SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|¨||REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) or (g)|
OF THE SECURITIES EXCHANGE ACT OF 1934
|þ||ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)|
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended 31 December 2011
|¨||TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
|¨||SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
Commission file number: 1-6262
(Exact name of Registrant as specified in its charter)
England and Wales
(Jurisdiction of incorporation or organization)
1 St Jamess Square, London SW1Y 4PD
(Address of principal executive offices)
Dr Brian Gilvary
1 St Jamess Square, London SW1Y 4PD
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||Name of each exchange on which registered|
|Ordinary Shares of 25c each||New York Stock Exchange*|
|Floating Rate Guaranteed Notes due June 2013||New York Stock Exchange|
|Floating Rate Guaranteed Notes due December 2013||New York Stock Exchange|
|Floating Rate Guaranteed Notes due 2014||New York Stock Exchange|
|3.125% Guaranteed Notes due 2012||New York Stock Exchange|
|5.25% Guaranteed Notes due 2013||New York Stock Exchange|
|3.625% Guaranteed Notes due 2014||New York Stock Exchange|
|1.7% Guaranteed Notes due 2014||New York Stock Exchange|
|3.875% Guaranteed Notes due 2015||New York Stock Exchange|
|3.125% Guaranteed Notes due 2015||New York Stock Exchange|
|2.248% Guaranteed Notes due 2016||New York Stock Exchange|
|3.2% Guaranteed Notes due 2016||New York Stock Exchange|
|4.75% Guaranteed Notes due 2019||New York Stock Exchange|
|4.5% Guaranteed Notes due 2020||New York Stock Exchange|
|4.742% Guaranteed Notes due 2021||New York Stock Exchange|
|3.561% Guaranteed Notes due 2021||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.
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
Indicate the number of outstanding shares of each of the issuers classes of capital or common stock as of the close of the period covered by the annual report.
|Ordinary Shares of 25c each||18,975,902,659|
|Cumulative First Preference Shares of £1 each||7,232,838|
|Cumulative Second Preference Shares of £1 each||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 þ||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 þ|
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.
|Yes þ||No ¨|
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 ¨|
*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):
|Large accelerated filer þ||Accelerated filer ¨||Non-accelerated filer ¨|
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
|U.S. GAAP ¨||
International Financial Reporting
Standards as issued by the
International Accounting Standards Board þ
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.
|Item 17 ¨||Item 18 ¨|
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 ¨||No þ|
Cross reference to Form 20-F
|Identity of Directors, Senior Management and Advisors||n/a|
|Offer Statistics and Expected Timetable||n/a|
|A.||Selected financial data||56|
|B.||Capitalization and indebtedness||n/a|
|C.||Reasons for the offer and use of proceeds||n/a|
|Information on the Company|
|A.||History and development of the company||5, 25-36|
|B.||Business overview||18-51, 64-111|
|D.||Property, plants and equipment||49, 81-83, 89-93, 157, 280-281|
|Unresolved Staff Comments||None|
|Operating and Financial Review and Prospects|
|A.||Operating results||56-58, 79, 81-82, 95-96, 101, 154-157|
|B.||Liquidity and capital resources||103-106|
|C.||Research and development, patent and licenses||74-76, 208|
|E.||Off-balance sheet arrangements||104|
|F.||Tabular disclosure of contractual commitments||104-105|
|Directors, Senior Management and Employees|
|A.||Directors and senior management||114-117|
|C.||Board practices||120-133, 246-249|
|E.||Share ownership||117, 140-150, 157-158, 246-247|
|Major Shareholders and Related Party Transactions|
|B.||Related party transactions||171, 215-216|
|C.||Interests of experts and counsel||n/a|
|A.||Consolidated statements and other financial information||159-166, 176-258|
|The Offer and Listing|
|A.||Offer and listing details||167-168|
|B.||Plan of distribution||n/a|
|F.||Expenses of the issue||n/a|
|B.||Memorandum and articles of association||136-138|
|F.||Dividends and paying agents||n/a|
|G.||Statements by experts||n/a|
|H.||Documents on display||170|
|Quantitative and Qualitative Disclosures about Market Risk||217-222, 224-228|
|Description of securities other than equity securities|
|B.||Warrants and Rights||n/a|
|D.||American Depositary Shares||171|
|Defaults, Dividend Arrearages and Delinquencies||None|
|Material Modifications to the Rights of Security Holders and Use of Proceeds||None|
|Controls and Procedures||135|
|Audit Committee Financial Expert||126|
|Code of Ethics||134|
|Principal Accountant Fees and Services||136|
|Exemptions from the Listing Standards for Audit Committees||n/a|
|Purchases of Equity Securities by the Issuer and Affiliated Purchasers||170|
|Change in Registrants Certifying Accountant||None|
|Financial Statements||176-258, 259-281|
|2||BP Annual Report and Form 20-F 2011|
|Business review: Group overview|
|12||Board of directors|
|14||Group chief executives letter|
|42||Our management of risk|
|Business review: BP in more depth|
|69||Environmental and social responsibility|
|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 groups business|
|Directors and senior management|
|114||Directors and senior management|
|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|
|Directors remuneration report|
|142||Executive directors remuneration|
|151||Non-executive directors remuneration|
|Additional information for shareholders|
|154||Critical accounting policies|
|157||Property, plant and equipment|
|159||Called-up share capital|
|167||Relationships with suppliers and contractors|
|167||Share prices and listings|
|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|
|172||Annual general meeting|
|176||Consolidated financial statements of the BP group|
|182||Notes on financial statements|
|259||Supplementary information on oil and natural gas (unaudited)|
|BP Annual Report and Form 20-F 2011||3|
In this document, unless the context otherwise requires, the following terms shall have the meaning set out below.
American depositary receipt.
American depositary share.
Annual general meeting.
The former Amoco Corporation and its subsidiaries.
Atlantic Richfield Company and its subsidiaries.
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.
159 litres, 42 US gallons.
barrels per day.
barrels of oil equivalent.
BP, BP group or the group
BP p.I.c. and its subsidiaries.
Burmah Castrol PLC and its subsidiaries.
Cent or c
One-hundredth of the US dollar.
Dollar or $
The US dollar.
Generally accepted accounting practice.
Gulf Coast Restoration Organization.
Crude oil and natural gas.
International Financial Reporting Standards.
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).
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.
Crude oil, condensate and natural gas liquids.
Liquefied natural gas.
London Stock Exchange or LSE
London Stock Exchange plc.
Liquefied petroleum gas.
Multi-District Litigation proceedings pending in New Orleans.
Multi-District Litigation proceedings pending in Houston.
thousand barrels per day.
thousand barrels of oil equivalent per day.
million British thermal units.
million barrels of oil equivalent.
million cubic feet.
million cubic feet per day.
Natural gas liquids.
Organization for Economic Co-operation and Development.
Organization of Petroleum Exporting Countries.
Ordinary fully paid shares in BP p.I.c. of 25c each.
Pence or p
One-hundredth of a pound sterling.
Pound, sterling or £
The pound sterling.
Cumulative First Preference Shares and Cumulative Second Preference Shares in BP p.l.c. of £1 each.
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.
The United States Securities and Exchange Commission.
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.
Deepwater Horizon Oil Spill Trust.
United Kingdom of Great Britain and Northern Ireland.
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. 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 176-177.
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).
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 Chairmans letter (pages 8-11), the Group chief executives 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, BPs 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 BPs 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 Marketings 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 BPs competitive position are based on the companys belief and, in some cases, rely on a range of sources, including investment analysts reports, independent market studies and BPs 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. BPs 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 companys 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 Jamess 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|
THIS PAGE INTENTIONALLY BLANK
|6||BP Annual Report and Form 20-F 2011|
2011 was a year of recovery, consolidation and change. We laid strong foundations, reshaped the portfolio and recovered momentum.
|Carl-Henric Svanberg sets out the actions taken by the board to establish a stronger, safer BP.|
|12||Board of directors|
|BPs board of directors, as at 6 March 2012.|
|14||Group chief executives letter|
|Bob Dudley reports on BPs progress against its priorities of enhancing safety, earning back trust and growing value.|
|From oil prices, natural gas prices and refining margins during the year to the long-term outlook for the global energy industry.|
|A clear overview of todays BP, from our business model to what we stand for and where we operate.|
|What you can expect from us and what you can measure, as we work to create a stronger, safer BP.|
|42||Our management of risk|
|The strengthened processes and systems we are putting in place to make BP a safer, more risk-aware company.|
|Key measures, actions and events in a year of consolidation and change.|
|BP Annual Report and Form 20-F 2011||7|
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 BPs 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.
BPs 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 groups 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. BPs 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 BPs LNG activities are focused on building competitively advantaged liquefaction projects.|
|BP Annual Report and Form 20-F 2011||9|
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
BPs joint venture
with Husky Energy.
For more information
on the board and its
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. Bills 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 companys 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 BPs 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 worlds 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 BPs progress at this point next year.
6 March 2012
|BP Annual Report and Form 20-F 2011||11|
|12||BP Annual Report and Form 20-F 2011|
|BP Annual Report and Form 20-F 2011||13|
Group Chief Executive
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 groups 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, BPs 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.
|14||BP Annual Report and Form 20-F 2011|
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.
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 companys 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.
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.
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 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|
Group chief executives letter
For more on the
strategic priorities set
out in the 10-point plan,
see Our strategy.
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
In giant fields, work with our partners has increased output at Iraqs 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.
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 BPs employees for their resilience. They were again tested hard this year. The character of BPs 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.
Group Chief Executive
6 March 2012
On a gross joint-venture basis (which includes 100% of the capacity of equity-accounted entities where BP has partial ownership). Including BPs share of joint ventures on a net basis, the capacity added was 274MW.
|BP Annual Report and Form 20-F 2011||17|
In 2011, energy markets proved resilient, with continued growth despite volatile conditions in the global economy.
work at BP's Whiting
refinery, Indiana, made
in 2011, with the
completion of a new
pipeline to Canada.
at our East Azeri
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.
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|
Below Work at BP's
margins in Europe
increased in 2011,
as demand for
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 2010s 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.
From Oil Market Report February 2012©, OECD/IEA 2012, page 5.
b BP Statistical Review of World Energy June 2011.
|BP Annual Report and Form 20-F 2011||19|
Left Operations at
BPs Na Kika field in
deepwater Gulf of
Mexico. BP is one of
the largest producers
of hydrocarbons in
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|
For more information, see
Refining and Marketing.
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
for a 1.25mtpa PTA
plant to be added to
in Zhuhai, China.
|BP Annual Report and Form 20-F 2011||21|
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 worlds needs.
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.
Long-term growth in energy demand
Energy demand is linked to economic growth, development and population. The worlds 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 lEAs 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.
|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
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.
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.
|BP Annual Report and Form 20-F 2011||23|
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.
|24||BP Annual Report and Form 20-F 2011|
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.
Above When completed in the
second half of 2013, modernization
work at our Whiting refinery
should enable BP to capture additional margins.
For more information about
Alternative Energy, see Other
businesses and corporate.
For definitions of subsidiaries,
joint ventures and associates,
see Miscellaneous terms.
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|
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.
|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
Right During 2011, full
Creek 2 wind farm in
For more information,
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|
Our organization: Business model
For more information on
Exploration and Production,
see BP in more depth.
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
|28||BP Annual Report and Form 20-F 2011|
For more information on
Refining and Marketing,
see BP in more depth.
Technology will continue to play a critical role in our upstream activities, as the upstream technology flagships diagram demonstrates. In addition, our Project 20K 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
|BP Annual Report and Form 20-F 2011||29|
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.
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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.
For more information, see
Above In 2011, BP
Below A team at work in
For more information on employees, see BP in more depth.
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.
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|
Our organization: People and governance
For more information on contractors, see Working with partners and contractors.
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 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.
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Find out more online
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.
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.
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.
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.
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.
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.
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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.
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|BP Annual Report and Form 20-F 2011||35|
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.
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.
Risk management review
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 BPs upstream business for 20 years.
Values and behaviours
We have refreshed our values and behaviours and continue embedding these into how we work together.
See Safety, page 65
In detail See Our management
of risk, page 42
In detail See Exploration and
Production, page 80
See Our values, page 32
Joint ventures not operated by BP
We have aligned performance and reward with our values and introduced safety and taking a long-term perspective as key indicators.
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.
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.
See Our values, page 32
In detail See Working with
partners and contractors, page 69
See Technology, page 74
In detail See Our partners in joint ventures, page 69
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Below BP has a
in Trinidad & Tobago,
operating 13 offshore
platforms and holding
an interest in Atlantic LNG.
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 BPs 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.
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.
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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|
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.
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.
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.
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.
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 groups investment in TNK-BP will be reported as a separate operating segment.
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|What you can measure|
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.
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
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.
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.
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 groups 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.
Left Lingen refinery in
Germany is one of Europes
most complex refineries due
to its ability to fully upgrade
crude during processing.
|BP Annual Report and Form 20-F 2011||39|
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|BP Annual Report and Form 20-F 2011||41|
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, BPs 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 groups 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.
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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 groups 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 groups 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.
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Our management of risk
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.
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.
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.
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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,
Above Work at BP's Tangguh
|BP Annual Report and Form 20-F 2011||45|
Our management of risk
For more information
on OMS, see Safety.
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.
|46||BP Annual Report and Form 20-F 2011|
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.
For more information, see Safer drilling.
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.
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|
For more information on the Gulf of Mexico oil spill, see BP in more depth.
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.
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.
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 groups financial results.
During 2010 and 2011 combined, we strengthened the groups 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 BPs 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.
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.
Net debt ratio is a non-GAAP measure. See Note 35 on page 230 for the equivalent measure on an IFRS basis.
|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.
a See Financial statements Note 6 on page 200.
b Based on sales of consolidated subsidiaries only this excludes equity-accounted entities.
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 BPs 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 segments 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|
See Financial statements Note 6 on page 200. See also Financial and operating performance on page 94.
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 BPs 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 segments 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
Above The SECCO facility is BP's
|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.
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|
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) 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.
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-BPs track record of successful licence renewal. Excluding this effect, BPs 2011 reserves replacement ratio would have been 83%.
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.
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.
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.
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.
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.
|52||BP Annual Report and Form 20-F 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.
This represents reported incidents occurring within BPs operational HSSE reporting boundary. That boundary includes BPs own operated facilities and certain other locations or situations.
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 organizations priorities highlighted as an area for improvement.
Relates to BP employees.
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.
Each year we record the percentage of women and individuals from countries other than the UK and US among BPs 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.
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 BPs 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.
|BP Annual Report and Form 20-F 2011||53|
THIS PAGE INTENTIONALLY BLANK
|54||BP Annual Report and Form 20-F 2011|
|BP in more depth|
|69||Environmental and social responsibility|
|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 groups business|
|BP Annual Report and Form 20-F 2011||55|
Selected financial informationa
|$ million except per share amounts|
|Income statement data|
Sales and other operating revenues
Replacement cost profit (loss) before interest and taxb
Exploration and Production
Refining and Marketing
Other businesses and corporate
Gulf of Mexico oil spill responsec
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
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
Replacement cost profit (loss) for the year attributable to BP shareholdersb (basic)
Dividends paid per share cents
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)|
BP shareholders equity
Finance debt due after more than one year
Net debt to net debt plus equityg
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.
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.
Under IFRS these costs are presented as a reconciling item between the sum of the results of the reportable segments and the group results.
AII 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 Corporations interest in the Arkoma Basin Woodford shale assets and the purchase of a 25% interest in Chesapeakes Fayetteville shale assets. 2007 included $1,132 million for the acquisition of Chevrons Netherlands manufacturing company.
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.
The number of ordinary shares shown has been used to calculate per share amounts.
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 managements 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 BPs 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 managements 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 managements measure of performance.
|56||BP Annual Report and Form 20-F 2011|
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.
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. BPs 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).
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 BPs 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 BPs 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|
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 groups 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
|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 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
Gulf of Mexico oil spill response
Total before interest and taxation
Total before taxation
Taxation credit (charge)f
Total after taxation
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).
2009 included $1,579 million in relation to the impairment of goodwill allocated to the US West Coast fuels value chain.
Relates to an embedded derivative arising from a financing arrangement.
2011 included charges of $687 million in relation to raw materials purchase contracts associated with our exit from the solar business.
Finance costs relate to the Gulf of Mexico oil spill. See Financial statements Note 2 on page 190 for further details.
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 managements 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 managements measure of performance
|Refining and Marketinga|
Unrecognized gains (losses) brought forward from previous period
Unrecognized (gains) losses carried forward
Favourable (unfavourable) impact relative to managements measure of performance
Taxation credit (charge)b
|Exploration and Production|
|Refining and Marketinga|
Fair value accounting effects arise solely in the fuels business.
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|
|Exploration and Production|
Replacement cost profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Replacement cost profit before interest and tax
|Refining and Marketing|
Replacement cost profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Replacement cost profit before interest and tax
Profit (loss) before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Profit (loss) before interest and tax
|58||BP Annual Report and Form 20-F 2011|
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 planpages 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 BPs 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 attentionthose 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 groups 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 BPs 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 BPs 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.
Access and renewal BPs 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 BPs reputation, which may have a long-term impact on the groups 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 BPs activities specifically, arising from the Incident, could increase this risk.
Prices and markets BPs 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 groups oil and natural gas properties. Such reviews would reflect managements 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 groups 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.
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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 BPs 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.
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 groups 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 groups financial framework during 2010 to make it more prudent may not be sufficient to avoid a substantial and unexpected cash call.
BPs 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 groups 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 groups 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 BPs 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 BPs 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 BPs 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 BPs 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
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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 BPs 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 BPs trading activities, see Operational risks Treasury and trading activities on page 63.
Liabilities and provisions BPs 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 groups 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 BPs 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 groups 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 BPs 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 90s 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.
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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 groups business, competitive position, cash flows, results of operations, financial position, prospects, liquidity, shareholder returns and/or implementation of the groups 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 groups 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.
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.
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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 groups 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, Moodys Investors Service, Standard and Poors and Fitch Ratings downgraded the groups long-term credit ratings. Since that time, the groups 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 groups credit ratings, taken together with the reputational consequences of any such incident, the ratings and assessments published by analysts and investors concerns about the groups costs arising from any such incident, ongoing contingencies, liquidity, financial performance and volatile credit spreads, could increase the groups financing costs and limit the groups access to financing. The groups ability to engage in its trading activities could also be impacted due to counterparty concerns about the groups 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 groups credit ratings are downgraded. Certain counterparties for the groups non-trading businesses could also require that the group provide collateral for certain of its contractual obligations, particularly if the groups credit ratings were downgraded below investment grade or where a counterparty had concerns about the groups 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 groups ability to obtain financing and to engage in its trading activities on acceptable terms (or at all) would put pressure on the groups 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 ventures or associates 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.
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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 groups 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.
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 BPs knowledge or consent. BP has registered and paid required fees for patents and trademarks in Sanctioned Countries.
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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
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 groups 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 BPs 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 BPs 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.
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 boards 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 BPs 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 boards 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.
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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.
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.
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.
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
in accordance with industry recommended practice. In addition, BP requires that remotely operated vehicles can activate these BOPs in an emergency.
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 BPs 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.
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.
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.
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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.
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.
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.
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 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.
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.
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
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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.
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.
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)
Does not include either small or non-hazardous releases.
Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).
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.
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.
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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.
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.
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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.
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.
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
Canadas oil sands are believed to hold one of the worlds 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 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.
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.
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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.
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.
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 relating to the Gulf of Mexico oil spill
Additions to environmental remediation provision
Other environmental expenditure
Additions to environmental remediation provision
Additions to decommissioning provision
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.
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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 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.
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.
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.
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.
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
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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.
Number of employees at 31 December
Exploration and Production
Refining and Marketinga
Other business and corporate
Gulf Coast Restoration Organization
Exploration and Production
Refining and Marketinga
Other business and corporate
Gulf Coast Restoration Organization
Exploration and Production
Refining and Marketinga
Other business and corporate
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.
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
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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.
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 organizations 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 BPs 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
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 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 BPs know-how.
BPs 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 BPs 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.
BPs 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 Augsburgs 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 Universitys Kennedy School focused on examining current and future potential policies on energy, security and climate change.
BP is a founding member of the UKs 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 UKs emissions targets.
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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 BPs 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 BPs 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 Water 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.
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 BPs 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 BPs 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.
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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 BPs 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.
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. BPs 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.
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Completing the response
Throughout 2011, BP, working under the direction of the US Coast Guards 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.
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 BPs 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, BPs 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.
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.
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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.
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 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 BPs 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 grants, which were supplemented by a further $3.3 million from other
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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.
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 BPs 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 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.
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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 groups finance, procurement and supply chain, human resources, technology and information technology functions.
From 1 January 2012, the groups 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 nat