

Non-qualifying hedge derivatives
Under IAS 39, there are strict criteria that need to be met in order for hedge accounting to be applied. This adjustment records the impact of those
derivatives, or elements thereof, held by the group that do not qualify for hedge accounting, or hedges for which hedge accounting has not been
claimed under IAS 39. From 1 January 2005, these positions will be fair valued (‘marked to market’) and the change in fair value taken to income.

Other non-ﬁnancial contracts at fair value
Certain net-settled non-ﬁnancial contracts are deemed to meet the deﬁnition of ﬁnancial instruments under IAS 39 and, as such, need to be recorded on
the balance sheet at fair value.

Other non-ﬁnancial contracts no longer at fair value
Certain non-ﬁnancial contracts held for trading purposes were marked to market under UK GAAP. However, under IFRS they could no longer be
recorded at fair value as they did not meet the deﬁnition of ﬁnancial assets or ﬁnancial liabilities. These contracts are accounted for on an accruals basis.

Available-for-sale ﬁnancial assets
Under UK GAAP, the group’s investments other than subsidiaries, jointly controlled entities and associates were stated at cost less accumulated
impairment losses.

For IFRS, these investments are classiﬁed as available-for-sale ﬁnancial assets, and are recorded at fair value with the gain or loss arising as a result

of the change in fair value being recorded directly in equity.

The transition adjustment relates to the fair value of listed investments held by the group. In accordance with IAS 39, all future fair value adjustments

will be booked directly in equity until disposal of the investment, when the cumulative associated gains or losses are recycled through the income
statement. At this point, the gain or loss on disposal under IFRS will be identical to that which would result using historical cost accounting.

Embedded derivatives
Embedded derivatives are required to be separated from their host contracts and separately recorded at fair value, with any resulting change in gain or
loss in the period being recognized in the income statement.

Certain contracts have been determined to contain embedded derivatives. These embedded derivatives will be fair valued at each period end with the

resulting gains or losses taken to the income statement.

Elimination of currently deferred gains and losses from derivatives
Under UK GAAP, gains and losses from derivatives are deferred and recognized in earnings or as adjustments to carrying amounts, as appropriate,
when the underlying debt matures or the hedged transaction occurs. Where derivatives that are used to manage interest rate risk, to convert non-US
dollar debtor to hedge other anticipated cash ﬂows are terminated before the underlying debt matures or the hedged transaction occurs, the resulting
gain or loss is recognized on a basis that matches the timing and accounting treatment of the underlying debt or hedged transaction.

On transition to IFRS, only assets and liabilities that qualify as such can continue to be recognized. Consequently, all gains and losses that were
generated by derivatives used for hedging purposes and deferred in the balance sheet as if they were assets or liabilities must be eliminated from the
transitional balance sheet. This is achieved by transferring gains and losses arising from cash ﬂow hedges to equity, pending recycling to income at a
later date, and by transferring gains and losses arising from fair value hedges to adjust the carrying value of the hedged item, in this case, ﬁnance debt.

170

50 Subsidiaries, jointly controlled entities and associates

The more important subsidiaries, jointly controlled entities and associates of the group at 31 December 2006 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Subsidiaries
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
International

Principal activities

Principal activities

Subsidiaries

%

%

Country of
incorporation

Country of
incorporation

100 England
100 England
100 England
100 England
100 England
100 England
100 Scotland

Petrochemicals
Exploration and production
Investment holding
Integrated oil operations
Integrated oil operations
Shipping
Lubricants

100 Scotland

Exploration and production

Netherlands
BP Capital
BP Nederland

100 Netherlands
100 Netherlands

Finance
Reﬁning and marketing

New Zealand

BP Oil New Zealand

100 New Zealand Marketing

Norway

BP Norge

Spain

BP Espan˜ a

South Africa

100 Norway

Exploration and production

100 Spain

Reﬁning and marketing

Trinidad & Tobago

BP Trinidad (LNG)
BP Trinidad and Tobago

100 Netherlands

70 US

Exploration and production
Exploration and production

100 Bahamas

Exploration and production

*BP Southern Africa

75 South Africa

Reﬁning and marketing

BP Exploration (Angola)

100 England

Exploration and production

100 Australia

Integrated oil operations

UK

100 Australia

Finance

100 Australia
100 Australia

Exploration and production
Finance

BP Capital Markets
BP Chemicals
BP Oil UK
Britoil
Jupiter Insurance

100 England
100 England
100 England
100 Scotland
100 Guernsey

Finance
Petrochemicals
Reﬁning and marketing
Exploration and production
Insurance

BP Chemicals
Investments

BP Exploration Op. Co.
*BP Global Investments
*BP International
BP Oil International
*BP Shipping
*Burmah Castrol

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

British Virgin Exploration and production

Petroleum
BP Exploration
(Caspian Sea)

Canada

BP Canada Energy
BP Canada Finance

Egypt

BP Egypt Co.
BP Egypt Gas Co.

France

BP France

Germany

Deutsche BP

100

Islands

100 England

Exploration and production

100 Canada
100 Canada

Exploration and production
Finance

100 US
100 US

Exploration and production
Exploration and production

100 France

Reﬁning and marketing
and petrochemicals

100 Germany

Reﬁning and marketing
and petrochemicals

US

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,
gas, power and
renewables,
reﬁning and marketing,
pipelines and
petrochemicals

Finance

BP Annual Report and Accounts 2006

171

50 Subsidiaries, jointly controlled entities and associates continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Country of incorporation
or registration

%

Jointly controlled entities
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Atlantic 4 Holdings
Atlantic LNG 2/3 Company of Trinidad and Tobago
LukArco
Pan American Energya
Ruhr Oel
Shanghai SECCO Petrochemical Co.
TNK-BP

LNG manufacture
LNG manufacture
Exploration and production, pipelines
Exploration and production
Reﬁning and marketing and petrochemicals
Petrochemicals
Integrated oil operations

US
Trinidad & Tobago
Netherlands
US
Germany
China
British Virgin Islands

38
43
46
60
50
50
50

Principal activities

a Pan American Energy is not controlled by BP, as certain key business decisions require joint approval of both BP and the minority partner. It is thus classified as a jointly
controlled entity rather than a subsidiary.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Associates
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Abu Dhabi

Country of incorporation

Principal activities

%

Abu Dhabi Marine Areas
Abu Dhabi Petroleum Co.

Azerbaijan

The Baku-Tbilisi-Ceyhan Pipeline Co.
South Caucasus Pipeline Co.

Trinidad & Tobago

Atlantic LNG Company of Trinidad and Tobago

37
24

30
26

34

England
England

Cayman Islands
Cayman Islands

Crude oil production
Crude oil production

Pipelines
Pipelines

Trinidad & Tobago

LNG manufacture

172

51 Oil and natural gas exploration and production activitiesa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Capitalized costs at 31 December
Gross capitalized costs
Proved properties
Unproved properties

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

117,102
4,590

32,528
423

44,856
1,443

15,516
936

3,569
1,155

9,404
379

4,951
116

6,278
137

–
1

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

32,951
22,908

5,067
3,175

46,299
19,724

9,783
4,618

4,724
1,709

16,452
6,944

1
–

6,415
1,708

121,692
60,786

10,043

1,892

26,575

5,165

3,015

9,508

1

4,707

60,906

Accumulated depreciation
Net capitalized costs

The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2006 was $10,870 million.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Costs incurred for the year ended 31 December
Acquisition of properties

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proved
Unproved

Exploration and appraisal costsb
Development costs
Total costs

–
–

–
132
794

–
–

–
26
214

–
74

74
838
3,579

–
8

8
135
820

–
2

2
45
238

–
70

70
434
2,356

–
–

–
73
–

–
–

–
82
1,108

–
154

154
1,765
9,109

926

240

4,491

963

285

2,860

73

1,190

11,028

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The group’s share of jointly controlled entities’ and associates’ costs incurred in 2006 was $1,688 million: in Russia $1,109 milion, Rest of Americas
$424 million, Asia Paciﬁc $16 million and other $139 million.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Results of operations for the year

ended 31 December

Sales and other operating revenuesc

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

5,378
2,329

7,707

628
1,024

1,652

1,381
14,572

15,953

2,196
3,229

5,425

1,159
807

1,966

1,647
2,875

4,522

–
–

–

768
7,640

8,408

13,157
32,476

45,633

20
1,312
492
(867)
1,612

(1)
145
38
90
213

634
2,311
887
2,561
2,083

132
638
295
478
685

11
155
63
154
175

132
509
–
104
865

17
–
–
32
–

100
238
2,079
3,121
510

1,045
5,308
3,854
5,673
6,143

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)d
Depreciation, depletion and amortization
Impairments and (gains) losses on sale of

businesses and ﬁxed assets

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(450)

2,119

5,588
2,567

(57)

428

1,224
793

(1,880)

6,596

9,357
3,136

42

2,270

3,155
1,443

(99)

459

1,507
472

(31)

1,579

2,943
1,328

–

49

(49)
3

–

(2,475)

6,048

2,360
737

19,548

26,085
10,479

3,021

431

6,221

1,712

1,035

1,615

(52)

1,623

15,606

Proﬁt before taxatione,f
Allocable taxes
Results of operations

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The group’s share of jointly controlled entities’ and associates’ results of operations in 2006 was a proﬁt of $3,302 million after deducting interest of
$324 million, taxation of $1,804 million and minority interest of $193 million.

a This note contains information relating to oil and natural gas exploration and production activities. Mid-stream activities of natural gas gathering and distribution and the
operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central
Area Transmission System. The group’s share of jointly controlled entities’ and associates’ activities is excluded from the tables and included in the footnotes, with the
exception of the Abu Dhabi operations, which are included in the income and expenditure items above.
b Includes 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.
c Sales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is
payable in cash.
d Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes, other government take and the fair value gain on embedded
derivatives $515 million.
e Excludes accretion expense attributable to exploration and production activities amounting to $153 million. Under IFRS, accretion expense is included in other finance
expense in the group income statement.
f The Exploration and Production profit before interest and tax is set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration and production activities

Group (as above)
Jointly controlled entities and associates

Mid-stream activities
Total proﬁt before interest and tax

5,588
–
250
5,838

1,224
–
(14)
1,210

9,357
1
(31)
9,327

3,155
535
85
3,775

1,507
33
(31)
1,509

2,943
1
(11)
2,933

(49)
2,730
(24)
2,657

2,360
2
18
2,380

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

26,085
3,302
242
29,629

BP Annual Report and Accounts 2006

173

51 Oil and natural gas exploration and production activitiesa

continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Capitalized costs at 31 December
Gross capitalized costs
Proved properties
Unproved properties

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

31,552
276
31,828
22,302
9,526

4,608
135
4,743
2,949
1,794

46,288
1,547
47,835
22,016
25,819

9,585
583
10,168
4,919
5,249

2,922
1,124
4,046
1,508
2,538

12,183
656
12,839
6,112
6,727

5,184
155
5,339
1,200
4,139

112,322
4,661
116,983
61,006
55,977

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Accumulated depreciation
Net capitalized costs

The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2005 was $10,670 million.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Costs incurred for the year ended 31 December
Acquisition of properties

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proved
Unproved

Exploration and appraisal costsb
Development costs
Total costs

–
–
–
51
790
841

–
–
–
7
188
195

–
29
29
606
2,965
3,600

–
34
34
133
681
848

–
–
–
11
186
197

–
–
–
264
1,691
1,955

–
–
–
68
1,177
1,245

–
63
63
1,266
7,678
9,007

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The group’s share of jointly controlled entities’ and associates’ costs incurred in 2005 was $1,205 million: in Russia $845 million and Rest of Americas
$360 million.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Results of operations for the year
ended 31 December
Sales and other operating revenuesc

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)d
Depreciation, depletion and amortization
Impairments and (gains) losses on sale of

businesses and ﬁxed assets

Proﬁt before taxatione f
Allocable taxes
Results of operations

4,667
2,458
7,125
32
1,082
485
1,857
1,548

44
5,048
2,077
405
1,672

635
976
1,611
1
118
33
(55)
220

(1,038)
(721)
2,332
880
1,452

2,048
14,842
16,890
426
1,814
610
2,200
2,288

232
7,570
9,320
3,377
5,943

2,260
2,863
5,123
84
578
281
537
675

(133)
2,022
3,101
1,390
1,711

1,045
782
1,827
6
159
54
170
162

–
551
1,276
447
829

1,350
2,402
3,752
81
460
–
98
542

–
1,181
2,571
1,043
1,528

690
4,796
5,486
17
180
1,536
2,042
193

–
3,968
1,518
409
1,109

12,695
29,119
41,814
684
4,391
2,999
6,857
5,628

(893)
19,666
22,148
7,950
14,198

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

–
185
185
–
185

–
–
–
126
–
126

–
–
–
37
–
–
8
–

2
47
(47)
(1)
(46)

The group’s share of jointly controlled entities’ and associates’ results of operations in 2005 was a proﬁt of $3,029 million after deducting interest of
$226 million, taxation of $1,250 million and minority interest of $104 million.

a This note contains information relating to oil and natural gas exploration and production activities. Mid-stream activities of natural gas gathering and distribution and the
operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central
Area Transmission System. The group’s share of jointly controlled entities’ and associates’ activities is excluded from the tables and included in the footnotes, with the
exception of the Abu Dhabi operations, which are included in the income and expenditure items above.
b Includes 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.
c Sales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is
payable in cash.
d Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes, other government take, the fair value loss on embedded derivatives
$1,688 million and a $265 million charge incurred on the cancellation of an intragroup gas supply contract. The UK region includes a $530 million charge offset by
corresponding gains primarily in the US, relating to the group’s self-insurance programme.
e Excludes accretion expense attributable to exploration and production activities amounting to $122 million. Under IFRS, accretion expense is included in other finance
expense in the group income statement.
f The Exploration and Production profit before interest and tax is set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration and production activities

Group (as above)
Jointly controlled entities and associates

Mid-stream activities
Total proﬁt before interest and tax

2,077
–
52
2,129

2,332
–
(11)
2,321

9,320
–
172
9,492

3,101
309
148
3,558

1,276
35
(20)
1,291

2,571
–
(39)
2,532

(47)
2,685
(1)
2,637

1,518
–
24
1,542

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

22,148
3,029
325
25,502

174

–
119
119
–
119

–
–
–
113
–
113

5
–
5
17
–
–
(3)
–

–
14
(9)
2
(11)

51 Oil and natural gas exploration and production activitiesa

continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Capitalized costs at 31 December
Gross capitalized costs
Proved properties
Unproved properties

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

30,639
300
30,939
20,780
10,159

4,691
170
4,861
2,794
2,067

43,011
1,395
44,406
19,713
24,693

10,450
456
10,906
5,546
5,360

2,892
1,240
4,132
1,350
2,782

10,401
526
10,927
5,573
5,354

3,834
105
3,939
1,014
2,925

105,918
4,311
110,229
56,770
53,459

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Accumulated depreciation
Net capitalized costs

The group’s share of jointly controlled entities’ and associates’ net capitalized costs at 31 December 2004 was $11,013 million.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Costs incurred for the year ended 31 December
Acquisition of properties

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proved
Unproved

Exploration and appraisal costsb
Development costs
Total costs

–
2
2
51
679
732

–
–
–
17
262
279

–
58
58
423
3,247
3,728

–
5
5
199
527
731

–
–
–
85
88
173

–
13
13
142
1,460
1,615

–
–
–
9
1,007
1,016

–
78
78
1,039
7,270
8,387

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The group’s share of jointly controlled entities’ and associates’ costs incurred in 2004 was $1,102 million: in Russia $773 million and Rest of Americas
$329 million.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Results of operations for the year
ended 31 December
Sales and other operating revenuesc

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)d
Depreciation, depletion and amortization
Impairments and (gains) losses on sale of

businesses and ﬁxed assets

Proﬁt before taxatione f
Allocable taxes
Results of operations

3,458
2,424
5,882
26
901
273
(211)
1,524

21
2,534
3,348
1,242
2,106

626
609
1,235
25
117
30
38
172

1
383
852
534
318

1,735
11,794
13,529
361
1,428
477
1,884
2,268

344
6,762
6,767
2,103
4,664

1,776
2,556
4,332
141
535
239
458
611

(55)
1,929
2,403
859
1,544

977
530
1,507
14
142
45
96
174

113
584
923
(4)
927

492
1,439
1,931
45
323
–
122
287

48
825
1,106
441
665

403
2,912
3,315
8
131
1,023
1,380
121

(3)
2,660
655
150
505

9,472
22,264
31,736
637
3,577
2,087
3,764
5,157

469
15,691
16,045
5,327
10,718

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The group’s share of jointly controlled entities’ and associates’ results of operations in 2004 was a proﬁt of $1,814 million after deducting interest of
$189 million, taxation of $969 million and minority interest of $43 million.

a This note contains information relating to oil and natural gas exploration and production activities. Mid-stream activities of natural gas gathering and distribution and the
operation of the main pipelines and tankers are excluded. The main mid-stream activities are the Alaskan transportation facilities, the Forties Pipeline system and the Central
Area Transmission System. The group’s share of jointly controlled entities’ and associates’ activities is excluded from the tables and included in the footnotes, with the
exception of the Abu Dhabi operations, which are included in the income and expenditure items above.
b Includes 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.
c Sales and other operating revenues represents proceeds from the sale of production and other crude oil and gas, including royalty oil sold on behalf of others where royalty is
payable in cash.
d Includes the value of royalty oil sold on behalf of others where royalty is payable in cash, property taxes and other government take.
e Excludes accretion expense attributable to exploration and production activities amounting to $120 million. Under IFRS, accretion expense is included in other finance
expense in the group income statement.
f The Exploration and Production profit before interest and tax is set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration and production activities

Group (as above)
Jointly controlled entities and associates

Mid-stream activities
Total proﬁt before interest and tax

3,348
–
105
3,453

852
–
(15)
837

6,767
–
40
6,807

2,403
113
123
2,639

923
36
(50)
909

1,106
–
(19)
1,087

(9)
1,665
–
1,656

655
–
42
697

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

16,045
1,814
226
18,085

BP Annual Report and Accounts 2006

175

Additional information for US reporting

52 Suspended exploration well costs

Included within the total exploration expenditure of $4,110 million (2005 $4,008 million and 2004 $3,761 million) shown as part of intangible assets (see
Note 28) is an amount of $1,863 million (2005 $1,931 million and 2004 $1,680 million) representing costs directly associated with exploration wells.
The carried costs of exploration wells 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. In evaluating whether costs incurred meet the criteria for initial and continued
capitalization management uses two main criteria: (a) that exploration drilling is still under way or ﬁrmly planned, or (b) that it either has been
determined, or work is underway 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.

The following table provides the year-end balances and movements for suspended exploration well costs.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Capitalized exploration well costs
At 1 January
Additions pending determination of proved reserves
Exploration well costs written off in the year
Costs of exploration wells divested in the year
Reclassiﬁed to tangible assets following determination of proved reserves
Reclassiﬁed to investment in jointly controlled entity
At 31 December

The following table provides an ageing proﬁle of suspended exploration wells.

2006

2005

2004

1,931
590
(168)
(36)
(251)
(203)

1,863

1,680
565
(81)
(72)
(161)
–
1,931

1,698
391
(84)
(34)
(291)
–
1,680

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December

Age
Less than 1 year
1 to 5 years
6 to 10 years
More than 10 years
Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Cost
$ million

611
736
267
249

2006

Wells
gross

45
64
37
26

1,863

172

2005

Wells
gross

46
69
42
20
177

Cost
$ million

411
787
292
190
1,680

Cost
$ million

593
823
309
206
1,931

2005

Projects

2004

Wells
gross

26
81
29
18
154

2004

Projects

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The following table provides an analysis of the amount of costs directly associated with exploration wells.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Cost
$ million

Wells
gross

Cost
$ million

Wells
gross

Cost
$ million

Wells
gross

2006

Projects

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration well costs
Projects with ﬁrst capitalized exploration well

Other projects with recent or planned drilling

activity

Projects with completed exploration activity
At 31 December

drilled in the 12 months ending 31 December

188

17

12

451

31

14

290

15

12

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

894
781

86
69

21
27

1,863

172

60

718
762
1,931

65
81
177

20
28
62

400
990
1,680

36
103
154

13
41
66

Exploration projects frequently involve the drilling of multiple wells over a number of years, and several discoveries may be grouped into a single
development project. The table above shows a total of 48 projects which have exploration well costs which have been capitalized for more than twelve
months as at 31 December 2006. Of these, there are 21 projects where exploratory wells have been drilled in the preceding 12 months or further
exploratory drilling is planned in the next year. Projects with completed exploration activity comprise a total of 27 projects, whose costs totalled
$781 million at 31 December 2006. Details of the activities being undertaken to progress these projects towards development are shown below.

176

77
43

43
3

17
51

51
72

72
48

52 Suspended exploration well costs continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Country
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Angola

2 2003-2005

2008-2009

Chumbo

26

Project

Cost
$ million

2006
wells
gross

Years
wells
drilled

Anticipated
year of
development
project sanction Comment

Plutao/Saturno/Marte/
Venus

51

5 2002-2005

2007

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Colombia

Volcanera

7
1 1993

2009

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Egypt

Ras El Bar Seth

1
1 1995

2009-2012

Western Mediterranean
Block B

14

3 2002-2004

2008-2017

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Indonesia

Tangguh Phase II

4
9 1994-1997

2009-2011

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Norway

Skarv/Snadd

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Trinidad

Chachalaca

9
8 1998-2002

2007

8
1 2005

2007

Assessment of hydrocarbon quantities as potentially
commercial completed; development option identiﬁed and
under evaluation; development plan for FPSO submitted.
Assessment of hydrocarbon quantities as potentially
commercial completed; development option using FPSO
identiﬁed and under evaluation.

Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects
of project in progress; development options identiﬁed and
under evaluation; planned phased development linked to
neighbouring ﬁeld using existing infrastructure; seismic
survey in process.

Assessment of hydrocarbon quantities as potentially
commercial completed; development options identiﬁed
and under evaluation; development planned through
tieback to existing infrastructure; gas sale agreement in
place.
Assessment of hydrocarbon quantities as potentially
commercial completed; development options identiﬁed
and under evaluation; seismic survey completed and under
review; concession agreement amendment negotiations
under way.

Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects
of project in progress; onshore and offshore development
options identiﬁed and under evaluation. This is the second
phase of the LNG project which is currently under
development.

Assessment of hydrocarbon quantities as potentially
commercial completed; development options identiﬁed
and under evaluation; planned development with ﬂoating
production system and export infrastructure agreed with
partners.

Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects
of project in progress; development option selected.
Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects
of project in progress; development options identiﬁed and
under evaluation; planned subsea tieback to existing
infrastructure.
Assessment of hydrocarbon quantities as potentially
commercial completed; development options identiﬁed
and under evaluation; planned subsea tieback to existing
infrastructure ﬁelds dedicated to LNG gas contract
delivery; dependent upon capacity in existing infrastruture.
Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects
of project in progress; development options identiﬁed and
under evaluation; planned subsea tieback to existing
production facilities and LNG train; inter-governmental
discussions on unitization continue.

Coconut

47

1 2005

2010+

Corallita/Lantana

24

2 1996

2007-2008

Manakin

21

1 2000

2010+

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

140

5

BP Annual Report and Accounts 2006

177

52 Suspended exploration well costs continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Country
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
UK

1 1998

Andrew

2007

Project

14

Cost
$ million

2006
wells
gross

Years
wells
drilled

Anticipated
year of
development
project sanction Comment

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

US

Entrada

153
24

16

2 2000

2007

Devenick

90

3 1983-2001

2007

Pufﬁn

29

9 1982-1991

2008-2010

Suilven

20

3 1995-1998

2010-2011

Liberty

20

1 1997

2008

Mad Dog Deep

Mad Dog Southwest Ridge

49

33

1 2005

2009-2011

3 2005

2008

Assessment of hydrocarbon quantities as potentially
commercial completed; development options identiﬁed
and under evaluation; development awaiting capacity in
existing infrastructure; negotiations under way for gas
sales contract.
Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects
of project in progress; development options identiﬁed and
under evaluation; development expected in conjunction
with Harding Gas Project nearby.
Assessment of hydrocarbon quantities as potentially
commercial completed; further assessment of economic
and developmental aspects of project to be undertaken;
sub-surface and feasibility review under way; development
awaiting capacity in existing infrastructure.
Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic and
developmental aspects of project in progress;
development anticipated to be by tieback to existing
production vessel; awaiting capacity in existing
infrastructure.

Assessment of hydrocarbon quantities as potentially
commercial completed; development options identiﬁed
and under evaluation; expected development as subsea
tieback to facilities installed in 2005; negotiations with
infrastructure owners for product handling agreement are
under way.
Assessment of hydrocarbon quantities as potentially
commercial completed; development options identiﬁed
and under evaluation; planned tieback via extended reach
drilling from existing infrastructure; Memorandums of
Understanding with two key permitting agencies have
been secured.
Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic and
developmental aspects of project under way.
Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects of
project under way; development options identiﬁed and under
evaluation; development expected to be by subsea tieback.

Assessment of hydrocarbon quantities as potentially
commercial completed; assessment of economic aspects
of project in place; development options identiﬁed and
under evaluation; licence extension under negotiation.
Initial assessment of hydrocarbon quantities as potentially
commercial completed; further assessment of
developmental aspects of project to be undertaken; further
seismic study planned for 2007.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Vietnam

Hai Thach

126
65

7
3 1995-2002

2008-2009

Kim Cuong Tay

13

1 1995

2010-2012

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

78

4

Miscellaneous

smaller projects

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

24
781

8
69

Certain projects which were classiﬁed as projects with completed exploration drilling activity at 31 December 2005 are not classiﬁed as such at
31 December 2006:

– The following projects were sanctioned for development in 2006: Florena/Pauto in Colombia; Ras El Bar/Taurt in Egypt; Cashima and Red Mango in

Trinidad; and Dorado in the US.

– In Egypt, further exploratory drilling was undertaken in 2006 on the Temsah project, and $8 million relating to part of the project was sanctioned

in 2006.

– In Angola, the Bavuca/Kakocha/Mavacola/Mbulumbumba/Vicango project was regrouped into two separate projects, with one project planning

further exploratory drilling in 2007 and an appraisal well having been drilled on the other in 2006.

– In the US, the Point Thompson/Sourdough project was written off resulting in an expense of $27million in respect of the well costs.

178

53 US GAAP reconciliation

The consolidated ﬁnancial statements of the BP group are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted for
use by the EU, which differ in certain respects from US generally accepted accounting principles (US GAAP). IFRS as adopted by the EU differs in
certain respects from IFRS as issued by the International Accounting Standards Board (IASB). However, the consolidated ﬁnancial statements for the
years presented would be no different had the group applied IFRS as issued by the IASB.

The following is a summary of the adjustments to proﬁt for the year attributable to BP shareholders and to BP shareholders’ equity that would be

required if US GAAP had been applied instead of IFRS.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt for the year
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
For the year ended 31 December
Proﬁt as reported in the Annual Report and Accounts to accord with IFRS
Texas City provision timing differencea
Proﬁt as reported in the Annual Report on Form 20-F to accord with IFRS
Adjustments

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

22,341
(315)
22,026

17,075
–
17,075

$ million except per share amounts

22,000
315

22,315

2005

2004

2006

Deferred taxation/business combinations (a)
Provisions (b)
Oil and natural gas reserves differences (c)
Goodwill and intangible assets (d)
Derivative ﬁnancial instruments (e)
Inventory valuation (f)
Gain arising on asset exchange (g)
Pensions and other post-retirement beneﬁts (h)
Impairments (i)
Equity-accounted investments (j)
Consolidation of variable interest entities (l)
Major maintenance expenditure (m)
Share-based payments (n)
Other

(224)
177
(243)
13
142
162
(10)
(873)
(332)
(104)
(5)
–
92
6

21,116

–

21,116
2

21,114

105.42
–

105.42

104.63
–

104.63

632.52
–

632.52

627.78
–

627.78

(496)
9
11
–
87
(232)
(12)
(486)
(378)
(255)
–
–
6
156
20,436

(794)
19,642
2
19,640

96.72
(3.76)
92.96
95.62
(3.71)
91.91

580.32
(22.56)
557.76
573.72
(22.26)
551.46

(517)
(80)
30
(61)
(337)
162
(107)
(47)
677
147
–
217
24
(93)
17,090

–
17,090
2
17,088

78.31
–
78.31
76.88
–
76.88

469.86
–
469.86
461.28
–
461.28

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt for the year before cumulative effect of accounting change as adjusted to accord with US GAAP
Cumulative effect of accounting change
Major maintenance expenditure (m)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt for the year as adjusted to accord with US GAAP
Dividend requirements on preference shares
Proﬁt for the year attributable to ordinary shares as adjusted to accord with US GAAP
Per ordinary share – cents

Basic – before cumulative effect of accounting change
Cumulative effect of accounting change

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Diluted – before cumulative effect of accounting change
Cumulative effect of accounting change

Per American depositary share – centsb

Basic – before cumulative effect of accounting change
Cumulative effect of accounting change

Diluted – before cumulative effect of accounting change
Cumulative effect of accounting change

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a BP’s financial statements for the year ended 31 December 2005 were authorized for issue on 6 February 2006 and were included in the 2005 Annual Report and Accounts.
BP filed its 2005 Annual Report on Form 20-F on 30 June 2006. The financial statements included in this filing were approved on 30 June 2006 and reflected an additional
provision of $315 million (post-tax) relating to the Texas City incident of March 2005 as a result of new information that came to light after 6 February 2006. The amount of
this timing difference therefore appears as a reconciling item between the profit to accord with IFRS reported in the Annual Report and Accounts and the profit to accord
with IFRS reported in the Form 20-F for both 2005 and 2006. Similarly, there was a difference of the same amount between BP shareholders’ equity to accord with IFRS at
31 December 2005 as reported in the 2005 Annual Report and Accounts and in the Form 20-F.
b One American depositary share is equivalent to six ordinary shares.

BP Annual Report and Accounts 2006

179

53 US GAAP reconciliation continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BP shareholders’ equity
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
At 31 December
BP shareholders’ equity as reported in the Annual Report and Accounts to accord with IFRS
Texas City provision timing differencea
BP shareholders’ equity as reported in the Annual Report on Form 20-F to accord with IFRS
Adjustments

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

79,976
(315)
79,661

84,624
–

84,624

$ million

2005

2006

Deferred taxation/business combinations (a)
Provisions (b)
Oil and natural gas reserves differences (c)
Goodwill and intangible assets (d)
Derivative ﬁnancial instruments (e)
Inventory valuation (f)
Gain arising on asset exchange (g)
Pensions and other post-retirement beneﬁts (h)
Impairments (i)
Equity-accounted investments (j)
Consolidation of variable interest entities (l)
Share-based payments (n)
Other

1,801
63
(202)
248
202
(5)
229
–
2
(160)
(5)
(254)
(26)

86,517

2,025
(112)
41
171
225
(167)
239
3,146
327
(43)
–
(334)
(32)
85,147

$ million

2006

2005

2004

21,116

19,642

17,090

1,824

(2,865)

2,143

480
(2)

(504)
27

291
(42)

(59)
(32)

141
–

(1,165)
–

102

(131)

–

82

23,125

249
17,053

(838)
17,371

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BP shareholders’ equity as adjusted to accord with US GAAP

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Comprehensive income
The components of comprehensive income, net of related tax, are as follows:

For the year ended 31 December
Proﬁt for the year as adjusted to accord with US GAAP
Currency translation differences net of tax beneﬁt (expense) of $(203) million (2005 $328 million and

2004 $(208) million)

Investments

Unrealized gains net of tax beneﬁt (expense) of $(83) million (2005 $(110) million and 2004 $(71) million)
Unrealized losses net of tax beneﬁt (expense) of $nil (2005 $16 million and 2004 $nil)
Less: reclassiﬁcation adjustment for gains included in net income net of tax beneﬁt (expense) of $191 million

(2005 $22 million and 2004 $627 million)

Currency translation differences net of tax beneﬁt (expense) of $nil (2005 $nil and 2004 $nil)

Unrealized gains (losses) on cash ﬂow hedges net of tax beneﬁt (expense) of $(3) million (2005 $63 million and

2004 $nil)

Minimum pension liability adjustment net of tax beneﬁt (expense) of $44 million (2005 $(94) million and

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004 $130 million)
Comprehensive income

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Accumulated other comprehensive income
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
At 31 December
Currency translation differences
Net unrealized gains on investments
Unrealized losses on cash ﬂow hedges
Minimum pension liability adjustment
Funded status of deﬁned beneﬁt pension and other post-retirement beneﬁt plansc d
Accumulated other comprehensive income

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,496
385
(131)
(866)
–
884

3,320
386
(29)
–
(1,383)

$ million

2,294

2005

2006

c The amount reported for the funded status of defined benefit pension and other post-retirement benefit plans at 31 December 2006 includes $(599) million resulting from the
adoption of FASB Statement of Financial Accounting Standards (SFAS) No. 158 ‘Employers’ Accounting for Defined Benefit Pension and Other Post-retirement Plans, an
amendment of FASB Statements No. 87, 88, 106, and 132(R)’. Further information on the effects of adoption of SFAS 158 is provided in note (h) Pensions and other
post-retirement benefits.
d Includes $(13) million relating to equity-accounted entities.

Consolidated statement of cash ﬂows
The group’s ﬁnancial statements include a consolidated cash ﬂow statement in accordance with IAS 7 ‘Cash Flow Statements’. The statement prepared
under IAS 7 presents substantially the same information as that required under FASB SFAS No. 95 ‘Statement of Cash Flows’; however, as permitted
under IAS 7, the group includes payments in respect of capitalized interest in operating activities. Under SFAS 95, these payments are treated as cash
outﬂows for investing activities.

The adjustments to the group’s cash ﬂow statement for the year to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

478
(478)

–

2005

351
(351)
–

$ million

2004

204
(204)
–

Increase (decrease) in caption heading
For the year ended 31 December
Net cash provided by operating activities
Net cash provided by (used in) investing activities
Increase (decrease) in cash and cash equivalents

180

53 US GAAP reconciliation continued

The principal differences between IFRS and US GAAP for BP group reporting relate to the following:

(a) Deferred taxation/business combinations
Under IFRS, deferred tax assets and liabilities are recognized for the difference between the assigned values and the tax bases of the assets and
liabilities recognized in a purchase business combination. IFRS 3 ‘Business Combinations’ typically requires the offset to the recognition of such
deferred tax assets and liabilities to be adjusted against goodwill. However, under the exemptions contained in IFRS 1 ‘First-time Adoption of
International Financial Reporting Standards’, business combinations prior to the group’s date of transition to IFRS were not restated in accordance with
IFRS 3 and the offset was taken as an adjustment to shareholders’ equity at the date of transition to IFRS.

Under US GAAP, deferred tax assets or liabilities are also recognized for the difference between the assigned values and the tax bases of the assets

and liabilities recognized in a purchase business combination. SFAS No. 141 ‘Business Combinations’, requires that the offset be recognized against
goodwill. As such, the treatment adopted under IFRS 1 as compared with SFAS 141 creates a difference related to business combinations accounted
for under the purchase method that occurred prior to the group’s date of transition to IFRS.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The major components of deferred tax liabilities and assets on a US GAAP basis at 31 December were as follows.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Depreciation, depletion and amortization
Taxation
Proﬁt for the year

Property, plant and equipment
Deferred tax liabilities
BP shareholders’ equity

Deferred tax liability
Depreciation
Pension plan surplus
Other taxable temporary differences

Deferred tax asset

Petroleum revenue tax
Pension plan and other post-retirement beneﬁt plan deﬁcits
Decommissioning, environmental and other provisions
Derivative ﬁnancial instruments
Tax credit and loss carry forward
Other deductible temporary differences

Gross deferred tax asset
Valuation allowance
Net deferred tax asset
Net deferred tax liability

$ million

2006

2005

2004

397
(173)
(224)

254
242
(496)

2,048
(1,531)
(517)

2006

2005

3,062
1,261
1,801

3,459
1,434
2,025

2006

2005

22,295
1,733
4,687

28,715

(457)
(2,012)
(2,942)
(928)
(3,920)
(2,623)

(12,882)
3,830

(9,052)

19,663

20,782
1,371
4,214
26,367

(407)
(1,154)
(2,292)
(770)
(3,533)
(1,591)
(9,747)
3,222
(6,525)
19,842

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(b) Provisions
Under IFRS, provisions for decommissioning and environmental liabilities are measured on a discounted basis if the effect of the time value of money is
material. In accordance with IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’, the provisions for decommissioning and environmental
liabilities are estimated using costs based on current prices and discounted using rates that take into consideration the time value of money and risks
inherent in the liability. The periodic unwinding of the discount is included in other ﬁnance expense. Similarly, the effect of a change in the discount rate
is included in other ﬁnance expense in connection with all provisions other than decommissioning liabilities.

Upon initial recognition of a decommissioning provision, a corresponding amount is also recognized as an item of property, plant and equipment and
is subsequently depreciated as part of the capital cost of the facilities. Adjustments to the decommissioning liabilities, associated with changes to the
future cash ﬂow assumptions or changes in the discount rate, are reﬂected as increases or decreases to the corresponding item of property, plant and
equipment and depreciated prospectively over the asset’s remaining economic useful life.

Under US GAAP, decommissioning liabilities are recognized in accordance with SFAS No. 143 ‘Accounting for Asset Retirement Obligations’. SFAS
143 is similar to IAS 37 and requires that when an asset retirement liability is recognized, a corresponding amount is capitalized and depreciated as an
additional cost of the related asset. The liability is measured based on the risk-adjusted future cash outﬂows discounted using a credit-adjusted risk-free
rate. The unwinding of the discount is included in operating proﬁt for the period. Unlike IFRS, subsequent changes to the discount rate do not impact
the carrying value of the asset or liability. Subsequent changes to the estimates of the timing or amount of future cash ﬂows, resulting in an increase to
the asset and liability, are remeasured using updated assumptions related to the credit-adjusted risk-free rate.

In addition, the use of different oil and natural gas reserves volumes between US GAAP and IFRS until 1 October 2006 (see note (c) Oil and natural
gas reserves differences) resulted in different ﬁeld lives and hence differences in the manner in which the subsequent unwinding of the discount and
the depreciation of the corresponding assets associated with decommissioning provisions were recognized.

BP Annual Report and Accounts 2006

181

53 US GAAP reconciliation continued

Under US GAAP, environmental liabilities are discounted only where the timing and amounts of payments are ﬁxed and reliably determinable.
Under IFRS, an expected loss is recognized immediately as a provision for an executory contract if the unavoidable costs of meeting the obligations

under the contract exceed the economic beneﬁts expected to be received under it. Under US GAAP, an expected loss can only be recognized if the
contract is within the scope of authoritative literature that speciﬁcally provides for such accruals. The group has recognized losses under IFRS on certain
sales contracts with ﬁxed-price ceilings which do not meet loss recognition criteria under US GAAP.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

Increase (decrease) in caption heading

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Production and manufacturing expenses and depreciation, depletion and amortization
Distribution and administration expenses
Other ﬁnance (income) expense
Taxation
Proﬁt for the year

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Property, plant and equipment
Provisions
Deferred tax liabilities
BP shareholders’ equity

At 1 January
Exchange adjustments
New provisions/adjustment to provisions
Unwinding of discount
Utilized/deleted
At 31 December

The following data summarizes the movements in the asset retirement obligations, as adjusted to accord with US GAAP.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(c) Oil and natural gas reserves differences
The group’s past practice was to use the UK accounting rules contained in the Statement of Recommended Practice ‘Accounting for Oil and Gas
Exploration, Development, Production and Decommissioning Activities’ (SORP) for estimating oil and natural gas reserves for accounting and reporting
purposes. These rules are different in certain respects from the corresponding SEC rules. In particular, the SEC requires the use of year-end prices,
whereas under SORP the group used long-term planning prices. The consequential difference in reserves volumes resulted in different charges for
depreciation, depletion and amortization (DD&A) between IFRS and US GAAP.

At the end of 2006, the group adopted the SEC rules for estimating oil and natural gas reserves for IFRS accounting and reporting purposes and the

charge for DD&A was calculated on this basis for the last three months of the year. This is a change in accounting estimate and the impact of the
change is applied prospectively. Differences in charges for DD&A between IFRS and US GAAP will continue due to the difference in net book values of
the underlying oil and natural gas properties.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Gain on sale of businesses and ﬁxed assets
Depreciation, depletion and amortization
Taxation
Proﬁt for the year

Property, plant and equipment
Deferred tax liabilities
BP shareholders’ equity

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

US GAAP requires the unit-of-production depreciation calculation to be based on development expenditure incurred to date and proved developed
reserves. Where production commences before all development wells are drilled, a portion of the development costs incurred to date is excluded from
the calculation. For the group’s portfolio of ﬁelds there is no material difference between the group’s charge for unit-of-production depreciation
determined on an IFRS basis and on a US GAAP basis.

182

$ million

2006

2005

2004

56
(108)
(245)
120
177

201
–
(201)
(9)
9

254
–
(196)
22
(80)

2006

2005

(2,065)
(2,184)
56
63

(1,842)
(1,666)
(64)
(112)

2006

4,429
9
1,679
280
(360)

6,037

2005

3,898
4
554
237
(264)
4,429

$ million

2006

2005

2004

(198)
201
(156)
(243)

–
(20)
9
11

–
(48)
18
30

2006
(331)
(129)
(202)

2005
68
27
41

2006
13
–
13

$ million

2004
–
61
(61)

2005
171
171

2005
–
–
–

2006
248
248

53 US GAAP reconciliation continued

(d) Goodwill and intangible assets
For the purposes of US GAAP, the group accounts for goodwill according to SFAS No. 141 ‘Business Combinations’, and SFAS No. 142 ‘Goodwill and
Other Intangible Assets’. For the purposes of IFRS, the group accounts for goodwill under the provisions of IFRS 3 ‘Business Combinations’ and IAS 38
‘Intangible Assets’. As a result of the transition rules available under IFRS 1, the group did not restate its past business combinations in accordance with
IFRS 3 and assumed its UK GAAP carrying amount for goodwill as its IFRS carrying amount upon transition to IFRS, at 1 January 2003.

Under US GAAP, goodwill and other indeﬁnite lived intangible assets have not been amortized since 31 December 2001. Such assets are subject to

periodic impairment testing. The group has goodwill, but does not have any other intangible assets with indeﬁnite lives. Under IFRS, goodwill
amortization ceased from 1 January 2003.

The movement in the goodwill difference during 2006 is the result of movements in foreign exchange rates and a difference in the amount of

goodwill allocated to the Gulf of Mexico Shelf assets sold.

During the fourth quarter of 2006 the group completed a goodwill impairment review using the two-step process prescribed in US GAAP. The ﬁrst
step includes a comparison of the fair value of a reporting unit to its carrying value, including goodwill. When the carrying value exceeds the fair value,
the goodwill of the reporting unit is potentially impaired and the second step is then completed in order to measure the impairment loss, if any. No
impairment charge resulted from this review.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Gain on sale of businesses and ﬁxed assets
Depreciation, depletion and amortization
Proﬁt for the year

Goodwill
BP shareholders’ equity

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

In accordance with group accounting practice, exploration licence acquisition costs are capitalized initially as an intangible asset and are amortized over
the estimated period of exploration. Where proved reserves of oil or natural gas are determined and development is sanctioned, the unamortized cost is
transferred to property, plant and equipment. Where exploration is unsuccessful, the unamortized cost is charged against income. At 31 December
2006 and 31 December 2005, exploration licence acquisition costs included in the group’s property, plant and equipment and intangible assets, net of
accumulated amortization were as follows.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration licence acquisition cost included in non-current assets (net of accumulated amortization)

2006

2005

Property, plant and equipment
Intangible assets

1,076
639

1,201
597

Changes to the net book amount of exploration expenditure, goodwill and other intangible assets, as adjusted to accord with US GAAP, during the years
ended 31 December 2006 and 2005 are shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Exploration
expenditure

3,761
(305)
552
4,008
(732)
834
4,110

Goodwill

11,535
–
(862)
10,673
–
476
11,149

Additional
minimum
pension
liability (h)

Other
intangibles

39
–
(12)
27
–
(27)
–

443
(161)
482
764
(217)
589
1,136

Total

15,778
(466)
160
15,472
(949)
1,872
16,395

Net book amount
At 1 January 2005
Amortization expense
Other movements
At 1 January 2006
Amortization expense
Other movements
At 31 December 2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Amortization expense relating to other intangibles is expected to be in the range of $200-250 million in each of the succeeding ﬁve years.

BP Annual Report and Accounts 2006

183

53 US GAAP reconciliation continued

(e) Derivative ﬁnancial instruments
Under IFRS, the group accounts for its derivative ﬁnancial instruments under IAS 39 ‘Financial Instruments: Recognition and Measurement’. IAS 39
requires that derivative ﬁnancial instruments be measured at fair value and changes in fair value are either recognized in the income statement or
directly in equity (other comprehensive income) depending on the classiﬁcation of the instrument. Changes in the fair value of derivatives held for
trading purposes or those not designated or effective as hedges are recognized in the income statement.

Changes in the fair value of derivatives designated and effective as cash ﬂow hedges are recognized directly in equity (other comprehensive income).
Amounts recorded in equity are transferred to the income statement when the hedged transaction affects proﬁt or loss. Where the hedged item is the
cost of a non-ﬁnancial asset or liability, the amounts taken to equity are transferred to the initial carrying amount of the non-ﬁnancial asset or liability.

Changes in the fair value of derivatives designated and effective as fair value hedges are recognized in the income statement. The carrying amount of
the hedged item is adjusted for gains and losses attributable to the risk being hedged with the corresponding gains and losses recognized in the income
statement.

On adoption of IAS 39 on 1 January 2005, all cash ﬂow and fair value hedges that previously qualiﬁed for hedge accounting under UK GAAP were

recorded on the balance sheet at fair value with the offset recorded through equity.

Under US GAAP all derivative ﬁnancial instruments are accounted for under SFAS No. 133 ‘Accounting for Derivative Instruments and Hedging
Activities’ and recorded on the balance sheet at their fair value. Similar to IAS 39, SFAS 133 requires that changes in the fair value of derivatives are
recorded each period in the income statement or other comprehensive income, depending on whether the instrument is designated as part of a hedge
transaction.

Prior to 1 January 2005, the group did not designate any of its derivative ﬁnancial instruments as part of hedged transactions under SFAS 133. As a
result, all changes in fair value were recognized in the income statement. A difference therefore exists between the treatment applied under SFAS 133
and that upon initial adoption of IAS 39 associated with those speciﬁc derivative instruments. This difference will remain until these individual derivative
transactions mature.

Additionally, under IFRS, hedge accounting can be applied to certain centrally-hedged foreign currency exposures. Under US GAAP, hedge accounting

can be applied only where the companies between the central treasury and the entity having the foreign currency exposure have the same functional
currency.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Production and manufacturing expenses
Finance costs
Taxation
Proﬁt for the year

Goodwill
Finance debt
Deferred tax liabilities
BP shareholders’ equity

(f) Inventory valuation
Under IFRS, inventory held for trading purposes is remeasured to fair value with the changes in fair value recognized in the income statement. Under
US GAAP, all balances recorded in inventory are measured at the lower of cost and net realizable value.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

Increase (decrease) in caption heading

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

2006

2005

2004

(169)
(17)
44
142

–
(15)
(72)
87

481
–
(144)
(337)

2006

2005

131
(117)
46
202

131
(140)
46
225

$ million

2006

2005

2004

(250)
88
162

357
(125)
(232)

(250)
88
162

2006

2005

(7)
(2)
(5)

(257)
(90)
(167)

Purchases
Taxation
Proﬁt for the year

Inventories
Deferred tax liabilities
BP shareholders’ equity

184

53 US GAAP reconciliation continued

(g) Gain arising on asset exchange
Under IFRS, exchanges of non-monetary assets are generally accounted for at fair value at the date of the transaction, with any gain or loss recognized
in proﬁt or loss. Under US GAAP prior to 1 January 2005, exchanges of non-monetary assets were accounted for at book value. From 1 January 2005
exchanges of non-monetary assets are generally accounted for at fair value under both IFRS and US GAAP.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Depreciation, depletion and amortization
Taxation
Proﬁt for the year

Property, plant and equipment
Deferred tax liabilities
BP shareholders’ equity

$ million

2006

2005

2004

15
(5)
(10)

19
(7)
(12)

117
(10)
(107)

2006

2005

352
123
229

367
128
239

(h) Pensions and other post-retirement beneﬁts
Under IFRS, the group accounts for its pension and other post-retirement beneﬁt plans according to IAS 19 ‘Employee Beneﬁts’. Surpluses and deﬁcits
of pension and other post-retirement beneﬁt plans are included in the group balance sheet at their fair values and all movements in these balances are
reﬂected in the income statement, except for those relating to actuarial gains and losses which are reﬂected in the statement of recognized income and
expense. In the past, this treatment has differed from the group’s US GAAP treatment under SFAS No. 87 ‘Employers’ Accounting for Pensions’ and
SFAS No. 106 ‘Employers’ Accounting for Post-retirement Beneﬁts Other Than Pensions’, where actuarial gains and losses were not recognized in the
income statement as they occurred but were recognized within income in full only when they exceeded certain thresholds, and otherwise were
amortized. This difference in recognition rules for actuarial gains and losses gave rise to differences in periodic pension and other post-retirement beneﬁt
expense as measured under IAS 19 compared to SFAS 87 and SFAS 106.

In addition, when a pension plan had an accumulated beneﬁt obligation which exceeded the fair value of the plan assets, SFAS 87 required the

unfunded amount to be recognized as a minimum liability in the balance sheet. The offset to this liability was recorded as an intangible asset up to the
amount of any unrecognized prior service cost or transitional liability, and thereafter directly in other comprehensive income. IAS 19 does not have a
similar concept. As a result, this created a difference in shareholders’ equity as measured under IFRS and US GAAP.

In September 2006, the FASB issued SFAS No. 158 ‘Employers’ Accounting for Deﬁned Beneﬁt Pension and Other Post-retirement Plans, an

amendment of FASB Statements No. 87, 88, 106, and 132(R)’. SFAS 158 requires an employer to recognize the overfunded or underfunded status of a
deﬁned beneﬁt post-retirement plan (other than a multi-employer plan) as an asset or liability in the balance sheet and to recognize changes in that
funded status in other comprehensive income in the year in which the changes occur. Because the funded status of beneﬁt plans is fully recognized in
the balance sheet, a minimum liability will no longer be recognized. Retrospective application of SFAS 158 is not permitted. Upon adoption of SFAS 158,
the recognition of the overfunded or underfunded status of the group’s deﬁned beneﬁt pension and other post-retirement plans generally accords with
the group’s IFRS accounting. Differences in recognition rules for actuarial gains and losses will continue to give rise to differences in periodic pension
and other post-retirement beneﬁt expense as measured under IFRS and US GAAP. The group has adopted SFAS 158 with effect from 31 December
2006, resulting in a $599 million decrease in BP shareholders’ equity, as adjusted to accord with US GAAP. Of this total effect, $586 million relates to
group entities and $13 million relates to equity-accounted entities. The effect on equity-accounted entities is included in note (j) Equity-accounted
investments. Further information on the effects of adoption of SFAS 158 is given below.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Production and manufacturing expenses
Other ﬁnance (income) expense
Taxation
Proﬁt for the year

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Intangible assets
Other receivables
Deﬁned beneﬁt pension plan surplus
Current liabilities
Provisions
Deﬁned beneﬁt pension plan and other post-retirement beneﬁt plan deﬁcits
Deferred tax liabilities
BP shareholders’ equity

$ million

2006

2005

2004

801
470
(398)
(873)

583
116
(213)
(486)

330
(29)
(254)
(47)

2006

2005

–
–
–
603
–
(603)
–
–

27
6,667
(3,282)
–
7,884
(9,230)
1,612
3,146

The incremental effects of adopting the provisions of SFAS 158 on the group’s balance sheet at 31 December 2006, as adjusted to accord with US
GAAP, are presented in the following table. The adoption of SFAS 158 had no effect on the group’s consolidated income statement, as adjusted to
accord with US GAAP, and will not affect the group’s US GAAP proﬁt in future periods. Had the group not been required to adopt SFAS 158 at 31
December 2006, the group would have recognized an additional minimum pension liability. The effect of recognizing the additional minimum pension
liability is included in the table below in the column headed ‘Prior to adoption’.

BP Annual Report and Accounts 2006

185

53 US GAAP reconciliation continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Prior to
adoption

Effect of
adoption

As
reported

12
7,022
–
–
8,622
–
573
(2,161)

1,022
238
784

(12)
(7,022)
6,753
603
(8,622)
8,673
(349)
(586)
935
349
586

–
–
6,753
603
–
8,673
224
(2,747)
1,957
587
1,370

$ million

757
2,012
(2,161)
9
445
64
(4)
60
1,182
162
1,344
(102)
1,242

829
1,940
(2,140)
11
934
55
(43)
278

1,864
177

2,041
–

2,041

785
2,022
(2,115)
10
656
79
(38)
49
1,448
172
1,620
(83)
1,537

Intangible assets
Other receivables
Deﬁned beneﬁt pension plan surplus
Current liabilities
Provisions
Deﬁned beneﬁt pension plan and other post-retirement beneﬁt plan deﬁcits
Deferred tax liabilities
BP shareholders’ equity
Accumulated other comprehensive income
Taxation
Accumulated other comprehensive income (net of deferred tax)

Deﬁned beneﬁt plans

Service cost – beneﬁts earned during year
Interest cost on projected beneﬁt obligation
Expected return on plan assets
Amortization of transition asset
Recognized net actuarial (gain) loss
Recognized prior service cost
Curtailment and settlement (gains) losses
Special termination beneﬁts

Deﬁned contribution plans

Further information in respect of the group’s deﬁned beneﬁt pension and other post-retirement plans required under US GAAP is set out below.

Analysis of the pension and other post-retirement beneﬁts expense

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Innovene operations
Total pension and other post-retirement beneﬁts expense for continuing operations

The table below shows the amounts included in accumulated other comprehensive income at 31 December 2006 that have not yet been recognized as
components of the pension and other post-retirement beneﬁts expense in the income statement, as adjusted to accord with US GAAP.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

Net actuarial (gain) loss
Prior service cost (credit)
Transition obligation (asset)

Net actuarial (gain) loss
Prior service cost (credit)
Transition obligation (asset)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The amounts included in accumulated other comprehensive income at 31 December 2006 which are expected to be recognized as components of the
pension and other post-retirement beneﬁts expense for the year ended 31 December 2007 in the income statement, as adjusted to accord with US
GAAP are shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

(1,407)

2,200

83

1,081

1,957

UK
pension
plans

(1,805)
398
–

US
pension
plans

2,099
101
–

US other
post-
retirement
beneﬁt
plans

514
(431)
–

Other
plans

1,055
19
7

Total

1,863
87
7

UK
pension
plans

US
pension
plans

243
76
–

222
11
–

US other
post-
retirement
beneﬁt
plans

47
(54)
–

Other
plans

120
3
–

Total

632
36
–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

319

233

(7)

123

668

186

53 US GAAP reconciliation continued

The table below shows, at 31 December 2006, the aggregate projected beneﬁt obligation and the aggregate fair value of plan assets for those pension
plans where the projected beneﬁt obligation exceeds the fair value of the plan assets.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Projected beneﬁt obligation
Fair value of plan assets
Excess of projected beneﬁt obligation over plan assets

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The table below shows, at 31 December 2006, the aggregate accumulated beneﬁt obligation and the aggregate fair value of plan assets for those
pension plans where the accumulated beneﬁt obligation exceeds the fair value of the plan assets.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Accumulated beneﬁt obligation
Fair value of plan assets
Excess of accumulated beneﬁt obligation over plan assets

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

A summary of beneﬁt obligations and amounts recognized under US GAAP in the balance sheet at 31 December 2005 is shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

UK
pension
plans

117
–

US
pension
plans

411
54

Other
plans

7,082
1,554

Total

7,610
1,608

117

357

5,528

6,002

UK
pension
plans

92
–

US
pension
plans

386
54

Other
plans

5,770
660

Total

6,248
714

92

332

5,110

5,534

US other
post-
retirement
beneﬁt
plans

3,478
28

(3,450)
–
793
(485)

(3,154)
–
12

US
pension
plans

7,900
7,317

(583)
–
3,249
70

2,535
12
189

UK
pension
plans

20,063
23,282

3,219
–
222
490

3,910
–
21

Other
plans

7,414
2,280

(5,134)
17
1,454
8

(4,508)
15
838

Total

38,855
32,907

(5,948)
17
5,718
83

(1,217)
27
1,060

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Beneﬁt obligation at 31 December
Fair value of plan assets at 31 December
Funded status
Unrecognized transition (asset) obligation
Unrecognized net actuarial (gain) loss
Unrecognized prior service cost
Net amount recognized
Prepaid beneﬁt cost (accrued beneﬁt liability)
Intangible asset
Accumulated other comprehensive incomea

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

3,931

2,736

(3,142)

(3,655)

(130)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Total $866 million net of deferred tax.

3,931

2,736

(3,142)

(3,655)

(130)

(i) Impairments
Under IFRS, in determining the amount of any impairment loss, the carrying value of property, plant and equipment and goodwill is compared with the
discounted value of the future cash ﬂows. Under US GAAP, SFAS No. 144 ‘Accounting for the Impairment or Disposal of Long-lived Assets’ requires
that the carrying value is compared with the undiscounted future cash ﬂows to determine if an impairment is present, and only if the carrying value is
less than the undiscounted cash ﬂows is an impairment loss recognized. The impairment is measured using the discounted value of the future cash
ﬂows. Due to this difference, some impairment charges recognized under IFRS, adjusted for the impacts of depreciation, have not been recognized for
US GAAP.

Additionally, under IFRS, in certain situations and subject to certain limitations, a previously-recognized impairment loss is reversed. Under US GAAP,

the reversal of a previously-recognized impairment loss for an asset to be held and used is not permitted.

The decrease to gain on sale of businesses and ﬁxed assets for the year ended 31 December 2006 represents the impact of a 2005 impairment

charge recognized under IFRS but not for US GAAP on certain Gulf of Mexico Shelf assets that were subsequently sold in 2006.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

Increase (decrease) in caption heading

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Gain on sale of businesses and ﬁxed assets
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and ﬁxed assets
Taxation
Proﬁt for the year

Property, plant and equipment
Deferred tax liabilities
BP shareholders’ equity

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

2006

2005

2004

(208)
6
340
(222)
(332)

–
28
477
(127)
(378)

–
–
(986)
309
677

2006

2005

(40)
(42)
2

504
177
327

BP Annual Report and Accounts 2006

187

53 US GAAP reconciliation continued

(j) Equity-accounted investments
Under IFRS the group’s accounting policies are applied in arriving at the amounts to be included in the ﬁnancial statements in relation to
equity-accounted investments. The major difference between IFRS and US GAAP in this respect relates to deferred tax (see note (a) Deferred
taxation/business combinations).

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Earnings from jointly controlled entities
Proﬁt for the year

Investments in jointly controlled entities
BP shareholders’ equity

(k) Assets classiﬁed as held for sale
Recognition and measurement of assets classiﬁed as held for sale (and liabilities directly associated with assets classiﬁed as held for sale) under IFRS is
substantially equivalent to US GAAP. However, the amounts presented for IFRS reporting differ from those under US GAAP due to differences in the
underlying carrying values of the assets and liabilities classiﬁed as held for sale.

The adjustments to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Goodwill
Assets classiﬁed as held for sale
BP shareholders’ equity

(l) Consolidation of variable interest entities
In December 2003, the FASB issued FASB Interpretation No. 46 (Revised) ‘Consolidation of Variable Interest Entities’. Interpretation 46 clariﬁes the
application of existing consolidation requirements to entities where a controlling ﬁnancial interest is achieved through arrangements that do not involve
voting interests. Under Interpretation 46, a variable interest entity is consolidated if a company is subject to a majority of the risk of loss from the
variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns.

The group currently has several ships under construction or in service which are accounted for under IFRS as operating leases. Under Interpretation
46 certain of the arrangements represent variable interest entities that would be consolidated by the group. The maximum exposure to loss as a result
of the group’s involvement with these entities is limited to the debt of the entity, less the fair value of the ships at the end of the lease term.

During 2006, a number of the existing leasing arrangements that were being consolidated for US GAAP reporting were modiﬁed. Under the revised

arrangements, the group is not the primary beneﬁciary. As such, the arrangements are no longer consolidated under US GAAP.

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

2006

2005

2004

(104)
(104)

(255)
(255)

147
147

2006

2005

(160)
(160)

(43)
(43)

$ million

2005

2006

(10)
10
–

–
–
–

$ million

2006

2005

2004

(18)
21
6
(4)
(5)

(32)
23
9
–
–

(15)
10
5
–
–

2006

2005

497
(45)
551
(4)
(5)

807
(31)
838
–
–

Increase (decrease) in caption heading

Production and manufacturing expenses
Depreciation, depletion and amortization
Finance costs
Taxation
Proﬁt for the year

Property, plant and equipment
Trade and other payables
Finance debt
Deferred tax liabilities
BP shareholders’ equity

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

188

53 US GAAP reconciliation continued

(m) Major maintenance expenditure
For the purposes of US GAAP reporting, prior to 1 January 2005, the group capitalized expenditures on maintenance, reﬁts or repairs where it enhanced
or restored the performance of an asset, or replaced an asset or part of an asset that was separately depreciated. This included other elements of
expenditure incurred during major plant maintenance shutdowns, such as overhaul costs.

With effect from 1 January 2005, the group changed its US GAAP accounting policy to expense the part of major maintenance that represents
overhaul costs and similar major maintenance expenditure as incurred. The effect of this accounting change for US GAAP reporting is reﬂected as a
cumulative effect of an accounting change for the year ended 31 December 2005 of $794 million (net of tax beneﬁts of $354 million). This adjustment is
equal to the net book value of capitalized overhaul costs as of 1 January 2005 as reported under US GAAP. This new accounting policy reﬂects the
policy applied under IFRS for all periods presented. As a result, a difference between IFRS and US GAAP exists for periods prior to 1 January 2005
which reﬂects the capitalization of overhaul costs net of the related depreciation charge as calculated under US GAAP.

The adjustments to proﬁt for the year to accord with US GAAP are summarized below.

Increase (decrease) in caption heading

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Production and manufacturing expenses
Depreciation, depletion and amortization
Taxation
Proﬁt for the year before cumulative effect of accounting change
Cumulative effect of accounting change
Proﬁt for the year

2006

2005

2004

$ million

–
–
–
–
–
–

–
–
–
–
(794)
(794)

(586)
296
73
217
–
217

The following pro forma information summarizes the proﬁt for the year assuming the change in accounting for major maintenance expenditure was
applied retrospectively with effect from 1 January 2004.

2005a

$ million

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt for the year attributable to ordinary shares as adjusted to accord with US GAAP

As reported
Pro forma

Per ordinary share – cents

Basic – as reported
Basic – pro forma
Diluted – as reported
Diluted – pro forma

Per American depositary share – cents

Basic – as reported
Basic – pro forma
Diluted – as reported
Diluted – pro forma

19,640
20,434

17,088
16,871

92.96
96.72
91.90
95.61

557.76
580.32
551.40
573.66

78.31
77.32
76.88
75.97

469.86
463.92
461.28
455.82

a Pro forma data for the year ended 31 December 2005 excludes the cumulative effect of adoption.

(n) Share-based payments
The group adopted SFAS No. 123 (revised 2004), ‘Share-Based Payment’ with effect from 1 January 2005 using the modiﬁed prospective transition
method. Under SFAS 123(R), share-based payments to employees are required to be measured based on their grant date fair value (with limited
exceptions) and recognized over the related service period. For periods prior to 1 January 2005, the group accounted for share-based payments under
Accounting Principles Board Opinion No. 25 using the intrinsic value method.

With effect from 1 January 2005, as part of the adoption of IFRS, the group adopted IFRS 2 ‘Share-based Payment’. IFRS 2 requires the recognition

of expense when goods or services are received from employees or others in consideration for equity instruments. In adopting IFRS 2, the group
elected to restate prior years to recognize an expense associated with share-based payments that were not fully vested at 1 January 2003, BP’s date of
transition to IFRS, and the liability relating to cash-settled share-based payments at 1 January 2003.

As a result of the transition requirements of SFAS 123(R) and IFRS 2, certain differences between US GAAP and IFRS have arisen. For periods prior

to 1 January 2005, the group has recognized share-based payments under IFRS using a fair value method which is substantially different from the
intrinsic value method used under US GAAP. From 1 January 2005, the group has used the fair value method to measure share-based payment
expense under both IFRS and US GAAP. A difference in expense exists however because the group uses a different valuation model under US GAAP
for issued options outstanding and not yet vested at 31 December 2004 as required under the transition rules of SFAS 123(R).

In addition, deferred taxes on share-based compensation are recognized differently under US GAAP than under IFRS. Under US GAAP, deferred taxes

are recorded on share-based payment expense recognized during the period in accordance with SFAS 109. Under IFRS, deferred taxes are only
recorded on the difference between the tax base of the underlying shares and the carrying value of the employee services as determined at each
balance sheet date in accordance with IAS 12.

BP Annual Report and Accounts 2006

189

$ million

2006

2005

2004

5
9
(106)
92

4
9
(19)
6

(28)
(58)
62
24

2006

2005

254
(254)

334
(334)

53 US GAAP reconciliation continued

The adjustments to proﬁt for the year and to BP shareholders’ equity to accord with US GAAP are summarized below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Increase (decrease) in caption heading

Production and manufacturing expenses
Distribution and administration expenses
Taxation
Proﬁt for the year

Deferred tax liabilities
BP shareholders’ equity

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(o) Discontinued operations
Under IFRS, a component of an entity held for sale as part of a single plan to dispose of a separate major line of business is classiﬁed as a discontinued
operation in the income statement.

Under US GAAP (EITF Issue No. 03-13 ‘Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations’), a disposed component of an enterprise is classiﬁed as a
discontinued operation only where the ongoing entity has no signiﬁcant continuing direct cash ﬂows and does not retain an interest, contract or other
arrangement sufﬁcient to enable the entity to exert signiﬁcant inﬂuence over the disposed component’s operating and ﬁnancial policies after disposal.

In connection with the sale of Innovene the group has a number of commercial arrangements with Innovene for the supply of reﬁning and

petrochemical feedstocks, and the purchase and sale of reﬁned products.

Because of continuing direct cash ﬂows that will result from activities with Innovene subsequent to divestment, under US GAAP the operations of
Innovene would not be classiﬁed as a discontinued operation but would be included in the group’s continuing operations. Under IFRS, the operations of
Innovene are classiﬁed as discontinued operations.

The following summarizes the income statement reclassiﬁcations that would be made if the operations of Innovene were shown in continuing

operations.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

As reported

Reclassiﬁcation

As adjusted

265,906

–

265,906

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

22,601

–

22,601

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

As reported

Reclassiﬁcation

As adjusted

Sales and other operating revenues
Proﬁt before interest and taxation from continuing operations
Finance costs
Other ﬁnance (income) expense
Proﬁt before taxation from continuing operations
Taxation
Proﬁt from continuing operations
Loss from Innovene operations
Proﬁt for the year

Sales and other operating revenues
Proﬁt before interest and taxation from continuing operations
Finance costs
Other ﬁnance (income) expense
Proﬁt before taxation from continuing operations
Taxation
Proﬁt from continuing operations
Proﬁt from Innovene operations
Proﬁt for the year

35,658
718
(202)

35,142
12,516

22,626
(25)

239,792
32,182
616
145
31,421
9,288
22,133
184
22,317

(184)
–
–

(184)
(159)

(25)
25

12,376
141
–
(3)
144
(40)
184
(184)
–

35,474
718
(202)

34,958
12,357

22,601
–

252,168
32,323
616
142
31,565
9,248
22,317
–
22,317

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

190

53 US GAAP reconciliation continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

As reported

Reclassiﬁcation

As adjusted

Sales and other operating revenues
Proﬁt before interest and taxation from continuing operations
Finance costs
Other ﬁnance expense
Proﬁt before taxation from continuing operations
Taxation
Proﬁt from continuing operations
Loss from Innovene operations
Proﬁt for the year

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

192,024
25,746
440
340
24,966
7,082
17,884
(622)
17,262

11,279
(714)
–
17
(731)
(109)
(622)
622
–

203,303
25,032
440
357
24,235
6,973
17,262
–
17,262

(p) Energy trading contracts
The disclosure requirements of EITF 02-03 ‘Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in
Energy Trading and Risk Management Activities’, in respect of energy trading contracts are set out below. For the group, energy trading contracts in oil,
natural gas, NGLs and power comprise exchange-traded derivative instruments such as futures and options and non-exchange-traded instruments such
as swaps, ‘over-the-counter’ options and forward contracts.

The following tables show the net fair value of contracts held for trading purposes at 31 December analysed by maturity period and by methodology

of fair value estimation.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Less than
1 year

1-3 years

4-5 years

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1-3 years

4-5 years

Prices actively quoted
Prices sourced from observable data or market corroboration
Prices based on models and other valuation methods

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

–
654
12
666

Less than
1 year

(179)
660
12
493

–
83
(26)
57

(146)
(89)
1
(234)

The following tables show the changes during the year in the net fair value of instruments held for trading purposes for the years 2006, 2005 and 2004.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fair value of contracts at 1 January 2006
Contracts realized or settled in the year
Unrealized gains (losses) recognized at inception of contract
Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions
Other unrealized gains (losses) recognized during the year
Fair value of contracts at 31 December 2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

18

729

41

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

Over
5 years

–
4
20
24

Over
5 years

(12)
–
46
34

Natural
gas
price

270
(259)
249
–
469

Natural
gas
price

414
(681)
(41)
–
578
270

–
55
(14)
41

(4)
49
77
122

Oil price

(34)
83
36
1
(68)

Oil price

(140)
144
(73)
–
35
(34)

Total

–
796
(8)
788

Total

(341)
620
136
415

Power
price

179
(33)
(69)
–
(36)

Power
price

177
76
1
–
(75)
179

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fair value of contracts at 1 January 2005
Contracts realized or settled in the year
Unrealized gains (losses) recognized at inception of contract
Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions
Other unrealized gains (losses) recognized during the year
Fair value of contracts at 31 December 2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BP Annual Report and Accounts 2006

191

53 US GAAP reconciliation continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fair value of contracts at 1 January 2004
Contracts realized or settled in the year
Unrealized gains (losses) recognized at inception of contract
Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions
Other unrealized gains (losses) recognized during the year
Fair value of contracts at 31 December 2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Oil price

(154)
154
(33)
–
(107)
(140)

Natural
gas
price

191
259
73
–
(109)
414

Power
price

134
54
(3)
–
(8)
177

In addition to the risk management activities related to equity crude disposal, reﬁnery supply and marketing, BP’s supply and trading function

undertakes trading in the full range of conventional derivative ﬁnancial and commodity instruments and physical cargoes available in the energy markets.
The group controls the scale of the trading exposures by using a value-at-risk model with a maximum value-at-risk limit authorized by the board.

The group measures its market risk exposure, i.e. potential gain or loss in fair values, on its trading activity using value-at-risk techniques. These
techniques are based on a variance/covariance model or a Monte Carlo simulation and make a statistical assessment of the market risk arising from
possible future changes in market values over a 24-hour period. The calculation of the range of potential changes in fair value takes into account a
snapshot of the end-of-day exposures and the history of one-day price movements, together with the correlation of these price movements. The
potential movement in fair values is expressed to 1.65 standard deviations which is equivalent to a 95% conﬁdence level. This means that, in broad
terms, one would expect to see an increase or a decrease in fair values greater than the value at risk on approximately one occasion per month if the
portfolio were left unchanged.

The group calculates value at risk on all instruments that are held for trading purposes and therefore give an exposure to market risk. The value-at-risk

models take account of derivative ﬁnancial instruments such as oil, natural gas and power price futures and swap agreements. Financial assets and
liabilities and physical crude oil and reﬁned products that are treated as held for trading positions are also included in these calculations. For options, a
linear approximation is included in the value-at-risk models. The value-at-risk calculation for oil, natural gas, NGLs and power price exposure also includes
derivative commodity instruments (commodity contracts that permit settlement either by delivery of the underlying commodity or in cash), such as
forward contracts.

The following table shows values at risk for energy trading activities.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

High

Low

Average

Year end

2006
Oil price trading
Natural gas and NGL price trading
Power price trading
2005
Oil price trading
Natural gas and NGL price trading
Power price trading
2004
Oil price trading
Natural gas and NGL price trading
Power price trading

56
29
11

80
39
16

30
23
10

16
10
2

17
6
2

10
6
1

29
19
6

33
15
7

16
13
4

22
15
3

31
17
9

25
10
4

Impact of new US accounting standards

Adopted for 2006
Accounting changes and error corrections
In May 2005, the FASB issued SFAS No. 154 ‘Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement
No. 3’. SFAS 154 applies to all voluntary changes in accounting principle and changes the requirements for the accounting for and reporting of a change
in accounting principle. SFAS 154 requires retrospective application to prior period ﬁnancial statements of a voluntary change in accounting principle
unless it is impracticable. Previously, most voluntary changes in accounting principle were recognized by including in net income of the period of the
change the cumulative effect of changing to the new accounting principle. SFAS 154 also requires that a change in the method of depreciation,
amortization or depletion for long-lived non-ﬁnancial assets be accounted for as a change in accounting estimate that is affected by a change in
accounting principle. Previously, such changes were reported as a change in accounting principle. SFAS 154 is effective for accounting changes and
corrections of errors made in accounting periods beginning after 15 December 2005. The group adopted SFAS 154 with effect from 1 January 2006.
The adoption of SFAS 154 did not have a signiﬁcant effect on the group’s proﬁt as adjusted to accord with US GAAP, or on BP shareholders’ equity as
adjusted to accord with US GAAP.

192

53 US GAAP reconciliation continued

Revenue
In September 2005, the FASB ratiﬁed the consensus reached by the EITF regarding Issue No. 04-13 ‘Accounting for Purchases and Sales of Inventory
with the Same Counterparty’. EITF 04-13 addresses accounting issues that arise when a company both sells inventory to and buys inventory from
another entity in the same line of business. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate
contractual arrangements and the inventory purchased or sold may be in the form of raw material, work-in-process or ﬁnished goods. At issue is
whether the revenue, inventory cost and cost of sales should be recorded at fair value or whether the transactions should be classiﬁed as non-monetary
transactions. EITF 04-13 requires purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another be
combined and recorded as exchanges measured at the book value of the item sold. EITF 04-13 is effective for new arrangements entered into and
modiﬁcations or renewals of existing arrangements in accounting periods beginning after 15 March 2006. The group adopted EITF 04-13 with effect
from 1 January 2006. The adoption of EITF 04-13 did not have a signiﬁcant effect on the group’s proﬁt as adjusted to accord with US GAAP, or on BP
shareholders’ equity as adjusted to accord with US GAAP.

Share-based payments
In February 2006, the FASB issued Staff Position No. FAS 123(R)-4 ‘Classiﬁcation of Options and Similar Instruments Issued as Employee Compensation
That Allow for Cash Settlement upon the Occurrence of a Contingent Event’. FSP 123(R)-4 clariﬁes the classiﬁcation of options and similar instruments
issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. Under FSP 123(R)-4, an option or similar
instrument with a contingent cash settlement provision is classiﬁed as an equity award provided that the contingent event that permits or requires cash
settlement is not considered probable of occurring, the contingent event is not within the control of the employee and the award includes no other features
that would require liability classiﬁcation. For entities that adopted SFAS 123(R) prior to the issuance of FSP 123(R)-4, FSP 123(R)-4 is effective for accounting
periods beginning after 3 February 2006. The group adopted FSP 123(R)-4 with effect from 1 January 2006. The adoption of FSP 123(R)-4 did not have a
signiﬁcant effect on the group’s proﬁt as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.

Consolidation of variable interest entities
In April 2006, the FASB issued Staff Position No. FIN 46(R)-6, ‘Determining the Variability to Be Considered in Applying FASB Interpretation No. 46(R)’.
FSP 46(R)-6 clariﬁes how variability should be considered in applying FIN 46(R). Variability is used in applying FIN 46(R) to determine whether an entity is
a variable interest entity, which interests are variable interests in the entity, and who is the primary beneﬁciary of the variable interest entity. Under FSP
46(R)-6, the variability to be considered in applying FIN 46(R)-6 is based on the design of the entity, the nature and risks of the entity and the purpose for
which entity was created. FSP 46(R)-6 is effective for accounting periods beginning after 15 June 2006. The group adopted FSP 46(R)-6 with effect from
1 July 2006. The adoption of FSP 46(R)-6 did not have a signiﬁcant effect on the group’s proﬁt as adjusted to accord with US GAAP, or on BP
shareholders’ equity as adjusted to accord with US GAAP.

Pensions and other post-retirement beneﬁts
In September 2006, the FASB issued SFAS No. 158 ‘Employers’ Accounting for Deﬁned Beneﬁt Pension and Other Post-retirement Plans, an
amendment of FASB Statements No. 87, 88, 106, and 132(R)’. SFAS 158 requires an employer to recognize the overfunded or underfunded status of a
deﬁned beneﬁt post-retirement plan (other than a multi-employer plan) as an asset or liability in the balance sheet and to recognize changes in that
funded status in other comprehensive income in the year in which the changes occur. The group adopted SFAS 158 with effect from 31 December
2006, resulting in a $599 million decrease in BP shareholders’ equity, as adjusted to accord with US GAAP. Of this total effect, $586 million relates to
group entities and $13 million relates to equity-accounted entities. Further information on the effects of adoption of SFAS 158 is provided in note (h)
Pensions and other post-retirement beneﬁts.

Financial statement misstatements
In September 2006, the staff of the SEC issued Staff Accounting Bulletin No. 108, ‘Considering the Effects of Prior Year Misstatements when Quantifying
Misstatements in Current Year Financial Statements’. SAB 108 was issued to address the diversity in practice in quantifying misstatements from prior years
and assessing their effect on current year ﬁnancial statements. SAB 108 is effective for ﬁscal years ending after 15 November 2006. The adoption of SAB 108
did not have a signiﬁcant effect on the group’s proﬁt as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.

Not yet adopted
Financial instruments
In February 2006, the FASB issued SFAS No. 155, ‘Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133
and 140’. SFAS 155 simpliﬁes the accounting for certain hybrid ﬁnancial instruments under SFAS 133 by permitting fair value remeasurement for
ﬁnancial instruments containing an embedded derivative that otherwise would require separation of the derivative from the ﬁnancial instrument. SFAS
155 is effective for all ﬁnancial instruments acquired, issued or subject to a remeasurement event occurring in ﬁscal years beginning after 15 September
2006. The adoption of SFAS 155 is not expected to have a signiﬁcant effect on the group’s proﬁt as adjusted to accord with US GAAP, or on BP
shareholders’ equity as adjusted to accord with US GAAP.

Taxes collected from customers
In June 2006, the FASB ratiﬁed the consensus reached by the EITF regarding Issue No. 06-3 ‘How Taxes Collected from Customers and Remitted to
Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)’. Under EITF 06-3, taxes collected
from customers and remitted to governmental authorities can be presented either gross within revenue and cost of sales, or net. Where such taxes are
signiﬁcant, EITF 06-3 requires disclosure of the accounting policy for presenting taxes and the amount of any such taxes that are recognized on a gross
basis. EITF 06-3 is effective for accounting periods beginning after 15 December 2006. The group has not yet adopted EITF 06-3. The group’s
accounting policy with regard to taxes collected from customers and remitted to governmental authorities is to present such taxes net in the income
statement, and as a result the adoption of EITF 06-3 will not have any impact.

BP Annual Report and Accounts 2006

193

53 US GAAP reconciliation continued

Income taxes
In June 2006, the FASB issued FASB Interpretation No. 48 ‘Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109’.
Interpretation 48 clariﬁes the accounting for uncertainty with regard to income taxes recognized in an entity’s ﬁnancial statements in accordance with
SFAS 109 and prescribes a recognition threshold and measurement attribute for the recognition and measurement of a tax position taken or expected to
be taken in a tax return. Interpretation 48 also provides guidance on derecognition, classiﬁcation, interest and penalties, accounting in interim periods,
disclosure and transition. The group will adopt Interpretation 48 with effect from 1 January 2007. Adoption of Interpretation 48 is not expected to have a
signiﬁcant effect on the group’s proﬁt as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.

Fair value measurements
In September 2006, the FASB issued SFAS No. 157 ‘Fair Value Measurements’. SFAS 157 deﬁnes fair value, establishes a framework for measuring
fair value and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair
value measurements. SFAS 157 is effective for accounting periods beginning after 15 November 2007. The group has not yet completed its evaluation
of the impact of adopting SFAS 157 on the group’s proﬁt as adjusted to accord with US GAAP, or on BP shareholders’ equity as adjusted to accord with
US GAAP.

Fair value option
In February 2007, the FASB issued SFAS No. 159 ‘The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB
Statement No. 115’. SFAS 159 permits an entity, at speciﬁed election dates, to choose to measure certain ﬁnancial instruments and other items at fair
value. The objective of SFAS 159 is to provide entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets
and liabilities differently, without having to apply complex hedge accounting provisions. SFAS 159 is effective for accounting periods beginning after
15 November 2007. The group has not yet completed its evaluation of the impact of adopting SFAS 159 on the group’s proﬁt as adjusted to accord with
US GAAP, or on BP shareholders’ equity as adjusted to accord with US GAAP.

54 Auditors’ remuneration for US reporting

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

31

64

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Acquisition and disposal due diligence
Pension plan audits
Other further assurance services

Tax services

2
–
3

3
–
5

2
–
16

2
1
23

6
–
6

7
1
9

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

5

9

UK

18
7
6

31
–

–
–

5
–

2006

Total

36
9
19

64
–

1
–

9
–

UK

15
3
7
25
(8)
17

5
–
23
–
23

2005

Total

31
6
23
60
(8)
52

10
–
36
(1)
35

UK

13
4
4
21
(2)
19

3
–
15
–
15

2004

Total

27
7
16
50
(2)
48

13
1
31
(1)
30

Audit fees – Ernst & Young
Group audit
Audit-related regulatory reporting
Statutory audit of subsidiaries

Innovene operations
Continuing operations
Fees for other services – Ernst & Young
Further assurance services

Compliance services
Advisory services

Innovene operations
Continuing operations

Audit fees for 2006 include $5 million of additional fees for 2005 (2005 $4 million of additional fees for 2004). Audit fees are included in the income
statement within distribution and administration expenses.

Other further assurance services include $nil (2005 $4 million and 2004 $3 million) in respect of advice on accounting, auditing and ﬁnancial reporting

matters; $nil (2005 $16 million and 2004 $1 million) in respect of internal accounting and risk management control reviews; $5 million (2005 $3 million
and 2004 $3 million) in respect of non-statutory audits and $nil (2005 $nil and 2004 $2 million) in respect of project assurance and advice on business
and accounting process improvement.

The tax compliance services relate to income tax and indirect tax compliance and employee tax 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 to that of other potential service providers. These services are for a ﬁxed term.

Fees paid to major ﬁrms of accountants other than Ernst & Young for other services amount to $52 million (2005 $151 million and 2004 $82 million).

194

55 Summarized ﬁnancial information on jointly controlled entities and associates

A summarized statement of income and assets and liabilities based on latest information available, with respect to the group’s equity-accounted jointly
controlled entities and associates, is set out below. These ﬁgures represent 100% of the income statements and balance sheets of the
equity-accounted entities, not BP’s ownership interest.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

56 Valuation and qualifying accounts

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Additions

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

77,464
17,745
9,113

61,698
14,451
8,043

38,842
9,063
5,466

2006

58,086
24,153

82,239
(17,804)
(23,973)

40,462

$ million

2005

52,401
19,808
72,209
(15,403)
(20,328)
36,478

Sales and other operating revenues
Gross proﬁt
Proﬁt for the year

At 31 December
Non-current assets
Current assets

Current liabilities
Non-current liabilities
Net assets

2006
Fixed assets – Investmentsb
Doubtful debtsb
2005
Fixed assets – Investmentsb
Doubtful debtsb
2004
Fixed assets – Investmentsb
Doubtful debtsb

Balance at
1 January

Charged to
costs and
expenses

Charged to
other

accountsa Deductions

Balance at
31 December

172
374

168
526

209
441

26
158

18
67

12
254

(3)
32

(13)
(30)

4
6

(44)
(143)

(1)
(189)

(57)
(175)

151
421

172
374

168
526

a Principally currency transactions.
b Deducted in the balance sheet from the assets to which they apply.

57 Computation of ratio of earnings to ﬁxed charges

For the year ended 31 December
Proﬁt before taxation
Group’s share of income in excess of dividends from equity-accounted entities
Capitalized interest, net of amortization

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Fixed charges

34,301

Interest expense
Rental expense representative of interest
Capitalized interest

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Total adjusted earnings available for payment of ﬁxed charges
Ratio of earnings to ﬁxed charges
Fixed charges, as adjusted to accord with US GAAP
Total adjusted earnings available for payment of ﬁxed charges, after taking account of adjustments to proﬁt before

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

taxation to accord with US GAAP

Ratio of earnings to ﬁxed charges with adjustments to accord with US GAAP

2006

34,642
–
(341)

718
946
478

2,142

36,443

17.0

2,142

34,856

16.3

$ million, except ratios

2005

2004

31,921
(710)
(193)
31,018

559
605
351
1,515
32,533
21.5
1,525

30,550
20.0

24,966
(81)
(133)
24,752

440
619
204
1,263
26,015
20.6
1,263

23,905
18.9

BP Annual Report and Accounts 2006

195

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

Supplementary information on oil and natural gas

Movements in estimated net proved reserves
For details of BP’s governance process for the booking of oil and natural gas reserves, see page 17.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Subsidiaries
At 1 January 2006

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

Crude oila

Developed
Undeveloped

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Changes attributable to

680

311

3,413

501

165

678

–

612

6,360

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December 2006c

(76)

(25)

(205)

(134)

(12)

27

–

(42)

(467)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

367

153

705

–

570

5,893

Equity-accounted entities (BP share)
At 1 January 2006

604

286

458
146

189
97

Developed
Undeveloped

Developed
Undeveloped

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Changes attributable to

–

–

–

331

1

–

2,119

754

3,205

UK

496
184

(3)
–
3
26
(92)
(10)

–
–

–
–
–
–
–
–

–
–

225
86

1,984
1,429

215
286

(11)
–
–
9
(23)
–

–
–

–
–
–
–
–
–

–
–

(108)
–
48
95
(178)
(62)

1,916
1,292
3,208e

–

–
–
–
–
–
–

–
–

(9)
–
–
13
(39)
(99)

130
237

207
124

(2)
28
1
34
(28)
(4)

221
139

70
95

–
–
1
4
(17)
–

67
86

1
–

–
–
–
–
–
–

1
–

142
536

2
–
67
22
(64)
–

193
512

–
–

–
–
–
–
–
–

–
–

2006

million barrels

69
543

3,201
3,159

16
–
–
–
(58)
–

(113)
–
119
169
(471)
(171)

88
482

3,041
2,852

–
–

–
–
–
–
–
–

–
–

1,688
431

590
164

2,486
719

1,215
–
–
–
(320)
(170)

(8)
–
–
–
(63)
–

1,205
28
1
34
(411)
(174)

2,200
644

520
163

2,942
946

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December 2006d

–

–

–

29

–

–

725

(71)

683

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

–

–

–

360

1

–

2,844

683

3,888

a Crude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash
or in kind.
b Excludes NGLs from processing plants in which an interest is held of 55 thousand barrels a day.
c Includes 779 million barrels of NGLs. Also includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 28 million barrels of NGLs. Also includes 179 million barrels of crude oil in respect of the 6.29% minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 81 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.

196

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Production
Sales of reserves-in-place

Developed
Undeveloped

Supplementary information on oil and natural gas continued

Movements in estimated net proved reserves
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Natural gasa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

billion cubic feet

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Subsidiaries
At 1 January 2006

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

Developed
Undeveloped

2,382
904

245
80

11,184
4,198

3,560
10,504

1,459
5,375

934
2,000

281
1,342

20,045
24,403

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Changes attributable to

3,286

325

15,382

14,064

6,834

2,934

–

1,623

44,448

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

(343)
–
101
144
(370)
(25)

11
–
–
–
(38)
–

(922)
–
116
1,755
(941)
(292)

(291)
–
–
344
(982)
(9)

(92)
–
21
71
(273)
–

(69)
–
5
6
(169)
–

33
–
2
9
(82)
–

(1,673)
–
245
2,329
(2,855)
(326)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December 2006c

(493)

(27)

(284)

(938)

(273)

(227)

–

(38)

(2,280)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Equity-accounted entities (BP share)
At 1 January 2006

2,793

298

15,098

13,126

6,561

2,707

–

1,585

42,168

1,968
825

242
56

10,438
4,660

3,932
9,194

1,359
5,202

1,032
1,675

331
1,254

19,302
22,866

–
–

–
–
–
–
–
–

–
–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Changes attributable to

–

–

–

2,340

76

–

1,258

182

3,856

–
–

–
–
–
–
–
–

–
–

–
–

–
–
–
–
–
–

–
–

–
–

–
–
–
–
–
–

–
–

1,492
848

7
–
23
73
(171)
(77)

1,460
735

50
26

13
–
–
1
(15)
–

52
23

–
–

–
–
–
–
–
–

–
–

1,089
169

130
52

2,761
1,095

217
–
–
–
(204)
–

47
–
–
–
(7)
–

284
–
23
74
(397)
(77)

1,087
184

170
52

2,769
994

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December 2006d

–

–

–

(145)

(1)

–

13

40

(93)

Developed
Undeveloped

Developed
Undeveloped

Developed
Undeveloped

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.
b Includes 178 billion cubic feet of natural gas consumed in operations, 147 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities and excludes
8.3 billion cubic feet of produced non-hydrocarbon components which meet regulatory requirements for sales.
c Includes 3,537 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 99 billion cubic feet of natural gas in respect of the 7.77% minority interest in TNK-BP.

–

–

–

2,195

75

–

1,271

222

3,763

BP Annual Report and Accounts 2006

197

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Supplementary information on oil and natural gas continued

Movements in estimated net proved reserves
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Crude oila

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

million barrels

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Subsidiaries
At 1 January 2005

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

At 31 December 2005c

Developed
Undeveloped

Equity-accounted entities (BP share)
At 1 January 2005

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Production
Sales of reserves-in-place

At 31 December 2005d

Developed
Undeveloped

UK

559
210
769

(31)
–
11
32
(101)
–
(89)

496
184
680

–
–
–

–
–
–
–
–
–
–

–
–
–

231
109
340

(8)
–
–
21
(27)
(15)
(29)

225
86
311

–
–
–

–
–
–
–
–
–
–

–
–
–

2,041
1,211
3,252

103
2
40
217
(200)
(1)
161

1,984
1,429
3,413e

–
–
–

–
–
–
–
–
–
–

–
–
–

311
299
610

(21)
–
3
1
(53)
(39)
(109)

215
286
501

204
125
329

1
–
2
25
(26)
–
2

207
124
331

65
85
150

21
–
11
–
(17)
–
15

70
95
165

1
–
1

–
–
–
–
–
–
–

1
–
1

204
643
847

(190)
–
83
2
(64)
–
(169)

142
536
678

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

1,863
294
2,157

319
–
–
–
(333)
(24)
(38)

1,688
431
2,119

62
725
787

(148)
–
–
7
(34)
–
(175)

69
543
612

592
100
692

119
–
–
–
(57)
–
62

590
164
754

3,473
3,282
6,755

(274)
2
148
280
(496)
(55)
(395)

3,201
3,159
6,360

2,660
519
3,179

439
–
2
25
(416)
(24)
26

2,486
719
3,205

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Crude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash
or in kind.
b Excludes NGLs from processing plants in which an interest is held of 58 thousand barrels a day.
c Includes 818 million barrels of NGLs. Also includes 29 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 33 million barrels of NGLs. Also includes 95 million barrels of crude oil in respect of the 4.47% minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 85 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.

198

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Supplementary information on oil and natural gas continued

Movements in estimated net proved reserves
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Natural gasa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

billion cubic feet

2005

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Subsidiaries
At 1 January 2005

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

10,811
3,270
14,081

4,101
10,663
14,764

1,624
5,419
7,043

1,015
1,886
2,901

282
1,396
1,678

20,579
25,071
45,650

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

245
80
325

11,184
4,198
15,382

3,560
10,504
14,064

1,459
5,375
6,834

934
2,000
2,934

281
1,342
1,623

20,045
24,403
44,448

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

At 31 December 2005c

Developed
Undeveloped

Equity-accounted entities (BP Share)
At 1 January 2005

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

At 31 December 2005d

Developed
Undeveloped

2,498
1,183
3,681

(102)
–
21
111
(425)
–
(395)

2,382
904
3,286

–
–
–

–
–
–
–
–
–
–

–
–
–

248
1,254
1,502

11
–
19
19
(44)
(1,182)
(1,177)

–
–
–

–
–
–
–
–
–
–

–
–
–

447
66
47
1,773
(1,018)
(14)
1,301

104
2
225
87
(888)
(230)
(700)

–
–
–

–
–
–
–
–
–
–

–
–
–

1,397
977
2,374

26
–
28
66
(154)
–
(34)

1,492
848
2,340

(133)
–
204
–
(280)
–
(209)

107
69
176

(81)
–
–
–
(19)
–
(100)

50
26
76

152
–
44
–
(163)
–
33

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

214
10
224

1,337
–
–
–
(184)
(119)
1,034

1,089
169
1,258

15
–
–
10
(80)
–
(55)

60
23
83

102
–
–
–
(3)
–
99

130
52
182

494
68
560
2,000
(2,898)
(1,426)
(1,202)

1,778
1,079
2,857

1,384
–
28
66
(360)
(119)
999

2,761
1,095
3,856

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.
b Includes 174 billion cubic feet of natural gas consumed in operations, 147 billion cubic feet in subsidiaries and 27 billion cubic feet in equity-accounted entities.
c Includes 3,812 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 57 billion cubic feet of natural gas in respect of the 4.47% minority interest in TNK-BP.

BP Annual Report and Accounts 2006

199

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Supplementary information on oil and natural gas continued

Movements in estimated net proved reserves
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Crude oila

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

million barrels

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Subsidiaries
At 1 January 2004

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

At 31 December 2004c

Developed
Undeveloped

Equity-accounted entities (BP share)
At 1 January 2004

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Production
Sales of reserves-in-place

At 31 December 2004d

Developed
Undeveloped

UK

697
245
942

(133)
–
24
57
(121)
–
(173)

559
210
769

–
–
–

–
–
–
–
–
–
–

–
–
–

236
127
363

1
–
–
4
(28)
–
(23)

231
109
340

–
–
–

–
–
–
–
–
–
–

–
–
–

1,902
1,499
3,401

(44)
–
74
55
(217)
(17)
(149)

2,041
1,211
3,252e

–
–
–

–
–
–
–
–
–
–

–
–
–

385
354
739

(92)
–
5
31
(63)
(10)
(129)

311
299
610

206
134
340

(5)
–
2
17
(25)
–
(11)

204
125
329

82
81
163

2
–
8
–
(17)
(6)
(13)

65
85
150

1
–
1

–
–
–
–
–
–
–

1
–
1

190
632
822

19
–
48
6
(48)
–
25

204
643
847

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

1,384
410
1,794

382
252
–
37
(304)
(4)
363

1,863
294
2,157

73
711
784

(192)
–
213
3
(21)
–
3

62
725
787

705
27
732

15
–
–
–
(55)
–
(40)

592
100
692

3,565
3,649
7,214

(439)
–
372
156
(515)
(33)
(459)

3,473
3,282
6,755

2,296
571
2,867

392
252
2
54
(384)
(4)
312

2,660
519
3,179

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Crude oil includes natural gas liquids (NGLs) and condensate. Net proved reserves of crude oil exclude production royalties due to others, whether royalty is payable in cash
or in kind.
b Excludes NGLs from processing plants in which an interest is held of 58 thousand barrels a day.
c Includes 724 million barrels of NGLs. Also includes 40 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 27 million barrels of NGLs. Also includes 127 million barrels of crude oil in respect of the 5.9% minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 77 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.

200

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Supplementary information on oil and natural gas continued

Movements in estimated net proved reserves
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Natural gasa

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

billion cubic feet

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Subsidiaries
At 1 January 2004

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Productionb
Sales of reserves-in-place

At 31 December 2004c

Developed
Undeveloped

Equity-accounted entities (BP share)
At 1 January 2004

Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Purchases of reserves-in-place
Extensions, discoveries and other additions
Improved recovery
Production
Sales of reserves-in-place

At 31 December 2004d

Developed
Undeveloped

2,996
1,095
4,091

262
1,255
1,517

11,482
3,337
14,819

4,212
11,531
15,743

(210)
–
127
134
(461)
–
(410)

28
–
–
4
(47)
–
(15)

(438)
3
140
870
(1,111)
(202)
(738)

(1,081)
2
991
76
(875)
(92)
(979)

2,498
1,183
3,681

248
1,254
1,502

10,811
3,270
14,081

4,101
10,663
14,764

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

1,591
916
2,507

(12)
–
–
23
(144)
–
(133)

1,397
977
2,374

1,976
3,026
5,002

106
–
2,478
–
(296)
(247)
2,041

1,624
5,419
7,043

136
80
216

(17)
–
–
–
(23)
–
(40)

107
69
176

640
2,188
2,828

16
–
233
29
(102)
(103)
73

1,015
1,886
2,901

–
–
–

–
–
–
–
–
–
–

–
–
–

–
–
–

–
–
–
–
–
–
–

–
–
–

46
14
60

341
–
–
–
(177)
–
164

214
10
224

255
900
1,155

21,823
23,332
45,155

558
–
3
38
(76)
–
523

(1,021)
5
3,972
1,151
(2,968)
(644)
495

282
1,396
1,678

20,579
25,071
45,650

58
28
86

–
–
–
–
(3)
–
(3)

60
23
83

1,831
1,038
2,869

312
–
–
23
(347)
–
(12)

1,778
1,079
2,857

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a Net proved reserves of natural gas exclude production royalties due to others, whether royalty is payable in cash or in kind.
b Includes 190 billion cubic feet of natural gas consumed in operations, 165 billion cubic feet in subsidiaries and 25 billion cubic feet in equity-accounted entities.
c Includes 4,064 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 13 billion cubic feet of natural gas in respect of the 5.9% minority interest in TNK-BP.

BP Annual Report and Accounts 2006

201

Supplementary information on oil and natural gas continued

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 measures 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 the requirements of FASB Statement of
Financial Accounting Standards No. 69 – ‘Disclosures about Oil and Gas Producing Activities’.

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 year-end crude oil and natural gas prices and exchange rates.
Furthermore, both 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 assumptions on which it is based
and its lack of comparability with the historical cost information presented in the ﬁnancial statements.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

net cash ﬂowse

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

7,800

1,600

40,300

7,900

7,600

13,400

12,000

90,600

At 31 December 2006
Future cash inﬂowsa
Future production costb
Future development costb
Future taxationc
Future net cash ﬂows
10% annual discountd
Standardized measure of discounted future

At 31 December 2005
Future cash inﬂowsa
Future production costb
Future development costb
Future taxationc
Future net cash ﬂows
10% annual discountd
Standardized measure of discounted future

At 31 December 2004
Future cash inﬂowsa
Future production costb
Future development costb
Future taxationc
Future net cash ﬂows
10% annual discountd
Standardized measure of discounted future

45,300
20,700
3,300
10,300

11,000
3,200

68,200
21,700
2,200
17,600

26,700
8,500

47,400
19,200
2,200
9,900

16,100
4,700

18,200
4,700
1,500
9,400

2,600
1,000

18,600
3,900
1,000
10,200

3,500
1,400

21,700
4,500
1,900
11,200

4,100
2,000

218,900
71,300
18,600
43,100

85,900
45,600

261,800
55,800
16,300
65,300

124,400
63,700

169,500
37,800
10,800
41,800

79,100
38,100

46,800
14,900
4,900
12,900

14,100
6,200

75,600
15,200
4,300
28,800

27,300
12,600

52,600
14,300
4,400
16,300

17,600
8,000

36,800
9,400
3,800
7,000

16,600
9,000

34,600
6,900
3,500
7,300

16,900
9,600

27,200
6,700
3,500
5,200

11,800
6,900

47,700
8,700
6,600
10,600

21,800
8,400

46,300
7,800
6,100
10,600

21,800
8,700

35,000
5,800
4,700
6,900

17,600
7,500

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

36,200
7,200
3,900
5,800

19,300
7,300

38,200
7,400
4,600
6,000

20,200
8,100

34,200
6,900
5,100
5,000

17,200
7,800

449,900
136,900
42,600
99,100

171,300
80,700

543,300
118,700
38,000
145,800

240,800
112,600

387,600
95,200
32,600
96,300

163,500
75,000

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

net cash ﬂowse

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

18,200

2,100

60,700

14,700

7,300

13,100

12,100

128,200

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

net cash ﬂowse

11,400

2,100

41,000

9,600

4,900

10,100

–

9,400

88,500

The following are the principal sources of change in the standardized measure of discounted future net cash ﬂows:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Sales and transfers of oil and gas produced, net of production costs
Development costs incurred during the year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production costf
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 year

2006

2005

2004

(35,800)
8,200
7,900
(43,900)
(9,500)
32,200
(7,000)
(2,500)
12,800

(37,600)

(24,300)
7,100
10,100
84,200
(17,400)
(20,500)
(5,800)
(2,500)
8,800
39,700

(24,100)
6,300
3,100
27,600
(10,700)
1,900
(3,200)
(1,000)
8,100
8,000

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a The year end marker prices used were Brent $58.93/bbl, Henry Hub $5.52/mmBtu (2005 Brent $58.21/bbl, Henry Hub $9.52/mmBtu; 2004 Brent $40.24/bbl, Henry Hub
$6.01/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 $1,300 million at 31 December 2006 ($2,700 million at 31 December 2005 and $1,600 million at 31 December
2004).
f Net changes in prices and production costs includes the effect of exchange rate movements.

202

Supplementary information on oil and natural gas continued

Equity-accounted entities
In addition, at 31 December 2006 the group’s share of the standardized measure of discounted future net cash ﬂows of equity-accounted entities
amounted to $14,700 million ($19,300 million at 31 December 2005 and $10,900 million at 31 December 2004).

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 2006, 2005 and 2004.

Production for the yeara

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Subsidiaries
Crude oilb
2006
2005
2004
Natural gasc
2006
2005
2004
Equity-accounted entities (BP share)
Crude oilb
2006
2005
2004
Natural gasc
2006
2005
2004

253
277
330

61
75
77

547
612
666

108
144
173

44
47
48

177
175
130

–
–
–

161
93
56

1,351
1,423
1,480

936
1,090
1,174

91
108
125

2,376
2,546
2,749

2,645
2,384
2,334

727
751
775

430
422
267

–
–
–

207
211
200

7,412
7,512
7,624

–
–
–

–
–
–

–
–
–

77
71
68

1
–
2

–
–
–

876
911
831

170
157
150

1,124
1,139
1,051

–
–
–

–
–
–

–
–
–

416
375
353

37
47
60

–
–
–

544
482
458

8
8
8

1,005
912
879

thousand barrels per day

million cubic feet per day

thousand barrels per day

million cubic feet per day

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

a All volumes are net of royalty, whether payable in cash or in kind.
b Crude oil includes natural gas liquids and condensate.
c Natural 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 of 31 December 2006. 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

Number of productive wells at 31 December 2006
Oil wellsa

Gas wellsb

– gross
– net
– gross
– net

270
145
300
140

87
27
38
14

8,226
2,402
17,601
11,318

3,379
1,839
2,256
1,377

351
151
648
238

603
524
83
40

18,967
8,090
42
20

1,491
198
124
52

33,374
13,376
21,092
13,199

a Includes approximately 976 gross (281.8 net) multiple completion wells (more than one formation producing into the same well bore).
b Includes approximately 2,283 gross (1,524.6 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

Oil and natural gas acreage at 31 December 2006
Developed

– gross
– net

Undevelopeda – gross

– net

a Undeveloped acreage includes leases and concessions.

433
203
2,100
1,154

138
44
1,053
339

7,392
4,725
6,809
4,797

3,161
1,470
12,436
5,861

1,072
262
7,765
2,939

477
211
16,215
9,764

3,991
1,728
13,778
5,694

1,865
419
18,684
7,677

18,529
9,062
78,840
38,225

BP Annual Report and Accounts 2006

203

Supplementary information on oil and natural gas continued

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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

0.1
–

4.9
–

0.5
0.3

10.6
–

–
–

10.0
0.1

0.1
–

1.6
–

0.8
–

3.5
0.3

–
–

0.3
–

2.9
7.4

418.8
4.5

10.7
6.4

473.9
5.0

0.5
1.0

154.0
5.0

2.0
1.0

151.7
3.3

2.1
3.2

1.3
1.5

513.3
3.0

138.2
1.8

1.0
1.5

12.4
0.2

0.3
0.3

22.7
0.4

–
–

8.6
–

3.2
0.5

23.8
–

2.0
1.3

17.9
1.0

6.6
2.0

12.9
2.0

15.6
5.7

227.2
20.8

14.5
5.2

212.8
17.7

11.0
5.2

166.8
8.7

1.4
0.3

14.5
1.0

–
–

12.1
0.3

1.3
1.1

16.0
2.4

24.8
16.4

857.2
31.5

30.8
14.5

905.2
28.0

22.3
13.0

866.1
18.0

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 of 31 December 2006. Suspended development wells and long-term suspended exploratory wells are also included in the
table.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

UK

Rest of
Europe

USA

Rest of
Americas

Asia
Paciﬁc

Africa

Russia

Other

Total

1
0.5

3
1.1

–
–

2
0.6

22
10.8

194
110.6

6
2.8

43
25.2

2
0.3

7
1.8

4
1.6

19
6.7

6
2.2

30
12.5

2
0.5

20
5.3

43
18.7

318
163.8

At 31 December 2006
Exploratory
Gross
Net

2006
Exploratory
Productive
Dry

Development
Productive
Dry
2005
Exploratory
Productive
Dry

Development
Productive
Dry
2004
Exploratory
Productive
Dry

Development
Productive
Dry

Development

Gross
Net

204

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:

– To select suitable accounting policies and then apply them consistently.
– To make judgements and estimates that are reasonable and prudent.
– To state whether applicable accounting standards have been followed, subject to any material departures disclosed and explained in the ﬁnancial

statements.

– To prepare the ﬁnancial statements on the going concern basis unless it is inappropriate to presume that the group will continue in business.

The directors are also responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the ﬁnancial position of
the company and enable them to ensure that the ﬁnancial statements comply with the Companies Act 1985. 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 234ZA of the

Companies Act 1985) 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.

BP Annual Report and Accounts 2006

205

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 2006 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. These parent
company ﬁnancial statements have been prepared under the accounting policies set out therein. We have also audited the information in the Directors’
Remuneration Report that is described as having been audited.

We have reported separately on the consolidated ﬁnancial statements of BP p.l.c. for the year ended 31 December 2006.
This report is made solely to the company’s members, as a body, in accordance with Section 235 of the Companies Act 1985. Our audit work has
been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditors’ report and for no
other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company’s
members as a body, for our audit work, for this report, or for the opinions we have formed.

Respective responsibilities of directors and auditors
The directors’ responsibilities for preparing the Annual Report, the Directors’ Remuneration Report and the parent company ﬁnancial statements in
accordance with applicable United Kingdom law and accounting standards (United Kingdom generally accepted accounting practice) are set out in the
Statement of Directors’ Responsibilities.

Our responsibility is to audit the parent company ﬁnancial statements and the part of the Directors’ Remuneration Report to be audited in accordance

with relevant legal and regulatory requirements and International Standards on Auditing (UK and Ireland).

We report to you our opinion as to whether the parent company ﬁnancial statements give a true and fair view and whether the parent company
ﬁnancial statements and the part of the Directors’ Remuneration Report to be audited have been properly prepared in accordance with the Companies
Act 1985. We also report to you whether in our opinion the information given in the parent company directors’ report is consistent with the ﬁnancial
statements.

In addition we report to you if, in our opinion, the company has not kept proper accounting records, if we have not received all the information and

explanations we require for our audit, or if information speciﬁed by law regarding directors’ remuneration and other transactions is not disclosed.
We read other information contained in the Annual Report and consider whether it is consistent with the audited parent company ﬁnancial

statements. The other information comprises the Directors’ report and the unaudited part of the Directors’ Remuneration Report. We consider the
implications for our report if we become aware of any apparent misstatements or material inconsistencies with the parent company ﬁnancial
statements. Our responsibilities do not extend to any other information.

Basis of audit opinion
We conducted our audit in accordance with International Standards on Auditing (UK and Ireland) issued by the Auditing Practices Board. An audit
includes examination, on a test basis, of evidence relevant to the amounts and disclosures in the parent company ﬁnancial statements and the part of
the Directors’ Remuneration Report to be audited. It also includes an assessment of the signiﬁcant estimates and judgements made by the directors in
the preparation of the parent company ﬁnancial statements, and of whether the accounting policies are appropriate to the company’s circumstances,
consistently applied and adequately disclosed.

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

Opinion
In our opinion:
– The parent company ﬁnancial statements give a true and fair view, in accordance with United Kingdom generally accepted accounting practice, of the

state of the company’s affairs as at 31 December 2006.

– The parent company ﬁnancial statements and the part of the Directors’ Remuneration Report to be audited have been properly prepared in

accordance with the Companies Act 1985.

– The information given in the directors’ report is consistent with the parent company ﬁnancial statements.

Ernst & Young LLP
Registered auditor
London
23 February 2007

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 occured to the ﬁnancial statements
since they were initially presented on the website or any other website they are presented on.

Legislation in the United Kingdom governing the preparation and dissemination of ﬁnancial statements may differ from legislation in other

jurisdictions.

206

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---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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 liabilities
Total assets less current liabilities
Creditors – amounts falling due after more than one year
Net assets excluding pension plan surplus
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
Other reserves
Shares held by ESOP trusts
Treasury shares
Share-based payment reserve
Proﬁt and loss account

$ million
(As restated)

Note

2006

2005

88,963
2

88,965

89,758
2
89,760

3
3

4
4
2

5

5

6
6

7
8
8
8
8
8
8
8
8

3,074
1,196
165
–

4,435
5,216

(781)

88,184
57

88,127
4,067
(76)

92,118

5,385
9,074
839
26,504
5
(154)
(22,182)
789
71,858

92,118

1,215
1,453
436
3
3,107
6,724
(3,617)
86,143
65
86,078
2,258
–
88,336

5,185
7,371
749
26,493
16
(140)
(10,598)
599
58,661
88,336

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The ﬁnancial statements on pages 207-220 were approved by a duly appointed and authorized committee of the board of directors on 23 February 2007
and were signed on its behalf by:

Peter Sutherland Chairman
The Lord Browne of Madingley Group Chief Executive

BP Annual Report and Accounts 2006

207

For the year ended 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Note

9

2006

2005

2004

(3,703)

(1,108)

23,913

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Company cash ﬂow statement

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 inﬂow (outﬂow) for capital expenditure and ﬁnancial investment
Equity dividends paid
Net cash inﬂow before ﬁnancing
Financing

Issue of ordinary share capital for TNK–BP
Other share-based payment movements
Repurchase of ordinary share capital

Net cash outﬂow from ﬁnancing
Increase (decrease) in cash

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Company statement of total recognized gains and losses

For the year ended 31 December
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Proﬁt for the year
Actuarial gain relating to pensions
Tax on actuarial gain relating to pensions
Total recognized gains and losses relating to the year

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

1,137
(104)
18,489
19,522
(3)

(31,517)
85
(31,432)
(6,041)
5,959

1,250
340
(7,548)
(5,958)
1

177
(702)
24,859

24,334

(3)

(1,397)
2,240

843

(7,686)

13,785

1,250
422
(15,481)

(13,809)

110
(249)
21,087
20,948
(8)

(2,929)
519
(2,410)
(7,359)
10,063

1,250
283
(11,597)
(10,064)
(1)

9

(24)

2006

2005

2004

24,186
1,120
(336)
24,970

20,858
1,159
(348)
21,669

18,613
197
(59)
18,751

3

8

6
2

208

Notes on ﬁnancial statements

1 Accounting policies

Accounting standards
These accounts are prepared in accordance with applicable UK accounting standards. In preparing the ﬁnancial statements for the current year, the
company has adopted the amendments to Financial Reporting Standard No. 26 ‘Financial Instruments: Measurement’ (FRS 26). This has resulted in a
change of accounting policy for ﬁnancial guarantee contracts given by the company in respect of its subsidiaries, associates and jointly controlled
entities. These contracts are recorded at fair value in the company’s ﬁnancial statements. This change in accounting policy has resulted in a restatement
of 2005 comparative information: investments in subsidiaries were increased by $20 million; amounts due from group undertakings were increased by
$23 million; other creditors were increased by $43 million. The effect on the company’s proﬁt for the year was not material.

Accounting convention
The accounts are prepared under the historical cost convention.

Foreign currency transactions
Foreign currency transactions are booked in the functional currency at the exchange rate ruling on the date of transaction. Foreign currency monetary
assets and liabilities are translated into the functional currency at rates of exchange ruling at the balance sheet date. Exchange differences are included
in proﬁt for the year.

Investments
Investments in subsidiaries and associated undertakings are held 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 they are granted and is
recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award. Fair
value is determined by using an appropriate valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other
than conditions linked to the price of the shares of the company (market conditions).

No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which are

treated as vesting irrespective of whether or not the market condition is satisﬁed, provided that all other performance conditions are satisﬁed.

At each balance sheet date before vesting, the cumulative expense is calculated, representing the extent to which the vesting period has expired and
management’s best estimate of the achievement or otherwise of non-market conditions and number of equity instruments that will ultimately vest or, in
the case of an instrument subject to a market condition, be treated as vesting as described above. The movement in cumulative expense since the
previous balance sheet date is recognized in the income statement, with a corresponding entry in equity.

Where the terms of an equity-settled award are modiﬁed or a new award is designated as replacing a cancelled or settled award, the cost based on

the original award terms continues to be recognized over the original vesting period. In addition, an expense is recognized over the remainder of the
new vesting period for the incremental fair value of any modiﬁcation, based on the difference between the fair value of the original award and the fair
value of the modiﬁed award, both as measured on the date of the modiﬁcation. No reduction is recognized if this difference is negative.

Where an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any cost not yet recognized in the income

statement for the award is expensed immediately. Any compensation paid up to the fair value of the award at the cancellation or settlement date is
deducted from equity, with any excess over fair value being treated as an expense in the income statement.

Cash-settled transactions
The cost of cash-settled transactions is measured at fair value using an appropriate option valuation model.
Fair value is established initially at the grant date and at each balance sheet date thereafter until the awards are settled. During the vesting period a
liability is recognized representing the product of the fair value of the award and the portion of the vesting period expired as at the balance sheet date.
From the end of the vesting period until settlement, the liability represents the full fair value of the award as at the balance sheet date. Changes in the
carrying amount for the liability are recognized in proﬁt or loss for the period.

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

The service cost of providing pension and other post-retirement beneﬁts to employees for the year is charged to the income statement. The cost of
making improvements to pension and other post-retirement beneﬁts is recognized in the income statement immediately when the company becomes
committed to the change.

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 recognized in the income statement during the period in which the settlement or curtailment occurs.

A charge representing the unwinding of the discount on the plan liabilities during the year is included within other ﬁnance income.
A credit representing the expected return on the plan assets during the year is included within other ﬁnance income. This credit 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.

BP Annual Report and Accounts 2006

209

1 Accounting policies continued

Actuarial gains and losses may result from: differences between the expected return and the actual return on plan assets; differences between the
actuarial assumption underlying the plan liabilities and actual experience during the year; or changes in the actuarial assumptions used in the valuation of
the plan liabilities. Actuarial gains and losses, and taxation thereon, are recognized in the statement of total recognized gains and losses.

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 statement of total recognized gains and losses
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Deferred tax

2004

2006

2005

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Origination and reversal of temporary differences in the current year

Tax included in statement of total recognized gains and losses

This comprises:

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Actuarial gain relating to pensions and other post-retirement beneﬁts
Tax included in statement of changes in equity

Deferred tax
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Balance sheet

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

Deferred tax liability

Pensions

Deferred tax asset

Other taxable temporary differences

Net deferred tax liability

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

336

336

2006

336

336

1,671

1,671

165

165

1,506

532
(18)
656
336

1,506

348
348

2005

348
348

968
968

436
436
532

265
(87)
6
348
532

59
59

$ million

2004

59
59

628
628

362
362
266

213
40
(47)
59
265

Analysis of movements during the year

At 1 January
Exchange adjustments
Charge for the year on ordinary activities
Charge for the year in the statement of total recognized gains and losses

At 31 December

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

210

Cost

At 1 January 2006
Additions
Deletions

At 31 December 2006
Amounts provided

At 1 January 2006
Provided in Year

At 31 December 2006
Cost

At 1 January 2005
Additions
Deletions

At 31 December 2005 (As restated)
Amounts provided

At 1 January 2005
At 31 December 2005
Net book amount

Subsidiary undertakings
International

BP Global Investments
BP International
BP Shipping
Burmah Castrol

South Africa

BP Southern Africa

US

BP America

4 Debtors

Group undertakings
Other

3 Fixed assets – investments

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Subsidiary
undertakings

Associated
undertakings
- - -- - - - -- - - - -- - - - -- - - - - -- - - - -- - - - - - -- - - - -- - - - -- - - - -- - - - - -- - - - -- - - -
Loans

Shares

Shares

89,775
1,397
(2,135)
89,037

17
57
74

17
17

87,345
2,949
(519)
89,775

2
–
–
2

–
–
–

2
–
–
2

–
–

Total

89,779
1,397
(2,135)
89,041

19
57
76

19
19

87,349
2,949
(519)
89,779

2
–
–
2

2
–
2

2
–
–
2

2
2

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

At 31 December 2006
At 31 December 2005 (As restated)

88,963
89,758

2
2

–
–

88,965
89,760

The more important subsidiary undertakings of the company at 31 December 2006 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The carrying amounts of debtors approximate their fair value.

5 Creditors

Overdraft
Group undertakings
Social security
Accruals and deferred income
Dividends
Other

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

%

Country of
incorporation

Principal activities

100
100
100
100

England
England
England
Scotland

Investment holding
Integrated oil operations
Shipping
Lubricants

75

South Africa

Reﬁning and marketing

100

US

Investment holding

Within
1 year
2,890
184
3,074

Within
1 year
21
5,025
5
10
1
154
5,216

2006

After
1 year
1,157
39
1,196

2006

After
1 year
–
–
–
30
–
27
57

$ million
(As restated)

2005

After
1 year
1,415
38
1,453

Within
1 year
1,088
127
1,215

$ million
(As restated)

2005

After
1 year
–
–
–
27
–
38
65

Within
1 year
–
6,513
15
8
1
187
6,724

BP Annual Report and Accounts 2006

211

$ million
(As restated)

2006

2005

7
35
15

57

14
37
14
65

%

2004

2006

2005

7.0
5.1
4.7
2.8
2.8
2.8

7.00
4.75
4.25
2.50
2.50
2.50

7.00
5.25
4.00
2.50
2.50
2.50

Years

2004

2006

2005

23.9
26.8
25.0
27.8

23.0
26.0
23.9
26.9

23.0
26.0
23.9
26.9

5 Creditors continued

The carrying amounts of creditors approximate their fair value.

The proﬁle of the maturity 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Due within

1 to 2 years
2 to 5 years
More than 5 years

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

6 Pensions

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 2006 are
used to determine the pension liabilities at that date and the pension cost for 2007.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

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

In addition to the ﬁnancial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumption reﬂects best
practice in the UK, and has been chosen with regard to the latest available published tables adjusted 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 female currently aged 60
Life expectancy at age 60 for a male currently aged 40
Life expectancy at age 60 for a female currently aged 40

The market values of the various categories of asset held by the pension plan at 31 December are set out below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Expected
long-term
rate of
return
%

7.5
4.7
6.5
3.8

7.0

Expected
long-term
rate of
return
%

7.50
4.50
6.50
4.00
7.00

Expected
long-term
rate of
return
%

7.50
4.25
6.50
3.50
7.00

Market
value
$ million

22,256
3,305
1,274
334

27,169
21,507

5,662
(1,671)

3,991

Market
value
$ million

17,330
2,231
1,085
896
21,542
18,316
3,226
(968)
2,258

Market
value
$ million

16,263
2,396
1,645
402
20,706
18,613
2,093
(628)
1,465

UK plans
Equities
Bonds
Property
Cash

Present value of plan liabilities
Surplus in the plan
Deferred tax
At 31 December

212

6 Pensions continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Analysis of the amount charged to operating proﬁt
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Current service cost
Past service cost
Settlement, curtailment and special termination beneﬁts
Total operating charge

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

341
5
36
382

360
4
36
400

411
(74)
–

337

2006

2005

2004

Analysis of the amount credited (charged) to other ﬁnance income
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Expected return on pension plan assets
Interest on pension plan liabilities
Other ﬁnance income

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

1,257
(899)
358

1,357
(914)
443

1,593
(918)

675

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 gain (loss) recognized in statement of total recognized gains and losses

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2,946
(1,721)
(66)
1,159

750
(710)
157
197

1,252
79
(211)

1,120

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Movements in beneﬁt obligation during the year
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Beneﬁt obligation at 1 January
Exchange adjustment
Current service cost
Past service cost
Interest cost
Curtailment
Settlement
Special termination beneﬁts
Contributions by plan participants
Beneﬁt payments (funded plans)
Disposals
Actuarial (gain) loss on obligation
Beneﬁt obligation at 31 December

18,613
(2,008)
360
4
914
–
–
36
35
(847)
(578)
1,787
18,316

18,316
2,524
411
(74)
918
(20)
(22)
42
37
(900)
143
132

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

21,507

2006

2005

Movements in fair value of plan assets during the year
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Fair value of plan assets at 1 January
Exchange adjustment
Expected return on plan assets
Contributions by plan participants
Contributions by employers (funded plans)
Beneﬁt payments (funded plans)
Disposals
Actuarial gain (loss) on plan assets
Fair value of plan assets at 31 December

20,706
(2,291)
1,357
35
214
(847)
(578)
2,946
21,542

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

21,542
3,082
1,593
37
420
(900)
143
1,252

27,169

Surplus (deﬁcit) at 31 December
Represented by

5,662

3,226

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The surplus (deﬁcit) may be analysed between funded and unfunded plans as follows

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The deﬁned beneﬁt obligation may be analysed between funded and unfunded plans as follows

Asset recognized
Liability recognized

Funded
Unfunded

Funded
Unfunded

5,771
(109)

5,662

5,771
(109)

5,662

21,616
(109)

3,226
–
3,226

3,226
–
3,226

18,316
–
18,316

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

The aggregate level of employer contributions in 2007 is expected to be approximately $500 million.

21,507

BP Annual Report and Accounts 2006

213

6 Pensions continued

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
History of surplus (deﬁcit) and of experience gains and losses
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
Beneﬁt obligation at 31 December
Fair value of plan assets at 31 December
Surplus (deﬁcit)

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

16,288
17,850
1,562

18,613
20,706
2,093

18,316
21,542
3,226

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

21,507
27,169

5,662

2003

2004

2006

2005

$ million

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 gain (loss) recognized in statement of total recognized gains and losses

Amount ($ million)
Percentage of beneﬁt obligation

Cumulative amount recognized in statement of total recognized gains and losses

7 Called up share capital

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

(211)

(1)%

(66)

0%

157

1%

621

4%

1,252

2,946

750

1,526

5%

14%

4%

9%

1,120

1,159

6%

6%

197

1%

3,317

2,197

1,038

841

5%

841

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Issued
8% cumulative ﬁrst preference shares of £1 each
9% cumulative second preference shares of £1 each

Ordinary shares of 25 cents each

1 January
Issue of new shares for employee share schemes
Issue of ordinary share capital for TNK-BP
Repurchase of ordinary share capital
Othera

31 December

Shares
(thousand)

7,233
5,473

20,657,045
64,854
111,151
(358,374)
982,625

21,457,301

2006

$ million

12
9

21

Shares
(thousand)

7,233
5,473

5,164 21,525,978
82,144
108,629
(1,059,706)
–
5,364 20,657,045

16
28
(90)
246

5,385

2005

$ million

12
9
21

5,382
20
27
(265)
–
5,164
5,185

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Authorized
8% cumulative ﬁrst preference shares of £1 each
9% cumulative second preference shares of £1 each
Ordinary shares of 25 cents each

a Reclassification in respect of share repurchases in 2005.

7,250
5,500
36,000,000

12
9

7,250
5,500
9,000 36,000,000

12
9
9,000

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.

Repurchase of ordinary share capital
The company purchased 1,334,362,750 ordinary shares (2005 1,059,706,481 and 2004 827,240,360 ordinary shares) for a total consideration of
$15,481 million (2005 $11,597 million and 2004 $7,548 million), of which 358,374,000 were for cancellation and 975,988,750 were retained in treasury.
At 31 December 2006, 1,946,804,533 shares of nominal value $487 million were held in treasury (2005 982,624,971 shares of nominal value
$246 million). Transaction costs of share repurchases amounted to $83 million (2005 $63 million and 2004 $43 million).

214

8 Capital and reserves

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

Share
capital

Share
premium
account

Capital
redemption
reserve

Merger
reserve

Other
reserves

Own
shares

Treasury
shares

Share-based
payment
reserve

Proﬁt
and loss
account

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
749
–
–
–
90
–
–
–
–
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
839

At 1 January 2006
Currency translation differences
Actuarial gain on pensions (net of tax)
Issue of ordinary share capital for TNK-BP
Repurchase of ordinary share capital
Share-based payments (net of tax)
Proﬁt for the year
Dividends
Othera
At 31 December 2006

88,336
(19)
785
1,250
(15,481)
747
24,186
(7,686)
–
92,118

(10,598)
–
–
–
(11,472)
134
–
–
(246)

58,661
–
785
–
(4,009)
(79)
24,186
(7,686)
–

26,493
–
–
–
–
11
–
–
–

5,185
–
–
28
(90)
16
–
–
246

7,371
–
–
1,222
–
481
–
–
–

(140)
(19)
–
–
–
5
–
–
–

16
–
–
–
–
(11)
–
–
–

599
–
–
–
–
190
–
–
–

(22,182)

71,858

26,504

5,385

9,074

(154)

789

5

a Reclassification in respect of share repurchases in 2005.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

Share
capital

Share
premium
account

Capital
redemption
reserve

Merger
reserve

Other
reserves

Own
shares

Treasury
shares

Share-based
payment
reserve

Proﬁt
and loss
account

Total

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
730
–
–
–
19
–
–
–
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
749

At 1 January 2005
Currency translation differences
Actuarial gain on pensions (net of tax)
Issue of ordinary share capital for TNK-BP
Repurchase of ordinary share capital
Share-based payments
Proﬁt for the year
Dividends
At 31 December 2005

83,657
12
811
1,250
(11,597)
704
20,858
(7,359)
88,336

–
–
–
–
(10,601)
3
–
–
(10,598)

45,062
–
811
–
(750)
39
20,858
(7,359)
58,661

26,465
–
–
–
–
28
–
–
26,493

5,403
–
–
27
(265)
20
–
–
5,185

5,636
–
–
1,223
–
512
–
–
7,371

(82)
12
–
–
–
(70)
–
–
(140)

44
–
–
–
–
(28)
–
–
16

399
–
–
–
–
200
–
–
599

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 $26,668 million (2005 $27,391 million and 2004 $25,026 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 2006 do not reﬂect

the dividend announced on 6 February 2007 and payable in March 2007; this will be treated as an appropriation of proﬁt in the year ended
31 December 2007.

9 Cash ﬂow

Reconciliation of net cash ﬂow to movement in net debt
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

$ million

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Notes on cash ﬂow statement
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
(a) Reconciliation of operating proﬁt to net cash (outﬂow) inﬂow from operating activities
Operating proﬁt
Depreciation and amounts provided
Net operating charge for pensions and other post-retirement beneﬁts, less contributions
Dividends, interest and other income
Share-based payments
(Increase) decrease in debtors
Increase (decrease) in creditors
Net cash (outﬂow) inﬂow from operating activities

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

20,674
–
186
(21,197)
278
(368)
(681)
(1,108)

18,313
12
168
(19,626)
224
22,374
2,448
23,913

24,768
–
(83)
(25,036)
325
(2,140)
(1,537)

(3,703)

$ million

2005

2004

2006

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

(b) Analysis of net debt

Cash at bank
Bank overdrafts

At
1 January
2006

3
–
3

$ million

At 31
December
2006

–
(21)
(21)

Cash
ﬂow

(3)
(21)
(24)

BP Annual Report and Accounts 2006

215

2006

(24)

(24)
3

(21)

2005

2004

(1)

(1)
4
3

1

1
3
4

Increase (decrease) in cash

Movement in net debt
Net debt at 1 January
Net debt at 31 December

10 Contingent liabilities

The parent company has issued guarantees under which amounts outstanding at 31 December 2006 were $20,458 million (2005 $16,878 million and
2004 $21,106 million), including $20,402 million (2005 $16,822 million and 2004 $21,050 million) in respect of borrowings by its subsidiary undertakings
and $56 million (2005 $56 million and 2004 $56 million) in respect of liabilities of other third parties.

11 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 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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

289
36
325
59
53

348
20
368
48
41

405
14

38
23

419

2004

2006

2005

$ million

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 (2005 onwards)
An equity-settled incentive share plan for executive directors driven by one performance measure over a three-year performance period. The award of
shares is determined by comparing BP’s total shareholder return (TSR) against the other oil majors. In addition, for the group chief executive, 27% of
the grant is based on long-term leadership (LTL) measures. After the performance period, the shares which vest (net of tax) are then subject to a
three-year retention period. The directors’ remuneration report on pages 68-75 includes full details of this plan.

Executive Directors’ Incentive Plan (EDIP) – share element (pre-2005)
An equity-settled incentive share plan for executive directors driven by three performance measures over a three-year performance period. The primary
measure is BP’s shareholder return against the market (SHRAM) versus that of the companies within the FTSE All World Oil & Gas Index. This accounts
for nearly two-thirds of the potential total award, with the remainder being assessed on BP’s relative return on average capital employed (ROACE) and
earnings per share (EPS) growth compared with the other oil majors. 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 68-75 includes full details of this plan. For 2005 and subsequent years, the
share element of EDIP was amended as described above.

Executive Directors’ Incentive Plan (EDIP) – share option element (pre-2005)
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. Options vest over three years (one-third each after one, two and three years respectively) and must be
exercised within seven years of the date of grant. 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
Medium Term Performance Plan (MTPP) (2005 onwards)
An equity-settled incentive share plan for senior employees driven by two performance measures over a three-year performance period. The award of
shares is determined by comparing BP’s TSR against the other oil majors and, additionally, by comparing free cash ﬂow (FCF) against a threshold
established for the period. For a small group of particularly senior employees, only the TSR measure is applicable in determining the award. The number
of shares awarded is increased to take account of the net dividends that would have been received during the performance period, assuming that such
dividends had been reinvested. With regard to leaver provisions, the general rule is that leaving employment during the performance period will preclude
an award of shares. However, special arrangements apply where the participant leaves for a qualifying reason and employment ceases after completion
of the ﬁrst year of the performance period.

Long Term Performance Plan (LTPP) (pre-2005)
An equity-settled incentive share plan for senior employees driven by three performance measures over a three-year performance period. The primary
measure is BP’s SHRAM versus that of the companies within the FTSE All World Oil & Gas Index. This accounts for nearly two-thirds of the potential
total award, with the remainder being assessed on BP’s relative ROACE and EPS growth compared with the other oil majors. Shares are awarded at the
end of the performance period and are then subject to a three-year restriction period. With regard to leaver provisions, the general rule is that leaving
during the performance period will preclude an award of shares. However, special arrangements apply where the participant leaves for a qualifying
reason and employment ceases after completion of the ﬁrst year of the performance period. This plan was replaced by the MTPP for 2005 onwards.

Deferred Annual Bonus Plan (DAB)
An equity-settled restricted share plan for senior employees. The award value is equal to 50% of the annual cash bonus awarded for the preceding
performance year (the ‘performance period’). The shares are restricted for a period of three years (the ‘restriction period’). Shares accrue dividends
during the restriction period and these are reinvested. With regard to leaver provisions, if a participant ceases to be employed by BP prior to the end of
the performance period, then the general rule is that this will preclude an award of shares. However, special arrangements apply where the participant
leaves for a qualifying reason. Similarly, if a participant ceases to be employed by BP prior to the end of the restriction period, the general rule is that the
restricted shares will be forfeited. Special arrangements apply where the participant leaves for a qualifying reason.

216

11 Share-based payments continued

Performance Share Plan (PSP)
An equity-settled restricted share plan for senior professionals and team leaders. The award takes into account the recipient’s performance in the prior
calendar year (the ‘performance period’). Shares, provided initially as share units, are restricted for a period of three years (‘the restriction period’).
Share units accrue notional dividends during the restriction period and these are reinvested. At the end of the restriction period additional units may be
awarded based on BP’s TSR performance against the other oil majors. At award, share units are converted into shares. With regard to leaver provisions,
the general rule is that leaving during the performance period will preclude an award of share units. If a participant ceases to be employed by BP prior
to the end of the restriction period, the general rule is that share units will lapse. Special arrangements apply where the participant leaves for a
qualifying reason.

Restricted Share Plan (RSP)
An equity-settled restricted share plan used predominantly for senior employees in special circumstances (such as recruitment and retention). There are
no performance conditions but the shares are subject to a three-year restriction period. During the restriction period, shares accrue dividends, which are
reinvested. With regard to leaver provisions, the general rule is that ceasing employment during the restriction period will result in the forfeit of shares.
However, special arrangements apply where the participant leaves for a qualifying reason.

BP Share Option Plan (BPSOP)
An equity-settled share option plan that applies to certain categories of employees. Participants are granted share options with an exercise price no
lower than market price of a share immediately preceding the date of grant. There are no performance conditions and the options are exercisable
between the third and 10th anniversaries of the grant date. The general rule is that the options will lapse if the participant leaves employment before the
end of the third calendar year from the date of grant (and that vested options are exercisable within 31/2 years from the date of leaving). However, special
arrangements apply where the participant leaves for a qualifying reason and employment ceases after the end of the calendar year of the date of grant.
From 2007, share options no longer form a regular element of our incentive plans.

Savings and matching plans
BP ShareSave Plan
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. Until 2003, a three-year savings plan was also run in a small number of other countries. Options will remain outstanding in respect of
these countries until the end of June 2007. 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
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
over 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.

The above share plans are indicated as being equity-settled. However in certain countries it is not possible to award shares to employees owing to local
legislation. In these instances the award will be settled in cash, calculated as the cash equivalent of the value to the employee of an equity-settled plan.

Cash plans
Cash Options / Stock Appreciation Rights (SARs)
These are cash-settled share-based payments available to certain employees that require the group to pay the intrinsic value of the cash option/SAR to
the employee at the date of exercise. There are no performance conditions, however participants must continue in employment with BP for the ﬁrst
three calendar years of the plan for the options/SARs to vest. Special arrangements may apply for qualifying leavers. The options/SARs are exercisable
between the third and 10th anniversaries of the grant date.

BP Annual Report and Accounts 2006

217

11 Share-based payments continued

Employee Share Ownership Plans (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards made to participants under EDIP, MTPP, LTPP, DAB and the BP ShareMatch
Plans. The ESOPs have waived their rights to dividends on shares held for future awards and are funded by the group. 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 Note 8, Capital and reserves. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.

At 31 December 2006, the ESOPs held 12,795,887 shares (2005 14,560,003 shares and 2004 8,621,219 shares) for potential future awards, which

had a market value of $142 million (2005 $156 million and 2004 $84 million).

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Share option transactions

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

Weighted
average
exercise price
$

7.64
11.18
8.69
6.52
7.99

8.25

Number
of
options

450,453,502
53,977,639
(7,169,710)
(70,658,480)
(131,489)

426,471,462

236,726,966

699,535,945

7.41

Number
of
options

470,263,808
54,482,053
(4,844,827)
(68,687,976)
(759,556)
450,453,502
222,729,398
955,924,506

2005

Weighted
average
exercise price
$

7.16
10.24
8.30
6.40
6.75
7.64
7.54

Number
of
options

461,885,881
80,394,760
(7,043,911)
(62,625,182)
(2,347,740)
470,263,808
224,627,758
966,076,636

2004

Weighted
average
exercise price
$

6.76
7.93
6.77
5.18
7.55
7.16
7.00

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

As share options are exercised continuously throughout the year, the weighted average share price during the year of $11.85 (2005 $10.77 and 2004
$8.95) is representative of the weighted average share price at the date of exercise. For the options outstanding at 31 December 2006, the exercise
price ranges and weighted average remaining contractual lives are shown below.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Options outstanding

Options exercisable

Outstanding at beginning of the year
Granted during the year
Forfeited during the year
Exercised during the year
Expired during the year
Outstanding at end of the year
Exercisable at the end of the year
Available for grant at 31 December

Range of exercise prices
$5.10 – $6.79
$6.80 – $8.50
$8.51 – $10.21
$10.22 – $11.92

Number
of
shares

100,854,491
196,009,067
55,376,829
74,231,075

Weighted
average
remaining life
years

Weighted
average
exercise price
$

Number
of
shares

Weighted
average
exercise price
$

3.92
4.93
5.79
8.81

6.02
8.01
9.30
11.14

87,474,704
122,344,799
26,907,463
–

6.06
8.08
8.76
–

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

426,471,462

5.48

8.25

236,726,966

7.41

218

11 Share-based payments continued

Fair values and associated details for options and shares granted
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

Options granted in 2006
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

Options granted in 2005
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

Options granted in 2004
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

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

BPSOP

ShareSave
3 year

ShareSave
5 year

Binomial
$2.46
$11.07
$11.17

Binomial
$2.88
$11.08
$9.10

Binomial
$3.08
$11.08
$9.10

22%

24%

24%

10 years

3.5 years

5.5 years

3.23%
4.50%

3.40%
5.00%

3.40%
4.75%

5% years 4-9,
70% year 10

100% year 4

100% year 6

BPSOP

ShareSave
3 year

ShareSave
5 year

Binomial
$2.34
$10.85
$10.63

Binomial
$2.76
$10.49
$7.96

Binomial
$2.94
$10.49
$7.96

18%

18%

18%

10 years

3.5 years

5.5 years

2.72%
4.25%

3.00%
4.00%

3.00%
4.25%

5% years 4-9,
70% year 10

100% year 4

100% year 6

EDIP
Options

BPSOP

ShareSave
3 year

ShareSave
5 year

Binomial
$1.34
$8.09
$8.09

22%

7 years

3.75%
3.50%

Binomial
$1.55
$8.12
$8.09

Binomial
$1.94
$8.75
$7.00

Binomial
$2.13
$8.75
$7.00

22%

22%

22%

10 years

3.5 years

5.5 years

3.75%
4.00%

3.75%
3.00%

3.75%
3.75%

5% years 2-6,
75% year 7

5% years 4-9,
70% year 10

100% year 4

100% year 6

The group uses a third party estimate of expected volatility of US ADSs for the quarter within which the grant date of the relevant plan falls. This
estimate takes into account the volatility implied by options in the market.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

MTPP -
TSR
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
8.7
$7.28
Monte Carlo

Shares granted in 2006
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

0.5
$11.07
Market value

0.5
$11.23
Market value

7.8
$11.23
Market value

3.3
$4.87
Monte Carlo

MTPP -
FCF

EDIP -
LTL

EDIP -
TSR

RSP

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

MTPP -
TSR
---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
9.3
$5.72
Monte Carlo

Shares granted in 2005
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

0.3
$11.04
Market value

0.5
$10.13
Market value

8.4
$11.04
Market value

3.7
$3.87
Monte Carlo

MTPP -
FCF

EDIP -
LTL

EDIP -
TSR

RSP

The group used a Monte Carlo simulation to fair value the TSR element of the 2006 and 2005 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.

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
LTPP -
SHRAM

Shares granted in 2004
Number of equity instruments granted (million)
Weighted average fair value
Fair value measurement basis

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------
6.8
$4.06
Monte Carlo

4.1
$7.21
Market value

0.5
$7.21
Market value

0.1
$8.12
Market value

0.9
$4.06
Monte Carlo

LTPP -
EPS/ROACE

EDIP -
EPS/ROACE

EDIP -
SHRAM

RSP

BP Annual Report and Accounts 2006

219

11 Share-based payments continued

The group used a Monte Carlo simulation to fair value the SHRAM element of the 2004 LTPP and EDIP plan. In accordance with the rules of the plan,
the model simulates BP’s SHRAM and compares it with the comparator companies (all companies in the FTSE All World Oil & Gas Index) over the
three-year period of the plan. The SHRAMs of the comparator companies have been determined from market data over the preceding three-year period.
The model takes into account the historic dividend yields, 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 SHRAM 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.

12 Auditors’ remuneration

Fees payable to the company’s auditors for the audit of the company’s accounts were $15 million (2005 $19 million and 2004 $13 million).

Remuneration receivable by the company’s auditors for the supply of other services to the company is not presented in the parent company accounts

as this information is provided in the group accounts.

13 Directors’ remuneration

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

---------------------------------- ------------------------------------------------------------------ -------------------------------------------------- ----------------------------- ------------------------------------------------------------------ -------------------------------------------------------

2006

2005

2004

$ million

Remuneration of directors

Total for all directors

Emoluments
Gains made on the exercise of share options
Amounts awarded under incentive schemes

14
12
14

18
–
8

19
3
6

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

Pension contributions
Five executive directors participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which contributions are
made by BP based on actuarial advice. One US executive director participated in the US BP Retirement Accumulation Plan during 2006.

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 68-75.

220

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BP Annual Report and Accounts 2006

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BP Annual Report and Accounts 2006

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224

Further information

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, please 
contact the Registrar or ADS Depositary.
  To elect to receive your company documents (such as the 
Annual Report and Accounts, Annual Review and Notice of Meeting) 
electronically, please register at www.bp.com/edelivery.

Publications
Publications

UK – Registrar’s Office 
The BP Registrar, Lloyds TSB Registrars
The Causeway, Worthing, West Sussex BN99 6DA
Telephone: +44 (0)121 415 7005; Freephone in UK: 0800 701107
Textphone: 0870 600 3950; Fax: +44 (0)1903 833371

US – ADS Administration
JPMorgan Chase Bank
PO Box 3408, South Hackensack, NJ 07606-3408
Telephone: +1 201 680 6630
Toll-free in US and Canada: +1 877 638 5672

11

222

333

444

These and other BP publications may be obtained, free of charge, from the following sources:

US and Canada
US and Canada
BP Shareholder Services
Toll-free: +1 800 638 5672
Fax: +1 630 821 3456
shareholderus@bp.com

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

www.bp.com/annualreview
11 www.bp.com/annualreview
BP Annual Review 2006 summarizes our 
financial and operating performance.

22 www.bp.com/financialandoperating 
 www.bp.com/financialandoperating 
BP Financial and Operating Information 
2002-2006 includes five-year financial 
and operating data.

 www.bp.com/sustainabilityreport
33 www.bp.com/sustainabilityreport
BP Sustainability Report 2006, published 
in May 2007, gives details of our 
environmental and social commitments 
and performance. 

44 www.bp.com/statisticalreview
 www.bp.com/statisticalreview
BP Statistical Review of World Energy, 
published in June each year, reports on 
key global energy trends. 

Acknowledgements
Design  VSA Partners, Chicago
Typesetting  St Ives Financial, UK
Printing  St Ives Financial, UK
Paper  This Annual Report and Accounts is printed on ReGen paper, 
which is manufactured from 100% de-inked post-consumer waste 
at a mill with IS0 14001 certification.

© BP p.l.c. 2007

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