Annual Report
and Form 20-F
2011
bp.com/annualreport
Building a
stronger, safer BP
Cover image
Photograph of Deepsea
Stavanger drilling rig, Angola
taken as part of the We are
BP programme.
(Mark One)
☐
☑
☐
☐
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g)
OF THE SECURITIES EXCHANGE ACT OF 1934
OR
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended 31 December 2011
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-6262
BP p.l.c.
(Exact name of Registrant as specified in its charter)
England and Wales
(Jurisdiction of incorporation or organization)
1 St James’s Square, London SW1Y 4PD
United Kingdom
(Address of principal executive offices)
Dr Brian Gilvary
BP p.l.c.
1 St James’s Square, London SW1Y 4PD
United Kingdom
Tel +44 (0) 20 7496 5311
Fax +44 (0) 20 7496 4573
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act
Title of each class
Ordinary Shares of 25c each
Floating Rate Guaranteed Notes due June 2013
Floating Rate Guaranteed Notes due December 2013
Floating Rate Guaranteed Notes due 2014
3.125% Guaranteed Notes due 2012
5.25% Guaranteed Notes due 2013
3.625% Guaranteed Notes due 2014
1.7% Guaranteed Notes due 2014
3.875% Guaranteed Notes due 2015
3.125% Guaranteed Notes due 2015
2.248% Guaranteed Notes due 2016
3.2% Guaranteed Notes due 2016
4.75% Guaranteed Notes due 2019
4.5% Guaranteed Notes due 2020
4.742% Guaranteed Notes due 2021
3.561% Guaranteed Notes due 2021
Name of each exchange on which registered
New York Stock Exchange*
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
*Not for trading, but only in connection with the registration of American Depositary
Shares, pursuant to the requirements of the Securities and Exchange Commission
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
Ordinary Shares of 25c each
Cumulative First Preference Shares of £1 each
Cumulative Second Preference Shares of £1 each
18,975,902,659
7,232,838
5,473,414
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☑
No ☐
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.
Yes ☐
No ☑
Note — Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their
obligations under those Sections.
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant
was required to submit and post such files).*
Yes ☑
No ☐
Yes ☐
No ☐
*This requirement does not apply to the registrant in respect of this filing.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘‘accelerated filer and large
accelerated filer’’ in Rule 12b-2 of the Exchange Act. (Check one):
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
Large accelerated filer ☑
Accelerated filer ☐
Non-accelerated filer ☐
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow.
U.S. GAAP ☐
International Financial Reporting
Standards as issued by the
International Accounting Standards Board ☑
Other ☐
Item 17 ☐
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes ☐
Item 18 ☐
No ☑
Cross reference to Form 20-F
Item 1.
Item 2.
Item 3.
Item 4.
Item 4A.
Item 5.
Identity of Directors, Senior Management and Advisors
Offer Statistics and Expected Timetable
A.
B.
C.
D.
Key Information
Selected financial data
Capitalization and indebtedness
Reasons for the offer and use of proceeds
Risk factors
Information on the Company
History and development of the company
A.
B.
Business overview
C. Organizational structure
D.
Property, plants and equipment
Unresolved Staff Comments
Operating and Financial Review and Prospects
Liquidity and capital resources
Research and development, patent and licenses
Trend information
A. Operating results
B.
C.
D.
E. Off-balance sheet arrangements
F.
G.
Tabular disclosure of contractual commitments
Safe harbor
Directors, Senior Management and Employees
Directors and senior management
Compensation
Board practices
Employees
Share ownership
Item 6.
A.
B.
C.
D.
E.
Item 7.
Major Shareholders and Related Party Transactions
Page
n/a
n/a
56
n/a
n/a
59-63
5, 25-36
18-51, 64-111
251-252
49, 81-83, 89-93, 157, 280-281
None
56-58, 79, 81-82, 95-96, 101, 154-157
103-106
74-76, 208
106
104
104-105
5
114-117
140-151, 246-249
120-133, 246-249
73-74
117, 140-150, 157-158, 246-247
A. Major shareholders
B.
C.
Related party transactions
Interests of experts and counsel
Financial Information
Consolidated statements and other financial information
Significant changes
The Offer and Listing
Item 8.
Item 9.
A.
B.
A. Offer and listing details
B.
Plan of distribution
C. Markets
D.
E.
F.
Selling shareholders
Dilution
Expenses of the issue
Additional Information
Share capital
A.
B. Memorandum and articles of association
C. Material contracts
Exchange controls
D.
Taxation
E.
Dividends and paying agents
F.
Statements by experts
G.
Documents on display
H.
Subsidiary information
I.
Quantitative and Qualitative Disclosures about Market Risk
Description of securities other than equity securities
A.
Debt Securities
B. Warrants and Rights
C. Other Securities
D.
American Depositary Shares
Defaults, Dividend Arrearages and Delinquencies
Material Modifications to the Rights of Security Holders and Use of Proceeds
Controls and Procedures
Audit Committee Financial Expert
Code of Ethics
Principal Accountant Fees and Services
Exemptions from the Listing Standards for Audit Committees
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Change in Registrant’s Certifying Accountant
Corporate governance
Financial Statements
Financial Statements
Exhibits
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16A.
Item 16B.
Item 16C.
Item 16D.
Item 16E.
Item 16F.
Item 16G.
Item 17.
Item 18.
Item 19.
2 BP Annual Report and Form 20-F 2011
158-159
171, 215-216
n/a
159-166, 176-258
None
167-168
n/a
167-168
n/a
n/a
n/a
n/a
136-138
168
168
168-170
n/a
n/a
170
n/a
217-222, 224-228
n/a
n/a
n/a
171
None
None
135
126
134
136
n/a
170
None
134
n/a
176-258, 259-281
172
Contents
7
Business review: Group overview
8 Chairman’s letter
12 Board of directors
14 Group chief executive’s letter
18 Our market
25 Our organization
37 Our strategy
42 Our management of risk
47 Our performance
55 Business review: BP in more depth
56 Financial review
59 Risk factors
65 Safety
69 Environmental and social responsibility
73 Employees
74 Technology
76 Gulf of Mexico oil spill
80 Exploration and Production
94 Refining and Marketing
101 Other businesses and corporate
103 Liquidity and capital resources
106 Regulation of the group’s business
110 Certain definitions
113 Directors and senior management
114 Directors and senior management
117 Directors’ interests
119 Corporate governance
120 Board performance report
134 Corporate governance practices
134 Code of ethics
135 Controls and procedures
136 Principal accountants’ fees and services
136 Memorandum and Articles of Association
139 Directors’ remuneration report
140 Remuneration overview
142 Executive directors’ remuneration
151 Non-executive directors’ remuneration
153 Additional information for
shareholders
154 Critical accounting policies
157 Property, plant and equipment
157 Share ownership
158 Major shareholders
159 Called-up share capital
159 Dividends
160 Legal proceedings
167 Relationships with suppliers and contractors
167 Share prices and listings
168 Material contracts
168 Exchange controls
168 Taxation
170 Documents on display
170 Purchases of equity securities by the issuer
and affiliated purchasers
171 Fees and charges payable by a holder of ADSs
171 Fees and payments made by the Depositary
to the issuer
171 Related-party transactions
172 Administration
172 Annual general meeting
172 Exhibits
173 Financial statements
174 Statement of directors’ responsibilities
175 Consolidated financial statements of the BP group
182 Notes on financial statements
259 Supplementary information on oil and natural
gas (unaudited)
PC1 Parent company financial statements of BP p.l.c.
BP Annual Report and Form 20-F 2011 3
Miscellaneous terms
In this document, unless the context
otherwise requires, the following terms
shall have the meaning set out below.
ADR
American depositary receipt.
ADS
American depositary share.
AGM
Annual general meeting.
Amoco
The former Amoco Corporation and its
subsidiaries.
Atlantic Richfield
Atlantic Richfield Company and its
subsidiaries.
Associate
An entity, including an unincorporated
entity such as a partnership, over which
the group has significant influence and
that is neither a subsidiary nor a joint
venture. Significant influence is the
power to participate in the financial and
operating policy decisions of an entity
but is not control or joint control over
those policies.
Barrel (bbl)
159 litres, 42 US gallons.
b/d
barrels per day.
boe
barrels of oil equivalent.
BP, BP group or the group
BP p.l.c. and its subsidiaries.
Burmah Castrol
Burmah Castrol PLC and its subsidiaries.
Cent or c
One-hundredth of the US dollar.
The company
BP p.l.c.
Dollar or $
The US dollar.
EU
European Union.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
GCRO
Gulf Coast Restoration Organization.
Hydrocarbons
Crude oil and natural gas.
IFRS
International Financial Reporting
Standards.
Joint control
Joint control is the contractually agreed
sharing of control over an economic
activity, and exists only when the
strategic financial and operating
decisions relating to the activity require
the unanimous consent of the parties
sharing control (the venturers).
Joint venture
A contractual arrangement whereby two
or more parties undertake an economic
activity that is subject to joint control.
Jointly controlled asset
A joint venture where the venturers
jointly control, and often have a direct
ownership interest in the assets of the
venture. The assets are used to obtain
benefits for the venturers. Each venturer
may take a share of the output from the
assets and each bears an agreed share
of the expenses incurred.
Jointly controlled entity
A joint venture that involves the
establishment of a corporation,
partnership or other entity in which each
venturer has an interest. A contractual
arrangement between the venturers
establishes joint control over the
economic activity of the entity.
Liquids
Crude oil, condensate and natural gas
liquids.
LNG
Liquefied natural gas.
London Stock Exchange or LSE
London Stock Exchange plc.
LPG
Liquefied petroleum gas.
MDL 2179
Multi-District Litigation proceedings
pending in New Orleans.
MDL 2185
Multi-District Litigation proceedings
pending in Houston.
mb/d
thousand barrels per day.
mboe/d
thousand barrels of oil equivalent per
day.
mmBtu
million British thermal units.
mmboe
million barrels of oil equivalent.
mmcf
million cubic feet.
mmcf/d
million cubic feet per day.
MW
Megawatt.
NGLs
Natural gas liquids.
OECD
Organization for Economic Co-operation
and Development.
OPEC
Organization of Petroleum Exporting
Countries.
Ordinary shares
Ordinary fully paid shares in BP p.l.c. of
25c each.
Pence or p
One-hundredth of a pound sterling.
Pound, sterling or £
The pound sterling.
Preference shares
Cumulative First Preference Shares and
Cumulative Second Preference Shares in
BP p.l.c. of £1 each.
PSA
A production-sharing agreement (PSA) is
an arrangement through which an oil
company bears the risks and costs of
exploration, development and
production. In return, if exploration is
successful, the oil company receives
entitlement to variable physical volumes
of hydrocarbons, representing recovery
of the costs incurred and a stipulated
share of the production remaining after
such cost recovery.
SEC
The United States Securities and
Exchange Commission.
Subsidiary
An entity that is controlled by the BP
group. Control is the power to govern
the financial and operating policies of an
entity so as to obtain the benefits from
its activities.
Tonne
2,204.6 pounds.
Trust
Deepwater Horizon Oil Spill Trust.
UK
United Kingdom of Great Britain and
Northern Ireland.
US
United States of America.
4 BP Annual Report and Form 20-F 2011
Information about this report
This document constitutes the Annual Report and Accounts in accordance
with UK requirements and the Annual Report on Form 20-F in accordance
with the US Securities Exchange Act of 1934, for BP p.l.c. for the year ended
31 December 2011. A cross reference to Form 20-F requirements is on
page 2.
This document contains the Directors’ Report, including the
Business Review and Management Report, on pages 7-138 and 153-172,
and 174. The Directors’ Remuneration Report is on pages 139-151. The
consolidated financial statements of the group are on pages 173-281 and
the corresponding reports of the auditor are on pages 175-177. The parent
company financial statements of BP p.l.c. and corresponding auditor’s report
are on pages PC1-PC14 and page PC1 respectively.
The statement of directors’ responsibilities, the independent
auditor’s report on the annual report and accounts to the members of
BP p.l.c. and the parent company financial statements of BP p.l.c. and
corresponding auditor’s report do not form part of BP’s Annual Report on
Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2011 and BP Summary Review
2011 may be downloaded from bp.com/annualreport. No material on the BP
website, other than the items identified as BP Annual Report and Form 20-F
2011 or BP Summary Review 2011, forms any part of those documents.
BP p.l.c. is the parent company of the BP group of companies.
Unless otherwise stated, the text does not distinguish between the activities
and operations of the parent company and those of its subsidiaries.
The term ‘shareholder’ in this report means, unless the context
otherwise requires, investors in the equity capital of BP p.l.c., both direct
and indirect. As BP shares, in the form of ADSs, are listed on the New York
Stock Exchange (NYSE), an Annual Report on Form 20-F is filed with the US
Securities and Exchange Commission (SEC).
Cautionary statement
In order to utilize the ‘Safe Harbor’ provisions of the United States Private
Securities Litigation Reform Act of 1995 (the “PSLRA”), BP is providing the
following cautionary statement. This document contains certain forward
looking statements within the meaning of the PSLRA with respect to the
financial condition, results of operations and businesses of BP and certain
of the plans and objectives of BP with respect to these items. These
statements may generally, but not always, be identified by the use of words
such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’,
‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar
expressions. In particular, among other statements, (i) certain statements in
the Chairman’s letter (pages 8-11), the Group chief executive’s letter (pages
14-17) and the Business review (pages 18-111), including but not limited
to statements under the headings ‘Our Strategy’, ‘Outlook’ and ‘Looking
Ahead’, with regard to strategy and strategic priorities, plans to deliver
shareholder value, expectations regarding the ‘10-point plan’, expectations
regarding future dividend payments, BP’s outlook on global energy trends to
2030 and beyond, the intention to make $38 billion of disposals, anticipated
increase in operating cash flow and margins, future capital expenditure,
expected level of investments, the anticipated timing for completion of and
final proceeds from the disposition of certain BP assets, future production
levels including expectations for an increase in high-margin production,
the timing and composition of future projects including expected start
up, completion, timing of production, level of production and margins,
expectations for drilling and rig activity in the Gulf of Mexico, the timing and
quantum of and timing for completion of contributions to and payments from
the $20-billion Trust fund, the expected terms of the proposed settlement
agreement with the Plaintiffs’ Steering Committee in MDL 2179 and the
expected timing of the fairness hearing and court approvals in respect
thereof, the expected amount, source and timing of payments under any
settlements, expectations regarding regulation and taxation of the energy
industry and energy users, future global refinery capacity and utilization,
the timing for completion of the Whiting refinery upgrade, plans regarding
the implementation of enhancements to BP’s risk management system,
expectations regarding the reduction of net debt and the net debt ratio,
the expected future level of depreciation, depletion and amortization, the
expected level of the refining marker margin, the completion of planned and
announced divestments, including the planned disposals of the Texas City
refinery and the southern part of the US West Coast FVC, dates or periods
in which production is scheduled or expected to come onstream or a project
or action is scheduled or expected to begin or be completed, and the level of
future turnaround activity; (ii) the statements in the Business review (pages
18-111), Corporate governance (pages 119-138), the Directors’ remuneration
report (pages 139-151) and Additional information for shareholders (pages
153-172) with regard to plans to continue the ongoing process of embedding
OMS, the timing for the implementation of the Bly report recommendations,
intentions to implement group-wide practices for oil spill preparedness
and response and crisis management, plans to spend $700 million on
certain refinery-related safety measures, plans to implement enhanced and
standardized technical practices across the refining business, the timing for
the completion of the Shoreline Clean-up, the timing of, cost of, source of
payment and provision for future remediation and restoration programmes
and environmental operating and capital expenditures, the anticipated future
level of time for conversion of proved undeveloped reserves to proved
reserves, expectations regarding Refining and Marketing’s intentions to
achieve $2 billion in performance improvement by the end of 2012, plans to
halve US refining capacity by the end of 2012, the timing for the completion
of construction at the Cherry Point refinery, anticipated investment in
Alternative Energy, expectations regarding greater regulation and increased
operating costs in the Gulf of Mexico in the future, and costs for providing
pension and other post-retirement benefits; (iii) the statements in the
Business review (pages 103-106) with regard to future dividend and optional
scrip dividend payments, future capital expenditures and capital expenditure
commitments, taxation, intentions to maintain a significant liquidity buffer,
future working capital and cash flows, gearing and the net debt ratio,
expected payments under contractual and commercial commitments and
purchase obligations, and including under ‘Liquidity and capital resources
– Trend information’, with regard to production excluding TNK-BP, the
expected level of turnarounds, the marketing environment in fuels, lubricants
and petrochemicals, underlying average quarterly charge from Other
businesses and corporate, and expectations regarding future disposals;
and (iv) certain statements in the Business review (page 84) and Additional
information for shareholders (pages 160-166) regarding the anticipated
timing of trial proceedings, court decisions and potential investigations and
civil or criminal actions by US state and/or local governments; are all forward
looking in nature.
By their nature, forward-looking statements involve risk and
uncertainty because they relate to events and depend on circumstances
that will or may occur in the future and are outside the control of BP. Actual
results may differ materially from those expressed in such statements,
depending on a variety of factors, including the specific factors identified in
the discussions accompanying such forward-looking statements; the timing
of bringing new fields onstream; the timing of certain disposals; future levels
of industry product supply, demand and pricing; OPEC quota restrictions;
PSA effects; operational problems; general economic conditions; political
stability and economic growth in relevant areas of the world; changes in
laws and governmental regulations; regulatory or legal actions including the
types of enforcement action pursued and the nature of remedies sought;
the actions of prosecutors, regulatory authorities and courts; the actions
of all parties to the Deepwater Horizon oil spill-related litigation at various
phases of the litigation; exchange rate fluctuations; development and use
of new technology; the success or otherwise of partnering; the actions
of competitors; the actions of contractors; 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’
(pages 59-63). 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.
Unless otherwise indicated, information in this document reflects 100% of the assets and
operations of the company and its subsidiaries that were consolidated at the date or for the
periods indicated, including minority interests. The company was incorporated in 1909 in England
and Wales and changed its name to BP p.l.c. in 2001. BP’s primary share listing is the London
Stock Exchange. Ordinary shares are also traded on the Frankfurt Stock Exchange in Germany
and, in the US, the company’s securities are traded on the New York Stock Exchange in the form
of ADSs (see page 167 for more details).
The registered office of BP p.l.c., and our worldwide headquarters, is:
1 St James’s Square,
London SW1Y 4PD, UK.
Tel +44 (0)20 7496 4000.
Registered in England and Wales No. 102498. Stock exchange symbol ‘BP’.
Our agent in the US is BP America Inc.,
501 Westlake Park Boulevard, Houston, Texas 77079.
Tel +1 281 366 2000.
BP Annual Report and Form 20-F 2011 5
6 BP Annual Report and Form 20-F 2011
Business review
Group overview
2011 was a year of recovery,
consolidation and change. We laid
strong foundations, reshaped the
portfolio and recovered momentum.
8
Chairman’s letter
Carl-Henric Svanberg sets out the actions taken by the
board to establish a stronger, safer BP.
25 Our organization
A clear overview of today’s BP, from our business
model to what we stand for and where we operate.
12 Board of directors
37 Our strategy
BP’s board of directors, as at 6 March 2012.
What you can expect from us and what you can
measure, as we work to create a stronger, safer BP.
14 Group chief executive’s letter
42 Our management of risk
Bob Dudley reports on BP’s progress against its
priorities of enhancing safety, earning back trust and
growing value.
The strengthened processes and systems we are
putting in place to make BP a safer, more risk-aware
company.
18 Our market
47 Our performance
From oil prices, natural gas prices and refining margins
during the year to the long-term outlook for the global
energy industry.
Key measures, actions and events in a year of
consolidation and change.
BP Annual Report and Form 20-F 2011 7
BP Annual Report and Form c 2011 7
Business review: Group overview Chairman’s letter
Carl-Henric Svanberg
Chairman
Dear fellow shareholder,
In 2011 we re-laid the foundations of BP. Our objective was to ensure your
company is able to deliver sustainable shareholder value in the months and years
ahead. Above all else, this is dependent on BP having the trust of the societies in
which it works – today and over the long term.
During the year the board oversaw a major reorganization designed to
establish a stronger, safer BP. The progress made demonstrates that the company
can and will recover from the consequences of the Deepwater Horizon accident.
We remained mindful of the tragic events seen in 2010 and the need to ensure
such an accident never happens again.
I thank you for the patience you have shown as we work to rebuild your
company.
The board set three priorities for BP. Safety must be enhanced and
embedded. Trust must be regained. Value must be created through a clear
strategic plan. While these priorities are simple to express, substantial activity
is required to turn them into tangible and lasting change.
On safety, the board supported and challenged Bob Dudley and his
executive team as they restructured and enhanced BP’s processes, systems and
culture. Furthermore, the board initiated a review of the way BP manages, reports
and acts on risk, including board oversight.
On trust, we ensured that BP continued to meet its commitments in the
Gulf of Mexico. We co-operated with every official investigation and prepared
for litigation. We worked closely with governments and regulators, and we
communicated openly with shareholders and the wider world.
On value, the board set a 10-point plan focused on growing operating cash
flow and increasing shareholder returns. The company will play to its greatest
strengths and prioritize value over volume. Relentless execution of this strategy
is now needed so we deliver value to our shareholders.
BP’s financial and operating performance in 2011 has created a springboard
for growth. In the upstream, we secured 55 new exploration licences in nine
8 BP Annual Report and Form 20-F 2011
countries, and our Refining and Marketing segment delivered very strong
earnings. Our $38-billion divestment programme is strengthening the group’s
financial position and focusing our portfolio.
In 2011 we restored your dividend, and I am pleased to report that we
increased the dividend by 14% in February 2012, in accordance with our policy.
The wider world did not stand still in 2011. We saw rapid and sometimes
unpredictable change. This included escalation of the European debt crisis and
political upheaval in countries where BP has significant operations, such as Libya
and Egypt. We kept a close watch on these developments and acted where
required. Our international advisory board assisted us in this task.
The company continually looks for ways to form new relationships and
enhance its partnerships around the world. Our new alliance with Reliance
Industries in India is a significant venture in a fast-growing market. Russia is
particularly important for BP. Our TNK-BP alliance is hugely successful. Since
acquiring 50% of the company for around $8 billion, BP has received around
$19 billion in dividends – which equates to around $2 billion per year. In 2011,
we saw new opportunities in Russia, but these did not progress. This region
still has excellent potential for BP and we remain committed to it. The nature
of our industry is rarely straightforward, and BP will never shrink from pursuing
opportunities simply because they involve challenges.
In my letter last year, I commented on the evolution of the board. This has
continued. My goal is to ensure that the board combines a broad set of skills and
experience. BP’s board should be diverse in the widest sense. It should have
the best blend of the best people from our industry and from other sectors. BP
remains committed to meritocracy as well as diversity.
Andrew Shilston and Professor Dame Ann Dowling have joined the board
as non-executive directors and Brian Gilvary has joined as an executive director.
Left BP’s LNG activities
are focused on building
competitively advantaged
liquefaction projects.
BP Annual Report and Form 20-F 2011 9
Business review: Group overview Chairman’s letter
Andrew, a former finance director at Rolls-Royce, brings substantial experience in
the oil and gas industry through previous roles at Enterprise Oil and Cairn Energy.
Ann is Head of the Department of Engineering at the University of Cambridge,
where she is Professor of Mechanical Engineering. She brings exceptional
academic and engineering expertise to BP.
Brian Gilvary is now our chief financial officer. His broad experience of BP,
gained over 25 years in influential roles such as the chief executive of integrated
supply and trading and as deputy group CFO, makes him a valuable addition.
Our previous CFO Byron Grote takes up a new role as the director responsible
for corporate business activities. Byron has made a substantial contribution over
his lengthy BP career and I am pleased we have retained his services as a board
member.
Left The East Azeri
platform in the Caspian
Sea in Azerbaijan. BP
is the largest foreign
investor in the country.
Right In 2011, the
chairman visited the
Alberta oil sands in
Canada including the
Sunrise Energy Project
– BP’s joint venture
with Husky Energy.
In detail
For more information
on the board and its
committees, see
Corporate governance
report.
Page 126
Bill Castell has decided not to seek re-election at the forthcoming AGM. Bill
has made a substantial contribution to the board, not least as chair of the safety,
ethics and environment assurance committee. Bill has devoted all the time that
was asked of him and more in the service of the board and the company. I speak
for the whole board when I thank him sincerely for all he has done. Bill’s role
as senior independent director will be taken by Andrew Shilston, who will be
supported on internal matters by Antony Burgmans.
The board committees have always played an important oversight role,
freeing the main board to concentrate on strategic matters. All of our committees
have been heavily involved this year. Each committee has dealt with different
challenges, and all of the directors have been unstinting in the time they have
given.
The Gulf of Mexico committee, formed in 2010 and chaired by Ian Davis,
has been invaluable in allowing the board to prioritize its work during the
restoration of the Gulf of Mexico and the ensuing litigation. During the year,
Antony Burgmans became chair of the remuneration committee and Brendan
Nelson became chair of the audit committee. Paul Anderson took over the chair
of the safety, ethics and environmental assurance committee in December.
10 BP Annual Report and Form 20-F 2011
During the year, the remuneration committee has worked with Bob Dudley and
his team to remodel the reward system within the group. The system below
the board is now clearly focused on the long term and is similar to that used for
executive directors. I believe our approach to rewarding directors balances the
company’s priorities of driving financial performance, meeting our responsibilities
as a corporate citizen and providing value for our shareholders.
Against all of this background, I have been keen to see how the board
could work more effectively. During the year, a working group of non-executive
directors reviewed board tasks, roles and processes. This work, coupled with
our board evaluation, has led to a number of changes in the way in which the
board operates. These are set out in the board performance section of this
annual report.
2011 was a testing year for everyone at the company. The board was
impressed by the way in which Bob and his executive team tackled a range of
considerable issues. We were also struck by the tenacity and dedication of BP’s
employees. On behalf of the board, I thank everyone for their efforts.
In 2012 we must execute our 10-point plan and continue to meet our
commitments in the Gulf of Mexico. While many of the investigations into the
causes of the accident have been completed, we still face major litigation in the
US during 2012. This must run its course, although we are pleased with the
continuing progress that we are making with settling some of these claims.
As part of its strategic role, the board must be mindful of the long-term
developments in our industry. BP Energy Outlook 2030 tells us that rising
populations, increasing levels of life expectancy and improving standards of living
will continue to generate growing demand for energy. The challenges in terms of
supply are immense. I expect these dynamics to provide BP with opportunities
for decades to come. The report projects that fossil fuels will be providing around
80% of the world’s energy in 2030. This will require companies such as ours to
overcome substantial technical and physical challenges. Lower carbon resources
and energy efficiency technologies are required to play their part in addressing
both demand and emissions. BP must understand and adapt to these changes
in order to remain sustainable in this changing world.
I believe BP ended the year stronger and safer, with increasing forward
momentum and a clear strategy matched to the world we see ahead. This
is a great company, with a strong board and excellent people. I thank you for
your continued support. I will report back to you on BP’s progress at this point
next year.
Carl-Henric Svanberg
Chairman
6 March 2012
BP Annual Report and Form 20-F 2011 11
Business review: Group overview Board of directors
As at 6 March 2012
From left to right, standing
Professor Dame Ann Dowling
Non-Executive Director
Frank Bowman
Non-Executive Director
Brendan Nelson
Non-Executive Director
Phuthuma Nhleko
Non-Executive Director
Sir William Castell
Senior Independent Director
Iain Conn
Chief Executive, Refining and
Marketing
Dr Brian Gilvary
Chief Financial Officer
George David
Non-Executive Director
Paul Anderson
Non-Executive Director
Dr Byron Grote
Executive Vice President,
Corporate Business Activities
Andrew Shilston
Non-Executive Director
From left to right, seated
Carl-Henric Svanberg
Chairman
Bob Dudley
Group Chief Executive
Ian Davis
Non-Executive Director
Antony Burgmans
Non-Executive Director
Cynthia Carroll
Non-Executive Director
Cynthia Carroll was unable to attend
on the day the board photograph
was taken.
12 BP Annual Report and Form 20-F 2011
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BP Annual Report and Form 20-F 2011 13
Group chief executive’s letter
Bob Dudley
Group Chief Executive
14 BP Annual Report and Form 20-F 2011
Dear fellow shareholder,
Following the tragic Deepwater Horizon accident of 2010, BP entered 2011
facing a range of uncertainties. These included concerns about our ability to
operate safely in deep water, meet our financial commitments in the Gulf of
Mexico, and recover the trust and value we had lost. We were also subject
to intense speculation around the future and direction of the company.
By the end of the year we had successfully resolved some significant
uncertainties facing the company. We set new standards for safety, led by our
safety and operational risk organization, and we reshaped our upstream business.
We strengthened the group’s financial position by progressing our divestment
programme. We worked to earn back trust through co-operation with the official
investigations and actively sharing the lessons learned. We set a clear strategic
direction through a 10-point plan focused on building value for shareholders.
We also received permission to resume operations in the Gulf of Mexico –
a significant milestone.
During the year more clarity also emerged over the 2010 accident as
official investigation reports were published. Their central conclusions supported
that of our own investigation – namely that what happened in the Gulf of Mexico
was a complex accident involving multiple causes and multiple parties. I am
pleased that we were able to reach settlements with Mitsui, Weatherford,
Anadarko and Cameron during 2011. On 3 March 2012 we announced a
settlement with the Plaintiffs’ Steering Committee, subject to final written
agreement and court approvals, to resolve the substantial majority of legitimate
economic loss and medical claims made by individual and business plaintiffs in
the Multi-District Litigation proceedings pending in New Orleans (MDL 2179). The
legal process continues with other parties.
We recognize there is a great deal more to do, but I can report that
BP finished its year of consolidation in robust shape.
Through the year, BP’s employees worked with great determination to
enhance what we do and how we do it. This work will continue. I want to
make it absolutely clear that we are not seeking a return to business as usual.
The events of 2010 demand more than that. As we move ahead, our job is to
make BP a stronger, safer company by further embedding safety at the heart
of the company, continuing to earn back trust, and creating long-term value for
shareholders once again. In this letter, I outline in more detail the actions taken
in 2011 to achieve these objectives.
Safety
During the year, we reorganized our upstream segment to improve clarity and
accountability. We introduced new systems and technologies to further enhance
oversight of operations. We continued to increase the capacity of our independent
safety and operational risk organization, and recruited experts from other high-
hazard industries to add new expertise and perspectives. We also renewed the
company’s performance and reward systems, values and code of conduct, which
require whoever works for BP to put safety first.
At the front line, we shut down platforms and operations to make necessary
upgrades. We set new, voluntary standards for blowout preventers, which shut
off the flow of oil in an emergency. We also designed a new type of capping
stack, which now stands ready for deployment anywhere in the world in the
event of a leak in deep water.
Trust
Looking back over events in the Gulf of Mexico, I am proud of how BP responded.
Just in financial terms, during 2010 and 2011 combined we made a pre-tax cash
outlay of more than $26 billion to cover oil spill response costs, meet claims
and litigation expenses, support research, promote tourism and help restore the
environment. The test of corporate responsibility is whether a company follows
up its words with actions. I believe we have. And we will continue to do so.
During the year we were invited to 25 countries to share what we have
learned in the Gulf. In turn, we have gone out to gain insights from organizations
in other high-hazard sectors, including NASA, the UK Atomic Energy Authority and
various naval bodies. We will keep listening to others and applying what we learn.
Value
As I write this letter, the market value of the company remains significantly
lower than it was before the incident. Our 10-point plan shows our belief that the
company can realize improved returns for shareholders. The plan sets out what
you can expect from us, and what you will be able to measure, over the next
three years.
• First and foremost, you will see a continuing, relentless focus on safety and risk
management.
• You will see the company play to its strengths – exploration; managing
deepwater activity; giant fields; gas supply chains; our world-class downstream
business; and our capabilities in developing technology and building relationships.
• You will see a company that is simpler and more focused as a result of a major
divestment programme.
• You will see a company that is organized effectively and applies its standards
Above During the
year BP gained its first
US exploration drilling
permit since the 2010
Deepwater Horizon oil
spill – for the Kaskida
field, Gulf of Mexico.
consistently.
• You will see more visibility from us on our individual businesses.
• You will be able to measure the effects of active portfolio management,
as we invest more in our areas of strength and generate cash through
further divestments.
• You will be able to measure the contribution of new upstream projects
with higher margins, as they come onstream over the next three years.
• You will be able to measure operating cash flow, which we expect to be around
50% higher by 2014.a
a See footnote c on page 39.
BP Annual Report and Form 20-F 2011 15
Business review: Group overview In detail
For more on the
strategic priorities set
out in the 10-point plan,
see Our strategy.
Pages 37-41
Group chief executive’s letter
• We plan to use around half of the increased cash flow for investment and half for
other uses including increased distributions to shareholders.
• And finally, you will be able to measure balance sheet strength.
The plan makes a greater priority of creating value for the shareholder, rather than
simply increasing production volume. We will sell assets earlier in their lifecycle
following discovery if we spot opportunities to reinvest in higher growth areas. We
are also being selective in where we invest along the supply chain. For example,
we are selling certain mature fields that hold more value for others, and we are
selling a number of refining and marketing assets that do not match our aspirations.
I want to say a little more about the areas of strength at the heart of
our strategy.
Exploration is our lifeblood. We had a record year for new access in
2011, gaining 55 exploration licences in nine countries. This opened up around
315,000km2 for exploration. We intend to more than double exploration
investment over the next three years.
In deep water, we are confident in our ability to design, engineer and operate
large installations safely. 2012 will be a busy year for us in the deepwater regions
of Angola, Brazil and the Gulf of Mexico.
Left New investment
announced in 2011 may
extend production at the
Clair field of the UK North
Sea to 2050.
Right February 2011
saw BP announce a
partnership with Reliance
Industries spanning the
gas value chain in India,
from exploration to
marketing.
In giant fields, work with our partners has increased output at Iraq’s
Rumaila field by more than 10%. BP was the first supermajor to exceed its
production target in Iraq. During the year we also announced we will be investing
approximately $14 billion – with our partners – in the UK North Sea.
Natural gas is set to be the fastest-growing fossil fuel globally to 2030.
Here, we are forging new partnerships, such as the strategic alliance created in
2011 with Reliance Industries in India. We continue to have a significant focus
on developing unconventional resources around the world. Taking technology
and skills developed in North America, we are working with the governments of
Oman and Algeria to develop their large tight gas reservoirs, and we also continue
to work in Indonesia to develop their onshore coalbed methane fields.
We also have exceptional expertise in building supply chains. For example,
we move gas from 6,000 metres below the Shah Deniz field in Azerbaijan to
markets in Western Europe, 3,000 kilometres away.
16 BP Annual Report and Form 20-F 2011
In Refining and Marketing, our world-class fuels, lubricants and petrochemicals
businesses are shifting the balance of their activity towards higher growth
markets, including China and India. We are moving forward with our plans to sell
around half of our refining capacity in the US, and we have made good progress
on the modernization of the Whiting refinery. Looking ahead, we expect our
downstream operations to be a material contributor to the cash flow we anticipate
over the next few years.
These strengths are supported by our long-standing track record in
developing and applying leading technology, and the deep and enduring
relationships we form. We were disappointed that our exploration plans with
Rosneft did not progress, but we remain committed to our TNK-BP investment
in Russia, which continues to be successful.
A well-balanced business
As the BP Energy Outlook 2030 shows, the world is now in a long wavelength
transition to a lower-carbon energy mix. For BP, that means helping to meet
current demand through the supply of oil and gas – including unconventional
resources – while developing a number of the lower-carbon options needed at
scale tomorrow.
During 2011, we invested a further $1.6 billion in our Alternative Energy
business, which takes total investment since 2005 to $6.6 billion. We have a
growing biofuels business in Brazil and we added 401MWa of wind generation
capacity during the year, with interests in more than 1,000 wind turbines now
turning across the US. In contrast, solar has evolved into a low-margin commodity
market, and in 2011 we began winding down our remaining solar operations as
we prepare to exit the business.
Looking ahead
BP is meeting its commitments and moving forward with increasing momentum.
2012 will be a year of milestone delivery, with financial momentum building in
2013 and 2014. In 2012, you can expect high-margin production coming back on
stream, major project start-ups and new exploration wells, further progress on
our divestment programme, continued improvement in downstream financial
performance and completion of payments into the Deepwater Horizon Oil Spill
Trust fund.
The company has a strong leadership team and non-executive directors
who provide rigorous oversight – challenging and supporting executives as
circumstances dictate. I want to thank BP’s employees for their resilience. They
were again tested hard this year. The character of BP’s people was evident
wherever we operate, not least in Egypt and Libya, where our teams evacuated
colleagues and their families safely during the upheavals in the region.
I thank investors for their continued patience through a tough time. One by
one, we are addressing the uncertainties facing our company. The days ahead
may bring further challenges, but we are in a much stronger position than this
time last year. There is a great deal more to do, but we are building a stronger,
safer BP that can play an important role in the world for many years to come.
Bob Dudley
Group Chief Executive
6 March 2012
a On a gross joint-venture basis (which includes 100% of the capacity of equity-accounted entities
where BP has partial ownership). Including BP’s share of joint ventures on a net basis, the capacity
added was 274MW.
BP Annual Report and Form 20-F 2011 17
Business review: Group overview Our market
In 2011, energy markets proved resilient, with
continued growth despite volatile conditions in the
global economy.
Left Modernization
work at BP’s Whiting
refinery, Indiana, made
significant progress
in 2011, with the
completion of a new
pipeline to Canada.
Right Operations
at our East Azeri
platform. BP
production in
Azerbaijan is an
important source of
natural gas for markets
in Western Europe.
The growth in world oil consumption slowed in 2011, albeit with continued robust
growth in China and certain other non-OECD countries partially offsetting an
overall decline in OECD countries. However, despite the slowdown in demand,
average crude oil prices in 2011 were significantly higher than in the previous year,
exceeding $100 per barrel for the first time (in nominal terms). Natural gas prices
diverged globally in 2011. Globally, refining margins improved on average as oil
product demand continued to grow.
Economic context
After a very strong 2010, world economic growth slowed in 2011 and we expect
subdued global growth to continue in 2012. Emerging economies with stronger
productivity and rising populations led by China and India are set to drive growth,
while developed countries may lag behind as they seek to address their internal
fiscal imbalances.
Energy demand, and in particular oil demand, has followed overall economic
trends in recent years, recovering strongly in 2010 but facing more challenging
conditions in 2011, especially in OECD markets.
Concerns about the volatility of commodity and financial markets, energy
security and climate change have led to continued debate over the appropriate
role of markets, government regulation and other policy measures that affect the
supply and consumption of energy. Given the pressures in the sector, we expect
regulation and taxation of the energy industry and energy users to increase in
many areas in the future.
18 BP Annual Report and Form 20-F 2011
Crude oil prices
Crude oil prices, as demonstrated by the industry benchmark of dated Brent for
the year, averaged $111.26 per barrel in 2011, about 40% above 2010’s average
of $79.50 per barrel. This represents the highest annual average ever (in nominal
terms), as well as the largest one-year increase ever.
Prices rose early in 2011 and then increased further following the loss of
Libyan supplies, which drove prices briefly above $125 per barrel in April. Thereafter,
weakening global economic growth, increased production by other OPEC producers
and the release of International Energy Agency (IEA) strategic stocks helped to
cushion the disruption. While oil prices eased over the remainder of the year, they
still ended the year above $100 per barrel.
These record prices prevailed despite the fact that the growth in global oil
consumption slowed in 2011 with demand rising by roughly 0.7 million barrels per
day for the year (0.8%)a in the face of slower economic growth and higher prices.
Growth in 2011 was concentrated in non-OECD countries, led by China. There was
relatively little change in non-OPEC production and, with the loss of Libyan supplies
beginning in February, OPEC crude oil production did not return to its January peak
until November. As a result, by mid-year OECD commercial oil inventories were
consistently below average for the first time since 2008.
By comparison, global oil consumption in 2010 grew by roughly 2.7 million
barrels per day (3.1%)b, the strongest growth in annual consumption since 2004,
driven by a renewed global economy. Crude oil prices in 2010 remained stable in a
range of $70-80 per barrel before beginning to increase in the fourth quarter due to
rising consumption and continuing OPEC production.
We expect oil price movements in 2012 to continue to be driven by the pace
of global economic growth and its resulting implications for oil consumption, and by
OPEC production decisions, especially in reaction to the recovery of Libyan supplies
and the EU embargo on Iranian crude.
a From Oil Market Report February 2012 ©, OECD/IEA 2012, page 5.
b BP Statistical Review of World Energy June 2011.
Crude oil and gas prices,
and refining margins
($ per barrel of oil equivalent)
Dated Brent oil price
Henry Hub gas price
(First of Month Index)
Average refining marker
margin (RMM)*
210
175
140
105
70
35
2007
2008
2009
2010
2011
Source: Platts/BP.
* See Refining and Marketing on page 94 for
further information on RMM.
Below Work at BP’s
Castellón refinery,
Spain. Refining
margins in Europe
increased in 2011,
as demand for
commercial transport
improved.
BP Annual Report and Form 20-F 2011 19
Business review: Group overview
Our market
Left Operations at
BP’s Na Kika field in
deepwater Gulf of
Mexico. BP is one of
the largest producers
of hydrocarbons in
the region.
Natural gas prices
Natural gas prices diverged globally in 2011, reflecting different regional dynamics.
The average US Henry Hub First of Month Index fell to $4.04/mmBtu, 8% lower
than the prices in 2010, while in Europe prices increased.
After a record increase in 2010, global gas consumption growth moderated
in 2011. In the US, economic momentum supported gas use in the first half of
the year and a hot summer raised demand. Yet domestic production outpaced
consumption growth due to further increases in the availability of shale gas.
Henry Hub gas prices fell and traded below coal parity in US power generation
throughout the year, leading to the displacement of coal by gas. Unusually mild
winter weather weakened prices at the end of year. The differentials of production
area prices to Henry Hub prices continued to narrow as pipeline bottlenecks were
reduced.
In Europe, spot gas prices at the UK National Balancing Point increased
by 33% to an average of 56.33 pence per therm for 2011 – the highest level
since 2008. The loss of Libyan gas supply raised continental European demand
for Russian gas in early 2011, but LNG supply and weak general demand kept
spot gas prices below oil-indexed contract levels. Competition between spot
and contract pipeline supplies continued. High volumes of LNG were available
to Europe, despite the Japanese earthquake and tsunami in March 2011, which
caused major nuclear outages and significantly increased LNG purchases in
Japan. This contributed to a tightening global LNG market over the year.
The economic rebound had led the average Henry Hub First of Month Index
to recover in 2010 from eight-year lows, rising by 10% to $4.39/mmBtu. In the
UK, National Balancing Point prices averaged 42.45 pence per therm in 2010 –
38% above the depressed prices in 2009.
In 2012, we expect gas markets to continue to be driven by the economy,
weather, domestic production, LNG supply and reductions in nuclear power
generation following the Fukushima disaster in Japan in March 2011.
20 BP Annual Report and Form 20-F 2011
In detail
For more information, see
Refining and Marketing.
Page 94
Refining margins
In 2011, demand for oil products continued to grow, albeit more slowly than
a year ago, with all of the demand increase occurring in non-OECD markets
and with overall demand in the OECD resuming its structural decline. As new
refining capacity continued to be commissioned in Asia and the Far East, global
refinery utilization rates fell in 2011. Despite this, a number of factors supported an
increase in refining margins across all regions for a second consecutive year. The
BP refining marker margin (RMM)a averaged $11.64 per barrel in 2011, compared
with $10.02 per barrel in 2010 and $9.19 per barrel in 2009.
In 2011, diesel prices relative to crude reached highs not seen since 2008
as the trend to lower-sulphur fuels continued and demand grew. Gasoline prices
were volatile in 2011. In the US, short-term supply issues supported gasoline
prices in the middle of the year despite a reduction in demand compared with last
year. By the fourth quarter, US gasoline prices relative to crude had fallen to the
lowest levels seen for at least 23 years. Refining margins improved in Asia Pacific,
due to continuing oil demand growth and the disruption to Japanese refining
operations caused by the earthquake and tsunami.
US mid-continent crude oils (including the key marker grade of West Texas
Intermediate) were heavily discounted throughout the year because of increasing
production in the US Lower 48 states and in Canada, coupled with constrained
logistics. This allowed refiners that are able to access these crudes to capture
additional margins.
The loss of Libyan crude oil supply in the first quarter of 2011 and production
problems in the North Sea during the summer resulted in record high prices for
low-sulphur grades of crude oil. This adversely impacted the margin for refiners
configured to process these grades, particularly in Europe, the US East Coast and
Asia.
By contrast, in 2010 the RMM increase compared with 2009 was due to
strongly-improved demand for oil products, in line with the economic bounce-back
from recession, despite unused refining capacity.
Looking ahead, the overall economic environment is expected to result in
limited demand growth such that refinery utilization levels are likely to remain low,
despite the announced shutdown of capacity in Europe and the US.
a See page 94 for further information on RMM.
Left In 2011, we
received local
government approval
for a 1.25mtpa PTA
plant to be added to
existing BP
petrochemicals facilities
in Zhuhai, China.
BP Annual Report and Form 20-F 2011 21
Business review: Group overview Our market: Longer-term outlook
The long-term outlook is one of growing demand
for energy and increasing challenges for our
industry in meeting the world’s needs.
Long-term growth in energy demand
Energy demand is linked to economic growth, development and population.
The world’s population is projected to increase by 1.4 billion over the next
20 years, while its real income is likely to grow by 100% over the same period.
This combination of factors is expected to increase world primary energy
consumption by approximately 40% over the next 20 years, with non-OECD
energy consumption as much as 70% higher by 2030. Energy and climate
policies, efficiency gains and a long-term structural shift in fast-growing
economies away from industry towards less energy-intensive activities may act
to restrain consumption, but the overall trend is likely to be one of strong growth in
energy demand.
Oil and gas are still expected to play a significant part in meeting this
demand and we project they will represent 53% of total energy consumption
in 2030 (compared with 57% in 2010). Even under the IEA’s most challenging
climate policy scenario (450 Scenario) that might with difficulty still be achievable,
oil and gas together still makes up 49% of the energy mix in 2030, with combined
demand projected to exceed current levels.a The 450 Scenario assumes
governments adopt commitments to limit the long-term concentration of
greenhouse gases in the atmosphere to 450 parts-per-million of CO2 equivalent.
We believe the political, technological, logistical, infrastructure and cost challenges
presented by the 450 Scenario make it increasingly unlikely to occur, meaning that
demand for fossil fuels would remain at a higher level for longer.
We also expect advances in technology to lead to new and more efficient
ways to transform base hydrocarbons (including natural gas and coal) into usable
forms of energy, petrochemicals and lubricants.
Beyond 2030, we believe it is currently very difficult to provide meaningful
projections. We expect that growing population and per-capita incomes will
continue to drive growing demand for the services that energy provides –
including mobility, heat and light. The way those services are provided will be
shaped by future technology developments, changes in tastes, and future policy
choices – all of which are inherently uncertain. Concerns about affordability,
energy security and environmental impacts – in particular climate change – are all
likely to be important considerations for the future. These factors may accelerate
the trend towards more diverse sources of energy supply, a lower average
carbon footprint, increased efficiency of energy provision and use, and demand
management.
We actively monitor developments and continually assess a range of
potential outcomes and their implications for our long-term strategy.
a From World Energy Outlook 2011©, OECD/IEA 2011, page 545.
The facts and figures used
in our longer-term outlook
commentary in this section
are derived from BP Energy
Outlook 2030, published in
January 2012, unless otherwise
indicated, and represent a ‘base
case’ or most likely projection.
Population
(billion)
Rest of World
India
China
1970
1990
2010
2030
Source: BP Energy Outlook 2030.
Energy
(billion tonnes of oil equivalent)
Rest of World
India
China
1970
1990
2010
2030
Source: BP Energy Outlook 2030.
10
8
6
4
2
20
15
10
5
22 BP Annual Report and Form 20-F 2011
Above An engineer on
board the BP oil tanker
British Gannet. At the
end of 2011, we had 53
international vessels.
Below The control
room at BP’s Atlantic
LNG facility in Trinidad,
where BP has been
operating since 1961.
Meeting the energy challenge
We estimate that there are enough energy resources available to meet the
increases in demand. As a measure of this availability, today’s oil reserves could
meet more than 45 years of demand at current consumption rates; while known
supplies of natural gas could meet demand for nearly 60 years; and coal could
meet demand for up to 120 years.a Meanwhile, new technologies are improving
the availability and affordability of unconventional fossil resources such as shale
gas, oil sands and coalbed methane. And emerging renewable resources have the
potential for significant growth as their markets mature and technological advances
make them more affordable and efficient.
While energy is available to meet demand, action is also required to limit
the volumes of carbon dioxide and other greenhouse gases being emitted
through energy use. Global economic challenges have reduced the focus of some
governments on climate policy, at least in the short term. But the position set
out at the UN’s 2010 climate change conference in Cancun that deep cuts are
required to hold global temperature rises to 2˚C, and the commitment by both
developed and developing countries in Durban in 2011 to negotiate an agreement
by 2015 that requires action from all countries, suggests that in the medium to
long term an emphasis on carbon policy will return and grow. We project that
under known and probable policy and technology, global CO2 emissions may be
28% higher in 2030 than they are today, partly as a consequence of coal use in
rapidly-growing economies. More aggressive, but still plausible, energy policy
and technology deployment could lead to slower growth in CO2 emissions than
expected, with emissions from energy use falling after 2020, but probably not
to the extent of putting the world on a global warming trajectory that does not
exceed 2˚C. And even these policies would require concerted multilateral action
from policymakers and a willingness by society to bear a significant cost.
Energy security also represents a major challenge. More than half of the
world’s natural gas is in just three countries, and more than 80% of global oil
reserves are in 10 countries, most of which are located well away from the hubs
of energy consumption. The ability and willingness of OPEC members to expand
capacity and production is one of the main factors determining the dynamics of
the oil market.
a BP Statistical Review of World Energy June 2011. These reserve estimates are compiled from official
sources and other third-party data, which may not be based on proved reserves as defined by SEC rules.
Non-OECD economies drive consumption growth
(billion tonnes of oil equivalent)
Non-OECD
OECD
Renewables*
Hydro
Nuclear
Coal
Gas
Oil
18
16
14
12
10
8
6
4
2
18
16
14
12
10
8
6
4
2
1990
2000
2010
2020
2030
1990
2000
2010
2020
2030
Source: BP Energy Outlook 2030.
*Includes biofuels.
BP Annual Report and Form 20-F 2011 23
Business review: Group overview Our market: Longer-term outlook
The dual challenges of emissions and energy security underline the value of
energy efficiency. Increases in efficiency have the potential to reduce emissions
without inhibiting economic growth, and they can help energy-importing countries
to reduce their dependency on others. For these reasons, we expect efficiency to
remain high on the agenda through to 2030.
A diverse energy mix
We believe the global energy challenge can only be met through a diverse mix of
fuels and technologies. This is why BP’s portfolio includes oil sands, shale gas,
deepwater production, and alternative energies such as biofuels and wind power,
in addition to conventional oil and gas. As well as simply meeting growth in overall
demand, a diverse mix can help to provide enhanced national and global energy
security while supporting the transition to a lower-carbon economy.
Within the energy mix, we see a key strategic role for natural gas as a lower-
carbon fuel that is increasingly secure and affordable. Used in place of coal for
power, it can reduce CO2 emissions by half.
Renewables will be essential in addressing the challenges of climate change
and energy security over the long term. Renewable energy is already the fastest-
growing fuel and is projected to grow 8.2% per annum to 2030 – a rate similar to
the emergence of nuclear power in the 1970s and 1980s. Renewable energies
are starting from a low base however, and we project that they are only likely
to meet around 6% of total energy demand by 2030. With a few exceptions,
renewables are not yet competitive with conventional power and transportation
fuels. Sufficient policy support is required to help the commercialization of
effective options and technologies, but renewables must ultimately become free
from subsidy and commercially self-sustaining. See Risk factors – climate change
and carbon pricing on page 60.
The future for hydrocarbons
Given the vital role oil will continue to play in meeting demand, substantial
investment in new technology will be required to boost recovery from declining
fields and commercialize currently inaccessible resources. The industry’s ability
to increase recovery from mature assets will be profoundly important, particularly
in the world’s giant fields. Over time, it will become increasingly difficult to reach,
extract and manage oil resources, and companies such as BP may be required
to move yet further into technically challenging areas. Greater energy intensity
could be required to extract these resources; operating costs and greenhouse gas
emissions from operations are likely to increase. Along with increasing supply, we
believe the energy industry will be required to make hydrocarbons cleaner and
more efficient to use.
Carbon capture and storage (CCS) may help to provide a path to cleaner coal
and gas, but CCS technologies still face significant technical and economic issues
and are unlikely to be in operation at scale in the near future.
Policy and access
If industry and the market are to meet the world’s growing demand for energy in
a sustainable way, governments must set a stable and enduring framework. As
part of this, governments will need to provide secure access for exploration and
development of energy resources, define mutual benefits for resource owners
and development partners, and establish and maintain an appropriate legal and
regulatory environment. Within this framework, we believe that the most effective
means of finding, producing and distributing diverse forms of energy is to foster the
use of markets that are open and competitive, and in which carbon has a price.
Global CO2 emissions from energy
use by region
(billion tonnes CO2)
Non-OECD
OECD
40
30
20
10
1990
2010
2030
Source: BP Energy Outlook 2030.
Global CO2 emissions from energy
use vs GDP and energy
(Index 1970 = 100)
GDP
Energy
CO2
800
700
600
500
400
300
200
1970
1990
2010
2030
Source: BP Energy Outlook 2030.
24 BP Annual Report and Form 20-F 2011
Our organization: Business model
BP’s business model is to create value across
the entire hydrocarbon value chain. This starts
with exploration and ends with the supply of
energy and other products that are fundamental
to everyday life.
BP is one of the world’s leading integrated oil and gas companies.a Our objective
is to create value for shareholders and supplies of energy for the world in a safe
and responsible way. We strive to be a safety leader in our industry, a world-class
operator, a responsible corporate citizen and a good employer.
At each stage of the hydrocarbon value chain there are opportunities for us
to create value – both through the successful execution of activities that are core
to our industry, and through the application of our own distinctive strengths and
capabilities in performing those activities.
We have two main business segments: Exploration and Production, and
Refining and Marketing. Through these, our activities are focused on finding,
developing and producing essential sources of energy, and turning these
sources into products that people need. We provide our customers with fuel for
transportation, energy for heat and light, lubricants to keep engines moving, and
the petrochemicals products used to make everyday items like plastic bottles.
We also invest in renewable energy sources, which we believe will be an
increasing source of value for BP. Our activities are focused on biofuels and wind.
These are managed through our Alternative Energy business, which is reported in
Other businesses and corporate.
Our projects and operations help to generate employment, investment and
tax revenues in countries and communities around the world. The relationships
we form with governments, partners, contractors, customers, franchisees and
suppliers are very important to the success of our business. We are committed to
being responsible, meeting our obligations, and building long-lasting relationships.
As a global group, our interests and activities are held or operated through
subsidiaries, branches, joint ventures or associates established in – and subject
to the laws and regulations of – many different jurisdictions. Our worldwide
headquarters is in London. The UK is a centre for trading, legal, finance and other
business functions as well as three of BP’s major global research and technology
groups. We have well-established operations in Europe, the US, Canada, Russia,
South America, Australasia, Asia and parts of Africa. Around 61% of the group’s
fixed assets are located in OECD countries, including around 37% in the US and
around 18% in Europe.
The significant subsidiaries of the group at 31 December 2011 and the group
percentage of ordinary share capital (to the nearest whole number) are set out in
Financial statements – Note 45 on page 251. For information on significant jointly
controlled entities and associates of the group, see Financial statements – Notes
24 and 25 on pages 215 and 216 respectively.
a On the basis of market capitalization, proved reserves and production.
BP Annual Report and Form 20-F 2011 25
Above When completed in the
second half of 2013, modernization
work at our Whiting refinery should
enable BP to capture additional
margins.
In detail
For more information about
Alternative Energy, see Other
businesses and corporate.
Page 101
In detail
For definitions of subsidiaries,
joint ventures and associates,
see Miscellaneous terms.
Page 4
Business review: Group overview Our organization: Business model
Value creation in our industry
BP’s core activities are similar to those carried out by other global, integrated, oil
and gas companies.
First, we acquire the rights to explore for oil and gas. When we are
successful in finding hydrocarbon resources, we create value by seeking to
develop them into proved reserves or by selling them on if they do not fit with
our strategic objectives. We often work with partners to mitigate risk or gain from
complementary skills. Through disciplined execution of capital projects we then
develop, extract and sell the resources. The benefits are shared with governments
and other partners.
We move oil and gas through pipelines and by ship, truck and rail. We use
our skills and knowledge to find the best routes to deliver supplies to the most
attractive markets.
We manufacture fuels and products, creating value by seeking to operate a
high-quality portfolio of well-located assets safely, reliably and efficiently. We use
our sales and marketing skills to add value to our fuels and other products.
And we also invest in renewable energy sources, with a focus on biofuels
and wind.
2
Developing
and extracting
oil and gas
3
Moving oil
and gas
Selling fuels
and products
5
Investing in
renewable energy
6
4
Making fuels
and products
Integrated model
Finding oil
and gas
1
26 BP Annual Report and Form 20-F 2011
BP’s distinctive capabilities and sources of value
By operating across the full hydrocarbon value chain we believe we can create
more value for shareholders, as benefits and costs can often be shared by our
two segments. We can develop shared functional excellence more efficiently
in areas such as safety and operational risk, environmental and social practices,
procurement, technology and treasury management.
We have a distinctive integrated supply and trading function, which aims
to maximize the value of our production while ensuring our refineries are fully
supplied. We buy and sell at each stage in the value chain to optimize value for
the group, often selling our own production and buying from elsewhere to satisfy
demand from our refineries and customers. The function also creates value
through entrepreneurial trading, where our presence across the major energy
trading hubs of the world provides access to vital information on the fundamentals
of markets that are increasingly connected.
We consider our ability to build a wide range of strong, long-term
relationships to be both a key strength and crucial to our success. We form
partnerships with national oil companies and our international oil company
peers. We partner with universities and governments in pursuit of improving the
technologies available to us, in order to enhance our operations and develop new
products. We also actively participate in industry bodies such as the American
Petroleum Institute and the Marine Well Containment Company in the US and the
Oil Spill Preventions and Response Advisory Group in the UK. Regular review and
audit processes enable us to maintain strong links with contractors and suppliers.
We work with our partners through the management frameworks embedded
in our joint venture and shareholder agreements to ensure safe and reliable
operations, and for our mutual commercial benefit.
Left Employees at
Prudhoe Bay – one
of the 15 North Slope
oilfields that BP
operates in Alaska.
Right During 2011, full
commercial operations
started at Cedar
Creek 2 wind farm in
Colorado.
We believe our development and application of technology represents a
distinctive capability that is central to our reputation and competitive advantage.
For us, technology is the practical application of scientific knowledge to manage
risks, capture business value and inform strategy development. This includes
the research, development, demonstration and acquisition of new technical
capabilities and support for the deployment of BP’s know-how.
We monitor the potential opportunities and risks presented by emerging
science, interdisciplinary innovation and new players; natural resource issues and
climate concerns; and evolving policy concerns, including the current emphasis on
energy security and efficiency.
Our technology advisory council, which is comprised of eminent
technology leaders from business and academia, advises the board and executive
management on research and technology matters.
BP Annual Report and Form 20-F 2011 27
In detail
For more information,
see Technology.
Page 74
Business review: Group overview In detail
For more information on
Exploration and Production,
see BP in more depth.
Page 80
Our organization: Business model
Upstream and midstream – playing to our strengths
Our Exploration and Production segment is responsible for our activities in
oil and natural gas exploration, field development and production; midstream
transportation, storage and processing; and the marketing and trading of natural
gas, including liquefied natural gas, together with power and natural gas liquids.
Our exploration division obtains access to and finds resources at scale in the
world’s key hydrocarbon basins. We are an industry leader in seismic imaging,
a key technology in the identification of potential hydrocarbon resources. Our
developments division develops our hydrocarbon resources, applying effective
project execution and capital efficiency. Our production division then extracts
resources efficiently and maximizes their recovery.
We focus on areas that play to our strengths – deepwater, gas value chains
(including the infrastructure required from field to market) and giant fields. We
are increasing investment with a particular focus on exploration. We actively
manage our portfolio, including divesting assets when we believe they may be
more valuable to others than to ourselves. This allows us to focus our leadership,
technical resources, and organizational capability on the resources we believe are
most likely to flourish in our portfolio.
In 2011, our upstream and midstream activities took place in 30 countries
including Angola, Azerbaijan, Canada, Egypt, Norway, Russia, Trinidad & Tobago
(Trinidad), the UK, the US and other locations within Asia, Australasia, South America,
North Africa and the Middle East. Exploration and Production also includes gas
marketing and trading activities, primarily in Canada, Europe and the US. In Russia,
we have an important associate through our 50% shareholding in TNK-BP, a major oil
company with exploration assets, refineries and other downstream infrastructure.
Upstream technology
flagships
Inherently reliable facilities
Managing and reducing
integrity risk.
Field of the Future®
Applying real-time
data capabilities to
enable safe and efficient
operations.
Advanced seismic imaging
Locating and accessing
new resource through
industry-leading imaging.
Beyond sand control
Maximizing production
and managing risk from
sand-prone reservoirs.
Well advisor
Delivering safe, reliable
and efficient well
operations through the
integration of real-time
data.
Deepwater facilities
Researching and
engineering advanced
equipment for safer, more
reliable deepwater subsea
systems.
Unconventional gas
Recovering gas from
unconventional rocks using
innovative technologies.
Pushing reservoir limits
Growing recovery factors
to maximize resources
from existing oilfields.
Unconventional oil
Developing new technologies
to recover heavy oil.
28 BP Annual Report and Form 20-F 2011
Technology will continue to play a critical role in our upstream activities, as the
upstream technology flagships diagram demonstrates. In addition, our Project
20KTM is a significant new initiative that illustrates how new advances have the
potential to deliver material value. Through this, we are investing in technology to
enable exploration, development and production of reservoirs that were previously
beyond reach due to high reservoir pressures, including those at a pressure
between 15,000 and 20,000 pounds per square inch. Successful deployment
of these technologies would enable us to further develop a number of our
existing resources substantially, and we also see opportunities to develop new
onshore and offshore resources – both as BP and in partnership with national oil
companies.
Downstream – working across our value chains
Our Refining and Marketing segment is responsible for the refining, manufacturing,
marketing, transportation, and supply and trading of crude oil, petroleum,
petrochemicals products and related services to wholesale and retail customers.
We have significant operations in Europe, North America and Asia, and we also
manufacture and market our products across Australasia, southern Africa and Central
and South America. In total we market our products in more than 70 countries.
The segment comprises three main businesses: fuels, lubricants and
petrochemicals. All of our businesses operate as value chains. Previously we
discussed the segment under the headings of fuels value chains and international
businesses, but we now report the value chains by business.
The fuels businesses sell refined petroleum products including gasoline,
diesel and aviation fuel. Within this, the fuels value chains (FVCs) integrate the
In detail
For more information on
Refining and Marketing,
see BP in more depth.
Page 94
Downstream technology
Conversion technology
Conversion of
unconventional
feedstocks, including
renewables, to fuels
and petrochemicals.
Refining technology
Optimizes crude oil selection, utilization
and refinery processing capability to
produce high-quality petroleum products.
End products: fuels, oils, bitumen, coke
M
S
A
U
R
P
K
P
E
T
R
O
C
H
E
M
I
C
A
L
S
Petrochemicals technology
Develops, deploys and optimizes
proprietary technologies to produce
high-value petrochemicals intermediates.
End products: solvents/resins,
plastics, textiles/fibres
R
E
F
I
N
I
N
G
Y
L
U
B
B
P
L
E
T
I
N
G
/
L
E
R
I
C
N
D
I
A
N
N
T
G
S
Lubricants technology
Develops unique lubricants and
high-performance fluids for
transportation and industrial applications.
End products: lubricants
Fuels technology
Develops and
implements new
high-efficiency
fuel products.
End products:
gasoline, diesel,
aviation fuel,
marine fuel
BP Annual Report and Form 20-F 2011 29
Business review: Group overview Our organization: Business model
activities of refining, logistics, marketing, and supply and trading on a regional
basis. This recognizes the geographic nature of the markets in which we compete,
providing the opportunity to optimize our activities from crude oil purchases to
end-consumer sales through our physical assets (refineries, terminals, pipelines
and retail stations). In addition, we operate a global aviation fuels business and an
LPG marketing business, from which we intend to divest the bulk and bottled LPG
marketing operations.
We own or have a share in 16 refineries including five in the US and seven
in Europe. Our focus is on complex, upgraded refineries that are able to process
cheaper feedstocks yet yield more valuable products. We also market fuels
through around 21,800 retail sites, principally in the US, Europe, Australia and
southern Africa. Many of our retail sites are now operated by franchisees with
whom we work in close partnership as we seek to ensure our standards and
brand are consistently applied. We divest assets and businesses when we believe
they will be of greater value to others. In 2011, we announced that we are seeking
buyers for our Texas City refinery; and for our Carson refinery near Los Angeles,
together with its associated integrated marketing business in southern California,
Arizona and Nevada.
Our lubricants business is involved in manufacturing and marketing lubricants
and related services to markets around the world. In 2011, approximately 45% of
our profit from lubricants was generated from non-OECD markets, and we see
good opportunities for further growth in these areas. We market lubricants to the
automotive, industrial, marine, aviation and energy markets. The business blends
and markets lubricants globally through our key brands of Castrol, BP and Aral.
Our strategic relationships with our original equipment manufacturing partners
provide the ongoing collaboration needed to develop the next generation of high-
performance lubricants, such as Castrol EDGE.
Our petrochemicals business operates on a global basis and includes the
manufacture and marketing of petrochemicals that are used in many everyday
products, such as plastic bottles and textiles for clothing. Future growth in our
business is focused on the demand centres of Asia, where our relationships
with joint venture partners are key to our strategy in these increasingly important
markets. From 2012 we plan to create a new revenue stream in petrochemicals
through licensing some of our leading technology.
Above BP is working
with Mendel
Biotechnology to
develop and
commercialize
seed products with
high resistance to
environmental stresses,
such as water and
nutrient limitation.
Left Developed with
Imperial College London,
new Permasense sensors
are helping BP corrosion
engineers to see what is
happening inside pipes.
30 BP Annual Report and Form 20-F 2011
Our organization: People and governance
The people of BP are united by a common code
of conduct and values, and share an aspiration to
make BP a stronger, safer company that makes a
positive difference to the world.
Our board
The board is responsible for the direction and oversight of BP on behalf of
shareholders. As at 31 December 2011, it comprised the chairman, nine non-
executive directors together with the group chief executive; the chief financial
officer and the chief executive of BP’s Refining and Marketing segment.
The executive directors have responsibility for the day-to-day running of BP,
while the non-executive directors bring independent viewpoints and a breadth of
experience, along with insights into how other companies manage key issues.
Five of our current non-executive directors have been appointed since 2010.
Board committees play an increasingly important role. The committees
are: the Gulf of Mexico committee; the safety, ethics and environment assurance
committee; the audit committee; the remuneration committee; the nomination
committee; and the chairman’s committee. In addition, an independent international
advisory board advises our chairman, group chief executive and board on strategic
and geopolitical issues relating to the long-term development of the group.
In 2011, an internal review of risk management systems and processes
was undertaken to enhance clarity, simplicity and the consistency of our risk
management system, from front-line operations through to the boardroom. See
Our management of risk on page 42 for further information. Also in 2011, a new
board steering group completed a review of board governance. The review looked
at the structure, roles, tools and processes involved in board and board committee
work. The findings of the review will inform a new set of board governance
principles, which will be published later in 2012. See Board performance report on
pages 120-133 for further information.
Our employees
We employ approximately 83,400 people (including 14,600 service station staff),
the majority of whom are located in the US and Europe. The Deepwater Horizon
oil spill in 2010 had a profound effect on our employees, and to strengthen and
standardize what we do, we launched a range of internal change projects in 2011.
See How BP is changing on page 36 for more information.
In addition, we are working hard to address a critical issue facing everyone
in our industry – a growing skills gap. This, alongside the increasing demand for
energy products and complexity of projects, means that attracting and retaining
skilled and talented people is vital.
Our leadership has focused on ensuring that appropriate development
opportunities and succession plans are in place to build capability. To supplement
our existing internal capability, we also target experienced and skilled professionals
in the external market and are continuing to increase our intake of graduates to
create a strong internal talent pipeline for the future.
We provide a range of professional development programmes and training
to build capabilities in our people and are committed to creating an inclusive work
environment where everyone is treated fairly, with dignity, respect and without
discrimination.
BP Annual Report and Form 20-F 2011 31
In detail
For more information,
see Corporate governance.
Page 119
Above In 2011, BP
announced the start of
natural gas production
from the Serrette field,
offshore Trinidad.
Below A team at
work in East Texas.
As operator, BP drilled
148 wells across the
US Lower 48 states
in 2011.
In detail
For more information
on employees, see
BP in more depth.
Page 73
Business review: Group overview In detail
For more information on
contractors, see Working
with partners and
contractors.
Page 69
Our organization: People and governance
Contractors and suppliers
Like our peers, BP rarely works in isolation. In 2011, for example, 55% of the
374 million hours worked were carried out by contractors. These individuals play an
important role for BP. During the year we initiated a far-reaching review of the way
we work with third parties, particularly those involved in potential high-consequence
activities. We are now implementing a range of measures based on our findings,
with a focus on six key themes: consistent standards and priorities; fewer suppliers
to enable deeper, longer-term relationships; detailed and systematic selection of
contractors; clear and specific contracts; intensive oversight and verification; and
assurance that supplier personnel are competent.
Our values
“Our approach is built on respect, being consistent and having the courage to do
the right thing. We believe success comes from the energy of our people. We
have a determination to learn and to do things better. We depend upon developing
and deploying the best technology, and building long-lasting relationships. We are
committed to making a real difference in providing the energy the world needs
today, and in the changing world of tomorrow. We are one team – a group of diverse
individuals from around the world united by shared values and a drive to rebuild BP.”
These words, taken from the BP code of conduct, capture what we strive
to stand for as a company – our renewed values. They are an expression of work
done across BP in 2011 to define and renew our principles and values. This work
was carried out in response to the events of recent years, which have caused us
to reflect on what is important and how we do what we do.
We launched our renewed values in 2011. They represent the qualities and
actions we wish to see in BP, and those that BP already demonstrates when it is
at its best. The values are aligned with our code of conduct and are there to guide
the way we do business and the decisions we take, every day. Safety has been
re-emphasized as our number one priority.
Left In 2011, we purchased
10 blocks in Brazil from Devon
Energy. Here, a worker on the
Deep Ocean Clarion moves
drilling pipes on to the rig.
Above Technicians on board
the Jack Ryan drilling ship,
Angola. In 2011, BP gained
access to five new deepwater
blocks, offshore Angola.
32 BP Annual Report and Form 20-F 2011
In detail
Find out more online.
bp.com/values
The values are much more than words – we are actively seeking to embed these
values at the heart of the systems and processes we are introducing to unify
and strengthen our business. We are both enforcing and incentivizing values-led
behaviour. For example, our updated performance and reward system, which
came into effect on 1 January 2012, now creates an explicit link between our
values and the way individuals are judged and rewarded within BP.
Our values
Safety
Respect
This statement of our values
expresses our aspirations and
intentions for BP, as we work
together to strengthen safety and
risk management, earn back trust
and create value. Our values are
aligned with, and an extension of,
our code of conduct.
Safety is good business.
Everything we do relies upon
the safety of our workforce
and the communities
around us. We care about
the safe management of
the environment. We are
committed to safely delivering
energy to the world.
Excellence
Courage
We are in a hazardous
business, and are committed
to excellence through the
systematic and disciplined
management of our
operations. We follow and
uphold the rules and standards
we set for our company. We
commit to quality outcomes,
have a thirst to learn, and to
improve. If something is not
right, we correct it.
What we do is rarely easy.
Achieving the best outcomes
often requires the courage
to face difficulty, to speak
up and stand by what we
believe. We always strive to
do the right thing. We explore
new ways of thinking and are
unafraid to ask for help. We
are honest with ourselves, and
actively seek feedback from
others. We aim for an enduring
legacy, despite the short-term
priorities of our world.
We respect the world in
which we operate. It begins
with compliance with laws and
regulations. We hold ourselves
to the highest ethical standards
and behave in ways that earn
the trust of others. We depend
on the relationships we have
and respect each other and
those we work with. We
value diversity of people and
thought. We care about the
consequences of our decisions,
large and small, on those
around us.
One Team
Whatever the strength of the
individual, we will accomplish
more together. We put the
team ahead of our personal
success and commit to
building its capability. We trust
each other to deliver on our
respective obligations.
Our code
The BP code of conduct sets the standard that we all work to. It is aligned with
our values, group standards and legal requirements, and it clarifies the ethics and
compliance expectations for everyone who works at BP. The code was updated
in 2011 and now puts greater emphasis on a values-based approach. Where
rules are not stated explicitly, our everyday business decisions will be guided by
our values.
BP Annual Report and Form 20-F 2011 33
Business review: Group overview Our organization: Where we operate
2011 saw BP streamline its operational footprint
through divestments while increasing new access
to resources. The map below shows the group’s
key operating sites in 2011.
Key to map
Exploration and Production
BP subsidiary.
Equity-accounted entity.
Assets held for sale at the end
of 2011.
These shaded areas indicate new
access success in 2011.
Refining and Marketing
BP refinery (wholly or partly owned).
Petrochemicals site(s) (wholly or
partly owned).
Proposed for disposal by the
end of 2012.
These shaded areas indicate the
approximate coverage of BP’s
integrated fuels value chains.
Lubricants and aviation marketing activity
is not reflected on this map.
Alternative Energy
Operational assets.
Technology assets.
BP group headcount by region
(including service station staff)
Africa (2,700)
Asia (10,800)
Australasia (9,400)
Europe (31,800)
North America (24,600)
South America (4,100)
34 BP Annual Report and Form 20-F 2011
BP Annual Report and Form 20-F 2011 35
Business review: Group overview Our organization: How BP is changing
Following the tragic events in the Gulf of Mexico
in 2010, we initiated a wide-ranging programme
designed to enhance safety and risk management
within the group, earn back trust and restore value.
Much was achieved in 2011, but there is a great
deal more to do.
Safety and
operational risk
Risk management
review
Upstream
restructuring
Values and
behaviours
We are strengthening our
group-wide application
of enhanced, consistent
standards driven by our
safety and operational
risk function, which is
independent from the
business segments.
We are enhancing the clarity,
consistency and quality of
the way risks are understood,
reported and acted upon,
from front-line operations
to the boardroom.
We restructured to create
three global divisions –
exploration, developments
and production. These
constitute the biggest
changes in BP’s upstream
business for 20 years.
We have refreshed our
values and behaviours and
continue embedding these
into how we work together.
In detail
See Safety, page 65
In detail See Our management
of risk, page 42
In detail See Exploration and
Production, page 80
In detail
See Our values, page 32
Individual
performance
and reward
We have aligned
performance and reward
with our values and
introduced ‘safety’ and
‘taking a long-term
perspective’ as key
indicators.
Contractor
management
Technology
We are driving consistent
global standards,
strengthening verification and
assurance, and developing
longer-term relationships
with contractors.
Through technology, we are
strengthening our capability
to manage risks, capture
business value and inform
strategy development.
Joint ventures
not operated
by BP
We initiated a review into our
approach to the management
of our relationships with
significant non-operated
joint venture operators and
partners. This work includes
safety and operational risk
as well as bribery and
corruption risk.
In detail
See Our values, page 32
In detail See Working with
partners and contractors, page 69
In detail
See Technology, page 74
In detail See Our partners in joint
ventures, page 69
36 BP Annual Report and Form 20-F 2011
Our strategy
In 2011, we put forward a clear 10-point plan that
defines what you can expect from us, and what
you will be able to measure, through to 2014.
Following the tragic Deepwater Horizon oil spill, we set out a strategy designed to
deliver stability, and restore trust and value. Our first priority was to work to make
BP a safer, more risk-aware business. We pursued that strategy with purpose
through 2011 and have now laid out a 10-point plan for BP’s future.
Our renewed strategy is designed to make BP a simpler, stronger company
that plays to its strengths. It concentrates our distinctive talents on high value,
advantaged assets, with new and enhanced structures, process and discipline
serving to support and sustain our businesses and operations. Our goal is to grow
operating cash flows to enable us to both invest for future growth and increase
distributions to shareholders.
Our upstream strategic focus is aligned with what we see as the five key
drivers of value growth in our operations. These are: managing risk; increasing
investment, with a particular focus on exploration; managing our portfolio actively;
growing operating cash faster than production; and focusing on the major growth
engines that capitalize on our strengths – deepwater, gas value chains and giant
fields.
In the downstream, we are in the business of hydrocarbon value chains, and
with an intense focus on safe and reliable operations, we believe we now have
the platform to sustain and grow a world-class business capable of generating
leading returns and cash flow growth.
Below BP has a
significant presence
in Trinidad & Tobago,
operating 13 offshore
platforms and holding an
interest in Atlantic LNG.
Above Having achieved our
improved production target
in 2010, BP and partners are
working to refurbish the
wells and facilities at the
Rumaila field in Iraq.
BP Annual Report and Form 20-F 2011 37
Business review: Group overview Our strategy: Strategic priorities
Our 10-point plan
Our 10-point plan is how we intend to build a stronger, safer BP. The first five points
are things you can expect from us; the second five are things you can measure.
What you can expect from us
1 We will keep a relentless focus on safety and managing risk
We are determined that BP will deliver world-class performance in safety, risk
management and operational discipline. We will be a company that systematically
applies our global standards as a single team.
2 We will play to our strengths
We have had major successes at finding oil and gas at scale. We are also among
the real pioneers of deepwater exploration. We have decades of experience
managing giant fields and developing valuable gas value chains. We have built
a world-class downstream business. Underpinning these strengths are deep
capabilities in building relationships and in developing technologies.
Left BP moves gas
from 6,000 metres
below the Shah Deniz
field in Azerbaijan to
markets in Western
Europe, 3,000
kilometres away.
Right As part of a
$1.2 billion investment
announced in 2011,
the Kinnoull reservoir,
UK North Sea, will be
connected to BP’s
Andrew platform.
3 We will be stronger and more focused
We intend to be a stronger and more focused BP, with a base of assets that is
high graded and high performing.
4 We will be simpler and more standardized
Our organization is already much more standardized than it was before the
Deepwater Horizon oil spill. The transformation of our Exploration and Production
segment from a regional business to one that is managed along lines of functional
expertise is an example of this. Our footprint is smaller, with fewer assets and
operations in fewer countries. Our internal reward and performance processes are
more streamlined. This should drive better and more sustainable performance in
safety, quality and efficiency, with less variation.
5 We will improve transparency through our reporting
We will improve transparency in the reporting of our business segments. We now
break out the numbers of certain parts of our businesses, such as lubricants and
petrochemicals in the downstream. From the first quarter of 2012, the group’s
investment in TNK-BP will be reported as a separate operating segment.
38 BP Annual Report and Form 20-F 2011
What you can measure
6 Active portfolio management
We want to focus our portfolio further on our areas of strength, and deliver
increased financial flexibility. By the end of 2013, we expect to have
completed $38 billion of disposals since the start of 2010.
7 New projects with higher margins
We have a strong list of upstream projects due to come onstream over the
next three years. By 2014, unit cash marginsa on production from this new
wave of projects are expected to be around double our existing average.b
8 Operating cash flow growth
We are aiming to generate an increase of around 50% net cash provided by
additional operating activities by 2014 compared with 2011c – approximately
half from ending Deepwater Horizon Oil Spill Trust fund payments and
around half from operations.
9 Use of cash flow for reinvestment and distributions
We will use additional operating cash prudently. We want to use around half
for increased investment in our project inventory for growth, and around half
for other purposes. This may include increased distributions to shareholders
through dividends or share buybacks or repayment of debt.
10 Strong balance sheet
We intend to enhance the strength of our balance sheet by targeting our
level of gearingd at the lower half of the 10-20% range over time.
a Unit cash margin is net cash provided by operating activities for the relevant projects in our Exploration
and Production segment, divided by the total number of barrels of oil and gas equivalent produced for the
relevant projects. It excludes dividends and production for TNK-BP.
b Assuming a constant oil price of $100 per barrel.
c Assuming an oil price of $100 per barrel in 2014. The projection reflects our expectation that all required
payments into the $20-billion trust fund will have been completed by the end of 2012. It does not reflect
any cash flows relating to other liabilities, contingent liabilities, settlements or contingent assets arising
from the Gulf of Mexico oil spill which may or may not arise at that time. We are not able to reliably
estimate the amount or timing of a number of contingent liabilities. See Financial statements – Note 43 on
page 249 for further information.
d Gearing refers to the ratio of the group’s net debt to net debt plus equity and is a non-GAAP measure. See
Financial statements – Note 35 on page 230 for further information including a reconciliation to gross debt,
which is the nearest equivalent measure on an IFRS basis.
Operating cash flow momentum
2011 operating
cash estimate
at oil price of
$113/bbl.
Completion of
contributions to
the $20-billion
trust fund.
Operational
restoration
and growth.
Divested
operations
and
environment.
2014 operating
cash estimate
at oil price
of $100/bbl.
Left Lingen refinery in
Germany is one of Europe’s
most complex refineries due
to its ability to fully upgrade
crude during processing.
BP Annual Report and Form 20-F 2011 39
Business review: Group overview Our strategy
A stronger, safer BP
We have set out a series of milestones by which
our progress can be tracked. These milestones
mark our aspirations, plans and intended progress
over the next three years.
At the Cherry Point refinery,
BP is investing in a clean
diesel project to produce
cleaner burning fuels that
will comply with new lower-
sulphur specifications.
40 BP Annual Report and Form 20-F 2011
B
B
u
u
s
s
i
i
n
n
e
e
s
s
s
s
r
r
e
e
v
v
i
i
e
e
w
w
:
:
G
G
r
r
o
o
u
u
p
p
o
o
v
v
e
e
r
r
v
v
i
i
e
e
w
w
2012
We see the full benefits of our 2011
turnarounds as high-margin production
comes back onstream in Angola, the
North Sea and elsewhere.
Exploration drilling activity increases
to 12 wells.
Six major upstream project start-ups.
Eight rigs expected to be operating in
the Gulf of Mexico.
Completion of our payments into the
Deepwater Horizon Oil Spill Trust.
$2 billion of financial performance
improvementa in Refining and
Marketing since 2009.
2013-14
Drilling up to 25 wells per year.
A further nine major upstream project
start-ups.
Unit operating cash marginsc from new
upstream projects in 2014 expected to
be double the 2011 average.d
We bring onstream the major upgrade
to the Whiting refinery in the second
half of 2013.
We complete our $38-billion
divestment programme by the end
of 2013.
We have a high value, focused portfolio
that plays to our strengths.
Organic capital expenditureb increases
to around $22 billion.
Overall operating cash flow in 2014 to
increase by 50% compared with 2011.e
a Refining and Marketing’s ‘performance
improvement’ is a non-GAAP measure.
See footnote a on page 95 for further information.
b Organic capital expenditure excludes acquisitions
and asset exchanges.
We expect to use around half of the
extra cash for increased investment
and around half for other purposes,
including increased distributions to
shareholders.
c See footnote a on page 39.
d See footnote b on page 39.
e See footnote c on page 39.
BP Annual Report and Form 20-F 2011 41
Our management of risk
Putting safety and risk management at the heart
of the company is the foundation for building trust
and creating value. In 2011 we began a process
to review, refresh and enhance our management
of risk.
The role of the board
The board is responsible for the direction and oversight of BP as set out in its
governance principles, which include that it will satisfy itself that the material
risks to BP are identified and understood and that systems of risk management,
compliance and control are in place to mitigate such risks. The board, through
its governance principles, requires the group chief executive to operate with a
comprehensive system of controls and internal audit to identify and manage the
risks that are material to BP. See Risk management: from operations to the board
on page 122.
Our system of internal control
The system of internal control comprises the holistic set of management systems,
organizational structures, processes, standards and behaviours that are employed
to conduct the business of BP. The system is designed to meet the expectations
of internal control of the Corporate Governance Code in the UK and of COSO
(Committee of Sponsoring Organizations of the Treadway Commission) in the US.
Key elements of the system include: the control environment; the
management of risk and operational performance; and the management of people
and individual performance. As such, BP’s risk management system is an integral
part of our system of internal control, and is designed to be a simple, consistent
and clear framework for managing and reporting all risk from the group’s
operations to the board.
Review of risk management
In 2011, we initiated a review of our risk management system. The review
considered the group’s existing risk management system, along with good
practices in risk management from outside the company, with a view to
identifying what might be done to enhance the clarity, simplicity and consistency
of our risk management system.
Using the findings of this review, we have begun implementing
enhancements to the way we manage and report risks. This has involved the
development of common language, concepts and templates for consistent
reporting on risks and risk management; designing enhancements to board and
executive processes; and greater alignment of risk management activities and
business processes. These improvements build from our existing management
systems, standards and practices and we will continue to embed these in 2012.
See the information on Safety and operational risk on page 65 for examples of
enhancements to the S&OR function and management of safety and operational
risks.
42 BP Annual Report and Form 20-F 2011
Our risk management system
Our enhanced risk management system focuses on three levels of activity:
• First, the system helps facilitate day-to-day risk management in the group’s
operations and functions, with the approach varying according to the types of
risk we face. Risks are to be identified and managed, and actions to improve the
management of risk are to be put in place where necessary. Our aim is to address
each different type of risk as well as we can – promoting safe, compliant and
reliable operations.
• Second, for our businesses and functions, risks arising are to be collated
periodically, risk management activities are to be assessed, and any necessary
further improvements or actions are to be planned. The system is designed
to facilitate this by incorporating a standardized form that we call the risk
management report (RMR) for businesses and functions to report consistently
the risks they face for management consideration, challenge, resource allocation
and intervention.
Left Operations at BP’s
Shah Deniz platform,
Azerbaijan. Located
offshore, 40 miles
south east of Baku,
Shah Deniz is thought
to hold 1 trillion cubic
metres of gas.
Right BP’s state-of-the-
art Houston monitoring
centre provides real-
time communications
between rigs in the
Gulf of Mexico and
experts based onshore.
• Third, the system facilitates executive and board oversight and governance over
the management of significant risks. It requires executive team level involvement
in the finalization of risk management activities and improvement plans for
the group’s most significant individual risks. Using the consistent bottom-up
risk identification and assessment process, coupled with top-down executive
overview, the system requires that the most significant risks requiring oversight
are identified. Oversight of the management of these risks is to be provided
through regular review by the board or one of its committees.
Drawing on this input, our enhanced risk management system assists us in our:
• Understanding of the risk environment for input into our strategy.
• Understanding of which risk types we operate with, given our strategy.
• Identification and assessment of actual specific risks and the potential exposure
they may represent.
• Decision-making on how best to deal with those risks to manage our overall
potential exposure.
• Active management of identified risks.
• Reporting to management and the board about how those risks are managed,
and monitoring of our potential exposure.
• Obtaining of assurance over the effectiveness of the management of those risks.
• Interventions for improvements in the management of those risks where
necessary.
• Consideration of the effect of the external environment and our business
activities on the principal activities of our risk management system.
BP Annual Report and Form 20-F 2011 43
Business review: Group overview Our management of risk
During 2011, functions, strategic performance units, divisions and segments
within BP were requested to prepare RMRs using the new, common approach.
This helped provide an overall data set of the key risks identified, an assessment
of their potential impact and likelihood on a consistent basis, information on how
they are being managed and any actions planned or in progress to improve the
management of risk. Based on these RMRs, together with additional executive
overview, a single group RMR has been prepared. Those risks identified on the
group RMR as requiring particular group-level oversight in the coming year have
been allocated to specific board and executive committees for oversight and
monitoring. These are discussed below. Also see Risk factors on pages 59-63
for a description of the material risks we face in our business.
Risk management can also be a foundation for creating value. The
willingness to take and appropriately manage certain risk is fundamental to the
success of any commercial enterprise. For example, in our upstream business
we consciously place significant amounts of capital at risk in exploring for new
hydrocarbon resources. Where this exploration is successful, we would generally
expect it to lead to future increases in our proved reserves and future cash flows.
However, exploration expenditure may not yield adequate returns, for example in
the case of unproductive wells or discoveries that prove uneconomic to develop.
Safety and operational risk function
We have redefined and strengthened the scope and accountabilities of the
group function for safety and operational risk (S&OR), creating a new team
independent of business line management to drive safe, compliant and reliable
operations in BP. The S&OR function, which continues to build towards its
full staffing complement, includes S&OR teams which have been formed to
work alongside line management but are independent of them. In pursuit of
safe, compliant and reliable operations, S&OR personnel can assist, challenge
and escalate or intervene as necessary to promote and assure the operating
businesses’ systematic and disciplined application of global standards on safety
and operational risk. The function helps provide assurance as to whether line
operations are carried out in accordance with the group’s operating management
system, and seeks to facilitate more comprehensive and assured S&OR risk
action plans for operational units, more incisive interventions on emerging risk
situations, and improved investigations and learning from significant incidents.
How we seek to manage our risks
The following is a summary of how we seek to manage the risks we have
identified as having a high priority in 2012. There can be no guarantee that our
risk management activities will mitigate or prevent these, or other, risks from
occurring.
Strategic risks
In response to risks associated with the general macroeconomic outlook and
changes in prices and markets, we monitor early warnings from our treasury
team and customer-facing businesses. To manage our liquidity, financial capacity
and financial exposure risks, we apply our financial framework (see Liquidity
and capital resources on page 103) and we conduct liquidity stress testing and
scenario-planning interventions.
Above BP’s Cooper River
petrochemicals plant in
South Carolina operates
two PTA units. PTA is
used in the production of
plastic bottles.
Below Working with Falex
Corporation, Air BP has
developed a faster and
more reliable way to test
aviation lubricants.
44 BP Annual Report and Form 20-F 2011
Our current strategic priorities are set out in our 10-point plan (see pages
38-39). Among other things, this aims to target investments and disposals
efficiently, renew and reposition our portfolio and deliver our major projects to
plan. As part of managing the risks to delivery of the 10-point plan we conduct
regular planning and performance-monitoring activity, including the planning
of disposals; we focus on the delivery of major projects; and we pursue the
development of continued technological advances and innovation.
The diverse locations of our operations around the world exposes us to a
wide range of political developments and consequent changes to the economic
and operating environment. For example, our investments in Russia could be
adversely affected by heightened political and other environment risks. As such,
we try to actively manage our relationships in Russia, including with the Russian
federal government and with TNK-BP. We also seek to manage the group’s
exposure in Russia through our development of BP’s overall portfolio.
Many of our major projects and operations are conducted through joint
ventures or associates and through contracting and sub-contracting arrangements
where BP may not have full operational control. We seek to manage such joint
venture and contractor relationships actively, and this may include monitoring
compliance with applicable standards.
As a result of the Deepwater Horizon oil spill there is significant uncertainty
regarding the extent and timing of costs and liabilities relating to the incident,
the impact of the incident on our reputation and the resulting possible impact on
our licence to operate including, among other things, our ability to access new
opportunities. In addressing these risks we seek to co-operate with investigators
and we encourage the application of responsible and objective scientific analysis
in determining outcomes. We always seek to comply with local regulations and,
in some cases, our required practices will exceed regulations if our assessment
of the operating risk indicates it would be beneficial to do so. We seek to engage
with local communities in order to foster improved relationships and reputation.
Left Bernard Looney, BP’s
Executive Vice President,
Developments, on board
the Deep Ocean Clarion
rig in Brazil.
Above Work at BP’s
Tangguh facility, West
Papua, Indonesia; where
gas is collected and
distributed to energy
markets via ship.
BP Annual Report and Form 20-F 2011 45
Business review: Group overview Our management of risk
Safety and operational risk
The nature of the group’s operations exposes us to a wide range of significant
health, safety and environmental risks such as incidents associated with the
drilling of wells, operation of facilities, transportation of hydrocarbons and product
quality. In addressing these risks we seek to apply our operating management
system (OMS) including group and engineering technical practices as applicable.
We seek to conduct maintenance and equipment testing and to apply product
quality control and testing procedures. We also provide our staff with training and
competency development. To better manage the risks inherent in drilling wells
where we are the operator, we conduct activity through a global wells organization
that is accountable for systems and processes for designing, constructing and
managing wells. See Safety on page 66 for information on the recommendations
of BP’s internal investigation into the Deepwater Horizon oil spill and the actions
we are pursuing to address them.
Security threats require continuous oversight and control as hostile
actions against our staff, our activities and our digital infrastructure (cyber
security) could cause harm to people and could disrupt our operations. We have
procedures that are intended to monitor for threats and vulnerabilities. We also
maintain business continuity plans.
Crisis-management plans are developed to help us to respond effectively
to emergencies and to avoid a potentially severe disruption in our business and
operations. For deepwater drilling, interim requirements for oil spill preparedness
and response, including crisis management response capability, were introduced
in 2011 in the Gulf of Mexico. The intention is to build on these interim
requirements to put in place group-wide practices for both oil spill preparedness
and response and crisis management.
Successful recruitment and development of staff is central to our plans.
We have programmes to recruit both graduates and experienced staff and
we maintain succession plans for key roles. We also operate training and
development programmes, including relating to leadership, and we engage all
employees in regular performance-management processes.
Compliance and control risk
Ethical misconduct or breaches of applicable laws or regulations could be
damaging to our reputation, results of operations and shareholder value and
could affect our licence to operate. Central to managing these risks is our code
of conduct (see page 31), the requirements of which apply to all employees,
supported by our various group standards covering issues such as anti-bribery and
corruption, anti-money laundering and competition/anti-trust law compliance. We
seek to monitor for new regulations and legislation and plan our response to them.
We also operate a range of compliance training and monitoring programmes for
our employees.
In the normal course of business, we are subject to risks around our
treasury and trading activities, which could arise from shortcomings or failures
in our systems, risk management methodology, internal control processes
or employees. In addressing these risks, we have adopted specific operating
standards and control processes, including guidelines in relation to trading, and
seek to monitor compliance through dedicated compliance and risk organizations.
We also seek to maintain a positive and collaborative relationship with regulators
and the industry at large.
In detail
For more information
on OMS, see Safety.
Page 65
46 BP Annual Report and Form 20-F 2011
Our performance
2011 was a year of further stern tests for BP. Our
challenge was to stabilize the company and meet
our commitments in the Gulf of Mexico while
laying firm foundations for the future.
We went into 2011 with a clear set of strategic priorities and determination to
rebuild the company. Our employees have worked to make BP a safer business
and to earn back trust. We also pushed forward on the journey to grow value over
the short, medium and long term. The key measures in this section show our
progress in numbers, and here you can also read about some of the significant
actions and events that defined our year.
Left The BP-Husky
refinery in Toledo,
Ohio – in operation
since 1919.
Right Azeri-Chirag-
Guneshli is the
largest oilfield under
development in the
Azerbaijan sector of
the Caspian basin.
In detail
For more information,
see Safer drilling.
Page 66
Safety
Our safety and operational risk function (S&OR) is driving the systematic and
disciplined application of global standards in safety and operational risk across the
company. We recruited 87 new employees into S&OR during the year, taking its
total headcount to around 600 against a target headcount of 800.
During the year, as part of our enhanced focus on safety and operational risk
management, we completed a programme of 47 major upstream turnarounds.
We set enhanced voluntary standards for how we drill in the Gulf of
Mexico, and implemented new global standards in our operations worldwide.
For example, in deepwater drilling, where we use drill rigs that are maintained in
position by computer-controlled systems rather than fixed moorings, we require
BP-contracted drill rigs to have no fewer than two blind shear rams and a casing
shear rama in order to provide additional assurance.
We initiated a review of the way we work with contractors and other
industry partners. Guided by our findings, we have implemented a range of new
measures, starting with our offshore rigs. We also reviewed and updated our
system of risk management – see Our management of risk on pages 42-46.
And we reviewed and updated our values and behaviours, linked them explicitly
to an enhanced code of conduct and embedded them in our approach to safety,
performance management and reward.
a Shear rams are devices within a blowout preventer designed to cut the drill pipe and seal the well in the
event of a blowout or other operational emergency.
BP Annual Report and Form 20-F 2011 47
Business review: Group overview Our performance
Our upstream business is now reorganized into three divisions – exploration,
developments and production. We have also reorganized our drilling operations
into a single global wells organization (GWO), which forms part of the
developments division and takes a consistent, global approach to managing risk.
GWO has implemented a number of standard processes since its formation,
covering activities such as rig start-up and well cementing.
Trust
Released in January 2011, the report of the National Commission on the BP
Deepwater Horizon Oil Spill and Offshore Drilling identified certain failures of
management and decision-making within BP and its contractors, as well as
regulatory failures, to be contributing factors to the accident. See Safety on
page 65 and Legal proceedings on pages 160-166 for information on other
investigations and reports. We are committed to working with government
officials and other operators and contractors to identify and implement operational
and regulatory changes that will enhance safety practices throughout the oil and
gas industry. BP teams have travelled to 25 countries to share the lessons learned
from events in the Gulf of Mexico with our industry, regulators and governments.
We also shared equipment and technology developed during the response with
the Marine Well Containment Company in the US.
On the ground, the focus of our work in the Gulf of Mexico shifted from
response to recovery. The majority of the clean-up work required along the
shoreline has now been completed. We are encouraged by local and state reports
that indicate tourism in many areas of the region is rebounding. And all federal
commercial fishing areas had been reopened by April 2011. We are still at work on
the recovery and remain committed to meeting our responsibilities in the region.
By the end of 2011, we had paid $15.1 billion into the $20-billion Deepwater
Horizon Oil Spill Trust fund (Trust) set up to meet the costs of the spill. In total, the
Trust and BP had paid a total of $7.8 billion in claims, advances and other payments
by the end of 2011.
Value
Our profit in 2011 was $25.7 billion compared with a loss of $3.7 billion in 2010.
After adjusting for inventory holding gains, our replacement cost profita in 2011
was $23.9 billion compared with a loss of $4.9 billion in 2010. Cash and cash
equivalents at the end of 2011 totalled $14.1 billion and our net debt ratiob was
20.5%. See Financial review on pages 56-58 for further information on the group’s
financial results.
During 2010 and 2011 combined, we strengthened the group’s financial
position by completing asset sales totalling almost $20 billion and we have
announced our intention to make further disposals that would bring the total to
$38 billion by the end of 2013. Previously this disposal target had been set at
$45 billion, however it was reduced in November 2011 when we received notice
of termination from Bridas Corporation of the agreement for their purchase of
BP’s 60% interest in Pan American Energy LLC. We intend to reduce our net
debt ratio to the lower half of the 10-20% range over time. During 2011 we
reached settlements with MOEX USA Corporation (MOEX), Weatherford U.S.,
L.P. (Weatherford), Anadarko Petroleum Corporation (Anadarko) and Cameron
International Corporation (Cameron) totalling $5.5 billion related to the Deepwater
Horizon oil spill. All cash received has been paid to the Trust.
a Replacement cost profit or loss for the group is not a recognized GAAP measure. The equivalent measure
on an IFRS basis is ‘Profit (loss) for the year attributable to BP shareholders’. See footnote b on page 56 and
page 110 for further information.
b Net debt ratio is a non-GAAP measure. See Note 35 on page 230 for the equivalent measure on an
IFRS basis.
In detail
For more information
on the Gulf of Mexico
oil spill, see BP in
more depth.
Page 76
48 BP Annual Report and Form 20-F 2011
Left BP employees
at work in Prudhoe
Bay, Alaska – the
largest oilfield in North
America and among
the 20 largest fields
ever discovered.
Right Operations on
the BP-operated
Atlantis PQ, Gulf of
Mexico – the deepest
moored semi-
submersible platform in
the world when it was
installed in 2007.
Exploration and Production
Replacement cost profit
before interest & taxa
US
Non-US
Average hydrocarbon
realizations ($/boe)b
$ billion
40
30
20
10
$/boe
80
60
40
20
2007
2008
2009
2010
2011
a See Financial statements – Note 6 on page 200.
b Based on sales of consolidated subsidiaries
only – this excludes equity-accounted entities.
Total net proved reserves 2011a
(million barrels of oil equivalent)
10,565
7,183
Liquidsb
Natural gasc
a Combined basis of subsidiaries and
equity-accounted entities, on a basis
consistent with general industry practice.
b Liquids comprise crude oil, condensate, natural gas
liquids and bitumen and include totals of 5,153 million
barrels for subsidiaries and 5,412 million barrels for
equity-accounted entities.
c Natural gas is converted to oil equivalent at 5.8 billion
cubic feet (bcf) = 1 million barrels and includes
6,273 million barrels of oil equivalent for subsidiaries
and 910 million barrels of oil equivalent for
equity-accounted entities.
On 3 March 2012, we announced we had reached a settlement with the
Plaintiffs’ Steering Committee (PSC), subject to final written agreement and
court approvals, to resolve the substantial majority of legitimate economic loss
and medical claims stemming from the Deepwater Horizon accident and oil spill.
The PSC acts on behalf of individual and business plaintiffs in the Multi-District
Litigation proceedings pending in New Orleans (MDL 2179). We estimate that
the cost of the proposed settlement would be approximately $7.8 billion, but with
no net impact on either the income or cash flow statements, since the proposed
settlement is expected to be payable from the $20-billion Trust. While this is
BP’s reliable best estimate of the cost of the proposed settlement, it is possible
that the actual cost could be higher or lower than this estimate depending on the
outcomes of the court-supervised claims processes. See Legal proceedings on
page 162 for further information.
Exploration and Production
The replacement cost profit before interest and tax for 2011 was $30,500 million,
compared with $30,886 million for the previous year. See Exploration and
Production on page 80 for further information on the segment’s financial results.
Our production was lower than in 2010 due to divestments, the suspension
of drilling in the Gulf of Mexico and the high number of turnarounds and
maintenance projects undertaken during the year. However, production began to
increase from the fourth quarter with the completion of turnarounds in the North
Sea, Angola and the Gulf of Mexico. Also, two new major projects were brought
onstream during the year – the BP-operated Serrette field in Trinidad and the
Pazflor field in Angola, operated by Total.
We had our best year for a decade in terms of access to new upstream
opportunities, with awards for a total of 55 new exploration licences. We also
gained approval for our exploration plan for the Kaskida field in the Gulf of Mexico
– our first drilling permit for an exploration well in the US since the Deepwater
Horizon oil spill.
In India, we completed a transaction that brings us into a unique relationship
with Reliance Industries and access to 21 oil and gas blocks which covered
approximately 83,000 square miles (216,000 square kilometres). In November
2011 we formed a 50:50 gas marketing joint venture to source and market gas.
In Russia, our plans to form a strategic alliance with Rosneft did not reach
fruition. Nonetheless, we remain committed to Russia and the ongoing success
of TNK-BP, which comprises 27% of our reserves and 29% of our production.
In Brazil, we acquired assets from Devon Energy, giving us a material
position in one of the great deepwater provinces of the world. We started
upstream operations during the year.
BP Annual Report and Form 20-F 2011 49
Business review: Group overview Refining and Marketing
Replacement cost profit
before interest & taxa
Fuels
Lubricants
Petrochemicals
BP average refining marker margin ($/bbl)
$ billion
10
8
6
4
2
0
-2
$/bbl
20
16
12
8
4
0
2007
2008
2009
2010
2011
a See Financial statements – Note 6 on page 200.
See also Financial and operating performance on
page 94.
Our performance
In the UK North Sea, we announced plans for investments totalling approximately
$14 billion – with our partners – in major new project developments.
In Iraq, working with our partners in the Rumaila Operating Organization,
we met a major milestone in reaching initial production targets agreed for the
Rumaila field.
Refining and Marketing
Replacement cost profit before interest and tax for 2011 was $5,474 million
compared with $5,555 million in 2010. Strong refinery operations enabled us to
capture the benefits of BP’s location advantage in accessing WTI-based crude
grades and, compared with 2010, the result also benefited from a higher refining
margin environment and a stronger supply and trading contribution. These
benefits were partly offset by a significantly higher level of turnarounds in 2011
than 2010 and negative impacts from the increased relative sweet crude prices in
Europe and Australia, primarily caused by the loss of Libyan production, and the
weather-related power outages in the second quarter. See Refining and Marketing
on page 94 for further information on the segment’s financial results.
Operating performance was strong, with Solomon refining availability of
94.8% and utilization rates above the industry average. We made significant
progress on the modernization of our Whiting refinery in the US, which is expected
to come onstream in the second half of 2013. This project will significantly increase
the capability of the refinery to process heavy crude and provide it with access to
crude from the Gulf of Mexico, the mid-continent US and Canada.
We achieved strong performance in our lubricants business, despite
a difficult marketing environment and increasing base oil prices. In our
petrochemicals business we received local government approval for our proposed
1.25 million tonnes per annum purified terephthalic acid (PTA) plant in Zhuhai,
China, and are now seeking final central governmental approval.
Left Air BP is one of
the world’s largest and
best-known aviation
fuels suppliers.
Above The SECCO
facility is BP’s single
largest investment in
China and has a capacity
of 3.2 million tonnes
of petrochemicals
per year.
50 BP Annual Report and Form 20-F 2011
We continued to sell non-core assets, and we are progressing with our intention
to divest about half of our US refining capacity. We completed the divestment of
non-strategic terminals and pipelines in the US East of Rockies and West Coast,
and of our fuels marketing businesses in several African countries.
In addition, in February 2012 we announced our intent to sell our bulk and
bottled LPG marketing businesses in nine countries.
Looking ahead
We believe our actions and achievements in 2011 brought BP to a turning point.
As we move into 2012, our operations are regaining momentum and we have a
clear strategy for value creation. Maintaining our absolute commitment to safety,
our intention is to build on our strengths so we can grow operating cash flows,
invest for future growth and increase returns to shareholders.
BP Annual Report and Form 20-F 2011 51
Business review: Group overview Our performance
We track performance against key financial
and non-financial indicators. This year, in
alignment with our 10-point strategic plan,
we have introduced gearing as a key measure.
Replacement cost profit (loss)
per ordinary share (cents)
Operating cash flow
($ billion)
Gearing (net debt ratio)
(%)
Total shareholder return
(%)
1
3
6
.
2
0
9
5
.
8
5
7
4
.
4
9
(
2
6
.
1
7
)
1
2
6
.
4
1
160
120
80
60
0
3
8
.
1
2
7
.
7
2
4
.
7
2
2
.
2
1
3
.
6
50
40
30
20
10
2
2
.
1
2
1
.
4
2
0
.
4
2
1
.
2
2
0
.
5
30
20
10
ADS basis
Ordinary share basis
3
3
.
0
2
7
.
6
2
.
5
3
.
0
(
2
4
.
1
)
(
2
1
.
4
)
6
.
8
1
4
.
1
(
3
4
.
6
)
(
1
5
.
1
)
60
40
20
0
-20
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
Replacement cost profit (loss) reflects
the replacement cost of supplies. It is
arrived at by excluding from profit
inventory holding gains and losses and
their associated tax effect. Replacement
cost profit for the group is the profitability
measure used by management. It is a
non-GAAP measure. See page 56 for
the equivalent measure on an IFRS basis.
In 2011, we returned to profitability
following the financial impact of the
Deepwater Horizon oil spill in 2010.
Operating cash flow is net cash flow
provided by operating activities, from
the group cash flow statement.
Operating activities are the principal
revenue-generating activities of the
group and other activities that are not
investing or financing activities.
In 2011, operating cash flow
recovered, primarily due to a reduction
in cash outflow in respect of the
Deepwater Horizon oil spill.
Gearing enables investors to see how
significant net debt is relative to equity
from shareholders. Net debt is equal to
gross finance debt, plus associated
derivatives, less cash and cash
equivalents. Net debt and net debt ratio
are non-GAAP measures. See Financial
statements – Note 35 on page 230 for the
nearest equivalent measure on an IFRS
basis and for further information.
In 2011, gearing decreased slightly
and we expect it to reduce to the lower
half of the 10-20% range over time.
Total shareholder return represents the
change in value of a BP shareholding
over a calendar year, assuming that
dividends are re-invested to purchase
additional shares at the closing price
applicable on the ex-dividend date.
In 2011, shareholder return improved
with the resumption of dividends.
Reserves replacement ratio
(%)
Production
(mboe/d)
Refining availability
(%)
1
2
9
1
2
1
1
1
2
1
0
6
1
0
3
3
,
8
1
8
3
,
8
3
8
3
,
9
9
8
3
,
8
2
2
150
120
90
60
30
4,250
4,000
3,750
3,500
3,250
3
,
4
5
4
8
8
.
8
8
2
.
9
9
5
.
0
9
4
.
8
9
3
.
6
100
95
90
85
80
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
We report crude oil, natural gas liquids
(NGLs) and natural gas produced from
subsidiaries and equity-accounted
entities. These are converted to barrels
of oil equivalent (boe) at 1 barrel of
NGL = 1boe and 5,800 standard cubic
feet of natural gas = 1boe.
Reported production in 2011 was
10% lower than in 2010, due to higher
turnaround and maintenance activity,
and the impact of the drilling
moratorium in the Gulf of Mexico.
Refining availability represents Solomon
Associates’ operational availability,
which is defined as the percentage
of the year that a unit is available for
processing after subtracting the
annualized time lost due to turnaround
activity and all planned mechanical,
process and regulatory maintenance
downtime.
Refining availability decreased slightly
in 2011 principally due to the second
quarter weather-related power outage
at Texas City.
Proved reserves replacement ratio (also
known as the production replacement
ratio) is the extent to which production
is replaced by proved reserves additions.
The ratio is expressed in oil equivalent
terms and includes changes resulting
from revisions to previous estimates,
improved recovery and extensions,
and discoveries. The measure reflects
both subsidiaries and equity-accounted
entities, but excludes acquisitions
and disposals.
The 2011 reserves additions for
TNK-BP include the effect of moving
from life-of-licence measurement to
life-of-field measurement, reflecting
TNK-BP’s track record of successful
licence renewal. Excluding this effect,
BP’s 2011 reserves replacement ratio
would have been 83%.
52 BP Annual Report and Form 20-F 2011
Reported recordable
injury frequencya
Employees
Contractors
0
.
8
4
0
.
5
9
0
.
3
5
0
.
3
5
0
.
5
0
0
.
4
3
0
.
2
3
0
.
2
5
0
.
4
10
.
3
1
1.25
1.00
0.75
0.50
0.25
Loss of primary containmenta
Oil spillsa
Greenhouse gas emissions
(million tonnes of CO2 equivalent)
6
5
8
5
3
7
Data only
available
from 2008
4
1
8
3
6
1
875
700
525
350
175
3
4
0
3
3
5
2
6
1
2
3
4
2
2
8
500
400
300
200
100
6
3
.
5
6
1
.
4
6
5
.
0
6
4
.
9
6
1
.
8
100
80
60
40
20
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
Reported recordable injury frequency
(RIF) measures the number of reported
work-related incidents that result in a
fatality or injury (apart from minor first
aid cases) per 200,000 hours worked.
In 2011, our workforce RIF, which
includes employees and contractors
combined, was 0.36, compared with
0.61 in 2010 and 0.34 in 2009. The 2010
group RIF was affected by the Gulf
Coast response effort.
a This represents reported incidents
occurring within BP’s operational HSSE
reporting boundary. That boundary
includes BP’s own operated facilities and
certain other locations or situations.
Loss of primary containment
is the number of unplanned or
uncontrolled releases of material,
excluding non-hazardous releases, such
as water from a tank, vessel, pipe, railcar
or other equipment used for
containment or transfer.
In 2011, there were 361 losses of
primary containment compared to 418 in
2010. Tracking losses of integrity is a
way of measuring safety performance
and helping drive improvements.
We report the number of spills of
hydrocarbons greater than or equal to
one barrel (159 litres, 42 US gallons).
We include spills that were contained,
as well as those that reached land or
water.
In 2011, there were 228 oil spills of
one barrel or more. We are taking
measures to strengthen mandatory
safety-related standards and processes,
including operational risk and integrity
management.
We report greenhouse gas (GHG)
emissions on a CO2-equivalent basis,
including CO2 and methane. This
represents all consolidated entities and
BP’s share of equity-accounted entities,
except TNK-BP. In 2010 we did not
report on GHG emissions associated
with the Deepwater Horizon incident or
response (see page 70).
The decrease of 3.1Mte in 2011 is
primarily explained by temporary
reduction in activity in some of our
businesses as a result of maintenance work
and also by the sale of assets as part of our
disposal programme.
Employee satisfactionb
(%)
Diversity and inclusionb
(%)
6
5
5
9
6
2
Survey
not
conducted
in 2007
Survey
not
conducted
in 2010
100
80
60
40
20
Women
Non UK/US
1
9
1
9
2
1
1
6
1
4
1
4
1
4
1
9
1
9
1
5
25
20
15
10
5
2007
2008
2009
2010
2011
2007
2008
2009
2010
2011
The employee satisfaction index comprises
10 questions that provide insight into levels
of employee satisfaction across topics such
as pay and trust in management.
Our 2010 survey was delayed to allow
for organizational changes to be reflected
in the survey construction. This was
completed and the 2011 survey showed
improvements in the level of employee
recognition, with the opportunity for clarity
about the organization’s priorities
highlighted as an area for improvement.
b Relates to BP employees.
Each year we record the percentage of
women and individuals from countries
other than the UK and US among BP’s
group leaders. The number of group
leaders in 2011 was 516, compared with
482 in 2010 and 492 in 2009.
BP has increased the percentage of
female leaders in 2011 and remains
focused on building a more sustainable
pipeline of diverse talent for the future.
BP Annual Report and Form 20-F 2011 53
Business review: Group overview
54 BP Annual Report and Form 20-F 2011
Business review
BP in more depth
56 Financial review
80 Exploration and Production
59 Risk factors
65 Safety
94 Refining and Marketing
101 Other businesses and corporate
69 Environmental and social
103 Liquidity and capital resources
responsibility
73 Employees
74 Technology
76 Gulf of Mexico oil spill
106 Regulation of the group’s business
110 Certain definitions
BP Annual Report and Form 20-F 2011 55
Business review – BP in more depth Financial review
Selected financial informationa
Income statement data
Sales and other operating revenues
Replacement cost profit (loss) before interest and taxb
By business
Exploration and Production
Refining and Marketing
Other businesses and corporate
Gulf of Mexico oil spill responsec
Consolidation adjustment
Replacement cost profit (loss) before interest and taxationb
Inventory holding gains (losses)
Profit (loss) before interest and taxation
Finance costs and net finance expense/income relating to pensions and other
post-retirement benefits
Taxation
Profit (loss) for the year
Profit (loss) for the year attributable to BP shareholders
Inventory holding (gains) losses, net of tax
Replacement cost profit (loss) for the year attributable to BP shareholdersb
Per ordinary share – cents
Profit (loss) for the year attributable to BP shareholders
Basic
Diluted
Replacement cost profit (loss) for the year attributable to BP shareholdersb (basic)
Dividends paid per share – cents
– pence
Capital expenditure and acquisitionsd
Capital expenditure, excluding acquisitions and asset exchangese
Ordinary share dataf
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 (at 31 December)
Total assets
Net assets
Share capital
BP shareholders’ equity
Finance debt due after more than one year
Net debt to net debt plus equityg
2011
2010
$ million except per share amounts
2007
2008
2009
375,517
297,107
239,272
361,143
284,365
30,500
5,474
(2,478)
3,800
(113)
37,183
2,634
39,817
(983)
(12,737)
26,097
25,700
(1,800)
23,900
135.93
134.29
126.41
28.00
17.4035
31,518
20,235
30,886
5,555
(1,516)
(40,858)
447
(5,486)
1,784
(3,702)
(1,123)
1,501
(3,324)
(3,719)
(1,195)
(4,914)
(19.81)
(19.81)
(26.17)
14.00
8.679
23,016
19,610
18,905
19,136
18,786
18,998
293,068
112,482
5,224
111,465
35,169
20.5%
272,262
95,891
5,183
94,987
30,710
21.2%
24,800
743
(2,322)
–
(717)
22,504
3,922
26,426
(1,302)
(8,365)
16,759
16,578
(2,623)
13,955
88.49
87.54
74.49
56.00
36.417
20,309
20,001
18,732
18,936
235,968
102,113
5,179
101,613
25,518
20.4%
38,308
4,176
(1,223)
–
466
41,727
(6,488)
35,239
(956)
(12,617)
21,666
21,157
4,436
25,593
112.59
111.56
136.20
55.05
29.387
30,700
28,186
18,790
18,963
228,238
92,109
5,176
91,303
17,464
21.4%
27,602
2,621
(1,209)
–
(220)
28,794
3,558
32,352
(741)
(10,442)
21,169
20,845
(2,475)
18,370
108.76
107.84
95.85
42.30
20.995
20,641
19,194
19,163
19,327
236,076
94,652
5,237
93,690
15,651
22.1%
a This information, insofar as it relates to 2011, has been extracted or derived from the audited consolidated financial statements of the BP group presented on pages 173-258. Note 1 to the financial
statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes
elsewhere herein.
b Replacement cost profit or loss reflects the replacement cost of supplies. The replacement cost profit or loss for the year is arrived at by excluding from profit inventory holding gains and losses and
their associated tax effect. Replacement cost profit or loss for the group is not a recognized GAAP measure. The equivalent measure on an IFRS basis is ‘Profit (loss) for the year attributable to BP
shareholders’. Further information on inventory holding gains and losses is provided on page 110.
c Under IFRS these costs are presented as a reconciling item between the sum of the results of the reportable segments and the group results.
d All capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing. 2008 included capital expenditure of
$2,822 million and an asset exchange of $1,909 million, both in respect of our transaction with Husky Energy Inc., as well as capital expenditure of $3,667 million in respect of our purchase of all of
Chesapeake Energy Corporation’s interest in the Arkoma Basin Woodford shale assets and the purchase of a 25% interest in Chesapeake’s Fayetteville shale assets. 2007 included $1,132 million for the
acquisition of Chevron’s Netherlands manufacturing company.
e 2011 included $1,096 million associated with deepening our natural gas asset base. 2010 included capital expenditure of $900 million relating to the formation of a partnership with Value Creation Inc.
f The number of ordinary shares shown has been used to calculate per share amounts.
g Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. We believe that these measures provide useful information to investors. Further information on net debt is given in
Financial statements – Note 35 on page 230.
Profit or loss for the year
Profit attributable to BP shareholders for the year ended 31 December
2011 was $25,700 million and included inventory holding gainsa, net of
tax, of $1,800 million and a net credit for non-operating items, after tax, of
$2,195 million. In addition, fair value accounting effects had a favourable
impact, net of tax, of $47 million relative to management’s measure of
performance. Non-operating items in 2011 included a $3.7 billion pre-tax
credit relating to the Gulf of Mexico oil spill. More information on non-
operating items and fair value accounting effects can be found on page 58.
See Gulf of Mexico oil spill on page 76 and in Financial statements – Note 2
on page 190 for further information on the impact of the Gulf of Mexico oil
spill on BP’s financial results.
Loss attributable to BP shareholders for the year ended 31 December 2010
included inventory holding gains, net of tax, of $1,195 million and a net charge
for non-operating items, after tax, of $25,449 million. In addition, fair value
accounting effects had a favourable impact, net of tax, of $13 million relative
to management’s measure of performance. Non-operating items in 2010
included a $40.9 billion pre-tax charge relating to the Gulf of Mexico oil spill.
Profit attributable to BP shareholders for the year ended
31 December 2009 included inventory holding gains, net of tax, of
$2,623 million and a net charge for non-operating items, after tax, of
$1,067 million. In addition, fair value accounting effects had a favourable
impact, net of tax, of $445 million relative to management’s measure of
performance.
56 BP Annual Report and Form 20-F 2011
Business review
The primary additional factors affecting the financial results for 2011,
compared with 2010, were higher realizations, higher earnings from equity-
accounted entities, a higher refining margin environment and a stronger
supply and trading contribution, partly offset by lower production volumes,
rig standby costs in the Gulf of Mexico, higher costs related to turnarounds,
higher exploration write-offs, and negative impacts of increased relative
sweet crude prices in Europe and Australia, primarily caused by the loss of
Libya production and the weather-related power outages in the US.
The primary additional factors affecting the financial results for
2010, compared with 2009, were higher realizations, lower depreciation,
higher earnings from equity-accounted entities, improved operational
performance, further cost efficiencies and a more favourable refining
environment in Refining and Marketing, partly offset by lower production,
a significantly lower contribution from supply and trading (including gas
marketing) and higher production taxes.
See Exploration and Production on page 80, Refining and Marketing
on page 94 and Other businesses and corporate on page 101 for further
information on segment results.
a Inventory holding gains and losses represent the difference between the cost of sales calculated
using the average cost to BP of supplies acquired during the year and the cost of sales calculated
on the first-in first-out (FIFO) method, after adjusting for any changes in provisions where the net
realizable value of the inventory is lower than its cost. BP’s management believes it is helpful to
disclose this information. An analysis of inventory holding gains and losses by business is shown in
Financial statements – Note 6 on page 200 and further information on inventory holding gains and
losses is provided on page 110.
Finance costs and net finance expense relating to pensions and other
post-retirement benefits
Finance costs comprise interest payable less amounts capitalized, and
interest accretion on provisions and long-term other payables. Finance
costs in 2011 were $1,246 million compared with $1,170 million in 2010
and $1,110 million in 2009.
Net finance income relating to pensions and other post-retirement
benefits in 2011 was $263 million compared with net finance income
of $47 million in 2010 and net finance expense of $192 million in 2009.
In 2011, compared with 2010, the improvement largely reflected the
additional expected returns on assets following the increases in the
pension asset base at the end of 2010 compared with the end of 2009.
During 2011 the value of our pension assets declined and this,
combined with changes to assumptions used to value benefit obligations,
most notably lower discount rates, meant that the deficit relating to
pension and other post-retirement benefits increased to $12.0 billion at the
end of the year (2010 $7.7 billion).
Taxation
The charge for corporate taxes in 2011 was $12,737 million, compared
with a credit of $1,501 million in 2010 and a charge of $8,365 million in
2009. The effective tax rate was 33% in 2011, 31% in 2010 and 33% in
2009. The group earns income in many countries and, on average, pays
taxes at rates higher than the UK statutory rate of 26%. The increase in the
effective tax rate in 2011 compared with 2010 primarily reflects a higher
level of income earned in jurisdictions with a higher tax rate. The decrease
in the effective tax rate in 2010 compared with 2009 primarily reflected the
absence of a one-off disbenefit that featured in 2009 in respect of goodwill
impairment, and other factors.
Acquisitions and disposals
In 2011, BP acquired from Reliance Industries Limited (Reliance) a 30%
interest in each of 21 oil and gas production-sharing agreements operated
by Reliance in India for $7.0 billion. We completed the purchase, for
$3.6 billion, of 10 exploration and production blocks in Brazil, which was
the final part of a $7-billion transaction with Devon Energy that had been
announced in March 2010, and our Alternative Energy business acquired
the Brazilian sugar and ethanol producer Companhia Nacional de Açúcar e
Álcool (CNAA) for $0.7 billion. See Financial statements – Note 3 on page
194 for further details of the business combinations undertaken during
the year.
Total disposal proceeds received during 2011, including the repayment
of the disposal deposit relating to Pan American Energy LLC (PAE) (see
below), were $2.7 billion.
In Exploration and Production, disposal proceeds included
$0.6 billion from the sale of our upstream assets in Pakistan to United
Energy Pakistan Limited, a subsidiary of United Energy Group (UEG),
$0.5 billion from the sale of half of the 3.29% interest in the Azeri-Chirag-
Gunashli (ACG) development in the Caspian Sea which we had acquired
from Devon Energy in 2010 to Azerbaijan (ACG) Limited and $0.5 billion
from the sale of our interests in the Wytch Farm, Wareham, Beacon and
Kimmeridge fields to Perenco UK Ltd. In addition, further payments of
$1.1 billion were received on completion of the sales of our upstream and
certain midstream interests in Venezuela and Vietnam and our oil and gas
exploration, production and transportation business in Colombia, for which
we had received $2.3 billion in 2010 as deposits. In November 2011, BP
received from Bridas Corporation (Bridas) a notice of termination of the
agreement for their purchase of BP’s 60% interest in PAE. As a result, the
deposit of $3.5 billion relating to the sale of PAE which had been received
by BP in 2010 was repaid to Bridas.
In Refining and Marketing we made disposals totalling $0.7 billion,
which included completion of the divestment of non-strategic pipelines and
terminals in the US, announced in 2009, for $0.3 billion and the disposal of
our fuels marketing businesses in several African countries (see Refining
and Marketing on page 97 for more details) for $0.2 billion.
Within Other businesses and corporate, we completed the sale of
BP’s wholly-owned subsidiary, ARCO Aluminum Inc., to a consortium of
Japanese companies for $0.7 billion.
In 2010, BP acquired a major portfolio of deepwater exploration
acreage and prospects in the US Gulf of Mexico and an additional interest
in the BP-operated ACG developments in the Caspian Sea, Azerbaijan for
$2.9 billion, as part of a $7-billion transaction with Devon Energy. Total
disposal proceeds during 2010 were $17 billion, which included $7 billion
from the sale of US Permian Basin, Western Canadian gas assets, and
Western Desert exploration concessions in Egypt to Apache Corporation
(and an existing partner that exercised pre-emption rights), and $6.2 billion
of deposits received in advance of disposal transactions expected to
complete in 2011. Of these deposits received, $3.5 billion was for the sale
of our interest in PAE to Bridas, however, this was subsequently repaid to
Bridas at the end of 2011 following the termination of the sale agreement.
See above and Financial statements – Note 4 on page 196 for further
information. The deposits received also included $1 billion for the sale of
our upstream and midstream interests in Venezuela and Vietnam to TNK-
BP, and $1.3 billion for the sale of our oil and gas exploration, production
and transportation business in Colombia to a consortium of Ecopetrol and
Talisman.
In Refining and Marketing we made disposals totalling $1.8 billion in
2010, which included our French retail fuels and convenience business to
Delek Europe, the fuels marketing business in Botswana to Puma Energy,
certain non-strategic pipelines and terminals in the US, our interests in
ethylene and polyethylene production in Malaysia to Petronas and our
interest in a futures exchange.
There were no significant acquisitions in 2009. Disposal proceeds in
2009 were $2.7 billion, principally from the sale of our interests in BP West
Java Limited, Kazakhstan Pipeline Ventures LLC and LukArco, and the sale
of our ground fuels marketing business in Greece and retail churn in the
US, Europe and Australasia. Further proceeds from the sale of LukArco
were received in 2011.
BP Annual Report and Form 20-F 2011 57
Business review: BP in more depthBusiness review Non-operating items
Non-operating items are charges and credits arising in consolidated entities
that BP discloses separately because it considers such disclosures to
be meaningful and relevant to investors. They are provided in order to
enable investors to better understand and evaluate the group’s financial
performance. An analysis of non-operating items is shown in the table
below.
Exploration and Production
Impairment and gain (loss) on sale
of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and
rationalization costs
Fair value gain (loss) on embedded
derivatives
Othera
Refining and Marketing
Impairment and gain (loss) on sale
of businesses and fixed assetsb
Environmental and other provisions
Restructuring, integration and
rationalization costs
Fair value gain (loss) on embedded
derivatives
Other
By business
Fuelsb
Lubricants
Petrochemicals
Other businesses and corporate
Impairment and gain (loss) on sale
of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and
rationalization costs
Fair value gain (loss) on embedded
derivativesc
Otherd
Gulf of Mexico oil spill response
Total before interest and taxation
Finance costse
Total before taxation
Taxation credit (charge)f
Total after taxation
2011
2010
$ million
2009
2,131
(27)
3,812
(54)
1,574
3
–
(137)
(10)
191
(1,165)
1,130
(309)
(113)
3,199
664
34
2,265
(334)
(219)
(4)
–
(45)
(602)
(703)
100
1
(602)
275
(220)
(39)
877
(98)
(97)
–
(52)
630
339
(47)
338
630
5
(103)
(81)
(123)
(715)
(822)
3,800
3,506
(58)
3,448
(1,253)
2,195
–
(21)
(200)
(40,858)
(37,229)
(77)
(37,306)
11,857
(25,449)
(1,604)
(219)
(907)
(57)
184
(2,603)
(2,394)
(171)
(38)
(2,603)
(130)
(75)
(183)
–
(101)
(489)
–
(827)
–
(827)
(240)
(1,067)
a 2011 included a charge of $700 million associated with the termination of the agreement to sell our
60% interest in Pan American Energy LLC to Bridas Corporation (see page 85).
b 2009 included $1,579 million in relation to the impairment of goodwill allocated to the US West
Coast fuels value chain.
c Relates to an embedded derivative arising from a financing arrangement.
d 2011 included charges of $687 million in relation to raw materials purchase contracts associated
with our exit from the solar business.
e Finance costs relate to the Gulf of Mexico oil spill. See Financial statements – Note 2 on page 190
for further details.
f Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf
of Mexico oil spill and, for 2011, the impact of a $683-million one-off deferred tax adjustment in
respect of an increase in the supplementary charge on UK oil and gas production) on group profit
or loss. However, the US statutory tax rate has been used for recoveries relating to the Gulf of
Mexico oil spill and expenditures that qualify for tax relief. In 2009, no tax credit was calculated on
the goodwill impairment in Refining and Marketing because the charge is not tax deductible.
Non-GAAP information on fair value accounting effects
The impacts of fair value accounting effects, relative to management’s
internal measure of performance, and a reconciliation to GAAP information
is also set out below. Further information on fair value accounting effects is
provided on page 110.
Exploration and Production
Unrecognized gains (losses) brought
forward from previous period
Unrecognized (gains) losses carried
forward
Favourable (unfavourable) impact
relative to management’s
measure of performance
Refining and Marketinga
Unrecognized gains (losses) brought
forward from previous period
Unrecognized (gains) losses carried
forward
Favourable (unfavourable) impact
relative to management’s
measure of performance
Taxation credit (charge)b
By region
Exploration and Production
US
Non-US
Refining and Marketinga
US
Non-US
2011
2010
(527)
(530)
538
527
$ million
2009
389
530
11
(3)
919
137
179
(82)
(74)
(137)
(179)
63
74
(27)
47
15
(4)
11
–
63
63
42
39
(26)
13
141
(144)
(3)
19
23
42
(261)
658
(213)
445
687
232
919
16
(277)
(261)
a Fair value accounting effects arise solely in the fuels business.
b Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf
of Mexico oil spill and, for 2011, the impact of a $683-million one-off deferred tax adjustment in
respect of an increase in the supplementary charge on UK oil and gas production) on group profit
or loss.
Reconciliation of non-GAAP information
2011
2010
$ million
2009
Exploration and Production
Replacement cost profit before
interest and tax adjusted for fair
value accounting effects
Impact of fair value accounting
30,489
30,889
23,881
effects
11
(3)
919
Replacement cost profit before
interest and tax
Refining and Marketing
Replacement cost profit before
interest and tax adjusted for fair
value accounting effects
Impact of fair value accounting
effects
Replacement cost profit before
30,500
30,886
24,800
5,411
5,513
1,004
63
42
(261)
interest and tax
5,474
5,555
743
Total group
Profit (loss) before interest and tax
adjusted for fair value
accounting effects
Impact of fair value accounting
effects
Profit (loss) before interest and tax
39,743
(3,741)
25,768
74
39,817
39
(3,702)
658
26,426
58 BP Annual Report and Form 20-F 2011
Business review Risk factors
We urge you to consider carefully the risks described below. The potential
impact of their occurrence could be for our business, financial condition
and results of operations to suffer (including through the failure to achieve
our current strategic priorities (see ‘10-point plan’ – pages 38-39)) and the
trading price and liquidity of our securities to decline.
Our system of risk management identifies and provides the
response to risks of group significance through the establishment of
standards and other controls. Any failure of this system could lead to the
occurrence, or re-occurrence, of any of the risks described below and a
consequent material adverse effect on BP’s business, financial position,
results of operations, competitive position, cash flows, prospects, liquidity,
shareholder returns and/or implementation of its strategic agenda.
The risks are categorized against the following areas: strategic;
compliance and control; and safety and operational. In addition, we have
also set out two further risks for your attention – those resulting from the
2010 Gulf of Mexico oil spill (the Incident) and those related to the general
macroeconomic outlook.
The Gulf of Mexico oil spill has had and could continue to have a
material adverse impact on BP.
There is significant uncertainty in the extent and timing of costs and
liabilities relating to the Incident, the impact of the Incident on our
reputation and the resulting possible impact on our licence to operate
including our ability to access new opportunities. There is also significant
uncertainty regarding potential changes in applicable regulations and
the operating environment that may result from the Incident. These
increase the risks to which the group is exposed and may cause our costs
to increase. These uncertainties are likely to continue for a significant
period. Thus, the Incident has had, and could continue to have, a material
adverse impact on the group’s business, competitive position, financial
performance, cash flows, prospects, liquidity, shareholder returns and/or
implementation of its strategic agenda, particularly in the US.
We recognized a pre-tax charge of $40.9 billion in 2010 and a pre-tax
credit of $3.7 billion in 2011 as a result of the Incident. The total amounts
that will ultimately be paid by BP in relation to all obligations relating to the
Incident are subject to significant uncertainty and the ultimate exposure and
cost to BP will be dependent on many factors. Furthermore, the amount
of claims that become payable by BP, the amount of fines ultimately
levied on BP (including any potential determination of BP’s negligence
or gross negligence), the outcome of litigation, the amount and timing of
payments under any settlements, and any costs arising from any longer-
term environmental consequences of the oil spill, will also impact upon the
ultimate cost for BP. Although the provision recognized is the current best
estimate of expenditures required to settle certain present obligations at the
end of the reporting period, there are future expenditures for which it is not
possible to measure the obligation reliably. The risks associated with the
Incident could also heighten the impact of the other risks to which the group
is exposed as further described below.
The general macroeconomic outlook can affect BP’s results given the
nature of our business.
In the continuing uncertain financial and economic environment, certain
risks may gain more prominence either individually or when taken together.
Oil and gas prices can be very volatile, with average prices and margins
influenced by changes in supply and demand. This is likely to exacerbate
competition in all businesses, which may impact costs and margins.
At the same time, governments are facing greater pressure on public
finances, which may increase their motivation to intervene in the fiscal
and regulatory frameworks of the oil and gas industry, including the risk of
increased taxation, nationalization and expropriation. The global financial
and economic situation may have a negative impact on third parties with
whom we do, or may do, business. In particular, ongoing instability in or a
collapse of the eurozone could trigger a new wave of financial crises and
push the world back into recession, leading to lower demand and lower oil
and gas prices. Any of these factors may affect our results of operations,
financial condition, business prospects and liquidity and may result in a
decline in the trading price and liquidity of our securities.
Capital markets are subject to volatility amid concerns over the European
sovereign debt crisis and the slow-down of the global economy. If there
are extended periods of constraints in these markets, or if we are unable
to access the markets, including due to our financial position or market
sentiment as to our prospects, at a time when cash flows from our
business operations may be under pressure, our ability to maintain our
long-term investment programme may be impacted with a consequent
effect on our growth rate, and may impact shareholder returns, including
dividends and share buybacks, or share price. Decreases in the funded
levels of our pension plans may also increase our pension funding
requirements.
Strategic risks
Access and renewal – BP’s future hydrocarbon production depends
on our ability to renew and reposition our portfolio. Increasing
competition for access to investment opportunities, the effects
of the Gulf of Mexico oil spill on our reputation and cash flows,
and more stringent regulation could result in decreased access to
opportunities globally.
Successful execution of our group strategy depends 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 among both national and international oil
companies, and heightened political and economic risks in certain countries
where significant hydrocarbon basins are located. Lack of material
positions in new markets could impact our future hydrocarbon production.
Moreover, the Gulf of Mexico oil spill has damaged BP’s reputation,
which may have a long-term impact on the group’s ability to access new
opportunities, both in the US and elsewhere. Adverse public, political
and industry sentiment towards BP, and towards oil and gas drilling
activities generally, could damage or impair our existing commercial
relationships with counterparties, partners and host governments and
could impair our access to new investment opportunities, exploration
properties, operatorships or other essential commercial arrangements
with potential partners and host governments, particularly in the US. In
addition, responding to the Incident has placed, and will continue to place,
a significant burden on our cash flow over the next several years, which
could also impede our ability to invest in new opportunities and deliver
long-term growth.
More stringent regulation of the oil and gas industry generally, and
of BP’s activities specifically, arising from the Incident, could increase this
risk.
Prices and markets – BP’s financial performance is subject to
the fluctuating prices of crude oil and gas as well as the volatile
prices of refined products and the profitability of our refining and
petrochemicals operations.
Oil, gas and product prices are subject to international supply and
demand. Political developments and the outcome of meetings of OPEC
can particularly affect world supply and oil prices. Previous oil price
increases have resulted in increased fiscal take, cost inflation and more
onerous terms for access to resources. As a result, increased oil prices
may not improve margin performance. In addition to the adverse effect
on revenues, margins and profitability from any fall in oil and natural
gas prices, a prolonged period of low prices or other indicators would
lead to further reviews for impairment of the group’s oil and natural gas
properties. Such reviews would reflect management’s view of long-term
oil and natural gas prices and could result in a charge for impairment
that could have a significant effect on the group’s results of operations
in the period in which it occurs. Rapid material or sustained change in
oil, gas and product prices can impact the validity of the assumptions on
which strategic decisions are based and, as a result, the ensuing actions
derived from those decisions may no longer be appropriate. A prolonged
period of low oil prices may impact our ability to maintain our long-term
investment programme with a consequent effect on our growth rate and
may impact shareholder returns, including dividends and share buybacks,
or share price. Periods of global recession could impact the demand for our
products, the prices at which they can be sold and affect the viability of the
markets in which we operate.
BP Annual Report and Form 20-F 2011 59
Business review: BP in more depthBusiness review Refining profitability can be volatile, with both periodic over-supply and
supply tightness in various regional markets, coupled with fluctuations
in demand. Sectors of the petrochemicals industry are also subject to
fluctuations in supply and demand, with a consequent effect on prices and
profitability.
Climate change and carbon pricing – climate change and carbon
pricing policies could result in higher costs and reduction in future
revenue and strategic growth opportunities.
Compliance with changes in laws, regulations and obligations relating
to climate change could result in substantial capital expenditure, taxes,
reduced profitability from changes in operating costs, and revenue
generation and strategic growth opportunities being impacted. Our
commitment to the transition to a lower-carbon economy may create
expectations for our activities, and the level of participation in alternative
energies carries reputational, economic and technology risks.
Socio-political – the diverse nature of our operations around the
world exposes us to a wide range of political developments and
consequent changes to the operating environment, regulatory
environment and law.
We have operations, and are seeking new opportunities, in countries
where political, economic and social transition is taking place. Some
countries have experienced, or may experience in the future, political
instability, changes to the regulatory environment, changes in taxation,
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, could limit our
ability to pursue new opportunities and could cause us to incur additional
costs. In particular, our investments in the US, Russia, Iraq, Egypt, Libya,
Bolivia, Argentina and other countries could be adversely affected by
heightened political and economic environment risks. See pages 34-35 for
information on the locations of our major assets and activities.
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 – BP’s group strategy depends upon continuous
innovation in a highly competitive market.
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, while ensuring safety and operational
risk is not compromised. The implementation of group strategy requires
continued technological advances and innovation including advances in
exploration, production, refining, petrochemicals manufacturing technology
and advances in technology related to energy usage. Our performance
could be impeded if competitors developed or acquired intellectual
property rights to technology that we required or if our innovation lagged
the industry.
Investment efficiency – poor investment decisions could negatively
impact our business.
Our organic growth is dependent on creating a portfolio of quality options
and investing in the best options. Ineffective investment selection and
development could lead to loss of value and higher capital expenditure.
Reserves replacement – inability to progress upstream resources in a
timely manner could adversely affect our long-term replacement of
reserves and negatively impact our business.
Successful execution of our group strategy depends critically on sustaining
long-term reserves replacement. If upstream resources are not progressed
in a timely and efficient manner, we will be unable to sustain long-term
replacement of reserves.
60 BP Annual Report and Form 20-F 2011
Liquidity, financial capacity and financial exposure – failure to operate
within our financial framework could impact our ability to operate
and result in financial loss. Exchange rate fluctuations can impact our
underlying costs and revenues.
The group seeks to maintain a financial framework to ensure that it is
able to maintain an appropriate level of liquidity and financial capacity. This
framework constrains the level of assessed capital at risk for the purposes
of positions taken in financial instruments. Failure to accurately forecast or
maintain sufficient liquidity and credit to meet these needs could impact
our ability to operate and result in a financial loss. Commercial credit risk is
measured and controlled to determine the group’s total credit risk. Inability
to determine adequately our credit exposure could lead to financial loss. A
credit crisis affecting banks and other sectors of the economy could impact
the ability of counterparties to meet their financial obligations to the group.
It could also affect our ability to raise capital to fund growth and to meet
our obligations. The change in the group’s financial framework during 2010
to make it more prudent may not be sufficient to avoid a substantial and
unexpected cash call.
BP’s clean-up costs and potential liabilities resulting from pending
and future claims, lawsuits, settlements and enforcement actions
relating to the Gulf of Mexico oil spill, together with the potential cost of
implementing remedies sought in the various proceedings, cannot be fully
estimated at this time but they have had, and could continue to have, a
material adverse impact on the group’s business, competitive position,
financial performance, cash flows, prospects, liquidity, shareholder
returns and/or implementation of its strategic agenda, particularly in the
US. Furthermore, we recognized a pre-tax charge of $40.9 billion in 2010
and a pre-tax credit of $3.7 billion in 2011, and further potential liabilities
may continue to have a material adverse effect on the group’s results of
operations and financial condition. See Financial statements – Note 2 on
pages 190-194 and Legal proceedings on pages 160-166. More stringent
regulation of the oil and gas industry arising from the Incident, and of BP’s
activities specifically, could increase this risk.
Crude oil prices are generally set in US dollars, while sales of
refined products may be in a variety of currencies. Fluctuations in exchange
rates can therefore give rise to foreign exchange exposures, with a
consequent impact on underlying costs and revenues.
See Financial statements – Note 26 on page 217 for more
information on financial instruments and financial risk factors.
Insurance – BP’s insurance strategy means that the group could,
from time to time, be exposed to material uninsured losses which
could have a material adverse effect on BP’s financial condition and
results of operations.
In the context of the limited capacity of the insurance market, many
significant risks are retained by BP. The group generally restricts its
purchase of insurance to situations where this is required for legal or
contractual reasons. This means that the group could be exposed to
material uninsured losses, which could have a material adverse effect
on its financial condition and results of operations. In particular, these
uninsured costs could arise at a time when BP is facing material costs
arising out of some other event which could put pressure on BP’s liquidity
and cash flows. For example, BP has borne and will continue to bear the
entire burden of its share of any property damage, well control, pollution
clean-up and third-party liability expenses arising out of the Gulf of Mexico
oil spill.
Compliance and control risks
Regulatory – the oil industry in general, and in particular the US
industry following the Gulf of Mexico oil spill, faces increased
regulation that could increase the cost of regulatory compliance and
limit our access to new exploration properties.
After the Gulf of Mexico oil spill, it is likely that there will be more stringent
regulation of oil and gas activities in the US and elsewhere, particularly
relating to environmental, health and safety controls and oversight of
drilling operations, as well as access to new drilling areas. Regulatory or
legislative action may impact the industry as a whole and could be directed
specifically towards BP. The US government imposed a moratorium on
certain offshore drilling activities, which was subsequently lifted in October
Business review 2010. Similar actions may be taken by governments elsewhere in the
world. New regulations and legislation, as well as evolving practices, could
increase the cost of compliance and may require changes to our drilling
operations, exploration, development and decommissioning plans, and
could impact our ability to capitalize on our assets and limit our access to
new exploration properties or operatorships, particularly in the deepwater
Gulf of Mexico. In addition, increases in taxes, royalties and other amounts
payable to governments or governmental agencies, or restrictions on
availability of tax relief, could also be imposed as a response to the
Incident.
In addition, 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, health and safety controls, controls over the
development and decommissioning of a field (including restrictions on
production) and, possibly, nationalization, expropriation, cancellation or
non-renewal of contract rights. We buy, sell and trade oil and gas products
in certain regulated commodity markets. Failure to respond to changes
in trading regulations could result in regulatory action and damage to our
reputation. The oil industry is also subject to the payment of royalties and
taxation, which tend to be high compared with those payable in respect
of other commercial activities, and operates in certain tax jurisdictions that
have a degree of uncertainty relating to the interpretation of, and changes
to, tax law. As a result of new laws and regulations or other factors, we
could be required to curtail or cease certain operations, or we could incur
additional costs.
See pages 107-110 for more information on environmental
regulation.
Ethical misconduct and non-compliance – ethical misconduct or
breaches of applicable laws by our employees could be damaging to
our reputation and shareholder value.
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. Our renewed values,
which were launched in 2011, are intended to guide the way we and our
employees behave and do business. Incidents of ethical misconduct or
non-compliance with applicable laws and regulations, including non-
compliance with anti-bribery, anti-corruption and other applicable laws
could be damaging to our reputation and shareholder value. Multiple events
of non-compliance could call into question the integrity of our operations.
For example, in our trading businesses, there is the risk that a determined
individual could operate as a ‘rogue trader’, acting outside BP’s delegations,
controls or code of conduct and in contravention of our renewed values in
pursuit of personal objectives that could be to the detriment of BP and its
shareholders.
For certain legal proceedings involving the group, see Legal
proceedings on pages 160-166. For further information on the risks
involved in BP’s trading activities, see Operational risks – Treasury and
trading activities on page 63.
Liabilities and provisions – BP’s potential liabilities resulting from
pending and future claims, lawsuits, settlements and enforcement
actions relating to the Gulf of Mexico oil spill, together with the
potential cost and burdens of implementing remedies sought in the
various proceedings, cannot be fully estimated at this time but they
have had, and are expected to continue to have, a material adverse
impact on the group’s business.
Under the Oil Pollution Act of 1990 (OPA 90), BP Exploration & Production
Inc. is one of the parties financially responsible for the clean-up of the Gulf
of Mexico oil spill and for certain economic damages as provided for in
OPA 90, as well as certain natural resource damages associated with the
spill and certain costs determined by federal and state trustees engaged in
a joint assessment of such natural resource damages.
BP and certain of its subsidiaries have also been named as
defendants in numerous lawsuits in the US arising out of the Incident,
including actions for personal injury and wrongful death, purported class
actions for commercial or economic injury, actions for breach of contract,
violations of statutes, property and other environmental damage, securities
law claims and various other claims. See Legal proceedings on pages
160-166.
BP is subject to a number of investigations related to the Incident
by numerous federal and State agencies. See Legal proceedings on pages
160-166. The types of enforcement action pursued and the nature of the
remedies sought will depend on the discretion of the prosecutors and
regulatory authorities and, in some circumstances, their assessment of
BP’s culpability, if any, following their investigations. Such enforcement
actions could include criminal proceedings against BP and/or employees
of the group. In addition to fines and penalties, such enforcement actions
could result in the suspension of operating licences and debarment from
government contracts. Debarment of BP Exploration & Production Inc.
would prevent it from bidding on or entering into new federal contracts or
other federal transactions, and from obtaining new orders or extensions
to existing federal contracts, including federal procurement contracts or
leases. Dependent on the circumstances, debarment or suspension may
also be sought against affiliated entities of BP Exploration & Production
Inc. Although BP believes that there are costs arising out of the spill that
are recoverable from its partners and other parties responsible under OPA
90, and although settlements have been agreed during 2011 with both
partners, one contractor, and the manufacturer of the blowout preventer at
the Macondo well, further recoveries are not certain and so have not been
recognized in the financial statements (see Financial statements – Note 2
on pages 190-194).
Any finding of gross negligence for purposes of penalties sought
against the group under the Clean Water Act would also have a material
adverse impact on the group’s reputation, would affect our ability to
recover costs relating to the Incident from other parties responsible under
OPA 90 and could affect the fines and penalties payable by the group with
respect to the Incident under enforcement actions outside the Clean Water
Act context.
The Gulf of Mexico oil spill has damaged BP’s reputation. This,
combined with other past events in the US (including the 2005 explosion
at the Texas City refinery and the 2006 pipeline leaks in Alaska), may lead
to an increase in the number of citations and/or the level of fines imposed
in relation to the Gulf of Mexico oil spill and any future alleged breaches of
safety or environmental regulations.
Claims by individuals and businesses under OPA 90’s claims
process have been administered by the Gulf Coast Claims Facility (GCCF)
headed by Kenneth Feinberg, who was appointed jointly by BP and the
US Administration. The proposed economic loss settlement reached with
the Plaintiffs’ Steering Committee (PSC), acting on behalf of individual and
business plaintiffs in MDL 2179, provides for a transition from the GCCF. A
court-supervised transitional claims process for economic loss claims will be
in operation while the infrastructure for the new settlement claims process
is put in place. During this transitional period, the processing of claims that
have been submitted to the GCCF will continue, and new claimants may
submit their claims.
The proposed settlement is subject to final written agreement and
court approvals and payments under the proposed settlement, and any
other payments that may be made by BP in respect of any other individual
and business claims under OPA 90, could ultimately be higher than the
amount for which we have recognized a provision. See Legal proceedings
on pages 160-164 and Financial statements – Note 36 on pages 231-234.
Changes in external factors could affect our results of operations and
the adequacy of our provisions.
We remain exposed to changes in the external environment, such as
new laws and regulations (whether imposed by international treaty or by
national or local governments in the jurisdictions in which we operate),
changes in tax or royalty regimes, price controls, government actions to
cancel or renegotiate contracts, market volatility or other factors. Such
factors could reduce our profitability from operations in certain jurisdictions,
limit our opportunities for new access, require us to divest or write-down
certain assets or affect the adequacy of our provisions for pensions, tax,
environmental and legal liabilities. Potential changes to pension or financial
market regulation could also impact funding requirements of the group.
BP Annual Report and Form 20-F 2011 61
Business review: BP in more depthBusiness review Reporting – failure to accurately report our data could lead to
regulatory action, legal liability and reputational damage.
External reporting of financial and non-financial data is reliant on the
integrity of systems and people. Failure to report data accurately and in
compliance with external standards could result in regulatory action, legal
liability and damage to our reputation.
Safety and operational risks
The risks inherent in our operations include a number of hazards that,
although many may have a low probability of occurrence, can have
extremely serious consequences if they do occur, such as the Gulf of
Mexico oil spill. The occurrence of any such risks could have a consequent
material adverse impact on the group’s business, competitive position,
cash flows, results of operations, financial position, prospects, liquidity,
shareholder returns and/or implementation of the group’s strategic goals.
Process safety, personal safety and environmental risks – the nature
of our operations exposes us to a wide range of significant health,
safety, security and environmental risks, the occurrence of which
could result in regulatory action, legal liability and increased costs
and damage to our reputation.
The nature of the group’s operations exposes us to a wide range of
significant health, safety, security and environmental risks. The scope of
these risks is influenced by the geographic range, operational diversity
and technical complexity of our activities. In addition, in many of our major
projects and operations, risk allocation and management is shared with
third parties, such as contractors, sub-contractors, joint venture partners
and associates. See ‘Joint ventures and other contractual arrangements
– BP may not have full operational control and may have exposure to
counterparty credit risk and disruptions to our operations and strategic
objectives due to the nature of some of its business relationships’ on
page 63.
There are risks of technical integrity failure as well as risk of natural
disasters and other adverse conditions in many of the areas in which we
operate, which could lead to loss of containment of hydrocarbons and
other hazardous material, as well as the risk of fires, explosions or other
incidents.
In addition, inability to provide safe environments for our workforce
and the public could lead to injuries or loss of life and could result in
regulatory action, legal liability and damage to our reputation.
Our operations are often conducted in difficult or environmentally
sensitive locations, in which the consequences of a spill, explosion,
fire or other incident could be greater than in other locations. These
operations are subject to various environmental and safety laws,
regulations and permits and the consequences of failure to comply
with these requirements can include remediation obligations, penalties,
loss of operating permits and other sanctions. Accordingly, inherent in
our operations is the risk that if we fail to abide by environmental and
safety and protection standards, such failure could lead to damage to the
environment and could result in regulatory action, legal liability, material
costs, damage to our reputation or denial of our licence to operate.
To help address health, safety, security, environmental and
operations risks, and to provide a consistent framework within which
the group can analyse the performance of its activities and identify
and remediate shortfalls, BP has introduced a group-wide operating
management system (OMS). Work on the application of OMS in individual
operating businesses continues and following the Gulf of Mexico oil spill
an enhanced safety and operational risk (S&OR) function was established,
reporting directly to the group chief executive. There can be no assurance
that OMS will adequately identify all process safety, personal safety and
environmental risk or provide the correct mitigations, or that all operations
will be in conformance with OMS at all times.
Security – hostile activities against our staff and activities could
cause harm to people and disrupt our operations.
Security threats require continuous oversight and control. Acts of terrorism,
piracy, sabotage, cyber-attacks and similar activities directed against our
operations and offices, pipelines, transportation or computer systems could
cause harm to people and could severely disrupt business and operations.
62 BP Annual Report and Form 20-F 2011
Our business activities could also be severely disrupted by civil strife and
political unrest in areas where we operate.
Product quality – failure to meet product quality standards could lead
to harm to people and the environment and loss of customers.
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 – these activities require high levels
of investment and are subject to natural hazards and other
uncertainties. Activities in challenging environments heighten many
of the drilling and production risks including those of integrity
failures, which could lead to curtailment, delay or cancellation
of drilling operations, or inadequate returns from exploration
expenditure.
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. Our exploration
and production activities are often conducted in extremely challenging
environments, which heighten the risks of technical integrity failure and
natural disasters discussed above. 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. In addition, exploration
expenditure may not yield adequate returns, for example in the case of
unproductive wells or discoveries that prove uneconomic to develop.
The Gulf of Mexico oil spill illustrates the risks we face in our drilling and
production activities.
Transportation – all modes of transportation of hydrocarbons involve
inherent and significant risks.
All modes of transportation of hydrocarbons involve inherent risks. An
explosion or fire or loss of containment of hydrocarbons or other hazardous
material could occur during transportation by road, rail, sea or pipeline. This
is a significant risk due to the potential impact of a release on people and
the environment and given the high volumes potentially involved.
Major project delivery – our group plan depends upon successful
delivery of major projects, and failure to deliver major projects
successfully could adversely affect our financial performance.
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 or production
growth, including maintenance turnaround programmes, and/or a major
programme designed to enhance shareholder value could adversely affect
our financial performance. Successful project delivery requires, among
other things, adequate engineering and other capabilities and therefore
successful recruitment and development of staff is central to our plans.
See ‘People and capability – successful recruitment and development of
staff is central to our plans’ on page 63.
Digital infrastructure is an important part of maintaining our
operations, and a breach of our digital security could result in serious
damage to business operations, personal injury, damage to assets,
harm to the environment, breaches of regulations, litigation, legal
liabilities and reparation costs.
The reliability and security of our digital infrastructure are critical to
maintaining the availability of our business applications, including the
reliable operation of technology in our various business operations and
the collection and processing of financial and operational data, as well as
the confidentiality of certain third-party information. A breach of our digital
security, either due to intentional actions or due to negligence, could cause
serious damage to business operations and, in some circumstances, could
result in injury to people, damage to assets, harm to the environment,
breaches of regulations, litigation, legal liabilities and reparation costs.
Business review Business continuity and disaster recovery – the group must be able
to recover quickly and effectively from any disruption or incident, as
failure to do so could adversely affect our business and operations.
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 our business and operations.
Crisis management – crisis management plans are essential to
respond effectively to emergencies and to avoid a potentially severe
disruption in our business and operations.
Crisis management plans and capability are essential to deal with
emergencies at every level of our operations. If we do not respond, or are
perceived not to respond, in an appropriate manner to either an external or
internal crisis, our business and operations could be severely disrupted.
People and capability – successful recruitment and development of
staff is central to our plans.
Successful recruitment of new staff, employee training, development
and long-term renewal of skills, in particular technical capabilities such
as petroleum engineers and scientists, are key to implementing our
plans. Inability to develop human capacity and capability, both across
the organization and in specific operating locations, could jeopardize
performance delivery.
In addition, significant management focus is required in responding
to the Gulf of Mexico oil spill Incident. Although BP set up the Gulf Coast
Restoration Organization to manage the group’s long-term response, key
management and operating personnel will need to continue to devote
substantial attention to responding to the Incident and to address the
associated consequences for the group. The group relies on recruiting
and retaining high-quality employees to execute its strategic plans and
to operate its business. The Incident response has placed significant
demands on our employees, and the reputational damage suffered by the
group as a result of the Incident and any consequent adverse impact on our
performance could affect employee recruitment and retention.
Treasury and trading activities – control of these activities depends
on our ability to process, manage and monitor a large number of
transactions. Failure to do this effectively could lead to business
disruption, financial loss, regulatory intervention or damage to our
reputation.
In the normal course of business, we are subject to operational risk around
our treasury and trading activities. Control of these activities is highly
dependent on our ability to process, manage and monitor a large number of
complex transactions across many markets and currencies. Shortcomings
or failures in our systems, risk management methodology, internal control
processes or people could lead to disruption of our business, financial loss,
regulatory intervention or damage to our reputation.
Following the Gulf of Mexico oil spill, Moody’s Investors Service,
Standard and Poor’s and Fitch Ratings downgraded the group’s long-term
credit ratings. Since that time, the group’s credit ratings have improved
somewhat but are still lower than they were immediately before the Gulf
of Mexico oil spill. The impact that a significant operational incident can
have on the group’s credit ratings, taken together with the reputational
consequences of any such incident, the ratings and assessments published
by analysts and investors’ concerns about the group’s costs arising from
any such incident, ongoing contingencies, liquidity, financial performance
and volatile credit spreads, could increase the group’s financing costs and
limit the group’s access to financing. The group’s ability to engage in its
trading activities could also be impacted due to counterparty concerns
about the group’s financial and business risk profile in such circumstances.
Such counterparties could require that the group provide collateral or
other forms of financial security for its obligations, particularly if the
group’s credit ratings are downgraded. Certain counterparties for the
group’s non-trading businesses could also require that the group provide
collateral for certain of its contractual obligations, particularly if the group’s
credit ratings were downgraded below investment grade or where a
counterparty had concerns about the group’s financial and business risk
profile following a significant operational incident. In addition, BP may be
unable to make a drawdown under certain of its committed borrowing
facilities in the event we are aware that there are pending or threatened
legal, arbitration or administrative proceedings which, if determined
adversely, might reasonably be expected to have a material adverse effect
on our ability to meet the payment obligations under any of these facilities.
Credit rating downgrades could trigger a requirement for the company to
review its funding arrangements with the BP pension trustees. Extended
constraints on the group’s ability to obtain financing and to engage in its
trading activities on acceptable terms (or at all) would put pressure on the
group’s liquidity. In addition, this could occur at a time when cash flows
from our business operations would be constrained following a significant
operational incident, and the group could be required to reduce planned
capital expenditures and/or increase asset disposals in order to provide
additional liquidity, as the group did following the Gulf of Mexico oil spill.
Joint ventures and other contractual arrangements – BP may not
have full operational control and may have exposure to counterparty
credit risk and disruptions to our operations and strategic objectives
due to the nature of some of its business relationships.
Many of our major projects and operations are conducted through joint
ventures or associates and through contracting and sub-contracting
arrangements. These arrangements often involve complex risk allocation,
decision-making processes and indemnification arrangements. In certain
cases, we may have less control of such activities than we would have
if BP had full operational control. Our partners may have economic or
business interests or objectives that are inconsistent with or opposed to,
those of BP, and may exercise veto rights to block certain key decisions
or actions that BP believes are in its or the joint venture’s or associate’s
best interests, or approve such matters without our consent. Additionally,
our joint venture partners or associates or contractual counterparties
are primarily responsible for the adequacy of the human or technical
competencies and capabilities which they bring to bear on the joint project,
and in the event these are found to be lacking, our joint venture partners
or associates may not be able to meet their financial or other obligations to
their counterparties or to the relevant project, potentially threatening the
viability of such projects. Furthermore, should accidents or incidents occur
in operations in which BP participates, whether as operator or otherwise,
and where it is held that our sub-contractors or joint-venture partners
are legally liable to share any aspects of the cost of responding to such
incidents, the financial capacity of these third parties may prove inadequate
to fully indemnify BP against the costs we incur on behalf of the joint
venture or contractual arrangement. Should a key sub-contractor, such as
a lessor of drilling rigs, be no longer able to make these assets available
to BP, this could result in serious disruption to our operations. Where BP
does not have operational control of a venture, BP may nonetheless still be
pursued by regulators or claimants in the event of an incident.
BP Annual Report and Form 20-F 2011 63
Business review: BP in more depthBusiness review BP sells lubricants in Cuba through a 50:50 joint venture and trades in
small quantities of lubricants. BP sold small quantities of lubricants to third
parties that were resold in Sudan; BP has terminated these sales.
BP has equity interests in non-operated joint ventures with air
fuel sellers, re-sellers, and fuel delivery services around the world. From
time to time, the joint venture operator may sell or deliver fuel to airlines
from Sanctioned Countries or flights to Sanctioned Countries without
BP’s knowledge or consent. BP has registered and paid required fees for
patents and trademarks in Sanctioned Countries.
Further note on certain activities
During the period covered by this report, non-US subsidiaries or other
non-US entities of BP conducted limited activities in, or with persons
from, certain countries identified by the US Department of State as
State Sponsors of Terrorism or otherwise subject to US sanctions
(‘Sanctioned Countries’). These activities continue to be insignificant to
the group’s financial condition and results of operations. In 2011, the US
enacted additional sanctions against Iran which included lower monetary
thresholds for certain investments in Iran for the development or refining
of petroleum resources, new restrictions on the petrochemicals industry
and restrictions on transactions with the Iran Central Bank, including
financial transactions for the purchase of Iranian-origin crude oil. Further
legislation is pending in the US Congress which may enact additional
sanctions against Iran. The UK adopted sanctions prohibiting UK persons
from engaging in any financial transactions with the Iran Central Bank
or other financial institutions incorporated in Iran. Both the US and the
EU enacted strong sanctions against Syria including a prohibition on the
purchase of Syrian-origin crude and a US prohibition on the provision of
services by US persons. (Libya sanctions were enacted in early 2011 and
largely lifted by the end of the year.) In January 2012, the EU imposed an
embargo on Iranian crude, among other measures, to be phased in over a
period of months. The EU also adopted more stringent sanctions against
Syria including a prohibition on supplying certain equipment used in the
production, refining, or liquefaction of petroleum resources as well as
restrictions on dealing with the Central Bank of Syria and numerous other
Syrian financial institutions. BP monitors its activities with Sanctioned
Countries and keeps them under review to ensure compliance with
applicable laws and regulations of the US, the EU and other countries
where BP operates.
BP has interests in, and is the operator of, two fields (the North
Sea Rhum field and the Azerbaijan Shah Deniz field) and, serving the Shah
Deniz field, a gas marketing entity and an entity that owns a gas pipeline
(both entities and related assets located outside Iran), in which Naftiran
Intertrade Co. Ltd (NICO) and NICO SPV Limited (collectively NICO) or
Iranian Oil Company (UK) Limited (IOC UK) have interests. Production
was suspended at the North Sea Rhum field (in which IOC UK has a 50%
interest) in November 2010 and Rhum remains shut-in. It is presently
unclear when it may be possible to resume production. The Shah Deniz
field, its gas marketing entity and the entity that owns a pipeline (in which
NICO has a 10% or less non-operating interest) continues in operation in
full compliance with current US and EU sanctions. BP has no operations
in Iran and does not purchase or ship crude oil or other products of Iranian
origin. Joint venture participants in non-BP controlled or operated joint
ventures may purchase Iranian-origin crude oil or other components
as feedstock for facilities located outside the EU and US. BP does not
sell crude oil or other products into Iran, except that small quantities of
lubricants are sold to non-Iranian third parties for resale or use in Iran. Until
January 2010, BP held an equity interest in an Iranian joint venture that
blended and marketed lubricants for sale to domestic consumers in Iran.
BP sold its equity interest but continues to sell small quantities of lubricant
components to the current owner. Transactions with Iranian shipping
companies have been terminated.
Following the imposition in 2011 of further US and EU sanctions
against Syria, BP terminated all sales of crude oil and petroleum products
into Syria, though continues to supply aviation fuel to non-governmental
Syrian resellers outside of Syria. Prior to the imposition of Syrian sanctions
in 2011, BP sold lubricants through third parties and obtained crude oil and
refinery feedstocks for sale to third parties in Europe and for use in certain
of its non-US refineries. BP also bought and sold crude oil and refined
products into and from Syria and incurred port costs for vessels utilizing
Syrian ports. Sales and purchases to and from Syrian shipping companies
have been terminated.
64 BP Annual Report and Form 20-F 2011
Business review Safety
Over the past year, we have been developing and implementing a wide-
ranging programme to further enhance safety, risk management and
compliance across BP. This programme was initiated in response to the
Deepwater Horizon incident in the Gulf of Mexico in April 2010.
The programme emphasizes the continuing importance of personal
and process safety within BP. Process safety involves applying good design
principles, along with robust engineering, operating and maintenance
practices, to managing operations safely. For BP, this means the plant
is designed, maintained and operated properly to avoid failures such as
spills or explosions that can result in injuries to people and impacts to
the environment. It also means that employees and contractors have the
appropriate training and competencies to carry out work, as well as observing
applicable procedures and policies that help to prevent personal injury.
In 2011, BP reported two workforce fatalities, and we regret the
loss of these lives. One was a rail-related fatality in the US, the other died
as a result of an unauthorized transfer of fuel in South Africa.
Safety and operational risk
Safety management
Our safety and risk management approach is built on deep experience in
the oil and gas industry. This includes learning from the recommendations
of investigations into the Deepwater Horizon oil spill in 2010 and the Texas
City refinery explosion in 2005, as well as operations audits, annual risk
reviews, other incident investigations and from industry practice of sharing
experience.
There are three key principles which we intend to be at the heart of
our approach:
• Leadership fostering a culture where everyone is focused on safety, on
managing and reducing risk and on safe, reliable and compliant
operations.
• Our operating management system (OMS) being the way BP seeks to
operate.
• Effective checks and balances independent of the business line and self-
verification being carried out at all levels of the organization.
While we maintain our focus on processes, practices and protocols, we
also place great emphasis on how our workforce applies them, thereby
working to strengthen safety culture and workforce capability.
A dedicated function
We established the safety and operational risk (S&OR) function in early
2011. S&OR supports the business line in delivering safe, reliable and
compliant operations across the group’s operated businesses. It does this
in four ways:
• It sets and updates the requirements, including those in OMS, that are
used across the business for safety and operational risk management.
• It provides expert scrutiny of safety and operational risk, independent of
line managers – advising, examining and providing assurance about what
our operations do.
• It provides deep technical expertise to the operations.
• It has the authority to intervene and escalate issues to cause corrective
action to be taken.
S&OR, as of the end of 2011, was made up of a central team of around
300, as well as nearly 300 more who are deployed in BP’s businesses,
providing guidance and scrutiny and examining how safety and operating
risks are being assessed and managed on oil and gas production and
drilling rigs, at refineries and across all our operations. The head of S&OR
reports directly to the group chief executive.
The central team serves as the custodian of group requirements,
runs safety and operational risk audit and capability programmes and
endorses the appointment of individuals for designated safety-critical
roles. The central team includes some of BP’s top engineers and safety
specialists, several of whom have experience of other industries where
major hazards have to be managed, including the military, nuclear energy
and space exploration.
Our deployed S&OR teams work with our operating businesses – ranging
from upstream oil and gas development and production to refineries,
petrochemicals plants and retail networks. They help the businesses apply
our standards to their operations and they help provide assurance to the
group on how operational risks are being managed, business by business.
Operating businesses remain accountable for delivering safe,
reliable and compliant operations. They have the responsibility of managing
risks and bringing together people with the right skills and competencies.
Working in collaboration with deployed S&OR subject specialists for
guidance, they are subject to new levels of independent scrutiny and
assurance.
Governance
BP reviews risks at all levels of the organization, with our S&OR function
providing an independent view of safety and operational risk. While line
managers are responsible for identifying and managing risks, we place
strong emphasis on checks and balances, including both enhanced self-
verification by individual BP operations – such as drilling rigs or refineries
– and independent assurance by the S&OR function.
The board’s safety, ethics and environment assurance committee
(SEEAC) receives updates from the group chief executive and the head
of S&OR on the work of the group operations risk committee (GORC), on
BP’s performance in process and personal safety, and our monitoring of
major incidents and near misses across the group. Where appropriate other
senior managers will attend to provide briefings on safety, environmental
and operational integrity in their areas of responsibility. SEEAC also
receives information from the Independent Expert appointed to monitor
the implementation of recommendations made by the BP US Refineries
Independent Safety Review Panel following the 2005 explosion at our
Texas City refinery. See Board performance report on pages 120-133 for
further information on the activities of the board’s committees, including
SEEAC and the Gulf of Mexico committee.
Lessons learned from major incidents are being incorporated
into our operating management system and capability development
programmes.
Operating management system
Launched in 2008, our operating management system (OMS) serves as
our group-wide framework designed to drive a rigorous and systematic
approach to safety, risk management, and operational integrity across the
group. OMS integrates requirements regarding health, safety, security,
environment, social responsibility and operational reliability, as well
as related issues such as maintenance, contractor management and
organizational learning, into a common system.
The principles and standards of OMS are supported by detailed
group-wide practices, as well as other technical guidance materials.
The goal of OMS is to apply certain standards, group-defined practices
and group engineering technical practices on a group-wide basis in our
operations; these include, among others, the practices on assessment,
prioritization and management of risk; incident investigation; integrity
management; and environmental and social requirements for major
new projects.
Following the principle of continuous improvement, our OMS
evolves over time, for example to reflect implementation experience as
well as learnings from incident investigations, audits and risk assessments,
and by strengthening mandatory practices.
Transitioning to OMS
The transition to OMS requires operations to develop a local OMS that
describes how the operation addresses site-specific local operating risks,
applies group standards and practices and manages compliance with
applicable health, safety, security and environment legal requirements.
As part of the transition, operations conduct a gap assessment against
defined aspects of OMS and their local processes and procedures, and
then develop a prioritized gap-closure plan. To formally transition to the
system, operations issue a local OMS handbook for the workforce to
follow, and complete a management-of-change document that details
the changes involved.
BP Annual Report and Form 20-F 2011 65
Business review: BP in more depthBusiness review All of our operations, with the exception of those recently acquired, are
now applying our OMS to govern their BP operations and have begun
working to achieve conformance to standards and practices required by
OMS through the performance improvement cycle process. This includes
our global wells organization and global projects organization which were
set up in 2011. See page 69 for information about joint ventures.
Conformance and continuous improvement
The application of a comprehensive management system such as OMS
across a global company is an ongoing process. OMS defines the process
for BP operations to apply and conform to required standards and practices
on an ongoing basis, as well as to continuously improve their operational
performance. Every year, after the initial gap assessment, as part of the
annual performance improvement cycle each operating unit – for example,
a region like the Gulf of Mexico in our upstream business, or a refinery in
our downstream business – is required to conduct another gap assessment
and to develop a further prioritized gap closure plan. These actions are risk-
prioritized and form an integral part of each operation’s annual and three-
year planning cycle. Where appropriate, actions are aggregated to provide
common solutions. The results of these annual assessments are subject to
review by S&OR.
Capability development
BP strives to equip its staff with the skills needed to apply the systems
and processes to strengthen further our management of risk and process
safety. We have provided extensive and focused training programmes for
our operations personnel at all levels.
Training provision for operations personnel includes our operations
academy programmes for senior management, delivered in partnership
with the Massachusetts Institute of Technology, US; specialized
operational and technical management programmes, for example courses
in engineering and project management at the University of Manchester,
UK; and process safety and management training for our front-line
leaders, delivered under our Operations Essentials programme, which
seeks to embed the BP way of operating as represented by our OMS.
To date, approximately 24,000 managers, supervisors and technicians
have attended at least one workshop within the operations essentials
programme since 2008; additionally, more than 180,000 eLearning
modules have been completed.
We communicate our expectations for qualified, competent and
experienced contractor personnel through our procurement process and
contractual provisions.
Safer drilling
Since the beginning of 2011, all BP-operated drilling and wells activity in
the world has been conducted through a single global wells organization
(GWO). By bringing functional wells expertise into a single organization
with common global standards, we are working to standardize BP drilling
and wells operations with the intent of delivering safe and compliant
wells. GWO works with our safety and operational risk function with a
view to reducing risk in drilling and so reduce the likelihood of an oil spill
or incident occurring through prevention efforts. We also aim to reduce
the consequences should an incident occur by focusing on containment,
spill response, relief wells and crisis management. See Exploration and
Production on page 80 for information about the upstream reorganization.
Oil spill prevention
We are implementing enhanced drilling safety standards across the
organization.
Blowout preventers
We have issued standards for the maintenance, testing, verification and use
of subsea blowout preventers (BOPs). For example, we require dynamically
positioned drill rigs contracted by BP to have no fewer than two blind
shear rams and a casing shear ram sitting within the blowout preventer
to enhance its reliability in cutting the drill pipe and sealing the well in the
event of a blowout or other operational emergency. We require third-party
verification that testing and maintenance of our subsea BOPs are performed
66 BP Annual Report and Form 20-F 2011
in accordance with industry recommended practice. In addition, BP requires
that remotely operated vehicles can activate these BOPs in an emergency.
Cementing
We are enhancing oversight of cementing services by implementing new
standards in cement design and testing. We have also strengthened the
technical approval process for critical cementing operations, and have
brought additional expertise into BP to oversee this. We are implementing
quality audits of our cementing contractors’ laboratories.
Well start-up procedure
We have introduced a new well start-up procedure. The checklist covers
a range of operational areas and verification of conformance is required
by leaders from the business line and S&OR before operations can begin
on certain wells and on new rigs. In one case, as a result of this process,
BP rejected a contractor rig put forward by another operator due to it not
meeting BP’s standards.
These requirements are designed to help identify and mitigate risks
prior to contractors’ drilling rigs being put into service for BP. Interventions
to date have included repairs to safety systems, additional training of
personnel, modifications to equipment, verification of quality and inspection
records, revised and clarified roles and responsibilities, enhanced training
requirements, and enhanced risk management techniques.
See Environment and social responsibility section on pages 69-73
for further information on BP’s approach to oil spill contingency planning
and response.
Bly Report – internal investigation recommendations and actions taken
In the immediate aftermath of the Deepwater Horizon oil spill, BP launched
an internal investigation, drawing on the expertise of more than 50
technical and other specialists within BP and the industry. The investigation
team was led by BP’s head of safety and operations, and worked
independently from BP’s other spill response activities and organizations.
The BP investigation (the Bly Report) concluded that no single cause
was responsible for the accident. The investigation instead found that a
complex, inter-linked series of mechanical failures, human judgements,
engineering design, operational implementation and team interfaces,
involving several companies including BP, contributed to the accident.
The recommendations
As a result, the investigation team made 26 recommendations specific
to drilling, which we accepted and are working to implement across our
worldwide drilling operations. The recommendations include measures
to improve contractor management, as well as to strengthen design and
assurance on blowout preventers (BOPs), well control, pressure-testing for
well integrity, emergency systems, cement testing, rig audit, verification,
and personnel competence.
Interim measures
Shortly following the publication of the Bly Report, BP developed interim
measures to immediately address the eight key findings contained
within the report. An interim guidance document was issued to each of
our 14 operating regions in December 2010 which contained specific
requirements, including the well start-up check list. This guidance
continues to be in effect across all BP drilling and completions operations.
We continue to progress implementation of the recommendations from
the Deepwater Horizon investigation report and that work will ultimately
replace the interim guidance.
Implementing the recommendations
Implementing the 26 recommendations across the group requires
detailed work and many activities – from creating new practices and
guidance, training and testing appropriate staff, changing requirements and
expectations of our contractors, and establishing verification processes to
assure the changes are sustainably embedded. We have a team of around
85 people working full-time on this.
A project of this scale takes time; we must work to assure that all
actions are delivered to a high standard across all of our well operations,
and independently verified by our S&OR audit or internal audit function.
Business review We have estimated and communicated delivery timelines for each of the
recommendations and will continue to provide periodic updates of our
progress. These timelines are based on existing facts and circumstances
and can shift due to complexity, resource availability and evolving
regulatory requirements.
The BP board has identified an independent expert to provide
further oversight and assurance regarding the implementation of the
Bly Report recommendations. The independent expert’s engagement is
expected to commence in the latter half of May 2012.
Progress update
At the end of 2011, four of the Bly Report recommendations have been
completed. These were:
• Recommendation 6: to propose a recommended practice for foam
cementing to the American Petroleum Institute.
• Recommendation 8: to strengthen the technical authority’s role in
cementing and zonal isolation.
• Recommendation 13: to strengthen our rig audit process to improve
closure and verification of audit findings across the rigs we own and
contract.
• Recommendation 14: to establish key performance indicators for well
integrity, well control, and rig safety-critical equipment.
We continue to make progress on all of the remaining recommendations
largely in line with our planned schedule, with a further 12
recommendations expected to be completed in 2012. Progress is tracked
in the quarterly HSE and operations integrity report supplied to the
executive team. See bp.com/internalinvestigation for the full report and
quarterly updates on progress.
External investigations
In addition, there have been a number of external investigations, including
those of the National Commission on the BP Deepwater Horizon Oil Spill
and Offshore Drilling (oilspillcommission.gov) and the Joint Investigation
Team of the Bureau of Ocean Energy Management, Regulation and
Enforcement and the United States Coast Guard
(boemre.gov/ooc/press/2011/press0914.htm). These reports were
consistent in their conclusions that the accident resulted from multiple
causes and was due to the actions of multiple parties. We are committed
to understanding the causes, impacts and implications of the Deepwater
Horizon incident and to learn and act on lessons from it. As part of this
commitment, BP is reviewing the recommendations from government and
industry reports.
Capping and containment
We have developed a mobile deepwater well capping package that
includes about 250 pieces of speciality equipment. Maintained in a
constant state of readiness in Houston, it is designed to be deployed by
air freight and arrive wherever it is needed in just a few days.
We also share capping and containment equipment with other
operators in the Gulf of Mexico, through the Marine Well Containment
Company, as well as with operators in the UK North Sea. Further, BP
provided project management for the Oil and Gas UK Oil Spill Prevention
and Response Advisory Group to develop a next generation well capping
system, now available in Europe, and is one of nine companies working in
the Subsea Well Response Project to enhance the industry’s capability to
respond globally to subsea well control events.
Relief wells
In responding to the Gulf of Mexico oil spill, we drilled two relief wells.
Prior to drilling a deepwater well, BP operations now have relief well plans
in place with equipment identified that can be moved to the site if needed.
This is of particular benefit in areas that do not have the same infrastructure
and support as more active basins such as the Gulf of Mexico.
Oil spill preparedness
We continue to develop and assimilate lessons from the response to the
Gulf of Mexico oil spill. In 2011, as a priority we incorporated many of
these lessons into new technical requirements for BP operations that drill
in deepwater. Conformance with these requirements is mandatory for all
operations drilling in water deeper than 1,000 feet and is subject to a formal
assessment and sign-off by technical experts, S&OR and senior leaders.
During 2011, we began implementing these requirements in Angola, the
North Sea, Brazil, the US and Egypt, where we have deepwater drilling
active or planned for 2012.
Crisis management
Crisis management planning is essential to respond effectively to
emergencies and to avoid a potentially severe disruption in our business
and operations. The intention is to build on interim requirements introduced
in 2011 for deepwater drilling to put in place group-wide practices for both
oil spill preparedness and response and crisis management.
During the response, we updated our incident action plan – an
operational crisis planning tool – every 12-24 hours, which allowed us to
have recent information to aid decision making. This was made possible by
developing a common operating picture (COP) which helped us collect and
present information in a way that enabled faster, better-informed decisions.
The COP created an integrated view across more than 200 different data
types. It provided an instant, interactive picture of the spill status and the
activities of all responders.
See Environmental and social responsibility on pages 69-73 for
further information on BP’s approach to oil spill contingency planning and
response.
Safer refining
We have been working hard to apply the lessons learned from the
tragic accident in our Texas City refinery in 2005 and are committed to
implementing the recommendations of the BP US Refineries Independent
Safety Review Panel.
Systematic management
The core business of our refineries is the safe storage, handling and
processing of hydrocarbons which involves systematic management of the
associated operating risks. In seeking to manage these risks, measures are
taken by our refineries to:
• Prevent loss of hydrocarbon containment, such as oil spills, through
well-designed, maintained and operated equipment.
• Reduce the likelihood of ignition of any hydrocarbon releases which may
occur through controlling ignition sources.
• Provide safe locations, emergency procedures and other mitigation
measures in the event of a fire or explosion occurring.
For example, across our refining business we are spending more than
$700 million to install safety shelters for individuals, move people further
away from hydrocarbon containing equipment and reduce the number of
vehicles in our sites.
In 2011, we enhanced and standardized a number of technical
practices that we intend to implement across our refining business in 2012
and 2013, including practices pertaining to:
• Control of work practices including rules for what work is done, who it is
done by, where it is done, when it is done and how it is done.
• Isolation of equipment from hydrocarbon and other energy sources to
safely allow maintenance.
• Design, operation, maintenance for instrumented systems throughout
their lifecycle to reliably achieve or maintain a safe operating state if
unacceptable or dangerous process conditions are detected.
• Procedures and equipment requirements to assure safe handling of
hydrogen sulphide containing streams.
• Design and operation of existing fired heaters.
• Identifying operating limits for our processes and equipment.
Risk assessment, prioritization and management
In 2011, all refineries used a consistent methodology to identify risks and
prioritize mitigation actions, including addressing low probability, high
consequence scenarios. Action plans have been developed for each risk
and reviewed by authorized line and S&OR leaders. A multi-year risk profile
reduction plan has been approved for each refinery and, learning from
BP Annual Report and Form 20-F 2011 67
Business review: BP in more depthBusiness review Mr Wilson reports to the board through the chairman of BP’s safety,
ethics and environment assurance committee. In addition to an annual
written report, he makes periodic oral reports of his observations to
the committee, in which he gives status updates on BP’s progress in
implementing the Panel’s recommendations.
Safety performance
Oil spills and loss of primary containment
We monitor the integrity of our operations, tanks, vessels and pipelines
used to produce, process and transport oil and other hydrocarbons – with
the aim of preventing the loss of material from its primary containment.
Accordingly, we record losses of material, including hydrocarbons, from our
assets, and losses or spills that reach land or water.
The loss of primary containment metric below includes unplanned
or uncontrolled releases from a tank, vessel, pipe, rail car or equipment
used for containment or transfer within our operational boundary, excluding
non-hazardous releases such as water.
The US government and third parties have announced various
estimates of the flow rate or total volume of oil spilled from the Deepwater
Horizon incident. The multi-district litigation beginning in 2012 in New
Orleans will address the amount of oil spilled. See Financial statements –
Note 36 on page 233 for information about the volume used to determine
the estimated liabilities.
Loss of primary containment and oil spills (excluding Deepwater
Horizon oil spill in respect of 2010 volume)
Loss of primary containment –
number of all incidentsa
Loss of primary containment –
number of oil spillsb
Number of oil spills to land and
water
Volume of oil spilled
(thousand litres)
Volume of oil unrecovered
(thousand litres)
2011
2010
2009
361
228
102
556
281
418
261
142
537
234
122
1,719
1,191
758
222
a Does not include either small or non-hazardous releases.
b Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).
Process safety
BP uses a disciplined framework for managing the integrity of hazardous
operating systems and processes. We apply a combination of good design
principles, engineering, and operating and maintenance practices to help
deliver process safety performance and we monitor the number of process
safety events occurring across our operations. The recently introduced
American Petroleum Institute RP-754 standard, which sets out leading
and lagging process safety indicators, organized into different tiers is used
as the basis for our internal process safety-related reporting. API tier 1
process safety events are the losses of primary containment of greatest
consequence – causing harm to a member of the workforce or costly
damage to equipment, or exceeding defined quantities. Seventy-four tier 1
process safety events were reported in BP in 2011.
Personal safety
BP reports publicly on its personal safety performance according to
standard industry metrics. In 2011, our overall reported recordable injury
frequency (RIF) was 0.36, compared with 0.61 in 2010 and 0.34 in 2009.
Our reported day away from work case frequency (DAFWCF) in 2011
was 0.090, compared with 0.193 in 2010 and 0.069 in 2009. The 2010
group personal safety data was affected by the Gulf Coast response effort.
our review of all the plans, we are introducing additional requirements to
enhance the mitigation of similar risks across our refining business.
Operational planning and controls
Each BP-operated entity develops an annual plan drawing on the output
from the performance improvement cycle including the risk management
process. The plan is prioritized with the aim of continually driving reductions
in the level of risk at the sites. We plan our work taking account of the
capacity needed to deliver the safety-related activities required.
Control of work has been an area of major focus in our refining
business since 2008. We continue to see improvement in the execution
of our maintenance planning, scheduling and work activities across our
refining sites as the overall control of work process is better understood,
learning shared and efficiency opportunities identified.
Competence and capability
Refinery leaders are experienced operations professionals with many
years’ experience within the industry and have typically attended the BP
Operations Academy. Each refinery, with S&OR direction and expertise,
is developing a consistent competency framework against which safety
critical roles are assessed. The US refineries completed process safety
competency assessments of over 3,500 employees in safety-critical roles
and developed gap closure plans in 2011.
A key element within this competency development plan is the
development of high fidelity process simulators. These will be used to train
operators via simulations to respond to low probability, high consequence
scenarios, similar to methods used with airline pilots.
Measurement, evaluation and corrective action
Regional vice presidents conduct performance reviews at each refinery.
We now use a set of common safety metrics that are standard across all
sites to help us proactively identify opportunities for improvement.
A quarterly assurance process has been introduced to enable S&OR
to develop an ongoing, independent view of OMS conformance by the
sites. Each site is assessed on their OMS self-assessment processes, the
strength of existing risk mitigations and progress on risk reduction plans.
Periodic S&OR audits against OMS requirements provide valuable insights
from experts outside the site and result in actions to close identified gaps.
In 2011, we strengthened and standardized our approach to
incident learning in our refining business, issuing briefings and alerts
on lessons learned from incidents and near misses and requiring each
refinery to assure that similar risks are assessed and appropriate actions
completed.
Reports of the US refineries’ Independent Expert
L. Duane Wilson was appointed in 2007 by the board as an Independent
Expert to provide an objective assessment of BP’s progress in
implementing the recommendations of the BP US Refineries Independent
Safety Review Panel (the Panel) aimed at improving process safety
performance at BP’s five US refineries. Mr Wilson is expected to deliver
his fifth annual report in April 2012, and BP will publish it at bp.com/
independentexpert. As in prior years, BP will have an opportunity to review
and comment on Mr Wilson’s draft report for factual accuracy, but he is
solely responsible for the report’s ultimate content.
The Independent Expert conducts his assessment of BP’s
implementation of the Panel’s recommendations both through sampling
and in-depth monitoring, evaluation and confirmation. Mr Wilson visited
each BP US refinery at least twice in 2011 and interviewed personnel at
many levels in the organization. He also engaged regularly with senior and
executive management, both within Refining and Marketing and our safety
and operational risk function, to gauge implementation progress. Mr Wilson
also reviews progress reports and other documentation from BP. These
include implementation status reports, process safety performance
reports, overtime reports (to monitor the potential for worker fatigue), open
and overdue process safety action item reports, incident investigations
reports and safety audit reports.
68 BP Annual Report and Form 20-F 2011
Business review Working with partners and contractors
BP, like our industry peers, rarely works in isolation – we need to work with
suppliers, contractors and partners to carry out our operations. In 2011,
more than 55% of the 374 million hours worked by BP were carried out by
contractors.
Our ability to fulfil our corporate responsibility depends in part
on the conduct of our suppliers, contractors and partners. We address
this in a variety of ways, from training and dialogue to confirming
operational standards through legally binding agreements. When we select
contractors, our due diligence is designed to identify safety, bribery and
corruption, money laundering and trade sanctions risks. We expect our
suppliers, contractors and partners to comply with legal requirements and
operate consistently with the principles of our code of conduct when they
work on our behalf.
Within our operating management system we have group-wide and
business-specific requirements and practices for working with contractors.
The objective is to provide assurance that goods, equipment and services
provided by third parties meet contractual and BP requirements and
that there is a consistent, shared understanding of responsibilities. For
example, in our drilling operations, where we have evaluated differences
between our own standards and those of contractors, we require bridging
documents to be put in place. These define how two or more safety
management systems co-exist to allow co-operation and co-ordination
between BP and the contractor.
Contractor management review
Following the Deepwater Horizon oil spill, we began an in-depth review
of contractor management practices, with the aim of documenting and
learning from best practice throughout BP and across a number of sectors
and industries that use contractors in potentially dangerous activities. We
studied 21 major organizations in six different sectors – airlines, mining,
construction, pharmaceuticals and chemicals, nuclear and space.
We found that these organizations working in potentially high-
risk arenas tended to have fewer and longer-lasting relationships with
contractors, supported by shared structures and practices. Clearly
defined responsibilities and decision rights at every stage of each process
are needed to make contractor relationships work – including training,
monitoring and auditing. Rigorous qualification of suppliers, including
competency assessments for critical roles, is also important.
The findings of this review are informing our contractor
management approach, with initial work focusing on contracts in our
upstream supply chain that involve potentially high-consequence activities.
Our partners in joint ventures
We seek to work in partnership with companies that share our
commitment to ethical and sustainable working practices. However, in
some of our joint ventures, we do not directly control how our partners and
their employees approach these issues.
Typically, our level of influence or control over a project or operation
is linked to the size of our financial stake compared to other participants.
In some joint ventures we act as the operator. Where we are the operator,
and where legal and contractual arrangements allow, our policies,
standards and operating systems apply.
In other cases, for example where one of our partners is the
designated operator or where the operator is a joint venture company
owned by BP and other partners, we are not the day-to-day operator. In
those cases our OMS provides for our businesses to consider whether
the management system used by the operator provides similar levels of
risk and performance management to our own. We seek to influence our
partners through dialogue and constructive engagement.
In 2011, BP initiated a review into our approach to the management
of our relationships with non-operated joint venture operators and partners.
This work includes safety and operational risk as well as bribery and
corruption risk.
Environmental and social
responsibility
The world’s demand for energy is increasing and our business of finding
and producing some of that energy means we operate in increasingly
diverse locations globally. Many of these locations have environmental and
social sensitivities.
To BP, working responsibly means managing our impacts on the
areas where we operate, and making this a core principle in all of our
activities. From the initial planning stages of a new project through to
its eventual decommissioning and any remediation work that follows,
our operating management system (OMS) lays out the standards and
processes required for environmentally and socially responsible operations.
Wherever we work, we strive to minimize our impact on the
environment – whether to land, air, water or wildlife – and to ensure that
local people are engaged, human rights are respected and cultural heritage
is conserved.
Our environmental and social practices
We are taking an increasingly systematic approach to the management of
the environmental and social impacts of our projects. Our environmental
and social practices, which form part of our OMS, set out how the major
projects to which they apply should identify and manage environmental
and social impacts. The practices also apply to projects that involve new
access, projects that could affect an international protected area and some
BP acquisition negotiations.
The practices help us deliver on the intent of the relevant sections
of the OMS, the BP code of conduct and on our external commitments.
They include several key requirements on impact assessment, security
and human rights, indigenous people, international protected areas,
greenhouse gas emissions, energy management, water management,
ozone depleting substances, drilling wastes, and moving communities.
Early in the planning stage, applicable projects complete a screening
process to identify environmental and social impacts that could arise from
their activities. Between implementation in April 2010 and the end of 2011,
nearly 60 projects had completed the screening process with the support
of a trained and independent screening facilitator.
More information about our approach to environmental and
social issues may be found in the BP Sustainability Review and on
bp.com/sustainability.
Working in internationally protected areas
Our environmental and social practices require the projects to which they
apply to understand the potential to affect international protected areas.
The UNEP World Conservation Monitoring Centre’s World Database on
Protected Areas is used to inform this screening process. Our international
protected areas classification includes areas designated as protected by the
International Union for the Conservation of Nature (categories I-IV), Ramsar
and World Heritage sites, as well as areas proposed for protected status.
Where screening indicates that a proposed BP project may
potentially affect an international protected area a high-level risk
assessment is carried out. Our safety and operational risk function provides
an independent review to inform the risk assessment, and before any
physical activity begins permission is sought from senior management,
together with appropriate mitigation measures. The Great Australian Bight
Project completed this process in 2011.
Oil spill contingency planning and response
Applicable laws generally include requirements for dealing with the
environmental and socio-economic impacts of oil spills or leaks. In some
countries, regulators require as part of our licences to operate that plans
are in place for responding to accidents and unplanned events such as
oil spills.
BP Annual Report and Form 20-F 2011 69
Business review: BP in more depthBusiness review The Deepwater Horizon oil spill demanded a response at an order of
magnitude never required before. We learned a great deal and made
advances in response technology and systems. As a result we are updating
our group requirements and are sharing our knowledge with the industry
and regulators.
In 2012, we will be working on the development of enhanced
oil spill preparedness and response requirements for all BP entities that
handle oil in a way that gives rise to a risk of an oil spill. Once these
requirements are incorporated into OMS, they will require relevant
businesses to follow a planning process to predict how the spilled oil will
behave; identify, assess and understand the environmental and social
sensitivities at risk; define effective response strategies and confirm that
appropriate response capabilities are in place. This practice will incorporate
our deepwater technical requirements, further enabling a single, consistent
process across BP.
Sensitivity mapping
Understanding the environmental and socio-economic sensitivities where
we operate is an important part of planning for an effective response. We
obtain sensitivity information from many sources, including environmental
and social impact assessments (ESIAs) for many of our projects. These
ESIAs include information about the potential environmental and socio-
economic impacts of planned activities and also the potential impacts that
might occur in the event of an unplanned event, such as an oil spill. In 2011,
we have used high resolution satellite imagery to enhance our sensitivity
mapping across thousands of miles of coastlines, and submersibles to
characterize the deep ocean. This has helped us better understand our
environmental risks in regions like Angola, Brazil and the US.
Contingency planning
Identifying and assessing environmentally and socio-economically
sensitive areas helps us to develop appropriate oil spill response and crisis
management plans. The objective is to use response techniques to avoid
or minimize the environmental and socio-economic impact of a spill to the
extent feasible based upon an assessment of the sensitivity of the local
environment. These plans are backed up by robust response ‘capability’, the
tools and people required to mount an effective response to an incident.
How we work with designated government regulatory bodies in
the event of a spill is critical. Sharing lessons learned and maintaining a
dialogue with regulators in the regions where we operate is an important
part of our approach. In many countries where BP operates, the regulator
will ultimately determine the procedures to deal with the environmental and
socio-economic impact.
Acute response plans are often focused on the physical
containment and recovery of the spilled oil, though they also recognize that
components in dispersed oil will be subject to processes of biodegradation,
which may be facilitated and accelerated by the application of chemical
dispersants.
For onshore operations, for example, BP refineries’ spill response
plans include passive and active containment measures that are designed
for the specific location and types of operations.
In the event of concurrent spills at multiple locations, each affected
facility would activate its independent oil spill response plan and respond
accordingly. Although responding to multiple spills of the same magnitude
and complexity as occurred in the Gulf of Mexico in 2010 would be a
challenge for the group, our response plans are not interdependent.
See Safety on pages 65-69 for further information on BP’s approach
to oil spill prevention and preparedness.
Gulf of Mexico – our long-term commitments
See Gulf of Mexico oil spill on pages 76-79 for further information on
BP’s response to the incident and environment and economic restoration
efforts.
Canadian oil sands
Canada’s oil sands are believed to hold one of the world’s largest untapped
supplies of oil, third in size to the resources in Saudi Arabia and Venezuela.
BP is involved in three oil sands projects, all of which are located in the
province of Alberta. Development of the Sunrise project, our joint venture
operated by Husky Energy, is under way, with production from Phase 1
expected to start in 2014. The other two proposed projects – Pike, which
will be operated by Devon, and Terre de Grace, which will be BP-operated
– are still in the early stages of development.
We reviewed and approved the decision to invest in Canadian oil
sands projects, taking into consideration greenhouse gas (GHG) emissions,
impacts on land, water use and local communities, and commercial
viability. As with all joint ventures in which we are not the operator, we will
monitor the progress of these projects and the mitigation of risk.
The extraction process to be used, in situ steam-assisted
gravity drainage (SAGD) technology, involves the injection of steam
underground. The steam liquefies the bitumen, allowing it to flow to the
surface through production wells. This production technique reduces land
disturbance and aligns to our strengths, particularly to our expertise with
wells and improving large-scale reservoir performance. Unlike mining,
in situ processes create a smaller physical footprint and do not involve
tailing ponds.
A key concern around oil sands operations using SAGD is the
amount of greenhouse gas emissions produced for steam generation
and the processing of the produced bitumen. A ‘well-to-wheels’ study
conducted in 2009, which measured total GHG emissions from production
through to consumption, found the lifecycle emissions for oil sands-based
products to be 5-15% higher than those from products from average crude
oils consumed in the US.
Climate change
Climate change represents a significant challenge for society, the energy
industry and BP. In response to the challenges and opportunities, BP is
taking a number of practical steps, including investing in lower-carbon
energy products such as biofuels and wind, and ventures focused on
sustainable energy solutions; and seeking to manage our own GHG
emissions through a focus on operational energy efficiency, reductions
in flaring and venting and the engineering design for new projects. We
see natural gas playing a key strategic role as a lower-carbon fuel that is
increasingly secure and affordable. We also consider the potential impacts
of a changing climate on our operations.
Greenhouse gas emissions
Our direct GHG emissionsa were 61.8 million tonnes (Mte) in 2011,
compared with 64.9 Mte in 2010. This decrease of 3.1 Mte is primarily
explained by the temporary reduction in activity in some of our businesses
as a result of maintenance work and also by the sale of assets as part of
our disposal programme. We achieved 0.2 Mte of sustainable emissions
reductions in 2011.
Over the long-term it is likely that the carbon intensity of parts of
our business will increase. In our upstream operations this is because
we expect to move further into technically difficult and potentially more
energy intensive areas. The intensity of certain refining operations may also
increase with the trend towards processing heavier crudes which requires
more energy.
In 2010 we did not report on GHG emissions associated with
the Deepwater Horizon incident or response. We have since estimated
the CO2 equivalent emissions from response activities in 2010 to be
approximately 481,000 metric tonnes, which includes major vessels
deployed. This figure does not include emissions associated with the
‘vessels of opportunity programme’, the onshore vehicles and equipment
and the incident itself, which are estimated to be minor.
a We report GHG emissions on a CO2-equivalent basis, including CO2 and methane. This represents
all consolidated entities and BP’s share of equity-accounted entities except TNK-BP.
70 BP Annual Report and Form 20-F 2011
Business review Greenhouse gas regulation
In the future, we expect that additional regulation of GHG emissions
aimed at addressing climate change will have an increasing impact on
our businesses, operating costs and strategic planning, but may also
offer opportunities for the development of low-carbon technologies and
businesses. See Regulation of the group’s business – Greenhouse gas
regulation on page 109.
To help address potential future regulation, we factor a carbon cost
into our investment appraisals and engineering designs for new projects.
We do this by requiring larger projects, and those for which emissions
costs would be a material part of the project, to apply a standard carbon
cost to the projected GHG emissions over the life of the project. The
standard cost is based on our estimate of the carbon price that might
realistically be expected in particular parts of the world. In industrialized
countries, this standard cost assumption is currently $40 per tonne of
CO2 equivalent. We use this as a basis for assessing the economic value
of the investment and as one consideration in optimizing the way the
project is engineered with respect to emissions. This helps to assess our
investments under scenarios in which the price of carbon emissions is
higher than the current market price.
Adaptation to impacts resulting from a changing climate
We have funded research into the impacts of climate change on our
operations for many years, to better understand the possible types of
climate change impacts, potential effects on the environment and on our
facilities and to develop potential responses to these impacts.
In the Beaufort Sea in Canada, for example, where BP is in the early
stages of an oil exploration project, we have collaborated with ArcticNet,
a local research organization devoted to understanding climate change
impacts in the Arctic, on a two-year environmental baseline study. For
ArcticNet the information gleaned will provide valuable data for analysis,
while for BP the data will provide a useful baseline with which to compare
future research, helping us to understand and chart the effects of climate
change in this deepwater ocean environment.
Projects implementing our environmental and social practices are
required to assess the potential impacts to the project from the changing
climate. Any significant potential impacts identified are managed via the
project’s risk management process. To support this risk assessment
process, we continually update and improve our climate impact modelling
tools. In the Caspian region, for example, we are working with meteorology
and oceanology consultants to enhance the existing modelling capability
and develop a regional climate model to provide long-term forecasts and
trends of wind speed, wave height and sea level.
We also have a guide on adapting to a changing climate which is
available for all projects and operations. This document sets out guidance
to help businesses across BP make appropriate allowance for the potential
effects of climate change.
For projects where climate change impacts are identified as a
risk, our engineers typically seek to address them like any other physical
and ecological hazard, rather than as a discrete category. We periodically
review and adjust existing design criteria and engineering technology
practices. For example, we adapt our drainage design practices based
on the frequency and severity of storms as well as rainfall and runoff
amounts; if storms are anticipated to become more frequent, or heavier,
the engineering design will accommodate this.
Water
We are taking a more strategic approach to water use and assessing
water-related risks within our businesses, including those associated with
the growing global issue of water scarcity. Our focus is on increasing
our ability to forecast, measure and manage emerging water risks and
engaging with external organizations to better understand these risks and
develop sustainable water management practices, particularly where water
is scarce.
With our industry association IPIECA, BP has also participated in the
development of a new customized oil and gas version of the World
Business Council for Sustainable Development’s Global Water Tool, which
helps oil and gas companies map their water use and assess risks of
freshwater scarcity and related biodiversity impacts, across their portfolio
of sites. BP has also invested in a water risk management tool, which is
currently being piloted at a number of BP’s operations, to investigate the
risks of water use and availability at a local level.
In the future, these tools will provide BP with a means of
consistently defining water risks and opportunities across a number of
our operations, enabling us to establish a more consistent approach to
managing water issues throughout the group.
Hydraulic fracturing
Technology helps to make it possible for BP to extract unconventional gas
resources safely and responsibly to help meet the growing global demand
for gas. Unconventional gas can be classified into three categories: tight
gas, coalbed methane and shale gas. BP is pursuing unconventional gas in
the US and in other countries such as Algeria, Oman and Indonesia.
Hydraulic fracturing, or ‘fracking’, is a process of pumping water
mixed with a small proportion of sand and chemicals underground at
high pressure to fracture the rock and release gas that would otherwise
not be accessible. Some stakeholders have expressed concerns about
the potential environmental impacts. BP recognizes these concerns and
seeks to apply responsible well design and construction, surface operation
and fluid handling practices and engages constructively with government
and industry to promote sound policies and regulation that protect water
resources and the environment. We expect that many of the jurisdictions
in which we operate will adopt stricter regulations governing ‘fracking’ and
other unconventional gas extraction technologies in the future which could
adversely affect our operations and profitability in our unconventional gas
business.
Environmental expenditure
Environmental expenditure relating to
the Gulf of Mexico oil spill
Spill response
Additions to environmental
remediation provision
Other environmental expenditure
Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental
remediation provision
Additions to decommissioning
2011
2010
$ million
2009
586
13,628
1,167
704
819
53
510
929
716
911
55
361
–
–
701
955
70
588
169
provision
4,596
1,800
BP continues to incur significant costs related to the 2010 Gulf of Mexico
oil spill. Of the spill response cost of $586 million incurred in the year (2010
$13,628 million) $336 million (2010 $1,043 million) remains as a provision
at 31 December 2011.
The environmental remediation provision includes amounts
for BP’s commitment to fund the Gulf of Mexico Research Initiative,
natural resource damage (NRD) assessment costs and emergency NRD
restoration projects. In addition, during the year BP entered a framework
agreement with natural resource trustees for the United States and
five Gulf Coast states, providing for up to $1 billion to be spent on early
restoration projects to address natural resource injuries resulting from
the Gulf of Mexico oil spill. Further amounts for spill response costs were
provided during the year primarily to recognize increased costs of shoreline
clean-up, patrolling and maintenance and vessel decontamination. The
majority of the active clean-up of the shorelines had been completed by the
end of the year.
See Financial statements – Note 2 on page 190, Note 36 on page
231 and Note 43 on page 249 for further information relating to the Gulf of
Mexico oil spill.
BP Annual Report and Form 20-F 2011 71
Business review: BP in more depthBusiness review Operating and capital expenditure on the prevention, control, abatement
or elimination of air, water and solid waste pollution is often not incurred
as a separately identifiable transaction. Instead, it forms part of a larger
transaction that includes, for example, normal maintenance expenditure.
The figures for environmental operating and capital expenditure in the table
are therefore estimates, based on the definitions and guidelines of the
American Petroleum Institute.
Environmental operating expenditure of $704 million in 2011 was at
a similar level to 2009 and 2010.
Similar levels of operating and capital expenditures are expected in
the foreseeable future. 2011 capital expenditure was lower than in 2010
due to the completion of various capital projects in our US refineries.
In addition to operating and capital expenditures, we also create
provisions for future environmental remediation. Expenditure against such
provisions normally occurs in subsequent periods and is not included in
environmental operating expenditure reported for such periods.
Provisions for environmental remediation are made when a clean-
up is probable and the amount of the obligation can be reliably estimated.
Generally, this coincides with the commitment to a formal plan of action or,
if earlier, on divestment or on closure of inactive sites.
The extent and cost of future environmental restoration,
remediation and abatement programmes are inherently difficult to
estimate. They often depend on the extent of contamination, and
the associated impact and timing of the corrective actions required,
technological feasibility and BP’s share of liability. Though the costs of
future programmes could be significant and may be material to the results
of operations in the period in which they are recognized, it is not expected
that such costs will be material to the group’s overall results of operations
or financial position.
Additions to our environmental remediation provision increased in
2011 largely due to changes in scope reassessments of the remediation
plans of a number of our US retail sites. The charge for environmental
remediation provisions in 2011 included $12 million in respect of provisions
for new sites (2010 $54 million and 2009 $6 million).
In addition, we make provisions on installation of our oil- and
gas-producing assets and related pipelines to meet the cost of eventual
decommissioning. On installation of an oil or natural gas production facility
a provision is established that represents the discounted value of the
expected future cost of decommissioning the asset.
The level of increase in the decommissioning provision varies with
We are a signatory to two voluntary agreements with implications for
specific aspects of human rights: the UN Global Compact, which helps
businesses align their operations and strategies with 10 principles,
including some that are related to human rights, and the Voluntary
Principles on Security and Human Rights, which define good practice for
security operations in extractive industry companies. We have contributed
to the work of oil and gas industry organization IPIECA’s human rights task
force, which works on human rights issues and develops good practice
guidance for companies in our industry.
In 2011 the UN Human Rights Council unanimously endorsed the
Guiding Principles on Business and Human Rights. These outline specific
responsibilities for businesses in relation to human rights. We participated
in discussions on the development of the Guiding Principles, and in 2011
we completed a comparison between our current policies and practices
and the expectations in the Guiding Principles, to help us identify what
work will be needed to achieve alignment with the principles.
BP’s code of conduct makes it clear that certain provisions, such
as BP’s stance on the rights and dignity of communities, relate directly
to human rights. See page 31 for further information about our code of
conduct.
Revenue transparency and business ethics
As a member of the Extractive Industries Transparency Initiative (EITI), we
work with governments, non-governmental organizations and international
agencies to improve transparency in this area. In several countries that are
in the process of becoming EITI compliant, BP is supporting the process;
for example, BP is an active member of the Trinidad & Tobago EITI steering
committee. In countries that have achieved EITI compliance, including
Azerbaijan and Norway, BP submits an annual report on payments to their
governments.
We have taken part in consultations in relation to new or proposed
revenue transparency reporting requirements in the US and Europe for
companies in the extractive industries. BP will fully comply with the
appropriate mandatory regulations when they come into effect.
We are working to respond effectively to the standards flowing
from the UK Bribery Act as well as other anti-corruption legislation such
as the Foreign Corrupt Practices Act in the US. Bribery and corruption are
serious risks in the oil and gas industry. Our code of conduct requires that
our employees or others working on behalf of BP do not engage in bribery
or corruption in any form in both the public and private sectors.
the number of new fields coming onstream in a particular year and the
outcome of the periodic reviews. There was a significant increase in 2010,
driven by activity in the Gulf of Mexico and this trend has continued in
2011 as a result of changes in estimation and detailed reviews of expected
future costs; the majority of the increase related to our sites in Trinidad, the
Gulf of Mexico and the North Sea.
In 2011, we issued a group-wide anti-bribery and corruption
standard, which applies to all BP employees and contractors. The standard
requires annual bribery and corruption risk assessments; due diligence
on all parties with whom BP does business; appropriate anti-bribery and
corruption clauses in contracts and the training of personnel in anti-bribery
and corruption measures.
On 15 October 2010, the Bureau of Ocean Energy Management,
Regulation and Enforcement (BOEMRE) issued Notice to Lessees
(NTL) 2010-G05, which requires that idle infrastructure on active
leases is decommissioned earlier than previously was required and
establishes guidelines to determine the future utility of idle infrastructure
on active leases. As a consequence, the timing and methodology
of well abandonment have changed, reflected in an increase to the
decommissioning provision.
Additionally, we undertake periodic reviews of existing provisions.
These reviews take account of revised cost assumptions, changes in
decommissioning requirements and any technological developments.
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 36 on page 231.
Respecting human rights
BP supports the Universal Declaration of Human Rights, which lays out the
rights to which all human beings are entitled. We have also supported recent
multi-stakeholder efforts to establish clear, universally-applicable guidelines
on the responsibilities of businesses in relation to human rights issues.
Socio-economic development
We believe each BP project has the potential to benefit local communities
by creating jobs, generating tax revenues and providing opportunities for
local suppliers. Our presence in a location also has the potential to bring
indirect economic benefits.
We run a range of programmes to build the skills of businesses
in places where we work and to develop the local supply chain. These
range from financing to sharing global standards and practice in areas such
as health and safety. The programmes can benefit local companies by
empowering them to reach the standards needed to supply BP and other
clients. At the same time BP benefits from the local sourcing of goods and
services.
BP’s social investments – the contributions we make to social and
community programmes in locations where we operate – aim to support
development programmes that we believe will seek to create a meaningful
and sustainable impact – one that is relevant to local needs, aligned with
BP’s business and undertaken in partnership with local organizations.
The programmes we support fall into three broad categories:
building business skills and developing enterprise, supporting education
and other community needs and sharing technical expertise with local
governments. In some developing economies we also support community
infrastructure programmes that help people improve their access to basic
72 BP Annual Report and Form 20-F 2011
Business review resources such as drinking water and public health improvements. We
work with local authorities, community groups and specialists to deliver
these community programmes.
We use our technical knowledge and global reach where relevant to
support national and regional governments in their efforts to develop their
economies sustainably and provide public resources such as education
and health. As well as country-specific projects, we support more general
initiatives, including the Oxford Centre for the Analysis of Resource-Rich
Economies, which studies how countries that are rich in natural resources
such as oil and gas can use their resources for successful development
rather than falling prey to mismanagement, corruption or other pitfalls.
Our direct spending on community programmes in 2011 was
$103.7 million, which included contributions of $37.5 million in the US,
$27.0 million in the UK (including $7.2 million to UK charities, of which
$2.5 million for arts and culture, $2.8 million for enterprise development,
$1.6 million for education), $2.6 million in other European countries and
$36.6 million in the rest of the world. These reported amounts exclude
social bonuses paid by BP to governments as part of licence acquisition
costs and which have been capitalised as intangible assets on the group
balance sheet. In such cases the group has no direct oversight of the
expenditure. Contributions relating to economic recovery following the
Deepwater Horizon oil spill are also excluded, see page 77 for details of
these contributions.
Employees
Number of employees at 31 December
2011
Exploration and Production
Refining and Marketinga
Other business and corporate
Gulf Coast Restoration Organization
2010
Exploration and Production
Refining and Marketinga
Other business and corporate
Gulf Coast Restoration Organization
2009
Exploration and Production
Refining and Marketinga
Other business and corporate
US
Non-US
Total
8,900
12,000
1,900
100
22,900
7,900
12,400
1,700
100
22,100
8,000
12,700
2,100
22,800
13,300
39,000
8,200
–
60,500
13,200
39,900
4,500
–
57,600
13,500
38,900
5,100
57,500
22,200
51,000
10,100
100
83,400
21,100
52,300
6,200
100
79,700
21,500
51,600
7,200
80,300
a Includes 14,600 (2010 15,200 and 2009 13,900) service station staff, all of whom are non-US.
To be sustainable as a business, BP needs employees who have the
right skills for their roles and who understand the values and expected
behaviours that guide everything we do as a group.
We have reviewed the way we express BP’s values and required
behaviours with the goal of ensuring they support our aspirations for
the future, align explicitly with our code of conduct and translate into
responsible actions in the work we do every day. We conducted a
programme in 2011 to renew employee awareness of our values and the
behaviours as we work to reset our priorities as a company. See bp.com/
values for more information.
We had approximately 83,400 employees at 31 December 2011,
compared with approximately 79,700 a year ago. During 2011, our
headcount has been most significantly affected by both external hiring in
order to build capability and acquisition and divestment activity as part of
the strategy to re-shape the business.
The group people committee, chaired by the group chief executive,
continues to take overall responsibility for key policy decisions relating to
employees. In 2011, some of the key subjects discussed were longer-term
people priorities; the design and implementation of a new reward model;
our ambition on diversity and inclusion and a review of the governance of
our learning programmes.
Our priorities for managing our people focus on ensuring the safety
of our employees, strengthening capability, developing the potential of our
own people, increasing diversity and inclusion and retaining the best people
by motivating and engaging them.
Strengthening capability
The increasing demand for energy products and the complexity of our
projects means that attracting and retaining skilled and talented people is
vital to BP’s delivery of its strategy and plans.
In support of this, the group chief executive and each member
of the executive team hold regular review meetings to ensure that
appropriate plans to build capability are in place and that a rigorous and
consistent succession process is followed for all group leadership roles.
To supplement our existing internal capability, we also target
experienced and skilled professionals in the external market and are
continuing to increase our intake of graduates to create a strong internal
talent pipeline for the future.
We conduct external assessments for all new hires into BP at
senior levels and for internal promotions to senior level and group leader
level roles. These assessments ensure rigour and objectivity in our
hiring and talent processes. They give an in-depth analysis of leadership
behaviours, intellectual capacity and the required experience and skills for
the role in question.
Our ongoing three-year graduate development programme
continued in 2011. It currently has about 1,600 participants from all over
the world.
Developing our people
We provide development opportunities for all our employees, including
external and on-the-job training, international assignments, mentoring,
team development days, workshops, seminars and online learning. We
encourage all employees to take at least five training days per year.
We continue to work to embed appropriate leadership behaviours
throughout our organization. In 2011, we delivered a new group leader
development programme, designed to help our most senior leaders apply
BP’s required leadership behaviours in their work. The first phase of the
programme has now been completed with about half the group leader
population having undertaken eight days of intensive training. We are
refreshing the content and will start the next phase in 2012.
Our group-wide suite of management development programmes,
Managing Essentials, has now run in 41 countries, with around 32,400
participants.
Meeting the expectations of our people
We have reviewed our reward strategy, including how the group
incentivizes business performance, with the aim of encouraging excellence
in safety, compliance and operational risk management. Our revised
performance management framework was implemented in 2011.
We encourage employee share ownership. For example, through
the ShareMatch plan run in around 50 countries, we match BP shares
purchased by our employees.
We aim to treat employees affected by mergers, acquisitions
and joint ventures fairly and with respect, through open and regular
communication. As part of the divestment programme following the Gulf
of Mexico oil spill, BP has been seeking the same or comparable pay and
benefits for employees transferring to other companies.
Diversity and inclusion
We are a global company and aim for a workforce that is representative of
the societies in which we operate. We work to attract, motivate, develop
and retain the best talent from the diversity the world offers – our ability
to be competitive and to thrive globally depends on it. We believe success
comes from the energy of our people.
Through living our values of safety, respect, excellence, courage
and one team, we create an inclusive working environment where
everyone can make a difference and give their best. Our work on diversity
and inclusion is overseen by the group people committee who review
BP Annual Report and Form 20-F 2011 73
Business review: BP in more depthBusiness review performance on a quarterly basis. They agree strategic direction and group
standards which are then implemented through business specific diversity
and inclusion plans. We supported the UK government-commissioned
Lord Davies review in 2011, which made recommendations on increasing
gender diversity on the boards of listed companies.
We are also incorporating detailed diversity and inclusion analysis
into talent reviews, with processes to identify actions where any issues are
found. We continue to increase the number of local leaders and employees
in our operations so that they reflect the communities in which we operate.
By 2020, more than half our operations are expected to be in
non-OECD countries and we see this as an opportunity to develop a new
generation of experts and skilled employees. At the end of 2011, 15% of
our group leaders were female and 19% came from countries other than
the UK and the US. When we started tracking the composition of our group
leadership in 2000, these percentages were 9% and 14% respectively. BP
has increased the percentage of female leaders in 2011 and remains focused
on building a more sustainable pipeline of diverse talent for the future.
We aim to ensure equal opportunity in recruitment, career
development, promotion, training and reward for all employees, including
those with disabilities. Where existing employees become disabled, our
policy is to provide continuing employment and training wherever practicable.
Employee engagement
Executive team members hold regular town halls and webcasts to
communicate with our employees around the world.
Team meetings and one-to-one meetings are the core of our
employee engagement, complemented by formal processes through
works councils in parts of Europe. These communications, along with
training programmes, are designed to contribute to employee development
and motivation by raising awareness of financial, economic, ethical, social
and environmental factors affecting our performance. The group seeks to
maintain constructive relationships with labour unions.
We conduct an employee engagement survey to monitor employee
attitudes and identify areas for improvement. Our 2010 employee survey
was delayed to allow for organizational changes to be reflected in the
survey construction. This was completed and we carried out an employee
engagement survey in 2011. The 2011 survey found that employees are
committed and understand BP procedures and standards. The results
show that there are a number of areas that can be improved. These include
increasing transparency of the promotion process and being clear about the
organization’s priorities. Business leadership teams reviewed the results of
the survey and have agreed actions to address the identified issues.
The survey includes 10 questions which make up the employee
satisfaction index. The overall employee satisfaction index score for 2011
(62%) was below the score from 2009 (65%) but above that of 2008 (59%).
The code of conduct
The BP code of conduct sets the standard that all BP employees are
required to work to. It is aligned with our values, group standards and legal
requirements, and it clarifies the ethics and compliance expectations for
everyone who works at BP. The code was updated in 2011 and now puts
greater emphasis on a values-based approach.
The code defines what BP expects of its people in key areas such as
safety, workplace behaviour, bribery and corruption and financial integrity.
Employees, contractors or other third parties who have questions or
concerns that laws, regulations or the code of conduct may be breached,
can get help through OpenTalk, an independent confidential helpline. The
number of cases raised through OpenTalk in 2011 was 796, compared
with 742 in 2010. In the US, former district court Judge Stanley Sporkin
acts as an ombudsperson. Employees and contractors can contact him
confidentially to report any suspected breach of compliance, ethics or the
code of conduct, including safety concerns.
We take steps to identify and correct areas of non-compliance and
take disciplinary action where appropriate. In 2011, 529 dismissals were
reported by BP’s businesses for non-adherence to the code of conduct or
unethical behaviour compared to 552 in 2010.
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. We review employees’ rights to political activity in each
74 BP Annual Report and Form 20-F 2011
country where we operate. For example, in the US, BP facilitates staff
participation in the political process by providing staff support to ensure BP
employee political action committee contributions are publicly disclosed
and comply with the law.
Technology
Technology in BP
We define technology in BP as the practical application of science to
manage risks, capture business value and inform strategy development.
This includes the research, development, demonstration and acquisition of
new technical capabilities and support for the deployment of BP’s know-
how.
BP’s model continues to be one of selective technology leadership,
under which we focus on major technology programmes that best support
our business priorities and competitive performance.
External assurance is achieved through the technology advisory
council, which advises the board and executive management on the state
of technology within BP. The council is comprised of eminent business and
academic technology leaders.
In 2011 we invested $636 million (of which $12 million related
to the response to the Deepwater Horizon incident) in research and
development (R&D). This compares with $780 million in 2010 (of which
$211 million related to the response to the Deepwater Horizon incident),
and $587 million in 2009. The increase in the underlying R&D spend is
related to our major technology programmes. See Financial statements –
Note 13 on page 208.
Our innovation ecosystem
BP has hundreds of scientists and technologists across the group, with
seven major technology centres in the US, UK and Germany. We access
external expertise through various forms of partnership and collaboration,
from joint research agreements to venturing. We have a strategic approach
to university relationships across our portfolio for the purposes of research,
recruitment, policy insights and education.
BP has long-term research programmes with major universities and
research institutions around the world, exploring areas from reservoir fluid
flow to energy biosciences. These include the following programmes:
• The Energy Biosciences Institute (EBI) is BP’s largest external R&D
investment, being a $500-million 10-year commitment to a multi-
disciplinary research partnership with the University of California
Berkeley, the Lawrence Berkeley National Laboratory, and the University
of Illinois. Now in its fourth year, the EBI is generating multiple
innovations, particularly in the field of cellulosic conversion, that give our
biofuels business viable opportunities for commercial application.
• BP’s energy sustainability challenge (ESC) is a research programme with
13 leading universities to establish trusted peer-reviewed data on the
relationships between natural resource usage and different energy
pathways. The aim is to better understand the implications of energy
production and consumption on potentially-constrained land, water and
materials resources, and assess corresponding technology and policy
opportunities. One of the early publications resulting from this research
is the University of Augsburg’s handbook, Materials critical to the energy
industry.
• In September 2011, BP opened the BP energy innovation laboratory at
the Dalian Institute for Chemical Physics (DICP) in China as part of a
10-year extension to our research agreements with DICP.
• In January 2011, BP started a new three-year policy programme at
Harvard University’s Kennedy School focused on examining current and
future potential policies on energy, security and climate change.
BP is a founding member of the UK’s Energy Technologies Institute
(ETI) – a public/private partnership established in 2008 to accelerate low-
carbon technology development. As at 31 December 2011, the ETI has
commissioned over $200 million of work covering over 30 projects across
a wide range of technologies. The ETI has also developed an integrated
model of the UK energy system which projects potential pathways out to
2050 to meet the UK’s emissions targets.
Business review Exploration and Production
In the upstream, our technology investment directly supports business
strategy by focusing on safety and operational risk management;
operational efficiency; increased recovery and reserves; and winning
new access. Our strengths in exploration, deepwater, giant fields and
gas are underpinned by flagship technology programmes that conduct
scientific research in proprietary laboratories and in partnership with
world-class research institutes and universities, to develop industry-leading
technologies in imaging, facilities, well design and completions, and field
recovery. These technologies are applied in the field, often in combination
with real-time data acquisition and visualization, to drive risk reduction and
excellence in exploration, developments and production.
• We are applying many of the lessons learned from the Deepwater Horizon
incident and response throughout our global deepwater operations. The
response required rapid innovation of new technologies to cap the well and
contain the spill and – in partnership with industry partners, government
agencies and leading universities – we have continued to develop and
deploy new equipment and standards. Among many new developments in
BP, we have built a global deepwater well cap and tooling package, now
available for global deployment. This new capability includes a containment
cap, remote operating vehicle (ROV) intervention system, subsea
dispersant injection system, subsea debris removal equipment, and other
tools.
• BP continues to develop and apply innovative exploration technologies.
BP has applied two novel seismic acquisition methods developed
in-house. Our distance separated simultaneous sources (DS3) and
independent simultaneous sources (ISS®) methods were used to
complete ultra-large, high density land seismic surveys in the Middle
East and North Africa. BP also has field trials under way to extend these
acquisition methods to the offshore.
• Through our Field of the Future® flagship technology programme, BP has
deployed a range of digital, sensing and control technologies in its
operations and is using the data to enhance real-time operating efficiency
and recovery. Field of the Future tools are enabling more effective
monitoring of production, multiple well components, and well
characteristics such as temperature, which help to optimize hydrocarbon
production. In addition, improved monitoring of facilities is helping to
reduce risk, reducing downtime and saving tens of millions of dollars.
• In 2011, we successfully completed BP well advisor module field trials in
Azerbaijan, a technology designed to aid decision making, enhance
safety, reduce cost and bring wells on line more quickly. Through well
advisor, we can harness real-time drilling data from sensors that see
ahead of the drill, enabling us to deploy technologies such as early kick
detection, which allow adjustments that can minimize down time during
this critical phase of development. Rolling field trials will continue
throughout 2012 to accelerate deployment.
• Enhanced oil recovery (EOR) technologies continue to push recovery
factors to new limits. We believe that by increasing the overall recovery
factor from our fields by 1%, we could be able to add 2 billion boe to our
estimated ultimate recovery from existing fields. As at the end of 2011,
BP, using its Designer Water® EOR technology, has treated 78 wells
with Bright Water™ particles (a BP idea) in Alaska, Argentina, Azerbaijan,
Pakistan and Russia. These applications have delivered more than 20
million barrels of additional gross recoverable volumes at a development
cost of less than $6 per barrel, and with an 80% success rate: BP has
pumped almost 90% of all Bright Water treatments in the industry.
Bright Water treatments involve the design and deployment of this
sweep-improving component with regular injection water over a period
of several days. These particles are activated deep in the reservoir to
form a waterflood sweep improving diversion at a point between the
injection and production wells.
• The $7.6 billion Clair Ridge project in the UK North Sea will be the first
offshore project to use BP’s LoSal® EOR technology to increase the
recovery of oil by modifying the salinity of the water injected into the
reservoir. (LoSal EOR is part of BP’s suite of Designer Water
technologies.) Earlier in 2011, BP and its partners also announced plans
for the $5 billion redevelopment of the Schiehallion and Loyal fields,
ISS®, Field of the Future®, Designer Water® and LoSal® are all trademarks of BP p.l.c.
Bright WaterTM is a trademark of Nalco Energy Services LP.
west of Shetland. The floating production, storage and offloading unit
(FPSO) is to be built with full polymer EOR application capability.
Refining and Marketing
Our Refining and Marketing technology focus is both operational and
customer facing. In our refineries and petrochemicals assets, we develop
and apply technology to monitor operational integrity, to optimize product
yields as a function of feedstock changes, to ensure quality attainment, and
to improve energy efficiency. We also apply our expertise to create quality
brand fuel and lubricant products for customers in on-road, off-road, air, sea
and industrial applications globally.
For example:
• We continued to expand our integrity monitoring systems, with the
deployment of over 1,000 wireless Permasense sensors in 2011, now
spanning all of our BP-operated refineries worldwide. These wireless
corrosion sensors are the product of collaborative research and
development between BP and Imperial College London. The sensors
enable frequent, repeatable wall-thickness monitoring and provide
previously unavailable insights into the condition of oil and gas assets.
• In fuels and lubricants, our technology focus is on creating sustainable,
differentiated and competitive products that enable advances in transport
and industry. We continue to support our partners and customers in
delivering greater energy efficiency and reduced CO2 emissions in both
established and emerging markets. In 2011, BP developed a new range
of industrial metalworking fluids that are both safer for workers and less
harmful to the environment, a new gear lubricant for maximizing the
efficiency of wind turbines, and co-engineered passenger car lubricants
for optimizing engine fuel efficiency. We are also working on new fuels
and lubricants that deliver improved fuel economy and compatibility with
the latest engine technology and with biofuel components. In 2011, we
launched our latest generation BP Ultimate gasoline and diesel fuels, and
BP’s first differentiated-performance heavy duty diesel offer.
• In July, we opened a new industrial technology centre in Turin, Italy. It
will serve customers across Europe and analyse about 30,000 oil
samples a year.
• In petrochemicals, our proprietary processing technologies and
operational experience continue to reduce the manufacturing costs and
environmental impact of our plants, helping to maintain competitive
advantage in purified terephthalic acid (PTA), paraxylene and acetic acid.
A third PTA plant is currently being engineered for Zhuhai, China. With a
capacity of 1.25 million tonnes per year it will be the first to employ BP’s
latest PTA technology, enabling scale and cost efficiencies which
significantly reduce both capital and conversion costs to a lower level
than any other PTA technology.
• In the field of unconventional feedstocks, we collaborate with KBR to
promote, market, and license the slurry-bed residue and coal-upgrading
Veba combi-cracking (VCC) technology. VCC is a hydrogen-addition
technology suitable for processing crude oil residuum into high-quality
distillates or synthetic crude oil in the refining, upstream-field upgrading
and coal-to-liquids sectors.
BP Annual Report and Form 20-F 2011 75
Business review: BP in more depthBusiness review Alternative Energy
In Alternative Energy, we are aligning technology capability with future
growth platforms, particularly biofuels.
• In addition to our expanding biofuel production business in Brazil, we are
developing advanced technologies that will unlock the commercial
potential of next generation biofuels. At our technology centre in San
Diego, bioscientists are advancing the technology to commercialize
cellulosic biofuels and utilizing our large scale demonstration facility in
Louisiana to prove the scale-up of proprietary cellulosic technology. In
the UK, BP and its partners have constructed a demonstration plant to
accelerate commercial-scale production of biobutanol, a highly-efficient
fuel molecule.
• Our portfolio of strategic venturing investments aims at putting BP at the
forefront in terms of innovation, particularly in developing sustainable
energy solutions. Our emerging business and ventures unit brings
together BP’s venturing and carbon markets expertise with extensive
carbon capture and storage capability and through this unit, we have
more than 29 separate investments spanning three broad areas:
bioenergy, electrification and carbon solutions.
The investments create insights and develop options to
grow value for BP, for both its oil and gas assets as well as its low-
carbon businesses. They cover a range of specialized innovations and
technologies, such as waste-heat recovery, energy storage, carbon
funds and land-carbon projects, new solar and bio-energy technologies.
For example, we have an investment stake in GMZ Energy, based
in the US, which is commercializing materials that allow the efficient
conversion of heat to electricity with a thermoelectric device – a building
block for a new generation of energy-efficient products. The investment
gives us insights into the ability of thermoelectric technology to recover
low-grade waste heat sources cost-effectively across the group.
Gulf of Mexico oil spill
From response to restoration – summary
Building on the efforts of 2010, BP has continued to demonstrate
its commitment to the US federal, state and local governments and
communities of the Gulf Coast following the Deepwater Horizon oil spill.
BP’s efforts in 2011 included:
• Continuing the clean-up of the waters and shorelines impacted across
the Gulf of Mexico and the ongoing protection of fish and wildlife.
• Supporting the economic restoration of impacted sectors of the Gulf
Coast economy through targeted support to the tourism and seafood
industries.
• Continuing the funding of the $20-billion Deepwater Horizon Oil Spill
Trust for the purposes of paying all legitimate individual, business, state
and local government claims and funding of settlements and Natural
Resource Damages (NRD) assessment and restoration activities.
• Progressing the NRD activities in collaboration with the federal and state
trustee agencies and progressing both emergency and early restoration
activities, including our voluntary commitment of up to $1 billion in early
restoration projects.
• Continuing the support of independent long-term research through the
Gulf of Mexico Research Initiative (GoMRI) to improve knowledge of the
Gulf ecosystem and to better understand and mitigate the potential
impacts of oil spills in the region and elsewhere.
Proposed settlement with the Plaintiffs’ Steering Committee
On 3 March 2012, BP announced that it had reached a settlement with the
Plaintiffs’ Steering Committee (PSC), subject to final written agreement
and court approvals, to resolve the substantial majority of legitimate
economic loss and medical claims stemming from the Deepwater Horizon
accident and oil spill. The PSC acts on behalf of individual and business
plaintiffs in the Multi-District Litigation proceedings pending in New
Orleans (MDL 2179).
The proposed settlement is comprised of two separate
agreements, one to resolve economic loss claims and another to resolve
medical claims. Each proposed agreement provides that class members
would be compensated for their claims on a claims-made basis, according
to agreed compensation protocols in separate court-supervised claims
processes. The proposed agreement to resolve economic loss claims
includes a BP commitment of $2.3 billion to help resolve economic loss
claims related to the Gulf seafood industry and a fund to support continued
advertising that promotes Gulf Coast tourism.
BP estimates that the cost of the proposed settlement, expected to
be paid from the $20 billion Trust, would be approximately $7.8 billion. This
includes the financial commitment for the Gulf seafood industry.
The proposed economic loss settlement provides for a transition
from the Gulf Coast Claims Facility (GCCF). A court-supervised transitional
claims process for economic loss claims will be in operation while the
infrastructure for the new settlement claims process is put in place. During
this transitional period, the processing of claims that have been submitted
to the GCCF will continue, and new claimants may submit their claims. BP
has agreed not to wait for final approval of the economic loss settlement
before claims are paid. The economic loss claims process will continue
under court supervision before final approval of the settlement, first under
the transitional claims process, and then through the settlement claims
process established by the proposed economic loss agreement.
This proposed settlement does not include claims against BP made
by the United States Department of Justice or other federal agencies
(including under the Clean Water Act and for Natural Resource Damages
under the Oil Pollution Act) or by the states and local governments. The
proposed settlement also excludes certain other claims against BP, such as
securities and shareholder claims pending in MDL 2185, and claims based
solely on the deepwater drilling moratorium and/or the related permitting
process.
For further details, see the Legal proceedings section on pages
160-164.
76 BP Annual Report and Form 20-F 2011
Business review Completing the response
Throughout 2011, BP, working under the direction of the US Coast Guard’s
Federal On-Scene Coordinator (FOSC), and collaboratively with individual
federal and state entities, continued to complete the Deepwater Horizon
operational response activities as described below.
Source control and site remediation
During the first half of 2011, BP completed the decommissioning of all
source control equipment including all vessels used in the response. We
also completed plugging and abandonment (P&A) of the second relief well
and conducted a seabed survey. BP conducted a further site survey of
the Macondo wellhead and the two relief wells during the third quarter of
2011. Following these surveys it was determined that no further activity is
necessary at the well site.
During the year we continued our efforts to recover and recycle
waste material in order to minimize impacts. We also continued or
completed the site remediation of multiple locations that were used during
the response.
Residual clean-up in the Gulf of Mexico
Since the beginning of the Deepwater Horizon response multi-party
Shoreline Clean-up Assessment Technique (SCAT) teams have
continuously and systematically surveyed the shoreline to assess oiling
conditions and develop shoreline treatment recommendations (STRs),
which are implemented at the direction of the FOSC. Over 110,000 miles
of aerial reconnaissance flights were conducted across the 11,000 miles of
Gulf Coast shoreline. From this surveillance information, the SCAT teams
identified more than 4,300 miles for further, ground-based survey. Of the
Gulf Coast shoreline, 635 miles required some measure of mechanical or
manual cleaning.
During 2011, mechanical or manual cleaning of the majority of
the segments was completed. Patrolling and maintenance activities
were initiated and will continue until the shoreline segments meet the
applicable clean-up standards for the FOSC to determine that operational
removal activity is complete. In November 2011, the FOSC also approved
the Shoreline Clean-up Completion plan. This plan describes the process
whereby the various shoreline segments included in the area of response
operations can be surveyed, verified as meeting the applicable clean-up
standards, and moved out of operational activity. It is expected that the
majority of the 4,300 miles of the Gulf Coast shoreline within the area of
response will be deemed operationally complete within 2012.
Environmentally sensitive areas were often hand cleaned. In some
areas cleaning was paused at the direction of, or in consultation with,
wildlife scientists, to minimize interference with migration patterns or
breeding cycles.
The Coast Guard has indicated that if oil is discovered in a segment
that has been deemed operationally complete, the Coast Guard will follow
long-standing response protocols established under the law and contact
whoever it believes is the responsible party or parties.
Response efforts guided by science
At the direction of the FOSC, scientific studies were conducted to study
the status of oil and dispersants in the water and sediments of the Gulf.
These studies are being used to guide continuing response activities in the
near shore environment and to better understand the potential impacts
of residual oil. These results have been published in Operational Scientific
Advisory Team (OSAT) reports (OSAT-1 and OSAT-2 reports, and a toxicity
addendum) and Net Environmental Benefits Analysis reports (NEBAs).
These reports confirmed the appropriateness of the steps taken to
remove oil and mitigate the impact on the environment. The OSAT-2 report
determined that further efforts, beyond guidelines established by the
FOSC to remove the residual oil from the shoreline, could potentially pose
a greater risk to the environment than allowing the residual oil to degrade
naturally.
To assess the potential impacts on fauna, the FOSC directed the
OSAT scientists to conduct a comprehensive toxicity study. The report,
which was an addendum to the OSAT-1 report, was issued on 8 July 2011.
Of the approximately 3,500 toxicity tests conducted, 90% showed no
statistically significant effects on wildlife.
At the request of the FOSC, several NEBA studies and specialized activities
were carried out, including an effort to detect anchors that had been
deployed during the response to keep containment boom in place. Based
on the NEBA results, the NEBA team recommended that the FOSC let
the anchors remain in place to allow them to degrade through natural
processes.
Economic restoration
BP continued to support economic recovery in local communities through a
variety of actions and programmes in 2011.
Deepwater Horizon Trust activity
BP has established the Deepwater Horizon Oil Spill Trust (the Trust) in the
amount of $20 billion to be used in compensating individuals, businesses,
government entities and others who have been impacted by the oil spill.
The Trust provides funds to satisfy legitimate state and local government
claims resolved by BP, final judgments and settlements, legitimate state
and local response costs, natural resource damages and related costs,
and legitimate individual and business claims administered by the GCCF,
which has been managed by Kenneth Feinberg. The proposed economic
loss settlement announced on 3 March 2012 with the Plaintiffs’ Steering
Committee on MDL 2179 provides for a transition from the GCCF. A court-
supervised transitional claims process for economic loss claims will be in
operation while the infrastructure for the new settlement claims process
is put in place. During this transitional period, the processing of claims that
have been submitted to the GCCF will continue and new claimants may
submit their claims. The establishment of the Trust does not represent
a cap or floor on BP’s liabilities and BP does not admit to a liability of
this amount.
In 2011, $1 billion was voluntarily set aside in the Trust for NRD
early restoration projects. BP is working with federal and state trustees to
select appropriate projects that will enhance habitats, wildlife and access
for recreational use.
As at 31 December 2011, BP’s cumulative contributions to the
Trust amounted to $15.1 billion since its inception, including our second-
year commitment of $5 billion and a total of $5.1 billion cash settlements
received during 2011 from MOEX USA Corporation (MOEX), Weatherford
US., L.P. (Weatherford), and Anadarko Petroleum Corporation (Anadarko).
The remaining committed contributions as at 31 December 2011 totalling
$4.9 billion are scheduled to be made by the end of 2012. In January
2012, we contributed to the Trust the $250 million settlement received
from Cameron International Corporation (Cameron). The Trust disbursed
$3.7 billion in 2011 and the total paid out since its establishment amounted
to $6.7 billion by the end of 2011.
Claims payments
All payments that were made in 2011 for legitimate claims by individuals,
businesses and government entities were paid from the Trust. During the
year, individuals and businesses received $3.1 billion in payments through
the GCCF. More than 189,000 individual and business claimants accepted
full and final settlements, while about 33,000 received interim payments.
Since May 2010, more than $6.2 billion has been paid to individuals and
businesses through the claims process, with the Trust paying $5.8 billion of
this and BP paying the remainder prior to the establishment of the Trust.
Government entities received more than $40 million in claims
payments during 2011. Nearly 60 loss-of-revenue claims have been paid to
government entities since May 2010. By the end of 2011, BP had resolved
over 90% of government claims filed.
During 2011, BP paid a total of $7.7 million to vessel owners whose
vessels were involved in clean-up and protection activities as part of the
Vessels of Opportunity (VoO) programme. In an effort to ensure fairness,
BP instructed the external adjusters to broaden the original compensation
guidelines. Once the new guidelines were established, adjusters have and
are continuing to re-examine property damage claims from about 1,200
vessel owners, whose property-damage claims had previously been denied
or partially paid to ensure that property damages reported by claimants
have been adequately addressed.
BP Annual Report and Form 20-F 2011 77
Business review: BP in more depthBusiness review Promoting tourism along the Gulf Coast
To support economic restoration in the impacted Gulf Coast communities,
BP entered into three-year agreements with the states of Alabama, Florida,
Louisiana and Mississippi to promote tourism, monitor seafood safety and
promote Gulf seafood.
During 2011, BP made commitments of $92 million in total over
three years to support tourism promotion within the four affected states.
This is in addition to $87 million in tourism grants provided by BP in
2010. Each state is using its tourism funds to develop specific marketing
programmes.
The proposed settlement announced on 3 March 2012 with the
Plaintiffs’ Steering Committee in MDL 2179 includes a fund to support
continued advertising that promotes Gulf Coast tourism.
Seafood testing, monitoring and promotion
Federal and state officials continue to collect and test seafood from the
Gulf of Mexico, and the results of these tests have indicated that Gulf
of Mexico seafood meets the US Food and Drug Administration (FDA)
safety guidelines. The National Oceanic and Atmospheric Administration
(NOAA) and the FDA are conducting widespread scientific evaluation of
seafood samples to protect and reassure consumers. Since May 2010,
more than 6,000 seafood samples have been collected by the FDA, NOAA,
and state agencies in Louisiana, Mississippi, Alabama, and Florida. The
FDA has also visited over 100 seafood processors and wholesalers across
the Gulf Coast, collecting seafood samples and inspecting processing
plants for biological, chemical, and physical hazards. Levels of residues of
oil contamination in seafood have consistently tested between 100 and
1,000 times lower than the safety thresholds established by the FDA.
Test results from NOAA, the FDA, and the Gulf of Mexico states are
publicly available.
Recreational fishing showed signs of recovery in 2011. To raise
public awareness of Gulf of Mexico seafood, BP has committed $34 million
for Gulf of Mexico states to conduct seafood testing and $48 million to
market Gulf of Mexico seafood.
Rig Worker Assistance Fund
BP established a $100-million Rig Worker Assistance Fund through the
Baton Rouge Area Foundation (the Foundation) to support unemployed rig
workers experiencing economic hardship as a result of the moratorium on
deepwater drilling imposed by the US federal government. In 2011, the
Foundation awarded $5.8 million to an expanded pool of applicants, after
awarding $5.6 million to nearly 350 rig workers in 2010. With less than
2,000 applying for funds, the Foundation granted $18 million of the BP
contribution to community-based organizations through its Future for the
Gulf Fund. At the end of 2011, the Foundation was assessing additional
funding requests from organizations assisting those impacted by the spill,
and has said it hopes to complete the distribution of the BP contribution by
the end of 2012.
Environmental restoration
We made progress during 2011 on multiple fronts as part of the
ongoing efforts to assess and address injury to natural resources in the
Gulf of Mexico.
We continued to support and participate in the Natural Resource
Damages (NRD) process. Work has been completed or is under way on
more than 150 cooperative studies with federal and state agencies to
gather data on potential impacts and injuries to birds, turtles and mammals;
fish and shell fish; near shore and shoreline habitats; and the Gulf of
Mexico water column and sediment.
We also worked with the Natural Resource Damage Assessment
(NRDA) trustees to begin assessing the potential lost human use of these
Gulf Coast natural resources. Additional studies focused on the potential
impacts on historical and archaeological resources and endangered species.
During the year we also supported two emergency restoration
projects and made a major commitment to fund early restoration projects.
In addition, the National Fish and Wildlife Foundation funded several
projects during 2011 using funds provided by BP in 2010 from the sale of
oil recovered from the spill.
We are working with NOAA to prepare and provide access to
summaries of the studies completed and data gathered during the
78 BP Annual Report and Form 20-F 2011
cooperative assessment process. We also prepared and participated in a
variety of scientific publications and seminars as part of our efforts to share
learnings from the oil spill as broadly as possible.
NRD process under way
In 2011, we continued to work with scientists and trustee agencies
through the NRD process to identify natural resources that may have
been exposed to oil or otherwise impacted by the incident, and to look for
evidence of injury.
As part of the NRD process, trustees from each state and the
federal government held a series of public meetings during 2011 in each of
the five states affected by the Deepwater Horizon oil spill. These
focused on the status of potential injury assessments and of potential
restoration process. To date, BP has paid over $600 million for NRD
assessment efforts.
Public comments were collected as part of the Programmatic
Environmental Impact Statement (PEIS) process, which will inform one of
the core planning documents for restoration. A final PEIS is scheduled to
be released by the trustees in late 2012.
Emergency restoration projects
Emergency restoration projects are defined under the Oil Pollution Act of
1990 (OPA 90) as preventative measures or actions undertaken to stop
continuing injuries to resources and to mitigate potential effects of the
spill. During 2011, two emergency restoration projects were completed
along the Gulf Coast in support of birds and turtles. A third project is in the
planning phase for submerged aquatic vegetation and is scheduled to be
implemented in 2012.
Early restoration projects
Under an agreement signed with federal and state trustees in April 2011,
BP voluntarily committed to provide up to $1 billion to fund projects that
will accelerate restoration efforts in Gulf Coast areas that were impacted by
the Deepwater Horizon oil spill.
The agreement enables work on restoration projects to begin at
the earliest opportunity, before all of the studies under the NRDA process
are complete, and before funding is required by OPA 90. Priority will be
assigned to projects aimed at improving areas that offer the greatest
benefits to wildlife, habitat, and recreational use that were impacted as a
result of the incident.
In December 2011, state and federal trustees unveiled the first set
of early environmental restoration projects that are proposed for funding
under the agreement. The eight proposed projects are located in
Alabama, Florida, Louisiana and Mississippi. Collectively, the projects will
restore and enhance wildlife, habitats, the ecosystem services provided
by those habitats, and provide additional access for fishing, boating and
related recreational uses. More early restoration projects are anticipated in
the future.
Funding for the early restoration projects will come from the
$20-billion Trust. Additional information about the projects, projected costs
and proposed credits can be found on the NOAA website.
Environmental studies and reports
BP is committed to sharing and providing access to the numerous studies
and reports generated during the course of the response. In total, since
May 2010, more than 150 NRDA studies have been completed or are in
progress throughout the Gulf. As the studies are completed, summaries
are expected to be published as appropriate either on BP’s website or on
government websites. Our website also contains numerous
technical reports and documentation on a variety of environmental and
health-related topics.
National Fish and Wildlife Foundation projects
In 2010, BP donated $22 million from the net revenue of the sale of oil
recovered from the spill to the US National Fish and Wildlife Foundation
(NFWF) which used the funds to quickly implement several conservation
projects along the Gulf Coast.
In 2011, the NFWF announced that it issued $6.9 million in
grants from the Recovered Oil Fund for Wildlife for 22 new projects. The
Business review BP considers that it is not possible to estimate reliably any obligation in
relation to NRD claims under OPA 90 (other than the estimated costs of
the assessment phase and the costs relating to emergency restoration
and the $1 billion agreement for early restoration), any amounts in relation
to fines and penalties except for those relating to the CWA and litigation
arising from alleged violations of OPA 90. These items are therefore
contingent liabilities.
BP holds a 100% interest in the Macondo well, with the lease
interests previously held by MOEX and Anadarko now assigned to BP as
part of the settlement agreements. MOEX paid BP $1.1 billion in cash and
Anadarko paid BP $4 billion in cash to settle all outstanding claims between
the companies related to the incident and to the prospect.
For details regarding the impacts and uncertainties relating to the
Gulf of Mexico oil spill refer to Financial statements – Note 2 on page 190,
Note 36 on page 231 and Note 43 on page 249. See also Risk factors on
page 59 and Proceedings and investigations relating to the Gulf of Mexico
oil spill on pages 160-164.
Legal proceedings and investigations
See Legal proceedings on pages 160-164 for a full discussion of legal
proceedings and investigations relating to the incident.
grants, which were supplemented by a further $3.3 million from other
contributors, were awarded for projects designed to:
• Improve sea turtle hatchling success across 56 miles of priority Florida
beaches.
• Increase the capacity of marine mammal and sea turtle treatment
facilities.
• Restore a combined 3.5 miles of oyster reefs, which in turn protect
sensitive coastal habitat.
• Reduce the incidence of sea turtles being caught in the course of
recreational and commercial fishing.
Commitment to long-term oil spill research
In 2010, BP committed $500 million over 10 years to fund independent
scientific research through the Gulf of Mexico Research Initiative (GoMRI).
The research will improve knowledge of the Gulf ecosystem and help the
industry and others to better understand and mitigate the impact of oil
spills in the region and elsewhere.
In June 2011, the GoMRI Research Board awarded 17 grants
totalling $1.5 million to support scientists as they continue time-sensitive
data collection. In August 2011, the Research Board awarded a total of
$112.5 million over three years to eight consortia comprised of over 70
research institutions. All eight consortia are led by Gulf Coast institutions.
Research recipients will use the grants to investigate the fate of oil
released by the spill, and for the development of new tools and technology
for responding to future spills and improving mitigation and restoration.
In December 2011, the GoMRI Research Board also issued a
request for proposals (RFP) for approximately $7.5 million per year for three
years, in smaller grants to individual or small teams of researchers.
Rebuilding trust through effective communications
During 2011, we worked to engage, inform and communicate with a wide
range of stakeholders throughout the region. We supported community
events and we shared information on a variety of issues and concerns with
individuals, community organizations, business leaders, elected officials,
non-governmental organizations and the news media.
Financial update
Profit before tax for the group includes a pre-tax credit of $3.8 billion
and finance costs of $0.1 billion in relation to the Gulf of Mexico oil spill.
The pre-tax credit reflects $5.5 billion in relation to settlements reached
with MOEX, Weatherford, Anadarko and Cameron, partially offset by
further costs associated with the ongoing spill response, adjustments to
provisions, and an increase in the amount provided for legal fees, as well as
functional expenses of BP’s Gulf Coast Restoration Organization (GCRO).
Provisions were established during 2010 for the environmental
expenditure, spill response costs, litigation and claims, and Clean Water
Act (CWA) penalties. Most of the costs incurred in 2011 were covered
by these existing provisions. Pre-tax charges were recorded in 2011
of $0.4 billion for the functional expenses of the GCRO, $1.1 billion for
increases in the amounts provided, primarily related to spill response costs
and legal fees, a $0.1 billion finance charge for unwinding of discount on
provisions, and $0.1 billion for spill response costs charged directly to the
income statement. These charges partially offset the $5.5 billion credit for
settlements reached during the year.
As at 31 December 2011, the cumulative charges for provisions to
be paid from the Trust and the associated reimbursement asset recognized
amounted to $16.6 billion. This represented an increase of
$4.0 billion in the provisioned amounts during 2011, primarily for the
$2.1-billion expected impact of the proposed settlement announced on
3 March 2012 with the Plaintiffs’ Steering Committee in MDL 2179, the
$1-billion commitment to NRD early restoration and new provisions for
personal injury and death claims and Vessel of Opportunity programme
claims. A further $3.4 billion could be provided in subsequent periods for
items covered by the Trust, with no net impact on the income statement.
BP has provided for all potential liabilities that can be estimated
reliably at this time, including fines and penalties under the CWA. The
total amounts that will ultimately be paid by BP in relation to all obligations
relating to the incident are subject to significant uncertainty.
BP Annual Report and Form 20-F 2011 79
Business review: BP in more depthBusiness review Additionally, our activities include the marketing and trading of natural gas,
power and natural gas liquids. These activities provide routes into liquid
markets for BP’s produced gas, and generate margins and fees associated
with the provision of physical products and derivatives to third parties and
income from asset optimization and trading.
Our oil and natural gas production assets are located onshore and
offshore and include wells, gathering centres, in-field flow lines, processing
facilities, storage facilities, offshore platforms, export systems (e.g. transit
lines), pipelines and LNG plant facilities.
Upstream operations in Abu Dhabi, Argentina, Bolivia, Chile, Russia,
Venezuela and Vietnam as well as some of our operations in Angola,
Canada, Indonesia and Trinidad are conducted through equity-accounted
entities.
Our market
Energy demand, and in particular oil demand, has followed overall
economic trends in recent years, recovering strongly in 2010 but facing
more challenging conditions in 2011.
Dated Brent for the year averaged $111.26 per barrel, 40%
above 2010’s average of $79.50 per barrel. In 2012, we expect oil price
movements to continue to be driven by the pace of global economic
growth and its resulting implications for oil consumption, and by OPEC
production decisions.
Natural gas prices diverged globally in 2011, reflecting different
regional dynamics. The average US Henry Hub First of Month Index fell
to $4.04/mmBtu, an 8% decrease from 2010, while in Europe prices
increased. Spot gas prices at the UK National Balancing Point increased by
33% to an average of $56.33 pence per therm for 2011.
After a record increase in 2010, global gas consumption growth
moderated in 2011. In the US, economic momentum supported gas use
in the first half of the year and a hot summer raised demand. Yet domestic
production outpaced consumption growth due to further increases in the
availability of shale gas.
In 2012, we expect gas markets to continue to be driven by the
economy, weather, domestic production, LNG supply and reductions in
nuclear power generation following the Fukushima disaster in Japan in
March 2011.
Our strategy
In Exploration and Production, our highest priority is to ensure safe, reliable
and compliant operations worldwide. Our strategy is to invest to grow long-
term value by continuing to build a portfolio of material, enduring positions
in the world’s key hydrocarbon basins with a focus on deepwater, gas
value chains and giant fields. Our strategy is enabled by:
• A continued focus on safety and managing risk.
• Strong relationships built on mutual advantage, deep knowledge of the
basins in which we operate, and technology.
• Building capability along the value chain in Exploration, Developments
and Production.
• Actively managing our portfolio.
We intend to increase investment with a focus on Exploration, a key
source of value creation, and evolve the nature of our relationships,
particularly with national oil companies.
Exploration and Production
At the end of 2010, as part of our response to the Deepwater Horizon
oil spill, we announced the decision to reorganize the Exploration and
Production segment to create three separate divisions: Exploration,
Developments and Production, integrated through a Strategy and
Integration organization. This structure was established in March 2011
and each of the four parts is led by an executive vice president reporting
directly to the group chief executive. The new organization is designed
to change the way we operate, with a particular focus on managing
risk, delivering common standards and processes and building technical
capability. The new organization has not changed the way we report our
operating segments under IFRS.
The Exploration division is accountable for renewing our resource
base through access, exploration and appraisal. The Developments
division is accountable for the safe and compliant execution of wells
(drilling and completions) and major projects and comprises the global
wells organization and the global projects organization, which were
established in 2011. The Production division is accountable for safe and
compliant operations, including upstream production assets, midstream
transportation and processing activities, and the development of our
resource base. Divisional activities are integrated on a regional basis by a
regional president reporting to the Production division. The Strategy and
Integration organization is accountable for optimization and integration
across the divisions, including the delivery of support from the group’s
finance, procurement and supply chain, human resources, technology and
information technology functions.
From 1 January 2012, the group’s investment in TNK-BP will
be reported as a separate operating segment, rather than within the
Exploration and Production segment, reflecting the way in which the
investment is now managed.
The group safety and operational risk (S&OR) function maintains
our global safety standards. S&OR staff are deployed at the operating level
within the Exploration and Production segment to support the systematic
and disciplined application of those standards. This creates an independent
reporting line, working alongside line management while having the power
to intervene.
Our Exploration and Production segment included upstream
and midstream activities in 30 countries in 2011, including Angola,
Azerbaijan, Brazil, Canada, Egypt, India, Iraq, Norway, Russia, Trinidad &
Tobago (Trinidad), the UK, the US and other locations within Africa, Asia,
Australasia and South America, as well as gas marketing and trading
activities, primarily in Canada, Europe and the US. Upstream activities
involve oil and natural gas exploration, field development and production.
Our exploration and appraisal programme is currently focused on Angola,
Australia, Azerbaijan, Brazil, Canada, Egypt, the deepwater Gulf of Mexico,
the UK North Sea, Oman and onshore US. Major development areas
include Angola, Australia, Azerbaijan, Canada, Egypt, the deepwater Gulf of
Mexico, North Africa, and the UK North Sea. During 2011, production came
from 24 countries. The principal areas of production are Angola, Argentina,
Azerbaijan, Egypt, Russia, Trinidad, the UAE, the UK and the US.
Midstream activities involve the ownership and management
of crude oil and natural gas pipelines, processing facilities and export
terminals, LNG processing facilities and transportation, and our NGL
extraction businesses in Canada, Indonesia, the US and the UK. Our most
significant midstream pipeline interests are the Trans-Alaska Pipeline
System in the US; the Forties Pipeline System and the Central Area
Transmission System pipeline, both in the UK sector of the North Sea;
the South Caucasus Pipeline, which runs from Azerbaijan through Georgia
to the Turkish border; and the Baku-Tbilisi-Ceyhan pipeline, which runs
through Azerbaijan, Georgia and Turkey. Major LNG activities are located in
Australia, Indonesia and Trinidad. BP is also investing in the LNG business
in Angola.
80 BP Annual Report and Form 20-F 2011
Business review Our performance
Key statistics
Sales and other operating revenuesa
Replacement cost profit before interest
and tax
Capital expenditure and acquisitions
Average BP crude oil realizationsb
Average BP NGL realizationsb
Average BP liquids realizationsb c
Average West Texas Intermediate
oil priced
Average Brent oil priced
Average BP natural gas realizationsb
Average BP US natural gas realizationsb
Average Henry Hub gas pricee
Average UK National Balancing Point
gas priced
Liquids production for subsidiariesc f
Liquids production for equity-accounted
entitiesc f
Total of subsidiaries and equity-
accounted entitiesc f
Natural gas production for subsidiariesf
Natural gas production for equity-
accounted entitiesf
Total of subsidiaries and equity-
accounted entitiesf
Total production for subsidiariesf g
Total production for equity-accounted
entitiesf g
Total of subsidiaries and equity-
accounted entitiesf g
2011
75,475
2010
66,266
30,500
25,535
107.91
51.18
101.29
30,886
17,753
77.54
42.78
73.41
$ million
2009
57,626
24,800
14,896
$ per barrel
59.86
29.60
56.26
95.04
111.26
79.45
79.50
61.92
61.67
$ per thousand cubic feet
3.25
3.07
$ per million British thermal units
3.99
pence per therm
3.97
3.88
4.39
4.69
3.34
4.04
56.33
992
42.45
30.85
thousand barrels per day
1,400
1,229
1,165
1,145
1,135
2,157
6,393
2,374
2,535
million cubic feet per day
7,450
7,332
1,125
1,069
1,035
7,518
8,485
8,401
thousand barrels of oil equivalent per day
2,684
2,492
2,094
1,360
1,330
1,314
3,454
3,822
3,998
million barrels
Estimated net proved crude oil reserves
for subsidiariesc h
5,153
5,559
5,658
Estimated net proved crude oil reserves
for equity-accounted entitiesc i
5,234
4,971
4,853
Estimated net proved bitumen reserves
for equity-accounted entities
Total of subsidiaries and equity-
accounted entitiesc h i
Estimated net proved natural gas
reserves for subsidiariesj
Estimated net proved natural gas
reserves for equity-accounted
entitiesk
Total of subsidiaries and equity-
accounted entitiesj k
Estimated net proved reserves for
178
179
–
10,565
10,709
10,511
billion cubic feet
36,381
37,809
40,388
5,278
4,891
4,742
41,659
42,700
45,130
million barrels of oil equivalent
subsidiariesh j
11,426
12,077
12,621
Estimated net proved reserves for
equity-accounted entitiesi k
Total of subsidiaries and equity-
accounted entitiesh i j k
6,322
5,994
5,671
17,748
18,071
18,292
a Includes sales between businesses.
b Realizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted
entities.
c Crude oil and natural gas liquids.
d All traded days average.
e Henry Hub First of Month Index.
f Net of royalties.
g Expressed in thousands of barrels of oil equivalent per day (mboe/d). Natural gas is converted to oil
equivalent at 5.8 billion cubic feet = 1 million barrels.
h Includes 20 million barrels (22 million barrels at 31 December 2010 and 23 million barrels at
31 December 2009) in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
i Includes 310 million barrels (254 million barrels at 31 December 2010 and 243 million barrels at
31 December 2009) in respect of the 7.37% minority interest in TNK-BP (7.03% at 31 December
2010 and 6.86% at 31 December 2009).
j Includes 2,759 billion cubic feet of natural gas (2,921 billion cubic feet at 31 December 2010 and
3,068 billion cubic feet at 31 December 2009) in respect of the 30% minority interest in BP Trinidad
and Tobago LLC.
k Includes 174 billion cubic feet (137 billion cubic feet at 31 December 2010 and 131 billion cubic feet
at 31 December 2009) in respect of the 6.27% minority interest in TNK-BP (7.03% at 31 December
2010 and 6.86% at 31 December 2009).
2011 performance
Safety and operational risk
In Exploration and Production, ensuring safe, reliable and compliant
operations remains our highest priority. The organizational and governance
changes in Exploration and Production and S&OR have been designed to
ensure we achieve this, supported by a systematic framework provided by
BP’s operating management system (OMS). All Exploration and Production
operated businesses, with the exception of those recently acquired, are
now applying our OMS to govern their BP operations and have begun
working to achieve conformance to standards and practices required by
OMS through the performance improvement cycle process. We continue
to work to enhance local systems and processes at all our sites. See Safety
on pages 65-66 for more information on OMS.
Safety performance is monitored by a suite of input and output
metrics which focus on personal and process safety including operational
integrity, occupational health and all aspects of compliance.
In 2011, there were no workforce fatalities in Exploration and
Production. In 2010, there was one workforce fatality.
The recordable injury frequency (RIF), which measures the number
of recordable injuries to the BP workforce per 200,000 hours worked, was
0.30. This is lower than 2010 when it was 0.32 and 2009 when it was 0.39.
Our day away from work case frequency (DAFWCF) in 2011 was 0.060.
This is lower than 2010 when it was 0.063 but higher than 2009 when it
was 0.038.
In 2011, the number of reported loss of primary containment
(LOPC) incidents in Exploration and Production was 152, down from 194
in 2010. The number of reported oil spills equal to or larger than 1 barrel
during 2011 was 71, down from 117 in 2010.
Financial and operating performance
We continually seek access to resources and in 2011, in addition to new
access resulting from acquisitions as detailed on page 83, this included
Angola, where BP gained access to five new deepwater exploration and
production blocks covering 24,200km2; Australia, where BP was awarded
four blocks covering 24,500km2 in the Ceduna Sub Basin off the coast of
South Australia; Azerbaijan, where the republic of Azerbaijan ratified the
Shafag-Asiman production-sharing agreement (PSA) covering 1,100km2
in the Caspian Sea; China, where BP was awarded access to a 9,700km2
block in the South China Sea; deepwater Gulf of Mexico, where 12 leases
from the March 2010 Outer Continental Shelf Lease Sale 213 covering
280km2 were executed; Indonesia, where BP was awarded four coalbed
methane PSAs covering 4,800km2 in the Barito basin of South Kalimantan
and two oil and gas PSAs covering 16,400km2 offshore in the Arafura Sea;
and Trinidad, where BP was awarded two deepwater blocks covering
3,600km2, subject to government approval.
In September 2011, we announced the Moccasin oil discovery in
the deepwater Gulf of Mexico (not BP-operated). In October 2011, we
announced the Salmon gas discovery in Egypt’s Nile Delta. In 2011, we
took final investment decisions on three projects and two major projects
came onstream: Serrette in Trinidad and Pazflor in Angola.
Production for 2011 was lower than last year. After adjusting for the
effect of entitlement changes in our PSAs and the effect of acquisitions
and disposals, underlying production was 7% lower than 2010. This
primarily reflects lower Gulf of Mexico production as a result of the impact
of the drilling moratorium as well as the impact of turnaround maintenance
activities. In 2011, full-year production growth in TNK-BP was 2.8%.
Sales and other operating revenues for 2011 were $75 billion,
compared with $66 billion in 2010 and $58 billion in 2009. The increase
BP Annual Report and Form 20-F 2011 81
Business review: BP in more depthBusiness review in 2011, compared with 2010, primarily reflected higher oil and gas
realizations, partly offset by lower production. The increase in 2010,
compared with 2009, primarily reflected higher oil and gas realizations,
partly offset by lower production.
The replacement cost profit before interest and tax for 2011 was
$30,500 million, compared with $30,886 million for the previous year. 2011
included net non-operating gains of $1,130 million, primarily a result of
gains on disposals being partly offset by impairments, a charge associated
with the termination of our agreement to sell our 60% interest in Pan
American Energy LLC (PAE) to Bridas Corporation and other non-operating
items. (See page 58 for further information on non-operating items.) In
addition, fair value accounting effects had a favourable impact of $11
million relative to management’s measure of performance. (See page 58
for further information on fair value accounting effects.)
The primary additional factors contributing to the 1% decrease in
replacement cost profit before interest and tax were higher realizations
partially offset by lower production volumes (including in higher margin
areas), rig standby costs in the Gulf of Mexico, higher costs related to
turnarounds, certain one-off costs and higher exploration write-offs.
Total capital expenditure including acquisitions and asset exchanges
in 2011 was $25.5 billion (2010 $17.8 billion and 2009 $14.9 billion). (See
page 83 for further information on acquisitions.)
Development expenditure of subsidiaries incurred in 2011,
excluding midstream activities, was $10.2 billion, compared with $9.7
billion in 2010 and $10.4 billion in 2009.
Provisions for decommissioning increased from $10.5 billion at the
end of 2010 to $17.2 billion at the end of 2011. The increase reflects higher
cost estimates, which are in part driven by new requirements in the Gulf of
Mexico. Decommissioning costs are initially capitalized within fixed assets
and are subsequently depreciated as part of the asset.
Prior years’ comparative financial information
The replacement cost profit before interest and tax for the year ended
31 December 2010 of $30,886 million included net non-operating gains of
$3,199 million, comprised primarily of gains on disposals that completed
during the year partly offset by impairment charges and fair value losses
on embedded derivatives. In addition, fair value accounting effects had an
unfavourable impact of $3 million relative to management’s measure of
performance.
The replacement cost profit before interest and tax for the year
ended 31 December 2009 of $24,800 million included a net credit for non-
operating items of $2,265 million, with the most significant items being
gains on the sale of operations (primarily from the disposal of our 46%
stake in LukArco, the sale of our 49.9% interest in Kazakhstan Pipeline
Ventures LLC and the sale of BP West Java Limited in Indonesia) and fair
value gains on embedded derivatives. In addition, fair value accounting
effects had a favourable impact of $919 million relative to management’s
measure of performance.
The primary additional factor contributing to the 25% increase in
the replacement cost profit before interest and tax for the year ended
31 December 2010 compared with the year ended 31 December 2009 were
higher realizations, lower depreciation and higher earnings from equity-
accounted entities, partly offset by lower production, a significantly lower
contribution from gas marketing and trading and higher production taxes.
Outlook
In 2012, we will continue to drive operational risk reduction through the
new Exploration and Production segment structure, supported by the
S&OR function. Our divisions will work to manage risk and deliver common
standards, driving functional excellence across the lifecycle of exploration,
development and production, while continuing to focus on building our
technical capability for the future. We believe that our portfolio of assets
remains well positioned to compete and grow value in a range of external
conditions and we continue to increase both investment and operating cash.
We expect production in 2012 to be broadly flat, normalizing for divestments
and price effects, and excluding TNK-BP. This is the net effect of growth
from new projects and new production from India and Brazil being offset by
normal base decline. In 2012, we intend to drill 12 exploration wells, start
up six major projects, and increase our activity in the Gulf of Mexico to eight
operational rigs, subject to approvals by US regulators.
82 BP Annual Report and Form 20-F 2011
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.
In 2011, our exploration and appraisal costs, excluding lease
acquisitions, were $2,398 million, compared with $2,706 million in 2010
and $2,805 million in 2009. These costs included exploration and appraisal
drilling expenditures, which were capitalized within intangible fixed assets,
and geological and geophysical exploration costs, which were charged to
income as incurred. Approximately 76% of 2011 exploration and appraisal
costs were directed towards appraisal activity. In 2011, we participated in
308 gross (73.33 net) exploration and appraisal wells in nine countries. The
principal areas of exploration and appraisal activity were Angola, Australia,
Azerbaijan, Brazil, Canada, Egypt, the deepwater Gulf of Mexico, the UK
North Sea, Oman and onshore US.
Total exploration expense in 2011 of $1,520 million (2010 $843
million and 2009 $1,116 million) included the write-off of expenses related
to unsuccessful drilling activities in the deepwater Gulf of Mexico ($284
million), Asia Pacific ($61 million) and others ($5 million). It also included
$14 million related to decommissioning of idle infrastructure, as required by
the Bureau of Ocean Energy Management Regulation and Enforcement’s
Notice of Lessees 2010 G05 issued in October 2010.
Reserves booking from new discoveries will depend on the results
of ongoing technical and commercial evaluations, including appraisal drilling.
Proved reserves replacement
Total hydrocarbon proved reserves, on an oil equivalent basis including
equity-accounted entities, comprised 17,748mmboe (11,426mmboe
for subsidiaries and 6,322mmboe for equity-accounted entities) at
31 December 2011, a decrease of 2% (decrease of 5% for subsidiaries
and increase of 5% for equity-accounted entities) compared with the
31 December 2010 reserves of 18,071mmboe (12,077mmboe for
subsidiaries and 5,994mmboe for equity-accounted entities). Natural
gas represented about 40% (55% for subsidiaries and 14% for equity-
accounted entities) of these reserves. The change includes a net decrease
from acquisitions and disposals of 361mmboe (218mmboe net decrease
for subsidiaries and 143mmboe net decrease for equity-accounted
entities). Acquisitions occurred in Brazil, Canada, India, the UK, the US,
Venezuela and Vietnam. Divestments occurred in Algeria, Azerbaijan,
Canada, Colombia, Pakistan, Trinidad, the US, the UK, Venezuela and
Vietnam.
The proved reserves replacement ratio is the extent to which
production is replaced by proved reserves additions. This ratio is expressed
in oil equivalent terms and includes changes resulting from revisions to
previous estimates, improved recovery and extensions and discoveries.
For 2011, the proved reserves replacement ratio excluding acquisitions and
disposals was 103% (106% in 2010 and 129% in 2009) for subsidiaries
and equity-accounted entities, 45% for subsidiaries alone and 194% for
equity-accounted entities alone. The 2011 reserves additions for TNK-BP
include the effect of moving from life-of-licence measurement to life-of-
field measurement, reflecting TNK-BP’s track record of successful licence
renewal. Excluding this effect, our 2011 reserves replacement ratio
excluding acquisitions and disposals would have been 83%.
In 2011, net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted to
1,320mmboe (348mmboe for subsidiaries and 972mmboe for equity-
accounted entities), through revisions to previous estimates, improved
recovery from, and extensions to, existing fields and discoveries of new
fields. Of our subsidiary reserves additions through improved recovery
from, and extensions to, existing fields and discoveries of new fields,
approximately 26% were associated with new projects and were proved
undeveloped reserves additions. The remaining additions were in existing
developments where they represented a mixture of proved developed and
proved undeveloped reserves. Volumes added in 2011 principally relied
on the application of conventional technologies. The principal reserves
additions in our subsidiaries were in the US (San Juan North, Mad Dog,
Ursa, Prudhoe Bay, Hawkville), Trinidad (Cashima, Juniper) and Indonesia
(Tangguh). The principal reserves additions in our equity-accounted entities
Business review were in Russia (Orenburg, Slavneft, Verkhnechonskoye, Uvat, Talinskoye),
Venezuela (Petromonagas) and Argentina (Cerro Dragon).
Twelve per cent of our proved reserves are associated with PSAs.
The countries in which we operated under PSAs in 2011 were Algeria,
Angola, Azerbaijan, Egypt, India, Indonesia, Oman, Trinidad and Vietnam.
In addition, the technical service contract (TSC) under which we operate in
Iraq functions as a PSA.
Production
Our total hydrocarbon production during 2011 averaged 3,454 thousand
barrels of oil equivalent per day (mboe/d). This comprised 2,094mboe/d for
subsidiaries and 1,360mboe/d for equity-accounted entities, a decrease of
16% (decreases of 19% for liquids and 13% for gas) and an increase of
2% (increases of 2% for liquids and 5% for gas) respectively compared
with 2010. In aggregate, after adjusting for entitlement impacts in our PSAs
and the effect of acquisitions and disposals, production was 7% lower
than 2010. For subsidiaries, 37% of our production was in the US, 20% in
Trinidad and 8% in the UK.
The group and its equity-accounted entities have numerous long-
term sales commitments in their various business activities, all of which
are expected to be sourced from supplies available to the group that
are not subject to priorities, curtailments or other restrictions. No single
contract or group of related contracts is material to the group.
Acquisitions and disposals
During 2011, we undertook a number of acquisitions and disposals. In
total, disposal transactions generated $1.1 billion in proceeds during
2011 including repayment of the $3.5 billion disposal deposit relating to
Pan American Energy. See Financial statements – Note 5 on page 197.
With regards to proved reserves, 211mmboe were acquired in 2011
(approximately 94mmboe for subsidiaries and approximately 117mmboe
for equity-accounted entities), while 572mmboe were disposed of
(approximately 312mmboe for subsidiaries and approximately 260mmboe
for equity-accounted entities).
Acquisitions
• On 24 January 2011, BP exercised a preferential right to acquire Shell’s
working interest in the Marlin and Dorado producing fields in the Gulf
of Mexico for a total consideration of $257 million. This brought BP’s
working interest in both fields to 100%.
• On 12 May 2011, BP completed the purchase of 10 exploration
and production blocks in Brazil from Devon Energy, concluding the
agreement announced in 2010.
• On 30 August 2011, BP completed its acquisition from Reliance
Industries Limited (RIL) of a 30% stake in 21 oil and gas PSAs that
RIL operates in India for an aggregate consideration of $7.0 billion. In
November 2011, the two companies formed a 50:50 joint venture for the
sourcing and marketing of gas in India. See India for further information
on page 87.
Disposals
• On 24 January 2011, following the approval of the Colombian authorities,
BP completed the sale of its oil and gas exploration, production and
transportation business in Colombia to a consortium of Ecopetrol,
Colombia’s national oil company, and Talisman of Canada. The sale had
been announced in August 2010.
• On 22 February 2011, BP announced its intention to sell its interests in
a number of operated oil and gas fields in the UK including the Wytch
Farm onshore oilfield in Dorset and all of BP’s operated gas fields in the
southern North Sea, including associated pipeline infrastructure and the
Dimlington terminal. The sale of Wytch Farm to Perenco UK Limited
completed on 14 December 2011 for consideration of up to $610 million
in cash, which includes $55 million contingent on Perenco’s future
development of the Beacon field and on oil prices in 2011-2013. A sale
of the southern North Sea assets has yet to be concluded. The assets
do not yet meet the criteria to be reclassified as non-current assets held
for sale and it is not yet possible to estimate the financial effect of the
intended disposal of these assets.
• In April 2011, the Wattenberg Plant in Colorado was divested to
Anadarko for $575 million.
• In April 2011, an exchange agreement was signed with Bluestone
Natural Resources, LLC for the divestment of a mature gas field in South
Texas in exchange for acreage in a non-operated property in Eagle Ford.
• In June 2011, BP completed the sale of its upstream businesses in
Venezuela to TNK-BP.
• On 5 July 2011, BP sold half of the 3.29% interest in the Azeri-Chirag-
Gunashli development in the Caspian Sea which had been acquired from
Devon Energy in 2010 to Azerbaijan (ACG) Limited, an affiliate wholly
owned and controlled by the State Oil Company of the Republic of
Azerbaijan (SOCAR) for $485 million.
• On 16 September 2011, the sale of BP’s upstream assets in Pakistan
to United Energy Group (UEG) was completed. UEG has now assumed
control of the upstream assets. The sale, for $775 million, had been
announced at the end of 2010.
• In October 2011, BP completed the sale of Tuscaloosa assets in
Louisiana to Hilcorp Energy I LLC for $110 million.
• Also in October 2011, BP completed the sale of its 35% interest in the
Lan Tay and Lan Do gas fields in Vietnam to TNK-BP. The sale of BP’s
interests in the associated pipeline completed in November 2011. The
sale of BP’s interest in the Phu My 3 power generation plant is expected
to complete in 2012. As at 31 December 2011, this was classified as
assets held for sale.
• On 5 November 2011, BP received a notice from Bridas Corporation of
termination of the agreement for their purchase of BP’s 60% interest
in PAE. As a result of their decision and action, the share purchase
agreement governing this transaction, originally agreed on 28 November
2010, has been terminated. BP has repaid the deposit for the transaction
of $3.5 billion received at the end of 2010. For details of payments in
respect of the termination of restrictive covenants see page 85.
• On 1 December 2011, BP announced the sale of its Canadian Natural
Gas Liquid (NGL) business to Plains All American Pipeline L.P. for
$1.67 billion subject to closing adjustments. BP’s Canadian NGL
business owns, operates and has contractual rights to assets involved
in the extraction, gathering, fractionation, storage, distribution and
wholesale marketing of NGLs across Canada and in the Midwest US.
As at 31 December 2011 these assets were held as assets held for
sale, awaiting completion of the sale.
• On 28 December 2011, BP completed the sale of its interests in the
Pompano and Mica fields in the deepwater Gulf of Mexico to Stone
Energy Corporation for $204 million. The sale includes BP’s 75%
operated working interest in the Pompano field and assets and
50% non-operated working interest in the Mica field, together with
a 51% operated working interest in Mississippi Canyon block 29 and
interests in certain leases located in the vicinity of the Pompano field.
• On 28 February 2012, BP announced it had agreed terms with LINN
Energy to sell BP’s Hugoton basin assets (including the Jayhawk
NGL Plant). Under the agreement, LINN Energy has agreed to pay BP
$1.2 billion in cash. Completion of the agreement is subject to closing
conditions including the receipt of all necessary governmental and
regulatory approvals. The sale is currently expected to complete on
30 March 2012.
The following discussion reviews operations in our Exploration and
Production business by continent and country, and lists associated
significant events that occurred in 2011. BP’s percentage working
interest in oil and gas assets is shown in brackets. Working interest is the
cost-bearing ownership share of an oil or gas lease. Consequently, the
percentages disclosed for certain agreements do not necessarily reflect the
percentage interests in reserves and production.
Europe
United Kingdom
BP is the largest producer of hydrocarbons in the UK. Key aspects of our
activities in the North Sea include a focus on in-field drilling and selected
new field developments.
• On 16 November 2010, production from the Rhum gas field in the
central North Sea was suspended in relation to certain aspects of the
EU sanctions. This action was taken to comply with the notification
requirements in the relevant EU Regulation. Rhum is owned by BP
(50%) and the Iranian Oil Company (50%) under a joint operating
BP Annual Report and Form 20-F 2011 83
Business review: BP in more depthBusiness review agreement dating back to the early 1970s. Rhum remains shut-in. The
restart and safe operation of Rhum remains contingent on the availability
of third parties to provide services to Rhum. Such services are not as yet
all available and it is presently unclear when resumption of production
may be possible.
• On 13 July 2011, BP and its co-venturers announced an agreement to
progress a major redevelopment of the Schiehallion and Loyal oilfields
to the west of the Shetland Islands. The investment of circa $5 billion
in the redevelopment of the fields is expected to extend the field
life to 2035. The project involves replacing the existing Schiehallion
Floating, Production, Storage and Offloading (FPSO) vessel with a
new FPSO which is scheduled to be installed in 2015. BP will have a
36.3% ownership interest in the new FPSO. There will also be a major
investment in the upgrading and replacement of the subsea facilities
to enable full development of the reserves. Production is scheduled to
commence from the new facilities in 2016.
• On 6 September 2011, BP and its co-venturers announced an agreement
to invest up to $1.2 billion to progress a project to develop the Kinnoull
reservoir in the central UK North Sea (BP 77.06%). The reservoir will
be connected to BP’s Andrew platform, enabling production from the
Andrew area to extend to 2021.
• On 13 October 2011, BP announced that a major milestone had been
reached on the Devenick gas project (BP 88.7%) with the installation of
a 600-tonne module to receive gas and condensate from the Devenick
reservoir. Production from the field is due to commence in 2012.
• On 13 October 2011, BP announced the successful completion of a
well drilled to establish a southwest extension of the Clair field, west of
Shetland in the UK North Sea. This well confirmed recoverable oil from
a new portion of the field, and also discovered oil in a new, shallower
reservoir horizon. During 2012, a further seismic survey of the field is
planned, to understand the reservoir structure in more detail.
• Also on 13 October 2011, BP announced that the UK government had
granted BP and its partners Shell, ConocoPhillips and Chevron, approval
to proceed with the $7.6 billion Clair Ridge project (BP 28.6%), the
second phase of development of the Clair field.
Rest of Europe
Our activities in the Rest of Europe are in Norway.
• In 2011, the Valhall redevelopment project continued, with production
switch-over to the new facility scheduled for 2012. The redevelopment
consists of a new processing platform required as a result of the existing
platform suffering subsidence from extraction of hydrocarbons and
includes a ‘power from shore system’ eliminating all gas-fired equipment
offshore.
• On 14 August 2011, the FPSO vessel for the Skarv field arrived on
location in the Norwegian Sea. Hook up of risers and commissioning work
is ongoing and production is due to commence at the Skarv field in 2012.
• On 6 October 2011, the Ula field on the Norwegian Continental Shelf
celebrated 25 years of production.
North America
United States
Our activities within the US take place in three main areas: deepwater Gulf
of Mexico, Lower 48 states and Alaska.
Deepwater Gulf of Mexico
For further information on the activities of BP’s Gulf Coast Restoration
Organization established following the Deepwater Horizon oil spill, see
pages 76-79.
BP is the largest producer of hydrocarbons and the largest acreage
holder in the deepwater Gulf of Mexico, operating seven production hubs.
• Following BP’s success in lease sale 213 in March 2010, seven of the
leases awarded in 2010 were executed in 2011 and a further five leases
from the sale were awarded and executed in 2011.
• During 2011, preparations for safely restarting drilling operations in
the Gulf of Mexico were progressed. In July 2011, BP announced
the implementation of a new set of voluntary drilling standards for its
operations in the Gulf of Mexico. The standards go beyond existing
regulatory obligations and have been developed through lessons learned
following the Deepwater Horizon oil spill in 2010. By the end of 2011
84 BP Annual Report and Form 20-F 2011
there were five BP-operated deepwater rigs engaged in abandonment
and appraisal activities in the Gulf of Mexico. A permit to drill an appraisal
well at Kaskida was approved and drilling operations commenced in
October. Looking forward to 2012, plans include the drilling of exploration,
appraisal and development wells and the start-up of additional three rigs,
subject to receiving approvals from the US regulators.
• On 7 September 2011, BP announced the drilling of a successful
appraisal well in a previously untested northern segment of the Mad Dog
field in the Gulf of Mexico. The well, located on Green Canyon Block
738, approximately 140 miles south of Grand Isle, Louisiana, confirms
a significant resource extension for the Mad Dog field complex, which
includes the existing field, in production since 2005, and appraisal drilling
of the Mad Dog South field in 2008 and 2009. Due to the materiality
of the Mad Dog South finds, BP has been advancing development
options to increase production from Mad Dog and has now sanctioned
the final investment decision on Mad Dog Phase 2. This will be the first
BP-operated, standalone facility in a decade and will develop significant
additional resources through the addition of subsea water injection and
installation of a new production host.
• On 14 December 2011, the Bureau of Ocean Energy Management held
its first western Gulf of Mexico lease sale since August 2009. BP bid on
leases for 15 blocks and expects to be awarded leases for 11 blocks in
early 2012.
Lower 48 states
The North America Gas business operates onshore in the Lower 48 states
producing natural gas, natural gas liquids and coalbed methane across nine
states. In 2011, BP drilled 148 wells as operator across the US, including
the Wyoming, San Juan, Anadarko, Arkoma and East Texas basins. BP also
continues to participate in Eagle Ford, Fayetteville and other non-operated
positions. For further information on the use of fracking in our shale gas
assets see page 71.
Alaska
BP operates 15 North Slope oilfields (including Prudhoe Bay, Endicott,
Northstar, and Milne Point) and four North Slope pipelines, and owns a
significant interest in six other producing fields.
• The Point Thomson Unit (PTU) was terminated by administrative
decision of the State of Alaska Department of Natural Resources (DNR)
in November 2006 (BP 32%). ExxonMobil, the operator, and the other
unit owners, including BP, appealed the unit termination in the Alaska
Superior Court. On 11 January 2010, the Alaska Superior Court reversed
the DNR’s administrative decision to terminate the unit, and in the
second quarter of 2010, the State of Alaska Supreme Court granted
the DNR’s petition for a limited review. Briefs have been submitted to
the Alaska Supreme Court, and a decision is expected in 2012. In the
meantime, ExxonMobil and the State of Alaska have also informed the
other unit owners, including BP, that they have reached a preliminary
settlement agreement. BP and the other owners asked to participate
in the settlement discussions but were precluded. We are currently
analysing the agreement.
• In light of the closure of the Denali operations (see page 88 for further
details) BP continues to explore ways to commercialize its North Slope
gas resources.
• On 29 November 2007, BP Exploration (Alaska) Inc. (BPXA) pled guilty
to a misdemeanour violation under the US Water Pollution Control Act
to settle the criminal allegations by the state and federal government
related to leaks in 2006 from oil transit lines in the Prudhoe Bay unit.
The penalty included payment of $20 million with three years’ probation
that was due to expire on 29 November 2010. On 29 November 2009,
a spill of approximately 360 barrels of crude oil and produced water was
discovered beneath a ruptured frozen three-phase flow line running from
a well pad to the Lisburne Processing Center. On 17 November 2010,
the US Probation Officer filed a petition in federal district court to revoke
BPXA’s probation based on an allegation that the Lisburne spill was a
criminal violation of state or federal law. In November 2011, a hearing
was held in federal court in Anchorage. On 27 December 2011, the
court issued a final decision denying the government’s petition and
releasing BPXA from probation. See page 165 in Legal proceedings for
further details.
Business review Canada
In Canada, BP is focused on oil sands, and will use in situ steam-assisted
gravity drainage (SAGD) technology. This uses the injection of steam
into the reservoir to warm the bitumen so that it can flow to the surface
through recovery wells. BP holds an interest in several oil sands leases
through the Sunrise oil sands and Terre de Grace oil sands partnerships
and the Pike Oil Sands joint venture. BP also develops and produces
natural gas, markets natural gas and has significant exploration interests in
the Canadian Beaufort Sea.
• The Pike Oil Sands joint venture and the Terre de Grace partnership
successfully completed winter drilling programmes in 2011, which were
conducted to further appraise in situ oil sands resources. In late 2011,
Pike Phase 1 moved to project appraisal status.
• The Sunrise operator, Husky Energy Inc., commenced building facilities,
drilling wells and creating operational systems to bring Phase 1 into
production. First production of Phase 1 bitumen is expected in 2014,
potentially building to 60,000 barrels per day gross capacity over the
subsequent 24 months.
• Interpretation of the 3D seismic survey acquired in 2009 and the seismic
data for the EL446 field acquired in 2010 in the Canadian Beaufort Sea
continued in 2011 and is nearing completion.
South America
Brazil
• On 12 May 2011, after receiving approval from the Brazilian National
Petroleum, Natural Gas and Biofuels Agency (ANP), BP concluded
the purchase of Devon Energy do Brasil (later renamed BP Energy do
Brasil), adding 10 exploration and production blocks to its portfolio. The
acquired blocks give BP a diverse and broad deepwater exploration
acreage position offshore Brazil, with interests in seven licence blocks
in the Campos basin, one in the Camamu-Almada basin in water depths
ranging from 330 to 9,100 feet (100 to 2,780 metres), as well as two
onshore licences in the Parnaíba basin. The Campos basin blocks include
three discoveries – Xerelete, Pre-Salt Wahoo, and Itaipú – and the Polvo
Field in shallow water, which is currently producing around 19,000boe/d
net. BP completed the drilling of Itaipú-2, the first appraisal well in the
Itaipú deepwater discovery in November 2011 and is in the process of
finishing a second appraisal well.
Argentina, Bolivia and Chile
BP conducts activity in the Southern Cone region of South America
(Argentina, Bolivia and Chile) through PAE, an equity-accounted joint
venture with Bridas Corporation in which BP has a 60% interest.
• Following the announcement in November 2011 of the termination of
the sale of BP’s interest in PAE to Bridas, BP no longer classifies these
assets as assets held for sale. Under the share purchase agreement
BP was required to make a payment of $700 million to Bridas upon
termination in full settlement of any and all past claims between the
two companies and also as consideration for amendments to the PAE
agreement which terminate certain legacy restrictive covenants among
BP, PAE and Bridas. Subsequent to payment of this amount by BP in
November 2011, Bridas returned this $700 million to BP claiming that the
share purchase agreement was void; BP disputes this claim by Bridas
and maintains that the share purchase agreement and its terms which
survive termination (including the settlement and termination of legacy
restrictive covenants) remain valid and binding. The $700 million returned
to BP is shown in the balance sheet at 31 December 2011 within cash
and cash equivalents and within current trade and other payables.
• On 24 January 2012, the Republic of Bolivia issued a press statement
declaring its intent to nationalize PAE’s interests in the Caipipendi
Operations Contract. No formal nationalization process has yet
commenced. PAE and its shareholders BP and Bridas intend to
vigorously defend their legal interests under the Caipipendi Operations
Contract and available Bilateral Investment Treaties.
Trinidad & Tobago
BP holds exploration and production licences covering 917,000 acres
offshore of the east coast. Facilities include 13 offshore platforms and one
onshore processing facility. Production is comprised of oil, gas and natural
gas liquids (NGLs).
• On 25 July 2011, BP announced that it had been awarded two
deepwater exploration and production blocks by the government of the
Republic of Trinidad & Tobago. The award was for a 100% interest in
blocks 23(a) and TTDAA 14 offshore Trinidad’s east coast, both under
PSAs. Government approval is expected in early 2012. These blocks will
increase the acreage in the region by 889,000 acres.
• On 26 August 2011, BP announced that first gas had been achieved
from the Serrette platform. Serrette, sanctioned in May 2009, has a
design capacity of 1 billion cubic feet per day and may deliver a peak
production of up to 500 million standard cubic feet per day. It is the fifth
normally unmanned installation (NUI) to be designed and constructed in
Trinidad & Tobago. The platform will tie into the Cassia B platform.
Africa
Angola
BP is present in four major deepwater licences offshore Angola (Blocks 15,
17, 18 and 31) and is operator in Blocks 18 and 31. In addition, BP holds a
13.6% interest in the first Angolan LNG project.
• During the second quarter of 2011, a 40-day planned maintenance
shutdown was conducted on the Greater Plutonio field. Corrosion in
the high pressure gas cooling systems had restricted operations from
September 2010, necessitating a complex replacement project that was
safely completed in June 2011.
• The Pazflor deepwater development, located in block 17 (BP 16.67%),
came onstream on 24 August 2011, ahead of schedule. It encompasses
a new build FPSO, 49 subsea wells, 180 kilometres of flowlines and
10,000 tonnes of equipment on the seabed. Pazflor is expected to have
a plateau production rate of 220,000boe/d gross which will come from
the Perpetua, Hortensia, Acacia and Zinia fields. The FPSO has topside
facilities to process both Oligocene and Miocene age oils.
• In December 2011, BP gained access to five new deepwater exploration
and production blocks offshore Angola. These gave BP a leading position
in Angola, with interests in nine blocks accounting for a total acreage of
30,842km2. BP was awarded operatorship of Blocks 19 and 24 with 50%
interest, and additional non-operating interests in Blocks 20 (20%) and 25
(15%) covering 19,400km2 in the Kwanza and Benguela basins. BP has
also taken a 40% stake in the 4,840km2 Block 26 in the Benguela basin,
by agreeing a farm-in deal with Brazilian national oil company, Petrobras,
which operates the block. The five new blocks, including block 26, cover
a total area of 24,000km2 in water depths from 200 to 2,500 metres, and
increase BP’s total Angolan acreage by 275%.
Algeria
BP is a partner with Sonatrach and Statoil in the In Salah (BP 33.15%)
and In Amenas (BP 45.89%) projects, which supply gas to the domestic
and European markets. BP is also in a joint venture with Sonatrach in
the Rhourde El Baguel (REB) oilfield (BP 60%), an enhanced oil recovery
project 75 kilometres east of the Hassi Messaoud oilfield. In addition, BP is
in a joint venture with Sonatrach in the Bourarhet Sud block, located to the
south west of In Amenas.
• In 2011, development of the In Salah Southern Fields was approved and
the primary engineering contracts awarded. First gas is expected in 2014.
• On 22 December 2011, BP and Sonatrach reached an agreement for BP
to withdraw from the REB PSA at the end of 2011.
Libya
In Libya, BP is in partnership with the Libyan Investment Authority (LIA)
to explore acreage in the onshore Ghadames and offshore Sirt basins,
covered under the exploration and production-sharing agreement ratified in
December 2007 (BP 85%). BP’s total assets in Libya at 31 December 2011
were $437 million. To date, all of the 3D seismic commitment has been
completed but no exploration wells have yet been drilled.
• Due to the outbreak of civil unrest leading to the regime change in Libya,
the BP office in Tripoli was closed on 21 February 2011 and our Libyan
operations suspended. BP declared force majeure – the contractual
mechanism which flows from the suspension of our activities in Libya
and the imposition of sanctions. We intend to resume exploration
activities with agreement of the new authorities, and when we are sure
it is safe to do so. We are currently assessing how long it will take to
re-establish exploration operations.
BP Annual Report and Form 20-F 2011 85
Business review: BP in more depthBusiness review Egypt
BP has a long-standing history in Egypt, successfully operating there
for close to 50 years. To date BP with its partners has produced almost
40% of Egypt’s entire oil production and supplies more than 35% of the
domestic gas demand. BP’s total assets in Egypt at 31 December 2011
were $8,784 million ($4,768 non-current and $4,016 current).
• The 25 January 2011 civil uprising resulted in the BP office in Cairo
closing for a period of 10 days, reopening on 7 February. Production and
operations were, and continue to be, unaffected. Parliamentary elections
started in late November 2011 and are expected to run until mid-March
2012. We continue to closely monitor the developing situation in the
country and its potential impact on the business and our people.
• In October 2011, BP announced the Salmon gas discovery in the North
El Burg (BP 50% and operator) offshore concession in the Nile Delta.
Salmon is the third discovery in the concession, following the Satis 1 and
Satis 3 gas discoveries. Further appraisal work to evaluate the resources
is under way.
Asia
Western Indonesia
BP has a joint interest in Virginia Indonesia Company LLC (VICO), the
operator of the Sanga-Sanga PSA (BP 38%) supplying gas to Indonesia’s
largest LNG export facility, the Bontang LNG plant in Kalimantan. BP also
participates in the Sanga-Sanga coalbed methane (CBM) PSA (BP 38%), a
brownfield, unconventional development overlaying the conventional PSA.
Sanga-Sanga CBM is the cornerstone of the BP Asia Pacific CBM growth
strategy.
• In March 2011, the first CBM long-term production test well was tied
into the system that supplies Bontang LNG plant.
• On 1 April 2011, BP signed four new CBM PSAs – Tanjung IV, Kapuas I,
II, and III in the Barito Basin of Central Kalimantan, covering a contiguous
area of approximately 4,800km2. BP holds a 44% interest in the
Pertamina-operated Tanjung IV PSA, and a 45% operating interest in
each of the Kapuas I, II, and III PSAs. Subsurface evaluation of the areas
covered by the new PSAs is under way.
China
BP’s upstream activities in the country include production from the China
National Offshore Oil Corporation (CNOOC) operated Yacheng offshore gas
field (BP 34.3%) as well as deepwater exploration in the South China Sea’s
Block 42/05 (BP 40.82%). Yacheng supplies gas to the Castle Peak Power
Company for up to 70% of Hong Kong’s gas-fired electricity generation.
Additional gas is sold to the Hainan Holdings Fuel & Chemical Corporation
Limited.
• On 10 January 2011, BP announced that it had signed a new agreement
with CNOOC for deepwater exploration in Block 43/11 in the South
China Sea and government approval was received on 30 January 2012.
Azerbaijan
BP is the largest foreign investor in the country. BP operates two PSAs,
Azeri-Chirag-Gunashli (ACG) and Shah Deniz, and also holds other
exploration leases.
• In June 1996, when the Shah Deniz PSA was awarded, Oil Industries
Engineering and Construction, an affiliate of the National Iranian Oil
Company and assignor to the current Iranian interest holder, Naftiran
Intertrade Co. Ltd (NICO), was selected as a Shah Deniz project
participant by the State of Azerbaijan, and has a 10% non-operating
interest under the Shah Deniz PSA. NICO also has a 10% or less, non-
operating, interest in both the Shah Deniz project gas marketing entity
and its gas transportation entity, both of which were incorporated in
2002 and derive from the award of the Shah Deniz PSA. Under article
30 of the new EU Regulations concerning restrictive measures against
Iran, any body, entity or holder of rights derived from an award of a
PSA before the entry into force of the EU Regulations by a sovereign
government other than Iran, shall not be considered an ‘Iranian person,
entity or body’ for the purposes of the main operative provisions of the
EU Regulations. As such, the restrictive measures do not apply to
NICO and Shah Deniz continues to operate in full compliance with EU
and US law.
86 BP Annual Report and Form 20-F 2011
• On 6 May 2011, the Parliament of the Republic of Azerbaijan ratified the
new PSA between BP and the State Oil Company of Azerbaijan (SOCAR)
on joint exploration and development of the Shafag-Asiman structure
in the Azerbaijan sector of the Caspian Sea. The ratification follows the
signing of the PSA in Baku in October 2010. Under the PSA, which has
a 30-year term, BP will be the operator with 50% interest while SOCAR
will hold the remaining 50% interest.
• Following the Memorandum of Understanding signed in June 2010
between Turkey and Azerbaijan for gas sales and transportation of gas
from the new Shah Deniz full field development to be sold to consumers
in Turkey and across Europe, on 25 October 2011, Azerbaijan and Turkey
signed a number of key gas export related agreements to enable Turkey
to buy gas from Azerbaijan and to transit gas from Azerbaijan through
Turkey to Europe. The documents signed included an intergovernmental
agreement between the government of Azerbaijan and the government
of Turkey, gas sales agreements between SOCAR and BOTAS and
also between the Azerbaijan Gas Supply Company (AGSC) and BOTAS
International Limited (BIL), a gas transit agreement between SOCAR
and BIL and a framework agreement setting the general terms and
conditions for transit of gas sourced from Azerbaijan through the territory
of Turkey. The agreements provide a legal framework to regulate the
sale of Shah Deniz gas to Turkey and its transportation to European
markets through Turkey.
Russia
• In May 2011, BP announced that both the Rosnefta share swap
agreement and the Arctic Opportunity, originally announced on
14 January 2011, had terminated. This termination was a result
of the deadline for the satisfaction of conditions precedent having
expired following delays resulting from interim orders granted by the
English High Court and a UNCITRAL arbitration tribunal. This followed
applications brought by Alfa Petroleum Holdings Limited (Alfa) and OGIP
Ventures Limited (OGIP) against BP International Limited (BPIL) and BP
Russian Investments Limited (BPRIL) alleging breach of the TNK-BP
shareholders agreement (SHA). These interim orders did not address
the question of whether or not BP breached the SHA. The UNCITRAL
arbitration proceedings with Alfa, Access and Renova (AAR) which
are subject to strict confidentiality obligations are ongoing. See Legal
proceedings on page 166 for further information.
TNK-BP
TNK-BP, an associate owned by BP (50%) and AAR (50%), is an integrated
oil company operating in Brazil, Russia, Ukraine, Venezuela and Vietnam.
TNK-BP’s strategic goal is to become an international oil and gas company
with a leading position in the Russian oil and gas industry. BP’s investment
in TNK-BP is reported in the Exploration and Production segment. From
2012 onward TNK-BP will be reported as a separate operating segment,
as explained more fully on page 80. The TNK-BP group’s major assets
are held in OAO TNK-BP Holding. Other assets include OAO Slavneft,
an equity-accounted joint venture. The workforce is comprised of more
than 50,000 people. TNK-BP’s main board is currently comprised of four
BP, four AAR, and one independent director, with two vacancies for
independent directors. The boards of key TNK-BP subsidiaries have both
BP and AAR directors. In December 2011, two independent non-executive
directors of TNK-BP Limited, Gerhard Schroeder and James Leng,
announced that they would be stepping down from their positions on the
board at the end of 2011.
• Upstream, TNK-BP operates either directly, or through equity-accounted
joint ventures, a number of oil and gas fields in Russia, Vietnam and
Venezuela which produced approximately 1.99mboe/d in 2011.
• Downstream, TNK-BP has interests in six refineries in Russia and
Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl
refinery), with throughput of approximately 711 thousand barrels per day
in 2011. TNK-BP has over 1,400 branded retail stations in Russia and
Ukraine.
a BP already holds a 1.3% investment in Rosneft Oil Company with a carrying value of $873 million.
Business review • In March 2011, TNK-BP completed the acquisition of 74.9% of CJSC
‘Toplivozapravochny kompleks Sheremetyevo’, the operator of jet fuel
storage and into-wing fuelling services at Sheremetyevo International
Airport in Moscow.
• In June 2011, TNK-BP completed the acquisition from BP of stakes in
three upstream assets in Venezuela. Acquisition of these assets was
announced in October 2010.
• In October 2011, TNK-BP entered into an agreement with HRT Oil & Gas
for the acquisition of a 45% stake in 21 blocks in the Brazilian Solimoes
Basin. These oil and gas exploration blocks are operated by HRT Oil &
Gas, and cover an area of approximately 48,000km2.
• Also in October 2011, TNK-BP announced that the Vietnamese Ministry
of Investment and Trade granted TNK Vietnam, a Vietnam-based
subsidiary of TNK-BP, the investment licence to operate offshore gas
Block 6.1. TNK-BP acquired BP’s 35% stake in Block 6.1, an integrated
gas to power project which contains the Lan Tay and Lan Do gas
condensate fields. As part of the deal, TNK-BP also acquired BP’s 32.7%
interest in the Nam Con Son Pipeline. Acquisition of these assets was
announced in October 2010.
Middle East
Production in the Middle East consists principally of the production
entitlement of associates in Abu Dhabi, where we have equity interests of
9.5% and 14.67% in onshore and offshore concessions respectively. The
Abu Dhabi onshore concession expires in January 2014 with a consequent
reduction in production of approximately 140mb/d.
• In the first quarter of 2011, extended well test production began in Oman.
• In August 2011, the seismic survey of the Risha concession in Jordan
was successfully completed.
India
• On 30 August 2011, BP and Reliance Industries Limited (RIL) announced
the completion of BP’s acquisition of a 30% stake in 21 oil and gas PSAs
that RIL operates in India, including the producing KG D6 block. BP paid
RIL an aggregate consideration of $7.0 billion for the interests acquired
in the 21 PSAs. Further performance payments of up to $1.8 billion could
be paid in case of exploration success in certain blocks that result in
the development of commercial discoveries. This step commenced the
planned alliance which will operate across the gas value chain in India,
from exploration and production to distribution and marketing.
• Five minority shareholders of OAO TNK-BP Holding (TBH) filed a civil
• On 17 November 2011, the two companies formed a 50:50 joint venture
action in Tyumen, Siberia, against BP Russia Investments Limited and
BP p.l.c. seeking to recover alleged losses of $13 billion relating to BP’s
attempt to form a strategic alliance with Rosneft in January 2011. The
action was dismissed by the Tyumen court fully on its merits. The Omsk
Appellate court confirmed the Tyumen court of first instance’s dismissal
of the minority suits. See Legal proceedings on page 166 for further
information.
• On 9 February 2012, BP reached agreement with its Russian partners
in TNK-BP on temporary amendments to the memorandum and articles
of association of TNK-BP Limited and the SHA that reduce quorum
requirements to require presence of directors nominated by BP and
AAR only. The amendments are aimed at enabling the continuing
functioning of the board of directors of TNK-BP (board of directors) while
two independent directors who recently resigned are being replaced.
This change is currently set to expire on 31 March 2012, unless both
independent directors are appointed earlier.
• On 9 February 2012, BP also reached agreement with its Russian
partners in TNK-BP regarding certain changes to the management board
of its main management company in Russia OAO TNK-BP Management
(management board). The changes were aimed at restructuring and
optimizing the management board, following the elimination of the
deputy TNK-BP group chief executive officer role. The restructured
management board will now consist of six people. BP will have the
right to nominate the chairman of the management board, as well
as two executive directors in charge of upstream and downstream
respectively (the BP members). AAR will have the right to nominate
two other executive directors (the AAR members). The sixth member
— the chief financial officer — will be nominated by the chairman of the
management board. The chairman of the management board will in time
also have the right to nominate the executive directors, subject to prior
concurrence by the respective shareholder. All of the aforementioned
nominations will require approval by the board of directors as a majority
matter, except for the chairman of the management board whose
appointment will require approval as a unanimous reserved matter. As
part of the agreement, BP and AAR agreed to approve the continued
appointment of the chief executive officer and the appointment of their
respective executive directors, with such appointments to expire no later
than 31 December 2013.
• All other provisions of the SHA (including those related to the review
of new business opportunities, the board of directors and dispute
resolution) remain unchanged.
Sakhalin
BP has interests in Sakhalin through a joint venture company, Elvary
Neftegaz, in which BP holds a 49% equity interest, and its partner,
Rosneft, holds the remaining 51% interest. In 2011, the process to exit
the licence areas held by Elvary Neftegaz and liquidate the joint venture
commenced. This follows the write-down of BP’s investment at the end of
2010 following an unsuccessful exploration programme.
for the sourcing and marketing of gas in India.
Iraq
Following a successful bid with PetroChina to run the Rumaila oilfield
in June 2009, the technical service contract (TSC) became effective
on 17 December 2009. BP holds a 38% working interest and is the
lead contractor. Rumaila is one of the world’s largest oilfields and was
discovered by BP in 1953 and comprises five producing reservoirs. BP
together with its partners is actively refurbishing the wells and facilities.
With the achievement of the improved production target on 25 December
2010, BP and PetroChina became eligible for service fees pursuant to the
TSC. In 2011 both companies lifted cargoes from the Basra terminal as
payment for service fees due.
Australasia
Australia
BP is one of seven partners in the North West Shelf (NWS) venture which
has been producing LNG, pipeline gas, condensate, LPG and oil since the
1980s. Six partners (including BP) hold an equal 16.67% interest in the
gas infrastructure and an equal 15.78% interest in the gas and condensate
reserves, with a seventh partner owning the remaining 5.32%. BP also has
a 16.67% interest in the NWS oil reserves and related infrastructure. The
NWS venture is currently the principal supplier to the domestic market in
Western Australia and one of the largest LNG export projects in Asia with
five LNG trainsa in operation. BP also holds a 5.375% interest in the
Jansz-Io field which is part of the Greater Gorgon project (Chevron,
ExxonMobil and Shell) and is currently being developed.
• In January 2011, BP announced that it had been awarded four
deepwater offshore exploration blocks in the Ceduna Sub Basin
within the Great Australian Bight, off the coast of South Australia. The
exploration work is to be phased over six years with a 3D seismic survey
covering approximately 12,500km2 commenced in November 2011 and
continuing into 2012. Following interpretation of the seismic survey, BP
will drill four deepwater wells in this frontier exploration basin.
Eastern Indonesia
BP has a 100% interest in an exploration asset, the North Arafura PSA,
located on the coast of the Arafura Sea, 480 kilometres south east of our
Tangguh LNG plant (BP 37.16% and operator) and covering an area of just
over 5,000km2. In addition, BP owns a 32% interest in Chevron’s operated
West Papua I and III PSAs, located circa 120 kilometres to the south of the
Tangguh LNG plant (see Liquefied natural gas on page 88).
• In December 2011, BP signed contracts with the Government of
Indonesia for two deepwater PSAs; West Aru I and II. The PSAs are
located 500 kilometres south west of the North Arafura PSA and 200
kilometres west of the Aru island group, covering areas of 8,100km2 and
8,300km2 respectively. BP holds 100% interest in the PSAs and expects
to commence seismic operations in the near future.
a An LNG train is a processing facility used to liquefy and purify LNG.
BP Annual Report and Form 20-F 2011 87
Business review: BP in more depthBusiness review Midstream activities
Oil and natural gas transportation
The group has direct or indirect interests in certain crude oil and natural
gas transportation systems. The following narrative details the significant
events that occurred during 2011 by country.
BP’s onshore US crude oil and product pipelines and related
transportation assets are included under Refining and Marketing (see
page 94).
Alaska
BP owns a 46.9% interest in the Trans-Alaska Pipeline System (TAPS),
with the balance owned by four other companies. The TAPS transports
crude oil from Prudhoe Bay on the Alaska North Slope to the port of
Valdez in south-east Alaska. BP also owns a 50% interest in a joint venture
company called ‘Denali – The Alaska Gas Pipeline’ (Denali).
• On 16 May 2011, Denali announced that its open season efforts did not
result in the commitments necessary to continue work on the Alaska
North Slope gas pipeline project. Denali also indicated that it planned to
close out its operations over the remainder of 2011. As a 50% owner in
Denali, BP, along with co-owner ConocoPhillips, was directly involved
in the decision to terminate Denali’s activities. BP’s focus as an owner
in Denali was to create a viable alternative for the owners of the North
Slope gas resource to commercialize their gas. BP has determined that
the North American natural gas market does not support the project at
this time. The Denali effort marked an important step in advancing the
industry understanding of the gas pipeline opportunity in Alaska. BP will
continue to pursue ways to commercialize our Alaskan gas resource.
North Sea
In the UK sector of the North Sea, BP operates the Forties Pipeline System
(FPS) (BP 100%), an integrated oil and NGLs transportation and processing
system that handles production from more than 50 fields in the central
North Sea. The system has a capacity of more than 1 million barrels per
day, with average throughput in 2011 of 473mboe/d. BP also operates
and has a 36% interest in the Central Area Transmission System (CATS),
a 400-kilometre natural gas pipeline system in the central UK sector of
the North Sea. The pipeline has a transportation capacity of 293mboe/d
to a natural gas terminal at Teesside in north-east England. Average
throughput in 2011 was 39mboe/d. CATS offers natural gas transportation
and processing services. In addition, BP operates the Sullom Voe oil
and gas terminal in Shetland and the Dimlington/Easington Terminals in
Humberside. Dimlington and Easington form part of the southern gas
assets that BP announced its intention to sell in February 2011 (see
Disposals on page 83).
Asia
BP, as operator, holds a 30.1% interest in and manages the Baku-Tbilisi-
Ceyhan (BTC) oil pipeline. The 1,768-kilometre pipeline transports oil
from the BP-operated ACG oilfield in the Caspian Sea to the eastern
Mediterranean port of Ceyhan and has a capacity of 1.2 million barrels
per day. BP is technical operator of, and holds a 25.5% interest in, the
693-kilometre South Caucasus Pipeline, which takes gas from Azerbaijan
through Georgia to the Turkish border and has a capacity of 780mmscf/d.
In addition, BP operates the Azerbaijan section of the Western Export
Route Pipeline between Azerbaijan and the Black Sea coast of Georgia
(as operator of Azerbaijan International Operating Company).
Liquefied natural gas
Our LNG activities are focused on building competitively advantaged
liquefaction projects, establishing diversified market positions to create
maximum value for our upstream natural gas resources and capturing third-
party LNG supply to complement our equity flows. Assets and significant
events in 2011 included:
• In Trinidad, BP’s net share of the capacity of Atlantic LNG trainsa 1,
2, 3 and 4 is 6 million tonnes of LNG per year (292 billion cubic feet
equivalent regasified). All of the LNG from Atlantic train 1 and most of
the LNG from trains 2 and 3 is sold to third parties in the US and Spain
under long-term contracts. All of BP’s LNG entitlement from Atlantic
LNG train 4 and some of its entitlement from trains 2 and 3 is marketed
88 BP Annual Report and Form 20-F 2011
via BP’s LNG marketing and trading business to a variety of markets
including the US, the Dominican Republic, Spain, the UK, Japan, India
and South Korea.
• We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction
Company, which in 2011 supplied 5.76 million tonnes of LNG (297 billion
cubic feet equivalent regasified).
• BP has a 13.6% share in the Angola LNG project, which is expected to
receive approximately 1 billion cubic feet of associated gas per day from
offshore producing blocks and to produce 5.2 million tonnes per annum
of LNG (gross), as well as related gas liquids products. Construction and
implementation of the project is proceeding and the plant is expected to
start up in 2012.
• In Indonesia, BP is involved in two of the three LNG centres in the
country. BP participates in Indonesia’s LNG exports through its holdings
in the Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently delivers
around 13% of the total gas feed to Bontang, one of the world’s largest
LNG plants. The Bontang plant produced more than 15 million tonnes of
LNG in 2011.
• Also in Indonesia, BP has its first operated LNG plant, Tangguh (BP
37.16%), in Papua Barat. The asset comprises of 14 producing wells,
two offshore platforms, two pipelines and an LNG plant with two
production trains with a total capacity of 7.6 million tonnes per annum.
Tangguh supplies LNG to customers in China, South Korea, Mexico and
Japan through long-term contracts. BP is currently progressing options to
expand the Tangguh facilities.
• In Australia, BP is one of seven partners in the NWS venture. The joint
venture operation covers offshore production platforms, trunklines,
onshore gas and LNG processing plants and LNG carriers. BP’s net share
of the capacity of NWS LNG trains 1-5 is 2.7 million tonnes per annum
of LNG. BP is one of five partners in the Browse LNG venture (operated
by Woodside) and holds approximately a 17% interest. A greenfield
LNG development at a proposed state government LNG precinct in
the Kimberley region is currently in the early design stage and remains
subject to regulatory, company and partner approvals.
• BP has a 30% equity stake in the 7mtpa capacity Guangdong LNG
regasification and pipeline project in south-east China, making it the
only foreign partner in China’s LNG import business. The terminal is
also supplied under a long-term contract with Australia’s NWS project in
which BP has an interest.
• In both the Atlantic and Asian regions, BP is marketing LNG using BP
LNG shipping and contractual rights to access import terminal capacity in
the liquid markets of the US (via Cove Point and Elba Island), the UK (via
the Isle of Grain) and Italy (Rovigo), and is supplying Asian customers in
Japan, South Korea and Taiwan.
Gas marketing and trading activities
Gas and power marketing and trading activity is undertaken primarily in
the US, Canada and Europe to market both BP production and third-party
natural gas, to support group LNG activities and manage market price risk,
as well as to create incremental trading opportunities through the use of
commodity derivative contracts. Additionally, this activity generates fee
income and enhances margins from sources such as the management of
price risk on behalf of third-party customers. These markets are large, liquid
and volatile. Market conditions have become more challenging over the
past few years due to the availability of shale gas and increased pipeline
builds in North America. This has resulted in limited basis differentials and
faster changes in production volumes in response to price movements.
However, new markets are continuing to develop with continental
European markets opening up and LNG becoming more liquid. The
business (including support functions) operates primarily from offices in
Houston and London and employs around 1,500 people.
In connection with its trading 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
a See footnote a on page 87.
Business review access advantageous pricing differences between locations, time periods
and arbitrage between markets. Natural gas futures and options are traded
through exchanges, while over-the-counter (OTC) options and swaps are
used for both gas and power transactions through bilateral and/or centrally-
cleared arrangements. Futures and options are primarily used to trade
the key index prices, such as Henry Hub, while swaps can be tailored to
price with reference to specific delivery locations where gas and power
can be bought and sold. OTC forward contracts have evolved in both
the US and UK markets, enabling gas and power to be sold forward in a
variety of locations and future periods. These contracts are used both to
sell production into the wholesale markets and as trading instruments to
buy and sell gas and power in future periods. Storage and transportation
contracts allow the group to store and transport gas, and transmit power
between these locations. The group has developed a risk governance
framework to manage and oversee the financial risks associated with this
trading activity, which is described in Note 26 to the Financial statements
on pages 217-222. The group’s trading activities in natural gas are managed
by the integrated supply and trading function.
The range of contracts that the group enters into is described in
Certain definitions – commodity trading contracts, on page 111.
Oil and gas disclosures
The following tables provide additional data and disclosures in relation to our oil and gas operations.
Average sales price per unit of production
Europe
North
America
South
America
Africa
Asia
UK
Rest of
Europe
US
Rest of
North
Americab
Russia
Rest of
Asia
$ per unit of productiona
Total
Australasia
group
average
Average sales pricec
Subsidiaries
2011
Liquidsd
Gas
2010
Liquidsd
Gas
2009
Liquidsd
Gas
Equity-accounted entitiese
2011
Liquidsd
Gas
2010
Liquidsd
Gas
2009
Liquidsd
Gas
107.83
7.91
106.89
13.15
76.33
5.44
62.19
4.68
81.09
7.16
60.73
7.62
96.34
3.34
70.79
3.88
53.68
3.07
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
86.60
3.60
104.37
5.24
74.87
4.11
57.40
3.61
–
–
–
–
–
–
111.10
4.73
101.22
9.13
101.29
4.69
78.80
4.05
61.27
3.30
8.11
12.21
6.72
7.83
5.59
5.25
75.81
7.01
57.22
5.25
–
–
–
–
–
–
73.41
3.97
56.26
3.25
71.35
2.40
52.81
2.04
41.93
1.68
–
–
–
–
–
–
84.39
2.23
60.39
1.91
47.27
1.51
48.26
4.20
30.77
3.53
–
–
–
–
–
–
71.01
2.80
52.48
2.50
73.51
2.31
61.60
1.97
51.01
1.90
a Units of production are barrels for liquids and thousands of cubic feet for gas.
b Producing assets now largely divested.
c Realizations include transfers between businesses.
d Crude oil and natural gas liquids.
e It is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets at discounted prices.
Average production cost per unit of production
The average production
cost per unit of productiona
Subsidiaries
2011
2010
2009
Equity-accounted entities
2011
2010
2009
Europe
North
America
South
America
Africa
Asia
UK
Rest of
Europe
US
Rest of
North
Americab
Russia
Rest of
Asia
$ per unit of productiona
Total
Australasia
group
average
21.59
12.79
12.38
18.23
9.76
10.72
12.09
8.10
7.26
–
15.78
14.45
–
–
–
–
–
–
–
–
–
–
–
–
3.20
2.48
2.20
9.04
6.32
6.12
10.82
7.52
6.05
–
–
–
–
–
–
5.68
5.04
4.63
8.65
4.59
4.35
2.70
2.61c
2.52c
3.05
2.03
1.60
10.08
6.77
6.39
–
–
–
5.58
4.83c
4.50c
a Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
b Producing assets now largely divested.
c A minor amendment has been made to comparative periods.
BP Annual Report and Form 20-F 2011 89
Business review: BP in more depthBusiness review Licence expiry
The Abu Dhabi onshore concession expires in January 2014 with a
consequent reduction in production of approximately 140mb/d. The group
holds no other licences due to expire within the next three years that
would have a significant impact on BP’s reserves or production.
Resource progression
BP manages its hydrocarbon resources in three major categories: prospect
inventory, contingent resources and proved reserves. When a discovery
is made, volumes usually transfer from the prospect inventory to the
contingent resources category. The contingent resources move through
various sub-categories as their technical and commercial maturity increases
through appraisal activity.
At the point of final investment decision, most proved reserves will
be categorized as proved undeveloped (PUD). Volumes will subsequently
be re-categorized from PUD to proved developed (PD) as a consequence
of development activity. When part of a well’s proved reserves depends
on a later phase of activity, only that portion of proved reserves associated
with existing, available facilities and infrastructure moves to PD. The first
PD bookings will typically occur at the point of first oil or gas production.
Major development projects typically take one to four years from the time
of initial booking of proved reserves to the start of production. Changes to
proved reserves bookings may be made due to analysis of new or existing
data concerning production, reservoir performance, commercial factors,
acquisition and disposal activity and additional reservoir development
activity.
Volumes can also be added or removed from our portfolio through
acquisition or divestment of properties and projects. When we dispose
of an interest in a property or project, the volumes associated with our
adopted plan of development for which we have a final investment
decision will be removed from our proved reserves upon completion.
When we acquire an interest in a property or project, the volumes
associated with the existing development and any committed projects
will be added to our proved reserves if BP has made a final investment
decision and they satisfy the SEC’s criteria for attribution of proved status.
Following the acquisition, additional volumes may be progressed to proved
reserves from contingent.
Contingent resources in a field will only be re-categorized as proved
reserves when all the criteria for attribution of proved status have been met
and the proved reserves are included in the business plan and scheduled
for development, typically within five years. The group will only book
proved reserves where development is scheduled to commence after five
years, if these proved reserves satisfy the SEC’s criteria for attribution of
proved status and BP management has reasonable certainty that these
proved reserves will be produced.
At the end of 2011, BP had material volumes of proved
undeveloped reserves held for more than five years in Trinidad, as well as
non-material volumes in Australia, Azerbaijan, Norway, the UK and the US,
that are part of ongoing development activities for which BP has a historical
track record of completing comparable projects in these countries.
The volumes are being progressed as part of an adopted development
plan where there are physical limits to the development timing such
as infrastructure limitations, contractual limits including gas delivery
commitments, late life compression and the complex nature of working in
remote locations.
BP has a three year average track record (since the adoption of
the modernised rules for reporting) of converting 20% of our proved
undeveloped reserves (excluding disposals) to proved developed reserves.
This equates to a turnover time of five years. We expect the turnover time
to remain at or below five years and anticipate no increase in the volume of
proved undeveloped reserves held for more than five years.
In 2011, we converted 1,062mmboe of proved undeveloped
reserves to proved developed reserves through ongoing investment in
our upstream development activities. Total development expenditure in
Exploration and Production, excluding midstream activities, was $13,329
million in 2011 ($10,194 million for subsidiaries and $3,135 million for
equity-accounted entities). The major areas converted in 2011 were
Argentina, Indonesia, Russia, Trinidad and the US. Revisions of previous
estimates for proved undeveloped reserves are due to the impact of
90 BP Annual Report and Form 20-F 2011
year-end price (net of 1%) and changes relating to field performance or
well results (99%). The table below describes the changes to our proved
undeveloped reserves position through the year.
Proved undeveloped reserves at 1 January 2011
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales
Total in year proved undeveloped reserves changes
Progressed to proved developed reserves
Proved undeveloped reserves at 31 December 2011
volumes in mmboe
7,899
693
522
92
77
(302)
8,981
(1,062)
7,919
BP bases its proved reserves estimates on the requirement of reasonable
certainty with rigorous technical and commercial assessments based on
conventional industry practice. BP only applies technologies that have been
field tested and have been demonstrated to provide reasonably certain
results with consistency and repeatability in the formation being evaluated
or in an analogous formation. BP applies high-resolution seismic data for
the identification of reservoir extent and fluid contacts only where there is
an overwhelming track record of success in its local application. In certain
deepwater fields BP has booked proved reserves before production flow
tests are conducted, in part because of the significant safety, cost and
environmental implications of conducting these tests. The industry has
made substantial technological improvements in understanding, measuring
and delineating reservoir properties without the need for flow tests. To
determine reasonable certainty of commercial recovery, BP employs a
general method of reserves assessment that relies on the integration of
three types of data: (1) well data used to assess the local characteristics
and conditions of reservoirs and fluids; (2) field scale seismic data to
allow the interpolation and extrapolation of these characteristics outside
the immediate area of the local well control; and (3) data from relevant
analogous fields. Well data includes appraisal wells or sidetrack holes, full
logging suites, core data and fluid samples. BP considers the integration
of this data in certain cases to be superior to a flow test in providing
understanding of overall reservoir performance. The collection of data
from logs, cores, wireline formation testers, pressures and fluid samples
calibrated to each other and to the seismic data can allow reservoir
properties to be determined over a greater volume than the localized
volume of investigation associated with a short-term flow test. There is
a strong track record of proved reserves recorded using these methods,
validated by actual production levels.
Governance
BP’s centrally controlled process for proved reserves estimation approval
forms part of a holistic and integrated system of internal control. It consists
of the following elements:
• Accountabilities of certain officers of the group to ensure that there is
review and approval of proved reserves bookings independent of the
operating business and that there are effective controls in the approval
process and verification that the proved reserves estimates and the
related financial impacts are reported in a timely manner.
• Capital allocation processes, whereby delegated authority is exercised
to commit to capital projects that are consistent with the delivery of the
group’s business plan. A formal review process exists to ensure that
both technical and commercial criteria are met prior to the commitment
of capital to projects.
• Internal audit, whose role is to consider whether the group’s system
of internal control is adequately designed and operating effectively to
respond appropriately to the risks that are significant to BP.
• Approval hierarchy, whereby proved reserves changes above certain
threshold volumes require central authorization and periodic reviews. The
frequency of review is determined according to field size and ensures
that more than 80% of the BP proved reserves base undergoes central
review every two years, and more than 90% is reviewed centrally every
four years.
Business review BP’s vice president of segment reserves is the petroleum engineer
primarily responsible for overseeing the preparation of the reserves
estimate. He has over 25 years of diversified industry experience with
the past eight spent managing the governance and compliance of BP’s
reserves estimation. He is a past member of the Society of Petroleum
Engineers Oil and Gas Reserves Committee, a sitting member of the
American Association of Petroleum Geologists Committee on Resource
Evaluation and vice chair of the bureau of the United Nations Economic
Commission for Europe Expert Group on Resource Classification.
For the executive directors and senior management, no specific
portion of compensation bonuses is directly related to proved reserves
targets. Additions to proved reserves is one of several indicators by
which the performance of the Exploration and Production segment is
assessed by the remuneration committee for the purposes of determining
compensation bonuses for the executive directors. Other indicators include
a number of financial and operational measures.
BP’s variable pay programme for the other senior managers in the
Exploration and Production segment is based on individual performance
contracts. Individual performance contracts are based on agreed items
from the business performance plan, one of which, if chosen, could relate
to proved reserves.
Compliance
International Financial Reporting Standards (IFRSs) do not provide
specific guidance on reserves disclosures. BP estimates proved reserves
in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant
Compliance and Disclosure Interpretations (C&DI) and Staff Accounting
Bulletins as issued by the SEC staff.
By their nature, there is always some risk involved in the ultimate
development and production of proved reserves, including, but not
limited to, final regulatory approval, the installation of new or additional
infrastructure, as well as changes in oil and gas prices, changes in
operating and development costs and the continued availability of additional
development capital. All the group’s proved reserves held in subsidiaries
and equity-accounted entities are estimated by the group’s petroleum
engineers.
BP’s estimated net proved reserves as at 31 December 2011
Seventy-five per cent of our total proved reserves of subsidiaries at
31 December 2011 were held through unincorporated joint ventures (75%
in 2010), and 33% of the proved reserves were held through
such unincorporated joint ventures where we were not the operator
(31% in 2010).
Estimated net proved reserves of liquids at 31 December 2011a b c
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
288
69
1,685
–
27
311
177
59
2,616
3,201
5,817
Undeveloped
445
230
1,173
–
48
315
279
47
2,537
million barrels
Total
733
299
2,858d
–
75e
626
456
106
5,153
2,211
4,748
5,412f
10,565
Estimated net proved reserves of natural gas at 31 December 2011a b
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Developed
1,411
43
9,721
28
2,869
1,224
1,034
3,570
19,900
3,367
23,267
Undeveloped
909
450
3,831
–
6,529
2,033
364
2,365
16,481
1,911
18,392
billion cubic feet
Total
2,320
493
13,552
28
9,398g
3,257
1,398
5,935
36,381
5,278h
41,659
Our proved reserves are associated with both concessions (tax
Total
and royalty arrangements) and agreements where the group is exposed to
the upstream risks and rewards of ownership, but where our entitlement
to the hydrocarbons is calculated using a more complex formula, such as
PSAs. In a concession, the consortium of which we are a part is entitled to
the proved reserves that can be produced over the licence period, which
may be the life of the field. In a PSA, we are entitled to recover volumes
that equate to costs incurred to develop and produce the proved reserves
and an agreed share of the remaining volumes or the economic equivalent.
As part of our entitlement is driven by the monetary amount of costs to
be recovered, price fluctuations will have an impact on both production
volumes and reserves.
We disclose our share of proved reserves held in equity-accounted
entities (jointly controlled entities and associates), although we do not
control these entities or the assets held by such entities.
Net proved reserves on an oil equivalent basis
Subsidiaries
Equity-accounted entities
Total
Developed
6,048
3,781
9,829
million barrels of oil equivalent
Undeveloped
Total
11,426
5,378
6,322i
2,541
7,919
17,748
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the
royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently, and include minority interests in consolidated
operations. We disclose our share of reserves held in jointly controlled entities and associates that
are accounted for by the equity method although we do not control these entities or the assets
held by such entities.
b The 2011 marker prices used were Brent $110.96/bbl (2010 $79.02/bbl and 2009 $59.91/bbl) and
Henry Hub $4.12/mmBtu (2010 $4.37/mmBtu and 2009 $3.82/mmBtu).
c Liquids include crude oil, condensate, natural gas liquids and bitumen.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 82 million barrels on which
a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay
Royalty Trust.
e Includes 20 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and
Tobago LLC.
f Includes 310 million barrels of crude oil in respect of the 7.37% minority interest in TNK-BP.
g Includes 2,759 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad
and Tobago LLC.
h Includes 174 billion cubic feet of natural gas in respect of the 6.27% minority interest in TNK-BP.
i Total proved reserves held as part of our equity interest in TNK-BP is 4,802mmboe comprising
100 million barrels in Venezuela, 14mmboe in Vietnam and 4,688mmboe in Russia. In 2011 BP
aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty
of licence renewals is demonstrated by evidence of Russian subsoil law, track record of renewals
within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted
in a 253mmboe increase in proved reserves.
BP Annual Report and Form 20-F 2011 91
Business review: BP in more depthBusiness review http://www.bp.com/downloads/oilandgasproduction
BP’s net production by major field for 2011, 2010 and 2009.
Liquids
Subsidiaries
UKb
Total UK
Norwayb
Total Rest of Europe
Total Europe
Alaska
Total Alaska
Lower 48 onshoreb
Gulf of Mexico deepwaterb
Total Gulf of Mexico deepwater
Total US
Canadab
Total Rest of North America
Total North America
Colombiab
Trinidad & Tobago
Brazilb
Total South America
Angola
Total Angola
Egyptb
Total Egypt
Algeriab
Total Africa
Azerbaijanb
Field or area
ETAPc
Foinavend
Other
Various
Prudhoe Bayd
Kuparuk
Milne Pointd
Other
Various
Thunder Horsed
Atlantisd
Mad Dogd
Mars
Na Kikad
Horn Mountaind
Kingd
Other
Variousd
Variousd
Variousd
Various
Greater Plutoniod
Kizomba C Dev
Dalia
Girassol FPSO
Other
Gupco
Other
Various
Azeri-Chirag-Gunashlid
Other
thousand barrels per day
BP net share of productiona
2009
34
29
105
168
40
40
208
69
45
24
43
181
97
133
54
35
29
27
25
22
62
387
665
8
8
673
23
38
–
61
70
43
32
22
44
211
55
16
71
22
304
94
7
101
5
–
17
123
123
31
–
31
1,400
2010
28
24
85
137
40
40
177
67
42
23
34
166
90
120
49
30
23
25
14
21
56
338
594
7
7
601
18
36
–
54
73
31
20
18
28
170
47
12
59
17
246
94
9
103
2
–
14
119
119
30
2
32
1,229
2011
22
26
65
113
32
32
145
64
39
19
31
153
69
77
34
8
19
14
8
15
56
231
453
2
2
455
1
31
7
39
51
21
12
12
27
123
34
11
45
22
190
86
8
94
2
31
11
138
138
23
2
25
992
Various
Various
Various
Various
Rumaila
Various
Total Azerbaijan
Western Indonesiab
Iraq
Other
Total Rest of Asiab
Total Asia
Australia
Other
Total Australasia
Total subsidiariese
Equity-accounted entities (BP share)
Russia – TNK-BPb
840
840
Total Russia
Abu Dhabif
182
12
Other
Total Rest of Asiab
194
1,034
Total Asia
75
Argentina
Venezuelab
25
Boliviab
1
101
Total South America
1,135
Total equity-accounted entities
Total subsidiaries and equity-accounted entities
2,535
a Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales
arrangements independently.
b In 2011, BP sold its holdings in Venezuela and Vietnam to TNK-BP. It also made acquisitions in India through a joint venture with Reliance, Brazil and additional volumes in the US Gulf of Mexico and
UK North Sea. BP divested its holdings in Pompano along with other interests in the US Gulf of Mexico, Tuscaloosa and interests in South Texas in the US onshore, a portion of our interest in the
Azeri-Chirag-Gunashli development in Azerbaijan, Wytch Farm in the UK, our interests in the REB field in Algeria, and the remainder of our interests in Colombia and Pakistan. In 2010, BP divested
its Permian Basin assets in Texas and south-east New Mexico, the East Badr El-Din and Western Desert concession in Egypt, its Canada gas assets and reduced its interest in the King field in the
Gulf of Mexico. It also acquired an increased holding in the Azeri-Chirag-Gunashli development in Azerbaijan and the Valhall and Hod fields in the Norwegian North Sea. Four other producing fields in
the Gulf of Mexico that were acquired during 2010 were subsequently disposed of in early 2011. In 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in Pakistan, swapped a number
of assets with BG Group plc. in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest Java to Pertamina, divested
its interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation payable, Pan American Energy’s shares of Chaco.
c Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell.
d BP-operated.
e Includes 28 net mboe/d of NGLs from processing plants in which BP has an interest (2010 29mboe/d and 2009 28mboe/d).
f The BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively.
856
856
190
1
191
1,047
75
23
–
98
1,145
2,374
865
865
209
1
210
1,075
74
16
-–
90
1,165
2,157
Various
Various
Various
Various
Various
92 BP Annual Report and Form 20-F 2011
Business review http://www.bp.com/downloads/oilandgasproduction
Natural gas
Subsidiaries
UKb
Total UK
Norwayb
Total Rest of Europe
Total Europe
Lower 48 onshoreb
Total Lower 48 onshore
Gulf of Mexico deepwaterb
Alaska
Total US
Canadab
Total Rest of North America
Total North America
Trinidad & Tobago
Total Trinidad
Colombiab
Total South America
Egyptb
Total Egypt
Algeria
Total Africa
Pakistanb
Azerbaijan
Western Indonesiab
Indiab
Total India
Vietnamb
China
Oman
Sharjah
Total Rest of Asia
Total Asia
Australia
Field or area
Bruce/Rhumc
Other
Various
San Juanc
Jonahc
Anadarko
Arkoma Central
Wamsutterc
Arkoma East
Arkoma West
Other
Total
Various
Various
Various
Mangoc
Cashima/NEQBc
Kapokc
Cannonballc
Amherstiac
Otherc
Various
Temsah
Ha’pyc
Taurtc
Other
Total
Variousc
Variousc
KGD6
Other
Variousc
Yacheng
Variousc
Perseus/Athena
Goodwyn
Angel
Other
million cubic feet per day
BP net share of productiona
2010
100
372
472
15
15
487
629
185
137
164
126
112
128
394
1,875
263
46
2,184
202
202
2,386
544
679
541
156
252
301
2,473
71
2,544
90
73
75
192
430
126
556
150
132
70
–
–
–
77
95
–
50
574
574
165
118
133
46
462
323
785
7,332
2009
110
508
618
16
16
634
659
227
146
194
146
67
65
451
1,955
303
58
2,316
263
263
2,579
664
571
540
225
197
233
2,430
62
2,492
118
94
73
177
462
159
621
173
126
106
–
–
–
63
83
–
59
610
610
142
139
120
39
440
74
514
7,450
2011
20
335
355
13
13
368
603
145
141
136
122
115
109
274
1,645
176
22
1,843
14
14
1,857
308
570
464
99
296
456
2,193
4
2,197
74
99
61
210
444
114
558
73
140
59
121
25
146
69
70
20
41
618
618
170
72
126
87
455
340
795
6,393
Various
Various
Various
Tangguhc
Total Australia
Eastern Indonesia
Total Australasia
Total subsidiariesd
Equity-accounted entities (BP share)
Russia – TNK-BPb
601
Total Russia
601
Western Indonesia
31
Vietnamb
–
Kazakhstanb
11
Total Rest of Asia
42
Total Asia
643
Argentina
378
Boliviab
11
Venezuelab
3
Total South America
392
Total equity-accounted entitiesd
1,035
Total subsidiaries and equity-accounted entities
8,485
a Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales
arrangements independently.
b In 2011, BP sold its holdings in Venezuela and Vietnam to TNK-BP. It also made acquisitions in India through a joint venture with Reliance, in the Eagle Ford shale in North America and additional
volumes in the US Gulf of Mexico. BP divested its holdings in Pompano along with other interests in the US Gulf of Mexico, Tuscaloosa and interests in South Texas in the US onshore, Wytch Farm in
the UK, minor volumes in Canada and the remainder of our interests in Colombia and Pakistan. In 2010, BP divested its Permian Basin assets in Texas and south-east New Mexico, the East Badr El-Din
concession in Egypt, its Canada gas assets and reduced its interest in the King field in the Gulf of Mexico. It also acquired an increased holding in the Valhall and Hod fields in the Norwegian North Sea.
Four other producing fields in the Gulf of Mexico that were acquired during 2010 were subsequently disposed of in early 2011. In 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in
Pakistan, swapped a number of assets with BG Group plc. in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest
Java to Pertamina, divested its interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation payable, Pan American Energy’s shares of Chaco.
c BP-operated.
d Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.
640
640
30
–
–
30
670
379
11
9
399
1,069
8,401
699
699
26
8
–
34
733
371
14
7
392
1,125
7,518
Various
Various
Various
BP Annual Report and Form 20-F 2011 93
Business review: BP in more depthBusiness review Refining and Marketing
Our Refining and Marketing segment is responsible for the refining,
manufacturing, marketing, transportation, and supply and trading of crude
oil, petroleum, petrochemicals products and related services to wholesale
and retail customers. We have significant operations in Europe, North
America and Asia, and we also manufacture and market our products
across Australasia, southern Africa and Central and South America; in total
we market our products in more than 70 countries.
The segment operates hydrocarbon value chains covering three
main businesses: fuels, lubricants and petrochemicals. Previously we
referred to lubricants and petrochemicals as international businesses, but
to provide greater transparency of the performance of these businesses
we are now providing our financial information separately for fuels,
lubricants and petrochemicals.
The fuels businesses sell refined petroleum products including
gasoline, diesel, aviation fuel and liquefied petroleum gas (LPG). Within
this, the fuels value chains (FVCs) integrate the activities of refining,
logistics, marketing, and supply and trading on a regional basis. This
recognizes the geographic nature of the markets in which we compete,
providing the opportunity to optimize our activities from crude oil purchases
to end-consumer sales through our physical assets (refineries, terminals,
pipelines and retail stations). In addition, we operate a global aviation fuels
marketing business and an LPG marketing business.
Our lubricants business is involved in manufacturing and marketing
lubricants and related services to markets around the world. We market
lubricants to the automotive, industrial, marine, aviation and energy
markets through our key brands of Castrol, BP and Aral. Our Castrol brand
is a highly recognized and popular lubricant brand worldwide. Distinctive
brands, cutting-edge technology and building and sustaining customer
relationships are cornerstones to our approach to market and underpin our
success. We are particularly strong in Europe and key Asia Pacific markets
including India.
Our petrochemicals business operates on a global basis and
includes the manufacture and marketing of petrochemicals that are
used in many everyday products, such as plastic bottles and textiles for
clothing. Technology is at the heart of our business and we own proprietary
world class technology for each of our main products. Our technological
advantage, operational experience and project execution track record
has made us an attractive partner which leads to material and distinctive
growth opportunities. Petrochemicals growth is focused on the demand
centre of Asia.
Our market
Overall world economic growth slowed in 2011, as did growth in world
oil consumption. Global oil demand grew by 0.7 million b/d, but in the
OECD, demand contracted again after growing for the first time in five
years in 2010. By contrast, there was demand growth in Australia and
Japan, where oil partially replaced nuclear power after the earthquake and
tsunami. Aggregate OECD oil demand in 2011 was 4.3 million b/d below
the 2005 peak.
The annual average BP refining marker margin (RMM) in 2011 was
16% higher than in 2010, averaging $11.64 per barrel. Margins followed
a typical seasonal pattern, with a peak in the second quarter in the run-up
to the summer driving season. The RMM is an environmental indicator,
similar to those used by many of our competitors, and is weighted
regionally based on our refining capacity in that part of the world. Each
regional marker margin is based upon product yields and a marker crude oil
deemed appropriate for the region.
The RMM uses regional crack spreads to calculate the margin
indicator, and does not include estimates of fuel costs and other variable
costs. The RMMs may not be representative of the margins achieved by
BP in any period because of BP’s particular refinery configurations and
crude and product slate. However, the RMM is useful for understanding
the indicative refining margin environment that is available to refiners in
each region.
Crude marker
2011
2010
2009
$ per barrel
Refining marker margin (RMM)
US West Coast
US Gulf Coast
US Midwest
Northwest Europe
Mediterranean
Singapore
BP Average RMM
ANS
Mars
LLS
Brent
Azeri Light
Dubai/Tapis blend
13.63
11.87
7.46
11.85
9.03
14.57
11.64
13.09
10.17
6.00
10.36
8.82
10.69
10.02
13.40
9.16
6.02
8.95
7.93
8.51
9.19
In 2011, refining margins increased in all the main US regions, despite a
contraction in domestic gasoline demand, with reduced gasoline import
volumes compensated for by higher domestic crude runs.
In Europe, where diesel accounts for a large proportion of regional
consumption, refining margins increased for a second year running despite
the loss of Libyan sweet crude supplies for much of the year, as demand
for commercial transport improved.
Refining margins also improved in Asia Pacific, averaging
$14.57 per barrel due to continuing oil demand growth and the disruption
to Japanese refining operations caused by the earthquake and tsunami.
US mid-continent crude oils (including West Texas Intermediate
(WTI)) were heavily discounted throughout the year because of increasing
production in the US mid-continent and Canada, coupled with constrained
infrastructure for crude transportation. This particularly benefited BP’s
location-advantaged refineries of Toledo and Whiting in the US Midwest.
In addition, fuel oil price discounts versus crude oil widened in 2011,
benefiting our highly upgraded refineries that produce relatively little
fuel oil.
In oil markets in 2011, supply was hampered by geo-political
issues and a series of technical problems in non-OPEC crude production.
This supply deficit brought OECD stocks down from historical highs to
near-average levels within the first nine months of the year. After very low
volatility levels in the second half of 2009 and in 2010, 2011 saw a return
towards more average volatility.
In lubricants, we saw modest improvement in demand for the
automotive and industrial sectors early in the year, but this came under
increasing pressure as the year progressed and by the fourth quarter
demand was declining in many geographies. Base oil prices rose markedly
in the first half of the year, increasing our input costs. We continued to
see a gradual shift towards higher-quality and higher-margin premium and
synthetic lubricants.
In the first half of 2011, the petrochemicals margin environment
was markedly different from the second half, due to strong demand
for purified terephthalic acid (PTA) coupled with supply interruptions in
both PTA and paraxylene (PX) leading to robust margins. In contrast the
second half of the year saw the installed capacity run normally along with
significant new capacity coming onstream. In addition concerns over the
global economy affected demand, leading to a rapid reduction in margins.
Acetic acid had a similar margin profile to PTA with supply interruptions in
the first half leading to higher margins followed by weaker margins in the
second half of the year as additional capacity came onstream.
Our strategy
Refining and Marketing is the product and service-led arm of BP, focused
on fuels, lubricants and petrochemicals products and related services. We
aim to be excellent in the markets in which we choose to participate –
those that allow BP to serve the major energy markets of the world. We
pursue competitive returns and sustainable growth, underpinned by safe
manufacturing operations and technology, as we serve customers and
promote BP and our brands through high-quality products.
We are focused on a consistent set of priorities executed in a
systematic and disciplined way. These priorities begin with safety and
include excellence of execution, portfolio quality and integration and
growing margin share via exposure to growth. This is all underpinned by a
disciplined financial framework. We believe that we now have a platform
to sustain a world-class downstream business, which will enable us to be
a leader in each of our chosen markets. Over time, we expect to shift the
94 BP Annual Report and Form 20-F 2011
Business review balance of participation and capital employed from established to growth
regions.
In March 2010, we set a target to shareholders to deliver a
performance improvement of at least $2 billion by 2012 relative to a 2009
baseline and we believe we are on track to deliver this by the end of 2012a.
In addition, post-2012, we plan to grow our margin further through our
focus on growth markets and expansion of our margin capture capability,
which we expect to achieve through projects such as those described
below.
In our fuels business, as previously announced, we are planning
to dispose of our Texas City refinery and the southern part of the
US West Coast FVC before the end of 2012. We are investing in our
existing operations to sustain safe, compliant standards and selectively
investing in cash margin capture projects. The largest of these projects
is the repositioning of the Whiting refinery towards heavy feedstock
advantage, which is already under way and scheduled to come onstream
in the second half of 2013. In addition to the repositioning of the Whiting
refinery, margin capture projects include the Cherry Point refinery clean
diesel project, Toledo refinery continuous catalytic reforming project,
Gelsenkirchen refinery margin improvement programme and the recently
announced Brazil aviation acquisition (see Acquisitions and disposals
section on page 97).
We are also well positioned for growth in our lubricants and
petrochemicals businesses. In our lubricants business, around half of our
profit growth in recent years has come from the emerging economies in
non-OECD countries as we have expanded in these markets. We have
a material presence in the Indian automotive lubricant market. These
positions provide a strong base to capture further long-term growth. In
petrochemicals around 45% of our capacity is in the demand centre of
Asia. Growth options are enabled by our distinctive technology, operational
capability and access through key strategic relationships. During 2011
the latest example of our strategy deployment was the signing of a
memorandum of understanding with IndianOil Corp (IOC) to explore the
potential for establishing a 50:50 joint venture to invest in a 1 million tonne
per annum (mtpa) acetic acid plant in Gujarat, India. The joint venture will
use BP’s latest Cativa® catalyst and technology, while the associated
gasification facilities would utilize petroleum coke feedstock from IOC.
Additionally, in 2011 BP received local government approval for a 1.25mtpa
PTA plant in Zhuhai, China, and is now seeking final central governmental
approval.
From 2012 we plan to create a new revenue stream in
petrochemicals through licencing our technology, beginning with our
aromatics products of PX and PTA.
As part of our drive towards more efficient operations, we have
been transforming our back office. In 2011, we made further progress on
our global SAP implementation within the fuels and lubricants businesses.
We also continued to expand the scale of our business service centres
(BSCs). BSCs are regional centres for certain finance, operational
procurement and IT services for the BP group.
a This performance improvement will be measured by comparing Refining and Marketing’s
replacement cost profit before interest and tax for 2009 with that of 2012, after adjusting for
non-operating items, fair value accounting effects and the impact of changes in the refining margin
and petrochemicals environment (including energy costs), foreign exchange impacts and price-lag
effects for crude and product purchases. This adjusted measure of replacement cost profit before
interest and tax is non-GAAP. We believe the measure is useful to investors because it is one that
is viewed and closely tracked by management as an important indicator of segment performance.
Our performance
2011 performance
Safety and operational risk
Safety remains the top priority across BP, and we are committed to
leadership in process safety and to ensuring that our operations are safe,
compliant and reliable with regard to both personal and process safety.
Refining and Marketing utilizes the group’s operating management
system (OMS). OMS provides a set of group-wide requirements and a
systematic way of working to continuously improve the way we operate.
(OMS is explained in more detail on page 65). While all Refining and
Marketing entities have transitioned on to OMS, we continue to work to
enhance local systems and processes at all our sites.
All our major manufacturing entities (refineries and petrochemicals
sites) have been through two performance improvement cycles (PIC) of
OMS, and all other entities across our FVCs will have completed their
second PIC by the end of 2012. The PIC is a management review carried
out within each entity of their local operating management system, which
identifies areas where further actions can be taken to enhance our systems
and processes. These actions are risk-prioritized and form an integral part
of each entity’s annual and longer-term planning. Where appropriate,
actions are aggregated to provide common solutions.
Direction and oversight of safety in Refining and Marketing is
provided by the segment operating risk committee (SORC) chaired by the
chief executive officer of Refining and Marketing. Monitoring of safety and
compliance in our operations is conducted by the newly-formed safety
and operational risk function, for which there is a Refining and Marketing
segment team independent of the segment CEO.
As outlined on page 65, BP has further strengthened its risk review
process, and this process was applied to Refining and Marketing to ensure
that appropriate risk management and mitigating actions were prioritized
throughout the segment.
We measure our personal safety performance through the
employment of a recordable injury frequency (RIF) rate and a days away
from work case frequency (DAFWCF) rate, as well as a severe vehicle
accident rate.
In 2011, our RIF (measured by the number of recordable injuries
to the BP workforce per 200,000 hours worked) was 0.37, slightly higher
than the 2010 rate of 0.35. The 2011 DAFWCF (a subset of the RIF that
measures the number of cases where an employee misses one or more
days from work) was 0.108, compared with 0.114 in 2010. There was a
significant improvement in the severe vehicle accident rate (SVAR) in 2011
with 61 severe vehicle accidents compared with 77 in 2010.
While progress has been made in the area of personal safety, there
were two workplace fatalities in 2011. These tragic events have been fully
investigated, and the learnings shared and actioned.
Process safety is measured by the process safety incident index
(PSII), a weighted index which reflects both the number and severity of
events per 200,000 hours worked. The PSII for 2011 was 0.36, equal to
the 2010 rate, and better than the 2009 rate of 0.48. While the number of
PSII events has increased from 2010, the overall severity of the events has
reduced.
In terms of operational integrity, the number of losses of primary
containment (LOPC), a measure of unplanned or uncontrolled releases of
material from primary containment, was 5% lower in 2011 than in 2010.
The number of oil spills greater than one barrel was slightly higher in 2011
(145) than 2010 (132) however the volumes of oil spills were significantly
lower in 2011 than in 2010 at 0.4 million litres compared with 1.3 million
litres respectively.
In our US refineries, we continue to implement the
recommendations of the BP US Refineries Independent Safety Review
Panel and regulatory bodies. See the Safety section on page 67 for further
information on progress.
BP Annual Report and Form 20-F 2011 95
Business review: BP in more depthBusiness review Sales and other operating revenues for 2011, analysed in the table below,
were $344 billion, compared with $267 billion in 2010 and $213 billion in
2009. These increases were primarily due to increasing oil prices.
Sales and other operating revenuesa
Sale of crude oil through spot and
2011
2010
$ million
2009
term contracts
57,055
44,290
35,625
Marketing, spot and term sales of
refined products
Other sales and operating revenues
a Includes sales between businesses.
273,940
13,121
344,116
209,221
13,240
266,751
166,088
11,337
213,050
The following table sets out oil sales volumes by type for the past three
years. Marketing sales volumes were 3,311mb/d, slightly lower than
2010, principally reflecting reduced demand in some OECD markets and
simplification of our portfolio.
Refined products volumes
Marketing salesa
Trading/supply salesb
Total refined product marketing sales
Crude oilc
Total oil sales
2011
3,311
2,465
5,776
1,532
7,308
thousand barrels per day
2009
3,560
2,327
5,887
1,824
7,711
2010
3,445
2,482
5,927
1,658
7,585
a Marketing sales include 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).
b Trading/supply sales are sales to large unbranded resellers and other oil companies.
c Crude oil sales relate to transactions executed by our integrated supply and trading function,
primarily for optimizing crude oil supplies to our refineries and in other trading. 79 thousand barrels
per day relate to revenues reported by Exploration and Production.
Prior years’ comparative financial information
The replacement cost profit before interest and tax for the year ended
31 December 2010 of $5,555 million included a net gain for non-operating
items of $630 million, mainly relating to gains on disposal, partly offset by
restructuring charges. Almost half of this gain related to our petrochemicals
business, mainly relating to the disposal of our share of BP’s interests in
ethylene and polyethylene production in Malaysia to Petronas. In addition,
fair value accounting effects had a favourable impact of $42 million relative
to management’s measure of performance. The primary additional factors
contributing to the increase in replacement cost profit before interest
and tax compared with 2009 were improved operational performance
in the FVCs, continued strong operational performance in lubricants and
petrochemicals, and further cost efficiencies, as well as a more favourable
refining environment. Against very good operational delivery, the results
were impacted by a significantly lower contribution from supply and trading
compared with 2009.
The replacement cost profit before interest and tax for the year
ended 31 December 2009 of $743 million included a net charge for non-
operating items of $2,603 million. The most significant non-operating items
were restructuring charges and a $1.6 billion one-off non-cash loss to impair
all of the segment’s goodwill in the US West Coast FVC relating to our
2000 ARCO acquisition. This resulted from our annual review of goodwill as
required under IFRS and reflected the prevailing weak refining environment
that, together with a review of future margin expectations in the FVC, led to
a reduction in expected future cash flows.
Financial and operating performance
2011
2010
Replacement cost profit (loss)
before interest and taxa
Fuelsb
Lubricants
Petrochemicalsc
Sales and other operating
revenuesd
Capital expenditure and acquisitions
Total refinery throughputse
Refining availabilityf
3,003
1,350
1,121
5,474
344,116
4,130
2,352
94.8
Total petrochemicals productiong
14,866
$ million
2009
(914)
1,059
598
743
2,628
1,357
1,570
5,555
213,050
266,751
4,114
4,029
thousand barrels per day
2,287
2,426
%
93.6
thousand tonnes
12,660
15,594
95.0
a Income from petrochemicals produced at our Gelsenkirchen and Mulheim sites is reported within
the fuels business. Segment level overhead expenses are included within the fuels business.
b 2009 includes a $1.6 billion impairment of goodwill in the US West Coast FVC.
c 2010 includes $338 million gain from non-operating items.
d Includes sales between businesses.
e Refinery throughputs reflect crude oil and other feedstock volumes.
f Refining availability represents Solomon Associates’ operational availability, which is defined as the
percentage of the year that a unit is available for processing after subtracting the annualized time
lost due to turnaround activity and all planned mechanical, process and regulatory maintenance
downtime.
g Petrochemicals production includes 1,699kte of petrochemicals produced at our Gelsenkirchen and
Mulheim sites in Germany for which the income is reported in our fuels business.
Replacement cost profit before interest and tax for the year ended
31 December 2011 was $5,474 million, compared with $5,555 million for
the previous year. The full-year results included a net loss for non-operating
items of $602 million, compared with a gain of $630 million in 2010. The
non-operating items in 2011 mainly related to impairment charges relating
to our disposal programme, partially offset by gains on disposal. (See
page 58 for further information on non-operating items). In addition, fair
value accounting effects had a favourable impact of $63 million, compared
to a favourable impact of $42 million in 2010. (See page 58 for further
information on fair value accounting effects.)
After adjusting for non-operating items and fair value accounting
effects, Refining and Marketing reported record earnings in 2011a.
Strong refinery operations enabled us to capture the benefits
available in 2011 from BP’s location advantage in accessing WTI-based
crude grades. Compared with 2010, the result also benefited from a higher
refining margin environment and a stronger supply and trading contribution.
These benefits were partly offset by a significantly higher level of
turnarounds in 2011 than 2010 and negative impacts from increased
relative sweet crude prices in Europe and Australia and the weather-related
power outages in the second quarter.
In the fuels business, financial performance for the full year was
impacted by the factors noted above. Operational performance was strong
with Solomon refining availability at 94.8% and refinery utilisation at 88%
for the year.
Performance in our lubricants business in 2011 was impacted by
an increasingly difficult marketing environment characterized by significant
base oil price increases and weaker demand. These impacts were partly
offset by supply chain efficiencies, and the strength of our products and
brands, which has allowed the increased cost of goods to be largely
recovered in the market.
In our petrochemicals business, compared with 2010, the 2011
result was negatively impacted by weakening market conditions as the
year progressed, as additional Asian capacity came onstream during the
year at a time of weaker demand. This was somewhat offset by the
strength in aromatics margins and volumes in the first half of the year.
a In 2011, there was a charge of $602 million for non-operating items and a favourable impact of
$63 million for fair value accounting effects. After adjusting for these impacts, replacement cost
profit before interest and tax was $6,013 million. This is a non-GAAP measure, which management
believes is useful to investors because it is viewed and closely tracked by management as an
important indicator of segment performance.
96 BP Annual Report and Form 20-F 2011
Business review Acquisitions and disposals
We have been managing our portfolio actively, investing in businesses
where we have strengths in terms of location, configuration, integration,
technology and brand, while divesting assets that do not display these
strategic characteristics.
• We completed the divestment programme of non-strategic pipelines and
terminals in the US East of Rockies and West Coast, announced in 2009.
• We completed the disposal of our fuels marketing businesses in Malawi,
Namibia, Tanzania, Zambia and Zimbabwe following the 2010 disposal of
the business in Botswana. This portfolio rationalization now allows us to
focus our activities within the continent on South Africa and Mozambique.
• We also announced our intention to divest the Texas City refinery and the
southern part of the US West Coast FVC, including the Carson refinery,
roughly halving our US refining capacity. BP is aiming to complete the
sales by the end of 2012 subject to signing definitive agreements for
the sales and subsequent satisfaction of any legal, regulatory or other
conditions. BP will ensure that the fulfilment of current regulatory
obligations associated with the Texas City refinery is reflected in any
transaction. These assets are classified as held for sale in the group
balance sheet as at 31 December 2011.
• In December 2011, Air BP announced the purchase of aviation fuels
assets at seven Brazilian airports from Shell Brasil Holding B.V. and
Cosan S.A. Industria e Commercio for approximately $100 million. The
acquisition will give Air BP access to several new airports in Brazil as
well as increasing capacity at existing Air BP operations. This deal is
expected to be completed in the first quarter of 2012 subject to regulatory
approvals.
• In February 2012, we announced our intent to sell our bulk and bottled
LPG marketing businesses in nine countries.
Fuels value chains
The six FVCs seek to optimize the activities of our assets across the supply
chain: crude delivery to the refineries; manufacture of high-quality fuels;
distribution through pipeline and terminal infrastructure; and marketing
and sales to our customers on a regional basis (see map on pages 34-35).
This integration, together with a focus on excellent execution and cost
management as well as a strong brand, market presence and customer
base, are key to our financial performance.
The FVC strategy focuses on feedstock-advantaged, upgraded,
well-located refineries integrated into advantaged logistics and marketing.
Consequently, in the US we intend to roughly halve our US refining capacity
by the end of 2012 (subject to all necessary legal and regulatory approvals)
(see also the Acquisitions and disposals section on this page).
In our remaining FVCs, we believe that we have a portfolio of
well-located refineries, integrated with strong marketing positions offering
the potential for improvement and growth. We currently own or have
a share in 16 refineries, which refine crude oil and produce refined fuel
products which we supply to retail and commercial customers. Strategic
investments in our refineries are focused on securing the safety and
reliability of our assets while improving our competitive position.
Key to our future refining capability is the Whiting refinery
modernization project (WRMP), which will allow the capture of additional
margin through the processing of heavy Canadian crudes. The project
continued to make significant progress in 2011. The coker’s six new drums
are now set in place, and the Southern Lights pipeline to Canada, and
Whiting’s interconnection to it, are in operation. This new pipeline capability
allows transport of diluent streams back to Canada which are used to
dilute heavy Canadian oils to facilitate their flow back to the US. WRMP is
expected to come onstream in the second half of 2013.
Fuels
Our fuels business is made up of six regionally organized integrated FVCs
(as shown in the refineries table below), the Texas City refinery, our global
aviation fuel and LPG marketing businesses, and a number of regionally-
focused fuels marketing businesses notably the UK, Turkey, China and
France. At the end of 2011, the operating capital employed relating to the
fuels business was approximately $44 billion.
The following tables summarize the BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2011.
US
California
Washington
Indiana
Ohio
Texas
Total US
Europe
Germany
Netherlands
Spain
Total Europe
Rest of World
Australia
New Zealand
South Africa
Total Rest of World
Total
Refinery
Fuels value chain
Carson
Cherry Point
Whiting
Toledo
Texas City
Bayernoilc
Gelsenkirchen
Karlsruhec
Lingen
Schwedtc
Rotterdam
Castellón
Bulwer
Kwinana
Whangereic
Durbanc
US West Coast
US West Coast
US East of Rockies
US East of Rockies
–
Rhine
Rhine
Rhine
Rhine
Rhine
Rhine
Iberia
ANZ
ANZ
ANZ
Southern Africa
a Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
b BP share of equity, which is not necessarily the same as BP share of processing entitlements.
c Indicates refineries not operated by BP.
Group interestb
%
thousand barrels per day
Crude distillation capacitiesa
BP
share
Total
100.0
100.0
100.0
50.0
100.0
22.5
50.0
12.0
100.0
18.8
100.0
100.0
100.0
100.0
23.7
50.0
266
234
413
160
475
1,548
217
265
322
93
239
377
110
1,623
102
146
118
180
546
266
234
413
80
475
1,468
49
132
39
93
45
377
110
845
102
146
28
90
366
3,717
2,679
BP Annual Report and Form 20-F 2011 97
Business review: BP in more depthBusiness review The table below summarizes the volume, by region, of crude oil and
feedstock processed by BP for its own account and for third parties.
Utilization data is also summarized below.
Refinery throughputsa
US
Europe
Rest of World
Total
Refinery capacity utilization
Crude distillation capacity
at 31 Decemberb
Refinery utilizationc
US
Europe
Rest of World
2011
1,277
771
304
2,352
2,679
88%
87%
91%
84%
thousand barrels per day
2009
1,238
755
294
2,287
2010
1,350
775
301
2,426
2,667
91%
93%
91%
84%
2,666
86%
85%
89%
83%
a Refinery throughputs reflect crude oil and other feedstock volumes.
b Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained
unit rate for a consecutive 30-day period.
c Refinery utilization is annual throughput divided by crude distillation capacity, expressed as a
percentage.
Overall refinery throughputs decreased by 74mb/d in 2011 relative to
2010, mainly due to the second quarter weather-related power outages
in the US.
We continue to invest to develop the capability of producing cleaner
fuels to meet the requirements of our customers and their communities.
For example, in April 2011, BP announced a major investment in a new
hydrotreater unit and hydrogen plant at our Cherry Point refinery, called
the clean diesel project. This project will allow the refinery to produce fuels
that meet ultra-low sulphur diesel (ULSD) standards for rail and marine
diesel customers. In addition, the new hydrogen plant will allow improved
operation of naphtha reforming units at the refinery.
In addition to refined petroleum products, we also blend and
market biofuels at our refineries. Biogasoline (bioethanol) and biodiesel
(hydrogenated vegetable oils and fatty acid methyl esters) continue to
grow in volume, primarily in Europe and the US, as regulatory requirements
demand heavier blending levels. Our response is to continue to develop
blend capabilities and to work with regulators, biofuels supply chains and
other stakeholders to improve the sustainability of the biofuels we blend
and supply.
Downstream of our refineries, our priorities are to operate an
advantaged infrastructure and logistics network (which includes pipelines,
storage terminals and road or rail tankers), drive excellence in operational
and transactional processes, and deliver compelling customer offers in the
various markets in which we operate.
We supply fuel and related convenience services to retail
consumers through company-owned and franchised retail sites, as well
as other channels, including wholesalers and jobbers. We also supply
commercial customers within the transport and industrial sectors.
Our retail network is largely concentrated in Europe and the US,
but also has established operations in Australasia, and southern Africa. We
have developed networks in China in two separate joint ventures, one with
PetroChina and the other with China Petroleum and Chemical Corporation
(Sinopec) and these joint ventures in China operate around 700 dual
branded sites.
As at 31 December 2011, BP’s worldwide retail network consisted
of some 21,800 sites across the US, Europe, Australia, New Zealand and
southern Africa. This is a reduction of 300 since 2010, primarily due to
a focus on fewer higher throughput sites and portfolio changes such as
the southern African disposals. These retail sites are primarily branded
BP, ARCO and Aral. We expect the number of sites to fall in 2012 as we
dispose of the southern part of our US West Coast FVC. In 2011, branded
fuels sales in the US continued to recover from the oil effects of the
Deepwater Horizon oil spill, and market share stabilized but remained lower
than before the oil spill, partly caused by the slowdown in US gasoline
demand. We continue to invest in our fuels marketing in growing markets,
for example in 2011, we piloted a new convenience retail offer in Poland
with Carrefour.
98 BP Annual Report and Form 20-F 2011
The table below shows the number of BP-branded retail sites by region.
Retail sitesa b
US
Europe
Rest of World
Total
Number of retail sites operated under a BP brand
2009
11,500
8,600
2,300
22,400
2010
11,300
8,400
2,400
22,100
2011
11,300
8,200
2,300
21,800
a The number of retail sites includes sites not operated by BP but instead operated by dealers,
jobbers, franchisees or brand licensees that operate under a BP brand. These may move to or from
the BP brand as their fuel supply or brand licence agreements expire and are renegotiated in the
normal course of business. Retail sites are primarily branded BP, ARCO and Aral.
b Excludes our interest in equity-accounted entities which are dual-branded.
Some of these retail sites include a convenience store which offers
consumers a range of food, drink and other consumables and services in a
convenient and innovative manner. The convenience offer includes brands
such as ampm, Wild Bean Café and Petit Bistro and includes partnerships
with leading retailers such as Marks & Spencer in the UK and Carrefour in
Poland.
BP’s integrated supply and trading function is responsible for
delivering value across the overall crude and oil products supply chain.
This structure enables the optimization of BP’s FVCs to maintain a single
interface with the oil trading markets and to operate with a single set
of trading compliance processes, systems and controls. The oil trading
business (including support functions) has trading offices in Europe, the
US and Asia and employs around 1,500 people. This enables the function
to maintain a presence in the more actively traded regions of the global
oil markets in order to gain an overall understanding of the supply and
demand forces across this market. It has a two-fold strategic purpose in
our business.
First, it seeks to identify the best markets and prices for our crude
oil, source optimal feedstocks for our refineries, and provide competitive
supply for our marketing businesses. In addition, where refinery
production is surplus to marketing requirements or can be sourced more
competitively, it is sold into the market. Wherever possible, the group will
look to optimize value across the supply chain. For example, BP will often
sell its own crude and purchase alternative crudes from third parties for its
refineries where this will provide incremental margin.
Second, the function seeks to create and capture incremental
trading opportunities. It enters into the full range of exchange-traded
commodity derivatives, over-the-counter (OTC) contracts and spot and
term contracts (described in Certain definitions – commodity trading
contracts on page 111). In order to facilitate the generation of trading
margin from arbitrage, blending and storage opportunities, it also owns
and contracts for storage and transport capacity. The group has developed
a risk governance framework to manage and oversee the financial risks
associated with this trading activity, see Financial statements – Note 26 on
pages 217-222.
The group’s trading activities in oil are managed by the integrated
supply and trading function. In order to carry out the unique delegations
from the BP group, the integrated supply and trading function operates and
enforces a robust system of internal control. The internal control systems
operated by the regional business leads are augmented by internal support
functions that provide independent oversight, including product control,
risk, trade completion and accounting and reporting. They are further
supported by regional and group ethics and compliance and group
internal audit.
Aviation
Our global aviation business, Air BP, is one of the world’s largest and best
known aviation fuels suppliers, serving many major commercial airlines
as well as the general aviation and military sectors. We have marketing
sales in excess of 450 thousand barrels per day. Air BP’s strategic aim is
to grow its position in the core locations of Europe, the US, Australasia
and the Middle East, while focusing its portfolio towards airports that offer
long-term competitive advantage.
Business review LPG
Our global LPG marketing business sells bulk, bottled, automotive and
wholesale LPG products in 10 countries, with sales of over 50 thousand
barrels per day. As noted in the Acquisitions and disposals section, BP
announced in February 2012 its intent to sell the bulk and bottled LPG
businesses in nine countries, and will retain the autogas and wholesale
LPG sales from refineries which will be integrated into the fuels value
chains.
Lubricants
Our lubricants business manufactures and markets lubricants and related
products and services to the automotive, industrial, marine, aviation and
energy markets across the world. At the end of 2011, the operating capital
employed relating to the lubricants business was approximately $5 billion
including goodwill of around $3 billion (see Financial statements – Note 10
on pages 206-207).
We organize our lubricants business into customer sectors. The
automotive sector serves the needs of land-based vehicles including cars,
trucks, motorbikes, buses, tractors, earth movers and other vehicles.
Our industrial sector serves customers who run or maintain plant and
equipment; our marine sector serves users of river and sea-going vessels;
aviation serves aircraft operators and maintenance industries; and our
energy sector serves the oil and gas and power industries.
In the automotive lubricants sector, which accounts for more than
two-thirds of our lubricants sales, we supply lubricants and other related
products and services to intermediate customers such as retailers and
workshops. These, in turn, serve end-consumers such as car, truck and
motorcycle owners.
BP’s marine lubricants business is one of the largest global
suppliers of lubricants to the marine industry, with a global presence in
over 800 ports. BP’s industrial lubricants business is a leading supplier to
those sectors of the market involved in the manufacturing of automobiles,
trucks, machinery components and steel. We are also a leading supplier of
lubricants for the oil, gas and aviation industries. In the oil and gas industry
we supply some of world’s largest production and drilling companies, and
we estimate that we supply over 30% of the world’s subsea control fluids.
In the aviation industry, we are the lubricants supplier for around 40% of
the jet engines of the world’s commercial airlines.
We look to market and sell our products across the world. We sell
products direct to our customers in around 45 countries and use approved
local distributors for other geographies. Approximately 40% of our
employees are located in non-OECD markets and around 20% of staff are
located in China and India alone. We are particularly strong in Europe and
key Asia Pacific markets including India.
Our lubricants business markets primarily through our major brands
of Castrol and BP, and through the Aral brand in specific European markets,
notably Germany. Castrol is a recognized brand worldwide and we believe
it provides us with a significant competitive advantage.
Distinctive brands, superior technology and building and sustaining
customer relationships remain the cornerstones of our long-term strategy.
Our participation in the value chain is focused on areas of
competitive differentiation and strength. These fall into three main areas:
the development of formulations and the application of cutting-edge
technology; developing product brands and communicating the benefits
that our products provide to our customers; and building and extending
our relationships with customers so that our products and services are
delivered in a manner which best meets their needs.
We have chosen not to participate at scale in base oil or additives
manufacturing. We are, however, one of the largest purchasers of base oil
in the market.
We participate in blending in locations where scale and competitive
advantage can be sustained, or where customer service or security of
supply are of critical importance and otherwise difficult to secure. We have
a network of 27 wholly-owned and operated blending plants worldwide and
joint ownership in five others operated by third parties.
Our focus is on developing premium products, and we often work
alongside original equipment manufacturers (OEMs) in doing this. The new
Castrol EDGE professional range was launched in 2011 to the franchised
workshop market in Europe and Africa.
In 2011, approximately 45% of the lubricants replacement cost profit
before interest and tax was generated from non-OECD markets.
Petrochemicals
Our petrochemicals business is global, with operations in the US, Europe
and Asia. The business buys a range of feedstocks for input into our
manufacturing units, the majority of which have been built and operate
utilizing our proprietary technology. We manufacture and market four main
product lines: purified terephthalic acid (PTA), paraxylene (PX), acetic acid,
and, through joint ventures, olefins and derivatives (O&D). We also produce
a number of other speciality petrochemicals products. At the end of 2011,
the operating capital employed relating to the petrochemicals business was
approximately $5 billion.
Our strategy is to leverage our industry-leading technology in the
markets in which we choose to participate, to grow the business, and to
deliver industry-leading returns. New investments are targeted principally in
the higher-growth Asian markets. We both own and operate 100%-owned
assets, and have also invested in a number of joint ventures in Asia, where
our partners are leading companies within their domestic market.
PTA is a raw material used in the manufacture of polyesters used
in fibres, textiles and film, and polyethylene terephthalate (PET) bottles.
PTA production requires PX as a feedstock, which we produce in the US
and Europe and buy in Asia. PTA is then reacted with glycol to produce
polyester chips or fibres, which are in turn used to produce PET bottles,
polyester fibres and various speciality products, including protective
screens for computers and TVs. PX production is primarily from the mixed
xylene stream produced in a reformer within a refinery.
Acetic acid is a versatile intermediate chemical used in a variety
of products such as paints, adhesives and solvents, as well as in the
production of PTA. In producing acetic acid, we purchase methanol and
either make or buy carbon monoxide (CO). CO can be produced from a
variety of hydrocarbon feedstocks, including natural gas, naphtha, fuel oil
and coal.
Our O&D business is based in China and is focused on serving
the Chinese and Asian markets. The SECCO joint venture between BP,
Sinopec and its subsidiary, Shanghai Petrochemical Company, is our main
O&D site and is BP’s single largest investment in China. BP also co-owns
one other naphtha cracker site outside Asia, which is integrated with our
Gelsenkirchen refinery in Germany.
The petrochemicals business runs 16 manufacturing sites in
the UK, the US, Belgium, Germany, China, Indonesia, South Korea,
Malaysia and Taiwan, including our joint ventures, and we also have two
petrochemicals plants which are managed by the fuels business as they
utilize feedstock from our Gelsenkirchen refinery.
BP Annual Report and Form 20-F 2011 99
Business review: BP in more depthBusiness review The table below summarizes BP’s petrochemicals production capacity, at 31 December 2011.
Petrochemicals production capacitya b
Geographical area
US
Europe
UK
Belgium
Germanyd
Rest of World
China
Indonesia
South Korea
Malaysia
Taiwan
Total BP share of capacity at 31 December 2011
Site
Product
Cooper River
Decatur
Texas City
Purified terephthalic acid (PTA)
PTA
Paraxylene (PX)
Naphthalene dicarboxylate
Acetic acid
PX
Metaxylene
Hull
Geel
Gelsenkirchen
Acetic acid
Acetic anhydride
Ethylidene diacetate
PTA
PX
Olefins and derivatives
Mülheim Solvents
Caojing
Chongqing
Nanjing
Zhuhai
Merak
Ulsan
Kertih
Kuantan
Kaohsiung
Taichung
Mai Liao
Olefins and derivatives
Acetic acid
Esters
Acetic acid
PTA
PTA
Acetic acid
Vinyl acetate monomer
Acetic acid
PTA
PTA
PTA
Acetic acid
Group interest
%
100.0
100.0
100.0
100.0
100.0c
100.0
100.0
100.0
100.0
100.0
100.0
100.0
50.0 to 61.0
50.0
50.0
51.0
51.0
50.0
85.0
50.0
51.0
34.0
70.0
100.0
61.4
61.4
50.0
BP share of
capacity
thousand tonnes
per year
1,345
1,026
1,101
29
583c
1,271
123
5,478
544
157
4
1,330
631
1,837b e
130b
4,633
3,230b
217b
52b
274b
1,564f
253b
267b
65b
391b
610
847b
474b
181b
8,425
18,536
a Petrochemicals production capacity is the proven maximum sustainable daily rate (MSDR) multiplied by the number of days in the respective period, where MSDR is the highest average daily rate ever
achieved over a sustained period.
b Includes BP share of equity-accounted entities, as indicated.
c Group interest is quoted at 100%, reflecting the capacity entitlement which is marketed by BP.
d Due to the integrated nature of these plants with our Gelsenkirchen refinery, the income and expenditure of these plants is managed and reported through the fuels business.
e Group interest varies by product.
f BP Zhuhai Chemical Company Ltd is a subsidiary of BP, the capacity of which is shown above at 100%.
Outlook
In 2012, we expect the overall economic environment to be challenging,
with below-average growth. Emerging economies are likely to drive
growth, while developing countries are expected to lag behind. We expect
that refiners will continue to operate with excess capacity globally, despite
the announced shutdown of refineries in the US East Coast and Europe.
The RMM in 2012 is expected to remain in a range of $8-12 per barrel. We
expect the differential between WTI and Brent crude to eventually return to
lower levels as additional US pipeline capacity is brought online. The level
of BP’s refinery turnaround activity is expected to be broadly similar in 2012
compared with 2011.
We expect the marketing environment for lubricants to remain
challenging given the outlook for global economic growth. Longer term
however, we expect to see growth in global lubricants demand through to
2020 as a result of continued growth in the number of vehicles, continuing
industrialization in emerging markets, and expanding world trade. This
growth is expected to be concentrated in non-OECD markets. Lubricants
demand is also expected to continue to shift towards higher quality,
premium products as new vehicles adopt advanced, smaller, more efficient
engines placing greater demands on lubricant performance.
In the petrochemicals industry, we expect significant new capacity to come
onstream in acetic acid and PTA in 2012, 7% and 15% of global capacity
respectively. Demand is expected to remain robust in 2012, but not
sufficient to absorb the additional capacity, hence we expect the margin
environment to be weaker in 2012 than in 2011.
Our priorities in 2012 remain consistent with those in 2011 and
2010. We will continue to focus on delivering safe, reliable and compliant
operations, improving the performance of our integrated FVCs, and driving
further cost efficiencies across all our businesses. We intend to increase
our investment levels slightly in 2012 versus 2011 and 2010, focusing
on key safety and operational integrity priorities, maintaining our quality
manufacturing and marketing portfolio, strengthening our US East of
Rockies FVC business through the Whiting refinery modernization project,
and continuing to grow our advantaged petrochemicals business in China.
We intend to continue to upgrade our portfolio through investments in
advantaged assets and the completion of our divestment programme,
including the US southern west coast FVC and the Texas City refinery,
announced in February 2011.
100 BP Annual Report and Form 20-F 2011
Business review Other businesses and corporate
Other businesses and corporate comprises the Alternative Energy
business, Shipping, Treasury (which includes interest income on the
group’s cash and cash equivalents), and corporate activities worldwide. It
also included the group’s aluminium business until its disposal in 2011.
The replacement cost loss before interest and tax for the year
ended 31 December 2011 was $2,478 million, compared with $1,516
million for the previous year. 2011 included a net charge for non-
operating items of $822 million. (See page 58 for further information
on non-operating items.) The primary additional factors affecting 2011’s
result compared with that of 2010 were significantly higher functional
and corporate costs; loss of aluminium contribution following disposal
of the group’s aluminium business in 2011; impacts of restructuring in
the Alternative Energy business; higher Shipping losses, partly offset by
improved foreign exchange hedging results.
The replacement cost loss before interest and tax for the year
ended 31 December 2010 included a net charge for non-operating items of
$200 million.
The replacement cost loss before interest and tax for the year
ended 31 December 2009 included a net charge for non-operating items of
$489 million.
The primary additional factors reflected in 2010’s result compared
with that of 2009 were improved business performance, more favourable
foreign exchange effects and cost efficiencies.
Key statistics
Sales and other operating revenuesa
Replacement cost (loss) before interest
and tax
Capital expenditure and acquisitions
a Includes sales between businesses.
2011
2,957
2010
3,328
$ million
2009
2,843
(2,478)
1,853
(1,516)
1,234
(2,322)
1,299
Alternative Energy
Alternative Energy comprises BP’s low-carbon businesses and future
growth options outside oil and gas, which we believe have the potential to
be a material source of low-carbon energy and are aligned with BP’s core
capabilities. These are biofuels, wind and a range of strategic investments.
Our market
A more diverse mix of energy will be required to meet long-term future
demand. BP’s own estimates suggest that global primary energy demand
will increase by around 40% between 2010 and 2030. Supported by
government policies, renewables’ global share of power generation,
is expected to be 11% by 2030. Between 2010 and 2030, biofuels are
expected to account for 23% of transport energy demand growtha.
Our performance
In 2011, our biofuels business acquired the Brazilian sugar and ethanol
producer Companhia Nacional de Açúcar e Álcool (CNAA) for $705 million.
Our wind business added 401MW of gross generation capacity during
2011 (274MW net), with the commercial start-up of the Cedar Creek 2 and
Sherbino 2 wind farms. At the end of 2011, BP began winding down its
remaining solar operations as it prepares to exit the solar business.
Alternative Energy continues to make progress against its
commitment to invest $8 billion in low-carbon businesses by 2015. Our
investment since 2005 is $6.6 billionb.
a BP Energy Outlook 2030.
b The majority of costs have been capitalized, some were expensed under IFRS.
Biofuels
BP believes that it has a key technological role to play in enabling the
transport sector to respond to the dual challenges of energy security and
climate change. We have embarked on a focused programme of biofuels
development based around the most efficient transformation of sustainable
and low-cost sugars into a range of fuel molecules. BP continues to invest
throughout the entire biofuels value chain, from sustainable feedstocks
that minimize pressure on food supplies through to the development of the
advantaged fuel molecule biobutanol, which has a higher energy content
than ethanol and delivers improved fuel economy. See Technology –
Alternative Energy on page 76 for further information.
BP has production facilities operating, or in the planning and
construction phases, in the US, Brazil and the UK.
The 2011 CNAA acquisition included mills located in Goiás and
Minas Gerais states that supply both Brazilian and international markets
with ethanol. We have also increased our share in the Brazilian biofuels
company, Tropical BioEnergia S.A., to 100%, by acquiring the remaining
50% for cash consideration of approximately $71 million. The acquisition
included an operating ethanol mill, located in Goiás state. BP now owns
and operates three producing ethanol mills in Brazil, with a total crush
capacitya of 7.2 million tonnes per annum. The blending and distribution
of biofuels continues to be carried out by our Refining and Marketing
segment, in line with regulation.
a Crush capacity represents a maximum capacity to process biofuels feedstock.
Wind
In wind power, BP has focused its business in the US, where we have
developed one of the leading wind portfolios.
During 2011, full commercial operations commenced at the Cedar
Creek 2 wind farm in Colorado with a gross capacity of 251MW (BP 50%)
and in Texas at the 150MW Sherbino 2 wind farm. Construction is nearly
complete at a further Texas wind farm, the 225MW Trinity Hills facility,
and construction has commenced at the 141MW Mehoopany wind farm in
Pennsylvania, and at the 470MW Flat Ridge wind farm in Kansas.
BP increased its net wind generation capacity to 1,048MW during
2011, an increase of 35% over the prior year.
Wind – net rated capacity at
year-end (megawatts)a
2011
1,048
2010
774
2009
711
a Net wind capacity is the sum of the rated capacities of the assets/turbines that have entered into
commercial operation, including BP’s share of equity-accounted entities. The equivalent capacities
on a gross-JV basis (which includes 100% of the capacity of equity-accounted entities where BP
has partial ownership) were 1,763MW in 2011, 1,362MW in 2010 and 1,237MW in 2009. This
includes 32MW of capacity in the Netherlands which is managed by our Refining and Marketing
segment.
Solar
BP has been involved in solar for more than 35 years and in the last two
years the industry has changed radically into a low margin commodity
market. At the end of 2011, BP began winding down its remaining solar
operations as it prepares to exit the solar business. BP will take the
necessary steps to transfer its obligations and assets to its affiliates or to
third parties.
Emerging business and ventures
Our emerging business and ventures unit brings together BP’s venturing
and carbon markets expertise with extensive carbon capture and storage
capability. Through venturing we have 29 separate venturing investments
spanning three broad areas: bioenergy, electrification and carbon solutions.
We are able to deploy specialist carbon capture and storage capabilities on
our own operations and to monitor CO2 storage opportunities, such as the
In Salah gas field where we have injected almost 4 million tonnes of CO2
since 2004.
In September 2011, SCS Energy, an independent power producer
involved in clean power projects, acquired the Hydrogen Energy California
joint venture project from BP and Rio Tinto.
Separately, the 400MW Hydrogen Power Abu Dhabi project
with CCS is awaiting further decisions, including arrangements for CO2
BP Annual Report and Form 20-F 2011 101
Business review: BP in more depthBusiness review Aluminium
During 2011, we terminated our interest in this business with the disposal
of our wholly-owned subsidiary, ARCO Aluminum Inc., to a consortium of
Japanese companies for cash consideration of $680 million.
Treasury
Treasury manages the financing of the group centrally, ensuring liquidity
sufficient to meet group requirements and manages key financial risks
including interest rate, foreign exchange, pension and financial institution
credit risk. From locations in the UK, the US and the Asia-Pacific region,
Treasury provides the interface between BP and the international financial
markets and supports the financing of BP’s projects around the world.
Treasury trades foreign exchange and interest rate products in the
financial markets, hedging group exposures and generating incremental
value through optimizing and managing cash flows. Trading activities
are underpinned by the compliance, control, and risk management
infrastructure common to all BP trading activities. For further information,
see Financial statements – Note 26 on page 217.
Insurance
The group generally restricts its purchase of insurance to situations where
this is required for legal or contractual reasons. Losses are borne as they
arise, rather than being spread over time through insurance premiums with
attendant transaction costs. This approach was reviewed following the
Deepwater Horizon oil spill but the group concluded that it will continue
with its current approach of not generally purchasing insurance cover.
transportation and storage. The project is a joint venture between BP
(40%) and Masdar (60%).
Shipping
We transport our products across oceans, around coastlines and along
waterways, using a combination of BP-operated, time-chartered and
spot-chartered vessels. All vessels conducting BP activities are subject to
our health, safety, security and environmental requirements. The primary
purpose of our shipping and chartering activities is the transportation of
our hydrocarbon products. In addition, we may use surplus capacity to
transport third-party products.
International fleet
At the end of 2011, we had 53 international vessels (37 medium-size
crude and product carriers, three very large crude carriers, one North Sea
shuttle tanker, eight LNG carriers and four LPG carriers). All these ships are
double-hulled. Of the eight LNG carriers, BP manages one on behalf of a
joint venture in which it is a participant.
Regional and specialist vessels
In Alaska, we retain a fleet of four double-hulled vessels. Outside the US,
we had 14 specialist vessels (two double-hulled lubricants oil barges and
12 offshore support vessels).
Time-charter vessels
At the end of 2011 BP had 93 hydrocarbon-carrying vessels above 600
deadweight tonnes on time-charter, all of which are double-hulled. All these
vessels participate in BP’s time-charter assurance programme.
Spot-charter vessels
BP spot-charters vessels, typically for single voyages. These vessels are
always vetted for safety assurance prior to each use.
Other vessels
BP uses various craft such as tugs, crew boats and seismic vessels in
support of the group’s business. We also use sub-600 deadweight tonne
barges to carry hydrocarbons on inland waterways.
Maritime security issues
At a strategic level, BP avoids known areas of pirate attack or armed
robbery; where this is not possible for trading reasons and we consider
it safe to do so, we will continue to trade vessels through these areas,
subject to the adoption of heightened security measures.
2011 has seen continuing pirate activity in the Gulf of Aden, Indian
Ocean (up to approximately 200 miles west of the Indian coast) and the
Arabian Sea. Activity has further extended into the north Arabian Sea
(approximately 200 miles south of Pakistan) and the southern Red Sea.
Despite an increasing level of piracy activity the number of vessels actually
attacked and/or hijacked has remained roughly the same as in 2010, and
the percentage success rate of the pirates has reduced. This is as a result
of stronger naval intervention off the Somali coast, heightened awareness
of the threat, and protective measures adopted by transiting ships.
At present, we follow available military and government agency
advice and are participating in protective group transits through the Gulf
of Aden Internationally Recommended Transit Corridor. BP uses the
protective measures recommended in the international shipping industry
guide BMP 4 – Best Management Practices for Protection against Somalia
Based Piracy, jointly published by industry bodies, including Oil Companies
International Marine Forum and supported by military operations in the
region.
We continue to monitor other areas where piracy is known to occur
e.g. West Africa and the South China Sea.
102 BP Annual Report and Form 20-F 2011
Business review Liquidity and capital resources
Following the Deepwater Horizon oil spill in 2010, the group initially faced
significant costs relating to the immediate response activities as well as
significant uncertainty regarding the ultimate magnitude of its liabilities and
timing of cash outflows. During 2011 the impact on the group’s liquidity
and capital resources has stabilized, allowing steps to be taken to enhance
the strength of the balance sheet.
The group’s long-term credit ratings are A (stable outlook) from
Standard & Poor’s, strengthened from A (negative outlook) in July 2011,
and A2 (stable outlook) from Moody’s Investor Services.
BP renegotiated its committed bank facilities during 2011 putting in
place $6.9 billion of facilities with 25 international banking counterparties,
mostly for a term of three years. In addition the group has increased
its access to commercial bank letters of credit (LC) by putting in place
committed LC facilities of $5.1 billion and secured LC arrangements of $2.2
billion, to supplement its uncommitted and unsecured LC lines.
The disposal programme of $30 billion initially announced in 2010
has been increased to $38 billion, for completion by the end of 2013. By
the end of 2011 agreements had been signed for more than $21 billion,
with cash receipts totalling $17 billion in 2010 and $2.7 billion in 2011.
BP accessed US and European capital markets throughout the year
with bond issuances amounting to $10.7 billion in 2011.
A further $0.8 billion of US Industrial Revenue/Municipal bonds
were re-issued in term-out mode of between three to 10 years during
the year.
During 2011 BP repaid $2.9 billion of the $5.3 billion of borrowings
raised in 2010 that were secured against working capital and other assets,
or backed by future crude oil sales from BP’s interests in specific offshore
Angola and Azerbaijan fields.
Financial framework
BP continues to refine its financial framework to support the pursuit of
value growth for shareholders, while maintaining a secure financial base.
BP intends to increase operating cash flowa by 50% in 2014 compared to
2011b. Half of the increase will arise as the remaining payments into the
Deepwater Horizon Oil Spill Trust fund complete by the end of 2012, and
half from operations. BP plans to use half of the expected additional cash
flows to increase investments and half for other purposes.
We intend to maintain a significant liquidity buffer and to reduce our
net debt ratio to the lower half of the 10-20% gearing range over time. See
Financial statements – Note 35 on page 230 for gross debt, which is the
nearest equivalent measure to net debt on an IFRS basis, and for further
information on net debt and net debt ratio.
a Operating cash flow is net cash provided by (used in) operating activities, as stated in the group
cash flow statement on page 181.
b Assuming an oil price of $100 per barrel in 2014. The projection reflects our expectation that all
required payments into the $20-billion trust fund will have been completed by the end of 2012.
It does not reflect any cash flows relating to other liabilities, contingent liabilities, settlements or
contingent assets arising from the Gulf of Mexico oil spill which may or may not arise at that time.
See Financial statements – Note 43 on page 249, for further information on contingent liabilities.
Dividends and other distributions to shareholders
On 1 February 2011, BP announced the resumption of quarterly dividend
payments, with a fourth-quarter 2010 dividend of 7 cents per share. The
resumption followed the suspension of dividend payments for the first
three quarters of 2010 announced in June 2010 in light of the Deepwater
Horizon oil spill and commitments to fund the $20-billion Trust. The same
level of dividend was maintained for the first three quarters of 2011.
The total dividend paid to BP shareholders in 2011 was $4.1 billion
with shareholders also having the option to receive a scrip dividend,
compared with $2.6 billion paid in 2010. The dividend is determined in US
dollars, the economic currency of BP.
On 7 February 2012, BP announced a dividend of 8 cents per share
in respect of the fourth quarter 2011.
During 2011 and 2010, the company did not repurchase any of
its own shares. Details of purchases to satisfy requirements of certain
employee share-based payment plans are set out on page 170.
Financing the group’s activities
The group’s principal commodity, oil, is priced internationally in US dollars.
Group policy has generally been to minimize economic exposure to
currency movements by financing operations with US dollar debt. Where
debt is issued in other currencies, including euros, it is generally swapped
back to US dollars using derivative contracts, or else hedged by maintaining
offsetting cash positions in the same currency. The overall cash balances
of the group are mainly held in US dollars or swapped to US dollars and
holdings are well-diversified to reduce concentration risk. The group is not
therefore exposed to significant currency risk, such as in relation to the
euro, regarding its borrowings. Also see Risk factors on page 59 for further
information on risks associated with the general macroeconomic outlook,
including the stability of the eurozone and Financial statements – Note 26
on page 217.
The group’s finance debt at 31 December 2011 amounted to $44.2
billion (2010 $45.3 billion). Of the total finance debt, $9.0 billion is classified
as short term at the end of 2011 (2010 $14.6 billion). The short-term
balance includes $4.9 billion for amounts repayable within the next 12
months relating to long-term borrowings (2010 $6.9 billion). Commercial
paper markets in the US and Europe are a further source of short-term
liquidity for the group to provide timing flexibility. At 31 December 2011,
outstanding commercial paper amounted to $3.6 billion (2010 $1.0 billion).
Also included within short-term debt at the end of 2010 was $6.2 billion
relating to deposits received for announced disposal transactions still
pending legal completion post the balance sheet date. At the end of 2011
the balance was de minimis at $30 million.
We have in place a European Debt Issuance Programme (DIP)
under which the group may raise up to $20 billion of debt for maturities
of one month or longer. At 31 December 2011, the amount drawn down
against the DIP was $11.6 billion (2010 $12.3 billion). In addition, the group
has in place an unlimited US shelf registration statement under which it
may raise debt with maturities of one month or longer. None of the capital
market bond issuances since the Deepwater Horizon oil spill contain any
additional financial covenants compared with the group’s capital markets
issuances prior to the incident.
The maturity profile and fixed/floating rate characteristics of the
group’s debt are described in Financial statements – Note 34 on page 229.
Net debt was $29.0 billion at the end of 2011, an increase of $3.1
billion from the 2010 year-end position of $25.9 billion. The ratio of net
debt to net debt plus equity was 20.5% at the end of 2011 (2010 21.2%).
Net debt and the ratio of net debt to net debt plus equity are non-GAAP
measures. We believe that these measures provide useful information to
investors. Net debt enables investors to see the economic effect of gross
debt, related hedges and cash and cash equivalents in total. The net debt
ratio enables investors to see how significant net debt is relative to equity
from shareholders. See Financial statements – Note 35 on page 230 for
gross debt, which is the nearest equivalent measure on an IFRS basis, and
for further information on net debt.
Included in net debt are cash and cash equivalents of $14.1 billion
at 31 December 2011 (2010 $18.6 billion). BP manages its cash position
to ensure the group has adequate cover to respond to potential short-term
market illiquidity, and expects to maintain a strong cash position. Cash
balances are pooled centrally where permissible, and deployed globally
as required. Cash surpluses are deposited with creditworthy banks and
money market funds with short maturities to ensure availability. The
group holds $1.2 billion of cash outside the UK and it is not expected
that any significant tax will arise on repatriation. Further information on
the management of liquidity risk and credit risk is provided in Financial
statements – Note 26 on pages 217-222, and on the cash position in
Financial statements – Note 30 on page 223.
The group also has access to significant sources of liquidity in the
form of committed bank facilities. At 31 December 2011, the group had
available undrawn committed standby borrowing facilities of $6.9 billion
(2010 $12.5 billion), made up of:
• $6.8 billion of standby facilities available to draw and repay by mid-March
2014.
• 625 million Chinese yuan ($0.1 billion) of 365-day standby facilities
available to draw and repay until the second half of 2012.
During 2011 $7.2 billion of 364-day facilities expired and were not renewed.
BP Annual Report and Form 20-F 2011 103
Business review: BP in more depthBusiness review BP believes that, taking into account the amounts of undrawn borrowing
facilities and increased levels of cash and cash equivalents, and the
ongoing ability to generate cash, including further disposal proceeds, the
group has sufficient working capital for foreseeable requirements.
Uncertainty remains regarding the amount and timing of future
expenditures relating to the Deepwater Horizon oil spill and the implications
for future activities. See Risk factors on pages 59-63, and Financial
statements – Note 2 on page 190, Note 36 on page 231 and Note 43 on
page 249 for further information.
Off-balance sheet arrangements
At 31 December 2011, the group’s share of third-party finance debt of
equity-accounted entities was $7,003 million (2010 $6,987 million). These
amounts are not reflected in the group’s debt on the balance sheet.
The group has issued third-party guarantees under which amounts
outstanding at 31 December 2011 are $415 million (2010 $404 million) in
respect of liabilities of jointly controlled entities and associates and $1,430
million (2010 $1,339 million) in respect of liabilities of other third parties.
Of these amounts, $220 million (2010 $355 million) of the jointly controlled
entities and associates guarantees relate to borrowings and for other
third-party guarantees, $1,267 million (2010 $1,324 million) relates to
guarantees of borrowings. Details of operating lease commitments, which
are not recognized on the balance sheet, are shown in the table below and
in Note 14 on page 208.
Contractual commitments
The following table summarizes the group’s principal contractual obligations at 31 December 2011, distinguishing between those for which a liability is
recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings and finance leases is given in Financial
statements – Note 34 on page 229 and more information on operating leases is given in Financial statements – Note 14 on page 208.
Expected payments by period under contractual
obligations and commercial commitments
Balance sheet obligations
Borrowingsa
Finance lease future minimum lease payments
Deepwater Horizon Oil Spill Trust funding liability
Decommissioning liabilitiesb
Environmental liabilitiesb
Pensions and other post-retirement benefitsc
Total balance sheet obligations
Off-balance sheet obligations
Operating leasesd
Unconditional purchase obligationse
Total off-balance sheet obligations
Total
Total
2012
2013
2014
2015
$ million
Payments due by period
2017 and
thereafter
2016
47,242
1,034
4,884
19,693
3,646
29,171
105,670
16,072
197,404
213,476
9,570
454
4,884
610
1,665
1,945
19,128
4,182
115,679
119,861
319,146
138,989
7,812
54
–
546
588
1,933
10,933
3,286
18,155
21,441
32,374
7,262
49
–
433
232
1,944
9,920
2,207
12,388
14,595
24,515
5,438
49
–
305
187
1,938
7,917
1,630
8,311
9,941
4,586
48
–
346
192
1,921
7,093
1,223
7,168
8,391
17,858
15,484
12,574
380
–
17,453
782
19,490
50,679
3,544
35,703
39,247
89,926
a Expected payments include interest payments on borrowings totalling $3,751 million ($896 million in 2012, $746 million in 2013, $582 million in 2014, $443 million in 2015, $333 million in 2016 and $751
million thereafter), and exclude disposal deposits of $30 million included in current finance debt on the balance sheet.
b The amounts are undiscounted. Environmental liabilities include those relating to the Gulf of Mexico oil spill, including liabilities for spill response costs.
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 The future minimum lease payments are before deducting related rental income from operating sub-leases. In the case of an operating lease entered into solely by BP as the operator of a jointly controlled
asset, the amounts shown in the table represent the net future minimum lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint venture partners. Where BP is not the
operator of a jointly controlled asset BP’s share of the future minimum lease payments are included in the amounts shown, whether BP has co-signed the lease or not. Where operating lease costs are
incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project.
e 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 2012 include purchase commitments existing at 31 December 2011 entered into
principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements
– Note 26 on page 217.
The following table summarizes the nature of the group’s unconditional purchase obligations.
Unconditional purchase obligations
Crude oil and oil products
Natural gas
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total
Total
130,824
38,370
9,962
3,038
892
8,061
6,257
197,404
2012
90,690
17,591
2,573
2,169
181
1,183
1,292
115,679
2013
9,095
5,258
1,129
644
154
957
918
18,155
2014
5,684
3,589
1,115
212
106
926
756
12,388
2015
3,344
2,516
1,028
11
97
731
584
8,311
$ million
Payments due by period
2017 and
thereafter
19,158
7,329
3,138
–
279
3,603
2,196
35,703
2016
2,853
2,087
979
2
75
661
511
7,168
104 BP Annual Report and Form 20-F 2011
Business review The group expects its total capital expenditure, excluding acquisitions and asset exchanges, to be around $22 billion in 2012. The following table
summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2011 and the proportion of that expenditure
for which contracts have been placed. Capital expenditure is considered to be committed when the project has received the appropriate level of internal
management approval. For jointly controlled assets, the net BP share is included in the amounts shown. Where operating lease costs are incurred in
connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. Such costs are included in the
amounts shown.
Capital expenditure commitments
Committed on major projects
Amounts for which contracts have been placed
Total
32,951
12,517
2012
15,113
7,689
2013
7,443
2,789
2014
4,268
1,094
2015
2,828
511
2016
1,535
315
$ million
2017 and
thereafter
1,764
119
In addition, at 31 December 2011, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to $610
million. Contracts were in place for $332 million of this total.
Cash flow
The following table summarizes the group’s cash flows.
Net cash provided by operating activities
Net cash (used in) investing activities
Net cash provided by (used in) financing
activities
Currency translation differences relating
to cash and cash equivalents
Increase (decrease) in cash and cash
2011
22,154
(26,633)
2010
13,616
(3,960)
$ million
2009
27,716
(18,133)
482
840
(9,551)
(492)
(279)
110
equivalents
(4,489) 10,217
142
Cash and cash equivalents at beginning
of year
Cash and cash equivalents at end of year
18,556
14,067
8,339
18,556
8,197
8,339
Net cash provided by operating activities for the year ended 31 December
2011 was $22,154 million compared with $13,616 million for 2010, the
increase primarily reflecting a reduction in the cash outflow in respect of
the Gulf of Mexico oil spill from $16,019 million in 2010 to $6,813 million
in 2011. Excluding the impacts of the Gulf of Mexico oil spill, net cash
provided by operating activities was $28,967 million for 2011, compared to
$29,635 million for 2010, a decrease of $668 million. Profit before taxation
decreased by $1,018 million, working capital requirements increased by
$1,509 million and income taxes paid increased by $1,879 million. These
impacts were partially offset by a decrease of $2,622 million in the net
impairment, gains and losses on sale of businesses and fixed assets,
and an increase in dividends received from jointly controlled entities and
associates of $2,104 million.
Net cash provided by operating activities for the year ended
31 December 2010 was $13,616 million compared with $27,716 million
for 2009, the reduction primarily reflecting a net cash outflow of $16,019
million in respect of the Gulf of Mexico oil spill. Excluding the impacts of
the Gulf of Mexico oil spill, profit before taxation increased by $10,986
million and a decrease in working capital requirements contributed $842
million. This higher profit before tax did not result in an equivalent net
increase in operating cash flow because it included $4,854 million in
net gains on disposals, net of impairments, a decrease of $1,160 million
in depreciation, depletion, amortization and exploration expense, and a
decrease of $787 million in the net charge for provisions, less payments, all
of which are non-cash items.
Net cash used in investing activities was $26,633 million in 2011,
compared with $3,960 million and $18,133 million in 2010 and 2009
respectively. The increase in cash used in 2011 reflected a decrease
of $14,222 million in disposal proceeds, including the impact of the
repayment in 2011 of a $3,530 million disposal deposit received in 2010,
following the termination of the Pan American Energy LLC sale agreement,
and an increase of $8,441 million in acquisitions, net of cash acquired; of
which $7.0 billion was for the Reliance transaction. The decrease in 2010
compared with 2009 reflected an increase of $14,273 million in disposal
proceeds and a decrease in capital expenditure and investments of $2,445
million, partly offset by an increase in acquisitions of $2,469 million.
Net cash provided by financing activities was $482 million in 2011
compared with $840 million net cash provided in 2010 and $9,551 million
net cash used in 2009. The decrease in net cash provided in 2011 primarily
reflected a decrease in net proceeds from long-term financing of $4,734
million, and an increase in dividends paid of $1,445 million partly offset by a
net increase in short-term debt of $5,846 million. The net increase in cash
provided in 2010 compared with 2009 reflected a decrease in dividends
paid of $7,957 million, an increase in net proceeds from long-term financing
of $1,686 million and a decrease in net repayments of short-term debt of
$786 million.
The group has had significant levels of capital investment for many
years. Cash flow in respect of capital investment, excluding acquisitions,
was $18.8 billion in 2011, $18.9 billion in 2010 and $21.4 billion in 2009.
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 $29.0 billion at the end of 2011, $25.9 billion at the
end of 2010 and $26.2 billion at the end of 2009.
During the period 2009 to 2011, our total sources of cash amounted
to $87 billion, while our total uses of cash amounted to $90 billion. The net
cash usage of $3 billion, and the increase in cash and cash equivalents held
of $6 billion, were financed by an increase in finance debt of $9 billion over
the three-year period. During this period, the price of Brent crude oil has
averaged $84.14 per barrel. The following table summarizes the three-year
sources and uses of cash.
Sources of cash
Net cash provided by operating activities
Disposals
Uses of cash
Capital expenditure
Acquisitions
Net repurchase of shares
Dividends paid to BP shareholders
Dividends paid to minority interests
Net use of cash
Increase in finance debt
Increase in cash and cash equivalents
$ billion
63
24
87
59
13
–
17
1
90
(3)
9
6
Disposal proceeds received during the three-year period exceeded cash
used for acquisitions, as a result in particular of our ongoing disposal
programme started in 2010. Net investment (capital expenditure and
acquisitions less disposal proceeds) during this period averaged $16 billion
per year. Dividends paid to BP shareholders totalled $17 billion during the
three-year period, with no ordinary share dividends being paid in respect
of the first three quarters of 2010. In the past three years, $4 billion has
been contributed to funded pension plans. This is reflected in net cash
provided by operating activities in the table above. The balance of cash and
cash equivalents held has been increased in light of the group’s current
circumstances, as noted above.
BP Annual Report and Form 20-F 2011 105
Business review: BP in more depthBusiness review Trend information
For information on external market trends, see Our market on pages 18-24.
We expect production excluding TNK-BP in 2012 to be broadly flat
compared with 2011, after adjusting for divestments and at an oil price of
$100 per barrel.
In Refining and Marketing, the level of BP’s refinery turnaround
activity is expected to be broadly similar in 2012 compared with 2011.
We also expect the marketing environment in fuels, lubricants and
petrochemicals to remain subdued given the outlook for global demand.
In 2012, we expect the quarterly loss, excluding non-operating
items, for Other businesses and corporate to average around $500 million.
As in previous years, this is likely to be volatile on an individual quarterly
basis.
We expect capital expenditure, excluding acquisitions and asset
exchanges, to increase to around $22 billion in 2012, as we invest to grow
in our Exploration and Production segment.
Having completed disposals of almost $20 billion during 2010 and
2011 combined, we expect to make further disposals that would bring the
total to $38 billion by the end of 2013.
We intend to reduce the net debt ratio to the lower half of the
10–20% range over time. Net debt is a non-GAAP measure.
Depreciation, depletion and amortization in 2012 is expected to be
around $1.0 billion higher than in 2011.
The discussion above contains forward-looking statements,
particularly those regarding external market trends, the future level of
production excluding TNK-BP, the expected level of turnarounds, the
marketing environment in fuels, lubricants and petrochemicals, the
expected quarterly loss for Other businesses and corporate, the expected
level of capital expenditures, expectations regarding future disposals, net
debt and net debt ratio, and future levels of depreciation, depletion and
amortization. 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 should not rely on
past performance as an indicator of future performance. You are urged to
read the cautionary statement on page 5 and Risk factors on pages 59-63,
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.
106 BP Annual Report and Form 20-F 2011
Regulation of the group’s business
BP’s activities, including its oil and gas exploration and production, pipelines
and transportation, refining and marketing, petrochemicals production,
trading, alternative energy and shipping activities, are conducted in
many different countries and are subject to a broad range of EU, US,
international, regional and local legislation and regulations, including
legislation that implements international conventions and protocols. These
cover virtually all aspects of our activities and include matters such as
licence acquisition, production rates, royalties, environmental, health and
safety protection, fuel specifications and transportation, trading, pricing,
anti-trust, export, taxes and foreign exchange.
The terms and conditions of the leases, licences and contracts
under which our oil and gas interests are held vary from country to country.
These leases, licences and contracts are generally granted by or entered
into with a government entity or state owned or controlled company
and are sometimes entered into with private property owners. These
arrangements with governmental or state entities usually take the form of
licences or production-sharing agreements (PSAs), although arrangements
with the US government can be by lease. Arrangements with private
property owners are usually in the form of leases.
Licences (or concessions) give the holder the right to explore for
and exploit a commercial discovery. Under a licence, the holder bears the
risk of exploration, development and production activities and provides the
financing for these operations. In principle, the licence holder is entitled to
all production, minus any royalties that are payable in kind. A licence holder
is generally required to pay production taxes or royalties, which may be in
cash or in kind. Less typically, BP may explore for and exploit hydrocarbons
under a service agreement with the host entity in exchange for
reimbursement of costs and/or a fee paid in cash rather than production.
PSAs entered into with a government entity or state owned or
controlled 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 only a portion of the area covered by the original exploration
licence. Both exploration and production licences are generally for a
specified period of time. In the US, leases from the US government
typically remain in effect for a specified term, but may be extended beyond
that term as long as there is production in paying quantities. The term of
BP’s licences and the extent to which these licences may be renewed vary
from country to country.
Frequently, BP conducts its exploration and production activities
in joint ventures or co-ownership arrangements with other international
oil companies, state owned or controlled companies and/or private
companies. These joint ventures may be incorporated or unincorporated
ventures, while the co-ownerships are typically unincorporated. Whether
incorporated or unincorporated, relevant agreements will set out each
party’s level of participation or ownership interest in the joint venture or co-
ownership. Conventionally, all costs, benefits, rights, obligations, liabilities
and risks incurred in carrying out joint venture or co-ownership operations
under a lease or licence are shared among the joint venture or co-owning
parties according to these agreed ownership interests. Ownership of
joint venture or co-owned property and hydrocarbons to which the joint
venture or co-ownership is entitled is also shared in these proportions.
To the extent that any liabilities arise, whether to governments or third
parties, or as between the joint venture parties or co-owners themselves,
each joint venture party or co-owner will generally be liable to meet these
in proportion to its ownership interest (see Financial statements – Note 2
in relation to the Gulf of Mexico oil spill). In many upstream operations,
a party (known as the operator) will be appointed (pursuant to a joint
operating agreement (JOA)) to carry out day-to-day operations on behalf of
the joint venture or co-ownership. The operator is typically one of the joint
venture parties or a co-owner and will carry out its duties either through its
own staff, or by contracting out various elements to third-party contractors
or service providers. BP acts as operator on behalf of joint ventures and
co-ownerships in a number of countries where we have exploration and
production activities.
Business review Frequently, work (including drilling and related activities) will be contracted
out to third-party service providers who have the relevant expertise
and equipment not available within the joint venture or the co-owning
operator’s organization. The relevant contract will specify the work to
be done and the remuneration to be paid and typically will set out how
major risks will be allocated between the joint venture or co-ownership
and the service provider. Generally, the joint venture or co-owner and
the contractor would respectively allocate responsibility for and provide
reciprocal indemnities to each other for harm caused to their respective
staff and property. Depending on the service to be provided, an oil and gas
industry service contract may also contain provisions allocating risks and
liabilities associated with pollution and environmental damage, damage
to a well or hydrocarbon reservoir and for claims from third parties or
other losses. The allocation of those risks vary among contracts and are
determined through negotiation between the parties.
In general, BP is required to pay income tax on income generated
from production activities (whether under a licence or PSAs). In addition,
depending on the area, BP’s production activities may be subject to a range
of other taxes, levies and assessments, including special petroleum taxes
and revenue taxes. The taxes imposed on oil and gas production profits
and activities may be substantially higher than those imposed on other
activities, for example in Abu Dhabi, Angola, Egypt, Norway, the UK, the
US, Russia and Trinidad & Tobago.
Environmental regulation
BP operates in more than 80 countries and is subject to a wide variety
of environmental regulations concerning our products, operations
and activities. Current and proposed fuel and product specifications,
emission controls and climate change programmes under a number of
environmental laws may have a significant effect on the production, sale
and profitability of many of our products.
United States
• The Clean Air Act (CAA) regulates air emissions, permitting, fuel
specifications and other aspects of our production, distribution and
marketing activities. Stricter limits on sulphur and benzene in fuels will
affect us in future, as will actions on greenhouse gas (GHG) emissions
and other air pollutants. Additionally, states may have separate, stricter
air emission laws in addition to the CAA.
• The Energy Policy Act of 2005 and the Energy Independence and
Security Act of 2007 affect our US fuel markets by, among other things,
imposing renewable fuel mandates and imposing GHG emissions
thresholds for certain renewable fuels. States such as California also
impose additional fuel carbon standards.
• The Clean Water Act regulates wastewater and other effluent discharges
from BP’s facilities, and BP is required to obtain discharge permits, install
control equipment and implement operational controls and preventative
measures.
• The Resource Conservation and Recovery Act regulates the generation,
storage, transportation and disposal of wastes associated with our
operations and can require corrective action at locations where such
wastes have been released.
• The Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) can, in certain circumstances, impose the entire
cost of investigation and remediation on a party who owned or operated
a site contaminated with a hazardous substance, or arranged for disposal
of a hazardous substance at the site. BP has incurred, or expects to
incur, liability under the CERCLA or similar state laws, including costs
attributed to insolvent or unidentified parties. BP is also subject to claims
for remediation costs under other federal and state laws, and to claims
for natural resource damages under the CERCLA, the Oil Pollution Act
of 1990 (OPA 90) (discussed below) and other federal and state laws.
CERCLA also requires hazardous substance release notification.
There are also environmental laws that require us to remediate
• The Toxic Substances Control Act regulates BP’s import, export and sale
and restore areas damaged by the accidental or unauthorized release
of hazardous substances or petroleum associated with our operations.
These laws may apply to sites that BP currently owns or operates, sites
that it previously owned or operated, or sites used for the disposal of its
and other parties’ waste. Provisions for environmental restoration and
remediation are made when a clean-up is probable and the amount of BP’s
legal obligation can be reliably estimated. The cost of future environmental
remediation obligations is often inherently difficult to estimate.
Uncertainties can include the extent of contamination, the appropriate
corrective actions, technological feasibility and BP’s share of liability. See
Financial statements – Note 36 on page 231 for the amounts provided in
respect of environmental remediation and decommissioning.
A number of pending or anticipated governmental proceedings
against BP and certain subsidiaries under environmental laws could
result in monetary sanctions. We are also subject to environmental
claims for personal injury and property damage alleging the release of
or exposure to hazardous substances. The costs associated with such
future environmental remediation obligations, governmental proceedings
and claims could be significant and may be material to the results
of operations in the period in which they are recognized. We cannot
accurately predict the effects of future developments on the group, such
as stricter environmental laws or enforcement policies, or future events
at our facilities, and there can be no assurance that material liabilities and
costs will not be incurred in the future. For a discussion of the group’s
environmental expenditure see page 71.
Approximately 56% of our fixed assets are located in the US
and the EU. US and EU environmental, health and safety regulations
significantly affect BP’s exploration and production, refining and marketing,
transportation and shipping operations. Significant legislation and regulation
in the US and the EU affecting our businesses and profitability includes the
following:
of new chemical products.
• The Occupational Safety and Health Act imposes workplace safety and
health requirements on our operations along with significant process
safety management obligations.
• The Emergency Planning and Community Right-to-Know Act requires
emergency planning and hazardous substance release notification as
well as public disclosure of our chemical usage and emissions.
• The US Department of Transportation (DOT) regulates the transport of
BP’s petroleum products such as crude oil, gasoline, and petrochemicals,
and other hydrocarbon liquids.
• The Marine Transportation Security Act (MTSA), the DOT Hazardous
Materials (HAZMAT) and the Chemical Facility Anti-Terrorism Standard
(CFATS) regulations impose security compliance regulations on
around 50 BP facilities. These regulations require security vulnerability
assessments, security risk mitigation plans and security upgrades,
increasing our cost of operations.
OPA 90 is implemented through regulation issued by the US Environmental
Protection Agency (EPA), the US Coast Guard, the DOT, the Occupational
Safety and Health Administration and various states, Alaska and the west
coast states currently have the most demanding state requirements
although regulation in the Gulf of Mexico has increased following the
2010 Deepwater Horizon oil spill. There is an expectation that OPA 90 and
its regulations will become more stringent in the future. The impact will
likely be more rigorous preparedness requirements (the ability to respond
over a longer period to larger spills), including the demonstration of that
preparedness. There will be additional costs associated with this increased
regulation. In 2012, we expect more unannounced exercises and potential
penalties for any failure to demonstrate required preparedness even
without any OPA 90 amendments.
As a consequence of the Deepwater Horizon oil spill we
have become subject to claims under OPA 90 and other laws and
have established a $20-billion trust fund for legitimate state and local
government response claims, final judgments and settlement claims,
legitimate state and local response costs, natural resource damages and
related costs and legitimate individual and business claims. We are also
subject to Natural Resource Damages claims and numerous civil lawsuits
BP Annual Report and Form 20-F 2011 107
Business review: BP in more depthBusiness review by individuals, corporations and governmental entities. The ultimate costs
for these claims cannot be determined at this time. We also expect the
industry in general, and BP in particular, to become subject to greater
regulation and increased operating costs in the Gulf of Mexico in the
future. For further disclosures relating to the consequences of the 2010
Deepwater Horizon oil spill, see Legal proceedings on page 160.
On 31 March 2009, the United States filed a complaint seeking civil
penalties and damages relating to oil leaks from oil transit lines operated by
BP Exploration (Alaska) Inc. (BPXA) at the Prudhoe Bay unit on the North
Slope of Alaska. (See Legal proceedings on page 165.) The complaint also
involved claims related to asbestos handling, allegations of non-compliance
at multiple facilities for failure to comply with EPA’s spill prevention plan
regulations, and for non-compliance with US Department of Transportation
orders and regulations. The parties settled the dispute and on 13 July 2011
the Court entered a Consent Agreement in which BPXA agreed to pay a
$25-million penalty and to perform certain injunctive measures over the
next three years with respect to pipeline inspection and maintenance.
Various environmental groups and the EPA have challenged
certain aspects of the air permits issued by the Indiana Department of
Environmental Management (IDEM) for upgrades to the Whiting refinery.
In response to these challenges, the IDEM has reviewed the permits and
responded formally to the EPA. BP is in discussions with EPA, the IDEM
and certain environmental groups over these and other CAA issues relating
to the Whiting refinery. BP has also been in settlement discussions with
EPA to resolve alleged CAA violations at the Toledo, Carson and Cherry
Point refineries.
European Union
BP’s operations in the EU are subject to a number of current and proposed
regulatory requirements that affect or could affect our operations and
profitability. These include:
• The EU Climate and Energy Package and the Emissions Trading Scheme
(ETS) Directive (see Greenhouse gas regulation on page 109).
• The EU Industrial Emissions Directive (IED) (revising and replacing the
Integrated Pollution Prevention and Control Directive (IPPC) and several
other industrial directives including the Large Combustion Plant Directive
(LCPD)) are in the process of transposition by the EU Member States.
The IED provides the framework for setting permits for major industrial
sites. Relative to IPPC and LCPD, the IED imposes tighter emission
standards for some large combustion plants and is more prescriptive
regarding the setting of emission of limit values based on use of Best
Available Techniques (BAT) in permits for other discharges to air and
water. The emission limit values are informed by the Sector specific and
cross-Sector BAT Reference documents (BREFs) which are reviewed
periodically. The outcome of the review of several BREFs key to our
major sites is expected in 2012/2013. The IED transposition and output
from the BREF revisions may result in requirements for further emission
reductions at our EU sites.
• The European Commission Thematic Strategy on Air Pollution and the
related work on revisions to the Gothenburg Protocol and National
Emissions Ceiling Directive (NECD) will establish national ceilings for
emissions of a variety of air pollutants in order to achieve EU-wide health
and environmental improvement targets. This may result in requirements
for further emission reductions at our EU sites.
• The EU Regulation on ozone depleting substances (ODS), which
implements the Montreal Protocol (Protocol) on ODS was most recently
revised in 2009. It requires BP to reduce the use of ODS and phase
out use of certain ODS substances. BP continues to replace ODS in
refrigerants and/or equipment, in the EU and elsewhere, in accordance
with the Protocol and related legislation. Methyl bromide (an ODS) is
a minor by-product in the production of purified terephthalic acid in
our petrochemicals operations. The progressive phase-out of methyl
bromide uses may result in future pressure to reduce our emissions of
methyl bromide.
108 BP Annual Report and Form 20-F 2011
• The EU Fuels Quality Directive affects our production and marketing of
transport fuels. Revisions adopted in 2009 mandate reductions in the
life cycle GHG emissions per unit of energy as described in Greenhouse
gas regulation above, and tighter environmental fuel quality standards
for petrol and diesel (for example see Greenhouse gas regulation on
page 109).
• The EU Registration, Evaluation and Authorization of Chemicals (REACH)
Regulation requires registration of chemical substances, manufactured
in, or imported into, the EU in quantities greater than 1 tonne per annum
per legal entity, together with the submission of relevant hazard and
risk data. REACH affects our refining, petrochemicals, exploration and
production, biofuels, lubricants and other manufacturing or trading/import
operations.
• Having completed registration of all the substances that we were
required to submit by the regulatory deadline of 1 December 2010,
we are now preparing registration dossiers for those substances
(manufactured or imported in amounts in the range 100-1,000 tonnes
per annum/legal entity) that are due to be submitted before 1 June
2013. Substances registered in 2010 are subject to evaluation and/
or authorization/restriction procedures by the authorities and this may
impact activities, product sales and their profitability.
• In addition, Europe has adopted the UN Global Harmonization System
for hazard classification and labelling of chemicals and products through
the Classification Labelling and Packaging (CLP) Regulation. This
requires us to assess the hazards of all of our chemicals and products
against new criteria and will, over time, result in significant changes to
warning labels and material safety data sheets. All our European Material
Safety Data Sheets will need to be updated to include both REACH
and CLP information. We have completed updates for all chemicals
substances we manufacture and market in the EU by the compliance
deadline of 3 January 2011, and have implemented a process to
maintain compliance in our European operations. We have also notified
the European Chemicals Agency of hazard classifications for our
manufactured and imported chemicals, for inclusion in a publicly available
inventory of hazardous chemicals. CLP will also apply to mixtures
(e.g. lubricants) by 2015. Activities covered by both CLP and REACH
are subject to possible enforcement activity by national regulatory
authorities.
• In the UK, significant health and safety legislation affecting BP includes
the Health and Safety at Work Act and regulations and the Control of
Major Accident Hazards Regulations.
The EU Commission has proposed the adoption of a regulation on safety
of offshore oil and gas prospection, exploration and production activities.
The proposed regulation aims to introduce harmonized regulation of the
potential environmental, health and safety impacts of the offshore oil and
gas industry throughout EU waters. Although it is at an early stage in the
legislative process, as published the proposal is not entirely aligned with
the regime operating in the UK and could also, if adopted, have the effect
of extending liability for clean-up and compensation of environmental
damage to marine waters.
Environmental maritime regulations
BP’s shipping operations are subject to extensive national and international
regulations governing liability, operations, training, spill prevention and
insurance. These include:
• In US waters, OPA 90 imposes liability and spill prevention and planning
requirements governing, among others, tankers, barges and offshore
facilities. It also mandates a levy on imported and domestically produced
oil to fund the oil spill response. Some states, including Alaska,
Washington, Oregon and California, impose additional liability for oil
spills.
• Outside US territorial waters, BP Shipping tankers are subject to
international liability, spill response and preparedness regulations
under the UN’s International Maritime Organization, including the
International Convention on Civil Liability for Oil Pollution, the MARPOL,
the International Convention on Oil Pollution, Preparedness, Response
and Co-operation and the International Convention on Civil Liability
for Bunker Oil Pollution Damage. In April 2010, a new protocol, the
Business review Hazardous and Noxious Substance (HNS) Convention 2010 was adopted
to address issues that have inhibited ratification of the International
Convention on Liability and Compensation for Damage in Connection
with the Carriage of Hazardous and Noxious Substances by Sea 1996
(the HNS Convention). This protocol will enter into force when at least
12 states have agreed to be bound by it (four of the states must have at
least 2 million gross tonnes of shipping) and contributing parties in the
consenting states have received at least 40 million tonnes of contributing
cargoes in the preceding year.
• International marine fuel regulations under International Maritime
Organization (IMO) and International Convention for the Prevention
of Pollution from Ships (MARPOL) regimes impose stricter sulphur
emission restrictions on ships in EU ports and inland waterways and
the North and Baltic seas since 2010 and with a stricter global cap on
marine sulphur emissions beginning in 2012. Further reductions are to
be phased in thereafter. These restrictions require the use of compliant
heavy fuel oil (HFO) or distillate, or the installation of abatement
technologies on ships. These regulations will place additional costs on
refineries producing marine fuel, including costs to dispose of sulphur,
as well as increased GHG emissions and energy costs for additional
refining.
To meet its financial responsibility requirements, BP Shipping maintains
marine liability pollution insurance to a maximum limit of $1 billion for each
occurrence through mutual insurance associations (P&I Clubs) but there
can be no assurance that a spill will necessarily be adequately covered by
insurance or that liabilities will not exceed insurance recoveries.
Greenhouse gas regulation
Increasing concerns about climate change have led to a number of
international climate agreements and negotiations are ongoing.
• The Kyoto Protocol commits the parties and other entities to meet
emissions targets in the first commitment period from 2008 to 2012.
• The UN summit in Cancun in December 2010 where parties to the
UN Framework Convention on Climate Change (UNFCCC) reached
formal agreement on a balanced package of measures to 2020. The
Cancun Agreement recognizes that deep cuts in global GHG emissions
are required to hold the increase in global temperature to below 2°C.
Signatories formally commit to carbon reduction targets or actions by
2020. Around 114 countries, including all the major economies and many
developing countries, have made such commitments supplemented
currently by an additional 27 parties that have agreed to be listed as
agreeing to the accord. Supporting those efforts, principles were
agreed for monitoring, verifying and reporting emissions reductions;
establishment of a green fund to help developing countries limit and
adapt to climate change; and measures to protect forests and transfer
low-carbon technology to poorer nations.
• In November 2011, parties to the UNFCCC conference in Durban (COP
17) agreed several measures. One was a ‘roadmap’ for negotiating
a legal framework by 2015 for action on climate change involving all
countries by 2020, to close the ’ambition gap’ between existing GHG
reduction pledges and what is required to achieve the goal of limiting
global temperature rise to 2°C. Another was a second commitment
period for the Kyoto Protocol, to begin immediately after the first period
and run for five or eight years. However, it will not include the US,
Canada, Japan and Russia, and quantitative targets and the rules for
carry-over of allowances from the first commitment will not be agreed
until the end of 2012.
These international concerns and agreements are reflected in national
and regional measures to limit GHG emissions. Additional stricter
measures can be expected in the future. These measures can increase
our production costs for certain products, increase demand for competing
energy alternatives or products with lower-carbon intensity and affect the
sales and specifications of many of our products. Current measures and
developments potentially affecting our businesses include the following:
• The European Union (EU) has agreed an overall GHG reduction target
of 20% by 2020. To meet this, a ‘Climate and Energy Package’ of
regulatory measures has been adopted including: national reduction
targets for emissions not covered by the EU Emissions Trading Scheme
(ETS); binding national renewable energy targets to double renewable
energy in the EU including at least a 10% share of final energy in
transport; a legal framework to promote carbon capture and storage
(CCS); and a revised EU ETS Phase 3. EU ETS revisions include a GHG
reduction of 21% from 2005 levels, a significant increase in allowance
auctioning, an expanded scope (sectors and gases), no free allocations
for electricity production but free allocations for energy-intense and trade
exposed industrial sectors. The EU ETS regulates approximately one-
fifth of our reported 2011 global GHG emissions and can be expected
to require additional expenditure from 2013 when Phase 3 comes into
effect. Finally, EU energy efficiency policy is currently addressed via
national energy efficiency action plans.
• Article 7a of the revised EU Fuels Quality Directive requires fuel suppliers
to reduce the life cycle GHG emissions per unit of fuel and energy
supplied in certain transport markets.
• Australia has committed to reduce its GHG emissions by at least 5%
below 2000 levels by 2020. In support of this, a Clean Energy legislative
package of 19 bills was passed in November 2011 which includes
imposing a carbon price on the top 500 emitting entities meeting the
thresholds in the bill. The carbon price is scheduled to take effect
from 1 July 2012 with a fixed price of $23 Australian dollar (indexed to
forecast inflation) until 1 July 2015, an international linked price (trading)
with floor and ceiling prices from 1 July 2015 through to 1 July 2018, and
a market based price (trading) forward. A certain portion of allowances
will be distributed to ‘emission intensive trade exposed’ businesses for
no cost; this transitional support decreases with time. The majority of our
Australia business emissions will be subject to the pricing scheme and
will require additional expenditures for compliance.
• New Zealand has agreed to cut GHG emissions by 10-20% below
1990 levels by 2020, subject to a comprehensive global agreement
for emissions reductions coming into force. New Zealand’s emission
trading scheme (NZ ETS) commenced on 1 July 2010 for transport fuels,
industrial processes, and stationary energy. The agriculture sector (45%
of New Zealand’s GHG emissions) has been proposed to join the NZ ETS
in January 2015. New Zealand also employs a portfolio of mandatory
and voluntary complementary measures aimed at GHG reductions. A
September 2011 review of the scheme recommended effective delays
to near-term emissions reductions targets, citing a lack of international
action on cutting emissions.
• In the US, with no current potential for passing comprehensive climate
legislation, the US Environmental Protection Agency (EPA) continues to
pursue regulatory measures to address GHGs under the Clean Air Act (CAA).
– In late 2009, the EPA released a GHG endangerment finding to
establish its authority to regulate GHG emissions under the CAA.
– Subsequent to this, the EPA finalized regulations imposing light duty
vehicle emissions standards for GHGs.
– The EPA finalized the initial GHG mandatory reporting rule (GHGRR)
in 2009 and continues to make amendments to the rule. The first
reports under the GHGRR were due on or before 30 September 2011.
The majority of BP’s US businesses were affected by the GHGRR
and submitted their first GHG emissions reports to the EPA under the
GHGRR on or before the 30 September 2011 deadline. In addition
to direct emissions from affected facilities, producers and importers/
exporters of petroleum products, certain natural gas liquids, and GHG’s
were required to report product volumes and notional GHG emissions
should these products be fully combusted. The EPA released
direct emission data and a small subset of product supplier data on
11 January 2012, with certain ‘confidential business information’
protections, in a ‘tool enabled’ database which allows transparency
to the individual facility/entity level. Release of the balance of the
product supply data is expected soon along with release of additional
non-confidential information which will enable aggregation of reported
emissions to the highest level US parent company.
– The EPA finalized permitting requirements for new or modified large
GHG emission sources in 2010, with these regulations taking effect in
January 2011 and the second phase taking effect on 1 July 2011. The
EPA has committed to additional actions, beginning in 2012, relating
to smaller sources of GHG emissions.
BP Annual Report and Form 20-F 2011 109
Business review: BP in more depthBusiness review – In a legal settlement with environmental advocacy groups the
EPA committed to propose regulations under their New Source
Performance Standards (NSPS) for GHG emissions from refineries
by December 2011 and to finalize these by November 2012; the EPA
was unable to meet the December deadline, which may delay final
rulemaking. The EPA has communicated that they are considering
three options for these standards, energy management, command
and control (source specific emission limits) and benchmarking (e.g. a
Solomon-type GHG intensity index or variation).
– Legal challenges to the EPA’s efforts to regulate GHG emissions
through the CAA continue along with active political debate with
the final content and scope of GHG regulation in the US remaining
uncertain.
• A number of additional state and regional initiatives in the US will affect
our operations. Of particular significance, California is seeking to reduce
GHG emissions to 1990 levels by 2020 and to reduce the carbon
intensity of transport fuel sold in the state. California implemented a
low-carbon fuel standard in 2010 although a preliminary injunction filed in
late December 2011 is preventing its implementation. California issued
final rules for its cap and trade programme in December 2011, with the
scheduled start of the scheme to begin January 2012, with obligations
commencing in 2013.
• Canada has established an action plan to reduce emissions to 17%
below 2005 levels by 2020 and the national government continues to
seek a co-ordinated approach with the US on environmental and energy
objectives. Additionally, Canada’s highest emitting province, Alberta,
has been running a market mechanism to reduce GHG since 2007.
Controversy, partially driven by perceived GHG intensity regarding
Canadian oil sand produced crude, continues with some jurisdictions
contemplating policies to restrict or penalize its use.
• China has committed to reducing carbon intensity of GDP 40-45%
below 2005 levels by 2020 and increasing the share of non-fossil fuels
in total energy consumption from 7.5% in 2005 to 15% by 2020. The
country’s 12th (2011-2015) Development Programme has set the target
to reduce carbon intensity by 17% within five years, and this national
target has been deconstructed into provincial ones for local actions.
Meanwhile, five provinces and eight cities were selected as pilots for
low carbon development, and seven provinces/cities were formally
given instruction to start emission trading trials. As part of the country’s
energy saving programme, the government also requires any operating
entity with annual energy consumption of 10 thousand tonnes of coal
equivalent (7ktoe/a) to have an energy saving target for the next five
years. A number of BP joint venture companies in China will be required
to participate in this initiative.
110 BP Annual Report and Form 20-F 2011
Certain definitions
Unless the context indicates otherwise, the following terms have the
meaning shown below:
Replacement cost profit
Replacement cost profit or loss reflects the replacement cost of supplies.
The replacement cost profit or loss for the year is arrived at by excluding
from profit or loss inventory holding gains and losses and their associated
tax effect. Replacement cost profit or loss for the group is not a recognized
GAAP measure.
BP believes that replacement cost profit before interest and
taxation for the group is a useful measure for investors because it is
the profitability measure used by management. See Selected financial
information on page 56 for the nearest equivalent measure on an IFRS
basis, which is ‘Profit (loss) for the year attributable to BP shareholders’.
Inventory holding gains and losses
Inventory holding gains and losses represent the difference between the
cost of sales calculated using the average cost to BP of supplies acquired
during the period and the cost of sales calculated on the first-in first-out
(FIFO) method after adjusting for any changes in provisions where the
net realizable value of the inventory is lower than its cost. Under the FIFO
method, which we use for IFRS reporting, the cost of inventory charged
to the income statement is based on its historic cost of purchase, or
manufacture, rather than its replacement cost. In volatile energy markets,
this can have a significant distorting effect on reported income. The
amounts disclosed represent the difference between the charge (to the
income statement) for inventory on a FIFO basis (after adjusting for any
related movements in net realizable value provisions) and the charge
that would have arisen if an average cost of supplies was used for the
period. For this purpose, the average cost of supplies during the period
is principally calculated on a monthly basis by dividing the total cost of
inventory acquired in the period by the number of barrels acquired. The
amounts disclosed are not separately reflected in the financial statements
as a gain or loss. No adjustment is made in respect of the cost of
inventories held as part of a trading position and certain other temporary
inventory positions.
Management believes this information is useful to illustrate to
investors the fact that crude oil and product prices can vary significantly
from period to period and that the impact on our reported result under
IFRS can be significant. Inventory holding gains and losses vary from
period to period due principally to changes in oil prices as well as changes
to underlying inventory levels. In order for investors to understand the
operating performance of the group excluding the impact of oil price
changes on the replacement of inventories, and to make comparisons
of operating performance between reporting periods, BP’s management
believes it is helpful to disclose this information.
Non-GAAP information on fair value accounting effects
BP uses derivative instruments to manage the economic exposure
relating to inventories above normal operating requirements of crude oil,
natural gas and petroleum products. Under IFRS, these inventories are
recorded at historic cost. The related derivative instruments, however, are
required to be recorded at fair value with gains and losses recognized in
income because hedge accounting is either not permitted or not followed,
principally due to the impracticality of effectiveness testing requirements.
Therefore, measurement differences in relation to recognition of gains and
losses occur. Gains and losses on these inventories are not recognized
until the commodity is sold in a subsequent accounting period. Gains and
losses on the related derivative commodity contracts are recognized in
the income statement from the time the derivative commodity contract is
entered into on a fair value basis using forward prices consistent with the
contract maturity.
BP enters into commodity contracts to meet certain business
requirements, such as the purchase of crude for a refinery or the sale
of BP’s gas production. Under IFRS these contracts are treated as
derivatives and are required to be fair valued when they are managed as
Business review part of a larger portfolio of similar transactions. Gains and losses arising
are recognized in the income statement from the time the derivative
commodity contract is entered into.
IFRS requires that inventory held for trading be recorded at its
fair value using period end spot prices whereas any related derivative
commodity instruments are required to be recorded at values based on
forward prices consistent with the contract maturity. Depending on market
conditions, these forward prices can be either higher or lower than spot
prices resulting in measurement differences.
BP enters into contracts for pipelines and storage capacity, oil
and gas processing and liquefied natural gas (LNG) that, under IFRS, are
recorded on an accruals basis. These contracts are risk-managed using a
variety of derivative instruments, which are fair valued under IFRS. This
results in measurement differences in relation to recognition of gains and
losses.
The way that BP manages the economic exposures described
above, and measures performance internally, differs from the way these
activities are measured under IFRS. BP calculates this difference for
consolidated entities by comparing the IFRS result with management’s
internal measure of performance. Under management’s internal measure
of performance the inventory, capacity, oil and gas processing and LNG
contracts in question are valued based on fair value using relevant forward
prices prevailing at the end of the period and the commodity contracts for
business requirements are accounted for on an accruals basis. We believe
that disclosing management’s estimate of this difference provides useful
information for investors because it enables investors to see the economic
effect of these activities as a whole. The impacts of fair value accounting
effects, relative to management’s internal measure of performance and a
reconciliation to GAAP information is shown on page 58.
Commodity trading contracts
BP’s Exploration and Production and Refining and Marketing segments
both participate in regional and global commodity trading markets in order
to manage, transact and hedge the crude oil, refined products and natural
gas that the group either produces or consumes in its manufacturing
operations. These physical trading activities, together with associated
incremental trading opportunities, are discussed further in Exploration and
Production on pages 88-89 and in Refining and Marketing on page 98.
The range of contracts the group enters into in its commodity trading
operations is as follows.
Exchange-traded commodity derivatives
These contracts are typically in the form of futures and options traded on
a recognized exchange, such as Nymex, SGX and ICE. Such contracts
are traded in standard specifications for the main marker crude oils, such
as Brent and West Texas Intermediate, the main product grades, such
as gasoline and gasoil, and for natural gas and power. 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 crude oil, refined products, natural gas and power.
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 contracts
These contracts are typically in the form of forwards, swaps and options.
Some of these contracts are traded bilaterally between counterparties;
others may be cleared by a central clearing counterparty. These contracts
can be used both for 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 Oseberg or BFO). Although the
contracts specify physical delivery terms for each crude blend, a significant
number are not settled physically. The contracts typically contain standard
delivery, pricing and settlement terms. Additionally, the BFO contract
specifies a standard volume and tolerance given that the physically settled
transactions are delivered by cargo.
Gas and power OTC markets are highly developed in North America and
the UK, where the commodities can be bought and sold for delivery in
future periods. These contracts are negotiated between two parties to
purchase and sell gas and power at a specified price, with delivery and
settlement at a future date. Typically, these contracts specify delivery
terms for the underlying commodity. Certain of these transactions are not
settled physically, which can be achieved by transacting offsetting sale
or purchase contracts for the same location and delivery period that are
offset during the scheduling of delivery or dispatch. The contracts contain
standard terms such as delivery point, pricing mechanism, settlement
terms and specification of the commodity. Typically, volume and price are
the main variable terms.
Swaps are often contractual obligations to exchange cash flows
between two parties: a typical swap transaction usually references a
floating price and a fixed price with the net difference of the cash flows
being settled. Options give the holder the right, but not the obligation, to
buy or sell crude, oil products, natural gas or power at a specified price on
or before a specific future date. Amounts under these derivative financial
instruments are settled at expiry. Typically, netting agreements are used 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 or around the delivery date when title to the inventory
is taken. Term contracts are contracts to purchase or sell a commodity at
regular intervals over an agreed term. Though spot and term contracts may
have a standard form, there is no offsetting mechanism in place. These
transactions result in physical delivery with operational and price risk. Spot
and term contracts typically relate to purchases of crude for a refinery,
purchases of products for marketing, purchases of third-party natural
gas, sales of the group’s oil production, sales of the group’s oil products
and sales of the group’s gas production to third parties. For accounting
purposes, spot and term sales are included in sales and other operating
revenues, when title passes. Similarly, spot and term purchases are
included in purchases for accounting purposes.
BP Annual Report and Form 20-F 2011 111
Business review: BP in more depthBusiness review 112 BP Annual Report and Form 20-F 2011
Directors and
senior management
114 Directors and
senior management
117 Directors’ interests
BP Annual Report and Form 20-F 2011 113
Directors and senior management Directors and senior management
The following lists the company’s directors and senior management as at 28 February 2012.
Chairman
Executive Director (Group Chief Executive)
Directors
C-H Svanberg
R W Dudley
Initially elected or appointed
Chairman since January 2010
Director since September 2009
Group chief executive since October 2010
Director since April 2009
February 2010
November 2010
February 2004
June 2007
July 2006
July 2004
February 2008
April 2010
February 2012
Executive Director (Chief Financial Officer)
January 2012
Executive Director (Executive Vice President, Corporate Business Activities) August 2000
Non-Executive Director
Non-Executive Director
Non-Executive Director
Non-Executive Director
P M Anderson
Non-Executive Director
F L Bowman
Non-Executive Director
A Burgmans
Non-Executive Director
C B Carroll
Non-Executive Director (Senior Independent Director)
Sir William Castell
Executive Director (Chief Executive, Refining and Marketing)
I C Conn
Non-Executive Director
G David
I E L Davis
Non-Executive Director
Professor Dame Ann Dowling Non-Executive Director
Dr B Gilvary
Dr B E Grote
B R Nelson
F P Nhleko
A Shilston
Senior management
M Bly
R Bondy
Dr M C Daly
R Fryar
A Hopwood
B Looney
H L McKay
D Sanyal
Dr H Schuster
Executive Vice President (Safety and Operational Risk)
Group General Counsel
Executive Vice President (Exploration)
Executive Vice President (Production)
Executive Vice President (Strategy and Integration)
Executive Vice President (Developments)
Executive Vice President (Chairman and President of BP America Inc.)
Executive Vice President and Group Chief of Staff
Executive Vice President (Human Resources)
November 2010
February 2011
January 2012
Initially elected or appointed
October 2010
May 2008
October 2010
October 2010
October 2010
October 2010
June 2008
January 2012
March 2011
Mr F P Nhleko was appointed as a director on 1 February 2011, Dr B Gilvary and Mr A Shilston were appointed as directors on 1 January 2012 and
Professor Dame Ann Dowling was appointed as a director on 3 February 2012. Dr H Schuster was appointed as executive vice president, human
resources on 1 March 2011 and Mr D Sanyal was appointed as executive vice president and group chief of staff on 1 January 2012.
Mr D J Flint and Dr D S Julius retired as directors on 14 April 2011. Mr S Westwell retired as executive vice president, strategy and integration on
31 December 2011.
At the company’s 2011 annual general meeting (AGM), the following directors retired, offered themselves for election/re-election and were duly
elected/re-elected: Mr P M Anderson, Mr F L Bowman, Mr A Burgmans, Mrs C B Carroll, Sir William Castell, Mr I C Conn, Mr G David, Mr I E L Davis,
Mr R W Dudley, Dr B E Grote, Mr B R Nelson, Mr F P Nhleko and Mr C-H Svanberg.
Sir William Castell will retire at the conclusion of the 2012 AGM. His role as senior independent director will be taken by Andrew Shilston upon his
retirement. All of the other directors will offer themselves for election/re-election at the company’s 2012 AGM.
David Jackson (59) was appointed company secretary in 2003. A solicitor, he is a director of BP Pension Trustees Limited.
114 BP Annual Report and Form 20-F 2011
Directors and senior management Directors
C-H Svanberg
Chairman of the chairman’s and nomination committees and attends
meetings of the Gulf of Mexico and remuneration committees
Carl-Henric Svanberg (59) joined BP’s board in September 2009 and
became chairman of BP on 1 January 2010. From 2003 until December
2009, he was president and chief executive officer of Ericsson, also
serving as the chairman of Sony Ericsson Mobile Communications AB. He
continues to be a non-executive director of Ericsson.
R W Dudley
Robert Dudley (56) joined the Amoco Corporation in 1979 for whom he
worked until its merger with BP in 1998. Following a variety of posts in
the US, the UK, the South China Sea and Moscow, in 2001 he became
group vice president responsible for BP’s upstream businesses in Russia,
the Caspian Region, Angola, Algeria and Egypt. From 2003 to 2008, he
was president and chief executive officer of TNK-BP in Moscow. He was
appointed an executive director in April 2009 and oversaw the group’s
activities in the Americas and Asia. Between 23 June and 30 September
2010, he served as the president and chief executive officer of BP’s Gulf
Coast Restoration Organization in the US. On 1 October 2010 he became
BP’s group chief executive.
P M Anderson
Member of the chairman’s and Gulf of Mexico committees and chairman of
the safety, ethics and environment assurance committee
Paul Anderson (66) was appointed a non-executive director of BP on
1 February 2010. He is a non-executive director of BAE Systems PLC and
of Spectra Energy Corp. He was formerly chief executive at Duke Energy
where he also served as chairman of the board. Having previously been chief
executive officer and managing director of BHP Limited and then BHP Billiton
Limited and BHP Billiton Plc, he re-joined these latter boards in 2006 as a
non-executive director, retiring on 31 January 2010. Previously he served as a
non-executive director on numerous boards in the US and Australia.
F L Bowman
Member of the chairman’s, Gulf of Mexico and safety, ethics and
environment assurance committees
Frank Bowman (67) joined BP’s board on 8 November 2010. He served
for over 38 years in the United States Navy, during which time he served
as commander of the nuclear submarine USS City of Corpus Christi and
commander of the submarine tender USS Holland, director of political-
military affairs on the joint staff and chief of naval personnel. He was
director of the naval nuclear propulsion programme in the Department of
Navy and Department of Energy. After retiring from the Navy as an admiral,
he became president and chief executive officer of the Nuclear Energy
Institute. He served on the BP Independent Safety Review Panel and on
the BP America Advisory Panel. He is president of Strategic Decisions, LLC
and a director of Morgan Stanley Mutual Funds.
A Burgmans, KBE
Member of the chairman’s, nomination and safety, ethics and environment
assurance committees and chairman of the remuneration committee
Antony Burgmans (65) joined BP’s board in 2004. He was appointed to
the board of Unilever in 1991. In 1999, he became chairman of Unilever
NV and vice chairman of Unilever PLC. In 2005, he became non-
executive chairman of Unilever PLC and Unilever NV, retiring from these
appointments in 2007. He is also a member of the supervisory boards of
Akzo Nobel N.V., Aegon N.V. and SHV Holdings N.V.
C B Carroll
Member of the chairman’s, nomination and safety, ethics and environment
assurance committees
Cynthia Carroll (55) joined BP’s board in 2007. She started her career at
Amoco and in 1989 she joined Alcan, where in 2002 she was appointed
president and chief executive officer of Alcan’s primary metals group and
an officer of Alcan, Inc. She was appointed as chief executive of Anglo
American plc, the global mining group, in 2007. She is also a director of De
Beers s.a. and chairman of Anglo Platinum Ltd.
Sir William Castell, LVO
Member of the chairman’s, Gulf of Mexico, nomination and safety, ethics and
environment assurance committees
Sir William (64) joined BP’s board in 2006 and is the senior independent
director. 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. He will retire from the
BP board at the conclusion of the 2012 AGM.
I C Conn
Iain Conn (49) joined BP in 1986. Following a variety of roles in oil trading,
commercial refining, retail and commercial marketing operations, and
exploration and production, in 2000 he became group vice president of
BP’s refining and marketing business. From 2002 to 2004, he was chief
executive of petrochemicals. He was appointed group executive officer
with a range of regional and functional responsibilities and an executive
director in 2004. He was appointed chief executive of Refining and
Marketing in 2007. He is a non-executive director and senior independent
director of Rolls-Royce Holdings plc, chairman of The Advisory Board of
Imperial College Business School and a member of The Council of The
Imperial College.
G David
Member of the chairman’s, audit, Gulf of Mexico and remuneration
committees
George David (69) began his career in The Boston Consulting Group before
joining the Otis Elevator Company in 1975. He held various roles in Otis
and later in United Technologies Corporation (UTC), following Otis’s merger
with UTC in 1977. In 1992, he became UTC’s chief operating officer.
He served as UTC’s chief executive officer from 1994 until 2008 and as
chairman from 1997 until his retirement in 2009.
I E L Davis
Member of the chairman’s, nomination and remuneration committees and
chairman of the Gulf of Mexico committee
Ian Davis (60) joined BP’s board on 2 April 2010. He spent his early career
at Bowater, moving to McKinsey & Company in 1979. He was managing
partner of McKinsey’s practice in the UK and Ireland from 1996 to 2003. In
2003, he was appointed as chairman and worldwide managing director of
McKinsey, serving in this capacity until 2009. He retired as senior partner
of McKinsey & Company in July 2010. He is a non-executive director of
Johnson & Johnson, Inc and a senior adviser to Apax Partners. He is also a
non-executive member of the UK’s Cabinet Office.
Professor Dame Ann Dowling
Member of the chairman’s and safety, ethics and environment assurance
committees
Dame Ann (59) joined BP’s board on 3 February 2012. She was appointed
a Professor of Mechanical Engineering in the Department of Engineering
at the University of Cambridge in 1993. Between 1999 and 2000 she
was the Jerome C Hunsaker Visiting Professor of Aerospace Systems at
MIT subsequently becoming a Moore distinguished scholar at Caltech in
2001. When she returned to the University of Cambridge, she became
Head of the Division of Energy, Fluid Mechanics and Turbomachinery
in the Department of Engineering, becoming UK lead of the Silent
Aircraft Initiative in 2003 and Head of the Department of Engineering
at the University of Cambridge in 2009. She is chair of the Physical
Sciences, Engineering and Mathematics Panel in the Research Excellence
Framework – the UK government’s review of research in universities.
She was appointed Director of the University Gas Turbine
Partnership with Rolls-Royce in 2001 and chairman in 2009. Between 2003
and 2008 she chaired the Rolls-Royce Propulsion and Power Advisory
Board. She chaired the Royal Society/Royal Academy of Engineering study
on Nanotechnology.
BP Annual Report and Form 20-F 2011 115
Directors and senior managementDirectors and senior management Dr B Gilvary
Brian Gilvary (50) joined BP in 1986. Following a variety of roles in
exploration and production, downstream and trading, in 2000 he became
chief of staff of BP’s refining and marketing business and held a number
of executive roles in the business, including chief financial officer and
commercial director from 2002 to 2005. In 2003 he was appointed director
of TNK-BP, retiring from the board in 2005 and re-joining in 2010. From
2005 to 2010 he was chief executive of integrated supply and trading, BP’s
commodity trading arm. In 2010 he was appointed deputy group chief
financial officer with responsibility for the finance function. On 1 January
2012 he was appointed to the board of BP p.l.c. and became chief
financial officer.
Dr B E Grote
Byron Grote (63) 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. Between 2002 and 31 December 2011 he
was BP’s chief financial officer. In January 2012 he became executive vice
president, corporate business activities. He is a non-executive director of
Unilever NV and Unilever PLC.
B R Nelson
Member of the chairman’s committee and chairman of the audit committee
Brendan Nelson (62) joined BP’s board on 8 November 2010. He is a
chartered accountant and was admitted as a partner of KPMG in London
in 1984. He served as a member of the UK Board of KPMG from 2000 to
2006 subsequently being appointed vice chairman until his retirement in
2010. At KPMG International he held a number of senior positions including
global chairman, banking and global chairman, financial services. He is a
non-executive director of The Royal Bank of Scotland Group plc where
he is chairman of the group audit committee. He is Vice President of the
Institute of Chartered Accountants of Scotland, a member of the Financial
Reporting Review Panel and a director of the Financial Skills Partnership.
F P Nhleko
Member of the chairman’s and audit committees
Phuthuma Nhleko (51) joined BP’s board on 1 February 2011. He began
his career as a civil engineer in the United States and as a project manager
for infrastructure developments in Southern Africa. Following this, he
became a senior executive of the Standard Corporate and Merchant Bank
in South Africa. He later held a succession of directorships before joining
MTN Group, a pan-African and Middle Eastern telephony group, as group
president and chief executive officer in 2002. He stepped down as group
chief executive of MTN Group at the end of March 2011 and became vice-
chairman of the MTN Group and chairman of MTN International. He is a
non-executive director of Anglo American plc.
A Shilston
Member of the chairman’s and audit committees
Andrew Shilston (56) trained as a chartered accountant before joining BP
as a management accountant. He subsequently joined Abbott Laboratories
before moving to Enterprise Oil plc in 1984 at the time of flotation. In 1989
he became treasurer of Enterprise Oil and was appointed finance director
in 1993. After the sale of Enterprise Oil to Shell in 2002, in 2003 he became
finance director of Rolls-Royce plc until his retirement on 31 December
2011. Andrew has served as a non-executive director on the boards of AEA
Technology plc and Cairn Energy plc where he chaired the remuneration
and audit committees. He recently joined the board of Circle Holdings plc
as a non-executive director. He will become senior independent director at
the conclusion of the 2012 AGM.
Senior management
M Bly
Mark Bly (52) joined BP in 1984. Following various engineering and
commercial leadership assignments he held business unit leader posts
in Alaska and the North Sea and was strategic performance unit leader
for BP’s North America Gas business. In 2007, he became group vice
president, Exploration and Production and a member of the exploration and
production operating committee. In 2008, he became group head of safety
and operations and in October 2010 he was appointed executive vice
president of safety and operational risk.
R Bondy
Rupert Bondy (50) joined BP as group general counsel in 2008. In 1989,
he joined US law firm Morrison & Foerster, working in San Francisco and
London. From 1994 to 1995, he worked for UK law firm Lovells in London.
In 1995, he joined SmithKline Beecham as senior counsel for mergers and
acquisitions and other corporate matters. He subsequently held positions
of increasing responsibility and, following the merger of SmithKline
Beecham and GlaxoWellcome, he was appointed senior vice president and
general counsel of GlaxoSmithKline in 2001.
Dr M C Daly
Mike Daly (58) joined BP in 1986 as a technical specialist in structural
geology, subsequently joining BP’s global basin analysis group. After a
series of exploration business and functional roles in South America, the
North Sea and new business development, in 2000 he became president
of BP’s Middle East and South Asia businesses. In 2006, he was appointed
BP’s head of exploration and new business development and in October
2010 he was appointed executive vice president, exploration.
R Fryar
Bob Fryar (48) joined Amoco Production Company in 1985, serving in a
variety of engineering and management positions in the onshore US and
deepwater Gulf of Mexico. In 2003, he was appointed vice president of
operations performance unit for BP Trinidad and later, in 2009, he became
chief executive officer for BP Angola. In October 2010, he was appointed
executive vice president, production.
A Hopwood
Andy Hopwood (54) joined BP in 1980 as a petroleum engineer. Following
a series of operational and corporate planning roles, in 1999 he was
appointed business unit leader in Azerbaijan, returning to London in 2001
as the upstream chief of staff. He became strategic performance unit
leader for BP’s North America Gas business in 2004, returning to London in
2009 as head of portfolio and technology for BP’s upstream businesses. In
October 2010, he was appointed executive vice president of strategy and
integration.
B Looney
Bernard Looney (41) joined BP in 1991 as a drilling engineer, working in
a variety of roles in the North Sea, Vietnam and the Gulf of Mexico and
later in the exploration and technology group. In 2005, he became senior
vice president for BP Alaska, before moving to be head of the group
chief executive’s office. He was appointed vice president for Norway and
infrastructure in 2008 and then, in 2009, he became managing director of
BP’s North Sea business. In October 2010, he was appointed executive
vice president, developments.
116 BP Annual Report and Form 20-F 2011
Directors and senior management H L McKay
Lamar McKay (53) was appointed chairman and president of BP America,
Inc. in 2009. He joined Amoco Production Company as a petroleum
engineer in 1980. He held a variety of roles before becoming group vice
president for Russia and Kazakhstan in 2003, also being appointed to the
board of TNK-BP in 2004. In 2007, he was appointed senior group vice
president of BP and executive vice president of BP America. In early 2008,
he became executive vice president of BP p.l.c. special projects, focusing
on Russia, subsequently joining the group executive management team. In
October 2010, in addition to his current duties, he was appointed president
and chief executive officer of the Gulf Coast Restoration Organization.
D Sanyal
Dev Sanyal (46) joined BP in 1989 and has held a variety of international
roles in London, Athens, Istanbul, Vienna and Dubai. He was appointed
chief executive, BP Eastern Mediterranean Fuels in 1999. In 2002,
he moved to London as chief of staff of BP’s worldwide downstream
businesses. In 2003, he was appointed chief executive officer of Air BP
following which in 2006, he became head of the group chief executive’s
office. He was appointed group vice president and group treasurer in 2007.
During this period, he was also chairman of BP Investment Management
Ltd and accountable for the Group’s aluminium interests. He was
appointed an executive vice president and group chief of staff with effect
from 1 January 2012.
Dr H Schuster
Helmut Schuster (51) joined BP in 1989. He held a number of roles working
in most parts of refining, marketing, trading and gas and power in the US,
UK and Continental Europe. In 2007 he became vice president, human
resources for Refining and Marketing in BP and in 2010 he added corporate
and functions to his portfolio. On 1 March 2011 he became group human
resources director and a member of BP’s executive team.
Directors’ interests
The figures below indicate and include all the beneficial and non-beneficial
interests of each director of the company in shares of the company (or
calculated equivalents) that have been disclosed to the company under the
Disclosure and Transparency Rules as at the applicable dates.
Current directors
C-H Svanberg
R W Dudley
P M Anderson
F L Bowman
A Burgmans
C B Carroll
Sir William Castell
I C Conn
G David
I E L Davis
Dr B E Grote
B R Nelson
Directors leaving the board
D J Flint
Dr D S Julius
At 31 Dec 2011
933,971
287,945a
6,000a
12,720a
10,156
10,500a
82,500
425,169b
579,000a
10,391
At 1 Jan 2011
925,000
280,799a
6,000a
2,520a
10,156
10,500a
82,500
339,637b
159,000a
10,000
1,394,819c 1,372,643c
–
11,040
At resignation/
retirement
15,000d
15,000d
At 1 Jan 2011
15,000
15,000
On
appointment
–e
236,029f
–g
–f
Change from
31 Dec 2011
to 1 Mar 2012
–
49,356
–
–
–
–
–
72,332
–
–
89,784
–
–
–
Change from
31 Dec 2011
to 1 Mar 2012
–
95,059
–
–
Directors joining the board
Professor Dame Ann Dowling
Dr B Gilvary
F P Nhleko
A Shilston
At 31 Dec 2011
–
–
–
–
a Held as ADSs.
b Includes 48,024 shares held as ADSs at 1 January 2011 and at 31 December 2011.
c Held as ADSs, except for 94 shares held as ordinary shares.
d On retirement at 14 April 2011.
e On appointment at 3 February 2012.
f On appointment at 1 January 2012.
g On appointment at 1 February 2011.
The following performance shares were awarded on 9 March 2011 under
the BP Executive Directors’ Incentive Plan (EDIP). These figures represent
the maximum possible vesting levels. The actual number of shares/ADSs
that vest will depend on the extent to which performance conditions have
been satisfied over a three-year period.
Director
R W Dudleya
I C Conn
Dr B E Grotea
a Held as ADSs.
Potential maximum
performance shares
2011 EDIP awards
1,330,332
623,025
785,394
Additional details regarding performance shares awarded can be found in
the Directors’ remuneration report on page 149.
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.
BP Annual Report and Form 20-F 2011 117
Directors and senior managementDirectors and senior management 118 BP Annual Report and Form 20-F 2011
Corporate governance
Over this coming year we will maintain
focus, discipline and follow through
at the board as we continue to deal
with a volume of issues.
120 Board performance report
126 Committee reports
133 Risk management and internal control review
134 Corporate governance practices
134 Code of ethics
135 Controls and procedures
136 Principal accountants’ fees and
services
136 Memorandum and Articles of
Association
BP Annual Report and Form 20-F 2011 119
BP Annual Report and Form 20-F 2011 119
Corporate governance Corporate governance Board performance report
Dear shareholder,
In my letter to shareholders earlier in this report I have endeavoured to give
an overview of the challenges which the company has faced in 2011 and
the work of the board in meeting those challenges.
In this letter, and in the report which follows, my aim is to give
shareholders, and indeed all those with whom the company interacts,
a deeper insight into the evolution of the BP board, the review which it
has undertaken and the changes that have been made, and which are
continuing to be made, to govern your company at the highest standard.
BP has a clear system of governance based upon the BP board
governance principles. This serves BP and its board well. It is vital that the
system of governance, “what” the board does, evolves with the company
and with the thinking of those charged with its governance.
The tragic events in the Gulf of Mexico require that the board
consider how it operates; however the substantial change in directors
has meant there have been new views on the role of the board. This has
resulted in the evolution that I have mentioned. In undertaking strong
governance of the company, I believe that the board should provide
leadership and challenge, but also support to executive management. In its
activities this year, the board has strived to achieve this role.
The tasks of the board set out later in this report have not and will
not change. It was clear though that a board which governs a company of
the scale and scope of BP needs to have a clear view of its role
and the steps it can take to support or challenge and the information
which it needs.
The board is initiating modifications in all of these areas and
will keep those changes under review. The actions from this work are
important as we operate a system of governance throughout the company.
The framework for how the board works is articulated in our board
governance principles, available on our website at bp.com/governance.
Over this coming year we will maintain focus, discipline and follow
through at the board as we continue to deal with a volume of issues.
Looking forward into 2012, one of our aims is to get back into a steady
rhythm of board meetings. We hope to do this through strengthening our
forward agenda and board planning processes. We will also maintain our
focus on the skills and experience of our directors, the composition of our
board and succession planning.
Diversity within UK boards was a topic of debate in 2011 and
will remain so going forward. BP is a company with global reach and we
believe that it is important to have a board that is diverse in the widest
sense; the company remains committed to meritocracy as well as to
diversity. As part of the update of our board governance principles we have
included a policy on board diversity. At the time of writing we have 12.5%
female representation on the board. Our goal is to increase the number
of women on the board to three by 2013 and to work towards 25%
representation by 2015.
In the governance report which follows we have outlined key
elements of the activities of the board and its committees during the year.
Carl-Henric Svanberg
Chairman
120 BP Annual Report and Form 20-F 2011
How the board works
BP’s governance framework
BP’s system of governance begins with the board and continues into
our subsidiaries. The governance framework is outlined in the BP board
governance principles which sets out the role of the board, its processes
and its relationship with executive management.
The board’s core activities include:
• The active consideration of long-term strategy.
• The monitoring of executive action and the performance of BP.
• Obtaining assurance that the material risks to BP are identified and that
systems of risk management and control are in place to mitigate such
risks.
• Ongoing board and executive management succession.
In all its work the board sets the ‘tone from the top’ for the organization by
considering specific issues, including health, safety, the environment and
BP’s reputation and working with management to set the values of the
company.
During 2011 the board undertook a review of its corporate
governance model. A working group consisting of the chairman and three
non-executive directors (Paul Anderson, Antony Burgmans and Cynthia
Carroll) examined key aspects of BP’s system of governance, including
the system of delegation, board processes, information, risk and the tasks
and role of the committees. During the review, input was sought from
board members and from executive management, both through board and
working group discussions and individually through our board evaluation
process.
The review concluded that BP’s system of governance is robust
but that further clarity on board processes would help reinforce the
board’s delegation to the group chief executive and strengthen the board’s
monitoring and assurance role.
Who’s on the BP board?
The composition of the board and the mix of knowledge, skills and
experience that our directors bring to the company is a key area of focus
for the nomination committee. The committee keeps this mix under review
and regularly maps the skillset of our existing board membership against
the likely tenure of individual directors. This is viewed against the potential
demands placed on the board due to developments in our strategy and
business activities. Further detail of the current skillset of the board and
the skills/competencies that the nomination committee has prioritized for
future non-executive director appointments is outlined in the report of the
nomination committee later in this section.
Full biographies of our board members can be found on our
website.
Succession: board and committee membership
Since the beginning of 2011, the following changes have taken place to the
composition of the board:
• Phuthuma Nhleko joined the board as a non-executive director on
1 February 2011.
• Dr DeAnne Julius and Douglas Flint retired from the board at the AGM in
April 2011.
• Dr Brian Gilvary joined the board as an executive director and chief
financial officer (CFO) on 1 January 2012.
• Andrew Shilston joined the board as a non-executive director on
1 January 2012.
• Professor Dame Ann Dowling joined the board as a non-executive
director on 3 February 2012.
Dr Byron Grote stepped down as CFO at the end of 2011 but will remain
on the board as an executive director during 2012, with responsibility for
BP’s integrated supply and trading operations, Alternative Energy, shipping,
technology and remediation activities.
Sir William Castell has decided not to seek re-election at this year’s
AGM and will retire from the board at the meeting. Andrew Shilston
will succeed Sir William as the senior independent director from the
2012 AGM and will be available to shareholders who have concerns that
cannot be addressed through normal channels. He will work closely with
Corporate governance Antony Burgmans who, given his length of service on the board, will
respond to any internal board matters, act as a sounding board for the
chairman and serve as an intermediary for other directors if necessary.
Sir William stepped down as chairman of the safety, ethics and
environment assurance committee (SEEAC) and Paul Anderson became its
chairman from 9 December 2011.
Ian Davis stepped down as a member of the audit committee on
3 February 2012 and Frank Bowman joined the Gulf of Mexico committee
on the same date.
Neither the chairman nor the senior independent director are
employed as executives of the group. The board maintains a succession
plan for the chairman and senior independent director, in addition to the
group chief executive and senior management.
Appointment and tenure
The chairman and our non-executive directors (NEDs) serve on the basis
of letters of appointment. BP does not place a term limit on director’s
service as we propose all directors for annual re-election by shareholders (a
practice we have followed since 2004).
Tenure of board directors as at 6 March 2012
0-3 years
8 NEDs
8 NEDs
4-6 years
3 NEDs
3 NEDs
7-9 years
1 NED
1 NED
The governance principles require our non-executive directors to be
independent in character and judgement and free from any business or
other relationship which could materially interfere with the exercise of their
judgement. The board has determined that those non-executive directors
who served during 2011 fulfilled this requirement and were independent.
The board also satisfied itself that there is no compromise to the
independence of, or existence of conflicts of interest for, those directors
who serve together as directors on the boards of outside entities or who
have other appointments in outside entities. These issues are considered
on a regular basis at board meetings. The nomination committee keeps
under review the nature of non-executive directors’ other interests to
ensure that the effectiveness of the board is not compromised. The
committee may make recommendations to the board if it concludes that a
director’s other commitments are inconsistent with those required by BP.
Time commitment and outside appointments
Letters of appointment for non-executive directors do not set out a fixed
time commitment for board duties as we believe that the time required
by directors may fluctuate depending on demands of the business and
other events. However, it is expected that directors will allocate sufficient
time to the company to perform their duties effectively. The chairman’s
appointment letter sets out the time commitment expected of him.
Following an approach from the Volvo Group, the chairman
discussed with the board, through the chairman’s committee, whether
to take an additional post as a part-time non-executive chairman of Volvo.
During this process, our senior independent director led a discussion of
non-executive directors without the chairman present to hear their views.
The board concluded that Mr Svanberg has sufficient time to carry out both
commitments and supported the chairman taking on this additional role.
The chairman will step down from his existing non-executive directorship
at Ericsson before assuming the chairmanship of Volvo in April 2012; he
also confirmed to the board that he does not intend to seek any additional
roles outside those at BP and Volvo.
Executive directors are permitted to take up one external board
appointment, subject to the agreement of the chairman and provided such
external appointment is reported to the BP board. Fees received for an
external appointment may be retained by the executive director and are
reported in the Directors’ remuneration report.
Diversity
BP recognizes the importance of diversity, including gender, at all levels
of the company as well as the board. The company is committed to
increasing diversity across our operations and has in place a wide range of
activities to support the development and promotion of talented individuals,
including women.
During the year, the board responded to Lord Davies’ report on
gender diversity and confirmed its goal to increase the number of women
on the BP board to three by 2013 and work towards the recommendation
of 25% female representation by 2015. With the appointment of Professor
BP governance framework
D
e
l
e
g
a
t
i
o
n
Owners/shareholders
Board
Nomination
Nomination
committee
committee
Remuneration
Remuneration
committee
committee
Chairman’s
Chairman’s
committee
committee
Gulf of Mexico
committee
SEEAC
Audit
Audit
committee
committee
Strategy/group risks/annual plan
Group chief executive
GCE’s delegations
Executive management
RCM
Resource
commitments
meeting
GPC
Group people
committee
GDC
Group
disclosures
committee
GFRC
Group
financial risk
committee
GORC
Group
operations risk
committee
BP Board Governance
Principles
• BP goal
• Governance process
• Delegation model
• Executive limitations
Delegation
Delegation of authority
through policy with
monitoring
Accountability
Assurance through
monitoring and reporting
Monitoring,
information and
assurance
Ernst & Young
Internal audit
Finance function
Safety & operational
risk function
General counsel
Group compliance
offi cer
External market
and reputation
research
Independent expert
Independent advice
(if requested)
A
c
c
o
u
n
t
a
b
i
l
i
t
y
BP Annual Report and Form 20-F 2011 121
Corporate governanceCorporate governance Dame Ann Dowling, BP currently has two female board members,
equating to 12.5% of our directors.
The board has agreed a board diversity policy which will be
included in our board governance principles. The policy states that when
considering the composition of the board, directors will be mindful of
diversity, inclusiveness and meritocracy. As part of its workplan for this
year, the nomination committee will develop and agree a set of measurable
objectives for implementing this policy and report back on these to
shareholders.
Induction and board learning
On joining BP non-executive directors are given a tailored induction
programme. This programme includes one-to-one meetings with senior
management, our auditors and site visits to our operations. The induction
will also cover the board committees that a director will join. An example of
the initial induction programme for one of our recently joined non-executive
directors is set out below.
Director induction programme
Board and governance
• BP’s board governance model, directors’ duties, interests and potential
conflicts.
• Committee induction.
• Strategy and planning.
• Group investor event on governance and board activities.
BP’s business
• History of the integrated oil company and BP.
• Upstream (exploration, development, production, overview of our
operations).
• Refining and Marketing.
• Alternative Energy.
Functional input
• Controls, external auditors and internal audit.
• Finance and corporate reporting.
• HR.
• Legal.
• Ethics and compliance.
• Safety and operational risk (S&OR), BP’s operating management
system (OMS) and environmental performance.
• Research and technology.
• Engineering.
We continue the board’s learning through board and committee events.
At our May 2011 board meeting in Houston, we ran a day-long event
to give our non-executive directors an insight into how BP manages
its learning and capability development, including briefings on seismic
interpretation, the company’s technical education programme and trading.
Non-executive directors are expected to attend at least one site visit per
year. During 2011, such visits included Texas City and Whiting refineries
with the independent expert, L. Duane Wilson, an offshore visit to the Gulf
of Mexico, visits to global wells organization leadership teams in the Gulf
of Mexico and the North America gas business, our business centre in
Budapest and BP’s offices in Houston and Canary Wharf. During the year
our chairman visited BP’s operations in Alaska and our oil sands projects in
Canada.
Board effectiveness
Board evaluation
We undertake an annual review of the board, its committees and individual
directors. The chairman undertakes the evaluation of individual directors,
with the chairman’s own performance evaluated by the chairman’s
committee (led by the senior independent director).
In 2009 and 2010, we undertook an external review of the board’s
performance. In 2011, we decided to continue external facilitation as a
122 BP Annual Report and Form 20-F 2011
way of building on the past year’s results and providing a robust, third-
party insight into the board’s effectiveness. To enable continuity and
comparability of results over the two year period, we used the same
external facilitator as for the 2010 review.
Evaluation process for 2011
• Each director (with the exception of those appointed in 2012) was sent a
questionnaire and a list of discussion topics.
• The facilitator held one-to-one reviews with each participating director,
using the questionnaire and discussion topics as a starting point.
• Each committee held its own review using online questionnaires that
were developed by us using an externally generated question bank. The
results from these questionnaires were then discussed with the external
facilitator by each committee (these are outlined in the reports of our
committees).
• A paper on the key themes and views from the one-to-one reviews and
the evaluation of the committees were sent to the board to review.
• The board held a discussion with the external facilitator to assess these
views and the issues raised.
• The board agreed on actions for the forthcoming year based on this
discussion.
Key conclusions of the 2011 evaluation
The review concluded the board had operated well in 2011. It had been
an eventful year and the board continues to deal with events from
the Gulf of Mexico. There was a strong view that the board had an
open and transparent style of discussion, with good engagement and
contribution from all members, particularly around strategic planning and
risk management. The board also considered that its focus, discipline
and follow through had strengthened over the year, which was seen as
important given the events of the previous 18 months and the volume of
issues dealt with by the board. It hoped to continue this trend in 2012.
The review also found that there was potential for continuous
improvement in areas such as board materials (including the length of
papers) and agendas, and that as the board endeavours to move back
into a ‘steady state’ of operation, it would need to revisit its collective
expectation around governance processes and style.
Tracking issues from our previous evaluation
Over 2011, the board acted upon the recommendations from the 2010
board evaluation. The board determined to conduct additional site visits
and participate in detailed briefings in order to gain further insight into the
company’s operations and activities – which it achieved through an active
programme over the year attended by individual or groups of directors. The
board set up a working group to review and revise the company’s board
governance principles to ensure that BP’s governance processes were
effective. The board also reviewed BP’s crisis and continuity plan, including
specific focus on the process through which board involvement is triggered
as part of its action to clarify the board’s role in the crisis planning process.
Finally, the board had extensive engagement with executive management
in forward-looking strategy discussions and an overview of BP’s risk
management systems.
Risk management: from operations to the board
One of the board’s tasks is to satisfy itself that the material risks to BP
are identified and understood and that systems of risk management,
compliance and control are in place to mitigate such risks. The board,
through its governance principles, requires the group chief executive to
operate with a comprehensive system of controls and internal audit to
identify and manage the risks that are material to BP. Authority for the
design and implementation of this system of internal control is delegated
by the board to the group chief executive. Components of our system
of internal control (which includes the risk management system) are
management systems, organizational structures, processes, standards and
behaviours employed to conduct the business of BP.
Corporate governance Board oversight
Occurs periodically at board level
Results in allocation and
oversight over group risks
Executive and functional oversight
Occurs periodically at
executive and function levels
Results in governance
over group risks
Business risk management
Occurs periodically at
business and function levels
Results in risk reports
Day to day risk management
Occurs at
operations and functions
Results in risk data
Risk management in BP is a ‘top-down’ and ‘bottom-up’ process. The
‘bottom-up’ process starts at the day-to-day level with businesses and
functions identifying and managing their risks using existing company
standards and practices, e.g. OMS. The most significant risks are organized
into common categories – strategic risks, safety and operational risks and
compliance and controls risks – so they can be reported up the line in a
standardized form.
During the year a review of BP’s risk management system was
initiated which has built on our current system of risk management. Using
the findings of this review, BP has started to implement enhancements
to drive consistency and clarity in how risks are reported and understood
in all levels of our organization from operations to the board. See
Our management of risk on page 42 for further discussion of the risk
management system and 2011 review.
Within BP’s risk management system, functions set standards,
provide guidance and provide a view of group risks in their functional area
of expertise, independent of line management. Certain functions also
deliver assurance that the activities to manage the risks are working as
intended in the businesses.
Group risks are allocated to one of the committees established
by the group chief executive for management and monitoring.
These executive level committees are sub-committees of our senior
management team and their role includes setting policy, making decisions
and overseeing the management of risks and performance. The executive
committees are:
• Group operations risk committee (GORC) for risks of a safety,
environment or operations nature.
• Group financial risk committee (GFRC) for finance and trading risks.
• Group disclosure committee (GDC) for financial reporting risks.
• Group people committee (GPC) for people risks.
• Resource commitments meeting (RCM) for risks related to investment
decisions.
At the group level, risk is examined by the board to apply a ‘top-down’
perspective. The group risks identified as requiring particular oversight in
the coming year are selected for discussion with the board. These are then
allocated for review by the board or one of its committees. A common
agenda for the review is established to enable the board or committee to
discuss risk in a consistent manner with executive management.
The board examines group risks both on a periodic basis and as part
of its review of the annual plan. The board also conducts an annual review
of the risk management and internal control systems as required by the UK
Corporate Governance Code. During the year there is flexibility to change
which risks have been identified as requiring particular oversight and which
have been allocated to the board and its committees, in the event there are
any changes to the internal or external environments or events arising.
Following its review of the 2012 annual plan, the risks described
above have been allocated for review by the board and its committees as
follows:
• The board has been allocated several strategic and safety and operational
group risks, including risks associated with the macroeconomic outlook,
the delivery of the 10-point plan, the group’s exposure to Russia, crisis
management, reputational impact and the recruitment and development
of staff.
• The audit committee has been allocated a number of compliance and
control and safety and operational risks, including risks associated with
treasury and trading activities, compliance with applicable laws and
regulations and security threats against our digital infrastructure.
• The safety, ethics and environment assurance committee has been
allocated several safety and operational and strategic risks, including
risks associated with conducting our operations through joint ventures
or associates and through contracting and sub-contracting arrangements
where BP may not have full operational control. Other safety and
operational risks the committee have been allocated include the health,
safety and environmental risks of incidents associated with the drilling of
wells, operation of facilities and transportation of hydrocarbons.
• The Gulf of Mexico committee has been allocated a number of strategic
risks, including risks associated with the extent and timing of costs and
liabilities relating to the incident and the possible impact on our licence
to operate.
Board activities during 2011
2011 was another active year for the board, which met 15 times. The
board’s focus remained on the incident in the Gulf of Mexico – both to
understand what happened and how the company can apply the lessons
learned. Within the board and its committees, debate and assurance
has been ongoing with management on key aspects such as the impact
on the group’s reputation, accounting treatment and provisioning,
implementation of the recommendations of the Bly Report and the legal
and communication strategy for litigation arising from the incident. The
challenge has remained for the board to ensure that it devoted enough
time to the ongoing business of the company whilst holding these
important discussions. Periodic meetings throughout the year of the non-
executive directors comprising the chairman’s committee, together with
liaison between the chairman and the chairs of the board committees,
have assisted in managing this challenge. Areas discussed by the board
included the following:
Strategy
The board is engaged at the early stages of discussion on strategy and the
annual plan in order to provide constructive challenge. During the year two
day-long meetings were held for strategic discussions. After the February
2011 update to the market the board continued to develop the company’s
strategy with respect to milestones and deliverables, resulting in a further
market update in October on the company’s ”10-point-plan”. Over the
year, the board considered key strategic elements, including biofuels,
Canadian heavy oil and the company’s disposal programme. The board also
spent considerable time discussing strategic opportunities and implications
of the strategic alliance that had been proposed with Rosneft and the new
relationship with Reliance.
BP Annual Report and Form 20-F 2011 123
Corporate governanceCorporate governance Assurance
The board undertook a number of activities as part of its assurance
role, including assessing the effectiveness of the company’s system of
internal controls and risk management. The group’s financial performance
was considered, as was a review of BP’s technology function and the
performance and role of the technology group within the outlook for energy
demand and supply.
The board received an overview of BP’s activities in the US and
received several updates during the year on legal issues, in particular on
litigation and enquiries resulting from events in the Gulf of Mexico. The
board discussed the UK Bribery Act and the steps the company was taking
to comply with the Act; as a result of this discussion the board endorsed
the updated anti-bribery policy outlined in BP’s code of conduct.
L. Duane Wilson, the independent expert appointed by the board
to provide an objective assessment of BP’s progress in implementing the
recommendations of the BP US Refineries Independent Review Panel,
presented his fourth annual report to the board where he assessed BP’s
progress against the Panel’s 10 recommendations. Further details of
Mr Wilson’s work are outlined in the report of the SEEAC and his report is
published on BP’s website at bp.com/independentexpert.
Risk
The board discussed the progress and outcome of the review of BP’s
risk management system over the year. The outcome of the review has
resulted in clearer and more consistent reporting, definitions and templates
for BP’s risk management activities, as well as greater alignment of these
risk management activities with existing BP business processes.
The board and its monitoring committees (audit, SEEAC and Gulf
of Mexico) monitored the group risks which had been allocated following
the board’s review of the annual plan at the end of 2010. The annual plan
and the group strategy are central to our risk management programme as
they provide a framework for the board to consider significant risks and
manage the group’s overall risk exposure as well as underpin the model
of delegation and assurance for the board in its oversight of executive
management and other activities.
Reputation
The board considers reputation from two perspectives – the reputational
risks to the group and the processes the company has in place to manage
these risks. During the year, the board reviewed external reputation data
which looked at BP’s reputation in the UK and US. It also discussed the
group’s communications strategy and its reputation management plan.
BP’s group-wide renewed values were launched in 2011 as part
of a programme of change called ‘We are BP’, by which the renewed
values will be reflected in how employees’ performance is assessed and
rewarded. The renewed values were also embedded within the updated
code of conduct.
Governance
As described above, over the year the board reviewed its system of board
governance and established a working group to assist in this process. The
main outcomes of the review were strengthened board processes around
information, risk and revisiting the role and tasks of the board and its
committees.
The board seeks to understand the views of its shareholders, and
feedback from investors is given to the board – either directly following
meetings with the chairman or other board members or indirectly through
an annual investor audit undertaken by a third party. Following our AGM in
April 2011, the board examined the voting results for each resolution and
considered the comments received from institutional investors to explain
their voting position.
124 BP Annual Report and Form 20-F 2011
Governance
• Board governance
review
• Investor audit
• Board evaluation
Reputation
• Group reputation review
• Communications
• Reputation management
• Crisis management
BP board
activities
in 2011
Strategy
• Russia
• Strategy: group
• Strategy: biofuels;
Canadian heavy oil
• Annual plan
• Competitor analysis
• Disposal programme
Assurance
• Group financial outlook
• Independent expert’s
annual report
• Legal update
• Technology review
• US overview
• Corporate reporting
• UK Bribery Act
Risk
• Risk management review
• Group risk: upstream capability
• Group risks for 2012
Shareholder engagement
The company continued its open dialogue with shareholders. Our
executive directors and members of our executive management team held
investor meetings following our strategy and financial results. We also held
meetings on operating and non-financial issues, including presentations
on BP’s Energy Outlook 2030, an update on BP’s activities in Canadian
oil sands, our Alternative Energy and Refining and Marketing businesses
and BP’s environmental and social requirements for new projects. These
events were intended to give shareholders a wider perspective on the
company’s thinking behind its strategy and an understanding of the
processes and standards we use to underpin our operations.
The chairman, senior independent director and chair of our
remuneration committee held a number of one-to-one meetings with
institutional investors to discuss strategy, the board’s view on the company’s
performance and governance and our remuneration structure. In addition
the chairman, with two members of our senior executive team, spoke at
group investor events in the US and UK to outline the company’s progress
on the Bly Report recommendations, the remit and work of the safety and
operational risk function and the work of the board. In March 2011 we held
our annual investor event with our chairman and the chairs of our board
committees. We continue to receive positive feedback on this event and find
it an effective way for our largest shareholders to hear about the work of our
board and our committees, and for our non-executive directors to engage in
dialogue with investors. We intend to hold a similar event in March 2012.
During the year we focused on enhancing communication with
our private shareholders, including a revision of dividend materials and
the shareholder information pages of our website. We continued our ‘lost
shareholder’ programme which returns shares and unclaimed dividends to
shareholders who have failed to keep their contact details up to date.
Materials from our investor presentations, including information on the
work of our board and its committees can be downloaded from the
investors page of our website.
Corporate governance
Board and committee attendance in 2011
Non-executive directors:
Carl-Henric Svanberg
Sir William Castell
Paul Anderson
Frank Bowman
Antony Burgmans
Cynthia Carroll
George David
Ian Davis
Douglas Flint
DeAnne Julius
Brendan Nelson
Phuthuma Nhleko
Executive directors:
Bob Dudley
Iain Conn
Byron Grote
a
15
15
15
15
15
15
15
15
8
8
15
15
15
15
15
Board
b
Audit
committee*
b
a
SEEAC*
b
a
Remuneration
committee
b
a
Gulf of Mexico
committee
b
a
Nomination
committee
b
a
Chairman’s
committee
b
a
9c
9
9
9
9
9
9
9
7
7
16
16
16
16c
14
16
16
16
7c
7
7
2c
7
7
7
2
5c
5
4
4
5
1
1
5
5
4
3
5
1
1
9c
9
9
9
9
9
9
9
3
3
9
8
9
9
9
8
9
8
9
9
3
3
8
8
11
11
5c
11c
7
11
10
5
11
6
15
15
14
15
15
13
14
15
7
8
13
13
14
14
15
a Total number of meetings the director was eligible to attend.
b Total number of meetings the director did attend.
c Committee chairman.
* Attendance for audit committee and SEEAC includes a joint meeting between the two committees.
NB: The chairman also attends meetings of the remuneration and Gulf of Mexico committees.
AGM
We continue to have a well-attended annual general meeting, usually
attracting over a thousand people. Our shareholder base is geographically
diverse and we offer a webcast and advance voting to make our meeting
accessible to those who cannot attend in person.
The voting levels for our 2011 AGM saw a moderate increase over
2010 levels to 60.6% (59.6% in 2010). Viewers of our 2011 AGM webcast
increased by fivefold over the previous year. We make our webcast,
speeches and presentations from the AGM available on our website after
the meeting, together with the outcome of voting on each resolution.
International advisory board
In 2009, BP formed an international advisory board (IAB) whose purpose is
to advise the chairman, group chief executive and our board on geopolitical
and strategic issues relating to the company. This group has an advisory
role and meets twice a year – although its members are on hand to provide
advice and counsel to the company when needed.
The IAB is chaired by our previous chairman, Peter Sutherland. Its
membership in 2011 included Kofi Annan, Lord Patten of Barnes, Josh
Bolten, President Romano Prodi, Dr Ernesto Zedillo and Dr Javier Solana.
Our chairman and chief executive attend meetings of the IAB. Issues
discussed during the year included developments in the eurozone, events
in the Middle East and the world energy outlook.
UK Corporate Governance Code compliance
BP complied throughout 2011 with the provisions of the UK Corporate
Governance Code, except in the following aspects:
B.3.2
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 demands of the business and
other events. 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.
The remuneration of the chairman is not set by the remuneration
committee. Instead the chairman’s remuneration is reviewed by
the remuneration committee which makes a recommendation
to the board as a whole for final approval, within the limits set
by shareholders. We believe this wider process lets all board
members discuss and approve the chairman’s remuneration
(rather than solely the members of the remuneration committee).
D.2.2
BP Annual Report and Form 20-F 2011 125
Corporate governanceCorporate governance Committee reports
Audit committee
Chairman’s introduction
In the first quarter of the year the committee, under Douglas Flint’s
chairmanship, continued to spend considerable time reviewing and
challenging BP’s assessment of its financial responsibilities relating to the
tragic incident in the Gulf of Mexico in April 2010. This task has remained a
key area of focus under my chairmanship during the remainder of the year.
We have continued to seek assurance that where liabilities are estimable,
they are fully provided for, and where uncertainty is too great to support
a provision that appropriate disclosure is made. Some greater clarity
developed during the year as experience was gained about the operation
of the Deepwater Horizon Oil Spill Trust fund, and as settlements were
reached with two of the partners in the Macondo well and two of the
contractors involved. However, as reported elsewhere in this document,
major uncertainty remains in respect of litigation, potential fines and
penalties and other matters which will require significant attention from the
audit committee for the foreseeable future. The committee has therefore
taken care to preserve its regular agenda content so as to continue fulfilling
its remit to the board with respect to monitoring risk management systems
and internal controls and financial reporting.
Amongst other topics, we have reviewed controls in trading, debt
and liquidity management and the company’s response to the UK Bribery
Act. During the course of the year, I have also participated in the group
chief executive’s audit forum and the group financial risk committee
(GFRC). In preparation for audit committee meetings, I have met regularly
with the chief financial officer, general auditor and the lead partner of the
external auditors. I also spent time with the leadership team of the internal
audit function.
I valued the time I took to visit one of the company’s largest data
centres in London, its European business service centre in Budapest, and
the trading floors in Houston and London. Such visits and interaction with
staff at all levels of the organization enhance both our understanding of
the company’s activities and our assurance over the way they are being
managed.
Although we lost Douglas Flint from the committee when he
stepped down from the board, I am delighted that Andrew Shilston has
now joined us. Andrew’s experience as the CFO at Rolls Royce, and his
previous background in the energy business, complements the skills
already present in the committee’s membership. I believe we have a
very good mix of commercial, financial and audit expertise to address
the complex accounting, audit and risk issues which the committee
monitors. I would also like to thank Ian Davis for his contribution to the
audit committee over the last two years. Ian is now stepping down from
the committee in anticipation of a period of heavier workload related to the
Gulf of Mexico committee.
Our report below seeks to highlight the key activities undertaken
in 2011 and provide some insight into the outcomes of the committee’s
work. I believe 2012 will be equally intense but the committee is well
equipped to address the tasks it faces.
Brendan Nelson
Chairman of the audit committee
Committee members
Brendan Nelson – committee chair (from 14 April 2011)
George David
Ian Davis (retired from the committee on 3 February 2012)
Phuthuma Nhleko (appointed 1 February 2011)
Andrew Shilston (appointed 3 February 2012)
Members who left during the year:
Douglas Flint – previously chair of the committee (retired 14 April 2011)
The audit committee is composed of independent, non-executive directors
selected to provide a wide range of financial, international and commercial
expertise appropriate to fulfil the committee’s duties.
126 BP Annual Report and Form 20-F 2011
Brendan Nelson became chair of the audit committee upon the retirement
of Douglas Flint from the board in April 2011. Mr Nelson, who was formerly
vice chairman of KPMG, is chairman of the Group Audit Committee of The
Royal Bank of Scotland Group plc, a member of the Financial Reporting
Review Panel, Vice President of the Institute of Chartered Accountants
of Scotland and a director of the Financial Skills Partnership. The board is
satisfied that Mr Nelson, in succession to Mr Flint, is the audit committee
member with recent and relevant financial experience as outlined in the
UK Corporate Governance Code. It considers that the committee as a
whole has an appropriate and experienced blend of commercial, financial
and audit expertise to assess the issues it is required to address. The board
also determined that the audit committee meets the independence criteria
provisions of Rule 10A-3 of the US Securities Exchange Act of 1934 and
that Mr Nelson may be regarded as an audit committee financial expert as
defined in Item 16A of Form 20-F.
Committee role and structure
The role and responsibilities of the audit committee are set out in the
appendix of BP’s board governance principles which is available on our
website. We keep these under review and test their effectiveness in
our annual evaluation of the audit committee. In addition, the chairs and
secretaries of the audit and safety, ethics and environment assurance
committees have worked together to ensure their respective agendas
neither duplicate nor omit coverage of key risk areas.
The committee met 11 times over the past year including one joint
meeting with the safety, ethics and environment assurance committee
(SEEAC). This joint meeting reviews the general auditor’s report on internal
control and risk management systems for the year in preparation for the
board’s report to shareholders in the annual report. It also reviews the
general auditor’s audit programme for the year ahead to ensure both
committees endorse the coverage.
Each audit committee meeting is attended by the group chief
financial officer, the group controller, the general auditor (head of internal
audit) and the chief accounting officer. The lead partner of our external
auditors (Ernst & Young) is also present.
The committee also holds separate private sessions during the
year with the external auditor and the general auditor – these sessions are
without the presence of executive management.
The board is kept updated and informed of the audit committee’s
activities and any issues arising through verbal reports at its meetings from
the committee chair and the circulation of the committee’s minutes.
Audit committee processes
Information and advice
Information and reports for the committee are received directly from
accountable functional and business managers and from relevant external
sources. In addition, like our board and other committees, the audit
committee can access independent advice and counsel when needed
on an unrestricted basis. During 2011, external specialist legal advice in
relation to corporate reporting was provided to the committee by Sullivan &
Cromwell LLP. As part of its annual evaluation, the committee reviews the
adequacy of reliable and timely information from management that enables
it to fulfil its responsibilities. The 2011 evaluation indicated that members
recognized the openness and transparent nature of the materials and
presentations provided by management.
Training and visits
In continuing to respond to the consequences of the Gulf of Mexico oil
spill, the committee placed emphasis on receiving appropriate briefings on
the relevant applications of accounting policy, particularly provisioning and
related disclosure. The committee received regular technical updates from
the chief accounting officer on developments in financial reporting and an
annual briefing on oil and gas reserves disclosures. In addition the external
auditors provided insight and commentary on international accounting
policy developments.
Induction programmes are provided for new members and are
tailored around their roles on the audit committee. During 2011 Brendan
Nelson and Phuthuma Nhleko completed their audit committee induction
programmes. This included sessions on tax, trading operations, accounting,
Corporate governance financial reporting and controls and the structure of BP’s finance function.
Individual private sessions with the external and internal auditors were also
provided. During 2012 we will undertake an audit committee induction for
Andrew Shilston.
When the board visited Houston in May, audit committee members
took the opportunity to visit the computing facility and the trading floor
at the Westlake complex. During the May trip, two members of the
committee, including the chairman, also visited the Atlantis offshore
platform in the Gulf of Mexico. In July the committee visited the
company’s data centre in London to review IT service and security matters.
Earlier in the year Mr Nelson accompanied SEEAC members on a visit to
the Whiting refinery where they were briefed on the progress of the major
modernization project. These visits enable the committee to see first-
hand examples of risk management and to address questions directly to
employees on site.
2011 Audit committee activities
Gulf of Mexico
The responsibilities of the board’s monitoring committees in reviewing
the company’s response to the Gulf of Mexico incident have been
carefully delineated. Whilst the Gulf of Mexico committee has considered
the ongoing work of the Gulf Coast Restoration Organization (GCRO)
and litigation matters, and the SEEAC has reviewed the company’s
implementation of the recommendations of the Bly Report, the audit
committee’s focus has been on financial reporting and controls. The
committee has reviewed each quarter the provisions and contingencies
related to the incident and their disclosure. It has also received a report
from the group controller on the status of financial controls in the GCRO.
Financial reporting
The group’s quarterly financial reports, the BP Annual Report and
Form 20-F and the BP Summary Review were reviewed by the committee
before recommending their publication to the board. In undertaking
this review, the committee discussed with management how they had
applied critical accounting policies and judgements to these documents,
including key assumptions regarding provisions for litigation, environmental
remediation and decommissioning. The committee also reviewed the
impairment testing process and the pricing assumptions that were utilized.
In considering the robustness of the valuations the committee also
referred to analysis undertaken by the external auditors. This year, with a
number of assets held for sale, the committee was appropriately engaged
in reviewing their accounting treatments. Further details on impairment
reviews are included in the Financial statements – Note 5. The committee
also reviewed the company’s methodology underpinning its disclosures
relating to oil and gas reserves.
Monitoring business risk
As discussed elsewhere in this annual report, the board periodically
reviews the company’s group risks and allocates monitoring of their
management and/or mitigation to itself or its committees. Within the
audit committee’s area of monitoring in 2011 were liquidity management,
trading risk and corruption risk. During the year, the committee also
undertook functional reviews of information technology and services,
integrated supply and trading, business service centres and the governance
and control of major project investment. Each year the committee also
reviews risk, governance and the control environment relating to TNK-BP.
Reports on the work of the group financial risk committee – the
executive-level committee that provides assurance on the management
of BP’s financial risk – were provided during the year by the chief financial
officer.
Internal control, audit and risk management
The forward agenda for the audit committee contains standing items
on internal control – these include quarterly reports of internal audit
findings, internal control deficiencies in financial reporting, and an annual
assessment of BP’s enterprise level controls. The committee also received
a joint report from the group controller and chief information officer on
access controls and segregation of duties.
An important input into the board’s review of the company’s risk
management and internal control systems is the annual joint meeting
between the audit committee and the SEEAC. This takes place at the
start of each year to review the general auditor’s report on internal
control and risk management systems for the previous year. The general
auditor reviews his team’s findings and management’s actions to
remedy significant issues identified in that work. His report also included
information on the results of audit work undertaken by the safety and
operational risk audit team and reviews by the group’s finance control
team. As noted earlier, this joint meeting also reviews the coming year’s
forward programme of audit work.
External auditors
In 2011 the committee held two scheduled meetings with the external
auditors without management being present. These sessions provided
the opportunity for direct feedback and dialogue between the committee
and the auditors. In addition, the chair of the audit committee met privately
with the external auditors before each audit committee.
Performance of the external auditors is evaluated by the audit
committee each year. This year the committee put particular focus on
assessing audit quality against a set of agreed key performance indicators.
The company has also developed an auditor assessment tool which will
be completed on an annual basis and apply five main performance criteria
– robustness of the audit process, independence and objectivity, quality of
delivery, quality of people and service, and value-added advice.
The committee reviews the composition of the audit team annually
and meets the relevant partners when undertaking business or function
reviews. Additionally, the committee has the opportunity to assess specific
technical capabilities in the audit firm when addressing specialist topics,
such as environmental provisioning and impairment testing.
We maintain auditor independence through limiting non-audit
services to tax and audit-related work that fall within defined categories.
For a list of those categories, the process by which non-audit work is
approved when the audit committee concludes that it is in the interests
of the company to purchase non-audit work from the external auditor
(rather than another supplier), see the section Principal accountants’ fees
and services on page 136. A new lead audit partner is appointed every
five years and other senior audit staff are rotated every seven years. No
partners or senior staff from Ernst & Young who are connected with the
BP audit may transfer to the group.
Non-audit work by Ernst & Young is subject to the audit
committee’s pre-approval policy. Non-audit work undertaken by Ernst
& Young and by other accountancy firms is regularly monitored by the
committee.
Fees paid to the external auditor for the year were $55 million, of
which 20% was for non-audit work (see Financial statements – Note 16).
Non-audit fees increased from $8 million in 2010 to $11 million in 2011 due
to additional work undertaken in providing services related to corporate
finance transactions. This increase resulted from Ernst & Young’s
engagement to carry out financial due diligence in connection with actual
and proposed sales of assets in North America.
The audit committee considers both the fee structure and the audit
engagement terms and monitors progress during the year. In October the
committee reviewed with management the criteria which would trigger
tendering the audit. The criteria considered were independence, quality
of service, audit quality, cost/value for money and regulatory changes.
The committee and management believe that assessed against each
of these criteria there is no case for recommending going to tender this
year. Nonetheless, preparatory work has been undertaken to understand
the potential for other audit firms to participate in a tender should this be
indicated at a future date. The committee has recommended to the board
that the re-appointment of Ernst & Young as the company’s external
auditors be proposed to shareholders at the 2012 AGM.
Internal audit
The committee receives quarterly reports from the general auditor which
enable the committee to monitor the progress of the internal audit against
its planned schedule of audits as well as to track key findings and any
material actions that are overdue or have been rescheduled. In reviewing
BP Annual Report and Form 20-F 2011 127
Corporate governanceCorporate governance the audit programme proposed each year, the committee looks at
whether it believes key risks facing the company have been appropriately
addressed. The programme for 2011 was approved by the committee in
January 2011.
The general auditor met privately with the committee once during the year,
without the presence of executive management or the external auditors.
This is complemented by regular meetings with the committee chair
between meetings.
The committee reviewed with the general auditor the number and
expertise of his team’s staff resources. The internal audit function provides
a source of skilled staff to many parts of the company and to maintain its
resources the general auditor recruits from both inside the company – to
bring in deep business expertise into the team – and externally – to bring
professional auditing skills. The committee has sought assurance that
these resources are sufficient to fulfil the function’s role, and the general
auditor has undertaken benchmarking work with other major companies in
the industry. In addition, an external review on internal audit effectiveness
has been undertaken in 2012. This review concluded that BP had an
effective internal audit function that compared favourably with other
complex and industry equivalents.
During 2011 the committee was satisfied that internal audit had
the appropriate access it required to information and that management had
committed to the provision of that information and had responded to the
results of audit findings in a timely manner.
Other activities
The committee monitors fraud and misconduct through quarterly updates
from the general auditor and any non-compliance with the BP code of
conduct through quarterly reports by the group ethics and compliance
officer. Actions arising are monitored to close out. The annual certification
report of compliance with the code of conduct, which is signed by the
group chief executive, is also reviewed by the committee.
The company’s employee concerns programme OpenTalk has
been adopted by the committee for whistle-blower monitoring, and all
financial issues that have been flagged are reviewed by the committee.
The quarterly reports the committee receives track trends in both the case
type and time taken to close out queries and reports.
Committee evaluation
Each year the audit committee examines its performance and
effectiveness, and ensures that its tasks and processes remain
appropriate. In 2011, the committee used an internally-designed
questionnaire administered by external consultants. The same question
set was used as in 2010 so that any trends could be identified. Key areas
covered included the clarity of its role and responsibilities, the balance
of skills among its members and the effectiveness of reporting its work
to the board. Specific areas identified for focus in 2012 included trading,
provisioning and the effectiveness of internal audit. Regarding process,
members noted that fulfilling the committee’s remit had led to lengthy
meetings, but at the same time they recognized a wish to extend deep
dives into specific topics. The committee noted that, in areas of common
interest such as compliance and ethics, it needed to continue to work
closely with the SEEAC. It also commented on the need for pre-read
papers to be well focused to ensure best use of agenda time. Overall the
committee considered it had the right composition in terms of expertise
and had effectively undertaken its activities and reported them to the board
during the year.
Safety, ethics and environment assurance committee
(SEEAC)
Chairman’s introduction
Whilst the Gulf of Mexico committee, as reported elsewhere in this
document, has focused its work on the company’s restoration activities
in the Gulf area and on oversight of ongoing litigation, the SEEAC spent
considerable time over the past year monitoring the group’s response to
the 26 recommendations that were made in BP’s investigation report (the
Bly Report) into the tragic incident in April 2010. Our role has been to seek
assurance on behalf of the board that each of those 26 recommendations
128 BP Annual Report and Form 20-F 2011
is being pursued globally with pace and commitment. We have received
progress reports at each of our meetings and made visits to meet key
members of the teams in the exploration and production and S&OR
organizations that are leading these changes. This included visiting an
offshore platform to get closer to the front line, two in-depth discussions
with managers in the Houston office and participating in management’s
wells inspection programme. We have put fresh emphasis on getting a
deeper perspective into the organization. In part we have achieved this
through individual committee members undertaking visits and meeting
staff outside the boardroom environment and then reporting back to the
committee at the first opportunity. We believe this approach both deepens
our collective understanding of risk and of management’s controls, and
enables us to make more informed, and hence more valuable, challenges.
We have endeavoured to follow this approach to all of our work undertaken
throughout 2011. As always, for a committee reviewing management’s
assessment and mitigation of non-financial risk, this work has extended
to a wide range of topics. The report below provides more detail but we
would highlight our reviews of risks and risk management in pipelines,
shipping and drilling. We have also taken a deeper look at risks in our
petrochemicals business, including a visit by three members of the
committee to the company’s paraxylene manufacturing facility in Texas.
We have continued to be very well served by L. Duane Wilson’s
independent perspective of the company’s response to the ‘Baker
Panel’ recommendations following the fire and explosion at the Texas
City refinery in 2005. We will shortly be appointing a highly experienced
individual to report independently to SEEAC on the implementation of the
Bly Report recommendations.
Overall this has been a year of significant change which will take
time to fully embed but we believe we have observed real and enduring
progress.
In February 2012 we welcomed to the committee Professor Dame
Ann Dowling who brings deep experience in technology and engineering.
We concluded during the year it would be appropriate for the
SEEAC chairmanship to transfer to Paul Anderson once the restructuring
and reorganization within the company was largely established. This
introduction to the committee’s report is therefore written by both of
us. We share the same commitment to monitor closely, and provide
constructive challenge to, management in its drive for safe and reliable
operations at all times. We believe that the extensive breadth and depth of
committee members’ experience will serve us well in the endeavour which
is so central for a company whose business encompasses the production
and distribution of hazardous materials.
Paul Anderson
Chairman (from December 2011)
Sir William Castell
Chairman (to December 2011)
Committee members
Paul Anderson – committee chair (from 9 December 2011)
Sir William Castell – committee chair (to 8 December 2011)
Frank Bowman
Antony Burgmans
Cynthia Carroll
Professor Dame Ann Dowling (from 3 February 2012)
Committee role and structure
The role of the SEEAC is to look at the processes adopted by BP’s
executive management to identify and mitigate significant non-
financial risk, including monitoring process safety management, and
receive assurance that they are appropriate in design and effective in
implementation.
The committee met nine times in 2011 including a joint meeting
with the audit committee at which the general auditor’s report on internal
control and risk management systems for the year was reviewed in
preparation for the board’s report to shareholders in the annual report. In
that joint meeting the committees reviewed the internal auditor’s audit
programme for the year ahead to ensure both committees endorsed the
coverage. SEEAC also reviewed the planned work of the S&OR audit
function and noted an enhanced focus on integrating audit work across the
company. The SEEAC and audit committee worked together, through their
Corporate governance chairs and secretaries, to ensure that the agendas did not overlap or omit
coverage of any key risks during the year.
In addition to the committee membership, each SEEAC meeting
was attended by the group chief executive, the executive vice president
for safety and operational risk, the general auditor and the external auditors.
The general counsel also attended most meetings. The committee held
private sessions for the committee members only (without the presence
of executive management) at the conclusion of its meetings to discuss
any issues arising and the quality of the meeting. Between meetings,
committee members took opportunities to visit company sites and
received informal briefings through the committee chair, the secretary,
the external auditor’s lead partner, the general auditor and executive
management.
SEEAC processes
Information and advice
The committee receives specific reports from the business segments
but also receives cross-business information from the functions. These
include but are not limited to the safety and operational risk function,
internal audit, group ethics and compliance and group security. During the
year, the main external input into the committee has been from L. Duane
Wilson, the independent expert (for further information, see the section
on independent expert below). As for the board and other committees,
SEEAC can access any other independent advice and counsel if it requires,
on an unrestricted basis.
Training and visits
The committee extended its coverage and number of visits this year by
encouraging members to participate individually, or in groups, and report
back to the next full meeting. Members have also presented at staff
training events, such as the operations academy at MIT in Boston. A key
area of focus has been following up on the implementation of the Bly
Report’s 26 recommendations and on the progress of the new S&OR
function. In March the chairman and secretary visited Houston to discuss
how S&OR management was being embedded in the upstream production
and development divisions and committee members made a further
visit to Houston in January 2012. In 2011, a committee member also
participated in an S&OR leadership event in London. Another committee
member accompanied the executive vice president for developments on
two inspection visits to oil and gas wells leadership teams. In May the
committee travelled offshore to the Atlantis platform in the deepwater Gulf
of Mexico, and also visited the upstream learning centre in Houston to see
the capability development activity being undertaken and its global reach.
Considerable focus also continues to be placed on the downstream
and on the company’s response to the BP US Refineries Independent
Safety Review Panel recommendations. In March two members of the
committee visited the Whiting refinery, accompanied by the independent
expert, Mr Wilson, to review progress in risk management systems
and OMS implementation. In January 2012 members of the committee
revisited Texas City refinery, again accompanied by Mr Wilson. This
followed previous committee visits in March 2010, April 2008 and
September 2007. During this visit, committee members also visited
the nearby petrochemicals facility to follow up on presentations it had
received in May and October and to gain plant level experience, as well
as to observe the extent to which the BP US Refineries Independent
Safety Review Panel recommendations had been implemented in the
petrochemicals context.
In addition to the extensive learning experiences provided by these
visits and meetings with executive management, induction programmes
are organized for new members of SEEAC. Frank Bowman, who joined
the committee in November 2010, completed his induction programme
in 2011.
environmental and regulatory compliance and audit findings. Operational
risk and performance forms a large part of the committee’s agenda.
In 2011, the committee put particular focus on gaining assurance that
the new S&OR organization was developing as envisaged. The S&OR
function has intervention rights in all aspects of the group’s technical
and operational activities, including key investment decisions and the
committee sought evidence that this was working in practice. The
committee’s visits, as mentioned above, provided opportunities to discuss
with local staff the interaction between line managers and embedded
S&OR staff, and where change had occurred as a result. The committee
was satisfied with the progress being made but will continue to monitor
this in 2012 along with the enhancement of standard practices and
processes within OMS.
Monitoring the company’s progress in implementing the 26
recommendations in the Bly Report is a key task for the committee
and it received regular updates, including written reports from the
executive vice president for developments, at five of its 2011 meetings.
The BP board has identified an independent expert to provide further
oversight and assurance regarding the implementation of the Bly Report
recommendations. The engagement of the independent expert is expected
to commence in the latter half of May 2012. The independent expert will
report directly to the board. He will track BP’s progress in implementing
the 26 recommendations from the company’s internal investigation of the
Deepwater Horizon oil spill and will independently assess the safety, health
and environmental work of global drilling operations. He will give regular
updates directly to the SEEAC.
During the year the committee received specific reports on the
company’s management of risks in shipping, wells and pipelines. The
potential environmental consequences of loss of containment in these
activities gave particular focus to the approaches to risk management
employed. These included design, such as double bottomed hulls
in tankers, and training, such as drilling simulators and naval cadet
training programmes. The committee noted that all new projects in
environmentally sensitive areas are submitted to the requirements of the
company’s environmental and social review process.
When a fatality in the workforce occurs the committee reviews the
incident in depth before reporting back to the board. The committee also
reviews specific incidents to understand root causes and actions being
taken to prevent recurrence. There has been a particular focus on ensuring
lessons learned are communicated widely across the company and not just
within the business segment in which the incident occurred.
Independent expert
Since L. Duane Wilson’s appointment by the board in 2007 as an
independent expert to provide an objective assessment of BP’s progress in
implementing the recommendations of the BP US Refineries Independent
Review Panel, he has presented to the committee at least four times
a year in person. His role has been to assist the company in improving
process safety performance at BP’s five US refineries. Annually the
committee approves his work plan for the year ahead and receives a full
written report which is made public on the company’s website. In his last
verbal report Mr Wilson advised that he had observed continued progress
in process safety performance at each visit he has made to the five
refineries. He also discussed work remaining to be completed and areas
requiring special emphasis. As process safety performance has reached
higher levels in recent years, he noted that the rate of change has naturally
slowed, but site metrics continued to demonstrate improvements.
Mr Wilson also noted that some aspects of implementing the Panel’s
10 recommendations require ongoing activity and hence could never be
complete, but he considers the company to have appropriate systems
and processes to continue its work towards process safety leadership.
Mr Wilson’s reports are published in full and available on our website at
bp.com/independentexpert.
2011 SEEAC activities
Safety, operations and environment
The committee receives regular reports from the S&OR function, including
quarterly reports prepared for executive management on the group’s
health, safety and environmental performance and operational integrity.
These include quarter-by-quarter measures of personal and process safety,
Regional and functional reports
Each year the committee receives a report on the progress made in HSE
at TNK-BP, noting however that formal oversight of HSE performance and
policies is exercised by TNK-BP’s own HSE committee. It was reported
that, whilst significant areas for improvement remained, TNK-BP had
BP Annual Report and Form 20-F 2011 129
Corporate governanceCorporate governance continued to make progress in addressing the main safety, ethical and
environmental challenges confronting it since it was formed in 2003. The
committee will continue to monitor progress regularly.
The committee continued to receive reports on the joint venture
operations in Iraq, and in particular was briefed by the company’s head of
security on the risks and management of security in Iraq. As mentioned
above, the committee reviewed the company’s shipping activities in 2011
and was briefed on the function’s response to the threat of piracy in the
waters off the Somali coast.
The committee also examined quarterly audit reports from BP’s
internal audit and safety and operational risk functions which highlighted
key findings and material actions arising from audits which had taken
place at segment, functional and regional levels and tracked their close
out. During the year the committee also received written reports from the
group ethics and compliance officer.
Activities from the executive-level group operations risk committee
(GORC) are reported to the SEEAC by the group chief executive and
executive vice president S&OR at each meeting. Improved co-ordination
of agenda planning was achieved to facilitate executive management level
review of key risk topics prior to board level review at SEEAC. The SEEAC
also received regular updates on the company’s interaction with regulatory
agencies.
Committee evaluation
For its 2011 evaluation, the SEEAC again used a questionnaire
administered by external consultants to examine the committee’s
performance and effectiveness. The committee responded to the same
questions as used in 2010 so that any change trends could be discerned.
The topics covered included the balance of skills and experience among its
membership, quality and timeliness of information the committee receives,
the level of challenge between committee members and management and
how well the committee communicates its activities and findings to the
board.
In 2010 the committee had concluded that it should increase its site
visits and training. In 2011, as reported above, the committee believed it
had increased these activities significantly and agreed it should continue to
do so in 2012. It also noted that given its broad remit across non-financial
risk, it would need to continue to balance that breadth with heightened
focus on specific risk and performance topics. It viewed its increased
use of member visits and briefings as important tool towards achieving
that heightened focus. Overall the committee considered that its current
membership provided a well-balanced and experienced resource, and also
noted the valuable contribution made by Mr Wilson in his capacity as the
independent expert.
Gulf of Mexico committee
Chairman’s introduction
The Gulf of Mexico committee was very active in 2011, meeting 16 times
over the course of the year. In addition to overseeing efforts to mitigate the
effects of the spill, the company’s strategy for resolving claims, and actions
to restore the group’s reputation, the committee focused a considerable
portion of its attention on legal matters. Some of these legal matters
included settlements reached with BP’s partners in the Macondo well and
various contractors, preparations for the upcoming trial in the Multi-District
Litigation and ongoing governmental investigations.
We have been joined in meetings by the leadership, management
and counsel of the Gulf Coast Restoration Organization (GCRO), which was
formed in mid-2010 to manage the company’s long-term response to the
tragic Deepwater Horizon oil spill. The committee members’ understanding
of the important issues and numerous interdependencies has been
facilitated by the frequency of meetings and the breadth of topics covered.
I believe the committee has maintained a rigorous approach to its
work, providing effective oversight on behalf of the board, to which reports
are provided following committee meetings. The report below summarizes
the activities of the committee in 2011. I anticipate 2012 will be an equally
demanding year but the committee is well prepared to conduct its tasks.
Ian Davis
Gulf of Mexico committee chair
Committee members
Ian Davis – committee chair
Paul Anderson
Frank Bowman (joined the committee 3 February 2012)
Sir William Castell
George David
In 2011 the membership of the Gulf of Mexico committee remained the
same as in 2010, including two US-based non-executive directors and the
previous and present chairmen of the SEEAC. There is cross-membership
with the audit committee, helping to inform discussions at the latter
regarding financial controls and incident-related costs. Frank Bowman
joined the committee in February 2012.
Each meeting of the committee is attended by Lamar McKay,
President and CEO of the GCRO, and by Jack Lynch, chief counsel to the
GCRO. The chairman, group chief executive and group general counsel join
the meeting whenever possible. Meetings also include private sessions
attended by non-executive members only.
Committee role and structure
The purpose of the committee is to provide non-executive oversight of the
GCRO and to support efforts to rebuild trust in BP and BP’s reputation with
a particular focus on the US.
The work of the committee is fully integrated with the work of the
board on reputation, safety, strategy and financial planning, and the board
retains ultimate accountability for oversight of the group’s response to the
incident.
Directors are invited to attend and observe committee meetings.
Committee meeting minutes are circulated to the board, and the
committee chairman provides verbal reports on the committee’s activities
at board meetings.
The committee met 16 times in 2011.
During the course of 2011, the committee has undertaken the
following tasks:
• Oversee and receive regular reports on work undertaken to mitigate the
effects of the oil spill in the Gulf of Mexico area.
• Oversee GCRO’s co-ordinated response programme for affected
communities and states, along with its strategies for managing external
relationships on issues relating to the incident.
• Oversee the legal strategy for litigation and investigations involving the
group arising from the incident or its aftermath.
• Oversee GCRO’s strategy for resolving claims, recognizing the
independent role of the Gulf Coast Claims Facility.
130 BP Annual Report and Form 20-F 2011
Corporate governance • Oversee GCRO’s plans for expenditures and investments on major
projects or matters beyond those included within the established claims
administration processes.
• Oversee management strategy and actions to restore the group’s
Remuneration committee report
The report of the remuneration committee is contained in the Directors’
remuneration report on pages 139 to 151.
reputation in the US.
Committee processes
Information and advice
The committee receives its information from the leadership of the GCRO
and external advisers. Privileged legal briefings are regularly provided by
the group general counsel and chief counsel for the GCRO, who are joined
on occasion in committee meetings by other internal and external legal
counsel.
BP’s internal audit function has conducted reviews of various
GCRO activities and processes, and these have been summarized for
the committee’s review. Primary monitoring of financial risk associated
with GCRO’s activities is undertaken by the audit committee. Safety risks
related to GCRO’s activities are monitored by the SEEAC.
Training and visits
The high frequency of meetings in 2011 has facilitated the committee’s
understanding of the important issues and numerous interdependencies.
Three of these meetings were held in the US and were of extended
duration, providing the opportunity for the committee to interact with
members of the GCRO leadership team.
Committee activities
The committee’s activities have included the following:
• Legal: legal updates from the chief counsel to the GCRO have formed
a significant part of the committee’s agenda, given the breadth and
pace of activities. The committee has overseen the GCRO’s integrated
legal approach, which incorporates all government, civil and criminal
investigations, the Multi-District Litigation, the Natural Resource Damage
Assessment process, and legal aspects of the claims processes. The
committee has overseen the company’s preparation for trial, as well as
the settlements entered into with the other working interest owners
in the Macondo well and with some sub-contractors working on the
development. The committee has continued to monitor engagement
with other responsible parties and contractors.
• Claims: the committee has monitored the status of claims from
individuals and businesses administered by the independent Gulf Coast
Claims Facility; and the status of claims from government entities, which
continue to be administered by BP. Assessments of potential future
claims for provisioning purposes are reviewed by the audit committee.
• Remediation: the committee has received regular updates on the
progress of clean-up and remediation activities. The committee also
monitored discussions with Natural Resource Trustees, with whom
agreement was reached on early restoration projects.
• GCRO controls: the committee oversaw the continued development
of financial controls underpinning the breadth of the GCRO’s complex
tasks. The audit committee remains the primary forum for the oversight
of these controls and associated audits.
BP Annual Report and Form 20-F 2011 131
Corporate governanceCorporate governance Nomination and chairman’s committees reports
Chairman’s introduction
I chair both the nomination and the chairman’s committees. Set out
below are reports on their activities during the year. As in previous years
there is often an overlap between the work of the committees as the
nomination committee may wish to sound out the view of the other
non-executive directors in the chairman’s committee on a particular issue,
such as executive succession or the skills and experience needed for non-
executive directors.
Carl-Henric Svanberg
Chairman
Nomination committee report
Committee members
Carl-Henric Svanberg – committee chair
Antony Burgmans (joined in May 2011)
Cynthia Carroll (joined in May 2011)
Sir William Castell
Ian Davis
Members who left during the year
Douglas Flint (retired 14 April 2011)
DeAnne Julius (retired 14 April 2011)
The committee met five times during 2011.
Committee’s role
The committee identifies, evaluates and recommends candidates for the
appointment or re-appointment as directors and for the appointment of the
company secretary.
The committee keeps the mix of knowledge, skills and experience
of the board under regular review (in consultation with the chairman’s
committee) to ensure an orderly succession of directors. The outside
directorships and broader commitments of the non-executive directors are
also monitored by the nomination committee.
Committee activities
The committee reviewed the independence and roles of each of the
directors prior to recommending them for re-election at the 2011 AGM. It
also discussed the composition of the board and its committees in terms
of service, skills and diversity.
Since the start of 2011, there were changes to the composition of
the board, with Phuthuma Nhleko, Andrew Shilston and Professor Dame
Ann Dowling joining on 1 February 2011, 1 January 2012 and 3 February
2012 respectively. The committee retained the services of external
advisers Egon Zehnder and Odgers to assist with the identification of
potential candidates over the period.
In undertaking its search for potential candidates for board
membership, the committee carried out a review of skills and experience
of existing board members and considered this against the board
succession plan based on tenure and other factors, including diversity.
This process enabled the committee to develop a list of selection criteria
for future appointments, which it then used with its external advisers to
develop a shortlist. Based on this, the committee determined an initial
focus on candidates in the fields of science and technology.
132 BP Annual Report and Form 20-F 2011
An outline of skills for our current board membership is as follows:
Key skills and experience
Oil and gas industry experience
Director
Paul Anderson
Frank Bowman
Antony Burgmans
Cynthia Carroll
Sir William Castell
Safety, technology and risk management
Food and consumer goods; leading a
global business
Oil, gas and extractive industry
experience; leading a global business
Nuclear and medical science industry;
technology
Technology and manufacturing
George David
Strategy, advisory and consulting
Ian Davis
Audit, financial services and trading
Brendan Nelson
Civil engineering, telecoms and banking
Phuthuma Nhleko
Andrew Shilston
Oil and gas industry experience; finance
Professor Dame Ann Dowling Engineering, technology and education
The committee also considered the succession of our chief financial
officer and the skillset and experience needed in light of the role and
the company’s strategy. There was an extensive process in which Egon
Zehnder advised the committee on both internal and external candidates.
The committee made its recommendation to the chairman’s committee,
and CFO succession was then discussed by all the non-executive directors.
It was agreed that Brian Gilvary, previously deputy chief financial officer,
was the preferred candidate and he became CFO on 1 January 2012.
During the year the committee considered the recommendations
of Lord Davies’ report on gender diversity. In line with the report, the
committee agreed to a set of aspirational targets to work towards by 2015
and recommended changes to BP’s board governance principles to include
a policy on board diversity, which emphasizes considerations of diversity,
inclusiveness and meritocracy when considering board composition. The
committee has determined to develop during 2012 a set of measurable
objectives for implementing its board diversity policy on which it will report
back to shareholders.
At the end of the year, the committee undertook its annual
examination of its effectiveness and performance, using an internally
administered questionnaire. As part of its evaluation, the committee
considered its role and its task for the year. The evaluation concluded that
the committee had worked well and had improved its focus on diversity.
Going forward the committee wishes to focus on agenda setting and
papers with a view to improving time management and workload.
Chairman’s committee report
Committee members
Carl-Henric Svanberg – committee chair
Sir William Castell
Paul Anderson
Frank Bowman
Cynthia Carroll
George David
Ian Davis
Professor Dame Ann Dowling (appointed 3 February 2012)
Brendan Nelson
Phuthuma Nhleko (appointed 1 February 2011)
Andrew Shilston (appointed 1 January 2012)
Members who left during the year
Douglas Flint (retired 14 April 2011)
DeAnne Julius (retired 14 April 2011)
The committee met nine times during 2011.
Corporate governance Committee’s role
The committee is comprised of the chairman and all the non-executive
directors.
The main tasks of the committee are:
• Evaluating the performance and effectiveness of the group chief
executive.
• Reviewing the structure and effectiveness of the business organization
of BP.
• Reviewing the systems for senior executive development and
determining the succession plan for the group chief executive, executive
directors and other senior members of executive management.
• Determining any other matter which is appropriate to be considered by
all of the non-executive directors.
• Opining on any matter referred to it by the chairman of any committee
comprised solely of non-executive directors.
Committee activities
The committee held private discussions between the non-executive
directors during the year on key issues for the group, including its strategic
direction, activities in Russia and risk management.
The chairman’s committee worked closely with the nomination
committee in matters around executive and non-executive succession,
in particular the succession of the chief financial officer (CFO) and in
redefining the roles of the CFO and executive director for corporate
business activities. It was agreed that outgoing CFO Byron Grote would
stay on the board as an executive director with responsibility for BP’s
corporate business activities, including its integrated supply and trading
operations, Alternative Energy, shipping, technology and remediation
activities.
The committee evaluated the performance of the group chief
executive at the half year and the full year. It reviewed succession planning
within the group and discussed the structure of the senior executive team.
The outcomes of the main board evaluation were discussed within
the chairman’s committee. The committee also reviewed the skills of the
board and discussed what would be needed to meet the challenges of the
company’s strategy. Issues of governance around committees and their
composition were examined. Led by the senior independent director, the
committee evaluated the performance of the chairman as part of BP’s
annual evaluation programme for the board and its directors.
Facilitated by the senior independent director, the committee met
to discuss an approach to the chairman by the Volvo Group to become
their part-time, non-executive chairman. The discussion was held without
the presence of the chairman and considered the time commitment of this
additional role, given that Carl-Henric Svanberg would be stepping down
from his existing non-executive directorship at Ericsson before taking on
the potential position at Volvo. The committee concluded it was supportive
of the chairman taking on this additional role.
Risk management and internal
control review
In discharging its responsibility for the company’s risk management and
internal control systems under the UK Corporate Governance Code, the
board, through its governance principles, requires the group chief executive
to operate with a comprehensive system of controls and internal audit
to identify and manage the risks that are material to BP. The governance
principles are reviewed periodically by the board and are consistent with
the requirements of the UK Corporate Governance Code including principle
C.2 (risk management and internal control).
The board has an established process by which the effectiveness
of the system of internal control (which includes the risk management
system) is reviewed as required by provision C.2.1 of the UK Corporate
Governance Code. This process enables the board and its committees
to consider the system of internal control being operated for managing
significant risks, including strategic, safety and operational and compliance
and control risks, throughout the year. Material joint ventures and
associates have not been dealt with as part of the group in this process.
As part of this process, the board and the audit, Gulf of Mexico
and safety, ethics and environment assurance committees requested,
received and reviewed reports from executive management, including
management of the business segments, divisions and functions, at their
regular meetings.
In considering the systems, the board noted that such systems are
designed to manage, rather than eliminate, the risk of failure to achieve
business objectives and can only provide reasonable, and not absolute,
assurance against material misstatement or loss.
During the year, the board, through its committees, regularly
reviewed with executive management processes whereby risks are
identified, evaluated and managed. These processes were in place for the
year under review, remain current at the date of this report and accord
with the guidance on the UK Corporate Governance Code provided by the
Financial Reporting Council. In December 2011, the board considered the
group’s significant risks within the context of the annual plan presented by
the group chief executive.
A joint meeting of the audit and safety, ethics and environment
assurance committees in February 2012 reviewed a report from
the general auditor as part of the board’s annual review of the risk
management and internal control systems. The report described the annual
summary of internal audit’s consideration of elements of BP’s system of
internal control over significant risks arising in the categories of strategic,
safety and operational and compliance and control and considered the
control environment for the group. The report also highlighted the results
of audit work conducted during the year and the remedial actions taken by
management in response to significant failings and weaknesses identified.
During the year, these committees engaged with management, the
general auditor and other monitoring and assurance providers (such as the
group ethics and compliance officer, head of safety and operational risk and
the external auditor) on a regular basis to monitor the management of risks.
Significant incidents that occurred and management’s response to them
were considered by the appropriate committee and reported to the board.
Subject to determining any additional appropriate actions arising
from items still in process, the board is satisfied that, where significant
failings or weaknesses in internal controls were identified during the year,
appropriate remedial actions were taken or are being taken.
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 (Turnbull).
BP Annual Report and Form 20-F 2011 133
Corporate governanceCorporate governance Corporate governance practices
Code of ethics
The company has adopted a code of ethics for its group chief executive,
chief financial officer, group controller, general auditor and chief accounting
officer as required by the provisions of Section 406 of the Sarbanes-Oxley
Act of 2002 and the rules issued by the SEC. There have been no waivers
from the code of ethics relating to any officers.
BP also has a code of conduct, which is applicable to all employees.
This was updated (and published) on 1 January 2012.
In the US, BP ADSs are listed on the New York Stock Exchange (NYSE).
The significant differences between BP’s corporate governance practices
as a UK company and those required by NYSE listing standards for US
companies are listed as follows:
Independence
BP has adopted a robust set of board governance principles, which
reflect the UK Corporate Governance Code and its principles-based
approach to corporate governance. As such, the way in which BP makes
determinations of directors’ independence differs from the NYSE rules.
BP’s board governance principles require that all non-executive directors
be determined by the board to be ‘independent in character and judgement and
free from any business or other relationship which could materially interfere
with the exercise of their judgement’. The BP board has determined that, in
its judgement, all of the non-executive directors are independent. In doing so,
however, the board did not explicitly take into consideration the independence
requirements outlined in the NYSE’s listing standards.
Committees
BP has a number of board committees that are broadly comparable in
purpose and composition to those required by NYSE rules for domestic
US companies. For instance, BP has a chairman’s (rather than executive)
committee, nomination (rather than nominating/corporate governance)
committee and remuneration (rather than compensation) committee.
BP also has an audit committee, which NYSE rules require for both US
companies and foreign private issuers. These committees are composed
solely of non-executive directors whom the board has determined to be
independent, in the manner described above.
The BP board governance principles prescribe the composition,
main tasks and requirements of each of the committees (see the board
committee reports). BP has not, therefore, adopted separate charters for
each committee.
Under US securities law and the listing standards of the NYSE,
BP is required to have an audit committee that satisfies the requirements
of Rule 10A-3 under the Exchange Act and Section 303A.06 of the NYSE
Listed Company Manual. BP’s audit committee complies with these
requirements. The BP audit committee does not have direct responsibility
for the appointment, re-appointment or removal of the independent
auditors – instead, it follows the UK Companies Act 2006 by making
recommendations to the board on these matters for it to put forward for
shareholder approval at the AGM.
One of the NYSE’s additional requirements for the audit
committee states that at least one member of the audit committee is to
have ‘accounting or related financial management expertise’. The board
determined that Brendan Nelson possessed such expertise and also
possesses the financial and audit committee experiences set forth in both
the UK Corporate Governance Code and SEC rules (see audit committee
report). Mr Nelson is the audit committee financial expert as defined in
Item 16A of Form 20-F.
Shareholder approval of equity compensation plans
The NYSE rules for US companies require that shareholders must be given
the opportunity to vote on all equity-compensation plans and material
revisions to those plans. BP complies with UK requirements that are
similar to the NYSE rules. The board, however, does not explicitly take
into consideration the NYSE’s detailed definition of what are considered
‘material revisions’.
Code of ethics
The NYSE rules require that US companies adopt and disclose a code of
business conduct and ethics for directors, officers and employees. BP has
adopted a code of conduct, which applies to all employees, and has board
governance principles that address the conduct of directors. In addition
BP has adopted a code of ethics for senior financial officers as required by
the SEC. BP considers that these codes and policies address the matters
specified in the NYSE rules for US companies.
134 BP Annual Report and Form 20-F 2011
Corporate governance The company’s internal control over financial reporting includes policies and
procedures that pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect transactions and dispositions of assets;
provide reasonable assurances that transactions are recorded as necessary
to permit preparation of financial statements in accordance with IFRS
and that receipts and expenditures are being made only in accordance
with authorizations of management and the directors of BP; and provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of BP’s assets that could have
a material effect on our financial statements. BP’s internal control over
financial reporting as of 31 December 2011 has been audited by
Ernst & Young LLP, an independent registered public accounting firm,
as stated in their report appearing on page 177 of this Annual Report and
Form 20-F 2011.
Changes in internal control over financial reporting
There were no changes in the group’s internal controls over financial
reporting that occurred during the period covered by the Form 20-F that
have materially affected or are reasonably likely to materially affect our
internal controls over financial reporting.
Controls and procedures
Evaluation of disclosure controls and procedures
The company maintains ‘disclosure controls and procedures’, as such term
is defined in Exchange Act Rule 13a-15(e), that are designed to ensure
that information required to be disclosed in reports the company files or
submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission rules and forms, and that such information is accumulated
and communicated to management, including the company’s group
chief executive and chief financial officer, as appropriate, to allow timely
decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures,
our management, including the group chief executive and chief financial
officer, recognize that any controls and procedures, no matter how
well designed and operated, can provide only reasonable, not absolute,
assurance that the objectives of the disclosure controls and procedures
are met. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control
issues and instances of fraud, if any, within the company have been
detected. Further, in the design and evaluation of our disclosure controls
and procedures our management necessarily was required to apply its
judgement in evaluating the cost-benefit relationship of possible controls
and procedures. Also, we have investments in certain unconsolidated
entities. As we do not control these entities, our disclosure controls and
procedures with respect to such entities are necessarily substantially
more limited than those we maintain with respect to our consolidated
subsidiaries. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be
detected. The company’s disclosure controls and procedures have been
designed to meet, and management believes that they meet, reasonable
assurance standards.
The company’s management, with the participation of the
company’s group chief executive and chief financial officer, has evaluated
the effectiveness of the company’s disclosure controls and procedures
pursuant to Exchange Act Rule 13a-15(b) as of the end of the period
covered by this annual report. Based on that evaluation, the group chief
executive and chief financial officer have concluded that the company’s
disclosure controls and procedures were effective at a reasonable
assurance level.
Management’s report on internal control over financial reporting
Management of BP is responsible for establishing and maintaining adequate
internal control over financial reporting. BP’s internal control over financial
reporting is a process designed under the supervision of the principal
executive and financial officers to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of BP’s financial
statements for external reporting purposes in accordance with IFRS.
As of the end of the 2011 fiscal year, management conducted an
assessment of the effectiveness of internal control over financial reporting
in accordance with the Internal Control Revised Guidance for Directors on
the Combined Code (Turnbull). Based on this assessment, management
has determined that BP’s internal control over financial reporting as of
31 December 2011 was effective.
BP Annual Report and Form 20-F 2011 135
Corporate governanceCorporate governance Principal accountants’ fees
and services
Memorandum and Articles
of Association
The audit committee has established policies and procedures for the
engagement of the independent registered public accounting firm, Ernst
& Young LLP, to render audit and certain assurance and tax services. The
policies provide for pre-approval by the audit committee of specifically
defined audit, audit-related, tax and other services that are not prohibited
by regulatory or other professional requirements. Ernst & Young are
engaged for these services when its expertise and experience of BP are
important. Most of this work is of an audit nature. Tax services were
awarded either through a full competitive tender process or following an
assessment of the expertise of Ernst & Young relative to that of other
potential service providers. These services are for a fixed term.
Under the policy, pre-approval is given for specific services within
the following categories: advice on accounting, auditing and financial
reporting matters; internal accounting and risk management control
reviews (excluding any services relating to information systems design
and implementation); non-statutory audit; project assurance and advice on
business and accounting process improvement (excluding any services
relating to information systems design and implementation relating to BP’s
financial statements or accounting records); due diligence in connection
with acquisitions, disposals and joint ventures (excluding valuation or
involvement in prospective financial information); income tax and indirect
tax compliance and advisory services; employee tax services (excluding
tax services that could impair independence); provision of, or access
to, Ernst & Young publications, workshops, seminars and other training
materials; provision of reports from data gathered on non-financial policies
and information; and assistance with understanding non-financial regulatory
requirements. BP operates a two-tier system for audit and non-audit
services. For audit related services, the audit committee has a pre-
approved aggregate level, within which specific work may be approved by
management. Non-audit services, including tax services, are pre-approved
for management to authorize per individual engagement, but above a
defined level must be approved by the chairman of the audit committee
or the full committee. The audit committee has delegated to the chairman
of the audit committee authority to approve permitted services provided
that the chairman reports any decisions to the committee at its next
scheduled meeting. Any proposed service not included in the approved
service list must be approved in advance by the audit committee chairman
and reported to the committee, or approved by the full audit committee in
advance of commencement of the engagement.
The audit committee evaluates the performance of the auditors
each year. The audit fees payable to Ernst & Young are reviewed by the
committee in the context of other global companies for cost effectiveness.
The committee keeps under review the scope and results of audit work
and the independence and objectivity of the auditors. External regulation
and BP policy requires the auditors to rotate their lead audit partner every
five years. (See Financial statements – Note 16 on page 209 and Audit
committee report on page 127 for details of audit fees.)
The following summarizes certain provisions of the company’s
Memorandum and Articles of Association and applicable English law. This
summary is qualified in its entirety by reference to the UK Companies Act
2006 (Act) and the company’s Memorandum and Articles of Association.
For information on where investors can obtain copies of the Memorandum
and Articles of Association see Documents on display on page 170.
At the AGM held on 17 April 2008 shareholders voted to adopt new
Articles of Association, largely to take account of changes in UK company
law brought about by the Act. Further amendments to the Articles of
Association were approved by shareholders at the AGM held on 15 April
2010. These amendments reflect the full implementation of the Act,
among other matters.
Objects and purposes
BP is incorporated under the name BP p.l.c. and is registered in England
and Wales with the registered number 102498. The provisions regulating
the operations of the company, known as its ‘objects’, were historically
stated in a company’s memorandum. The Act abolished the need to have
object provisions and so at the AGM held on 15 April 2010 shareholders
approved the removal of its objects clause together with all other
provisions of its Memorandum that, by virtue of the Act, are treated as
forming part of the company’s Articles of Association.
Directors
The business and affairs of BP shall be managed by the directors. The
company’s Articles of Association provide that directors may be appointed
by the existing directors or by the shareholders in a general meeting. Any
person appointed by the directors will hold office only until the next general
meeting and will then be eligible for re-election by the shareholders. There
is no requirement for a director to retire on reaching any age.
The Articles of Association place a general prohibition on a director
voting in respect of any contract or arrangement in which the director has
a material interest other than by virtue of such director’s 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
or any of its subsidiaries.
• Any proposal in which the director is interested, concerning the
underwriting of company securities or debentures or the giving of any
security to a third party for a debt or obligation of the company or any of
its subsidiaries.
• Any proposal concerning any other company in which the director is
interested, directly or indirectly (whether as an officer or shareholder
or otherwise) provided that the director and persons connected with
such director are not the holder or holders of 1% or more of the voting
interest in the shares of such company.
• Any proposal concerning the purchase or maintenance of any insurance
policy under which the director may benefit.
136 BP Annual Report and Form 20-F 2011
Corporate governance The 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 the director’s interest at a meeting of the directors of the company.
The definition of ‘interest’ includes the interests of spouses, children,
companies and trusts. The Act also requires that a director must avoid a
situation where a director has, or could have, a direct or indirect interest
that conflicts, or possibly may conflict, with the company’s interests. The
Act allows directors of public companies to authorize such conflicts where
appropriate, if a company’s Articles of Association so permit. BP’s Articles
of Association permit the authorization of such conflicts. The directors may
exercise all the powers of the company to borrow money, except that the
amount remaining undischarged of all moneys borrowed by the company
shall not, without approval of the shareholders, exceed the amount paid
up on the share capital plus the aggregate of the amount of the capital and
revenue reserves of the company. Variation of the borrowing power of the
board may only be affected by amending the Articles of Association.
Remuneration of non-executive directors shall be determined in the
aggregate by resolution of the shareholders. Remuneration of executive
directors is determined by the remuneration committee. This committee is
made up of non-executive directors only. There is no requirement of share
ownership for a director’s qualification.
Dividend rights; other rights to share in company profits; capital calls
If recommended by the directors of BP, BP shareholders may, by
resolution, declare dividends but no such dividend may be declared in
excess of the amount recommended by the directors. The directors may
also pay interim dividends without obtaining shareholder approval. No
dividend may be paid other than out of profits available for distribution,
as determined under IFRS and the 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.
At the company’s AGM held on 15 April 2010, shareholders
approved the introduction of a Scrip Dividend Programme (Programme) and
to include provisions in the Articles of Association to enable the company
to operate the Programme. The Programme enables ordinary shareholders
and BP ADS holders to elect to receive new fully paid ordinary shares (or
BP ADSs in the case of BP ADS holders) instead of cash. The operation
of the Programme is always subject to the directors’ decision to make
the scrip offer available in respect of any particular dividend. Should the
directors decide not to offer the scrip in respect of any particular dividend,
cash will automatically be paid instead.
Apart from shareholders’ rights to share in BP’s profits by dividend
(if any is declared or announced), 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 the company provide that voting on
resolutions at a shareholders’ meeting will be decided on a poll other than
resolutions of a procedural nature, which may be decided on a show of
hands. If voting is on a poll, every shareholder who is present in person
or by proxy has one vote for every ordinary share held and two votes for
every £5 in nominal amount of BP preference shares held. If voting is
on a show of hands, each shareholder who is present at the meeting in
person or whose duly appointed proxy is present in person will have one
vote, regardless of the number of shares held, unless a poll is requested.
Shareholders do not have cumulative voting rights.
Holders of record of ordinary shares may appoint a proxy, including
a beneficial owner of those shares, to attend, speak and vote on their
behalf at any shareholders’ meeting.
Record holders of BP ADSs are also entitled to attend, speak
and vote at any shareholders’ meeting of BP by the appointment by the
approved depositary, JPMorgan Chase Bank N.A., of them as proxies in
respect of the ordinary shares represented by their ADSs. Each such proxy
may also appoint a proxy. Alternatively, holders of BP ADSs are entitled to
vote by supplying their voting instructions to the depositary, who will vote
the ordinary shares represented by their ADSs in accordance with their
instructions.
Proxies may be delivered electronically.
Matters are transacted at shareholders’ meetings by the proposing
and passing of resolutions, of which there are two types: ordinary or
special. An annual general meeting must be held once in every year.
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.
A special resolution requires the affirmative vote of not less than three-
fourths of the persons voting at a meeting at which there is a quorum. Any
AGM requires 21 days’ notice. The notice period for a general meeting is
14 days subject to the company obtaining annual shareholder approval,
failing which, a 21-day notice period will apply.
Liquidation rights; redemption provisions
In the event of a liquidation of BP, after payment of all liabilities and
applicable deductions under UK laws and subject to the payment of
secured creditors, the holders of BP preference shares would be entitled
to the sum of (i) the capital paid up on such shares plus, (ii) accrued and
unpaid dividends and (iii) a premium equal to the higher of (a) 10% of the
capital paid up on the BP preference shares and (b) the excess of the
average market price over par value of such shares on the LSE during the
previous six months. The remaining assets (if any) would be divided pro
rata among the holders of ordinary shares.
Without prejudice to any special rights previously conferred on
the holders of any class of shares, BP may issue any share with such
preferred, deferred or other special rights, or subject to such restrictions as
the shareholders by resolution determine (or, in the absence of any such
resolutions, by determination of the directors), and may issue shares that
are to be or may be redeemed.
Variation of rights
The rights attached to any class of shares may be varied with the consent
in writing of holders of 75% of the shares of that class or on the adoption
of a special 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.
BP Annual Report and Form 20-F 2011 137
Corporate governanceCorporate governance Shareholders’ meetings and notices
Shareholders must provide BP with a postal or electronic address in the
UK to be entitled to receive notice of shareholders’ meetings. 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 on page 137 under the heading Voting rights.
Under the Act, the AGM of shareholders must be held within
the six-month period once every year. All general meetings shall be held
at a time and place determined by the directors within the UK. If any
shareholders’ meeting is adjourned for lack of quorum, notice of the time
and place of the meeting may be given in any lawful manner, including
electronically. Powers exist for action to be taken either before or at the
meeting by authorized officers to ensure its orderly conduct and safety of
those attending.
Limitations on voting and shareholding
There are no limitations imposed by English law or the company’s
Memorandum or Articles of Association on the right of non-residents or
foreign persons to hold or vote the company’s ordinary shares or BP ADSs,
other than limitations that would generally apply to all of the shareholders.
Disclosure of interests in shares
The Act permits a public company to give notice to any person whom the
company believes to be or, at any time during the three years prior to the
issue of the notice, to have been interested in its voting shares requiring
them 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.
138 BP Annual Report and Form 20-F 2011
Corporate governance Directors’ remuneration report
Remuneration is directly linked to
strategy, strongly performance related and
weighted heavily towards the long term.
140 Remuneration overview
140 Chairman’s letter
140 Summary of remuneration components
141 Summary of remuneration in 2011
142 Executive directors’ remuneration
142 Remuneration committee
142 Executive directors’ remuneration 2011
144 Remuneration policy
146 Remuneration policy for 2012 in more depth
148 Pensions
149 Share plans in detail
150 Service contracts and external appointments
151 Non-executive directors’ remuneration
BP Annual Report and Form 20-F 2011 139
BP Annual Report and Form 20-F 2011 00 Directors’ remuneration report Remuneration overview
Dear shareholder,
For the senior executives of BP, remuneration is directly linked to strategy,
strongly performance related and heavily weighted towards the long term.
In a year of consolidation following the events of 2010, the company
achieved a creditable performance overall in 2011. The outcome of the
various plans that make up 2011 total remuneration for executive directors
is set out in the table opposite.
The remuneration committee is keenly aware of its responsibility to
balance sometimes conflicting perspectives in making judgements on
senior executive pay. We recognize a concern by government, and society
at large, of excess in this area, but cannot ignore the reality of a global
competitive market for top executive talent. We respect investors’
expectation for pay to be strongly tied to performance while also wanting
to ensure that executives receive fair reward for their achievements.
The committee’s commitment to exercising judgement in a
balanced way and being transparent in communicating its conclusions
continues. In years where performance has been strong, bonuses have
reflected that and when performance has been poor, bonuses have
appropriately been reduced and even in some cases, as in 2010,
eliminated. The long-term plan has, over the last five years, vested less
than 10% of the possible shares, reflecting the impact of major incidents.
In this context, the committee carefully considered 2011
performance against targets set at the start of the year. Safety and risk
management metrics were all met or exceeded including recordable injury
frequency, loss of primary containment, implementation of change
programmes and capability building. Group results were at or near target
for financial metrics, including replacement cost profit, cash costs,
upstream operating cash and downstream profitability. External survey
results show some modest recovery in the company’s external reputation,
as well as good results on internal employee morale. The overall
assessment of group results based on the above was judged to be
‘on-target’ for the group as a whole.
Bob Dudley’s bonus was based entirely on group results, resulting in an
amount, including the deferred element, at ‘on-target’ level. Iain Conn’s and
Byron Grote’s bonuses were based 70% on group results and 30% on
their respective business or functional units. Mr Conn’s results met or
exceeded targets resulting in a bonus just above ‘on-target’, and Dr Grote’s
largely met resulting in an ‘on-target’ bonus. In all cases one-third of their
bonus is deferred into shares on a mandatory basis, matched, and will vest
in three years subject to a review of safety and environmental sustainability
during the period. They may elect to defer an additional one-third into shares
on the same basis as the mandatory deferral, which they all chose to do for
this year’s bonus. All of the above is reflected in the table opposite.
The 2009-2011 share element included performance conditions
relating to total shareholder return, production growth, group net income,
and Refining and Marketing profitability – all relative to the other oil majors.
Of these all but Refining and Marketing profitability missed the level
required to vest. Refining and Marketing profitability compared to the other
oil majors was strong, and based on this, the overall vesting was 16.67%
of the shares – again reflected in the table opposite. The committee
concluded that the result from a straight numerical assessment relative to
agreed metrics provided an appropriate vesting level in light of overall
company performance during the period.
For 2012 the overall policy for executive directors will remain largely
unchanged, as summarized below. The committee will continue to monitor
trends and external perspectives in reviewing the quantum and structure of
total remuneration. It will also continue to operate with independence and
rigour in making its judgements. Ultimately decisions will be guided by our
commitment to both shareholder interests and executive engagement.
Antony Burgmans, KBE
Chairman of the remuneration committee
6 March 2012
Summary of remuneration components
Salary
Bonus
Deferred bonus
and match
• Salaries as at 1 January 2012 are: Bob Dudley $1,700,000, Iain Conn £730,000, Brian Gilvary £690,000 and Byron Grote
$1,442,000.
• On-target bonus of 150% of salary and maximum of 225% of salary based on performance relative to targets set at
start of year relating to financial and operational metrics.
• One-third of actual bonus awarded as shares with three-year deferral and the ability to voluntarily defer an additional
one-third.
• All deferred shares matched one-for-one, with vesting of both subject to an assessment of safety and environmental
sustainability over the three-year period.
Performance shares
Pension
• Award of shares of up to 5.5 times salary for group chief executive, and 4 times for other executive directors.
• Vesting after three years based on performance relative to other oil majors and strategic imperatives.
• Three-year retention period after vesting before release of shares.
• Final salary scheme appropriate to home country of executive.
140 BP Annual Report and Form 20-F 2011
Directors’ remuneration report Summary of remuneration of executive directors in 2011 (audited)
Annual remuneration
Salary
R W Dudley
2011
2010
2011
I C Conn
2010
Dr B E Grote
2011
2010
$1,700,000a
$1,175,000
£720,000
£690,000
$1,426,500
$1,380,000
Annual cash performance bonus b
$850,000
0
£396,000
£207,000
$713,250
$207,000
Other emoluments
$66,000
$564,000c
£227,500d
£34,000
$15,000
$10,000
Total
Vested equitye
$2,616,000
$1,739,000
£1,343,500
£931,000
$2,154,750
$1,597,000
Performance share element plan period
2009-2011
2008-2010
2009-2011
2008-2010
2009-2011
2008-2010
Vesting date
Shares vestedf
Value
Conditional equitye
Feb 2012
Feb 2011
Feb 2012
Feb 2011
Feb 2012
Feb 2011
101,735
$788,300
0
0
149,259
155,695g
187,193
£743,300
£764,000
$1,450,400
0
0
Deferred bonus in respect of bonus year h
2011
2010
2011
2010
2011
2010
Vesting date
Feb 2015
Feb 2014
Feb 2015
Feb 2014
Feb 2015
Feb 2014
Mandatory shares (including one-for-one match)
Voluntary shares (including one-for-one match)
218,412
218,412
0
0
161,304
161,304
42,768
0
183,276
183,276
53,208
53,208
Performance share element
2011-2013
2010-2012
2011-2013
2010-2012
2011-2013
2010-2012
Vesting date
Feb 2014
Feb 2013
Feb 2014
Feb 2013
Feb 2014
Feb 2013
Potential maximum shares
1,330,332
581,084
623,025
656,813
785,394
801,894
Amounts shown are in the currency received by executive directors. Annual bonuses are shown in the year they were earned.
a Increase in salary for Mr Dudley relates to his appointment to group chief executive in October 2010.
b This reflects the amount of total bonus paid in cash with the deferred bonus as set out in the conditional equity section.
c This amount includes costs of London accommodation and any tax liability thereon that ceased at the end of 2010 following Mr Dudley’s appointment as group chief executive.
d As for all employees affected by the new UK pension tax limits and who wished to remain within these limits, with effect from April 2011, Mr Conn received a cash supplement of 35% of basic salary in
lieu of future service pension accrual amounting to £191,625.
e Mr Dudley and Dr Grote hold shares in the form of ADSs. The above numbers reflect calculated equivalent in ordinary shares.
f Represents vesting of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes re-invested dividends on the shares vested. The
market price of ordinary shares on 14 February 2012 was £4.98 and for ADSs was $46.49.
g There was no vesting under the performance share element. The shares that vested in February 2011 for Mr Conn pertained to a separate restricted award made in 2008.
h It is anticipated that the 2011 deferred bonus award will be made in early March 2012. The number of deferred shares is calculated using the three-day average share price following the full-year result
announcement which was £4.84/share and $46.68/ADS in February 2011 and £4.91/share and $46.70/ADS in February 2012. Both deferred and matched shares are subject to a safety and environmental
hurdle over the three-year deferral period.
Historical TSR performance
Remuneration of non-executive directors in 2011 (audited)
FTSE 100
BP
£200
£150
£100
£50
i
l
g
n
d
o
h
0
0
1
£
l
a
c
i
t
e
h
t
o
p
y
h
f
o
e
u
a
V
l
C-H Svanberg
P M Anderson
F L Bowman
A Burgmans
C B Carroll
Sir William Castell
G David
I E L Davis
B R Nelson
F P Nhlekob
Directors leaving the board in 2011
D J Flint
Dr D S Julius
2011
750
128
120
100
85
168
128a
160
103
113
35
32c
£ thousand
2010
750
118
17
90
90
147
135
69
17
–
108
100
06
07
08
09
10
11
This graph shows the growth in value of a hypothetical £100 holding in
BP p.l.c. ordinary shares over five years, relative to the FTSE 100 Index
(of which the company is a constituent). The values of the hypothetical
£100 holdings at the end of the five-year period were £96.37 and
£105.95 respectively.
a In addition, George David received a £28,000 fee for chairing the BP technical advisory council.
b Appointed on 1 February 2011.
c This figure excludes a superannuation gratuity of £1,543.
While fees were held at 2010 levels, in 2011 actual fees paid to
non-executive directors were affected by changes in committee
membership and the number of intercontinental meetings for which an
attendance allowance was paid.
BP Annual Report and Form 20-F 2011 141
Directors’ remuneration reportDirectors’ remuneration report
Executive directors’ remuneration
Remuneration committee
During the year the committee met seven times, and was made up of the
following independent non-executive directors:
Mr Antony Burgmans (chairman from 2011 Annual General Meeting (AGM))
Mr George David
Mr Ian Davis
Dr DeAnne Julius was chairman of the committee until her retirement at
the 2011 AGM. Mr Svanberg has attended all meetings.
The group chief executive is consulted on matters relating to the other
executive directors and senior executives who report to him and on
matters relating to the performance of the company; neither he nor the
chairman of the board participate in decisions on their own remuneration.
The committee’s tasks are set out in the board governance principles:
• 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 schemes of which the executive directors are
members.
• To nominate, on behalf of the board, any trustees (or directors of
corporate trustees) of such schemes.
• To review and approve the policies and actions being applied by the
group chief executive in remunerating senior executives other than
executive directors to ensure alignment and proportionality.
Executive directors’ remuneration 2011
This section contains detail on executive directors’ remuneration including
salary, annual bonus and deferred bonus relating to 2011 and the share
element for the performance period 2009-2011.
Salary
Mr Dudley’s current salary of $1,700,000 was unchanged during 2011.
As reported in last year’s remuneration report, Mr Conn’s and Dr Grote’s
salaries were increased in April 2011 to £730,000 and $1,442,000
respectively, their first increase since 2008.
Annual bonus
Framework
All executive directors were eligible for an overall annual bonus, including
deferral, of 150% of salary at target and a maximum of 225% of salary.
Mr Dudley’s annual bonus was based entirely on group results and
Mr Conn’s and Dr Grote’s based 70% on group results and 30% on their
respective segment and function.
Measures and targets for the annual bonus were set at the start of
the year and were derived from the company’s annual plan which, in turn,
reflected its strategic priorities of reinforcing safety and risk management,
rebuilding trust and reinforcing value creation. Targets are set so that
meeting plan equates to on-target bonus.
At group level, the safety and risk management component
included targets for recordable injury frequency, loss of primary
containment and implementation of change programmes. Rebuilding trust
was focused on external reputation as measured by external surveys and
internal morale as measured by surveys. Finally, the value component
included measures for underlying replacement cost profit, total cash
costs, upstream operating cash and downstream profitability.
• To recommend to the board the quantum and structure of remuneration
Mr Conn’s Refining and Marketing segment similarly included
for the chairman of the board.
The committee operates with a high level of independence. The board
considers all committee members to be independent (see page 121). They
have no personal financial interest, other than as shareholders, in the
committee’s decisions. Each member of the remuneration committee is
subject to annual re-election as a director of the company.
Gerrit Aronson, an independent consultant, is the committee’s
independent adviser as well as secretary. He is engaged directly by the
committee and not by executive management. Advice is also received
from David Jackson, the company secretary, and from the company
secretary’s office, which is independent of executive management and
reports to the chairman of the board.
The committee also appoints external advisers to provide specialist advice
and services on particular remuneration matters. The independence of
the advice is subject to periodic review. In 2011, the committee continued
to engage Towers Watson as its principal external adviser, primarily for
market information. Towers Watson also provided other remuneration and
benefits advice to parts of the group. Freshfields Bruckhaus Deringer LLP
provided legal advice on specific matters to the committee, as well as
providing some legal advice to the group.
The committee values its dialogue with major shareholders
on remuneration matters. 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.
targets for various safety measures, onstream availability, cost efficiency
and profitability. Dr Grote’s functional segment included measures for IST
compliance, succession and divestments.
Apart from the specific measures set out, the committee may
consider any other results that it deems relevant and apply its judgement
in determining final bonus scores.
Results
Outcomes for the year are summarized in the table below, with a more
detailed explanation following.
2011 bonus measures and outcomes
Key measures for 2011 bonus
Below target
On target
Better than
target
Safety and risk management
Recordable injury frequency
Loss of primary containment
Implementation of change
programmes
Retaining and building capability
Rebuilding trust
External reputation
Internal alignment and morale
Restoring value
Underlying replacement cost profit
Total cash costs
Upstream operating cash
Refining and Marketing profitability
142 BP Annual Report and Form 20-F 2011
Directors’ remuneration report Safety and risk management performance was strong with most targets
exceeded. Loss of primary containment showed a 14% reduction on
the number of incidents that occurred in the previous year and process
safety related high potential incidents dropped 26% – both metrics
are important indicators of process safety performance. Recordable
injury frequency was better than target. A major change programme
related to safety and risk management progressed very well. A central
part of this was the completed implementation of the safety and
operational risk function as a group-wide organization independent of line
management. The change programme also included a major upstream
reorganization, the introduction of a contractor management process,
global rollout of a values and behaviours charter, implementation of a new
individual performance and reward framework and completion of a risk
management review.
Rebuilding trust showed some early signs of improvement but
with clear work remaining to be done related to the long-term impact
of the Deepwater Horizon oil spill. Independent external surveys
reflect some recovery of trust and reputation in key markets as the
year progressed. Internal employee alignment and morale remained
encouragingly strong through a difficult period for the company. Employee
satisfaction, as measured by survey, was near pre-Deepwater Horizon
levels and a new ‘progress index’ was implemented to track specific
employee alignment related to the company’s strategic priorities.
Rebuilding value measures were at or near target. Relative to
target, underlying replacement cost profit was around 90% and total cash
costs were 7% above. Upstream operating cash was some 3% better
than target and Refining and Marketing profitability met its plan level.
Refining and Marketing had a strong year overall with record earnings,
good safety, and high utilization availability.
Based on these results, the committee assessed group
performance to be on-target. Mr Dudley therefore received a total bonus
of 150% of salary including deferral, reflecting on-target performance.
Mr Conn’s total bonus of 165% of salary reflected achievements above
target for the Refining and Marketing segment. Dr Grote’s total bonus of
150% of salary reflects on-target results at both group and function level.
Of the total bonuses referred to above, one-third is paid in cash,
one-third is deferred on a mandatory basis and one-third is paid either
in cash or voluntarily deferred at the individual’s discretion. Amounts, as
received by the individuals, are shown in the table on page 141.
Deferred bonus
One-third of the total bonus awarded to the executive directors is deferred
into shares on a mandatory basis under the terms of the deferred bonus
element. Their deferred shares are matched on a one-for-one basis
and will vest in three years contingent on an assessment of safety and
environmental sustainability over the three-year deferral period.
Individuals may elect to defer an additional one-third into shares
on the same basis as the mandatory deferral. All three executive directors
chose to participate in the voluntary deferral. Again this is reflected in the
table on page 141.
All deferred bonuses will be converted to shares based on the
average price of BP shares over the three days following the company’s
announcement of 2011 results (£4.91/share, $46.70/ADS).
2009-2011 share element
Framework
Performance shares were awarded to each executive director in early
2009 with vesting after three years dependent on performance relative
to measures reflecting the company’s strategic priorities at the time. For
the 2009 plan, vesting was based 50% on total shareholder return (TSR)
versus the oil majors, and 50% on a balanced scorecard of underlying
performance factors versus the same peers. The underlying performance
factors were production growth, Refining and Marketing profitability, and
underlying net income growth. The peer group included ExxonMobil,
Shell, Total, Chevron and ConocoPhillips. Vesting was set at 100%, 70%
and 35% for performance equivalent to first, second, and third rank
respectively and none for fourth or fifth place.
Results
Reflecting the impact of the Deepwater Horizon oil spill, the TSR,
production growth and net income growth measures for the three-year
period 2009-2011 were all below the third place required for vesting.
Refining and Marketing profitability was strong and based on a first
place ranking achieved full vesting for that portion. Based on the agreed
formula, this resulted in a vesting of 16.67% of the original award.
The committee considered this result was a fair reflection of
overall performance over the period. The resulting shares and value of the
vesting is shown in the table on page 149.
2011 total remuneration outcomes
The charts below summarize the actual total remuneration outcome of
2011 for each of the executive directors.
The salary is the amount actually received during the year and
the cash bonus reflects the portion of total bonus for 2011 that is
received in cash.
The deferred bonus reflects that portion of total bonus for 2011
that is deferred, either on a mandatory or voluntary basis. The value
shown is converted to shares, matched one-for-one and vests after three
years contingent on the review of safety and environmental sustainability
over the three years.
Finally the share element portion reflects the value of the vesting
that occurred for the 2009-2011 plan. These shares now enter a further
three-year retention period before they are released to the individual.
2011 total remuneration outcomes
R W Dudley
Salary
Cash bonus
Deferred bonus (before match)
Share element vesting
$688
thousand
$1,700
I C Conn
Salary
Cash bonus
Deferred bonus (before match)
Share element vesting
Dr B E Grote
Salary
Cash bonus
Deferred bonus (before match)
Share element vesting
$1,700
$850
£626
£720
£792
£396
$1,267
$1,427
$1,427
$713
BP Annual Report and Form 20-F 2011 143
Directors’ remuneration reportDirectors’ remuneration report Remuneration policy
This section provides information on principles underlying the company’s
remuneration policy followed by an overview and an in-depth review of
the policy.
Remuneration principles
Remuneration policy for executive directors is guided by key principles:
• Link to strategy – A substantial portion of executive remuneration
should be linked to success in implementing the company’s business
strategy.
• Performance linked – The major part of total remuneration should vary
with performance, with the largest elements share based, further
aligning interests with shareholders.
• Long-term based – The structure of pay should reflect the long-term
nature of BP’s business and the significance of safety and
environmental risks.
• Rigorous process – Performance conditions for variable pay should be
set by the committee at the start of each year and assessed by the
committee at the end of each performance period. Assessment should
take into account material changes in the market environment
(predominantly oil prices) and BP’s competitive position (primarily
vis-à-vis other oil majors).
The chart below shows the range of results possible for the group chief
executive depending on performance outcomes.
The on-target column assumes one-third of total bonus is deferred
and matched, and the share element is valued at half the award.
The maximum column assumes that two-thirds of the total bonus
is deferred and matched, and full vesting of the share element.
Range of pay outcomes based on performance
1,200
1,000
Share element
Deferred bonus including matching
Cash bonus received after deferral
Salary
y
r
a
a
s
l
f
o
%
800
600
400
200
Minimum
On-target
Maximum
• Informed judgement – There should be both quantitative and qualitative
assessments of performance with the committee making an informed
judgement within a framework approved by shareholders.
Remuneration is strongly performance dependent:
• Bonus based on metrics from annual plan.
• Deferred bonus vesting based on additional safety and environment
sustainability assessment.
• Share element based on metrics reflecting strategic priorities.
It is also heavily weighted towards the long term:
• Deferred bonus – three years.
• Share element – six years.
• Fair treatment – The committee reviews the pay policy and levels for
executives below board, as well as pay and conditions of employees
throughout the group. These are considered when determining
executive directors’ remuneration. Salaries should be reviewed annually,
in the context of the total quantum of pay, and taking into account both
external market and internal company conditions.
• Personal shareholding – Executives should develop and be required to
hold a significant shareholding as this represents the best way to align
their interests with those of shareholders.
• Shareholder engagement – The remuneration committee will actively
seek to understand shareholder preferences and be transparent in
explaining its remuneration policy and practices.
These principles result in a remuneration policy that is directly linked to
strategy, strongly performance related and heavily weighted towards long
term.
144 BP Annual Report and Form 20-F 2011
Directors’ remuneration report
Remuneration policy overview
Component
Salary
Policy
Base salaries should be competitive relative to relevant market
peer groups.
2012 application
Peer group for executive directors includes large European
multinationals and the oil majors.
Pension and other
benefits
Executive directors should participate in the normal pension and
benefit schemes applying in their home countries.
Both UK and US executive directors remain on defined benefit
pension plans reflecting respective national norms. UK
directors, as for all UK employees who exceed the annual
allowance set by legislation, may receive a cash supplement in
lieu of future service pension accrual.
Variable remuneration
Annual bonus
Annual bonus should be based on performance relative to
measures and targets reflecting the annual plan.
Bonus measures for 2012 are:
• Safety and risk management (30%).
Achieving plan results should equate to on-target bonus.
On-target bonus is set at 150% of salary for executive directors
with a maximum of 225% of salary.
–
–
–
Recordable injury frequency.
Loss of primary containment.
Process safety related major incident announcements
and high potential incidents.
• Rebuilding trust (20%).
External reputation.
Internal morale and alignment.
–
–
• Value creation (50%).
Total cash costs.
– Operating cash flow.
– Underlying replacement cost profit.
–
– Gearing.
– Divestments.
– Upstream production efficiency.
– Upstream major project delivery.
–
Refining and Marketing net income per barrel.
Deferred bonus
A portion of annual bonus should be paid in shares and deferred
to add long-term sustainability and shareholder alignment to
short-term performance achievement.
One-third of annual bonus is deferred on a mandatory basis and
a further one-third can be deferred on a voluntary basis.
Performance
shares
A large portion of total remuneration for executive directors
should be tied to the long-term performance of the company.
Shares to a value of 5.5 times salary for the group chief
executive and 4 times salary for the other executive directors
are normally awarded annually.
Vesting of the shares after three years is dependent on
performance relative to measures reflecting the strategic
priorities of the company.
Those shares that vest are held for an additional three-year
retention period, after payment of tax on vesting.
Executive directors should develop significant personal
shareholding in order to align their interests with shareholders.
Personal
shareholding
in BP
All deferred shares are matched on a one-for-one basis.
All deferred and matched shares vest after three years
contingent on an assessment of safety and environmental
sustainability over the three-year deferral period.
The 2012-2014 share element will vest based equally on the
following three performance metrics:
• Total shareholder return versus oil majors.
• Operating cash flow.
• Strategic imperatives.
–
–
–
Reserves replacement versus oil majors.
Process safety.
Rebuilding trust.
Executive directors are required to develop, and maintain, a
shareholding equivalent to five times salary, within a reasonable
time of appointment.
BP Annual Report and Form 20-F 2011 145
Directors’ remuneration reportDirectors’ remuneration report In all cases, targets for each measure are set so that achieving plan
levels of performance equates to an on-target bonus. As in past years,
in addition to the specific bonus metrics, the committee will also review
the underlying performance of the group in light of competitors’ results,
analysts’ reports and the views of the chairmen of the other committees.
Based on this broader view, the committee can decide to adjust bonuses
where it is warranted and, in exceptional circumstances, to pay no
bonuses.
Deferred bonus
The structure of deferred bonus, paid in shares, places increased focus
on long-term alignment with shareholders, and reinforces the critical
importance of maintaining high safety and environmental standards. It
effectively translates the outcome of a portion of the annual performance
bonus into a long-term plan with additional performance hurdles. As
shown below, the results of 2012 will form the basis for determining the
deferred bonus in 2013.
Timeline for 2012 deferred bonus
Result of
Result of
annual
annual
performance
performance
2012
Performance period
Deferral
Deferral
2013
2014
2015
Vesting
Vesting
2016
For 2012, as last year, one-third of the annual bonus will be deferred
into shares for three years and matched by the company on a one-for-
one basis. Under the rules of the plan, the average share price over
the three days following announcement of full-year results is used to
determine the number of shares. Both deferred and matched shares
will vest in February 2016 contingent on an assessment of safety and
environmental sustainability over the three-year deferral period. If the
committee assesses that there has been a material deterioration in safety
and environmental metrics, or there have been major incidents revealing
underlying weaknesses in safety and environmental management, then it
may conclude that shares should vest in part, or not at all. In reaching its
conclusion, the committee will obtain advice from the safety, ethics and
environment assurance committee (SEEAC).
Executive directors may voluntarily defer a further one-third of their
annual bonus into shares, which will be capable of vesting, and will qualify
for matching, on the same basis as set out above. Where shares vest,
the executive director will also receive additional shares representing the
value of the re-invested dividends.
Performance shares
The performance share element reflects the committee’s policy that a
large proportion of total remuneration is tied to long-term performance.
Performance shares are awarded at the start of each year and vesting,
after three years, is based on performance relative to measures and
targets derived from the company’s strategic priorities. Those shares
that vest are then held for a further three-year retention period before
being released to the executive after payment of tax on vesting.
This gives executive directors a six-year incentive structure, which is
designed to ensure their interests are aligned with those of shareholders.
Where shares vest, the executive director will receive additional shares
representing the value of the re-invested dividends.
Timeline for 2012-2014 share element
Performance period
Retention period
Award
Award
2012
2013
2014
2015
2016
2017
2018
Vesting
Vesting
Release
Release
Remuneration policy for 2012 in more depth
This section contains a more detailed explanation of the components of
total remuneration for executive directors and how they will be
implemented in 2012.
Salary
The committee normally reviews salaries annually, taking into account
other large Europe-based global companies, other oil majors, and relevant
US companies. It also considers salary treatment throughout the company
when determining appropriate increases for executive directors.
Annual bonus
The group strategy provides the context for the company’s annual plan,
from which measures and targets are derived at the start of the year for
senior managers including executive directors. Measures typically include
a range of financial and operating metrics as well as those relating to
safety and environment, and people.
At the end of each year, performance is assessed relative to the
measures and targets established at the start of the year, adjusted for any
material changes in the market environment (predominantly oil prices).
Assessment includes both quantitative and qualitative views as well as
input from the other committees on relevant aspects. The committee
considers that this informed judgement is important to establishing a fair
overall assessment.
The chart below shows the average annual bonus result (before
any deferral) and relative to an on-target level for executive directors for
the current year and previous five.
History of annual bonus results
200
150
100
50
t
e
g
r
a
t
f
o
%
2006
2007
2008
2009
2010
2011
on-target
average actual result
For 2012, all executive directors will again be eligible for a total bonus
(including deferral) of 150% of salary at target and 225% at maximum.
Mr Dudley’s bonus will be based entirely on group measures. Mr Conn,
Dr Gilvary and Dr Grote will have 70% of their bonus based on group
results and 30% on their respective segment or function.
The measures used to determine bonus results flow directly from
the group’s annual plan which reflects the strategic priorities of reinforcing
safety and risk management, rebuilding trust, and reinforcing value
creation.
At group level, safety and risk management measures include
recordable injury frequency, loss of primary containment and process
related major incident announcements and high potential incidents.
Rebuilding trust will be measured via surveys to assess both external
reputation and internal staff alignment and morale. Restoring value will
provide the dominant set of measures and include operating cash flow,
underlying replacement cost profit, total cash costs, gearing, divestments,
upstream production efficiency, major project delivery and Refining and
Marketing profitability.
The Refining and Marketing segment will include specific safety
metrics for the segment. Value metrics will include availability, efficiency,
and profitability metrics, as well as divestments and major project
delivery. Finance function measures will include divestments, gearing
and major project delivery. The corporate business function will include
profitability and compliance measures for IST and Alternative Energy.
146 BP Annual Report and Form 20-F 2011
Directors’ remuneration report
The maximum number of shares that can be awarded will be 5.5 times
salary for the group chief executive and 4 times salary for the other
executive directors. Performance shares will only vest to the extent that
performance conditions, as described below, are met and subject to the
committee concluding that this is appropriate. The history of vesting of
the share element is shown below.
History of share element vesting
100
d
e
t
s
e
v
m
u
m
x
a
m
i
f
o
%
80
60
40
20
2004-2006
2005-2007
2006-2008
2007-2009
2008-2010
2009-2011
Performance conditions
Performance conditions for the 2012-2014 share element will be aligned
with the company’s strategic agenda which continues to focus on value
creation, reinforcing safety and risk management, and rebuilding trust.
Vesting of shares will be based one-third on BP’s total shareholder return
(TSR) compared to the other oil majors, reflecting the central importance
of restoring the value of the company. A further one-third will be based
on the operating cash flow of the company, reflecting a central element
of value creation. The final one-third will be based on a set of strategic
imperatives; in particular, reserves replacement, process safety, and
rebuilding trust.
For the relative measures, TSR and the reserves replacement ratio,
the comparator group will consist of ExxonMobil, Shell, Total and Chevron.
This group can be altered if circumstances change, for example, if there is
significant consolidation in the industry. While a narrow group, it continues
to represent the comparators that both shareholders and management
use in assessing relative performance.
The TSR will be calculated as the share price performance over
the three-year period, assuming dividends are re-invested. All share prices
will be averaged over the three-month period before the beginning and
end of the performance period. They will be measured in US dollars.
The reserves replacement ratio is defined according to industry standard
specifications and its calculation is audited. As in previous years, the
methodology used for the relative measures will rank each of the five
oil majors on each measure. Performance shares for each component
will vest at levels of 100%, 70% and 35% respectively, for performance
equivalent to first, second and third rank. No shares will vest for fourth or
fifth place.
Operating cash flow has been identified as a core strategic priority
of the company. As has been communicated publicly, the target is to
grow operating cash flow to $33 billion by 2014 based on $100/bbl oil
price assumption. Below $31 billion, there will be no vesting under this
component. Between $31 billion and $35 billion there will be a straight
line vesting from 60% to 100% respectively.
Finally the remaining strategic imperatives relating to process
safety and rebuilding trust will be determined by a mixture of internal
targets and external assessment. In the case of process safety, high
potential incidents and major incident announcements will provide
the key factual data as well as the input of the SEEAC. The rebuilding
trust component will include both external and internal surveys that
will be used by the committee, along with input from the other board
committees, to judge performance. The results will be explained in
subsequent directors’ remuneration reports.
The committee considers that this combination of quantitative
and qualitative measures reflects the long-term value creation priorities of
the company as well as the key underpinnings for business sustainability.
As in previous years, the committee may exercise its discretion, in a
reasonable and informed manner, to adjust vesting levels upwards or
downwards if it concludes that the formulaic approach does not reflect
the true underlying health and performance of BP’s business relative to its
peers. It will explain any adjustments in the directors’ remuneration report
following vesting, in line with its commitment to transparency.
Shareholding policy
The committee’s policy, reflected in the Executive Directors’ Incentive
Plan (EDIP), continues to be that each executive director builds and
maintains a significant personal shareholding in BP to create strong
alignment with shareholders. Executive directors, under the policy, are
required to build a share base equating to five times salary, within a
reasonable time from their appointment. Each director’s shareholding as
at 31 December 2011 is set out on page 117.
BP Annual Report and Form 20-F 2011 147
Directors’ remuneration reportDirectors’ remuneration report
Pensions
Executive directors are eligible to participate in the appropriate pension
schemes applying in their home countries. Details are set out in the
table below.
UK directors
UK directors are members of the regular BP pension scheme. The core
benefits under this scheme are non-contributory. They include a pension
accrual of 1/60th of basic salary for each year of service, up to a maximum
of two-thirds of final basic salary and a dependant’s benefit of two-thirds of
the member’s pension. The scheme pension is not integrated with state
pension benefits.
The rules of the BP pension scheme were amended in 2006 such
that the normal retirement age is 65. Prior to 1 December 2006, scheme
members could retire on or after age 60 without reduction. Special early
retirement terms apply to pre-1 December 2006 service for members with
long service as at 1 December 2006.
Until the end of March 2011, pension benefits in excess of the
individual lifetime allowance set by legislation were paid via an unapproved,
unfunded pension arrangement provided directly by the company.
With the reduction in the annual allowance applicable to plans such
as the BP pension scheme in 2011 the company reviewed the options
available for employees who might wish to limit the increase in the value of
their pension to remain within the new limit. To provide employees with
flexibility, should they wish to limit the value of the increase in their
pension to within the new limit, those impacted are able to elect a lower
accrual rate and in addition receive a cash supplement so that the total cost
to BP remains equivalent to the cost of providing 1/60th of basic salary.
Some employees have had to cease pension accrual for future service to
remain within the new annual allowance. For these employees the cash
supplement is equal to 35% of basic salary.
Mr Conn has elected to cease to accrue pension benefits for future
service in order to keep within the new annual allowance and has received
a cash supplement of 35% of his basic salary from 1 April 2011. This is
included in the remuneration table on page 141.
US directors
Mr Dudley and Dr Grote participate in the US BP retirement accumulation
plan (US pension plan), which features a cash balance formula. Pension
benefits are provided through a combination of tax-qualified and
non-qualified benefit restoration plans, consistent with US tax regulations
as applicable.
BP also provides a supplemental executive retirement benefits plan
(supplemental plan), which is a non-qualified arrangement that became
effective on 1 January 2002 for US employees with salary above a
specified salary grade level. Mr Dudley and Dr Grote are eligible to
participate under the supplemental plan. The benefit formula is a target of
1.3% of final average earnings (base pay plus bonus) for each year of
service, inclusive of all other BP (US) qualified and non-qualified pension
arrangements. This benefit is unfunded and therefore paid from corporate
assets.
Mr Dudley retains the heritage Amoco retirement plan, which
provides benefits on a final average pay formula of 1.67% of highest
average earnings (base pay plus bonus in accordance with standard US
practice) for each year of service, reduced by 1.5% of the primary social
security benefit for each year of service. The highest benefit of the plans
produced by the different formulas will be payable and this is currently the
benefit determined under the Amoco heritage terms.
Their pension accrual for 2011, shown in the table below, takes into
account the total amount that could be payable under relevant plans.
Other benefits
Executive directors are eligible to participate in regular employee benefit
plans and in all-employee share saving schemes applying in their home
countries. Benefits in kind are not pensionable.
Pensions (audited)
R W Dudley (US)
I C Conn (UK)
Dr B E Grote (US)
Service at
31 Dec 2011
32 years
26 years
32 years
Accrued pension
entitlement
at 31 Dec 2011
$948
£307
$1,328
Additional pension
earned during the
year ended
31 Dec 2011a
$244
£20
$47
Transfer value of
accrued benefit
at 31 Dec 2010 (A)b
$10,336
£5,373
$16,501
Transfer value of
accrued benefit
at 31 Dec 2011 (B)b
$15,244
£6,582
$18,251
Amount of B-A less
contributions made by
the director in 2011
$4,908
£1,209
$1,750
thousand
a Additional pension earned during the year includes an inflation increase of 4.8% for UK directors and 3.6% for US directors.
b Transfer values have been calculated in accordance with guidance issued by the actuarial profession.
148 BP Annual Report and Form 20-F 2011
Directors’ remuneration report Share plans in detail
Performance share element of EDIP (audited)
R W Dudleyc
I C Conn
Dr B E Grotec
Former directors
Dr A B Hayward
A G Inglis
Performance
period
2009-2011
2010-2012
2011-2013
2008-2010
2008-2011e
2008-2013e
2009-2011
2010-2012
2011-2013
2008-2010
2009-2011
2010-2012
2011-2013
Date of
award of
performance
shares
06 May 2009
09 Feb 2010
09 Mar 2011d
13 Feb 2008
13 Feb 2008
13 Feb 2008
11 Feb 2009
09 Feb 2010
09 Mar 2011d
13 Feb 2008
11 Feb 2009
09 Feb 2010
09 Mar 2011d
2008-2010
2009-2011
2010-2012
2008-2010
2009-2011
2010-2012
13 Feb 2008
11 Feb 2009
09 Feb 2010
13 Feb 2008
11 Feb 2009
09 Feb 2010
Share element interests
Potential maximum performance sharesa
At 1 Jan
2011
539,634
581,082
–
578,376
133,452
133,452
780,816
656,813
–
581,748
992,928
801,894
–
845,319
755,512
303,948
578,376
520,544
218,938
Awarded
2011
–
–
1,330,332
–
–
–
–
–
623,025
–
–
–
785,394
At 31 Dec
2011
539,634
581,082
1,330,332
–
–
133,452
780,816
656,813
623,025
–
992,928
801,894
785,394
–
–
–
–
–
–
–
755,512f
303,948f
–
520,544f
218,938f
Interests vested in 2011 and 2012
Number of
ordinary
shares
vestedb
101,735
–
–
0
155,695
–
149,259
–
–
0
187,193
–
–
0
144,422
–
0
99,506
–
Vesting
date
15 Feb 2012
–
–
–
22 Feb 2011
–
15 Feb 2012
–
–
–
15 Feb 2012
–
–
–
15 Feb 2012
–
–
15 Feb 2012
–
Market price
of each share
at vesting
£
4.98
–
–
–
4.91
–
4.98
–
–
–
4.98
–
–
–
4.98
–
–
4.98
–
a BP’s performance is measured against the oil sector. For awards under the 2009-2011 plan, performance conditions are measured 50% on TSR against ExxonMobil, Shell, Total, ConocoPhillips and
Chevron and 50% on a balanced scorecard of underlying performance. For the awards under the 2010-2012 plan, performance conditions are measured one third on TSR against ExxonMobil, Shell, Total,
ConocoPhillips and Chevron and two thirds on a balanced scorecard of underlying performance. For awards under 2011-2013 plan, performance conditions are measured 50% on TSR against ExxonMobil,
Shell, Total, ConocoPhillips and Chevron; 20% on reserves replacement against the same peer group; and 30% against a balanced scorecard of strategic imperatives. Each performance period ends on
31 December of the third year.
b Represents vestings of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes re-invested dividends on the shares vested.
c Dr Grote and Mr Dudley receive awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares.
d The market price of ordinary shares on 9 March 2011 was £4.85 and for ADSs was $47.41.
e Restricted award under share element of EDIP. As reported in the 2007 directors’ remuneration report in February 2008, the committee awarded Mr Conn restricted shares, as set out above and includes
re-invested dividends on the shares vested. The remaining award vests on the fifth anniversary of the award, dependent on the remuneration committee being satisfied as to their personal performance at
the date of vesting. Any unvested tranche will lapse in the event of cessation of employment with the company.
f Potential maximum of performance shares reflect actual service during performance period on a pro-rated basis.
Deferred share element of EDIP (audited)
Name
I C Conn
Bonus
year
2010
Dr B E Groteb
2010
Type
Compulsory
Voluntary
Matching
Compulsory
Voluntary
Matching
Performance
period
2011-2013
2011-2013
2011-2013
2011-2013
2011-2013
2011-2013
Date of award
of deferred
sharesa
09 Mar 2011
09 Mar 2011
09 Mar 2011
09 Mar 2011
09 Mar 2011
09 Mar 2011
Deferred share element interests
Potential maximum deferred shares
At 1 Jan
2011
–
–
–
–
–
–
Awarded
2011
21,384
–
21,384
26,604
26,604
53,208
At 31 Dec
2011
21,384
–
21,384
26,604
26,604
53,208
Interests vested in 2010 and 2011
Number of
ordinary
shares
vested
–
–
–
–
–
–
Market price
of each share
at vesting
£
–
–
–
–
–
–
Vesting
date
–
–
–
–
–
–
a The market price of ordinary shares on 9 March 2011 was £4.85 and for ADSs was $47.41.
b Dr Grote received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares.
BP Annual Report and Form 20-F 2011 149
Directors’ remuneration reportDirectors’ remuneration report
Share options (audited)
R W Dudleya
I C Conn
Dr B E Grotea
Option
type
BP SOP
BP SOP
BP SOP
BP SOP
SAYE
SAYE
SAYE
SAYE
EXEC
EXEC
EDIP
At 1 Jan 2011
6,460
1,073
17,835
17,835
1,498
617
605
3,017
72,250
130,000
58,333
Granted
–
–
–
–
–
–
–
–
–
–
–
Exercised
–
–
–
–
1,498
–
–
–
–
–
–
At 31 Dec
2011
–b
–b
17,835
17,835
–
617
605
3,017
–b
130,000
–b
Option
price
$49.65
$43.82
$48.99
$38.10
£4.41
£4.87
£4.20
£3.68
£5.67
£5.72
$48.53
Market price
at date of
exercise
Date from
which first
exercisable
Expiry date
23 Feb 2004 22 Feb 2011
17 Dec 2004 16 Dec 2011
18 Feb 2005 17 Feb 2012
17 Feb 2006 16 Feb 2013
£4.93c 01 Sep 2010 28 Feb 2011
01 Sep 2011 29 Feb 2012
01 Sep 2012 28 Feb 2013
01 Sep 2016 28 Feb 2017
23 Feb 2004 23 Feb 2011
18 Feb 2005 18 Feb 2012
25 Feb 2005 25 Feb 2011
The closing market prices of an ordinary share and of an ADS on 31 December 2011 were £4.61 and $42.74 respectively.
During 2011, the highest market prices were £5.09 and $49.25 respectively and the lowest market prices were £3.63 and $35.22 respectively.
EDIP = Executive Directors’ Incentive Plan adopted by shareholders in 2010 as described on page 147.
EXEC = Executive Share Option Scheme. These options were granted to the relevant individuals prior to their appointments as directors and are not subject to performance conditions.
SAYE = Save As You Earn employee share scheme.
BP SOP = BP Share Option Plan. These options were granted to Mr Dudley prior to his appointment as a director and are not subject to performance conditions.
a Numbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.
b Options lapsed.
c Options exercised on 22 February 2011. Closing market price for information. Shares were retained after exercise of options.
Service contracts
Executive directors – external appointments
Service contracts have a notice period of one year and may be terminated
by the company at any time with immediate effect on payment in lieu of
notice equivalent to one year’s salary or the amount of salary that would
have been paid if the contract had been terminated on the expiry of the
remainder of the notice period. Other than in the case of Dr Gilvary (who
became a director on 1 January 2012), the service contracts are expressed
to expire at a normal retirement age of 60 (subject to age discrimination).
The board encourages executive directors to broaden their knowledge and
experience by taking up appointments outside the company. Each
executive director is permitted to accept one non-executive appointment,
from which they may retain any fee. External appointments are subject to
agreement by the chairman and reported to the board. Any external
appointment must not conflict with a director’s duties and commitments
to BP.
Director
R W Dudley
I C Conn
Dr B Gilvary
Dr B E Grote
Contract
date
6 Apr 2009
22 Jul 2004
22 Feb 2012
7 Aug 2000
Salary as at
1 Jan 2012
$1,700,000
£730,000
£690,000
$1,442,000
Mr Dudley’s contract is with BP Corporation North America Inc. He is
seconded to BP p.l.c. under a secondment agreement of 15 April 2009,
which expires on 15 April 2012. Dr Grote’s contract is with BP Exploration
(Alaska) Inc. He is seconded to BP p.l.c. under a secondment agreement
of 7 August 2000, which expires at the date of the 2013 AGM. Both
secondments can be terminated by one month’s notice by either party and
terminate automatically on the termination of their service contracts.
There are no other provisions for compensation payable on early
termination of the above contracts. In the event of the early termination of
any of the contracts by the company, other than for cause (or under a
specific termination payment provision), the relevant director’s then current
salary and benefits would be taken into account in calculating any liability of
the company. The committee will consider mitigation to reduce
compensation to a departing director, when appropriate to do so.
During the year, the fees received by executive directors for
external appointments were as follows:
Director
I C Conn
Appointee
company
Rolls-Royce
Dr B E Grote
Unilever
Additional position
held at appointee
company
Senior
independent
director
Audit committee
member
Total
fees
£74,166
Unilever PLC
£33,500
Unilever NV
€48,625
Past directors
Tony Hayward was engaged by BP to serve as a non-executive director
of TNK-BP until 11 October 2011. For his service during 2011 he was
paid $194,973.
150 BP Annual Report and Form 20-F 2011
Directors’ remuneration report Non-executive directors’
remuneration
Policy
The board sets the level of remuneration for all non-executive directors
within a limit approved from time to time by shareholders. Key elements of
BP’s policy on non-executive director remuneration include:
• Remuneration should be sufficient to attract, motivate and retain
world-class non-executive talent.
• Remuneration of non-executive directors is proposed by the chairman
of the board and agreed by the board and should be proportional to their
contribution towards the interests of the company.
• Remuneration practice should be consistent with recognized best
practice standards for non-executive directors’ remuneration.
• Remuneration should be in the form of cash fees, payable monthly.
• Non-executive directors should not receive share options from the
company.
• Non-executive directors are encouraged to establish a holding in BP
shares of the equivalent value of one-year’s base fee.
Process
BP reviews the quantum and structure of chairman of the board and
non-executive remuneration on an annual basis. The chairman’s
remuneration is reviewed by the remuneration committee, who makes a
recommendation to the board; the chairman does not vote on his own
remuneration. Non-executive director remuneration is reviewed by the
chairman, who makes a recommendation to the board; non-executive
directors do not vote on their own remuneration.
Following the 2011 review of non-executive remuneration, it was
concluded that in light of wider economic circumstances, an increase
would not be appropriate and therefore no adjustment would be made to
fee levels. It was agreed that the policy of annual review would continue
and that the transatlantic attendance allowance be renamed the
intercontinental travel allowance to better reflect when the allowance
is awarded.
Fee structure
The table below shows the current fee structure for non-executive
directors on 1 January 2012:
Chairmana
Senior independent directorb
Board member
Audit, Gulf of Mexico and safety, ethics and environment
assurance committees chairmanship feesc
Remuneration committee chairmanship feec
Committee membership feed
Intercontinental travel allowance
£ thousand
Fee level
750
120
75
30
20
5
5
a The chairman remains ineligible for committee chairmanship and membership fees or
intercontinental attendance allowance. He has the use of a fully maintained office for company
business, a chauffeured car and security advice in London. He receives secretarial support as
appropriate to his needs in Sweden.
b The senior independent director is still eligible for committee chairmanship fees and
intercontinental attendance allowance plus any committee membership fees.
c Committee chairmen do not receive an additional membership fee for the committee they chair.
d For members of the audit, Gulf of Mexico, SEEAC and remuneration committees.
Remuneration of non-executive directors in 2011 (audited)
C-H Svanberg
P M Anderson
F L Bowman
A Burgmans
C B Carroll
Sir William Castell
G David
I E L Davis
B R Nelson
F P Nhlekob
Directors leaving the board in 2011
D J Flint
Dr D S Julius
2011
750
128
120
100
85
168
128a
160
103
113
35
32c
£ thousand
2010
750
118
17
90
90
147
135
69
17
–
108
100
a In addition, George David received a £28,000 fee for chairing the BP technical advisory council.
b Appointed on 1 February 2011.
c This figure excludes a superannuation gratuity of £1,543.
While fees were held at 2010 levels, in 2011 actual fees paid to
non-executive directors were affected by changes in chairmanship and
committee membership and the number of intercontinental meetings for
which an attendance allowance was paid.
No share or share option awards were made to any non-executive
director in respect of service on the board during 2011.
Non-executive directors have letters of appointment which
recognize that, subject to the Articles of Association, their service is at the
discretion of shareholders. All directors stand for re-election at each AGM.
Superannuation gratuities
Until 2002, BP maintained a long-standing practice whereby non-executive
directors who retired from the board after at least six years’ service were
eligible for consideration for a superannuation gratuity. The board was, and
continues to be, authorized to make such payments under the company’s
Articles of Association and the amount of the payment is determined at the
board’s discretion, taking into consideration the director’s period of service
and other relevant factors.
In 2002, the board revised its policy with respect to superannuation
gratuities so that:
• Non-executive directors appointed to the board after 1 July 2002 would
not be eligible for consideration for such a payment.
• While non-executive directors in service at 1 July 2002 would remain
eligible for consideration for a payment, service after that date would
not be taken into account by the board in considering the amount of any
such payment.
Dr DeAnne Julius who retired on 14 April 2011 was paid a superannuation
gratuity of £1,543, in line with the policy arrangements agreed in 2002 and
outlined above. With the retirement of Dr Julius from the board, no other
non-executive directors are eligible for superannuation gratuities.
Past directors
Sir Ian Prosser (who retired as a non-executive director of BP in April 2010)
was appointed as a director and non-executive chairman of BP Pension
Trustees Limited on 29 September 2010. During 2011, he received
£100,000 for this role.
Peter Sutherland (who was chairman of BP until 31 December
2009) continued his membership of the BP international advisory board
after his retirement from the board of BP p.l.c. During 2011, he received
e100,000 for this role.
This directors’ remuneration report was approved by the board and signed
on its behalf by David J Jackson, Company Secretary on 6 March 2012.
BP Annual Report and Form 20-F 2011 151
Directors’ remuneration reportDirectors’ remuneration report 152 BP Annual Report and Form 20-F 2011
Additional information
for shareholders
154 Critical accounting policies
168 Taxation
157 Property, plant and equipment
170 Documents on display
157 Share ownership
158 Major shareholders
170 Purchases of equity securities by the
issuer and affiliated purchasers
171 Fees and charges payable by a
159 Called-up share capital
holder of ADSs
159 Dividends
160 Legal proceedings
171 Fees and payments made by the
Depositary to the issuer
171 Related-party transactions
167 Relationships with suppliers and
contractors
172 Administration
167 Share prices and listings
172 Annual general meeting
168 Material contracts
172 Exhibits
168 Exchange controls
BP Annual Report and Form 20-F 2011 153
Additional information for shareholders Critical accounting policies
The significant accounting policies of the group are summarized in Financial
statements – Note 1 on pages 182-189.
Inherent in the application of many of the accounting policies used
in preparing the financial statements is the need for BP management to
make judgements, 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 period. Actual
outcomes could differ from the estimates and assumptions used. The
following summary provides more information about the critical accounting
judgements and estimates that could have a significant impact on the
results of the group and should be read in conjunction with the information
provided in the Notes on financial statements, including Note 1 Significant
accounting policies.
The areas requiring the most significant judgement and estimation
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, business combinations, taxation,
derivative financial instruments, provisions and contingencies, and in
particular, provisions and contingencies related to the Gulf of Mexico oil
spill, and pensions and other post-retirement benefits.
Oil and natural gas accounting
The group follows the principles of the successful efforts method
of accounting for its oil and natural gas exploration, appraisal and
development expenditure. The group’s accounting policy for oil and natural
gas exploration, appraisal and development expenditure is provided in
Financial statements – Note 1 on page 184.
The accounting for oil and natural gas exploration, appraisal and
development expenditure requires the use of various judgements and
estimates in management’s determination of the economic viability of a
project based on a range of technical and commercial considerations, the
establishment of development plans and timing, and estimates of future
expenditure.
Exploration licence and leasehold property acquisition costs are
capitalized within intangible assets and are reviewed at each reporting date
to confirm that there is no indication that the carrying amount exceeds
the recoverable amount. This review includes confirming that exploration
drilling is still under way or firmly planned or that it has been determined,
or work is under way to determine, that the discovery is economically
viable based on a range of technical and commercial considerations and
sufficient progress is being made on establishing development plans and
timing. If no future activity is planned, the remaining balance of the licence
and property acquisition costs is written off. Lower value licences are
pooled and amortized on a straight-line basis over the estimated period of
exploration.
For exploration wells and exploratory-type stratigraphic test wells,
costs directly associated with the drilling of wells are initially capitalized
within intangible assets, pending determination of whether potentially
economic oil and gas reserves have been discovered by the drilling effort.
These costs include employee remuneration, materials and fuel used, rig
costs, delay rentals and payments made to contractors. The determination
is usually made within one year after well completion, but can take longer,
depending on the complexity of the geological structure. If the well did
not encounter potentially economic oil and gas quantities, the well costs
are expensed as a dry hole and are reported in exploration expense.
Exploration wells that discover potentially economic quantities of oil and
natural gas and are in areas where major capital expenditure (e.g. offshore
platform or a pipeline) would be required before production could begin,
and where the economic viability of that major capital expenditure depends
on the successful completion of further exploration work in the area,
remain capitalized on the balance sheet as long as additional exploration
appraisal work is under way or firmly planned.
It is not unusual to have exploration wells and exploratory-type stratigraphic
test wells remaining suspended on the balance sheet for several years
while additional appraisal drilling and seismic work on the potential oil and
natural gas field is performed or while the optimum development plans and
timing are established.
All such carried costs are subject to regular technical, commercial
and management review on at least an annual basis to confirm the
continued intent to develop, or otherwise extract value from, the discovery.
Where this is no longer the case, the costs are immediately expensed.
The determination of the group’s estimated oil and gas reserves
requires significant judgements and estimates to be applied and these
are regularly reviewed and updated. Factors such as the availability of
geological and engineering data, reservoir performance data, acquisition
and divestment activity, drilling of new wells and commodity prices all
impact on the determination of the group’s estimates of its oil and gas
reserves. BP bases its proved reserves estimates on the requirement of
reasonable certainty with rigorous technical and commercial assessments
based on conventional industry practice.
The estimation of oil and natural gas reserves and BP’s process
to manage reserves bookings is described in Exploration and Production
– Oil and gas disclosures on page 89, which is unaudited. Details on BP’s
proved reserves and production compliance and governance processes are
provided on pages 90-91.
Estimates of oil and gas reserves are used to calculate depreciation,
depletion and amortization charges for the group’s oil and gas properties.
The impact of changes in estimated proved reserves is dealt with
prospectively by amortizing the remaining carrying value of the asset over
the expected future production. As discussed below, oil and natural gas
reserves also have a direct impact on the assessment of the recoverability
of asset carrying values reported in the financial statements.
If proved reserves estimates are revised downwards, earnings
could be affected by higher depreciation expense or an immediate write-
down of the property’s carrying value (see discussion of recoverability of
asset carrying values below).
The 2011 movements in proved reserves are reflected in the
tables showing movements in oil and gas reserves by region in Financial
statements – Supplementary information on oil and natural gas (unaudited)
on pages 259-281. Information on the carrying amounts of the group’s oil
and gas properties, together with the amounts recognized in the income
statement as depreciation, depletion and amortization is contained in
Financial statements – Note 15 and Note 9 respectively.
Recoverability of asset carrying values
BP assesses its fixed assets, including goodwill, for possible impairment
if there are events or changes in circumstances that indicate that carrying
values of the assets may not be recoverable and, as a result, charges for
impairment are recognized in the group’s results from time to time, with
corresponding reductions in the carrying values of the group’s assets.
Such indicators include changes in the group’s business plans, changes
in commodity prices leading to sustained unprofitable performance, an
increase in the discount rate, low plant utilization, evidence of physical
damage and, for oil and natural gas properties, significant downward
revisions of estimated volumes or increases in estimated future
development expenditure. If there are low oil prices, natural gas prices,
refining margins or marketing margins during an extended period, the
group may need to recognize significant impairment charges.
The assessment for impairment entails comparing the carrying
value of the asset or cash-generating unit with its recoverable amount,
that is, the higher of fair value less costs to sell and value in use. Value
in use is usually determined on the basis of discounted estimated future
net cash flows. Determination as to whether and how much an asset is
impaired involves management estimates on highly uncertain matters such
as future commodity prices, the effects of inflation on operating expenses,
discount rates, production profiles and the outlook for global or regional
market supply-and-demand conditions for crude oil, natural gas and refined
products.
154 BP Annual Report and Form 20-F 2011
Additional information for shareholders For oil and natural gas properties, the expected future cash flows are
estimated using management’s best estimate of future oil and natural
gas prices and reserves volumes. 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 price assumptions thereafter. As at
31 December 2011, the group’s long-term price assumptions were $90
per barrel for Brent and $6.50/mmBtu for Henry Hub (2010 $75 per barrel
and $6.50/mmBtu). These long-term price assumptions are subject to
periodic review and modification. The estimated future level of production
is based on assumptions about future commodity prices, production
and development costs, field decline rates, current fiscal regimes and
other factors.
The future cash flows are adjusted for risks specific to the cash-
generating unit and are discounted using a pre-tax discount rate. The
discount rate is derived from the group’s post-tax weighted average
cost of capital and is adjusted where applicable to take into account any
specific risks relating to the country where the cash-generating unit is
located, although other rates may be used if appropriate to the specific
circumstances. In 2011 the rates ranged from 12% to 14% nominal
(2010 11% to 14% nominal). The rate applied in each country is
reassessed each year.
Irrespective of whether there is any indication of impairment, BP is
required to test annually for impairment of goodwill acquired in a business
combination. The group carries goodwill of approximately $12.1 billion
on its balance sheet (2010 $8.6 billion), principally relating to the Atlantic
Richfield, Burmah Castrol, Devon Energy and Reliance transactions. In
testing goodwill for impairment, the group uses a similar approach to that
described above for asset impairment. If there are low oil prices or natural
gas prices or refining margins or marketing margins for an extended period,
the group may need to recognize significant goodwill impairment charges.
In 2009, an impairment loss of $1.6 billion was recognized to write off all
of the goodwill allocated to the US West Coast fuels value chain (FVC).
The prevailing weak refining environment, together with a review of future
margin expectations in the FVC, led to a reduction in the expected future
cash flows.
Refer to Oil and natural gas accounting above for a discussion on
the recoverability of intangible exploration and appraisal expenditure.
Details of impairment charges recognized in the income statement
are provided in Financial statements – Note 5 and details on the carrying
amounts of assets are shown in Financial statements – Note 21, Note 22
and Note 23.
Business combinations
Accounting for business combinations using the acquisition method
requires the determination of the fair value of the consideration transferred,
together with the fair value of the identifiable assets acquired and liabilities
assumed at the acquisition date. Goodwill is measured as being the excess
of the aggregate of the consideration transferred, the amount recognized
for any minority interest and the acquisition-date fair values of any
previously held interest in the acquiree over the fair value of the identifiable
assets acquired and liabilities assumed at the acquisition date.
Judgement is required in determining whether a transaction meets
the criteria to be treated as a business combination or not. Judgements
and estimates are also required in order to determine the fair values of the
assets acquired and the liabilities assumed, and the group uses all available
information, including external valuations and appraisals where appropriate,
to determine these fair values. If necessary, the group has up to one year
from the acquisition date to finalize the determinations of fair value.
Details of the business combinations undertaken by the group in
2011 are provided in Financial statements – Note 3 on page 194.
Taxation
The computation of the group’s income tax expense and liability
involves the interpretation of applicable tax laws and regulations in many
jurisdictions throughout the world. The resolution of tax positions taken
by the group, through negotiations with relevant tax authorities or through
litigation, can take several years to complete and in some cases it is
difficult to predict the ultimate outcome.
In addition, the group has carry-forward tax losses and tax credits in
certain taxing jurisdictions that are available to offset against future taxable
profit. However, deferred tax assets are recognized only to the extent
that it is probable that taxable profit will be available against which the
unused tax losses or tax credits can be utilized. Management judgement is
exercised in assessing whether this is the case.
To the extent that actual outcomes differ from management’s
estimates, income tax charges or credits, and changes in deferred tax
assets or liabilities, may arise in future periods. For more information see
Financial statements – Note 18 on page 210 and Note 43 on page 249.
Derivative financial instruments
The group uses derivative financial instruments to manage certain
exposures to fluctuations in foreign currency exchange rates, interest
rates and commodity prices as well as for trading purposes. In addition,
derivatives embedded within other financial instruments or other host
contracts are treated as separate derivatives when their risks and
characteristics are not closely related to those of the host contract. All
such derivatives are initially recognized at fair value on the date on which a
derivative contract is entered into and are subsequently remeasured at fair
value. Gains and losses arising from changes in the fair value of derivatives
that are not designated as effective hedging instruments are recognized in
the income statement.
In some cases the fair values of derivatives are estimated using
internal models and other valuation methods due to the absence of quoted
prices or other observable, market-corroborated data. This applies to the
group’s longer-term, structured derivative products and complex options,
as well as to the majority of the group’s natural gas embedded derivatives.
The group’s embedded derivatives arise primarily from long-term UK gas
contracts that use pricing formulae not related to gas prices, for example,
oil product and power prices. These contracts are valued using models
with inputs that include price curves for each of the different products that
are built up from active market pricing data and extrapolated to the expiry
of the contracts using the maximum available external pricing information.
Additionally, where limited data exists for certain products, prices are
interpolated using historic and long-term pricing relationships. Price
volatility is also an input for the models.
Changes in the key assumptions could have a material impact on
the fair value gains and losses on derivatives and embedded derivatives
recognized in the income statement. For more information see Financial
statements – Note 33 on page 224.
Details of the value-at-risk techniques used by the group to
measure market risk exposure arising from its derivative trading positions
is provided in Financial statements – Note 26 on page 217. An analysis of
the sensitivity of the fair value of the embedded derivatives to changes
in the key assumptions is provided in Financial statements – Note 26 on
page 217.
BP Annual Report and Form 20-F 2011 155
Additional information for shareholdersAdditional information for shareholders 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 decommissioning obligations facing BP relate to the
plugging and abandonment of wells and the removal and disposal of oil
and natural gas platforms and pipelines around the world. The estimated
discounted costs of performing this work are recognized as we drill the
wells and install the 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
decommissioning 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. Decommissioning 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. Any changes in the expected future
costs are reflected in both the provision and the asset.
Decommissioning provisions associated with downstream and
petrochemicals facilities are generally not recognized, as such potential
obligations cannot be measured, given their indeterminate settlement
dates. The group performs periodic reviews of its downstream
and petrochemicals long-lived assets for any changes in facts and
circumstances that might require the recognition of a decommissioning
provision.
The timing and amount of future expenditures are reviewed
annually, together with the interest rate used in discounting the cash flows.
The interest rate used to determine the balance sheet obligation at the end
of 2011 was 0.5% (2010 1.5%). The interest rate represents the real rate
(i.e. excluding the impacts of inflation) on long-dated government bonds.
Other provisions and liabilities are recognized in the period when
it becomes probable that there will be a future outflow of funds resulting
from past operations or events and the amount of cash outflow can
be reliably estimated. The timing of recognition and quantification of
the liability require the application of judgement to existing facts and
circumstances, which can be subject to change. Since the actual cash
outflows can take place many years in the future, the carrying amounts
of provisions and liabilities are reviewed regularly and adjusted to take
account of changing facts and circumstances.
A change in estimate of a recognized provision or liability would
result in a charge or credit to net income in the period in which the change
occurs (with the exception of decommissioning costs as described above).
Provisions for environmental remediation are made when a
clean-up is probable and the amount of the obligation can be reliably
estimated. Generally, this coincides with commitment to a formal plan
of action or, if earlier, on divestment or on closure of inactive sites. The
provision for environmental liabilities is estimated based on current legal
and constructive requirements, technology, price levels and expected
plans for remediation. Actual costs and cash outflows can differ from
estimates because of changes in laws and regulations, public expectations,
prices, discovery and analysis of site conditions and changes in clean-up
technology.
The provision for environmental liabilities is reviewed at least
annually. The interest rate used to determine the balance sheet obligation
at 31 December 2011 was 0.5% (2010 1.5%).
Information about the group’s provisions is provided in Financial
statements – Note 36.
As further described in Financial statements – Note 43 on page 249,
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
established or revised. Accordingly, significant management judgement
relating to provisions and contingent liabilities is required, since the
outcome of litigation is difficult to predict.
Gulf of Mexico oil spill
Detailed information on the Gulf of Mexico oil spill, including the financial
impacts, is provided in Financial statements – Note 2 on pages 190-194.
As a consequence of the Gulf of Mexico oil spill, as described on
pages 76-79, BP continues to incur costs and has also recognized liabilities
for future costs. Liabilities of uncertain timing or amount and contingent
liabilities have been accounted for and/or disclosed in accordance with IAS
37 ‘Provisions, contingent liabilities and contingent assets’. BP’s rights and
obligations in relation to the $20-billion trust fund which was established
in 2010 are accounted for in accordance with IFRIC 5 ‘Rights to interests
arising from decommissioning, restoration and environmental rehabilitation
funds’.
The total amounts that will ultimately be paid by BP in relation to all
obligations relating to the incident are subject to significant uncertainty and
the ultimate exposure and cost to BP will be dependent on many factors
(including, with respect to certain of the obligations, any determination of
BP’s culpability based on any findings of negligence, gross negligence or
wilful misconduct). Furthermore, significant uncertainty exists in relation to
the amount of claims that will become payable by BP, the amount of fines
that will ultimately be levied on BP, the outcome of litigation and arbitration
proceedings, the amount and timing of payments under any settlements,
and any costs arising from any longer-term environmental consequences
of the oil spill, which will also impact upon the ultimate cost for BP. Any
further settlements which may be reached relating to the Deepwater
Horizon oil spill could impact the amount and timing of any future
payments. Although the provision recognized is the current best reliable
estimate of expenditures required to settle certain present obligations at
the end of the reporting period, there are future expenditures for which
it is not possible to measure the obligation reliably as noted below under
Contingent liabilities.
The magnitude and timing of possible obligations in relation to the
Gulf of Mexico oil spill are subject to a very high degree of uncertainty
as described further in Risk factors on pages 59-63. Furthermore, other
material unanticipated obligations may arise in future in relation to the
incident. Refer to Financial statements – Note 43 on page 249 for further
information.
Expenditure to be met from the $20-billion trust fund
In 2010, BP established the Deepwater Horizon Oil Spill Trust (the Trust) to
be funded in the amount of $20 billion over the period to the fourth quarter
of 2013, which is available to satisfy legitimate individual and business
claims administered by the Gulf Coast Claims Facility (GCCF), state and
local government claims resolved by BP, final judgments and settlements,
state and local response costs, and natural resource damages and related
costs. It is currently expected that the cost of the proposed settlement
will be payable from the Trust. In 2010, BP contributed $5 billion to the
fund, and further regular contributions totalling $5 billion were made in
2011. During 2011, BP also contributed the cash settlements received
from MOEX, Weatherford and Anadarko amounting in total to $5.1 billion.
A further cash settlement from Cameron was received in January 2012
and was also contributed to the trust fund. As a result of these accelerated
contributions, it is now expected that the $20-billion commitment will have
been paid in full by the end of 2012.
Fines, penalties and claims administration costs are not covered by
the trust fund. BP’s obligation to make contributions to the trust fund was
recognized in full in the 2010 group income statement and the remaining
liability to fund the Trust is included within other payables on the balance
sheet after taking account of the time value of money. The establishment
of the trust fund does not represent a cap or floor on BP’s liabilities and BP
does not admit to a liability of this amount.
An asset has been recognized representing BP’s right to receive
reimbursement from the trust fund. This is the portion of the estimated
future expenditure provided for that will be settled by payments from
the trust fund. We use the term “reimbursement asset” to describe this
asset. BP will not actually receive any reimbursements from the trust fund,
instead payments will be made directly to claimants from the trust fund,
and BP will be released from its corresponding obligation.
156 BP Annual Report and Form 20-F 2011
Additional information for shareholders Contingent liabilities relating to the Gulf of Mexico oil spill
BP has provided for its best estimate of certain claims under the Oil
Pollution Act 1990 (OPA 90) that will be paid through the $20-billion
trust fund, including the increased estimate of the cost of individual and
business claims as a result of the proposed settlement announced on
3 March 2012 as described in Note 2 and Note 36. It is not possible, at
this time, to measure reliably any other items that will be paid from the
trust fund, namely any obligation in relation to Natural Resource Damages
claims (except for the estimated costs of the assessment phase and the
costs relating to emergency and early restoration agreements) and claims
asserted in civil litigation, including any further litigation through potential
opt-outs from the proposed settlement agreement with the Plaintiffs’
Steering Committee announced on 3 March 2012 (see page 76 for further
information), nor is it practicable to estimate their magnitude or possible
timing of payment. Although these items, which will be paid through the
trust fund, have not been provided for at this time, BP’s full obligation
under the $20-billion trust fund was expensed in the income statement in
2010, taking account of the time value of money.
For those items not covered by the trust fund it is not possible to
measure reliably any obligation in relation to other litigation or potential
fines and penalties except, subject to certain assumptions, for those
relating to the Clean Water Act. Therefore no amounts have been provided
for these items as at 31 December 2011. There are a number of federal
and state environmental and other provisions of law, other than the Clean
Water Act, under which one or more governmental agencies could seek
civil fines and penalties from BP. Given the large number of claims that
may be asserted, it is not possible at this time to determine whether and
to what extent any such claims would be successful or what penalties or
fines would be assessed.
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,
assumptions for inflation rates, US healthcare cost trend rates and rates of
utilization of healthcare services by US retirees.
These assumptions are based on the environment in each country.
Determination of the projected benefit obligations for the group’s defined
benefit pension and post-retirement plans is important to the recorded
amounts for such obligations on the balance sheet and to the amount of
benefit expense in the income statement. The assumptions used may
vary from year to year, which will affect future results of operations. Any
differences between these assumptions and the actual outcome also
affect future results of operations.
Pension and other post-retirement benefit assumptions are
reviewed by management at the end of each year. These assumptions
are used to determine the projected benefit obligation at the year-end and
hence the surpluses and deficits recorded on the group’s balance sheet,
and pension and other post-retirement benefit expense for the following
year.
The pension and other post-retirement benefit assumptions at
December 2011, 2010 and 2009 are provided in Financial statements –
Note 37 on page 234.
The assumed rate of investment return, discount rate, inflation
rate and the US healthcare cost trend rate have a significant effect on the
amounts reported. A sensitivity analysis of the impact of changes in these
assumptions on the benefit expense and obligation is provided in Financial
statements – Note 37 on page 234.
In addition to the financial assumptions, we regularly review the
demographic and mortality assumptions. Mortality assumptions reflect
best practice in the countries in which we provide pensions and have been
chosen with regard to the latest available published tables adjusted where
appropriate to reflect the experience of the group and an extrapolation of
past longevity improvements into the future. A sensitivity analysis of the
impact of changes in the mortality assumptions on the benefit expense
and obligation is provided in Financial statements – Note 37 on page 234.
Actuarial gains and losses are recognized in full within other
comprehensive income in the year in which they occur.
Property, plant and equipment
BP has freehold and leasehold interests in real estate in numerous
countries, but no individual property is significant to the group as a whole.
See Exploration and Production on page 80 for a description of the group’s
significant reserves and sources of crude oil and natural gas. Significant
plans to construct, expand or improve specific facilities are described under
each of the business headings within this section.
Share ownership
Directors and senior management
As at 1 March 2012, 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:
Director
C-H Svanberg
R W Dudley
P M Anderson
F L Bowman
A Burgmans
C B Carroll
Sir William Castell
I C Conn
G David
I E L Davis
Professor Dame Ann Dowling
Dr B Gilvary
Dr B E Grote
B R Nelson
F P Nhleko
A Shilston
6,000c
12,720c
10,156
10,500c
82,500
Performance
Ordinary
sharesa
shares
933,971
–
337,301c 1,911,414c
–
–
–
–
–
497,501d 1,322,606
579,000c
–
–
10,391
–
–
45,000
331,088
1,693,704c
1,484,603f
–
11,040
–
–
–
–
Restricted
sharesb
–
–
–
–
–
–
–
133,452b
–
–
–
269,145e
–
–
–
–
a Performance shares awarded under the BP Executive Directors’ Incentive Plan. These figures
represent the maximum possible vesting levels. The actual number of shares/ADSs that vest
will depend on the extent to which performance conditions have been satisfied over a three-year
period.
b Restricted share award under the BP Executive Directors’ Incentive Plan. These shares will vest in
2013, subject to the director’s continued service and satisfactory performance.
c Held as ADSs.
d Includes 48,024 shares held as ADSs.
e Held as restricted share units under the BP Deferred Annual Bonus Plan and the BP Executive
Performance Plan.
f Held as ADSs, except for 94 shares held as ordinary shares.
As at 1 March 2012, 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:
Director
R W Dudleya
I C Conn
Dr B Gilvary
Dr B E Grotea
a Held as ADSs.
Options
107,010
3,622
504,191
–
There are no directors or members of senior management who own more
than 1% of the ordinary shares outstanding. At 1 March 2012, all directors
and senior management as a group held interests in 10,760,373 ordinary
shares or their calculated equivalent, 5,536,676 performance shares or
their calculated equivalent and 7,575,135 options for ordinary shares or
their calculated equivalent under the BP group share options schemes.
Additional details regarding the options granted and performance
shares awarded can be found in the Directors’ remuneration report on
pages 139-151.
BP Annual Report and Form 20-F 2011 157
Additional information for shareholdersAdditional information for shareholders
Employee share plans
The following table shows employee share options granted.
2011a
Options thousands
2009
2010
Employee share options granted
during the yearb
152,473
10,420
9,680
a 142,550,350 options were granted pursuant to the BP Plan 2011, adopted on 7 September 2011.
For more information on the BP Plan 2011, see Financial statements – Note 40 on page 246.
b For the options outstanding at 31 December 2011, the exercise price ranges and weighted average
remaining contractual lives are shown in Financial statements – Note 40 on page 246.
BP offers most of its employees the opportunity to acquire a shareholding
in the company through savings-related and/or matching share plan
arrangements. BP also uses performance plans and option plans (see
Financial statements – Note 40 on page 246) as elements of remuneration
for executive directors and senior employees.
Shares acquired through the company’s employee share plans
rank pari passu with shares in issue and have no special rights, save
as described below. For legal and practical reasons, the rules of these
plans set out the consequences of a change of control of the company,
and generally provide for options and conditional awards to vest on an
accelerated basis.
Matching and saving plans
BP ShareMatch plans
These matching share plans give employees the opportunity to buy
ordinary shares in BP p.l.c. and receive free matching shares in BP p.l.c.,
up to a predetermined limit. The plans are run in the UK and in more than
50 other countries. The UK plan is an approved HMRC plan and runs on
a monthly basis. Under the UK plan, shares must be held in trust for at
least three years to receive beneficial tax treatment. In other countries,
the plan is run on an annual basis with shares being held in trust for three
years. The plan is operated on a cash basis in those countries where there
are regulatory restrictions preventing the holding of BP shares. When the
employee leaves BP all shares must be removed from trust and units
under the plan operated on a cash basis must be encashed.
Once shares have been awarded to an employee under the plan,
the employee may instruct the trustee how to vote their shares.
BP ShareSave Plan
This is an approved HMRC plan which is open to all eligible UK employees.
Participants can contribute up to a maximum of £250 per month from
their net salary to a savings account over a three- or five-year contractual
savings period. At the end of the savings period, they are entitled to
purchase shares in BP p.l.c. at a preset price determined on the date when
the invitations are sent to eligible employees. This price is usually set at a
discount to the market price of a share of up to 20%. The option must be
exercised within six months of maturity of the savings contract, otherwise
it lapses. The plan is run in the UK and options are granted annually, usually
in June. Participants leaving for a qualifying reason before the savings
contract matured will have up to six months in which to use their savings
to exercise their options on a pro-rated basis.
Local plans
In some countries, BP provides local scheme benefits, the rules and
qualifications for which vary according to local circumstances. Certain US
employees may participate in a defined contribution (401k) plan in which
BP matches employee contributions up to certain limits. Participants may
invest in several investment options including a BP Stock Fund that holds
BP ADSs and a small percentage of cash. At 31 December 2011 the BP
Stock Fund held 39,026,928 BP ADSs with a market value of $1,682 million
(2010: 38,382,657 BP ADSs and $1,715 million). Participants in the fund as
of the record date may direct the trustee how to vote their portion of the
BP Stock Fund.
Cash-settled share-based payments
Grants are settled in cash where participants are located in a country
whose regulatory environment prohibits the holding of BP shares.
Employee Share Ownership Plan Trusts (ESOPs)
ESOPs have been established to hold BP shares to satisfy any releases
made to participants under the Executive Directors’ Incentive Plan, the
Long-Term Performance Plan and the Share Option Plan. The ESOPs
have waived their rights to dividends on shares held for future awards and
are funded by the group. Pending vesting, the ESOPs have independent
trustees that have the discretion in relation to the voting of such shares.
Until such time as the company’s own shares held by the ESOPs vest
unconditionally in employees, the amount paid for those shares is
deducted in arriving at shareholders’ equity (see Financial statements –
Note 39 on page 242). Assets and liabilities of the ESOPs are recognized
as assets and liabilities of the group.
At 31 December 2011, the ESOPs held 27,784,503 shares
(2010 11,477,253 shares and 2009 18,062,246 shares) for potential
future awards, which had a market value of $197 million (2010 $82 million
and 2009 $174 million).
Pursuant to the various BP group share option schemes, the
following options for ordinary shares of the company were outstanding at
17 February 2012:
Options outstanding (shares)
334,424,461
Expiry dates
of options
2012-2021
Exercise price
per share
$5.66-11.92
More details on share options appear in Financial statements – Note 40 on
page 246.
Major shareholders
The disclosure of certain major and significant shareholdings in the
share capital of the company is governed by the Companies Act 2006, the
UK Financial Services Authority’s Disclosure and Transparency Rules (DTR)
and the US Securities Exchange Act of 1934.
Register of members holding BP ordinary shares as at
31 December 2011
Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000a
Totals
Number of ordinary
shareholders
59,824
112,279
119,628
11,107
923
755
304,516
Percentage of total
ordinary shareholders
19.65
36.87
39.28
3.65
0.30
0.25
100.00
Percentage of total
ordinary share capital
excluding shares
held in treasury
0.02
0.31
1.88
1.17
1.81
94.81
100.00
a Includes JPMorgan Chase Bank, N.A. holding 26.50% of the total ordinary issued share capital
(excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which is
shown in the table below.
Register of holders of American depositary shares (ADSs) as at
31 December 2011a
Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000b
Totals
Number of
ADS holders
62,206
30,364
16,856
966
9
1
110,402
Percentage of total
ADS holders
56.35
27.50
15.27
0.87
0.01
0.00
100.00
Percentage of total
ADSs
0.42
1.73
5.34
1.96
0.15
90.40
100.00
a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 792,991 underlying shareholders.
As at 31 December 2011, there were also 1,591 preference shareholders.
Preference shareholders represented 0.44% and ordinary shareholders
represented 99.56% of the total issued nominal share capital of the
company (excluding shares held in treasury) as at that date.
158 BP Annual Report and Form 20-F 2011
Additional information for shareholders In accordance with DTR 5, we have received notification that as at
31 December 2011 BlackRock, Inc. held 5.69% and Legal & General
Group Plc held 3.90% of the voting rights of the issued share capital of the
company. As at 17 February 2012 BlackRock, Inc. held 5.37% and Legal
& General Group Plc held 3.99% of the voting rights of the issued share
capital of the company.
Under the US Securities Exchange Act of 1934 we have received
notification of the following interests as at 17 February 2012:
Holder
JPMorgan Chase Bank, depositary for
ADSs, through its nominee Guaranty
Nominees Limited
BlackRock, Inc.
Legal & General Group plc
Percentage
of ordinary
share capital
excluding
shares held
in treasury
Holding of
ordinary shares
5,031,905,448
1,019,731,492
758,363,148
26.51
5.37
4.00
The company’s major shareholders do not have different voting rights.
On 17 May 2011, BP announced that the Rosneft Share Swap
Agreement, originally announced on 14 January 2011, had terminated. For
further information see Legal proceedings on page 166.
The company has also been notified of the following interests in
preference shares as at 17 February 2012:
Holder
The National Farmers Union Mutual
Insurance Society
M & G Investment Management Ltd.
Duncan Lawrie Ltd.
Smith & Williamson Investment
Management Ltd.
Barclays Wealth
Holder
The National Farmers Union Mutual
Insurance Society
M & G Investment Management Ltd.
Royal London Asset Management Ltd.
Smith & Williamson Investment
Management Ltd.
Ruffer LLP
Holding of 8%
cumulative first
preference shares
Percentage of
class
945,000
528,150
426,876
407,250
370,931
13.07
7.30
5.90
5.63
5.13
Holding of 9%
cumulative second
preference shares
Percentage of
class
987,000
644,450
438,000
405,500
294,000
18.03
11.77
8.00
7.41
5.37
Lazard Asset Management Limited disposed of its interests in 374,000
8% cumulative first preference shares and 404,500 9% cumulative second
preference shares during 2011.
Gartmore Investment Management Limited disposed of its interest
in 394,538 8% cumulative first preference shares and 500,000 9%
cumulative second preference shares during 2010.
As at 17 February 2012, the total preference shares in issue
comprised only 0.44% of the company’s total issued nominal share capital
(excluding shares held in treasury), the rest being ordinary shares.
2008
2009
2010
2011
Called-up share capital
Details of the allotted, called-up and fully-paid share capital at 31 December
2011 are set out in Financial statements – Note 38 on page 241.
At the AGM on 14 April 2011, authorization was given to the
directors to allot shares up to an aggregate nominal amount equal to
$3,133 million. Authority was also given to the directors to allot shares for
cash and to dispose of treasury shares, other than by way of rights issue,
up to a maximum of $235 million, without having to offer such shares
to existing shareholders. These authorities are given for the period until
the next AGM in 2012 or 14 July 2012, whichever is the earlier. These
authorities are renewed annually at the AGM.
Dividends
When dividends are paid on its ordinary shares, BP’s policy is to pay
interim dividends on a quarterly basis.
BP policy is also to announce dividends for ordinary shares in US
dollars and state an equivalent sterling dividend. Dividends on BP ordinary
shares will be paid in sterling and on BP ADSs in US dollars. The rate of
exchange used to determine the sterling amount equivalent is the average
of the market exchange rates in London over the four business days prior
to the sterling equivalent 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.
Information regarding dividends announced and paid by the
company on ordinary shares and preference shares is provided in Financial
statements – Note 19 on page 212.
A Scrip Dividend Programme (Programme) was introduced in
2011 which enables BP ordinary shareholders and ADS holders to elect to
receive new fully paid ordinary shares in BP (or ADSs in the case of ADS
holders) instead of cash. The operation of the Programme is always subject
to the directors’ decision to make the scrip offer available in respect of
any particular dividend. Should the directors decide not to offer the scrip in
respect of any particular dividend, cash will automatically be paid instead.
Future dividends will be dependent on future earnings, the financial
condition of the group, the Risk factors set out on pages 59-63 and other
matters that may affect the business of the group set out in Our strategy
on pages 37-41 and in Liquidity and capital resources on page 103.
The following table shows dividends announced and paid by the
company per ADS for each of the past five years.
Dividends per ADS
2007
June September December
31.8
31.7
30.9
64.95
64.95
61.95
UK pence
US cents
Canadian
cents
UK pence
US cents
Canadian
centsa
UK pence
US cents
UK pence
US cents
UK pence
US cents
March
31.5
61.95
73.3
40.9
81.15
80.8
58.91
84
52.07
84
26.02
42
Total
125.9
253.8
274.2
176.3
330.3
63.6
52.2
84.0
108.6
51.07
84
–
–
357.7
218.5
336
52.07
84
26.82 104.42
168
42
69.5
41.0
81.15
82.5
57.50
84
–
–
25.68
42
67.8
42.2
84.0
85.8
51.02
84
–
–
25.90
42
a BP shares were de-listed from the Toronto Stock Exchange on 15 August 2008 and the last
dividend payment in Canadian dollars was made on 8 December 2008.
BP Annual Report and Form 20-F 2011 159
Additional information for shareholdersAdditional information for shareholders Legal proceedings
Proceedings relating to the Deepwater Horizon oil spill
BP p.l.c., BP Exploration & Production Inc. (BP E&P) and various other BP
entities (collectively referred to as BP) are among the companies named
as defendants in approximately 600 private civil lawsuits resulting from the
20 April 2010 explosions and fire on the semi-submersible rig Deepwater
Horizon and resulting oil spill (the Incident) and further actions are likely
to be brought. BP E&P is lease operator of Mississippi Canyon, Block
252 in the Gulf of Mexico (Macondo), where the Deepwater Horizon was
deployed at the time of the Incident. The other working interest owners at
the time of the Incident were Anadarko Petroleum Company (Anadarko)
and MOEX Offshore 2007 LLC (MOEX). The Deepwater Horizon,
which was owned and operated by certain affiliates of Transocean Ltd.
(Transocean), sank on 22 April 2010. The pending lawsuits and/or claims
arising from the Incident have been brought in US federal and state courts.
Plaintiffs include individuals, corporations, insurers, and governmental
entities and many of the lawsuits purport to be class actions. The lawsuits
assert, among others, claims for personal injury in connection with the
Incident itself and the response to it, wrongful death, commercial and
economic injury, breach of contract and violations of statutes. The lawsuits
seek various remedies including compensation to injured workers and
families of deceased workers, recovery for commercial losses and property
damage, claims for environmental damage, remediation costs, claims
for unpaid wages, injunctive and declaratory relief, treble damages and
punitive damages. Purported classes of claimants include residents of
the states of Louisiana, Mississippi, Alabama, Florida, Texas, Tennessee,
Kentucky, Georgia and South Carolina, property owners and rental agents,
fishermen and persons dependent on the fishing industry, charter boat
owners and deck hands, marina owners, gasoline distributors, shipping
interests, restaurant and hotel owners, cruise lines and others who are
property and/or business owners alleged to have suffered economic loss.
Among other claims arising from the spill response efforts, lawsuits have
been filed claiming that additional payments are due by BP under certain
Master Vessel Charter Agreements entered into in the course of the
Vessels of Opportunity Program implemented as part of the response to
the Incident.
Shareholder derivative lawsuits related to the Incident have also
been filed in US federal and state courts against various current and
former officers and directors of BP alleging, among other things, breach
of fiduciary duty, gross mismanagement, abuse of control and waste of
corporate assets. On 15 September 2011, the judge in the federal multi-
district litigation proceeding in Houston granted BP’s motion to dismiss the
consolidated shareholder derivative litigation pending there on the grounds
that the courts of England are the appropriate forum for the litigation. On
8 December 2011, a final judgment was entered dismissing the shareholder
derivative case, and on 3 January 2012, one of the derivative plaintiffs filed
a notice of appeal to the US Court of Appeals for the Fifth Circuit.
On 13 February 2012, the judge in the federal multi-district litigation
proceeding in Houston issued two decisions on the defendants’ motions to
dismiss the two consolidated securities fraud complaints filed on behalf of
purported classes of BP ordinary shareholders and ADS holders. In those
decisions the court dismissed all of the claims of the ordinary shareholders,
dismissed the claims of the lead class of ADS holders against most of the
individual defendants while holding that a subset of the claims against two
individual defendants and the corporate defendants could proceed, and
dismissed all of the claims of a smaller purported subclass with leave to
re-plead in 20 days.
Purported class action lawsuits have been filed in US federal courts
against BP entities and various current and former officers and directors
alleging, among other things, securities fraud claims, violations of the
Employee Retirement Income Security Act (ERISA) and contractual and
quasi-contractual claims related to the cancellation of the dividend on
16 June 2010. In addition, BP has been named in several lawsuits alleging
claims under the Racketeer-Influenced and Corrupt Organizations Act
(RICO). In August 2010, many of the lawsuits pending in federal court were
consolidated by the Federal Judicial Panel on Multidistrict Litigation into
160 BP Annual Report and Form 20-F 2011
two multi-district litigation proceedings, one in federal court in Houston for
the securities, derivative, ERISA and dividend cases and another in federal
court in New Orleans for the remaining cases.
On 1 June 2010, the US Department of Justice (DoJ) announced
that it is conducting an investigation into the Incident encompassing
possible violations of US civil or criminal laws. The types of enforcement
action that might be pursued and the nature of the remedies that might
be sought will depend on the judgement and discretion of the prosecutors
and regulatory authorities and their assessment as to whether BP has
violated any applicable laws and its culpability following their investigations.
Such enforcement actions could include criminal proceedings against
BP and/or employees of the group. Prosecutors have broad discretion in
identifying what, if any, charges to pursue, but such charges could include,
among others, criminal environmental, criminal securities, manslaughter
and obstruction-related offences. The United States filed a civil complaint
in the multi-district litigation proceeding in New Orleans against BP E&P
and others on 15 December 2010 (DoJ Action). The complaint seeks a
declaration of liability under the Oil Pollution Act of 1990 (OPA 90) and civil
penalties under the Clean Water Act and sets forth a purported reservation
of rights on behalf of the US to amend the complaint or file additional
complaints seeking various remedies under various US federal laws
and statutes. On 8 December 2011, the US brought a motion for partial
summary judgment seeking, among other things, an order finding that BP,
Transocean, and Anadarko are strictly liable for a civil penalty under Section
311(b) (7)(A) of the Clean Water Act. This motion remains pending.
On 18 February 2011, Transocean filed a third-party complaint
against BP, the US government, and other corporations involved in the
Incident, naming those entities as formal parties in its Limitation of Liability
action pending in federal court in New Orleans.
On 4 April 2011, BP initiated contractual out-of-court dispute
resolution proceedings against Anadarko and MOEX, claiming that
they have breached the parties’ contract by failing to reimburse BP
for their working-interest share of Incident-related costs. On 19 April
2011, Anadarko filed a cross-claim against BP, alleging gross negligence
and 15 other counts under state and federal laws. Anadarko sought a
declaration that it was excused from its contractual obligation to pay
Incident-related costs. Anadarko also sought damages from alleged
economic losses and contribution or indemnity for claims filed against it
by other parties. On 20 May 2011, BP and MOEX announced a settlement
agreement of all claims between them, including a cross-claim brought
by MOEX on 19 April 2011 similar to the Anadarko claim. Under the
settlement agreement, MOEX has paid BP $1.065 billion, which BP has
applied towards the $20-billion Trust and has also agreed to transfer all of
its 10% interest in the MC252 lease to BP. On 17 October 2011, BP and
Anadarko announced that they had reached a final agreement to settle all
claims between the companies related to the Incident, including mutual
releases of all claims between BP and Anadarko that are subject to the
contractual out-of-court dispute resolution proceedings or the federal
multi-district litigation proceeding in New Orleans. Under the settlement
agreement, Anadarko has paid BP $4 billion, which BP has applied towards
the $20-billion Trust, and has also agreed to transfer all of its 25% interest
in the MC252 lease to BP. The settlement agreement also grants Anadarko
the opportunity for a 12.5% participation in certain future recoveries
from third parties and certain insurance proceeds in the event that such
recoveries and proceeds exceed $1.5 billion in aggregate. Any such
payments to Anadarko are capped at a total of $1 billion. BP has agreed to
indemnify Anadarko and MOEX for certain claims arising from the Incident
(excluding civil, criminal or administrative fines and penalties, claims for
punitive damages, and certain other claims). The settlement agreements
with Anadarko and MOEX are not an admission of liability by any party
regarding the Incident.
On 20 April 2011, Transocean filed claims in its Limitation of
Liability action alleging that BP had breached BP America Production
Company’s contract with Transocean Holdings LLC by BP not agreeing
to indemnify Transocean against liability related to the Incident and by not
paying certain invoices. Transocean also asserted claims against BP under
state law, maritime law, and OPA 90 for contribution. On 1 November
2011, Transocean filed a motion for partial summary judgment on certain
claims filed in the Limitation Action and the DoJ Action between BP and
Transocean. Transocean’s motion sought an order which would bar BP’s
Additional information for shareholders contribution claims against Transocean and require BP to defend and
indemnify Transocean against all pollution claims, including those resulting
from any gross negligence, and from civil fines and penalties sought by the
government. On 7 December 2011, BP filed a cross-motion for
summary judgment seeking an order that BP is not required to indemnify
Transocean for any civil fines and penalties sought by the government or
for punitive damages.
On 26 January 2012, the judge ruled on BP’s and Transocean’s
indemnity motions, holding that BP is required to indemnify Transocean
for third-party claims for compensatory damages resulting from pollution
originating beneath the surface of the water, regardless of whether
the claim results from Transocean’s strict liability, negligence, or gross
negligence. The court, however, ruled that BP does not owe Transocean
indemnity for such claims to the extent Transocean is held liable for
punitive damages or for civil penalties under the Clean Water Act, or
if Transocean acted with intentional or wilful misconduct in excess of
gross negligence. The court further held that BP’s obligation to defend
Transocean for third-party claims does not require BP to fund Transocean’s
defence of third-party claims at this time, nor does it include Transocean’s
expenses in proving its right to indemnity. The court deferred a final ruling
on the question of whether Transocean breached its drilling contract with
BP so as to invalidate the contract’s indemnity clause.
On 22 February 2012, the judge ruled on motions filed in the
DoJ Action by the US, Anadarko, and Transocean seeking early rulings
regarding the liability of BP, Anadarko, and Transocean under OPA 90 and
the Clean Water Act, but limited the order to addressing the discharge of
hydrocarbons occurring under the surface of the water. Regarding OPA
90, the judge held that BP and Anadarko are responsible parties under
OPA 90 with regard to the subsurface discharge. The judge ruled that BP
and Anadarko have joint and several liability under OPA 90 for removal
costs and damages for such discharge, but did not rule on whether such
liability under OPA 90 is unlimited. While the judge held that Transocean
is not a responsible party under OPA 90 for subsurface discharge, the
judge left open the question of whether Transocean may be liable under
OPA 90 for removal costs for such discharge as the owner/operator of the
Deepwater Horizon. Regarding the Clean Water Act, the judge held that
the subsurface discharge was from the Macondo well, rather than from the
Deepwater Horizon, and that BP and Anadarko are liable for civil penalties
under Section 311 of the Clean Water Act as owners of the well. The judge
left open the question of whether Transocean may be liable under the
Clean Water Act as an operator of the Macondo well.
On 20 April 2011, Halliburton Energy Services, Inc. (Halliburton),
filed claims in Transocean’s Limitation of Liability action seeking
indemnification from BP for claims brought against Halliburton in that
action, and Cameron International Corporation (Cameron) asserted claims
against BP for contribution under state law, maritime law, and OPA 90, as
well as for contribution on the basis of comparative fault. Halliburton also
asserted a claim for negligence, gross negligence and wilful misconduct
against BP and others. On 19 April 2011, Halliburton filed a separate
lawsuit in Texas state court seeking indemnification from BP E&P for
certain tort and pollution-related liabilities resulting from the Incident. On
3 May 2011, BP E&P removed Halliburton’s case to federal court, and
on 9 August 2011, the action was transferred to the federal multi-district
litigation proceedings pending in New Orleans.
Subsequently, on 30 November 2011, Halliburton filed a motion
for summary judgment in the federal multi-district litigation proceedings
pending in New Orleans. Halliburton’s motion seeks an order stating that
Halliburton is entitled to full and complete indemnity, including payment of
defence costs, from BP for claims related to the Incident and denying BP’s
claims seeking contribution against Halliburton. On 21 December 2011, BP
filed a cross-motion for partial summary judgment seeking an order that BP
has no contractual obligation to indemnify Halliburton for fines, penalties, or
punitive damages resulting from the Incident.
On 31 January 2012, the judge ruled on BP’s and Halliburton’s
indemnity motions, holding that BP is required to indemnify Halliburton for
third-party claims for compensatory damages resulting from pollution that
did not originate from property or equipment of Halliburton located above
the surface of the land or water, regardless of whether the claims result
from Halliburton’s gross negligence. The court, however, ruled that BP
does not owe Halliburton indemnity to the extent that Halliburton is held
liable for punitive damages or for civil penalties under the Clean Water
Act. The court further held that BP’s obligation to defend Halliburton for
third-party claims does not require BP to fund Halliburton’s defence of
third-party claims at this time, nor does it include Halliburton’s expenses in
proving its right to indemnity. The court deferred ruling on whether BP is
required to indemnify Halliburton for any penalties or fines under the Outer
Continental Shelf Lands Act. It also deferred ruling on whether Halliburton
acted so as to invalidate the indemnity by breaching its contract with BP,
by committing fraud, or by committing another act that materially increased
the risk to BP or prejudiced the rights of BP as an indemnitor.
On 1 September 2011, Halliburton filed an additional lawsuit
against BP in Texas state court. Its complaint alleges that BP did not
identify the existence of a purported hydrocarbon zone at the Macondo
well to Halliburton in connection with Halliburton’s cement work performed
before the Incident and that BP has concealed the existence of this
purported hydrocarbon zone following the Incident. Halliburton claims that
the alleged failure to identify this information has harmed its business
ventures and reputation and resulted in lost profits and other damages. On
16 September 2011, BP removed the action to federal court, where it was
stayed pending a decision by the Judicial Panel on Multidistrict Litigation
on transfer of the action to the multi-district litigation proceeding in New
Orleans. On 1 September 2011, Halliburton also moved to amend its
claims in Transocean’s Limitation of Liability action to add claims for fraud
based on similar factual allegations to those included in its 1 September
2011 lawsuit against BP in Texas state court. On 11 October 2011, the
magistrate judge in the federal multi-district litigation proceeding in New
Orleans denied Halliburton’s motion to amend its claims, and Halliburton’s
motion to review the order was denied by the judge on 19 December
2011.
On 20 April 2011, BP asserted claims against Cameron, Halliburton,
and Transocean in the Limitation of Liability action. BP’s claims against
Transocean include breach of contract, unseaworthiness of the Deepwater
Horizon vessel, negligence (or gross negligence and/or gross fault as
may be established at trial based upon the evidence), contribution and
subrogation for costs (including those arising from litigation claims)
resulting from the Incident, as well as a declaratory claim that Transocean
is wholly or partly at fault for the Incident and responsible for its
proportionate share of the costs and damages. BP asserted claims against
Halliburton for fraud and fraudulent concealment based on Halliburton’s
misrepresentations to BP concerning, among other things, the stability
testing on the foamed cement used at the Macondo well; for negligence
(or, if established by the evidence at trial, gross negligence) based on
Halliburton’s performance of its professional services, including cementing
and mud logging services; and for contribution and subrogation for
amounts that BP has paid in responding to the Incident, as well as in OPA
assessments and in payments to plaintiffs. BP filed a similar complaint in
federal court in the Southern District of Texas, Houston Division, against
Halliburton, and the action was transferred on 4 May 2011 to the federal
multi-district litigation proceeding pending in New Orleans.
On 20 April 2011, BP filed claims against Cameron, Halliburton, and
Transocean in the DoJ Action, seeking contribution for any assessments
against BP under OPA 90 based on those entities’ fault. On 20 June 2011,
Cameron and Halliburton moved to dismiss BP’s claims against them in
the DoJ Action. BP’s claim against Cameron has been resolved pursuant to
settlement, but Halliburton’s motion remains pending.
On 16 December 2011, BP and Cameron announced their
agreement to settle all claims between the companies related to the
Incident, including mutual releases of claims between BP and Cameron
that are subject to the federal multi-district litigation proceeding in New
Orleans. Under the settlement agreement, Cameron has paid BP $250
million in cash in January 2012, which BP has applied towards the
$20-billion Trust. BP has agreed to indemnify Cameron for compensatory
claims arising from the Incident, including claims brought relating to
pollution damage or any damage to natural resources, but excluding civil,
criminal or administrative fines and penalties, claims for punitive damages,
and certain other claims.
On 20 May 2011, Dril-Quip, Inc. and M-I L.L.C. (M-I) filed claims
against BP in Transocean’s Limitation of Liability action, each claiming
a right to contribution from BP for damages assessed against them as
a result of the Incident, based on allegations of negligence. M-I also
BP Annual Report and Form 20-F 2011 161
Additional information for shareholdersAdditional information for shareholders claimed a right to indemnity for such damages based on its well services
contracts with BP. On 20 June 2011, BP filed counter-complaints against
Dril-Quip, Inc. and M-I, asking for contribution and subrogation based on
those entities’ fault in connection with the Incident and under OPA 90,
and seeking declaratory judgment that Dril-Quip, Inc. and M-I caused or
contributed to, and are responsible in whole or in part for damages incurred
by BP in relation to, the Incident. On 20 January 2012, the court granted
Dril-Quip, Inc.’s motion for summary judgment, dismissing with prejudice
all claims asserted against Dril-Quip in the federal multi-district litigation
proceeding in New Orleans.
On 21 January 2012, BP and M-I entered into an agreement settling
all claims between the companies related to the Incident, including mutual
releases of claims between BP and M-I that are subject to the federal
multi-district litigation proceeding in New Orleans. Under the settlement
agreement, M-I has agreed to indemnify BP for personal injury and death
claims brought by M-I employees. BP has agreed to indemnify M-I for
claims resulting from the Incident, but excluding certain claims.
On 30 May 2011, Transocean filed claims against BP in the DoJ
Action alleging that BP America Production Company had breached its
contract with Transocean Holdings LLC by not agreeing to indemnify
Transocean against liability related to the Incident. Transocean also
asserted claims against BP under state law, maritime law, and OPA 90 for
contribution. On 20 June 2011, Cameron filed similar claims against BP in
the DoJ Action.
On 26 August 2011, the judge in the federal multi-district litigation
proceeding in New Orleans granted in part BP’s motion to dismiss a
master complaint raising claims for economic loss by private plaintiffs,
dismissing plaintiffs’ state law claims and limiting the types of maritime law
claims plaintiffs may pursue, but also held that certain classes of claimants
may seek punitive damages under general maritime law. The judge did not,
however, lift an earlier stay on the underlying individual complaints raising
those claims or otherwise apply his dismissal of the master complaint to
those individual complaints.
On 14 September 2011, the BOEMRE issued its report (BOEMRE
Report) regarding the causes of the 20 April 2010 Macondo well blowout.
The BOEMRE Report states that decisions by BP, Halliburton and
Transocean increased the risk or failed to fully consider or mitigate the
risk of a blowout on 20 April 2010. The BOEMRE Report also states that
BP, and Transocean and Halliburton, violated certain regulations related
to offshore drilling. In itself, the BOEMRE Report does not constitute
the initiation of enforcement proceedings relating to any violation. On
12 October 2011, the U.S. Department of the Interior Bureau of Safety
and Environmental Enforcement issued to BP E&P, Transocean, and
Halliburton Notification of Incidents of Noncompliance (INCs). The
notification issued to BP E&P is for a number of alleged regulatory
violations concerning Macondo well operations. The Department of
Interior has indicated that this list of violations may be supplemented as
additional evidence is reviewed, and on 7 December 2011, the Bureau of
Safety and Environmental Enforcement issued to BP E&P a second INC.
This notification was issued to BP for five alleged violations related to
drilling and abandonment operations at the Macondo well. BP has filed an
administrative appeal with respect to the first and second INCs. BP has
also filed a joint stay of proceedings with the Department of Interior with
respect to the 12 October 2011 INCs and plans to file a joint stay regarding
the 7 December 2011 INCs.
On 30 September 2011, the judge in the federal multi-district
litigation proceeding in New Orleans granted in part BP’s motion to dismiss
a master complaint asserting personal injury claims on behalf of persons
exposed to crude oil or chemical dispersants, dismissing plaintiffs’ state
law claims, claims by seamen for punitive damages, claims for medical
monitoring damages by asymptomatic plaintiffs, claims for battery and
nuisance under maritime law, and claims alleging negligence per se. As
with his other rulings on motions to dismiss master complaints, the judge
did not lift an earlier stay on the underlying individual complaints raising
those claims or otherwise apply his dismissal of the master complaint to
those individual complaints.
A Trial of Liability, Limitation, Exoneration, and Fault Allocation
was originally scheduled to begin in the federal multi-district litigation
proceeding in New Orleans in February 2012. The court’s pre-trial order
issued 14 September 2011 provided for the trial to proceed in three phases
162 BP Annual Report and Form 20-F 2011
and to include issues asserted in or relevant to the claims, counterclaims,
cross-claims, third-party claims, and comparative fault defences raised in
Transocean’s Limitation of Liability Action.
On 18 October 2011, Cameron filed a petition for writ of mandamus
with US Court of Appeals for the Fifth Circuit seeking an order vacating the
trial plan for the 27 February 2012 trial and requiring that all claims against
Cameron in that proceeding be tried before a jury. On 26 December 2011,
the Court of Appeals denied the application for mandamus.
The State of Alabama has filed a lawsuit seeking damages for
alleged economic and environmental harms, including natural resource
damages, civil penalties under state law, declaratory and injunctive
relief, and punitive damages as a result of the Incident. The State of
Louisiana has filed a lawsuit to declare various BP entities (as well as
other entities) liable for removal costs and damages, including natural
resource damages under federal and state law, to recover civil penalties,
attorney’s fees, and response costs under state law, and to recover
for alleged negligence, nuisance, trespass, fraudulent concealment
and negligent misrepresentation of material facts regarding safety
procedures and BP’s (and other defendants’) ability to manage the
oil spill, unjust enrichment from economic and other damages to the
State of Louisiana and its citizens, and punitive damages. The Louisiana
Department of Environmental Quality has issued an administrative order
seeking environmental civil penalties and other relief under state law.
On 23 September 2011, BP removed this matter to federal district court.
Several local governments in the State of Louisiana have filed suits
under state wildlife statutes seeking penalties for damage to wildlife as a
result of the spill. On 10 December 2010, the Mississippi Department of
Environmental Quality issued a Complaint and Notice of Violation alleging
violations of several state environmental statutes.
On 14 November 2011, the judge in the federal multi-district
litigation proceeding in New Orleans granted in part BP’s motion to
dismiss the complaints filed by the States of Alabama and Louisiana.
The judge’s order dismissed the States’ claims brought under state law,
including claims for civil penalties and the State of Louisiana’s request
for a declaratory judgment under the Louisiana Oil Spill Prevention and
Response Act, holding that those claims were pre-empted by federal
law. It also dismissed the State of Louisiana’s claims of nuisance and
trespass under general maritime law. The judge’s order further held that
the States have stated claims for negligence and products liability under
general maritime law, that the States have sufficiently alleged presentment
of their claims under OPA 90, and that the States may seek punitive
damages under general maritime law. On 9 December 2011, the judge
in the federal multi-district litigation proceeding in New Orleans granted
in part BP’s motion to dismiss a master complaint brought on behalf of
local government entities. The judge’s order dismissed plaintiffs’ state law
claims and limited the types of maritime law claims plaintiffs may pursue,
but also held that the plaintiffs have sufficiently alleged presentment
of their claims under OPA 90 and that certain local government entity
claimants may seek punitive damages under general maritime law. The
judge did not, however, lift an earlier stay on the underlying individual
complaints raising those claims or otherwise apply his dismissal of the
master complaint to those individual complaints.
On 9 December 2011 and 28 December 2011, the judge in the
federal multi-district litigation proceeding in New Orleans also granted BP’s
motions to dismiss complaints filed by the District Attorneys of 11 parishes
in the State of Louisiana seeking penalties for damage to wildlife, holding
that those claims are pre-empted by the Clean Water Act. Many of the
parishes have filed notices of appeal to the U.S. Court of Appeals for the
Fifth Circuit.
On 3 March 2012, BP announced a settlement with the Plaintiffs’
Steering Committee (PSC) in the federal Multi-District Litigation
proceedings pending in New Orleans (MDL 2179) to resolve the substantial
majority of legitimate private economic loss and medical claims stemming
from the Incident. The agreement in principle is subject to final written
agreement and court approvals.
The proposed settlement is comprised of two separate
agreements. The first of these resolves economic loss claims and the
other resolves medical claims. The proposed agreement to resolve
economic loss claims includes a $2.3 billion BP commitment to help
resolve economic loss claims related to the Gulf seafood industry and a
Additional information for shareholders fund to support continued advertising that promotes Gulf Coast tourism.
It also resolves claims for additional payments under certain Master
Vessel Charter Agreements entered into in the course of the Vessels of
Opportunity Program implemented as part of the response to the Incident.
The proposed agreement to resolve medical claims involves
payments based on a matrix for certain currently manifested physical
conditions, as well as a 21-year medical consultation programme for
qualifying class members. It also provides that class members claiming
later-manifested physical conditions may pursue their claims through a
mediation/litigation process. Consistent with its commitment to the Gulf,
BP has also agreed to provide $105 million to improve the availability,
scope and quality of healthcare in Gulf communities. This healthcare
outreach programme would be available to all individuals in those
communities, regardless of whether they are class members.
Each proposed agreement provides that class members would be
compensated for their claims on a claims-made basis, according to agreed
compensation protocols in separate court-supervised claims processes.
The compensation protocols under the proposed economic loss settlement
agreement include a risk transfer premium (RTP). The RTP is an agreed
factor to be used in calculating certain types of damages, including
potential future damages that are not currently known, relating to the
Incident.
BP estimates the cost of the proposed settlement would be
approximately $7.8 billion (including the $2.3 billion commitment to
help resolve economic loss claims related to the Gulf seafood industry).
While this is BP’s reliable best estimate of the cost of the proposed
settlement, it is possible that the actual cost could be higher or lower
than this estimate depending on the outcomes of the court-supervised
claims processes. In accordance with its normal procedures, BP will
re-evaluate the assumptions underlying this estimate on a quarterly basis
as more information, including the outcomes of the court-supervised
claims processes, becomes available. (For more information, see Financial
statements – Note 36.)
At this time, BP expects all settlements under these agreements
to be paid from the Trust. Other costs to be paid from the Trust include
state and local government claims, state and local response costs,
natural resource damages and related claims, and final judgments and
settlements. It is not possible at this time to determine whether the Trust
will be sufficient to satisfy all of these claims as well as those under the
proposed settlement. Should the Trust not be sufficient, payments under
the proposed settlement would be made by BP directly.
The proposed economic loss settlement provides for a transition
from the Gulf Coast Claims Facility (GCCF) to a new court-supervised
claims programme, to administer payments made to qualifying class
members. A court-supervised transitional claims process will be in
operation while the infrastructure for the new settlement claims process
is put in place. During this transitional period, the processing of claims
that have been submitted to the GCCF will continue, and new claimants
may submit their claims. BP has agreed not to wait for final approval of
the economic loss settlement before claims are paid. The economic loss
claims process will continue under court supervision before final approval
of the settlement, first under the transitional claims process, and then
through the settlement claims process established by the proposed
economic loss settlement.
Under the proposed settlement, class members would release and
dismiss their claims against BP. The proposed settlement also provides
that, to the extent permitted by law, BP will assign to the PSC certain of
its claims, rights and recoveries against Transocean and Halliburton for
damages with protections such that Transocean and Halliburton cannot
pass those damages through to BP.
The proposed settlement is subject to reaching definitive and fully-
documented agreements within 45 days of 2 March 2012, and if those
agreements are not reached, either party has the right to terminate the
proposed settlement. Once definitive agreements have been reached, BP
and the PSC will seek the court’s preliminary approval of the settlement.
Under US federal law, there is an established procedure for determining
the fairness, reasonableness and adequacy of class action settlements.
Pursuant to this procedure, and subject to the court granting preliminary
approval of both agreements, there would be an extensive outreach
programme to the public to explain settlement agreements and class
members’ rights, including the right to “opt out” of the classes, and the
processes for making claims. The court would then conduct fairness
hearings at which class members and various other parties would have an
opportunity to be heard and present evidence and decide whether or not to
approve each proposed settlement agreement. Should the number of class
members opting out exceed an agreed and court-approved threshold, BP
will have the right to terminate the proposed settlement.
The proposed settlement does not include claims made against
BP by the DoJ or other federal agencies (including under the Clean Water
Act and for Natural Resource Damages under the Oil Pollution Act) or by
the states and local governments. Also excluded are certain other claims
against BP, such as securities and shareholder claims pending in MDL
2185, and claims based solely on the deepwater drilling moratorium and/or
the related permitting process.
The court has subsequently ordered that the first phase of the trial
be adjourned. The court will schedule a status conference to discuss issues
raised by the proposed settlement and to set a new trial date.
On 15 September 2010, three Mexican states bordering the Gulf of
Mexico (Veracruz, Quintana Roo, and Tamaulipas) filed lawsuits in federal
court in Texas against several BP entities. These lawsuits allege that the
Incident harmed their tourism, fishing, and commercial shipping industries
(resulting in, among other things, diminished tax revenue), damaged natural
resources and the environment, and caused the states to incur expenses
in preparing a response to the Incident. On 9 December 2011, the judge
in the federal multi-district litigation proceeding in New Orleans granted
in part BP’s motion to dismiss the three Mexican states’ complaints,
dismissing their claims under OPA 90 and for nuisance and negligence
per se, and preserving their claims for negligence and gross negligence
only to the extent there has been a physical injury to a proprietary
interest of the states. On 5 April 2011, the State of Yucatan submitted
a claim to the GCCF alleging potential damage to its natural resources
and environment, and seeking to recover the cost of assessing the
alleged damage. BP anticipates further claims from the Mexican federal
government.
Citizens groups have also filed either lawsuits or notices of intent
to file lawsuits seeking civil penalties and injunctive relief under the Clean
Water Act and other environmental statutes. On 16 June 2011, the judge
in the federal multi-district litigation proceeding in New Orleans granted
BP’s motion to dismiss a master complaint raising claims for injunctive
relief under various federal environmental statutes brought by various
citizens groups and others. The judge did not, however, lift an earlier stay
on the underlying individual complaints raising those claims for injunctive
relief or otherwise apply his dismissal of the master complaint to those
individual complaints. In addition, a different set of environmental groups
filed a motion to reconsider dismissal of their Endangered Species Act
claims on 14 July 2011. That motion remains pending. On 31 January
2012, the court, on motion by the Center for Biological Diversity, entered
final judgment on the basis of the 16 June 2011 order with respect to two
actions brought against BP by that plaintiff. On 2 February 2012, the Center
for Biological Diversity filed a notice of appeal of both actions.
On 15 July 2011, the judge granted BP’s motion to dismiss a
master complaint raising RICO claims against BP. The court’s order
dismissed the claims of the plaintiffs in four RICO cases encompassed by
the master complaint.
The DoJ announced on 7 March 2011 that it created a unified task
force of federal agencies, led by the DoJ Criminal Division, to investigate
the Incident. Other US federal agencies may commence investigations
relating to the Incident. The SEC and DoJ are investigating securities
matters arising in relation to the Incident.
On 21 April 2011, BP entered a framework agreement with natural
resource trustees for the US and five Gulf coast states, providing for up
to $1 billion to be spent on early restoration projects to address natural
resource injuries resulting from the Incident. Funding for these projects will
come from the $20-billion Trust fund.
BP’s potential liabilities resulting from threatened, pending and
potential future claims, lawsuits and enforcement actions relating to
the Incident, together with the potential cost of implementing remedies
sought in the various proceedings, cannot be fully estimated at this time
but they have had and are expected to have a material adverse impact
on the group’s business, competitive position, cash flows, prospects,
BP Annual Report and Form 20-F 2011 163
Additional information for shareholdersAdditional information for shareholders liquidity, shareholder returns and/or implementation of its strategic agenda,
particularly in the US. These potential liabilities may continue to have a
material adverse effect on the group’s results and financial condition. See
Financial statements – Note 2 on pages 190-194 for information regarding
the financial impact of the Incident.
Investigations and reports relating to the Deepwater Horizon oil spill
BP is subject to a number of investigations related to the Incident by
numerous agencies of the US government. The related published reports
are available on the websites of the agencies and commissions referred to
below.
On 11 January 2011, the National Commission on the BP
Deepwater Horizon Oil Spill and Offshore Drilling (National Commission),
established by President Obama, published its report on the causes of the
Incident and its recommendations for policy and regulatory changes for
offshore drilling. On 17 February 2011, the National Commission’s Chief
Counsel published a separate report on his investigation that provides
additional information regarding the causes of the Incident.
In a report dated 20 March 2011, with an Addendum dated
30 April 2011, the Joint Investigation Team (JIT) for the Marine Board of
Investigation established by the US Coast Guard and Bureau of Ocean
Energy Management (BOEMRE) issued the Final Report of the Forensic
Examination of the Deepwater Horizon Blowout Preventer (BOP) prepared
by Det Norske Veritas (BOP Report). The BOP Report concludes that
the position of the drill pipe against the blind shear rams prevented the
BOP from functioning as intended. Subsequently, BP helped to sponsor
additional BOP testing conducted by Det Norske Veritas under court
auspices, which concluded on 21 June 2011. BP continues to review the
BOP Report and is in the process of evaluating the data obtained from the
additional testing.
On 22 April 2011, the US Coast Guard issued its report (Maritime
Report) focused upon the maritime aspects of the Incident. The Maritime
Report criticizes Transocean’s maintenance operations and safety culture,
while also criticizing the Republic of the Marshall Islands – the flag state
responsible for certifying Transocean’s Deepwater Horizon vessel.
The US Chemical Safety and Hazard Investigation Board (CSB)
is also conducting an investigation of the Incident that is focused on the
explosions and fire, and not the resulting oil spill or response efforts. The
CSB is expected to issue a single investigation report in 2012 that will
seek to identify the alleged root cause(s) of the Incident, and recommend
improvements to BP and industry practices and to regulatory programmes
to prevent recurrence and mitigate potential consequences.
Also, at the request of the Department of the Interior, the National
Academy of Engineering/National Research Council established a
Committee (Committee) to examine the performance of the technologies
and practices involved in the probable causes of the Incident and to identify
and recommend technologies, practices, standards and other measures to
avoid similar future events. On 17 November 2010, the Committee publicly
released its interim report setting forth the Committee’s preliminary
findings and observations on various actions and decisions including well
design, cementing operations, well monitoring, and well control actions.
The interim report also considers management, oversight, and regulation of
offshore operations. On 14 December 2011, the Committee published its
final report, including findings and recommendations. A second, unrelated
National Academies Committee will be looking at the methodologies
available for assessing spill impacts on ecosystem services in the Gulf of
Mexico, with a final report expected in late 2012 or early 2013, and a third
National Academies Committee will be studying methods for assessing the
effectiveness of safety and environmental management systems (SEMS)
established by offshore oil and gas operators.
On 10 March 2011, the Flow Rate Technical Group (FRTG),
Department of the Interior, issued its final report titled “Assessment
of Flow Rate Estimates for the Deepwater Horizon/Macondo Well Oil
Spill.” The report provides a summary of the strengths and limitations of
the different methods used by the US government to estimate the flow
rate and a range of estimates from 13,000 b/d to over 100,000 b/d. The
report concludes that the most accurate estimate was 53,000 b/d just
prior to shut in, with an uncertainty on that value of ±10% based on FRTG
collective experience and judgement, and, based on modelling, the flow on
day one of the Incident was 62,000 b/d.
164 BP Annual Report and Form 20-F 2011
On 18 March 2011, the US Coast Guard ISPR team released its final
report capturing lessons learned from the Incident as well as making
recommendations on how to improve future oil spill response and recovery
efforts.
Additionally, since April 2010, BP representatives have testified
multiple times before the US Congress regarding the Incident. BP has
provided documents and written information in response to requests from
Members, committees and subcommittees of the US Congress.
Other legal proceedings
The US Federal Energy Regulatory Commission (FERC) and the US
Commodity Futures Trading Commission (CFTC) are currently investigating
several BP entities regarding trading in the next-day natural gas market at
Houston Ship Channel during September, October and November 2008.
The FERC Office of Enforcement staff notified BP on 12 November 2010
of their preliminary conclusions relating to alleged market manipulation in
violation of 18 C.F.R. Sec. 1c.1. On 30 November 2010, CFTC Enforcement
staff also provided BP with a notice of intent to recommend charges
based on the same conduct alleging that BP engaged in attempted market
manipulation in violation of Section 6(c), 6(d), and 9(a)(2) of the Commodity
Exchange Act. On 23 December 2010, BP submitted responses to the
FERC and CFTC November 2010 notices providing a detailed response
that it did not engage in any inappropriate or unlawful activity. On 28 July
2011, the FERC staff issued a Notice of Alleged Violations stating that it
had preliminarily determined that several BP entities fraudulently traded
physical natural gas in the Houston Ship Channel and Katy markets
and trading points to increase the value of their financial swing spread
positions. Other investigations into BP’s trading activities continue to be
conducted from time to time.
On 23 March 2005, an explosion and fire occurred in the
isomerization unit of BP Products North America’s (BP Products) Texas
City refinery as the unit was coming out of planned maintenance. Fifteen
workers died in the incident and many others were injured. BP Products
has resolved all civil injury claims arising from the March 2005 incident.
In March 2007, the US Chemical Safety and Hazard Investigation
Board (CSB) issued a report on the incident. The report contained
recommendations to the Texas City refinery and to the board of directors
of BP. In May 2007, BP responded to the CSB’s recommendations. BP and
the CSB will continue to discuss BP’s responses with the objective of the
CSB’s agreeing to close out its recommendations.
On 25 October 2007, the DoJ announced that it had entered
into a criminal plea agreement with BP Products related to the March
2005 explosion and fire. On 4 February 2008, BP Products pleaded
guilty, pursuant to the plea agreement, to one felony violation of the risk
management planning regulations promulgated under the US Clean Air
Act (CAA) and on 12 March 2009, the court accepted the plea agreement.
In connection with the plea agreement, BP Products paid a $50-million
criminal fine and was sentenced to three years’ probation which is set
to expire on 12 March 2012. Compliance with a 2005 US Occupational
Safety and Health Administration (OSHA) settlement agreement (2005
Agreement) and a 2006 agreed order entered into by BP Products with
the Texas Commission on Environmental Quality (TCEQ) are conditions of
probation.
The Texas Office of Attorney General, on behalf of the Texas
Commission on Environmental Quality (TCEQ), has filed a petition against
BP Products asserting certain air emissions and reporting violations at the
Texas City refinery from 2005 to 2010. BP Products settled this lawsuit by
an Agreed Final Judgment entered by the court on 20 December 2011.
The Texas Attorney General filed a separate petition against BP
Products asserting emissions violations relating to a 6 April 2010 flaring
event. This lawsuit was also settled by the Agreed Final Judgment
mentioned in the preceding paragraph. This emissions event is also the
subject of a number of civil suits by many area workers and residents
alleging personal injury and property damages and seeking substantial
damages. In addition, this emissions event is the subject of a federal
governmental investigation.
In September 2009, BP Products filed a petition to clarify specific
required actions and deadlines under the 2005 Agreement with OSHA.
That agreement resolved citations issued in connection with the March
2005 Texas City refinery explosion. OSHA denied BP Products’ petition.
Additional information for shareholders In October 2009 OSHA issued citations to the Texas City refinery seeking
a total of $87.4 million in civil penalties for alleged violations of the 2005
Agreement and alleged process safety management violations.
A settlement agreement between BP Products and OSHA in
August 2010 (2010 Agreement) resolved the petition filed by BP Products
in September 2009 and the alleged violations of the 2005 Agreement.
BP Products has paid a penalty of $50.6 million in that matter and
agreed to perform certain abatement actions. Compliance with the 2010
Agreement (which is set to expire on 12 March 2012) is also a condition of
probation due to the linkage between this 2010 Agreement and the 2005
Agreement.
On 6 May 2010, certain persons qualifying under the US Crime
Victims’ Rights Act as victims in relation to the Texas City plea agreement
requested that the federal court revoke BP Products’ probation based
on alleged violations of the Court’s conditions of probation. The alleged
violations of probation relate to the alleged failure to comply with the 2005
Agreement.
The OSHA process safety management citations issued in October
2009 were not resolved by the August 2010 settlement agreement.
The proposed penalties in that matter are $30.7 million. The matter is
currently before the OSH Review Commission which has assigned an
Administrative Law Judge for purposes of mediation. These citations do
not allege violations of the 2005 Agreement.
A shareholder derivative action was filed against several current
and former BP officers and directors based on alleged violations of the US
Clean Air Act (CAA) and Occupational Safety and Health Administration
(OSHA) regulations at the Texas City refinery subsequent to the March
2005 explosion and fire. An investigation by a special committee of
BP’s board into the shareholder allegations has been completed and the
committee has recommended that the allegations do not warrant action
by BP against the officers and directors. BP filed a motion to dismiss the
shareholder derivative action and a plea to the jurisdiction. On 16 June
2011, the court granted BP’s plea to the jurisdiction and dismissed the
action in its entirety. The shareholder has appealed the dismissal and the
appeal is pending.
In March and August 2006, oil leaked from oil transit pipelines
operated by BP Exploration (Alaska) Inc. (BPXA) at the Prudhoe Bay unit
on the North Slope of Alaska. Several legal proceedings resulted from
these events. On 29 November 2007, BPXA entered into a criminal plea
agreement with the DoJ relating to these leaks. BPXA’s guilty plea, to a
misdemeanour violation of the US Water Pollution Control Act, included
a term of three years’ probation. On 29 November 2009, a spill of
approximately 360 barrels of crude oil and produced water was discovered
beneath a line running from a well pad to the Lisburne Processing Center
in Prudhoe Bay, Alaska. On 17 November 2010, the US Probation Officer
filed a petition in federal district court to revoke BPXA’s probation based
on allegations that the Lisburne event was a criminal violation of state
and federal law and therefore BPXA was in violation of its probation
obligations. BPXA contested the petition at an evidentiary hearing that
was completed on 7 December 2011 in U.S. District Court in Anchorage,
Alaska. On 27 December 2011, the Court issued a decision and order
finding that BPXA did not violate the terms of its probation, dismissing the
government’s petition and terminating BPXA’s probation.
On 12 May 2008, a BP p.l.c. shareholder filed a consolidated
complaint alleging violations of federal securities law on behalf of a putative
class of BP p.l.c. shareholders against BP p.l.c., BPXA, BP America, and
four officers of the companies, based on alleged misrepresentations
concerning the integrity of the Prudhoe Bay pipeline before its shutdown
on 6 August 2006. On 8 February 2010, the Ninth Circuit Court of Appeals
accepted BP’s appeal from a decision of the lower court granting in part
and denying in part BP’s motion to dismiss the lawsuit. On 29 June
2011, the Ninth Circuit ruled in BP’s favour that the filing of a trust related
agreement with the SEC containing contractual obligations on the part of
BP was not a misrepresentation which violated federal securities laws. The
BP p.l.c. shareholder has filed an amended complaint, in response to which
BP filed a new motion to dismiss, which is pending. On 31 March 2009,
the United States filed a complaint seeking civil penalties and damages
relating to the events at Prudhoe Bay. The complaint also involved claims
related to asbestos handling, allegations of non-compliance at multiple
facilities for failure to comply with EPA’s spill prevention plan regulations,
and for non-compliance with US Department of Transportation orders and
regulations. The parties settled the dispute and on 13 July 2011 the Court
entered a Consent Agreement in which BPXA agreed to pay a $25-million
penalty and to perform certain injunctive measures over the next three
years with respect to pipeline inspection and maintenance. On 31 March
2009, the State of Alaska filed a complaint seeking civil penalties and
damages relating to these events. The complaint alleges that the two
releases and BPXA’s corrosion management practices violated various
statutory, contractual and common law duties to the State, resulting
in penalty liability, damages for lost royalties and taxes, and liability for
punitive damages. In December 2011, the State of Alaska and BPXA
entered into a Dispute Resolution Agreement concerning this matter that
will result in arbitration of the amount of the State’s lost royalty income and
payment by BPXA of the additional amount of $10 million on account of
other claims in the complaint.
Approximately 200 lawsuits were filed in state and federal courts
in Alaska seeking compensatory and punitive damages arising out of the
Exxon Valdez oil spill in Prince William Sound in March 1989. Most of
those suits named Exxon (now ExxonMobil), Alyeska Pipeline Service
Company (Alyeska), which operates the oil terminal at Valdez, and the
other oil companies that own Alyeska. Alyeska initially responded to
the spill until the response was taken over by Exxon. BP owns a 46.9%
interest (reduced during 2001 from 50% by a sale of 3.1% to Phillips)
in Alyeska through a subsidiary of BP America Inc. and briefly indirectly
owned a further 20% interest in Alyeska following BP’s combination with
Atlantic Richfield. Alyeska and its owners have settled all the claims against
them under these lawsuits. Exxon has indicated that it may file a claim for
contribution against Alyeska for a portion of the costs and damages that it
has incurred. If any claims are asserted by Exxon that affect Alyeska and its
owners, BP will defend the claims vigorously.
Since 1987, Atlantic Richfield Company (Atlantic Richfield), a
subsidiary of BP, has been named as a co-defendant in numerous lawsuits
brought in the US alleging injury to persons and property caused by lead
pigment in paint. The majority of the lawsuits have been abandoned or
dismissed against Atlantic Richfield. Atlantic Richfield is named in these
lawsuits as alleged successor to International Smelting and Refining
and another company that manufactured lead pigment during the period
1920-1946. Plaintiffs include individuals and governmental entities.
Several of the lawsuits purport to be class actions. The lawsuits seek
various remedies including compensation to lead-poisoned children, cost
to find and remove lead paint from buildings, medical monitoring and
screening programmes, public warning and education of lead hazards,
reimbursement of government healthcare costs and special education for
lead-poisoned citizens and punitive damages. No lawsuit against Atlantic
Richfield has been settled nor has Atlantic Richfield been subject to a final
adverse judgment in any proceeding. The amounts claimed and, if such
suits were successful, the costs of implementing the remedies sought in
the various cases could be substantial. While it is not possible to predict
the outcome of these legal actions, Atlantic Richfield believes that it has
valid defences. It intends to defend such actions vigorously and believes
that the incurrence of liability is remote. Consequently, BP believes that
the impact of these lawsuits on the group’s results, financial position or
liquidity will not be material.
On 8 March 2010, OSHA issued citations to BP’s Toledo refinery
alleging violations of the Process Safety Management Standard, with
penalties of approximately $3 million. These citations resulted from an
inspection conducted pursuant to OSHA’s Petroleum Refinery Process
Safety Management National Emphasis Program. BP Products has
contested the citations, and the matter is currently scheduled for trial
before the OSH Review Commission in June 2012.
In April 2009, Kenneth Abbott, as relator, filed a US False Claims
Act lawsuit against BP, alleging that BP violated federal regulations, and
made false statements in connection with its compliance with those
regulations, by failing to have necessary documentation for the Atlantis
subsea and other systems. BP is the operator and 56% interest owner
of the Atlantis unit in production in the Gulf of Mexico. That complaint
was unsealed in May 2010 and served on BP in June 2010. Abbott seeks
damages measured by the value, net of royalties, of all past and future
production from the Atlantis platform, trebled, plus penalties. In September
2010, Kenneth Abbott and Food & Water Watch filed an amended
BP Annual Report and Form 20-F 2011 165
Additional information for shareholdersAdditional information for shareholders On 17 May 2011, BP announced that both the Rosneft Share Swap
Agreement and the Arctic Opportunity, originally announced on 14 January
2011, had terminated. This termination was as a result of the deadline
for the satisfaction of conditions precedent having expired following
delays resulting from the interim orders referred to above. These interim
orders did not address the question of whether or not BP breached the
Shareholders Agreement. The arbitration proceedings, which are subject to
strict confidentiality obligations, are ongoing.
Five minority shareholders of OAO TNK-BP Holding (TBH) have
filed two civil actions in Tyumen, Siberia, against BP Russia Investments
Limited and BP p.l.c. and against two of the BP nominated directors
of TBH. These two actions sought to recover alleged losses to TBH
of $13 billion and $2.7 billion respectively. On 11 November 2011,
the Tyumen Court dismissed both claims fully on their merits. The
shareholders appealed both of these decisions to the Omsk Appellate
court. On 26 January 2012, the Appellate court upheld the Tyumen Court’s
dismissal of the claim in relation to the BP nominated directors of TBH. The
Omsk Appellate court subsequently confirmed the Tyumen court of first
instance’s dismissal of the minority suits against BP Russia Investments
Limited and BP p.l.c. BP believes the allegations made are wholly without
merit. No losses have been incurred and BP believes the likelihood of the
claims being ultimately successful is remote. Consequently no amounts
have been provided and the claim is not disclosed as a contingent liability.
On 9 February 2011, Apache Canada Ltd (Apache) commenced
an arbitration against BP Canada Energy. Apache alleges that various
properties/sites in respect of which it acquired interests from BP Canada
Energy pursuant to the parties’ Purchase and Sale Agreement signed in
July 2010 will require work to bring the properties/sites into compliance
with applicable environmental laws, and Apache claims that the purchase
price should be adjusted for its estimated possible costs. BP Canada
Energy denies such costs will arise or require any adjustment to the
purchase price. The parties have appointed the arbitrator, and currently
the hearing on the merits is scheduled to commence during the second
quarter of 2012.
On 24 January 2012, the Republic of Bolivia issued a press
statement declaring its intent to nationalize Pan American Energy’s
interests in the Caipipendi Operations Contract. No formal nationalization
process has yet commenced. Pan American Energy and its shareholders
BP and Bridas intend to vigorously defend their legal interests under the
Caipipendi Operations Contract and available Bilateral Investment Treaties.
complaint in the False Claims Act lawsuit seeking an injunction shutting
down the Atlantis platform. The court denied BP’s motion to dismiss
the complaint in March 2011. Separately, also in March 2011, BOEMRE
issued its investigation report of the Abbott Atlantis allegations, which
concluded that Mr Abbott’s allegations that Atlantis operations personnel
lacked access to critical, engineer-approved drawings were without merit
and that his allegations about false submissions by BP to BOEMRE were
unfounded. Trial is scheduled to begin on 10 April 2012.
BP Products’ US refineries are subject to a 2001 consent
decree with the EPA that resolved alleged violations of the CAA,
and implementation of the decree’s requirements continues. A 2009
amendment to the decree resolves remaining alleged air violations at
the Texas City refinery through the payment of a $12-million civil fine,
a $6-million supplemental environmental project and enhanced CAA
compliance measures estimated to cost approximately $150 million. The
fine has been paid, and BP Products is implementing the other provisions.
On 30 September 2010, the EPA and BP Products lodged a
civil consent decree with the federal court in Houston. Following a
public comment period, the federal court approved the settlement on
30 December 2010. The decree resolves allegations of civil violations of
the risk management planning regulations promulgated under the CAA that
are alleged to have occurred in 2004 and 2005 at the Texas City refinery.
BP Products has paid the $15-million civil penalty and the Texas City
refinery is implementing requirements to enhance reporting to
the EPA regarding employee training, equipment inspection and
incident investigation.
Various environmental groups and the EPA have challenged
certain aspects of the air permits issued by the Indiana Department of
Environmental Management (IDEM) for upgrades to the Whiting refinery.
In response to these challenges, the IDEM has reviewed the permits and
responded formally to the EPA. BP is in discussions with the EPA, the
IDEM and certain environmental groups over these and other CAA issues
relating to the Whiting refinery. BP has also been in settlement discussions
with EPA to resolve alleged CAA violations at the Toledo, Carson and
Cherry Point refineries.
An application was brought in the English High Court on 1 February
2011 by Alfa Petroleum Holdings Limited and OGIP Ventures Limited
against BP International Limited and BP Russian Investments Limited
alleging breach of a Shareholders Agreement on the part of BP and
seeking an interim injunction restraining BP from taking steps to conclude,
implement or perform the transactions with Rosneft Oil Company,
originally announced on 14 January 2011, relating to oil and gas exploration,
production, refining and marketing in Russia (the Arctic Opportunity).
Those transactions included the issue or transfer of shares between
Rosneft Oil Company and any BP group company (pursuant to the Rosneft
Share Swap Agreement). The court granted an interim order restraining
BP from taking any further steps in relation to the Rosneft transactions
pending an expedited UNCITRAL arbitration procedure in accordance with
the Shareholders Agreement between the parties. The arbitration has
commenced and the interim injunction was continued by the arbitration
panel.
166 BP Annual Report and Form 20-F 2011
Additional information for shareholders Relationships with suppliers
and contractors
Essential contracts
BP has contractual and other arrangements with numerous third parties in
support of its business activities. This report does not contain information
about any of these third parties as none of our arrangements with them are
considered to be essential to the business of BP.
Suppliers and contractors
Our processes are designed to enable us to choose suppliers carefully
on merit, avoiding conflicts of interest and inappropriate gifts and
entertainment. We expect suppliers to comply with legal requirements
and we seek to do business with suppliers who act in line with BP’s
commitments to compliance and ethics, as outlined in our code of conduct.
We engage with suppliers in a variety of ways, including performance
review meetings to identify mutually advantageous ways to improve
performance.
Creditor payment policy and practice
Statutory regulations issued under the UK Companies Act 2006 require
companies to make a statement of their policy and practice in respect
of the payment of trade creditors. In view of the international nature of
the group’s operations there is no specific group-wide policy in respect
of payments to suppliers. Relationships with suppliers are, however,
governed by the group’s policy commitment to long-term relationships
founded on trust and mutual advantage. Within this overall policy, individual
operating companies are responsible for agreeing terms and conditions for
their business transactions and ensuring that suppliers are aware of the
terms of payment.
Share prices and listings
Markets and market prices
The primary market for BP’s ordinary shares is the London Stock Exchange
(LSE). BP’s ordinary shares are a constituent element of the Financial
Times Stock Exchange 100 Index. BP’s ordinary shares are also traded on
the Frankfurt Stock Exchange in Germany.
Trading of BP’s shares on the LSE is primarily through the use of
the Stock Exchange Electronic Trading Service (SETS), introduced in 1997
for the largest companies in terms of market capitalization whose primary
listing is the LSE. Under SETS, buy and sell orders at specific prices may
be sent electronically to the exchange by any firm that is a member of the
LSE, on behalf of a client or on behalf of itself acting as a principal. The
orders are then anonymously displayed in the order book. When there is
a match on a buy and a sell order, the trade is executed and automatically
reported to the LSE. Trading is continuous from 8.00 a.m. to 4.30 p.m. UK
time but, in the event of a 20% movement in the share price either way,
the LSE may impose a temporary halt in the trading of that company’s
shares in the order book to allow the market to re-establish equilibrium.
Dealings in ordinary shares may also take place between an investor and a
market-maker, via a member firm, outside the electronic order book.
In the US, the company’s securities are traded on the New York
Stock Exchange (NYSE) in the form of ADSs, for which JPMorgan Chase
Bank, N.A. is the depositary (the Depositary) and transfer agent. The
Depositary’s principal office is 1 Chase Manhattan Plaza, N.A., Floor 21,
New York, NY 10005-1401, US. Each ADS represents six ordinary shares.
ADSs are listed on the New York Stock Exchange. ADSs are evidenced
by American depositary receipts (ADRs), which may be issued in either
certificated or book entry form.
The following table sets forth for the periods indicated the highest
and lowest middle market quotations for BP’s ordinary shares and ADSs
for the periods shown. These are derived from the highest and lowest
sales prices as reported on the LSE and NYSE, respectively.
Year ended 31 December
2007
2008
2009
2010
2011
Year ended 31 December
2010: First quarter
Second quarter
Third quarter
Fourth quarter
2011: First quarter
Second quarter
Third quarter
Fourth quarter
2012: First quarter (to 17 February)
Month of
September 2011
October 2011
November 2011
December 2011
January 2012
February 2012 (to 17 February)
a One ADS is equivalent to six 25 cent ordinary shares.
Pence
Ordinary shares
Low
High
Dollars
American depositary sharesa
Low
High
640.00
657.25
613.40
658.20
514.90
640.10
658.20
438.25
479.00
514.90
480.23
483.04
477.54
501.37
426.04
477.54
466.05
471.45
487.60
501.37
504.50
370.00
400.00
296.00
361.25
555.00
296.00
312.65
418.25
431.00
425.00
361.25
363.95
455.05
361.25
363.95
416.99
433.00
455.05
473.05
79.77
77.69
60.00
62.38
49.50
62.38
60.98
41.59
44.83
49.50
47.45
47.09
45.83
47.67
39.72
45.83
44.89
44.26
46.03
47.67
58.62
37.57
33.71
26.75
33.63
52.00
26.75
28.79
39.58
42.51
41.26
35.10
33.63
42.85
35.10
33.63
39.41
40.40
42.85
45.23
BP Annual Report and Form 20-F 2011 167
Additional information for shareholdersAdditional information for shareholders
Market prices for the ordinary shares on the LSE and in after-hours trading
off the LSE, in each case while the NYSE is open, and the market prices for
ADSs on the NYSE, are closely related due to arbitrage among the various
markets, although differences may exist from time to time due to various
factors, including UK stamp duty reserve tax.
On 17 February 2012, 838,650,908 ADSs (equivalent to
approximately 5,031,905,448 ordinary shares or some 26.51% of the total
issued share capital, excluding shares held in treasury) were outstanding
and were held by approximately 109,640 ADS holders. Of these, about
108,369 had registered addresses in the US at that date. One of the
registered holders of ADSs represents some 811,108 underlying holders.
On 17 February 2012, there were approximately 303,020 holders
of record of ordinary shares. Of these holders, around 1,585 had registered
addresses in the US and held a total of some 4,331,996 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.
Material contracts
On 6 August 2010, BP entered into a trust agreement with John S Martin,
Jr and Kent D Syverud, as individual trustees, and Citigroup Trust-Delaware,
N.A., as corporate trustee (the Trust Agreement) which established the
Deepwater Horizon Oil Spill Trust (the Trust) to be funded in the amount of
$20 billion (the trust fund) over the period to the fourth quarter of 2013. The
trust fund is available to satisfy legitimate individual and business claims
administered by the Gulf Coast Claims Facility (GCCF), state and local
government claims resolved by BP, final judgments and settlements, state
and local response costs, and natural resource damages and related costs.
Fines, penalties and claims administration costs are not covered by the trust
fund. Under the terms of the Trust Agreement, BP has no right to access
the funds once they have been contributed to the trust fund. BP will receive
funds from the trust fund only upon its expiration, if there are any funds
remaining at that point. BP has the authority under the Trust Agreement to
present certain resolved claims, including natural resource damages claims
and state and local response claims, to the Trust for payment, by providing
the trustees with all the required documents establishing that such claims
are valid under the Trust Agreement. However, any such payments can
only be made on the authority of the trustee and any funds distributed are
paid directly to the claimants, not to BP. The Trust Agreement is governed
by the laws of the State of Delaware.
On 30 September 2010, BP entered a pledge and collateral
agreement in favour of John S Martin, Jr and Kent D Syverud (the Pledge
Agreement), which pledged certain Gulf of Mexico assets as collateral
for the trust fund funding obligation. The pledged collateral consists of an
overriding royalty interest in oil and gas production of BP’s Thunder Horse,
Atlantis, Mad Dog, Great White and Mars, Ursa and Na Kika assets in the
Gulf of Mexico. A wholly-owned company called Verano Collateral Holdings
LLC (Verano) has been created to hold the overriding royalty interest, which
was capped at $1.25 billion per quarter and $17 billion in total. Verano
pledged the overriding royalty interest to the Trust as collateral for BP’s
remaining contribution obligations to the Trust. An event of default under
the Pledge Agreement arose if BP failed to make any contribution under
the Trust Agreement when due or otherwise failed to observe certain other
obligations, subject to specified cure periods. Following an event of default,
the trustees were entitled to exercise all remedies as secured parties in
respect of the collateral, including receipt of royalty interests from the
pledged assets, having all or part of the limited liability company interests
registered in the trustees’ name and selling the collateral at public or
private sale. The Pledge Agreement was governed by the laws of the State
of Texas. On 9 November 2011 the Pledge Agreement and the related
overriding royalty interest conveyance and mortgage were amended and
restated (such documents collectively referred to as the Amended and
Restated Pledge Agreement) to change the overriding royalty interest
effective as of 1 October 2011 to $14.7 billion. Beginning on 2 January
2012, and on the first business day of each subsequent calendar quarter,
the overriding royalty interest is recalculated as the remaining outstanding
contributions owed by BP to the Trust as of that date multiplied by a factor
168 BP Annual Report and Form 20-F 2011
of 1.45. On 2 January 2012 the overriding royalty interest was recalculated
as $7.1 billion. The Amended and Restated Pledge Agreement also
changed the definition of an event of default to be a failure by BP to make
required payments pursuant to the terms of the Trust Agreement.
Exchange controls
There are currently no UK foreign exchange controls or restrictions on
remittances of dividends on the ordinary shares or on the conduct of the
company’s operations.
There are no limitations, either under the laws of the UK or under
the company’s Articles of Association, restricting the right of non-resident
or foreign owners to hold or vote BP ordinary or preference shares in the
company.
Taxation
This section describes the material US federal income tax and UK taxation
consequences of owning ordinary shares or ADSs to a US holder who
holds the ordinary shares or ADSs as capital assets for tax purposes.
It does not apply, however, to members of special classes of holders
subject to special rules and holders that, directly or indirectly, hold 10%
or more of the company’s voting stock. In addition, if a partnership holds
the shares or ADSs, the US federal income tax treatment of a partner will
generally depend on the status of the partner and the tax treatment of the
partnership and may not be described fully below.
A US holder is any beneficial owner of ordinary shares or ADSs that
is for US federal income tax purposes (i) a citizen or resident of the US, (ii)
a US domestic corporation, (iii) an estate whose income is subject to US
federal income taxation regardless of its source, or (iv) a trust if a US court
can exercise primary supervision over the trust’s administration and one or
more US persons are authorized to control all substantial decisions of the
trust.
This section is based on the Internal Revenue Code of 1986,
as amended, its legislative history, existing and proposed regulations
thereunder, published rulings and court decisions, and the taxation laws
of the UK, all as currently in effect, as well as the income tax convention
between the US and the UK that entered into force on 31 March 2003
(the ‘Treaty’). These laws are subject to change, possibly on a retroactive
basis. This section is further based in part on the representations of the
Depositary and assumes that each obligation in the Deposit Agreement
and any related agreement will be performed in accordance with its terms.
For purposes of the Treaty and the estate and gift tax Convention
(the ‘Estate Tax Convention’,) and for US federal income tax and UK
taxation purposes, a holder of ADRs evidencing ADSs will be treated as
the owner of the company’s ordinary shares represented by those ADRs.
Exchanges of ordinary shares for ADRs and ADRs for ordinary shares
generally will not be subject to US federal income tax or to UK taxation
other than stamp duty or stamp duty reserve tax, as described below.
Investors should consult their own tax adviser regarding the US
federal, state and local, UK and other tax consequences of owning and
disposing of ordinary shares and ADSs in their particular circumstances,
and in particular whether they are eligible for the benefits of the Treaty.
Taxation of dividends
UK taxation
Under current UK taxation law, no withholding tax will be deducted from
dividends paid by the company, including dividends paid to US holders.
A shareholder that is a company resident for tax purposes in the UK
or trading in the UK through a permanent establishment generally will
not be taxable in the UK on a dividend it receives from the company. A
shareholder who is an individual resident for tax purposes in the UK is
subject to UK tax but entitled to a tax credit on cash dividends paid on
ordinary shares or ADSs of the company equal to one-ninth of the
cash dividend.
Additional information for shareholders US federal income taxation
A US holder is subject to US federal income taxation on the gross amount
of any dividend paid by the company out of its current or accumulated
earnings and profits (as determined for US federal income tax purposes).
Dividends paid to a non-corporate US holder in taxable years beginning
before 1 January 2013 that constitute qualified dividend income will be
taxable to the holder at a maximum tax rate of 15%, provided that the
holder has a holding period in the ordinary shares or ADSs of more than
60 days during the 121-day period beginning 60 days before the ex-
dividend date and meets other holding period requirements. Dividends
paid by the company with respect to the shares or ADSs will generally be
qualified dividend income.
As noted above in UK taxation, a US holder will not be subject to
UK withholding tax. A US holder will include in gross income for US federal
income tax purposes the amount of the dividend actually received from the
company, and the receipt of a dividend will not entitle the US holder to a
foreign tax credit.
For US federal income tax purposes, a dividend must be included
in income when the US holder, in the case of ordinary shares, or the
Depositary, in the case of ADSs, actually or constructively receives the
dividend and will not be eligible for the dividends-received deduction
generally allowed to US corporations in respect of dividends received from
other US corporations. Dividends will be income from sources outside the
US and generally will be ‘passive category income’ or, in the case of certain
US holders, ‘general category income’, each of which is treated separately
for purposes of computing a US holder’s foreign tax credit limitation.
The amount of the dividend distribution on the ordinary shares
or ADSs that is paid in pounds sterling will be the US dollar value of the
pounds sterling payments made, determined at the spot pounds sterling/
US dollar rate on the date the dividend distribution is includible in income,
regardless of whether the payment is, in fact, converted into US dollars.
Generally, any gain or loss resulting from currency exchange fluctuations
during the period from the date the pounds sterling dividend payment is
includible in income to the date the payment is converted into US dollars
will be treated as ordinary income or loss and will not be eligible for the
15% tax rate on qualified dividend income. The gain or loss generally
will be income or loss from sources within the US for foreign tax credit
limitation purposes.
Distributions in excess of the company’s earnings and profits, as
determined for US federal income tax purposes, will be treated as a return
of capital to the extent of the US holder’s basis in the ordinary shares or
ADSs and thereafter as capital gain, subject to taxation as described in
Taxation of capital gains – US federal income taxation section below.
In addition, the taxation of dividends may be subject to the rules
for passive foreign investment companies (PFIC), described below under
‘Taxation of capital gains – US federal income taxation’. Distributions made
by a PFIC do not constitute qualified dividend income and are not eligible
for the 15% tax rate.
Taxation of capital gains
UK taxation
A US holder may be liable for both UK and US tax in respect of a gain
on the disposal of ordinary shares or ADSs if the US holder is (i) a citizen
of the US resident or ordinarily resident in the UK, (ii) a US domestic
corporation resident in the UK by reason of its business being managed or
controlled in the UK or (iii) a citizen of the US or a corporation that carries
on a trade or profession or vocation in the UK through a branch or agency
or, in respect of corporations for accounting periods beginning on or
after 1 January 2003, through a permanent establishment, and that have
used, held, or acquired the ordinary shares or ADSs for the purposes of
such trade, profession or vocation of such branch, agency or permanent
establishment. However, such persons may be entitled to a tax credit
against their US federal income tax liability for the amount of UK capital
gains tax or UK corporation tax on chargeable gains (as the case may be)
that is paid in respect of such gain.
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 who 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. Any capital gain of a non-corporate US holder is generally taxed at
preferential rates if the holder’s holding period for such ordinary shares or
ADSs exceeds one year. The gain or loss will generally be income or loss
from sources within the US for foreign tax credit limitation purposes. The
deductibility of capital losses is subject to limitations.
We do not believe that ordinary shares or ADSs will be treated as
stock of a passive foreign investment company, or PFIC, for US federal
income tax purposes, but this conclusion is a factual determination that
is made annually and thus is subject to change. If we are treated as a
PFIC, unless a US holder elects to be taxed annually on a mark-to-market
basis with respect to ordinary shares or ADSs, any gain realized on the
sale or other disposition of ordinary shares or ADSs would in general not
be treated as capital gain. Instead, a US holder would be treated as if he
or she had realized such gain rateably over the holding period for ordinary
shares or ADSs and would be taxed at the highest tax rate in effect for
each such year to which the gain was allocated, in addition to which an
interest charge in respect of the tax attributable to each such year would
apply. Certain ‘excess distributions’ would be similarly treated if we were
treated as a PFIC.
Additional tax considerations
Scrip Dividend Programme
The company has introduced an optional Scrip Dividend Programme,
wherein holders of ordinary shares or ADSs may elect to receive any
dividends in the form of new, fully-paid ordinary shares or ADSs of
the company, instead of cash. Please consult your tax adviser for the
consequences to you.
UK inheritance tax
The Estate Tax Convention applies to inheritance tax. ADSs held by an
individual who is domiciled for the purposes of the Estate Tax Convention
in the US and is not for the purposes of the Estate Tax Convention
a national of the UK will not be subject to UK inheritance tax on the
individual’s death or on transfer during the individual’s lifetime unless,
among other things, the ADSs are part of the business property of a
permanent establishment situated in the UK used for the performance of
independent personal services. In the exceptional case where ADSs are
subject to both inheritance tax and 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.
BP Annual Report and Form 20-F 2011 169
Additional information for shareholdersAdditional information for shareholders UK stamp duty and stamp duty reserve tax
The statements below relate to what is understood to be the current
practice of HM Revenue & Customs in the UK under existing law.
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.
Provided that any instrument of transfer is not executed in the UK
and remains at all times outside the UK and the transfer does not relate
to any matter or thing done or to be done in the UK, no UK stamp duty is
payable on the acquisition or transfer of ADSs. Neither will an agreement
to transfer ADSs in the form of ADRs give rise to a liability to stamp duty
reserve tax.
Purchases of ordinary shares, as opposed to ADSs, through the
CREST system of paperless share transfers will be subject to stamp duty
reserve tax at 0.5%. The charge will arise as soon as there is an agreement
for the transfer of the shares (or, in the case of a conditional agreement,
when the condition is fulfilled). The stamp duty reserve tax will apply to
agreements to transfer ordinary shares even if the agreement is made
outside the UK between two non-residents. Purchases of ordinary shares
outside the CREST system are subject either to stamp duty at a rate of £5
per £1,000 (or part, unless the stamp duty is less than £5, when no stamp
duty is charged), or stamp duty reserve tax at 0.5%. Stamp duty and stamp
duty reserve tax are generally the liability of the purchaser.
A subsequent transfer of ordinary shares to the Depositary’s
nominee will give rise to further stamp duty at the rate of £1.50 per £100
(or part) or stamp duty reserve tax at the rate of 1.5% of the value of the
ordinary shares at the time of the transfer. An ADR holder electing to
receive ADSs instead of a cash dividend will be responsible for the stamp
duty reserve tax due on issue of shares to the Depositary’s nominee
and calculated at the rate of 1.5% on the issue price of the shares. It is
understood that HM Revenue & Customs practice is to calculate the issue
price by reference to the total cash receipt to which a US holder would
have been entitled had the election to receive ADSs instead of a cash
Documents on display
BP Annual Report and Form 20-F 2011 is also available online at
bp.com/annualreport. Shareholders may obtain a hard copy of BP’s
complete audited financial statements, free of charge, by contacting BP
Distribution Services at +44 (0)870 241 3269 or through an email request
addressed to bpdistributionservices@bp.com (UK and Rest of World)
or from Precision IR at + 1 888 301 2505 or through an email request
addressed to bpreports@precisionir.com (US and Canada).
The company is subject to the information requirements of the US
Securities Exchange Act of 1934 applicable to foreign private issuers. In
accordance with these requirements, the company files its Annual Report
on Form 20-F and other related documents with the SEC. It is possible to
read and copy documents that have been filed with the SEC at the SEC’s
public reference room located at 100 F Street NE, Washington, DC 20549,
US. You may also call the SEC at +1 800-SEC-0330. In addition, BP’s SEC
filings are available to the public at the SEC’s website. BP discloses on its
website at bp.com/ NYSEcorporategovernancerules, and in this report
(see Corporate governance practices (Form 20-F Item 16G) on page 134)
significant ways (if any) in which its corporate governance practices differ
from those mandated for US companies under NYSE listing standards.
Purchases of equity securities by the issuer and affiliated purchasers
At the AGM on 14 April 2011, authorization was given to repurchase up to 1.9 billion ordinary shares in the period to the next AGM in 2012 or 14 July
2012, the latest date by which an AGM must be held. This authorization is renewed annually at the AGM. No repurchases of shares were made in the
period 1 January 2011 to 17 February 2012.
The following table provides details of ordinary share purchases made by Employee Share Ownership Plan Trusts (ESOPs) and other purchases of
ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans.
2011
January
February
March
April
May
June
July
August
September
October
November
December
2012
January
February (to 17 February)
Total number
of shares
purchased as
part of publicity
announced
programmes
Maximum
number of
shares that
may yet
be purchased
under the
programmea
Total number
of shares
purchased
Average
paid per share
$
12,692,114
1,660,496
65
1,159,235
50,550
253,500
35,224
903,513
1,202,286
1,682,852
513,392
42,034,522
Nil
792
8.01
7.77
7.53
7.69
7.43
7.01
7.35
6.57
6.07
6.18
7.26
7.09
7.90
a No shares were repurchased pursuant to a publicly announced plan. Transactions represent the purchase of ordinary shares by ESOPs and other purchases of ordinary shares and ADSs made to satisfy
requirements of certain employee share-based payment plans.
170 BP Annual Report and Form 20-F 2011
Additional information for shareholders Fees and charges payable by a holder of ADSs
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of
withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the
amounts distributed or by selling a portion of the distributable property to pay the fees.
The charges of the Depositary payable by investors are as follows:
Type of service
Depositary actions
Fee
Depositing or substituting the
underlying shares
Selling or exercising rights
Withdrawing an
underlying share
Expenses of the Depositary
Issuance of ADSs against the deposit of shares, including
deposits and issuances in respect of:
• Share distributions, stock splits, rights, merger.
• Exchange of securities or other transactions or event
or other distribution affecting the ADSs or deposited
securities.
Distribution or sale of securities, the fee being in an amount
equal to the fee for the execution and delivery of ADSs that
would have been charged as a result of the deposit of such
securities.
Acceptance of ADSs surrendered for withdrawal of deposited
securities.
Expenses incurred on behalf of holders in connection with:
• Stock transfer or other taxes and governmental charges.
• Cable, telex, electronic and facsimile transmission/
delivery.
• Transfer or registration fees, if applicable, for the
registration of transfers of underlying shares.
• Expenses of the Depositary in connection with the
conversion of foreign currency into US dollars (which are
paid out of such foreign currency).
$5.00 per 100 ADSs (or portion thereof)
evidenced by the new ADSs delivered.
$5.00 per 100 ADSs (or portion thereof).
$5.00 for each 100 ADSs (or portion
thereof) evidenced by the ADSs
surrendered.
Expenses payable at the sole discretion
of the Depositary by billing holders or by
deducting charges from one or more cash
dividends or other cash distributions.
Under certain circumstances, including removal of the Depositary or
termination of the ADR programme by the company, the company is
required to repay the Depositary amounts reimbursed and/or expenses
paid to or on behalf of the company during the 12-month period prior to
notice of removal or termination.
Related-party transactions
Transactions between the group and its significant jointly controlled entities
and associates are summarized in Financial statements – Note 24 on page
215 and Note 25 on page 216. In the ordinary course of its business, the
group enters into transactions with various organizations with which certain
of its directors or executive officers are associated. Except as described
in this report, the group did not have material transactions or transactions
of an unusual nature with, and did not make loans to, related parties in the
period commencing 1 January 2011 to 28 February 2012.
Fees and payments made by the
Depositary to the issuer
The Depositary has agreed to reimburse certain company expenses
related to the company’s ADS programme and incurred by the company
in connection with the programme. The Depositary reimbursed to the
company, or paid amounts on the company’s behalf to third parties,
or waived its fees and expenses, of $3,330,826 for the year ended
31 December 2011.
The table below sets out the types of expenses that the Depositary
has agreed to reimburse and the fees it has agreed to waive for standard
costs associated with the administration of the ADS programme relating to
the year ended 31 December 2011. The Depositary has also paid certain
expenses directly to third parties on behalf of the company.
Category of expense reimbursed,
waived or paid directly to third parties
NYSE listing fees reimbursed
Service fees and out of pocket expenses
waiveda
Broker fees reimbursedb
Other third-party mailing costs reimbursedc
Legal advice reimbursedd
Other third-party expenses paid directly
Total
Amount reimbursed, waived or paid
directly to third parties for
the year ended 31 December 2011
$500,000
$1,940,127
$798,177
$76,736
$2,918
$12,868
$3,330,826
a Includes fees in relation to transfer agent costs and costs of the BP Scrip Dividend Programme
operated by JPMorgan Chase Bank, N.A.
b Broker reimbursements are fees payable to Broadridge for the distribution of hard copy material to
ADR beneficial holders in the Depositary Trust Company. Corporate materials include information
related to shareholders’ meetings and related voting instructions. These fees are SEC approved.
c Payment of fees to Precision IR for proxy solicitation and investor support.
d Reimbursement for legal advice from Ziegler, Ziegler & Associates.
BP Annual Report and Form 20-F 2011 171
Additional information for shareholdersAdditional information for shareholders Administration
Exhibits
The following documents are filed in the Securities and Exchange
Commission (SEC) EDGAR system, as part of this Annual Report on Form
20-F, and can be viewed on the SEC’s website.
Exhibit 1
Exhibit 4.1
Exhibit 4.2 BP Plan 2011†
Exhibit 4.3 BP Share Value Plan 2012†
Exhibit 4.4
Memorandum and Articles of Association of BP p.l.c.*†
The BP Executive Directors’ Incentive Plan*†
Amended Director’s Service Contract and Secondment
Agreement for R W Dudley*†
Amended Director’s Service Contract and Secondment
Agreement for Dr B E Grote†
Exhibit 4.6 Director’s Service Contract for I C Conn**†
Exhibit 4.7 Director’s Service Contract for Dr B Gilvary†
Exhibit 7
Exhibit 4.5
Computation of Ratio of Earnings to Fixed Charges
(Unaudited)†
Subsidiaries (included as Note 45 to the Financial
Statements)
Trust Agreement dated as of 6 August 2010 among BP
Exploration & Production Inc., John S Martin, Jr and
Kent D Syverud, as individual trustees, and Citigroup
Trust-Delaware, N.A., as corporate trustee, as amended
by an Addendum, dated 6 August 2010*†
Amended and Restated Pledge and Collateral Agreement
dated as of 9 November 2011 by BP Exploration &
Production Inc. in favor of John S Martin, Jr and
Kent D Syverud, as individual trustees†
Code of Ethics***†
Rule 13a – 14(a) Certifications†
Rule 13a – 14(b) Certifications#†
Exhibit 8
Exhibit 10.1
Exhibit 10.2
Exhibit 11
Exhibit 12
Exhibit 13
* Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended
31 December 2010.
** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended
31 December 2004.
*** Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended
31 December 2009.
# Furnished only.
† Included only in the annual report filed in the Securities and Exchange Commission EDGAR
system.
The total amount of long-term securities of the Registrant and its
subsidiaries authorized under any one instrument does not exceed 10% of
the total assets of BP p.l.c. and its subsidiaries on a consolidated basis. The
company agrees to furnish copies of any or all such instruments to the SEC
on request.
If you have any queries about the administration of shareholdings, such
as change of address, change of ownership, dividend payments, the Scrip
Dividend Programme or to change the way you receive your company
documents (such as the BP Annual Report and Form 20-F, BP Summary
Review and Notice of BP Annual General Meeting) please contact the BP
Registrar or BP ADS Depositary.
Ordinary and preference shareholders – BP Registrar
Equiniti
Aspect House, Spencer Road, Lancing, West Sussex BN99 6DA, UK
Freephone in UK 0800 701107 or +44 (0)121 415 7005 from outside
the UK
Textphone 0871 384 2255; fax +44 (0)871 384 2100
Please note that any numbers quoted with the prefix 0871 will be
charged at 8p per minute from a BT landline. Other network providers’
costs may vary.
ADS holders – BP ADS Depositary
JPMorgan Chase Bank, N.A.
PO Box 64504, St Paul, MN 55164-0504, US
Toll-free in US and Canada +1 877 638 5672 or +1 651 306 4383 from
outside the US and Canada
For the hearing impaired +1 651 453 2133
Annual general meeting
The 2012 AGM will be held on Thursday,12 April 2012 at 11.30 a.m. at
ExCeL London, One Western Gateway, Royal Victoria Dock, London
E16 1XL. A separate notice convening the meeting is distributed to
shareholders, which includes an explanation of the items of business to be
considered at the meeting.
All resolutions of which notice has been given will be decided
on a poll.
Ernst & Young LLP have expressed their willingness to continue
in office as auditors and a resolution for their reappointment is included in
Notice of BP Annual General Meeting 2012.
By order of the board
David J Jackson
Company Secretary
6 March 2012
BP p.l.c.
Registered in England and Wales No. 102498
172 BP Annual Report and Form 20-F 2011
Additional information for shareholders Financial statements
174 Statement of directors’
responsibilities
175 Consolidated financial statements
of the BP group
Independent auditor’s reports
Group income statement
Group statement of comprehensive income
Group statement of changes in equity
Group balance sheet
Group cash flow statement
182 Notes on financial statements
Significant accounting policies
Significant event – Gulf of Mexico oil spill
1
2
3 Business combinations
4 Non-current assets held for sale
5 Disposals and impairment
Segmental analysis
6
Interest and other income
7
8
Production and similar taxes
9 Depreciation, depletion and amortization
10
11 Distribution and administration expenses
12 Currency exchange gains and losses
13 Research and development
14 Operating leases
15 Exploration for and evaluation of oil and
Impairment review of goodwill
natural gas resources
Intangible assets
Investments in jointly controlled entities
Investments in associates
16 Auditor’s remuneration
17 Finance costs
18 Taxation
19 Dividends
20 Earnings per ordinary share
21 Property, plant and equipment
22 Goodwill
23
24
25
26 Financial instruments and financial risk factors
27 Other investments
28
29 Trade and other receivables
30 Cash and cash equivalents
31 Valuation and qualifying accounts
32 Trade and other payables
33 Derivative financial instruments
Inventories
175
178
179
179
180
181
182
190
194
196
197
200
205
205
205
206
207
208
208
208
209
209
209
210
212
212
213
214
214
215
216
217
222
222
223
223
223
224
224
34 Finance debt
35 Capital disclosures and analysis of changes
229
in net debt
230
36 Provisions
231
234
37 Pensions and other post-retirement benefits
38 Called-up share capital
241
242
39 Capital and reserves
40 Share-based payments
246
41 Employee costs and numbers
248
42 Remuneration of directors and senior management 248
249
43 Contingent liabilities
250
44 Capital commitments
45
Subsidiaries, jointly controlled entities and
associates
Condensed consolidating information on certain
US subsidiaries
251
253
46
259 Supplementary information
on oil and natural gas (unaudited)
Oil and natural gas exploration and production activities 260
Movements in estimated net proved reserves
266
Standardized measure of discounted future net
cash flows and changes therein relating to proved
oil and gas reserves
Operational and statistical information
277
280
PC1 Parent company financial
Taxation
Fixed assets – investments
statements of BP p.l.c.
Independent auditor’s report to the members of BP p.l.c. PC1
PC2
Company balance sheet
Company cash flow statement
PC3
Company statement of total recognized gains and losses PC3
PC4
Notes on financial statements
PC4
1 Accounting policies
PC5
2
PC5
3
PC6
4 Debtors
PC6
5 Creditors
Pensions
6
PC7
PC10
7 Called-up share capital
8 Capital and reserves
PC10
9 Cash flow
PC11
10 Contingent liabilities
PC11
11 Share-based payments
PC11
12 Auditor’s remuneration
PC13
13 Directors’ remuneration
PC14
BP Annual Report and Form 20-F 2011 173
BP Annual Report and Form 20-F 2011 173
BP Annual Report and Form c 2011 173 Financial statements
Statement of directors’ responsibilities
The directors are responsible for preparing the Annual Report and the financial statements in accordance with applicable law and regulations.
The directors are required by the UK Companies Act 2006 to prepare financial statements for each financial year that give a true and fair view
of the financial position of the group and the parent company and the financial performance and cash flows of the group and parent company for that
period. Under that law they are required to prepare the consolidated financial statements in accordance with International Financial Reporting Standards
(IFRS) as adopted by the European Union (EU) and applicable law and have elected to prepare the parent company financial statements in accordance
with applicable United Kingdom law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice). In preparing the
consolidated financial statements the directors have also elected to comply with IFRSs as issued by the International Accounting Standards Board (IASB).
In preparing those financial statements, the directors are required to:
• Select suitable accounting policies and then apply them consistently.
• Make judgements and estimates that are reasonable and prudent.
• 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 applicable accounting standards have been followed, subject to any material departures disclosed and explained in the parent company
financial statements.
• Prepare the financial statements on the going concern basis unless it is inappropriate to presume that the company will continue in business.
The directors are responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the financial position of the
group and company and enable them to ensure that the consolidated financial statements comply with the Companies Act 2006 and Article 4 of the IAS
Regulation and the parent company financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the assets of
the group and company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.
The directors draw attention to Notes 2, 36 and 43 on the consolidated financial statements which describe the uncertainties surrounding the
amounts and timings of liabilities arising from the Gulf of Mexico oil spill.
The group’s business activities, performance, position and risks are set out in this report. The financial position of the group, its cash flows,
liquidity position and borrowing facilities are detailed in the appropriate sections on pages 103 to 106 and elsewhere in the notes on the consolidated
financial statements. The report also includes details of the group’s risk mitigation and management. Information on the Gulf of Mexico oil spill and BP’s
response is included on pages 76 to 79 and elsewhere in this report, including Safety on pages 65 to 69. The group has considerable financial resources,
and the directors believe that the group is well placed to manage its business risks successfully. After making enquiries, the directors have a reasonable
expectation that the company and the group have adequate resources to continue in operational existence for the foreseeable future. Accordingly, they
continue to adopt the going concern basis in preparing the annual report and accounts.
Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 418(3) of
the Companies Act 2006) of which the 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.
The directors confirm that to the best of their knowledge:
• The consolidated financial statements, prepared in accordance with IFRS as issued by the IASB, IFRS as adopted by the EU and in accordance with the
provisions of the Companies Act 2006, give a true and fair view of the assets, liabilities, financial position and profit or loss of the group;
• The parent company financial statements, prepared in accordance with United Kingdom generally accepted accounting practice, give a true and fair
view of the assets, liabilities, financial position, performance and cash flows of the company; and
• The management report, which is incorporated in the directors’ report, includes a fair review of the development and performance of the business and
the position of the group, together with a description of the principal risks and uncertainties.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
174 BP Annual Report and Form 20-F 2011
Consolidated financial statements of the BP group Consolidated financial statements of the BP group
Independent auditor’s report on the Annual Report and Accounts
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 2011 which comprise the group income statement,
the group statement of comprehensive income, the group statement of changes in equity, the group balance sheet, the group cash flow statement
and the related notes 1 to 45. The financial reporting framework that has been applied in their preparation is applicable law and International Financial
Reporting Standards (IFRS) as adopted by the European Union.
This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit
work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report
and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the
company’s members as a body, for our audit work, for this report, or for the opinions we have formed.
Respective responsibilities of directors and auditor
As explained more fully in the Statement of directors’ responsibilities set out on page 174, the directors are responsible for the preparation of the
consolidated financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the
consolidated financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us
to comply with the Auditing Practices Board’s Ethical Standards for Auditors.
Scope of the audit of the financial statements
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the
financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting
policies are appropriate to the group’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant
accounting estimates made by the directors; and the overall presentation of the financial statements. In addition, we read all the financial and non-financial
information in the annual report to identify material inconsistencies with the audited financial statements. If we become aware of any apparent material
misstatements or inconsistencies we consider the implications for our report.
Opinion on financial statements
In our opinion the consolidated financial statements:
• give a true and fair view of the state of the group’s affairs as at 31 December 2011 and of its profit for the year then ended;
• have been properly prepared in accordance with IFRS as adopted by the European Union; and
• have been prepared in accordance with the requirements of the Companies Act 2006 and Article 4 of the IAS Regulation.
Separate opinion in relation to IFRS as issued by the International Accounting Standards Board
As explained in Note 1 to the consolidated financial statements, the group in addition to applying IFRS as adopted by the European Union, has also applied
IFRS as issued by the International Accounting Standards Board (IASB).
In our opinion the consolidated financial statements comply with IFRS as issued by the IASB.
Emphasis of matter – significant uncertainty over provisions and contingencies related to the Gulf of Mexico oil spill
In forming our opinion we have considered the adequacy of the disclosures made in Notes 2, 36 and 43 to the financial statements concerning the
provisions, future expenditures for which reliable estimates cannot be made and other contingencies related to the Gulf of Mexico oil spill significant
event. The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the
ultimate exposure and cost to BP will be dependent on many factors, including any determination of BP’s culpability based on any findings of negligence,
gross negligence or wilful misconduct. Actual costs could ultimately be significantly higher or lower than those recorded in relation to all obligations
relating to the oil spill. Our opinion is not qualified in respect of these matters.
Opinion on other matter prescribed by the Companies Act 2006
In our opinion the information given in the Directors’ Report for the financial year for which the consolidated financial statements are prepared is
consistent with the consolidated financial statements.
Matters on which we are required to report by exception
We have nothing to report in respect of the following:
Under the Companies Act 2006 we are required to report to you if, in our opinion:
• certain disclosures of directors’ remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
Under the Listing Rules we are required to review:
• the directors’ statement, set out on page 174, in relation to going concern;
• the part of the BP board performance report relating to the company’s compliance with the nine provisions of the UK Corporate Governance Code
specified for our review; and
• certain elements of the report to shareholders by the Board on directors’ remuneration.
Other matter
We have reported separately on the parent company financial statements of BP p.l.c. for the year ended 31 December 2011 and on the information in the
Directors’ Remuneration Report that is described as having been audited.
Ernst & Young LLP
Allister Wilson (Senior Statutory Auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
6 March 2012
The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not involve
consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements
since they were initially presented on the website. Legislation in the United Kingdom governing the preparation and dissemination of financial statements
may differ from legislation in other jurisdictions.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2011 175
Financial statementsConsolidated financial statements of the BP group Report of Independent Registered Public Accounting Firm on the
Annual Report on Form 20-F
The Board of Directors and Shareholders of BP p.l.c.
We have audited the accompanying group balance sheets of BP p.l.c. as of 31 December 2011 and 2010, and the related group income statement, group
statement of comprehensive income, group statement of changes in equity and group cash flow statement for each of the three years in the period
ended 31 December 2011. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion
on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing
the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the group financial position of BP p.l.c. at 31 December
2011 and 2010, and the group results of operations and cash flows for each of the three years in the period ended 31 December 2011, in accordance with
International Financial Reporting Standards as adopted by the European Union and International Financial Reporting Standards as issued by the International
Accounting Standards Board.
In forming our opinion we have considered the adequacy of the disclosures made in Notes 2, 36 and 43 to the financial statements concerning
the provisions, future expenditures for which reliable estimates cannot be made and other contingencies related to the Gulf of Mexico oil spill significant
event. The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the
ultimate exposure and cost to BP will be dependent on many factors, including any determination of BP’s culpability based on any findings of negligence,
gross negligence or wilful misconduct. Actual costs could ultimately be significantly higher or lower than those recorded in relation to all obligations
relating to the oil spill. Our opinion is not qualified in respect of these matters.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BP p.l.c.’s internal
control over financial reporting as of 31 December 2011, based on criteria established in the Internal Control: Revised Guidance for Directors on the
Combined Code (Turnbull) as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull criteria) and our report dated 6 March
2012 expressed an unqualified opinion thereon.
/s/ERNST & YOUNG LLP
Ernst & Young LLP
London, England
6 March 2012
The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not involve
consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements
since they were initially presented on the website. Legislation in the United Kingdom governing the preparation and dissemination of financial statements
may differ from legislation in other jurisdictions.
176 BP Annual Report and Form 20-F 2011
Consolidated financial statements of the BP group Report of Independent Registered Public Accounting Firm on the
Annual Report on Form 20-F
The Board of Directors and Shareholders of BP p.l.c.
We have audited BP p.l.c.’s internal control over financial reporting as of 31 December 2011, based on criteria established in Internal Control: Revised
Guidance for Directors on the Combined Code (Turnbull) as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull criteria).
BP p.l.c.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of
internal control over financial reporting included in the accompanying Management’s report on internal control over financial reporting on page 135. Our
responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained
in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s
internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a
material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
In our opinion, BP p.l.c. maintained, in all material respects, effective internal control over financial reporting as of 31 December 2011, based on the
Turnbull criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the group balance
sheets of BP p.l.c. as of 31 December 2011 and 2010, and the related group income statement, group statement of comprehensive income, group
statement of changes in equity and group cash flow statement for each of the three years in the period ended 31 December 2011, and our report dated
6 March 2012 expressed an unqualified opinion thereon.
/s/ERNST & YOUNG LLP
Ernst & Young LLP
London, England
6 March 2012
Consent of independent registered public accounting firm
We consent to the incorporation by reference of our reports dated 6 March 2012 with respect to the consolidated financial statements of BP p.l.c., and
the effectiveness of internal control over financial reporting of BP p.l.c., included in this Annual Report (Form 20-F) for the year ended 31 December 2011
in the following registration statements:
Registration Statement on Form F-3 (File No. 333-157906) of BP Capital Markets p.l.c. and BP p.l.c.; and
Registration Statements on Form S-8 (File Nos. 333-149778, 333-119934, 333-103923, 333-79399, 333-67206, 333-102583, 333-103924,
333-123482, 333-123483, 333-131583, 333-146868, 333-146870, 333-146873, 333-131584, 333-132619, 333-173136, 333-177423 and
333-179406) of BP p.l.c.
/s/ERNST & YOUNG LLP
Ernst & Young LLP
London, England
6 March 2012
The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not involve
consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements
since they were initially presented on the website. Legislation in the United Kingdom governing the preparation and dissemination of financial statements
may differ from legislation in other jurisdictions.
BP Annual Report and Form 20-F 2011 177
Financial statementsConsolidated financial statements of the BP group http://www.bp.com/downloads/incomestatement
Group income statement
For the year ended 31 December
Sales and other operating revenues
Earnings from jointly controlled entities – after interest and tax
Earnings from associates – after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expensesa
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 (loss) before interest and taxation
Finance costsa
Net finance expense (income) relating to pensions and other post-retirement benefits
Profit (loss) before taxation
Taxationa
Profit (loss) for the year
Attributable to
BP shareholders
Minority interest
Earnings per share – cents
Profit (loss) for the year attributable to BP shareholders
Basic
Diluted
a See Note 2 for information on the impact of the Gulf of Mexico oil spill on the income statement line items in 2011 and 2010.
Note
6
24
25
7
5
28
8
9
5
15
11
33
17
37
18
39
39
20
20
2011
375,517
1,304
4,916
596
4,130
386,463
285,618
24,145
8,280
11,135
2,058
1,520
13,958
(68)
39,817
1,246
(263)
38,834
12,737
26,097
25,700
397
26,097
2010
297,107
1,175
3,582
681
6,383
308,928
216,211
64,615
5,244
11,164
1,689
843
12,555
309
(3,702)
1,170
(47)
(4,825)
(1,501)
(3,324)
$ million
2009
239,272
1,286
2,615
792
2,173
246,138
163,772
23,202
3,752
12,106
2,333
1,116
14,038
(607)
26,426
1,110
192
25,124
8,365
16,759
(3,719)
395
(3,324)
16,578
181
16,759
135.93
134.29
(19.81)
(19.81)
88.49
87.54
178 BP Annual Report and Form 20-F 2011
Consolidated financial statements of the BP group
http://www.bp.com/downloads/sociandcine
Group statement of comprehensive income
For the year ended 31 December
Profit (loss) for the year
Currency translation differences
Exchange (gains) or losses on translation of foreign operations transferred
to gain or loss on sale of businesses and fixed assets
Actuarial loss 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
Share of equity-accounted entities’ other comprehensive income, net of tax
Taxation
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Minority interest
Group statement of changes in equitya
Note
37
18, 39
2011
26,097
(531)
19
(5,960)
(71)
(3)
44
(195)
(13)
(57)
1,659
(5,108)
2010
(3,324)
259
(20)
(320)
(191)
(150)
(65)
(25)
53
–
(137)
(596)
$ million
2009
16,759
1,826
(27)
(682)
705
2
652
366
136
–
525
3,503
20,989
(3,920)
20,262
39
39
20,605
384
20,989
(4,318)
398
(3,920)
20,137
125
20,262
Share
capital
Own
shares and
Foreign
currency
Share–
based
Profit
BP
and capital
treasury
translation
Fair value
payment
and loss
shareholders'
Minority
reserves
43,448
–
–
–
–
shares
(21,211)
–
–
–
–
reserve
4,937
–
(515)
(515)
–
reserves
469
–
(202)
(202)
–
reserve
1,586
–
–
–
–
account
65,758
25,700
(4,378)
21,322
(4,072)
equity
94,987
25,700
(5,095)
20,605
(4,072)
interest
904
397
(13)
384
(245)
$ million
Total
equity
95,891
26,097
(5,108)
20,989
(4,317)
(4)
102
(8)
–
(8)
(47)
83,063
(47)
111,465
(26)
1,017
(73)
112,482
At 1 January 2011
Profit for the year
Other comprehensive income
Total comprehensive income
Dividends
Share-based payments
(net of tax)
Transactions involving
minority interests
At 31 December 2011
At 1 January 2010
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividends
Share-based payments
6
(112)
–
–
43,454
–
(21,323)
43,304
–
–
–
–
(21,517)
–
–
–
–
–
4,422
4,811
–
126
126
–
(net of tax)
144
306
–
Transactions involving minority
interests
At 31 December 2010
At 1 January 2009
Profit for the year
Other comprehensive income
Total comprehensive income
Dividends
Share-based payments
(net of tax)
Changes in associates’ equity
Transactions involving minority
interests
At 31 December 2009
aSee Note 39 for further information.
–
43,448
43,217
–
–
–
–
87
–
–
(21,211)
(21,839)
–
–
–
–
322
–
–
4,937
2,353
–
2,458
2,458
–
–
–
–
43,304
–
(21,517)
–
4,811
–
–
267
776
–
(307)
(307)
–
–
–
469
(803)
–
1,579
1,579
–
–
–
–
776
–
1,582
1,584
–
–
–
–
–
1,586
1,295
–
–
–
–
289
–
–
1,584
2
(113)
339
72,655
(3,719)
(418)
(4,137)
(2,627)
101,613
(3,719)
(599)
(4,318)
(2,627)
(20)
65,758
(20)
94,987
67,080
16,578
(478)
16,100
(10,483)
91,303
16,578
3,559
20,137
(10,483)
23
(43)
721
(43)
500
395
3
398
(315)
–
321
904
806
181
(56)
125
(416)
–
–
102,113
(3,324)
(596)
(3,920)
(2,942)
339
301
95,891
92,109
16,759
3,503
20,262
(10,899)
721
(43)
(22)
72,655
(22)
101,613
(15)
500
(37)
102,113
BP Annual Report and Form 20-F 2011 179
Financial statementsConsolidated financial statements of the BP group
http://www.bp.com/downloads/balancesheet
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
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Minority interest
Total equity
a Adjusted following the termination of the Pan American Energy LLC sale agreement, as described in Note 4.
C-H Svanberg Chairman
R W Dudley Group Chief Executive
6 March 2012
180 BP Annual Report and Form 20-F 2011
Note
2011
$ million
2010a
110,163
8,598
14,298
14,927
13,335
1,191
162,512
894
6,298
4,210
1,432
528
2,176
178,050
247
26,218
36,549
4,356
1,574
693
1,532
18,556
89,725
4,487
94,212
119,214
12,100
21,102
15,518
13,291
2,117
183,342
884
4,337
5,038
1,255
611
17
195,484
244
25,661
43,526
3,857
1,286
235
288
14,067
89,164
8,420
97,584
293,068
272,262
52,405
3,220
5,932
9,044
1,941
11,238
83,780
538
84,318
3,437
3,773
389
35,169
15,078
26,404
12,018
96,268
46,329
3,856
5,612
14,626
2,920
9,489
82,832
1,047
83,879
14,285
3,677
637
30,710
10,908
22,418
9,857
92,492
180,586
112,482
176,371
95,891
111,465
1,017
112,482
94,987
904
95,891
21
22
23
24
25
27
29
33
18
37
28
29
33
27
30
4
32
33
34
36
4
32
33
34
18
36
37
39
39
39
Consolidated financial statements of the BP group http://www.bp.com/downloads/cashflow
Group cash flow statement
For the year ended 31 December
Operating activities
Profit (loss) before taxation
Adjustments to reconcile profit (loss) before taxation to net cash provided by
operating activities
Exploration expenditure written off
Depreciation, depletion and amortization
Impairment and (gain) loss on sale of businesses and fixed assets
Earnings from jointly controlled entities and associates
Dividends received from jointly controlled entities and associates
Interest receivable
Interest received
Finance costs
Interest paid
Net finance expense (income) relating to pensions and other post-retirement benefits
Share-based payments
Net operating charge for pensions and other post-retirement benefits, less
contributions and benefit payments for unfunded plans
Net charge for provisions, less payments
(Increase) decrease in inventories
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Income taxes paid
Net cash provided by operating activities
Investing activities
Capital expenditure
Acquisitions, net of cash acquired
Investment in jointly controlled entities
Investment in associates
Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposeda
Proceeds from loan repayments
Other
Net cash used in investing activities
Financing activities
Net issue of shares
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
Dividends paid
BP shareholders
Minority interest
Net cash provided by (used in) financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Note
2011
2010
$ million
2009
38,834
(4,825)
25,124
15
9
5
17
37
5
5
1,024
11,135
(2,072)
(6,220)
5,381
(198)
216
1,246
(1,110)
(263)
(88)
(1,004)
2,976
(3,988)
(9,913)
(5,767)
(8,035)
22,154
(17,845)
(10,909)
(857)
(55)
3,500
(768)
301
–
(26,633)
74
11,600
(9,102)
2,227
(4,072)
(245)
482
(492)
(4,489)
18,556
14,067
375
11,164
(4,694)
(4,757)
3,277
(277)
205
1,170
(912)
(47)
197
(959)
19,217
(3,895)
(15,620)
20,607
(6,610)
13,616
(18,421)
(2,468)
(461)
(65)
7,492
9,462
501
–
(3,960)
169
11,934
(4,702)
(3,619)
(2,627)
(315)
840
(279)
10,217
8,339
18,556
593
12,106
160
(3,901)
3,003
(258)
203
1,110
(909)
192
450
(887)
650
(5,363)
7,595
(5,828)
(6,324)
27,716
(20,650)
1
(578)
(164)
1,715
966
530
47
(18,133)
207
11,567
(6,021)
(4,405)
(10,483)
(416)
(9,551)
110
142
8,197
8,339
a 2010 included a deposit received in advance of $3,530 million in respect of the expected sale of our interest in Pan American Energy LLC; 2011 includes the repayment of the same amount following
the termination of the sale agreement as described in Note 4.
BP Annual Report and Form 20-F 2011 181
Financial statementsConsolidated financial statements of the BP group
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 2011 were approved and signed by the chairman and group
chief executive on 6 March 2012 having been duly authorized to do so by
the board of directors. BP p.l.c. is a public limited company incorporated and
domiciled in England and Wales. The consolidated financial statements have
been prepared in accordance with International Financial Reporting Standards
(IFRS) as issued by the International Accounting Standards Board (IASB),
IFRS as adopted by the European Union (EU) and in accordance with the
provisions of the Companies Act 2006. IFRS as adopted by the EU differs in
certain respects from IFRS as issued by the IASB, however, the differences
have no impact on the group’s consolidated financial statements for the
years presented. The significant accounting policies of the group are set out
below.
Basis of preparation
The consolidated financial statements have been prepared in accordance
with IFRS and IFRS Interpretations Committee (IFRIC) interpretations
issued and effective for the year ended 31 December 2011, or issued and
early adopted. The standards and interpretations adopted in the year are
described further on page 188.
The accounting policies that follow have been consistently applied
to all years presented. The group balance sheet as at 1 January 2010 is
not presented as it is not affected by the retrospective adoption of any
new accounting policies during the year, nor any other retrospective
restatements or reclassifications.
The consolidated financial statements are presented in US dollars
and all values are rounded to the nearest million dollars ($ million), except
where otherwise indicated.
For further information regarding the key judgements and estimates
made by management in applying the group’s accounting policies, refer to
Critical accounting policies on pages 154 to 157, which forms part of these
financial statements.
Basis of consolidation
The group financial statements consolidate the financial statements
of BP p.l.c. and the entities it controls (its subsidiaries) drawn up to 31
December each year. Control comprises the power to govern the financial
and operating policies of the investee so as to obtain benefit from its
activities and is achieved through direct and indirect ownership of voting
rights; currently exercisable or convertible potential voting rights; or by way
of contractual agreement. Subsidiaries are consolidated from the date of
their acquisition, being the date on which the group obtains control, and
continue to be consolidated until the date that such control ceases. The
financial statements of subsidiaries are prepared for the same reporting
year as the parent company, using consistent accounting policies.
Intercompany balances and transactions, including unrealized profits arising
from intragroup transactions, have been eliminated. Unrealized losses are
eliminated unless the transaction provides evidence of an impairment of the
asset transferred. Minority interests represent the equity in subsidiaries that
is not attributable, directly or indirectly, to the group.
Segmental reporting
The group’s operating segments are established on the basis of those
components of the group that are evaluated regularly by the chief operating
decision maker in deciding how to allocate resources and in assessing
performance. During the second quarter of 2010 a separate organization
was created within the group to deal with the ongoing response to the
Gulf of Mexico oil spill. This organization reports directly to the group
chief executive officer and its costs are excluded from the results of the
existing operating segments. Under IFRS its costs are therefore presented
as a reconciling item between the sum of the results of the reportable
segments and the group results.
182 BP Annual Report and Form 20-F 2011
182 BP Annual Report and Form 20-F 2011
The accounting policies of the operating segments are the same as the
group’s accounting policies described in this note, except that IFRS requires
that the measure of profit or loss disclosed for each operating segment
is the measure that is provided regularly to the chief operating decision
maker. For BP, this measure of profit or loss is replacement cost profit
before interest and tax which reflects the replacement cost of supplies by
excluding from profit inventory holding gains and losses. Replacement cost
profit for the group is not a recognized measure under generally accepted
accounting practice (GAAP). For further information see Note 6.
Interests in joint ventures
A joint venture is a contractual arrangement whereby two or more parties
(venturers) undertake an economic activity that is subject to joint control.
Joint control exists only when the strategic financial and operating decisions
relating to the activity require the unanimous consent of the venturers. A
jointly controlled entity is a joint venture that involves the establishment of a
company, partnership or other entity to engage in economic activity that the
group jointly controls with its fellow venturers.
The results, assets and liabilities of a jointly controlled entity are
incorporated in these financial statements using the equity method of
accounting. Under the equity method, the investment in a jointly controlled
entity is carried in the balance sheet at cost, plus post-acquisition changes
in the group’s share of net assets of the jointly controlled entity, less
distributions received and less any impairment in value of the investment.
Loans advanced to jointly controlled entities that have the characteristics of
equity financing are also included in the investment on the group balance
sheet. The group income statement reflects the group’s share of the
results after tax of the jointly controlled entity.
Financial statements of jointly controlled entities are prepared for
the same reporting year as the group. Where necessary, adjustments are
made to those financial statements to bring the accounting policies used
into line with those of the group.
Unrealized gains on transactions between the group and its jointly
controlled entities are eliminated to the extent of the group’s interest in the
jointly controlled entities. Unrealized losses are also eliminated unless the
transaction provides evidence of an impairment of the asset transferred.
The group assesses investments in jointly controlled entities for
impairment whenever events or changes in circumstances indicate that the
carrying value may not be recoverable. If any such indication of impairment
exists, the carrying amount of the investment is compared with its
recoverable amount, being the higher of its fair value less costs to sell and
value in use. Where the carrying amount exceeds the recoverable amount,
the investment is written down to its recoverable amount.
The group ceases to use the equity method of accounting on the
date from which it no longer has joint control or significant influence over
the joint venture or associate respectively, or when the interest becomes
held for sale.
Certain of the group’s activities, particularly in the Exploration and
Production segment, are conducted through joint ventures where the
venturers have a direct ownership interest in, and jointly control, the assets
of the venture. BP recognizes, on a line-by-line basis in the consolidated
financial statements, its share of the assets, liabilities and expenses of
these jointly controlled assets incurred jointly with the other partners, along
with the group’s income from the sale of its share of the output and any
liabilities and expenses that the group has incurred in relation to the venture.
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.
Notes on financial statements 1. Significant accounting policies continued
Foreign currency translation
The functional currency is the currency of the primary economic environment
in which an entity operates and is normally the currency in which the entity
primarily generates and expends cash.
In individual companies, transactions in foreign currencies are initially
Goodwill may also arise upon investments in jointly controlled entities and
associates, being the surplus of the cost of investment over the group’s
share of the net fair value of the identifiable assets. Such goodwill is
recorded within investments in jointly controlled entities and associates,
and any impairment of the investment is included within the earnings from
jointly controlled entities and associates.
recorded in the functional currency by applying the rate of exchange ruling
at the date of the transaction. Monetary assets and liabilities denominated
in foreign currencies are retranslated into the functional currency at the
rate of exchange ruling at the balance sheet date. Any resulting exchange
differences are included in the income statement. Non-monetary assets
and liabilities, other than those measured at fair value, are not retranslated
subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities
of non-US dollar functional currency subsidiaries, jointly controlled entities
and associates, including related goodwill, are translated into US dollars at
the rate of exchange ruling at the balance sheet date. The results and cash
flows of non-US dollar functional currency subsidiaries, jointly controlled
entities and associates are translated into US dollars using average rates
of exchange. Exchange adjustments arising when the opening net assets
and the profits for the year retained by non-US dollar functional currency
subsidiaries, jointly controlled entities and associates are translated into
US dollars are taken to a separate component of equity and reported in
the statement of comprehensive income. Exchange gains and losses
arising on long-term intragroup foreign currency borrowings used to
finance the group’s non-US dollar investments are also taken to other
comprehensive income. On disposal or partial disposal of a non-US dollar
functional currency subsidiary, jointly controlled entity or associate, the
deferred cumulative amount of exchange gains and losses recognized in
equity relating to that particular non-US dollar operation is reclassified to
income statement.
Business combinations and goodwill
A business combination is a transaction or other event in which an acquirer
obtains control of one or more businesses. A business is an integrated set
of activities and assets that is capable of being conducted and managed
for the purpose of providing a return in the form of dividends or lower
costs or other economic benefits directly to investors or other owners or
participants. A business consists of inputs and processes applied to those
inputs that have the ability to create outputs.
Business combinations are accounted for using the acquisition
method. The identifiable assets acquired and liabilities assumed are
measured at their fair values at the acquisition date. The cost of an
acquisition is measured as the aggregate of the consideration transferred,
measured at acquisition-date fair value, and the amount of any minority
interest in the acquiree. Minority interests are stated either at fair value
or at the proportionate share of the recognized amounts of the acquiree’s
identifiable net assets. Acquisition costs incurred are expensed and
included in distribution and administration expenses.
Goodwill is initially measured as the excess of the aggregate of the
consideration transferred, the amount recognized for any minority interest
and the acquisition-date fair values of any previously held interest in the
acquiree over the fair value of the identifiable assets acquired and liabilities
assumed at the acquisition date.
At the acquisition date, any goodwill acquired is allocated to each of
the cash-generating units, or groups of cash-generating units, expected to
benefit from the combination’s synergies.
Following initial recognition, goodwill is measured at cost less any
accumulated impairment losses. Goodwill is reviewed for impairment annually
or more frequently if events or changes in circumstances indicate that the
carrying value may be impaired. Impairment is determined by assessing the
recoverable amount of the cash-generating unit to which the goodwill relates.
Where the recoverable amount of the cash-generating unit is less than the
carrying amount, an impairment loss is recognized. An impairment loss
recognized for goodwill is not reversed in a subsequent period.
Goodwill arising on business combinations prior to 1 January 2003
is stated at the previous carrying amount, less subsequent impairments,
under UK generally accepted accounting practice.
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 subject only to terms that are
usual and customary for sales of such assets. 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 as held
for sale.
Property, plant and equipment and intangible assets once classified
as held for sale are not depreciated. The group ceases to use the equity
method of accounting on the date from which an interest in a jointly
controlled entity or an interest in an associate becomes held for sale.
If a non-current asset or disposal group has been classified as held
for sale, but subsequently ceases to meet the criteria to be classified as
held for sale, the group ceases to classify the asset or disposal group as
held for sale. Non-current assets and disposal groups that cease to be
classified as held for sale are measured at the lower of carrying amount
before the asset or disposal group was classified as held for sale (adjusted
for any depreciation, amortization or revaluation that would have been
recognized had the asset or disposal group not been classified as held for
sale) and its recoverable amount at the date of the subsequent decision
not to sell. Except for any interests in equity-accounted entities that cease
to be classified as held for sale, any adjustment to the carrying amount
is recognized in profit or loss in the period in which the asset ceases to
be classified as held for sale. When an interest in an equity-accounted
entity ceases to be classified as held for sale, it is accounted for using the
equity method as from the date of its classification as held for sale and the
financial statements for the periods since classification as held for sale are
amended accordingly.
Intangible assets
Intangible assets, other than goodwill, include expenditure on the
exploration for and evaluation of oil and natural gas resources, computer
software, patents, licences and trademarks and are stated at the amount
initially recognized, less accumulated amortization and accumulated
impairment losses. For information on accounting for expenditures on the
exploration for and evaluation of oil and gas resources, see the accounting
policy for oil and natural gas exploration, appraisal and development
expenditure below.
Intangible assets acquired separately from a business are carried
initially at cost. The initial cost is the aggregate amount paid and the fair
value of any other consideration given to acquire the asset. An intangible
asset acquired as part of a business combination is measured at fair value
at the date of acquisition and is recognized separately from goodwill if the
asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life are amortized on a straight-line
basis over their expected useful lives. For patents, licences and trademarks,
expected useful life is the shorter of the duration of the legal agreement
and economic useful life, and can range from three to 15 years. Computer
software costs generally 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.
BP Annual Report and Form 20-F 2011 183
Financial statementsNotes on financial statements 1. Significant accounting policies continued
Oil and natural gas exploration, appraisal and development expenditure
Oil and natural gas exploration, appraisal and development expenditure
is accounted for using the principles of the successful efforts method of
accounting.
Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalized
within intangible assets and are reviewed at each reporting date to confirm
that there is no indication that the carrying amount exceeds the recoverable
amount. This review includes confirming that exploration drilling is still
under way or firmly planned or that it has been determined, or work is
under way to determine, that the discovery is economically viable based on
a range of technical and commercial considerations and sufficient progress
is being made on establishing development plans and timing. If no future
activity is planned, the remaining balance of the licence and property
acquisition costs is written off. Lower value licences are pooled and
amortized on a straight-line basis over the estimated period of exploration.
Upon recognition of proved reserves and internal approval for development,
the relevant expenditure is transferred to property, plant and equipment.
Expenditure on major maintenance refits or repairs comprises the cost
of replacement assets or parts of assets, inspection costs and overhaul
costs. Where an asset or part of an asset that was separately depreciated
is replaced and it is probable that future economic benefits associated
with the item will flow to the group, the expenditure is capitalized and
the carrying amount of the replaced asset is derecognized. Inspection
costs associated with major maintenance programmes are capitalized and
amortized over the period to the next inspection. Overhaul costs for major
maintenance programmes, and 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, common
facilities and future decommissioning costs are amortized over total proved
reserves. The unit-of-production rate for the amortization of common
facilities costs takes into account expenditures incurred to date, together
with the future capital expenditure expected to be incurred in relation to
these common facilities.
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:
Exploration and appraisal expenditure
Geological and geophysical exploration costs are charged against income
as incurred. Costs directly associated with an exploration well are initially
capitalized as an intangible asset until the drilling of the well is complete
and the results have been evaluated. These costs include employee
remuneration, materials and fuel used, rig costs and payments made to
contractors. If potentially commercial quantities of hydrocarbons are not
found, the exploration well is written off as a dry hole. If hydrocarbons are
found and, subject to further appraisal activity, are likely to be capable of
commercial development, the costs continue to be carried as an asset.
Costs directly associated with appraisal activity, undertaken to
determine the size, characteristics and commercial potential of a reservoir
following the initial discovery of hydrocarbons, including the costs of
appraisal wells where hydrocarbons were not found, are initially capitalized
as an intangible asset.
All such carried costs are subject to technical, commercial and
management review at least once a year to confirm the continued intent
to develop or otherwise extract value from the discovery. When this is no
longer the case, the costs are written off. When proved reserves of oil and
natural gas are determined and development is approved by management,
the relevant expenditure is transferred to property, plant and equipment.
Development expenditure
Expenditure on the construction, installation and completion of infrastructure
facilities such as platforms, pipelines and the drilling of development wells,
including service and unsuccessful development or delineation wells, is
capitalized within property, plant and equipment and is depreciated from the
commencement of production as described below in the accounting policy
for property, plant and equipment.
Property, plant and equipment
Property, plant and equipment is stated at cost, less accumulated
depreciation and accumulated impairment losses.
The initial cost of an asset comprises its purchase price or construction
cost, any costs directly attributable to bringing the asset into operation, the
initial estimate of any decommissioning obligation, if any, and, for qualifying
assets, borrowing costs. The purchase price or construction cost is the
aggregate amount paid and the fair value of any other consideration given
to acquire the asset. The capitalized value of a finance lease is also included
within property, plant and equipment. Exchanges of assets are measured
at fair value unless the exchange transaction lacks commercial substance or
the fair value of neither the asset received nor the asset given up is reliably
measurable. The cost of the acquired asset is measured at the fair value
of the asset given up, unless the fair value of the asset received is more
clearly evident. Where fair value is not used, the cost of the acquired asset is
measured at the carrying amount of the asset given up. The gain or loss on
derecognition of the asset given up is recognized in profit or loss.
184 BP Annual Report and Form 20-F 2011
184 BP Annual Report and Form 20-F 2011
Land improvements
Buildings
Refineries
Petrochemicals
Pipelines
Service stations
Office equipment
Fixtures and fittings
15 to 25 years
20 to 50 years
20 to 30 years
20 to 30 years
10 to 50 years
15 years
3 to 7 years
5 to 15 years
The expected useful lives of property, plant and equipment are reviewed on
an annual basis and, if necessary, changes in useful lives are accounted for
prospectively.
The carrying amount of property, plant and equipment is reviewed
for impairment whenever events or changes in circumstances indicate the
carrying value may not be recoverable.
An item of property, plant and equipment is derecognized upon
disposal or when no future economic benefits are expected to arise from
the continued use of the asset. Any gain or loss arising on derecognition of
the asset (calculated as the difference between the net disposal proceeds
and the carrying amount of the item) is included in the income statement in
the period in which the item is derecognized.
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 amount of
an asset may not be recoverable, for example, low prices or margins for an
extended period or, for oil and gas assets, significant downward revisions
of estimated volumes or increases in estimated future development
expenditure. If any such indication of impairment exists, the group makes an
estimate of the asset’s recoverable amount. Individual assets are grouped
for impairment assessment purposes at the lowest level at which there are
identifiable cash flows that are largely independent of the cash flows of other
groups of assets. An asset group’s recoverable amount is the higher of its fair
value less costs to sell and its value in use. Where the carrying amount of an
asset group exceeds its recoverable amount, the asset group is considered
impaired and is written down to its recoverable amount. In assessing value in
use, the estimated future cash flows are adjusted for the risks specific to the
asset group and are discounted to their present value using a pre-tax discount
rate that reflects current market assessments of the time value of money.
An assessment is made at each reporting date as to whether there
is any indication that previously recognized impairment losses may no longer
exist or may have decreased. If such an 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
Notes on financial statements Available-for-sale financial assets
If an available-for-sale financial asset is impaired, the cumulative loss
previously recognized in equity is transferred to the income statement. Any
subsequent recovery in the fair value of the asset is recognized within other
comprehensive income.
If there is objective evidence that an impairment loss on an
unquoted equity instrument that is carried at cost has been incurred, the
amount of the loss is measured as the difference between the asset’s
carrying amount and the present value of estimated future cash flows
discounted at the current market rate of return for a similar financial asset.
Inventories
Inventories, other than inventory held for trading purposes, are stated at
the lower of cost and net realizable value. Cost is determined by the first-in
first-out method and comprises direct purchase costs, cost of production,
transportation and manufacturing expenses. Net realizable value is
determined by reference to prices existing at the balance sheet date.
Inventories held for trading purposes are stated at fair value less
costs to sell and any changes in net realizable value are recognized in the
income statement.
Supplies are valued at cost to the group mainly using the average
method or net realizable value, whichever is the lower.
Financial liabilities
Financial liabilities are classified as financial liabilities at fair value through
profit or loss; derivatives designated as hedging instruments in an effective
hedge; or as financial liabilities measured at amortized cost, as appropriate.
Financial liabilities include trade and other payables, accruals, most items of
finance debt and derivative financial instruments. The group determines the
classification of its financial liabilities at initial recognition. The measurement
of financial liabilities depends on their classification, as follows:
Financial liabilities at fair value through profit or loss
Derivatives, other than those designated as effective hedging instruments,
are classified as held for trading and are included in this category. These
liabilities are carried on the balance sheet at fair value with gains or losses
recognized in the income statement.
Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value. The treatment
of gains and losses arising from revaluation is described below in the
accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value. For interest-
bearing loans and borrowings this is the fair value of the proceeds received
net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently
measured at amortized cost using the effective interest method. Amortized
cost is calculated by taking into account any issue costs, and any discount
or premium on settlement. Gains and losses arising on the repurchase,
settlement or cancellation of liabilities are recognized respectively in interest
and other income and finance costs.
This category of financial liabilities includes trade and other payables
and finance debt.
1. Significant accounting policies continued
impairment loss been recognized for the asset in prior years. Such reversal
is recognized in profit or loss. After such a reversal, the depreciation charge
is adjusted in future periods to allocate the asset’s revised carrying amount,
less any residual value, on a systematic basis over its remaining useful life.
Financial assets
Financial assets are classified as loans and receivables; available-for-sale
financial assets; financial assets at fair value through profit or loss; or as
derivatives designated as hedging instruments in an effective hedge, as
appropriate. Financial assets include cash and cash equivalents, trade
receivables, other receivables, loans, other investments, and derivative
financial instruments. The group determines the classification of its financial
assets at initial recognition. Financial assets are recognized initially at fair
value, normally being the transaction price plus, in the case of financial assets
not at fair value through profit or loss, directly attributable transaction costs.
The subsequent measurement of financial assets depends on their
classification, as follows:
Loans and receivables
Loans and receivables are non-derivative financial assets with fixed or
determinable payments that are not quoted in an active market. Such
assets are carried at amortized cost using the effective interest method if
the time value of money is significant. Gains and losses are recognized in
income when the loans and receivables are derecognized or impaired, as
well as through the amortization process. This category of financial assets
includes trade and other receivables.
Available-for-sale financial assets
Available-for-sale financial assets are those non-derivative financial assets
that are not classified as loans and receivables. After initial recognition,
available-for-sale financial assets are measured at fair value, with gains
or losses recognized within other comprehensive income. Accumulated
changes in fair value are recorded as a separate component of equity until
the investment is derecognized or impaired.
The fair value of quoted investments is determined by reference to
bid prices at the close of business on the balance sheet date. Where there
is no active market, fair value is determined using valuation techniques.
Where fair value cannot be reliably measured, assets are carried at cost.
Financial assets at fair value through profit or loss
Derivatives, other than those designated as effective hedging instruments,
are classified as held for trading and are included in this category. These
assets are carried on the balance sheet at fair value with gains or losses
recognized in the income statement.
Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value. The
treatment of gains and losses arising from revaluation is described below
in the accounting policy for derivative financial instruments and hedging
activities.
Impairment of financial assets
The group assesses at each balance sheet date whether a financial asset or
group of financial assets is impaired.
Loans and receivables
If there is objective evidence that an impairment loss on loans and
receivables carried at amortized cost has been incurred, the amount of the
loss is measured as the difference between the asset’s carrying amount
and the present value of estimated future cash flows discounted at the
financial asset’s original effective interest rate. The carrying amount of the
asset is reduced, with the amount of the loss recognized in the income
statement.
BP Annual Report and Form 20-F 2011 185
Financial statementsNotes on financial statements Cash flow hedges
For cash flow hedges, the effective portion of the gain or loss on the
hedging instrument is recognized within other comprehensive income,
while the ineffective portion is recognized in profit or loss. Amounts taken
to other comprehensive income are transferred to the income statement
when the hedged transaction affects profit or loss. The gain or loss
relating to the effective portion of interest rate swaps hedging variable rate
borrowings is recognized in the income statement within finance costs.
Where the hedged item is the cost of a non-financial asset or
liability, such as a forecast transaction for the purchase of property, plant
and equipment, the amounts recognized within other comprehensive
income are transferred to the initial carrying amount of the non-financial
asset or liability.
If the hedging instrument expires or is sold, terminated or exercised
without replacement or rollover, or if its designation as a hedge is revoked,
amounts previously recognized within other comprehensive income remain in
equity until the forecast transaction occurs and are transferred to the income
statement or to the initial carrying amount of a non-financial asset or liability
as above. If a forecast transaction is no longer expected to occur, amounts
previously recognized in equity are reclassified to the income statement.
Embedded derivatives
Derivatives embedded in other financial instruments or other host contracts
are treated as separate derivatives when their risks and characteristics are
not closely related to those of the host contract. Contracts are assessed for
embedded derivatives when the group becomes a party to them, including
at the date of a business combination. Embedded derivatives are measured
at fair value at each balance sheet date. Any gains or losses arising from
changes in fair value are taken directly to the income statement.
Provisions, contingencies and reimbursement assets
Provisions are recognized when the group has a present obligation (legal
or constructive) as a result of a past event, it is probable that an outflow
of resources embodying economic benefits will be required to settle
the obligation and a reliable estimate can be made of the amount of the
obligation. Where appropriate, the future cash flow estimates are adjusted
to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are
determined by discounting the expected future cash flows at a pre-tax
risk-free rate that reflects current market assessments of the time value
of money. Where discounting is used, the increase in the provision due to
the passage of time is recognized within finance costs. Provisions are split
between amounts expected to be settled within 12 months of the balance
sheet date (current) and amounts expected to be settled later (non-current).
Contingent liabilities are possible obligations whose existence will only be
confirmed by future events not wholly within the control of the group, or
present obligations where it is not probable that an outflow of resources
will be required or the amount of the obligation cannot be measured with
sufficient reliability.
Contingent liabilities are not recognized in the financial statements
but are disclosed unless the possibility of an outflow of economic resources
is considered remote.
Where the group makes contributions into a separately administered
fund for restoration, environmental or other obligations, which it does
not control, and the group’s right to the assets in the fund is restricted,
the obligation to contribute to the fund is recognized as a liability where
it is probable that such additional contributions will be made. The group
recognizes a reimbursement asset separately, being the lower of the
amount of the associated restoration, environmental or other provision and
the group’s share of the fair value of the net assets of the fund available to
contributors.
1. Significant accounting policies continued
Leases
Finance leases, which transfer to the group substantially all the risks and
benefits incidental to ownership of the leased item, are capitalized at the
commencement of the lease term at the fair value of the leased property
or, if lower, at the present value of the minimum lease payments. Finance
charges are allocated to each period so as to achieve a constant rate of
interest on the remaining balance of the liability and are charged directly
against income.
Capitalized leased assets are depreciated over the shorter of
the estimated useful life of the asset or the lease term. Operating lease
payments are recognized as an expense in the income statement on a
straight-line basis over the lease term. For both finance and operating
leases, contingent rents are recognized in the income statement in the
period in which they are incurred.
Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain
exposures to fluctuations in foreign currency exchange rates, interest
rates and commodity prices as well as for trading purposes. Such
derivative financial instruments are initially recognized at fair value on the
date on which a derivative contract is entered into and are subsequently
remeasured at fair value. Derivatives are carried as assets when the fair
value is positive and as liabilities when the fair value is negative.
Contracts to buy or sell a non-financial item that can be settled net in
cash or another financial instrument, or by exchanging financial instruments
as if the contracts were financial instruments, with the exception of
contracts that were entered into and continue to be held for the purpose
of the receipt or delivery of a non-financial item in accordance with the
group’s expected purchase, sale or usage requirements, are accounted for
as financial instruments.
Gains or losses arising from changes in the fair value of derivatives
that are not designated as effective hedging instruments are recognized in
the income statement.
For the purpose of hedge accounting, hedges are classified as:
• Fair value hedges when hedging exposure to changes in the fair value of
a recognized asset or liability.
• Cash flow hedges when hedging exposure to variability in cash flows that
is either attributable to a particular risk associated with a recognized asset
or liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at
inception, together with the risk management objective and strategy for
undertaking the hedge. The documentation includes identification of the
hedging instrument, the hedged item or transaction, the nature of the
risk being hedged, and how the entity will assess the hedging instrument
effectiveness in offsetting the exposure to changes in the hedged item’s
fair value or cash flows attributable to the hedged item. Such hedges
are expected at inception to be highly effective in achieving offsetting
changes in fair value or cash flows. Hedges meeting the criteria for hedge
accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss.
The change in the fair value of the hedged item attributable to the risk being
hedged is recorded as part of the carrying value of the hedged item and is
also recognized in profit or loss.
The group applies fair value hedge accounting for hedging fixed
interest rate risk on borrowings. The gain or loss relating to the effective
portion of the interest rate swap is recognized in the income statement
within finance costs, offsetting the amortization of the interest on the
underlying borrowings.
If the criteria for hedge accounting are no longer met, or if the
group revokes the designation, the adjustment to the carrying amount of a
hedged item for which the effective interest method is used is amortized to
profit or loss over the period to maturity.
186 BP Annual Report and Form 20-F 2011
186 BP Annual Report and Form 20-F 2011
Notes on financial statements 1. Significant accounting policies continued
Decommissioning
Liabilities for decommissioning costs are recognized when the group has
an obligation to dismantle and remove a facility or an item of plant and
to restore the site on which it is located, and when a reliable estimate of
that liability can be made. Where an obligation exists for a new facility,
such as oil and natural gas production or transportation facilities, this
liability will be recognized on construction or installation. An obligation for
decommissioning may also crystallize during the period of operation of a
facility through a change in legislation or through a decision to terminate
operations. The amount recognized is the present value of the estimated
future expenditure determined in accordance with local conditions and
requirements.
A corresponding item of property, plant and equipment of an
amount equivalent to the provision is also recognized. This is subsequently
depreciated as part of the asset.
Other than the unwinding discount on the provision, any change
in the present value of the estimated expenditure is reflected as an
adjustment to the provision and the corresponding item of property, plant
and equipment. Such changes include foreign exchange gains and losses
arising on the retranslation of the liability into the functional currency of the
reporting entity, when it is known that the liability will be settled in a foreign
currency.
Environmental expenditures and liabilities
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an
existing condition caused by past operations and do not contribute to
current or future earnings are expensed.
Liabilities for environmental costs are recognized when a clean-up is
probable and the associated costs can be reliably estimated. Generally, the
timing of recognition of these provisions coincides with the commitment to
a formal plan of action or, if earlier, on divestment or on closure of inactive
sites.
The amount recognized is the best estimate of the expenditure
required. Where the liability will not be settled for a number of years,
the amount recognized is the present value of the estimated future
expenditure.
Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave
and sick leave are accrued in the period in which the associated services
are rendered by employees of the group. Deferred bonus arrangements
that have a vesting date more than 12 months after the period end are
valued on an actuarial basis using the projected unit credit method and
amortized on a straight-line basis over the service period until the award
vests. The accounting policies for share-based payments and for pensions
and other post-retirement benefits are described below.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by
reference to the fair value at the date at which equity instruments are
granted and is recognized as an expense over the vesting period, which
ends on the date on which the relevant employees become fully entitled to
the award. Fair value is determined by using an appropriate valuation model.
In valuing equity-settled transactions, no account is taken of any vesting
conditions, other than conditions linked to the price of the shares of the
company (market conditions). Non-vesting conditions, such as the condition
that employees contribute to a savings-related plan, are taken into account
in the grant-date fair value, and failure to meet a non-vesting condition is
treated as a cancellation, where this is within the control of the employee.
No expense is recognized for awards that do not ultimately vest,
except for awards where vesting is conditional upon a market condition,
which are treated as vesting irrespective of whether or not the market
condition is satisfied, provided that all other performance conditions are
satisfied.
At each balance sheet date before vesting, the cumulative expense is
calculated, representing the extent to which the vesting period has expired
and management’s best estimate of the achievement or otherwise of non-
market conditions and the number of equity instruments that will ultimately
vest or, in the case of an instrument subject to a market condition, be
treated as vesting as described above. The movement in cumulative
expense since the previous balance sheet date is recognized in the income
statement, with a corresponding entry in equity.
When the terms of an equity-settled award are modified or a new
award is designated as replacing a cancelled or settled award, the cost
based on the original award terms continues to be recognized over the
original vesting period. In addition, an expense is recognized over the
remainder of the new vesting period for the incremental fair value of any
modification, based on the difference between the fair value of the original
award and the fair value of the modified award, both as measured on the
date of the modification. No reduction is recognized if this difference is
negative.
When an equity-settled award is cancelled, it is treated as if it had
vested on the date of cancellation and any cost not yet recognized in the
income statement for the award is expensed immediately.
Cash-settled transactions
The cost of cash-settled transactions is measured at fair value and
recognized as an expense over the vesting period, with a corresponding
liability recognized on the balance sheet.
Pensions and other post-retirement benefits
The cost of providing benefits under the defined benefit plans is
determined separately for each plan using the projected unit credit method,
which attributes entitlement to benefits to the current period (to determine
current service cost) and to the current and prior periods (to determine
the present value of the defined benefit obligation). Past service costs
are recognized immediately when the company becomes committed
to a change in pension plan design. When a settlement (eliminating all
obligations for benefits already accrued) or a curtailment (reducing future
obligations as a result of a material reduction in the scheme membership
or a reduction in future entitlement) occurs, the obligation and related
plan assets are remeasured using current actuarial assumptions and the
resultant gain or loss is recognized in the income statement during the
period in which the settlement or curtailment occurs.
The interest element of the defined benefit cost represents the
change in present value of scheme obligations resulting from the passage
of time, and is determined by applying the discount rate to the opening
present value of the benefit obligation, taking into account material changes
in the obligation during the year. The expected return on plan assets is
based on an assessment made at the beginning of the year of long-term
market returns on plan assets, adjusted for the forecasts of contributions
received and benefits paid during the year. The difference between the
expected return on plan assets and the interest cost is recognized in the
income statement as other finance income or expense.
Actuarial gains and losses are recognized in full within other
comprehensive income in the year in which they occur.
The defined benefit pension plan surplus or deficit in the balance
sheet comprises the total for each plan of the present value of the defined
benefit obligation (using a discount rate based on high quality corporate
bonds), less the fair value of plan assets out of which the obligations are to
be settled directly. Fair value is based on market price information and, in
the case of quoted securities, is the published bid price.
Contributions to defined contribution schemes are recognized in the
income statement in the period in which they become payable.
BP Annual Report and Form 20-F 2011 187
Financial statementsNotes on financial statements 1. Significant accounting policies continued
Corporate taxes
Income tax expense represents the sum of the tax currently payable and
deferred tax. Interest and penalties relating to tax are also included in
income tax expense.
The tax currently payable is based on the taxable profits for the
period. Taxable profit differs from net profit as reported in the income
statement because it excludes items of income or expense that are taxable
or deductible in other periods and it further excludes items that are never
taxable or deductible. The group’s liability for current tax is calculated using
tax rates and laws 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 accounting profit nor taxable profit or loss.
• In respect of taxable temporary differences associated with investments
in subsidiaries, jointly controlled entities and associates, where the group
is able to control the timing of the reversal of the temporary differences
and it is probable that the temporary differences will not reverse in the
foreseeable future.
Deferred tax assets are recognized for all deductible temporary differences,
carry-forward of unused tax credits and unused tax losses, to the extent
that it is probable that taxable profit will be available against which the
deductible temporary differences and the carry-forward of unused tax
credits and unused tax losses can be utilized:
• 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 accounting profit nor taxable profit or loss.
• In respect of deductible temporary differences associated with
investments in subsidiaries, jointly controlled entities and associates,
deferred tax assets are recognized only to the extent that it is probable
that the temporary differences will reverse in the foreseeable future and
taxable profit will be available against which the temporary differences
can be utilized.
The carrying amount of deferred tax assets is reviewed at each balance
sheet date and reduced to the extent that it is no longer probable that
sufficient taxable profit will be available to allow all or part of the deferred
income tax asset to be utilized.
Deferred tax assets and liabilities are measured at the tax rates that
are expected to apply to the year when the asset is realized or the liability
is settled, based on tax rates (and tax laws) that have been enacted or
substantively enacted at the balance sheet date.
Tax relating to items recognized in other comprehensive income
is recognized in other comprehensive income and tax relating to items
recognized directly in equity is recognized directly 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 within receivables or payables in the balance sheet.
Own equity instruments
The group’s holdings in its own equity instruments, including ordinary
shares held by Employee Share Ownership Plan Trusts (ESOPs), are
classified as ‘treasury shares’, or ‘own shares’ for the ESOPs, and are
shown as deductions from shareholders’ equity at cost. Consideration
received for the sale of such shares is also recognized in equity, with any
difference between the proceeds from sale and the original cost being
taken to the profit and loss account reserve. No gain or loss is recognized
in the income statement on the purchase, sale, issue or cancellation of
equity shares.
Revenue
Revenue arising from the sale of goods is recognized when the significant
risks and rewards of ownership have passed to the buyer, which is typically
at the point that title passes, and the revenue can be reliably measured.
Revenue is measured at the fair value of the consideration received
or receivable and represents amounts receivable for goods provided in the
normal course of business, net of discounts, customs duties and sales
taxes.
Physical exchanges are reported net, as are sales and purchases
made with a common counterparty, as part of an arrangement similar to
a physical exchange. Similarly, where the group acts as agent on behalf
of a third party to procure or market energy commodities, any associated
fee income is recognized but no purchase or sale is recorded. Additionally,
where forward sale and purchase contracts for oil, natural gas or power
have been determined to be for trading purposes, the associated sales
and purchases are reported net within sales and other operating revenues
whether or not physical delivery has occurred.
Generally, revenues from the production of oil and natural gas
properties in which the group has an interest with joint venture partners are
recognized on the basis of the group’s working interest in those properties
(the entitlement method). Differences between the production sold and the
group’s share of production are not significant.
Interest income is recognized as the interest accrues (using the
effective interest rate that is the rate that exactly discounts estimated
future cash receipts through the expected life of the financial instrument to
the net carrying amount of the financial asset).
Dividend income from investments is recognized when the
shareholders’ right to receive the payment is established.
Research
Research costs are expensed as incurred.
Finance costs
Finance costs directly attributable to the acquisition, construction or
production of qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use, are added
to the cost of those assets, until such time as the assets are substantially
ready for their intended use. All other finance costs are recognized in the
income statement in the period in which they are incurred.
Use of estimates
The preparation of financial statements requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities as well as the disclosure of contingent assets and liabilities at the
balance sheet date and the reported amounts of revenues and expenses
during the reporting period. Actual outcomes could differ from those
estimates.
Impact of new International Financial Reporting Standards
Adopted for 2011
There are no new or amended standards or interpretations adopted with
effect from 1 January 2011 that have a significant impact on the financial
statements.
188 BP Annual Report and Form 20-F 2011
188 BP Annual Report and Form 20-F 2011
Notes on financial statements 1. Significant accounting policies continued
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.
• Interests in other entities and related disclosures
In May 2011, the IASB issued three new standards relating to interests
in other entities and related disclosures. The new standards are IFRS 10
‘Consolidated Financial Statements’, IFRS 11 ‘Joint Arrangements’ and
IFRS 12 ‘Disclosure of Interests in Other Entities’. In addition, the IASB
issued amendments to IAS 27 ‘Consolidated and Separate Financial
Statements’ (now renamed IAS 27 ‘Separate Financial Statements’) and
IAS 28 ‘Investments in Associates’ (now renamed IAS 28 ‘Investments in
Associates and Joint Ventures’).
IFRS 10 introduces a single consolidation model that identifies
control as the basis for consolidation. The new model applies to all types
of entities, including structured entities. Under the new model, an investor
controls an investee when it is exposed, or has rights, to variable returns
from its involvement with the investee and has the ability to affect those
returns through its power over the investee.
IFRS 11 establishes a principle that applies to the accounting
for all joint arrangements, whereby parties to the arrangement account
for their underlying contractual rights and obligations relating to the
joint arrangement. IFRS 11 identifies two types of joint arrangements.
A ‘joint venture’ is defined as a joint arrangement whereby the parties
that have joint control of the arrangement have rights to the net assets
of the arrangement. A ‘joint operation’ is defined as a joint arrangement
whereby the parties that have joint control of the arrangement have
rights to the assets, and obligations for the liabilities, relating to the
arrangement. Investments in joint ventures will be accounted for using the
equity method. Investments in joint operations will be accounted for by
recognizing the group’s assets, liabilities, revenue and expenses relating to
the joint operation.
IFRS 12 combines all the disclosure requirements for an entity’s
interests in subsidiaries, joint arrangements, associates and structured
entities into one comprehensive disclosure standard.
These new and amended standards are effective for annual periods
beginning on or after 1 January 2013 and BP intends to adopt them from
this date. The evaluation of the effect of adoption of these standards has
not yet been completed. It is expected that the main impact of this suite
of new standards is that certain of the group’s existing jointly controlled
entities, which are currently equity accounted, will fall under the definition
of a joint operation under IFRS 11 and thus we will be required to cease
equity accounting and instead recognize the group’s assets, liabilities,
revenue and expenses relating to these arrangements. This new suite of
standards has not yet been adopted by the EU.
• Other new standards not yet adopted
As part of the IASB’s project to replace IAS 39 ‘Financial Instruments:
Recognition and Measurement’, in November 2009 the IASB issued the
first phase of IFRS 9 ‘Financial Instruments’, dealing with the classification
and measurement of financial assets. In October 2010, the IASB updated
IFRS 9 by incorporating the requirements for the accounting for financial
liabilities. The remaining phases of IFRS 9 (covering impairment and hedge
accounting) are still to be completed. In December 2011, the IASB decided
that IFRS 9 will be effective for annual periods beginning on or after 1
January 2015, rather than 1 January 2013 as originally indicated. BP has not
yet decided the date of adoption for the group and has not yet completed
its evaluation of the effect of adoption. The new standard has not yet been
adopted by the EU.
In May 2011, the IASB issued a new standard, IFRS 13 ‘Fair value
measurement’. The new standard defines fair value, sets out a framework
for measuring fair value and the required disclosures about fair value
measurements. IFRS 13 does not require fair value measurements in
addition to those already required or permitted by other IFRSs, rather it
prescribes how fair value should be measured if another IFRS requires it.
Fair value is defined as the price that would be received to sell an asset
or paid to transfer a liability in an orderly transaction between market
participants at the measurement date i.e. it is an exit price. IFRS 13 is
effective for annual periods beginning on or after 1 January 2013 and BP
intends to adopt it from this date. The evaluation of the effect of adoption of
IFRS 13 has not yet been completed.
In June 2011, the IASB issued an amended version of IAS
19 ‘Employee Benefits’, which brings in various changes relating to
the recognition and measurement of termination benefits and post-
employment defined benefit expense, and to the disclosures for all
employee benefits. The main impact for BP will be that the expense for
defined benefit pension and other post-retirement benefit plans will include
a net interest income or expense, which will be calculated by applying the
discount rate used for measuring the obligation and applying that to the net
defined benefit asset or liability. This means that the expected return on
assets credited to profit or loss (currently calculated based on the expected
long-term return on pension assets) will now be based on a lower corporate
bond rate, the same rate that is used to discount the pension liability. The
amended IAS 19 is effective for annual periods beginning on or after 1
January 2013 and BP intends to adopt this new standard with effect from
that date. The evaluation of the effect of adoption of the amended standard
has not yet been completed, however, based upon our analysis to date,
we expect the change to result in a significantly higher net charge to the
income statement once adopted.
In June 2011, the IASB issued amendments to IAS 1 ‘Presentation
of Financial Statements’ on the presentation of other comprehensive
income (OCI). The amendments require that those items of OCI that could
be reclassified to profit or loss at a future date be presented separately
from those items that will never be reclassified to profit or loss. These
amendments to IAS 1 are effective for annual periods beginning on or
after 1 July 2012. BP intends to adopt the amendments with effect from
1 January 2013. The adoption of the amended standard is expected to only
have a presentational impact on the group’s financial statements, with no
effect on the reported income or net assets of the group.
In December 2011, the IASB issued amendments to IFRS 7
‘Disclosures – Offsetting Financial Assets and Financial Liabilities’ and
amendments to IAS 32 ‘Offsetting Financial Assets and Financial Liabilities’.
These amendments introduce new disclosure requirements about the
effects of offsetting financial assets and financial liabilities and related
arrangements on an entity’s financial position. The amendments to IFRS 7
are effective for annual periods beginning on or after 1 January 2013, with
the amendments to IAS 32 effective for annual periods beginning on or
after 1 January 2014. BP intends to adopt these amendments with effect
from 1 January 2013 and 1 January 2014 respectively. The evaluation of the
effect of adoption of these amendments has not yet been completed.
In October 2010, the IASB issued amendments to IFRS 7 ‘Financial
Instruments: Disclosures – Transfers of Financial Assets’. The amendments
address the disclosures of transfers of financial assets. These amendments
to IFRS 7 are effective for periods beginning on or after 1 July 2011. BP
intends to adopt the amendments with effect from 1 January 2012. The
extent to which BP will be required to amend its disclosures in the light of
these new requirements is currently being evaluated.
With the exception of the amendments to IFRS 7 regarding the
disclosures of transfers of financial assets, the EU has not yet adopted any
of the above-mentioned other new standards that have been issued but not
yet adopted by the group.
There are no other standards and interpretations in issue but not
yet adopted that the directors anticipate will have a material effect on the
reported income or net assets of the group.
BP Annual Report and Form 20-F 2011 189
Financial statementsNotes on financial statements http://www.bp.com/downloads/gom
2. Significant event – Gulf of Mexico oil spill
As a consequence of the Gulf of Mexico oil spill, as described on pages 76 to 79, BP continues to incur costs and has also recognized liabilities for future
costs. Liabilities of uncertain timing or amount and contingent liabilities have been accounted for and/or disclosed in accordance with IAS 37 ‘Provisions,
contingent liabilities and contingent assets’. These are discussed in further detail in Note 36 for provisions and Note 43 for contingent liabilities. BP’s rights
and obligations in relation to the $20-billion trust fund which was established in 2010 are accounted for in accordance with IFRIC 5 ‘Rights to interests
arising from decommissioning, restoration and environmental rehabilitation funds’. Key aspects of the accounting for the oil spill are summarized below.
The financial impacts of the Gulf of Mexico oil spill on the income statement, balance sheet and cash flow statement of the group are shown in
the table below. Amounts related to the trust fund are separately identified.
Income statement
Production and manufacturing expenses
Profit (loss) before interest and taxation
Finance costs
Profit (loss) before taxation
Less: Taxation
Profit (loss) for the period
Balance sheet
Current assets
Trade and other receivables
Current liabilities
Trade and other payables
Provisions
Net current liabilities
Non-current assets
Other receivables
Non-current liabilities
Other payables
Provisions
Deferred tax
Net non-current liabilities
Net assets
Cash flow statement
Profit (loss) before taxation
Finance costs
Net charge for provisions, less payments
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Pre-tax cash flows
2011
Of which:
amount related
to the trust
fund
(3,995)
3,995
52
3,943
–
3,943
Total
(3,800)
3,800
58
3,742
(1,387)
2,355
$ million
2010
Of which:
amount related
to the trust
fund
7,261
(7,261)
73
(7,334)
–
(7,334)
Total
40,858
(40,858)
77
(40,935)
12,894
(28,041)
8,487
8,233
5,943
5,943
(5,425)
(9,437)
(6,375)
(4,872)
–
3,361
(6,587)
(7,938)
(8,582)
(5,002)
–
941
1,642
1,642
3,601
3,601
–
(5,896)
7,775
3,521
(2,854)
3,742
58
2,699
(4,292)
(11,113)
(8,906)
–
–
–
1,642
5,003
3,943
52
–
(4,038)
(10,097)
(10,140)
(9,899)
(8,397)
11,255
(3,440)
(12,022)
(40,935)
77
19,354
(12,567)
16,413
(17,658)
(9,899)
–
–
(6,298)
(5,357)
(7,334)
73
–
(12,567)
14,828
(5,000)
Adjusting event after the reporting period: Settlement with the Plaintiffs’ Steering Committee, subject to final written agreement and court
approvals, to resolve economic loss and medical claims
Subsequent to BP releasing its preliminary announcement of the fourth quarter 2011 results on 7 February 2012, BP announced on 3 March 2012 that it
had reached a proposed settlement with the Plaintiffs’ Steering Committee (PSC), subject to final written agreement and court approvals, to resolve the
substantial majority of legitimate economic loss and medical claims stemming from the Deepwater Horizon accident and oil spill. The PSC acts on behalf
of individual and business plaintiffs in the Multi-District Litigation proceedings pending in New Orleans (MDL 2179). Under the proposed settlement, class
members would release and dismiss their claims against BP. The proposed settlement is not an admission of liability by BP. The proposed settlement is
an adjusting event after the reporting period and therefore has been reflected in the financial statements for 2011 included in this report.
The proposed settlement has not resulted in any increase in the $37.2 billion net pre-tax charge previously recorded in the financial statements.
BP estimates that the cost of the proposed settlement, which covers Individual and Business Claims and associated costs that are expected to be paid
from the $20-billion trust fund, would be approximately $7.8 billion. This represents an increase of $2.1 billion in the provision compared to the amount
reflected in the fourth quarter 2011 preliminary results announcement, with no net impact to either the income statement or cash flow statement, since
it is expected to be payable from the trust fund – see below for information on accounting for the trust fund. The increase in provision of $2.1 billion has
been recognized along with a corresponding increase of $2.1 billion in the reimbursement asset. The amount that can further be provided with no net
impact to the income statement is therefore reduced from approximately $5.5 billion to approximately $3.4 billion. While this is BP’s reliable best estimate
of the cost of the proposed settlement, it is possible that the actual cost could be higher or lower than this estimate depending on the outcomes of
the court-supervised claims processes. It is not possible at this time to determine whether the $20-billion trust fund will be sufficient to cover the total
amounts payable under the proposed settlement and other claims covered by the trust fund.
The proposed settlement is comprised of two separate agreements; one to resolve economic loss claims and another to resolve medical
claims. Each proposed agreement provides that the class members would be compensated for their claims on a claims-made basis according to agreed
compensation protocols in separate court-supervised claims processes. The proposed settlement contains a commitment of $2.3 billion in respect of the
Gulf seafood industry.
190 BP Annual Report and Form 20-F 2011
190 BP Annual Report and Form 20-F 2011
Notes on financial statements http://www.bp.com/downloads/gom
2. Significant event – Gulf of Mexico oil spill continued
The proposed economic loss settlement provides for a transition from the Gulf Coast Claims Facility (GCCF). A court-supervised transitional claims
process for economic loss claims will be in operation while the infrastructure for the new settlement claims process is put in place. During this transitional
period, the processing of claims that have been submitted to the GCCF will continue, and new claimants may submit their claims.
Costs of the proposed settlement will be paid either from the $20-billion Trust or, should the Trust not be sufficient, directly by BP. At this time BP
expects all claims to be paid from the Trust.
The proposed settlement does not include claims against BP made by the United States Department of Justice or other federal agencies (including
under the Clean Water Act and for Natural Resource Damages under the Oil Pollution Act) or by the states and local governments. The proposed
settlement also excludes certain other claims against BP, such as securities and shareholder claims pending in MDL 2185, and claims based solely on the
deepwater drilling moratorium and/or the related permitting process.
The proposed settlement also provides that, to the extent permitted by law, BP will assign to the PSC certain of its claims, rights and recoveries
against Transocean and Halliburton for damages with protections such that Transocean and Halliburton cannot pass those damages through to BP.
The proposed settlement is subject to reaching definitive and fully documented agreements within 45 days of 2 March 2012. If those agreements
are not reached, either party has the right to terminate the proposed settlement. Once there are definitive and fully documented agreements, BP and
the PSC would then seek the court’s preliminary approval of the settlement. Under US federal law, there is an established procedure for determining the
fairness, reasonableness and adequacy of class action settlements. Pursuant to this procedure and subject to the court granting preliminary approval of
both agreements, there would be an extensive outreach programme to the public to explain the settlement agreements, class members’ rights, including
the right to ‘opt out’ of the classes, and the process of making claims. The court would then conduct fairness hearings at which class members and
various other parties would have an opportunity to be heard and present evidence. The court would then decide whether or not to approve each proposed
settlement agreement.
For further details of the proposed settlement see Legal proceedings on pages 160 to 164.
Trust fund
In 2010, BP established the Deepwater Horizon Oil Spill Trust (the Trust) to be funded in the amount of $20 billion (the trust fund) over the period to
the fourth quarter of 2013, which is available to satisfy legitimate individual and business claims administered by the Gulf Coast Claims Facility (GCCF),
state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural resource damages and
related costs. In 2010, BP contributed $5 billion to the fund, and further regular contributions totalling $5 billion were made in 2011. During 2011, BP also
contributed the cash settlements received from MOEX, Weatherford and Anadarko, amounting in total to $5.1 billion. A further cash settlement from
Cameron was received in January 2012 and was also contributed to the trust fund. As a result of these accelerated contributions, it is now expected that
the $20-billion commitment will have been paid in full by the end of 2012. The income statement charge for 2010 included $20 billion in relation to the
trust fund, adjusted to take account of the time value of money. Fines, penalties and claims administration costs are not covered by the trust fund. The
establishment of the trust fund does not represent a cap or floor on BP’s liabilities and BP does not admit to a liability of this amount.
Under the terms of the Trust agreement, BP has no right to access the funds once they have been contributed to the trust fund and BP
has no decision-making role in connection with the payment by the trust fund of individual and business claims resolved by the GCCF and the new
court-supervised claims processes referred to below. BP will receive funds from the trust fund only upon its expiration, if there are any funds remaining
at that point. Any amount remaining in the trust fund when the trustees determine that all claims have been settled would be returned to BP. However,
it is not possible to reliably estimate the number or total amount of the claims that will be settled from the trust fund, and therefore it is not possible to
reliably measure the fair value of BP’s residual interest in it. The carrying amount of BP’s residual interest is, consequently, nil. BP has the authority under
the Trust agreement to present certain resolved claims, including natural resource damages claims and state and local response claims, to the Trust for
payment, by providing the trustees with all the required documents establishing that such claims are valid under the Trust agreement. However, any such
payments can only be made on the authority of the Trustee and any funds distributed are paid directly to the claimants, not to BP. BP will not settle any
such items directly or receive reimbursement from the trust fund for such items.
The proposed settlement with the PSC announced on 3 March 2012 provides for a transition from the GCCF. A court-supervised transitional claims
process for economic loss claims will be in operation while the infrastructure for the new settlement claims process is put in place. During this transitional
period, the processing of claims that have been submitted to the GCCF will continue, and new claimants may submit their claims. BP has agreed not to
wait for final approval of the economic loss settlement before claims are paid. The economic loss claims process will continue under court supervision
before final approval of the settlement, first under the transitional claims process, and then through the settlement claims process established by the
proposed economic loss settlement.
The Trust will remain in place, unaffected by the proposed settlement and the transition from the GCCF to the new court-supervised claims processes.
BP’s obligation to make contributions to the trust fund was recognized in full in 2010, amounting to $20 billion on an undiscounted basis as it
is committed to making these contributions. On initial recognition the discounted amount recognized was $19,580 million. After BP’s contributions
of $15,140 million to the trust fund during 2010 and 2011, and adjustments for discounting, the remaining liability as at 31 December 2011 was
$4,872 million. This liability is recorded within current other payables on the balance sheet, and is expected to be paid in full before the end of 2012.
The table below shows movements in the funding obligation during the period to 31 December 2011.
At 1 January
Trust fund liability initially recognized – discounted
Unwinding of discount
Change in discounting
Contributions
Other
At 31 December
Of which – current
– non-current
2011
14,901
–
52
43
(10,140)
16
4,872
4,872
–
$ million
2010
–
19,580
73
240
(5,000)
8
14,901
5,002
9,899
An asset has been recognized representing BP’s right to receive reimbursement from the trust fund. This is the portion of the estimated future
expenditure provided for that will be settled by payments from the trust fund. We use the term ’reimbursement asset‘ to describe this asset. BP will not
actually receive any reimbursements from the trust fund, instead payments will be made directly to claimants from the trust fund, and BP will be released
from its corresponding obligation.
BP Annual Report and Form 20-F 2011 191
Financial statementsNotes on financial statements
http://www.bp.com/downloads/gom
2. Significant event – Gulf of Mexico oil spill continued
The portion of the provision recognized during the year for items that will be covered by the trust fund, including the increased estimate of the cost of
individual and business claims as a result of the proposed settlement with the PSC announced on 3 March 2012, was $4,038 million (2010 $12,567 million)
and payments of $3,707 million (2010 $3,023 million) were made during the year from the trust fund. The remaining reimbursement asset as at 31 December
2011 was $9,875 million and is recorded within other receivables on the balance sheet. The amount of the reimbursement asset is equal to the amount of
provisions as at 31 December 2011 that will be covered by the trust fund – see Note 36 in the table under Provisions relating to the Gulf of Mexico oil spill.
Movements in the reimbursement asset are presented in the table below.
At 1 January
Increase in provision for items covered by the trust fund
Amounts paid directly by the trust fund
At 31 December
Of which – current
– non-current
The amount charged or credited in the income statement, before finance costs, related to the trust fund comprises:
Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset
Other
Total (credit) charge relating to the trust fund
2011
9,544
4,038
(3,707)
9,875
8,233
1,642
2011
–
43
(4,038)
–
(3,995)
$ million
2010
–
12,567
(3,023)
9,544
5,943
3,601
$ million
2010
19,580
240
(12,567)
8
7,261
As noted above, the obligation to fund the $20-billion trust fund was recognized in full in 2010, on a discounted basis. In addition, a reimbursement asset
of $12,567 million was recognized, reflecting the portion of provisions recognized in 2010 that will be covered by the trust fund. Any new provisions, or
increases in provisions, that are covered by the trust fund (up to the amount of $20 billion) have no net income statement effect as a reimbursement asset
is also recognized, as described above. During 2011, a further $4,038 million was recognized for new or increased provisions for items covered by the
trust fund with a corresponding increase in the reimbursement asset, resulting in no net income statement effect. The cumulative charges for provisions,
and the associated reimbursement asset, recognized during 2010 and 2011 amounted to $16,605 million. Thus, a further $3,395 million could be provided
in subsequent periods for items covered by the trust fund with no net impact on the income statement. Such future increases in amounts provided could
arise from adjustments to existing provisions, or from the initial recognition of provisions for items that currently cannot be estimated reliably, namely final
judgments and settlements and natural resource damages and related costs.
It is not possible at this time to conclude as to whether the $20-billion fund will be sufficient to satisfy all claims under the Oil Pollution Act of
1990 (OPA 90) that will ultimately be paid. Further information on those items that currently cannot be reliably estimated is provided under Provisions and
contingencies and in Note 43.
The Trust agreement does not require BP to make further contributions to the trust fund in excess of the agreed $20 billion should this be
insufficient to cover all claims administered by the GCCF and the new court-supervised claims processes, or to settle other items that are covered by
the trust fund, as described above. Should the $20-billion trust fund not be sufficient, BP would commence settling legitimate claims and other costs by
making payments directly to claimants. In this case, increases in estimated future expenditure above $20 billion would be recognized as provisions with a
corresponding charge in the income statement. The provisions would be utilized and derecognized at the point that BP made the payments.
BP pledged certain Gulf of Mexico assets as collateral for the trust fund funding obligation under an agreement entered into in September 2010. In
November 2011, the agreement was amended and restated to change the way the overriding royalty interest is determined. For further information see
Material contracts on page 168. The pledged collateral consists of an overriding royalty interest in oil and gas production of BP’s Thunder Horse, Atlantis,
Mad Dog, Great White and Mars, Ursa and Na Kika assets in the Gulf of Mexico. A wholly owned company called Verano Collateral Holdings LLC (Verano)
has been created to hold the overriding royalty interest, which is capped at an amount equal to the product of (i) the outstanding funding obligation as
calculated at the start of each calendar quarter, from and after 1 October 2011, and (ii) a factor of 1.45 (resulting in an amount of $14.7 billion at 1 October
2011, which remained unchanged at 31 December 2011). Verano has pledged the overriding royalty interest to the Trust as collateral for BP’s remaining
contribution obligations to the Trust, amounting to $4.9 billion at the end of 2011. On 2 January 2012 the overriding royalty interest was recalculated as
$7.1 billion. There has been no change in operatorship or the marketing of the production from the assets and there is no effect on the other partners’
interests in the assets. For financial reporting purposes Verano is a consolidated entity of BP and there is no impact on the consolidated financial
statements from the pledge of the overriding royalty interest.
Provisions and contingencies
At 31 December 2011 BP has recorded certain provisions and disclosed certain contingent liabilities as a consequence of the Gulf of Mexico oil spill.
These are described below under Oil Pollution Act of 1990 and Other items.
Oil Pollution Act of 1990 (OPA 90)
The claims against BP under the OPA 90 and for personal injury fall into three categories: (i) claims by individuals and businesses for removal costs,
damage to real or personal property, lost profits or impairment of earning capacity, loss of subsistence use of natural resources and for personal injury
(“Individual and Business Claims”); (ii) claims by state and local government entities for removal costs, physical damage to real or personal property, loss
of government revenue and increased public services costs (“State and Local Claims”); and (iii) claims by the United States, a State trustee, an Indian tribe
trustee, or a foreign trustee for natural resource damages (“Natural Resource Damages claims”). In addition, BP faces civil litigation in which claims for
liability under OPA 90 along with other causes of actions, including personal injury claims, are asserted by individuals, businesses and government entities.
A provision has been recorded for Individual and Business Claims and State and Local Claims. The proposed settlement with the PSC, subject to
final written agreement and court approvals, announced on 3 March 2012 relates to Individual and Business Claims. A provision has also been recorded
for claims administration costs, natural resource damage assessment costs and costs relating to emergency and early natural resource damages
restoration agreements.
192 BP Annual Report and Form 20-F 2011
192 BP Annual Report and Form 20-F 2011
Notes on financial statements
http://www.bp.com/downloads/gom
2. Significant event – Gulf of Mexico oil spill continued
BP considers that it is not possible to measure reliably any other obligation in relation to Natural Resource Damages claims under OPA 90 or litigation for
violations of OPA 90 (other than as included within the proposed settlement). These items are therefore disclosed as contingent liabilities.
The $20-billion trust fund described above is available to satisfy the OPA 90 claims and litigation referred to above, however claims administration
costs associated with the existing GCCF organization are borne separately by BP. The administration costs of processing claims made under the proposed
settlement agreement with the PSC are expected to be paid from the trust fund. However, at this time, the provision for these costs is shown as payable
from outside the trust fund as the proposed settlement agreement is subject to final written agreement and court approvals. BP’s rights and obligations
in relation to the trust fund have been recognized and $20 billion, adjusted to take account of the time value of money, was charged to the income
statement in 2010.
Other items
Provisions at 31 December 2011 also include amounts in relation to completing the oil spill response, BP’s commitment to a 10-year research programme
in the Gulf of Mexico, estimated penalties for liability under Clean Water Act Section 311 and estimated legal fees. These are not covered by the trust fund.
The provision does not reflect any amounts in relation to fines and penalties except for those relating to the Clean Water Act, as it is not possible
to estimate reliably either the amount or timing of such additional items. BP also considers that it is not possible to measure reliably any obligation in
relation to litigation other than as included within the proposed settlement with the PSC. These items are therefore disclosed as contingent liabilities.
Further information on provisions is provided below and in Note 36. Further information on contingent liabilities is provided in Note 43.
A provision has been recognized for estimated future expenditure relating to the incident, for items that can be measured reliably at this time,
including the increased estimate of the cost of Individual and Business Claims as a result of the proposed settlement with the PSC as described above, in
accordance with BP’s accounting policy for provisions, as set out in Note 1.
The total amount recognized as a provision during the year was $5,183 million, including $4,038 million for items covered by the trust fund and
$1,145 million for other items (2010 $30,261 million, including $12,567 million for items covered by the trust fund and $17,694 million for other items).
After deducting amounts utilized during the year totalling $6,208 million, including payments from the trust fund of $3,707 million and payments made
directly by BP of $2,501 million (2010 $13,935 million, including payments from the trust fund of $3,023 million and payments made directly by BP of
$10,912 million), and after adjustments for discounting, the remaining provision as at 31 December 2011 was $15,333 million (2010 $16,335 million).
Movements in the provision are presented in the table below.
At 1 January
Increase in provision – items not covered by the trust fund
Increase in provision – items covered by the trust fund
Unwinding of discount
Change in discount rate
Utilization – paid by BP
Utilization – paid by the trust fund
At 31 December
Of which – current
Of which – non-current
2011
16,335
1,145
4,038
6
17
(2,501)
(3,707)
15,333
9,437
5,896
$ million
2010
–
17,694
12,567
4
5
(10,912)
(3,023)
16,335
7,938
8,397
The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the ultimate
exposure and cost to BP will be dependent on many factors (including, with respect to certain of the obligations, any determination of BP’s culpability based
on any findings of negligence, gross negligence or wilful misconduct). Significant uncertainty exists in relation to the amount of claims that will become
payable by BP, the amount of fines that will ultimately be levied on BP, the outcome of litigation and arbitration proceedings, the amount and timing of
payments under any settlements, and any costs arising from any longer-term environmental consequences of the oil spill, which will also impact upon
the ultimate cost for BP. BP is ready to settle any remaining matters on fair and reasonable terms, but will continue to prepare vigorously for trial. Any
settlements which may be reached relating to the Deepwater Horizon oil spill could impact the amount and timing of any future payments. Although the
provision recognized is the current best reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period,
there are future expenditures for which it is not possible to measure the obligation reliably as noted above.
Impact upon the group income statement
The group income statement for 2011 includes a pre-tax credit of $3,742 million (2010 pre-tax charge of $40,935 million) in relation to the Gulf of Mexico
oil spill. The amount charged to date comprises costs incurred up to 31 December 2011, settlements agreed with our co-owners of the Macondo well
and other third parties, estimated obligations for future costs that can be estimated reliably at this time and rights and obligations relating to the trust fund.
Finance costs of $58 million (2010 $77 million) reflect the unwinding of the discount on the trust fund liability and provisions.
The amount of the provision recognized during the year can be reconciled to the income statement amount as follows:
Increase in provision
Change in discount rate relating to provisions
Costs charged directly to the income statement
Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset
Settlements credited to the income statement
(Profit) loss before interest and taxation
2011
5,183
17
512
–
43
(4,038)
(5,517)
(3,800)
$ million
2010
30,261
5
3,339
19,580
240
(12,567)
–
40,858
Costs charged directly to the income statement relate to expenditure prior to the establishment of a provision at the end of the second quarter 2010 and
ongoing operating costs of the Gulf Coast Restoration Organization (GCRO). The accounting associated with the recognition of the trust fund liability and
the expenditure which will be settled from the trust fund is described above.
BP Annual Report and Form 20-F 2011 193
Financial statementsNotes on financial statements http://www.bp.com/downloads/gom
2. Significant event – Gulf of Mexico oil spill continued
The total amount in the income statement is analysed in the table below. Costs charged directly to the income statement in 2010 in relation to spill
response, environmental and litigation and claims are those that arose prior to recording a provision at the end of the second quarter of that year.
Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset
Other
Total (credit) charge relating to the trust fund
Spill response – amount provided
– costs charged directly to the income statement
Total charge relating to spill response
Environmental – amount provided
– change in discount rate relating to provisions
– costs charged directly to the income statement
Total charge relating to environmental
Litigation and claims – amount provided
– costs charged directly to the income statement
Total charge relating to litigation and claims
Clean Water Act penalties – amount provided
Other costs charged directly to the income statement
Settlements credited to the income statement
(Profit) loss before interest and taxation
Finance costs
(Profit) loss before taxation
2011
–
43
(4,038)
–
(3,995)
586
85
671
1,167
17
–
1,184
3,430
–
3,430
–
427
(5,517)
(3,800)
58
(3,742)
$ million
2010
19,580
240
(12,567)
8
7,261
10,883
2,745
13,628
929
5
70
1,004
14,939
184
15,123
3,510
332
–
40,858
77
40,935
The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty as described
above under Provisions and contingencies.
Pre-tax cash flows amounted to $8,906 million (2010 $17,658 million) and the impact on net cash provided by operating activities, on a post-tax
basis, amounted to $6,813 million (2010 $16,019 million).
3. Business combinations
Business combinations in 2011
BP undertook a number of business combinations in 2011. Total consideration paid in cash amounted to $11.3 billion, offset by cash acquired of
$0.4 billion. In addition, the fair value of contingent consideration payable amounted to $0.1 billion.
On 30 August 2011, BP acquired from Reliance Industries Limited (Reliance) a 30% interest in 21 oil and gas production-sharing agreements
(PSAs) operated by Reliance in India for $7,026 million. This includes the producing KG D6 block.
In addition, on 17 November 2011, the companies formed a 50:50 joint venture for the sourcing and marketing of gas in India.
This transaction provides BP with access to an emerging market with growth in energy demand; it builds BP’s business in natural gas and it
represents an important partnership with a leading national energy business.
The transaction has been accounted for as a business combination using the acquisition method. Measurement period adjustments to the
acquisition-date fair values of the identifiable assets and liabilities acquired, and contingent consideration payable, were recognized between the date of
acquisition and 31 December 2011. These adjustments reflected new information obtained, including further understanding of the acquired assets and
potential development options, and amounted to an overall decrease of $785 million in the net fair value of the identifiable assets and liabilities acquired,
an increase of $854 million in the goodwill arising on acquisition and the recognition of $69 million of contingent consideration.
Goodwill of $2,523 million arose on acquisition, attributed to market access and other benefits arising from the business combination. It is
currently uncertain as to whether goodwill recognized for accounting purposes will be deductible for income tax purposes in India, as jurisprudence in
this area is currently evolving.
The provisional fair values of the identifiable assets and liabilities acquired, as at the date of acquisition, are as shown in the table below.
Assets
Property, plant and equipment
Intangible assets
Inventories
Prepayments
Liabilities
Trade and other payables
Provisions
Goodwill arising on acquisition
Total consideration
$ million
1,860
2,970
55
5
(145)
(242)
4,503
2,523
7,026
The consideration for the transaction included $6,957 million in cash. In addition, contingent consideration of up to $1,800 million, dependent upon
exploration success in certain of the interests resulting in the development of commercial discoveries, was agreed. The fair value of contingent
consideration recognized as at the acquisition date amounted to $69 million.
194 BP Annual Report and Form 20-F 2011
194 BP Annual Report and Form 20-F 2011
Notes on financial statements
3. Business combinations continued
The acquisition-date fair values of the assets and liabilities acquired and the fair value of contingent consideration to be paid are provisional. As we gain
further understanding of the acquired properties and development options, these fair values may be further adjusted to reflect information which may be
obtained in respect of the acquired assets and liabilities.
An analysis of the cash flows relating to the acquisition is provided below.
Transaction costs of the acquisition (included in cash flows from operating activities)
Cash consideration paid (included in cash flows from investing activities)
Total net cash outflow for the acquisition
$ million
13
6,957
6,970
Transaction costs of $13 million have been charged within production and manufacturing expenses in the group income statement.
From the date of acquisition to 31 December 2011, the acquired activities contributed revenues of $268 million and profit of $49 million to the
group. If the business combination had taken place on 1 January 2011, it is estimated that the acquired activities would have contributed revenues of
$884 million and profit of $219 million to the group.
In addition to the Reliance transaction described above, BP undertook a number of other business combinations in 2011. These included the
completion of the final part of the transaction with Devon Energy (Devon), the acquisition of Devon’s equity stake in a number of assets in Brazil for
consideration of $3.6 billion (see below). Additionally, BP’s Alternative Energy business acquired Companhia Nacional de Açúcar e Álcool (CNAA) in Brazil
for consideration of $0.7 billion and increased its share in the Brazilian biofuels company, Tropical BioEnergia S.A., to 100% by acquiring the remaining
50% for consideration of $71 million. There were a number of other individually insignificant business combinations.
Business combinations in 2010
BP undertook a number of business combinations in 2010 for a total consideration of $3.6 billion, of which $3 billion comprised cash consideration. The
most significant acquisition was a transaction in the Exploration and Production segment with Devon, undertaken in a number of stages during 2010 and
2011. This transaction strengthens BP’s position in the Gulf of Mexico, enhances interests in Azerbaijan and facilitates the development of Canadian assets.
On 27 April 2010, BP acquired 100% of Devon’s Gulf of Mexico deepwater properties for $1.8 billion. This included a number of exploration
properties, Devon’s interest in the major Paleogene discovery Kaskida (giving BP a 100% interest in the project), four producing assets and one non-
producing asset. As part of the transaction, BP sold to Devon a 50% stake in its Kirby oil sands interests in Alberta, Canada for $500 million and Devon
committed to fund an additional $150 million of capital costs on BP’s behalf by issuing a promissory note to BP. In addition, the companies formed a 50:50
joint venture, operated by Devon, to pursue the development of the interest. On 16 August 2010, the group acquired Devon’s 3.29% (after pre-emption
exercised by some of the partners) interest in the BP-operated Azeri-Chirag-Gunashli (ACG) development in the Azerbaijan sector of the Caspian Sea for
$1.1 billion, increasing BP’s interest to 37.43%.
The business combination was accounted for using the acquisition method. Goodwill of $332 million was recognized on the 2010 part of the
Devon transaction. As part of the Devon transaction, the gain on the disposal of the group’s 50% interest in the Kirby oil sands in Alberta, Canada
amounted to $633 million.
The final part of the Devon transaction, the acquisition of 100% of Devon’s equity stake in a number of entities holding all of Devon’s assets in
Brazil for consideration of $3.6 billion, completed in May 2011. The acquisition-date fair values are provisional. Goodwill of $966 million was recognized in
2011 for this part of the transaction.
In addition to the Devon transaction, BP undertook a number of other minor business combinations in 2010, the most significant of which was the
acquisition by BP’s Alternative Energy business of Verenium Corporation’s lignocellulosic biofuels business, for consideration of $98 million.
Business combinations in 2009
BP did not undertake any significant business combinations in 2009.
BP Annual Report and Form 20-F 2011 195
Financial statementsNotes on financial statements 4. Non-current assets held for sale
As a result of the group’s disposal programme following the Gulf of Mexico oil spill, various assets, and associated liabilities, have been presented as
held for sale in the group balance sheet at 31 December 2011. The carrying amount of the assets held for sale is $8,420 million, with associated liabilities
of $538 million. Included within these amounts are the following items, all of which relate to the Exploration and Production segment, unless otherwise
stated.
On 18 October 2010, BP announced that it had reached agreement to sell its upstream and midstream assets in Vietnam, together with its
upstream businesses and associated interests in Venezuela, to TNK-BP for $1.8 billion in cash, subject to post-closing adjustments. The sale of the
Venezuelan business and the upstream and certain midstream assets in Vietnam completed during 2011. BP is in ongoing negotiations and expects to
complete a sale of its equity-accounted investment in the Phu My 3 plant facility in 2012, subject to the satisfaction of regulatory and other approvals and
conditions. The investment in the Phu My 3 plant facility has been classified as held for sale in the group balance sheet at 31 December 2011.
On 1 December 2011, BP announced that it had agreed to sell its Canadian natural gas liquids (NGL) business to Plains Midstream Canada ULC
(Plains Midstream), a wholly-owned subsidiary of Plains All American Pipeline, L.P. Plains Midstream will pay BP a total of $1.67 billion in cash, subject
to post-closing adjustments, for the business. The assets, and associated liabilities, of this business have been classified as held for sale in the group
balance sheet at 31 December 2011. Completion of the transaction is subject to closing conditions including the receipt of all necessary governmental and
regulatory approvals. The sale is expected to be completed in the first half of 2012.
Within the Refining and Marketing segment, BP intends to divest the Texas City refinery and related assets, and the southern part of its US West
Coast fuels value chain, including the Carson refinery. The non-current assets, together with the inventories, of these businesses have been classified as
held for sale in the group balance sheet at 31 December 2011. BP intends to complete the sales in 2012.
Impairment losses amounting to $398 million (2010 $192 million) have been recognized in relation to certain assets classified as held for sale.
See Note 5 for further information.
Non-current assets classified as held for sale are not depreciated. It is estimated that the benefit arising from the absence of depreciation for the
assets noted above amounted to approximately $166 million (2010 $162 million).
Deposits of $30 million ($6,197 million at 31 December 2010) received in advance of completion of certain of these transactions have been
classified as finance debt on the group balance sheet at 31 December 2011 and of this, none (2010 $4,780 million) has been secured on the assets held
for sale.
The majority of the transactions noted above are subject to post-closing adjustments, which may include adjustments for working capital and
adjustments for profits attributable to the purchaser between the agreed effective date and the closing date of the transaction. Such post-closing
adjustments may result in the final amounts received by BP from the purchasers differing from the disposal proceeds noted above.
The major classes of assets and liabilities reclassified as held for sale as at 31 December are as follows:
Assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in jointly controlled entities
Investments in associates
Loans
Inventories
Cash
Other current assets
Assets classified as held for sale
Liabilities
Trade and other payables
Provisions
Deferred tax liabilities
Liabilities directly associated with assets classified as held for sale
2011
4,772
8
20
122
38
–
3,167
–
293
8,420
300
98
140
538
$ million
2010a
2,971
87
135
467
333
12
92
34
356
4,487
597
383
67
1,047
a On 28 November 2010, BP announced that it had reached agreement to sell its interests in Pan American Energy LLC (PAE) to Bridas Corporation (Bridas) for $7.06 billion in cash. PAE is an Argentina-based
oil and gas company owned by BP (60%) and Bridas (40%). On 5 November 2011, BP received from Bridas a notice of termination of the agreement. As a result of Bridas’s decision and action, the share
purchase agreement governing this transaction was terminated. BP’s interest in PAE was classified as held for sale in the group balance sheet from the date the sale was originally agreed in 2010, and
equity accounting for PAE was discontinued from that date. Following the termination of the sale agreement, BP’s interest in PAE no longer meets the criteria to be classified as held for sale. Under
IFRS, equity accounting is reinstated and prior periods are adjusted when a jointly controlled entity ceases to be classified as held for sale. Consequently, BP’s investment in PAE at 31 December 2010 of
$2,641 million has been reclassified in the group balance sheet from assets classified as held for sale to investments in jointly controlled entities. BP’s share of PAE’s profit for 2011 has been recognized
in full in the group income statement; the 2010 income statement has not been adjusted as the amount is insignificant. Comparative financial information for 2010 presented in the table above has been
adjusted to exclude PAE. For further information on the termination of this agreement see page 85.
There were no accumulated foreign exchange gains or losses recognized directly in equity relating to the assets held for sale at 31 December 2011 (2010 nil).
196 BP Annual Report and Form 20-F 2011
Notes on financial statements 5. Disposals and impairment
Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposed
By business
Exploration and Production
Refining and Marketing
Other businesses and corporate
2011
3,500
(768)
2,732
1,080
721
931
2,732
2010
7,492
9,462
16,954
14,392
1,840
722
16,954
$ million
2009
1,715
966
2,681
940
1,294
447
2,681
Included in proceeds from disposal for 2010 are deposits of $6,197 million received from counterparties in respect of disposal transactions in the
Exploration and Production segment not completed at 31 December 2010, of which $30 million related to transactions still not completed at 31 December
2011. This included a deposit of $3,530 million received in advance of the expected sale of our interest in Pan American Energy LLC. 2011 proceeds from
disposal included the repayment of the same amount following the termination of the sale agreement as described in Note 4. No disposal deposits were
received in 2011 or 2009 for expected transactions which had not completed by the end of those years. For further information on disposal transactions
not yet completed see Note 4.
Deferred consideration relating to disposals of businesses and fixed assets at 31 December 2011 amounted to $117 million receivable within one
year (2010 $562 million and 2009 $807 million) and $111 million receivable after one year (2010 $271 million and 2009 $691 million).
Gains on sale of businesses and fixed assets
Exploration and Production
Refining and Marketing
Other businesses and corporate
Losses on sale of businesses and fixed assets
Exploration and Production
Refining and Marketing
Other businesses and corporate
Impairment losses
Exploration and Production
Refining and Marketing
Other businesses and corporate
Impairment reversals
Exploration and Production
Refining and Marketing
Other businesses and corporate
2011
2010
3,477
317
336
4,130
2011
49
52
3
104
1,443
599
58
2,100
(146)
–
–
(146)
5,267
999
117
6,383
2010
196
119
6
321
1,259
144
113
1,516
–
(141)
(7)
(148)
$ million
2009
1,717
384
72
2,173
$ million
2009
28
154
21
203
118
1,834
189
2,141
(3)
–
(8)
(11)
Impairment and losses on sale of businesses and fixed assets
2,058
1,689
2,333
Disposals
As part of the response to the consequences of the Gulf of Mexico oil spill, the group announced plans to deliver up to $30 billion of disposal proceeds by
the end of 2011. This target has now been increased to $38 billion of disposal proceeds by the end of 2013. Prior to this, in the normal course of business,
the group has sold interests in exploration and production properties, service stations and pipeline interests as well as non-core businesses. The group has
also disposed of other assets in the past, such as refineries, when this has met strategic objectives.
See Note 4 for further information relating to assets and associated liabilities held for sale at 31 December 2011.
Exploration and Production
In 2011, the major disposal transactions were the sale of our interests in Colombia to Ecopetrol and Talisman, the sale of our upstream and midstream
assets in Vietnam and our investments in equity-accounted entities in Venezuela to TNK-BP, and the sale of our assets in Pakistan to United Energy
Group. In addition, we also completed the disposal of half of the 3.29% interest in the Azeri-Chirag-Gunashli development in Azerbaijan to SOCAR and a
number of interests in the Gulf of Mexico to Marubeni Group. All of these transactions resulted in gains.
In 2010, the major transactions were the sale of Permian Basin assets in the US, upstream gas assets in Canada and exploration concessions in
Egypt to Apache Corporation. In addition, we sold 50% of our interests in Kirby oil sands in Canada to Devon Energy as part of a business combination
described in Note 3. All of these transactions resulted in gains.
In 2009, the major transactions were the sale of BP West Java Limited in Indonesia, the sale of our 49.9% interest in Kazakhstan Pipeline
Ventures LLC and the sale of our 46% stake in LukArco, all of which resulted in gains. We also exchanged interests in a number of fields in the North Sea
with BG Group plc.
BP Annual Report and Form 20-F 2011 197
Financial statementsNotes on financial statements 5. Disposals and impairment continued
Refining and Marketing
In 2011, gains on disposal resulted from our disposal of the fuels marketing business in Namibia, Malawi, Zambia and Tanzania to Puma Energy, certain
non-strategic pipelines and terminals in the US and other assets in the segment. Losses resulted from the disposal of a number of assets in the segment
portfolio.
In 2010, gains resulted from our disposals of the French retail fuels and convenience business to Delek Europe, the fuels marketing business in
Botswana to Puma Energy, certain non-strategic pipelines and terminals in the US, our interests in ethylene and polyethylene production in Malaysia to
Petronas and our interest in a futures exchange. Losses resulted from the disposal of a number of assets in the segment portfolio.
In 2009, gains on disposal mainly resulted from the disposal of our ground fuels marketing business in Greece and retail churn in the US, Europe
and Australasia. Losses resulted from the disposal of company-owned and company-operated retail sites in the US, retail churn and disposals of assets
elsewhere in the segment portfolio. Retail churn is the overall process of acquiring and disposing of retail sites by which the group aims to improve the
quality and mix of its portfolio of service stations.
Other businesses and corporate
In 2011, we disposed of our aluminium business in the US which resulted in a gain. We also contributed Mehoopany and Flat Ridge 2 wind energy
development assets in exchange for cash and 50% equity interests in the jointly controlled entities Mehoopany Wind Holdings LLC and Flat Ridge 2 Wind
Holdings LLC.
In 2010, we disposed of our 35% interest in K-Power, a gas-fired power asset in South Korea, and contributed our Cedar Creek 2 wind energy
development asset in exchange for a 50% equity interest in a jointly controlled entity, Cedar Creek II Holdings LLC (Cedar Creek 2) and cash. In addition,
there was a return of capital in the jointly controlled entities Fowler II Holdings LLC and Cedar Creek II Holdings LLC which did not change our percentage
interest in either entity.
During 2009, we disposed of our wind energy business in India and contributed our Fowler 2 wind energy development asset in the US in
exchange for a 50% equity interest in a jointly controlled entity, Fowler II Holdings LLC. In addition, there was a return of capital in the jointly controlled
entity Fowler Ridge Wind Farm LLC which did not change our percentage interest in the entity.
Summarized financial information relating to the sale of businesses is shown in the table below. Information relating to sales of fixed assets is
excluded from the table.
Non-current assets
Current assets
Non-current liabilities
Current liabilities
Total carrying amount of net assets disposed
Recycling of foreign exchange on disposal
Costs on disposal
Profit on sale of businessesa
Total consideration
Consideration received (receivable)b
Proceeds from the sale of businesses related to completed transactions
Deposits received (repaid) related to assets classified as held for salec
Disposals completed in relation to which deposits had been received in prior year
Proceeds from the sale of businessesd
2011
2,085
1,008
(212)
(611)
2,270
8
17
2,295
2,232
4,527
11
4,538
(3,530)
(1,776)
(768)
2010
2,319
310
(303)
(124)
2,202
(52)
18
2,168
1,968
4,136
20
4,156
5,306
–
9,462
$ million
2009
536
444
(146)
(152)
682
(27)
3
658
314
972
(6)
966
–
–
966
a Of which $278 million gain was not recognized in the income statement in 2011 as it represented an unrealized gain on the sale of business assets in Vietnam to our associate TNK-BP.
b Consideration received from prior year business disposals or not yet received from current year disposals.
c 2010 included a deposit received in advance of $3,530 million in respect of the expected sale of our interest in Pan American Energy LLC; 2011 includes the repayment of the same amount following
the termination of the sale agreement as described in Note 4.
d Net of cash and cash equivalents disposed of $14 million (2010 $55 million and 2009 $91 million).
Impairment
In assessing whether a write-down is required in the carrying value of a potentially impaired intangible asset, item of property, plant and equipment or an
equity-accounted investment, the asset’s carrying value is compared with its recoverable amount. The recoverable amount is the higher of the asset’s fair
value less costs to sell and value in use. Unless indicated otherwise, the recoverable amount used in assessing the impairment losses described below
is value in use. The group estimates value in use using a discounted cash flow model. The future cash flows are adjusted for risks specific to the asset
and are discounted using a pre-tax discount rate. This discount rate is derived from the group’s post-tax weighted average cost of capital and is adjusted
where applicable to take into account any specific risks relating to the country where the cash-generating unit is located, although other rates may be used
if appropriate to the specific circumstances. In 2011 the rates used ranged from 12-14% (2010 11-14%). The rate applied in each country is reassessed
each year. In certain circumstances an impairment assessment may be carried out using fair value less costs to sell as the recoverable amount when, for
example, a recent market transaction for a similar asset has taken place. For impairments of available-for-sale financial assets that are quoted investments,
the fair value is determined by reference to bid prices at the close of business at the balance sheet date. Any cumulative loss previously recognized in
other comprehensive income is transferred to the income statement.
198 BP Annual Report and Form 20-F 2011
Notes on financial statements 5. Disposals and impairment continued
Exploration and Production
During 2011, the Exploration and Production segment recognized impairment losses of $1,443 million. The main elements were a $555-million
impairment loss relating to a number of our interests in the Gulf of Mexico, caused by an increase in the decommissioning provision as a result of further
assessments of the regulations relating to idle infrastructure and a decrease in our assumption of the discount rate for provisions; the $393-million
write-down of our interest in the Fayetteville shale gas asset in the US, triggered by a decrease in value by reference to a sale transaction by a partner of
its interest in the same asset; and the $153-million write-down of our interest in the proposed Denali gas pipeline in Alaska, resulting from a decision not
to proceed with the project. There were several other impairment losses amounting to $342 million in total that were not individually significant. These
impairment losses were partly offset by reversals of impairment of certain of our interests in the Gulf of Mexico and Egypt amounting to $146 million in
total, triggered by an increase in our assumption of long-term oil prices.
During 2010, the Exploration and Production segment recognized impairment losses of $1,259 million. The main elements were the $501-million
write-down of assets in the Gulf of Mexico, triggered by an increase in the decommissioning provision as a result of new regulations in the US relating
to idle infrastructure; impairments of oil and gas properties in the Gulf of Mexico and onshore North America of $310 million and $80 million respectively,
as a result of decisions to dispose of assets at a price lower than the assets’ carrying values; a $341-million write-down of accumulated costs in Sakhalin,
Russia, triggered by a change in the outlook on the future recoverability of the investment; and several other individually insignificant impairment losses
amounting to $27 million in total.
During 2009, the Exploration and Production segment recognized impairment losses of $118 million. The main elements were the write-down of
our $42-million investment in the East Shmidt interest in Russia, triggered by a decision to not proceed to development; a $62-million charge associated
with our nErgize gas scheduling system; and several other individually insignificant impairment losses amounting to $14 million.
Refining and Marketing
During 2011, the Refining and Marketing segment recognized impairment losses of $599 million. Impairment losses of $398 million related to assets
classified as held for sale. Other impairment losses were also recognized relating to retail churn in Europe and other minor asset disposals amounting to
$201 million in total.
During 2010, the Refining and Marketing segment recognized impairment losses amounting to $144 million relating to retail churn in Europe and
other minor asset disposals. These losses were largely offset by the reversal of a previously recognized impairment loss of $141 million relating to the
investment in our jointly controlled entity China American Petrochemical Company resulting from a change in market conditions.
During 2009, an impairment loss of $1,579 million was recognized against the goodwill allocated to the US West Coast fuels value chain (FVC). The
goodwill was originally recognized at the time of the ARCO acquisition in 2000. The prevailing weak refining environment, together with a review of future
margin expectations in the FVC, led to a reduction in the expected future cash flows. Other impairment losses were also recognized by the segment on a
number of assets which amounted to $255 million.
Other businesses and corporate
During 2011, 2010 and 2009, Other businesses and corporate recognized impairment losses totalling $58 million, $113 million and $189 million
respectively related to various assets in the Alternative Energy business.
BP Annual Report and Form 20-F 2011 199
Financial statementsNotes on financial statements 6. Segmental analysis
The group’s organizational structure reflects the various activities in which BP is engaged. In 2011, BP had two reportable segments: Exploration and
Production and Refining and Marketing. BP’s activities in low-carbon energy are managed through our Alternative Energy business, which is reported in
Other businesses and corporate. The group is managed on an integrated basis.
Exploration and Production’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage
and processing; and the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs).
At the end of 2010, BP announced its decision to reorganize its Exploration and Production segment to create three functional divisions –
Exploration, Developments and Production, integrated through a Strategy and Integration organization. This structure was established in March 2011 but
this has not affected the group’s reportable segments and Exploration and Production continues to be reported as a single operating segment.
From 1 January 2012, the group’s investment in TNK-BP will be reported as a separate operating segment, rather than within the Exploration and
Production segment, reflecting the way in which the investment is now managed.
Refining and Marketing’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum,
petrochemicals products and related services to wholesale and retail customers.
Other businesses and corporate comprises the Alternative Energy business, Shipping, Treasury (which in the segmental analysis includes all of
the group’s cash, cash equivalents and associated interest income), and corporate activities worldwide. It also included the group’s aluminium business
until its disposal during 2011. The Alternative Energy business is an operating segment that has been aggregated with the other activities within Other
businesses and corporate as it does not meet the materiality thresholds for separate segment reporting.
In 2010, following the Gulf of Mexico incident, we established the Gulf Coast Restoration Organization (GCRO) and equipped it with dedicated
resources and capabilities to manage all aspects of our response to the incident. This organization reports directly to the group chief executive and is
overseen by a board committee, however it is not an operating segment.
The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires
that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for
the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit or loss before interest
and tax which reflects the replacement cost of supplies by excluding from profit or loss inventory holding gains and lossesa. Replacement cost profit or
loss for the group is not a recognized GAAP measure.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues
and segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on
consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are based on
the location of the seller. The UK region includes the UK-based international activities of Refining and Marketing.
All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to
Other businesses and corporate. However, the periodic expense relating to these plans is allocated to the other operating segments based upon the
business in which the employees work.
Certain financial information is provided separately for the US as this is an individually material country for BP, and for the UK as this is BP’s
country of domicile.
a Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated
on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS
reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have
a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any
related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during
the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in
the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.
200 BP Annual Report and Form 20-F 2011
Notes on financial statements http://www.bp.com/downloads/segmentalanalysis
6. Segmental analysis continued
By business
Segment revenues
Sales and other operating revenues
Less: sales between businesses
Third party sales and other operating revenues
Equity-accounted earnings
Interest revenues
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gainsa
Profit (loss) before interest and taxation
Finance costs
Net finance income relating to pensions and
other post-retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Fair value (gain) loss on embedded derivatives
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
Segment assets
Equity-accounted investments
Additions to non-current assets
Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset
Exploration
and
Production
Refining
and
Marketing
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2011
Total
group
75,475
(44,766)
30,709
5,466
(4)
30,500
132
30,632
344,116
(1,396)
342,720
787
25
5,474
2,487
7,961
2,957
(869)
2,088
(33)
146
(2,478)
15
(2,463)
8,693
1,443
(146)
(191)
2,117
599
–
–
213
371
325
58
–
123
942
21,054
34,527
6,731
4,128
1,024
1,864
–
–
–
–
–
(47,031)
47,031
–
–
–
375,517
–
375,517
6,220
167
3,800
–
3,800
(113)
–
(113)
–
–
–
–
5,200
–
–
–
–
–
–
–
–
–
–
–
37,183
2,634
39,817
(1,246)
263
38,834
11,135
2,100
(146)
(68)
6,726
28,809
40,519
25
(1,089)
(7,937)
31,518
Capital expenditure and acquisitions
25,535
4,130
1,853
a See explanation of inventory holding gains and losses on page 200.
BP Annual Report and Form 20-F 2011 201
Financial statementsNotes on financial statements http://www.bp.com/downloads/segmentalanalysis
6. Segmental analysis continued
By business
Segment revenues
Sales and other operating revenues
Less: sales between businesses
Third party sales and other operating revenues
Equity-accounted earnings
Interest revenues
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gainsa
Profit (loss) before interest and taxation
Finance costs
Net finance income relating to pensions and other post-retirement
benefits
Loss before taxation
Other income statement items
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Fair value loss on embedded derivatives
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
Segment assets
Equity-accounted investmentsb
Additions to non-current assets
Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset
Exploration
and
Production
Refining
and
Marketing
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2010
Total
group
66,266
(37,049)
29,217
3,979
83
30,886
84
30,970
266,751
(1,358)
265,393
755
46
5,555
1,684
7,239
3,328
(831)
2,497
23
109
(1,516)
16
(1,500)
–
–
–
–
–
(39,238)
39,238
–
–
–
297,107
–
297,107
4,757
238
(40,858)
–
(40,858)
447
–
447
(5,486)
1,784
(3,702)
(1,170)
47
(4,825)
11,164
1,516
(148)
309
31,050
28,262
25,369
20
(401)
(1,972)
23,016
–
–
–
–
–
–
–
–
8,616
1,259
–
309
2,258
144
(141)
–
290
113
(7)
–
–
–
–
–
303
275
206
30,266
20,379
20,113
7,043
4,030
840
1,226
–
–
–
Capital expenditure and acquisitions
17,753
4,029
1,234
a See explanation of inventory holding gains and losses on page 200.
b Includes BP’s investment in Pan American Energy LLC following the termination of the sale agreement and the reinstatement of equity accounting. See Note 4 for further information.
202 BP Annual Report and Form 20-F 2011
Notes on financial statements http://www.bp.com/downloads/segmentalanalysis
6. Segmental analysis continued
By business
Segment revenues
Sales and other operating revenues
Less: sales between businesses
Third party sales and other operating revenues
Equity-accounted earnings
Interest revenues
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gainsa
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
Impairment losses
Impairment reversals
Fair value (gain) loss on embedded derivatives
Charges for provisions, net of write-back of unused provisions,
including change in discount rate
Segment assets
Equity-accounted investments
Additions to non-current assets
Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset
Capital expenditure and acquisitions
a See explanation of inventory holding gains and losses on page 200.
Exploration
and
Production
Refining
and
Marketing
Other
businesses
and
corporate
Consolidation
adjustment
and
eliminations
57,626
(32,540)
25,086
3,309
98
24,800
142
24,942
213,050
(821)
212,229
558
32
743
3,774
4,517
9,557
118
(3)
(664)
2,236
1,834
–
57
307
756
2,843
(886)
1,957
34
95
(2,322)
6
(2,316)
313
189
(8)
–
488
20,289
15,855
6,882
4,083
1,088
1,297
14,896
4,114
1,299
(34,247)
34,247
–
–
–
(717)
–
(717)
–
–
–
–
–
–
–
–
$ million
2009
Total
group
239,272
–
239,272
3,901
225
22,504
3,922
26,426
(1,110)
(192)
25,124
12,106
2,141
(11)
(607)
1,551
28,259
21,235
19
(7)
(938)
20,309
BP Annual Report and Form 20-F 2011 203
Financial statementsNotes on financial statements http://www.bp.com/downloads/segmentalanalysis
6. Segmental analysis continued
By geographical area
Revenues
Third party sales and other operating revenuesa
Results
Replacement cost profit before interest and taxation
Non-current assets
Other non-current assetsb c
Other investments
Loans
Other receivables
Derivative financial instruments
Deferred tax assets
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions
a Non-US region includes UK $75,816 million.
b Non-US region includes UK $18,363 million.
c Excluding financial instruments, deferred tax assets and post-retirement benefit plan surpluses.
By geographical area
Revenues
Third party sales and other operating revenuesa
Results
Replacement cost profit (loss) before interest and taxation
Non-current assets
Other non-current assetsb c d
Other investments
Loans
Other receivables
Derivative financial instruments
Deferred tax assets
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions
US
Non-US
$ million
2011
Total
131,488
244,029
375,517
10,202
26,981
37,183
68,707
113,773
8,830
22,688
US
Non-US
182,480
2,117
884
4,337
5,038
611
17
195,484
31,518
$ million
2010
Total
101,768
195,339
297,107
(30,087)
24,601
(5,486)
67,498
95,255
10,370
12,646
162,753
1,191
894
6,298
4,210
528
2,176
178,050
23,016
a Non-US region includes UK $62,794 million.
b Non-US region includes UK $16,650 million.
c Excluding financial instruments, deferred tax assets and post-retirement benefit plan surpluses.
d Includes BP’s investment in Pan American Energy LLC following the termination of the sale agreement and the reinstatement of equity accounting. See Note 4 for further information.
By geographical area
Revenues
Third party sales and other operating revenuesa
Results
Replacement cost profit before interest and taxation
Non-current assets
Other non-current assetsb c
Other investments
Loans
Other receivables
Derivative financial instruments
Deferred tax assets
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions
a Non-US region includes UK $51,172 million.
b Non-US region includes UK $16,713 million.
c Excluding financial instruments, deferred tax assets and post-retirement benefit plan surpluses.
204 BP Annual Report and Form 20-F 2011
US
Non-US
$ million
2009
Total
83,982
155,290
239,272
2,806
19,698
22,504
64,529
93,580
9,865
10,444
158,109
1,567
1,039
1,729
3,965
516
1,390
168,315
20,309
Notes on financial statements 7. Interest and other income
Interest income
Interest income from available-for-sale financial assetsa
Interest income from loans and receivablesa
Interest from loans to equity-accounted entities
Other interest
Other income
Dividend income from available-for-sale financial assetsa
Other income
a Total interest and other income related to financial instruments amounted to $151 million (2010 $148 million and 2009 $116 million).
8. Production and similar taxes
US
Non-US
http://www.bp.com/downloads/dda
9. Depreciation, depletion and amortization
By business
Exploration and Production
US
Non-US
Refining and Marketing
US
Non-USa
Other businesses and corporate
US
Non-US
By geographical area
US
Non-US
a Non-US area includes the UK-based international activities of Refining and Marketing.
2011
21
101
32
13
167
29
400
429
596
2010
23
88
36
91
238
37
406
443
681
2011
1,854
6,426
8,280
2010
1,093
4,151
5,244
2011
2010
3,201
5,492
8,693
840
1,277
2,117
151
174
325
3,751
4,865
8,616
955
1,303
2,258
140
150
290
$ million
2009
15
69
53
88
225
32
535
567
792
$ million
2009
649
3,103
3,752
$ million
2009
4,150
5,407
9,557
919
1,317
2,236
136
177
313
4,192
6,943
11,135
4,846
6,318
11,164
5,205
6,901
12,106
BP Annual Report and Form 20-F 2011 205
Financial statementsNotes on financial statements 10. Impairment review of goodwill
Goodwill at 31 December
Exploration and Production
Refining and Marketing
Other businesses and corporate
2011
7,931
4,014
155
12,100
$ million
2010
4,450
4,074
74
8,598
Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the synergies
of the acquisition. For Exploration and Production, goodwill is held at the segment level; previously it was allocated to each geographic region (UK, US and
Rest of World) (see below). For Refining and Marketing, goodwill has been allocated to the Rhine fuels value chain (FVC), Lubricants and Other.
In assessing whether goodwill has been impaired, the carrying amount of the cash-generating unit (including goodwill) is compared with the
recoverable amount of the cash-generating unit. The recoverable amount is the higher of fair value less costs to sell and value in use. In the absence of any
information about the fair value of a cash-generating unit, the recoverable amount is deemed to be the value in use.
The group calculates the value in use using a discounted cash flow model. The future cash flows are adjusted for risks specific to the
cash-generating unit and are discounted using a pre-tax discount rate. The discount rate is derived from the group’s post-tax weighted average cost of
capital and is adjusted where applicable to take into account any specific risks relating to the country where the cash-generating unit is located. The rate
to be applied to each country is reassessed each year. Discount rates of 12% and 14% have been used for goodwill impairment calculations performed in
2011 (2010 12% and 14%).
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the
determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined
products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step in the preparation of these plans, various environmental
assumptions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates, are set by senior management.
These environmental assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors
and historical trends and variability.
Exploration and Production
Goodwill
Excess of recoverable amount over carrying amount
2011
Total
7,931
49,247
UK
341
7,556
US
3,479
18,968
Rest of
world
630
41,714
$ million
2010
Total
4,450
n/a
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates
of cessation of production of each producing field. As the production profile and related cash flows can be estimated from BP’s past experience,
management believes that the cash flows generated over the estimated life of field is the appropriate basis upon which to assess goodwill and individual
assets for impairment. The date of cessation of production depends on the interaction of a number of variables, such as the recoverable quantities of
hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure necessary to recover the hydrocarbons,
the production costs, the contractual duration of the production concession and the selling price of the hydrocarbons produced. As each producing field
has specific reservoir characteristics and economic circumstances, the cash flows of the fields are computed using appropriate individual economic
models and key assumptions agreed by BP’s management for the purpose. Capital expenditure and operating costs for the first four years and expected
hydrocarbon production profiles up to 2020 are derived from the business segment plan. Estimated production quantities and cash flows up to the date
of cessation of production on a field-by-field basis are developed to be consistent with this. The production profiles used are consistent with the resource
volumes approved as part of BP’s centrally-controlled process for the estimation of proved reserves and total resources.
Prior to 2011, goodwill in the Exploration and Production segment was allocated to each geographic region, that is UK, US and Rest of World, and
impairment reviews of goodwill were performed at this level. Following a reorganization of the Exploration and Production segment, the group has revised
the way goodwill is monitored for internal management purposes. Given the global nature of our upstream business, the impairment review of goodwill is
now performed at the Exploration and Production segment level. Consistent with prior years, the 2011 review for impairment was carried out during the
fourth quarter.
The table above shows the carrying amount of the goodwill for the segment and the excess of the recoverable amount over the carrying amount
(the headroom). Consistent with prior periods, midstream and intangible oil and gas assets were excluded from the headroom calculation.
The Brent oil price assumption used in the impairment review of goodwill is shown in the table below.
Brent oil price ($/bbl)
Brent oil price ($/bbl)
2012
106
2011
85
2013
101
2012
88
2014
97
2013
89
2015
94
2014
89
2011
2017 and
thereafter
90
2010
2016 and
thereafter
75
2016
92
2015
90
Key assumptions for oil and gas prices for the first five years were derived from forward price curves in the fourth quarter. Prices in 2017 and beyond
were determined using long-term views of global supply and demand, building upon past experience of the industry and consistent with external sources.
These prices were adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas, or where appropriate, contracted oil
and gas prices were applied.
206 BP Annual Report and Form 20-F 2011
Notes on financial statements 10. Impairment review of goodwill continued
The key assumptions required for the value-in-use estimation are the oil and natural gas prices, production volumes and the discount rate. To test the
sensitivity of the headroom to changes in production volumes and oil and natural gas prices, management has developed ‘rules of thumb’ for key
assumptions. Applying these gives an indication of the impact on the headroom of possible changes in the key assumptions. Due to the non-linear
relationship of different variables, the calculations were performed using a number of simplified assumptions, therefore a detailed calculation at any given
price may produce a different result.
It was estimated that if the oil price assumption was around 25% lower than the current assumption for 2017 and beyond, this would cause the
recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment. It was estimated that no reasonably
possible change in the long-term price of natural gas would cause the headroom to be reduced to zero.
Estimated production volumes are based on detailed data for the fields and take into account development plans for the fields agreed by
management as part of the long-term planning process. In 2011, it was estimated that, if all our production were to be reduced by 10% for the whole of
the next 15 years, this would not be sufficient to reduce the excess of recoverable amount over the carrying amount to zero. Consequently, management
believes no reasonably possible change in the production assumption would cause the carrying amount to exceed the recoverable amount.
Management also believes that currently there is no reasonably possible change in discount rate that would cause the carrying amount to exceed
the recoverable amount.
Refining and Marketing
Goodwill
Excess of recoverable amount over carrying
amount
Rhine FVC
618
Lubricants
3,284
2,264
n/a
Other
112
n/a
2011
Total
4,014
Rhine FVC
629
Lubricants
3,285
n/a
4,091
n/a
Other
160
n/a
$ million
2010
Total
4,074
n/a
Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of two to five years. To determine the value
in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value.
Rhine FVC
The key assumptions to which the calculation of value in use for the Rhine FVC is most sensitive are refinery gross margins, throughput volumes and
discount rate. Gross margin assumptions used in the Rhine FVC plan are consistent with those used to develop the regional Refining Marker Margin
(RMM). The regional RMM is a margin measure based upon product yields and a marker crude oil deemed appropriate for the region. The average values
assigned to the regional RMM and refinery throughput volume over the plan period are $11.35 per barrel and 257 million barrels per year (2010 $11.05 per
barrel and 248 million barrels per year). These values reflect past experience and are consistent with external sources. Cash flows beyond the five-year
plan period are extrapolated using a nominal 4% growth rate (2010 cash flows beyond the five-year plan period were extrapolated using a nominal 4%
growth rate).
Sensitivity analysis
Sensitivity of value in use to a change in refinery margins of $1 per barrel ($ billion)
Adverse change in refinery margins to reduce recoverable amount to carrying amount ($ per barrel)
Sensitivity of value in use to a 5% change in throughput volume ($ billion)
Adverse change in throughput volume to reduce recoverable amount to carrying amount (million barrels per year)
Sensitivity of value in use to a change in the discount rate of 1% ($ billion)
Discount rate to reduce recoverable amount to carrying amount
2011
1.5
1.5
0.9
31
0.7
16%
Lubricants
As permitted by IAS 36, the detailed calculations of the Lubricants unit’s recoverable amount performed in the most recent detailed calculation in 2009
were used for the 2011 impairment test as the criteria in that standard were considered satisfied: the headroom was substantial in 2009; there have been
no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount at the time of
the test was remote.
The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes
and discount rate. The values assigned to these key assumptions reflect past experience. No reasonably possible changes in any of these key
assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the two-year plan period were extrapolated
using a nominal 3% growth rate.
11. Distribution and administration expenses
Distribution
Administration
2011
12,416
1,542
13,958
2010
11,393
1,162
12,555
$ million
2009
12,798
1,240
14,038
BP Annual Report and Form 20-F 2011 207
Financial statementsNotes on financial statements 12. Currency exchange gains and losses
Currency exchange (gains) losses (credited) charged to the income statementa
a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
13. Research and development
Expenditure on research and development
2011
(70)
2010
218
$ million
2009
193
2011
636
2010
780
$ million
2009
587
In addition to the expenditure on research and development presented in the table above, BP also made donations to external organizations for research
purposes, including the Gulf of Mexico Research Initiative as described on page 79. These donations are not included in the amounts reported above.
14. Operating leases
In the case of an operating lease entered into by BP as the operator of a jointly controlled asset, the amounts shown in the tables below represent the net
operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or to be reimbursed, by
joint venture partners, whether the joint venture partners have co-signed the lease or not. Where BP is not the operator of a jointly controlled asset, BP’s
share of the lease expense and future minimum lease payments is included in the amounts shown, whether BP has co-signed the lease or not.
The table below shows the expense for the year in respect of operating leases.
Minimum lease payments
Contingent rentals
Sub-lease rentals
2011
4,866
(97)
(153)
4,616
2010
5,371
(60)
(121)
5,190
$ million
2009
4,109
(9)
(133)
3,967
The future minimum lease payments at 31 December, before deducting related rental income from operating sub-leases of $566 million (2010 $365
million), are shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor, the
future minimum lease payments are based on the factor as at inception of the lease.
Future minimum lease payments
Payable within
1 year
2 to 5 years
Thereafter
2011
4,182
8,346
3,544
$ million
2010
3,521
6,798
3,654
16,072
13,973
The group enters into operating leases of ships, plant and machinery, commercial vehicles and land and buildings. Typical durations of the leases are
as follows:
Ships
Plant and machinery
Commercial vehicles
Land and buildings
Years
up to 15
up to 10
up to 15
up to 40
The group has entered into a number of structured operating leases for ships and in most cases the lease rental payments vary with market interest rates.
The variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is treated as
contingent rental expense. The group also routinely enters into bareboat charters, time-charters and spot-charters for ships on standard industry terms.
The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Exploration and Production segment. At
31 December 2011 the future minimum lease payments relating to drilling rigs amounted to $6,292 million (2010 $4,515 million). In some cases, drilling
rig lease rental rates are adjusted periodically to market rates that are influenced by oil prices and may be significantly different from the rates at the
inception of the lease. Differences between the rate paid and rate at inception of the lease are treated as contingent rental expense.
Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in
the land and buildings category.
The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of ships
and buildings allow for renewals at BP’s option, and some of the group’s operating leases contain escalation clauses.
208 BP Annual Report and Form 20-F 2011
Notes on financial statements 15. Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and
evaluation of oil and natural gas resources. All such activity is recorded within the Exploration and Production segment.
Exploration and evaluation costs
Exploration expenditure written off
Other exploration costs
Exploration expense for the year
Intangible assets – exploration and appraisal expenditure
Liabilities
Net assets
Capital expenditure
Net cash used in operating activities
Net cash used in investing activities
16. Auditor’s remuneration
Fees – Ernst & Young
Fees payable to the company’s auditors for the audit of the company’s accountsa
Fees payable to the company’s auditors and its associates for other services
Audit of the company’s subsidiaries pursuant to legislation
Other services pursuant to legislation
Tax services
Services relating to corporate finance transactions
All other services
Audit fees in respect of the BP pension plans
a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.
2011
2010
1,024
496
1,520
19,887
306
19,581
8,911
496
8,556
375
468
843
13,126
157
12,969
6,422
468
6,428
2011
15
19
10
44
2
4
4
1
55
2010
13
22
12
47
2
1
4
1
55
$ million
2009
593
523
1,116
10,388
–
10,388
2,715
523
3,306
$ million
2009
13
22
11
46
1
–
6
1
54
2011 includes $1 million of additional fees for 2010 and 2010 includes $1 million of additional fees for 2009. Auditor’s remuneration is included in the
income statement within distribution and administration expenses.
The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services.
The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain
assurance and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for
cost-effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements
and were pre-approved by the committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most of
this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the expertise of
Ernst & Young compared with that of other potential service providers. These services are for a fixed term.
Under SEC regulations, the remuneration of the auditor of $55 million (2010 $55 million and 2009 $54 million) is required to be presented as
follows: audit $44 million (2010 $47 million and 2009 $46 million); other audit-related services $1 million (2010 $1 million and 2009 $2 million); tax
$2 million (2010 $2 million and 2009 $1 million); and fees for all other services $8 million (2010 $5 million and 2009 $5 million).
17. Finance costs
Interest payable
Capitalized at 2.63% (2010 2.75% and 2009 2.75%)a
Unwinding of discount on provisionsb
Unwinding of discount on other payablesb
2011
1,135
(347)
243
215
1,246
2010
955
(254)
234
235
1,170
$ million
2009
906
(188)
247
145
1,110
a Tax relief on capitalized interest is $107 million (2010 $71 million and 2009 $63 million).
b Unwinding of discount on provisions relating to the Gulf of Mexico oil spill was $6 million (2010 $4 million and 2009 nil) and unwinding of discount on other payables relating to the Gulf of Mexico oil spill
was $52 million (2010 $73 million and 2009 nil). See Note 2 for further information on the financial impacts of the Gulf of Mexico oil spill.
BP Annual Report and Form 20-F 2011 209
Financial statementsNotes on financial statements http://www.bp.com/downloads/taxation
18. Taxation
Tax on profit
Current tax
Charge for the year
Adjustment in respect of prior years
Deferred tax
Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years
Tax charge (credit) on profit (loss)
Tax included in other comprehensive incomea
Current tax
Deferred tax
a See Note 39 for further information.
Tax included directly in equity
Current tax
Deferred tax
2011
2010
7,477
111
7,588
5,664
(515)
5,149
12,737
2011
(10)
(1,649)
(1,659)
2011
–
(7)
(7)
6,766
(74)
6,692
(8,157)
(36)
(8,193)
(1,501)
2010
(107)
244
137
2010
(37)
64
27
$ million
2009
6,045
(300)
5,745
2,131
489
2,620
8,365
$ million
2009
–
(525)
(525)
$ million
2009
–
(65)
(65)
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 or loss before taxation.
With effect from 1 April 2011 the UK statutory corporation tax rate reduced from 28% to 26%.
For 2010, the items presented in the reconciliation are distorted as a result of the overall tax credit for the year and the loss before taxation. In
order to provide a more meaningful analysis of the effective tax rate for 2010, the table also presents separate reconciliations for the group excluding
the impacts of the Gulf of Mexico oil spill, and for the impacts of the Gulf of Mexico oil spill in isolation. For 2011, the effective tax rate is not impacted
significantly by the Gulf of Mexico oil spill.
2010
excluding
impacts of
Gulf of
Mexico oil
spill
36,110
11,393
32%
2010
impacts of
Gulf of
Mexico oil
spill
(40,935)
(12,894)
31%
2011
38,834
12,737
33%
$ million
2010
(4,825)
(1,501)
31%
2009
25,124
8,365
33%
26
14
(3)
(1)
–
–
(1)
–
(2)
–
33
28
9
(3)
–
–
–
(1)
–
(1)
–
32
31
% of profit or loss before taxation
28
28
28
7
–
–
–
–
–
(4)
–
–
(4)
23
2
1
–
9
(30)
5
(3)
31
8
(3)
1
–
2
(2)
–
–
(1)
33
Profit (loss) before taxation
Tax charge (credit) on profit (loss)
Effective tax rate
UK statutory corporation tax rate
Increase (decrease) resulting from:
UK supplementary and overseas taxes at higher/lower rates
Tax reported in equity-accounted entities
Adjustments in respect of prior years
Current year losses unrelieved
Goodwill impairment
Tax incentives for investment
Gulf of Mexico oil spill non-deductible costs
Permanent differences relating to disposals
Other
Effective tax rate
210 BP Annual Report and Form 20-F 2011
Notes on financial statements http://www.bp.com/downloads/taxation
18. Taxation continued
Deferred tax
Deferred tax liability
Depreciation
Pension plan surpluses
Other taxable temporary differences
Deferred tax asset
Pension plan and other post-retirement benefit plan deficits
Decommissioning, environmental and other provisions
Derivative financial instruments
Tax credits
Loss carry forward
Other deductible temporary differences
Net deferred tax charge (credit) and net deferred tax liability
Of which – deferred tax liabilities
– deferred tax assets
Analysis of movements during the year
At 1 January
Exchange adjustments
Charge (credit) for the year on profit
Charge (credit) for the year in other comprehensive income
Charge (credit) for the year in equity
Acquisitions
Reclassified as assets held for sale
Deletions
At 31 December
2011
4,511
–
129
4,640
388
(1,324)
24
(401)
(218)
2,040
509
5,149
Income statement
2009
2010
1,565
38
1,178
2,781
179
(8,151)
(56)
(1,088)
24
(1,882)
(10,974)
(8,193)
1,983
(6)
978
2,955
180
86
80
(516)
402
(567)
(335)
2,620
$ million
Balance sheet
2010
27,309
469
5,538
33,316
(2,155)
(13,296)
(298)
(2,118)
(943)
(4,126)
(22,936)
10,380
10,908
528
$ million
2010
18,146
3
(8,193)
244
64
187
(67)
(4)
10,380
2011
33,038
–
5,683
38,721
(2,872)
(14,565)
(274)
(2,549)
(1,295)
(2,699)
(24,254)
14,467
15,078
611
2011
10,380
55
5,149
(1,649)
(7)
692
(140)
(13)
14,467
Deferred tax assets are recognized to the extent that it is probable that taxable profit will be available against which the deductible temporary differences
and the carry-forward of unused tax credits and unused tax losses can be utilized.
At 31 December 2011, the group had approximately $4.6 billion (2010 $3.9 billion) of carry-forward tax losses that would be available to offset
against future taxable profit. A deferred tax asset has been recognized in respect of $3.8 billion of losses (2010 $3.0 billion). No deferred tax asset has
been recognized in respect of $0.8 billion of losses (2010 $0.9 billion). In 2011, a current tax benefit of $0.1 billion arose relating to losses utilized on which
a deferred tax asset had not previously been recognized (2010 nil). Substantially all the tax losses have no fixed expiry date.
At 31 December 2011, the group had approximately $18.2 billion of unused tax credits predominantly in the UK and US (2010 $13.9 billion).
At 31 December 2011 there is a deferred tax asset of $2.5 billion in respect of unused tax credits (2010 $2.1 billion). No deferred tax asset has been
recognized in respect of $15.7 billion of tax credits (2010 $11.8 billion). In 2011, a current tax benefit of $0.1 billion arose relating to tax credits utilized on
which a deferred tax asset had not previously been recognized (2010 $0.3 billion).
The UK tax credits, arising in UK branches overseas with no deferred tax asset, amounting to $13.0 billion (2010 $9.9 billion) do not have a
fixed expiry date. In addition there are also temporary differences in overseas branches of UK companies with no deferred tax asset recognized. At
31 December 2011 the unrecognized deferred tax amounted to $0.9 billion (2010 $0.9 billion). These credits and temporary differences arise in UK
branches predominantly based in high tax rate jurisdictions and so are unlikely to have value in the future as UK taxes on these overseas branches are
largely mitigated by the double tax relief on the local foreign tax.
The US tax credits with no deferred tax asset amounting to $2.7 billion (2010 $1.9 billion) expire 10 years after generation, and the majority expire
in the period 2014-2021.
The group recognized significant costs in 2010 in relation to the Gulf of Mexico oil spill and in 2011 has recognized certain recoveries relating to the
incident as well as further costs. Tax has been calculated on the expenditures that are expected to qualify for tax relief, and on the recoveries, at the US
statutory tax rate. A deferred tax asset has been recognized in respect of provisions for future expenditure that are expected to qualify for tax relief. This is
included under the heading decommissioning, environmental and other provisions.
The other major components of temporary differences at the end of 2011 relate to tax depreciation, provisions, including items relating to the Gulf
of Mexico oil spill, US inventory holding gains (classified as other taxable temporary differences) and pension plan and other post-retirement benefit plan
deficits.
At 31 December 2011, there were no material temporary differences associated with investments in subsidiaries and equity-accounted entities for
which deferred tax liabilities have not been recognized.
In 2011, the enactment of a 12% increase in the UK supplementary charge on oil and gas production activities in the North Sea increased the
deferred tax charge in the income statement by $713 million of which $683 million relates to the revaluation of the opening deferred tax balance.
Also in 2011, the enactment of a 2% reduction in the rate of UK corporation tax to 25% with effect from 1 April 2012 on profits arising from
activities outside the North Sea reduced the deferred tax charge in the income statement by $120 million. In 2010 the enactment of a 1% reduction in the
rate of UK corporation tax to 27% with effect from 1 April 2011 similarly reduced the deferred tax charge in the income statement by $86 million.
In 2012, legislation to restrict relief for UK decommissioning expenditure from 62% to 50% is expected to be enacted. New legislation is also likely
to be introduced in Australia which would bring BP’s North West Shelf activities into the charge to Petroleum Resource Rent Tax (PRRT) from July 2012.
The impacts of both of these changes are currently being assessed.
BP Annual Report and Form 20-F 2011 211
Financial statementsNotes on financial statements
19. Dividends
The quarterly dividend expected to be paid on 30 March 2012 in respect of the fourth quarter 2011 is 8 cents per ordinary share ($0.48 per American
Depositary Share (ADS)). The corresponding amount in sterling will be announced on 19 March 2012. A scrip dividend alternative is available, allowing
shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs.
On 1 February 2011 BP announced the resumption of quarterly dividend payments with a fourth-quarter 2010 dividend of 7 cents per share. The
resumption came after the suspension of dividends for the first three quarters of 2010 in light of the Gulf of Mexico oil spill and commitments to fund the
$20-billion Trust.
2011
Pence per share
2009
2010
2011
Cents per share
2009
2010
2011
2010
$ million
2009
Dividends announced and paid in cash
Preference shares
Ordinary shares
March
June
September
December
Dividend announced, payable in
March 2012a
a The amount in sterling will be announced on 19 March 2012.
4.3372
4.2809
4.3160
4.4694
17.4035
8.679
–
–
–
8.679
9.818
9.584
8.503
8.512
36.417
The details of the scrip dividends issued are shown in the table below.
Number of shares issued (thousand)
Value of shares issued ($ million)
2
2
2
7
7
7
7
28
8
14
–
–
–
14
14
14
14
14
56
808
794
1,224
1,244
4,072
1,517
2,625
–
–
–
2,627
2,619
2,619
2,620
2,623
10,483
2011
165,601
1,219
2010
–
–
2009
–
–
The financial statements for the year ended 31 December 2011 do not reflect the dividend announced on 7 February 2012 and expected to be paid in
March 2012; this will be treated as an appropriation of profit in the year ended 31 December 2012.
20. Earnings per ordinary share
Basic earnings per share
Diluted earnings per share
2011
135.93
134.29
2010
(19.81)
(19.81)
Cents per share
2009
88.49
87.54
Basic earnings per ordinary share amounts are calculated by dividing the profit or loss 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 Plan Trusts (ESOPs) and includes certain shares that will be issuable in the future under employee share plans.
For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the number of
shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method. If the inclusion of potentially
issuable shares would decrease the loss per share, the potentially issuable shares are excluded from the diluted earnings per share calculation.
Profit (loss) attributable to BP shareholders
Less: dividend requirements on preference shares
Profit (loss) for the year attributable to BP ordinary shareholders
Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share schemes
2011
25,700
2
25,698
2010
(3,719)
2
(3,721)
$ million
2009
16,578
2
16,576
2011
2010
Shares thousand
2009
18,904,812 18,785,912 18,732,459
203,232
19,136,200 18,997,807 18,935,691
211,895
231,388
The number of ordinary shares outstanding at 31 December 2011, excluding treasury shares and the shares held by the ESOPs, and including certain
shares that will be issuable in the future under employee share plans was 18,977,213,826. Between 31 December 2011 and 17 February 2012, the latest
practicable date before the completion of these financial statements, there was a net increase of 379,374 in the number of ordinary shares outstanding
as a result of share issues in relation to employee share plans. The number of potential ordinary shares issuable through the exercise of employee
share plans was 254,106,576 at 31 December 2011. There has been a decrease of 53,225,107 in the number of potential ordinary shares between
31 December 2011 and 17 February 2012.
212 BP Annual Report and Form 20-F 2011
Notes on financial statements http://www.bp.com/downloads/ppe
21. Property, plant and equipment
Land and land
improvements
Buildings
Oil and gas
properties
Plant,
machinery and
equipment
Fixtures,
fittings
and office
equipment Transportation
Oil depots,
storage tanks
and service
stations
Cost
At 1 January 2011
Exchange adjustments
Additions
Acquisitions
Transfers
Reclassified as assets held for sale
Deletions
At 31 December 2011
Depreciation
At 1 January 2011
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Reclassified as assets held for sale
Deletions
At 31 December 2011
Net book amount at 31 December 2011
Cost
At 1 January 2010
Exchange adjustments
Additions
Acquisitions
Transfers
Reclassified as assets held for sale
Deletions
At 31 December 2010
Depreciation
At 1 January 2010
Exchange adjustments
Charge for the year
Impairment losses
Reclassified as assets held for sale
Deletions
At 31 December 2010
Net book amount at 31 December 2010
Net book amount at 1 January 2010
Assets held under finance leases at net book amount
included above
At 31 December 2011
At 31 December 2010
Assets under construction included above
At 31 December 2011
At 31 December 2010
3,560
(73)
39
62
–
(325)
(164)
3,099
572
(10)
36
133
–
(115)
(106)
510
2,589
3,786
(85)
39
2
–
(6)
(176)
3,560
571
1
34
57
–
(91)
572
2,988
3,215
2,835
(73)
46
134
–
–
(96)
2,846
1,384
(36)
111
4
–
–
(91)
1,372
1,474
2,918
(68)
96
3
–
(10)
(104)
2,835
1,389
(46)
82
5
(8)
(38)
1,384
1,451
1,529
160,184
–
18,515
2,100
1,013
(832)
(5,106)
175,874
88,047
–
8,116
1,239
(146)
(680)
(4,582)
91,994
83,880
157,197
3
11,980
1,931
2,633
(6,610)
(6,950)
160,184
86,975
–
8,024
918
(4,342)
(3,528)
88,047
72,137
70,222
42,827
(294)
3,782
567
–
(9,931)
(1,242)
35,709
19,183
(108)
1,411
245
–
(5,761)
(704)
14,266
21,443
41,599
35
3,354
41
–
(1,083)
(1,119)
42,827
18,903
(19)
1,492
117
(514)
(796)
19,183
23,644
22,696
2,965
(35)
370
4
–
–
(209)
3,095
1,876
(34)
278
–
–
–
(209)
1,911
1,184
3,022
(41)
279
5
–
(87)
(213)
2,965
1,893
(25)
291
1
(76)
(208)
1,876
1,089
1,129
12,216
(12)
655
–
–
–
(106)
12,753
7,940
(6)
252
42
–
–
(79)
8,149
4,604
12,441
28
152
15
–
(212)
(208)
12,216
7,852
16
268
–
(97)
(99)
7,940
4,276
4,589
$ million
Total
234,239
(712)
23,919
2,867
1,013
(11,088)
(8,251)
241,987
124,076
(307)
10,771
1,709
(146)
(6,556)
(6,774)
122,773
9,652
(225)
512
–
–
–
(1,328)
8,611
5,074
(113)
567
46
–
–
(1,003)
4,571
4,040
119,214
10,295
(72)
610
–
–
–
(1,181)
9,652
5,400
(13)
606
21
–
(940)
5,074
4,578
4,895
231,258
(200)
16,510
1,997
2,633
(8,008)
(9,951)
234,239
122,983
(86)
10,797
1,119
(5,037)
(5,700)
124,076
110,163
108,275
–
–
10
14
213
236
326
386
–
–
7
7
18
18
574
661
26,443
23,055
BP Annual Report and Form 20-F 2011 213
Financial statementsNotes on financial statements 2011
10,177
(26)
3,602
(50)
–
13,703
(1,579)
(66)
42
(1,603)
12,100
8,598
Exploration
and appraisal
expenditure
Other
intangibles
2011
Total
Exploration
and appraisal
expenditure
Other
intangibles
13,476
–
5,563
3,348
(1,013)
–
(704)
20,670
350
–
1,024
7
–
(598)
783
19,887
13,126
3,403
(21)
176
352
–
(66)
(370)
3,474
2,231
(11)
364
79
(46)
(358)
2,259
1,215
1,172
16,879
(21)
5,739
3,700
(1,013)
(66)
(1,074)
24,144
2,581
(11)
1,388
86
(46)
(956)
3,042
21,102
14,298
10,713
6
982
5,440
(2,633)
(134)
(898)
13,476
325
–
375
–
–
(350)
350
13,126
10,388
3,284
(29)
118
297
–
(4)
(263)
3,403
2,124
(11)
367
–
(3)
(246)
2,231
1,172
1,160
$ million
2010
10,199
(154)
335
(87)
(116)
10,177
(1,579)
–
–
(1,579)
8,598
8,620
$ million
2010
Total
13,997
(23)
1,100
5,737
(2,633)
(138)
(1,161)
16,879
2,449
(11)
742
–
(3)
(596)
2,581
14,298
11,548
22. Goodwill
Cost
At 1 January
Exchange adjustments
Acquisitions
Reclassified as assets held for sale
Deletions
At 31 December
Impairment losses
At 1 January
Impairment losses for the year
Reclassified as assets held for sale
At 31 December
Net book amount at 31 December
Net book amount at 1 January
23. Intangible assets
Cost
At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers
Reclassified as assets held for sale
Deletions
At 31 December
Amortization
At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Reclassified as assets held for sale
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
214 BP Annual Report and Form 20-F 2011
Notes on financial statements http://www.bp.com/downloads/investments
24. Investments in jointly controlled entities
The significant jointly controlled entities of the BP group at 31 December 2011 are shown in Note 45. Summarized financial information for the group’s
share of jointly controlled entities is shown below. Balance sheet information shown below excludes data relating to jointly controlled entities reclassified
as assets held for sale as at the end of the period. Income statement information shown below includes data relating to jointly controlled entities
reclassified as assets held for sale for the period up until their date of reclassification as held for sale.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Profit for the year
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Group investment in jointly controlled entities
Group share of net assets (as above)
Loans made by group companies to jointly controlled entities
$ million
2009
9,396
1,815
155
1,660
374
1,286
2011
15,720
1,918
134
1,784
480
1,304
16,495
4,613
21,108
2,553
3,980
6,533
14,575
14,575
943
15,518
2010a
11,679
1,730
122
1,608
433
1,175
16,035
4,167
20,202
2,101
4,131
6,232
13,970
13,970
957
14,927
a 2010 information has been adjusted following the termination of the Pan American Energy LLC sale agreement. See Note 4 for further information.
Transactions between the group and its jointly controlled entities are summarized below.
Sales to jointly controlled entities
Product
LNG, crude oil and oil products, natural gas, employee services
Sales
5,095
Purchases from jointly controlled entities
Product
LNG, crude oil and oil products, natural gas, refinery operating costs,
Purchases
2011
Amount
receivable at
31 December
1,616
2011
Amount
payable at
31 Decembera
2010
Amount
receivable at
31 December
1,352
2010
Amount
payable at
31 Decembera
Sales
3,804
Purchases
$ million
2009
Amount
receivable at
31 December
1,328
$ million
2009
Amount
payable at
31 Decembera
Sales
2,182
Purchases
plant processing fees
7,798
369
8,063
683
5,377
214
a In addition to the amounts shown above, there are amounts payable to jointly controlled entities of $2,256 million (2010 $2,583 million and 2009 $2,509 million) relating to BP’s contribution on the
establishment of the Sunrise Oil Sands joint venture.
The terms of the outstanding balances receivable from jointly controlled entities are typically 30 to 45 days, except for a receivable from Ruhr Oel of
$605 million (2010 $585 million), part of which is a reimbursement balance relating to pensions that will be received over several years. The balances
are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense
recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the above balances.
BP has commitments amounting to $4,155 million (2010 $3,389 million) in relation to contracts with jointly controlled entities for the purchase of
LNG, crude oil and oil products, refinery operating costs and storage and handling services. See Note 44 for further information on capital commitments
relating to BP’s investments in jointly controlled entities.
BP Annual Report and Form 20-F 2011 215
Financial statementsNotes on financial statements http://www.bp.com/downloads/investments
25. Investments in associates
The significant associates of the BP group are shown in Note 45. The principal associate is TNK-BP. Summarized financial information for the group’s
share of associates is set out below. Balance sheet information shown below excludes data relating to associates reclassified as assets held for sale as at
the end of the period. Income statement information shown below includes data relating to associates reclassified as assets held for sale for the period
up until their date of reclassification as held for sale.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Minority interest
Profit for the year
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Minority interest
Group investment in associates
Group share of net assets (as above)
Loans made by group companies to associates
TNK-BP
30,100
5,992
132
5,860
1,333
342
4,185
16,172
4,210
20,382
3,086
6,416
9,502
867
10,013
10,013
–
10,013
Other
12,145
958
13
945
214
–
731
3,865
2,273
6,138
2,149
1,744
3,893
–
2011
Total
42,245
6,950
145
6,805
1,547
342
4,916
20,037
6,483
26,520
5,235
8,160
13,395
867
TNK-BP
22,323
3,866
128
3,738
913
208
2,617
14,686
4,500
19,186
3,284
5,283
8,567
624
Other
10,031
1,215
22
1,193
228
–
965
4,024
1,989
6,013
1,888
1,914
3,802
–
2010
Total
32,354
5,081
150
4,931
1,141
208
3,582
18,710
6,489
25,199
5,172
7,197
12,369
624
2,245
12,258
9,995
2,211
12,206
2,245
1,033
3,278
12,258
1,033
13,291
9,995
–
9,995
2,211
1,129
3,340
12,206
1,129
13,335
TNK-BP
17,377
3,178
220
2,958
871
139
1,948
Other
8,301
811
19
792
125
–
667
$ million
2009
Total
25,678
3,989
239
3,750
996
139
2,615
Transactions between the group and its associates are summarized below.
Sales to associates
Product
LNG, crude oil and oil products, natural gas, employee services
2011
Amount
receivable at
31 December
393
Sales
3,855
2010
Amount
receivable at
31 December
330
Sales
3,561
Sales
2,801
Purchases from associates
Product
Crude oil and oil products, natural gas, transportation tariff
2011
Amount
payable at
31 December
815
2010
Amount
payable at
31 December
633
Purchases
4,889
Purchases
8,159
Purchases
5,110
$ million
2009
Amount
receivable at
31 December
320
$ million
2009
Amount
payable at
31 December
614
The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash.
There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect
of bad or doubtful debts.
The amounts receivable and payable at 31 December 2011, as shown in the table above, exclude $220 million (2010 $299 million) due from and
due to an intermediate associate which provides funding for our associate The Baku-Tbilisi-Ceyhan Pipeline Company. These balances are expected to be
settled in cash throughout the period to 2015.
Dividends receivable at 31 December 2011 of $38 million (2010 $39 million) are also excluded from the table above.
BP has commitments amounting to $1,477 million (2010 $310 million) in relation to contracts with its associates for the purchase of crude oil and
oil products, transportation and storage. See Note 44 for further information on capital commitments relating to BP’s investments in associates.
On 18 October 2010, BP announced that it had reached agreement to sell assets in Vietnam, together with its upstream businesses and
associated interests in Venezuela, to TNK-BP which is an associate and therefore a related party of the group. This transaction is part of the group’s
disposal programme and is the result of normal commercial negotiations. As at 31 December 2010, a deposit of $1 billion had been received from
TNK-BP in advance of completion of this transaction and was reported within finance debt on the group balance sheet. This deposit was not reflected
in the amount payable in the table above. The sale of the Venezuelan business and the sale of the upstream and certain midstream assets in Vietnam
completed during 2011. Additional disposal proceeds of $0.7 billion were received upon completion of these transactions. The sale of the group’s
remaining equity-accounted investment in the Phu My 3 plant facility in Vietnam is expected to complete in 2012. See Note 4 for further information.
A deposit of $30 million relating to the disposal of the Phu My 3 plant facility remains reported within finance debt on the group balance sheet at
31 December 2011.
216 BP Annual Report and Form 20-F 2011
Notes on financial statements 26. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.
At 31 December
Financial assets
Other investments – equity shares
– other
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
At 31 December
Financial assets
Other investments – equity shares
– other
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
$ million
2011
Total
carrying
amount
1,128
1,277
1,128
36,879
8,895
14,067
$ million
2010
Total
carrying
amount
1,191
1,532
1,141
32,380
8,566
18,556
Note
Loans and
receivables
Available-for-
sale financial
assets
At fair value
through profit
or loss
Derivative
hedging
instruments
Financial
liabilities
measured at
amortized cost
27
27
29
33
30
32
33
34
–
–
1,128
36,879
–
9,750
–
–
–
–
47,757
1,128
1,277
–
–
–
4,317
–
–
–
–
6,722
–
–
–
–
7,188
–
–
(6,436)
–
–
752
–
–
–
–
1,707
–
–
–
–
–
–
–
–
(557)
–
–
1,150
(50,651)
–
(6,321)
(44,183)
(101,155)
(50,651)
(6,993)
(6,321)
(44,183)
(44,774)
Note
Loans and
receivables
Available-for-
sale financial
assets
At fair value
through profit
or loss
Derivative
hedging
instruments
Financial
liabilities
measured at
amortized cost
27
27
29
33
30
32
33
34
–
–
1,141
32,380
–
13,462
–
–
–
–
46,983
1,191
1,532
–
–
–
5,094
–
–
–
–
7,817
–
–
–
–
7,222
–
–
(7,254)
–
–
(32)
–
–
–
–
1,344
–
–
–
–
–
–
–
–
(279)
–
–
1,065
(56,499)
–
(6,249)
(39,139)
(101,887)
(56,499)
(7,533)
(6,249)
(39,139)
(46,054)
The fair value of finance debt is shown in Note 34. For all other financial instruments, the carrying amount is either the fair value, or approximates the fair value.
Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments including:
market risks relating to commodity prices, foreign currency exchange rates, interest rates and equity prices; credit risk; and liquidity risk.
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC
is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated
supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for the
group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial
risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with
group policies and group risk appetite.
The group’s trading activities in the oil, natural gas and power markets are managed within the integrated supply and trading function, while the
activities in the financial markets are managed by the integrated supply and trading function, on behalf of the treasury function. All derivative activity is
carried out by specialist teams that have the appropriate skills, experience and supervision. These teams are subject to close financial and management
control.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk associated with
trading activity. These processes meet generally accepted industry practice and reflect the principles of the Group of Thirty Global Derivatives Study
recommendations. A policy and risk committee monitors and validates limits and risk exposures, reviews incidents and validates risk-related policies,
methodologies and procedures. A commitments committee approves value-at-risk delegations, the trading of new products, instruments and strategies
and material commitments.
In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a separate control
framework as described more fully below.
BP Annual Report and Form 20-F 2011 217
Financial statementsNotes on financial statements
26. Financial instruments and financial risk factors continued
(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The primary
commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s financial
assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In addition, the
group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In accordance with the
control framework the group enters into various transactions using derivatives for risk management purposes.
The group measures market risk exposure arising from its trading positions using value-at-risk techniques. These techniques are based on Monte
Carlo simulation and make a statistical assessment of the market risk arising from possible future changes in market prices over a one-day holding period.
The calculation of the range of potential changes in fair value takes into account a snapshot of the end-of-day exposures and the history of one-day price
movements, together with the correlation of these price movements. The value-at-risk measure is supplemented by stress testing.
The value-at-risk table does not incorporate any of the group’s natural business exposures or any derivatives entered into to risk manage those
exposures. Market risk exposure in respect of embedded derivatives is also not included in the value-at-risk table.
Value-at-risk limits are in place for each trading activity and for the group’s trading activity in total. The board has delegated a limit of $100 million
value at risk in support of this trading activity. The high and low values at risk indicated in the table below for each type of activity are independent of each
other. Through the portfolio effect the high value at risk for the group as a whole is lower than the sum of the highs for the constituent parts. The potential
movement in fair values is expressed to a 95% confidence interval. This means that, in statistical terms, one would expect to see a decrease in fair values
greater than the trading value at risk on one occasion per month if the portfolio were left unchanged.
Value at risk for 1 day at 95% confidence interval
Group trading
Oil price trading
Gas and power trading
High
83
84
20
Low
28
23
6
Average
42
39
11
2011
Year end
28
27
7
High
70
39
62
Low
15
10
7
Average
34
19
27
$ million
2010
Year end
33
25
18
The major components of market risk are commodity price risk, foreign currency exchange risk, interest rate risk and equity price risk, each of which is
discussed below.
(i) Commodity price risk
The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes available in the related
commodity markets. Oil and natural gas swaps, options and futures are used to mitigate price risk. Power trading is undertaken using a combination
of over-the-counter forward contracts and other derivative contracts, including options and futures. This activity is on both a standalone basis and in
conjunction with gas derivatives in relation to gas-generated power margin. In addition, NGLs are traded around certain US inventory locations using
over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories. Trading value-at-risk information in
relation to these activities is shown in the table above.
As described above, the group also carries out risk management of certain natural business exposures using over-the-counter swaps and
exchange futures contracts. Together with certain physical supply contracts that are classified as derivatives, these contracts fall outside of the value-at-
risk framework. For these derivative contracts the sensitivity of the net fair value to an immediate 10% increase or decrease in all reference prices would
have been $23 million at 31 December 2011 (2010 $104 million). This figure does not include any corresponding economic benefit or disbenefit that
would arise from the natural business exposure which would be expected to offset the gain or loss on the over-the-counter swaps and exchange futures
contracts mentioned above.
In addition, the group has embedded derivatives relating to certain natural gas contracts. The net fair value of these contracts was a liability of
$1,417 million at 31 December 2011 (2010 liability of $1,607 million). Key information on the natural gas contracts is given below.
At 31 December
Remaining contract terms
Contractual/notional amount
2011
3 years and 5 months to 6 years and 9 months
952 million therms
2010
4 years and 5 months to 7 years and 9 months
1,688 million therms
For these embedded derivatives the sensitivity of the net fair value to an immediate 10% favourable or adverse change in the key assumptions is
as follows.
At 31 December
Favourable 10% change
Unfavourable 10% change
Gas price
100
(109)
Oil price
74
(77)
Power price
4
(4)
2011
Discount
rate
5
(5)
Gas price
145
(180)
Oil price
48
(68)
Power price
10
(10)
$ million
2010
Discount
rate
10
(10)
218 BP Annual Report and Form 20-F 2011
Notes on financial statements 26. Financial instruments and financial risk factors continued
The sensitivities for risk management activity and embedded derivatives are hypothetical and should not be considered to be predictive of future
performance. In addition, for the purposes of this analysis, in the above table, the effect of a variation in a particular assumption on the fair value of the
embedded derivatives is calculated independently of any change in another assumption. In reality, changes in one factor may contribute to changes in
another, which may magnify or counteract the sensitivities. Furthermore, the estimated fair values as disclosed should not be considered indicative of
future earnings on these contracts.
(ii) Foreign currency exchange risk
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-risk
techniques as explained above. This activity is included within oil price trading in the value-at-risk table above.
Since BP has global operations, fluctuations in foreign currency exchange rates can have significant effects on the group’s reported results. The
effects of most exchange rate fluctuations are absorbed in business operating results through changing cost competitiveness, lags in market adjustment
to movements in rates and translation differences accounted for on specific transactions. For this reason, the total effect of exchange rate fluctuations
is not identifiable separately in the group’s reported results. The main underlying economic currency of the group’s cash flows is the US dollar. This is
because BP’s major product, oil, is priced internationally in US dollars. BP’s foreign currency exchange management policy is to minimize economic
and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign currency
exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible, and then dealing with any material residual foreign
currency exchange risks.
The group manages these exposures by constantly reviewing the foreign currency economic value at risk and aims to manage such risk to
keep the 12-month foreign currency value at risk below $200 million. At 31 December 2011, the foreign currency value at risk was $100 million (2010
$81 million). At no point over the past three years did the value at risk exceed the maximum risk limit. The most significant exposures relate to capital
expenditure commitments and other UK and European operational requirements, for which a hedging programme is in place and hedge accounting is
claimed as outlined in Note 33.
For highly probable forecast capital expenditures the group locks in the US dollar cost of non-US dollar supplies by using currency forwards and
futures. The main exposures are sterling, euro, Norwegian krone, Australian dollar and Korean won and at 31 December 2011 open contracts were in
place for $1,242 million sterling, $158 million euro, $118 million Norwegian krone, $210 million Australian dollar and $230 million Korean won capital
expenditures maturing within five years, with over 69% of the deals maturing within two years (2010 $989 million sterling, $115 million euro, $212 million
Norwegian krone and $143 million Australian dollar capital expenditures maturing within five years, with over 80% of the deals maturing within two years).
For other UK, European and Australian operational requirements the group uses cylinders and currency forwards to hedge the estimated
exposures on a 12-month rolling basis. At 31 December 2011, the open positions relating to cylinders consisted of receive sterling, pay US dollar,
purchased call and sold put options (cylinders) for $2,683 million (2010 $1,340 million); receive euro, pay US dollar cylinders for $1,304 million (2010
$650 million); receive Australian dollar, pay US dollar cylinders for $312 million (2010 $286 million). At 31 December 2011 there were no open positions
relating to currency forwards (2010 buy sterling, sell US dollar currency forwards for $925 million; buy euro, sell US dollar currency forwards for $630
million; buy Canadian dollar, sell US dollar currency forwards for $162 million).
In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2011, the total foreign
currency net borrowings not swapped into US dollars amounted to $371 million (2010 $278 million). Of this total, $129 million was denominated in
currencies other than the functional currency of the individual operating unit being entirely Canadian dollars (2010 $125 million, being entirely Canadian
dollars). It is estimated that a 10% change in the corresponding exchange rates would result in an exchange gain or loss in the income statement of
$13 million (2010 $12 million).
(iii) Interest rate risk
Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques as
described above. This activity is included within oil price trading in the value-at-risk table above.
BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its
financial instruments, principally finance debt.
While the group issues debt in a variety of currencies based on market opportunities, it uses derivatives to swap the debt to a floating rate
exposure, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar fixed rate exposure for a proportion of debt. The
proportion of floating rate debt net of interest rate swaps and excluding disposal deposits at 31 December 2011 was 65% of total finance debt
outstanding (2010 62%). The weighted average interest rate on finance debt at 31 December 2011 is 2% (2010 2%) and the weighted average maturity
of fixed rate debt is five years (2010 five years).
The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates
applicable to floating rate instruments were to have increased by 1% on 1 January 2012, it is estimated that the group’s profit before taxation for 2012
would decrease by approximately $289 million (2010 $241 million decrease in 2011). 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 2011 and that the change in interest rates is effective from the
beginning of the year. Where the interest rate applicable to an instrument is reset during a quarter it is assumed that this occurs at the beginning of the
quarter and remains unchanged for the rest of the year. In reality, the fixed/floating rate mix will fluctuate over the year and interest rates will change
continually. Furthermore, the effect on earnings shown by this analysis does not consider the effect of any other changes in general economic activity that
may accompany such an increase in interest rates.
(iv) Equity price risk
The group holds equity investments, typically made for strategic purposes, that are classified as non-current available-for-sale financial assets and are
measured initially at fair value with changes in fair value recognized in other comprehensive income. Accumulated fair value changes are recycled to the
income statement on disposal, or when the investment is impaired. No impairment losses have been recognized for the years presented relating to listed
non-current available-for-sale investments. For further information see Note 27.
At 31 December 2011, it is estimated that an increase of 10% in quoted equity prices would result in an immediate credit to other comprehensive
income of $87 million (2010 $95 million credit to other comprehensive income), while a decrease of 10% in quoted equity prices would result in an
immediate charge to other comprehensive income of $87 million (2010 $95 million charge to other comprehensive income).
BP Annual Report and Form 20-F 2011 219
Financial statementsNotes on financial statements 26. Financial instruments and financial risk factors continued
At 31 December 2011, 77% (2010 80%) of the carrying amount of non-current available-for-sale equity financial assets represented the group’s stake in
Rosneft, thus the group’s exposure is concentrated on changes in the share price of this equity investment in particular.
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to
the group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit
exposures to customers relating to outstanding receivables.
The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to
measure and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract
the extent to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy are formal delegated authorities to
the sales and marketing teams to incur credit risk and to a specialized credit function to set counterparty limits; the establishment of credit systems and
processes to ensure that counterparties are rated and limits set; and systems to monitor exposure against limits and report regularly on those exposures,
and immediately on any excesses, and to track and report credit losses. The treasury function provides a similar credit risk management activity with
respect to group-wide exposures to banks and other financial institutions.
The global credit environment exhibited deterioration in 2011, suffering not only from continuing economic and political uncertainties but also from
key event risks, causing the group to further heighten awareness, discussion and co-ordination around the material credit risks arising from its activities.
Before trading with a new counterparty can start, its creditworthiness is assessed and a credit rating is allocated that indicates the probability
of default, along with a credit exposure limit. The assessment process takes into account all available qualitative and quantitative information about
the counterparty and the group, if any, to which the counterparty belongs. The counterparty’s business activities, financial resources and business risk
management processes are taken into account in the assessment, to the extent that this information is publicly available or otherwise disclosed to BP by
the counterparty, together with external credit ratings. Creditworthiness continues to be evaluated after transactions have been initiated and a watchlist of
higher-risk counterparties is maintained.
The group does not aim to remove credit risk but expects to experience a certain level of credit losses. The group attempts to mitigate credit
risk by entering into contracts that permit netting and allow for termination of the contract on the occurrence of certain events of default. Depending on
the creditworthiness of the counterparty, the group may require collateral or other credit enhancements such as cash deposits, letters of credit, trade
credit insurance, liens, third-party guarantees and other forms of credit mitigation. Trade receivables and payables, and derivative assets and liabilities,
are presented on a net basis where unconditional netting arrangements are in place with counterparties and where there is an intent to settle amounts
due on a net basis. The maximum credit exposure associated with financial assets is equal to the carrying amount. Collateral received and recognized
in the balance sheet at the year end was $273 million (2010 $313 million) and collateral held off balance sheet was $6 million (2010 $52 million). As at
31 December 2011, the group had in place other credit enhancements designed to mitigate approximately $8.6 billion of credit risk (2010 $7.0 billion).
Credit exposure exists in relation to guarantees issued by group companies under which amounts outstanding at 31 December 2011 were $415 million
(2010 $404 million) in respect of liabilities of jointly controlled entities and associates and $1,430 million (2010 $1,339 million) in respect of liabilities of
other third parties.
Notwithstanding the processes described above, significant unexpected credit losses can occasionally occur. Exposure to unexpected losses
increases with concentrations of credit risk that exist when a number of counterparties are involved in similar activities or operate in the same industry
sector or geographical area, which may result in their ability to meet contractual obligations being impacted by changes in economic, political or other
conditions. The group’s principal customers, suppliers and financial institutions with which it conducts business are located throughout the world. In
addition, these risks are managed by maintaining a group watchlist and aggregating multi-segment exposures to ensure that a material credit risk is
not missed.
Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit exposure and expected loss trends, exposure by
segment, and overall quality of the portfolio. The reports also include details of the largest counterparties by exposure level and expected loss, and details
of counterparties on the group watchlist.
For the contracts comprising derivative financial instruments in an asset position at 31 December 2011, it is estimated that over 76% (2010 over
80%) of the unmitigated credit exposure is to counterparties of investment grade credit quality.
For cash and cash equivalents, the treasury function dynamically manages bank deposit limits to ensure cash is well-diversified and to reduce
concentration risks. At 31 December 2011, 98% of the cash and cash equivalents balance was deposited with financial institutions rated at least A by
Standard & Poor’s and A2 by Moody’s. Direct cash and cash equivalent exposures to Greek, Italian, Irish, Portuguese and Spanish financial institutions
totalled less than 1% of total cash and cash equivalents.
Trade and other receivables of the group are analysed in the table below. By comparing the BP credit ratings to the equivalent external credit
ratings, it is estimated that approximately 70-80% (2010 approximately 50-60%) of the unmitigated trade receivables portfolio exposure is of investment
grade credit quality. With respect to the trade and other receivables that are neither impaired nor past due, there are no indications as of the reporting
date that the debtors will not meet their payment obligations.
Trade and other receivables at 31 December
Neither impaired nor past due
Impaired (net of valuation allowance)
Not impaired and past due in the following periods
within 30 days
31 to 60 days
61 to 90 days
over 90 days
220 BP Annual Report and Form 20-F 2011
2011
34,563
33
1,263
250
132
638
$ million
2010
30,181
67
1,358
249
101
424
36,879
32,380
Notes on financial statements 26. Financial instruments and financial risk factors continued
The movement in the valuation allowance for trade receivables is set out below.
At 1 January
Exchange adjustments
Charge for the year
Utilization
Write-back
At 31 December
2011
428
(16)
115
(124)
(71)
332
$ million
2010
430
(9)
150
(143)
–
428
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed centrally
with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations, subsidiaries
pool their cash surpluses to treasury, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the market or arrange
for necessary external borrowings, while managing the group’s overall net currency positions.
In managing its liquidity risk, the group has access to a wide range of funding at competitive rates through capital markets and banks. The group’s
treasury function centrally co-ordinates relationships with banks, borrowing requirements, foreign exchange requirements and cash management. The
group believes it has access to sufficient funding through its own current cash holdings and future cash generation including disposal proceeds, the
commercial paper markets and by using undrawn committed borrowing facilities to meet foreseeable liquidity requirements.
The group has in place a European Debt Issuance Programme (DIP) under which the group may raise up to $20 billion of debt for maturities of
one month or longer. At 31 December 2011, the amount drawn down against the DIP was $11,582 million (2010 $12,272 million). In addition, the group
has in place an unlimited US Shelf Registration under which it may raise debt with maturities of one month or longer.
The group has long-term debt ratings of A2 (stable outlook) assigned by Moody’s consistently throughout the year, and A (stable outlook) assigned
by Standard & Poor’s since July 2011, strengthened from A (negative outlook) in force at the start of the year.
During 2011 $10.7 billion of long-term taxable bonds were issued with tenors of between 18 months and 10 years, and $0.8 billion of US
Industrial/Municipal bonds were re-issued in term-out mode of between three and ten years. Flexible commercial paper is issued at competitive rates to
meet short-term borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, invested with highly rated banks or
money market funds and readily accessible at immediate and short notice ($14.1 billion at the end of 2011; $18.6 billion at the end of 2010).
At 31 December 2011, the group had substantial amounts of undrawn borrowing facilities available, consisting of $6,925 million of standby
facilities (of which $6,825 million is available to draw and repay until mid-March 2014, and the equivalent of $100 million is available to draw and repay
in Chinese yuan with half expiring in mid-September 2012 and half in December 2012). These facilities were renegotiated during 2011 across 25
international banks, and borrowings under them would be at pre-agreed rates.
The group also has committed letter of credit (LC) facilities totalling $5,125 million with a number of banks for a one-year duration, allowing LCs
to be issued to a maximum one-year duration. There were also uncommitted secured LC evergreen facilities in place at the year end for $2,160 million,
secured against inventories or receivables when utilized.
The amounts shown for finance debt in the table below include expected interest payments on borrowings and the future minimum lease
payments with respect to finance leases.
Current finance debt on the group balance sheet at 31 December 2011 includes $30 million (2010 $6,197 million) in respect of cash deposits
received for disposals expected to complete in 2012, which will be considered extinguished on completion of the transactions. This amount is excluded
from the table below.
The table also shows the timing of cash outflows relating to trade and other payables and accruals.
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
Trade and
other
payablesa
47,678
1,605
569
449
259
31
72
50,663
Accruals
5,933
137
55
26
49
82
39
6,321
2011
Finance
debt
10,024
7,866
7,311
5,487
4,634
12,381
573
48,276
Trade and
other
payablesa
42,691
6,549
6,242
411
365
323
25
56,606
Accruals
5,612
278
125
42
28
110
54
6,249
$ million
2010
Finance
debt
9,353
6,816
7,542
6,105
5,494
6,642
724
42,676
a Trade and other payables at 31 December 2011 includes the Gulf of Mexico oil spill trust fund liability which is payable as follows: $4,884 million within one year (2010 $5,008 million within one year,
$5,000 million payable in 1 to 2 years and $5,000 million payable in 2 to 3 years).
BP Annual Report and Form 20-F 2011 221
Financial statementsNotes on financial statements 26. Financial instruments and financial risk factors continued
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of both
derivative assets and liabilities as indicated in Note 33. Management does not currently anticipate any cash flows that could be of a significantly different
amount, or could occur earlier than the expected maturity analysis provided.
The table below shows cash outflows for derivative hedging instruments based upon contractual payment dates. The amounts reflect the
maturity profile of the fair value liability where the instruments will be settled net, and the gross settlement amount where the pay leg of a derivative will
be settled separately from the receive leg, as in the case of cross-currency interest rate swaps hedging non-US dollar finance debt. The swaps are with
high investment-grade counterparties and therefore the settlement day risk exposure is considered to be negligible. Not shown in the table are the gross
settlement amounts for the receive leg of derivatives that are settled separately from the pay leg, which amount to $9,099 million at 31 December 2011
(2010 $6,725 million) to be received on the same day as the related cash outflows.
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
2011
1,738
1,372
1,115
298
1,262
3,459
9,244
$ million
2010
986
1,682
1,358
1,124
295
947
6,392
The group has issued third-party guarantees, as described above under credit risk. These amounts represent the maximum exposure of the group,
substantially all of which could be called within one year.
27. Other investments
Equity investments – listed
– unlisted
Repurchased gas pre-paid bonds
Current
–
–
288
288
2011
Non-current
876
252
989
2,117
$ million
2010
Non-current
953
238
–
1,191
Current
–
–
1,532
1,532
Equity investments have no fixed maturity date or coupon rate, and are classified as available-for-sale financial assets. As such they are recorded at fair
value with the gain or loss arising as a result of changes in fair value recorded directly in other comprehensive income. Accumulated fair value changes are
recycled to the income statement on disposal, or when the investment is impaired.
The fair value of listed investments has been determined by reference to quoted market bid prices and as such are in level 1 of the fair value
hierarchy. Unlisted investments are stated at cost less accumulated impairment losses.
The most significant listed investment is the group’s stake in Rosneft which had a fair value of $873 million at 31 December 2011 (2010
$948 million). The fair value loss arising on revaluation of this investment during 2011 has been recorded within other comprehensive income.
In 2011, impairment losses of $12 million were incurred relating to unlisted investments; there were no impairment losses relating to listed
investments. In 2010, no impairment losses were incurred relating to either unlisted investments or listed investments.
BP has entered into long-term gas supply contracts which are backed by gas pre-paid bonds. In 2010, BP was unsuccessful in the remarketing of
these bonds and repurchased them. The outstanding bonds associated with these long-term gas supply contracts held by BP are recorded within other
investments, with the related liability recorded within other payables on the balance sheet. The fair value of the gas pre-paid bonds is the same as the
carrying amount, as the bonds are based on floating rate interest with weekly market re-set, and as such are in Level 1 of the fair value hierarchy.
BP has no investments pledged as security for liabilities as at 31 December 2011. As at 31 December 2010, BP had pledged listed equity
investments with a carrying value of $948 million as part of a financing arrangement. As BP had retained substantially all the risks and rewards associated
with the shares, they continued to be reflected as an asset on the balance sheet, with a liability being reflected within finance debt. The terms of the
arrangement meant that BP could request to have the shares returned at any time with 20 days notice, up to the date of maturity (in three tranches, up to
December 2013), subject to repayment of the outstanding loan. The financing arrangement was terminated during 2011.
28. Inventories
Crude oil
Natural gas
Refined petroleum and petrochemical products
Supplies
Trading inventories
Cost of inventories expensed in the income statement
222 BP Annual Report and Form 20-F 2011
2011
7,702
178
14,909
22,789
2,057
24,846
815
25,661
285,618
$ million
2010
8,969
112
13,997
23,078
1,669
24,747
1,471
26,218
216,211
Notes on financial statements
29. Trade and other receivables
Financial assets
Trade receivables
Amounts receivable from jointly controlled entities
Amounts receivable from associates
Other receivables
Non-financial assets
Gulf of Mexico oil spill trust fund reimbursement asseta
Other receivables
a See Note 2 for further information.
Trade and other receivables are predominantly non-interest bearing. See Note 26 for further information.
30. Cash and cash equivalents
Cash at bank and in hand
Term bank deposits
Cash equivalents
Current
2011
Non-current
27,929
1,004
492
5,429
34,854
8,233
439
8,672
43,526
508
612
159
746
2,025
1,642
670
2,312
4,337
$ million
2010
Non-current
–
601
220
1,342
2,163
3,601
534
4,135
6,298
Current
24,255
751
448
4,763
30,217
5,943
389
6,332
36,549
2011
4,872
4,878
4,317
14,067
$ million
2010
8,209
5,253
5,094
18,556
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; term deposits of three months or less with banks
and similar institutions; and short-term highly liquid investments that are readily convertible to known amounts of cash, are subject to insignificant risk of
changes in value and have a maturity of three months or less from the date of acquisition. The carrying amounts of cash at bank and in hand and term
bank deposits approximate their fair values. All of the other cash equivalents are categorized within level 1 of the fair value hierarchy.
Cash and cash equivalents at 31 December 2011 includes $901 million (2010 $982 million) that is restricted. This relates principally to amounts
required to cover initial margins on trading exchanges.
See Note 26 for further information.
31. Valuation and qualifying accounts
At 1 January
Charged to costs and expenses
Charged to other accountsa
Deductions
At 31 December
a Principally currency transactions.
Doubtful
debts
428
115
(16)
(195)
332
2011
Fixed assets –
investments
540
111
(3)
(5)
643
Doubtful
debts
430
150
(9)
(143)
428
2010
Fixed assets –
investments
349
376
(3)
(182)
540
$ million
2009
Fixed assets –
investments
935
66
6
(658)
349
Doubtful
debts
391
157
12
(130)
430
Valuation and qualifying accounts are deducted in the balance sheet from the assets to which they apply.
BP Annual Report and Form 20-F 2011 223
Financial statementsNotes on financial statements 32. Trade and other payables
Financial liabilities
Trade payables
Amounts payable to jointly controlled entities
Amounts payable to associates
Gulf of Mexico oil spill trust fund liabilitya
Other payables
Non-financial liabilities
Other payables
a See Note 2 for further information.
Current
29,830
1,578
876
4,872
10,510
47,666
4,739
52,405
2011
Non-current
–
1,047
159
–
1,779
2,985
452
3,437
$ million
2010
Non-current
–
1,905
220
9,899
1,790
13,814
471
14,285
Current
27,510
1,361
712
5,002
8,100
42,685
3,644
46,329
Trade and other payables are predominantly interest free, however the Gulf of Mexico oil spill trust fund liability is recorded on a discounted basis. See
Note 26 for further information.
http://www.bp.com/downloads/dfi
33. Derivative financial instruments
An outline of the group’s financial risks and the objectives and policies pursued in relation to those risks is set out in Note 26.
In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in
relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed
rate debt, consistent with risk management policies and objectives. Additionally, the group has a well-established entrepreneurial trading operation that is
undertaken in conjunction with these activities using a similar range of contracts.
IAS 39 prescribes strict criteria for hedge accounting, whether as a cash flow or fair value hedge or a hedge of a net investment in a foreign
operation, and requires that any derivative that does not meet these criteria should be classified as held for trading and fair valued, with gains and losses
recognized in the income statement.
The fair values of derivative financial instruments at 31 December are set out below.
Fair
value
asset
217
823
5,305
843
7,188
–
–
–
25
–
25
842
840
1,682
8,895
3,857
5,038
2011
Fair
value
liability
(217)
(536)
(3,603)
(663)
(5,019)
(1,417)
–
(1,417)
(159)
–
(159)
(398)
–
(398)
(6,993)
(3,220)
(3,773)
$ million
2010
Fair
value
liability
(280)
(877)
(3,951)
(432)
(5,540)
(1,625)
(89)
(1,714)
(124)
(1)
(125)
(80)
(74)
(154)
(7,533)
(3,856)
(3,677)
Fair
value
asset
194
1,099
5,350
561
7,204
18
–
18
134
101
235
772
337
1,109
8,566
4,356
4,210
Derivatives held for trading
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Embedded derivatives
Commodity price contracts
Other embedded derivatives
Cash flow hedges
Currency forwards, futures and cylinders
Cross-currency interest rate swaps
Fair value hedges
Currency forwards, futures and swaps
Interest rate swaps
Of which – current
– non-current
224 BP Annual Report and Form 20-F 2011
Notes on financial statements 33. Derivative financial instruments continued
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy supply
requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective, and are
recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of contract types
in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these exposures is monitored
using market value-at-risk techniques as described in Note 26.
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Derivative assets held for trading have the following fair values and maturities.
http://www.bp.com/downloads/dfi
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Less than
1 year
194
573
2,493
498
3,758
Less than
1 year
124
797
2,591
389
3,901
1-2 years
18
135
1,160
160
1,473
1-2 years
41
128
1,100
125
1,394
2-3 years
5
77
597
101
780
2-3 years
18
82
652
35
787
3-4 years
–
25
346
54
425
3-4 years
11
64
375
11
461
4-5 years
–
10
207
30
247
4-5 years
–
21
231
1
253
Derivative liabilities held for trading have the following fair values and maturities.
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Less than
1 year
(168)
(483)
(1,696)
(328)
(2,675)
Less than
1 year
(228)
(794)
(2,174)
(287)
(3,483)
1-2 years
(49)
(37)
(876)
(176)
(1,138)
2-3 years
–
(7)
(347)
(89)
(443)
3-4 years
–
(4)
(197)
(46)
(247)
4-5 years
–
(3)
(102)
(24)
(129)
1-2 years
(6)
(76)
(741)
(103)
(926)
2-3 years
(46)
(6)
(484)
(32)
(568)
3-4 years
–
(1)
(161)
(9)
(171)
4-5 years
–
–
(114)
(1)
(115)
$ million
2011
Total
217
823
5,305
843
7,188
$ million
2010
Total
194
1,099
5,350
561
7,204
$ million
2011
Total
(217)
(536)
(3,603)
(663)
(5,019)
$ million
2010
Total
(280)
(877)
(3,951)
(432)
(5,540)
Over
5 years
–
3
502
–
505
Over
5 years
–
7
401
–
408
Over
5 years
–
(2)
(385)
–
(387)
Over
5 years
–
–
(277)
–
(277)
If at inception of a contract the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is not
recognized in the income statement but is deferred on the balance sheet and is commonly known as ‘day-one profit or loss’. This deferred gain or loss
is recognized in the income statement over the life of the contract until substantially all of the remaining contract term can be valued using observable
market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation from this initial valuation are
recognized immediately through the income statement.
BP Annual Report and Form 20-F 2011 225
Financial statementsNotes on financial statements 33. Derivative financial instruments continued
The following table shows the changes in the day-one profits and losses deferred on the balance sheet.
http://www.bp.com/downloads/dfi
Fair value of contracts not recognized through the income statement at 1 January
Fair value of new contracts at inception not recognized in the income statement
Fair value recognized in the income statement
Fair value of contracts not recognized through profit at 31 December
Power price
–
9
–
9
2011
Natural
gas price
69
51
(6)
114
Oil price
21
–
(21)
–
$ million
2010
Natural
gas price
33
39
(3)
69
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology of
fair value estimation.
IFRS 7 ‘Financial Instruments: Disclosures’ sets out a fair value hierarchy which consists of three levels that describe the methodology of
estimation as follows:
Level 1 – using quoted prices in active markets for identical assets or liabilities.
Level 2 – using inputs for the asset or liability, other than quoted prices, that are observable either directly (i.e. as prices) or indirectly
(i.e. derived from prices).
Level 3 – using inputs for the asset or liability that are not based on observable market data such as prices based on internal models or other
valuation methods.
This information is presented on a gross basis, that is, before netting by counterparty.
Less than
1 year
229
7,225
310
7,764
(4,006)
3,758
(168)
(6,323)
(190)
(6,681)
4,006
(2,675)
1,083
Less than
1 year
122
7,132
341
7,595
(3,694)
3,901
(239)
(6,733)
(205)
(7,177)
3,694
(3,483)
418
1-2 years
2-3 years
3-4 years
4-5 years
18
2,725
284
3,027
(1,554)
1,473
(49)
(2,479)
(164)
(2,692)
1,554
(1,138)
335
5
1,123
253
1,381
(601)
780
–
(887)
(157)
(1,044)
601
(443)
337
–
269
221
490
(65)
425
–
(163)
(149)
(312)
65
(247)
178
–
81
170
251
(4)
247
–
(21)
(112)
(133)
4
(129)
118
1-2 years
2-3 years
3-4 years
4-5 years
36
1,928
314
2,278
(884)
1,394
(6)
(1,685)
(148)
(1,839)
884
(955)
439
12
639
296
947
(160)
787
(46)
(617)
(125)
(788)
160
(628)
159
5
239
267
511
(50)
461
–
(107)
(114)
(221)
50
(171)
290
–
109
165
274
(21)
253
–
(44)
(92)
(136)
21
(115)
138
$ million
2011
Total
252
11,431
1,738
13,421
(6,233)
7,188
(217)
(9,880)
(1,155)
(11,252)
6,233
(5,019)
2,169
$ million
2010
Total
175
10,047
1,793
12,015
(4,811)
7,204
(291)
(9,186)
(963)
(10,440)
4,811
(5,629)
1,575
Over
5 years
–
8
500
508
(3)
505
–
(7)
(383)
(390)
3
(387)
118
Over
5 years
–
–
410
410
(2)
408
–
–
(279)
(279)
2
(277)
131
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
226 BP Annual Report and Form 20-F 2011
Notes on financial statements
33. Derivative financial instruments continued
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value hierarchy.
http://www.bp.com/downloads/dfi
Net fair value of contracts at 1 January 2011
Gains (losses) recognized in the income statement
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2011
Net fair value of contracts at 1 January 2010
Gains (losses) recognized in the income statement
Settlements
Transfers out of level 3
Transfers into level 3
Exchange adjustments
Net fair value of contracts at 31 December 2010
Oil
price
164
69
(71)
–
162
Oil
price
215
21
(54)
(18)
–
–
164
Natural
gas price
667
129
(110)
(278)
408
Natural
gas price
72
637
(11)
(38)
4
3
667
Power
price
(1)
11
3
–
13
Power
price
(1)
(1)
1
–
–
–
(1)
$ million
Total
830
209
(178)
(278)
583
$ million
Total
286
657
(64)
(56)
4
3
830
Transfers out of level 3 of the fair value hierarchy in 2011 relate primarily to the delivery dates for a number of natural gas forward contracts moving into a
time period where market observable prices are available, and therefore being reclassified to level 2 of the fair value hierarchy.
The amount recognized in the income statement for the year relating to level 3 held for trading derivatives still held at 31 December 2011 was a
$204 million gain (2010 $651 million gain relating to derivatives still held at 31 December 2010).
Gains and losses relating to derivative contracts are included either within sales and other operating revenues or within purchases in the income
statement depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures, options,
swaps and certain forward sales and forward purchases contracts, and relate to both currency and commodity trading activities. Gains or losses arise
on contracts entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are
for normal procurement or sales activity for the group but that are required to be fair valued under accounting standards. Also included within sales and
other operating revenues are gains and losses on inventory held for trading purposes. The total amount relating to all of these items was a net loss of
$934 million (2010 $1,738 million net gain and 2009 $4,046 million net gain).
Embedded derivatives
The group has embedded derivatives relating to certain natural gas contracts. Prior to the development of an active gas trading market, UK gas contracts
were priced using a basket of available price indices, primarily relating to oil products, power and inflation. After the development of an active UK gas
market, certain contracts were entered into or renegotiated using pricing formulae not directly related to gas prices, for example, oil product and power
prices. In these circumstances, pricing formulae have been determined to be derivatives, embedded within the overall contractual arrangements that are
not clearly and closely related to the underlying commodity. The resulting fair value relating to these contracts is recognized on the balance sheet with
gains or losses recognized in the income statement.
All the commodity price embedded derivatives relate to natural gas contracts, are categorized in level 3 of the fair value hierarchy and are valued
using inputs that include price curves for each of the different products that are built up from active market pricing data. Where necessary, these are
extrapolated to the expiry of the contracts (the last of which is in 2018) using all available external pricing information. Additionally, where limited data
exists for certain products, prices are interpolated using historic and long-term pricing relationships.
In addition, at 31 December 2010, BP was party to a collar-backed financing arrangement involving an available-for-sale investment held by the
group. This arrangement contained an embedded derivative whose fair value was related to the equity price of the investment and was categorized in
level 2 of the fair value hierarchy. The arrangement was terminated in 2011.
BP Annual Report and Form 20-F 2011 227
Financial statementsNotes on financial statements 33. Derivative financial instruments continued
Embedded derivative assets and liabilities have the following fair values and maturities.
Liabilities – commodity price contracts
Net fair value
Assets – commodity price contracts
Liabilities – commodity price contracts
– other embedded derivatives
Net fair value
Less than
1 year
(347)
(347)
Less than
1 year
18
(325)
–
(307)
1-2 years
(319)
(319)
2-3 years
(306)
(306)
3-4 years
(236)
(236)
4-5 years
(134)
(134)
1-2 years
–
(326)
(29)
(355)
2-3 years
–
(285)
(60)
(345)
3-4 years
–
(281)
–
(281)
4-5 years
–
(212)
–
(212)
$ million
2011
Total
(1,417)
(1,417)
$ million
2010
Total
18
(1,625)
(89)
(1,696)
Over
5 years
(75)
(75)
Over
5 years
–
(196)
–
(196)
The following table shows the changes during the year in the net fair value of embedded derivatives, within level 3 of the fair value hierarchy.
Net fair value of contracts at 1 January
Settlements
Losses recognized in the income statement
Exchange adjustments
Net fair value of contracts at 31 December
2011
Commodity
price
(1,607)
301
(106)
(5)
$ million
2010
Commodity
price
(1,331)
37
(350)
37
(1,417)
(1,607)
The amount recognized in the income statement for the year relating to level 3 embedded derivatives still held at 31 December 2011 was a $106 million
loss (2010 $350 million loss relating to embedded derivatives still held at 31 December 2010).
The fair value gain (loss) on embedded derivatives is shown below.
Commodity price embedded derivatives
Other embedded derivatives
Fair value gain (loss)
2011
190
(122)
68
2010
(309)
–
(309)
$ million
2009
607
–
607
Cash flow hedges
At 31 December 2011, the group held currency forwards and futures contracts and cylinders that were being used to hedge the foreign currency risk of
highly probable forecast transactions. Note 26 outlines the management of risk aspects for currency risk. For cash flow hedges the group only claims
hedge accounting for the intrinsic value on the currency with any fair value attributable to time value taken immediately to the income statement.
There were no highly probable transactions for which hedge accounting has been claimed that have not occurred and no significant element of hedge
ineffectiveness requiring recognition in the income statement. For cash flow hedges the pre-tax amount removed from equity during the period and
included in the income statement is a gain of $195 million (2010 gain of $25 million and 2009 loss of $366 million). The entire gain of $195 million is
included in production and manufacturing expenses (2010 $25 million gain in production and manufacturing expense; 2009 $332 million loss in production
and manufacturing expense and $34 million loss in finance costs). The amount removed from equity during the period and included in the carrying amount
of non-financial assets was a gain of $13 million (2010 $53 million loss and 2009 $136 million loss).
The amounts retained in equity at 31 December 2011 consist of deferred losses of $78 million maturing in 2012, deferred losses of $39 million
maturing in 2013 and deferred losses of $30 million maturing in 2014 and beyond.
Fair value hedges
At 31 December 2011, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk on
fixed rate debt issued by the group. The effectiveness of each hedge relationship is quantitatively assessed and demonstrated to continue to be highly
effective. The gain on the hedging derivative instruments taken to the income statement in 2011 was $328 million (2010 $563 million gain and 2009 $98
million loss) offset by a loss on the fair value of the finance debt of $327 million (2010 $554 million loss and 2009 $117 million gain).
The interest rate and cross-currency interest rate swaps mature within one to 10 years, with an average maturity of four to five years (2010 four
to five years) and are used to convert sterling, euro, Swiss franc, Australian dollar, Japanese yen and Hong Kong dollar denominated borrowings into US
dollar floating rate debt. Note 26 outlines the group’s approach to interest rate and currency risk management.
228 BP Annual Report and Form 20-F 2011
Notes on financial statements
34. Finance debt
Borrowings
Net obligations under finance leases
Disposal deposits
Current
8,675
339
9,014
30
9,044
Non-current
34,816
353
35,169
–
35,169
2011
Total
43,491
692
44,183
30
44,213
Current
8,312
117
8,429
6,197
Non-current
30,017
693
30,710
–
14,626
30,710
$ million
2010
Total
38,329
810
39,139
6,197
45,336
Current finance debt includes the portion of long-term borrowings and net obligations under finance leases that will mature in the next 12 months,
amounting to $5,214 million (2010 $6,976 million).
The main elements of current borrowings are the current portion of long-term bonds of $4,875 million (2010 $6,859 million) and issued commercial
paper of $3,635 million (2010 $1,025 million).
Deposits for disposal transactions expected to complete in 2012 of $30 million are also included in current finance debt (2010 $6,197 million for
transactions expected to complete in 2011). This debt will be considered extinguished on completion of the transactions.
At 31 December 2011, $131 million (2010 $790 million) of finance debt was secured by the pledging of assets, and no finance debt was secured in
connection with deposits received relating to certain disposal transactions expected to complete in subsequent periods (2010 $4,780 million). In addition,
in connection with $2,344 million (2010 $4,588 million) of finance debt, BP has entered into crude oil sales contracts in respect of oil produced from
certain fields in offshore Angola and Azerbaijan to provide security to the lending banks. The remainder of finance debt was unsecured.
The following table shows, by major currency, the group’s finance debt at 31 December and the weighted average interest rates achieved at those
dates through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures. The disposal
deposits noted above are excluded from this analysis.
US dollar
Euro
Other currencies
US dollar
Euro
Other currencies
Fixed rate debt
Floating rate debt
Total
Weighted
average
interest
rate
%
Weighted
average
time for
which rate
is fixed
Years
4
5
4
4
4
6
5
3
12
5
3
18
Weighted
average
interest
rate
%
1
3
3
1
2
4
Amount
$ million
15,016
25
240
15,281
14,797
53
140
14,990
Amount
$ million
27,285
1,575
42
28,902
21,076
2,988
85
24,149
Amount
$ million
2011
42,301
1,600
282
44,183
2010
35,873
3,041
225
39,139
The euro debt not swapped to US dollar is naturally hedged for the foreign currency risk by holding equivalent euro cash and cash equivalent amounts.
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. The terms and conditions of these finance leases do not impose any significant financial restrictions on
the group. Future minimum lease payments under finance leases are set out below.
Future minimum lease payments payable within
1 year
2 to 5 years
Thereafter
Less: finance charges
Net obligations
Of which – payable within 1 year
– payable within 2 to 5 years
– payable thereafter
2011
454
200
380
1,034
342
692
339
99
254
$ million
2010
153
535
438
1,126
316
810
117
404
289
BP Annual Report and Form 20-F 2011 229
Financial statementsNotes on financial statements
34. Finance debt continued
Fair values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the year from 31 December 2011, whereas in the balance
sheet the amount would be reported within current finance debt. The disposal deposits noted above are excluded from this analysis.
The carrying amount of the group’s short-term borrowings, comprising mainly commercial paper, approximates their fair value. The fair value of
the group’s long-term borrowings and finance lease obligations is estimated using quoted prices or, where these are not available, discounted cash flow
analyses based on the group’s current incremental borrowing rates for similar types and maturities of borrowing.
Short-term borrowings
Long-term borrowings
Net obligations under finance leases
Total finance debt
2011
Carrying
amount
3,800
39,691
692
44,183
$ million
2010
Fair value Carrying amount
1,453
36,876
810
39,139
1,453
37,258
928
39,639
Fair value
3,800
40,606
776
45,182
35. Capital disclosures and analysis of changes in net debt
The group defines capital as total equity. The group’s approach to managing capital is set out in its financial framework which BP continues to refine to
support the pursuit of value growth for shareholders, while maintaining a secure financial base. We intend to maintain a significant liquidity buffer and to
reduce our net debt ratio to the lower half of the 10-20% gearing range over time as our disposal programme progresses.
The group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross
finance debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange
and interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Net debt and net debt ratio are
non-GAAP measures. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of
gross debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity
from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. All components of equity are
included in the denominator of the calculation. At 31 December 2011 the net debt ratio was 20.5% (2010 21.2%).
During 2011 and 2010, the company did not repurchase any of its own shares, other than to satisfy the requirements of certain employee
2011
44,213
14,067
1,133
29,013
112,482
20.5%
Finance
debta
(44,420)
30
(4,725)
6,167
(132)
(43,080)
Cash and
cash
equivalents
18,556
(492)
(3,997)
–
–
14,067
2011
Net
debt
(25,864)
(462)
(8,722)
6,167
(132)
(29,013)
Finance
debta
(34,500)
194
(3,613)
(6,197)
(304)
(44,420)
Cash and
cash
equivalents
8,339
(279)
10,496
–
–
18,556
$ million
2010
45,336
18,556
916
25,864
95,891
21.2%
$ million
2010
Net
debt
(26,161)
(85)
6,883
(6,197)
(304)
(25,864)
share-based payment plans.
http://www.bp.com/downloads/changesinnetdebt
At 31 December
Gross debt
Less: Cash and cash equivalents
Less: Fair value asset of hedges related to finance debt
Net debt
Equity
Net debt ratio
An analysis of changes in net debt is provided below.
Movement in net debt
At 1 January
Exchange adjustments
Net cash flow
Movement in finance debt relating to investing activitiesb
Other movements
At 31 December
a Including fair value of associated derivative financial instruments.
b See Note 34 for further information.
230 BP Annual Report and Form 20-F 2011
Notes on financial statements http://www.bp.com/downloads/provisions
36. Provisions
At 1 January 2011
Exchange adjustments
Acquisitions
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Change in discount rate
Utilization
Reclassified as liabilities directly associated
with assets held for sale
Deletions
At 31 December 2011
Of which – current
– non-current
At 1 January 2010
Exchange adjustments
Acquisitions
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Change in discount rate
Utilization
Reclassified as liabilities directly associated
with assets held for sale
Deletions
At 31 December 2010
Of which – current
– non-current
Decommissioning Environmental Spill response
1,043
–
–
586
–
–
–
(1,293)
10,544
(27)
163
4,596
(1)
195
3,211
(342)
2,465
(4)
–
1,677
(140)
27
90
(840)
Litigation and
claims
11,967
(13)
9
3,821
(92)
15
45
(4,715)
Clean Water
Act penalties
3,510
–
–
–
–
–
–
–
(51)
(1,048)
17,240
596
16,644
–
(11)
3,264
1,375
1,889
–
–
336
282
54
–
(61)
10,976
8,518
2,458
–
–
3,510
–
3,510
Decommissioning
9,020
(114)
188
1,800
(12)
168
444
(164)
Environmental
1,719
–
–
1,290
(120)
29
22
(460)
Spill response
–
–
–
10,883
–
–
–
(9,840)
Litigation and
claims
1,076
(7)
2
15,171
(51)
18
9
(4,250)
Clean Water
Act penalties
–
–
–
3,510
–
–
–
–
(381)
(405)
10,544
432
10,112
(1)
(14)
2,465
635
1,830
–
–
1,043
982
61
–
(1)
11,967
7,011
4,956
–
–
3,510
–
3,510
$ million
Total
31,907
(56)
290
11,825
(649)
243
3,356
(8,066)
(51)
(1,157)
37,642
11,238
26,404
$ million
Total
14,630
(171)
205
33,462
(649)
234
469
(15,469)
(383)
(421)
31,907
9,489
22,418
Other
2,378
(12)
118
1,145
(416)
6
10
(876)
–
(37)
2,316
467
1,849
Other
2,815
(50)
15
808
(466)
19
(6)
(755)
(1)
(1)
2,378
429
1,949
The group makes full provision for the future cost of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis upon
installation. The provision for the costs of decommissioning these wells, production facilities and pipelines at the end of their economic lives has been
estimated using existing technology, at current prices or future assumptions, depending on the expected timing of the activity, and discounted using a real
discount rate of 0.5% (2010 1.5%). These costs are generally expected to be incurred over the next 30 years. While the provision is based on the best
estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty regarding both the amount and timing of these costs.
Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be estimated reliably.
Generally, this coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provision for
environmental liabilities has been estimated using existing technology, at current prices and discounted using a real discount rate of 0.5% (2010 1.5%).
The majority of these costs are expected to be incurred over the next 10 years. The extent and cost of future remediation programmes are inherently
difficult to estimate. They depend on the scale of any possible contamination, the timing and extent of corrective actions, and also the group’s share of
the liability.
The litigation category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures
of third parties to toxic substances. Included within the other category at 31 December 2011 are provisions for deferred employee compensation of
$666 million (2010 $728 million). These provisions are discounted using either a nominal discount rate of 2.5% (2010 3.75%) or a real discount rate of
0.5% (2010 1.5%), as appropriate.
Provisions relating to the Gulf of Mexico oil spill
The Gulf of Mexico oil spill is described on pages 76 to 79 and in Note 2. Provisions relating to the Gulf of Mexico oil spill, included in the table above, are
separately presented below:
At 1 January 2011
New or increased provisions
Unwinding of discount
Change in discount rate
Utilization
At 31 December 2011
Of which – current
– non-current
Of which – payable from the trust fund
Environmental Spill response
1,043
586
–
–
(1,293)
336
809
1,167
6
17
(482)
1,517
Litigation and
claims
10,973
3,430
–
–
(4,433)
9,970
Clean Water
Act penalties
3,510
–
–
–
–
3,510
961
556
1,066
282
54
–
8,194
1,776
8,809
–
3,510
–
$ million
Total
16,335
5,183
6
17
(6,208)
15,333
9,437
5,896
9,875
BP Annual Report and Form 20-F 2011 231
Financial statementsNotes on financial statements
http://www.bp.com/downloads/provisions
36. Provisions continued
At 1 January 2010
New or increased provisions
Unwinding of discount
Change in discount rate
Utilization
At 31 December 2010
Of which – current
– non-current
Of which – payable from the trust fund
Environmental
–
929
4
5
(129)
809
Spill response
–
10,883
–
–
(9,840)
1,043
Litigation and
claims
–
14,939
–
–
(3,966)
10,973
Clean Water
Act penalties
–
3,510
–
–
–
3,510
314
495
382
982
61
–
6,642
4,331
9,162
–
3,510
–
$ million
Total
–
30,261
4
5
(13,935)
16,335
7,938
8,397
9,544
As described in Note 2, BP has recorded provisions at 31 December 2011 relating to the Gulf of Mexico oil spill including amounts in relation to
environmental expenditure, spill response costs, litigation and claims, and Clean Water Act penalties, each of which is described below. The total amounts
that will ultimately be paid by BP are subject to significant uncertainty as described in Note 2.
Subsequent to BP releasing its preliminary announcement of the fourth quarter 2011 results on 7 February 2012, BP announced on 3 March 2012
that it had reached a proposed settlement with the Plaintiffs’ Steering Committee (PSC), subject to final written agreement and court approvals, to resolve
the substantial majority of legitimate economic loss and medical claims stemming from the Deepwater Horizon accident and oil spill. The proposed
settlement has been reflected in the financial statements for 2011 included in this report.
Certain items are subject to settlement discussions or may be subject to settlement discussions in the future. Any further settlements which may
be reached relating to the Deepwater Horizon accident and oil spill could impact the amount and timing of any future payments.
Environmental
The amounts committed by BP for a 10-year research programme to study the impact of the incident on the marine and shoreline environment of the
Gulf of Mexico have been provided for. BP’s commitment is to provide $500 million of funding, and the remaining commitment, on a discounted basis, of
$421 million was included in provisions at 31 December 2011. This amount is expected to be spent over the remaining life of the programme.
As a responsible party under the Oil Pollution Act of 1990 (OPA 90), BP faces claims by the United States, as well as by State, tribal, and foreign
trustees, if any, for natural resource damages (“Natural Resource Damages claims”). These damages include, among other things, the reasonable costs
of assessing the injury to natural resources as well as some emergency restoration projects which are expected to occur over the next two years. BP
has been incurring natural resource damage assessment costs and a provision has been made for the estimated costs of the assessment phase. The
assessment covers a large area of potential impact and will take some time to complete in order to determine both the severity and duration of the
impact of the oil spill. The process of interpreting the large volume of data collected is expected to take at least several months and, in order to determine
potential injuries to certain animal populations, data will need to be collected over one or more reproductive cycles. This expected assessment spend is
based upon past experience as well as identified projects. During 2011, BP entered a framework agreement with natural resource trustees for the United
States and five Gulf Coast states, providing for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from
the Gulf of Mexico oil spill. Funding for these projects will come from the $20-billion trust fund. The total amount provided for these items was $1,096
million at 31 December 2011. Until the size, location and duration of the impact is assessed, it is not possible to estimate reliably either the amounts
or timing of the remaining Natural Resource Damages claims other than the emergency and early restoration agreements noted above, therefore no
amounts have been provided for these items and they are disclosed as a contingent liability. See Note 43 for further information.
Spill response
Further amounts were provided relating to the spill response during 2011, totalling $0.6 billion. This primarily reflected increased costs of shoreline
clean-up, patrolling and maintenance and vessel decontamination. The majority of the active clean-up of the shorelines had been completed by the end of
the year.
Litigation and claims
Individual and Business Claims, and State and Local Claims under the Oil Pollution Act of 1990 (OPA 90) and claims for personal injury
BP faces claims under OPA 90 by individuals and businesses for removal costs, damage to real or personal property, lost profits or impairment of
earning capacity, loss of subsistence use of natural resources and for personal injury (“Individual and Business Claims”) and by state and local government
entities for removal costs, physical damage to real or personal property, loss of government revenue and increased public services costs
(“State and Local Claims”).
The estimated future cost of settling Individual and Business Claims, State and Local Claims under OPA 90 and claims for personal injuries, both
reported and unreported, has been provided for. Claims administration costs and legal fees have also been provided for.
Subsequent to BP releasing its preliminary announcement of the fourth quarter 2011 results on 7 February 2012, BP announced on 3 March
2012 that it had reached a proposed settlement with the PSC, subject to final written agreement and court approvals, to resolve the substantial majority
of legitimate economic loss and medical claims stemming from the Deepwater Horizon accident and oil spill. The details of the proposed settlement
agreement are explained in Legal proceedings on pages 160 to 164.
In 2010 and for the 2011 preliminary results, BP believed that the history of claims received, and settlements made, provided sufficient data to
enable the company to use an approach based on a combination of actuarial methods and management judgements to estimate IBNR (Incurred But Not
Reported) claims to determine a reliable best estimate of BP’s exposure for claims not yet reported in relation to Individual and Business claims, and State
and Local claims under OPA 90. The amount provided for these claims was determined in accordance with IFRS and represented BP’s best estimate of
the expenditure required to settle its obligations at the balance sheet date.
In estimating the amount of the provision, BP determined a range of possible outcomes for Individual and Business Claims, and State and Local
Claims. As disclosed in the preliminary announcement of the fourth quarter 2011 results, BP had concluded that a reasonable range of possible outcomes
for the amount of the provision as at 31 December 2011 was $4.1 billion to $8.3 billion. This range was for claims payable through the Gulf Coast Claims
Facility and State and Local Claims only.
232 BP Annual Report and Form 20-F 2011
Notes on financial statements 36. Provisions continued
Following the proposed settlement agreement entered into with the PSC, subject to final written agreement and court approvals, BP reviewed
the amount of the provision for the items covered by the proposed settlement based upon information available at the time that the consolidated financial
statements were approved. The provision for these items at 31 December 2011 is now $7.8 billion which represents a reliable best estimate of the
liability under the proposed settlement agreement which, under accounting standards, is the amount that BP would rationally pay to settle the obligation.
Substantially all of this amount is included as payable from the trust fund under Litigation and claims in the table above. Future claims administration
costs are expected to be paid from the trust fund. However, at this time, the provision for these costs is shown as payable from outside the trust fund,
consistent with how the administration costs associated with the GCCF were treated, as the proposed settlement is subject to final written agreement
and court approvals. Further information on the proposed settlement with the PSC is included in Legal proceedings on pages 160 to 164.
The provision is in addition to the $6.3 billion of claims paid in total ($2.9 billion in 2011 and $3.4 billion in 2010). Of this total paid, $6.1 billion is
included within utilization of provision in the table ($2.9 billion in 2011 and $3.2 billion in 2010), and the remaining $0.2 billion was a period expenditure
prior to the recognition of the provision at the end of the second quarter 2010. Also included within the utilization of the provision of $4.4 billion (2010 $4.0
billion) under Litigation and claims in the table are amounts relating to claims administration costs, legal fees and other settlements. Of the total payments
of $6.3 billion, $5.9 billion was paid out of the trust fund ($2.9 billion in 2011 and $3.0 billion in 2010) and $0.4 billion was paid by BP in 2010.
Many key assumptions underlie and influence the reliable best estimates of total expenditures derived for both categories of claims. The amount
provided for Individual and Business Claims is based upon the expected terms of the proposed settlement with the PSC, which is subject to final written
agreement and court approvals. Other key assumptions include the amounts that will ultimately be paid in relation to current claims, the number, type
and amounts for claims not yet reported, the outcomes of any further litigation through potential opt-outs from the proposed settlement and the amount
of administration and other costs associated with the proposed settlement. While BP has determined a reliable best estimate of the cost of the proposed
settlement with the PSC, it is possible that the actual cost could be higher or lower than this estimate.
The outcomes of claims and litigation are likely to be paid out over many years to come. BP will re-evaluate the assumptions underlying this
analysis on a quarterly basis as more information becomes available and the claims process matures.
BP also faces other litigation for which no reliable estimate of the cost can currently be made. Therefore no amounts have been provided for these
items. See Note 43 for further information.
Clean Water Act penalties
A provision has been made for the estimated penalties for strict liability under Section 311 of the Clean Water Act. Such penalties are subject to a
statutory maximum calculated as the product of a per-barrel maximum penalty rate and the number of barrels of oil spilled. Uncertainties currently exist in
relation to both the per-barrel penalty rate that will ultimately be imposed and the volume of oil spilled.
A charge for potential Clean Water Act Section 311 penalties was first included in BP’s second-quarter 2010 interim financial statements. At the
time that charge was taken, the latest estimate from the intra-agency Flow Rate Technical Group created by the National Incident Commander in charge
of the spill response was between 35,000 and 60,000 barrels per day. The mid-point of that range, 47,500 barrels per day, was used for the purposes
of calculating the charge. For the purposes of calculating the amount of the oil flow that was discharged into the Gulf of Mexico, the amount of oil that
had been or was projected to be captured in vessels on the surface was subtracted from the total estimated flow up until when the well was capped on
15 July 2010. The result of this calculation was an estimate that approximately 3.2 million barrels of oil had been discharged into the Gulf. This estimate
of 3.2 million barrels was calculated using a total flow of 47,500 barrels per day multiplied by the 85 days from 22 April 2010 through 15 July 2010 less an
estimate of the amount captured on the surface (then estimated at approximately 850,000 barrels).
This estimated discharge volume was then multiplied by $1,100 per barrel – the maximum amount the statute allows in the absence of gross
negligence or wilful misconduct – for the purposes of estimating a potential penalty. This resulted in a provision of $3,510 million for potential penalties
under Section 311.
In utilizing the $1,100 per-barrel input, BP took into account that the actual per-barrel penalty a court may impose, or that the Government might
agree to in settlement, could be lower than $1,100 per barrel if it were determined that such a lower penalty was appropriate based on the factors a court
is directed to consider in assessing a penalty. In particular, in determining the amount of a civil penalty, Section 311 directs a court to consider a number
of enumerated factors, including ”the seriousness of the violation or violations, the economic benefit to the violator, if any, resulting from the violation,
the degree of culpability involved, any other penalty for the same incident, any history of prior violations, the nature, extent, and degree of success of any
efforts of the violator to minimize or mitigate the effects of the discharge, the economic impact of the penalty on the violator, and any other matters as
justice may require.” Civil penalties above $1,100 per barrel up to a statutory maximum of $4,300 per barrel of oil discharged would only be imposed if
gross negligence or wilful misconduct were alleged and subsequently proven. BP expects to seek assessment of a penalty lower than $1,100 per barrel
based on several of these factors. However, the $1,100 per-barrel rate was utilized for the purposes of calculating a charge after considering and weighing
all possible outcomes and in light of: (i) BP’s conclusion that it did not act with gross negligence or engage in wilful misconduct; and (ii) the uncertainty as
to whether a court would assess a penalty below the $1,100 statutory maximum.
On 2 August 2010, the United States Department of Energy and the Flow Rate Technical Group had issued an estimate that 4.9 million barrels
of oil had flowed from the Macondo well, and 4.05 million barrels had been discharged into the Gulf (the difference being the amount of oil captured by
vessels on the surface as part of BP’s well containment efforts).
It was and remains BP’s view, that the 2 August 2010 Government estimate and other similar estimates are not reliable estimates because
they are based on incomplete or inaccurate information, rest in large part on assumptions that have not been validated, and are subject to far greater
uncertainties than have been acknowledged. As BP has publicly asserted, including at a 22 October 2010 meeting with the staff of the National
Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, BP believes that the 2 August 2010 discharge estimate and similar estimates are
overstated by a significant amount, and that the flow rate is potentially in the range of 20–50% lower. If the flow rate is 50% lower than the 2 August 2010
estimate, then the amount of oil that flowed from the Macondo well would be approximately 2.5 million barrels, and the amount discharged into the Gulf
would be approximately 1.6 million barrels. If the flow rate is 20% lower than the 2 August 2010 estimate, then the amount of oil that flowed from the
Macondo well would be approximately 3.9 million barrels and the amount discharged into the Gulf would be approximately 3.1 million barrels, which is not
materially different from the amount we used for our original estimate at the second quarter of 2010.
BP Annual Report and Form 20-F 2011 233
Financial statementsNotes on financial statements 36. Provisions continued
Therefore, for the purposes of calculating a provision for fines and penalties under Section 311 of the Clean Water Act, BP has continued to use an
estimate of 3.2 million barrels of oil discharged to the Gulf of Mexico as its current best estimate, as defined in paragraphs 36-40 of IAS 37 ‘Provisions,
contingent liabilities and contingent assets’, of the amount which may be used in calculating the penalty under Section 311 of the Clean Water Act.
This reflects an estimate of total flow from the well of approximately 4 million barrels, and an estimate of barrels captured by vessels on the surface,
currently estimated at 811,000 barrels. In utilizing this estimate, BP has taken into consideration not only its own analysis of the flow and discharge issue,
but also the analyses and conclusions of other parties, including the US government. The estimate of BP and of other parties as to how much oil was
discharged to the Gulf of Mexico may change, perhaps materially, over time. Changes in estimates as to flow and discharge could affect the amount
actually assessed for Clean Water Act fines and penalties. The year-end provision continued to be based on a per-barrel penalty of $1,100 for the reasons
discussed above, including BP’s continued conclusion that it did not act with gross negligence or engage in wilful misconduct.
The amount and timing of these costs will depend upon what is ultimately determined to be the volume of oil spilled and the per-barrel penalty
rate that is imposed. It is not currently practicable to estimate the timing of expending these costs and the provision has been included within non-current
liabilities on the balance sheet. No other amounts have been provided as at 31 December 2011 in relation to other potential fines and penalties because it
is not possible to measure the obligation reliably. Fines and penalties are not covered by the trust fund.
37. 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 plans) or defined benefit plans (final salary and other types of plans with
committed pension payments). For defined contribution plans, retirement benefits are determined by the value of funds arising from contributions paid in
respect of each employee. For defined benefit plans, retirement benefits are based on such factors as the employees’ pensionable salary and length of
service. Defined benefit plans may be externally funded or unfunded. The assets of funded plans are generally held in separately administered trusts.
In particular, the primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of
their benefit as an annuity. With effect from 1 April 2010, BP closed its UK plan to new joiners other than some of those joining the North Sea business.
The plan remains open to ongoing accrual for those employees who had joined BP on or before 31 March 2010. The majority of new joiners in the UK
have the option to join a defined contribution plan.
In the US, a range of retirement arrangements is provided. This includes a funded final salary pension plan for certain heritage employees and a
cash balance arrangement for new hires. Retired US employees typically take their pension benefit in the form of a lump sum payment. US employees are
also eligible to participate in a defined contribution (401k) plan in which employee contributions are matched with company contributions.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall
due. During 2011, contributions of $429 million (2010 $411 million and 2009 $9 million) and $777 million (2010 $694 million and 2009 $795 million) were
made to the UK plans and US plans respectively. In addition, contributions of $223 million (2010 $188 million and 2009 $204 million) were made to other
funded defined benefit plans. The aggregate level of contributions in 2012 is expected to be approximately $1,250 million, and includes contributions in all
countries that we expect to be required to make by law or under contractual agreements as well as an allowance for discretionary funding.
Certain group companies, principally in the US, provide post-retirement healthcare and life insurance benefits to their retired employees and
dependants. The entitlement to these benefits is usually based on the employee remaining in service until retirement age and completion of a minimum
period of service.
The obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The
date of the most recent actuarial review was 31 December 2011. The group’s principal plans are subject to a formal actuarial valuation every three years in
the UK, with valuations being required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension plans was as
at 31 December 2008.
The material financial assumptions used for estimating the benefit obligations of the various plans are set out below. The assumptions are reviewed by
management at the end of each year, and are used to evaluate accrued pension and other post-retirement benefits at 31 December. The same assumptions
are used to determine pension and other post-retirement benefit expense for the following year, that is, the assumptions at 31 December 2011 are used to
determine the pension liabilities at that date and the pension expense for 2012.
Financial assumptions
Discount rate for pension
plan liabilities
Discount rate for other
post-retirement benefit plans
Rate of increase in salaries
Rate of increase for pensions
in payment
Rate of increase in deferred
pensions
Inflation
2011
2010
4.8
n/a
5.1
3.2
3.2
3.2
5.5
n/a
5.4
3.5
3.5
3.5
UK
2009
5.8
n/a
5.3
3.4
3.4
3.4
2011
2010
4.3
4.5
3.7
–
–
1.9
4.7
5.3
4.1
–
–
2.3
US
2009
5.4
5.8
4.2
–
–
2.4
2011
2010
4.7
n/a
3.7
1.7
1.2
2.2
5.3
n/a
3.8
1.8
1.3
2.3
%
Other
2009
5.8
n/a
3.8
1.8
1.2
2.3
Our discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and Germany we use yields
that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference
between the yields on index-linked and fixed-interest long-term government bonds. In other countries we use either this approach, or the central bank
inflation target, or advice from the local actuary depending on the information that is available to us. The inflation rate assumptions are used to determine
the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.
234 BP Annual Report and Form 20-F 2011
Notes on financial statements
37. Pensions and other post-retirement benefits continued
Our assumptions for the rate of increase in salaries are based on our inflation rate assumption plus an allowance for expected long-term real salary
growth. These include allowance for promotion-related salary growth, of between 0.3% and 0.4% depending on country.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best
practice in the countries in which we provide pensions, and have been chosen with regard to the latest available published tables adjusted where appropri-
ate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension liabilities are
in the UK, the US and Germany where our mortality assumptions are as follows:
Mortality assumptions
Life expectancy at age 60 for a
male currently aged 60
Life expectancy at age 60 for a
male currently aged 40
Life expectancy at age 60 for a
female currently aged 60
Life expectancy at age 60 for a
female currently aged 40
2011
2010
27.6
30.5
29.3
32.0
26.1
29.1
28.7
31.6
UK
2009
26.0
29.0
28.6
31.5
2011
2010
24.8
26.3
26.4
27.3
24.7
26.2
26.3
27.2
US
2009
24.6
26.1
26.3
27.2
2011
2010
23.5
26.3
28.0
30.7
23.3
26.2
27.9
30.6
Years
Germany
2009
23.2
26.1
27.8
30.4
Our assumption for future US healthcare cost trend rate for the first year after the reporting date reflects the rate of actual cost increases seen in recent
years. The ultimate trend rate reflects our long-term expectations of the level at which cost inflation will stabilize based on past healthcare cost inflation
seen over a longer period of time. The assumed future US healthcare cost trend rate assumptions are as follows:
First year’s US healthcare cost trend rate
Ultimate US healthcare cost trend rate
Year in which ultimate trend rate is reached
2011
7.6
5.0
2020
2010
7.8
5.0
2018
%
2009
8.0
5.0
2016
Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligations of
the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in
portfolio management.
A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term with an acceptable level of
risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment
portfolios are highly diversified. The long-term asset allocation policy for the major plans is as follows:
Asset category
Total equity
Bonds/cash
Property/real estate
UK
%
73
20
7
US
%
70
30
–
Other
%
17-63
25-75
0-10
Some of the group’s pension plans use derivative financial instruments as part of their asset mix and to manage the level of risk. The group’s main pen-
sion plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.
Return on asset assumptions reflect the group’s expectations built up by asset class and by plan. The group’s expectation is derived from
a combination of historical returns over the long term and the forecasts of market professionals. Our assumption for return on equities is based on a
long-term view, and the size of the resulting equity risk premium over government bond yields is reviewed each year for reasonableness. Our assumption
for return on bonds reflects the portfolio mix of government fixed-interest, index-linked and corporate bonds.
BP Annual Report and Form 20-F 2011 235
Financial statementsNotes on financial statements 37. Pensions and other post-retirement benefits continued
The expected long-term rates of return and market values of the various categories of assets held by the defined benefit plans at 31 December are set
out below. The market values shown include the effects of derivative financial instruments. The amounts classified as equities include investments in
companies listed on stock exchanges as well as unlisted investments. Movements in the value of plan assets during the year are shown in detail in the
table on page 238.
UK pension plans
Equitiesa
Bonds
Property/real estate
Cash
US pension plans
Equitiesa
Bonds
Property/real estate
Cash
US other post-retirement benefit plans
Equities
Bonds
Cash
Other plans
Equities
Bonds
Property/real estate
Cash
2011
2010
2009
Expected
long-term
rate of
return
%
8.0
4.4
6.5
1.7
7.0
9.0
4.0
8.0
0.2
7.4
–
–
0.2
0.2
7.9
3.3
6.2
2.2
4.7
Expected
long-term
rate of
return
%
8.0
5.0
6.5
1.4
7.2
9.1
4.5
8.0
0.3
8.0
–
–
0.3
0.3
8.0
4.2
6.3
2.7
5.4
Expected
long-term
rate of
return
%
8.0
5.3
6.5
1.1
7.3
9.0
4.8
8.0
0.9
8.0
8.5
4.8
–
7.6
8.6
4.4
6.5
2.0
5.9
Market
value
$ million
18,546
3,866
1,462
406
24,280
5,058
1,419
7
165
6,649
–
–
8
8
1,182
1,874
83
155
3,294
Market
value
$ million
17,202
4,141
1,710
534
23,587
5,034
2,022
4
144
7,204
–
–
4
4
831
1,951
117
387
3,286
Market
value
$ million
16,945
3,701
1,269
634
22,549
4,326
1,218
8
271
5,823
8
4
–
12
1,091
1,651
82
245
3,069
a The amounts classified as equities include investments in companies listed on stock exchanges as well as private equity investments which are substantially all unlisted. The market value of private equity
investments at 31 December 2011 was $4,099 million (2010 $3,348 million and 2009 $2,956 million). The equity return assumption shown above is the weighted average of the assumed returns for listed
and private equity investments in each fund. Comparative return assumptions for the US pension plans’ equities have been restated to reflect this. Equity return assumptions previously disclosed reflected
the assumption for listed equities only.
236 BP Annual Report and Form 20-F 2011
Notes on financial statements 37. Pensions and other post-retirement benefits continued
The assumed rate of investment return, discount rate, inflation, US healthcare cost trend rate and the mortality assumptions all have a significant effect on
the amounts reported.
A one-percentage point change in the following assumptions for the group’s plans would have had the effects shown in the table below. The
effects shown for the expense in 2012 include current service cost and interest on plan liabilities.
Investment return
Effect on pension and other post-retirement benefit expense in 2012
Discount rate
Effect on pension and other post-retirement benefit expense in 2012
Effect on pension and other post-retirement benefit obligation at 31 December 2011
Inflation rate
Effect on pension and other post-retirement benefit expense in 2012
Effect on pension and other post-retirement benefit obligation at 31 December 2011
US healthcare cost trend rate
Effect on US other post-retirement benefit expense in 2012
Effect on US other post-retirement obligation at 31 December 2011
$ million
One percentage point
Decrease
Increase
(351)
351
(78)
(5,585)
494
5,323
27
350
101
7,285
(381)
(4,301)
(22)
(290)
One additional year of longevity in the mortality assumptions would have the effects shown in the table below. The effect shown for the expense in 2012
includes current service cost and interest on plan liabilities.
One additional year’s longevity
Effect on pension and other post-retirement benefit expense in 2012
Effect on pension and other post-retirement benefit obligation at 31 December 2011
UK
pension
plans
44
609
US
pension
plans
US other post-
retirement
benefit
plans
5
111
4
73
$ million
German
pension
plans
9
166
BP Annual Report and Form 20-F 2011 237
Financial statementsNotes on financial statements 37. Pensions and other post-retirement benefits continued
UK
pension
plans
US
pension
plans
US other post-
retirement
benefit
plans
Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service cost
Settlement, curtailment and special termination benefits
Payments to defined contribution plans
Total operating chargeb
Analysis of the amount credited (charged) to other finance expense
Expected return on plan assets
Interest on plan liabilities
Other finance income (expense)
Analysis of the amount recognized in other comprehensive income
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial (loss) gain recognized in other comprehensive income
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Current service costa
Past service cost
Interest cost
Curtailment
Settlement
Special termination benefitsc
Contributions by plan participantsd
Benefit payments (funded plans)e
Benefit payments (unfunded plans)e
Disposals
Actuarial loss (gain) on obligation
Benefit obligation at 31 Decembera f
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Expected return on plan assetsa g
Contributions by plan participantsd
Contributions by employers (funded plans)
Benefit payments (funded plans)e
Disposals
Actuarial gain (loss) on plan assetsg
Fair value of plan assets at 31 December
Deficit at 31 December
Represented by
Asset recognized
Liability recognized
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded
plans as follows
Funded
Unfunded
383
–
3
5
391
1,799
(1,263)
536
(1,990)
(2,680)
(84)
(4,754)
22,363
(137)
383
–
1,263
–
–
3
33
(993)
(4)
–
2,764
25,675
24,280
29
1,799
33
429
(993)
–
(1,990)
23,587
(2,088)
–
(2,088)
(2,088)
(1,852)
(236)
(2,088)
(25,439)
(236)
(25,675)
280
184
–
199
663
518
(369)
149
10
(512)
(102)
(604)
7,988
–
280
184
369
–
–
–
–
(750)
(68)
–
614
8,617
6,649
–
518
–
777
(750)
–
10
7,204
(1,413)
–
(1,413)
(1,413)
(784)
(629)
(1,413)
(7,988)
(629)
(8,617)
$ million
2011
Total
849
191
43
245
1,328
2,502
(2,239)
263
(2,042)
(3,795)
(123)
(5,960)
41,912
(463)
849
191
2,239
(1)
4
40
43
(1,972)
(658)
(20)
3,918
46,082
34,231
(94)
2,502
43
1,429
(1,972)
(16)
(2,042)
34,081
(12,001)
17
(12,018)
(12,001)
(3,169)
(8,832)
(12,001)
Other
plans
133
7
40
41
221
185
(444)
(259)
(61)
(642)
(26)
(729)
8,404
(326)
133
7
444
(1)
4
37
10
(226)
(405)
(20)
668
8,729
3,294
(123)
185
10
223
(226)
(16)
(61)
3,286
(5,443)
17
(5,460)
(5,443)
(492)
(4,951)
(5,443)
53
–
–
–
53
–
(163)
(163)
(1)
39
89
127
3,157
–
53
–
163
–
–
–
–
(3)
(181)
–
(128)
3,061
8
–
–
–
–
(3)
–
(1)
4
(3,057)
–
(3,057)
(3,057)
(41)
(3,016)
(3,057)
(45)
(3,016)
(3,061)
(3,778)
(4,951)
(8,729)
(37,250)
(8,832)
(46,082)
a The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pension plan benefits are generally included in current service cost and the
costs of administering our other post-retirement benefit plans are included in the benefit obligation.
b Included within production and manufacturing expenses and distribution and administration expenses.
c The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
d Most of the contributions made by plan participants after 1 January 2010 into UK pension plans were made under salary sacrifice arrangements.
e The benefit payments amount shown above comprises $2,576 million benefits plus $54 million of plan expenses incurred in the administration of the benefit.
f The benefit obligation for other plans includes $3,909 million for the German plan, which is largely unfunded.
g 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.
238 BP Annual Report and Form 20-F 2011
Notes on financial statements 37. Pensions and other post-retirement benefits continued
Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service cost
Settlement, curtailment and special termination benefits
Payments to defined contribution plans
Total operating chargeb
Analysis of the amount credited (charged) to other finance expense
Expected return on plan assets
Interest on plan liabilities
Other finance income (expense)
Analysis of the amount recognized in other comprehensive income
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial (loss) gain recognized in other comprehensive income
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Current service costa
Past service cost
Interest cost
Curtailment
Settlement
Special termination benefitsc
Contributions by plan participantsd
Benefit payments (funded plans)e
Benefit payments (unfunded plans)e
Acquisitions
Disposals
Actuarial (gain) loss on obligation
Benefit obligation at 31 Decembera f
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Expected return on plan assetsa g
Contributions by plan participantsd
Contributions by employers (funded plans)
Benefit payments (funded plans)e
Acquisitions
Disposals
Actuarial gain (loss) on plan assetsg
Fair value of plan assets at 31 December
Surplus (deficit) at 31 December
Represented by
Asset recognized
Liability recognized
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded
plans as follows
Funded
Unfunded
UK
pension
plans
393
–
24
1
418
1,580
(1,183)
397
1,577
(1,144)
12
445
21,425
(835)
393
–
1,183
–
11
13
39
(952)
(3)
–
(43)
1,132
22,363
22,549
(881)
1,580
39
411
(952)
–
(43)
1,577
24,280
1,917
2,120
(203)
1,917
2,115
(198)
1,917
(22,165)
(198)
(22,363)
US
pension
plans
US other post-
retirement
benefit
plans
241
–
–
187
428
465
(396)
69
425
(498)
(167)
(240)
7,519
–
241
–
396
–
–
–
–
(758)
(75)
–
–
665
7,988
5,823
–
465
–
694
(758)
–
–
425
6,649
(1,339)
–
(1,339)
(1,339)
(838)
(501)
(1,339)
(7,487)
(501)
(7,988)
48
–
–
–
48
1
(169)
(168)
(1)
(132)
(8)
(141)
2,996
–
48
–
169
–
–
–
–
(4)
(192)
–
–
140
3,157
12
–
1
–
–
(4)
–
–
(1)
8
(3,149)
–
(3,149)
(3,149)
(39)
(3,110)
(3,149)
(47)
(3,110)
(3,157)
$ million
2010
Total
802
3
185
223
1,213
2,224
(2,177)
47
2,037
(2,263)
(94)
(320)
40,073
(1,104)
802
3
2,177
4
29
152
52
(1,906)
(657)
2
(72)
2,357
41,912
31,453
(852)
2,224
52
1,292
(1,906)
2
(71)
2,037
34,231
(7,681)
2,176
(9,857)
(7,681)
1,015
(8,696)
(7,681)
Other
plans
120
3
161
35
319
178
(429)
(251)
36
(489)
69
(384)
8,133
(269)
120
3
429
4
18
139
13
(192)
(387)
2
(29)
420
8,404
3,069
29
178
13
187
(192)
2
(28)
36
3,294
(5,110)
56
(5,166)
(5,110)
(223)
(4,887)
(5,110)
(3,517)
(4,887)
(8,404)
(33,216)
(8,696)
(41,912)
a The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pension plan benefits are generally included in current service cost and the
costs of administering our other post-retirement benefit plans are included in the benefit obligation.
b Included within production and manufacturing expenses and distribution and administration expenses.
c The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
d Most of the contributions made by plan participants after 1 January 2010 into UK pension plans were made under salary sacrifice arrangements.
e The benefit payments amount shown above comprises $2,507 million benefits plus $56 million of plan expenses incurred in the administration of the benefit.
f The benefit obligation for other plans includes $3,871 million for the German plan, which is largely unfunded.
g 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.
BP Annual Report and Form 20-F 2011 239
Financial statementsNotes on financial statements 37. Pensions and other post-retirement benefits continued
Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service cost
Settlement, curtailment and special termination benefits
Payments to defined contribution plans
Total operating chargeb
Analysis of the amount credited (charged) to other finance expense
Expected return on plan assets
Interest on plan liabilities
Other finance income (expense)
Analysis of the amount recognized in other comprehensive income
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial (loss) gain recognized in other comprehensive income
UK
pension
plans
311
–
37
–
348
1,426
(1,112)
314
1,761
(2,217)
(141)
(597)
US
pension
plans
US other post-
retirement
benefit
plans
243
–
–
205
448
405
(456)
(51)
617
(501)
(229)
(113)
48
(22)
–
–
26
1
(183)
(182)
2
(50)
71
23
$ million
2009
Total
719
(21)
90
233
1,021
1,979
(2,171)
(192)
2,549
(2,810)
(421)
(682)
Other
plans
117
1
53
28
199
147
(420)
(273)
169
(42)
(122)
5
a The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pension plan benefits are generally included in current service cost and the
costs of administering our other post-retirement benefit plans are included in the benefit obligation.
b Included within production and manufacturing expenses and distribution and administration expenses.
At 31 December 2011, reimbursement balances due from or to other companies in respect of pensions amounted to $546 million reimbursement assets
(2010 $483 million) and $13 million reimbursement liabilities (2010 $13 million). These balances are not included as part of the pension surpluses and
deficits, but are reflected within other receivables and other payables in the group balance sheet.
History of surplus (deficit) and of experience gains and losses
Benefit obligation at 31 December
Fair value of plan assets at 31 December
Deficit
Experience losses on plan liabilities
Actual return less expected return on pension plan assets
Actual return on plan assets
Actuarial (loss) gain recognized in other comprehensive income
Cumulative amount recognized in other comprehensive income
2011
2010
2009
2008
46,082
34,081
(12,001)
(123)
(2,042)
460
(5,960)
(9,902)
41,912
34,231
(7,681)
(94)
2,037
4,261
(320)
(3,942)
40,073
31,453
(8,620)
(421)
2,549
4,528
(682)
(3,622)
34,847
26,154
(8,693)
(178)
(10,253)
(7,331)
(8,430)
(2,940)
Estimated future benefit payments
The expected benefit payments, which reflect expected future service as appropriate, but exclude plan expenses, up until 2021 are as follows:
2012
2013
2014
2015
2016
2017-2021
UK
pension
plans
998
1,031
1,068
1,109
1,154
6,476
US
pension
plans
743
756
766
778
776
3,721
US other post-
retirement
benefit
plans
181
183
186
188
190
955
Other
plans
619
588
592
583
567
2,728
$ million
2007
43,100
42,799
(301)
(200)
302
3,157
1,717
5,490
$ million
Total
2,541
2,558
2,612
2,658
2,687
13,880
240 BP Annual Report and Form 20-F 2011
Notes on financial statements 38. Called-up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share plansb
At 31 December
Shares
thousand
7,233
5,473
20,647,160
165,601
649
20,813,410
2011
$ million
12
9
21
Shares
thousand
7,233
5,473
2010
$ million
12
9
21
Shares
thousand
7,233
5,473
5,162 20,629,665
–
17,495
41
–
5,203 20,647,160
5,224
5,158 20,618,458
–
11,207
–
4
5,162 20,629,665
5,183
2009
$ million
12
9
21
5,155
–
3
5,158
5,179
a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference
shares.
b The nominal value of new shares issued for the employee share plans in 2011 amounted to $162,000. Consideration received relating to the issue of new shares for employee share plans amounted to
$4 million (2010 $138 million and 2009 $84 million).
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every
£5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other
resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference
shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference
shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.
Treasury shares
At 1 January
Shares gifted to ESOPs
Shares transferred to ESOPs at market price
Shares re-issued for employee share plans
At 31 December
Shares
thousand
1,850,699
–
–
(13,191)
1,837,508
2011
Nominal value
$ million
462
–
–
(3)
459
Shares
thousand
1,869,777
–
(7,125)
(11,953)
1,850,699
2010
Nominal value
$ million
467
–
(2)
(3)
462
Shares
thousand
1,888,151
(1,265)
–
(17,109)
1,869,777
2009
Nominal value
$ million
472
(1)
–
(4)
467
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury during the year, representing 9.0% (2010
9.1% and 2009 9.2%) of the called-up ordinary share capital of the company.
During 2011, the movement in treasury shares represented less than 0.1% (2010 less than 0.1% and 2009 less than 0.1%) of the ordinary share
capital of the company.
BP Annual Report and Form 20-F 2011 241
Financial statementsNotes on financial statements 39. Capital and reserves
At 1 January 2011
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of equity-accounted entities’ other comprehensive income, net of tax
Profit for the year
Total comprehensive income
Dividends
Share-based paymentsa
Transactions involving minority interests
At 31 December 2011
At 1 January 2010
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Profit (loss) for the year
Total comprehensive income
Dividends
Share-based paymentsa
Transactions involving minority interests
At 31 December 2010
At 1 January 2009
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Profit for the year
Total comprehensive income
Dividends
Share-based paymentsa
Changes in associates’ equity
Transactions involving minority interests
At 31 December 2009
Share
capital
5,183
Share
premium
account
9,987
Capital
redemption
reserve
1,072
Total
share capital
and capital
reserves
43,448
Merger
reserve
27,206
–
–
–
–
–
–
–
41
–
–
5,224
5,179
–
–
–
–
–
–
–
4
–
5,183
5,176
–
–
–
–
–
–
–
3
–
–
5,179
–
–
–
–
–
–
–
(41)
6
–
9,952
9,847
–
–
–
–
–
–
–
140
–
9,987
9,763
–
–
–
–
–
–
–
84
–
–
9,847
–
–
–
–
–
–
–
–
–
–
1,072
1,072
–
–
–
–
–
–
–
–
–
1,072
1,072
–
–
–
–
–
–
–
–
–
–
1,072
–
–
–
–
–
–
–
–
–
–
27,206
27,206
–
–
–
–
–
–
–
–
–
27,206
27,206
–
–
–
–
–
–
–
–
–
–
27,206
–
–
–
–
–
–
–
–
6
–
43,454
43,304
–
–
–
–
–
–
–
144
–
43,448
43,217
–
–
–
–
–
–
–
87
–
–
43,304
a Includes new share issues and movements in own shares and treasury shares where these relate to employee share-based payment plans.
Total own
shares and
Foreign
currency
Available-
Own
shares
Treasury
shares
treasury
translation
for-sale
Cash flow
shares
investments
hedges
(126)
(21,085)
(21,211)
reserve
4,937
(515)
Share-
based
payment
reserve
1,586
Total
fair value
reserves
469
(1)
–
(74)
(127)
463
(74)
6
(1)
(127)
BP
shareholders’
Minority
interest
(262)
150
(112)
(4)
(515)
(74)
(128)
(202)
(245)
(4,317)
(388)
(20,935)
(21,323)
4,422
389
(122)
267
1,582
83,063
111,465
1,017
112,482
(214)
(21,303)
(21,517)
754
22
776
1,584
72,655
101,613
500
102,113
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
4,811
126
126
(291)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(291)
63
(2)
693
–
–
–
–
–
–
–
2
–
–
–
–
–
–
6
–
–
–
–
–
–
–
(18)
(16)
(866)
(37)
925
888
–
–
–
–
–
2
–
–
–
–
–
–
–
–
–
–
–
(291)
(18)
(307)
(803)
(39)
693
925
Profit
and loss
account
65,758
(4,321)
–
–
–
(57)
25,700
21,322
(4,072)
102
(47)
(418)
–
–
–
(3,719)
(4,137)
(2,627)
(113)
(20)
(478)
–
–
–
16,578
16,100
23
(43)
(22)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
2
–
–
–
–
–
–
–
–
–
–
equity
94,987
(516)
(4,321)
(74)
(127)
(57)
25,700
20,605
(4,072)
(8)
(47)
128
(418)
(291)
(18)
(3,719)
(4,318)
(2,627)
339
(20)
91,303
2,419
(478)
693
925
16,578
20,137
721
(43)
(22)
$ million
Total
equity
95,891
(526)
(4,324)
(74)
(127)
(57)
26,097
20,989
(8)
(73)
131
(418)
(291)
(18)
(3,324)
(3,920)
(2,942)
339
301
95,891
92,109
2,363
(478)
693
925
16,759
20,262
721
(43)
(37)
904
(10)
(3)
–
–
–
397
384
–
(26)
3
–
–
–
395
398
(315)
–
321
904
806
(56)
181
125
–
–
–
–
–
(15)
88
218
306
(126)
(21,085)
(21,211)
4,937
463
469
1,586
65,758
94,987
(326)
(21,513)
(21,839)
2,353
2,458
1,295
67,080
112
210
322
289
2,458
691
1,579
(10,483)
(10,483)
(416)
(10,899)
(214)
(21,303)
(21,517)
4,811
754
22
776
1,584
72,655
101,613
500
102,113
242 BP Annual Report and Form 20-F 2011
242 BP Annual Report and Form 20-F 2011
Notes on financial statements At 1 January 2010
5,179
9,847
1,072
27,206
43,304
39. Capital and reserves
At 1 January 2011
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of equity-accounted entities’ other comprehensive income, net of tax
Profit for the year
Total comprehensive income
Dividends
Share-based paymentsa
Transactions involving minority interests
At 31 December 2011
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Profit (loss) for the year
Total comprehensive income
Dividends
Share-based paymentsa
Transactions involving minority interests
At 31 December 2010
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Profit for the year
Total comprehensive income
Dividends
Share-based paymentsa
Changes in associates’ equity
Transactions involving minority interests
At 31 December 2009
a Includes new share issues and movements in own shares and treasury shares where these relate to employee share-based payment plans.
Share
capital
5,183
Share
premium
account
9,987
Capital
redemption
reserve
1,072
Total
share capital
and capital
reserves
43,448
Merger
reserve
27,206
Own
shares
(126)
Treasury
shares
(21,085)
Total own
shares and
treasury
shares
(21,211)
Foreign
currency
translation
reserve
4,937
Available-
for-sale
investments
463
Cash flow
hedges
6
Total
fair value
reserves
469
Share-
based
payment
reserve
1,586
41
(41)
5,224
9,952
1,072
27,206
43,454
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
4
–
–
–
–
–
–
–
–
3
–
–
–
–
–
–
–
–
–
6
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
6
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
140
144
5,183
9,987
1,072
27,206
43,448
84
87
5,179
9,847
1,072
27,206
43,304
–
–
–
–
–
–
–
–
(262)
–
(388)
(214)
–
–
–
–
–
–
–
88
–
(126)
(326)
–
–
–
–
–
–
–
112
–
–
(214)
–
–
–
–
–
–
–
–
150
–
(20,935)
(21,303)
–
–
–
–
–
–
–
218
–
(21,085)
(21,513)
–
–
–
–
–
–
–
210
–
–
(21,303)
–
–
–
–
–
–
–
–
(112)
–
(21,323)
(21,517)
–
–
–
–
–
–
–
306
–
(21,211)
(21,839)
–
–
–
–
–
–
–
322
–
–
(21,517)
(515)
–
–
–
–
–
(515)
–
–
–
4,422
4,811
126
–
–
–
–
126
–
–
–
4,937
2,353
2,458
–
–
–
–
2,458
–
–
–
–
4,811
–
–
(74)
–
–
–
(74)
–
–
–
389
754
–
–
(291)
–
–
(291)
–
–
–
463
63
(2)
–
693
–
–
691
–
–
–
–
754
(1)
–
–
(127)
–
–
(128)
–
–
–
(122)
22
2
–
–
(18)
–
(16)
–
–
–
6
(866)
(37)
–
–
925
–
888
–
–
–
–
22
(1)
–
(74)
(127)
–
–
(202)
–
–
–
267
776
2
–
(291)
(18)
–
(307)
–
–
–
469
(803)
(39)
–
693
925
–
1,579
–
–
–
–
776
–
–
–
–
–
–
–
–
(4)
–
1,582
1,584
–
–
–
–
–
–
–
2
–
1,586
1,295
–
–
–
–
–
–
–
289
–
–
1,584
Profit
and loss
account
65,758
–
(4,321)
–
–
(57)
25,700
21,322
(4,072)
102
(47)
83,063
72,655
–
(418)
–
–
(3,719)
(4,137)
(2,627)
(113)
(20)
65,758
67,080
–
(478)
–
–
16,578
16,100
(10,483)
23
(43)
(22)
72,655
At 1 January 2009
5,176
9,763
1,072
27,206
43,217
BP
shareholders’
equity
94,987
Minority
interest
904
$ million
Total
equity
95,891
(526)
(4,324)
(74)
(127)
(57)
26,097
(10)
(3)
–
–
–
397
384
(245)
–
(26)
1,017
20,989
(4,317)
(8)
(73)
112,482
500
3
–
–
–
395
398
(315)
–
321
904
806
(56)
–
–
–
181
125
(416)
–
–
(15)
500
102,113
131
(418)
(291)
(18)
(3,324)
(3,920)
(2,942)
339
301
95,891
92,109
2,363
(478)
693
925
16,759
20,262
(10,899)
721
(43)
(37)
102,113
(516)
(4,321)
(74)
(127)
(57)
25,700
20,605
(4,072)
(8)
(47)
111,465
101,613
128
(418)
(291)
(18)
(3,719)
(4,318)
(2,627)
339
(20)
94,987
91,303
2,419
(478)
693
925
16,578
20,137
(10,483)
721
(43)
(22)
101,613
BP Annual Report and Form 20-F 2011 243
Financial statementsNotes on financial statements 39. 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.
Own shares
Own shares represent BP shares held in Employee Share Ownership Plan Trusts (ESOPs) to meet the future requirements of the employee share-based
payment plans, as discussed in Note 40. At 31 December 2011, a further 21,420,000 ordinary share equivalents were held by the group in the form of
ADSs to meet the requirements of employee share-based payment plans in the US.
Treasury shares
Treasury shares represent BP shares repurchased and available for re-issue.
Foreign currency translation reserve
The foreign currency translation reserve is used to record exchange differences arising from the translation of the financial statements of foreign
operations. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement. This reserve is also
used to record the effect of hedging net investments in foreign operations.
Available-for-sale investments
This reserve records the changes in fair value of available-for-sale investments. On disposal or impairment, the cumulative changes in fair value are
recycled to the income statement.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. When the
hedged transaction occurs, the gain or loss on the hedging instrument is transferred out of equity to either profit or loss or the carrying value of assets, as
appropriate. If the forecast transaction is no longer expected to occur the gain or loss recognized in equity is transferred to profit or loss.
Share-based payment reserve
This reserve represents cumulative amounts charged to profit in respect of employee share-based payment plans where the scheme has not yet been
settled by means of an award of shares to an individual.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
244 BP Annual Report and Form 20-F 2011
244 BP Annual Report and Form 20-F 2011
Notes on financial statements 39. Capital and reserves continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of equity-accounted entities’ other comprehensive income
Other comprehensive income
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Other comprehensive income
Currency translation differences (including recycling)
Actuarial loss relating to pensions and other post-retirement benefits
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Other comprehensive income
$ million
2011
Net of tax
(526)
(4,324)
(74)
(127)
(57)
(5,108)
$ million
2010
Net of tax
131
(418)
(291)
(18)
(596)
$ million
2009
Net of tax
2,363
(478)
693
925
3,503
Tax
(14)
1,636
–
37
–
1,659
Tax
(108)
(98)
50
19
(137)
Tax
564
204
(14)
(229)
525
Pre-tax
(512)
(5,960)
(74)
(164)
(57)
(6,767)
Pre-tax
239
(320)
(341)
(37)
(459)
Pre-tax
1,799
(682)
707
1,154
2,978
BP Annual Report and Form 20-F 2011 245
Financial statementsNotes on financial statements 40. Share-based payments
Effect of share-based payment transactions on the group’s result and financial position
Total expense recognized for equity-settled share-based payment transactions
Total expense (credit) recognized for cash-settled share-based payment transactions
Total expense recognized for share-based payment transactions
Closing balance of liability for cash-settled share-based payment transactions
Total intrinsic value for vested cash-settled share-based payments
2011
579
5
584
12
1
2010
577
(1)
576
16
1
$million
2009
506
15
521
32
7
For ease of presentation, options and shares 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 main
share-based payment plans that existed during the year are detailed below.
Plans for executive directors
For further information on the Executive Directors’ Incentive Plan (EDIP) see the Directors’ remuneration report on pages 139 to 151.
Plans for senior employees
The group operates a number of equity-settled share plans under which share units are granted to its senior leaders and certain other employees. These
plans typically have a three-year performance or restricted period during which the units accrue net notional dividends which are treated as having been
reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for
qualifying reasons. Grants are settled in cash where the regulatory environment prohibits participants to hold BP shares.
Performance unit plans
The number of units granted is related to the level of seniority of employees. The number of units converted to shares is determined by reference to
performance measures over the three-year performance period. The main performance measure used is BP’s total shareholder return (TSR) compared to
the other oil majors. Plans included in this category are the Competitive Performance Plan (CPP) and, in part, the Performance Share Plan (PSP).
Restricted share unit plans
Share unit grants under BP’s restricted plans typically take into account the employee’s performance in either the current or the prior year, track record
of delivery, business and leadership skills and potential. One restricted share unit plan for senior employees, used in special circumstances such as
recruitment and retention, normally has no performance conditions. Plans included in this category are the Executive Performance Plan (EPP), the
Restricted Share Plan (RSP), the Deferred Annual Bonus Plan (DAB) and, in part, the Performance Share Plan (PSP).
BP Share Option Plan (BPSOP)
Share options with an exercise price equivalent to the market price of a BP share immediately preceding the date of grant were granted to participants annually
until 2006. These options are not subject to any performance conditions and are exercisable between the third and tenth anniversaries of the grant date.
BP Plan 2011
Share options with an exercise price equivalent to the market price of a BP share immediately preceding the date of grant were granted to participants in
2011. These options are not subject to any performance conditions and will be exercisable between the third and tenth anniversaries of the grant date.
Share Value Plan
In 2012, the group will launch a new performance plan known as the Share Value Plan (SVP) which will grant restricted share units with a three-year
performance period. The number of units granted is dependent on grade and country of operation. The performance measures are grade specific and
include individual rating, balanced scorecard and TSR criteria. For the 2012 performance year, no further grants will be made under DAB; and from
1 January 2012, no further grants will be made under CPP, EPP or PSP.
Other plans
For further information on BP’s savings and matching plans, including the BP ShareMatch plans and the BP ShareSave Plan, see page 158.
246 BP Annual Report and Form 20-F 2011
Notes on financial statements 40. Share-based payments continued
Share option transactions
Details of share option transactions for the year under the share options plans are as follows:
Share option transactions
Outstanding at 1 January
Granteda
Forfeited
Exercised
Expired
Outstanding at 31 December
Exercisable at 31 December
Number
of
options
263,306,722
152,472,556
(9,058,406)
(2,502,306)
(29,717,854)
374,500,712
209,776,014
2011
Weighted
average
exercise price
$
8.75
6.03
7.22
7.64
8.26
7.73
9.01
Number
of
options
295,895,357
10,420,287
(9,499,661)
(31,839,034)
(1,670,227)
263,306,722
242,530,635
2010
Weighted
average
exercise price
$
8.73
6.08
7.88
7.97
8.71
8.75
8.90
Number
of
options
326,254,599
9,679,836
(5,954,325)
(21,293,871)
(12,790,882)
295,895,357
274,685,068
2009
Weighted
average
exercise price
$
8.70
6.55
8.81
7.53
8.01
8.73
8.80
a Share options granted during 2011 include 142.5 million options awarded under the BP Plan 2011 with a fair value of $1.02 per option at the date of grant, determined using a binomial option pricing model
including assumptions for share price volatility, dividends and cancellations.
The weighted average share price at the date of exercise was $7.71 (2010 $9.54 and 2009 $9.10).
For options outstanding at 31 December 2011, the exercise price ranges and weighted average remaining contractual lives were as shown below:
Range of exercise prices
$5.66 – $7.22
$7.23 – $8.79
$8.80 – $10.35
$10.36 – $11.92
Weighted
average
remaining life
Years
7.51
1.21
2.73
3.81
5.15
Options outstandinga
Weighted
average
exercise price
$
6.11
8.13
9.83
11.14
7.73
Number
of
shares
199,571,741
81,608,110
22,264,187
71,056,674
374,500,712
Options exercisable
Weighted
average
exercise price
$
6.37
8.13
9.92
11.14
9.01
Number
of
shares
37,283,772
81,608,110
19,827,458
71,056,674
209,776,014
a Included within options outstanding at 31 December 2011 are options granted under the BPSOP of 208 million options (2010 239 million options).
Fair values and associated details for restricted share units granted
For restricted share units granted in 2011, the number of units and weighted average fair value at the date of grant were as shown below:
Restricted share units granted in 2011
Number of restricted share units granted (million)
Weighted average fair value
Fair value measurement basis
Restricted share units granted in 2010
Number of restricted share units granted (million)
Weighted average fair value
Fair value measurement basis
Restricted share units granted in 2009
Number of restricted share units granted (million)
Weighted average fair value
Fair value measurement basis
CPP
1.4
$11.99
PSP
19.2
$7.51
Monte Carlo Market value Market value Market value Market value
EPP
8.9
$7.51
RSP
20.0
$6.86
DAB
17.5
$7.51
CPP
1.3
$19.81
PSP
16.0
$9.43
Monte Carlo Market value Market value Market value Market value
EPP
7.6
$9.43
DAB
24.5
$9.43
RSP
21.4
$6.78
CPP
1.4
$9.76
PSP
16.5
$8.32
Monte Carlo Market value Market value Market value Monte Carlo
EPP
7.6
$6.56
DAB
38.9
$6.56
RSP
2.4
$8.76
The group uses the observable market price for ordinary shares at the date of grant to determine the fair value of non-TSR restricted share units.
The group used a Monte Carlo simulation to determine the fair values of the TSR elements of the 2011, 2010 and 2009 CPP and EDIP grants and
the 2009 PSP grant. In accordance with the plans’ rules, the model simulates BP’s TSR and compares it against its principal strategic competitors over the
three-year period of the plans. The model takes into account the historical dividends, share price volatilities and covariances of BP and each comparator
company to produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the TSR
element.
Accounting expense does not necessarily represent the actual value of share-based payments made to recipients, which are determined by the
remuneration committee according to established criteria.
Employee Share Ownership Plan Trusts (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards made to participants under the BP share plans as required. The ESOPs have
waived their rights to dividends on shares held for future awards and are funded by the group. Until such time as the company’s own shares held by the
ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity (see Note 39). Assets and
liabilities of the ESOPs are recognized as assets and liabilities of the group.
At 31 December 2011, the ESOPs held 27,784,503 shares (2010 11,477,253 shares and 2009 18,062,246 shares) for potential future awards,
which had a market value of $197 million (2010 $82 million and 2009 $174 million).
BP Annual Report and Form 20-F 2011 247
Financial statementsNotes on financial statements 41. Employee costs and numbers
Employee costs
Wages and salariesa
Social security costs
Share-based payments
Pension and other post-retirement benefit costs
2011
9,827
851
584
1,065
2010
9,242
789
576
1,166
$ million
2009
9,702
780
521
1,213
12,327
11,773
12,216
Number of employees at 31 December
Exploration and Production
Refining and Marketingb
Other businesses and corporate
Gulf Coast Restoration Organization
By geographical area
US
Non-USb
Average number of employees
Exploration and Production
Refining and Marketing
Other businesses and corporate
Gulf Coast Restoration Organization
2011
22,200
51,000
10,100
100
83,400
22,900
60,500
83,400
2010
21,100
52,300
6,200
100
79,700
22,100
57,600
79,700
US
8,500
12,300
1,700
100
22,600
Non-US
13,200
39,200
6,500
–
58,900
2011
Total
21,700
51,500
8,200
100
81,500
US
8,100
12,600
1,900
–
22,600
Non-US
13,500
38,300
5,000
–
56,800
2010
Total
21,600
50,900
6,900
–
79,400
US
7,900
14,700
2,300
–
24,900
Non-US
13,800
40,700
5,800
–
60,300
2009
21,500
51,600
7,200
–
80,300
22,800
57,500
80,300
2009
Total
21,700
55,400
8,100
–
85,200
a Includes termination payments of $126 million (2010 $166 million and 2009 $945 million).
b Includes 14,600 (2010 15,200 and 2009 13,900) service station staff.
42. Remuneration of directors and senior management
Remuneration of directors
Total for all directors
Emoluments
Gains made on exercise of share options
Amounts awarded under incentive schemes
2011
2010
10
–
1
15
2
4
$ million
2009
19
2
2
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. There was no compensation for loss of office in 2011 (2010 $3 million and
2009 nil).
Pension contributions
During 2011 one executive director participated in a non-contributory pension plan established for UK employees by a separate trust fund to which
contributions are made by BP based on actuarial advice. Two US executive directors participated in the US BP Retirement Accumulation Plan during 2011.
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 139 to 151.
Remuneration of directors and senior management
Total for all senior management
Total for all senior management
Short-term employee benefits
Post-retirement benefits
Share-based payments
248 BP Annual Report and Form 20-F 2011
2011
2010
34
3
27
25
3
29
$ million
2009
36
3
20
Notes on financial statements 42. Remuneration of directors and senior management continued
Senior management, in addition to executive and non-executive directors, includes other senior managers who are members of the executive
management team.
Short-term employee benefits
In addition to fees paid to the non-executive chairman and non-executive directors, these amounts comprise, for executive directors and senior managers,
salary and benefits earned during the year, plus cash bonuses awarded for the year. Deferred annual bonus awards, to be settled in shares, are included in
share-based payments. Short-term employee benefits includes compensation for loss of office of $9 million (2010 $3 million and 2009 $6 million).
Post-retirement benefits
The amounts represent the estimated cost to the group of providing defined benefit pensions and other post-retirement benefits to senior management
in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares
granted accounted for in accordance with IFRS 2 ‘Share-based Payments’. The main plans in which senior management have participated are the EDIP,
DAB and RSP. For details of these plans refer to Note 40.
43. Contingent liabilities
Contingent liabilities relating to the Gulf of Mexico oil spill
As a consequence of the Gulf of Mexico oil spill, as described on pages 76 to 79, BP has incurred costs during the year and recognized provisions for
certain future costs. Further information is provided in Note 2 and Note 36.
BP has provided for its best estimate of amounts expected to be paid from the $20-billion trust fund. This includes certain amounts expected to
be paid pursuant to the Oil Pollution Act of 1990 (OPA 90) as well as the increased estimate of the cost of individual and business claims as a result of the
proposed settlement with the PSC announced on 3 March 2012 as described in Note 2 and Note 36. It is not possible, at this time, to measure reliably
any other items that will be paid from the trust fund, namely any obligation in relation to Natural Resource Damages claims other than the emergency
and early restoration costs as described in Note 36, and claims asserted in civil litigation including any further litigation through potential opt-outs from the
proposed settlement agreement, nor is it practicable to estimate their magnitude or possible timing of payment.
Natural resource damages resulting from the oil spill are currently being assessed (see Note 36 for further information). BP and the federal
and state trustees are collecting extensive data in order to assess the extent of damage to wildlife, shoreline, near shore and deepwater habitats,
and recreational uses, among other things. Because the affected areas and their uses vary by seasons, we are continuing our work to complete a full
assessment of the natural resource damages. In addition, as and when early restoration projects are undertaken, these projects could mitigate the total
damages resulting from the incident. Accordingly, until the size, location and duration of the impact have been fully determined and the effects of early
restoration projects are fully assessed, or other actions such as potential future settlement discussions occur, it is not possible to obtain a range of
outcomes or to estimate reliably either the amounts (other than the amounts previously provided for emergency and early restoration projects) or timing
of the remaining Natural Resource Damages claims.
BP is named as a defendant in approximately 600 civil lawsuits brought by individuals, corporations and governmental entities in US federal and
state courts resulting from the Gulf of Mexico oil spill. Additional lawsuits are likely to be brought. The lawsuits assert, among others, claims for personal
injury in connection with the incident itself and the response to it, and wrongful death, commercial or economic injury, securities and shareholder claims,
breach of contract and violations of statutes. The lawsuits, many of which purport to be class actions, seek various remedies including compensation to
injured workers and families of deceased workers, recovery for commercial losses and property damage, claims for environmental damage, remediation
costs, injunctive relief, treble damages and punitive damages. Most of these lawsuits have been consolidated into one of two multi-district litigation
(MDL) proceedings. On 3 March 2012, BP announced that it had reached a proposed settlement with the Plaintiffs’ Steering Committee (PSC), subject
to final written agreement and court approvals, to resolve the substantial majority of legitimate economic loss and medical claims stemming from the
Deepwater Horizon accident and oil spill. The PSC acts on behalf of individual and business plaintiffs in the MDL 2179 and the estimated cost of the
proposed settlement has been reflected in the financial statements. While BP announced that it had reached a proposed settlement with the PSC, a trial
of liability issues in the MDL 2179 is, at this time, still expected to go ahead. Damage issues will be scheduled for trial thereafter. Until further fact and
expert disclosures occur, court rulings clarify the issues in dispute, liability and damage trial activity nears, or other actions such as possible settlements
occur, it is not possible given these uncertainties to arrive at a range of outcomes or a reliable estimate of the liability other than the estimated cost of the
proposed settlement with the PSC. See Legal proceedings on pages 160 to 164 for further information.
Therefore, with the exception of the estimated costs of the proposed settlement agreement with the PSC, no amounts have been provided for
these items as of 31 December 2011. Although these items, which will be paid through the trust fund, have not been provided for at this time, BP‘s full
obligation under the $20-billion trust fund has been expensed in the income statement, taking account of the time value of money. The aggregate of
amounts paid and provided for items to be settled from the trust fund currently falls within the amount committed by BP to the trust fund.
For those items not covered by the trust fund it is not possible to measure reliably any obligation in relation to other litigation or potential fines and
penalties except, subject to certain assumptions detailed in Note 36, for those relating to the Clean Water Act. There are a number of federal and state
environmental and other provisions of law, other than the Clean Water Act, under which one or more governmental agencies could seek civil fines and
penalties from BP. For example, a complaint filed by the United States sought to reserve the ability to seek penalties and other relief under a number
of other laws. Given the large number of claims that may be asserted, it is not possible at this time to determine whether and to what extent any such
claims would be successful or what penalties or fines would be assessed. Therefore no amounts have been provided for these items.
Under the settlement agreements with Anadarko and MOEX, BP has agreed to indemnify Anadarko and MOEX for certain claims arising from
the accident (excluding civil, criminal or administrative fines and penalties, claims for punitive damages, and certain other claims). Under the settlement
agreement entered into with M-I L.L.C. (M-I) (see Legal proceedings on pages 160 to 164), BP agreed to indemnify M-I for certain claims resulting from
the accident. M-I was contracted by BP to provide specialized drilling mud and mud engineering services for the Macondo well. It is therefore possible
that BP may face claims under these indemnities, but it is not currently possible to reliably measure any obligation in relation to such claims and therefore
no amount has been provided as at 31 December 2011.
BP Annual Report and Form 20-F 2011 249
Financial statementsNotes on financial statements 43. Contingent liabilities continued
The magnitude and timing of possible obligations in relation to the Gulf of Mexico oil spill are subject to a very high degree of uncertainty as
described further in Risk factors on pages 59 to 63. Any such possible obligations are therefore contingent liabilities and, at present, it is not
practicable to estimate their magnitude or possible timing of payment. Certain items are subject to settlement discussions or may be subject to
settlement discussions in the future. Any settlements which may be reached relating to the Deepwater Horizon accident and oil spill could impact the
amount and timing of any future payments. Furthermore, other material unanticipated obligations may arise in future in relation to the incident.
Other contingent liabilities
There were contingent liabilities at 31 December 2011 in respect of guarantees and indemnities entered into as part of the ordinary course of the group‘s
business. No material losses are likely to arise from such contingent liabilities. Further information is included in Note 26.
Lawsuits arising out of the Exxon Valdez oil spill in Prince William Sound, Alaska, in March 1989 were filed against Exxon (now ExxonMobil),
Alyeska Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies that own Alyeska. Alyeska
initially responded to the spill until the response was taken over by Exxon. BP owns a 46.9% interest (reduced during 2001 from 50% by a sale
of 3.1% to Phillips) in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following
BP‘s combination with Atlantic Richfield Company (Atlantic Richfield). Alyeska and its owners have settled all the claims against them under these
lawsuits. Exxon has indicated that it may file a claim for contribution against Alyeska for a portion of the costs and damages that Exxon has incurred.
BP will defend any such claims vigorously. It is not possible to estimate any financial effect.
In the normal course of the group‘s business, legal proceedings are pending or may be brought against BP group entities arising out
of current and past operations, including matters related to commercial disputes, product liability, antitrust, premises-liability claims, general
environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals.
BP believes that the impact of these legal proceedings on the group‘s results of operations, liquidity or financial position will not be material.
With respect to lead pigment in paint in particular, Atlantic Richfield, a subsidiary of BP, has been named as a co-defendant in numerous
lawsuits brought in the US alleging injury to persons and property. Although it is not possible to predict the outcome of the legal proceedings,
Atlantic Richfield believes it has valid defences that render the incurrence of a liability remote; however, the amounts claimed and the costs of
implementing the remedies sought in the various cases could be substantial. The majority of the lawsuits have been abandoned or dismissed against
Atlantic Richfield. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any
proceeding. Atlantic Richfield intends to defend such actions vigorously.
The group files income tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group‘s
income tax returns. Tax returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the
resolution of tax positions through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is
difficult to predict the ultimate outcome in some cases, the group does not anticipate that there will be any material impact upon the group‘s results
of operations, financial position or liquidity.
The group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other
activities. These laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or
release of chemicals or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries,
chemical plants, oilfields, service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales
or closed facilities. The ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known
environmental obligations has been provided in these accounts in accordance with the group‘s accounting policies. While the amounts of future
costs could be significant and could be material to the group‘s results of operations in the period in which they are recognized, it is not practical to
estimate the amounts involved. BP does not expect these costs to have a material effect on the group‘s financial position or liquidity.
The group also has obligations to decommission oil and natural gas production facilities and related pipelines. Provision is made for the
estimated costs of these activities, however there is uncertainty regarding both the amount and timing of these costs, given the long-term nature
of these obligations. BP believes that the impact of any reasonably foreseeable changes to these provisions on the group‘s results of operations,
financial position or liquidity will not be material.
The group generally restricts its purchase of insurance to situations where this is required for legal or contractual reasons. This is because
external insurance is not considered an economic means of financing losses for the group. Losses will therefore be borne as they arise rather than
being spread over time through insurance premiums with attendant transaction costs. The position is reviewed periodically.
44. Capital commitments
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been placed at 31 December 2011
amounted to $12,517 million (2010 $11,279 million). In addition, at 31 December 2011, the group had contracts in place for future capital expenditure
relating to investments in jointly controlled entities of $296 million (2010 $437 million) and investments in associates of $36 million (2010 $80 million).
BP’s share of capital commitments of jointly controlled entities amounted to $1,244 million (2010 $1,117 million).
250 BP Annual Report and Form 20-F 2011
Notes on financial statements 45. Subsidiaries, jointly controlled entities and associates
The more important subsidiaries, jointly controlled entities and associates of the group at 31 December 2011 and the group percentage of ordinary share
capital or joint venture interest (to nearest whole number) are set out below. 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
*BP Corporate Holdings
BP Europa SE
BP Exploration Operating Company
*BP Global Investments
*BP International
BP Oil International
*BP Shipping
*Burmah Castrol
Jupiter Insurance
Algeria
BP Amoco Exploration (In Amenas)
BP Exploration (El Djazair)
Angola
BP Exploration (Angola)
Australia
BP Australia Capital Markets
BP Developments Australia
BP Finance Australia
BP Oil Australia
Azerbaijan
Amoco Caspian Sea Petroleum
BP Exploration (Caspian Sea)
Brazil
BP Energy do Brazil
Canada
BP Canada Energy
BP Canada Finance
Egypt
BP Egypt Company
India
%
100
100
100
100
100
100
100
100
100
100
100
Country of
incorporation
England & Wales
Germany
England & Wales
England & Wales
England & Wales
England & Wales
England & Wales
Scotland
Guernsey
Scotland
Bahamas
Principal activities
Investment holding
Refining and marketing and petrochemicals
Exploration and production
Investment holding
Integrated oil operations
Integrated oil operations
Shipping
Lubricants
Insurance
Exploration and production
Exploration and production
100
England & Wales
Exploration and production
100
100
100
100
100
100
Australia
Australia
Australia
Australia
Finance
Exploration and production
Finance
Integrated oil operations
British Virgin Islands
England & Wales
Exploration and production
Exploration and production
100
Brazil
100
100
Canada
Canada
100
US
Exploration and production
Exploration and production
Finance
Exploration and production
BP Exploration (Alpha)
100
England & Wales
Exploration and production
Indonesia
BP Berau
New Zealand
100
US
Exploration and production
BP Oil New Zealand
100
New Zealand
Marketing
Norway
BP Norge
Spain
BP España
South Africa
*BP Southern Africa
Trinidad & Tobago
BP Trinidad and Tobago
UK
US
BP Capital Markets
BP Oil UK
Britoil
*BP Holdings North America
Atlantic Richfield Company
BP America
BP America Production Company
BP Amoco Chemical Company
BP Company North America
BP Corporation North America
BP Exploration & Production
BP Exploration (Alaska)
BP Products North America
BP West Coast Products
Standard Oil Company
Verano Collateral Holdings
BP Capital Markets America
100
Norway
Exploration and production
100
Spain
Refining and marketing
75
70
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
South Africa
Refining and marketing
US
Exploration and production
England & Wales
England & Wales
Scotland
England & Wales
US
US
US
US
US
US
US
US
US
US
US
US
US
Finance
Marketing
Exploration and production
Investment holding
Exploration and production, refining and
marketing, pipelines and petrochemicals
Finance
BP Annual Report and Form 20-F 2011 251
Financial statementsNotes on financial statements 45. Subsidiaries, jointly controlled entities and associates continued
Jointly controlled entities
Angola
Angola LNG Supply Services
Argentina
Pan American Energya
Canada
Sunrise Oil Sands
China
Country of
incorporation
%
Principal activities
14
US
60
US
LNG processing and transportation
Exploration and production
50
Canada
Exploration and production
Shanghai SECCO Petrochemical Company
50
China
Petrochemicals
Germany
Ruhr Oel
Trinidad & Tobago
50
Germany
Refining and petrochemicals
Atlantic 4 Holdings
Atlantic LNG 2/3 Company of Trinidad and Tobago
38
43
US
Trinidad & Tobago
LNG manufacture
LNG manufacture
Taiwan
China American Petrochemical Companya
61
Taiwan
Petrochemicals
UK
US
Vivergo Fuels
46
England & Wales
Biofuels
BP-Husky Refining
Watson Cogenerationa b
50
51
US
US
Refining
Power generation
a The entity is not controlled by BP as certain key business decisions require joint approval of both BP and the minority partner. It is therefore classified as a jointly controlled entity rather than a subsidiary.
b As at 31 December 2011 the group’s interests in Watson Cogeneration have been classified as assets held for sale. See Note 4 for further information.
Associates
Abu Dhabi
%
Country of incorporation
Principal activities
Abu Dhabi Gas Liquefaction Company
Abu Dhabi Marine Areas
Abu Dhabi Petroleum Company
Azerbaijan
The Baku-Tbilisi-Ceyhan Pipeline Company
South Caucasus Pipeline Company
10
33
24
30
26
United Arab Emirates
England & Wales
England & Wales
Crude oil production
Crude oil production
Crude oil production
Cayman Islands
Cayman Islands
Pipelines
Pipelines
Russia
TNK-BP
50
British Virgin Islands
Integrated oil operations
252 BP Annual Report and Form 20-F 2011
Notes on financial statements 46. Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe
Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a condensed consolidating
basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its subsidiary issuers of registered
securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of each subsidiary issuer of public debt
securities. Investments include the investments in subsidiaries recorded under the equity method for the purposes of the condensed consolidating
financial information. Equity income of subsidiaries is the group’s share of profit related to such investments. The eliminations and reclassifications
column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration (Alaska) Inc. and other
subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. for all years includes equity income arising from
subsidiaries of BP Exploration (Alaska) Inc., some of which operate outside of Alaska and excludes the BP group’s midstream operations in Alaska that are
reported through different legal entities and that are included within the ‘other subsidiaries’ column in these tables. BP p.l.c. also fully and unconditionally
guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These companies are 100%-owned finance subsidiaries of
BP p.l.c.
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
Equity-accounted income of subsidiaries – after interest and tax
Interest and other 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 on embedded derivatives
Profit before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and
other post-retirement benefits
Profit before taxation
Taxation
Profit for the year
Attributable to
BP shareholders
Minority interest
Issuer
BP
Exploration
(Alaska) Inc.
6,159
–
–
313
10
–
6,482
978
1,280
1,684
335
–
4
27
–
2,174
32
–
2,142
729
1,413
1,413
–
1,413
Guarantor
BP p.l.c.
–
–
–
26,158
242
1
26,401
–
–
–
–
–
–
1,048
–
25,353
47
(533)
25,839
139
25,700
25,700
–
25,700
Other
subsidiaries
375,517
1,304
4,916
–
664
4,129
386,530
290,799
22,865
6,596
10,800
2,058
1,516
12,992
(68)
38,972
1,378
270
37,324
11,869
25,455
25,058
397
25,455
$ million
2011
BP group
375,517
1,304
4,916
–
596
4,130
386,463
285,618
24,145
8,280
11,135
2,058
1,520
13,958
(68)
39,817
1,246
Eliminations
and
reclassifications
(6,159)
–
–
(26,471)
(320)
–
(32,950)
(6,159)
–
–
–
–
–
(109)
–
(26,682)
(211)
–
(263)
(26,471)
–
(26,471)
(26,471)
–
(26,471)
38,834
12,737
26,097
25,700
397
26,097
BP Annual Report and Form 20-F 2011 253
Financial statementsNotes on financial statements 46. Condensed consolidating information on certain US subsidiaries continued
Income statement continued
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
Equity-accounted income of subsidiaries – after interest and tax
Interest and other 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 loss on embedded derivatives
Profit (loss) before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and
other post-retirement benefits
Profit (loss) before taxation
Taxation
Profit (loss) for the year
Attributable to
BP shareholders
Minority interest
Issuer
BP
Exploration
(Alaska) Inc.
4,793
–
–
620
–
–
5,413
637
966
998
351
1,524
–
16
–
921
2
4
915
143
772
772
–
772
Guarantor
BP p.l.c.
–
–
–
(3,567)
188
260
(3,119)
–
–
–
–
–
–
673
–
(3,792)
31
(388)
(3,435)
31
(3,466)
(3,466)
–
(3,466)
Other
subsidiaries
297,107
1,175
3,582
–
714
6,376
308,954
220,367
63,649
4,246
10,813
1,689
843
11,975
309
(4,937)
1,249
337
(6,523)
(1,675)
(4,848)
(5,243)
395
(4,848)
Eliminations
and
reclassifications
(4,793)
–
–
2,947
(221)
(253)
(2,320)
(4,793)
–
–
–
(1,524)
–
(109)
–
4,106
(112)
–
4,218
–
4,218
4,218
–
4,218
$ million
2010
BP group
297,107
1,175
3,582
–
681
6,383
308,928
216,211
64,615
5,244
11,164
1,689
843
12,555
309
(3,702)
1,170
(47)
(4,825)
(1,501)
(3,324)
(3,719)
395
(3,324)
254 BP Annual Report and Form 20-F 2011
Notes on financial statements 46. Condensed consolidating information on certain US subsidiaries continued
Income statement continued
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
Equity-accounted income of subsidiaries – after interest and tax
Interest and other 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 on embedded derivatives
Profit before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and
other post-retirement benefits
Profit before taxation
Taxation
Profit for the year
Attributable to
BP shareholders
Minority interest
Issuer
BP
Exploration
(Alaska) Inc.
4,189
–
–
838
17
–
5,044
510
970
602
424
–
–
27
–
2,511
22
10
2,479
583
1,896
1,896
–
1,896
Guarantor
BP p.l.c.
–
–
–
17,315
144
9
17,468
–
–
–
–
–
–
1,145
–
16,323
26
(310)
16,607
20
16,587
16,587
–
16,587
Other
subsidiaries
239,272
1,286
2,615
–
832
2,173
246,178
167,451
22,232
3,150
11,682
2,333
1,116
12,974
(607)
25,847
1,155
492
24,200
7,762
16,438
16,257
181
16,438
Eliminations
and
reclassifications
(4,189)
–
–
(18,153)
(201)
(9)
(22,552)
(4,189)
–
–
–
–
–
(108)
–
(18,255)
(93)
–
(18,162)
–
(18,162)
(18,162)
–
(18,162)
$ million
2009
BP group
239,272
1,286
2,615
–
792
2,173
246,138
163,772
23,202
3,752
12,106
2,333
1,116
14,038
(607)
26,426
1,110
192
25,124
8,365
16,759
16,578
181
16,759
BP Annual Report and Form 20-F 2011 255
Financial statementsNotes on financial statements 46. Condensed consolidating information on certain US subsidiaries continued
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
Subsidiaries – equity-accounted basis
Fixed assets
Loans
Other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit
plan deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Minority interest
Total equity
256 BP Annual Report and Form 20-F 2011
Issuer
BP
Exploration
(Alaska) Inc.
Guarantor
BP p.l.c.
Other
subsidiaries
Eliminations
and
reclassifications
8,653
–
456
–
–
–
4,802
13,911
46
–
–
–
–
–
13,957
–
167
4,109
–
7
–
–
(1)
4,282
–
–
–
–
–
2
–
129,042
129,044
38
–
–
–
–
–
129,082
–
–
17,698
–
–
–
–
–
17,698
–
110,561
12,100
20,646
15,518
13,289
2,117
–
174,231
5,113
4,337
5,038
1,255
611
17
190,602
244
25,494
49,753
3,857
1,279
235
288
14,068
95,218
8,420
–
–
–
–
–
–
(133,844)
(133,844)
(4,313)
–
–
–
–
–
(138,157)
–
–
(28,034)
–
–
–
–
–
(28,034)
–
$ million
2011
BP group
119,214
12,100
21,102
15,518
13,291
2,117
–
183,342
884
4,337
5,038
1,255
611
17
195,484
244
25,661
43,526
3,857
1,286
235
288
14,067
89,164
8,420
4,282
18,239
17,698
146,780
103,638
294,240
(28,034)
(166,191)
97,584
293,068
5,035
–
–
–
287
–
5,322
–
5,322
9
–
–
–
1,966
1,620
–
3,595
8,917
9,322
9,322
–
9,322
2,390
–
28
–
–
–
2,418
–
2,418
4,264
–
35
–
–
–
2,088
6,387
8,805
137,975
137,975
–
137,975
73,014
3,220
5,904
9,044
1,654
11,238
104,074
538
104,612
3,477
3,773
354
35,169
13,112
24,784
9,930
90,599
195,211
99,029
(28,034)
–
–
–
–
–
(28,034)
–
(28,034)
(4,313)
–
–
–
–
–
–
(4,313)
(32,347)
(133,844)
52,405
3,220
5,932
9,044
1,941
11,238
83,780
538
84,318
3,437
3,773
389
35,169
15,078
26,404
12,018
96,268
180,586
112,482
98,012
1,017
99,029
(133,844)
–
111,465
1,017
(133,844)
112,482
Notes on financial statements
46. Condensed consolidating information on certain US subsidiaries continued
Balance Sheet continued
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in jointly controlled entities
Investments in associates
Other investments
Subsidiaries – equity-accounted basis
Fixed assets
Loans
Other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit
plan deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Minority interest
Total equity
a Adjusted following the termination of the Pan American Energy LLC sale agreement as described in Note 4.
Issuer
BP
Exploration
(Alaska) Inc.
7,679
–
425
–
–
–
4,489
12,593
–
–
–
–
–
–
12,593
–
244
3,173
–
6
–
–
(1)
3,422
–
Guarantor
BP p.l.c.
–
–
–
–
2
–
112,227
112,229
38
–
–
–
–
1,870
114,137
–
–
14,444
–
–
–
–
4
14,448
–
Other
subsidiariesa
Eliminations
and
reclassifications
102,484
8,598
13,873
14,927
13,333
1,191
–
154,406
5,161
6,298
4,210
1,432
528
306
172,341
247
25,974
42,783
4,356
1,568
693
1,532
18,553
95,706
4,487
–
–
–
–
–
–
(116,716)
(116,716)
(4,305)
–
–
–
–
–
(121,021)
–
–
(23,851)
–
–
–
–
–
(23,851)
–
$ million
2010
BP groupa
110,163
8,598
14,298
14,927
13,335
1,191
–
162,512
894
6,298
4,210
1,432
528
2,176
178,050
247
26,218
36,549
4,356
1,574
693
1,532
18,556
89,725
4,487
3,422
16,015
14,448
128,585
100,193
272,534
(23,851)
(144,872)
94,212
272,262
4,931
–
–
–
182
–
5,113
–
2,362
–
23
–
–
–
2,385
–
62,887
3,856
5,589
14,626
2,738
9,489
99,185
1,047
(23,851)
–
–
–
–
–
(23,851)
–
5,113
2,385
100,232
(23,851)
14,323
3,677
602
30,710
8,472
21,460
9,857
89,101
189,333
83,201
(4,305)
–
–
–
–
–
–
(4,305)
(28,156)
(116,716)
9
–
–
–
2,026
958
–
2,993
8,106
7,909
7,909
–
7,909
4,258
–
35
–
410
–
–
4,703
7,088
121,497
121,497
–
121,497
46,329
3,856
5,612
14,626
2,920
9,489
82,832
1,047
83,879
14,285
3,677
637
30,710
10,908
22,418
9,857
92,492
176,371
95,891
82,297
904
83,201
(116,716)
–
(116,716)
94,987
904
95,891
BP Annual Report and Form 20-F 2011 257
Financial statementsNotes on financial statements
46. Condensed consolidating information on certain US subsidiaries continued
Cash flow statement
For the year ended 31 December
Net cash provided by operating activities
Net cash used in investing activities
Net cash (used in) provided by financing activities
Currency translation differences relating to cash and cash equivalents
Decrease in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
For the year ended 31 December
Net cash provided by (used in) operating activities
Net cash (used in) provided by investing activities
Net cash (used in) provided by 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
For the year ended 31 December
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
(Decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Issuer
BP
Exploration
(Alaska) Inc.
661
(661)
–
–
–
(1)
(1)
Guarantor
BP p.l.c.
8,321
(3,710)
(4,615)
–
(4)
4
–
Other
subsidiaries
25,114
(22,262)
(6,845)
(492)
(4,485)
18,553
14,068
Eliminations
and
reclassifications
(11,942)
–
11,942
–
–
–
–
Issuer
BP
Exploration
(Alaska) Inc.
829
(752)
(56)
–
21
(22)
(1)
Issuer
BP
Exploration
(Alaska) Inc.
1,022
(935)
(99)
–
(12)
(10)
(22)
Guarantor
BP p.l.c.
32,111
(29,325)
(2,810)
–
(24)
28
4
Guarantor
BP p.l.c.
14,514
(4,227)
(10,270)
–
17
11
28
Other
subsidiaries
(4,584)
26,117
(11,034)
(279)
10,220
8,333
18,553
Eliminations
and
reclassifications
(14,740)
–
14,740
–
–
–
–
Other
subsidiaries
47,466
(12,971)
(34,468)
110
137
8,196
8,333
Eliminations
and
reclassifications
(35,286)
–
35,286
–
–
–
–
$ million
2011
BP group
22,154
(26,633)
482
(492)
(4,489)
18,556
14,067
$ million
2010
BP group
13,616
(3,960)
840
(279)
10,217
8,339
18,556
$ million
2009
BP group
27,716
(18,133)
(9,551)
110
142
8,197
8,339
258 BP Annual Report and Form 20-F 2011
Notes on financial statements Supplementary information on oil and natural gas (unaudited)
The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved
reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements.
Oil and gas reserves – certain definitions
Unless the context indicates otherwise, the following terms have the meanings shown below:
Proved oil and gas reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods,
and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must
have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)
The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any; and
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain
economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
(iii)
(iv)
(v)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well
penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas
cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data
and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection)
are included in the proved classification when:
(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the
operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the
reasonable certainty of the engineering analysis on which the project or programme was based; and
The project has been approved for development by all necessary parties and entities, including governmental entities.
(B)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the
average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic
average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding
escalations based upon future conditions.
Undeveloped oil and gas reserves
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion.
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production
when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an
analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
(ii)
(iii)
Developed oil and gas reserves
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor
compared to the cost of a new well; and
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not
involving a well.
(ii)
For details on BP’s proved reserves and production compliance and governance processes, see pages 90 to 91.
BP Annual Report and Form 20-F 2011 259
i
F
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Oil and natural gas exploration and production activities
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2011
Total
Russia
Rest of
Asia
Subsidiariesa
Capitalized costs at 31 Decemberb j
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
37,491
368
37,859
26,953
10,906
8,994
180
9,174
3,715
5,459
73,626
6,198
79,824
36,009
43,815
182
1,471
1,653
139
1,514
7,471
2,986
10,457
3,839
6,618
29,358
3,689
33,047
14,595
18,452
Costs incurred for the year ended 31 Decemberb j
Acquisition of propertiesc k
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
–
–
–
211
1,361
1,572
–
1
1
1
889
891
1,178
418
1,596
566
3,016
5,178
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and amortization
Impairments and (gains) losses on sale of
businesses and fixed assets
Profit (loss) before taxationg
Allocable taxes
Results of operations
1,997
3,495
5,492
37
1,372
72
(1,357)
874
26
1,024
4,468
2,483
1,985
–
1,273
1,273
1
230
–
101
199
(64)
467
806
384
422
751
19,089
19,840
1,065
3,402
1,854
4,688
2,980
(492)
13,497
6,343
2,152
4,191
8
–
8
117
–
125
25
20
45
9
66
–
49
6
237
2,592
2,829
271
405
3,505
2,263
1,409
3,672
35
503
278
935
523
15
145
(100)
(159)
59
(1,085)
1,189
2,483
1,205
1,278
–
679
679
490
2,933
4,102
3,353
4,858
8,211
163
1,146
–
215
1,668
18
3,210
5,001
2,184
2,817
–
–
–
–
–
–
–
–
6
–
6
–
–
–
6
4
–
72
–
(1)
81
(81)
(21)
(60)
14,833
4,495
19,328
6,235
13,093
3,370 175,325
1,279
20,666
4,649 195,991
1,294
92,779
3,355 103,212
1,733
3,008
4,741
511
1,340
6,592
1,450
10,811
12,261
134
787
5,956
118
1,692
(537)
8,150
4,111
1,001
3,110
–
–
–
225
251
476
3,156
6,698
9,854
2,398
10,195
22,447
1,611
967
2,578
70
194
147
257
172
–
840
1,738
677
1,061
11,450
41,922
53,372
1,520
7,704
8,307
5,078
8,114
(2,120)
28,603
24,769
9,906
14,863
Exploration and Production segment replacement cost profit before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream activities – subsidiariesh
Equity-accounted entitiesi
Total replacement cost profit
before interest and tax
4,468
(118)
–
806
29
12
6,343
(157)
10
(100)
299
58
2,483
(58)
598
5,001
(4)
69
(81)
(1)
4,095
4,111
42
573
1,738
284
–
24,769
316
5,415
4,350
847
6,196
257
3,023
5,066
4,013
4,726
2,022
30,500
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. They do not include any costs relating to the Gulf of Mexico oil spill. Midstream activities
relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream
activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline
System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad,
Indonesia and Australia and BP is also investing in the LNG business in Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $191 million. The UK region includes a $1,442 million gain offset by corresponding charges primarily
in the US, relating to the group self-insurance programme. The South America region includes a charge of $700 million associated with the termination of the agreement to sell our 60% interest in Pan
American Energy LLC to Bridas Corporation (see page 85).
g Excludes the unwinding of the discount on provisions and payables amounting to $352 million which is included in finance costs in the group income statement.
h Midstream activities exclude inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and tax.
j Excludes balances associated with assets held for sale.
k Excludes goodwill associated with business combinations.
260 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Russia
Rest of
Asia
16,214
652
16,866
6,978
9,888
3,571
9
3,580
3,017
563
–
37
37
167
1,862
2,066
7,380
5,149
12,529
72
1,846
5,000
2
988
–
7,908
4,621
806
3,815
46
–
46
9
435
490
3,828
23
3,851
1
212
3,125
(1)
431
–
3,768
83
19
64
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
168
1,510
1,678
–
1,678
6,562
19
6,581
2,644
3,937
–
–
–
–
251
251
–
–
–
–
–
–
–
–
–
–
–
–
–
–
6
6
2
587
595
2,381
–
2,381
10
459
1,098
(239)
329
–
1,657
724
294
430
Equity-accounted entities (BP share)a
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Impairments and (gains) losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
Exploration and production activities –
equity-accounted entities after tax
(as above)
Midstream and other activities after taxf
Total replacement cost profit
after interest and tax
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
$ million
2011
Total
26,515
2,190
28,705
12,639
16,066
46
43
89
178
3,135
3,402
13,589
5,172
18,761
83
2,517
9,223
(238)
1,748
–
13,333
5,428
1,119
4,309
4,309
1,106
5,415
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
12
12
–
10
10
–
58
58
430
168
598
–
69
69
3,815
280
4,095
64
509
573
a These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream
activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream
activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs and sales taxes.
f Includes interest, minority interest and the net results of equity-accounted entities of equity-accounted entities, and excludes inventory holding gains and losses.
BP Annual Report and Form 20-F 2011 261
Financial statementsSupplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities continued
Europe
North
America
South
America
UK
Rest of
Europe
US
Rest of
North
America
Africa
Asia
Australasia
$ million
2010
Total
Russia
Rest of
Asia
Subsidiariesa
Capitalized costs at 31 Decemberb j
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decemberb j
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
36,161
787
36,948
27,688
9,260
7,846
179
8,025
3,515
4,510
67,724
5,968
73,692
33,972
39,720
–
–
–
401
726
–
519
519
13
816
1,127
1,348
655
1,599
2,254
1,096
3,034
6,384
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and amortization
Impairments and (gains) losses on sale of
businesses and fixed assets
Profit (loss) before taxationg
Allocable taxes
Results of operations
1,472
3,405
4,877
82
1,018
52
(316)
897
(1)
1,732
3,145
1,333
1,812
58
1,134
1,192
(2)
152
–
76
209
–
435
757
530
227
1,148
18,819
19,967
465
2,867
1,093
3,502
3,477
(1,441)
9,963
10,004
3,504
6,500
278
1,363
1,641
216
1,425
1
1,200
1,201
78
251
1,530
90
453
543
25
240
2
129
95
(2,190)
(1,699)
2,242
610
1,632
6,047
220
6,267
3,282
2,985
27,014
2,694
29,708
13,893
15,815
–
–
–
68
414
482
1,896
1,574
3,470
9
445
249
209
575
(3)
1,484
1,986
1,084
902
–
–
–
607
3,003
3,610
3,158
4,353
7,511
189
938
–
130
1,771
(427)
2,601
4,910
1,771
3,139
–
–
–
–
–
–
–
–
7
–
7
–
–
–
7
9
–
76
–
341k
433
(433)
(23)
(410)
11,497
1,113
12,610
4,569
8,041
3,088 159,655
1,149
13,473
4,237 173,128
88,340
1,205
84,788
3,032
1,121
151
1,272
316
1,244
2,832
1,272
6,697
7,969
51
365
3,764
90
829
–
5,099
2,870
813
2,057
–
–
–
120
187
307
1,777
3,469
5,246
2,706
9,675
17,627
1,398
929
2,327
17
124
109
195
168
–
613
1,714
410
1,304
10,492
37,364
47,856
843
6,158
5,269
4,091
8,021
(3,721)
20,661
27,195
10,032
17,163
Exploration and Production segment replacement cost profit before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream activities – subsidiariesh
Equity-accounted entitiesi
Total replacement cost profit
before interest and tax
3,145
23
–
757
42
4
10,004
(347)
27
2,242
3
171
1,986
49
614
4,910
(26)
63
(433)
4
2,613
2,870
(23)
487
1,714
(13)
–
27,195
(288)
3,979
3,168
803
9,684
2,416
2,649
4,947
2,184
3,334
1,701
30,886
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. They do not include any costs relating to the Gulf of Mexico oil spill. Midstream activities relating
to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of
marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties
Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is
also investing in the LNG business in Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value loss on embedded derivatives of $309 million. The UK region includes a $822 million gain offset by corresponding charges primarily in the
US, relating to the group self-insurance programme.
g Excludes the unwinding of the discount on provisions and payables amounting to $313 million which is included in finance costs in the group income statement.
h Midstream activities exclude inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and tax.
j Excludes balances associated with assets held for sale.
k This amount represents the write-down of our investment in Sakhalin. A portion of these costs was previously reported within capitalized costs of equity-accounted entities with the remainder previously
reported as a loan, which was not included in the disclosures of oil and natural gas exploration and production activities.
262 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities continued
Europe
North
America
South
America
UK
Rest of
Europe
US
Rest of
North
America
Equity-accounted entities (BP share)a
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
Exploration and production activities –
equity-accounted entities after tax
(as above)
Midstream and other activities after taxf
Total replacement cost profit
after interest and tax
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
4
4
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
27
27
142
1,284
1,426
–
1,426
5,778
163
5,941
2,250
3,691
–
–
–
–
49
49
–
–
–
–
–
–
67
–
–
67
(67)
–
(67)
(67)
238
171
–
9
9
2
549
560
2,268
–
2,268
22
316
911
75
269
–
1,593
675
260
415
415
199
614
Africa
Asia
Australasia
Russia
Rest of
Asia
14,486
652
15,138
6,300
8,838
3,192
–
3,192
2,674
518
–
66
66
94
1,416
1,576
5,610
3,432
9,042
40
1,602
3,567
3
954
43
6,209
2,833
475
2,358
–
–
–
–
355
355
2,557
19
2,576
–
184
2,029
(2)
363
–
2,574
2
33
(31)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
63
63
2,358
255
(31)
518
2,613
487
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
$ million
2010
Total
23,598
2,099
25,697
11,224
14,473
–
75
75
96
2,369
2,540
10,435
3,451
13,886
62
2,102
6,507
143
1,586
43
10,443
3,443
768
2,675
2,675
1,304
3,979
a These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream
activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream
activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs and sales taxes.
f Includes interest, minority interest and the net results of equity-accounted entities of equity-accounted entities.
BP Annual Report and Form 20-F 2011 263
Financial statementsSupplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities continued
Europe
North
America
South
America
UK
Rest of
Europe
US
Rest of
North
America
Africa
Asia
Australasia
$ million
2009
Total
Russia
Rest of
Asia
Subsidiariesa
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
35,096
752
35,848
26,794
9,054
6,644
–
6,644
3,306
3,338
64,366
5,464
69,830
31,728
38,102
3,967
147
4,114
2,309
1,805
8,346
198
8,544
4,837
3,707
24,476
2,377
26,853
12,492
14,361
Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
179
(1)
178
183
751
1,112
–
–
–
–
1,054
1,054
(17)
370
353
1,377
4,208
5,938
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and amortization
Impairments and (gains) losses on sale of
businesses and fixed assets
Profit (loss) before taxationg
Allocable taxes
Results of operations
2,239
2,482
4,721
59
1,243
(3)
(1,259)
1,148
(122)
1,066
3,655
1,568
2,087
68
809
877
–
164
–
51
185
(7)
393
484
76
408
972
15,100
16,072
663
2,821
649
2,353
3,857
(208)
10,135
5,937
1,902
4,035
–
1
1
79
386
466
99
484
583
80
284
1
145
170
–
680
(97)
(58)
(39)
–
–
–
78
453
531
1,525
1,409
2,934
16
395
220
184
697
(11)
1,501
1,433
916
517
–
18
18
712
2,707
3,437
1,846
5,313
7,159
219
908
–
144
2,041
(1)
3,311
3,848
1,517
2,331
–
–
–
–
–
–
–
–
8
–
8
–
–
–
8
15
–
76
–
–
99
(99)
(25)
(74)
10,900
733
11,633
4,798
6,835
2,894 156,689
1,039
10,710
3,933 167,399
87,302
1,038
80,097
2,895
306
–
306
315
560
1,181
636
6,257
6,893
49
361
2,854
967
757
(702)j
4,286
2,607
682
1,925
–
10
10
53
277
340
468
398
866
2,805
10,396
14,067
785
726
1,511
22
70
72
178
96
–
438
1,073
2
1,071
8,170
32,580
40,750
1,116
6,261
3,793
2,839
8,951
(1,051)
21,909
18,841
6,580
12,261
Exploration and Production segment replacement cost profit before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream activities – subsidiariesh j
Equity-accounted entitiesi
Total replacement cost profit
before interest and tax
3,655
925
–
484
17
5
5,937
719
29
(97)
833
134
1,433
17
630
3,848
(27)
56
(99)
(37)
1,924
2,607
518
531
1,073
(315)
–
18,841
2,650
3,309
4,580
506
6,685
870
2,080
3,877
1,788
3,656
758
24,800
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. Midstream activities relating to the management and ownership of crude oil and natural
gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in
the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System
pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes. Sales between businesses and third party sales have been amended in the US without net effect to total sales.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $663 million. The UK region includes a $783 million gain offset by corresponding charges primarily in the
US, relating to the group self-insurance programme.
g Excludes the unwinding of the discount on provisions and payables amounting to $308 million which is included in finance costs in the group income statement.
h Midstream activities exclude inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and tax.
j Includes the gain on disposal of upstream assets associated with our sale of our 46% stake in LukArco (see Note 5).
264 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Oil and natural gas exploration and production activities continued
Europe
North
America
South
America
UK
Rest of
Europe
US
Rest of
North
America
Africa
Asia
Australasia
Equity-accounted entities (BP share)a
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and amortization
Impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
Exploration and production activities –
equity-accounted entities after
tax (as above)
Midstream and other activities after taxf
Total replacement cost profit
after interest and tax
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
5
5
Russia
Rest of
Asia
13,266
737
14,003
5,550
8,453
2,259
–
2,259
1,739
520
–
10
10
77
1,182
1,269
4,919
2,838
7,757
37
1,428
2,597
12
1,073
72
5,219
2,538
501
2,037
–
–
–
3
246
249
1,874
–
1,874
–
159
1,523
(2)
274
–
1,954
(80)
–
(80)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1,378
1,378
–
1,378
5,789
197
5,986
2,084
3,902
–
–
–
–
30
30
–
–
–
–
–
–
–
–
–
–
–
–
–
–
31
31
21
538
590
1,977
–
1,977
23
354
702
(69)
281
–
1,291
686
270
416
–
29
29
–
134
134
416
214
630
–
56
56
2,037
(113)
(80)
611
1,924
531
$ million
2009
Total
21,314
2,312
23,626
9,373
14,253
–
41
41
101
1,996
2,138
8,770
2,838
11,608
60
1,941
4,822
(59)
1,628
72
8,464
3,144
771
2,373
2,373
936
3,309
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
a These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Midstream activities relating to the management and ownership of crude oil and
natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream activities of TNK-BP are excluded. The amounts reported for equity-accounted
entities exclude the corresponding amounts for their equity-accounted entities.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes.
f Includes interest, minority interest and the net results of equity-accounted entities of equity-accounted entities.
BP Annual Report and Form 20-F 2011 265
Financial statementsSupplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves
Crude oila
Subsidiaries
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2011c
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2011d g
Developed
Undeveloped
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2011
Developed
Undeveloped
364
431
795
At 31 December 2011
Developed
Undeveloped
288
445
733
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
USe
Africa
Asia
Australasia
million barrels
2011
Total
Russia
Rest of
Asia
364
431
795
(1)
14
–
–
(41)
(34)
(62)
288
445
733
–
–
–
–
–
–
–
–
–
–
–
–
–
77
221
298
5
8
–
–
(12)
–
1
69
230
299
–
–
–
–
–
–
–
–
–
–
–
–
–
1,729
1,190
2,919
27
97
10
1
(162)
(34)
(61)
1,685
1,173
2,858
–
–
–
–
–
–
–
–
–
–
–
–
–
77
221
298
69
230
299
1,729
1,190
2,919
1,685
1,173
2,858
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
44
58
102
6
1
7
1
(13)
(29)
(27)
27
48
75
408
407
815
(12)
70
98
–
(30)
(244)
(118)
349
348
697
452
465
917
376
396
772
371
374
745
(68)
10
–
19
(68)
(12)
(119)
311
315
626
–
12
12
2
–
–
–
–
–
2
–
14
14
371
386
757
311
329
640
–
–
–
–
–
–
–
–
–
–
–
–
–
2,388
1,362
3,750
677
73
–
25
(316)
–
459
2,596
1,613
4,209
2,388
1,362
3,750
2,596
1,613
4,209
269
325
594
(131)
70
4
–
(50)
(31)
(138)
177
279
456
370
24
394
(5)
–
1
–
(76)
–
(80)
256
58
314
639
349
988
433
337
770
48
58
106
2,902
2,657
5,559
3
6
–
–
(9)
–
–
59
47
106
–
–
–
–
–
–
–
–
–
–
–
–
–
(159)
206
21
21
(355)
(140)
(406)
2,616
2,537
5,153
3,166
1,805
4,971
662
143
99
25
(422)
(244)
263
3,201
2,033
5,234
48
58
106
59
47
106
6,068
4,462
10,530
5,817
4,570
10,387
a Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and
the option and ability to make lifting and sales arrangements independently.
b Excludes NGLs from processing plants in which an interest is held of 28 thousand barrels per day.
c Includes 616 million barrels of NGLs. Also includes 20 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 19 million barrels of NGLs. Also includes 310 million barrels of crude oil in respect of the 7.37% minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 82 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.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Total proved liquid reserves held as part of our equity interest in TNK-BP is 4,305 million barrels, comprising 95 million barrels in Venezuela, one million barrels in Vietnam and 4,209 million barrels in Rus-
sia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated by evidence of Russian subsoil law, track record of
renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved liquid reserves of 221 million barrels.
266 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
2011
Total
billion cubic feet
Russia
Rest of
Asia
Natural gasa
Subsidiaries
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2011c
Developed
Undeveloped
Equity-accounted entities (BP share)e
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2011d f
Developed
Undeveloped
1,416
829
2,245
169
56
8
–
(146)
(12)
75
1,411
909
2,320
40
430
470
9,495
4,248
13,743
30
1
–
–
(8)
–
23
–
597
93
219
(737)
(363)
(191)
43
450
493
9,721
3,831
13,552
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
58
–
58
(9)
–
7
–
(5)
(23)
(30)
28
–
28
–
–
–
–
–
–
–
–
–
–
–
–
–
3,575
6,575
10,150
1,329
2,351
3,680
202
84
–
47
(811)
(274)
(752)
2,869
6,529
9,398
1,075
1,192
2,267
(75)
190
31
–
(167)
(96)
(117)
1,144
1,006
2,150
(206)
15
–
–
(232)
–
(423)
1,224
2,033
3,257
–
175
175
20
–
–
–
–
–
20
–
195
195
–
–
–
–
–
–
–
–
–
–
–
–
–
1,290
268
1,558
3,563
2,342
5,905
20,766
17,043
37,809
69
28
310
–
(244)
(323)
(160)
299
22
–
–
(291)
–
30
554
803
418
266
(2,474)
(995)
(1,428)
1,034
364
1,398
3,570
2,365
5,935
19,900
16,481
36,381
1,900
459
2,359
683
–
–
–
(264)
–
419
2,119
659
2,778
1,900
459
2,359
2,119
659
2,778
71
19
90
(3)
12
76
–
(20)
–
65
104
51
155
–
–
–
–
–
–
–
–
–
–
–
–
–
3,046
1,845
4,891
625
202
107
–
(451)
(96)
387
3,367
1,911
5,278
1,361
287
1,648
1,138
415
1,553
3,563
2,342
5,905
3,570
2,365
5,935
23,812
18,888
42,700
23,267
18,392
41,659
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2011
Developed
Undeveloped
1,416
829
2,245
At 31 December 2011
Developed
Undeveloped
1,411
909
2,320
40
430
470
43
450
493
9,495
4,248
13,743
9,721
3,831
13,552
58
–
58
28
–
28
4,650
7,767
12,417
4,013
7,535
11,548
1,329
2,526
3,855
1,224
2,228
3,452
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b Includes 196 billion cubic feet of natural gas consumed in operations,155 billion cubic feet in subsidiaries, 41 billion cubic feet in equity-accounted entities and excludes 14 billion cubic feet of produced
non-hydrocarbon components which meet regulatory requirements for sales.
c Includes 2,759 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 174 billion cubic feet of natural gas in respect of the 6.27% minority interest in TNK-BP.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Total proved gas reserves held as part of our equity interest in TNK-BP is 2,881 billion cubic feet, comprising 30 billion cubic feet in Venezuela, 73 billion cubic feet in Vietnam and 2,778 billion cubic feet in
Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated by evidence of Russian subsoil law, track record
of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved gas reserves of 185 billion cubic feet.
BP Annual Report and Form 20-F 2011 267
Financial statementsSupplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Bitumena
Equity-accounted entities (BP share)
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2011
Developed
Undeveloped
million barrels
2011
Total
–
179
179
(1)
–
–
–
–
–
(1)
–
178
178
Rest of
North
America
–
179
179
(1)
–
–
–
–
–
(1)
–
178
178
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
268 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Total hydrocarbonsa
Subsidiaries
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb f
Sales of reserves-in-place
At 31 December 2011c
Developed
Undeveloped
Equity-accounted entities (BP share)g
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb f
Sales of reserves-in-place
At 31 December 2011d h
Developed
Undeveloped
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2011
Developed
Undeveloped
608
574
1,182
At 31 December 2011
Developed
Undeveloped
531
602
1,133
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
USe
Africa
Asia
Australasia
2011
Total
million barrels of oil equivalent
Russia
Rest of
Asia
608
574
1,182
28
24
1
–
(66)
(36)
(49)
531
602
1,133
–
–
–
–
–
–
–
–
–
–
–
–
–
84
295
379
10
8
–
–
(13)
–
5
76
308
384
–
–
–
–
–
–
–
–
–
–
–
–
–
3,366
1,923
5,289
27
200
26
39
(289)
(97)
(94)
3,362
1,833
5,195
–
–
–
–
–
–
–
–
–
–
–
–
–
84
295
379
76
308
384
3,366
1,923
5,289
3,362
1,833
5,195
10
–
10
(2)
–
2
–
(1)
(4)
(5)
5
–
5
–
179
179
(1)
–
–
–
–
–
(1)
–
178
178
10
179
189
5
178
183
660
1,192
1,852
600
779
1,379
41
15
7
9
(153)
(76)
(157)
522
1,173
1,695
593
613
1,206
(25)
103
103
–
(59)
(260)
(138)
546
522
1,068
1,253
1,805
3,058
1,068
1,695
2,763
(103)
12
–
19
(108)
(12)
(192)
522
665
1,187
–
43
43
5
–
–
–
–
–
5
–
48
48
600
822
1,422
522
713
1,235
–
–
–
–
–
–
–
–
–
–
–
–
–
2,716
1,441
4,157
795
73
–
25
(362)
–
531
2,961
1,727
4,688
2,716
1,441
4,157
2,961
1,727
4,688
491
371
862
(119)
75
58
–
(92)
(87)
(165)
355
342
697
382
27
409
(5)
2
14
–
(80)
–
(69)
274
66
340
662
462
6,481
5,596
1,124
12,077
55
10
–
–
(59)
–
6
(63)
344
94
67
(781)
(312)
(651)
675
455
6,048
5,378
1,130
11,426
–
–
–
–
–
–
–
–
–
–
–
–
–
3,691
2,303
5,994
769
178
117
25
(501)
(260)
328
3,781
2,541
6,322
873
398
1,271
629
408
1,037
662
462
1,124
675
455
1,130
10,172
7,899
18,071
9,829
7,919
17,748
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b Excludes NGLs from processing plants in which an interest is held of 28 thousand barrels of oil equivalent per day.
c Includes 616 million barrels of NGLs. Also includes 496 million barrels of oil equivalent in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 19 million barrels of NGLs. Also includes 340 million barrels of oil equivalent in respect of the minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 82 million barrels of oil equivalent upon which a net profits royalty will be payable.
f Includes 34 million barrels of oil equivalent of natural gas consumed in operations, 27 million barrels of oil equivalent in subsidiaries, seven million barrels of oil equivalent in equity-accounted entities and
excludes two million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Total proved reserves held as part of our equity interest in TNK-BP is 4,802 million barrels of oil equivalent, comprising 100 million barrels of oil equivalent in Venezuela, 14 million barrels of oil equivalent in
Vietnam and 4,688 million barrels of oil equivalent in Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated
by evidence of Russian subsoil law, track record of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved reserves of
253 million barrels of oil equivalent.
BP Annual Report and Form 20-F 2011 269
Financial statementsSupplementary information on oil and natural gas (unaudited)
Movements in estimated net proved reserves continued
Crude oila
Subsidiaries
At 1 January 2010
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb j
Sales of reserves-in-place
At 31 December 2010c g
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January 2010
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2010d
Developed
Undeveloped
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2010
Developed
Undeveloped
403
291
694
At 31 December 2010
Developed
Undeveloped
364
431
795
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
USe
Africa
Asia
Australasia
million barrels
2010
Total
Russia
Rest of
Asia
403
291
694
20
100
–
31
(50)
–
101
364
431
795
–
–
–
–
–
–
–
–
–
–
–
–
–
83
184
267
3
9
33
1
(15)
–
31
77
221
298
–
–
–
–
–
–
–
–
–
–
–
–
–
1,862
1,211
3,073
(45)
133
6
80
(211)
(117)
(154)
1,729
1,190
2,919
–
–
–
–
–
–
–
–
–
–
–
–
–
83
184
267
77
221
298
1,862
1,211
3,073
1,729
1,190
2,919
11
1
12
1
–
–
–
(2)
(11)
(12)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
11
1
12
–
–
–
49
56
105
(1)
17
–
–
(19)
–
(3)
44
58
102
407
405
812
4
33
–
1
(35)i k
–
3
408
407
815h
456
461
917
452
465
917
422
454
876
(62)
14
–
19
(87)
(15)
(131)
371
374
745
–
9
9
3
–
–
–
–
–
3
–
12
12
422
463
885
371
386
757
–
–
–
–
–
–
–
–
–
–
–
–
–
2,351
1,198
3,549
248
269
–
–
(313)
(3)
201
2,388
1,362
3,750
2,351
1,198
3,549
2,388
1,362
3,750
182
334
516
(62)
145
38
–
(43)
–
78
269
325
594
363
120
483
(20)
–
–
–
(69)
–
(89)
370
24
394
545
454
999
639
349
988
58
57
115
–
3
–
–
(12)
–
(9)
48
58
106
–
–
–
–
–
–
–
–
–
–
–
–
–
3,070
2,588
5,658
(146)
421
77
131
(439)
(143)
(99)
2,902
2,657
5,559
3,121
1,732
4,853
235
302
–
1
(417)
(3)
118
3,166
1,805
4,971
58
57
115
48
58
106
6,191
4,320
10,511
6,068
4,462
10,530
a Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production
and the option and ability to make lifting and sales arrangements independently.
b Excludes NGLs from processing plants in which an interest is held of 29 thousand barrels per day.
c Includes 643 million barrels of NGLs. Also includes 22 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 18 million barrels of NGLs. Also includes 254 million barrels of crude oil in respect of the 7.03% minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 78 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.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 70 million barrels relating to assets held for sale at 31 December 2010. Amounts by region are: 6 million barrels in US; 30 million barrels in South America; and 34 million barrels in Rest of Asia.
h Includes 213 million barrels relating to assets held for sale at 31 December 2010.
i Includes 2 million barrels of crude oil sold relating to production since classification of equity-accounted entities as held for sale.
j Includes 15 million barrels of crude oil sold relating to production from assets held for sale at 31 December 2010. Amounts by region are: 2 million barrels in US; 6 million barrels in South America; and
7 million barrels in Rest of Asia.
k Includes 9 million barrels of crude oil sold relating to production from assets held for sale at 31 December 2010.
270 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Natural gasa
Subsidiaries
At 1 January 2010
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb i
Sales of reserves-in-place
At 31 December 2010c f
Developed
Undeveloped
Equity-accounted entities (BP share)e
At 1 January 2010
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2010d
Developed
Undeveloped
Europe
North
America
South
America
UK
Rest of
Europe
US
Rest of
North
America
1,602
670
2,272
49
397
446
9,583
5,633
716
453
3,177
7,393
15,216
1,169 10,570
(8)
152
–
26
(191)
(6)
(27)
(5)
6
31
–
(8)
–
24
(1,854)
830
97
739
(861)
(424)
(1,473)
(11)
–
1
9
(77)
(1,033)
(1,111)
2
512
–
19
(953)
–
(420)
1,416
829
2,245
40
430
470
9,495
4,248
13,743
58
–
3,575
6,575
58 10,150
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1,252
1,010
2,262
(141)
291
–
23
(168)h j
–
5
1,075
1,192
2,267g
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2010
Developed
Undeveloped
1,602
670
2,272
At 31 December 2010
Developed
Undeveloped
1,416
829
2,245
49
397
446
40
430
470
9,583
5,633
15,216
9,495
4,248
13,743
716
453
4,429
8,403
1,169 12,832
58
–
4,650
7,767
58 12,417
Africa
Asia
Australasia
2010
Total
billion cubic feet
Russia
Rest of
Asia
1,107
1,454
2,561
3
18
–
1,378
(229)
(51)
1,119
1,329
2,351
3,680
–
165
165
10
–
–
–
–
–
10
–
175
175
1,107
1,619
2,726
1,329
2,526
3,855
–
–
–
–
–
–
–
–
–
–
–
–
–
1,579
249
1,828
3,219
3,107
6,326
21,032
19,356
40,388
(142)
83
17
–
(228)
–
(270)
(191)
58
–
–
(288)
–
(421)
(2,206)
1,659
146
2,171
(2,835)
(1,514)
(2,579)
1,290
268
1,558
3,563
2,342
5,905
20,766
17,043
37,809
1,703
519
2,222
382
–
–
–
(244)
(1)
137
1,900
459
2,359
1,703
519
2,222
1,900
459
2,359
80
13
93
2
12
–
–
(17)
–
(3)
71
19
90
–
–
–
–
–
–
–
–
–
–
–
–
–
3,035
1,707
4,742
253
303
–
23
(429)
(1)
149
3,046
1,845
4,891
1,659
262
1,921
1,361
287
1,648
3,219
3,107
6,326
3,563
2,342
5,905
24,067
21,063
45,130
23,812
18,888
42,700
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b Includes 204 billion cubic feet of natural gas consumed in operations, 166 billion cubic feet in subsidiaries, 38 billion cubic feet in equity-accounted entities and excludes 14 billion cubic feet of produced
non-hydrocarbon components which meet regulatory requirements for sales.
c Includes 2,921 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 137 billion cubic feet of natural gas in respect of the 5.89% minority interest in TNK-BP.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 740 billion cubic feet relating to assets held for sale at 31 December 2010. Amounts by region are: 158 billion cubic feet in US; 205 billion cubic feet in South America; and 377 billion cubic feet in
Rest of Asia.
g Includes 50 billion cubic feet relating to assets held for sale at 31 December 2010.
h Includes 1 billion cubic feet of gas sales relating to production since classification of equity-accounted entities as held for sale.
i Includes 133 billion cubic feet of gas (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010. Amounts by region are: 23 billion cubic feet in US;
27 billion cubic feet in South America; and 83 billion cubic feet in Rest of Asia.
j Includes 3 billion cubic feet of gas (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010.
BP Annual Report and Form 20-F 2011 271
Financial statementsSupplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Bitumena
Equity-accounted entities (BP share)
At 1 January 2010
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2010
Developed
Undeveloped
million barrels
2010
Total
–
–
–
–
–
–
179
–
–
179
–
179
179
Rest of
North
America
–
–
–
–
–
–
179
–
–
179
–
179
179
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
272 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
USe
Africa
Asia
Australasia
2010
Total
million barrels of oil equivalent
Russia
Rest of
Asia
Total hydrocarbonsa
Subsidiaries
At 1 January 2010
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb f l
Sales of reserves-in-place
At 31 December 2010c i
Developed
Undeveloped
Equity-accounted entities (BP share)g
At 1 January 2010
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb f
Sales of reserves-in-place
At 31 December 2010d
Developed
Undeveloped
680
406
1,086
18
126
–
36
(83)
(1)
96
608
574
1,182
–
–
–
–
–
–
–
–
–
–
–
–
–
91
253
344
2
10
38
1
(16)
–
35
84
295
379
–
–
–
–
–
–
–
–
–
–
–
–
–
(364)
276
22
207
(359)
(190)
(408)
3,366
1,923
5,289
–
–
–
–
–
–
–
–
–
–
–
–
–
3,514
2,183
5,697
135
79
214
596
1,331
1,927
613
704
1,317
(61)
17
–
257
(127)
(24)
62
600
779
1,379
–
37
37
6
–
–
–
–
–
6
–
43
43
613
741
1,354
600
822
1,422
–
–
–
–
–
–
–
–
–
–
–
–
–
2,645
1,287
3,932
314
269
–
–
(354)
(4)
225
2,716
1,441
4,157
2,645
1,287
3,932
2,716
1,441
4,157
455
376
831
(87)
160
41
–
(83)
–
31
491
371
862
377
122
499
(19)
2
–
–
(73)
–
(90)
382
27
409
612
593
1,205
6,696
5,925
12,621
(33)
13
–
–
(61)
–
(81)
(528)
707
101
507
(927)
(404)
(544)
662
462
6,481
5,596
1,124
12,077
–
–
–
–
–
–
–
–
–
–
–
–
–
3,645
2,026
5,671
281
354
–
183
(491)
(4)
323
3,691
2,303
5,994
832
498
1,330
873
398
1,271
612
593
1,205
662
462
1,124
10,341
7,951
18,292
10,172
7,899
18,071
(2)
–
–
2
(15)
(189)
(204)
(1)
105
–
4
(183)
–
(75)
10
–
10
660
1,192
1,852
–
–
–
623
580
1,203
–
–
–
179
–
–
179
–
179
179
135
79
214
10
179
189
(20)
83
–
4
(64)k m
–
3
593
613
1,206j
1,219
1,911
3,130
1,253
1,805
3,058
Total subsidiaries and equity-accounted entities (BP share)h
At 1 January 2010
Developed
Undeveloped
680
406
1,086
At 31 December 2010
Developed
Undeveloped
608
574
1,182
91
253
344
84
295
379
3,514
2,183
5,697
3,366
1,923
5,289
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b Excludes NGLs from processing plants in which an interest is held of 29 thousand barrels of oil equivalent per day.
c Includes 643 million barrels of NGLs. Also includes 526 million barrels of oil equivalent in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 18 million barrels of NGLs. Also includes 278 million barrels of oil equivalent in respect of the minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 78 million barrels of oil equivalent upon which a net profits royalty will be payable.
f Includes 35 million barrels of oil equivalent of natural gas consumed in operations, 28 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities and
excludes 2 million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 1,311 million barrels of oil equivalent (197 million barrels of oil equivalent for subsidiaries and 1,114 million barrels of oil equivalent for equity-accounted entities) associated with properties
currently held for sale where the disposal has not yet been completed.
i Includes 197 million barrels of oil equivalent relating to assets held for sale at 31 December 2010. Amounts by region are: 34 million barrels of oil equivalent in US; 64 million barrels of oil equivalent in
South America; and 99 million barrels of oil equivalent in Rest of Asia.
j Includes 222 million barrels of oil equivalent relating to assets held for sale at 31 December 2010.
k Includes 2 million barrels of oil equivalent sold relating to production since classification of equity-accounted entities as held for sale.
l Includes 38 million barrels of oil equivalent (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010. Amounts by region are: 6 million barrels of oil
equivalent in US; 11 million barrels of oil equivalent in South America; and 21 million barrels of oil equivalent in Rest of Asia.
m Includes 9 million barrels of oil equivalent (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010.
BP Annual Report and Form 20-F 2011 273
Financial statementsSupplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Crude oila
Subsidiaries
At 1 January 2009
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2009c
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January 2009
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2009d
Developed
Undeveloped
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2009
Developed
Undeveloped
410
119
529
At 31 December 2009
Developed
Undeveloped
403
291
694
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
USe
Africa
Asia
Australasia
million barrels
2009
Total
Russia
Rest of
Asia
410
119
529
7
42
1
184
(61)
(8)
165
403
291
694
–
–
–
–
–
–
–
–
–
–
–
–
–
81
194
275
(1)
7
–
–
(14)
–
(8)
1,717
1,273
2,990
165
82
–
73
(237)
–
83
83
184
267
1,862
1,211
3,073
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
81
194
275
83
184
267
1,717
1,273
2,990
1,862
1,211
3,073
11
1
12
2
–
–
–
(2)
–
–
11
1
12
–
–
–
–
–
–
–
–
–
–
–
–
–
11
1
12
11
1
12
47
55
102
18
7
–
–
(22)
–
3
49
56
105
399
409
808
2
50
–
3
(37)
(14)
4
407
405
812
446
464
910
456
461
917
464
496
960
(121)
32
–
114
(109)
–
(84)
422
454
876
–
11
11
(2)
–
–
–
–
–
(2)
–
9
9
464
507
971
422
463
885
–
–
–
–
–
–
–
–
–
–
–
–
–
2,227
944
3,171
590
8
–
87
(307)
–
378
2,351
1,198
3,549
2,227
944
3,171
2,351
1,198
3,549
195
488
683
(128)
31
1
–
(45)
(26)
(167)
182
334
516
499
199
698
(28)
–
–
–
(71)
(116)
(215)
363
120
483
56
58
114
3
2
–
7
(11)
–
1
2,981
2,684
5,665
(55)
203
2
378
(501)
(34)
(7)
58
57
115
3,070
2,588
5,658
–
–
–
–
–
–
–
–
–
–
–
–
–
3,125
1,563
4,688
562
58
–
90
(415)
(130)
165
3,121
1,732
4,853
694
687
1,381
545
454
999
56
58
114
58
57
115
6,106
4,247
10,353
6,191
4,320
10,511
a Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and
the option and ability to make lifting and sales arrangements independently.
b Excludes NGLs from processing plants in which an interest is held of 26 thousand barrels per day.
c Includes 819 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 20 million barrels of NGLs. Also includes 243 million barrels of crude oil in respect of the 6.86% minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 68 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.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
274 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited)
Natural gasa
Subsidiaries
At 1 January 2009
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2009c
Developed
Undeveloped
Equity-accounted entities (BP share)e
At 1 January 2009
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2009d
Developed
Undeveloped
Movements in estimated net proved reserves continued
Europe
North
America
South
America
UK
Rest of
Europe
US
Rest of
North
America
Africa
Asia
Australasia
2009
Total
billion cubic feet
Russia
Rest of
Asia
1,822
582
2,404
61
402
463
9,059
5,473
659
468
3,316
7,434
14,532
1,127
10,750
1,050
1,382
2,432
(114)
34
159
150
(243)
(118)
(132)
(8)
–
–
–
(9)
–
(17)
549
550
–
496
(907)
(4)
684
43
5
–
94
(100)
–
42
322
322
–
105
(929)
–
(180)
270
49
–
59
(249)
–
129
1,602
670
2,272
49
397
446
9,583
5,633
716
453
3,177
7,393
15,216
1,169
10,570
1,107
1,454
2,561
–
–
–
–
–
–
–
–
–
–
–
–
–
1,102
1,308
2,410
1,887
4,000
5,887
18,956
21,049
40,005
(231)
82
31
–
(241)
(223)
(582)
22
75
–
531
(189)
–
439
853
1,117
190
1,435
(2,867)
(345)
383
1,579
249
1,828
3,219
3,107
6,326
21,032
19,356
40,388
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1,498
1,023
2,521
(26)
314
–
6
(165)
(388)
(259)
1,252
1,010
2,262
–
182
182
(17)
–
–
–
–
–
(17)
–
165
165
1,560
653
2,213
204
1
–
23
(219)
–
9
1,703
519
2,222
1,560
653
2,213
1,703
519
2,222
176
111
287
(19)
4
–
–
(25)
(154)
(194)
80
13
93
–
–
–
–
–
–
–
–
–
–
–
–
–
3,234
1,969
5,203
142
319
–
29
(409)
(542)
(461)
3,035
1,707
4,742
1,278
1,419
2,697
1,659
262
1,921
1,887
4,000
5,887
3,219
3,107
6,326
22,190
23,018
45,208
24,067
21,063
45,130
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2009
Developed
Undeveloped
1,822
582
2,404
At 31 December 2009
Developed
Undeveloped
1,602
670
2,272
61
402
463
49
397
446
9,059
5,473
14,532
9,583
5,633
15,216
659
468
1,127
716
453
1,169
4,814
8,457
13,271
4,429
8,403
12,832
1,050
1,564
2,614
1,107
1,619
2,726
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b Includes 195 billion cubic feet of natural gas consumed in operations, 164 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities and excludes 16 billion cubic feet of produced
non-hydrocarbon components which meet regulatory requirements for sales.
c Includes 3,068 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 131 billion cubic feet of natural gas in respect of the 5.79% minority interest in TNK-BP.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
BP Annual Report and Form 20-F 2011 275
Financial statementsSupplementary information on oil and natural gas (unaudited) Movements in estimated net proved reserves continued
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
USe
Africa
Asia
Australasia
2009
Total
million barrels of oil equivalent
Russia
Rest of
Asia
Total hydrocrabonsa
Subsidiaries
At 1 January 2009
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb f
Sales of reserves-in-place
At 31 December 2009c
Developed
Undeveloped
Equity-accounted entities (BP share)g
At 1 January 2009
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb f
Sales of reserves-in-place
At 31 December 2009d
Developed
Undeveloped
724
219
943
(13)
48
28
210
(102)
(28)
143
680
406
1,086
–
–
–
–
–
–
–
–
–
–
–
–
–
91
264
355
(2)
7
–
–
(16)
–
(11)
91
253
344
–
–
–
–
–
–
–
–
–
–
–
–
–
3,279
2,217
5,496
260
177
–
158
(393)
(1)
201
3,514
2,183
5,697
–
–
–
–
–
–
–
–
–
–
–
–
–
126
81
207
9
1
–
17
(20)
–
7
135
79
214
–
–
–
–
–
–
–
–
–
–
–
–
–
617
1,337
1,954
645
734
1,379
74
63
–
18
(182)
–
(27)
596
1,331
1,927
658
586
1,244
(2)
104
–
4
(66)
(81)
(41)
623
580
1,203
1,275
1,923
3,198
1,219
1,911
3,130
(74)
40
–
124
(152)
–
(62)
613
704
1,317
–
42
42
(5)
–
–
–
–
–
(5)
–
37
37
645
776
1,421
613
741
1,354
–
–
–
–
–
–
–
–
–
–
–
–
–
2,495
1,057
3,552
625
8
–
92
(345)
–
380
2,645
1,287
3,932
2,495
1,057
3,552
2,645
1,287
3,932
385
714
382
747
6,249
6,313
1,099
1,129
12,562
(168)
45
6
–
(86)
(65)
(268)
455
376
831
529
218
747
(32)
1
–
–
(75)
(142)
(248)
377
122
499
7
15
–
98
(44)
–
76
93
396
34
625
(995)
(94)
59
612
593
6,696
5,925
1,205
12,621
–
–
–
–
–
–
–
–
–
–
–
–
–
3,682
1,903
5,585
586
113
–
96
(486)
(223)
86
3,645
2,026
5,671
914
932
1,846
832
498
1,330
382
747
1,129
612
593
1,205
9,931
8,216
18,147
10,341
7,951
18,292
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2009
Developed
Undeveloped
724
219
943
At 31 December 2009
Developed
Undeveloped
680
406
1,086
91
264
355
91
253
344
3,279
2,217
5,496
3,514
2,183
5,697
126
81
207
135
79
214
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b Excludes NGLs from processing plants in which an interest is held of 26 thousand barrels of oil equivalent per day.
c Includes 819 million barrels of NGLs. Also includes 552 million barrels of oil equivalent in respect of the 30% minority interest in BP Trinidad and Tobago LLC.
d Includes 20 million barrels of NGLs. Also includes 266 million barrels of oil equivalent in respect of the minority interest in TNK-BP.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 68 million barrels of oil equivalent upon which a net profits royalty will be payable.
f Includes 34 million barrels of oil equivalent of natural gas consumed in operations, 29 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities and
excludes 3 million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
276 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Standardized measure of discounted future net cash flows and
changes therein relating to proved oil and gas reserves
The following tables set out the standardized measure of discounted future net cash flows, and changes therein, relating to crude oil and natural gas
production from the group’s estimated proved reserves. This information is prepared in compliance with FASB Oil and Gas Disclosures requirements.
Future net cash flows have been prepared on the basis of certain assumptions which may or may not be realized. These include the timing
of future production, the estimation of crude oil and natural gas reserves and the application of average crude oil and natural gas prices and exchange
rates from the previous 12 months. Furthermore, both proved reserves estimates and production forecasts are subject to revision as further technical
information becomes available and economic conditions change. BP cautions against relying on the information presented because of the highly arbitrary
nature of the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2011
Total
Russia
Rest of
Asia
At 31 December 2011
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowse
Equity-accounted entities (BP share)f
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
future net cash flows
97,900
30,500
8,500
37,100
21,800
11,200
36,400 332,900
10,900 140,700
32,300
57,000
7,600 102,900
55,500
3,100
2,700
15,200
100
100
–
–
–
–
39,100
10,500
7,600
11,400
9,600
4,100
82,100
16,800
13,200
19,800
32,300
12,500
10,600
4,500
47,400
–
5,500
19,800
–
–
–
–
–
–
–
59,200
16,000
9,600
8,100
25,500
9,800
53,900 701,600
15,600 241,100
77,100
3,200
9,000 157,600
26,100 225,800
13,500 109,700
15,700
12,600 116,100
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
9,100
3,100
1,900
900
3,200
2,800
46,700
21,500
5,000
5,900
14,300
8,700
– 188,900
– 123,800
15,600
–
9,600
–
39,900
–
19,000
–
34,200
30,100
2,400
200
1,500
600
– 278,900
– 178,500
24,900
–
16,600
–
58,900
–
31,100
–
400
5,600
–
20,900
900
–
27,800
10,600
4,500
47,400
400
11,100
19,800
20,900
16,600
12,600 143,900
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeari
Equity-accounted
entities (BP share)
(5,700)
2,900
2,800
15,800
2,100
(1,400)
(2,700)
(2,700)
1,500
12,600
$ million
Total subsidiaries and
equity-accounted
entities
(36,600)
15,700
9,400
90,800
(19,900)
(19,600)
(13,500)
(9,200)
11,500
28,600
Subsidiaries
(30,900)
12,800
6,600
75,000
(22,000)
(18,200)
(10,800)
(6,500)
10,000
16,000
a The marker prices used were Brent $110.96/bbl, Henry Hub $4.12/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
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 $1,600 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those
entities.
g Minority interest in TNK-BP amounted to $1,600 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements.
BP Annual Report and Form 20-F 2011 277
Financial statementsSupplementary information on oil and natural gas (unaudited)
Standardized measure of discounted future net cash flows and changes therein relating to proved oil
and gas reserves continued
At 31 December 2010
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowse
Equity-accounted entities (BP share)f
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowsg h
Europe
North
America
South
America
UK
Rest of
Europe
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2010
Total
Russia
Rest of
Asia
73,100
25,700
7,400
19,900
20,100
9,800
25,800 264,800
9,800 111,400
24,300
2,500
41,900
8,100
87,200
5,400
45,500
2,300
200
200
–
–
–
–
29,300
6,800
6,100
8,200
8,200
3,300
70,800
14,000
14,600
14,100
28,100
11,900
10,300
3,100
41,700
–
4,900
16,200
–
–
–
–
–
–
–
52,500
13,400
9,900
7,000
22,200
8,200
42,300 558,800
12,800 194,100
67,900
3,100
6,200 105,400
20,200 191,400
91,300
10,300
14,000
9,900 100,100
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
9,700
4,500
2,000
800
2,400
2,400
45,500
19,200
4,300
7,500
14,500
8,700
– 110,500
80,900
–
11,000
–
3,900
–
14,700
–
6,100
–
31,000
26,500
2,800
200
1,500
700
– 196,700
– 131,100
20,100
–
12,400
–
33,100
–
17,900
–
–
–
5,800
–
8,600
800
–
15,200
10,700
16,200
8,600
14,800
9,900 115,300
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
future net cash flowsj
10,300
3,100
41,700
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeari
Equity-accounted
entities (BP share)
(4,900)
2,000
1,600
1,900
200
(300)
(1,400)
–
1,500
600
$ million
Total subsidiaries and
equity-accounted
entities
(31,500)
12,400
11,200
54,700
(9,000)
(13,700)
(5,700)
(1,500)
9,000
25,900
Subsidiaries
(26,600)
10,400
9,600
52,800
(9,200)
(13,400)
(4,300)
(1,500)
7,500
25,300
a The marker prices used were Brent $79.02/bbl, Henry Hub $4.37/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
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 $1,200 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
g Minority interest in TNK-BP amounted to $600 million.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements.
j Includes future net cash flows for assets held for sale at 31 December 2010.
278 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Standardized measure of discounted future net cash flows and changes therein relating to proved oil
and gas reserves continued
Europe
North
America
South
America
Africa
Asia
Australasia
$ million
2009
Total
At 31 December 2009
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowse
Equity-accounted entities (BP share)f
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
future net cash flows
UK
Rest of
Europe
US
50,800
20,000
5,000
12,900
12,900
5,800
17,700 204,000
91,300
24,900
27,300
60,500
29,500
8,000
2,500
3,700
3,500
1,600
Rest of
North
America
4,900
2,700
1,000
200
1,000
500
26,400
6,700
5,600
5,800
8,300
3,200
58,400
12,000
12,200
11,300
22,900
9,800
7,100
1,900
31,000
500
5,100
13,100
Russia
Rest of
Asia
–
–
–
–
–
–
–
36,100
9,200
6,400
4,700
15,800
6,300
32,500 430,800
11,000 160,900
60,700
70,400
13,900 138,800
64,000
3,100
4,500
7,300
9,500
6,600
74,800
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
37,700
17,000
4,000
5,200
11,500
6,800
4,700
–
–
–
–
–
–
–
96,700
65,200
10,200
4,300
17,000
7,900
30,000
25,200
3,100
100
1,600
800
– 164,400
– 107,400
17,300
–
9,600
–
30,100
–
15,500
–
9,100
800
–
14,600
7,100
1,900
31,000
500
9,800
13,100
9,100
10,300
6,600
89,400
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeari
Equity-accounted
entities (BP share)
(3,400)
2,100
1,600
5,900
(200)
(1,600)
900
(900)
900
5,300
$ million
Total subsidiaries and
equity-accounted
entities
(22,300)
13,800
10,100
43,100
(4,500)
(12,200)
300
(1,000)
5,600
32,900
Subsidiaries
(18,900)
11,700
8,500
37,200
(4,300)
(10,600)
(600)
(100)
4,700
27,600
a The marker prices used were Brent $59.91/bbl, Henry Hub $3.82/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
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.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those
entities.
g Minority interest in TNK-BP amounted to $600 million.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements.
BP Annual Report and Form 20-F 2011 279
Financial statementsSupplementary information on oil and natural gas (unaudited) Operational and statistical information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include amounts
attributable to assets held for sale.
Crude oil and natural gas production
The following table shows crude oil and natural gas production for the years ended 31 December 2011, 2010 and 2009.
Production for the yeara
Subsidiaries
Crude oilb
2011
2010
2009
Natural gasc
2011
2010
2009
Equity-accounted entities (BP share)
Crude oilb
2011
2010
2009
Natural gasc
2011
2010
2009
Europe
North
America
South
America
Africa
Asia
Australasia
Total
UK
Rest of
Europe
113
137
168
355
472
618
–
–
–
–
–
–
32
40
40
13
15
16
–
–
–
–
–
–
Rest of
North
America
2
7
8
14
202
263
–
–
–
–
–
–
US
453
594
665
1,843
2,184
2,316
–
–
–
–
–
–
Russia
Rest of
Asia
39
54
61
2,197
2,544
2,492
90
98
101
392
399
392
190
246
304
558
556
621
–
–
–
–
–
–
–
–
–
–
–
–
865
856
840
699
640
601
138
119
123
618
574
610
210
191
194
34
30
42
25
32
31
thousand barrels per day
992
1,229
1,400
million cubic feet per day
6,393
7,332
7,450
795
785
514
–
–
–
thousand barrels per day
1,165
1,145
1,135
million cubic feet per day
1,125
1,069
1,035
–
–
–
a Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b 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 at 31 December 2011. 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.
Number of productive wells at
Oil wellsa
31 December 2011
– gross
– net
– gross
– net
Gas wellsb
Oil and natural gas acreage at 31 December 2011
Developed
– gross
– net
Undevelopedc – gross
– net
Europe
North
America
South
America
UK
Rest of
Europe
US
Rest of
North
America
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
197
97
273
137
334
182
1,276
764
73
28
–
–
65
21
186
79
2,629
1,063
24,986
12,863
7,350
4,266
7,210
4,798
36
18
376
185
3,764
2,090
467
152
566
429
122
47
228
111
6,273
4,253
1,718
450
10,064
4,571
560
207
27,000
17,895
20,308
9,131
72
36
1,618
723
33,704
14,712
1,750
315
589
219
1,952
384
56,189
17,890
13
2
68
14
29,336
13,173
26,953
13,653
Thousands of acres
13,987
162
6,379
35
18,641 160,543
78,414
13,452
a Includes approximately 3,866 gross (1,702 net) multiple completion wells (more than one formation producing into the same well bore).
b Includes approximately 2,683 gross (1,689 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.
c Undeveloped acreage includes leases and concessions.
280 BP Annual Report and Form 20-F 2011
Supplementary information on oil and natural gas (unaudited) Operational and statistical information (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.
Europe
North
America
South
America
Africa
Asia
Australasia
Total
2011
Exploratory
Productive
Dry
Development
Productive
Dry
2010
Exploratory
Productive
Dry
Development
Productive
Dry
2009
Exploratory
Productive
Dry
Development
Productive
Dry
Rest of
Europe
US
Rest of
North
America
Russia
Rest of
Asia
–
–
–
–
0.2
–
1.2
–
–
–
1.5
–
34.1
2.1
199.4
0.2
39.3
0.3
260.0
0.5
47.2
4.2
403.8
3.3
–
–
–
–
–
–
4.4
0.2
101.3
3.0
1.3
0.9
31.7
–
105.7
1.2
–
–
3.0
–
17.9
–
135.4
–
2.1
–
16.0
2.7
1.2
1.4
18.9
2.7
4.5
1.4
20.8
0.5
16.7
7.2
582.0
–
10.5
4.0
364.3
–
7.0
4.5
293.0
4.0
1.0
0.3
45.1
0.4
2.8
–
53.3
2.4
5.3
6.0
45.8
0.4
0.2
0.3
–
–
0.3
–
–
–
0.6
0.2
1.6
0.6
58.9
10.1
945.5
6.3
55.6
7.3
841.5
8.5
67.7
16.5
929.1
8.8
UK
0.4
–
1.7
–
–
0.7
6.4
1.7
0.1
0.2
9.3
–
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 2011. Suspended development wells and long-term suspended exploratory wells are also included in the table.
Europe
North
America
South
America
Africa
Asia
Australasia
Total
At 31 December 2011
Exploratory
Gross
Net
Development
Gross
Net
UK
1.0
0.1
6.0
4.2
Rest of
Europe
US
Rest of
North
America
Russia
Rest of
Asia
–
–
1.0
0.4
108.0
30.5
748.0
235.7
3.0
1.5
36.0
18.0
6.0
2.3
16.0
9.2
1.0
0.2
36.0
13.2
22.0
10.5
209.0
101.2
–
–
37.0
10.3
–
–
–
–
141.0
45.1
1,089.0
392.2
BP Annual Report and Form 20-F 2011 281
Financial statementsSupplementary information on oil and natural gas (unaudited) Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to
sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/D.J. JACKSON
D.J. Jackson
Company Secretary
Dated 6 March 2012
282 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.
Independent auditor’s report to the members of BP p.l.c.
We have audited the parent company financial statements of BP p.l.c. for the year ended 31 December 2011 which comprise the company balance sheet,
the company cash flow statement, the company statement of total recognized gains and losses and the related notes 1 to 13. The financial reporting
framework that has been applied in their preparation is applicable law and United Kingdom accounting standards (United Kingdom generally accepted
accounting practice).
This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit
work has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report
and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the
company’s members as a body, for our audit work, for this report, or for the opinions we have formed.
Respective responsibilities of directors and auditors
As explained more fully in the Statement of directors’ responsibilities set out on page 174, the directors are responsible for the preparation of the parent
company financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit the parent company financial
statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the
Auditing Practices Board’s Ethical Standards for Auditors.
Scope of the audit of the financial statements
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the
financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting
policies are appropriate to the parent company’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of
significant accounting estimates made by the directors; and the overall presentation of the financial statements.
Opinion on financial statements
In our opinion the parent company financial statements:
• give a true and fair view of the state of the company’s affairs as at 31 December 2011;
• have been properly prepared in accordance with United Kingdom generally accepted accounting practice; and
• have been prepared in accordance with the requirements of the Companies Act 2006.
Opinion on other matters prescribed by the Companies Act 2006
In our opinion:
• the part of the Directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006; and
• the information given in the Directors’ Report for the financial year for which the parent company financial statements are prepared is consistent with
the parent company financial statements.
Matters on which we are required to report by exception
We have nothing to report in respect of the following matters where the Companies Act 2006 requires us to report to you if, in our opinion:
• adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not been received from branches not
visited by us; or
• the parent company financial statements and the part of the Directors’ remuneration report to be audited are not in agreement with the accounting
records and returns; or
• certain disclosures of directors’ remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
Other matter
We have reported separately on the consolidated financial statements of BP p.l.c. for the year ended 31 December 2011. That report includes an
emphasis of matter on the significant uncertainty over provisions and contingencies related to the Gulf of Mexico oil spill.
Ernst & Young LLP
Allister Wilson (Senior statutory auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
6 March 2012
The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not involve
consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements
since they were initially presented on the website. Legislation in the United Kingdom governing the preparation and dissemination of financial statements
may differ from legislation in other jurisdictions.
BP Annual Report and Form 20-F 2011 PC1
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Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
Company balance sheet
At 31 December
Fixed assets
Investments
Subsidiary undertakings
Associated undertakings
Total fixed assets
Current assets
Debtors – amounts falling due:
Within one year
After more than one year
Deferred taxation
Cash at bank and in hand
Creditors – amounts falling due within one year
Net current assets
Total assets less current liabilities
Creditors – amounts falling due after more than one year
Net assets excluding pension plan surplus
Defined benefit pension plan surplus
Defined benefit pension plan deficit
Net assets
Represented by
Capital and reserves
Called-up share capital
Share premium account
Capital redemption reserve
Merger reserve
Own shares
Treasury shares
Share-based payment reserve
Profit and loss account
Note
2011
$ million
2010
3
3
4
4
2
5
5
6
6
7
8
8
8
8
8
8
8
126,360
2
126,362
122,649
2
122,651
17,698
38
–
–
17,736
2,418
15,318
141,680
4,299
137,381
–
(2,088)
135,293
5,224
9,952
1,072
26,509
(388)
(20,935)
1,574
112,285
135,293
14,444
38
70
4
14,556
2,385
12,171
134,822
4,293
130,529
1,537
(147)
131,919
5,183
9,987
1,072
26,509
(126)
(21,085)
1,585
108,794
131,919
The financial statements on pages PC2-PC14 were approved and signed by the chairman and group chief executive on 6 March 2012 having been duly
authorized to do so by the board of directors:
C-H Svanberg Chairman
R W Dudley Group Chief Executive
PC2 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. Company cash flow statement
For the year ended 31 December
Net cash (outflow) inflow from operating activities
Servicing of finance and returns on investments
Interest received
Interest paid
Dividends received
Net cash inflow from servicing of finance and returns on investments
Tax paid
Capital expenditure and financial investment
Payments for fixed assets – investments
Proceeds from sale of fixed assets – investments
Net cash (outflow) inflow for capital expenditure and financial investment
Equity dividends paid
Net cash (outflow) inflow before financing
Financing
Other share-based payment movements
Net cash inflow (outflow) from financing
Increase (decrease) in cash
Company statement of total recognized gains and losses
For the year ended 31 December
Profit for the year
Currency translation differences
Actuarial (loss) gain relating to pensions
Tax on actuarial loss (gain) relating to pensions
Total recognized gains and losses relating to the year
Note
9
9
Note
6
2
2011
(3,799)
234
(47)
11,942
12,129
(9)
(3,719)
9
(3,710)
(4,072)
539
(543)
(543)
(4)
$ million
2010
17,231
175
(31)
14,739
14,883
(3)
(29,636)
311
(29,325)
(2,627)
159
(183)
(183)
(24)
2011
11,484
164
(4,770)
583
7,461
$ million
2010
14,776
(45)
457
(123)
15,065
BP Annual Report and Form 20-F 2011 PC3
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Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
Notes on financial statements
1. Accounting policies
Accounting standards
These financial statements are prepared in accordance with applicable UK accounting standards.
Accounting convention
The financial statements are prepared under the historical cost convention.
Foreign currency transactions
Functional currency is the currency of the primary economic environment in which an entity operates and is normally the currency in which the entity
primarily generates and expends cash. Transactions in foreign currencies are initially recorded in the functional currency by applying the rate of exchange
ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional currency at the
rate of exchange ruling at the balance sheet date. Any resulting exchange differences are included in profit for the year. Exchange adjustments arising
when the opening net assets and the profits for the year retained by non-US dollar functional currency branches are translated into US dollars are taken to
a separate component of equity and reported in the statement of total recognized gains and losses.
Investments
Investments in subsidiaries and associated undertakings are recorded at cost. The company assesses investments for impairment whenever events
or changes in circumstances indicate that the carrying value of an investment may not be recoverable. If any such indication of impairment exists, the
company makes an estimate of its recoverable amount. Where the carrying amount of an investment exceeds its recoverable amount, the investment is
considered impaired and is written down to its recoverable amount.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which equity instruments are granted
and is recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award.
Fair value is determined by using an appropriate valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions,
other than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees
contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition is treated as a
cancellation, where this is within the control of the employee.
No expense is recognized for awards that do not ultimately vest, except for awards where vesting is conditional upon a market condition, which
are treated as vesting irrespective of whether or not the market condition is satisfied, provided that all other performance conditions are satisfied.
At each balance sheet date before vesting, the cumulative expense is calculated, representing the extent to which the vesting period has expired
and management’s best estimate of the achievement or otherwise of non-market conditions and the number of equity instruments that will ultimately
vest or, in the case of an instrument subject to a market condition, be treated as vesting as described above. The movement in cumulative expense since
the previous balance sheet date is recognized in the income statement, with a corresponding entry in equity.
When the terms of an equity-settled award are modified or a new award is designated as replacing a cancelled or settled award, the cost based on
the original award terms continues to be recognized over the original vesting period. In addition, an expense is recognized over the remainder of the new
vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of
the modified award, both as measured on the date of the modification. No reduction is recognized if this difference is negative.
When an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation and any cost not yet recognized in the income
statement for the award is expensed immediately.
Cash-settled transactions
The cost of cash-settled transactions is measured at fair value and recognized as an expense over the vesting period, with a corresponding liability
recognized on the balance sheet.
Pensions
The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit credit method, which
attributes entitlement to benefits to the current period (to determine current service cost) and to the current and prior periods (to determine the present
value of the defined benefit obligation). Past service costs are recognized immediately when the company becomes committed to a change in pension
plan design. When a settlement (eliminating all obligations for benefits already accrued) or a curtailment (reducing future obligations as a result of a material
reduction in the scheme membership or a reduction in future entitlement) occurs, the obligation and related plan assets are remeasured using current
actuarial assumptions and the resultant gain or loss is recognized in the income statement during the period in which the settlement or curtailment occurs.
The interest element of the defined benefit cost represents the change in present value of scheme obligations resulting from the passage of
time, and is determined by applying the discount rate to the opening present value of the benefit obligation, taking into account material changes in the
obligation during the year. The expected return on plan assets is based on an assessment made at the beginning of the year of long-term market returns
on plan assets, adjusted for the forecasts of contributions received and benefits paid during the year. The difference between the expected return on plan
assets and the interest cost is recognized in the income statement as other finance income or expense.
Actuarial gains and losses are recognized in full within the statement of total recognized gains and losses in the year in which they occur.
The defined benefit pension plan surplus or deficit in the balance sheet comprises the total for each plan of the present value of the defined benefit
obligation (using a discount rate based on high quality corporate bonds), less the fair value of plan assets out of which the obligations are to be settled
directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. The surplus or deficit, net of
taxation thereon, is presented separately above the total for net assets on the face of the balance sheet.
PC4 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 1. Accounting policies continued
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 (credit) charge included in the statement of total recognized gains and losses
Deferred tax
Origination and reversal of timing differences in the current year
This comprises:
Actuarial (loss) gain relating to pensions and other post-retirement benefits
Deferred tax
Pensions
Other taxable timing differences
Net deferred tax liability (asset)
Analysis of movements during the year
At 1 January
Exchange adjustments
Charge (credit) for the year on ordinary activities
Charge (credit) for the year in the statement of total recognized gains and losses
At 31 December
2011
(583)
(583)
–
–
–
410
34
139
(583)
–
$ million
2010
123
123
480
70
410
149
45
93
123
410
At 31 December 2011, deferred tax assets of $559 million on pensions (2010 nil) and $91 million on other timing differences (2010 nil) were not recognized
as it is not considered more likely than not that suitable taxable profits will be available in the company from which the future reversal of the underlying
timing differences can be deducted. It is anticipated that the reversal of these timing differences will benefit other group companies in the future.
3. Fixed assets – investments
Cost
At 1 January 2011
Additions
Disposals
At 31 December 2011
Amounts provided
At 1 January 2011
At 31 December 2011
Cost
At 1 January 2010
Additions
Disposals
At 31 December 2010
Amounts provided
At 1 January 2010
At 31 December 2010
Net book amount
At 31 December 2011
At 31 December 2010
Subsidiary
undertakings
Shares
Associated
undertakings
Shares
Loans
Total
$ million
122,723
3,719
(8)
126,434
74
74
93,137
29,637
(51)
122,723
74
74
126,360
122,649
2
–
–
2
–
–
2
–
–
2
–
–
2
2
2
–
–
2
2
2
2
–
–
2
2
2
–
–
122,727
3,719
(8)
126,438
76
76
93,141
29,637
(51)
122,727
76
76
126,362
122,651
BP Annual Report and Form 20-F 2011 PC5
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Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
3. Fixed assets – investments continued
The more important subsidiary undertakings of the company at 31 December 2011 and the percentage holding of ordinary share capital (to the nearest
whole number) are set out below. 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.
International
BP Global Investments
BP International
BP Holdings North America
BP Corporate Holdings
Burmah Castrol
%
100
100
100
100
100
Country of
incorporation
England & Wales
England & Wales
England & Wales
England & Wales
Scotland
Principal activities
Investment holding
Integrated oil operations
Investment holding
Investment holding
Lubricants
The carrying value of BP International Ltd in the accounts of the company at 31 December 2011 was $62.63 billion (2010 $59.63 billion).
4. Debtors
Group undertakings
Other
The carrying amounts of debtors approximate their fair value.
5. Creditors
Group undertakings
Accruals and deferred income
Dividends
Other
Within
1 year
17,695
3
17,698
2011
After
1 year
38
–
38
Within
1 year
14,440
4
14,444
Within
1 year
2,334
28
1
55
2,418
2011
After
1 year
4,264
35
–
–
4,299
Within
1 year
2,343
23
1
18
2,385
$ million
2010
After
1 year
38
–
38
$ million
2010
After
1 year
4,258
35
–
–
4,293
The carrying amounts of creditors approximate their fair value.
The maturity profile of the financial liabilities included in the balance sheet at 31 December is shown in the table below. These amounts are
included within Creditors – amounts falling due after more than one year, and are denominated in US dollars.
Amounts falling due after one year include $4,236 million payable to a group undertaking. This amount is subject to interest payable quarterly at
LIBOR plus 55 basis points.
Due within
1 to 2 years
2 to 5 years
More than 5 years
2011
49
14
4,236
4,299
$ million
2010
41
16
4,236
4,293
PC6 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 6. Pensions
The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an
annuity. With effect from 1 April 2010, BP closed its UK plan to new joiners other than some of those joining the North Sea business. The plan remains
open to ongoing accrual for those employees who joined BP on or before 31 March 2010. The majority of new joiners have the option to join a defined
contribution plan.
The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most recent
actuarial review was 31 December 2011. The principal plans are subject to a formal actuarial valuation every three years in the UK. The most recent formal
actuarial valuation of the main UK pension plan was as at 31 December 2008.
The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions used to evaluate
accrued pension at 31 December in any year are used to determine pension expense for the following year, that is, the assumptions at 31 December
2011 are used to determine the pension liabilities at that date and the pension cost for 2012.
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
2011
7.0
4.8
5.1
3.2
3.2
3.2
2010
7.3
5.5
5.4
3.5
3.5
3.5
%
2009
7.4
5.8
5.3
3.4
3.4
3.4
Our discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the expected benefit
payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long-term government bonds.
The inflation rate assumption is used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions.
Our assumption for the rate of increase in salaries is based on our inflation rate assumption plus an allowance for expected long-term real salary
growth. This includes allowance for promotion-related salary growth of 0.4%.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best
practice in the UK, and have been chosen with regard to the latest available published tables adjusted where appropriate to reflect the experience of the
group and an extrapolation of past longevity improvements into the future.
Mortality assumptions
Life expectancy at age 60 for a male currently aged 60
Life expectancy at age 60 for a male currently aged 40
Life expectancy at age 60 for a female currently aged 60
Life expectancy at age 60 for a female currently aged 40
2011
27.6
30.5
29.3
32.0
2010
26.1
29.1
28.7
31.6
Years
2009
26.0
29.0
28.6
31.5
On 31 March 2011, the Burmah Castrol Pension Fund was merged into the BP Pension Fund. As at that date the assets of the Burmah Castrol Pension
Fund were transferred to the BP Pension Fund, and in return the BP Pension Fund will provide the pension benefits which would otherwise have been
provided under the Burmah Castrol Pension Fund. There was no change to the benefits provided to members of either fund as a result of the merger.
In addition, the obligation to provide benefits under an unfunded pension plan operated by Lubricants UK Limited (LUL) was transferred to BP p.l.c.
on 31 March 2011. After this date the benefits previously provided under the LUL plan will be provided through an unfunded pension plan operated by
BP p.l.c.
In each case these transfers were effected at the market value of the pension assets and liabilities as at the date of transfer. As a consequence of
the transfers, the pension plan asset amount of the BP Pension Fund, which is reflected in the accounts of BP p.l.c., was increased by $1,743 million and
the pension liability was increased by $1,671 million.
Movements in the value of plan assets during the year are shown in detail below.
Equities
Bonds
Property
Cash
Present value of plan liabilities
Surplus (deficit) in the plan
Expected
long-term
rate of
return
%
8.0
4.4
6.5
1.7
7.0
2011
2010
Expected
long-term
rate of
return
%
8.0
5.1
6.5
1.4
7.3
Market
value
$ million
17,202
4,141
1,710
534
23,587
25,675
(2,088)
Market
value
$ million
17,703
3,128
1,412
369
22,612
20,742
1,870
Expected
long-term
rate of
return
%
8.0
5.4
6.5
1.1
7.4
$ million
2009
Market
value
$ million
16,148
2,989
1,221
595
20,953
19,882
1,071
BP Annual Report and Form 20-F 2011 PC7
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Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
6. Pensions continued
Analysis of the amount charged to operating profit
Current service costa
Settlement, curtailment and special termination benefitsb
Payments to defined contribution plans
Total operating chargec
Analysis of the amount credited (charged) to other finance income
Expected return on pension plan assets
Interest on pension plan liabilities
Other finance income
Analysis of the amount recognized in the statement of total recognized gains and losses
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial (loss) gain recognized in statement of total recognized gains and losses
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustment
Current service costa
Interest cost
Transfers of plans from other group companiesd
Disposals
Special termination benefits
Contributions by plan participants
Benefit payments (funded plans)e
Benefit payments (unfunded plans)e
Actuarial loss on obligation
Benefit obligation at 31 December
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustment
Expected return on plan assetsa f
Contributions by plan participantsg
Contributions by employers (funded plans)
Transfers of plans from other group companiesd
Disposals
Benefit payments (funded plans)e
Actuarial gain (loss) on plan assetsf
Fair value of plan assets at 31 Decemberh
Surplus (deficit) at 31 December
2011
380
3
5
388
1,773
(1,240)
533
(1,976)
(2,710)
(84)
(4,770)
2011
20,742
(204)
380
1,240
1,671
–
3
33
(980)
(4)
2,794
25,675
22,612
(41)
1,773
33
423
1,743
–
(980)
(1,976)
23,587
(2,088)
$ million
2010
381
21
1
403
1,486
(1,098)
388
1,479
(1,034)
12
457
$ million
2010
19,882
(775)
381
1,098
–
(43)
21
38
(879)
(3)
1,022
20,742
20,953
(819)
1,486
38
397
–
(43)
(879)
1,479
22,612
1,870
a The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are included in current service cost.
b The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
c Included within production and manufacturing expenses and distribution and administration expenses.
d Transfer of the Burmah Castrol Pension Fund and the Lubricants UK Limited pension plan.
e The benefit payments amount shown above comprises $965 million benefits plus $15 million of plan expenses incurred in the administration of the benefit.
f The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain or loss on plan assets as disclosed above.
g The contributions by plan participants for the UK are mostly comprised of contributions made under salary sacrifice arrangements.
h Reflects $23,482 million of assets held in the BP Pension Fund (2010 $22,516 million) and $75 million held in the BP Global Pension Trust (2010 $68 million), with $30 million representing the company’s
share of Merchant Navy Officers Pension Fund (2010 $28 million).
PC8 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 6. Pensions continued
Represented by
Asset recognized
Liability recognized
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded plans as follows
Fundeda
Unfunded
2011
–
(2,088)
(2,088)
(1,852)
(236)
(2,088)
$ million
2010
2,069
(199)
1,870
2,064
(194)
1,870
(25,439)
(236)
(25,675)
(20,548)
(194)
(20,742)
a Reflects $25,324 million of liabilities of the BP Pension Fund (2010 $20,448 million), $78 million of liabilities of the BP Global Pension Trust (2010 $67 million) and $37 million of liabilities representing the
company’s share of the multi-employer Merchant Navy Officers Pension Fund (2010 $33 million).
Reconciliation of plan surplus (deficit) to balance sheet
Surplus (deficit) at 31 December
Deferred tax
Represented by
Asset recognized on balance sheet
Liability recognized on balance sheet
2011
(2,088)
–
(2,088)
–
(2,088)
(2,088)
$ million
2010
1,870
(480)
1,390
1,537
(147)
1,390
The aggregate level of employer contributions into the BP Pension Fund in 2012 is expected to be $492 million.
History of surplus and of experience gains and losses
Benefit obligation at 31 December
Fair value of plan assets at 31 December
Surplus (deficit)
Experience gains and losses on plan liabilities
Amount ($ million)
Percentage of benefit obligation
Actual return less expected return on pension plan assets
Amount ($ million)
Percentage of plan assets
Actuarial (loss) gain recognized in statement of total recognized gains and losses
Amount ($ million)
Percentage of benefit obligation
2011
2010
2009
2008
25,675
23,587
(2,088)
20,742
22,612
1,870
19,882
20,953
1,071
15,414
16,930
1,516
$ million
2007
22,146
29,411
7,265
(84)
0%
12
0%
(146)
(1)%
(65)
0%
(155)
(1)%
(1,976)
1,479
1,634
(6,533)
(8)%
7%
8%
(39)%
(4,770)
(19)%
457
2%
(585)
(5,122)
(3)%
(33)%
404
1%
698
3%
Cumulative amount recognized in statement of total recognized gains and losses
(6,005)
(1,235)
(1,692)
(1,107)
4,015
BP Annual Report and Form 20-F 2011 PC9
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Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
7. Called-up share capital
The allotted, called-up and fully paid share capital at 31 December was as follows:
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share plansb
31 December
Shares
(thousands)
7,233
5,473
20,647,160
165,601
649
20,813,410
2011
$ millions
12
9
21
Shares
(thousands)
7,233
5,473
41
–
5,162 20,629,665
–
17,495
5,203 20,647,160
5,224
2010
$millions
12
9
21
5,158
–
4
5,162
5,183
a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of
preference shares.
b The nominal value of new shares issued for the employee share plans in 2011 amounted to $162,000. Consideration received relating to the issue of new shares for employee share plans amounted to
$4 million (2010 $138 million).
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes for every
£5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands vote on other
resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the preference
shares plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid up on the preference
shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous six months over par value.
8. Capital and reserves
At 1 January 2011
Currency translation differences
Actuarial loss on pensions
(net of tax)
Share-based payments
Profit for the year
Dividends
At 31 December 2011
At 1 January 2010
Currency translation differences
Actuarial gain on pensions
(net of tax)
Share-based payments
Profit for the year
Dividends
At 31 December 2010
Share
capital
5,183
–
–
–
–
41
5,224
Share
capital
5,179
–
–
4
–
–
5,183
Share
premium
account
9,987
–
Capital
redemption
reserve
1,072
–
–
6
–
(41)
9,952
Share
premium
account
9,847
–
–
140
–
–
9,987
–
–
–
–
1,072
Capital
redemption
reserve
1,072
–
–
–
–
–
1,072
Merger
reserve
26,509
–
–
–
–
–
26,509
Merger
reserve
26,509
–
–
–
–
–
26,509
Treasury
shares
(21,085)
–
–
150
–
–
(20,935)
Share-based
payment
reserve
1,585
–
–
(11)
–
–
1,574
Profit
and loss
account
108,794
164
(4,187)
102
11,484
(4,072)
112,285
Treasury
shares
(21,303)
–
Share-based
payment
reserve
1,519
–
Profit
and loss
account
96,564
(45)
$ million
Total
131,919
164
(4,187)
(15)
11,484
(4,072)
135,293
$ million
Total
119,173
(45)
–
–
276
276
218
–
–
(21,085)
66
–
–
1,585
(150)
14,776
(2,627)
108,794
366
14,776
(2,627)
131,919
Own
shares
(126)
–
–
(262)
–
–
(388)
Own
shares
(214)
–
–
88
–
–
(126)
As a consolidated income statement is presented for the group, a separate income statement for the parent company is not required to be published.
The profit and loss account reserve includes $24,107 million (2010 $24,107 million), the distribution of which is limited by statutory or other
restrictions.
The accounts for the year ended 31 December 2011 do not reflect the dividend announced on 7 February 2012 and payable in March 2012; this will
be treated as an appropriation of profit in the year ended 31 December 2012.
PC10 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 9. Cash flow
Reconciliation of net cash flow to movement of funds
Decrease in cash
Movement of funds
Net cash at 1 January
Net cash at 31 December
Notes on cash flow statement
(a) Reconciliation of operating profit to net cash (outflow) inflow from operating activities
Operating profit
Net operating charge for pensions 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
(b) Analysis of movements of funds
Cash at bank
10. Contingent liabilities
2011
$ million
2010
(4)
(4)
4
–
2011
11,136
(117)
(12,132)
528
(3,253)
39
(3,799)
(24)
(24)
28
4
2010
14,514
2
(15,188)
549
17,405
(51)
17,231
At
1 January
2011
4
$ million
At
31 December
2011
–
Cash
flow
(4)
The parent company has issued guarantees under which amounts outstanding at 31 December 2011 were $41,847 million (2010 $36,779 million), of
which $40,449 million (2010 $36,747 million) related to guarantees in respect of subsidiary undertakings, including $39,708 million (2010 $36,006 million)
in respect of borrowings by its subsidiary undertakings and $30 million (2010 $30 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 (credit) recognized for cash-settled share-based payment transactions
Total expense recognized for share-based payment transactions
Closing balance of liability for cash-settled share-based payment transactions
Total intrinsic value for vested cash-settled share-based payments
2011
579
5
584
12
1
$ million
2010
577
(1)
576
16
1
For ease of presentation, options and shares 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 main
share-based payment plans that existed during the year are detailed below.
Plans for executive directors
For further information on the Executive Directors’ Incentive Plan (EDIP) see the Directors’ remuneration report on pages 139 to 151.
Plans for senior employees
The group operates a number of equity-settled share plans under which share units are granted to its senior leaders and certain other employees. These
plans typically have a three-year performance or restricted period during which the units accrue net notional dividends which are treated as having been
reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements apply for participants that leave for
qualifying reasons. Grants are settled in cash where the regulatory environment prohibits participants to hold BP shares.
Performance unit plans
The number of units granted is related to the level of seniority of employees. The number of units converted to shares is determined by reference to
performance measures over the three-year performance period. The main performance measure used is BP’s total shareholder return (TSR) compared to
the other oil majors. Plans included in this category are the Competitive Performance Plan (CPP), and, in part, the Performance Share Plan (PSP).
BP Annual Report and Form 20-F 2011 PC11
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Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
11. Share-based payments continued
Restricted share unit plans
Share unit grants under BP’s restricted plans typically take into account the employee’s performance in either the current or the prior year, track record
of delivery, business and leadership skills and potential. One restricted share unit plan for senior employees, used in special circumstances such as
recruitment and retention, normally has no performance conditions. Plans included in this category are the Executive Performance Plan (EPP), the
Restricted Share Plan (RSP), the Deferred Annual Bonus Plan (DAB) and, in part, the Performance Share Plan (PSP).
BP Share Option Plan (BPSOP)
Share options with an exercise price equivalent to the market price of a BP share immediately preceding the date of grant were granted to participants
annually until 2006. These options are not subject to any performance conditions and are exercisable between the third and tenth anniversaries of the
grant date.
BP Plan 2011
Share options with an exercise price equivalent to the market price of a BP share immediately preceding the date of grant were granted to participants in
2011. These options are not subject to any performance conditions and will be exercisable between the third and tenth anniversaries of the grant date.
Share Value Plan
In 2012, the group will launch a new performance plan known as the Share Value Plan (SVP) which will grant restricted share units with a three-year
performance period. The number of units granted is dependent on grade and country of operation. The performance measures are grade specific and
include: individual rating, balanced scorecard and TSR criteria. For the 2012 performance year, no further grants will be made under DAB. From 1 January
2012, no further grants will be made under CPP, EPP or PSP.
Other plans
For further information on BP’s savings and matching plans, including the BP ShareMatch plans and the BP ShareSave Plan, see page 158.
Share option transactions
Details of share option transactions for the year under the share options plans are as follows:
Share option transactions
Outstanding at 1 January
Granteda
Forfeited
Exercised
Expired
Outstanding at 31 December
Exercisable at 31 December
Number
of
options
263,306,722
152,472,556
(9,058,406)
(2,502,306)
(29,717,854)
374,500,712
209,776,014
2011
Weighted
average
exercise price
$
8.75
6.03
7.22
7.64
8.26
7.73
9.01
Number
of
options
295,895,357
10,420,287
(9,499,661)
(31,839,034)
(1,670,227)
263,306,722
242,530,635
2010
Weighted
average
exercise price
$
8.73
6.08
7.88
7.97
8.71
8.75
8.90
a Share options granted during 2011 include 142.5 million options awarded under the BP Plan 2011 with a fair value of $1.02 per option at the date of grant, determined using a binomial option pricing model
including assumptions for share price volatility, dividends and cancellations.
The weighted average share price at the date of exercise was $7.71 (2010 $9.54 and 2009 $9.10).
For options outstanding at 31 December 2011, the exercise price ranges and weighted average remaining contractual lives were as shown below:
Range of exercise prices
$5.66 – $7.22
$7.23 – $8.79
$8.80 – $10.35
$10.36 – $11.92
Weighted
average
remaining life
Years
7.51
1.21
2.73
3.81
5.15
Options outstandinga
Weighted
average
exercise price
$
6.11
8.13
9.83
11.14
7.73
Number
of
shares
199,571,741
81,608,110
22,264,187
71,056,674
374,500,712
Options exercisable
Weighted
average
exercise price
$
6.37
8.13
9.92
11.14
9.01
Number
of
shares
37,283,772
81,608,110
19,827,458
71,056,674
209,776,014
a Included within options outstanding at 31 December 2011 are options granted annually under the BPSOP until 2006 of 208 million options (2010 239 million options).
PC12 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. 11. Share-based payments continued
Fair values and associated details for restricted share units granted
For restricted share units granted in 2011, the number of units and weighted average fair value at the date of grant were as shown below:
Restricted share units granted in 2011
Number of restricted share units granted (million)
Weighted average fair value
Fair value measurement basis
Restricted share units granted in 2010
Number of restricted share units granted (million)
Weighted average fair value
Fair value measurement basis
CPP
1.4
$11.99
Monte
Carlo
CPP
1.3
$19.81
Monte
Carlo
EPP
8.9
$7.51
Market
value
EPP
7.6
$9.43
Market
value
RSP
20.0
$6.86
Market
value
RSP
21.4
$6.78
Market
value
DAB
17.5
$7.51
Market
value
DAB
24.5
$9.43
Market
value
PSP
19.2
$7.51
Market
value
PSP
16.0
$9.43
Market
value
The group uses the observable market price for ordinary shares at the date of grant to determine the fair value of non-TSR restricted share units.
The group used a Monte Carlo simulation to determine the fair values of the TSR elements of the 2011, 2010 and 2009 CPP and EDIP grants and
the 2009 PSP grant. In accordance with the plans’ rules, the model simulates BP’s TSR and compares it against its principal strategic competitors over the
three-year period of the plans. The model takes into account the historical dividends, share price volatilities and covariances of BP and each comparator
company to produce a predicted distribution of relative share performance. This is applied to the reward criteria to give an expected value of the TSR
element.
Accounting expense does not necessarily represent the actual value of share-based payments made to recipients, which are determined by the
remuneration committee according to established criteria.
Employee Share Ownership Plan Trusts (ESOPs)
ESOPs have been established to acquire BP shares to satisfy any awards made to participants under the BP share plans as required. The ESOPs have
waived their rights to dividends on shares held for future awards and are funded by the group. Until such time as the company’s own shares held by the
ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in shareholders’ equity (see Note 8). Assets and
liabilities of the ESOPs are recognized as assets and liabilities of the group.
At 31 December 2011 the ESOPs held 27,784,503 shares (2010 11,477,253 shares and 2009 18,062,246 shares) for potential future awards,
which had a market value of $197 million (2010 $82 million and 2009 $174 million).
12. Auditor’s remuneration
Fees payable to the company’s auditors for the audit of the company’s accounts were $15 million (2010 $17 million).
Remuneration receivable by the company’s auditors for the supply of other services to the company is not presented in the parent company
financial statements as this information is provided in the consolidated financial statements.
BP Annual Report and Form 20-F 2011 PC13
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Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
13. Directors’ remuneration
Remuneration of directors
Total for all directors
Emoluments
Gains made on the exercise of share options
Amounts awarded under incentive schemes
2011
10
–
1
$ million
2010
15
2
4
Emoluments
These amounts comprise fees paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and benefits earned
during the relevant financial year, plus bonuses awarded for the year. There was no compensation for loss of office in 2011 (2010 $3 million and 2009 nil).
Pension contributions
During 2011, one executive director participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which
contributions are made by BP based on actuarial advice. Two US executive directors participated in the US BP Retirement Accumulation Plan during 2011.
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 139 to 151.
PC14 BP Annual Report and Form 20-F 2011
Parent company financial statements of BP p.l.c.The parent company financial statements of BP p.l.c. on pages PC1 – PC14 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC. Reports and publications
BP’s reports and publications are available to view online
or download from bp.com/annualreport
Summary Review 2011
Read a summary of our fi nancial
and operating performance in
BP Summary Review 2011 in print
or online.
bp.com/summaryreview
Sustainability Review
Read the summary
BP Sustainability Review
2011 in print or read more
online from late March 2012.
bp.com/sustainability
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Acknowledgements
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© BP p.l.c. 2012