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SECURITIES AND EXCHANGE COMMISSION
OF THE SECURITIES EXCHANGE ACT OF 1934
OR
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 1-6262
(Jurisdiction of incorporation or organization)
United Kingdom
(Address of principal executive offices)
BP p.l.c.
1 St James’s Square, London SW1Y 4PD
United Kingdom
Tel +44 (0) 20 7496 4495
Fax +44 (0) 20 7496 4630
(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 2011 | New York Stock Exchange | |
Substitute Floating Rate Guaranteed Note due 2011 | New York Stock Exchange | |
1.55% Guaranteed Notes due 2011 | 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 | |
3.875% Guaranteed Notes due 2015 | New York Stock Exchange | |
3.125% Guaranteed Notes due 2015 | New York Stock Exchange | |
4.75% Guaranteed Notes due 2019 | New York Stock Exchange | |
4.5% Guaranteed Notes due 2020 | 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 |
None
None
Ordinary Shares of 25c each | 18,796,461,292 | |||
Cumulative First Preference Shares of £1 each | 7,232,838 | |||
Cumulative Second Preference Shares of £1 each | 5,473,414 |
Yesþ | Noo |
Yeso | Noþ |
Yesþ | Noo |
Yesþ | Noo |
Large accelerated filerþ | Accelerated filero | Non-accelerated filero |
International Financial Reporting | ||||
Standards as issued by the | ||||
U.S. GAAPo | International Accounting Standards Boardþ | Othero |
Item 17o | Item 18o |
Yeso | Noþ |
Annual Report | ||
and Form 20-F | ||
2010 |
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Page | ||||||||
Item 1. | Identity of Directors, Senior Management and Advisors | n/a | ||||||
Item 2. | Offer Statistics and Expected Timetable | n/a | ||||||
Item 3. | Key Information | |||||||
A. | Selected financial data | 23 | ||||||
B. | Capitalization and indebtedness | n/a | ||||||
C. | Reasons for the offer and use of proceeds | n/a | ||||||
D. | Risk factors | 27-32 | ||||||
Item 4. | Information on the Company | |||||||
A. | History and development of the company | 4, 14-15 | ||||||
B. | Business overview | 14-22, 33-82 | ||||||
C. | Organizational structure | 220-221 | ||||||
D. | Property, plants and equipment | 22, 43, 50-54, 127, 247-248 | ||||||
Item 4A. | Unresolved Staff Comments | None | ||||||
Item 5. | Operating and Financial Review and Prospects | |||||||
A. | Operating results | 24-26, 34, 41-42, 56-57, 61, 124-127 | ||||||
B. | Liquidity and capital resources | 63-67 | ||||||
C. | Research and development, patent and licenses | 76-77, 175 | ||||||
D. | Trend information | 67 | ||||||
E. | Off-balance sheet arrangements | 64 | ||||||
F. | Tabular disclosure of contractual commitments | 65 | ||||||
G. | Safe harbor | 4 | ||||||
Item 6. | Directors, Senior Management and Employees | |||||||
A. | Directors and senior management | 84-87 | ||||||
B. | Compensation | 112-121, 214-217 | ||||||
C. | Board practices | 90-104, 214-217 | ||||||
D. | Employees | 74-75 | ||||||
E. | Share ownership | 87, 112-118, 127-128, 214-216 | ||||||
Item 7. | Major Shareholders and Related Party Transactions | |||||||
A. | Major shareholders | 128-129 | ||||||
B. | Related party transactions | 129, 183-184 | ||||||
C. | Interests of experts and counsel | n/a | ||||||
Item 8. | Financial Information | |||||||
A. | Consolidated statements and other financial information | 129-133, 134, 144-227 | ||||||
B. | Significant changes | None | ||||||
Item 9. | The Offer and Listing | |||||||
A. | Offer and listing details | 134 | ||||||
B. | Plan of distribution | n/a | ||||||
C. | Markets | 134 | ||||||
D. | Selling shareholders | n/a | ||||||
E. | Dilution | n/a | ||||||
F. | Expenses of the issue | n/a | ||||||
Item 10. | Additional Information | |||||||
A. | Share capital | n/a | ||||||
B. | Memorandum and articles of association | 108-109 | ||||||
C. | Material contracts | 135 | ||||||
D. | Exchange controls | 135 | ||||||
E. | Taxation | 135-137 | ||||||
F. | Dividends and paying agents | n/a | ||||||
G. | Statements by experts | n/a | ||||||
H. | Documents on display | 137 | ||||||
I. | Subsidiary information | n/a | ||||||
Item 11. | Quantitative and Qualitative Disclosures about Market Risk | 185-190, 192-196 | ||||||
Item 12. | Description of securities other than equity securities | |||||||
A. | Debt Securities | n/a | ||||||
B. | Warrants and Rights | n/a | ||||||
C. | Other Securities | n/a | ||||||
D. | American Depositary Shares | 138 | ||||||
Item 13. | Defaults, Dividend Arrearages and Delinquencies | None | ||||||
Item 14. | Material Modifications to the Rights of Security Holders and Use of Proceeds | None | ||||||
Item 15. | Controls and Procedures | 106-107 | ||||||
Item 16A. | Audit Committee Financial Expert | 97 | ||||||
Item 16B. | Code of Ethics | 106 | ||||||
Item 16C. | Principal Accountant Fees and Services | 107 | ||||||
Item 16D. | Exemptions from the Listing Standards for Audit Committees | n/a | ||||||
Item 16E. | Purchases of Equity Securities by the Issuer and Affiliated Purchasers | 137 | ||||||
Item 16F. | Change in Registrant’s Certifying Accountant | None | ||||||
Item 16G. | Corporate governance | 105 | ||||||
Item 17. | Financial Statements | n/a | ||||||
Item 18. | Financial Statements | 144-227, 228-248 | ||||||
Item 19. | Exhibits | 140 |
2 BP Annual Report and Form 20-F 2010
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BP Annual Report and Form 20-F 2010 3
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1 St James’s Square,
London SW1Y4PD, UK.
Tel +44 (0)20 7496 4000.
Registered in England and Wales No. 102498. Stock exchange symbol ‘BP’.
501 Westlake Park Boulevard, Houston,Texas 77079.
Tel +1 281 366 2000.
4 BP Annual Report and Form 20-F 2010
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6 | Chairman’s letter | |
8 | Board of directors | |
10 | Group chief executive’s letter | |
12 | Progress in 2010 | |
14 | Group overview | |
34 | Gulf of Mexico oil spill | |
40 | Exploration and Production | |
55 | Refining and Marketing | |
61 | Other businesses and corporate |
63 | Liquidity and capital resources | |
68 | Corporate responsibility | |
76 | Research and technology | |
78 | Regulation of the group’s business | |
81 | Certain definitions |
BP Annual Report and Form 20-F 2010 5
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letter
pollution. Our response has been unprecedented
in scale, and we are determined to live up to our
commitments in the Gulf. We will also do
everything necessary to ensure BP is a company
that can be trusted by shareholders and
communities around the world.
6 BP Annual Report and Form 20-F 2010
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Carl-Henric Svanberg
Chairman
2 March 2011
BP Annual Report and Form 20-F 2010 7
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BP Annual Report and Form 20-F 2010 9
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executive’s letter
10 BP Annual Report and Form 20-F 2010
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a | On 1 February 2011 the English High Court granted an interim injunction restraining BP from taking any further steps in relation to the Rosneft transactions pending the outcome of arbitration proceedings. See Note 6 Events after the reporting period. |
Bob Dudley
Group Chief Executive
2 March 2011
BP Annual Report and Form 20-F 2010 11
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In 2010 our workforce RIF, which includes employees and contractors combined, was 0.61, compared with 0.34 in 2009 and 0.43 in 2008. The nature of the Gulf Coast response effort resulted in personal safety incident rates significantly higher than in other BP operations.
Our 2010 employee survey was delayed to allow for organizational changes to be reflected in the survey construction, with the survey expected to be carried out in summer 2011.
In 2010 there were 261 oil spills of one barrel or more, including the Gulf of Mexico oil spill. We are taking measures to strengthen mandatory safety-related standards and processes, including operational risk and integrity management.
In 2007 we began a process of making BP a simpler, more efficient organization. Since then our total number of employees has reduced by approximately 18,000, including around 9,200 in our non-retail businesses.
BP is progressively moving towards this as one of the key indicators for process safety, as we believe it provides a more comprehensive and better performance indicator of the safety and integrity of our facilities than oil spills alone.
(million tonnes of carbon dioxide equivalent)
We aim to manage our GHG emissions through a focus on operational energy efficiency and reductions in flaring and venting.
BP has maintained the percentage of female leaders in 2010 and remains focused on building a more sustainable pipeline of diverse talent for the future.
12 BP Annual Report and Form 20-F 2010
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Reported production in 2010 was 4% lower than in 2009, due to the effect of entitlement changes in our production-sharing agreements, the effect of acquisitions and disposals, and the impact of events in the Gulf of Mexico.
In 2010 we recorded a replacement cost loss primarily driven by a $40.9-billion pre-tax charge in relation to the Gulf of Mexico incident.
Our reserves replacement ratio in 2010 exceeded 100% once again. We continue to drive renewal through new access, exploration, targeted acquisitions and a strategic focus on increasing resources from fields we currently operate.
In June 2010 the BP board reviewed its dividend policy in light of the Gulf of Mexico incident, and the agreement to establish a $20-billion trust fund, and decided to cancel ordinary share dividends in respect of the first three quarters of 2010.
Refining availability continued its increasing trend in 2010, with the biggest contributor being the restoration of our Texas City refinery.
The reduction in operating cash flow primarily reflected the impacts of the Gulf of Mexico incident.
Total shareholder returns in 2010 were significantly impacted by the cancellation of dividend payments and the fall in share price brought about by the events in the Gulf of Mexico.
BP Annual Report and Form 20-F 2010 13
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a | On the basis of market capitalization, proved reserves and production. |
14 BP Annual Report and Form 20-F 2010
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BP Annual Report and Form 20-F 2010 15
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a | BP Energy Outlook 2030. |
b | See footnote e on page 56. |
c | Oil Market Report 10 February 2011©OECD/IEA 2011, page 4, first paragraph. |
d | BP Statistical Review of World Energy June 2010. |
e | Oil Market Report 10 February 2011©OECD/IEA 2011, Table 1, page 59. |
16 BP Annual Report and Form 20-F 2010
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a See footnote e on page 56. |
BP Annual Report and Form 20-F 2010 17
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a | BP Energy Outlook 2030. |
b | BP Statistical Review of World Energy June 2010.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. |
18 BP Annual Report and Form 20-F 2010
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BP Annual Report and Form 20-F 2010 19
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20 BP Annual Report and Form 20-F 2010
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a | See footnote a in Environment on page 72. |
b | See Exploration and Production – proved reserves replacement on page 42 for more detailed information on reserves replacement for subsidiaries and equity-accounted entities. |
c | Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime. |
• | Replacing more than 100% of our proved reserves, excluding acquisitions and disposals, on a combined basis of subsidiaries and equity-accounted entitiesb. | |
• | Taking final investment decisions on 15 projects, with an expected total BP net capital investment of $20 billion. | |
• | Increasing production for the Rumaila field in Southern Iraq by more than 10% above the rate initially agreed between the Rumaila Operating Organization partners and the Iraqi Ministry of Oil in December 2009. This significant milestone means that BP and its partners became eligible for service fees from the first quarter of 2011. | |
• | Accessing new resources across the globe – in Azerbaijan, China, the Gulf of Mexico, Indonesia, onshore North America and the UK. | |
• | Making the Hodoa discovery in Egypt, the first Oligocene deepwater discovery in the West Nile Delta. | |
• | TNK-BP increasing its production by 2.5% in 2010 compared with 2009. | |
• | Securing agreements to dispose of almost $22 billion of non-core assets in line with our plans following the Gulf of Mexico oil spill. |
• | Improving overall financial performance delivery, primarily driven by strong operational performance across all of our businesses, the continuation of our programme to deliver further efficiencies and a more favourable refining environment. | |
• | Achieving a Solomon refining availabilityc of 95.0%, which is an increase of 1.4 percentage points compared with 2009. | |
• | Achieving record volumes in petrochemicals and strong lubricants performance. | |
• | Making significant progress in the Whiting refinery modernization project. | |
• | Starting commercial production at our new joint venture acetyls plant in Nanjing, China. | |
• | Castrol’s sponsorship of the 2010 FIFA World Cup™ in South Africa. | |
• | Successfully exiting from our convenience retail business in France. | |
• | Completing the divestment of several packages of non-strategic terminals and pipelines in the US East of Rockies and West Coast. | |
• | Selling our 15% interest in Ethylene Malaysia Sdn Bhd (EMSB) and 60% interest in Polyethylene Malaysia Sdn Bhd (PEMSB) to Petronas. |
BP Annual Report and Form 20-F 2010 21
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2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
Crude oil production for subsidiaries (thousand barrels per day) | 1,229 | 1,400 | 1,263 | 1,304 | 1,351 | |||||||||||||||
Crude oil production for equity-accounted entities (thousand barrels per day) | 1,145 | 1,135 | 1,138 | 1,110 | 1,124 | |||||||||||||||
Natural gas production for subsidiaries (million cubic feet per day) | 7,332 | 7,450 | 7,277 | 7,222 | 7,412 | |||||||||||||||
Natural gas production for equity-accounted entities (million cubic feet per day) | 1,069 | 1,035 | 1,057 | 921 | 1,005 | |||||||||||||||
Estimated net proved crude oil reserves for subsidiaries (million barrels)b | 5,559 | 5,658 | 5,665 | 5,492 | 5,893 | |||||||||||||||
Estimated net proved crude oil reserves for equity-accounted entities (million barrels)c | 4,971 | 4,853 | 4,688 | 4,581 | 3,888 | |||||||||||||||
Estimated net proved bitumen reserves for equity-accounted entities (million barrels) | 179 | – | – | – | – | |||||||||||||||
Estimated net proved natural gas reserves for subsidiaries (billion cubic feet)d | 37,809 | 40,388 | 40,005 | 41,130 | 42,168 | |||||||||||||||
Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet)e | 4,891 | 4,742 | 5,203 | 3,770 | 3,763 | |||||||||||||||
a | Crude oil includes natural gas liquids (NGLs) and condensate. Production and proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations. |
b | Includes 22 million barrels (23 million barrels at 31 December 2009 and 21 million barrels at 31 December 2008) in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
c | Includes 254 million barrels (243 million barrels at 31 December 2009 and 216 million barrels at 31 December 2008) in respect of the 7.03% minority interest in TNK-BP (6.86% at 31 December 2009 and 6.80% at 31 December 2008). |
d | Includes 2,921 billion cubic feet of natural gas (3,068 billion cubic feet at 31 December 2009 and 3,108 billion cubic feet at 31 December 2008) in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
e | Includes 137 billion cubic feet (131 billion cubic feet at 31 December 2009 and 2008) in respect of the 5.89% minority interest in TNK-BP (5.79% at 31 December 2009 and 5.92% at 31 December 2008). |
a | Natural gas is converted to oil equivalent at 5.8 billion cubic feet (bcf) = 1 million barrels. |
22 BP Annual Report and Form 20-F 2010
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$ million except per share amounts | |||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006* | |||||||||||||||||
Income statement data | |||||||||||||||||||||
Sales and other operating revenues from continuing operationsb | 297,107 | 239,272 | 361,143 | 284,365 | 265,906 | ||||||||||||||||
Replacement cost profit (loss) before interest and taxc | |||||||||||||||||||||
By business | |||||||||||||||||||||
Exploration and Production | 30,886 | 24,800 | 38,308 | 27,602 | 31,026 | ||||||||||||||||
Refining and Marketing | 5,555 | 743 | 4,176 | 2,621 | 5,661 | ||||||||||||||||
Other businesses and corporate | (1,516 | ) | (2,322 | ) | (1,223 | ) | (1,209 | ) | (841 | ) | |||||||||||
Gulf of Mexico oil spill responsed | (40,858 | ) | – | – | – | – | |||||||||||||||
Consolidation adjustment – unrealized profit in inventory | 447 | (717 | ) | 466 | (220 | ) | 65 | ||||||||||||||
Replacement cost profit (loss) before interest and taxation from continuing operationsb | (5,486 | ) | 22,504 | 41,727 | 28,794 | 35,911 | |||||||||||||||
Inventory holding gains (losses) | 1,784 | 3,922 | (6,488 | ) | 3,558 | (253 | ) | ||||||||||||||
Profit (loss) before interest and taxation from continuing operationsb | (3,702 | ) | 26,426 | 35,239 | 32,352 | 35,658 | |||||||||||||||
Finance costs and net finance expense or income relating to pensions and other post-retirement benefits | (1,123 | ) | (1,302 | ) | (956 | ) | (741 | ) | (516 | ) | |||||||||||
Taxation | 1,501 | (8,365 | ) | (12,617 | ) | (10,442 | ) | (12,516 | ) | ||||||||||||
Profit (loss) from continuing operationsb | (3,324 | ) | 16,759 | 21,666 | 21,169 | 22,626 | |||||||||||||||
Profit (loss) for the year | (3,324 | ) | 16,759 | 21,666 | 21,169 | 22,601 | |||||||||||||||
Profit (loss) for the year attributable to BP shareholders | (3,719 | ) | 16,578 | 21,157 | 20,845 | 22,315 | |||||||||||||||
Per ordinary share – cents | |||||||||||||||||||||
Profit (loss) for the year attributable to BP shareholders | |||||||||||||||||||||
Basic | (19.81 | ) | 88.49 | 112.59 | 108.76 | 111.41 | |||||||||||||||
Diluted | (19.81 | ) | 87.54 | 111.56 | 107.84 | 110.56 | |||||||||||||||
Profit (loss) from continuing operations attributable to BP shareholdersb | |||||||||||||||||||||
Basic | (19.81 | ) | 88.49 | 112.59 | 108.76 | 111.54 | |||||||||||||||
Diluted | (19.81 | ) | 87.54 | 111.56 | 107.84 | 110.68 | |||||||||||||||
Replacement cost profit (loss) for the yearc | (4,519 | ) | 14,136 | 26,102 | 18,694 | 22,823 | |||||||||||||||
Replacement cost profit (loss) for the year attributable to BP shareholdersc | (4,914 | ) | 13,955 | 25,593 | 18,370 | 22,537 | |||||||||||||||
Per ordinary share – cents | |||||||||||||||||||||
Replacement cost profit (loss) for the year attributable to BP shareholdersc | (26.17 | ) | 74.49 | 136.20 | 95.85 | 112.52 | |||||||||||||||
Dividends paid per share – cents | 14.00 | 56.00 | 55.05 | 42.30 | 38.40 | ||||||||||||||||
– pence | 8.679 | 36.417 | 29.387 | 20.995 | 21.104 | ||||||||||||||||
Capital expenditure and acquisitionse | 23,016 | 20,309 | 30,700 | 20,641 | 17,231 | ||||||||||||||||
Ordinary share dataf | |||||||||||||||||||||
Average number outstanding of 25 cent ordinary shares (shares million undiluted) | 18,786 | 18,732 | 18,790 | 19,163 | 20,028 | ||||||||||||||||
Average number outstanding of 25 cent ordinary shares (shares million diluted) | 18,998 | 18,936 | 18,963 | 19,327 | 20,195 | ||||||||||||||||
Balance sheet data | |||||||||||||||||||||
Total assets | 272,262 | 235,968 | 228,238 | 236,076 | 217,601 | ||||||||||||||||
Net assets | 95,891 | 102,113 | 92,109 | 94,652 | 85,465 | ||||||||||||||||
Share capital | 5,183 | 5,179 | 5,176 | 5,237 | 5,385 | ||||||||||||||||
BP shareholders’ equity | 94,987 | 101,613 | 91,303 | 93,690 | 84,624 | ||||||||||||||||
Finance debt due after more than one year | 30,710 | 25,518 | 17,464 | 15,651 | 11,086 | ||||||||||||||||
Net debt to net debt plus equityg | 21 % | 20 % | 21 % | 22 % | 20 % | ||||||||||||||||
a | This information, insofar as it relates to 2010, has been extracted or derived from the audited consolidated financial statements of the BP group presented on pages 141-227. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes elsewhere herein. |
b | Excludes Innovene, which was treated as a discontinued operation in accordance with IFRS 5 ‘Non-current Assets Held for Sale and Discontinued Operations’ in 2006. |
c | 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 81. |
d | Under IFRS these costs are presented as a reconciling item between the sum of the results of the reportable segments and the group results. |
e | Excluding acquisitions and asset exchanges, capital expenditure for 2010 was $19,610 million (2009 $20,001 million, 2008 $28,186 million, 2007 $19,194 million and 2006 $16,910 million). All capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing. 2008 included capital expenditure of $2,822 million and an asset exchange of $1,909 million, both in respect of our transaction with Husky Energy Inc., as well as capital expenditure of $3,667 million in respect of our purchase of all of Chesapeake Energy Corporation’s interest in the Arkoma Basin Woodford Shale assets and the purchase of a 25% interest in Chesapeake’s Fayetteville Shale assets. 2007 included $1,132 million for the acquisition of Chevron’s Netherlands manufacturing company. Capital expenditure in 2006 included $1 billion in respect of our investment in Rosneft. |
f | The number of ordinary shares shown has been used to calculate per share amounts. |
g | Net debt and the ratio of net debt to net debt plus equity are non-GAAP measures. We believe that these measures provide useful information to investors. Further information on net debt is given in Financial statements – Note 36 on page 198. |
* | As reported in Annual Report on Form 20-F. There was a $500 million ($315 million post tax) timing difference between the profit reported under IFRS in the Annual Report and Accounts and the profit reported under IFRS inBP Annual Report on Form 20-F 2006.For further information seeBP Annual Report and Accounts 2006. |
BP Annual Report and Form 20-F 2010 23
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a | Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the year and the cost of sales calculated on the first-in first-out (FIFO) method, after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. BP’s management believes it is helpful to disclose this information An analysis of inventory holding gains and losses by business is shown in Financial statements – Note 7 on page 167 and further information on inventory holding gains and losses is provided on page 81. |
24 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Exploration and Production | ||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assets | 3,812 | 1,574 | (1,015 | ) | ||||||||
Environmental and other provisions | (54 | ) | 3 | (12 | ) | |||||||
Restructuring, integration and rationalization costs | (137 | ) | (10 | ) | (57 | ) | ||||||
Fair value gain (loss) on embedded derivatives | (309 | ) | 664 | (163 | ) | |||||||
Other | (113 | ) | 34 | 257 | ||||||||
3,199 | 2,265 | (990 | ) | |||||||||
Refining and Marketing | ||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assetsa | 877 | (1,604 | ) | 801 | ||||||||
Environmental and other provisions | (98 | ) | (219 | ) | (64 | ) | ||||||
Restructuring, integration and rationalization costs | (97 | ) | (907 | ) | (447 | ) | ||||||
Fair value gain (loss) on embedded derivatives | – | (57 | ) | 57 | ||||||||
Other | (52 | ) | 184 | – | ||||||||
630 | (2,603 | ) | 347 | |||||||||
Other businesses and corporate | ||||||||||||
Impairment and gain (loss) on sale of businesses and fixed assets | 5 | (130 | ) | (166 | ) | |||||||
Environmental and other provisions | (103 | ) | (75 | ) | (117 | ) | ||||||
Restructuring, integration and rationalization costs | (81 | ) | (183 | ) | (254 | ) | ||||||
Fair value gain (loss) on embedded derivatives | – | – | (5 | ) | ||||||||
Other | (21 | ) | (101 | ) | (91 | ) | ||||||
(200 | ) | (489 | ) | (633 | ) | |||||||
Gulf of Mexico oil spill response | (40,858 | ) | – | – | ||||||||
Total before interest and taxation | (37,229 | ) | (827 | ) | (1,276 | ) | ||||||
Finance costsb | (77 | ) | – | – | ||||||||
Total before taxation | (37,306 | ) | (827 | ) | (1,276 | ) | ||||||
Taxation credit (charge)c | 11,857 | (240 | ) | 480 | ||||||||
Total after taxation | (25,449 | ) | (1,067 | ) | (796 | ) | ||||||
a | 2009 includes $1,579 million in relation to the impairment of goodwill allocated to the US West Coast fuels value chain. |
b | Finance costs relate to the Gulf of Mexico oil spill. See Financial statements – Note 2 on page 158 for further details. |
c | Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill) on group profit or loss, to the non-operating items as they arise each quarter. However, the US statutory tax rate has been used for expenditures relating to the Gulf of Mexico oil spill that qualify for tax relief. In 2009, no tax credit was calculated on the goodwill impairment in Refining and Marketing because the charge is not tax deductible. |
BP Annual Report and Form 20-F 2010 25
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Exploration and Production | ||||||||||||
Unrecognized gains (losses) brought forward from previous period | (530 | ) | 389 | 107 | ||||||||
Unrecognized (gains) losses carried forward | 527 | 530 | (389 | ) | ||||||||
Favourable (unfavourable) impact relative to management’s measure of performance | (3 | ) | 919 | (282 | ) | |||||||
Refining and Marketing | ||||||||||||
Unrecognized gains (losses) brought forward from previous period | 179 | (82 | ) | 429 | ||||||||
Unrecognized (gains) losses carried forward | (137 | ) | (179 | ) | 82 | |||||||
Favourable (unfavourable) impact relative to management’s measure of performance | 42 | (261 | ) | 511 | ||||||||
39 | 658 | 229 | ||||||||||
Taxation credit (charge)a | (26 | ) | (213 | ) | (83 | ) | ||||||
13 | 445 | 146 | ||||||||||
By region | ||||||||||||
Exploration and Production | ||||||||||||
US | 141 | 687 | (231 | ) | ||||||||
Non-US | (144 | ) | 232 | (51 | ) | |||||||
(3 | ) | 919 | (282 | ) | ||||||||
Refining and Marketing | ||||||||||||
US | 19 | 16 | 231 | |||||||||
Non-US | 23 | (277 | ) | 280 | ||||||||
42 | (261 | ) | 511 | |||||||||
a | Tax is calculated by applying discrete quarterly effective tax rates (excluding the impact of the Gulf of Mexico oil spill) on group profit or loss, to the fair value accounting effects as they arise each quarter. |
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Exploration and Production | ||||||||||||
Replacement cost profit before interest and tax adjusted for fair value accounting effects | 30,889 | 23,881 | 38,590 | |||||||||
Impact of fair value accounting effects | (3 | ) | 919 | (282 | ) | |||||||
Replacement cost profit before interest and tax | 30,886 | 24,800 | 38,308 | |||||||||
Refining and Marketing | ||||||||||||
Replacement cost profit before interest and tax adjusted for fair value accounting effects | 5,513 | 1,004 | 3,665 | |||||||||
Impact of fair value accounting effects | 42 | (261 | ) | 511 | ||||||||
Replacement cost profit before interest and tax | 5,555 | 743 | 4,176 | |||||||||
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2010 | ||||
Total pre-tax cost recognized in income statement ($ million) | 40,935 | |||
Total cash flow expended (pre-tax) ($ million) | 17,658 | |||
Total payments from $20-billion trust fund ($ million) | 3,023 | |||
Total number of claimants to GCCFa | 468,869 | |||
Number of people deployed (at peak) (approximately) | 48,000 | |||
Number of active response vessels deployed during the response (approximately) | 6,500 | |||
Barrels of oil collected or flared (approximately) | 827,000 | |||
Barrels of oily liquid skimmed from surface of sea (approximately) | 828,000 | |||
Barrels of oil removed through surface burns (UAC estimate) | 265,450 | |||
a | Gulf Coast Claims Facility (GCCF). |
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• | The annulus cement barrier – and in particular the cement slurry that was used – at the bottom of the Macondo well failed to contain hydrocarbons within the reservoir, as it was designed to do. The annulus cement probably experienced nitrogen breakout and migration, allowing gas and liquids to enter the wellbore annulus. The investigation team concluded that there were weaknesses in cement design and testing, quality assurance and risk assessment. |
• | The shoe track barriers at the bottom of the Macondo well failed to contain hydrocarbons as they were designed to do, allowing hydrocarbons to flow up the production casing. The shoe track barriers consisted of two barriers in the shoe track: the cement in the shoe track and the float collar. BP’s investigation team identified a number of potential failure modes that could explain how both the shoe track cement and the float collar allowed hydrocarbon ingress into the production casing, but has not determined which of these failure modes occurred. |
• | The results of the negative pressure test were incorrectly accepted by BP and Transocean, although well integrity had not been established. |
• | Over a 40-minute period, the Transocean rig crew failed to recognize and act on the influx of hydrocarbons into the well until the hydrocarbons had passed through the BOP and into the riser and were rapidly flowing to the surface. |
• | Well control response actions failed to regain control of the well. The first well control actions were to close the BOP and diverter, routing the fluids exiting the riser to a mud gas separator rather than to the overboard diverter line. If fluids had been diverted overboard, rather than to the mud gas separator, there may have been more time to respond, and the consequences of the accident may have been reduced. |
• | Diversion of the hydrocarbons to the mud gas separator resulted in gas venting onto the rig. The design of the mud gas separator system allowed diversion of the riser contents to the mud gas separator vessel although the well was in a high-flow condition. This overwhelmed the mud gas separator system, resulting in gas venting onto the rig. This increased the potential for the gas to reach an ignition source. |
• | The flow of gas into the engine rooms through the ventilation system created a potential for ignition that the rig’s fire and gas system did not prevent. |
• | Even after the explosion and fire had disabled its crew-operated controls, the rig’s BOP on the seabed should have activated automatically to seal the well. But it failed to operate, probably because critical components were not working. Through a review of rig audit findings and maintenance records, the investigation team found indications of potential weaknesses in the testing regime and maintenance management system for the BOP. |
• | Update and clarify current practices to ensure that a clear and comprehensive set of cementing guidelines and associated Engineering Technical Practices (ETPs) are available as controlled standards. |
• | Review and update requirements for subsea BOP configuration. |
• | Update the relevant technical practices to incorporate certain improved design requirements for subsea wellheads. |
• | Review and update ETPs regarding negative-pressure testing. |
• | Clarify and strengthen standards for well-control and well-integrity incident reporting and investigation. |
• | Propose to the American Petroleum Institute the development of a recommended practice for design and testing of foam cement slurries in high-pressure, high-temperature applications. |
• | Review and assess the consistency, rigour and effectiveness of the current risk management and management of change processes practised by Drilling and Completions (D&C). |
• | Reassess and strengthen the current technical authority’s role in the areas of cementing and zonal isolation. |
• | Enhance D&C competency programmes to deepen the capabilities of personnel in key operational and leadership positions and augment existing knowledge and proficiency in managing deepwater drilling and wells. |
• | Develop an advanced deepwater well-control training programme that supplements current industry and regulatory training and embeds lessons learned from the Gulf of Mexico incident. |
• | Establish BP’s in-house expertise in the areas of subsea BOPs and BOP control systems through the creation of a central expert team, including a defined segment engineering technical authority role to provide independent assurance of the integrity of drilling contractors’ BOPs and BOP control systems. |
• | Request that the International Association of Drilling Contractors review and consider the need to develop a programme for formal subsea engineering certification of personnel who are responsible for the maintenance and modification of deepwater BOPs and control systems. |
• | Strengthen BP’s rig audit process to improve the closure and verification of audit findings and actions across BP-owned and BP-contracted drilling rigs. |
• | Establish D&C leading and lagging indicators for well integrity, well control and rig safety critical equipment. |
• | Require drilling contractors to implement an auditable integrity monitoring system to continuously assess and improve the integrity performance of well-control equipment against a set of established leading and lagging indicators. |
• | Conduct an immediate review of the quality of the services provided by all cementing service providers. Confirm that adequate oversight and controls are in place within the service provider’s organization and BP. |
• | Assess and confirm that essential well-control and well-monitoring practices, such as well monitoring and shut-in procedures, are clearly defined and rigorously applied on all BP-owned and BP-contracted offshore rigs. |
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• | Require hazard and operability reviews of the surface gas and drilling fluid systems for all BP-owned and BP-contracted drilling rigs. |
• | Include in the hazard and operability reviews a study of all surface system hydrocarbon vents, reviewing suitability of location and design. |
• | Establish minimum levels of redundancy and reliability for BP’s BOP systems. Require drilling contractors to implement an auditable risk management process to ensure that their BOP systems are operated above these minimum levels. |
• | Strengthen BP’s minimum requirements for drilling contractors’ BOP testing, including emergency systems. |
• | Strengthen BP’s minimum requirements for drilling contractors’ BOP maintenance management systems. |
• | Define BP’s minimum requirements for drilling contractors’ management of changes for subsea BOPs. |
• | Develop a clear plan for remotely operated vehicle intervention as part of the emergency BOP operations in each of BP’s operating regions, including all emergency options for shearing pipe and sealing the wellbore. |
• | Require drilling contractors to implement a qualification process to verify that shearing performance capability of blind shear rams is compatible with the inherent variations in wall thickness, material strength and toughness of the rig drill pipe inventory. |
• | Include testing and verification of these BOP recommendations in the rig audit process. |
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• | Continuously reducing operating risk. |
• | Strong relationships built on mutual advantage, deep knowledge of the basins in which we operate, and technology. |
• | Building capability along the value chain in Exploration, Developments and Production. |
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Sales and other operating revenuesa | 66,266 | 57,626 | 86,170 | |||||||||
Replacement cost profit before interest and taxb | 30,886 | 24,800 | 38,308 | |||||||||
Capital expenditure and acquisitions | 17,753 | 14,896 | 22,227 | |||||||||
$ per barrel | ||||||||||||
Average BP crude oil realizationsc | 77.54 | 59.86 | 95.43 | |||||||||
Average BP NGL realizationsc | 42.78 | 29.60 | 52.30 | |||||||||
Average BP liquids realizationsc d | 73.41 | 56.26 | 90.20 | |||||||||
Average West Texas Intermediate oil pricee | 79.45 | 61.92 | 100.06 | |||||||||
Average Brent oil pricee | 79.50 | 61.67 | 97.26 | |||||||||
$ per thousand cubic feet | ||||||||||||
Average BP natural gas realizationsc | 3.97 | 3.25 | 6.00 | |||||||||
Average BP US natural gas realizationsc | 3.88 | 3.07 | 6.77 | |||||||||
$ per million British thermal units | ||||||||||||
Average Henry Hub gas pricef | 4.39 | 3.99 | 9.04 | |||||||||
pence per therm | ||||||||||||
Average UK National Balancing Point gas pricee | 42.45 | 30.85 | 58.12 | |||||||||
thousand barrels of oil equivalent per day | ||||||||||||
Total production for subsidiariesgh | 2,492 | 2,684 | 2,517 | |||||||||
Total production for equity-accounted entitiesgh | 1,330 | 1,314 | 1,321 | |||||||||
Total of subsidiaries and equity-accounted entitiesgh | 3,822 | 3,998 | 3,838 | |||||||||
million barrels of oil equivalent | ||||||||||||
Net proved reserves for subsidiaries | 12,077 | 12,621 | 12,562 | |||||||||
Net proved reserves for equity-accounted entities | 5,994 | 5,671 | 5,585 | |||||||||
Total of subsidiaries and equity-accounted entities | 18,071 | 18,292 | 18,147 | |||||||||
a | Includes sales between businesses. |
b | Includes profit after interest and tax of equity-accounted entities. |
c | Realizations are based on sales of consolidated subsidiaries only, which excludes equity-accounted entities. |
d | Crude oil and natural gas liquids. |
e | All traded days average. |
f | Henry Hub First of Month Index. |
g | Net of royalties. |
h | Expressed in thousands of barrels of oil equivalent per day (mboe/d). Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels. |
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• | In March 2010, BP announced a broad-ranging transaction with Devon Energy to enhance its position in core strategic areas. BP agreed to pay Devon Energy $6.9 billion in cash for assets in Brazil, Azerbaijan and the US deepwater Gulf of Mexico. |
In addition, BP sold to Devon Energy a 50% stake in BP’s Kirby oil sands interests in Alberta, Canada, for $500 million. The parties have agreed to form a 50:50 joint venture, operated by Devon, to pursue the development of the interest. Devon committed to fund an additional $150 million of capital costs on BP’s behalf. In Brazil, subject to government and regulatory approvals, the transaction will give BP a diverse and broad deepwater exploration acreage position offshore Brazil with interests in eight licence blocks in the Campos and Camamu-Almada basins, as well as two onshore licences in the Parnaiba basin. The Campos basin blocks include three discoveries – Xerelete, pre-salt Wahoo and Itaipu – and the producing Polvo field. |
In the US deepwater Gulf of Mexico, BP gained a high-quality portfolio with interests in some 240 leases, with a particular focus on the emerging Paleogene play in the ultra-deepwater. The addition of Devon’s 30% interest in the major Paleogene discovery, Kaskida, gave BP a 100% interest in the project. The assets also included interests in four producing oilfields: Magnolia, Merganser, Nansen, and Zia, and one non-producing asset. |
In Azerbaijan, acquisition of Devon’s 3.29% (after pre-emption exercised by some of the partners) stake in the BP-operated Azeri-Chirag-Gunashli development increased BP’s interest to 37.43%. The undeveloped Kirby oil sands leases are in the south-east of the Athabasca region of Alberta, close to the Devon-operated Jackfish development, which started production in 2007. BP and Devon have agreed an initial appraisal programme to assess the significant potential of the Kirby acreage and to establish a long-term development plan. In addition to forming the joint venture, BP and Devon have agreed to enter into a long-term heavy crude off-take agreement for production from the Kirby development as well as a portion of the production from some of Devon’s other oil sands assets. |
• | Also in March 2010, BP announced that it had entered into a partnership in Canada with Value Creation Inc. (VCI) to develop the Terre de Grace (TDG) oil sands lease, one of VCI’s large oil sands leases, in the Athabasca region. BP is now the operator and majority partner for the partnership, with VCI and BP together providing strategic direction and guidance. TDG is a large, contiguous 185,000 acres of high-quality oil sands land with substantial delineation of the East Graceland area and further potential in the less-delineated remainder of the leases. In 2010, capital expenditure in relation to the formation of this partnership was $900 million. |
• | On 1 September 2010, BP increased its equity holding in the significant Norwegian Valhall and Hod fields by acquiring 7.9% interest in the Valhall field and 12.5% in the Hod field from Total. The transaction increased the equity holding in Valhall to 35.95% and Hod to 37.5%. The final purchase consideration was $492 million. The acquisition is expected to strengthen BP’s existing business in Norway and the North Sea. |
• | In September 2010, BP announced an agreement with Devon Energy in which BP acquired 40.82% of Devon’s existing share in Block 42/05 in the South China Sea. The remaining 59.18% of Devon’s share was purchased by Chevron, who will be the operator in the exploration phase under the amendment agreements to the production-sharing contract with CNOOC. All pre-development spending will be incurred by BP and Chevron. During the development phase, CNOOC has the right to back-in to a 51% share in the project thus leaving working interest shares as follows: BP 20%, CNOOC 51%, Chevron 29%. |
• | On 24 January 2011, BP exercised a preferential right to acquire Shell’s working interest in the Marlin and Dorado producing fields for a total consideration of $257 million. This brings BP’s working interest in both fields to 100%. |
• | On 21 February 2011, Reliance Industries Limited and BP announced that they intend to form an upstream joint venture in which BP will take a 30% stake in 23 oil and gas production-sharing contracts that Reliance operates in India, including the producing KG D6 block, and form a 50:50 joint venture for the sourcing and marketing of gas in India. BP will pay Reliance Industries Limited an aggregate consideration of $7.2 billion, and completion adjustments, for the interests to be acquired in the 23 production-sharing contracts. Future performance payments of up to $1.8 billion could be paid based on exploration success that results in development of commercial discoveries. Reliance will continue to be the operator under the production-sharing contracts. Completion of the transactions is subject to Indian regulatory approvals and other customary conditions. |
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• | In July 2010, BP announced that it had entered into several agreements to sell upstream assets in the US, Canada and Egypt to Apache Corporation (and an existing partner that exercised pre-emption rights). The deals, together worth a total of $7 billion, comprise BP’s Permian Basin assets in Texas and south-east New Mexico, US; its Western Canadian upstream gas assets; and the Western Desert business concessions and East Badr El-din exploration concession in Egypt. These transactions were completed during 2010. | |
• | On 3 August 2010, BP announced that it had agreed to sell its oil and gas exploration, production and transportation business in Colombia to a consortium of Ecopetrol, Colombia’s national oil company (51%), and Talisman of Canada (49%). The two companies agreed to pay BP a total of $1.9 billion in cash, subject to customary post-completion price adjustments, for 100% of the shares in BP Exploration Company (Colombia) Limited (BPXC), the wholly-owned BP subsidiary company that held BP’s oil and gas exploration, production and transportation interests in Colombia. Following the approval of the Colombian authorities, completion occurred on 24 January 2011. | |
• | On 31 August 2010, BP completed the sale of its entire interest in the Overthrust assets (Painter Complex Gas Plant, Painter Reservoir Unit and Whitney Canyon field and inlet facility) to Merit Energy Company for $217 million. | |
• | On 18 October 2010, BP announced it had reached agreement to sell its upstream businesses and associated interests in Venezuela and Vietnam to TNK-BP for a total of $1.8 billion subject to customary post-completion price adjustments. The agreement includes BP’s interests in the Petroperijá, Boquerón and PetroMonagas joint ventures in Venezuela and, in Vietnam, BP’s 35% operating interest in the Lan Tay and Lan Do gas fields (Block 6.1) and associated pipeline and power generation interests. Block 6.1 partners, PetroVietnam and ONGC Videsh Ltd, have waived pre-emption rights to purchase BP’s Block 6.1 interest. BP will retain an economic interest in these assets through its 50% interest in TNK-BP. | |
• | In October 2010, BP announced it had reached an agreement with its partner, Hess Corporation, for the sale of a 20% interest in the Tubular Bells field in the Gulf of Mexico. Hess agreed to acquire the 20% interest from BP for $40 million and became the operator. The increased ownership brought Hess’s working interest in Tubular Bells to 40%. Chevron holds a 30% interest and BP retains 30%. Tubular Bells, which was discovered in 2003, is a deepwater field approximately 135 miles south-east of New Orleans, Louisiana. | |
• | On 25 October 2010, BP announced that it had reached agreement to sell its recently acquired interests in four mature producing deepwater oil and gas fields in the US Gulf of Mexico to Marubeni Oil and Gas for $650 million. BP acquired the interests in the fields – Magnolia, Merganser, Nansen and Zia – from Devon Energy earlier in 2010 as part of the wider acquisition of assets in the Gulf of Mexico, Brazil and Azerbaijan, but determined that they did not fit well with the rest of the group’s assets in the region and would be of more value to another company. | |
• | On 28 November 2010, BP announced that it had entered into an agreement to sell its interests in Pan American Energy (PAE) to Bridas Corporation. PAE is an Argentina-based oil and gas company owned by BP (60%) and Bridas Corporation (40%). Bridas Corporation will pay BP a total of $7.06 billion in cash for BP’s interest in PAE. The transaction is expected to be completed in 2011. The transaction excludes the shares of PAE E&P Bolivia Ltd. Completion of the transaction is subject to closing conditions including the receipt of all necessary governmental and regulatory approvals. | |
• | On 14 December 2010, BP announced that it had reached agreement to sell its upstream assets in Pakistan to United Energy Group for $775 million. Subject to certain closing conditions, including the receipt of all necessary governmental and regulatory approvals, closing is anticipated to occur by the end of the first quarter of 2011. |
• | During 2010, BP also announced its intention to divest its interest in the Tuscaloosa fields in Louisiana, the Wattenberg plant in Colorado and its NGL business in Canada. |
• | On 22 February 2011, BP announced its intention to sell its interests in a number of operated oil and gas fields in the UK. The assets involved are the Wytch Farm onshore oilfield in Dorset and all of BP’s operated gas fields in the southern North Sea, including associated pipeline infrastructure and the Dimlington terminal. BP aims to complete the disposals around the end of 2011, subject to receipt of suitable offers and regulatory and third party approvals. The assets do not yet meet the criteria to be reclassified as non-current assets held for sale and it is not yet possible to estimate the financial effect of these intended transactions. |
• | In July 2010, the UK Parliament’s Energy and Climate Change Select Committee launched an investigation into the safety of deepwater drilling in the UK, in light of the accident in the Gulf of Mexico. In September, BP provided both written and oral evidence to the Committee, as did a number of other operators and organizations with a stake in the UK Continental Shelf (UKCS). |
• | In the UK, BP has been closely involved in communicating the lessons learned from the Gulf of Mexico oil spill to industry and the regulatory authorities, and has also been widely represented in the Oil Spill Prevention and Response Advisory Group (OSPRAG), a group formed in late May to co-ordinate and lead the UK’s response to such incidents. BP has provided support, for example, through the transfer of two containment devices to Oil Spill Response Limited’s Southampton depot and by leading the design and procurement of a capping stack for use in the deepwater of the UKCS. The capping stack project is due for completion in mid-2011. |
• | The European Commission published its policy and pre-legislative communication on offshore safety in October 2010. Preparation of a draft legislative package is now with the European Commission services, for expected publication in spring 2011. |
• | BP is scheduled to drill a deepwater exploration well in the west of Shetland during 2011 and, together with its drilling contractor, plans to implement all relevant lessons from the Gulf of Mexico accident during the planning and execution of that well. Much has already been done during 2010 in the North Sea business to further improve the safety of drilling operations. |
• | In October 2010, BP was awarded interests in seven offshore exploration blocks in the 26th round of UK Continental Shelf licensing. Five of these blocks are BP-operated and two are partner-operated. This represents the largest licence award for BP in the UK for more than 10 years. |
• | On 27 October 2010, the European Union followed the UN and US in enacting further restrictive measures against Iran (the EU Regulations). The EU Regulations target, among other things, legal persons, entities or bodies outside of Iran that have direct or indirect Iranian ownership. |
• | On 16 November 2010, production from the Rhum gas field in the central North Sea was suspended pending clarification from the UK government on certain aspects of the EU Regulations. This action was taken to comply with the notification requirements in the EU Regulations. Rhum is owned by BP (50%) and the Iranian Oil Company (50%) under a joint operating agreement dating back to the early 1970s. |
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• | On 9 November 2010, the development of the Norwegian oil and gas field Skarv reached a significant milestone with the naming ceremony of the Skarv Floating Production, Storage and Offloading (FPSO) unit. The ceremony took place in Geoje in South Korea. The vessel will operate in the Norwegian Sea close to the Arctic Circle, 210km off the coast of Nordland. It is due to start production at the Skarv oil and gas field in the autumn of 2011. |
• | In 2010, the Valhall redevelopment project passed a major milestone with the completion of the heavy lift programme. The main deck and living quarters were successfully installed offshore in July 2010. The living quarters are scheduled to be ready for habitation in April 2011, with production start-up from the new facility scheduled for early 2012. |
• | On 31 March 2010, first oil was achieved from the Great White field (BP 33.3%) located in the ultra-deep waters of the Gulf of Mexico. Production is processed by the Perdido Regional Host floating production facility (BP 27.5%), an integrated spar and drilling rig. The development is operated by Shell on behalf of BP and Chevron. Great White marks the first development of a Paleogene (Lower Tertiary) reservoir in the Gulf of Mexico and is expected to represent 80% of the estimated total production through the Perdido Host. |
• | In September 2010, the final investment decision was made for the Mars B (BP 28.5%) deepwater development, located approximately 130 miles south of New Orleans, Louisiana in the Gulf of Mexico. The development will include a second tension-leg platform, named Olympus, to enhance recovery from the Mars field. The Mars B development will draw production from eight Mississippi Canyon blocks – 762, 763, 764, 805, 806, 807, 850 and 851. |
• | In March 2010, BP participated in lease sale 213. Following this sale we were awarded 18 leases, 11 of which have now been executed, a further seven leases were awarded but have not yet been executed. |
• | In 2010, we progressed the previously announced development activities for the Liberty oilfield, which is located on federal leases about six miles offshore in the Beaufort Sea, and east of the Prudhoe Bay oilfield. The planned development includes up to six ultra-extended reach wells, including four producers and two injectors, to be drilled from existing infrastructure in the BP-operated Endicott field to minimize the onshore and offshore environmental footprint. As part of a continuous evaluation of project design, materials, and systems, we suspended physical construction of the rig on-site in the fourth quarter. Following a review of engineering and design elements, and resolution of any issues, we plan to continue rig construction. As this review moves forward, we will develop a revised project schedule. BP drilled the Liberty discovery well in 1997, and is the operator and sole owner of the field. |
• | The Point Thomson Unit (PTU) was terminated by administrative decision of the State of Alaska Department of Natural Resources (DNR) in November 2006 (BP 32%). ExxonMobil, the operator, and the other unit owners, including BP, appealed the unit termination in the Alaska Superior Court. At the end of 2006, based on the DNR’s termination of the Unit, BP wrote off all historical costs associated with the PTU. In January 2009, ExxonMobil was granted permission by the DNR, under a conditional interim decision, to conduct drilling operations on two of the 31 leases comprising the PTU. On 11 January 2010, the Alaska Superior Court reversed the DNR’s administrative decision to terminate the unit. The DNR petitioned the State of Alaska Supreme Court for limited review, and the petition was granted in the second quarter of 2010. As of the end of 2010, the case is still pending before the Alaska Supreme Court. ExxonMobil and the State of Alaska have also informed the other unit owners, including BP, that they are negotiating a settlement agreement. BP has asked to participate in the settlement discussions. |
• | In November 2010, phase 1 of the Sunrise oil sands project (BP 50%) was sanctioned. BP and its partner, Husky Energy Inc, have committed funding to build facilities, drill wells and create the operational systems and resources to bring Sunrise phase 1 into production. First production of bitumen is expected in 2014, building to 60,000 barrels per day gross capacity over the subsequent 24 months. Long-term drilling and facility development is planned to continue thereafter in order to maintain that rate for 40 years or more. Future additional phases of Sunrise are being contemplated. |
• | In July 2010, BP signed a joint operating agreement with ExxonMobil Canada Limited and Imperial Oil Resources Ventures Limited, a subsidiary of ExxonMobil, to exchange 50% of BP’s working interest in the EL 449 field for 50% working interest in Imperial/Exxon’s EL 446 field, both in the Canadian Beaufort Sea. Under this agreement, operatorship was assigned to Imperial with BP remaining actively involved in major exploration decisions. |
• | In 2010, interpretation of the 2009 3D-seismic survey of licences in the Canadian Beaufort Sea commenced and access to seismic data for the EL 446 licence was acquired. |
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• | On 21 April 2010, BP Trinidad & Tobago’s (bpTT) Serrette platform was installed in Trinidad waters in bpTT’s east coast offshore acreage. The Serrette platform is located 51 kilometres north of bpTT’s Mango development. It represents the first development in the northern area of bpTT’s Columbus Basin acreage and has been equipped to enable future development opportunities in this area. Serrette, bpTT’s thirteenth offshore production platform, is the fifth normally unmanned installation (NUI), designed and constructed in Trinidad &Tobago. The Serrette project was sanctioned in May 2009 and has a design capacity of 1 billion cubic feet per day and will deliver a peak production of 500 million standard cubic feet per day. The platform will tie into the Cassia B platform. Drilling is expected to commence in the first quarter of 2011 and production is planned for the second quarter of 2011. |
• | In August 2010, Total, as operator of Block 17 (BP 16.67%), announced the development of the Cravo Lirio Orquidea Violeta (CLOV) project and the award of the principal contracts. This project is the fourth development in Angola’s deepwater offshore Block 17, after Girassol, Dalia and Pazflor, and is located approximately 140 kilometres from Luanda and 40 kilometres north-west of Dalia in water depths ranging from 1,100 to 1,400 metres. The CLOV development will lead to four fields coming onstream. Drilling is expected to start in 2012 and first oil is expected in 2014. A total of 34 subsea wells are planned to be tied back to the CLOV FPSO unit, which will have a processing capacity of 160mb/d and a storage capacity of approximately 1.8 million barrels. |
• | Sanctioned in 2008, PSVM comprises the development of the Plutão, Saturno, Vênus and Marte fields, in a water depth of approximately 2,000 metres, some 400 kilometres north-west of Luanda. In 2010, BP commenced the offshore stage of this major project with the arrival of several vessels into Angola waters. Pile installation has been completed and installation of the production flowlines started. Parallel to this, in Singapore the PSVM FPSO was modified to include the new Turret Support Structure. Oil production from PSVM is scheduled to start in 2011. The remaining discoveries in Block 31 will be developed through hubs similar to the first development, PSVM. |
• | In 2010, the In Salah compressions project successfully achieved first gas. |
• | During 2010, the next phase of the In Amenas development was approved with the award of the engineering primary contracts for compression. The In Salah Southern Fields project is expected to be approved in early 2011 with first gas for both projects expected by 2014. |
• | In September 2010, the Algerian government approved an extension to the second prospecting period for the Bourarhet Sud block. |
• | The first phase of the offshore 3D seismic acquisition was completed in October 2009, fulfilling BP’s marine 3D seismic commitment. The programme covered a surface area of 17,000 square kilometres and was the largest offshore 3D proprietary survey ever undertaken by an international energy company. It involved the deployment of the largest and most powerful data-processing facility ever installed on a seismic vessel and included a technology trial of a multi-azimuth (MAZ) seismic technique, the first ever three-azimuth seismic survey in Libyan waters. |
• | The onshore 3D seismic acquisition in BP’s Ghadames acreage commenced in November 2008 and is ongoing. This 14,000 square kilometre commitment represents one of the largest single 3D land seismic commitments in the industry. |
The programme involves the first at-scale deployment of the ISS™ seismic acquisition technology, a cutting-edge proprietary BP technique using independent simultaneous sources that is allowing BP to operate one of the most efficient land seismic programmes in the world today. The technology has enabled BP to acquire high-quality, densely-sampled 3D land data for the same cost as 3D marine or 2D land data while minimizing environmental impacts, a major achievement for the industry. |
• | Due to the outbreak of political unrest in Libya, the BP office in Tripoli was closed on 21 February 2011 and our Libyan operations suspended. All BP expatriate staff and their families have been evacuated from Libya. Currently, it is not possible to say what impact the ongoing unrest, potential political changes and international sanctions will have on the now-suspended seismic operations and start-up of the exploration drilling programme which had been scheduled to commence onshore and offshore in 2011. |
• | In July 2010, BP signed a new agreement with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation to develop the significant hydrocarbon resources in the North Alexandria and West Mediterranean deepwater concessions. Production from the West Nile Delta development, at an estimated investment of $9 billion gross, is projected to reach up to 1 billion cubic feet per day, providing a major new source of gas for the domestic market in Egypt. The first phase will develop gas and associated condensate through subsea development of five offshore fields into a new purpose-built onshore gas plant on Egypt’s Mediterranean coast. First gas is expected in late 2014. The new agreement amends the commercial terms and the governance structure for the two concessions located in the West Nile Delta, enabling BP and its partner, RWE Dea, to proceed with the development. |
• | On 24 November 2010, BP announced that it has made a significant gas discovery in the deepwater West Nile Delta area. The Hodoa discovery is located in the West Mediterranean deepwater Nile Delta concession, some 80 kilometres northwest of Alexandria. The WMDW-7 well was drilled to a depth of 6,350 metres and is the first Oligocene deepwater discovery in the West Nile Delta area. Further appraisal is under way. BP operates and holds 80% of the West Mediterranean deepwater concession with RWE Dea holding the remaining 20%. Hodoa was drilled by the Pride North America semi-submersible rig, in a water depth of 1,077 metres. |
46 BP Annual Report and Form 20-F 2010
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• | Due to the recent significant political unrest in Cairo and other major cities in Egypt, the BP Egypt office in Cairo was closed from 28 January for a period of 10 days. Furthermore, BP expatriate staff and their families were evacuated from Egypt. The BP Egypt office was reopened on 7 February, and national staff returned to work. Most expatriate staff and families returned to Egypt during February. Production at BP Egypt’s joint ventures (GUPCO and PHP) was not affected by the office closures. The office closure and staff evacuation will have some short-term impacts on project activity. On 11 February, President Mubarak resigned and handed over power to the Supreme Council of the Egyptian Armed Forces. Currently, it is not possible to say what impact, if any, future politicial changes will have on the BP Egypt business. |
• | In June 2010, BP was awarded joint study rights with the Indonesia Directorate General of Oil and Gas on the West Sanga Sanga block immediately adjacent to the Sanga-Sanga PSA. This study involves gathering, processing and interpreting data to evaluate the viability of a coalbed methane (CBM) project in the area. The award of the joint study secures matching rights for BP and its partner over the 3,500-square kilometre area when the area will be tendered for production-sharing contracts (PSC), allowing them to change their bid to match that of the highest bidder at that time. |
• | On 12 January 2011, BP announced that it had signed a new agreement with the China National Offshore Oil Corporation (CNOOC) for deepwater exploration in Block 43/11 in the South China Sea, subject to partner and government approval. |
• | On 9 March 2010, the steering committee for the development of the ACG field sanctioned investment in the Chirag Oil Project (COP). This is the next major capital investment in the ongoing development of the ACG field in the Azerbaijan sector of the Caspian Sea. The project is planned to increase oil production and recovery from the field through a new offshore facility which is designed to fill a critical gap in the field infrastructure between the existing Deepwater Gunashli and Chirag-1 platforms. |
• | On 7 June 2010, the government of Azerbaijan and the government of Turkey signed a Memorandum of Understanding (MOU) as part of a package of documents that will regulate the sale of Azerbaijani gas to Turkey and transit terms for transportation of the gas to the European markets through the territory of Turkey. This marks a major step forward towards conclusion of required agreements for Shah Deniz Stage 2 gas sales to Turkey and beyond, and is a milestone that underpins the significance of the Stage 2 development plans and paves the way for the project to move forward towards a final investment decision by the Shah Deniz partnership. At this stage, discussions to define the best option for further gas marketing and sales continue and these are led by the Azerbaijani government in conjunction with the Shah Deniz partnership. |
• | On 7 October 2010, BP and the State Oil Company of the Republic of Azerbaijan (SOCAR) signed a new PSA for the joint exploration and development of the Shafag-Asiman structure in the Azerbaijan sector of the Caspian Sea. Under the PSA, which is for 30 years, BP will be the operator with 50% working interest and SOCAR will hold the remaining 50% equity. The block lies some 125 kilometres (78 miles) to the south east of Baku. It covers an area of some 1,100 square kilometres and has never been explored before. It is located in a deepwater section of about 650-800 metres with reservoir depth of about 7,000 metres. |
• | On 24 December 2010, BP and its partners received a five-year PSA extension for Shah Deniz from SOCAR. The PSA extension allows the Shah Deniz partners to negotiate new long-term gas contracts and underpins the economics of the project. |
• | During 2010, the remedial work necessary following the subsurface gas release that occurred beneath the Central Azeri platform in September 2008 was completed. With the exception of two wells that were abandoned, all wells on the Central Azeri platform are online and in service. |
• | Naftiran Intertrade Co (NICO) Ltd is an Iranian company and has a less than 10% non-operating interest in Shah Deniz. NICO was selected as a Shah Deniz project participant by the State of Azerbaijan when the Shah Deniz PSA was awarded in June 1996. Under article 30 of the new EU Regulations concerning restrictive measures against Iran, any body, entity or holder of rights derived from an award of a PSA before the entry into force of the EU Regulations by a sovereign government other than Iran, shall not be considered an ‘Iranian person, entity or body’ for the purposes of the main operative provisions of the EU Regulations. |
• | On 14 January 2011, BP and Rosnefta announced a strategic global alliance. Rosneft and BP have agreed to explore and develop three licence blocks in Russia’s South Kara Sea covering approximately 125,000 square kilometres. Additionally, BP has agreed to issue 988,694,683 ordinary BP shares to Rosneft (representing 5% of BP) in a swap where Rosneft has agreed to transfer 1,010,158,003 ordinary Rosneft shares to BP (representing 9.5% of Rosneft). Finally, BP and Rosneft have agreed to other joint pursuits including the establishment of an Arctic technology centre in Russia, joint technical studies in the Russian Arctic beyond the South Kara Sea area and the search for additional international collaboration opportunities. The share swap transaction is subject to certain listing approvals and the completion of certain administrative requirements. The share swap agreement is subject to the outcome of arbitration proceedings between BP and Alfa Petroleum Holdings Limited (APH) and OGIP Ventures Limited (OGIP) who have raised issues relating to the share swap agreement and the alliance. APH is a company owned by Alpha Group. APH and OGIP each own 25% of TNK-BP in which BP also has a 50% shareholding. See further information in Legal proceedings on page 133. |
• | Downstream, TNK-BP has interests in six refineries in Russia and Ukraine (including Ryazan and Lisichansk and Slavneft’s Yaroslavl refinery), with throughput of approximately 715 thousand barrels per day. TNK-BP supplies approximately 1,400 branded filling stations in Russia and Ukraine and has more than 25% market share of the Moscow retail market. |
a | BP already holds a 1.3% investment in Rosneft Oil Company with a carrying value of $948 million. |
BP Annual Report and Form 20-F 2010 47
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• | On 17 February 2010, the TNK-BP board of directors endorsed investment projects totalling more than $1.8 billion to be spent in 2010 – 2012. Of this amount, $1.7 billion is allocated for two major upstream projects: full field development and creation of regional infrastructure in the eastern part of the Uvat group of fields and further development of the Verkhnechonskoye oilfield in East Siberia. Members of the board also endorsed TNK-BP’s participation in a joint venture between National Petroleum Consortium LLP and Petroleos de Venezuela (PDVSA), the state oil company of Venezuela, to appraise and develop the JUNIN 6 block in Venezuela and to release funding of $180 million to support these activities in 2010 – 2012. |
• | On 28 May 2010, TNK-BP announced completion of a deal to acquire 100% of the Vik Oil group of companies in the Ukraine. Previously Vik Oil owned 118 fuel stations in 13 Ukrainian regions, as well as 8 oil depots, 49 petrol tankers and 122 land plots in various stages of development. TNK-BP paid $302 million for these interests. |
• | On 28 February 2011, TNK-BP announced that it had sold its interest in the Kovykta gas field to Gazprom. |
• | On 3 January 2010, BP received approval from the government of Jordan to join the state-owned National Petroleum Company to exploit the onshore Risha concession in the north-east of the country. BP established an office in February and has started its exploration and appraisal work programme, including commencement of a 5,000-square kilometre seismic programme. |
• | On 11 October 2010, after 32 years as operator of the Sharjah concession area, BP agreed to transfer its operatorship of the concession to the government of Sharjah. BP will retain its equity ownership of 40% of the concession until expiry in November 2013. |
• | During 2010, major milestones achieved in the Oman Khazzan Makarem gas appraisal programme included the award of the contract for early engineering, design and concept studies for the potential long-term development of hydrocarbon resources in the block, and the commissioning of early well test facilities. |
• | On 1 July 2010, the Rumaila Operating Organization (ROO) was established and began to take over operatorship of the Rumaila oilfield from South Oil Company (SOC), one of the state-owned oil companies in Iraq. The ROO is made up of approximately 4,000 assignees from BP, PetroChina and SOC, and its creation is one of the first steps in the plan to grow Rumaila production to 2.85 million barrels per day over the next few years. |
• | In September 2010, BP and PetroChina, as the international partners in the ROO, signed an agreement with the British Council to fund dedicated English language tuition for approximately 500 employees of the ROO. The British Council teachers will be based in the Rumaila oilfield and provide training for the current English language teachers in SOC and the local North Rumaila Village school. According to the TSC, BP and PetroChina are required to spend $5 million per year on education and this agreement with the British Council is the first major programme funded as part of this commitment. |
• | In December 2010, as a result of increasing activity throughout 2010, production was sustained at 10% above the initial production rate to achieve the improved production target which is the first significant milestone in the rehabilitation of Rumaila. Achievement of IPT was formally agreed with the Government of Iraq on 25 December 2010 and consequently the Contractors (BP and PetroChina) in accordance with the TSC, become eligible for Service Fees during 2011. |
• | The North Rankin 2 project linking a second platform to the existing North Rankin A platform, sanctioned in 2008, remains on track for start-up in late 2012. On completion, the North Rankin A and North Rankin B platforms will operate as a single integrated facility and recover low-pressure gas from the North Rankin and Perseus gas fields. |
• | The Janz-lo field (BP 5.375%) development, which is part of the Greater Gorgon project, is on track. The Jansz-lo field will be developed as part of the Greater Gorgon project, which will comprise three LNG trains, each with a capacity of 5 million tonnes per annum (mtpa), on Barrow Island, with first gas expected in 2014. As part of this, a unitization and unit operating agreement has been executed with the joint venture partners and sales and purchase agreements for the wellhead sale of raw gas and repurchase of LNG ex-Barrow Island have been executed between BP and Shell. |
• | In January 2011, BP announced that it had been awarded four deepwater offshore exploration blocks in the Ceduna Sub Basin within the Great Australian Bight, off the coast of south Australia. |
• | On 26 November 2010, BP was awarded a 100% interest in the North Arafura oil and gas PSA in onshore Papua province. The PSA was signed in Jakarta by representatives of the government and BP. The North Arafura PSA is located on the coast of the Arafura Sea, 480 kilometres south east of the BP-operated Tangguh plant, covering an area of just over 5,000 square kilometres. BP expects to commence seismic operations on the block in the near future. |
a | An LNG train is a processing facility used to liquefy and purify LNG. |
48 BP Annual Report and Form 20-F 2010
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• | Denali conducted concurrent 90-day open season bidding processes for both the US and Canadian portions of the Denali project during the third quarter of 2010, the bidding for each concluded on 4 October 2010. Conditional bids were received for significant capacity from potential shippers. At the end of 2010, Denali is evaluating the bids received, and confidential negotiations with potential shippers continue in an effort to reach binding agreements. If agreements can be concluded for sufficient capacity, Denali will seek certification from the Federal Energy Regulatory Commission (FERC) of the US and the National Energy Board (NEB) of Canada to move forward with project construction. Denali would manage the project, and would own and operate the pipeline when completed. BP may consider other equity participants, including pipeline companies, that can add value to the project and help manage the risks involved. |
• | On 12 January 2010, an agreement to settle challenges to TAPS carrier interstate tariff rate filings for the calendar year 2008 and the first half of 2009 was signed by the TAPS carriers and those challenging the tariffs at the US FERC. The agreement was approved by the US FERC on 1 April 2010. Under the terms of the settlement, in the second quarter of 2010 BP paid additional refunds to third-party shippers, amounting to $0.4 million, representing the $0.12/bbl difference between the $3.45/bbl tariff rate on which the interim refunds paid in 2009 for this period were based, and the $3.33/bbl tariff rate in the approved settlement agreement. |
• | In Trinidad, BP’s net share of the capacity of Atlantic LNG Trainsa 1, 2, 3 and 4 is 6 million tonnes of LNG per year (292 billion cubic feet equivalent regasified). All of the LNG from Atlantic Train 1 and most of the LNG from Trains 2 and 3 is sold to third parties in the US and Spain under long-term contracts. All of BP’s LNG entitlement from Atlantic LNG Train 4 and some of its LNG entitlement from Trains 2 and 3 is marketed via BP’s LNG marketing and trading business to a variety of markets including the US, the Dominican Republic, Spain, the UK and the Far East. |
• | We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction Company, which in 2010 supplied 5.85 million tonnes (302,231mmscf) of LNG. |
• | BP has a 13.6% share in the Angola LNG project, which is expected to receive approximately 1 billion cubic feet of associated gas per day from offshore producing blocks and to produce 5.2 million tonnes per year of LNG (gross), as well as related gas liquids products. Construction and implementation of the project is proceeding and the plant is expected to start up in 2012. |
• | In Indonesia, BP is involved in two of the three LNG centres in the country. BP participates in Indonesia’s LNG exports through its holdings in the Sanga-Sanga PSA (BP 38%). Sanga-Sanga currently delivers around 13% of the total gas feed to Bontang, one of the world’s largest LNG plants. The Bontang plant produced more than 17 million tonnes of LNG in 2010. |
• | Also in Indonesia, BP has its first operated LNG plant, Tangguh (BP 37.16%), in Papua Barat. The first phase of Tangguh, which is in its first full year of operations, comprises two offshore platforms, two pipelines and an LNG plant with two production trains with a total capacity of 7.6mtpa. The Tangguh project has six long-term contracts in place to supply LNG to customers in China, South Korea, Mexico and Japan. |
• | In Australia, we are one of seven partners in the NWS venture. The joint venture operation covers offshore production platforms, trunklines, onshore gas and LNG processing plants and LNG carriers. BP’s net share of the capacity of NWS LNG Trains 1-5 is 2.7mtpa of LNG. |
• | BP has a 30% equity stake in the 7mtpa capacity Guangdong LNG regasification and pipeline project in south-east China, making it the only foreign partner in China’s LNG import business. The terminal is also supplied under a long-term contract with Australia’s NWS project. |
• | In both the Atlantic and Asian regions, BP is marketing LNG using BP LNG shipping and contractual rights to access import terminal capacity in the liquid markets of the US (via Cove Point and Elba Island), the UK (via the Isle of Grain) and Italy (Rovigo), and is supplying Asian customers in Japan, South Korea and Taiwan. |
a See footnote a on page 48. |
BP Annual Report and Form 20-F 2010 49
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$ per unit of productiona | |||||||||||||||||||||||||||||||||||||||
┌───Europe───┐ | ┌───North───┐ | ┌─South─┐ | ┌─Africa─┐ | ┌───Asia───┐ | ┌Australasia┐ | Total group | |||||||||||||||||||||||||||||||||
America | America | average | |||||||||||||||||||||||||||||||||||||
Rest of | |||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | |||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | ||||||||||||||||||||||||||||||||||
Average sales priceb | |||||||||||||||||||||||||||||||||||||||
Subsidiaries | |||||||||||||||||||||||||||||||||||||||
2010 | |||||||||||||||||||||||||||||||||||||||
Liquidsc | 76.33 | 81.09 | 70.79 | 48.26 | 71.01 | 74.87 | – | 78.80 | 75.81 | 73.41 | |||||||||||||||||||||||||||||
Gas | 5.44 | 7.16 | 3.88 | 4.20 | 2.80 | 4.11 | – | 4.05 | 7.01 | 3.97 | |||||||||||||||||||||||||||||
2009 | |||||||||||||||||||||||||||||||||||||||
Liquidsc | 62.19 | 60.73 | 53.68 | 30.77 | 52.48 | 57.40 | – | 61.27 | 57.22 | 56.26 | |||||||||||||||||||||||||||||
Gas | 4.68 | 7.62 | 3.07 | 3.53 | 2.50 | 3.61 | – | 3.30 | 5.25 | 3.25 | |||||||||||||||||||||||||||||
2008 | |||||||||||||||||||||||||||||||||||||||
Liquidsc | 89.82 | 93.77 | 89.22 | 64.42 | 91.61 | 89.44 | – | 97.20 | 86.33 | 90.20 | |||||||||||||||||||||||||||||
Gas | 8.41 | 6.96 | 6.77 | 7.87 | 4.90 | 4.46 | – | 3.63 | 9.22 | 6.00 | |||||||||||||||||||||||||||||
Equity-accounted entitiesd | |||||||||||||||||||||||||||||||||||||||
2010 | |||||||||||||||||||||||||||||||||||||||
Liquidsc | – | – | – | – | 61.60 | – | 60.39 | 6.72 | – | 52.81 | |||||||||||||||||||||||||||||
Gas | – | – | – | – | 1.97 | – | 1.91 | 7.83 | – | 2.04 | |||||||||||||||||||||||||||||
2009 | |||||||||||||||||||||||||||||||||||||||
Liquidsc | – | – | – | – | 51.01 | – | 47.27 | 5.59 | – | 41.93 | |||||||||||||||||||||||||||||
Gas | – | – | – | – | 1.90 | – | 1.51 | 5.25 | – | 1.68 | |||||||||||||||||||||||||||||
2008 | |||||||||||||||||||||||||||||||||||||||
Liquidsc | – | – | – | – | 56.39 | – | 73.7 | 4.80 | – | 61.39 | |||||||||||||||||||||||||||||
Gas | – | – | – | – | 1.97 | – | 1.68 | 10.53 | – | 1.94 | |||||||||||||||||||||||||||||
a | Units of production are barrels for liquids and thousands of cubic feet for gas. |
b | Realizations include transfers between businesses. |
c | Crude oil and natural gas liquids. |
d | It is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets at discounted prices. |
$ per unit of productiona | |||||||||||||||||||||||||||||||||||||||
┌───Europe───┐ | ┌───North───┐ | ┌─South─┐ | ┌─Africa─┐ | ┌───Asia───┐ | ┌Australasia┐ | Total group | |||||||||||||||||||||||||||||||||
America | America | average | |||||||||||||||||||||||||||||||||||||
Rest of | |||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | |||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | ||||||||||||||||||||||||||||||||||
The average production cost per | |||||||||||||||||||||||||||||||||||||||
unit of productiona | |||||||||||||||||||||||||||||||||||||||
Subsidiaries | |||||||||||||||||||||||||||||||||||||||
2010 | 12.79 | 9.76 | 8.10 | 15.78 | 2.48 | 7.52 | – | 4.59 | 2.03 | 6.77 | |||||||||||||||||||||||||||||
2009 | 12.38 | 10.72 | 7.26 | 14.45 | 2.20 | 6.05 | – | 4.35 | 1.60 | 6.39 | |||||||||||||||||||||||||||||
2008 | 12.19 | 8.74 | 9.02 | 15.35 | 2.34 | 6.72 | – | 5.24 | 1.74 | 7.24 | |||||||||||||||||||||||||||||
Equity-accounted entities | |||||||||||||||||||||||||||||||||||||||
2010 | – | – | – | – | 6.32 | – | 5.04 | 0.97 | – | 4.26 | |||||||||||||||||||||||||||||
2009 | – | – | – | – | 6.12 | – | 4.63 | 0.94 | – | 3.95 | |||||||||||||||||||||||||||||
2008 | – | – | – | – | 5.84 | – | 5.97 | 0.87 | – | 4.73 | |||||||||||||||||||||||||||||
a | Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes. |
50 BP Annual Report and Form 20-F 2010
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volumes in mmboe | ||||
Proved undeveloped reserves at 1 January 2010 | 7,952 | |||
Revisions of previous estimates | (247 | ) | ||
Improved recovery | 1,062 | |||
Discoveries and extensions | 689 | |||
Purchases | 74 | |||
Sales | (150 | ) | ||
Total in year proved undeveloped reserves changes | 9,380 | |||
Progressed to proved developed reserves | (1,481 | ) | ||
Proved undeveloped reserves at 31 December 2010 | 7,899 | |||
• | Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner. |
• | Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects. |
• | Internal Audit, whose role is to consider whether the Group’s system of internal control is adequately designed and operating effectively to respond appropriately to the risks that are significant to BP. |
• | Approval hierarchy, whereby proved reserves changes above certain threshold volumes require central authorization and periodic reviews. The frequency of review is determined according to field size and ensures that more than 80% of the BP proved reserves base undergoes central review every two years, and more than 90% is reviewed centrally every four years. |
BP Annual Report and Form 20-F 2010 51
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million barrels | ||||||||||||
Developed | Undeveloped | Total | ||||||||||
UK | 364 | 431 | 795 | |||||||||
Rest of Europe | 77 | 221 | 298 | |||||||||
US | 1,729 | 1,190 | 2,919 | d | ||||||||
Rest of North America | – | – | – | |||||||||
South America | 44 | 58 | 102 | e | ||||||||
Africa | 371 | 374 | 745 | |||||||||
Rest of Asia | 269 | 325 | 594 | |||||||||
Australasia | 48 | 58 | 106 | |||||||||
Subsidiaries | 2,902 | 2,657 | 5,559 | |||||||||
Equity-accounted entities | 3,166 | 1,984 | 5,150 | f | ||||||||
Total | 6,068 | 4,641 | 10,709 | |||||||||
billion cubic feet | ||||||||||||
Developed | Undeveloped | Total | ||||||||||
UK | 1,416 | 829 | 2,245 | |||||||||
Rest of Europe | 40 | 430 | 470 | |||||||||
US | 9,495 | 4,248 | 13,743 | |||||||||
Rest of North America | 58 | – | 58 | |||||||||
South America | 3,575 | 6,575 | 10,150 | g | ||||||||
Africa | 1,329 | 2,351 | 3,680 | |||||||||
Rest of Asia | 1,290 | 268 | 1,558 | |||||||||
Australasia | 3,563 | 2,342 | 5,905 | |||||||||
Subsidiaries | 20,766 | 17,043 | 37,809 | |||||||||
Equity-accounted entities | 3,046 | 1,845 | 4,891 | h | ||||||||
Total | 23,812 | 18,888 | 42,700 | |||||||||
million barrels of oil equivalent | ||||||||||||
Developed | Undeveloped | Total | ||||||||||
Subsidiaries | 6,481 | 5,596 | 12,077 | |||||||||
Equity-accounted entities | 3,691 | 2,303 | 5,994 | |||||||||
Total | 10,172 | 7,899 | 18,071 | |||||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently, and include minority interests in consolidated operations. We disclose our share of reserves held in jointly controlled entities and associates that are accounted for by the equity method although we do not control these entities or the assets held by such entities. |
b | The 2010 marker prices used were Brent $79.02/bbl (2009 $59.91/bbl and 2008 $36.55/bbl) and Henry Hub $4.37/mmBtu (2009 $3.82/mmBtu and 2008 $5.63/mmBtu). |
c | Liquids include crude oil, condensate, natural gas liquids and bitumen. |
d | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 78 million barrels on which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
e | Includes 22 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
f | Includes 254 million barrels of crude oil in respect of the 7.03% minority interest in TNK-BP. |
g | Includes 2,921 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
h | Includes 137 billion cubic feet of natural gas in respect of the 5.89% minority interest in TNK-BP. |
52 BP Annual Report and Form 20-F 2010
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thousand barrels per day | ||||||||||||||
Subsidiaries | BP net share of productiona | |||||||||||||
Field or area | 2010 | 2009 | 2008 | |||||||||||
UKb | ETAPc | 28 | 34 | 27 | ||||||||||
Foinavend | 24 | 29 | 26 | |||||||||||
Other | 85 | 105 | 120 | |||||||||||
Total UK | 137 | 168 | 173 | |||||||||||
Norwayb | Various | 40 | 40 | 43 | ||||||||||
Total Rest of Europe | 40 | 40 | 43 | |||||||||||
Total Europe | 177 | 208 | 216 | |||||||||||
Alaska | Prudhoe Bayd | 67 | 69 | 72 | ||||||||||
Kuparuk | 42 | 45 | 48 | |||||||||||
Milne Pointd | 23 | 24 | 27 | |||||||||||
Other | 34 | 43 | 50 | |||||||||||
Total Alaska | 166 | 181 | 197 | |||||||||||
Lower 48 onshoreb | Various | 90 | 97 | 97 | ||||||||||
Gulf of Mexico deepwaterb | Thunder Horsed | 120 | 133 | 24 | ||||||||||
Atlantisd | 49 | 54 | 42 | |||||||||||
Mad Dogd | 30 | 35 | 31 | |||||||||||
Mars | 23 | 29 | 28 | |||||||||||
Na Kikad | 25 | 27 | 29 | |||||||||||
Horn Mountaind | 14 | 25 | 18 | |||||||||||
Kingd | 21 | 22 | 23 | |||||||||||
Other | 56 | 62 | 49 | |||||||||||
Total Gulf of Mexico deepwater | 338 | 387 | 244 | |||||||||||
Total US | 594 | 665 | 538 | |||||||||||
Canadab | Variousd | 7 | 8 | 9 | ||||||||||
Total Rest of North America | 7 | 8 | 9 | |||||||||||
Total North America | 601 | 673 | 547 | |||||||||||
Colombia | Variousd | 18 | 23 | 24 | ||||||||||
Trinidad & Tobago | Variousd | 36 | 38 | 38 | ||||||||||
Venezuelab | Various | – | – | 4 | ||||||||||
Total South America | 54 | 61 | 66 | |||||||||||
Angola | Greater Plutoniod | 73 | 70 | 69 | ||||||||||
Kizomba C Dev | 31 | 43 | 30 | |||||||||||
Dalia | 20 | 32 | 34 | |||||||||||
Girassol FPSO | 18 | 22 | 22 | |||||||||||
Other | 28 | 44 | 46 | |||||||||||
Total Angola | 170 | 211 | 201 | |||||||||||
Egyptb | Gupco | 47 | 55 | 41 | ||||||||||
Other | 12 | 16 | 16 | |||||||||||
Total Egypt | 59 | 71 | 57 | |||||||||||
Algeria | Various | 17 | 22 | 19 | ||||||||||
Total Africa | 246 | 304 | 277 | |||||||||||
Azerbaijanb | Azeri-Chirag-Gunashlid | 94 | 94 | 97 | ||||||||||
Other | 9 | 7 | 8 | |||||||||||
Total Azerbaijan | 103 | 101 | 105 | |||||||||||
Western Indonesiab | Various | 2 | 5 | 7 | ||||||||||
Other | Various | 14 | 17 | 16 | ||||||||||
Total Rest of Asiab | 119 | 123 | 128 | |||||||||||
Total Asia | 119 | 123 | 128 | |||||||||||
Australia | Various | 30 | 31 | 29 | ||||||||||
Other | Various | 2 | – | – | ||||||||||
Total Australasia | 32 | 31 | 29 | |||||||||||
Total subsidiariese | 1,229 | 1,400 | 1,263 | |||||||||||
Equity-accounted entities (BP share) | ||||||||||||||
Russia – TNK-BPb | Various | 856 | 840 | 826 | ||||||||||
Total Russia | 856 | 840 | 826 | |||||||||||
Abu Dhabif | Various | 190 | 182 | 210 | ||||||||||
Other | Various | 1 | 12 | 10 | ||||||||||
Total Rest of Asiab | 191 | 194 | 220 | |||||||||||
Total Asia | 1,047 | 1,034 | 1,046 | |||||||||||
Argentina | Various | 75 | 75 | 70 | ||||||||||
Venezuelab | Various | 23 | 25 | 19 | ||||||||||
Boliviab | Various | – | 1 | 3 | ||||||||||
Total South America | 98 | 101 | 92 | |||||||||||
Total equity-accounted entities | 1,145 | 1,135 | 1,138 | |||||||||||
Total subsidiaries and equity-accounted entities | 2,374 | 2,535 | 2,401 | |||||||||||
a | Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | In 2010, BP divested its Permian Basin assets in Texas and south-east New Mexico, the East Badr El-Din and Western Desert concession in Egypt, its Canada gas assets and reduced its interest in the Tubular Bells and King fields in the Gulf of Mexico. It also acquired an increased holding in the Azeri-Chirag-Gunashli development in Azerbaijan and the Valhall and Hod fields in the Norwegian North Sea. Four other producing fields in the Gulf of Mexico that were acquired during 2010 were subsequently disposed of in early 2011. In 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in Pakistan, swapped a number of assets with BG Group plc in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest Java to Pertamina, divested its interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation payable, Pan American Energy’s shares of Chaco. In 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position, and TNK-BP disposed of some non-core interests. |
c | Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell. |
d | BP-operated. |
e | Includes 29 net mboe/d of NGLs from processing plants in which BP has an interest (2009 26mboe/d and 2008 19mboe/d). |
f | The BP group holds interests, through associates, in onshore and offshore concessions in Abu Dhabi, expiring in 2014 and 2018 respectively. |
BP Annual Report and Form 20-F 2010 53
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million cubic feet per day | ||||||||||||||
Subsidiaries | BP net share of productiona | |||||||||||||
Field or area | 2010 | 2009 | 2008 | |||||||||||
UKb | Bruce/Rhumc | 100 | 110 | 165 | ||||||||||
Brae East | 46 | 62 | 71 | |||||||||||
Other | 326 | 446 | 523 | |||||||||||
Total UK | 472 | 618 | 759 | |||||||||||
Norwayb | Various | 15 | 16 | 23 | ||||||||||
Total Rest of Europe | 15 | 16 | 23 | |||||||||||
Total Europe | 487 | 634 | 782 | |||||||||||
Lower 48 onshoreb | San Juanc | 629 | 659 | 682 | ||||||||||
Jonahc | 185 | 227 | 221 | |||||||||||
Arkoma Central | 164 | 194 | 240 | |||||||||||
Arkoma West | 128 | 65 | – | |||||||||||
Arkoma East | 112 | 67 | – | |||||||||||
Wamsutterc | 126 | 146 | 136 | |||||||||||
Other | 531 | 597 | 607 | |||||||||||
Total Lower 48 onshore | Total | 1,875 | 1,955 | 1,886 | ||||||||||
Gulf of Mexico deepwaterb | Thunder Horsec | 80 | 83 | 11 | ||||||||||
Other | 183 | 220 | 219 | |||||||||||
Total Gulf of Mexico deepwater | 263 | 303 | 230 | |||||||||||
Alaska | Various | 46 | 58 | 41 | ||||||||||
Total US | 2,184 | 2,316 | 2,157 | |||||||||||
Canadab | Various | 202 | 263 | 245 | ||||||||||
Total Rest of North America | 202 | 263 | 245 | |||||||||||
Total North America | 2,386 | 2,579 | 2,402 | |||||||||||
Trinidad & Tobago | Mangoc | 544 | 664 | 471 | ||||||||||
Cashima/NEQBc | 679 | 571 | 375 | |||||||||||
Kapokc | 541 | 540 | 619 | |||||||||||
Cannonballc | 156 | 225 | 336 | |||||||||||
Amherstiac | 252 | 197 | 288 | |||||||||||
Otherc | 301 | 233 | 357 | |||||||||||
Total Trinidad | 2,473 | 2,430 | 2,446 | |||||||||||
Colombia | Various | 71 | 62 | 84 | ||||||||||
Venezuelab | Various | – | – | 2 | ||||||||||
Total South America | 2,544 | 2,492 | 2,532 | |||||||||||
Egyptb | Temsah | 90 | 118 | 109 | ||||||||||
Ha’pyc | 73 | 94 | 94 | |||||||||||
Taurtc | 75 | 73 | 24 | |||||||||||
Other | 192 | 177 | 145 | |||||||||||
Total Egypt | 430 | 462 | 372 | |||||||||||
Algeria | Total | 126 | 159 | 112 | ||||||||||
Total Africa | 556 | 621 | 484 | |||||||||||
Pakistanb | Variousc | 150 | 173 | 162 | ||||||||||
Azerbaijanb | Variousc | 132 | 126 | 143 | ||||||||||
Western lndonesiab | Sanga-Sanga | 69 | 71 | 69 | ||||||||||
Other | 1 | 35 | 97 | |||||||||||
Total Western Indonesia | 70 | 106 | 166 | |||||||||||
China | Yacheng | 95 | 83 | 91 | ||||||||||
Vietnam | Variousc | 77 | 63 | 61 | ||||||||||
Sharjah | Variousc | 50 | 59 | 73 | ||||||||||
Total Rest of Asia | 574 | 610 | 696 | |||||||||||
Total Asia | 574 | 610 | 696 | |||||||||||
Australia | Perseus/Athena | 165 | 142 | 229 | ||||||||||
Goodwyn | 118 | 139 | 74 | |||||||||||
Angel | 133 | 120 | 6 | |||||||||||
Other | 46 | 39 | 71 | |||||||||||
Total Australia | 462 | 440 | 380 | |||||||||||
Eastern Indonesia | Tangguhc | 323 | 74 | 1 | ||||||||||
Total Australasia | 785 | 514 | 381 | |||||||||||
Total subsidiariesd | 7,332 | 7,450 | 7,277 | |||||||||||
Equity-accounted entities (BP share) | ||||||||||||||
Russia – TNK-BPb | Various | 640 | 601 | 564 | ||||||||||
Total Russia | 640 | 601 | 564 | |||||||||||
Western Indonesia | Various | 30 | 31 | 31 | ||||||||||
Kazakhstanb | Various | – | 11 | 8 | ||||||||||
Total Rest of Asia | 30 | 42 | 39 | |||||||||||
Total Asia | 670 | 643 | 603 | |||||||||||
Argentina | Various | 379 | 378 | 385 | ||||||||||
Boliviab | Various | 11 | 11 | 63 | ||||||||||
Venezuelab | Various | 9 | 3 | 6 | ||||||||||
Total South America | 399 | 392 | 454 | |||||||||||
Total equity-accounted entitiesd | 1,069 | 1,035 | 1,057 | |||||||||||
Total subsidiaries and equity-accounted entities | 8,401 | 8,485 | 8,334 | |||||||||||
a | Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | In 2010, BP divested its Permian Basin assets in Texas and south-east New Mexico, the East Badr El-Din and Western Desert concession in Egypt, its Canada gas assets and reduced its interest in the Tubular Bells and King fields in the Gulf of Mexico. It also acquired an increased holding in the Azeri-Chirag-Gunashli development in Azerbaijan and the Valhall and Hod fields in the Norwegian North Sea. Four other producing fields in the Gulf of Mexico that were acquired during 2010 were subsequently disposed of in early 2011. In 2009, BP assumed operatorship of the Mirpurkhas and Khipro blocks in Pakistan, swapped a number of assets with BG Group plc in the UK sector of the North Sea, divested some minor interests in the US Lower 48, divested its holdings in Indonesia’s Offshore Northwest Java to Pertamina, divested it’s interests in LukArco to Lukoil and the Bolivian government nationalized, with compensation payable, Pan American Energy’s shares of Chaco. In 2008, BP concluded the migration of the Cerro Negro operations to an incorporated joint venture with PDVSA while retaining its equity position, and TNK-BP disposed of some non-core interests. |
c | BP-operated. |
d | Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves. |
54 BP Annual Report and Form 20-F 2010
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a | This performance improvement will be measured by comparing Refining and Marketing’s replacement cost profit for 2009 with that of 2012, after adjusting for non-operating items, fair value accounting effects and the impact of changes in the refining margin environment, foreign exchange impacts and price-lag effects for crude and product purchases. |
BP Annual Report and Form 20-F 2010 55
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Sales and other operating revenuesa | 266,751 | 213,050 | 320,039 | |||||||||
Replacement cost profit before interest and taxb | 5,555 | 743 | 4,176 | |||||||||
Capital expenditure and acquisitions | 4,029 | 4,114 | 6,634 | |||||||||
thousand barrels per day | ||||||||||||
Total refinery throughputs | 2,426 | 2,287 | 2,155 | |||||||||
Refining availabilityc | 95.0% | 93.6% | 88.8% | |||||||||
thousand tonnes | ||||||||||||
Total petrochemicals productiond | 15,594 | 12,660 | 12,835 | |||||||||
$ per barrel | ||||||||||||
Global indicator refining margin (GIM)e | ||||||||||||
US West Coast | 6.16 | 5.88 | 7.42 | |||||||||
US Gulf Coast | 4.96 | 4.63 | 6.78 | |||||||||
US Midwest | 5.19 | 5.43 | 5.17 | |||||||||
Northwest Europe | 3.80 | 3.26 | 6.72 | |||||||||
Mediterranean | 3.29 | 2.11 | 6.00 | |||||||||
Singapore | 1.63 | 0.21 | 6.30 | |||||||||
BP Average GIM | 4.44 | 4.00 | 6.50 | |||||||||
a | Includes sales between businesses. |
b | Includes profit after interest and tax of equity-accounted entities. |
c | Refining availability represents Solomon Associates’ operational availability, which is defined as the percentage of the year that a unit is available for processing after subtracting the annualized time lost due to turnaround activity and all planned mechanical, process and regulatory maintenance downtime. |
d | A minor amendment has been made to comparative periods. |
e | The global indicator refining margin (GIM) is the average of regional industry indicator margins weighted for BP’s crude refining capacity in each region. Each regional indicator margin is based on a single representative crude with product yields characteristic of the typical level of upgrading complexity. The indicator margin may not be representative of the margins achieved by BP in any period because of BP’s particular refining configurations and crude and product slate. |
Safety and operational risk
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Sale of crude oil through spot and term contracts | 44,290 | 35,625 | 54,901 | |||||||||
Marketing, spot and term sales of refined products | 209,221 | 166,088 | 248,561 | |||||||||
Other sales and operating revenues | 13,240 | 11,337 | 16,577 | |||||||||
266,751 | 213,050 | 320,039 | ||||||||||
The following tables set out oil sales volumes by type for the past three years and give further details of refined product marketing sales by product type: | ||||||||||||
thousand barrels per day | ||||||||||||
Refined products | 2010 | 2009 | 2008 | |||||||||
US | 1,433 | 1,426 | 1,460 | |||||||||
Europe | 1,402 | 1,504 | 1,566 | |||||||||
Rest of World | 610 | 630 | 685 | |||||||||
Total marketing salesa | 3,445 | 3,560 | 3,711 | |||||||||
Trading/supply salesb | 2,482 | 2,327 | 1,987 | |||||||||
Total refined product sales | 5,927 | 5,887 | 5,698 | |||||||||
Crude oilc | 1,658 | 1,824 | 1,689 | |||||||||
Total oil sales | 7,585 | 7,711 | 7,387 | |||||||||
a | Marketing sales are sales to service stations, end-consumers, bulk buyers and jobbers (i.e. third parties who own networks of a number of service stations and small resellers). |
b | Trading/supply sales are sales to large unbranded resellers and other oil companies. |
c | 113 thousand barrels per day of the crude volumes relates to revenues reported by Exploration and Production. |
56 BP Annual Report and Form 20-F 2010
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thousand barrels per day | ||||||||||||
Marketing sales by refined product | 2010 | 2009 | 2008 | |||||||||
Aviation fuel | 546 | 495 | 501 | |||||||||
Gasolines | 1,326 | 1,444 | 1,500 | |||||||||
Middle distillates | 1,012 | 1,012 | 1,055 | |||||||||
Fuel oil | 391 | 418 | 460 | |||||||||
Other products | 170 | 191 | 195 | |||||||||
Total marketing sales | 3,445 | 3,560 | 3,711 | |||||||||
thousand barrels per day | ||||||||||||||||||||
Crude distillation capacitiesa | ||||||||||||||||||||
Group interestb | BP | |||||||||||||||||||
Refinery | Fuels value chain | % | Total | share | ||||||||||||||||
Europe | ||||||||||||||||||||
Germany | Bayernoil | Rhine | 22.5 | % | 215 | 48 | ||||||||||||||
Gelsenkirchenc | Rhine | 50.0 | % | 265 | 132 | |||||||||||||||
Karlsruhe | Rhine | 12.0 | % | 324 | 39 | |||||||||||||||
Lingenc | Rhine | 100.0 | % | 93 | 93 | |||||||||||||||
Schwedt | Rhine | 18.8 | % | 237 | 45 | |||||||||||||||
Netherlands | Rotterdamc | Rhine | 100.0 | % | 377 | 377 | ||||||||||||||
Spain | Castellónc | Iberia | 100.0 | % | 110 | 110 | ||||||||||||||
Total Europe | 1,621 | 844 | ||||||||||||||||||
US | ||||||||||||||||||||
California | Carsonc | US West Coast | 100.0 | % | 266 | 266 | ||||||||||||||
Washington | Cherry Pointc | US West Coast | 100.0 | % | 234 | 234 | ||||||||||||||
Indiana | Whitingc | US Mid-West | 100.0 | % | 405 | 405 | ||||||||||||||
Ohio | Toledoc | US Mid-West | 50.0 | % | 160 | 80 | ||||||||||||||
Texas | Texas Cityc | – | 100.0 | % | 475 | 475 | ||||||||||||||
Total US | 1,540 | 1,460 | ||||||||||||||||||
Rest of World | ||||||||||||||||||||
Australia | Bulwerc | ANZ | 100.0 | % | 102 | 102 | ||||||||||||||
Kwinanac | ANZ | 100.0 | % | 143 | 143 | |||||||||||||||
New Zealand | Whangerei | ANZ | 23.7 | % | 118 | 28 | ||||||||||||||
South Africa | Durban | Southern Africa | 50.0 | % | 180 | 90 | ||||||||||||||
Total Rest of World | 543 | 363 | ||||||||||||||||||
Total | 3,704 | 2,667 | ||||||||||||||||||
a | Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period. |
b | BP share of equity, which is not necessarily the same as BP share of processing entitlements. |
c | Indicates refineries operated by BP. |
BP Annual Report and Form 20-F 2010 57
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thousand barrels per day | ||||||||||||||
Refinery throughputsa | 2010 | 2009 | 2008 | |||||||||||
US | 1,350 | 1,238 | 1,121 | |||||||||||
Europe | 775 | 755 | 739 | |||||||||||
Rest of World | 301 | 294 | 295 | |||||||||||
Total | 2,426 | 2,287 | 2,155 | |||||||||||
Refinery capacity utilization | ||||||||||||||
Crude distillation capacity at 31 Decemberb | 2,667 | 2,666 | 2,678 | |||||||||||
Refinery utilizationc | 91% | 86% | 81% | |||||||||||
US | 93% | 85% | 77% | |||||||||||
Europe | 91% | 89% | 87% | |||||||||||
Rest of World | 84% | 83% | 80% | |||||||||||
a | Refinery throughputs reflect crude oil and other feedstock volumes. |
b | Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period. |
c | Refinery utilization is annual throughput divided by crude distillation capacity, expressed as a percentage. The measure was redefined in 2009 to be more consistent with industry standards. |
Number of retail sites operated under a BP brand | ||||||||||||
Retail sitesa b | 2010 | 2009 | 2008 | |||||||||
US | 11,300 | 11,500 | 11,700 | |||||||||
Europe | 8,400 | 8,600 | 8,600 | |||||||||
Rest of World | 2,400 | 2,300 | 2,300 | |||||||||
Total | 22,100 | 22,400 | 22,600 | |||||||||
a | The number of retail sites includes sites not operated by BP but instead operated by dealers, jobbers, franchisees or brand licensees that operate under a BP brand. These may move to or from the BP brand as their fuel supply or brand licence agreements expire and are renegotiated in the normal course of business. Retail sites are primarily branded BP, ARCO and Aral. |
b | Excludes our interest in equity-accounted entities which are dual-branded. |
58 BP Annual Report and Form 20-F 2010
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• | The Whiting refinery modernization project made significant progress in 2010 as above ground construction began, including the reactors for the new gasoil hydrotreater, the new towers on the revamped crude distillation unit and the coker’s six new drums. Two third-party world-scale hydrogen units were commissioned in 2010 and began providing hydrogen to the refinery. Progress on important pipeline interconnections completed in 2010 will allow Whiting early access to greater crude imports and product export opportunities. | |
• | In the US, BP’s reputation suffered as a result of the oil spill in the Gulf of Mexico, which had an adverse impact on our branded fuels marketing, but this had recovered by year end. We offered additional marketing support to our customers in an attempt to mitigate these declines. | |
• | In the Gulf of Mexico region, sales were down year on year by up to 30% in some sites in the second quarter, but regained ground over the second half of 2010. | |
• | In October, BP opened a cutting-edge fuels technology development centre in South Africa, which will focus on quality assurance, technical service and marketing support for the local market. | |
• | The integrated supply and trading function within the FVCs announced that it was reorganizing its internal structure in order to simplify the organization and reduce costs. | |
• | In October, BP sold its French retail business to Delek Europe B.V. | |
• | During 2010, BP also completed the divestment of several packages of non-strategic terminals and pipelines in the US East of Rockies and West Coast. This programme of divestment of non-strategic pipelines and terminals will continue during 2011. | |
• | Following a strategic review of our businesses in southern Africa, we intend to focus our activities within the continent on South Africa and Mozambique. As a result, BP agreed to sell its fuels marketing businesses in Namibia, Zambia and Botswana to Puma Energy and in addition, BP intends to sell its 50% interest in BP Malawi and BP Tanzania to Puma Energy. The sale of BP Tanzania to Puma Energy is subject to the pre-emption rights of its co-shareholders. Only the sale of the Botswana business had been completed as at 31 December 2010, the other sales are expected to be completed in 2011. | |
• | During 2010 BP completed the sale of a number of European terminals as part of ongoing asset optimization activities. |
thousand barrels per day | ||||||||||||
International businesses sales volumes | 2010 | 2009 | 2008 | |||||||||
Air BP | 450 | 434 | 478 | |||||||||
LPG | 58 | 67 | 64 | |||||||||
Lubricants | 50 | 49 | 54 | |||||||||
558 | 550 | 596 | ||||||||||
a | Operating capital employed is total assets (excluding goodwill) less total liabilities, excluding finance debt and current and deferred taxation. |
BP Annual Report and Form 20-F 2010 59
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Petrochemicals production capacitya b |
BP share of | ||||||||||||||
capacity | ||||||||||||||
Group interest | thousand tonnes | |||||||||||||
Geographical area | Site | Product | % | per year | ||||||||||
US | ||||||||||||||
Cooper River | Purified terephthalic acid (PTA) | 100.0 | 1,342 | |||||||||||
Decatur | PTA | 100.0 | 1,043 | |||||||||||
Paraxylene (PX) | 100.0 | 1,101 | ||||||||||||
Naphthalene dicarboxylate | 100.0 | 29 | ||||||||||||
Texas City | Acetic acid | 100.0 | 583 | c | ||||||||||
PX | 100.0 | 1,271 | ||||||||||||
Metaxylene | 100.0 | 123 | ||||||||||||
5,492 | ||||||||||||||
Europe | ||||||||||||||
UK | Hull | Acetic acid | 100.0 | 532 | ||||||||||
Acetic anhydride | 100.0 | 153 | ||||||||||||
Ethylidene diacetate | 100.0 | 4 | ||||||||||||
Belgium | Geel | PTA | 100.0 | 1,343 | ||||||||||
PX | 100.0 | 631 | ||||||||||||
Germany | Gelsenkirchen | Olefins and derivatives | 50.0 to 61.0 | 1,764 | b d | |||||||||
Mulheim | Solvents | 50.0 | 130 | b | ||||||||||
4,557 | ||||||||||||||
Rest of World | ||||||||||||||
China | Caojing | Olefins and derivatives | 50.0 | 3,103 | b | |||||||||
Chongqing | Acetic acid | 51.0 | 215 | b | ||||||||||
Esters | 51.0 | 52 | b | |||||||||||
Nanjing | Acetic acid | 50.0 | 274 | b | ||||||||||
Zhuhai | PTA | 85.0 | 1,549 | e | ||||||||||
Indonesia | Merak | PTA | 50.0 | 253 | b | |||||||||
Korea | Ulsan | Acetic acid | 51.0 | 261 | b | |||||||||
Vinyl acetate monomer | 34.0 | 56 | b | |||||||||||
Malaysia | Kertih | Acetic acid | 70.0 | 391 | b | |||||||||
Kuantan | PTA | 100.0 | 610 | |||||||||||
Taiwan | Kaohsiung | PTA | 61.4 | 847 | b | |||||||||
Taichung | PTA | 61.4 | 471 | b | ||||||||||
Mai Liao | Acetic acid | 50.0 | 179 | b | ||||||||||
8,261 | ||||||||||||||
Total BP share of capacity at 31 December 2010 | 18,310 | |||||||||||||
a | Petrochemicals production capacity is the proven maximum sustainable daily rate (msdr) multiplied by the number of days in the respective period, where msdr is the highest average daily rate ever achieved over a sustained period. |
b | Includes BP share of equity-accounted entities, as indicated. |
c | Sterling Chemicals plant, 100% of the output of which is marketed by BP. |
d | Group interest varies by product. |
e | BP Zhuhai Chemical Company Ltd is a subsidiary of BP, the capacity of which is shown above at 100%. |
• | Castrol was a sponsor of the 2010 FIFA World Cup™ in South Africa and used this to deliver a significant programme of brand visibility and customer engagement. Castrol leveraged the sponsorship to support our businesses in all regions. We have seen increased brand awareness for our Castrol master brand and product brands. | |
• | In July 2010, Castrol opened a new lubricants technology development centre in China. Employing scientists and engineers from China and abroad, this team will work collaboratively with vehicle manufacturers, distributors and other partners, focusing on cutting-edge lubricant |
60 BP Annual Report and Form 20-F 2010
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technology development and support, as well as providing world-class training for customers and distributors. | ||
• | During 2010, the LPG business further simplified its portfolio. In China, the LPG business decided to focus its in-country operations on core marketing activities and sold its interest in the China Zhuhai cavern complex. This completes the exit from all major China LPG import facilities. In Europe, BP sold its LPG businesses in Spain and Denmark. | |
• | The BP YPC Acetyls Company (Nanjing) Limited (BYACO) joint venture between BP and Yangzi Petrochemical Co. Ltd (a subsidiary of Sinopec) successfully commenced commercial production at its 548,000 tonnes per annum (ktepa) acetic acid plant in the fourth quarter of 2010. | |
• | The petrochemicals business started a debottleneck project to add a further 200ktepa PTA capacity at the BP Zhuhai Chemical Company Limited site in Guangdong province (China), which is scheduled for completion in the first quarter of 2012. This additional capacity employs BP’s latest proprietary technology and will bring the site’s total PTA capacity to 1,750ktepa, continuing our growth in China. | |
• | During 2010, BP sold its 15% interest in Ethylene Malaysia Sdn Bhd (EMSB) and its 60% interest in Polyethylene Malaysia Sdn Bhd (PEMSB) to Petronas. |
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Sales and other operating revenuesa | 3,328 | 2,843 | 4,634 | |||||||||
Replacement cost profit (loss) before | ||||||||||||
interest and taxb | (1,516 | ) | (2,322 | ) | (1,223 | ) | ||||||
Capital expenditure and acquisitions | 1,234 | 1,299 | 1,839 | |||||||||
a | Includes sales between businesses. |
b | Includes profit after interest and tax of equity-accounted entities. |
a | Global Wind Energy Council –Annex Stats 2009. |
b | World Energy Outlook 2010©OECD/IEA 2010, page 306. |
c | BP Energy Outlook 2030. |
d | The majority of costs have been capitalized, some were expensed under IFRS. |
BP Annual Report and Form 20-F 2010 61
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2010 | 2009 | 2008 | ||||||||||
Wind – net rated capacity at year-end | ||||||||||||
(megawatts)a | 774 | 711 | 432 | |||||||||
Solar – module sales (megawatts)b | 325 | 203 | 162 | |||||||||
a | Net wind capacity is the sum of the rated capacities of the assets/turbines that have entered into commercial operation, including BP’s share of equity-accounted entities. The equivalent capacities on a gross-JV basis (which includes 100% of the capacity of equity-accounted entities where BP has partial ownership) were 1,362MW in 2010, 1,237MW in 2009 and 785MW in 2008. This includes 32MW of capacity in the Netherlands which is managed by our Refining and Marketing segment. |
b | Solar sales are the total sales of solar modules to third-party customers, expressed in MW. Previously we reported the theoretical cell production capacity of our in-house solar manufacturing facilities. Reporting sales volumes operating data brings us in line with the broader solar industry. |
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a | Jointly published by industry bodies, including the Oil Companies International Marine Forum (OCIMF) and supported by military operations in the region. |
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• | $5.3 billion of standby facilities, of which $0.4 billion is available to draw and repay by mid-September 2011, $4.6 billion until mid-October 2011, and $0.3 billion until mid-January 2013. | |
• | $7.2 billion of 364-day facilities, of which $4.0 billion can be drawn until late May 2011, $2.0 billion drawn until the end of June 2011, $0.7 billion drawn until early July 2011 and $0.5 billion drawn until late August 2011. Any amounts drawn are repayable up to 364 days from the date of drawing. |
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$ million | ||||||||||||||||||||||||||||
Payments due by period | ||||||||||||||||||||||||||||
Expected payments by period under contractual | 2016 and | |||||||||||||||||||||||||||
obligations and commercial commitments | Total | 2011 | 2012 | 2013 | 2014 | 2015 | thereafter | |||||||||||||||||||||
Balance sheet obligations | ||||||||||||||||||||||||||||
Borrowingsa | 41,550 | 9,200 | 6,439 | 7,486 | 6,054 | 5,443 | 6,928 | |||||||||||||||||||||
Finance lease future minimum lease payments | 1,126 | 153 | 377 | 56 | 51 | 51 | 438 | |||||||||||||||||||||
Deepwater Horizon Oil Spill Trust funding liability | 15,008 | 5,008 | 5,000 | 5,000 | – | – | – | |||||||||||||||||||||
Decommissioning liabilitiesb | 14,876 | 461 | 453 | 370 | 362 | 413 | 12,817 | |||||||||||||||||||||
Environmental liabilitiesb | 3,903 | 1,763 | 545 | 275 | 189 | 158 | 973 | |||||||||||||||||||||
Pensions and other post-retirement benefitsc | 25,670 | 1,916 | 1,905 | 1,403 | 976 | 983 | 18,487 | |||||||||||||||||||||
Total balance sheet obligations | 102,133 | 18,501 | 14,719 | 14,590 | 7,632 | 7,048 | 39,643 | |||||||||||||||||||||
Off-balance sheet obligations | ||||||||||||||||||||||||||||
Operating leasesd | 13,973 | 3,521 | 2,475 | 1,878 | 1,413 | 1,032 | 3,654 | |||||||||||||||||||||
Unconditional purchase obligationse | 166,942 | 97,355 | 16,330 | 9,291 | 6,778 | 5,634 | 31,554 | |||||||||||||||||||||
Total off-balance sheet obligations | 180,915 | 100,876 | 18,805 | 11,169 | 8,191 | 6,666 | 35,208 | |||||||||||||||||||||
Total | 283,048 | 119,377 | 33,524 | 25,759 | 15,823 | 13,714 | 74,851 | |||||||||||||||||||||
a | Expected payments include interest payments on borrowings totalling $3,221 million ($888 million in 2011, $679 million in 2012, $520 million in 2013, $362 million in 2014, $225 million in 2015 and $547 million thereafter), and exclude disposal deposits of $6,197 million included in current finance debt on the balance sheet. |
b | The amounts are undiscounted. Environmental liabilities include those relating to the Gulf of Mexico oil spill, including liabilities for spill response costs. |
c | Represents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post-retirement benefits. |
d | The future minimum lease payments are before deducting related rental income from operating sub-leases. In the case of an operating lease entered into solely by BP as the operator of a jointly controlled asset, the amounts shown in the table represent the net future minimum lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint venture partners. Where BP is not the operator of a jointly controlled asset BP’s share of the future minimum lease payments are included in the amounts shown, whether BP has co-signed the lease or not. Where operating lease costs are incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project. |
e | Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The amounts shown include arrangements to secure long-term access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2011 include purchase commitments existing at 31 December 2010 entered into principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial statements – Note 27 on page 186. |
$ million | ||||||||||||||||||||||||||||
Payments due by period | ||||||||||||||||||||||||||||
2016 and | ||||||||||||||||||||||||||||
Unconditional purchase obligations | Total | 2011 | 2012 | 2013 | 2014 | 2015 | thereafter | |||||||||||||||||||||
Crude oil and oil products | 101,671 | 70,572 | 7,058 | 3,582 | 2,207 | 1,934 | 16,318 | |||||||||||||||||||||
Natural gas | 36,147 | 19,780 | 5,117 | 2,827 | 2,078 | 1,450 | 4,895 | |||||||||||||||||||||
Chemicals and other refinery feedstocks | 8,912 | 2,055 | 1,278 | 923 | 888 | 858 | 2,910 | |||||||||||||||||||||
Power | 2,784 | 1,915 | 688 | 162 | 16 | 2 | 1 | |||||||||||||||||||||
Utilities | 925 | 156 | 154 | 111 | 98 | 89 | 317 | |||||||||||||||||||||
Transportation | 8,525 | 1,184 | 875 | 796 | 726 | 637 | 4,307 | |||||||||||||||||||||
Use of facilities and services | 7,978 | 1,693 | 1,160 | 890 | 765 | 664 | 2,806 | |||||||||||||||||||||
Total | 166,942 | 97,355 | 16,330 | 9,291 | 6,778 | 5,634 | 31,554 | |||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||
2016 and | ||||||||||||||||||||||||||||
Capital expenditure commitments | Total | 2011 | 2012 | 2013 | 2014 | 2015 | thereafter | |||||||||||||||||||||
Committed on major projects | 31,376 | 15,193 | 7,205 | 4,304 | 2,170 | 986 | 1,518 | |||||||||||||||||||||
Amounts for which contracts have been placed | 11,279 | 7,239 | 1,966 | 1,093 | 504 | 316 | 161 | |||||||||||||||||||||
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Net cash provided by operating activities | 13,616 | 27,716 | 38,095 | |||||||||
Net cash used in investing activities | (3,960 | ) | (18,133 | ) | (22,767 | ) | ||||||
Net cash provided by (used in) financing activities | 840 | (9,551 | ) | (10,509 | ) | |||||||
Currency translation differences relating to cash and cash equivalents | (279 | ) | 110 | (184 | ) | |||||||
Increase in cash and cash equivalents | 10,217 | 142 | 4,635 | |||||||||
Cash and cash equivalents at beginning of year | 8,339 | 8,197 | 3,562 | |||||||||
Cash and cash equivalents at end of year | 18,556 | 8,339 | 8,197 | |||||||||
$ billion | ||||
Sources of cash | ||||
Net cash provided by operating activities | 79 | |||
Disposals | 22 | |||
101 | ||||
Uses of cash | ||||
Capital expenditure | 64 | |||
Acquisitions | 3 | |||
Net repurchase of shares | 2 | |||
Dividends paid to BP shareholders | 23 | |||
Dividends paid to minority interests | 1 | |||
93 | ||||
Net source of cash | 8 | |||
Increase in finance debt | 7 | |||
Increase in cash and cash equivalents | 15 | |||
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• | The creation of an enhanced safety and operational risk function that is independent of the business line and is represented in every BP operation. | |
• | The reorganization of our upstream business to create three functional divisions, each reporting directly to the group chief executive. (See Exploration and Production on pages 40-41 for further details.) | |
• | A review of employee reward frameworks to increase the focus on performance in safety, compliance, and operational risk management. (See Employees on page 74 for further details.) | |
• | An examination of how we can strengthen the oversight of contractors. Strengthening these core areas will require some profound changes in how we operate and will take several years to fully embed. |
• | BOPs used on BP-operated projects, along with other well-control equipment, were checked to confirm that they had been properly maintained and are capable of shutting in the well in an emergency. | |
• | Remotely operated vehicles were confirmed to be capable of activating BOPs in emergency situations. | |
• | New decision matrix, designed to aid key decisions on well design and operations, was developed and distributed to our operations globally. | |
• | Two containment hats were delivered to the UK to aid North Sea containment capability. | |
• | We updated our oil spill response plan, and submitted it to the US Department of the Interior. |
• | Provide checks and balances independent of the business line. | |
• | Strengthen mandatory safety-related standards and processes, including operational risk management. | |
• | Provide an independent view on operational risk. | |
• | Assess and enhance the competency and capability of our workforce in matters related to safety. |
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• | Identify crisis and continuity management scenarios utilising the entity risk register, the output of the entity’s major accident risk assessment and other information. | |
• | Implement and maintain crisis and continuity management plans to manage the scenarios identified. These will include procedures from initiation to response and recovery. At site level these plans shall include arrangements for evacuation and, where needed, for initial shelter-in-place. | |
• | Validate the plans through exercising them at defined intervals. Review the plans at least annually to reflect changes in hazards, risks, organization or contact details, and implement identified improvements. | |
• | Provide access to trained personnel, resources, medical emergency and other facilities needed to implement and execute the crisis and continuity management plans. | |
• | Implement, maintain and exercise a documented process for accounting for personnel during and after an emergency evacuation. |
• | Collaboration: a broad range of stakeholders came together in the wake of the Deepwater Horizon incident to provide effective solutions and build new capabilities. It would have been extremely difficult for any one company alone to address challenges on the scale of the Deepwater Horizon incident. The response benefited from close collaboration with and the capabilities of the US Coast Guard, Bureau of Ocean Energy Management, Regulation and Enforcement and dozens of other partners and stakeholders from government, industry, academia and the affected communities, as well as around the globe. | |
• | Systemization: the response to the incident required the development of extensive systems, procedures and organizational capabilities to adapt to changing and unique conditions. As the Deepwater Horizon spill continued despite efforts at the wellhead, the response effort progressed, expanded, and took on not just new tasks and directions but new personnel and resources. As a result, from source to shore, existing systems were evolved and expanded and new ones developed to advance work flow, improve co-ordination, focus efforts and manage risks. The adoption of these systems will ensure the ability to respond to future spills more rapidly at scale with a clear direction as to personnel, resource and organizational needs. | |
• | Information: timely and reliable information was essential across both the containment and response operations to achieve better decision-making, ensure safe operations and inform stakeholders and the public. | |
• | Innovation: the urgency in containing the spill and dealing with its effects drove innovations in tools, equipment, processes and know-how, ranging from incremental enhancements to step changes in technologies and techniques, that have advanced the state of the art and laid the foundation for future refinements as part of an enhanced regime for any type of source-to-shore response. |
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2010 | 2009 | 2008 | |||||||||||
Loss of primary containment – number of all incidentsa | 418 | 537 | 658 | ||||||||||
Loss of primary containment – number of oil spillsb | 261 | 234 | 335 | ||||||||||
Number of oil spills to land and water | 142 | 122 | 170 | ||||||||||
Volume of oil spilled (thousand litres) | 1,719 | 1,191 | 3,440 | ||||||||||
Volume of oil unrecovered (thousand litres) | 758 | 222 | 911 | ||||||||||
a | Does not include either small or non-hazardous releases. |
b | Number of spills greater than or equal to one barrel (159 litres, 42 US gallons). |
• | addressing overtime issues, and in particular high individual overtime rates; | |
• | the development and implementation of management systems for safety instrumented systems (SIS), required by BP’s internal standards, to address areas such as documentation, training for personnel competency, and auditing (collectively, “SIS life cycle” issues); | |
• | taking advantage of certain additional opportunities to further strengthen the process safety culture at BP’s US refineries and increasing the pace to achieve this desired culture change; and | |
• | addressing issues of non-conformance with standards and practices and ensuring that installed equipment continues to meet applicable standards and practices. |
• | in relation to reduction of overtime rates, the US refineries had reduced their average overtime rates to levels that are perceived to be at or near industry norms for both operations and maintenance personnel in 2010, and significant reductions in overtime rates for individuals had also been achieved, with only a few people exceeding BP’s individual overtime target at the end of 2010; | |
• | in relation to SIS management systems, the US refineries had made accelerated progress in 2010 in addressing SIS life-cycle requirements; the Fourth Report noted that rigourous implementation of these new SIS life-cycle policies and procedures for all existing and newly installed SISs will be a challenging task; | |
• | in relation to process safety culture, the US refineries had developed a common safety culture vision in 2010 and progress was being made in communicating the new vision; the Fourth Report also noted that progress is being made toward improved communication, co-operation and sharing between the refineries and commented on some improvements with respect to individuals adopting a more proactive and self-critical approach towards identifying and addressing risks. The Fourth Report noted that input from Mr Wilson was still sometimes required to catalyze the identification of and timely response to process safety issues; and | |
• | in relation to implementing internal and external standards and practices, BP had clearly identified those standards and practices that apply to the US refineries and is implementing them through risk-prioritized plans. The Fourth Report noted that, although progress is being made in the implementation of standards and practices, special emphasis will be required to address certain remaining issues in a timely manner, including: the time required to implement some new standards; the need to identify requirements in standards that apply retroactively to existing equipment; and the need for a process to ensure that existing equipment remains in conformance with applicable standards. |
• | additional sustained efforts, building on sincere messages from executive management to date, may be required to ensure that executive management effectively stimulates and supports a process safety culture within BP’s US refineries that promotes industry-leading process safety performance; | |
• | with the exception of action items resulting from audits and incident investigations, overdue process safety action items were not being reported to executive management and to the board, as recommended by the Panel; in addition, Mr Wilson recommended that BP consider ways to systematically gather information sufficient to ensure completion of identified process safety action items within reasonable time periods; and | |
• | in the second half of 2010, the quality of some aspects of incident investigations and reports did not maintain the levels achieved in 2009. In response, a Continuous Improvement Team was chartered that developed a number of process improvements to be implemented in early 2011. |
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• | Booms can be placed around the spill to gather the oil. A curtain is attached to its underside to prevent the oil from sliding out underneath it and spreading further. | |
• | Sorbents can absorb the oil. | |
• | In situ burning can be used to reduce the amount of oil on the water. | |
• | Skimming equipment can be placed around the area to scoop it from the water’s surface. | |
• | Chemical dispersants can help the oil break up more quickly and mix more easily with the water column. Specific dispersants have been developed for different oils. The net environmental benefit of using chemical dispersants should always be considered and assessed before use. |
a | We report GHG emissions, on a CO2 – equivalent basis, including CO2 and methane. This represents all consolidated entities and BP’s share of equity-accounted entities except TNK-BP. |
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Environmental expenditure
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Environmental expenditure relating to the Gulf of Mexico oil spill | ||||||||||||
Spill response | 13,628 | – | – | |||||||||
Additions to environmental remediation provision | 929 | – | – | |||||||||
Other environmental expenditure | ||||||||||||
Operating expenditure | 716 | 701 | 755 | |||||||||
Capital expenditure | 911 | 955 | 1,104 | |||||||||
Clean-ups | 55 | 70 | 64 | |||||||||
Additions to environmental remediation provision | 361 | 588 | 270 | |||||||||
Additions to decommissioning provision | 1,800 | 169 | 327 | |||||||||
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Number of employees at 31 December | US | Non-US | Total | |||||||||
2010 | ||||||||||||
Exploration and Production | 7,900 | 13,200 | 21,100 | |||||||||
Refining and Marketinga | 12,400 | 39,900 | 52,300 | |||||||||
Other businesses and corporate | 1,700 | 4,500 | 6,200 | |||||||||
Gulf Coast Restoration Organization | 100 | – | 100 | |||||||||
22,100 | 57,600 | 79,700 | ||||||||||
2009 | ||||||||||||
Exploration and Production | 8,000 | 13,500 | 21,500 | |||||||||
Refining and Marketinga | 12,700 | 38,900 | 51,600 | |||||||||
Other businesses and corporate | 2,100 | 5,100 | 7,200 | |||||||||
22,800 | 57,500 | 80,300 | ||||||||||
2008 | ||||||||||||
Exploration and Production | 7,700 | 13,700 | 21,400 | |||||||||
Refining and Marketinga | 19,000 | 42,500 | 61,500 | |||||||||
Other businesses and corporate | 2,600 | 6,500 | 9,100 | |||||||||
29,300 | 62,700 | 92,000 | ||||||||||
a Includes 15,200 (2009 13,900 and 2008 21,200) service station staff. |
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• | In response to the Gulf of Mexico oil spill, BP has established the Gulf of Mexico Research Initiative, a 10-year $500-million open-research programme into the effects of the spill. The ultimate goal of the research efforts will be to improve society’s ability to mitigate the impacts of hydrocarbon pollution and related stressors of the marine environment. In 2010, BP awarded $40 million of short-term contracts for immediate research into the effects of the spill. | |
• | BP has significant, long-term research programmes with major universities and research institutions around the world, exploring areas from energy bioscience and conversion technology to carbon mitigation and nanotechnology in solar power. 2010 marked two significant milestones – the 10-year anniversaries of both the Carbon Mitigation Initiative (CMI) at Princeton University and the BP Institute for Multiphase Flow (BPI) at the University of Cambridge. The success of the CMI has resulted in agreement for BP to support an additional five years of research. BP has also agreed to increase the BPI endowment fund to support an extra senior researcher and part-time administrator. | |
• | The BP Foundation funded the new McKenzie Chair in Earth Sciences at the University of Cambridge. The Chair will ensure the continued excellence of research and teaching of quantitative earth sciences in the department. | |
• | At the Energy Biosciences Institute (EBI) in Berkeley, US, the investment in foundational research platforms has started to generate innovations with direct commercial relevance. The first of these are being adopted by the biofuels business into commercial practice. The EBI’s capabilities developed for the study of microbially-enhanced oil and gas recovery were leveraged to study the microbial biodegradation of the oil spill in the Gulf of Mexico. | |
• | BP is a founding member of the UK’s Energy Technologies Institute (ETI) – a public / private partnership established in 2008 to accelerate low-carbon technology development. As at 31 December 2010, the ETI had commissioned over $92 million of work covering more than 20 projects across a wide range of technologies. The ETI has also developed an integrated model of the UK energy system, which projects potential pathways out to 2050 to meet the UK’s emissions targets. | |
• | The Energy Sustainability Challenge is a multi-disciplinary research programme aimed at understanding pressures on freshwater availability and increasing competition for land and mineral resources, driven by the impact of increasing population and urbanization on energy demand. Research projects with leading universities are under way, investigating the effects of natural resource scarcities on patterns of energy supply and consumption, and which technologies are likely to be needed in an increasingly resource-constrained world. |
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• | The Gulf of Mexico oil spill required rapid innovation of new technologies to cap the well and contain the spill. Innovation will continue as part of Gulf restoration efforts. BP worked with industry partners, multiple government agencies, and academia to develop solutions and, as a result, now has a set of additional assets covering: |
– | An inventory of immediately deployable open and closed containment systems proven at depth with associated operating procedures. | ||
– | Proven systems for processing and transporting contained oil. | ||
– | Diagnostic and surveillance techniques for dispersed oil analysis and monitoring. | ||
– | Plans and organizational models for the immediate deployment of dedicated source containment. | ||
– | Enhanced technologies and procedures to drill relief wells in deep water. | ||
– | Experience in using all of the above capabilities. |
• | BP continues to develop and apply innovative exploration technologies. Following the successful use of the ISS™ seismic acquisition technique in Libya in 2009, we have conducted field trials, combined with cableless node receivers to further increase seismic acquisition efficiency. Positive test results led to a decision to acquire 3,000 square kilometres of the 2010/11 Libya onshore acquisition programme using this method. | |
• | Through the inherently reliable facilities (IRF) flagship technology programme, BP is developing a fundamental understanding of corrosion and erosion risks and corresponding mitigation barriers and techniques. The IRF programme has developed fibre optic pipeline monitoring technologies to reduce the risk of third-party interference and monitor for leaks. These were deployed on the Baku-Tbilisi-Ceyhan pipeline in 2010, and further applications are planned. | |
• | 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 can add 2 billion boe to our reserves. As at the end of 2010, BP has treated 56 wells with Bright Water™ technology in Alaska, Argentina, Azerbaijan and Pakistan, which has delivered increased reserves at a development cost of less than $6 per barrel, and with an 80% success rate. Following field trials in Alaska, LoSal™ EOR in the Clair field (UK North Sea) is now in front end engineering design stage. The Clair Ridge LoSal EOR project will be the world’s first offshore LoSal technology waterflood. Following extensive EOR studies for the Schiehallion field in the West of Shetland, BP and co-owners have approved the design of the new Quad 204 Schiehallion FPSO (the floating production, storage and offloading unit, which is expected to be sanctioned in the second quarter of 2011) to be fully polymer EOR ready. |
• | Technology advances in our refining and logistics businesses give us better understanding and processing of different feedstocks, optimization of our assets, enhanced flexibility and reliability of our refineries, and stronger margins. In 2010, following extensive development work with BP and Imperial College London, Permasense launched a new integrity-monitoring system that enables frequent, repeatable wall-thickness monitoring. This provides previously unavailable insights into the condition and capability of oil and gas assets. The Permasense system has been proven in operation at BP refineries in Germany and the US, and is now being deployed at our refineries worldwide. |
Bright Wateris a trade mark of Nalco Energy Services LP.
• | In fuels and lubricants, our technology focus is on supplying products with greater fuel efficiency and reduced CO2 emissions. In partnership with original equipment manufacturers, BP has developed a new passenger car engine oil offering 2.4% fuel saving; a transmission oil for military vehicles with a 1.5% fuel saving; and the turbine oil for the new Boeing 787 Dreamliner. We are working on prototype fuels to optimize the performance and efficiency of next-generation engines and to enable increased biofuel content to meet national mandates. In the US, BP’s Invigorate™ gasoline has been endorsed by BMW for its superior performance in cleaning engine fuel injection systems. | |
• | In 2010, we opened a new lubricants technology centre in Shanghai, China, and a new fuels technology centre in Johannesburg, South Africa. Both represent the first investments of their type in those countries for an international oil company and underpin BP’s commitment to these important markets. | |
• | Our proprietary processing technologies and operational experience continue to reduce the manufacturing costs and environmental impact of our petrochemicals plants, helping to maintain competitive advantage in purified terephthalic acid (PTA), paraxylene, and acetic acid. Learning from successful project implementations in Asia, continuous improvement of our CATIVA® technology for manufacture of acetic acid maintains BP’s world-class capital and operating cost position. | |
• | In the field of conversion technology, we continue to work with potential third-party licensees to commercialize BP’s fixed-bed Fischer-Tropsch technology. This technology can be applied to the conversion of unconventional feedstocks, including biomass, to high-quality diesel and other liquid hydrocarbons. In addition, BP and KBR agreed a 25-year collaboration to promote, market, and execute licensing and engineering services for the slurry-bed residue and coal-upgrading Veba Combi Cracker (VCC) Technology. VCC Technology 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. |
• | In 2010, our biofuels business acquired Verenium’s lignocellulosic biofuels business, which will accelerate the development of lignocellulosic ethanol technology to commercialization. BP has acquired: R&D facilities in San Diego, California; intellectual property related to proprietary lignocellulosic biofuels R&D and conversion technology; a pilot plant and demonstration facility in Jennings, Louisiana; and BP is now the sole owner of Vercipia Biofuels, which is commercializing production of lignocellulosic ethanol. | |
• | In the wind business, the quest for more energy-efficient wind turbine generators continues. In the US, BP Wind Energy is testing state-of-the-art laser wind sensor units to deliver improved wind turbine performance and increase energy output. | |
• | In our solar business, a new technology designed to make solar cells more efficient in extremely high temperatures, InnerCool™ solar technology, is being piloted at a university in Saudi Arabia, where we have demonstrated increases in energy generation of approximately 3%. We have also developed and introduced a new anti-reflective glass coating for solar modules, reducing the amount of energy lost through reflection and allowing more light to reach the cells, thus increasing energy generation by up to 4% compared to plain glass modules. | |
• | In 2010, the first phase of BP’s joint industry project with Sonatrach and Statoil at In Salah, Algeria – to demonstrate new technologies for monitoring stored CO2 – drew to a close. The project is helping to set operational parameters for the secure geological storage of CO2, with particular highlights including the Quantitative Risk Assessment developed, tested and benchmarked at In Salah, as well as the integration of technologies, such as satellite imaging and 3D and 4D seismic, to better understand the behaviour of CO2 plumes in the subsurface. |
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• | The Kyoto Protocol currently commits 38 ratified parties to meet emissions targets in the commitment period 2008 to 2012. | |
• | The UN summit in Cancun in December 2010 where Parties to the UN Framework Convention on Climate Change (UNFCCC) reached formal agreement on a balanced package of measures to 2020. The Cancun Agreement recognizes that deep cuts in global GHG emissions are required to hold the increase in global temperature to below 2°C. |
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Signatories formally commit to carbon reduction targets or actions by 2020. Around 80 countries, including all the major economies and many developing countries, have made such commitments. Supporting those efforts, principles were agreed for monitoring, verifying and reporting emissions reductions; establishment of a green fund to help developing countries limit and adapt to climate change; and measures to protect forests and transfer low-carbon technology to poorer nations. | ||
• | The European Union (EU) Climate Action and Renewable Energy Package which requires increased greenhouse gas reductions, improvements in energy efficiency and increased renewable energy use by 2020, as well as including the Revision of the EU Emissions Trading Scheme (EU ETS) directive. This regulates approximately one-fifth of our reported 2009 global CO2 emissions and can be expected to require additional expenditure from 2013 when the next revision of the scheme (EU ETS Phase 3) comes into effect. The main changes in EU ETS will be a significant increase in the auctioning of allowances, the end of free allocations for electricity production, an expanded scope covering additional commercial sectors and gases, certain free allocations determined mainly by EU-wide sector benchmarks as compensation for carbon leakage (relocation to less regulated jurisdictions), and consideration of carbon capture and storage installations. | |
• | The EU Renewables Energy Directive (RED) requires that the share of energy from renewable sources in all forms of transport in 2020 be at least 10 % of the final consumption of energy in transport in that member state. | |
• | Article 7a of the revised EU Fuels Quality Directive requires fuel suppliers to reduce the life cycle GHG emissions per unit of fuel and energy supplied in certain transport markets from 2011. | |
• | BP’s facilities in the UK are subject to the UK Carbon Reduction Commitment Scheme (CRC EES), which has recently been modified to end the recycling of revenues back to participants. This can be expected to require additional expenditures for compliance. | |
• | Australia has committed to reduce its GHG emissions by between 5-25% below 2000 levels by 2020, depending on the extent of international action. A proposed GHG emissions trading scheme (CPRS) has been scrapped by the incoming coalition government, but a forum (the Multi Party Climate Change Committee) has been established to investigate options for implementing a carbon price and to help build consensus on Australia’s measures to address climate change. | |
• | New Zealand has agreed to cut GHG emissions by 10-20% from 1990 levels by 2020, subject to certain conditions. New Zealand’s emission trading scheme (NZ ETS) commenced on 1 July 2010 for transport fuels, industrial processes, and stationary energy. The agriculture sector (45% of New Zealand’s GHG emissions) has been proposed to join the NZ ETS in January 2015. | |
• | In the US, following the failure to pass comprehensive climate legislation, the US Environmental Protection Agency (EPA) is pursuing regulatory measures to address GHGs under the Clean Air Act (CAA). |
– | In late 2009, the EPA released a GHG endangerment finding to establish its authority to regulate GHG emissions under the CAA. | ||
– | Subsequent to this, EPA finalized regulations imposing light duty vehicle emissions standards for GHGs. | ||
– | The EPA finalized the initial GHG mandatory reporting rule (MRR) in 2009 and amended or proposed amendments to it several times during 2010. | ||
– | The EPA finalized permitting requirements for new or modified large GHG sources in 2010, with these regulations taking effect in January 2011. | ||
– | The EPA’s efforts to regulate GHG emissions through the CAA are subject to numerous legal challenges and active political debate so that the final content and scope of GHG regulation in the US remains uncertain. |
• | A number of additional state and regional initiatives in the US will affect our operations. Of particular significance, California is seeking to reduce GHG emissions to 1990 levels by 2020 and to reduce the carbon intensity of transport fuel sold in the state. California implemented a low-carbon fuel standard in 2010 and is on target to complete emissions cap-and-trade, low carbon fuel, and other GHG regulations in 2011 for programme start up in January 2012. | |
• | Canada has adopted an action plan to reduce emissions to 17% below 2005 levels by 2020 and the national government seeks a co-ordinated approach with the US on environmental and energy objectives. |
• | The Clean Air Act (CAA) regulates air emissions, permitting, fuel specifications and other aspects of our production, distribution and marketing activities. Stricter limits on sulphur and benzene in fuels will affect us in future, as will actions on GHG emissions. Additionally, many states have separate air emission laws in addition to the CAA. | |
• | The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 affect our US fuel markets by, among other things, imposing renewable fuel mandates and imposing GHG emissions thresholds for certain renewable fuels. States such as California also impose additional fuel carbon standards. | |
• | The Clean Water Act (CWA) regulates wastewater and other effluent discharges from BP’s facilities, and BP is required to obtain discharge permits, install control equipment and implement operational controls and preventative measures. | |
• | The Resource Conservation and Recovery Act (RCRA) regulates the generation, storage, transportation and disposal of wastes associated with our operations and can require corrective action at locations where such wastes have been released. | |
• | The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), can, in certain circumstances, impose the entire cost of investigation and remediation on a party who owned or operated a contaminated site or arranged for waste disposal at the site. BP has incurred, or expects to incur, liability under the CERCLA or similar state laws, including costs attributed to insolvent or unidentified parties. BP is also subject to claims for remediation costs under other federal and state laws, and to claims for natural resource damages under the CERCLA, the Oil Pollution Act of 1990 (OPA 90) and other federal and state laws. | |
• | The Toxic Substances Control Act regulates BP’s import, export and sale of new chemical products. | |
• | The Occupational Safety and Health Act imposes workplace safety and health requirements on our operations along with significant process safety management obligations. | |
• | The Emergency Planning and Community Right-to-Know Act requires emergency planning and hazardous substance release notification as well as public disclosure of our chemical usage and emissions. | |
• | The US Department of Transportation (DOT) regulates the transport of BP’s petroleum products such as crude oil, gasoline and petrochemicals. | |
• | The Marine Transportation Security Act (MTSA), the DOT Hazardous Materials (HAZMAT) and the Chemical Facility Anti-Terrorism Standard (CFATS) regulations impose security compliance regulations on approximately 150 BP facilities. These regulations require security vulnerability assessments, security mitigation plans and security upgrades, increasing our cost of operations. |
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• | The EU Climate Action and Renewable Energy Package and the Emissions Trading Scheme (ETS) Directive(see Greenhouse gas regulation on page 78). | |
• | The EU European Integrated Pollution Prevention and Control (IPPC) Directive imposes a unified environmental permit requirement on our major European sites, including refineries and chemical facilities, and requires assessments and upgrades to our facilities. A proposed Industrial Emission Directive would replace the IPPC Directive. It would merge several existing industrial emission directives, impose tighter emission standards for large combustion plants and be more prescriptive as to the emission limits that have to be achieved by Best Available Techniques (BAT). When finally transposed into national legislation it will result in requirements for further emission reductions at our EU sites. | |
• | The European Commission (EC) Thematic Strategy on Air Pollution and the related work on revisions to the Gothenburg Protocol and National Emissions Ceiling Directive (NECD), will establish national ceilings for emissions of a variety of air pollutants in order to achieve EU-wide health and environmental improvement targets. The EC is also considering the use of a NOx and SO2 trading scheme as a tool to achieve emission reductions. This may result in requirements for further emission reductions at our EU sites. |
• | The EU Regulation on ozone depleting substances (ODS), which implements the Montreal Protocol on ODS was most recently revised in 2009. It requires BP to reduce the use of ODS and phase out use of certain ODS substances. BP continues to replace ODS in refrigerants and/or equipment, in the EU and elsewhere, in accordance with the Protocol and related legislation. Methyl bromide (an ODS) is a minor by-product in the production of purified terephthalic acid in our petrochemicals operations. The progressive phase-out of methyl bromide uses may result in future pressure to reduce our emissions of methyl bromide. | |
• | The EU Fuels Quality Directive affects our production and marketing of transport fuels. Revisions adopted in 2009 mandate reductions in the life cycle GHG emissions per unit of energy as described in Greenhouse gas regulation above, and tighter environmental fuel quality standards for petrol and diesel. | |
• | The EU Registration, Evaluation and Authorization of Chemicals (REACH) Regulation requires registration of chemical substances, manufactured in, or imported into, the EU in quantities greater than 1 tonne per annum per legal entity together with the submission of relevant hazard and risk data. Having complied with the 2008 pre-registration requirements, we have now completed full registration of all the substances that we were required to submit by the regulatory deadline of 1 December 2010. This first phase covered high tonnage/high hazard chemicals; chemicals with lower production/import tonnage materials will be subject to registration in the period 2013-2018. REACH affects our refining, petrochemicals, lubricants and other manufacturing or trading/import operations. |
• | International marine fuel regulations under International Maritime Organization (IMO) and International Convention for the Prevention of Pollution from Ships (MARPOL) regimes impose stricter sulphur emission restrictions on ships in EU ports and inland waterways and the North and Baltic seas beginning in 2010 and with a stricter global cap on marine sulphur emissions beginning in 2012. Further reductions are to be phased in thereafter. These restrictions require the use of compliant heavy fuel oil (HFO) or distillate, or the installation of abatement technologies on ships. These regulations will place additional costs on refineries producing marine fuel, including costs to dispose of sulphur, as well as increased CO2 emissions and energy costs for additional refining. | |
• | In the UK, significant health and safety legislation affecting BP includes the Health and Safety at Work Act and regulations and the Control of Major Accident Hazards Regulations. |
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• | In US waters, the OPA 90 imposes liability and spill prevention and planning requirements governing, amongst others, tankers, barges and offshore facilities. It also mandates a levy on imported and domestically produced oil to fund the oil spill response. Following the 2010 oil spill in the Gulf of Mexico, several members of the US Congress have introduced bills proposing to increase or eliminate the OPA 90 liability caps, some of them seek to impose a retroactive expansion of liability. At this time, none of the bills have been enacted into law and their fate is uncertain. Some states, including Alaska, Washington, Oregon and California, impose additional liability for oil spills. | |
• | Outside US territorial waters, BP Shipping tankers are subject to international liability, spill response and preparedness regulations under the UN’s International Maritime Organization, including the International Convention on Civil Liability for Oil Pollution, the MARPOL, the International Convention on Oil Pollution, Preparedness, Response and Co-operation and the International Convention on Civil Liability for Bunker Oil Pollution Damage. In April 2010, a new protocol, the Hazardous and Noxious Substance (HNS) Convention 2010 was adopted to address issues that have inhibited ratification of the International Convention on Liability and Compensation for Damage in Connection with the Carriage of Hazardous and Noxious Substances by Sea 1996 (the HNS Convention). This protocol will enter into force when (1) at least 12 states have agreed to be bound by it (four of the states must have at least 2 million gross tonnes of shipping) and (2) contributing parties in the consenting states have received at least 40 million tonnes of contributing cargoes in the preceding year. |
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Name | Initially elected or appointed | |||||||||||
C-H Svanberg | Chairman | Chairman since January 2010 | ||||||||||
Director since September 2009 | ||||||||||||
R W Dudley | Executive Director (Group Chief Executive) | Group chief executive since October 2010 | ||||||||||
Director since April 2009 | ||||||||||||
P M Anderson | Non-Executive Director | February 2010 | ||||||||||
F L Bowman | Non-Executive Director | November 2010 | ||||||||||
A Burgmans | Non-Executive Director | February 2004 | ||||||||||
C B Carroll | Non-Executive Director | June 2007 | ||||||||||
Sir William Castell | Non-Executive Director (Senior Independent Director) | July 2006 | ||||||||||
I C Conn | Executive Director (Chief Executive, Refining and Marketing) | July 2004 | ||||||||||
G David | Non-Executive Director | February 2008 | ||||||||||
I E L Davis | Non-Executive Director | April 2010 | ||||||||||
D J Flint | Non-Executive Director | January 2005 | ||||||||||
Dr B E Grote | Executive Director (Chief Financial Officer) | August 2000 | ||||||||||
Dr D S Julius | Non-Executive Director | November 2001 | ||||||||||
B R Nelson | Non-Executive Director | November 2010 | ||||||||||
F P Nhleko | Non-Executive Director | February 2011 | ||||||||||
M Bly | Executive Vice President (Safety and Operational Risk) | October 2010 | ||||||||||
R Bondy | Group General Counsel | May 2008 | ||||||||||
S Bott | Executive Vice President (Human Resources) | March 2005 | ||||||||||
Dr M C Daly | Executive Vice President (Exploration) | October 2010 | ||||||||||
R Fryar | Executive Vice President (Production) | October 2010 | ||||||||||
A Hopwood | Executive Vice President (Exploration and Production, Strategy and Integration) | October 2010 | ||||||||||
B Looney | Executive Vice President (Developments) | October 2010 | ||||||||||
H L McKay | Executive Vice President (Chairman and President of BP America Inc.) | June 2008 | ||||||||||
S Westwell | Executive Vice President (Strategy and Integration) | January 2008 | ||||||||||
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meetings of the remuneration committee
environment assurance committees
committees
committees
the audit committee
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the remuneration committee
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Change from | ||||||||||||
Current directors | 31 Dec 2010 | |||||||||||
At 31 Dec 2010 | At 1 Jan 2010 | to 24 Feb 2011 | ||||||||||
C-H Svanberg | 925,000 | – | – | |||||||||
R W Dudley | 280,799 | a | 276,846 | a | – | |||||||
A Burgmans | 10,156 | 10,156 | – | |||||||||
C B Carroll | 10,500 | a | 10,500 | a | – | |||||||
Sir William Castell | 82,500 | 82,500 | – | |||||||||
I C Conn | 339,637 | b | 293,216 | b | 77,916 | |||||||
G David | 159,000 | a | 39,000 | a | – | |||||||
D J Flint | 15,000 | 15,000 | – | |||||||||
Dr B E Grote | 1,372,643 | c | 1,291,643 | c | – | |||||||
Dr D S Julius | 15,000 | 15,000 | – | |||||||||
Directors leaving the board | At resignation/ | |||||||||||
retirement | At 1 Jan 2010 | |||||||||||
E B Davis, Jr | 77,238 | a d | 76,497 | a | ||||||||
Dr A B Hayward | 677,488 | e | 535,383 | |||||||||
A G Inglis | 309,823 | f g | 259,163f | |||||||||
Sir Ian Prosser | 16,301 | h | 16,301 | |||||||||
Change from | ||||||||||||
Directors joining the board | On | 31 Dec 2010 | ||||||||||
At 31 Dec 2010 | appointment | to 24 Feb 2011 | ||||||||||
P M Anderson | 6,000 | a | 6,000 | a i | – | |||||||
F L Bowman | 2,520 | a | 2,520 | a j | 4,800 | |||||||
I E L Davis | 10,000 | 10,000 | k | – | ||||||||
B R Nelson | – | – | l | – | ||||||||
F P Nhleko | – | – | m | – | ||||||||
a | Held as ADSs. |
b | Includes 48,024 shares held as ADSs at 31 December 2010 and 47,320 shares held as ADSs at 1 January 2010. |
c | Held as ADSs, except for 94 shares held as ordinary shares. |
d | On retirement at 15 April 2010. |
e | On resignation at 30 November 2010. |
f | Includes 34,962 shares held as ADSs. |
g | On resignation at 31 October 2010. |
h | On retirement at 15 April 2010. |
i | On appointment at 1 February 2010. |
j | On appointment at 8 November 2010. |
k | On appointment at 2 April 2010. |
l | On appointment at 8 November 2010. |
m | On appointment at 1 February 2011. |
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• | Active consideration of long-term strategy. | |
• | Monitoring executive management and the performance of the company. | |
• | Obtaining assurance that material risks to BP are identified and that systems of risk management and internal control are in place to manage such risks. | |
• | Board and executive management succession. |
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• | Simplification (how to focus the company’s operations across a wide geography). | |
• | How the company could manage risk more tightly. | |
• | How BP could focus on its core capabilities. | |
• | The opportunity to reset the company’s portfolio. |
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• | Regular reviews of the material risks to the group and their recognition in the company’s annual plan. |
• | Ensuring through the board’s system of delegation that its approach to risk is adopted by the group chief executive (GCE) and that decisions are taken in accordance with this system. |
• | Maintaining through the board and its committees clear oversight of the system of internal control and risk management established and maintained by the group chief executive. |
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Board | Audit | Remuneration | Gulf of Mexico | Nomination | Chairman’s | |||||||||||||||||||||||||||||||||||||||||||||||||||
committee | SEEAC | committee | committee | committee | committee | |||||||||||||||||||||||||||||||||||||||||||||||||||
a | b | a | b | a | b | a | b | a | b | a | b | a | b | |||||||||||||||||||||||||||||||||||||||||||
Carl-Henric Svanberg | 25 | 25 | 8 | c | 8 | 8 | c | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||
Sir William Castell | 25 | 24 | 9 | c | 9 | 9 | 6 | 8 | 8 | 8 | 8 | |||||||||||||||||||||||||||||||||||||||||||||
Paul Anderson | 23 | 21 | 8 | 8 | 9 | 9 | 7 | 7 | ||||||||||||||||||||||||||||||||||||||||||||||||
Frank ‘Skip’ Bowman | 2 | 2 | 1 | 1 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Antony Burgmans | 25 | 19 | 9 | 8 | 6 | 6 | 8 | 7 | ||||||||||||||||||||||||||||||||||||||||||||||||
Cynthia Carroll | 25 | 19 | 9 | 7 | 8 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||||
George David | 25 | 21 | 15 | 15 | 6 | 6 | 9 | 9 | 8 | 7 | ||||||||||||||||||||||||||||||||||||||||||||||
Erroll Davis, Jr | 4 | 3 | 5 | 5 | 3 | 2 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||
Ian Davis | 22 | 21 | 10 | 9 | 4 | 3 | 9 | c | 9 | 4 | 1 | 7 | 7 | |||||||||||||||||||||||||||||||||||||||||||
Douglas Flint | 25 | 25 | 15 | c | 14 | 6 | 6 | 8 | 7 | |||||||||||||||||||||||||||||||||||||||||||||||
DeAnne Julius | 25 | 23 | 6 | c | 6 | 8 | 8 | 8 | 8 | |||||||||||||||||||||||||||||||||||||||||||||||
Brendan Nelson | 2 | 2 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Sir Ian Prosser | 4 | 3 | 5 | 5 | 2 | 1 | 3 | 3 | 1 | 1 | ||||||||||||||||||||||||||||||||||||||||||||||
Executive directors: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Bob Dudley | �� | 25 | 25 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
lain Conn | 25 | 24 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Byron Grote | 25 | 25 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Tony Hayward | 24 | 23 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Andy Inglis | 23 | 23 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
a | Total number of meetings the director was eligible to attend. |
b | Total number of meetings the director did attend. |
c | Committee chairman. |
• | Sir lan Prosser and Erroll Davis, Jr retired from the board at the AGM in April 2010. | |
• | Two non-executive directors were appointed prior to the 2010 AGM: Paul Anderson in February 2010 and Ian Davis in April 2010. | |
• | Dr Tony Hayward stepped down as group chief executive on 1 October 2010 and left the board on 30 November 2010. | |
• | Andy Inglis stepped down as chief executive, Exploration and Production and as an executive director of the board at the end of October 2010. | |
• | Two further non-executive directors were appointed on 8 November 2010, Frank ‘Skip’ Bowman and Brendan Nelson. |
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• | Conduct additional site visits and participate in detailed briefings on significant operating activities of the company, including upstream businesses. | |
• | Review and, if necessary, revise the company’s board governance principles. | |
• | Clarify the board’s role in the crisis planning process. | |
• | Build on the strong working relationships within the board to continue and enhance good communication and cohesion. | |
• | Co-ordinate and clarify external and stakeholder communications. | |
• | Meet more often with senior managers below the level of executive directors as part of the board’s management succession oversight function. | |
• | Remain involved in strategic planning and related risk analyses. |
• | How global and regional trends in the areas of economics, politics and business might affect the development of BP’s business in the long term. | |
• | How the international business community and individual governments perceive BP’s plans and programmes of activities. |
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• | Monitoring the remediation work to mitigate the effects of the oil spill in the waters of the Gulf of Mexico and on the affected shorelines. | |
• | Overseeing a co-ordinated response programme with affected communities and states, and overseeing the approach for relationships with communities, states and the US government on issues relating to the incident. | |
• | Overseeing the legal and communication strategy for litigation involving the company or its subsidiaries arising from the incident or its aftermath, including government claims for fines and penalties. | |
• | Overseeing the strategy connected with claims, recognizing the independent nature of the connected Gulf Coast Claims Facility. |
• | Overseeing BP’s activities and responsibilities with respect to the Gulf Coast Claims Facility and the Deepwater Horizon Oil Spill Trust. | |
• | Overseeing the process for distribution of the goodwill fund for rig workers who have been impacted by the drilling moratorium imposed by the US government. | |
• | Overseeing expenditures and investments that fall outside the established claims administration process, or any redirection of resources outside the normal course of business. | |
• | Reviewing and monitoring management strategy and actions to restore the group’s reputation in the US and supporting management in any activities aimed at that goal. |
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Committee members
Committee members
• | Evaluating the performance and effectiveness of the group chief executive. | |
• | Reviewing the structure and effectiveness of the business organization of BP. | |
• | Reviewing the systems for senior executive development and determining the succession plan for the group chief executive, executive directors and other senior members of executive management. | |
• | Determining any other matter that is appropriate to be considered by all of the non-executive directors. | |
• | Opining on any matter referred to it by the chairman of any committee comprised solely of non-executive directors. |
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B.3.2 | Letters of appointment do not set out fixed time commitments since the schedule of board and committee meetings is subject to change according to the exigencies of the business. All directors are expected to demonstrate their commitment to the work of the board on an ongoing basis. This is reviewed by the nomination committee in recommending candidates for annual re-election. | |
D.2.2 | The remuneration of the chairman is not set by the remuneration committee. Instead, the chairman’s remuneration is reviewed by the remuneration committee, who makes a recommendation to the board as a whole for final approval, within the limits set by shareholders. |
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• | Establishing unique invoice-processing procedures and related controls to ensure appropriate accounting for costs. | |
• | Developing methodologies for estimating the various elements of accruals and provisions and instituting related controls to validate assumptions and ensure adequate management review. | |
• | Creating period-end financial reporting processes and related controls, including management and analytical review. | |
• | Hiring additional resources to process and account for the significant level of expenditure. |
and services
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• | The giving of security or indemnity with respect to any money lent or obligation taken by the director at the request or benefit of the company or any of its subsidiaries. | |
• | Any proposal in which the director is interested, concerning the underwriting of company securities or debentures or the giving of any security to a third party for a debt or obligation of the company or any of its subsidiaries. | |
• | Any proposal concerning any other company in which the director is interested, directly or indirectly (whether as an officer or shareholder or otherwise) provided that the director and persons connected with such director are not the holder or holders of 1% or more of the voting interest in the shares of such company. | |
• | Proposals concerning the modification of certain retirement benefits schemes under which the director may benefit and that have been approved by either the UK Board of Inland Revenue or by the shareholders. | |
• | Any proposal concerning the purchase or maintenance of any insurance policy under which the director may benefit. |
capital calls
• | A special reserve fund out of the balance of profits each year to make up any deficit of cumulative dividend on the BP preference shares. | |
• | A general reserve out of the balance of profits each year, which shall be applicable for any purpose to which the profits of the company may properly be applied. This may include capitalization of such sum, pursuant to an ordinary shareholders’ resolution, and distribution to shareholders as if it were distributed by way of a dividend on the ordinary shares or in paying up in full unissued ordinary shares for allotment and distribution as bonus shares. |
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remuneration report
112 | Part 1 Summary | |
114 | Part 2 Executive directors’ remuneration | |
120 | Part 3 Non-executive directors’ remuneration |
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Chairman, Remuneration Committee
2 March 2011
Annual remuneration | Long-term remuneration (EDIP) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Share element of EDIP | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2010 deferred | 2008-2010 plan | 2010-2012 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
annual bonus | (vested in Feb 2011) | plan | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual cash | Non-cash benefits and | Potential | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Salarya | performance bonus | other emoluments | Total | Potential | Actual | maximum | ||||||||||||||||||||||||||||||||||||||||||||||||||||
(thousand) | (thousand) | (thousand) | (thousand) | Mandatory | voluntary | shares | Value | performance | ||||||||||||||||||||||||||||||||||||||||||||||||||
2009 | 2010 | 2009 | 2010 | 2009 | 2010 | 2009 | 2010 | deferralb | deferralc | vested | (thousand) | sharesd | ||||||||||||||||||||||||||||||||||||||||||||||
R W Dudleye | $750 | $1,175 | $1,125 | 0 | $304 | f | $564 | f | $2,179 | $1,739 | 0 | 0 | 0 | 0 | 581,084 | |||||||||||||||||||||||||||||||||||||||||||
I C Conn | £690 | £690 | £1,104 | £104 | £46 | £34 | £1,840 | £828 | £104 | £104 | 0 | 0 | 656,813 | |||||||||||||||||||||||||||||||||||||||||||||
Dr B E Grotee | $1,380 | $1,380 | $2,070 | $207 | $8 | $10 | $3,458 | $1,597 | $207 | $207 | 0 | 0 | 801,894 | |||||||||||||||||||||||||||||||||||||||||||||
Directors leaving the board in 2010 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dr A B Haywardg | £1,045 | £958 | £2,090 | 0 | £23 | £95 | £3,158 | £1,053 | 0 | 0 | 0 | 0 | 303,948 | |||||||||||||||||||||||||||||||||||||||||||||
A G lnglish | £690 | £575 | £1,311 | 0 | £216 | f | £168 | f i | £2,217 | £743 | 0 | 0 | 0 | 0 | 218,938 | |||||||||||||||||||||||||||||||||||||||||||
Amounts shown are in the currency received by executive directors. Annual bonuses are shown in the year they were earned. | |
a | Figures show the total salary received during the calendar year. The last salary increase was in July 2008 other than on promotion of Mr Dudley to group chief executive. |
b | This amount will be converted to deferred shares at the three-day average share price following the full-year results announcement (£4.84, $46.68). Deferred shares will be matched one-for-one and both deferred and matched shares are subject to a safety and environmental hurdle over the three-year deferral period. |
c | Executive directors have the choice to have this portion either paid in cash or deferred voluntarily into shares on the same basis as the mandatory deferral. |
d | Maximum potential shares that could vest at the end of the three-year period depending on performance–reduced pro-rata for Dr Hayward and Mr Inglis to reflect actual service during performance period. |
e | Mr Dudley and Dr Grote hold shares in the form of ADSs. The above number reflects calculated equivalent in ordinary shares. |
f | This amount includes costs of London accommodation and any tax liability thereon that ceased at the end of 2010 following Mr Dudley’s appointment as group chief executive and Mr Inglis’s retirement from the board. |
g | Dr Hayward left the board on 30 November 2010. In addition to the above he was awarded compensation for loss of office equal to one year’s salary (£1,045,000) and a further £30,000 in respect of UK statutory compensation rights. |
h | Mr Inglis left the board on 31 October 2010. In addition to the above he was awarded compensation for loss of office equal to one year’s salary (£690,000) and a further £200,000 to cover various repatriation and relocation costs in accordance with his international assignment arrangements. |
i | In addition to this amount, under a tax equalization arrangement, BP discharged a US tax liability arising from the participation by Mr Inglis in the UK pension scheme amounting to $1,260,000. |
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Summary of future remuneration components | ||||
Salary | • | Mr Dudley’s salary remains at $1,700,000. Both Mr Conn and Dr Grote, who last received salary increases in July 2008, will have their salaries increased effective 1 April 2011. Mr Conn’s new salary will be £730,000 (from £690,000) and Dr Grote’s will be $1,442,000 (from $1,380,000). | ||
Bonus | • | On-target bonus of 150% of salary and maximum of 225% of salary based on performance relative to targets set at start of year relating to financial and operational metrics. | ||
Deferred bonus and match | • | One-third of actual bonus awarded as deferred shares with three-year deferral, with ability to voluntarily defer an additional one-third. | ||
• | All deferred shares matched one-for-one, both subject to an assessment of safety and environmental performance over the three-year period. | |||
Performance shares | • | Award of shares of up to 5.5 times salary for group chief executive and 4 times for other executive directors. | ||
• | Vesting after three years based on performance relative to other oil majors and strategic imperatives. | |||
• | Three-year retention period after vesting before release of shares. | |||
Pension | • | Final salary scheme appropriate to home country of executive. | ||
Remuneration of non-executive directors in 2010a | ||||||||
£ thousand | ||||||||
2009 | 2010 | |||||||
P Andersonb | – | 118 | ||||||
F Bowmanc | – | 17 | ||||||
A Burgmans | 93 | 90 | ||||||
C B Carroll | 90 | 90 | ||||||
Sir William Castell | 115 | 147 | ||||||
G Davidd | 118 | 135 | ||||||
I Davise | – | 69 | ||||||
D J Flint | 85 | 108 | ||||||
Dr D S Julius | 105 | 100 | ||||||
B Nelsonf | – | 17 | ||||||
C-H Svanbergg | 30 | 750 | ||||||
Directors leaving the board in 2010 | ||||||||
E B Davis, Jrh | 105 | 33 | ||||||
Sir Ian Prosseri | 165 | 52 | ||||||
a | This information has been subject to audit. |
b | Appointed on 1 February 2010. |
c | Appointed on 8 November 2010. |
d | Also received £28,000 for serving as a member of BP’s technology advisory council. |
e | Appointed on 2 April 2010. |
f | Appointed on 8 November 2010. |
g | Also received a relocation allowance of £90,000. |
h | Also received a superannuation gratuity of £21,000. |
i | Also received a superannuation gratuity of £43,945. |
BP Annual Report and Form 20-F 2010 113
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• | A substantial portion of executive remuneration should be linked to success in implementing the company’s business strategy to maximize long-term shareholder value. | |
• | The structure of pay should reflect the long-term nature of BP’s business and the significance of safety and environmental risks. | |
• | Performance conditions for variable pay should be set independently by the committee at the outset of each year and assessed by the committee both quantitatively and qualitatively at the end of each performance period. | |
• | Performance assessment should take into account material changes in the market environment (predominantly oil prices) and BP’s competitive position (primarily vis-à-vis other oil majors). | |
• | Salaries should be reviewed annually, in the context of the total quantum of pay, and taking into account both external market and internal company conditions. | |
• | Executives should develop and be required to hold a significant shareholding as this represents the best way to align their interests with those of shareholders. | |
• | The remuneration committee will actively seek to understand shareholder preferences and be as transparent as possible in explaining its remuneration policy and practices. |
• | Safety and operational risk metrics–including full implementation of the S&OR functional model. | |
• | Short-term performance–including key financial and operating metrics. | |
• | Long-term performance–including progress on key projects and reserves replacement. | |
• | People–including a new performance and reward framework. |
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BP Annual Report and Form 20-F 2010 115
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Pensionsa (information subject to audit) | |||||||||||||||||||||||
thousand | |||||||||||||||||||||||
Additional pension | |||||||||||||||||||||||
Accrued pension | earned during the | Transfer value of | Transfer value of | Amount of B-A less | |||||||||||||||||||
Service at | entitlement | year ended | accrued benefitb | accrued benefitb | contributions made by | ||||||||||||||||||
31 Dec 2010 | at 31 Dec 2010 | 31 Dec 2010a | at 31 Dec 2009 (A) | at 31 Dec 2010 (B) | the director in 2010 | ||||||||||||||||||
R W Dudley (US) | 31 years | $704 | $298 | $4,353 | $10,336 | $5,983 | |||||||||||||||||
I C Conn (UK) | 25 years | £287 | £12 | £4,508 | £5,373 | £865 | |||||||||||||||||
Dr B E Grote (US) | 31 years | $1,281 | $270 | $12,047 | $16,501 | $4,454 | |||||||||||||||||
Directors leaving the board in 2010 | |||||||||||||||||||||||
Dr A B Hayward (UK)c | 29 years | £605 | £21 | £10,840 | £13,677 | £2,837 | |||||||||||||||||
A G Inglis (UK)c | 30 years | £349 | £12 | £6,000 | £7,633 | £1,633 | |||||||||||||||||
a | Additional pension earned during the year includes an inflation increase of 2.4% for UK directors and 1.5% for US directors. |
b | Transfer values have been calculated in accordance with guidance issued by the actuarial profession. |
c | Figures are calculated to end of 2010. |
116 BP Annual Report and Form 20-F 2010
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Performance share element of EDIP (information subject to audit) | ||||||||||||||||||||||||||||||||||||||
Share element interests | Interests vested in 2010 and 2011 | |||||||||||||||||||||||||||||||||||||
Market price | Potential maximum performance sharesa | |||||||||||||||||||||||||||||||||||||
of each share | ||||||||||||||||||||||||||||||||||||||
Date of | at date of award | Number of | Market price | |||||||||||||||||||||||||||||||||||
award of | of performance | ordinary | of each share | |||||||||||||||||||||||||||||||||||
Performance | performance | shares | At 1 Jan | Awarded | At 31 Dec | shares | Vesting | at vesting | ||||||||||||||||||||||||||||||
period | shares | £ | 2010 | 2010 | 2010 | vestedb | date | £ | ||||||||||||||||||||||||||||||
R W Dudleyc | 2009-2011 | 06 May 2009 | 5.00 | 539,634 | – | 539,634 | – | – | – | |||||||||||||||||||||||||||||
2010-2012 | 09 Feb 2010 | 5.64 | – | 581,082 | 581,082 | – | – | – | ||||||||||||||||||||||||||||||
I C Conn | 2007-2009 | 06 Mar 2007 | 5.12 | 456,748 | – | – | 95,697 | 3 Feb 2010 | 5.76 | |||||||||||||||||||||||||||||
2008-2010 | 13 Feb 2008 | 5.61 | 578,376 | – | 578,376 | 0 | – | – | ||||||||||||||||||||||||||||||
2008-2011 | d | 13 Feb 2008 | 5.61 | 133,452 | – | 133,452 | 155,695 | 22 Feb 2011 | 4.91 | |||||||||||||||||||||||||||||
2008-2013 | d | 13 Feb 2008 | 5.61 | 133,452 | – | 133,452 | – | – | – | |||||||||||||||||||||||||||||
2009-2011 | 11 Feb 2009 | 5.10 | 780,816 | – | 780,816 | – | – | – | ||||||||||||||||||||||||||||||
2010-2012 | 09 Feb 2010 | 5.64 | – | 656,813 | 656,813 | – | – | – | ||||||||||||||||||||||||||||||
Dr B E Grotec | 2007-2009 | 06 Mar 2007 | 5.12 | 491,640 | – | – | 101,502 | 3 Feb 2010 | 5.76 | |||||||||||||||||||||||||||||
2008-2010 | 13 Feb 2008 | 5.61 | 581,748 | – | 581,748 | 0 | – | – | ||||||||||||||||||||||||||||||
2009-2011 | 11 Feb 2009 | 5.10 | 992,928 | – | 992,928 | – | – | – | ||||||||||||||||||||||||||||||
2010-2012 | 09 Feb 2010 | 5.64 | – | 801,894 | 801,894 | – | – | – | ||||||||||||||||||||||||||||||
Directors leaving the board in 2010 | ||||||||||||||||||||||||||||||||||||||
Dr A B Hayward | 2007-2009 | 06 Mar 2007 | 5.12 | 706,311 | – | – | 147,985 | 3 Feb 2010 | 5.76 | |||||||||||||||||||||||||||||
2008-2010 | 13 Feb 2008 | 5.61 | 845,319 | – | 821,838 | e | 0 | – | – | |||||||||||||||||||||||||||||
2009-2011 | 11 Feb 2009 | 5.10 | 1,182,540 | – | 755,512 | e | – | – | – | |||||||||||||||||||||||||||||
2010-2012 | 09 Feb 2010 | 5.64 | – | 994,739 | 303,948 | e | – | – | – | |||||||||||||||||||||||||||||
A G Inglis | 2007-2009 | 06 Mar 2007 | 5.12 | 400,243 | – | – | 83,859 | 3 Feb 2010 | 5.76 | |||||||||||||||||||||||||||||
2008-2010 | 13 Feb 2008 | 5.61 | 578,376 | – | 578,376 | 0 | – | – | ||||||||||||||||||||||||||||||
2008-2011 | d | 13 Feb 2008 | 5.61 | 133,452 | – | – | 0 | – | – | |||||||||||||||||||||||||||||
2008-2013 | d | 13 Feb 2008 | 5.61 | 133,452 | – | – | 0 | – | – | |||||||||||||||||||||||||||||
2009-2011 | 11 Feb 2009 | 5.10 | 780,816 | – | 520,544 | e | – | – | – | |||||||||||||||||||||||||||||
2010-2012 | 09 Feb 2010 | 5.64 | – | 656,813 | 218,938 | e | – | – | – | |||||||||||||||||||||||||||||
a | BP’s performance is measured against the oil sector. For awards under the 2007-2009 and 2008-2010 plans, the performance condition is TSR measured against ExxonMobil, Shell, Total and Chevron. For awards under the 2009-2011 plan, performance conditions are measured 50% on TSR against ExxonMobil, Shell, Total, ConocoPhillips and Chevron and 50% on a balanced scorecard of underlying performance. For the awards under the 2010-2012 plan, performance conditions are measured one third on TSR against ExxonMobil, Shell, Total, ConocoPhillips and Chevron and two thirds on a balanced scorecard of underlying performance. Each performance period ends on 31 December of the third year. |
b | Represents awards of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes re-invested dividends on the shares awarded. |
c | Dr Grote and Mr Dudley receive awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. |
d | Restricted award under share element of EDIP. As reported in the 2007 directors’ remuneration report in February 2008, the committee awarded both Mr Inglis and Mr Conn restricted shares, as set out above. These one-off awards will vest on the third and fifth anniversary of the award, dependent on the remuneration committee being satisfied as to their personal performance at the date of vesting. Any unvested tranche will lapse in the event of cessation of employment with the company. Mr Inglis left the company on 31 December 2010 and accordingly his restricted awards lapsed. |
e | Potential maximum of performance shares has been reduced to reflect actual service during performance period on a pro-rated basis. |
BP Annual Report and Form 20-F 2010 117
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Share options (information subject to audit) | ||||||||||||||||||||||||||||||||||||
Market price | Date from | |||||||||||||||||||||||||||||||||||
Option | At 31 Dec | Option | at date of | which first | ||||||||||||||||||||||||||||||||
type | At 1 Jan 2010 | Granted | Exercised | 2010 | price | exercise | exercisable | Expiry date | ||||||||||||||||||||||||||||
R W Dudleya | BP SOP | 1,800 | – | 1,800 | – | $48.94 | $58.15 | b | 28 Mar 2003 | 27 Mar 2010 | ||||||||||||||||||||||||||
BP SOP | 6,460 | – | – | 6,460 | $49.65 | 23 Feb 2004 | 22 Feb 2011 | |||||||||||||||||||||||||||||
BP SOP | 1,073 | – | – | 1,073 | $43.82 | 17 Dec 2004 | 16 Dec 2011 | |||||||||||||||||||||||||||||
BP SOP | 17,835 | – | – | 17,835 | $48.99 | 18 Feb 2005 | 17 Feb 2012 | |||||||||||||||||||||||||||||
BP SOP | 17,835 | – | – | 17,835 | $38.10 | 17 Feb 2006 | 16 Feb 2013 | |||||||||||||||||||||||||||||
I C Conn | SAYE | 1,498 | – | – | 1,498 | £4.41 | £4.93 | d | 01 Sep 2010 | 28 Feb 2011 | ||||||||||||||||||||||||||
SAYE | 617 | – | – | 617 | £4.87 | 01 Sep 2011 | 29 Feb 2012 | |||||||||||||||||||||||||||||
SAYE | 605 | – | – | 605 | £4.20 | 01 Sep 2012 | 28 Feb 2013 | |||||||||||||||||||||||||||||
EXEC | 72,250 | – | – | 72,250 | £5.67 | 23 Feb 2004 | 23 Feb 2011 | |||||||||||||||||||||||||||||
EXEC | 130,000 | – | – | 130,000 | £5.72 | 18 Feb 2005 | 18 Feb 2012 | |||||||||||||||||||||||||||||
Dr B E Grotea | BPA | 12,600 | – | 12,600 | – | $48.94 | $58.40-$58.42 | 28 Mar 2001 | 27 Mar 2010 | |||||||||||||||||||||||||||
EDIP | 13,173 | – | 13,173 | – | $37.76 | $54.36 | 17 Feb 2004 | 17 Feb 2010 | ||||||||||||||||||||||||||||
EDIP | 58,333 | – | – | 58,333 | $48.53 | 25 Feb 2005 | 25 Feb 2011 | |||||||||||||||||||||||||||||
Directors leaving the board in 2010 | ||||||||||||||||||||||||||||||||||||
Dr A B Hayward | SAYE | 3,220 | – | – | 3,220 | £5.00 | 01 Sep 2011 | 29 Feb 2012 | ||||||||||||||||||||||||||||
EXEC | 34,000 | – | – | –c | £5.99 | n/a | 15 May 2003 | 15 May 2010 | ||||||||||||||||||||||||||||
EXEC | 77,400 | – | – | 77,400 | £5.67 | 23 Feb 2004 | 23 Feb 2011 | |||||||||||||||||||||||||||||
EXEC | 160,000 | – | – | 160,000 | £5.72 | 18 Feb 2005 | 18 Feb 2012 | |||||||||||||||||||||||||||||
EDIP | 275,000 | – | 275,000 | – | £4.22 | £6.31 | b | 25 Feb 2005 | 25 Feb 2011 | |||||||||||||||||||||||||||
A G Inglis | EXEC | 72,250 | – | – | 72,250 | £5.67 | 23 Feb 2004 | 22 Feb 2011 | ||||||||||||||||||||||||||||
EXEC | 119,000 | – | – | 119,000 | £5.72 | 18 Feb 2005 | 17 Feb 2012 | |||||||||||||||||||||||||||||
EXEC | 119,000 | – | 119,000 | – | £3.88 | £6.31 | 17 Feb 2006 | 16 Feb 2013 | ||||||||||||||||||||||||||||
EXEC | 100,500 | – | 100,500 | – | £4.22 | £6.31 | 25 Feb 2007 | 24 Feb 2014 | ||||||||||||||||||||||||||||
The closing market prices of an ordinary share and of an ADS on 31 December 2010 were £4.66 and $44.17 respectively. | |
During 2010, the highest market prices were £6.55 and $62.32 respectively and the lowest market prices were £3.03 and $27.02 respectively. | |
BPA = BP Amoco share option plan, which applied to US executive directors prior to the adoption of the EDIP. | |
EDIP = Executive Directors’ Incentive Plan adopted by shareholders in 2010 as described on page 114. | |
EXEC = Executive Share Option Scheme. These options were granted to the relevant individuals prior to their appointments as directors and are not subject to performance conditions. | |
SAYE = Save As You Earn employee share scheme. | |
BP SOP = BP Share Option Plan. These options were granted to Mr Dudley prior to his appointment as a director and are not subject to performance conditions. | |
a | Numbers shown are ADSs under option. One ADS is equivalent to six ordinary shares. |
b | Closing market price for information. Shares were retained after exercise of options. |
c | Options lapsed. |
d | Options exercised on 22 February 2011. Closing market price for information only, as shares were retained after exercise of options. |
Executive director | |||||||||||
Additional position | |||||||||||
Appointee | held at appointee | Total | |||||||||
company | company | fees | |||||||||
I C Conn | Rolls-Royce | Senior | £65,000 | ||||||||
Independent | |||||||||||
Director | |||||||||||
Dr B E Grote | Unilever | Audit committee | Unilever PLC | ||||||||
member | £33,000 | ||||||||||
Unilever NV | |||||||||||
€47,500 | |||||||||||
A G Inglisa | BAE | Chair of | £49,280 | ||||||||
Systems | Corporate | ||||||||||
Responsibility | |||||||||||
Committee | |||||||||||
a | Member of BAE Systems Board until 9 July 2010. |
118 BP Annual Report and Form 20-F 2010
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Director | ||||||||
Contract | Salary as at | |||||||
date | 31 Dec 2010 | |||||||
R W Dudley | 6 Apr 2009 | $1,700,000 | ||||||
I C Conn | 22 Jul 2004 | £690,000 | ||||||
Dr B E Grote | 7 Aug 2000 | $1,380,000 | ||||||
• | To determine, on behalf of the board, the terms of engagement and remuneration of the group chief executive and the executive directors and to report on these to the shareholders. | |
• | To determine, on behalf of the board, matters of policy over which the company has authority regarding the establishment or operation of the company’s pension scheme of which the executive directors are members. | |
• | To nominate, on behalf of the board, any trustees (or directors of corporate trustees) of the scheme. | |
• | To review and approve the policies and actions being applied by the group chief executive in remunerating senior executives other than executive directors to ensure alignment and proportionality. | |
• | To recommend to the board the quantum and structure of remuneration for the chairman. |
BP Annual Report and Form 20-F 2010 119
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• | Remuneration should be sufficient to attract, motivate and retain world-class non-executive talent. | |
• | Remuneration of non-executive directors is proposed by the chairman and agreed by the board and should be proportional to their contribution towards the interests of the company. | |
• | Remuneration practice should be consistent with recognized best practice standards for non-executive directors’ remuneration. | |
• | Remuneration should be in the form of cash fees, payable monthly. | |
• | Non-executive directors should not receive share options from the company. | |
• | Non-executive directors are encouraged to establish a holding in BP shares of the equivalent value of one year’s base fee. |
£ thousand | ||||
Fee level | ||||
Chairmana | 750 | |||
Senior independent directorb | 120 | |||
Board member | 75 | |||
Audit, Gulf of Mexico and safety, ethics and environment assurance committees (SEEAC) chairmanship feesc | 30 | |||
Remuneration committee chairmanship feec | 20 | |||
Committee membership feed | 5 | |||
Transatlantic attendance allowance | 5 | |||
a | The chairman remains ineligible for committee chairmanship and membership fees or transatlantic attendance allowance. He has the use of a fully maintained office for company business, a chauffeured car and security advice in London. He receives secretarial support as appropriate to his needs in Sweden and a relocation allowance for expenses incurred in relocating to London. |
b | The senior independent director is still eligible for committee chairmanship fees and transatlantic attendance allowance plus any committee membership fees. |
c | Committee chairmen do not receive an additional membership fee for the committee they chair. |
d | For members of the SEEAC, the audit, the Gulf of Mexico and the remuneration committees. |
Remuneration of non-executive directors in 2010a | ||||||||
£ thousand | ||||||||
2009 | 2010 | |||||||
P Andersonb | – | 118 | ||||||
F Bowmanc | – | 17 | ||||||
A Burgmans | 93 | 90 | ||||||
C B Carroll | 90 | 90 | ||||||
Sir William Castell | 115 | 147 | ||||||
G Davidd | 118 | 135 | ||||||
I Davise | – | 69 | ||||||
D J Flint | 85 | 108 | ||||||
Dr D S Julius | 105 | 100 | ||||||
B Nelsonf | – | 17 | ||||||
C-H Svanbergg | 30 | 750 | ||||||
Directors leaving the board in 2010 | ||||||||
E B Davis, Jrh | 105 | 33 | ||||||
Sir Ian Prosseri | 165 | 52 | ||||||
a | This information has been subject to audit. |
b | Appointed on 1 February 2010. |
c | Appointed on 8 November 2010. |
d | Also received £28,000 for serving as a member of BP’s technology advisory council. |
e | Appointed on 2 April 2010. |
f | Appointed on 8 November 2010. |
g | Also received a relocation allowance of £90,000. |
h | Also received a superannuation gratuity of £21,000. |
i | Also received a superannuation gratuity of £43,945. |
• | Non-executive directors appointed to the board after 1 July 2002 would not be eligible for consideration for such a payment. | |
• | While non-executive directors in service at 1 July 2002 would remain eligible for consideration for a payment, service after that date would not be taken into account by the board in considering the amount of any such payment. |
120 BP Annual Report and Form 20-F 2010
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Date on | ||||||||
Interest in BP ADSs | which director | |||||||
at 1 Jan 2010 | a | reaches age 70 | b | |||||
Director leaving the board in 2010 | ||||||||
E B Davis, Jrc | 4,490 | 5 August 2014 | ||||||
a | No awards were granted and no awards lapsed during the year. The awards were granted over Amoco stock prior to the merger but their notional weighted average market value at the date of grant (applying the subsequent merger ratio of 0.66167 of a BP ADS for every Amoco share) was $27.87 per BP ADS. |
b | For the purposes of the regulations, the date on which the director retires from the board at or after the age of 70 is the end of the qualifying period. If the director retires prior to this date, the board may waive the restrictions. |
c | Erroll Davis, Jr retired from the board on 15 April 2010. He had received awards of Amoco shares under the plan between 23 April 1991 and 28 April 1998 prior to the merger. These interests had been converted into BP ADSs at the time of the merger. In accordance with the terms of the plan, the board exercised its discretion over this award and the shares vested on 21 May 2010 (when the BP ADS market price was $43.86) without payment by him. |
BP Annual Report and Form 20-F 2010 121
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122 BP Annual Report and Form 20-F 2010
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for shareholders
124 | Critical accounting policies | |
127 | Property, plants and equipment | |
127 | Share ownership | |
128 | Major shareholders and related party transactions | |
129 | Dividends | |
130 | Legal proceedings | |
133 | Relationships with suppliers and contractors | |
134 | Share prices and listings | |
135 | Material contracts | |
135 | Exchange controls | |
135 | Taxation | |
137 | Documents on display | |
137 | Purchases of equity securities by the issuer and affiliated purchasers | |
138 | Fees and charges payable by a holder of ADSs | |
138 | Fees and payments made by the Depositary to the issuer | |
139 | Called-up share capital |
139 | Administration | |
139 | Annual general meeting | |
140 | Exhibits |
BP BP Annual Report and Form 20-F 2010 123
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• | Cost of producing wells – proved developed reserves. | |
• | Licence and property acquisition, common facilities and future decommissioning costs – total proved reserves. |
124 BP Annual Report and Form 20-F 2010
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BP Annual Report and Form 20-F 2010 125
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126 BP Annual Report and Form 20-F 2010
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Ordinary | Performance | Restricted | ||||||||||
Director | shares | shares | a | shares | b | |||||||
C-H Svanberg | 925,000 | – | – | |||||||||
R W Dudley | 280,799 | c | 1,120,716 | c | – | |||||||
P M Anderson | 6,000 | c | – | – | ||||||||
F L Bowman | 7,320 | c | – | – | ||||||||
A Burgmans | 10,156 | – | – | |||||||||
C B Carroll | 10,500 | c | – | – | ||||||||
Sir William Castell | 82,500 | – | – | |||||||||
I C Conn | 417,553 | d | 2,016,005 | 133,452 | ||||||||
G David | 159,000 | c | – | – | ||||||||
I E L Davis | 10,000 | – | – | |||||||||
D J Flint | 15,000 | – | – | |||||||||
Dr B E Grote | 1,372,643 | e | 2,376,570 | c | – | |||||||
Dr D S Julius | 15,000 | – | – | |||||||||
B R Nelson | – | – | – | |||||||||
F P Nhleko | – | – | – | |||||||||
a | Performance shares awarded under the BP Executive Directors’ Incentive Plan. These figures represent the maximum possible vesting levels. The actual number of shares/ADSs that vest will depend on the extent to which performance conditions have been satisfied over a three-year period. |
b | Restricted share award under the BP Executive Directors’ Incentive Plan. These shares will vest in 2013, subject to the director’s continued service and satisfactory performance. |
c | Held as ADSs. |
d | Includes 48,024 shares held as ADSs. |
e | Held as ADSs, except for 94 shares held as ordinary shares. |
Director | Options | |||
R W Dudleya | 259,218 | |||
I C Conn | 203,472 | |||
Dr B E Grotea b | 349,998 | |||
a | Held as ADSs. |
b | These options lapsed on 25 February 2011. |
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Options thousands | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Employee share options granted during the yeara | 10,420 | 9,680 | 8,063 | |||||||||
a | For the options outstanding at 31 December 2010, the exercise price ranges and weighted average remaining contractual lives are shown in Financial statements – Note 41 on page 214. |
Expiry dates | Exercise price | |||||||
Options outstanding (shares) | of options | per share | ||||||
261,526,262 | 2011-2016 | $ | 6.09-$11.92 | |||||
31 December 2010
Number of | Percentage of | Percentage of | ||||||||||
ordinary | total ordinary | total ordinary | ||||||||||
Range of holdings | shareholders | shareholders | share capital | |||||||||
1-200 | 59,514 | 18.86 | 0.02 | |||||||||
201-1,000 | 118,266 | 37.48 | 0.30 | |||||||||
1,001-10,000 | 124,516 | 39.46 | 1.80 | |||||||||
10,001-100,000 | 11,488 | 3.64 | 1.12 | |||||||||
100,001-1,000,000 | 960 | 0.30 | 1.72 | |||||||||
Over 1,000,000a | 809 | 0.26 | 95.04 | |||||||||
Totals | 315,553 | 100.00 | 100.00 | |||||||||
a | Includes JPMorgan Chase Bank holding 25.88% of the total ordinary issued share capital (excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which is shown in the table below. |
31 December 2010a
Number of | Percentage of total ADS | Percentage of | ||||||||||
Range of holdings | ADS holders | holders | total ADSs | |||||||||
1-200 | 64,433 | 55.73 | 0.46 | |||||||||
201-1,000 | 32,209 | 27.85 | 1.89 | |||||||||
1,001-10,000 | 17,933 | 15.51 | 5.85 | |||||||||
10,001-100,000 | 1,051 | 0.91 | 2.18 | |||||||||
100,001-1,000,000 | 11 | 0.00 | 0.21 | |||||||||
Over 1,000,000b | 1 | 0.00 | 89.41 | |||||||||
Totals | 115,638 | 100.00 | 100.00 | |||||||||
a | One ADS represents six 25 cent ordinary shares. |
b | One holder of ADSs represents some 795,382 underlying shareholders. |
128 BP Annual Report and Form 20-F 2010
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March | June | September | December | Total | ||||||||||||||||||||
Dividends per American depositary share | ||||||||||||||||||||||||
2006 | UK pence | 31.7 | 31.5 | 31.9 | 31.4 | 126.5 | ||||||||||||||||||
US cents | 56.25 | 56.25 | 58.95 | 58.95 | 230.4 | |||||||||||||||||||
Canadian cents | 64.5 | 64.1 | 67.4 | 66.5 | 262.5 | |||||||||||||||||||
2007 | UK pence | 31.5 | 30.9 | 31.7 | 31.8 | 125.9 | ||||||||||||||||||
US cents | 61.95 | 61.95 | 64.95 | 64.95 | 253.8 | |||||||||||||||||||
Canadian cents | 73.3 | 69.5 | 67.8 | 63.6 | 274.2 | |||||||||||||||||||
2008 | UK pence | 40.9 | 41.0 | 42.2 | 52.2 | 176.3 | ||||||||||||||||||
US cents | 81.15 | 81.15 | 84.0 | 84.0 | 330.3 | |||||||||||||||||||
Canadian cents | 80.8 | 82.5 | 85.8 | 108.6 | 357.7 | |||||||||||||||||||
2009 | UK pence | 58.91 | 57.50 | 51.02 | 51.07 | 218.5 | ||||||||||||||||||
US cents | 84 | 84 | 84 | 84 | 336 | |||||||||||||||||||
Canadian cents | a | n/a | n/a | n/a | n/a | n/a | ||||||||||||||||||
2010 | UK pence | 52.07 | – | – | – | 52.07 | ||||||||||||||||||
US cents | 84 | – | – | – | 84 | |||||||||||||||||||
a | BP shares were de-listed from the Toronto Stock Exchange on 15 August 2008 and the last dividend payment in Canadian dollars was made on 8 December 2008. |
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Gulf of Mexico oil spill
130 BP Annual Report and Form 20-F 2010
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and contractors
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Pence | Dollars | |||||||||||||||
American | ||||||||||||||||
depositary | ||||||||||||||||
Ordinary shares | Shares | a | ||||||||||||||
High | Low | High | Low | |||||||||||||
Year ended 31 December | ||||||||||||||||
2006 | 723.00 | 558.50 | 76.85 | 63.52 | ||||||||||||
2007 | 640.00 | 504.50 | 79.77 | 58.62 | ||||||||||||
2008 | 657.25 | 370.00 | 77.69 | 37.57 | ||||||||||||
2009 | 613.40 | 400.00 | 60.00 | 33.71 | ||||||||||||
2010 | 658.20 | 296.00 | 62.38 | 26.75 | ||||||||||||
Year ended 31 December | ||||||||||||||||
2009: First quarter | 566.50 | 400.00 | 49.83 | 33.71 | ||||||||||||
Second quarter | 543.75 | 426.50 | 53.24 | 38.50 | ||||||||||||
Third quarter | 568.50 | 459.25 | 55.61 | 44.63 | ||||||||||||
Fourth quarter | 613.40 | 528.00 | 60.00 | 50.60 | ||||||||||||
2010: First quarter | 640.10 | 555.00 | 62.38 | 52.00 | ||||||||||||
Second quarter | 658.20 | 296.00 | 60.98 | 26.75 | ||||||||||||
Third quarter | 438.25 | 312.65 | 41.59 | 28.79 | ||||||||||||
Fourth quarter | 479.00 | 418.25 | 44.83 | 39.58 | ||||||||||||
2011: First quarter (to 18 February) | 514.90 | 471.65 | 49.50 | 44.83 | ||||||||||||
Month of | ||||||||||||||||
September 2010 | 436.15 | 375.75 | 41.30 | 35.67 | ||||||||||||
October 2010 | 443.50 | 418.25 | 42.08 | 39.58 | ||||||||||||
November 2010 | 459.20 | 420.70 | 44.37 | 39.76 | ||||||||||||
December 2010 | 479.00 | 426.15 | 44.83 | 40.15 | ||||||||||||
January 2011 | 514.90 | 479.00 | 49.50 | 44.83 | ||||||||||||
February 2011 (to 18 February) | 495.60 | 471.65 | 48.28 | 45.46 | ||||||||||||
a | An ADS is equivalent to six 25-cent ordinary shares. |
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Maximum | ||||||||||||||||
Total number | number of | |||||||||||||||
of shares | shares that | |||||||||||||||
purchased as | may yet | |||||||||||||||
Total number of | Average | part of publicly | be purchased | |||||||||||||
shares | paid per share | announced | under the | |||||||||||||
purchased | $ | programmes | programme | a | ||||||||||||
2010 | ||||||||||||||||
January | 51 | 10.36 | ||||||||||||||
February | 144,523 | 11.41 | ||||||||||||||
March | 626 | 8.41 | ||||||||||||||
April | 5,001,610 | 11.41 | ||||||||||||||
May | 1,941,069 | 11.41 | ||||||||||||||
June | 181,384 | 11.41 | ||||||||||||||
July | 4,550,658 | 6.25 | ||||||||||||||
August | 849 | 6.82 | ||||||||||||||
September | 817,606 | 6.32 | ||||||||||||||
October | nil | |||||||||||||||
November | 280,559 | 7.20 | ||||||||||||||
December | 38 | 7.18 | ||||||||||||||
2011 | ||||||||||||||||
January | 338,506 | 7.86 | ||||||||||||||
February (to 18 February) | 311,362 | 7.60 | ||||||||||||||
a | No shares were repurchased pursuant to a publicly announced plan. Transactions represent the purchase of ordinary shares by ESOP trusts to satisfy future requirements of employee share schemes. |
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Type of service | Depositary actions | Fee | ||
Depositing or substituting the underlying shares | Issuance of ADSs against the deposit of shares, including deposits and issuances in respect of: | $5.00 per 100 ADSs (or portion thereof) evidenced by the new ADSs delivered | ||
• Share distributions, stock splits, rights, merger | ||||
• Exchange of securities or other transactions or event or other distribution affecting the ADSs or deposited securities | ||||
Selling or exercising rights | Distribution or sale of securities, the fee being in an amount equal to the fee for the execution and delivery of ADSs that would have been charged as a result of the deposit of such securities | $5.00 per 100 ADSs (or portion thereof) | ||
Withdrawing an underlying share | Acceptance of ADSs surrendered for withdrawal of deposited securities | $5.00 for each 100 ADSs (or portion thereof) evidenced by the ADSs surrendered | ||
Expenses of the Depositary | Expenses incurred on behalf of holders in connection with: | Expenses payable at the sole discretion of the Depositary by billing holders or by deducting charges from one or more cash dividends or other cash distributions | ||
• Stock transfer or other taxes and governmental charges | ||||
• Cable, telex, electronic and facsimile transmission/delivery | ||||
• Transfer or registration fees, if applicable, for the registration of transfers of underlying shares | ||||
• Expenses of the Depositary in connection with the conversion of foreign currency into US dollars (which are paid out of such foreign currency) | ||||
Category of expense reimbursed | Amount reimbursed for the year | |||
to the company | ended 31 December 2010 | |||
NYSE listing fees | $500,000 | |||
Total | $500,000 | |||
Category of expense waived or paid | Amount reimbursed for the year | |||
directly to third parties | ended 31 December 2010 | |||
Service fees and out of pocket expenses waiveda | $2,802,482 | |||
Broker reimbursementsb | $1,150,475 | |||
Other third-party mailing costsc | $136,542 | |||
Legal adviced | $26,391 | |||
Other third-party expenses paid directly | $31,364 | |||
Total | $4,147,254 | |||
a | Includes fees in relation to transfer agent costs and costs of the of BP Direct Access Plan operated by JPMorgan Chase. |
b | Broker reimbursements are fees payable to Broadridge for the distribution of hard copy material to ADR beneficial holders in the Depositary Trust Company. Corporate materials include information related to shareholders’ meetings and related voting instructions. These fees are SEC approved. |
c | Payment of fees to Precision IR and CIBC Mellon for distribution of hard copy materials to ADR beneficial holders, proxy solicitation and investor support. |
d | Reimbursement for legal advice from Ziegler, Ziegler & Associates. |
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Exhibit 1. | Memorandum and Articles of Association of BP p.l.c.† | |
Exhibit 4.1 | The BP Executive Directors’ Incentive Plan† | |
Exhibit 4.2 | Amended Director’s Service Contract and Secondment Agreement for R W Dudley† | |
Exhibit 4.3 | Amended Director’s Service Contract and Secondment Agreement for B E Grote† | |
Exhibit 7. | Computation of Ratio of Earnings to Fixed Charges (Unaudited)† | |
Exhibit 8. | Subsidiaries (included as Note 46 to the Financial Statements) | |
Exhibit 10.1 | Trust Agreement dated as of 6 August 2010 among BP Exploration & Production Inc., John S Martin, Jr and Kent D Syverud, as individual trustees, and Citigroup Trust-Delaware, N.A., as corporate trustee, as amended by an Addendum, dated 6 August 2010† | |
Exhibit 10.2 | Pledge and Collateral Agreement dated as of 30 September 2010 by BP Exploration & Production Inc. in favor of John S Martin, Jr and Kent D Syverud, as individual trustees† | |
Exhibit 11. | Code of Ethics*† | |
Exhibit 12. | Rule 13a – 14(a) Certifications† | |
Exhibit 13. | Rule 13a – 14(b) Certifications#† | |
Exhibit 99. | Deepwater Horizon Accident Investigation Report** |
* | Incorporated by reference to the company’s Annual Report on Form 20-F for the year ended 31 December 2009. |
** | Incorporated by reference to the Company’s Report on Form 6-K filed on 24 September 2010 (File No. 001-06262). |
# | Furnished only. |
† | Included only in the annual report filed in the Securities and Exchange Commission EDGAR system. |
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34 | Derivative financial instruments | 192 | ||||||
35 | Finance debt | 197 | ||||||
36 | Capital disclosures and analysis of changes in net debt | 198 | ||||||
37 | Provisions | 199 | ||||||
38 | Pensions and other post-retirement benefits | 202 | ||||||
39 | Called-up share capital | 209 | ||||||
40 | Capital and reserves | 210 | ||||||
41 | Share-based payments | 214 | ||||||
42 | Employee costs and numbers | 216 | ||||||
43 | Remuneration of directors and senior management | 217 | ||||||
44 | Contingent liabilities and contingent assets | 218 | ||||||
45 | Capital commitments | 219 | ||||||
46 | Subsidiaries, jointly controlled entities and associates | 220 | ||||||
47 | Condensed consolidating information on certain US subsidiaries | 222 | ||||||
228 | Supplementary information on oil and natural gas (unaudited) | |||||||
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Annual Report on Form 20-F
Ernst & Young LLP
London, England
2 March 2011
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Annual Report on Form 20-F
Ernst & Young LLP
London, England
2 March 2011
Ernst & Young LLP
London, England
2 March 2011
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For the year ended 31 December | $ million | |||||||||||||||
Note | 2010 | 2009 | 2008 | |||||||||||||
Sales and other operating revenues | 7 | 297,107 | 239,272 | 361,143 | ||||||||||||
Earnings from jointly controlled entities – after interest and tax | 1,175 | 1,286 | 3,023 | |||||||||||||
Earnings from associates – after interest and tax | 3,582 | 2,615 | 798 | |||||||||||||
Interest and other income | 8 | 681 | 792 | 736 | ||||||||||||
Gains on sale of businesses and fixed assets | 5 | 6,383 | 2,173 | 1,353 | ||||||||||||
Total revenues and other income | 308,928 | 246,138 | 367,053 | |||||||||||||
Purchases | 216,211 | 163,772 | 266,982 | |||||||||||||
Production and manufacturing expensesa | 64,615 | 23,202 | 26,756 | |||||||||||||
Production and similar taxes | 9 | 5,244 | 3,752 | 8,953 | ||||||||||||
Depreciation, depletion and amortization | 10 | 11,164 | 12,106 | 10,985 | ||||||||||||
Impairment and losses on sale of businesses and fixed assets | 5 | 1,689 | 2,333 | 1,733 | ||||||||||||
Exploration expense | 16 | 843 | 1,116 | 882 | ||||||||||||
Distribution and administration expenses | 12 | 12,555 | 14,038 | 15,412 | ||||||||||||
Fair value (gain) loss on embedded derivatives | 34 | 309 | (607 | ) | 111 | |||||||||||
Profit (loss) before interest and taxation | (3,702 | ) | 26,426 | 35,239 | ||||||||||||
Finance costsa | 18 | 1,170 | 1,110 | 1,547 | ||||||||||||
Net finance expense (income) relating to pensions and other post-retirement benefits | 38 | (47 | ) | 192 | (591 | ) | ||||||||||
Profit (loss) before taxation | (4,825 | ) | 25,124 | 34,283 | ||||||||||||
Taxationa | 19 | (1,501 | ) | 8,365 | 12,617 | |||||||||||
Profit (loss) for the year | (3,324 | ) | 16,759 | 21,666 | ||||||||||||
Attributable to | ||||||||||||||||
BP shareholders | (3,719 | ) | 16,578 | 21,157 | ||||||||||||
Minority interest | 395 | 181 | 509 | |||||||||||||
(3,324 | ) | 16,759 | 21,666 | |||||||||||||
Earnings per share – cents | ||||||||||||||||
Profit (loss) for the year attributable to BP shareholders | ||||||||||||||||
Basic | 21 | (19.81 | ) | 88.49 | 112.59 | |||||||||||
Diluted | 21 | (19.81 | ) | 87.54 | 111.56 | |||||||||||
a | See Note 2 for information on the impact of the Gulf of Mexico oil spill on the income statement line items. |
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For the year ended 31 December | $ million | |||||||||||||||
Note | 2010 | 2009 | 2008 | |||||||||||||
Profit (loss) for the year | (3,324 | ) | 16,759 | 21,666 | ||||||||||||
Currency translation differences | 259 | 1,826 | (4,362 | ) | ||||||||||||
Exchange gains on translation of foreign operations transferred to gain or loss on sale of businesses and fixed assets | (20 | ) | (27 | ) | – | |||||||||||
Actuarial loss relating to pensions and other post-retirement benefits | 38 | (320 | ) | (682 | ) | (8,430 | ) | |||||||||
Available-for-sale investments marked to market | (191 | ) | 705 | (994 | ) | |||||||||||
Available-for-sale investments – recycled to the income statement | (150 | ) | 2 | 526 | ||||||||||||
Cash flow hedges marked to market | (65 | ) | 652 | (1,173 | ) | |||||||||||
Cash flow hedges – recycled to the income statement | (25 | ) | 366 | 45 | ||||||||||||
Cash flow hedges – recycled to the balance sheet | 53 | 136 | (38 | ) | ||||||||||||
Taxation | 19 | (137 | ) | 525 | 2,946 | |||||||||||
Other comprehensive income | (596 | ) | 3,503 | (11,480 | ) | |||||||||||
Total comprehensive income | (3,920 | ) | 20,262 | 10,186 | ||||||||||||
Attributable to | ||||||||||||||||
BP shareholders | (4,318 | ) | 20,137 | 9,752 | ||||||||||||
Minority interest | 398 | 125 | 434 | |||||||||||||
(3,920 | ) | 20,262 | 10,186 | |||||||||||||
$ million | ||||||||||||||||||||||||||||||||||||
2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||
BP | BP | BP | ||||||||||||||||||||||||||||||||||
shareholders' | Minority | Total | shareholders’ | Minority | Total | shareholders’ | Minority | Total | ||||||||||||||||||||||||||||
equity | interest | equity | equity | interest | equity | equity | interest | equity | ||||||||||||||||||||||||||||
At 1 January | 101,613 | 500 | 102,113 | 91,303 | 806 | 92,109 | 93,690 | 962 | 94,652 | |||||||||||||||||||||||||||
Total comprehensive income | (4,318 | ) | 398 | (3,920 | ) | 20,137 | 125 | 20,262 | 9,752 | 434 | 10,186 | |||||||||||||||||||||||||
Dividends | (2,627 | ) | (315 | ) | (2,942 | ) | (10,483 | ) | (416 | ) | (10,899 | ) | (10,342 | ) | (425 | ) | (10,767 | ) | ||||||||||||||||||
Repurchase of ordinary share capital | – | – | – | – | – | – | (2,414 | ) | – | (2,414 | ) | |||||||||||||||||||||||||
Share-based payments (net of tax) | 339 | – | 339 | 721 | – | 721 | 617 | – | 617 | |||||||||||||||||||||||||||
Changes in associates’ equity | – | – | – | (43 | ) | – | (43 | ) | – | – | – | |||||||||||||||||||||||||
Transactions involving minority interests | (20 | ) | 321 | 301 | (22 | ) | (15 | ) | (37 | ) | – | (165 | ) | (165 | ) | |||||||||||||||||||||
At 31 December | 94,987 | 904 | 95,891 | 101,613 | 500 | 102,113 | 91,303 | 806 | 92,109 | |||||||||||||||||||||||||||
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At 31 December | $ million | |||||||||||
Note | 2010 | 2009 | ||||||||||
Non-current assets | ||||||||||||
Property, plant and equipment | 22 | 110,163 | 108,275 | |||||||||
Goodwill | 23 | 8,598 | 8,620 | |||||||||
Intangible assets | 24 | 14,298 | 11,548 | |||||||||
Investments in jointly controlled entities | 25 | 12,286 | 15,296 | |||||||||
Investments in associates | 26 | 13,335 | 12,963 | |||||||||
Other investments | 28 | 1,191 | 1,567 | |||||||||
Fixed assets | 159,871 | 158,269 | ||||||||||
Loans | 894 | 1,039 | ||||||||||
Other receivables | 30 | 6,298 | 1,729 | |||||||||
Derivative financial instruments | 34 | 4,210 | 3,965 | |||||||||
Prepayments | 1,432 | 1,407 | ||||||||||
Deferred tax assets | 19 | 528 | 516 | |||||||||
Defined benefit pension plan surpluses | 38 | 2,176 | 1,390 | |||||||||
175,409 | 168,315 | |||||||||||
Current assets | ||||||||||||
Loans | 247 | 249 | ||||||||||
Inventories | 29 | 26,218 | 22,605 | |||||||||
Trade and other receivables | 30 | 36,549 | 29,531 | |||||||||
Derivative financial instruments | 34 | 4,356 | 4,967 | |||||||||
Prepayments | 1,574 | 1,753 | ||||||||||
Current tax receivable | 693 | 209 | ||||||||||
Other investments | 28 | 1,532 | – | |||||||||
Cash and cash equivalents | 31 | 18,556 | 8,339 | |||||||||
89,725 | 67,653 | |||||||||||
Assets classified as held for sale | 4 | 7,128 | – | |||||||||
96,853 | 67,653 | |||||||||||
Total assets | 272,262 | 235,968 | ||||||||||
Current liabilities | ||||||||||||
Trade and other payables | 33 | 46,329 | 35,204 | |||||||||
Derivative financial instruments | 34 | 3,856 | 4,681 | |||||||||
Accruals | 5,612 | 6,202 | ||||||||||
Finance debt | 35 | 14,626 | 9,109 | |||||||||
Current tax payable | 2,920 | 2,464 | ||||||||||
Provisions | 37 | 9,489 | 1,660 | |||||||||
82,832 | 59,320 | |||||||||||
Liabilities directly associated with assets classified as held for sale | 4 | 1,047 | – | |||||||||
83,879 | 59,320 | |||||||||||
Non-current liabilities | ||||||||||||
Other payables | 33 | 14,285 | 3,198 | |||||||||
Derivative financial instruments | 34 | 3,677 | 3,474 | |||||||||
Accruals | 637 | 703 | ||||||||||
Finance debt | 35 | 30,710 | 25,518 | |||||||||
Deferred tax liabilities | 19 | 10,908 | 18,662 | |||||||||
Provisions | 37 | 22,418 | 12,970 | |||||||||
Defined benefit pension plan and other post-retirement benefit plan deficits | 38 | 9,857 | 10,010 | |||||||||
92,492 | 74,535 | |||||||||||
Total liabilities | 176,371 | 133,855 | ||||||||||
Net assets | 95,891 | 102,113 | ||||||||||
Equity | ||||||||||||
Share capital | 39 | 5,183 | 5,179 | |||||||||
Reserves | 89,804 | 96,434 | ||||||||||
BP shareholders’ equity | 40 | 94,987 | 101,613 | |||||||||
Minority interest | 40 | 904 | 500 | |||||||||
Total equity | 40 | 95,891 | 102,113 | |||||||||
R W Dudley Group Chief Executive
2 March 2011
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For the year ended 31 December | $ million | |||||||||||||||
Note | 2010 | 2009 | 2008 | |||||||||||||
Operating activities | ||||||||||||||||
Profit (loss) before taxation | (4,825 | ) | 25,124 | 34,283 | ||||||||||||
Adjustments to reconcile profit (loss) before taxation to net cash provided byoperating activities | ||||||||||||||||
Exploration expenditure written off | 16 | 375 | 593 | 385 | ||||||||||||
Depreciation, depletion and amortization | 10 | 11,164 | 12,106 | 10,985 | ||||||||||||
Impairment and (gain) loss on sale of businesses and fixed assets | 5 | (4,694 | ) | 160 | 380 | |||||||||||
Earnings from jointly controlled entities and associates | (4,757 | ) | (3,901 | ) | (3,821 | ) | ||||||||||
Dividends received from jointly controlled entities and associates | 3,277 | 3,003 | 3,728 | |||||||||||||
Interest receivable | (277 | ) | (258 | ) | (407 | ) | ||||||||||
Interest received | 205 | 203 | 385 | |||||||||||||
Finance costs | 18 | 1,170 | 1,110 | 1,547 | ||||||||||||
Interest paid | (912 | ) | (909 | ) | (1,291 | ) | ||||||||||
Net finance expense (income) relating to pensions and other post-retirement benefits | 38 | (47 | ) | 192 | (591 | ) | ||||||||||
Share-based payments | 197 | 450 | 459 | |||||||||||||
Net operating charge for pensions and other post-retirement benefits, less contributions and benefit payments for unfunded plans | (959 | ) | (887 | ) | (173 | ) | ||||||||||
Net charge for provisions, less payments | 19,217 | 650 | (298 | ) | ||||||||||||
(Increase) decrease in inventories | (3,895 | ) | (5,363 | ) | 9,010 | |||||||||||
(Increase) decrease in other current and non-current assets | (15,620 | ) | 7,595 | 2,439 | ||||||||||||
Increase (decrease) in other current and non-current liabilities | 20,607 | (5,828 | ) | (6,101 | ) | |||||||||||
Income taxes paid | (6,610 | ) | (6,324 | ) | (12,824 | ) | ||||||||||
Net cash provided by operating activities | 13,616 | 27,716 | 38,095 | |||||||||||||
Investing activities | ||||||||||||||||
Capital expenditure | (18,421 | ) | (20,650 | ) | (22,658 | ) | ||||||||||
Acquisitions, net of cash acquired | (2,468 | ) | 1 | (395 | ) | |||||||||||
Investment in jointly controlled entities | (461 | ) | (578 | ) | (1,009 | ) | ||||||||||
Investment in associates | (65 | ) | (164 | ) | (81 | ) | ||||||||||
Proceeds from disposals of fixed assets | 5 | 7,492 | 1,715 | 918 | ||||||||||||
Proceeds from disposals of businesses, net of cash disposed | 5 | 9,462 | 966 | 11 | ||||||||||||
Proceeds from loan repayments | 501 | 530 | 647 | |||||||||||||
Other | – | 47 | (200 | ) | ||||||||||||
Net cash used in investing activities | (3,960 | ) | (18,133 | ) | (22,767 | ) | ||||||||||
Financing activities | ||||||||||||||||
Net issue (repurchase) of shares | 169 | 207 | (2,567 | ) | ||||||||||||
Proceeds from long-term financing | 11,934 | 11,567 | 7,961 | |||||||||||||
Repayments of long-term financing | (4,702 | ) | (6,021 | ) | (3,821 | ) | ||||||||||
Net decrease in short-term debt | (3,619 | ) | (4,405 | ) | (1,315 | ) | ||||||||||
Dividends paid | ||||||||||||||||
BP shareholders | (2,627 | ) | (10,483 | ) | (10,342 | ) | ||||||||||
Minority interest | (315 | ) | (416 | ) | (425 | ) | ||||||||||
Net cash provided by (used in) financing activities | 840 | (9,551 | ) | (10,509 | ) | |||||||||||
Currency translation differences relating to cash and cash equivalents | (279 | ) | 110 | (184 | ) | |||||||||||
Increase in cash and cash equivalents | 10,217 | 142 | 4,635 | |||||||||||||
Cash and cash equivalents at beginning of year | 8,339 | 8,197 | 3,562 | |||||||||||||
Cash and cash equivalents at end of year | 18,556 | 8,339 | 8,197 | |||||||||||||
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Land improvements | 15 to 25 years | |||
Buildings | 20 to 50 years | |||
Refineries | 20 to 30 years | |||
Petrochemicals | 20 to 30 years | |||
Pipelines | 10 to 50 years | |||
Service stations | 15 years | |||
Office equipment | 3 to 7 years | |||
Fixtures and fittings | 5 to 15 years | |||
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• | Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability. | |
• | Cash flow hedges when hedging exposure to variability in cash flows that is either attributable to a particular risk associated with a recognized asset or liability or a highly probable forecast transaction. | |
• | Hedges of a net investment in a foreign operation. |
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• | Except where the deferred tax liability arises on goodwill that is not tax deductible or the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss. |
• | In respect of taxable temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, except where the group is able to control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future. |
• | Except where the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss. |
• | In respect of deductible temporary differences associated with investments in subsidiaries, jointly controlled entities and associates, deferred tax assets are recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be available against which the temporary differences can be utilized. |
• | Where the customs duty or sales tax incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the customs duty or sales tax is recognized as part of the cost of acquisition of the asset or as part of the expense item as applicable. | |
• | Receivables and payables are stated with the amount of customs duty or sales tax included. |
156 BP Annual Report and Form 20-F 2010
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$ million | ||||||||
2010 | ||||||||
Of which: | ||||||||
amount related | ||||||||
Total | to the trust fund | |||||||
Income statement | ||||||||
Production and manufacturing expenses | 40,858 | 7,261 | ||||||
Profit (loss) before interest and taxation | (40,858 | ) | (7,261 | ) | ||||
Finance costs | 77 | 73 | ||||||
Profit (loss) before taxation | (40,935 | ) | (7,334 | ) | ||||
Less: Taxation | 12,894 | – | ||||||
Profit (loss) for the period | (28,041 | ) | (7,334 | ) | ||||
Balance sheet | ||||||||
Current assets | ||||||||
Trade and other receivables | 5,943 | 5,943 | ||||||
Current liabilities | ||||||||
Trade and other payables | (6,587 | ) | (5,002 | ) | ||||
Provisions | (7,938 | ) | – | |||||
Net current liabilities | (8,582 | ) | 941 | |||||
Non-current assets | ||||||||
Other receivables | 3,601 | 3,601 | ||||||
Non-current liabilities | ||||||||
Other payables | (9,899 | ) | (9,899 | ) | ||||
Provisions | (8,397 | ) | – | |||||
Deferred tax | 11,255 | – | ||||||
Net non-current liabilities | (3,440 | ) | (6,298 | ) | ||||
Net assets | (12,022 | ) | (5,357 | ) | ||||
Cash flow statement | ||||||||
Profit (loss) before taxation | (40,935 | ) | (7,334 | ) | ||||
Finance costs | 77 | 73 | ||||||
Net charge for provisions, less payments | 19,354 | – | ||||||
Increase in other current and non-current assets | (12,567 | ) | (12,567 | ) | ||||
Increase in other current and non-current liabilities | 16,413 | 14,828 | ||||||
Pre-tax cash flows | (17,658 | ) | (5,000 | ) | ||||
158 BP Annual Report and Form 20-F 2010
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$ million | ||||
Trust fund liability initially recognized – discounted | 19,580 | |||
Unwinding of discount | 73 | |||
Change in discount rate | 240 | |||
Contributions | (5,000 | ) | ||
Other | 8 | |||
At 31 December 2010 | 14,901 | |||
Of which – current | 5,002 | |||
– non-current | 9,899 | |||
$ million | ||||
Increase in provision for items covered by the trust fund | 12,567 | |||
Amounts paid directly by the trust fund | (3,023 | ) | ||
At 31 December 2010 | 9,544 | |||
Of which – current | 5,943 | |||
– non-current | 3,601 | |||
$ million | ||||
Trust fund liability – discounted | 19,580 | |||
Change in discount rate relating to trust fund liability | 240 | |||
Recognition of reimbursement asset | (12,567 | ) | ||
Other | 8 | |||
Total charge relating to the trust fund | 7,261 | |||
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$ million | ||||||
Increase in provision – items not covered by the trust fund | 17,694 | |||||
– items covered by the trust fund | 12,567 | |||||
Unwinding of discount | 4 | |||||
Change in discount rate | 5 | |||||
Utilization – paid by BP | (10,912 | ) | ||||
– paid by the trust fund | (3,023 | ) | ||||
At 31 December 2010 | 16,335 | |||||
Of which – current | 7,938 | |||||
– non-current | 8,397 | |||||
160 BP Annual Report and Form 20-F 2010
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$ million | ||||
Increase in provision | 30,261 | |||
Change in discount rate relating to provisions | 5 | |||
Costs charged directly to the income statement | 3,339 | |||
Trust fund liability – discounted | 19,580 | |||
Change in discount rate relating to trust fund liability | 240 | |||
Recognition of reimbursement asset | (12,567 | ) | ||
(Profit) loss before interest and taxation | 40,858 | |||
$ million | ||||
Trust fund liability – discounted | 19,580 | |||
Change in discount rate relating to trust fund liability | 240 | |||
Recognition of reimbursement asset | (12,567 | ) | ||
Other | 8 | |||
Total charge relating to the trust fund | 7,261 | |||
Spill response – amount provided | 10,883 | |||
– costs charged directly to the income statement | 2,745 | |||
Total charge relating to spill response | 13,628 | |||
Environmental – amount provided | 929 | |||
– change in discount rate relating to provisions | 5 | |||
– costs charged directly to the income statement | 70 | |||
Total charge relating to environmental | 1,004 | |||
Litigation and claims – amount provided | 14,939 | |||
– costs charged directly to the income statement | 184 | |||
Total charge relating to litigation and claims | 15,123 | |||
Clean Water Act penalties – amount provided | 3,510 | |||
Other costs charged directly to the income statement | 332 | |||
(Profit) loss before interest and taxation | 40,858 | |||
Finance costs | 77 | |||
(Profit) loss before taxation | 40,935 | |||
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162 BP Annual Report and Form 20-F 2010
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$ million | ||||
2010 | ||||
Assets | ||||
Property, plant and equipment | 2,971 | |||
Goodwill | 87 | |||
Intangible assets | 135 | |||
Investments in jointly controlled entities | 3,108 | |||
Investments in associates | 333 | |||
Loans | 12 | |||
Cash | 34 | |||
Other current assets | 448 | |||
Assets classified as held for sale | 7,128 | |||
Liabilities | ||||
Trade and other payables | 597 | |||
Provisions | 383 | |||
Deferred tax liabilities | 67 | |||
Liabilities directly associated with assets classified as held for sale | 1,047 | |||
BP Annual Report and Form 20-F 2010 163
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Proceeds from disposal of businesses, net of cash disposed | 9,462 | 966 | 11 | |||||||||
Proceeds from disposal of fixed assets | 7,492 | 1,715 | 918 | |||||||||
16,954 | 2,681 | 929 | ||||||||||
By business | ||||||||||||
Exploration and Production | 14,392 | 940 | 19 | |||||||||
Refining and Marketing | 1,840 | 1,294 | 813 | |||||||||
Other businesses and corporate | 722 | 447 | 97 | |||||||||
16,954 | 2,681 | 929 | ||||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Gains on sale of businesses and fixed assets | ||||||||||||
Exploration and Production | 5,267 | 1,717 | 34 | |||||||||
Refining and Marketing | 999 | 384 | 1,258 | |||||||||
Other businesses and corporate | 117 | 72 | 61 | |||||||||
6,383 | 2,173 | 1,353 | ||||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Losses on sale of businesses and fixed assets | ||||||||||||
Exploration and Production | 196 | 28 | 18 | |||||||||
Refining and Marketing | 119 | 154 | 297 | |||||||||
Other businesses and corporate | 6 | 21 | 1 | |||||||||
321 | 203 | 316 | ||||||||||
Impairment losses | ||||||||||||
Exploration and Production | 1,259 | 118 | 1,186 | |||||||||
Refining and Marketing | 144 | 1,834 | 159 | |||||||||
Other businesses and corporate | 113 | 189 | 227 | |||||||||
1,516 | 2,141 | 1,572 | ||||||||||
Impairment reversals | ||||||||||||
Exploration and Production | – | (3 | ) | (155 | ) | |||||||
Refining and Marketing | (141 | ) | – | – | ||||||||
Other businesses and corporate | (7 | ) | (8 | ) | – | |||||||
(148 | ) | (11 | ) | (155 | ) | |||||||
Impairment and losses on sale of businesses and fixed assets | 1,689 | 2,333 | 1,733 | |||||||||
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Non-current assets | 2,319 | 536 | 759 | |||||||||
Current assets | 310 | 444 | 485 | |||||||||
Non-current liabilities | (303 | ) | (146 | ) | – | |||||||
Current liabilities | (124 | ) | (152 | ) | (134 | ) | ||||||
Total carrying amount of net assets disposed | 2,202 | 682 | 1,110 | |||||||||
Recycling of foreign exchange on disposal | (52 | ) | (27 | ) | – | |||||||
Costs on disposal | 18 | 3 | 7 | |||||||||
2,168 | 658 | 1,117 | ||||||||||
Profit on sale of businessesa | 1,968 | 314 | 1,721 | |||||||||
Total consideration | 4,136 | 972 | 2,838 | |||||||||
Fair value of interest received in a jointly controlled entity | – | – | (2,838 | ) | ||||||||
Consideration received (receivable)b | 20 | (6 | ) | 11 | ||||||||
Proceeds from the sale of businesses related to completed transactions | 4,156 | 966 | 11 | |||||||||
Deposits received related to assets classified as held for sale | 5,306 | – | – | |||||||||
Proceeds from the sale of businessesc | 9,462 | 966 | 11 | |||||||||
a | Of which $929 million gain was not recognized in the income statement in 2008 as it represented an unrealized gain on the transfer of the Toledo refinery into a jointly controlled entity. |
b | Consideration received from prior year business disposals or not yet received from current year disposals. |
c | Net of cash and cash equivalents disposed of $55 million (2009 $91 million and 2008 nil). |
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a | Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. |
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$ million | |||||||||||||||||||||||||
2010 | |||||||||||||||||||||||||
Other | Gulf of | Consolidation | |||||||||||||||||||||||
Exploration | Refining | businesses | Mexico | adjustment | |||||||||||||||||||||
and | and | and | oil spill | and | Total | ||||||||||||||||||||
By business | Production | Marketing | corporate | response | eliminations | group | |||||||||||||||||||
Segment revenues | |||||||||||||||||||||||||
Sales and other operating revenues | 66,266 | 266,751 | 3,328 | – | (39,238 | ) | 297,107 | ||||||||||||||||||
Less: sales between businesses | (37,049 | ) | (1,358 | ) | (831 | ) | – | 39,238 | – | ||||||||||||||||
Third party sales and other operating revenues | 29,217 | 265,393 | 2,497 | – | – | 297,107 | |||||||||||||||||||
Equity-accounted earnings | 3,979 | 755 | 23 | – | – | 4,757 | |||||||||||||||||||
Interest revenues | 83 | 46 | 109 | – | – | 238 | |||||||||||||||||||
Segment results | |||||||||||||||||||||||||
Replacement cost profit (loss) before interest and taxation | 30,886 | 5,555 | (1,516 | ) | (40,858 | ) | 447 | (5,486 | ) | ||||||||||||||||
Inventory holding gainsa | 84 | 1,684 | 16 | – | – | 1,784 | |||||||||||||||||||
Profit (loss) before interest and taxation | 30,970 | 7,239 | (1,500 | ) | (40,858 | ) | 447 | (3,702 | ) | ||||||||||||||||
Finance costs | (1,170 | ) | |||||||||||||||||||||||
Net finance income relating to pensions and other post-retirement benefits | 47 | ||||||||||||||||||||||||
Loss before taxation | (4,825 | ) | |||||||||||||||||||||||
Other income statement items | |||||||||||||||||||||||||
Depreciation, depletion and amortization | 8,616 | 2,258 | 290 | – | – | 11,164 | |||||||||||||||||||
Impairment losses | 1,259 | 144 | 113 | – | – | 1,516 | |||||||||||||||||||
Impairment reversals | – | 141 | 7 | – | – | 148 | |||||||||||||||||||
Fair value loss on embedded derivatives | 309 | – | – | – | – | 309 | |||||||||||||||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate | 303 | 275 | 206 | 30,266 | – | 31,050 | |||||||||||||||||||
Segment assets | |||||||||||||||||||||||||
Equity-accounted investments | 17,738 | 7,043 | 840 | – | – | 25,621 | |||||||||||||||||||
Additions to non-current assets | 20,113 | 4,030 | 1,226 | – | – | 25,369 | |||||||||||||||||||
Additions to other investments | 20 | ||||||||||||||||||||||||
Element of acquisitions not related to non-current assets | (401 | ) | |||||||||||||||||||||||
Additions to decommissioning asset | (1,972 | ) | |||||||||||||||||||||||
Capital expenditure and acquisitions | 17,753 | 4,029 | 1,234 | – | – | 23,016 | |||||||||||||||||||
a | Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. |
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$ million | |||||||||||||||||||||||||
2009 | |||||||||||||||||||||||||
Other | Consolidation | ||||||||||||||||||||||||
Exploration | Refining | businesses | adjustment | ||||||||||||||||||||||
and | and | and | and | Total | |||||||||||||||||||||
By business | Production | Marketing | corporate | eliminations | group | ||||||||||||||||||||
Segment revenues | |||||||||||||||||||||||||
Sales and other operating revenues | 57,626 | 213,050 | 2,843 | (34,247 | ) | 239,272 | |||||||||||||||||||
Less: sales between businesses | (32,540 | ) | (821 | ) | (886 | ) | 34,247 | – | |||||||||||||||||
Third party sales and other operating revenues | 25,086 | 212,229 | 1,957 | – | 239,272 | ||||||||||||||||||||
Equity-accounted earnings | 3,309 | 558 | 34 | – | 3,901 | ||||||||||||||||||||
Interest revenues | 98 | 32 | 95 | – | 225 | ||||||||||||||||||||
Segment results | |||||||||||||||||||||||||
Replacement cost profit (loss) before interest and taxation | 24,800 | 743 | (2,322 | ) | (717 | ) | 22,504 | ||||||||||||||||||
Inventory holding gainsa | 142 | 3,774 | 6 | – | 3,922 | ||||||||||||||||||||
Profit (loss) before interest and taxation | 24,942 | 4,517 | (2,316 | ) | (717 | ) | 26,426 | ||||||||||||||||||
Finance costs | (1,110 | ) | |||||||||||||||||||||||
Net finance expense relating to pensions and other post-retirement benefits | (192 | ) | |||||||||||||||||||||||
Profit before taxation | 25,124 | ||||||||||||||||||||||||
Other income statement items | |||||||||||||||||||||||||
Depreciation, depletion and amortization | 9,557 | 2,236 | 313 | – | 12,106 | ||||||||||||||||||||
Impairment losses | 118 | 1,834 | 189 | – | 2,141 | ||||||||||||||||||||
Impairment reversals | 3 | – | 8 | – | 11 | ||||||||||||||||||||
Fair value (gain) loss on embedded derivatives | (664 | ) | 57 | – | – | (607 | ) | ||||||||||||||||||
Charges for provisions, net of write-back of unused provisions, including change in discount rate | 307 | 756 | 488 | – | 1,551 | ||||||||||||||||||||
Segment assets | |||||||||||||||||||||||||
Equity-accounted investments | 20,289 | 6,882 | 1,088 | – | 28,259 | ||||||||||||||||||||
Additions to non-current assets | 15,855 | 4,083 | 1,297 | – | 21,235 | ||||||||||||||||||||
Additions to other investments | 19 | ||||||||||||||||||||||||
Element of acquisitions not related to non-current assets | (7 | ) | |||||||||||||||||||||||
Additions to decommissioning asset | (938 | ) | |||||||||||||||||||||||
Capital expenditure and acquisitions | 14,896 | 4,114 | 1,299 | – | 20,309 | ||||||||||||||||||||
a | Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. |
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$ million | ||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||
Other | Consolidation | |||||||||||||||||||||||
Exploration | Refining | businesses | adjustment | |||||||||||||||||||||
and | and | and | and | Total | ||||||||||||||||||||
By business | Production | Marketing | corporate | eliminations | group | |||||||||||||||||||
Segment revenues | ||||||||||||||||||||||||
Sales and other operating revenues | 86,170 | 320,039 | 4,634 | (49,700 | ) | 361,143 | ||||||||||||||||||
Less: sales between businesses | (45,931 | ) | (1,918 | ) | (1,851 | ) | 49,700 | – | ||||||||||||||||
Third party sales and other operating revenues | 40,239 | 318,121 | 2,783 | – | 361,143 | |||||||||||||||||||
Equity-accounted earnings | 3,565 | 131 | 125 | – | 3,821 | |||||||||||||||||||
Interest revenues | 114 | 35 | 220 | – | 369 | |||||||||||||||||||
Segment results | ||||||||||||||||||||||||
Replacement cost profit (loss) before interest and taxation | 38,308 | 4,176 | (1,223 | ) | 466 | 41,727 | ||||||||||||||||||
Inventory holding lossesa | (393 | ) | (6,060 | ) | (35 | ) | – | (6,488 | ) | |||||||||||||||
Profit (loss) before interest and taxation | 37,915 | (1,884 | ) | (1,258 | ) | 466 | 35,239 | |||||||||||||||||
Finance costs | (1,547 | ) | ||||||||||||||||||||||
Net finance income relating to pensions and other post-retirement benefits | 591 | |||||||||||||||||||||||
Profit before taxation | 34,283 | |||||||||||||||||||||||
Other income statement items | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 8,440 | 2,208 | 337 | – | 10,985 | |||||||||||||||||||
Impairment losses | 1,186 | 159 | 227 | – | 1,572 | |||||||||||||||||||
Impairment reversals | 155 | – | – | – | 155 | |||||||||||||||||||
Fair value (gain) loss on embedded derivatives | 163 | (57 | ) | 5 | – | 111 | ||||||||||||||||||
Charges for provisions, net of write-back of unused provisions | 573 | 479 | 657 | – | 1,709 | |||||||||||||||||||
Segment assets | ||||||||||||||||||||||||
Equity-accounted investments | 20,131 | 6,622 | 1,073 | – | 27,826 | |||||||||||||||||||
Additions to non-current assets | 21,584 | 6,636 | 1,802 | – | 30,022 | |||||||||||||||||||
Additions to other investments | 52 | |||||||||||||||||||||||
Element of acquisitions not related to non-current assets | 11 | |||||||||||||||||||||||
Additions to decommissioning asset | 615 | |||||||||||||||||||||||
Capital expenditure and acquisitions | 22,227 | 6,634 | 1,839 | – | 30,700 | |||||||||||||||||||
a | Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated on the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions. |
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$ million | ||||||||||||
2010 | ||||||||||||
By geographical area | US | Non-US | Total | |||||||||
Revenues | ||||||||||||
Third party sales and other operating revenuesa | 101,768 | 195,339 | 297,107 | |||||||||
Results | ||||||||||||
Replacement cost profit (loss) before interest and taxation | (30,087 | ) | 24,601 | (5,486 | ) | |||||||
Non-current assets | ||||||||||||
Other non-current assetsb c | 67,498 | 92,614 | 160,112 | |||||||||
Other investments | 1,191 | |||||||||||
Loans | 894 | |||||||||||
Other receivables | 6,298 | |||||||||||
Derivative financial instruments | 4,210 | |||||||||||
Deferred tax assets | 528 | |||||||||||
Defined benefit pension plan surpluses | 2,176 | |||||||||||
Total non-current assets | 175,409 | |||||||||||
Capital expenditure and acquisitions | 10,370 | 12,646 | 23,016 | |||||||||
a | Non-US region includes UK $62,794 million. |
b | Non-US region includes UK $16,650 million. |
c | Excluding financial instruments, deferred tax assets and post-employment benefit plan surpluses. |
$ million | ||||||||||||
2009 | ||||||||||||
By geographical area | US | Non-US | Total | |||||||||
Revenues | ||||||||||||
Third party sales and other operating revenuesa | 83,982 | 155,290 | 239,272 | |||||||||
Results | ||||||||||||
Replacement cost profit before interest and taxation | 2,806 | 19,698 | 22,504 | |||||||||
Non-current assets | ||||||||||||
Other non-current assetsb c | 64,529 | 93,580 | 158,109 | |||||||||
Other investments | 1,567 | |||||||||||
Loans | 1,039 | |||||||||||
Other receivables | 1,729 | |||||||||||
Derivative financial instruments | 3,965 | |||||||||||
Deferred tax assets | 516 | |||||||||||
Defined benefit pension plan surpluses | 1,390 | |||||||||||
Total non-current assets | 168,315 | |||||||||||
Capital expenditure and acquisitions | 9,865 | 10,444 | 20,309 | |||||||||
a | Non-US region includes UK $51,172 million. |
b | Non-US region includes UK $16,713 million. |
c | Excluding financial instruments, deferred tax assets and post-employment benefit plan surpluses. |
$ million | ||||||||||||
2008 | ||||||||||||
By geographical area | US | Non-US | Total | |||||||||
Revenues | ||||||||||||
Third party sales and other operating revenuesa | 123,364 | 237,779 | 361,143 | |||||||||
Results | ||||||||||||
Replacement cost profit before interest and taxation | 10,678 | 31,049 | 41,727 | |||||||||
Non-current assets | ||||||||||||
Other non-current assetsb c | 62,679 | 89,823 | 152,502 | |||||||||
Other investments | 855 | |||||||||||
Loans | 995 | |||||||||||
Other receivables | 710 | |||||||||||
Derivative financial instruments | 5,054 | |||||||||||
Defined benefit pension plan surpluses | 1,738 | |||||||||||
Total non-current assets | 161,854 | |||||||||||
Capital expenditure and acquisitions | 16,046 | 14,654 | 30,700 | |||||||||
a | Non-US region includes UK $81,773 million. |
b | Non-US region includes UK $15,990 million. |
c | Excluding financial instruments, and post-employment benefit plan surpluses. |
BP Annual Report and Form 20-F 2010 171
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Interest income | ||||||||||||
Interest income from available-for-sale financial assetsa | 23 | 15 | 32 | |||||||||
Interest income from loans and receivablesa | 88 | 69 | 163 | |||||||||
Interest from loans to equity-accounted entities | 36 | 53 | 115 | |||||||||
Other interest | 91 | 88 | 59 | |||||||||
238 | 225 | 369 | ||||||||||
Other income | ||||||||||||
Dividend income from available-for-sale financial assetsa | 37 | 32 | 37 | |||||||||
Other income | 406 | 535 | 330 | |||||||||
443 | 567 | 367 | ||||||||||
681 | 792 | 736 | ||||||||||
a | Total interest and other income related to financial instruments amounted to $148 million (2009 $116 million and 2008 $232 million). |
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
US | 1,093 | 649 | 2,602 | |||||||||
Non-US | 4,151 | 3,103 | 6,351 | |||||||||
5,244 | 3,752 | 8,953 | ||||||||||
$ million | ||||||||||||
By business | 2010 | 2009 | 2008 | |||||||||
Exploration and Production | ||||||||||||
US | 3,751 | 4,150 | 3,012 | |||||||||
Non-US | 4,865 | 5,407 | 5,428 | |||||||||
8,616 | 9,557 | 8,440 | ||||||||||
Refining and Marketing | ||||||||||||
US | 955 | 919 | 825 | |||||||||
Non-USa | 1,303 | 1,317 | 1,383 | |||||||||
2,258 | 2,236 | 2,208 | ||||||||||
Other businesses and corporate | ||||||||||||
US | 140 | 136 | 132 | |||||||||
Non-US | 150 | 177 | 205 | |||||||||
290 | 313 | 337 | ||||||||||
By geographical area | ||||||||||||
US | 4,846 | 5,205 | 3,969 | |||||||||
Non-USa | 6,318 | 6,901 | 7,016 | |||||||||
11,164 | 12,106 | 10,985 | ||||||||||
a | Non-US area includes the UK-based international activities of Refining and Marketing. |
172 BP Annual Report and Form 20-F 2010
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$ million | ||||||||
Goodwill at 31 December | 2010 | 2009 | ||||||
Exploration and Production | 4,450 | 4,297 | ||||||
Refining and Marketing | 4,074 | 4,245 | ||||||
Other businesses and corporate | 74 | 78 | ||||||
8,598 | 8,620 | |||||||
Exploration and Production | ||||||||||||||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||||||||||
Rest of | Rest of | |||||||||||||||||||||||||||||||
UK | US | World | Total | UK | US | World | Total | |||||||||||||||||||||||||
Goodwill | 341 | 3,479 | 630 | 4,450 | 341 | 3,441 | 515 | 4,297 | ||||||||||||||||||||||||
Excess of recoverable amount over carrying amount | 7,556 | 18,968 | 41,714 | n/a | 7,721 | 15,528 | n/a | n/a | ||||||||||||||||||||||||
BP Annual Report and Form 20-F 2010 173
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Refining and Marketing | ||||||||||||||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||||||||||
Rhine FVC | Lubricants | Other | Total | Rhine FVC | Lubricants | Other | Total | |||||||||||||||||||||||||
Goodwill | 629 | 3,285 | 160 | 4,074 | 655 | 3,416 | 174 | 4,245 | ||||||||||||||||||||||||
Excess of recoverable amount over carrying amount | 4,091 | n/a | n/a | n/a | 2,034 | n/a | n/a | n/a | ||||||||||||||||||||||||
2010 | ||||
Sensitivity analysis | ||||
Sensitivity of value in use to a change in refinery margins of $1 per barrel ($ billion) | 1.6 | |||
Adverse change in refinery margins to reduce recoverable amount to carrying amount ($ per barrel) | 2.6 | |||
Sensitivity of value in use to a 5% change in production volume ($ billion) | 0.9 | |||
Adverse change in production volume to reduce recoverable amount to carrying amount (mmbbl per year) | 54 | |||
Sensitivity of value in use to a change in the discount rate of 1% ($ billion) | 0.8 | |||
Discount rate to reduce recoverable amount to carrying amount | 19 % | |||
174 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Distribution | 11,393 | 12,798 | 14,075 | |||||||||
Administration | 1,162 | 1,240 | 1,337 | |||||||||
12,555 | 14,038 | 15,412 | ||||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Currency exchange losses charged to incomea | 218 | 193 | 156 | |||||||||
a | Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss. |
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Expenditure on research and development | 780 | 587 | 595 | |||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Minimum lease payments | 5,371 | 4,109 | 4,114 | |||||||||
Contingent rentals | (60 | ) | (9 | ) | 97 | |||||||
Sub-lease rentals | (121 | ) | (133 | ) | (194 | ) | ||||||
5,190 | 3,967 | 4,017 | ||||||||||
$ million | ||||||||
Future minimum lease payments | 2010 | 2009 | ||||||
Payable within | ||||||||
1 year | 3,521 | 3,251 | ||||||
2 to 5 years | 6,798 | 7,334 | ||||||
Thereafter | 3,654 | 4,131 | ||||||
13,973 | 14,716 | |||||||
BP Annual Report and Form 20-F 2010 175
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Years | ||||
Ships | up to 15 | |||
Plant and machinery | up to 10 | |||
Commercial vehicles | up to 15 | |||
Land and buildings | up to 40 | |||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Exploration and evaluation costs | ||||||||||||
Exploration expenditure written offa | 375 | 593 | 385 | |||||||||
Other exploration costs | 468 | 523 | 497 | |||||||||
Exploration expense for the yearb | 843 | 1,116 | 882 | |||||||||
Intangible assets – exploration and appraisal expenditure | 13,126 | 10,388 | 9,031 | |||||||||
Net assets | 13,126 | 10,388 | 9,031 | |||||||||
Capital expenditure | 6,422 | 2,715 | 4,780 | |||||||||
Net cash used in operating activities | 468 | 523 | 497 | |||||||||
Net cash used in investing activities | 6,428 | 3,306 | 4,163 | |||||||||
a | 2010 includes $157 million related to decommissioning provisions for idle infrastructure, as required by BOEMRE’s Notice of Lessees 2010 GO5 issued in October 2010. |
b | ln addition to these amounts, an impairment charge of $210 million was recognized in 2008 relating to exploration assets in Vietnam following BP’s decision to withdraw from activities in the area concerned. |
$ million | ||||||||||||
Fees – Ernst & Young | 2010 | 2009 | 2008 | |||||||||
Fees payable to the company’s auditors for the audit of the company’s accountsa | 13 | 13 | 16 | |||||||||
Fees payable to the company’s auditors and its associates for other services | ||||||||||||
Audit of the company’s subsidiaries pursuant to legislation | 22 | 22 | 28 | |||||||||
Other services pursuant to legislation | 12 | 11 | 13 | |||||||||
47 | 46 | 57 | ||||||||||
Tax services | 2 | 1 | 2 | |||||||||
Services relating to corporate finance transactions | 1 | – | 2 | |||||||||
All other services | 4 | 6 | 5 | |||||||||
Audit fees in respect of the BP pension plans | 1 | 1 | 1 | |||||||||
55 | 54 | 67 | ||||||||||
a | Fees in respect of the audit of the accounts of BP p.I.c. including the group’s consolidated financial statements. |
176 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Interest payable | 955 | 906 | 1,319 | |||||||||
Capitalized at 2.75% (2009 2.75% and 2008 4.00%)a | (254 | ) | (188 | ) | (162 | ) | ||||||
Unwinding of discount on provisionsb | 234 | 247 | 287 | |||||||||
Unwinding of discount on other payablesb | 235 | 145 | 103 | |||||||||
1,170 | 1,110 | 1,547 | ||||||||||
a | Tax relief on capitalized interest is $71 million (2009 $63 million and 2008 $42 million). |
b | Unwinding of discount on provisions relating to the Gulf of Mexico oil spill was $4 million and unwinding of discount on other payables relating to the Gulf of Mexico oil spill was $73 million. See Note 2 for further information on the financial impacts of the Gulf of Mexico oil spill. |
Tax on profit | ||||||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Current tax | ||||||||||||
Charge for the year | 6,766 | 6,045 | 13,468 | |||||||||
Adjustment in respect of prior years | (74 | ) | (300 | ) | (85 | ) | ||||||
6,692 | 5,745 | 13,383 | ||||||||||
Deferred tax | ||||||||||||
Origination and reversal of temporary differences in the current year | (8,157 | ) | �� | 2,131 | (324 | ) | ||||||
Adjustment in respect of prior years | (36 | ) | 489 | (442 | ) | |||||||
(8,193 | ) | 2,620 | (766 | ) | ||||||||
Tax on profit (loss) | (1,501 | ) | 8,365 | 12,617 | ||||||||
Tax included in other comprehensive income | ||||||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Current tax | (107 | ) | – | (264 | ) | |||||||
Deferred tax | 244 | (525 | ) | (2,682 | ) | |||||||
137 | (525 | ) | (2,946 | ) | ||||||||
Tax included directly in equity | ||||||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Current tax | (37 | ) | – | – | ||||||||
Deferred tax | 64 | (65 | ) | 190 | ||||||||
27 | (65 | ) | 190 | |||||||||
BP Annual Report and Form 20-F 2010 177
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$ million | ||||||||||||||||||||
2010 | ||||||||||||||||||||
excluding | 2010 | |||||||||||||||||||
impacts of | impacts of | |||||||||||||||||||
Gulf of | Gulf of | |||||||||||||||||||
Mexico oil | Mexico oil | |||||||||||||||||||
spill | spill | 2010 | 2009 | 2008 | ||||||||||||||||
Profit (loss) before taxation | 36,110 | (40,935 | ) | (4,825 | ) | 25,124 | 34,283 | |||||||||||||
Tax charge (credit) on profit (loss) | 11,393 | (12,894 | ) | (1,501 | ) | 8,365 | 12,617 | |||||||||||||
Effective tax rate | 32% | 31% | 31% | 33% | 37% | |||||||||||||||
% of profit or loss before taxation | ||||||||||||||||||||
UK statutory corporation tax rate | 28 | 28 | 28 | 28 | 28 | |||||||||||||||
Increase (decrease) resulting from | ||||||||||||||||||||
UK supplementary and overseas taxes at higher rates | 9 | 7 | (6 | ) | 8 | 14 | ||||||||||||||
Tax reported in equity-accounted entities | (3 | ) | – | 23 | (3 | ) | (2 | ) | ||||||||||||
Adjustments in respect of prior years | – | – | 2 | 1 | (2 | ) | ||||||||||||||
Current year losses unrelieved (prior year losses utilized) | – | – | 1 | – | (1 | ) | ||||||||||||||
Goodwill impairment | – | – | – | 2 | – | |||||||||||||||
Tax incentives for investment | (1 | ) | – | 9 | (2 | ) | (1 | ) | ||||||||||||
Gulf of Mexico oil spill non-deductible costs | – | (4 | ) | (30 | ) | – | – | |||||||||||||
Other | (1 | ) | – | 4 | (1 | ) | 1 | |||||||||||||
Effective tax rate | 32 | 31 | 31 | 33 | 37 | |||||||||||||||
$ million | ||||||||||||||||||||
Income statement | Balance sheet | |||||||||||||||||||
2010 | 2009 | 2008 | 2010 | 2009 | ||||||||||||||||
Deferred tax liability | ||||||||||||||||||||
Depreciation | 1,565 | 1,983 | 1,248 | 27,309 | 25,398 | |||||||||||||||
Pension plan surpluses | 38 | (6 | ) | 108 | 469 | 271 | ||||||||||||||
Other taxable temporary differences | 1,178 | 978 | (2,471 | ) | 5,538 | 4,307 | ||||||||||||||
2,781 | 2,955 | (1,115 | ) | 33,316 | 29,976 | |||||||||||||||
Deferred tax asset | ||||||||||||||||||||
Pension plan and other post-retirement benefit plan deficits | 179 | 180 | 104 | (2,155 | ) | (2,269 | ) | |||||||||||||
Decommissioning, environmental and other provisions | (8,151 | ) | 86 | (333 | ) | (13,296 | ) | (4,930 | ) | |||||||||||
Derivative financial instruments | (56 | ) | 80 | 228 | (298 | ) | (243 | ) | ||||||||||||
Tax credit | (1,088 | ) | (516 | ) | 330 | (2,118 | ) | (1,034 | ) | |||||||||||
Loss carry forward | 24 | 402 | (212 | ) | (943 | ) | (1,014 | ) | ||||||||||||
Other deductible temporary differences | (1,882 | ) | (567 | ) | 232 | (4,126 | ) | (2,340 | ) | |||||||||||
(10,974 | ) | (335 | ) | 349 | (22,936 | ) | (11,830 | ) | ||||||||||||
Net deferred tax (credit) charge and net deferred tax liability | (8,193 | ) | 2,620 | (766 | ) | 10,380 | 18,146 | |||||||||||||
Of which – deferred tax liabilities | 10,908 | 18,662 | ||||||||||||||||||
– deferred tax assets | 528 | 516 | ||||||||||||||||||
$ million | ||||||||
Analysis of movements during the year | 2010 | 2009 | ||||||
At 1 January | 18,146 | 16,198 | ||||||
Exchange adjustments | 3 | (7 | ) | |||||
Charge (credit) for the year on profit (loss) | (8,193 | ) | 2,620 | |||||
Charge (credit) for the year in other comprehensive income | 244 | (525 | ) | |||||
Charge (credit) for the year in equity | 64 | (65 | ) | |||||
Acquisitions | 187 | – | ||||||
Reclassified as liabilities directly associated with assets held for sale | (67 | ) | – | |||||
Deletions | (4 | ) | (75 | ) | ||||
At 31 December | 10,380 | 18,146 | ||||||
178 BP Annual Report and Form 20-F 2010
Table of Contents
a | 2009 comparative data has been amended. |
pence per share | cents per share | $ million | ||||||||||||||||||||||||||||||||||
2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||
Dividends announced and paid | ||||||||||||||||||||||||||||||||||||
Preference shares | 2 | 2 | 2 | |||||||||||||||||||||||||||||||||
Ordinary shares | ||||||||||||||||||||||||||||||||||||
March | 8.679 | 9.818 | 6.813 | 14.000 | 14.000 | 13.525 | 2,625 | 2,619 | 2,553 | |||||||||||||||||||||||||||
June | – | 9.584 | 6.830 | – | 14.000 | 13.525 | – | 2,619 | 2,545 | |||||||||||||||||||||||||||
September | – | 8.503 | 7.039 | – | 14.000 | 14.000 | – | 2,620 | 2,623 | |||||||||||||||||||||||||||
December | – | 8.512 | 8.705 | – | 14.000 | 14.000 | – | 2,623 | 2,619 | |||||||||||||||||||||||||||
8.679 | 36.417 | 29.387 | 14.000 | 56.000 | 55.050 | 2,627 | 10,483 | 10,342 | ||||||||||||||||||||||||||||
Dividend announced per ordinary share, payable in March 2011a | 7.000 | 1,315 | ||||||||||||||||||||||||||||||||||
a | The amount in sterling will be announced on 14 March 2011. |
BP Annual Report and Form 20-F 2010 179
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cents per share | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Basic earnings per share | (19.81 | ) | 88.49 | 112.59 | ||||||||
Diluted earnings per share | (19.81 | ) | 87.54 | 111.56 | ||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Profit (loss) attributable to BP shareholders | (3,719 | ) | 16,578 | 21,157 | ||||||||
Less dividend requirements on preference shares | 2 | 2 | 2 | |||||||||
Profit (loss) for the year attributable to BP ordinary shareholders | (3,721 | ) | 16,576 | 21,155 | ||||||||
shares thousand | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Basic weighted average number of ordinary shares | 18,785,912 | 18,732,459 | 18,789,827 | |||||||||
Potential dilutive effect of ordinary shares issuable under employee share schemes | 211,895 | 203,232 | 172,690 | |||||||||
18,997,807 | 18,935,691 | 18,962,517 | ||||||||||
180 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||||||||||||||||||
Oil depots, | ||||||||||||||||||||||||||||||||
Plant, | Fixtures, | storage | ||||||||||||||||||||||||||||||
Land | Oil and | machinery | fittings and | tanks and | ||||||||||||||||||||||||||||
and land | gas | and | office | Transport- | service | |||||||||||||||||||||||||||
improvements | Buildings | properties | equipment | equipment | ation | stations | Total | |||||||||||||||||||||||||
Cost | ||||||||||||||||||||||||||||||||
At 1 January 2010 | 3,786 | 2,918 | 157,197 | 41,599 | 3,022 | 12,441 | 10,295 | 231,258 | ||||||||||||||||||||||||
Exchange adjustments | (85 | ) | (68 | ) | 3 | 35 | (41 | ) | 28 | (72 | ) | (200 | ) | |||||||||||||||||||
Additions | 39 | 96 | 11,980 | 3,354 | 279 | 152 | 610 | 16,510 | ||||||||||||||||||||||||
Acquisitions | 2 | 3 | 1,931 | 41 | 5 | 15 | – | 1,997 | ||||||||||||||||||||||||
Transfers | – | – | 2,633 | – | – | – | – | 2,633 | ||||||||||||||||||||||||
Reclassified as assets held for sale | (6 | ) | (10 | ) | (6,610 | ) | (1,083 | ) | (87 | ) | (212 | ) | – | (8,008 | ) | |||||||||||||||||
Deletions | (176 | ) | (104 | ) | (6,950 | ) | (1,119 | ) | (213 | ) | (208 | ) | (1,181 | ) | (9,951 | ) | ||||||||||||||||
At 31 December 2010 | 3,560 | 2,835 | 160,184 | 42,827 | 2,965 | 12,216 | 9,652 | 234,239 | ||||||||||||||||||||||||
Depreciation | ||||||||||||||||||||||||||||||||
At 1 January 2010 | 571 | 1,389 | 86,975 | 18,903 | 1,893 | 7,852 | 5,400 | 122,983 | ||||||||||||||||||||||||
Exchange adjustments | 1 | (46 | ) | – | (19 | ) | (25 | ) | 16 | (13 | ) | (86 | ) | |||||||||||||||||||
Charge for the year | 34 | 82 | 8,024 | 1,492 | 291 | 268 | 606 | 10,797 | ||||||||||||||||||||||||
Impairment losses | 57 | 5 | 918 | 117 | 1 | – | 21 | 1,119 | ||||||||||||||||||||||||
Reclassified as assets held for sale | – | (8 | ) | (4,342 | ) | (514 | ) | (76 | ) | (97 | ) | – | (5,037 | ) | ||||||||||||||||||
Deletions | (91 | ) | (38 | ) | (3,528 | ) | (796 | ) | (208 | ) | (99 | ) | (940 | ) | (5,700 | ) | ||||||||||||||||
At 31 December 2010 | 572 | 1,384 | 88,047 | 19,183 | 1,876 | 7,940 | 5,074 | 124,076 | ||||||||||||||||||||||||
Net book amount at 31 December 2010 | 2,988 | 1,451 | 72,137 | 23,644 | 1,089 | 4,276 | 4,578 | 110,163 | ||||||||||||||||||||||||
Cost | ||||||||||||||||||||||||||||||||
At 1 January 2009 | 3,964 | 2,742 | 146,813 | 37,905 | 3,045 | 12,295 | 10,345 | 217,109 | ||||||||||||||||||||||||
Exchange adjustments | 148 | 85 | 2 | 877 | 83 | 66 | 546 | 1,807 | ||||||||||||||||||||||||
Additions | 59 | 313 | 11,928 | 3,743 | 145 | 115 | 739 | 17,042 | ||||||||||||||||||||||||
Transfers | – | – | 745 | – | – | – | – | 745 | ||||||||||||||||||||||||
Deletions | (385 | ) | (222 | ) | (2,291 | ) | (926 | ) | (251 | ) | (35 | ) | (1,335 | ) | (5,445 | ) | ||||||||||||||||
At 31 December 2009 | 3,786 | 2,918 | 157,197 | 41,599 | 3,022 | 12,441 | 10,295 | 231,258 | ||||||||||||||||||||||||
Depreciation | ||||||||||||||||||||||||||||||||
At 1 January 2009 | 598 | 1,313 | 79,955 | 17,298 | 1,696 | 7,542 | 5,507 | 113,909 | ||||||||||||||||||||||||
Exchange adjustments | 19 | 38 | – | 446 | 54 | 30 | 272 | 859 | ||||||||||||||||||||||||
Charge for the year | 31 | 102 | 8,951 | 1,372 | 302 | 289 | 618 | 11,665 | ||||||||||||||||||||||||
Impairment losses | 88 | 53 | 10 | 185 | 10 | 8 | 52 | 406 | ||||||||||||||||||||||||
Deletions | (165 | ) | (117 | ) | (1,941 | ) | (398 | ) | (169 | ) | (17 | ) | (1,049 | ) | (3,856 | ) | ||||||||||||||||
At 31 December 2009 | 571 | 1,389 | 86,975 | 18,903 | 1,893 | 7,852 | 5,400 | 122,983 | ||||||||||||||||||||||||
Net book amount at 31 December 2009 | 3,215 | 1,529 | 70,222 | 22,696 | 1,129 | 4,589 | 4,895 | 108,275 | ||||||||||||||||||||||||
Net book amount at 1 January 2009 | 3,366 | 1,429 | 66,858 | 20,607 | 1,349 | 4,753 | 4,838 | 103,200 | ||||||||||||||||||||||||
Assets held under finance leases at net book amount | ||||||||||||||||||||||||||||||||
included above | ||||||||||||||||||||||||||||||||
At 31 December 2010 | – | 14 | 236 | 386 | – | 7 | 18 | 661 | ||||||||||||||||||||||||
At 31 December 2009 | – | 14 | 225 | 110 | – | 7 | 19 | 375 | ||||||||||||||||||||||||
Decommissioning asset at net book amount | ||||||||||||||||||||||||||||||||
included above | Cost | Depreciation | Net | |||||||||||||||||||||||||||||
At 31 December 2010 | 9,237 | 4,585 | 4,652 | |||||||||||||||||||||||||||||
At 31 December 2009 | 7,968 | 4,129 | 3,839 | |||||||||||||||||||||||||||||
Assets under construction included above | ||||||||||||||||||||||||||||||||
At 31 December 2010 | 23,055 | |||||||||||||||||||||||||||||||
At 31 December 2009 | 19,120 | |||||||||||||||||||||||||||||||
BP Annual Report and Form 20-F 2010 181
Table of Contents
$ million | ||||||||
2010 | 2009 | |||||||
Cost | ||||||||
At 1 January | 10,199 | 9,878 | ||||||
Exchange adjustments | (154 | ) | 350 | |||||
Acquisitions | 335 | – | ||||||
Reclassified as assets held for sale | (87 | ) | – | |||||
Deletions | (116 | ) | (29 | ) | ||||
At 31 December | 10,177 | 10,199 | ||||||
Impairment losses | ||||||||
At 1 January | (1,579 | ) | – | |||||
Impairment losses for the year | – | (1,579 | ) | |||||
At 31 December | (1,579 | ) | (1,579 | ) | ||||
Net book amount at 31 December | 8,598 | 8,620 | ||||||
Net book amount at 1 January | 8,620 | 9,878 | ||||||
$ million | ||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||
Exploration | Exploration | |||||||||||||||||||||||
and appraisal | Other | and appraisal | Other | |||||||||||||||||||||
expenditure | intangibles | Total | expenditure | intangibles | Total | |||||||||||||||||||
Cost | ||||||||||||||||||||||||
At 1 January | 10,713 | 3,284 | 13,997 | 9,425 | 2,927 | 12,352 | ||||||||||||||||||
Exchange adjustments | 6 | (29 | ) | (23 | ) | 8 | 75 | 83 | ||||||||||||||||
Acquisitions | 982 | 118 | 1,100 | – | – | – | ||||||||||||||||||
Additions | 5,440 | 297 | 5,737 | 2,715 | 441 | 3,156 | ||||||||||||||||||
Transfers | (2,633 | ) | – | (2,633 | ) | (745 | ) | – | (745 | ) | ||||||||||||||
Reclassified as assets held for sale | (134 | ) | (4 | ) | (138 | ) | – | – | – | |||||||||||||||
Deletions | (898 | ) | (263 | ) | (1,161 | ) | (690 | ) | (159 | ) | (849 | ) | ||||||||||||
At 31 December | 13,476 | 3,403 | 16,879 | 10,713 | 3,284 | 13,997 | ||||||||||||||||||
Amortization | ||||||||||||||||||||||||
At 1 January | 325 | 2,124 | 2,449 | 394 | 1,698 | 2,092 | ||||||||||||||||||
Exchange adjustments | – | (11 | ) | (11 | ) | – | 32 | 32 | ||||||||||||||||
Charge for the year | 375 | 367 | 742 | 593 | 441 | 1,034 | ||||||||||||||||||
Impairment losses | – | – | – | – | 90 | 90 | ||||||||||||||||||
Reclassified as assets held for sale | – | (3 | ) | (3 | ) | – | – | – | ||||||||||||||||
Deletions | (350 | ) | (246 | ) | (596 | ) | (662 | ) | (137 | ) | (799 | ) | ||||||||||||
At 31 December | 350 | 2,231 | 2,581 | 325 | 2,124 | 2,449 | ||||||||||||||||||
Net book amount at 31 December | 13,126 | 1,172 | 14,298 | 10,388 | 1,160 | 11,548 | ||||||||||||||||||
Net book amount at 1 January | 10,388 | 1,160 | 11,548 | 9,031 | 1,229 | 10,260 | ||||||||||||||||||
182 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||||||
2010a | 2009 | 2008 | ||||||||||||||||||
TNK-BP | Other | Total | ||||||||||||||||||
Sales and other operating revenues | 11,679 | 9,396 | 25,936 | 10,796 | 36,732 | |||||||||||||||
Profit before interest and taxation | 1,730 | 1,815 | 3,588 | 1,343 | 4,931 | |||||||||||||||
Finance costs | 122 | 155 | 275 | 185 | 460 | |||||||||||||||
Profit before taxation | 1,608 | 1,660 | 3,313 | 1,158 | 4,471 | |||||||||||||||
Taxation | 433 | 374 | 882 | 397 | 1,279 | |||||||||||||||
Minority interest | – | – | 169 | – | 169 | |||||||||||||||
Profit for the year | 1,175 | 1,286 | 2,262 | 761 | 3,023 | |||||||||||||||
Non-current assets | 12,054 | 15,857 | ||||||||||||||||||
Current assets | 3,595 | 4,124 | ||||||||||||||||||
Total assets | 15,649 | 19,981 | ||||||||||||||||||
Current liabilities | 1,615 | 2,276 | ||||||||||||||||||
Non-current liabilities | 2,701 | 3,768 | ||||||||||||||||||
Total liabilities | 4,316 | 6,044 | ||||||||||||||||||
11,333 | 13,937 | |||||||||||||||||||
Group investment in jointly controlled entities | ||||||||||||||||||||
Group share of net assets (as above) | 11,333 | 13,937 | ||||||||||||||||||
Loans made by group companies to jointly controlled entities | 953 | 1,359 | ||||||||||||||||||
12,286 | 15,296 | |||||||||||||||||||
a | Balance sheet information shown above excludes data relating to jointly controlled entities reclassified as assets held for sale as at 31 December 2010. Income statement information shown above includes data relating to jointly controlled entities reclassified as assets held for sale during 2010 for the period from 1 January 2010 up until their date of reclassification as held for sale. |
$ million | ||||||||||||||||||||||||
Sales to jointly controlled entities | 2010 | 2009 | 2008 | |||||||||||||||||||||
Amount | Amount | Amount | ||||||||||||||||||||||
receivable at | receivable at | receivable at | ||||||||||||||||||||||
Product | Sales | 31 December | Sales | 31 December | Sales | 31 December | ||||||||||||||||||
LNG, crude oil and oil products, natural gas, employee services | 3,804 | 1,352 | 2,182 | 1,328 | 2,971 | 1,036 | ||||||||||||||||||
$ million | ||||||||||||||||||||||||
Purchases from jointly controlled entities | 2010 | 2009 | 2008 | |||||||||||||||||||||
Amount | Amount | Amount | ||||||||||||||||||||||
payable at | payable at | payable at | ||||||||||||||||||||||
Product | Purchases | 31 Decembera | Purchases | 31 Decembera | Purchases | 31 Decembera | ||||||||||||||||||
LNG, crude oil and oil products, natural gas, refinery operating costs, plant processing fees | 8,063 | 683 | 5,377 | 214 | 9,115 | 182 | ||||||||||||||||||
a | Amounts payable to jointly controlled entities shown above exclude $2,583 million (2009 $2,509 million and 2008 $2,365 million) relating to BP’s contribution on the establishment of the Sunrise Oil Sands joint venture. |
The terms of the outstanding balances receivable from jointly controlled entities are typically 30 to 45 days, except for a receivable from Ruhr Oel of $585 million (2009 $419 million), which will be paid over several years as it relates partly to pension payments. The balances are unsecured and will be settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in respect of bad or doubtful debts. Dividends receivable are not included in the above balances. |
BP Annual Report and Form 20-F 2010 183
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$ million | ||||||||||||||||||||||||||||
2010a | 2009 | 2008 | ||||||||||||||||||||||||||
TNK-BP | Other | Total | TNK-BP | Other | Total | |||||||||||||||||||||||
Sales and other operating revenues | 22,323 | 10,031 | 32,354 | 17,377 | 8,301 | 25,678 | 11,709 | |||||||||||||||||||||
Profit before interest and taxation | 3,866 | 1,215 | 5,081 | 3,178 | 811 | 3,989 | 1,065 | |||||||||||||||||||||
Finance costs | 128 | 22 | 150 | 220 | 19 | 239 | 33 | |||||||||||||||||||||
Profit before taxation | 3,738 | 1,193 | 4,931 | 2,958 | 792 | 3,750 | 1,032 | |||||||||||||||||||||
Taxation | 913 | 228 | 1,141 | 871 | 125 | 996 | 234 | |||||||||||||||||||||
Minority interest | 208 | – | 208 | 139 | – | 139 | – | |||||||||||||||||||||
Profit for the year | 2,617 | 965 | 3,582 | 1,948 | 667 | 2,615 | 798 | |||||||||||||||||||||
Non-current assets | 14,686 | 4,024 | 18,710 | 13,437 | 4,573 | 18,010 | ||||||||||||||||||||||
Current assets | 4,500 | 1,989 | 6,489 | 4,205 | 1,887 | 6,092 | ||||||||||||||||||||||
Total assets | 19,186 | 6,013 | 25,199 | 17,642 | 6,460 | 24,102 | ||||||||||||||||||||||
Current liabilities | 3,284 | 1,888 | 5,172 | 3,122 | 1,640 | 4,762 | ||||||||||||||||||||||
Non-current liabilities | 5,283 | 1,914 | 7,197 | 4,797 | 2,277 | 7,074 | ||||||||||||||||||||||
Total liabilities | 8,567 | 3,802 | 12,369 | 7,919 | 3,917 | 11,836 | ||||||||||||||||||||||
Minority interest | 624 | – | 624 | 582 | – | 582 | ||||||||||||||||||||||
9,995 | 2,211 | 12,206 | 9,141 | 2,543 | 11,684 | |||||||||||||||||||||||
Group investment in associates | ||||||||||||||||||||||||||||
Group share of net assets (as above) | 9,995 | 2,211 | 12,206 | 9,141 | 2,543 | 11,684 | ||||||||||||||||||||||
Loans made by group companies to associates | – | 1,129 | 1,129 | – | 1,279 | 1,279 | ||||||||||||||||||||||
9,995 | 3,340 | 13,335 | 9,141 | 3,822 | 12,963 | |||||||||||||||||||||||
a | Balance sheet information shown above excludes data relating to associates reclassified as held for sale as at 31 December 2010. Income statement information shown above includes data relating to associates reclassified as assets held for sale during 2010 for the period from 1 January 2010 up until the date of reclassification as held for sale. |
$ million | ||||||||||||||||||||||||
Sales to associates | 2010 | 2009 | 2008 | |||||||||||||||||||||
Amount | Amount | Amount | ||||||||||||||||||||||
receivable at | receivable at | receivable at | ||||||||||||||||||||||
Product | Sales | 31 December | Sales | 31 December | Sales | 31 December | ||||||||||||||||||
LNG, crude oil and oil products, natural gas, employee services | 3,561 | 330 | 2,801 | 320 | 3,248 | 219 | ||||||||||||||||||
Purchases from associates | 2010 | 2009 | 2008 | |||||||||||||||||||||
Amount | Amount | Amount | ||||||||||||||||||||||
payable at | payable at | payable at | ||||||||||||||||||||||
Product | Purchases | 31 December | Purchases | 31 December | Purchases | 31 December | ||||||||||||||||||
Crude oil and oil products, natural gas, transportation tariff | 4,889 | 633 | 5,110 | 614 | 4,635 | 295 | ||||||||||||||||||
184 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||||||||||||||
At 31 December | 2010 | |||||||||||||||||||||||||||
Financial | ||||||||||||||||||||||||||||
Available-for- | At fair value | Derivative | liabilities | Total | ||||||||||||||||||||||||
Loans and | sale financial | through profit | hedging | measured at | carrying | |||||||||||||||||||||||
Note | receivables | assets | and loss | instruments | amortized cost | amount | ||||||||||||||||||||||
Financial assets | ||||||||||||||||||||||||||||
Other investments – equity shares | 28 | – | 1,191 | – | – | – | 1,191 | |||||||||||||||||||||
– other | 28 | – | 1,532 | – | – | – | 1,532 | |||||||||||||||||||||
Loans | 1,141 | – | – | – | – | 1,141 | ||||||||||||||||||||||
Trade and other receivables | 30 | 32,380 | – | – | – | – | 32,380 | |||||||||||||||||||||
Derivative financial instruments | 34 | – | – | 7,222 | 1,344 | – | 8,566 | |||||||||||||||||||||
Cash and cash equivalents | 31 | 13,462 | 5,094 | – | – | – | 18,556 | |||||||||||||||||||||
Financial liabilities | ||||||||||||||||||||||||||||
Trade and other payables | 33 | – | – | – | – | (56,499 | ) | (56,499 | ) | |||||||||||||||||||
Derivative financial instruments | 34 | – | – | (7,254 | ) | (279 | ) | – | (7,533 | ) | ||||||||||||||||||
Accruals | – | – | – | – | (6,249 | ) | (6,249 | ) | ||||||||||||||||||||
Finance debt | 35 | – | – | – | – | (39,139 | ) | (39,139 | ) | |||||||||||||||||||
46,983 | 7,817 | (32 | ) | 1,065 | (101,887 | ) | (46,054 | ) | ||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||
At 31 December | 2009 | |||||||||||||||||||||||||||
Financial | ||||||||||||||||||||||||||||
Available-for- | At fair value | Derivative | liabilities | Total | ||||||||||||||||||||||||
Loans and | sale financial | through profit | hedging | measured at | carrying | |||||||||||||||||||||||
Note | receivables | assets | and loss | instruments | amortized cost | amount | ||||||||||||||||||||||
Financial assets | ||||||||||||||||||||||||||||
Other investments | 28 | – | 1,567 | – | – | – | 1,567 | |||||||||||||||||||||
Loans | 1,288 | – | – | – | – | 1,288 | ||||||||||||||||||||||
Trade and other receivables | 30 | 31,016 | – | – | – | – | 31,016 | |||||||||||||||||||||
Derivative financial instruments | 34 | – | – | 7,960 | 972 | – | 8,932 | |||||||||||||||||||||
Cash and cash equivalents | 31 | 6,570 | 1,769 | – | – | – | 8,339 | |||||||||||||||||||||
Financial liabilities | ||||||||||||||||||||||||||||
Trade and other payables | 33 | – | – | – | – | (34,325 | ) | (34,325 | ) | |||||||||||||||||||
Derivative financial instruments | 34 | – | – | (7,389 | ) | (766 | ) | – | (8,155 | ) | ||||||||||||||||||
Accruals | – | – | – | – | (6,905 | ) | (6,905 | ) | ||||||||||||||||||||
Finance debt | 35 | – | – | – | – | (34,627 | ) | (34,627 | ) | |||||||||||||||||||
38,874 | 3,336 | 571 | 206 | (75,857 | ) | (32,870 | ) | |||||||||||||||||||||
BP Annual Report and Form 20-F 2010 185
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$ million | ||||||||||||||||||||||||||||||||
Value at risk for 1 day at 95% confidence interval | 2010 | 2009 | ||||||||||||||||||||||||||||||
High | Low | Average | Year end | High | Low | Average | Year end | |||||||||||||||||||||||||
Group trading | 70 | 15 | 34 | 33 | 79 | 24 | 45 | 30 | ||||||||||||||||||||||||
Gas price trading | 62 | 7 | 27 | 18 | 62 | 11 | 28 | 26 | ||||||||||||||||||||||||
Oil price trading | 39 | 10 | 19 | 25 | 75 | 11 | 29 | 13 | ||||||||||||||||||||||||
At 31 December | 2010 | 2009 | ||||||
Remaining contract terms | 4 years and 5 months to 7 years and 9 months | 9 months to 8 years 9 months | ||||||
Contractual/notional amount | 1,688 million therms | 2,460 million therms | ||||||
$ million | ||||||||||||||||||||||||||||||||
At 31 December | 2010 | 2009 | ||||||||||||||||||||||||||||||
Discount | Discount | |||||||||||||||||||||||||||||||
Gas price | Oil price | Power price | rate | Gas price | Oil price | Power price | rate | |||||||||||||||||||||||||
Favourable 10% change | 145 | 48 | 10 | 10 | 175 | 26 | 23 | 20 | ||||||||||||||||||||||||
Unfavourable 10% change | (180 | ) | (68 | ) | (10 | ) | (10 | ) | (215 | ) | (43 | ) | (19 | ) | (20 | ) | ||||||||||||||||
186 BP Annual Report and Form 20-F 2010
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BP Annual Report and Form 20-F 2010 187
Table of Contents
$ million | ||||||||
Trade and other receivables at 31 December | 2010 | 2009 | ||||||
Neither impaired nor past due | 30,181 | 29,426 | ||||||
Impaired (net of valuation allowance) | 67 | 91 | ||||||
Not impaired and past due in the following periods | ||||||||
within 30 days | 1,358 | 808 | ||||||
31 to 60 days | 249 | 151 | ||||||
61 to 90 days | 101 | 76 | ||||||
over 90 days | 424 | 464 | ||||||
32,380 | 31,016 | |||||||
188 BP Annual Report and Form 20-F 2010
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$ million | ||||||||
2010 | 2009 | |||||||
At 1 January | 430 | 391 | ||||||
Exchange adjustments | (9 | ) | 12 | |||||
Charge for the year | 150 | 157 | ||||||
Utilization | (143 | ) | (130 | ) | ||||
At 31 December | 428 | 430 | ||||||
$ million | ||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||
Trade and | Trade and | |||||||||||||||||||||||
other | Finance | other | Finance | |||||||||||||||||||||
payablesa | Accruals | debt | payables | Accruals | debt | |||||||||||||||||||
Within one year | 42,691 | 5,612 | 9,353 | 31,413 | 6,202 | 9,790 | ||||||||||||||||||
1 to 2 years | 6,549 | 278 | 6,816 | 1,059 | 231 | 6,861 | ||||||||||||||||||
2 to 3 years | 6,242 | 125 | 7,542 | 1,089 | 106 | 5,359 | ||||||||||||||||||
3 to 4 years | 411 | 42 | 6,105 | 566 | 78 | 5,528 | ||||||||||||||||||
4 to 5 years | 365 | 28 | 5,494 | 67 | 49 | 3,151 | ||||||||||||||||||
5 to 10 years | 323 | 110 | 6,642 | 85 | 163 | 5,723 | ||||||||||||||||||
Over 10 years | 25 | 54 | 724 | 46 | 76 | 1,150 | ||||||||||||||||||
56,606 | 6,249 | 42,676 | 34,325 | 6,905 | 37,562 | |||||||||||||||||||
a | Trade and other payables at 31 December 2010 includes the Gulf of Mexico oil spill trust fund liability which is payable as follows: $5,008 million within one year; $5,000 million payable in 1 to 2 years and $5,000 million payable in 2 to 3 years. |
BP Annual Report and Form 20-F 2010 189
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$ million | ||||||||
2010 | 2009 | |||||||
Within one year | 986 | 2,826 | ||||||
1 to 2 years | 1,682 | 1,395 | ||||||
2 to 3 years | 1,358 | 1,669 | ||||||
3 to 4 years | 1,124 | 1,349 | ||||||
4 to 5 years | 295 | 1,104 | ||||||
5 to 10 years | 947 | 322 | ||||||
6,392 | 8,665 | |||||||
$ million | ||||||||||||
2010 | 2009 | |||||||||||
Current | Non-current | Non-current | ||||||||||
Listed | – | 953 | 1,296 | |||||||||
Unlisted | 1,532 | 238 | 271 | |||||||||
1,532 | 1,191 | 1,567 | ||||||||||
$ million | ||||||||
2010 | 2009 | |||||||
Crude oil | 8,969 | 6,237 | ||||||
Natural gas | 112 | 105 | ||||||
Refined petroleum and petrochemical products | 13,997 | 12,337 | ||||||
23,078 | 18,679 | |||||||
Supplies | 1,669 | 1,661 | ||||||
24,747 | 20,340 | |||||||
Trading inventories | 1,471 | 2,265 | ||||||
26,218 | 22,605 | |||||||
Cost of inventories expensed in the income statement | 216,211 | 163,772 | ||||||
190 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Current | Non-current | Current | Non-current | |||||||||||||
Financial assets | ||||||||||||||||
Trade receivables | 24,255 | – | 22,604 | – | ||||||||||||
Amounts receivable from jointly controlled entities | 751 | 601 | 1,317 | 11 | ||||||||||||
Amounts receivable from associates | 448 | 220 | 417 | 298 | ||||||||||||
Other receivables | 4,763 | 1,342 | 4,949 | 1,420 | ||||||||||||
30,217 | 2,163 | 29,287 | 1,729 | |||||||||||||
Non-financial assets | ||||||||||||||||
Gulf of Mexico oil spill trust fund reimbursement asseta | 5,943 | 3,601 | – | – | ||||||||||||
Other receivables | 389 | 534 | 244 | – | ||||||||||||
6,332 | 4,135 | 244 | – | |||||||||||||
36,549 | 6,298 | 29,531 | 1,729 | |||||||||||||
a | See Note 2 for further information. |
$ million | ||||||||
2010 | 2009 | |||||||
Cash at bank and in hand | 8,209 | 3,359 | ||||||
Term bank deposits | 5,253 | 3,211 | ||||||
Other cash equivalents | 5,094 | 1,769 | ||||||
18,556 | 8,339 | |||||||
$ million | ||||||||||||||||||||||||
2010 | 2009 | 2008 | ||||||||||||||||||||||
Doubtful | Fixed assets – | Doubtful | Fixed assets – | Doubtful | Fixed assets – | |||||||||||||||||||
debts | investments | debts | investments | debts | investments | |||||||||||||||||||
At 1 January | 430 | 349 | 391 | 935 | 406 | 146 | ||||||||||||||||||
Charged to costs and expenses | 150 | 376 | 157 | 66 | 191 | 647 | ||||||||||||||||||
Charged to other accountsa | (9 | ) | (3 | ) | 12 | 6 | (32 | ) | 143 | |||||||||||||||
Deductions | (143 | ) | (182 | ) | (130 | ) | (658 | ) | (174 | ) | (1 | ) | ||||||||||||
At 31 December | 428 | 540 | 430 | 349 | 391 | 935 | ||||||||||||||||||
a | Principally currency transactions. |
BP Annual Report and Form 20-F 2010 191
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$ million | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Current | Non-current | Current | Non-current | |||||||||||||
Financial liabilities | ||||||||||||||||
Trade payables | 27,510 | – | 22,886 | – | ||||||||||||
Amounts payable to jointly controlled entities | 1,361 | 1,905 | 304 | 2,419 | ||||||||||||
Amounts payable to associates | 712 | 220 | 692 | 298 | ||||||||||||
Gulf of Mexico oil spill trust fund liabilitya | 5,002 | 9,899 | – | – | ||||||||||||
Other payables | 8,100 | 1,790 | 7,531 | 195 | ||||||||||||
42,685 | 13,814 | 31,413 | 2,912 | |||||||||||||
Non-financial liabilities | ||||||||||||||||
Other payables | 3,644 | 471 | 3,791 | 286 | ||||||||||||
46,329 | 14,285 | 35,204 | 3,198 | |||||||||||||
a | See Note 2 for further information. |
$ million | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Fair | Fair | Fair | Fair | |||||||||||||
value | value | value | value | |||||||||||||
asset | liability | asset | liability | |||||||||||||
Derivatives held for trading | ||||||||||||||||
Currency derivatives | 194 | (280 | ) | 318 | (226 | ) | ||||||||||
Oil price derivatives | 1,099 | (877 | ) | 1,140 | (1,191 | ) | ||||||||||
Natural gas price derivatives | 5,350 | (3,951 | ) | 5,636 | (3,960 | ) | ||||||||||
Power price derivatives | 561 | (432 | ) | 682 | (497 | ) | ||||||||||
Other derivatives | – | (89 | ) | 47 | (47 | ) | ||||||||||
7,204 | (5,629 | ) | 7,823 | (5,921 | ) | |||||||||||
Embedded derivative commodity price contracts | 18 | (1,625 | ) | 137 | (1,468 | ) | ||||||||||
Cash flow hedges | ||||||||||||||||
Currency forwards, futures and cylinders | 134 | (124 | ) | 182 | (114 | ) | ||||||||||
Cross-currency interest rate swaps | 101 | (1 | ) | 44 | (298 | ) | ||||||||||
235 | (125 | ) | 226 | (412 | ) | |||||||||||
Fair value hedges | ||||||||||||||||
Currency forwards, futures and swaps | 772 | (80 | ) | 490 | (232 | ) | ||||||||||
Interest rate swaps | 337 | (74 | ) | 256 | (122 | ) | ||||||||||
1,109 | (154 | ) | 746 | (354 | ) | |||||||||||
8,566 | (7,533 | ) | 8,932 | (8,155 | ) | |||||||||||
Of which – current | 4,356 | (3,856 | ) | 4,967 | (4,681 | ) | ||||||||||
– non-current | 4,210 | (3,677 | ) | 3,965 | (3,474 | ) | ||||||||||
192 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Currency derivatives | 124 | 41 | 18 | 11 | – | – | 194 | |||||||||||||||||||||
Oil price derivatives | 797 | 128 | 82 | 64 | 21 | 7 | 1,099 | |||||||||||||||||||||
Natural gas price derivatives | 2,591 | 1,100 | 652 | 375 | 231 | 401 | 5,350 | |||||||||||||||||||||
Power price derivatives | 389 | 125 | 35 | 11 | 1 | – | 561 | |||||||||||||||||||||
3,901 | 1,394 | 787 | 461 | 253 | 408 | 7,204 | ||||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Currency derivatives | 162 | 83 | 33 | 22 | 16 | 2 | 318 | |||||||||||||||||||||
Oil price derivatives | 814 | 136 | 69 | 59 | 44 | 18 | 1,140 | |||||||||||||||||||||
Natural gas price derivatives | 2,958 | 1,059 | 582 | 354 | 186 | 497 | 5,636 | |||||||||||||||||||||
Power price derivatives | 496 | 139 | 32 | 12 | 3 | – | 682 | |||||||||||||||||||||
Other derivatives | 47 | – | – | – | – | – | 47 | |||||||||||||||||||||
4,477 | 1,417 | 716 | 447 | 249 | 517 | 7,823 | ||||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Currency derivatives | (228 | ) | (6 | ) | (46 | ) | – | – | – | (280 | ) | |||||||||||||||||
Oil price derivatives | (794 | ) | (76 | ) | (6 | ) | (1 | ) | – | – | (877 | ) | ||||||||||||||||
Natural gas price derivatives | (2,174 | ) | (741 | ) | (484 | ) | (161 | ) | (114 | ) | (277 | ) | (3,951 | ) | ||||||||||||||
Power price derivatives | (287 | ) | (103 | ) | (32 | ) | (9 | ) | (1 | ) | – | (432 | ) | |||||||||||||||
Other derivatives | – | (29 | ) | (60 | ) | – | – | – | (89 | ) | ||||||||||||||||||
(3,483 | ) | (955 | ) | (628 | ) | (171 | ) | (115 | ) | (277 | ) | (5,629 | ) | |||||||||||||||
$ million | ||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Currency derivatives | (110 | ) | (58 | ) | (20 | ) | (32 | ) | (4 | ) | (2 | ) | (226 | ) | ||||||||||||||
Oil price derivatives | (1,083 | ) | (67 | ) | (29 | ) | (11 | ) | (1 | ) | – | (1,191 | ) | |||||||||||||||
Natural gas price derivatives | (2,381 | ) | (607 | ) | (248 | ) | (222 | ) | (78 | ) | (424 | ) | (3,960 | ) | ||||||||||||||
Power price derivatives | (335 | ) | (109 | ) | (39 | ) | (11 | ) | (3 | ) | – | (497 | ) | |||||||||||||||
Other derivatives | (47 | ) | – | – | – | – | – | (47 | ) | |||||||||||||||||||
(3,956 | ) | (841 | ) | (336 | ) | (276 | ) | (86 | ) | (426 | ) | (5,921 | ) | |||||||||||||||
BP Annual Report and Form 20-F 2010 193
Table of Contents
$ million | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Natural | Natural | |||||||||||||||
Oil price | gas price | Oil price | gas price | |||||||||||||
Fair value of contracts not recognized through the income statement at 1 January | 21 | 33 | 32 | 83 | ||||||||||||
Fair value of new contracts at inception not recognized in the income statement | – | 39 | – | (14 | ) | |||||||||||
Fair value recognized in the income statement | (21 | ) | (3 | ) | (11 | ) | (36 | ) | ||||||||
Fair value of contracts not recognized through profit at 31 December | – | 69 | 21 | 33 | ||||||||||||
Level 1 – | using quoted prices in active markets for identical assets or liabilities. | |||
Level 2 – | using inputs for the asset or liability, other than quoted prices, that are observable either directly (i.e. as prices) or indirectly (i.e. derived from prices). | |||
Level 3 – | using inputs for the asset or liability that are not based on observable market data such as prices based on internal models or other valuation methods. |
$ million | ||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Fair value of derivative assets | ||||||||||||||||||||||||||||
Level 1 | 122 | 36 | 12 | 5 | – | – | 175 | |||||||||||||||||||||
Level 2 | 7,132 | 1,928 | 639 | 239 | 109 | – | 10,047 | |||||||||||||||||||||
Level 3 | 341 | 314 | 296 | 267 | 165 | 410 | 1,793 | |||||||||||||||||||||
7,595 | 2,278 | 947 | 511 | 274 | 410 | 12,015 | ||||||||||||||||||||||
Less: netting by counterparty | (3,694 | ) | (884 | ) | (160 | ) | (50 | ) | (21 | ) | (2 | ) | (4,811 | ) | ||||||||||||||
3,901 | 1,394 | 787 | 461 | 253 | 408 | 7,204 | ||||||||||||||||||||||
Fair value of derivative liabilities | ||||||||||||||||||||||||||||
Level 1 | (239 | ) | (6 | ) | (46 | ) | – | – | – | (291 | ) | |||||||||||||||||
Level 2 | (6,733 | ) | (1,685 | ) | (617 | ) | (107 | ) | (44 | ) | – | (9,186 | ) | |||||||||||||||
Level 3 | (205 | ) | (148 | ) | (125 | ) | (114 | ) | (92 | ) | (279 | ) | (963 | ) | ||||||||||||||
(7,177 | ) | (1,839 | ) | (788 | ) | (221 | ) | (136 | ) | (279 | ) | (10,440 | ) | |||||||||||||||
Less: netting by counterparty | 3,694 | 884 | 160 | 50 | 21 | 2 | 4,811 | |||||||||||||||||||||
(3,483 | ) | (955 | ) | (628 | ) | (171 | ) | (115 | ) | (277 | ) | (5,629 | ) | |||||||||||||||
Net fair value | 418 | 439 | 159 | 290 | 138 | 131 | 1,575 | |||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Fair value of derivative assets | ||||||||||||||||||||||||||||
Level 1 | 163 | 76 | 23 | 17 | 10 | 1 | 290 | |||||||||||||||||||||
Level 2 | 9,544 | 2,182 | 915 | 357 | 146 | – | 13,144 | |||||||||||||||||||||
Level 3 | 264 | 188 | 162 | 148 | 128 | 527 | 1,417 | |||||||||||||||||||||
9,971 | 2,446 | 1,100 | 522 | 284 | 528 | 14,851 | ||||||||||||||||||||||
Less: netting by counterparty | (5,494 | ) | (1,029 | ) | (384 | ) | (75 | ) | (35 | ) | (11 | ) | (7,028 | ) | ||||||||||||||
4,477 | 1,417 | 716 | 447 | 249 | 517 | 7,823 | ||||||||||||||||||||||
Fair value of derivative liabilities | ||||||||||||||||||||||||||||
Level 1 | (95 | ) | (39 | ) | (14 | ) | (24 | ) | – | (1 | ) | (173 | ) | |||||||||||||||
Level 2 | (9,086 | ) | (1,681 | ) | (597 | ) | (234 | ) | (47 | ) | – | (11,645 | ) | |||||||||||||||
Level 3 | (269 | ) | (150 | ) | (109 | ) | (93 | ) | (74 | ) | (436 | ) | (1,131 | ) | ||||||||||||||
(9,450 | ) | (1,870 | ) | (720 | ) | (351 | ) | (121 | ) | (437 | ) | (12,949 | ) | |||||||||||||||
Less: netting by counterparty | 5,494 | 1,029 | 384 | 75 | 35 | 11 | 7,028 | |||||||||||||||||||||
(3,956 | ) | (841 | ) | (336 | ) | (276 | ) | (86 | ) | (426 | ) | (5,921 | ) | |||||||||||||||
Net fair value | 521 | 576 | 380 | 171 | 163 | 91 | 1,902 | |||||||||||||||||||||
194 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||
Oil | Natural gas | Power | ||||||||||||||
price | price | price | Total | |||||||||||||
Net fair value of contracts at 1 January 2010 | 215 | 72 | (1 | ) | 286 | |||||||||||
Gains (losses) recognized in the income statement | 21 | 637 | (1 | ) | 657 | |||||||||||
Settlements | (54 | ) | (11 | ) | 1 | (64 | ) | |||||||||
Purchases | – | – | – | – | ||||||||||||
Sales | – | – | – | – | ||||||||||||
Transfers out of level 3 | (18 | ) | (38 | ) | – | (56 | ) | |||||||||
Transfers into level 3 | – | 4 | – | 4 | ||||||||||||
Exchange adjustments | – | 3 | – | 3 | ||||||||||||
Net fair value of contracts at 31 December 2010 | 164 | 667 | (1 | ) | 830 | |||||||||||
$ million | ||||||||||||||||||||||||
Oil | Natural gas | Power | ||||||||||||||||||||||
Currency | price | price | price | Other | Total | |||||||||||||||||||
Net fair value of contracts at 1 January 2009 | 3 | 149 | 17 | – | – | 169 | ||||||||||||||||||
Gains (losses) recognized in the income statement | (1 | ) | 205 | 91 | – | (1 | ) | 294 | ||||||||||||||||
Settlements | – | (91 | ) | (5 | ) | – | – | (96 | ) | |||||||||||||||
Purchases | – | – | – | 1 | – | 1 | ||||||||||||||||||
Sales | – | – | – | (2 | ) | 1 | (1 | ) | ||||||||||||||||
Transfers out of level 3 | (2 | ) | (50 | ) | (4 | ) | – | – | (56 | ) | ||||||||||||||
Transfers into level 3 | – | 2 | (25 | ) | – | – | (23 | ) | ||||||||||||||||
Exchange adjustments | – | – | (2 | ) | – | – | (2 | ) | ||||||||||||||||
Net fair value of contracts at 31 December 2009 | – | 215 | 72 | (1 | ) | – | 286 | |||||||||||||||||
$ million | ||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Assets | 18 | – | – | – | – | – | 18 | |||||||||||||||||||||
Liabilities | (325 | ) | (326 | ) | (285 | ) | (281 | ) | (212 | ) | (196 | ) | (1,625 | ) | ||||||||||||||
Net fair value | (307 | ) | (326 | ) | (285 | ) | (281 | ) | (212 | ) | (196 | ) | (1,607 | ) | ||||||||||||||
$ million | ||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||
Less than | Over | |||||||||||||||||||||||||||
1 year | 1-2 years | 2-3 years | 3-4 years | 4-5 years | 5 years | Total | ||||||||||||||||||||||
Assets | 134 | – | – | – | – | 3 | 137 | |||||||||||||||||||||
Liabilities | (154 | ) | (236 | ) | (231 | ) | (227 | ) | (232 | ) | (388 | ) | (1,468 | ) | ||||||||||||||
Net fair value | (20 | ) | (236 | ) | (231 | ) | (227 | ) | (232 | ) | (385 | ) | (1,331 | ) | ||||||||||||||
BP Annual Report and Form 20-F 2010 195
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$ million | ||||||||
2010 | 2009 | |||||||
Commodity | Commodity | |||||||
price | price | |||||||
Net fair value of contracts at 1 January | (1,331 | ) | (1,892 | ) | ||||
Settlements | 37 | 221 | ||||||
Gains (losses) recognized in the income statementa | (350 | ) | 535 | |||||
Exchange adjustments | 37 | (195 | ) | |||||
Net fair value of contracts at 31 December | (1,607 | ) | (1,331 | ) | ||||
a | The amount for gains (losses) recognized in the income statement for 2009 includes a loss of $224 million arising as a result of refinements in the modelling and valuation methods used for these contracts. |
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Commodity price embedded derivatives | (309 | ) | 607 | (106 | ) | |||||||
Interest rate embedded derivatives | – | – | (5 | ) | ||||||||
Fair value (loss) gain | (309 | ) | 607 | (111 | ) | |||||||
196 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||
Current | Non-current | Total | Current | Non-current | Total | |||||||||||||||||||
Borrowings | 8,312 | 30,017 | 38,329 | 9,018 | 25,020 | 34,038 | ||||||||||||||||||
Net obligations under finance leases | 117 | 693 | 810 | 91 | 498 | 589 | ||||||||||||||||||
8,429 | 30,710 | 39,139 | 9,109 | 25,518 | 34,627 | |||||||||||||||||||
Disposal deposits | 6,197 | – | 6,197 | – | – | – | ||||||||||||||||||
14,626 | 30,710 | 45,336 | 9,109 | 25,518 | 34,627 | |||||||||||||||||||
Fixed rate debt | Floating rate debt | Total | ||||||||||||||||||||||
Weighted | ||||||||||||||||||||||||
Weighted | average | Weighted | ||||||||||||||||||||||
average | time for | average | ||||||||||||||||||||||
interest | which rate | interest | ||||||||||||||||||||||
rate | is fixed | Amount | rate | Amount | Amount | |||||||||||||||||||
% | Years | $ million | % | $ million | $ million | |||||||||||||||||||
2010 | ||||||||||||||||||||||||
US dollar | 4 | 5 | 14,797 | 1 | 21,076 | 35,873 | ||||||||||||||||||
Euro | 4 | 3 | 53 | 2 | 2,988 | 3,041 | ||||||||||||||||||
Other currencies | 6 | 18 | 140 | 4 | 85 | 225 | ||||||||||||||||||
14,990 | 24,149 | 39,139 | ||||||||||||||||||||||
2009 | ||||||||||||||||||||||||
US dollar | 4 | 4 | 12,525 | 1 | 20,566 | 33,091 | ||||||||||||||||||
Euro | 4 | 2 | 63 | 2 | 1,199 | 1,262 | ||||||||||||||||||
Other currencies | 6 | 14 | 171 | 3 | 103 | 274 | ||||||||||||||||||
12,759 | 21,868 | 34,627 | ||||||||||||||||||||||
$ million | ||||||||
2010 | 2009 | |||||||
Future minimum lease payments payable within | ||||||||
1 year | 153 | 109 | ||||||
2 to 5 years | 535 | 329 | ||||||
Thereafter | 438 | 407 | ||||||
1,126 | 845 | |||||||
Less finance charges | 316 | 256 | ||||||
Net obligations | 810 | 589 | ||||||
Of which – payable within 1 year | 117 | 91 | ||||||
– payable within 2 to 5 years | 404 | 202 | ||||||
– payable thereafter | 289 | 296 | ||||||
BP Annual Report and Form 20-F 2010 197
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$ million | ||||||||||||||||
2010 | 2009 | |||||||||||||||
Carrying | Carrying | |||||||||||||||
Fair value | amount | Fair value | amount | |||||||||||||
Short-term borrowings | 1,453 | 1,453 | 5,144 | 5,144 | ||||||||||||
Long-term borrowings | 37,600 | 36,876 | 29,918 | 28,894 | ||||||||||||
Net obligations under finance leases | 928 | 810 | 599 | 589 | ||||||||||||
Total finance debt | 39,981 | 39,139 | 35,661 | 34,627 | ||||||||||||
$ million | ||||||||
At 31 December | 2010 | 2009 | ||||||
Gross debt | 45,336 | 34,627 | ||||||
Less: Cash and cash equivalents | 18,556 | 8,339 | ||||||
Less: Fair value asset of hedges related to finance debt | 916 | 127 | ||||||
Net debt | 25,864 | 26,161 | ||||||
Equity | 95,891 | 102,113 | ||||||
Net debt ratio | 21% | 20% | ||||||
$ million | ||||||||||||||||||||||||
2010 | 2009 | |||||||||||||||||||||||
Cash and | Cash and | |||||||||||||||||||||||
Finance | cash | Net | Finance | cash | Net | |||||||||||||||||||
Movement in net debt | debt | a | equivalents | debt | debt | a | equivalents | debt | ||||||||||||||||
At 1 January | (34,500 | ) | 8,339 | (26,161 | ) | (33,238 | ) | 8,197 | (25,041 | ) | ||||||||||||||
Exchange adjustments | 194 | (279 | ) | (85 | ) | (60 | ) | 110 | 50 | |||||||||||||||
Net cash flow | (3,613 | ) | 10,496 | 6,883 | (1,141 | ) | 32 | (1,109 | ) | |||||||||||||||
Movement in finance debt relating to investing activitiesb | (6,197 | ) | – | (6,197 | ) | – | – | – | ||||||||||||||||
Other movements | (304 | ) | – | (304 | ) | (61 | ) | – | (61 | ) | ||||||||||||||
At 31 December | (44,420 | ) | 18,556 | (25,864 | ) | (34,500 | ) | 8,339 | (26,161 | ) | ||||||||||||||
a | Including fair value of associated derivative financial instruments. |
b | See Note 35 for further information. |
198 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||||||||||||||
Litigation and | Clean Water | |||||||||||||||||||||||||||
Decommissioning | Environmental | Spill response | claims | Act penalties | Other | Total | ||||||||||||||||||||||
At 1 January 2010 | 9,020 | 1,719 | – | 1,076 | – | 2,815 | 14,630 | |||||||||||||||||||||
Exchange adjustments | (114 | ) | – | – | (7 | ) | – | (50 | ) | (171 | ) | |||||||||||||||||
Acquisitions | 188 | – | – | 2 | – | 15 | 205 | |||||||||||||||||||||
New or increased provisions | 1,800 | 1,290 | 10,883 | 15,171 | 3,510 | 808 | 33,462 | |||||||||||||||||||||
Write-back of unused provisions | (12 | ) | (120 | ) | – | (51 | ) | – | (466 | ) | (649 | ) | ||||||||||||||||
Unwinding of discount | 168 | 29 | – | 18 | – | 19 | 234 | |||||||||||||||||||||
Change in discount rate | 444 | 22 | – | 9 | – | (6 | ) | 469 | ||||||||||||||||||||
Utilization | (164 | ) | (460 | ) | (9,840 | ) | (4,250 | ) | – | (755 | ) | (15,469 | ) | |||||||||||||||
Reclassified as liabilities directly associated with assets held for sale | (381 | ) | (1 | ) | – | – | – | (1 | ) | (383 | ) | |||||||||||||||||
Deletions | (405 | ) | (14 | ) | – | (1 | ) | – | (1 | ) | (421 | ) | ||||||||||||||||
At 31 December 2010 | 10,544 | 2,465 | 1,043 | 11,967 | 3,510 | 2,378 | 31,907 | |||||||||||||||||||||
Of which – current | 432 | 635 | 982 | 7,011 | – | 429 | 9,489 | |||||||||||||||||||||
– non-current | 10,112 | 1,830 | 61 | 4,956 | 3,510 | 1,949 | 22,418 | |||||||||||||||||||||
$ million | ||||||||||||||||||||||||||||
Decommissioning | Environmental | Litigation | Other | Total | ||||||||||||||||||||||||
At 1 January 2009 | 8,418 | 1,691 | 1,446 | 2,098 | 13,653 | |||||||||||||||||||||||
Exchange adjustments | 398 | 15 | 22 | 29 | 464 | |||||||||||||||||||||||
New or increased provisions | 169 | 588 | 302 | 1,256 | 2,315 | |||||||||||||||||||||||
Write-back of unused provisions | – | (259 | ) | (99 | ) | (228 | ) | (586 | ) | |||||||||||||||||||
Unwinding of discount | 184 | 32 | 15 | 16 | 247 | |||||||||||||||||||||||
Change in discount rate | 324 | 18 | (35 | ) | 8 | 315 | ||||||||||||||||||||||
Utilization | (383 | ) | (308 | ) | (574 | ) | (361 | ) | (1,626 | ) | ||||||||||||||||||
Deletions | (90 | ) | (58 | ) | (1 | ) | (3 | ) | (152 | ) | ||||||||||||||||||
At 31 December 2009 | 9,020 | 1,719 | 1,076 | 2,815 | 14,630 | |||||||||||||||||||||||
Of which – current | 287 | 368 | 433 | 572 | 1,660 | |||||||||||||||||||||||
– non-current | 8,733 | 1,351 | 643 | 2,243 | 12,970 | |||||||||||||||||||||||
BP Annual Report and Form 20-F 2010 199
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$ million | ||||||||||||||||||||
Litigation and | Clean Water | |||||||||||||||||||
Environmental | Spill response | claims | Act penalties | Total | ||||||||||||||||
At 1 January 2010 | – | – | – | – | – | |||||||||||||||
New or increased provisions | 929 | 10,883 | 14,939 | 3,510 | 30,261 | |||||||||||||||
Unwinding of discount | 4 | – | – | – | 4 | |||||||||||||||
Change in discount rate | 5 | – | – | – | 5 | |||||||||||||||
Utilization | (129 | ) | (9,840 | ) | (3,966 | ) | – | (13,935 | ) | |||||||||||
At 31 December 2010 | 809 | 1,043 | 10,973 | 3,510 | 16,335 | |||||||||||||||
Of which – current | 314 | 982 | 6,642 | – | 7,938 | |||||||||||||||
– non-current | 495 | 61 | 4,331 | 3,510 | 8,397 | |||||||||||||||
Of which – payable from the trust fund | 382 | – | 9,162 | – | 9,544 | |||||||||||||||
BP faces claims under OPA 90 by individuals and businesses for removal costs, damage to real or personal property, lost profits or impairment of earning capacity, loss of subsistence use of natural resources and for personal injury (“Individual and Business Claims”) and by state and local government entities for removal costs, physical damage to real or personal property, loss of government revenue and increased public services costs (“State and Local Claims”).
200 BP Annual Report and Form 20-F 2010
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BP Annual Report and Form 20-F 2010 201
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% | ||||||||||||||||||||||||||||||||||||
Financial assumptions | UK | US | Other | |||||||||||||||||||||||||||||||||
2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||
Discount rate for pension plan liabilities | 5.5 | 5.8 | 6.3 | 4.7 | 5.4 | 6.3 | 5.3 | 5.8 | 5.7 | |||||||||||||||||||||||||||
Discount rate for other post-retirement benefit plans | n/a | n/a | n/a | 5.3 | 5.8 | 6.2 | n/a | n/a | n/a | |||||||||||||||||||||||||||
Rate of increase in salaries | 5.4 | 5.3 | 4.9 | 4.1 | 4.2 | 2.2 | 3.8 | 3.8 | 3.5 | |||||||||||||||||||||||||||
Rate of increase for pensions in payment | 3.5 | 3.4 | 3.0 | – | – | – | 1.8 | 1.8 | 1.7 | |||||||||||||||||||||||||||
Rate of increase in deferred pensions | 3.5 | 3.4 | 3.0 | – | – | – | 1.3 | 1.2 | 1.0 | |||||||||||||||||||||||||||
Inflation | 3.5 | 3.4 | 3.0 | 2.3 | 2.4 | 0.4 | 2.3 | 2.3 | 2.0 | |||||||||||||||||||||||||||
202 BP Annual Report and Form 20-F 2010
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Years | ||||||||||||||||||||||||||||||||||||
Mortality assumptions | UK | US | Germany | |||||||||||||||||||||||||||||||||
2010 | 2009 | 2008 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||||||||||||
Life expectancy at age 60 for a male currently aged 60 | 26.1 | 26.0 | 25.9 | 24.7 | 24.6 | 24.4 | 23.3 | 23.2 | 23.0 | |||||||||||||||||||||||||||
Life expectancy at age 60 for a male currently aged 40 | 29.1 | 29.0 | 28.9 | 26.2 | 26.1 | 25.9 | 26.2 | 26.1 | 25.9 | |||||||||||||||||||||||||||
Life expectancy at age 60 for a female currently aged 60 | 28.7 | 28.6 | 28.5 | 26.3 | 26.3 | 26.1 | 27.9 | 27.8 | 27.6 | |||||||||||||||||||||||||||
Life expectancy at age 60 for a female currently aged 40 | 31.6 | 31.5 | 31.4 | 27.2 | 27.2 | 27.0 | 30.6 | 30.4 | 30.3 | |||||||||||||||||||||||||||
% | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
First year’s US healthcare cost trend rate | 7.8 | 8.0 | 8.1 | |||||||||
Ultimate US healthcare cost trend rate | 5.0 | 5.0 | 5.0 | |||||||||
Year in which ultimate trend rate is reached | 2018 | 2016 | 2014 | |||||||||
Policy range | ||||
Asset category | % | |||
Total equity | 45-75 | |||
Bonds/cash | 17.5-50 | |||
Property/real estate | 0-10 | |||
BP Annual Report and Form 20-F 2010 203
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2010 | 2009 | 2008 | ||||||||||||||||||||||
Expected | Expected | Expected | ||||||||||||||||||||||
long-term | long-term | long-term | ||||||||||||||||||||||
rate of | Market | rate of | Market | rate of | Market | |||||||||||||||||||
return | value | return | value | return | value | |||||||||||||||||||
% | $ million | % | $ million | % | $ million | |||||||||||||||||||
UK pension plans Equities | 8.0 | 18,546 | 8.0 | 16,945 | 8.0 | 13,704 | ||||||||||||||||||
Bonds | 5.0 | 3,866 | 5.3 | 3,701 | 6.1 | 3,258 | ||||||||||||||||||
Property | 6.5 | 1,462 | 6.5 | 1,269 | 6.5 | 978 | ||||||||||||||||||
Cash | 1.4 | 406 | 1.1 | 634 | 2.9 | 299 | ||||||||||||||||||
7.2 | 24,280 | 7.3 | 22,549 | 7.4 | 18,239 | |||||||||||||||||||
US pension plans | ||||||||||||||||||||||||
Equities | 8.5 | 5,058 | 8.5 | 4,326 | 8.5 | 3,991 | ||||||||||||||||||
Bonds | 4.5 | 1,419 | 4.8 | 1,218 | 3.7 | 1,247 | ||||||||||||||||||
Property | 8.0 | 7 | 8.0 | 8 | 8.0 | 8 | ||||||||||||||||||
Cash | 0.3 | 165 | 0.9 | 271 | 1.9 | 131 | ||||||||||||||||||
8.0 | 6,649 | 8.0 | 5,823 | 8.0 | 5,377 | |||||||||||||||||||
US other post-retirement benefit plans | ||||||||||||||||||||||||
Equities | – | – | 8.5 | 8 | 8.5 | 9 | ||||||||||||||||||
Bonds | – | – | 4.8 | 4 | 3.7 | 4 | ||||||||||||||||||
Cash | 0.3 | 8 | – | – | – | – | ||||||||||||||||||
0.3 | 8 | 7.6 | 12 | 7.3 | 13 | |||||||||||||||||||
Other plans | ||||||||||||||||||||||||
Equities | 8.0 | 1,182 | 8.6 | 1,091 | 8.4 | 799 | ||||||||||||||||||
Bonds | 4.2 | 1,874 | 4.4 | 1,651 | 4.2 | 1,481 | ||||||||||||||||||
Property | 6.3 | 83 | 6.5 | 82 | 6.3 | 127 | ||||||||||||||||||
Cash | 2.7 | 155 | 2.0 | 245 | 3.1 | 118 | ||||||||||||||||||
5.4 | 3,294 | 5.9 | 3,069 | 5.8 | 2,525 | |||||||||||||||||||
204 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||
One-percentage point | ||||||||
Increase | Decrease | |||||||
Investment return | ||||||||
Effect on pension and other post-retirement benefit expense in 2011 | (343 | ) | 343 | |||||
Discount rate | ||||||||
Effect on pension and other post-retirement benefit expense in 2011 | (76 | ) | 101 | |||||
Effect on pension and other post-retirement benefit obligation at 31 December 2010 | (5,370 | ) | 6,864 | |||||
Inflation rate | ||||||||
Effect on pension and other post-retirement benefit expense in 2011 | 470 | (364 | ) | |||||
Effect on pension and other post-retirement benefit obligation at 31 December 2010 | 5,060 | (4,135 | ) | |||||
US healthcare cost trend rate | ||||||||
Effect on US other post-retirement benefit expense in 2011 | 31 | (24 | ) | |||||
Effect on US other post-retirement benefit obligation at 31 December 2010 | 401 | (328 | ) | |||||
$ million | ||||||||||||||||
US other post- | ||||||||||||||||
UK | US | retirement | German | |||||||||||||
pension | pension | benefit | pension | |||||||||||||
plans | plans | plans | plans | |||||||||||||
One additional year’s longevity | ||||||||||||||||
Effect on pension and other post-retirement benefit expense in 2011 | 41 | 4 | 4 | 9 | ||||||||||||
Effect on pension and other post-retirement benefit obligation at 31 December 2010 | 581 | 73 | 72 | 187 | ||||||||||||
BP Annual Report and Form 20-F 2010 205
Table of Contents
$ million | ||||||||||||||||||||
2010 | ||||||||||||||||||||
US other post- | ||||||||||||||||||||
UK | US | retirement | ||||||||||||||||||
pension | pension | benefit | Other | |||||||||||||||||
plans | plans | plans | plans | Total | ||||||||||||||||
Analysis of the amount charged to profit (loss) before interest and taxation | ||||||||||||||||||||
Current service costa | 393 | 241 | 48 | 120 | 802 | |||||||||||||||
Past service cost | – | – | – | 3 | 3 | |||||||||||||||
Settlement, curtailment and special termination benefits | 24 | – | – | 161 | 185 | |||||||||||||||
Payments to defined contribution plans | 1 | 187 | – | 35 | 223 | |||||||||||||||
Total operating chargeb | 418 | 428 | 48 | 319 | 1,213 | |||||||||||||||
Analysis of the amount credited (charged) to other finance expense | ||||||||||||||||||||
Expected return on plan assets | 1,580 | 465 | 1 | 178 | 2,224 | |||||||||||||||
Interest on plan liabilities | (1,183 | ) | (396 | ) | (169 | ) | (429 | ) | (2,177 | ) | ||||||||||
Other finance income (expense) | 397 | 69 | (168 | ) | (251 | ) | 47 | |||||||||||||
Analysis of the amount recognized in other comprehensive income | ||||||||||||||||||||
Actual return less expected return on pension plan assets | 1,577 | 425 | (1 | ) | 36 | 2,037 | ||||||||||||||
Change in assumptions underlying the present value of the plan liabilities | (1,144 | ) | (498 | ) | (132 | ) | (489 | ) | (2,263 | ) | ||||||||||
Experience gains and losses arising on the plan liabilities | 12 | (167 | ) | (8 | ) | 69 | (94 | ) | ||||||||||||
Actuarial (loss) gain recognized in other comprehensive income | 445 | (240 | ) | (141 | ) | (384 | ) | (320 | ) | |||||||||||
Movements in benefit obligation during the year | ||||||||||||||||||||
Benefit obligation at 1 January | 21,425 | 7,519 | 2,996 | 8,133 | 40,073 | |||||||||||||||
Exchange adjustments | (835 | ) | – | – | (269 | ) | (1,104 | ) | ||||||||||||
Current service costa | 393 | 241 | 48 | 120 | 802 | |||||||||||||||
Past service cost | – | – | – | 3 | 3 | |||||||||||||||
Interest cost | 1,183 | 396 | 169 | 429 | 2,177 | |||||||||||||||
Curtailment | – | – | – | 4 | 4 | |||||||||||||||
Settlement | 11 | – | – | 18 | 29 | |||||||||||||||
Special termination benefitsc | 13 | – | – | 139 | 152 | |||||||||||||||
Contributions by plan participantsd | 39 | – | – | 13 | 52 | |||||||||||||||
Benefit payments (funded plans)e | (952 | ) | (758 | ) | (4 | ) | (192 | ) | (1,906 | ) | ||||||||||
Benefit payments (unfunded plans)e | (3 | ) | (75 | ) | (192 | ) | (387 | ) | (657 | ) | ||||||||||
Acquisitions | – | – | – | 2 | 2 | |||||||||||||||
Disposals | (43 | ) | – | – | (29 | ) | (72 | ) | ||||||||||||
Actuarial loss on obligation | 1,132 | 665 | 140 | 420 | 2,357 | |||||||||||||||
Benefit obligation at 31 Decembera f | 22,363 | 7,988 | 3,157 | 8,404 | 41,912 | |||||||||||||||
Movements in fair value of plan assets during the year | ||||||||||||||||||||
Fair value of plan assets at 1 January | 22,549 | 5,823 | 12 | 3,069 | 31,453 | |||||||||||||||
Exchange adjustments | (881 | ) | – | – | 29 | (852 | ) | |||||||||||||
Expected return on plan assetsa g | 1,580 | 465 | 1 | 178 | 2,224 | |||||||||||||||
Contributions by plan participantsd | 39 | – | – | 13 | 52 | |||||||||||||||
Contributions by employers (funded plans) | 411 | 694 | – | 187 | 1,292 | |||||||||||||||
Benefit payments (funded plans)e | (952 | ) | (758 | ) | (4 | ) | (192 | ) | (1,906 | ) | ||||||||||
Acquisitions | – | – | – | 2 | 2 | |||||||||||||||
Disposals | (43 | ) | – | – | (28 | ) | (71 | ) | ||||||||||||
Actuarial gain (loss) on plan assetsg | 1,577 | 425 | (1 | ) | 36 | 2,037 | ||||||||||||||
Fair value of plan assets at 31 December | 24,280 | 6,649 | 8 | 3,294 | 34,231 | |||||||||||||||
Surplus (deficit) at 31 December | 1,917 | (1,339 | ) | (3,149 | ) | (5,110 | ) | (7,681 | ) | |||||||||||
Represented by | ||||||||||||||||||||
Asset recognized | 2,120 | – | – | 56 | 2,176 | |||||||||||||||
Liability recognized | (203 | ) | (1,339 | ) | (3,149 | ) | (5,166 | ) | (9,857 | ) | ||||||||||
1,917 | (1,339 | ) | (3,149 | ) | (5,110 | ) | (7,681 | ) | ||||||||||||
The surplus (deficit) may be analysed between funded and unfunded plans as follows | ||||||||||||||||||||
Funded | 2,115 | (838 | ) | (39 | ) | (223 | ) | 1,015 | ||||||||||||
Unfunded | (198 | ) | (501 | ) | (3,110 | ) | (4,887 | ) | (8,696 | ) | ||||||||||
1,917 | (1,339 | ) | (3,149 | ) | (5,110 | ) | (7,681 | ) | ||||||||||||
The defined benefit obligation may be analysed between funded and unfunded plans as follows | ||||||||||||||||||||
Funded | (22,165 | ) | (7,487 | ) | (47 | ) | (3,517 | ) | (33,216 | ) | ||||||||||
Unfunded | (198 | ) | (501 | ) | (3,110 | ) | (4,887 | ) | (8,696 | ) | ||||||||||
(22,363 | ) | (7,988 | ) | (3,157 | ) | (8,404 | ) | (41,912 | ) | |||||||||||
a | The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pension plan benefits are generally included in current service cost and the costs of administering our other post-retirement benefit plans are included in the benefit obligation. |
b | Included within production and manufacturing expenses and distribution and administration expenses. |
c | The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes. |
d | Most of the contributions made by plan participants after 1 January 2010 into UK pension plans were made under salary sacrifice. |
e | The benefit payments amount shown above comprises $2,507 million benefits plus $56 million of plan expenses incurred in the administration of the benefit. |
f | The benefit obligation for other plans includes $3,871 million for the German plan, which is largely unfunded. |
g | The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain on plan assets as disclosed above. |
206 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||
2009 | ||||||||||||||||||||
US other post- | ||||||||||||||||||||
UK | US | retirement | ||||||||||||||||||
pension | pension | benefit | Other | |||||||||||||||||
plans | plans | plans | plans | Total | ||||||||||||||||
Analysis of the amount charged to profit before interest and taxation | ||||||||||||||||||||
Current service costa | 311 | 243 | 48 | 117 | 719 | |||||||||||||||
Past service cost | – | – | (22 | ) | 1 | (21 | ) | |||||||||||||
Settlement, curtailment and special termination benefits | 37 | – | – | 53 | 90 | |||||||||||||||
Payments to defined contribution plans | – | 205 | – | 28 | 233 | |||||||||||||||
Total operating chargeb | 348 | 448 | 26 | 199 | 1,021 | |||||||||||||||
Analysis of the amount credited (charged) to other finance expense | ||||||||||||||||||||
Expected return on plan assets | 1,426 | 405 | 1 | 147 | 1,979 | |||||||||||||||
Interest on plan liabilities | (1,112 | ) | (456 | ) | (183 | ) | (420 | ) | (2,171 | ) | ||||||||||
Other finance income (expense) | 314 | (51 | ) | (182 | ) | (273 | ) | (192 | ) | |||||||||||
Analysis of the amount recognized in other comprehensive income | ||||||||||||||||||||
Actual return less expected return on pension plan assets | 1,761 | 617 | 2 | 169 | 2,549 | |||||||||||||||
Change in assumptions underlying the present value of the plan liabilities | (2,217 | ) | (501 | ) | (50 | ) | (42 | ) | (2,810 | ) | ||||||||||
Experience gains and losses arising on the plan liabilities | (141 | ) | (229 | ) | 71 | (122 | ) | (421 | ) | |||||||||||
Actuarial (loss) gain recognized in other comprehensive income | (597 | ) | (113 | ) | 23 | 5 | (682 | ) | ||||||||||||
Movements in benefit obligation during the year | ||||||||||||||||||||
Benefit obligation at 1 January | 16,655 | 7,534 | 3,003 | 7,655 | 34,847 | |||||||||||||||
Exchange adjustments | 1,896 | – | – | 363 | 2,259 | |||||||||||||||
Current service costa | 311 | 243 | 48 | 117 | 719 | |||||||||||||||
Past service cost | – | – | (22 | ) | 1 | (21 | ) | |||||||||||||
Interest cost | 1,112 | 456 | 183 | 420 | 2,171 | |||||||||||||||
Curtailment | – | – | – | 11 | 11 | |||||||||||||||
Settlement | – | – | – | (3 | ) | (3 | ) | |||||||||||||
Special termination benefitsc | 37 | – | – | 45 | 82 | |||||||||||||||
Contributions by plan participants | 37 | – | – | 10 | 47 | |||||||||||||||
Benefit payments (funded plans)d | (977 | ) | (1,371 | ) | (4 | ) | (209 | ) | (2,561 | ) | ||||||||||
Benefit payments (unfunded plans)d | (4 | ) | (73 | ) | (191 | ) | (399 | ) | (667 | ) | ||||||||||
Disposals | – | – | – | (42 | ) | (42 | ) | |||||||||||||
Actuarial (gain) loss on obligation | 2,358 | 730 | (21 | ) | 164 | 3,231 | ||||||||||||||
Benefit obligation at 31 Decembera e | 21,425 | 7,519 | 2,996 | 8,133 | 40,073 | |||||||||||||||
Movements in fair value of plan assets during the year | ||||||||||||||||||||
Fair value of plan assets at 1 January | 18,239 | 5,377 | 13 | 2,525 | 26,154 | |||||||||||||||
Exchange adjustments | 2,054 | – | – | 242 | 2,296 | |||||||||||||||
Expected return on plan assetsa f | 1,426 | 405 | 1 | 147 | 1,979 | |||||||||||||||
Contributions by plan participants | 37 | – | – | 10 | 47 | |||||||||||||||
Contributions by employers (funded plans) | 9 | 795 | – | 204 | 1,008 | |||||||||||||||
Benefit payments (funded plans)d | (977 | ) | (1,371 | ) | (4 | ) | (209 | ) | (2,561 | ) | ||||||||||
Disposals | – | – | – | (19 | ) | (19 | ) | |||||||||||||
Actuarial gain on plan assetsf | 1,761 | 617 | 2 | 169 | 2,549 | |||||||||||||||
Fair value of plan assets at 31 December | 22,549 | 5,823 | 12 | 3,069 | 31,453 | |||||||||||||||
Surplus (deficit) at 31 December | 1,124 | (1,696 | ) | (2,984 | ) | (5,064 | ) | (8,620 | ) | |||||||||||
Represented by | ||||||||||||||||||||
Asset recognized | 1,290 | – | – | 100 | 1,390 | |||||||||||||||
Liability recognized | (166 | ) | (1,696 | ) | (2,984 | ) | (5,164 | ) | (10,010 | ) | ||||||||||
1,124 | (1,696 | ) | (2,984 | ) | (5,064 | ) | (8,620 | ) | ||||||||||||
The surplus (deficit) may be analysed between funded and unfunded plans as follows | ||||||||||||||||||||
Funded | 1,287 | (1,280 | ) | (33 | ) | (164 | ) | (190 | ) | |||||||||||
Unfunded | (163 | ) | (416 | ) | (2,951 | ) | (4,900 | ) | (8,430 | ) | ||||||||||
1,124 | (1,696 | ) | (2,984 | ) | (5,064 | ) | (8,620 | ) | ||||||||||||
The defined benefit obligation may be analysed between funded and unfunded plans as follows | ||||||||||||||||||||
Funded | (21,262 | ) | (7,103 | ) | (45 | ) | (3,233 | ) | (31,643 | ) | ||||||||||
Unfunded | (163 | ) | (416 | ) | (2,951 | ) | (4,900 | ) | (8,430 | ) | ||||||||||
(21,425 | ) | (7,519 | ) | (2,996 | ) | (8,133 | ) | (40,073 | ) | |||||||||||
a | The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pension plan benefits are generally included in current service cost and the costs of administering our other post-retirement benefit plans are included in the benefit obligation. |
b | Included within production and manufacturing expenses and distribution and administration expenses. |
c | The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes. |
d | The benefit payments amount shown above comprises $3,174 million benefits plus $54 million of plan expenses incurred in the administration of the benefit. |
e | The benefit obligation for other plans includes $3,880 million for the German plan, which is largely unfunded. |
f | The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain on plan assets as disclosed above. |
BP Annual Report and Form 20-F 2010 207
Table of Contents
$ million | ||||||||||||||||||||
2008 | ||||||||||||||||||||
US other post- | ||||||||||||||||||||
UK | US | retirement | ||||||||||||||||||
pension | pension | benefit | Other | |||||||||||||||||
plans | plans | plans | plans | Total | ||||||||||||||||
Analysis of the amount charged to profit before interest and taxation | ||||||||||||||||||||
Current service costa | 448 | 235 | 40 | 128 | 851 | |||||||||||||||
Past service cost | 7 | 74 | – | 1 | 82 | |||||||||||||||
Settlement, curtailment and special termination benefits | 30 | – | – | 12 | 42 | |||||||||||||||
Payments to defined contribution plans | – | 170 | – | 25 | 195 | |||||||||||||||
Total operating chargeb | 485 | 479 | 40 | 166 | 1,170 | |||||||||||||||
Analysis of the amount credited (charged) to other finance expense | ||||||||||||||||||||
Expected return on plan assets | 2,094 | 632 | 2 | 194 | 2,922 | |||||||||||||||
Interest on plan liabilities | (1,239 | ) | (444 | ) | (198 | ) | (450 | ) | (2,331 | ) | ||||||||||
Other finance income (expense) | 855 | 188 | (196 | ) | (256 | ) | 591 | |||||||||||||
Analysis of the amount recognized in other comprehensive income | ||||||||||||||||||||
Actual return less expected return on pension plan assets | (6,946 | ) | (2,895 | ) | (8 | ) | (404 | ) | (10,253 | ) | ||||||||||
Change in assumptions underlying the present value of the plan liabilities | 1,570 | 3 | 215 | 214 | 2,002 | |||||||||||||||
Experience gains and losses arising on the plan liabilities | (73 | ) | (194 | ) | 18 | 70 | (179 | ) | ||||||||||||
Actuarial (loss) gain recognized in other comprehensive income | (5,449 | ) | (3,086 | ) | 225 | (120 | ) | (8,430 | ) | |||||||||||
a | The costs of managing the plan’s investments are treated as being part of the investment return, the costs of administering our pensions fund benefits are generally included in current service cost, and the costs of administering our other post-retirement benefit plans are included in the benefit obligation. |
b | Included within production and manufacturing expenses and distribution and administration expenses. |
$ million | ||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
History of surplus (deficit) and of experience gains and losses | ||||||||||||||||||||
Benefit obligation at 31 December | 41,912 | 40,073 | 34,847 | 43,100 | 42,433 | |||||||||||||||
Fair value of plan assets at 31 December | 34,231 | 31,453 | 26,154 | 42,799 | 39,910 | |||||||||||||||
Deficit | (7,681 | ) | (8,620 | ) | (8,693 | ) | (301 | ) | (2,523 | ) | ||||||||||
Experience losses on plan liabilities | (94 | ) | (421 | ) | (178 | ) | (200 | ) | (124 | ) | ||||||||||
Actual return less expected return on pension plan assets | 2,037 | 2,549 | (10,253 | ) | 302 | 1,967 | ||||||||||||||
Actual return on plan assets | 4,261 | 4,528 | (7,331 | ) | 3,157 | 4,377 | ||||||||||||||
Actuarial (loss) gain recognized in other comprehensive income | (320 | ) | (682 | ) | (8,430 | ) | 1,717 | 2,615 | ||||||||||||
Cumulative amount recognized in other comprehensive income | (3,942 | ) | (3,622 | ) | (2,940 | ) | 5,490 | 3,773 | ||||||||||||
$ million | ||||||||||||||||||||
US other post- | ||||||||||||||||||||
UK | US | retirement | ||||||||||||||||||
pension | pension | benefit | Other | |||||||||||||||||
plans | plans | plans | plans | Total | ||||||||||||||||
2011 | 994 | 805 | 207 | 612 | 2,618 | |||||||||||||||
2012 | 1,035 | 807 | 209 | 581 | 2,632 | |||||||||||||||
2013 | 1,069 | 810 | 213 | 584 | 2,676 | |||||||||||||||
2014 | 1,122 | 808 | 217 | 588 | 2,735 | |||||||||||||||
2015 | 1,167 | 788 | 221 | 576 | 2,752 | |||||||||||||||
2016-2020 | 6,581 | 3,636 | 1,132 | 2,815 | 14,164 | |||||||||||||||
208 BP Annual Report and Form 20-F 2010
Table of Contents
2010 | 2009 | 2008 | ||||||||||||||||||||||
Shares | Shares | Shares | ||||||||||||||||||||||
Issued | (thousand) | $ million | (thousand) | $ million | (thousand) | $ million | ||||||||||||||||||
8% cumulative first preference shares of £1 each | 7,233 | 12 | 7,233 | 12 | 7,233 | 12 | ||||||||||||||||||
9% cumulative second preference shares of £1 each | 5,473 | 9 | 5,473 | 9 | 5,473 | 9 | ||||||||||||||||||
21 | 21 | 21 | ||||||||||||||||||||||
Ordinary shares of 25 cents each At 1 January | 20,629,665 | 5,158 | 20,618,458 | 5,155 | 20,863,424 | 5,216 | ||||||||||||||||||
Issue of new shares for employee share schemesa | 17,495 | 4 | 11,207 | 3 | 24,791 | 6 | ||||||||||||||||||
Repurchase of ordinary share capitalb | – | – | – | – | (269,757 | ) | (67 | ) | ||||||||||||||||
At 31 December | 20,647,160 | 5,162 | 20,629,665 | 5,158 | 20,618,458 | 5,155 | ||||||||||||||||||
5,183 | 5,179 | 5,176 | ||||||||||||||||||||||
Authorized | ||||||||||||||||||||||||
8% cumulative first preference shares of £1 each | 7,250 | 12 | 7,250 | 12 | 7,250 | 12 | ||||||||||||||||||
9% cumulative second preference shares of £1 each | 5,500 | 9 | 5,500 | 9 | 5,500 | 9 | ||||||||||||||||||
Ordinary shares of 25 cents each | 36,000,000 | 9,000 | 36,000,000 | 9,000 | 36,000,000 | 9,000 | ||||||||||||||||||
a | Consideration received relating to the issue of new shares for employee share schemes amounted to $138 million (2009 $84 million and 2008 $180 million). |
b | Purchased for a total consideration of nil (2009 nil and 2008 $2,914 million), all of which were for cancellation. At 31 December 2010, 112,803,287 (2009 112,803,287 and 2008 150,444,408) ordinary shares bought back were awaiting cancellation. These shares have been excluded from ordinary shares in issue shown above. Transaction costs of share repurchases amounted to nil (2009 nil and 2008 $16 million). |
2010 | 2009 | 2008 | ||||||||||||||||||||||
Shares | Nominal value | Shares | Nominal value | Shares | Nominal value | |||||||||||||||||||
(thousand) | $ million | (thousand) | $ million | (thousand) | $ million | |||||||||||||||||||
At 1 January | 1,869,777 | 467 | 1,888,151 | 472 | 1,940,639 | 485 | ||||||||||||||||||
Shares gifted to the Employee Share Ownership Plans | – | – | (1,265 | ) | (1 | ) | (10,000 | ) | (2 | ) | ||||||||||||||
Shares transferred at market price to the Employee Share Ownership Plans | (7,125 | ) | (2 | ) | – | – | (20,000 | ) | (5 | ) | ||||||||||||||
Shares re-issued to employee share schemes | (11,953 | ) | (3 | ) | (17,109 | ) | (4 | ) | (22,488 | ) | (6 | ) | ||||||||||||
At 31 December | 1,850,699 | 462 | 1,869,777 | 467 | 1,888,151 | 472 | ||||||||||||||||||
BP Annual Report and Form 20-F 2010 209
Table of Contents
Share | Capital | |||||||||||||||
Share | premium | redemption | Merger | |||||||||||||
capital | account | reserve | reserve | |||||||||||||
At 1 January 2010 | 5,179 | 9,847 | 1,072 | 27,206 | ||||||||||||
Currency translation differences (including recycling) | – | – | – | – | ||||||||||||
Actuarial loss relating to pensions and other post-retirement benefits | – | – | – | – | ||||||||||||
Available-for-sale investments (including recycling) | – | – | – | – | ||||||||||||
Cash flow hedges (including recycling) | – | – | – | – | ||||||||||||
Profit (loss) for the year | – | – | – | – | ||||||||||||
Total comprehensive income | – | – | – | – | ||||||||||||
Dividends | – | – | – | – | ||||||||||||
Share-based paymentsa | 4 | 140 | – | – | ||||||||||||
Transactions involving minority interests | – | – | – | – | ||||||||||||
At 31 December 2010 | 5,183 | 9,987 | 1,072 | 27,206 | ||||||||||||
Share | Capital | |||||||||||||||
Share | premium | redemption | Merger | |||||||||||||
capital | account | reserve | reserve | |||||||||||||
At 1 January 2009 | 5,176 | 9,763 | 1,072 | 27,206 | ||||||||||||
Currency translation differences (including recycling) | – | – | – | – | ||||||||||||
Actuarial loss relating to pensions and other post-retirement benefits | – | – | – | – | ||||||||||||
Available-for-sale investments (including recycling) | – | – | – | – | ||||||||||||
Cash flow hedges (including recycling) | – | – | – | – | ||||||||||||
Profit for the year | – | – | – | – | ||||||||||||
Total comprehensive income | – | – | – | – | ||||||||||||
Dividends | – | – | – | – | ||||||||||||
Share-based paymentsa | 3 | 84 | – | – | ||||||||||||
Changes in associates’ equity | – | – | – | – | ||||||||||||
Transactions involving minority interests | – | – | – | – | ||||||||||||
At 31 December 2009 | 5,179 | 9,847 | 1,072 | 27,206 | ||||||||||||
Share | Capital | |||||||||||||||
Share | premium | redemption | Merger | |||||||||||||
capital | account | reserve | reserve | |||||||||||||
At 1 January 2008 | 5,237 | 9,581 | 1,005 | 27,206 | ||||||||||||
Currency translation differences (including recycling) | – | – | – | – | ||||||||||||
Actuarial loss relating to pensions and other post-retirement benefits | – | – | – | – | ||||||||||||
Available-for-sale investments (including recycling) | – | – | – | – | ||||||||||||
Cash flow hedges (including recycling) | – | – | – | – | ||||||||||||
Profit for the year | – | – | – | – | ||||||||||||
Total comprehensive income | – | – | – | – | ||||||||||||
Dividends | – | – | – | – | ||||||||||||
Repurchase of ordinary share capital | (67 | ) | – | 67 | – | |||||||||||
Share-based paymentsa | 6 | 182 | – | – | ||||||||||||
Transactions involving minority interests | – | – | – | – | ||||||||||||
At 31 December 2008 | 5,176 | 9,763 | 1,072 | 27,206 | ||||||||||||
a | Includes new share issues and movements in own shares and treasury shares where these relate to share-based payment plans. |
210 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||||||||||||||||||||||||||||||
Foreign | Share- | |||||||||||||||||||||||||||||||||||||||
currency | Available- | based | Profit | BP | ||||||||||||||||||||||||||||||||||||
Own | Treasury | translation | for-sale | Cash flow | payment | and loss | shareholders' | Minority | Total | |||||||||||||||||||||||||||||||
shares | shares | reserve | investments | hedges | reserve | account | equity | interest | equity | |||||||||||||||||||||||||||||||
(214 | ) | (21,303 | ) | 4,811 | 754 | 22 | 1,584 | 72,655 | 101,613 | 500 | 102,113 | |||||||||||||||||||||||||||||
– | – | 126 | – | 2 | – | – | 128 | 3 | 131 | |||||||||||||||||||||||||||||||
– | – | – | – | – | – | (418 | ) | (418 | ) | – | (418 | ) | ||||||||||||||||||||||||||||
– | – | – | (291 | ) | – | – | – | (291 | ) | – | (291 | ) | ||||||||||||||||||||||||||||
– | – | – | – | (18 | ) | – | – | (18 | ) | – | (18 | ) | ||||||||||||||||||||||||||||
– | – | – | – | – | – | (3,719 | ) | (3,719 | ) | 395 | (3,324 | ) | ||||||||||||||||||||||||||||
– | – | 126 | (291 | ) | (16 | ) | – | (4,137 | ) | (4,318 | ) | 398 | (3,920 | ) | ||||||||||||||||||||||||||
– | – | – | – | – | – | (2,627 | ) | (2,627 | ) | (315 | ) | (2,942 | ) | |||||||||||||||||||||||||||
88 | 218 | – | – | – | 2 | (113 | ) | 339 | – | 339 | ||||||||||||||||||||||||||||||
– | – | – | – | – | – | (20 | ) | (20 | ) | 321 | 301 | |||||||||||||||||||||||||||||
(126 | ) | (21,085 | ) | 4,937 | 463 | 6 | 1,586 | 65,758 | 94,987 | 904 | 95,891 | |||||||||||||||||||||||||||||
Foreign | Share- | |||||||||||||||||||||||||||||||||||||||
currency | Available- | based | Profit | BP | ||||||||||||||||||||||||||||||||||||
Own | Treasury | translation | for-sale | Cash flow | payment | and loss | shareholders' | Minority | Total | |||||||||||||||||||||||||||||||
shares | shares | reserve | investments | hedges | reserve | account | equity | interest | equity | |||||||||||||||||||||||||||||||
(326 | ) | (21,513 | ) | 2,353 | 63 | (866 | ) | 1,295 | 67,080 | 91,303 | 806 | 92,109 | ||||||||||||||||||||||||||||
– | – | 2,458 | (2 | ) | (37 | ) | – | – | 2,419 | (56 | ) | 2,363 | ||||||||||||||||||||||||||||
– | – | – | – | – | – | (478 | ) | (478 | ) | – | (478 | ) | ||||||||||||||||||||||||||||
– | – | – | 693 | – | – | – | 693 | – | 693 | |||||||||||||||||||||||||||||||
– | – | – | – | 925 | – | – | 925 | – | 925 | |||||||||||||||||||||||||||||||
– | – | – | – | – | – | 16,578 | 16,578 | 181 | 16,759 | |||||||||||||||||||||||||||||||
– | – | 2,458 | 691 | 888 | – | 16,100 | 20,137 | 125 | 20,262 | |||||||||||||||||||||||||||||||
– | – | – | – | – | – | (10,483 | ) | (10,483 | ) | (416 | ) | (10,899 | ) | |||||||||||||||||||||||||||
112 | 210 | – | – | – | 289 | 23 | 721 | – | 721 | |||||||||||||||||||||||||||||||
– | – | – | – | – | – | (43 | ) | (43 | ) | – | (43 | ) | ||||||||||||||||||||||||||||
– | – | – | – | – | – | (22 | ) | (22 | ) | (15 | ) | (37 | ) | |||||||||||||||||||||||||||
(214 | ) | (21,303 | ) | 4,811 | 754 | 22 | 1,584 | 72,655 | 101,613 | 500 | 102,113 | |||||||||||||||||||||||||||||
Foreign | Share- | |||||||||||||||||||||||||||||||||||||||
currency | Available- | based | Profit | BP | ||||||||||||||||||||||||||||||||||||
Own | Treasury | translation | for-sale | Cash flow | payment | and loss | shareholders' | Minority | Total | |||||||||||||||||||||||||||||||
shares | shares | reserve | investments | hedges | reserve | account | equity | interest | equity | |||||||||||||||||||||||||||||||
(60 | ) | (22,112 | ) | 6,540 | 481 | 106 | 1,196 | 64,510 | 93,690 | 962 | 94,652 | |||||||||||||||||||||||||||||
– | – | (4,187 | ) | – | – | – | – | (4,187 | ) | (75 | ) | (4,262 | ) | |||||||||||||||||||||||||||
– | – | – | – | – | – | (5,828 | ) | (5,828 | ) | – | (5,828 | ) | ||||||||||||||||||||||||||||
– | – | – | (418 | ) | – | – | – | (418 | ) | – | (418 | ) | ||||||||||||||||||||||||||||
– | – | – | – | (972 | ) | – | – | (972 | ) | – | �� | (972 | ) | |||||||||||||||||||||||||||
– | – | – | – | – | – | 21,157 | 21,157 | 509 | 21,666 | |||||||||||||||||||||||||||||||
– | – | (4,187 | ) | (418 | ) | (972 | ) | – | 15,329 | 9,752 | 434 | 10,186 | ||||||||||||||||||||||||||||
– | – | – | – | – | – | (10,342 | ) | (10,342 | ) | (425 | ) | (10,767 | ) | |||||||||||||||||||||||||||
– | – | – | – | – | – | (2,414 | ) | (2,414 | ) | – | (2,414 | ) | ||||||||||||||||||||||||||||
(266 | ) | 599 | – | – | – | 99 | (3 | ) | 617 | – | 617 | |||||||||||||||||||||||||||||
– | – | – | – | – | – | – | – | (165 | ) | (165 | ) | |||||||||||||||||||||||||||||
(326 | ) | (21,513 | ) | 2,353 | 63 | (866 | ) | 1,295 | 67,080 | 91,303 | 806 | 92,109 | ||||||||||||||||||||||||||||
BP Annual Report and Form 20-F 2010 211
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212 BP Annual Report and Form 20-F 2010
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$ million | ||||||||||||
2010 | ||||||||||||
Pre-tax | Tax | Net of tax | ||||||||||
Currency translation differences (including recycling) | 239 | (108 | ) | 131 | ||||||||
Actuarial loss relating to pensions and other post-retirement benefits | (320 | ) | (98 | ) | (418 | ) | ||||||
Available-for-sale investments (including recycling) | (341 | ) | 50 | (291 | ) | |||||||
Cash flow hedges (including recycling) | (37 | ) | 19 | (18 | ) | |||||||
Other comprehensive income | (459 | ) | (137 | ) | (596 | ) | ||||||
$ million | ||||||||||||
2009 | ||||||||||||
Pre-tax | Tax | Net of tax | ||||||||||
Currency translation differences (including recycling) | 1,799 | 564 | 2,363 | |||||||||
Actuarial loss relating to pensions and other post-retirement benefits | (682 | ) | 204 | (478 | ) | |||||||
Available-for-sale investments (including recycling) | 707 | (14 | ) | 693 | ||||||||
Cash flow hedges (including recycling) | 1,154 | (229 | ) | 925 | ||||||||
Other comprehensive income | 2,978 | 525 | 3,503 | |||||||||
$ million | ||||||||||||
2008 | ||||||||||||
Pre-tax | Tax | Net of tax | ||||||||||
Currency translation differences (including recycling) | (4,362 | ) | 100 | (4,262 | ) | |||||||
Actuarial loss relating to pensions and other post-retirement benefits | (8,430 | ) | 2,602 | (5,828 | ) | |||||||
Available-for-sale investments (including recycling) | (468 | ) | 50 | (418 | ) | |||||||
Cash flow hedges (including recycling) | (1,166 | ) | 194 | (972 | ) | |||||||
Other comprehensive income | (14,426 | ) | 2,946 | (11,480 | ) | |||||||
BP Annual Report and Form 20-F 2010 213
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$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Total expense recognized for equity-settled share-based payment transactions | 577 | 506 | 524 | |||||||||
Total (credit) expense recognized for cash-settled share-based payment transactions | (1 | ) | 15 | (16 | ) | |||||||
Total expense recognized for share-based payment transactions | 576 | 521 | 508 | |||||||||
Closing balance of liability for cash-settled share-based payment transactions | 16 | 32 | 21 | |||||||||
Total intrinsic value for vested cash-settled share-based payments | 1 | 7 | 2 | |||||||||
214 BP Annual Report and Form 20-F 2010
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2010 | 2009 | 2008 | |||||||||||||||||||||||
Weighted | Weighted | Weighted | |||||||||||||||||||||||
Number | average | Number | average | Number | average | ||||||||||||||||||||
of | exercise price | of | exercise price | of | exercise price | ||||||||||||||||||||
options | $ | options | $ | options | $ | ||||||||||||||||||||
Outstanding at 1 January | 295,895,357 | 8.73 | 326,254,599 | 8.70 | 358,094,243 | 8.51 | |||||||||||||||||||
Granted | 10,420,287 | 6.08 | 9,679,836 | 6.55 | 8,062,899 | 8.96 | |||||||||||||||||||
Forfeited | (9,499,661 | ) | 7.88 | (5,954,325 | ) | 8.81 | (2,502,784 | ) | 8.50 | ||||||||||||||||
Exercised | (31,839,034 | ) | 7.97 | (21,293,871 | ) | 7.53 | (37,277,895 | ) | 6.97 | ||||||||||||||||
Expired | (1,670,227 | ) | 8.71 | (12,790,882 | ) | 8.01 | (121,864 | ) | 7.00 | ||||||||||||||||
Outstanding at 31 December | 263,306,722 | 8.75 | 295,895,357 | 8.73 | 326,254,599 | 8.70 | |||||||||||||||||||
Exercisable at 31 December | 242,530,635 | 8.90 | 274,685,068 | 8.80 | 260,178,938 | 8.22 | |||||||||||||||||||
The weighted average share price at the date of exercise was $9.54 (2009 $9.10 and 2008 $10.87). For the options outstanding at 31 December 2010, the exercise price ranges and weighted average remaining contractual lives are shown below. | |||||||||||||||||||||||||
Options outstanding | Options exercisable | ||||||||||||||||||||||||
Weighted | Weighted | Weighted | |||||||||||||||||||||||
Number | average | average | Number | average | |||||||||||||||||||||
of | remaining life | exercise price | of | exercise price | |||||||||||||||||||||
Range of exercise prices | shares | Years | $ | shares | $ | ||||||||||||||||||||
$6.09 – $7.53 | 54,821,144 | 2.68 | 6.36 | 39,231,453 | 6.40 | ||||||||||||||||||||
$7.54 – $8.99 | 115,187,261 | 1.71 | 8.19 | 112,551,834 | 8.17 | ||||||||||||||||||||
$9.00 – $10.45 | 21,827,393 | 3.54 | 9.88 | 19,276,424 | 9.98 | ||||||||||||||||||||
$10.46 – $11.92 | 71,470,924 | 4.81 | 11.14 | 71,470,924 | 11.14 | ||||||||||||||||||||
263,306,722 | 2.90 | 8.75 | 242,530,635 | 8.90 | |||||||||||||||||||||
2010 | 2009 | 2008 | ||||||||||||||||||||||
ShareSave | ShareSave | ShareSave | ShareSave | ShareSave | ShareSave | |||||||||||||||||||
3 year | 5 year | 3 year | 5 year | 3 year | 5 year | |||||||||||||||||||
Option pricing model used | Binomial | Binomial | Binomial | Binomial | Binomial | Binomial | ||||||||||||||||||
Weighted average fair value | $0.06 | $0.08 | $1.07 | $1.07 | $1.82 | $1.74 | ||||||||||||||||||
Weighted average share price | $4.58 | $4.58 | $7.87 | $7.87 | $11.26 | $11.26 | ||||||||||||||||||
Weighted average exercise price | $5.90 | $5.90 | $6.92 | $6.92 | $9.70 | $9.70 | ||||||||||||||||||
Expected volatility | 22% | 23% | 32% | 32% | 23% | 23% | ||||||||||||||||||
Option life | 3.5 years | 5.5 years | 3.5 years | 5.5 years | 3.5 years | 5.5 years | ||||||||||||||||||
Expected dividends | 8.40% | 8.40% | 7.40% | 7.40% | 4.60% | 4.60% | ||||||||||||||||||
Risk free interest rate | 1.25% | 2.00% | 3.00% | 3.75% | 5.00% | 5.00% | ||||||||||||||||||
Expected exercise behaviour | 100% year 4 | 100% year 6 | 100% year 4 | 100% year 6 | 100% year 4 | 100% year 6 | ||||||||||||||||||
BP Annual Report and Form 20-F 2010 215
Table of Contents
EDIP- | EDIP- | |||||||||||||||||||||||||||
Shares granted in 2010 | CPP | EPP | TSR | BSC | RSP | DAB | PSP | |||||||||||||||||||||
Number of equity instruments granted (million) | 1.3 | 7.6 | 1.2 | 2.5 | 21.4 | 24.5 | 16.0 | |||||||||||||||||||||
Weighted average fair value | $19.81 | $9.43 | $4.42 | $8.94 | $6.78 | $9.43 | $9.43 | |||||||||||||||||||||
Fair value measurement basis | Monte Carlo | Market value | Monte Carlo | Market value | Market value | Market value | Market value | |||||||||||||||||||||
EDIP- | EDIP- | |||||||||||||||||||||||||||
Shares granted in 2009 | CPP | EPP | TSR | BSC | RSP | DAB | PSP | |||||||||||||||||||||
Number of equity instruments granted (million) | 1.4 | 7.6 | 2.1 | 2.1 | 2.4 | 38.9 | 16.5 | |||||||||||||||||||||
Weighted average fair value | $9.76 | $6.56 | $2.74 | $7.27 | $8.76 | $6.56 | $8.32 | |||||||||||||||||||||
Fair value measurement basis | Monte Carlo | Market value | Monte Carlo | Market value | Market value | Market value | Monte Carlo | |||||||||||||||||||||
MTPP- | MTPP- | EDIP- | EDIP- | |||||||||||||||||||||||||
Shares granted in 2008 | TSR | FCF | TSR | RETa | RSP | DAB | PSP | |||||||||||||||||||||
Number of equity instruments granted (million) | 9.1 | 9.1 | 2.6 | 0.5 | 7.7 | 5.8 | 16.7 | |||||||||||||||||||||
Weighted average fair value | $5.07 | $10.34 | $4.55 | $11.13 | $8.83 | $10.34 | $12.89 | |||||||||||||||||||||
Fair value measurement basis | Monte Carlo | Market value | Monte Carlo | Market value | Market value | Market value | Monte Carlo | |||||||||||||||||||||
a | EDIP – retention element. |
$ million | ||||||||||||
Employee costs | 2010 | 2009 | 2008 | |||||||||
Wages and salariesa | 9,242 | 9,702 | 10,388 | |||||||||
Social security costs | 789 | 780 | 805 | |||||||||
Share-based payments | 576 | 521 | 508 | |||||||||
Pension and other post-retirement benefit costs | 1,166 | 1,213 | 579 | |||||||||
11,773 | 12,216 | 12,280 | ||||||||||
Number of employees at 31 December | 2010 | 2009 | 2008 | |||||||||
Exploration and Production | 21,100 | 21,500 | 21,400 | |||||||||
Refining and Marketingb | 52,300 | 51,600 | 61,500 | |||||||||
Other businesses and corporate | 6,200 | 7,200 | 9,100 | |||||||||
Gulf Coast Restoration Organization | 100 | – | – | |||||||||
79,700 | 80,300 | 92,000 | ||||||||||
By geographical area | ||||||||||||
US | 22,100 | 22,800 | 29,300 | |||||||||
Non-USb | 57,600 | 57,500 | 62,700 | |||||||||
79,700 | 80,300 | 92,000 | ||||||||||
2010 | 2009 | 2008 | ||||||||||||||||||||||||||||||||||
Average number of employees | US | Non-US | Total | US | Non-US | Total | US | Non-US | Total | |||||||||||||||||||||||||||
Exploration and Production | 8,100 | 13,500 | 21,600 | 7,900 | 13,800 | 21,700 | 7,800 | 13,800 | 21,600 | |||||||||||||||||||||||||||
Refining and Marketing | 12,600 | 38,300 | 50,900 | 14,700 | 40,700 | 55,400 | 21,600 | 43,400 | 65,000 | |||||||||||||||||||||||||||
Other businesses and corporate | 1,900 | 5,000 | 6,900 | 2,300 | 5,800 | 8,100 | 2,600 | 6,500 | 9,100 | |||||||||||||||||||||||||||
22,600 | 56,800 | 79,400 | 24,900 | 60,300 | 85,200 | 32,000 | 63,700 | 95,700 | ||||||||||||||||||||||||||||
a | Includes termination payments of $166 million (2009 $945 million and 2008 $669 million). |
b | Includes 15,200 (2009 13,900 and 2008 21,200) service station staff. |
216 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Total for all directors | ||||||||||||
Emoluments | 15 | 19 | 19 | |||||||||
Gains made on the exercise of share options | 2 | 2 | 1 | |||||||||
Amounts awarded under incentive schemes | 4 | 2 | – | |||||||||
$ million | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Total for all senior management | ||||||||||||
Short-term employee benefits | 25 | 36 | 34 | |||||||||
Post-retirement benefits | 3 | 3 | 4 | |||||||||
Share-based payments | 29 | 20 | 20 | |||||||||
BP Annual Report and Form 20-F 2010 217
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218 BP Annual Report and Form 20-F 2010
Table of Contents
BP Annual Report and Form 20-F 2010 219
Table of Contents
Country of | ||||||||||
Subsidiaries | % | incorporation | Principal activities | |||||||
International | ||||||||||
*BP Corporate Holdings | 100 | England & Wales | Investment holding | |||||||
*BP Europa SE | 100 | Germany | Refining and marketing and petrochemicals | |||||||
BP Exploration Op. Co. | 100 | England & Wales | Exploration and production | |||||||
*BP Global Investments | 100 | England & Wales | Investment holding | |||||||
*BP International | 100 | England & Wales | Integrated oil operations, investment holding, finance | |||||||
BP Oil International | 100 | England & Wales | Integrated oil operations | |||||||
*BP Shipping | 100 | England & Wales | Shipping | |||||||
*Burmah Castrol | 100 | Scotland | Lubricants | |||||||
Jupiter Insurance | 100 | Guernsey | Insurance | |||||||
Algeria | ||||||||||
BP Amoco Exploration (In Amenas) | 100 | Scotland | Exploration and production | |||||||
BP Exploration (El Djazair) | 100 | Bahamas | Exploration and production | |||||||
Angola | ||||||||||
BP Exploration (Angola) | 100 | England & Wales | Exploration and production | |||||||
Australia | ||||||||||
BP Oil Australia | 100 | Australia | Integrated oil operations | |||||||
BP Australia Capital Markets | 100 | Australia | Finance | |||||||
BP Developments Australia | 100 | Australia | Exploration and production | |||||||
BP Finance Australia | 100 | Australia | Finance | |||||||
Azerbaijan | ||||||||||
Amoco Caspian Sea Petroleum | 100 | British Virgin Islands | Exploration and production | |||||||
BP Exploration (Caspian Sea) | 100 | England & Wales | Exploration and production | |||||||
Canada | ||||||||||
BP Canada Energy | 100 | Canada | Exploration and production | |||||||
BP Canada Finance | 100 | Canada | Finance | |||||||
Egypt | ||||||||||
BP Egypt Co. | 100 | US | Exploration and production | |||||||
Indonesia | ||||||||||
BP Berau | 100 | US | Exploration and production | |||||||
New Zealand | ||||||||||
BP Oil New Zealand | 100 | New Zealand | Marketing | |||||||
Norway | ||||||||||
BP Norge | 100 | Norway | Exploration and production | |||||||
Spain | ||||||||||
BP España | 100 | Spain | Refining and marketing | |||||||
South Africa | ||||||||||
*BP Southern Africa | 75 | South Africa | Refining and marketing | |||||||
Trinidad & Tobago | ||||||||||
BP Trinidad and Tobago | 70 | US | Exploration and production | |||||||
UK | ||||||||||
BP Capital Markets | 100 | England & Wales | Finance | |||||||
BP Oil UK | 100 | England & Wales | Marketing | |||||||
Britoil | 100 | Scotland | Exploration and production | |||||||
US | ||||||||||
*BP Holdings North America | 100 | England & Wales | Investment holding | |||||||
Atlantic Richfield Co. | 100 | US | ||||||||
BP America | 100 | US | ||||||||
BP America Production Company | 100 | US | ||||||||
BP Amoco Chemical Company | 100 | US | ||||||||
BP Company North America | 100 | US | ||||||||
BP Corporation North America | 100 | US | Exploration and production, refining and | |||||||
BP Exploration and Production | 100 | US | marketing, pipelines and petrochemicals | |||||||
BP Exploration (Alaska) | 100 | US | ||||||||
BP Products North America | 100 | US | ||||||||
BP West Coast Products | 100 | US | ||||||||
Standard Oil Co. | 100 | US | ||||||||
Verano Collateral Holdings | 100 | US | ||||||||
BP Capital Markets America | 100 | US | Finance | |||||||
220 BP Annual Report and Form 20-F 2010
Table of Contents
Country of incorporation | ||||||||
Jointly controlled entities | % | or registration | Principal activities | |||||
Angola | ||||||||
Angola LNG Supply Services | 14 | US | LNG processing and transportation | |||||
Argentina | ||||||||
Pan American Energya b | 60 | US | Exploration and production | |||||
Canada | ||||||||
Sunrise Oil Sands | 50 | Canada | Exploration and production | |||||
China | ||||||||
Shanghai SECCO Petrochemical Co. | 50 | China | Petrochemicals | |||||
Germany | ||||||||
Ruhr Oel | 50 | Germany | Refining and marketing and petrochemicals | |||||
Russia | ||||||||
Elvary Neftegaz Holdings BV | 49 | Netherlands | Exploration and appraisal | |||||
Trinidad & Tobago | ||||||||
Atlantic 4 Holdings | 38 | US | LNG manufacture | |||||
Atlantic LNG 2/3 Company of Trinidad and Tobago | 43 | Trinidad & Tobago | LNG manufacture | |||||
US | ||||||||
BP-Husky Refining | 50 | US | Refining | |||||
Watson Cogenerationa | 51 | US | Power generation | |||||
Venezuela | ||||||||
Petromonagasb | 17 | Venezuela | Exploration and production | |||||
a | The entity is not controlled by BP as certain key business decisions require joint approval of both BP and the minority partner. It is therefore classified as a jointly controlled entity rather than a subsidiary. |
b | As at 31 December 2010 the group’s interests in Pan American Energy and Petromonagas have been reclassified as assets held for sale. See Note 4 for further information. |
Associates | % | Country of incorporation | Principal activities | |||||
Abu Dhabi | ||||||||
Abu Dhabi Marine Areas | 37 | England & Wales | Crude oil production | |||||
Abu Dhabi Petroleum Co. | 24 | England & Wales | Crude oil production | |||||
Azerbaijan | ||||||||
The Baku-Tbilisi-Ceyhan Pipeline Co. | 30 | Cayman Islands | Pipelines | |||||
South Caucasus Pipeline Co. | 26 | Cayman Islands | Pipelines | |||||
Russia | ||||||||
TNK-BP | 50 | British Virgin Islands | Integrated oil operations | |||||
BP Annual Report and Form 20-F 2010 221
Table of Contents
$ million | ||||||||||||||||||||
For the year ended 31 December | 2010 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Sales and other operating revenues | 4,793 | – | 297,107 | (4,793 | ) | 297,107 | ||||||||||||||
Earnings from jointly controlled entities – after interest and tax | – | – | 1,175 | – | 1,175 | |||||||||||||||
Earnings from associates – after interest and tax | – | – | 3,582 | – | 3,582 | |||||||||||||||
Equity-accounted income of subsidiaries – after interest and tax | 620 | (3,567 | ) | – | 2,947 | – | ||||||||||||||
Interest and other revenues | – | 188 | 714 | (221 | ) | 681 | ||||||||||||||
Gains on sale of businesses and fixed assets | – | 260 | 6,376 | (253 | ) | 6,383 | ||||||||||||||
Total revenues and other income | 5,413 | (3,119 | ) | 308,954 | (2,320 | ) | 308,928 | |||||||||||||
Purchases | 637 | – | 220,367 | (4,793 | ) | 216,211 | ||||||||||||||
Production and manufacturing expenses | 966 | – | 63,649 | – | 64,615 | |||||||||||||||
Production and similar taxes | 998 | – | 4,246 | – | 5,244 | |||||||||||||||
Depreciation, depletion and amortization | 351 | – | 10,813 | – | 11,164 | |||||||||||||||
Impairment and losses on sale of businesses and fixed assets | 1,524 | – | 1,689 | (1,524 | ) | 1,689 | ||||||||||||||
Exploration expense | – | – | 843 | – | 843 | |||||||||||||||
Distribution and administration expenses | 16 | 673 | 11,975 | (109 | ) | 12,555 | ||||||||||||||
Fair value loss on embedded derivatives | – | – | 309 | – | 309 | |||||||||||||||
Profit (loss) before interest and taxation | 921 | (3,792 | ) | (4,937 | ) | 4,106 | (3,702 | ) | ||||||||||||
Finance costs | 2 | 31 | 1,249 | (112 | ) | 1,170 | ||||||||||||||
Net finance (income) expense relating to pensions and other post-retirement benefits | 4 | (388 | ) | 337 | – | (47 | ) | |||||||||||||
Profit (loss) before taxation | 915 | (3,435 | ) | (6,523 | ) | 4,218 | (4,825 | ) | ||||||||||||
Taxation | 143 | 31 | (1,675 | ) | – | (1,501 | ) | |||||||||||||
Profit (loss) for the year | 772 | (3,466 | ) | (4,848 | ) | 4,218 | (3,324 | ) | ||||||||||||
Attributable to | ||||||||||||||||||||
BP shareholders | 772 | (3,466 | ) | (5,243 | ) | 4,218 | (3,719 | ) | ||||||||||||
Minority interest | – | – | 395 | – | 395 | |||||||||||||||
772 | (3,466 | ) | (4,848 | ) | 4,218 | (3,324 | ) | |||||||||||||
222 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||
For the year ended 31 December | 2009 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Sales and other operating revenues | 4,189 | – | 239,272 | (4,189 | ) | 239,272 | ||||||||||||||
Earnings from jointly controlled entities – after interest and tax | – | – | 1,286 | – | 1,286 | |||||||||||||||
Earnings from associates – after interest and tax | – | – | 2,615 | – | 2,615 | |||||||||||||||
Equity-accounted income of subsidiaries – after interest and tax | 838 | 17,315 | – | (18,153 | ) | – | ||||||||||||||
Interest and other revenues | 17 | 144 | 832 | (201 | ) | 792 | ||||||||||||||
Gains on sale of businesses and fixed assets | – | 9 | 2,173 | (9 | ) | 2,173 | ||||||||||||||
Total revenues and other income | 5,044 | 17,468 | 246,178 | (22,552 | ) | 246,138 | ||||||||||||||
Purchases | 510 | – | 167,451 | (4,189 | ) | 163,772 | ||||||||||||||
Production and manufacturing expenses | 970 | – | 22,232 | – | 23,202 | |||||||||||||||
Production and similar taxes | 602 | – | 3,150 | – | 3,752 | |||||||||||||||
Depreciation, depletion and amortization | 424 | – | 11,682 | – | 12,106 | |||||||||||||||
Impairment and losses on sale of businesses and fixed assets | – | – | 2,333 | – | 2,333 | |||||||||||||||
Exploration expense | – | – | 1,116 | – | 1,116 | |||||||||||||||
Distribution and administration expenses | 27 | 1,145 | 12,974 | (108 | ) | 14,038 | ||||||||||||||
Fair value gain on embedded derivatives | – | – | (607 | ) | – | (607 | ) | |||||||||||||
Profit before interest and taxation | 2,511 | 16,323 | 25,847 | (18,255 | ) | 26,426 | ||||||||||||||
Finance costs | 22 | 26 | 1,155 | (93 | ) | 1,110 | ||||||||||||||
Net finance (income) expense relating to pensions and other post-retirement benefits | 10 | (310 | ) | 492 | – | 192 | ||||||||||||||
Profit before taxation | 2,479 | 16,607 | 24,200 | (18,162 | ) | 25,124 | ||||||||||||||
Taxation | 583 | 20 | 7,762 | – | 8,365 | |||||||||||||||
Profit for the year | 1,896 | 16,587 | 16,438 | (18,162 | ) | 16,759 | ||||||||||||||
Attributable to | ||||||||||||||||||||
BP shareholders | 1,896 | 16,587 | 16,257 | (18,162 | ) | 16,578 | ||||||||||||||
Minority interest | – | – | 181 | – | 181 | |||||||||||||||
1,896 | 16,587 | 16,438 | (18,162 | ) | 16,759 | |||||||||||||||
BP Annual Report and Form 20-F 2010 223
Table of Contents
$ million | ||||||||||||||||||||
For the year ended 31 December | 2008 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Sales and other operating revenues | 6,782 | – | 361,143 | (6,782 | ) | 361,143 | ||||||||||||||
Earnings from jointly controlled entities – after interest and tax | – | – | 3,023 | – | 3,023 | |||||||||||||||
Earnings from associates – after interest and tax | – | – | 798 | – | 798 | |||||||||||||||
Equity-accounted income of subsidiaries – after interest and tax | 469 | 20,295 | – | (20,764 | ) | – | ||||||||||||||
Interest and other revenues | 514 | 173 | 1,025 | (976 | ) | 736 | ||||||||||||||
Gains on sale of businesses and fixed assets | – | – | 1,353 | – | 1,353 | |||||||||||||||
Total revenues and other income | 7,765 | 20,468 | 367,342 | (28,522 | ) | 367,053 | ||||||||||||||
Purchases | 895 | – | 272,869 | (6,782 | ) | 266,982 | ||||||||||||||
Production and manufacturing expenses | 1,083 | – | 25,673 | – | 26,756 | |||||||||||||||
Production and similar taxes | 2,343 | – | 6,610 | – | 8,953 | |||||||||||||||
Depreciation, depletion and amortization | 365 | – | 10,620 | – | 10,985 | |||||||||||||||
Impairment and losses on sale of businesses and fixed assets | – | – | 1,733 | – | 1,733 | |||||||||||||||
Exploration expense | – | – | 882 | – | 882 | |||||||||||||||
Distribution and administration expenses | 22 | 28 | 15,469 | (107 | ) | 15,412 | ||||||||||||||
Fair value loss on embedded derivatives | – | – | 111 | – | 111 | |||||||||||||||
Profit before interest and taxation | 3,057 | 20,440 | 33,375 | (21,633 | ) | 35,239 | ||||||||||||||
Finance costs | 158 | 169 | 2,089 | (869 | ) | 1,547 | ||||||||||||||
Net finance (income) expense relating to pensions and | ||||||||||||||||||||
other post-retirement benefits | – | (822 | ) | 231 | – | (591 | ) | |||||||||||||
Profit before taxation | 2,899 | 21,093 | 31,055 | (20,764 | ) | 34,283 | ||||||||||||||
Taxation | 944 | (64 | ) | 11,737 | – | 12,617 | ||||||||||||||
Profit for the year | 1,955 | 21,157 | 19,318 | (20,764 | ) | 21,666 | ||||||||||||||
Attributable to | ||||||||||||||||||||
BP shareholders | 1,955 | 21,157 | 18,809 | (20,764 | ) | 21,157 | ||||||||||||||
Minority interest | – | – | 509 | – | 509 | |||||||||||||||
1,955 | 21,157 | 19,318 | (20,764 | ) | 21,666 | |||||||||||||||
224 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||
At 31 December | 2010 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Non-current assets | ||||||||||||||||||||
Property, plant and equipment | 7,679 | – | 102,484 | – | 110,163 | |||||||||||||||
Goodwill | – | – | 8,598 | – | 8,598 | |||||||||||||||
Intangible assets | 425 | – | 13,873 | – | 14,298 | |||||||||||||||
Investments in jointly controlled entities | – | – | 12,286 | – | 12,286 | |||||||||||||||
Investments in associates | – | 2 | 13,333 | – | 13,335 | |||||||||||||||
Other investments | – | – | 1,191 | – | 1,191 | |||||||||||||||
Subsidiaries – equity-accounted basis | 4,489 | 112,227 | – | (116,716 | ) | – | ||||||||||||||
Fixed assets | 12,593 | 112,229 | 151,765 | (116,716 | ) | 159,871 | ||||||||||||||
Loans | – | 38 | 5,161 | (4,305 | ) | 894 | ||||||||||||||
Other receivables | – | – | 6,298 | – | 6,298 | |||||||||||||||
Derivative financial instruments | – | – | 4,210 | – | 4,210 | |||||||||||||||
Prepayments | – | – | 1,432 | – | 1,432 | |||||||||||||||
Deferred tax assets | – | – | 528 | – | 528 | |||||||||||||||
Defined benefit pension plan surpluses | – | 1,870 | 306 | – | 2,176 | |||||||||||||||
12,593 | 114,137 | 169,700 | (121,021 | ) | 175,409 | |||||||||||||||
Current assets | ||||||||||||||||||||
Loans | – | – | 247 | – | 247 | |||||||||||||||
Inventories | 244 | – | 25,974 | – | 26,218 | |||||||||||||||
Trade and other receivables | 3,173 | 14,444 | 42,783 | (23,851 | ) | 36,549 | ||||||||||||||
Derivative financial instruments | – | – | 4,356 | – | 4,356 | |||||||||||||||
Prepayments | 6 | – | 1,568 | – | 1,574 | |||||||||||||||
Current tax receivable | – | – | 693 | – | 693 | |||||||||||||||
Other investments | – | – | 1,532 | – | 1,532 | |||||||||||||||
Cash and cash equivalents | (1 | ) | 4 | 18,553 | – | 18,556 | ||||||||||||||
3,422 | 14,448 | 95,706 | (23,851 | ) | 89,725 | |||||||||||||||
Assets classified as held for sale | – | – | 7,128 | – | 7,128 | |||||||||||||||
Total assets | 16,015 | 128,585 | 272,534 | (144,872 | ) | 272,262 | ||||||||||||||
Current liabilities | ||||||||||||||||||||
Trade and other payables | 4,931 | 2,362 | 62,887 | (23,851 | ) | 46,329 | ||||||||||||||
Derivative financial instruments | – | – | 3,856 | – | 3,856 | |||||||||||||||
Accruals | – | 23 | 5,589 | – | 5,612 | |||||||||||||||
Finance debt | – | – | 14,626 | – | 14,626 | |||||||||||||||
Current tax payable | 182 | – | 2,738 | – | 2,920 | |||||||||||||||
Provisions | – | – | 9,489 | – | 9,489 | |||||||||||||||
5,113 | 2,385 | 99,185 | (23,851 | ) | 82,832 | |||||||||||||||
Liabilities directly associated with assets classified as held for sale | – | – | 1,047 | – | 1,047 | |||||||||||||||
5,113 | 2,385 | 100,232 | (23,851 | ) | 83,879 | |||||||||||||||
Non-current liabilities | ||||||||||||||||||||
Other payables | 9 | 4,258 | 14,323 | (4,305 | ) | 14,285 | ||||||||||||||
Derivative financial instruments | – | – | 3,677 | – | 3,677 | |||||||||||||||
Accruals | – | 35 | 602 | – | 637 | |||||||||||||||
Finance debt | – | – | 30,710 | – | 30,710 | |||||||||||||||
Deferred tax liabilities | 2,026 | 410 | 8,472 | – | 10,908 | |||||||||||||||
Provisions | 958 | – | 21,460 | – | 22,418 | |||||||||||||||
Defined benefit pension plan and other post-retirement benefit plan deficits | – | – | 9,857 | – | 9,857 | |||||||||||||||
2,993 | 4,703 | 89,101 | (4,305 | ) | 92,492 | |||||||||||||||
Total liabilities | 8,106 | 7,088 | 189,333 | (28,156 | ) | 176,371 | ||||||||||||||
Net assets | 7,909 | 121,497 | 83,201 | (116,716 | ) | 95,891 | ||||||||||||||
Equity | ||||||||||||||||||||
BP shareholders’ equity | 7,909 | 121,497 | 82,297 | (116,716 | ) | 94,987 | ||||||||||||||
Minority interest | – | – | 904 | – | 904 | |||||||||||||||
Total equity | 7,909 | 121,497 | 83,201 | (116,716 | ) | 95,891 | ||||||||||||||
BP Annual Report and Form 20-F 2010 225
Table of Contents
$ million | ||||||||||||||||||||
At 31 December | 2009 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Non-current assets | ||||||||||||||||||||
Property, plant and equipment | 7,366 | – | 100,909 | – | 108,275 | |||||||||||||||
Goodwill | – | – | 8,620 | – | 8,620 | |||||||||||||||
Intangible assets | 321 | – | 11,227 | – | 11,548 | |||||||||||||||
Investments in jointly controlled entities | – | – | 15,296 | – | 15,296 | |||||||||||||||
Investments in associates | – | 2 | 12,961 | – | 12,963 | |||||||||||||||
Other investments | – | – | 1,567 | – | 1,567 | |||||||||||||||
Subsidiaries – equity-accounted basis | 4,424 | 101,760 | – | (106,184 | ) | – | ||||||||||||||
Fixed assets | 12,111 | 101,762 | 150,580 | (106,184 | ) | 158,269 | ||||||||||||||
Loans | 283 | 1,178 | 5,490 | (5,912 | ) | 1,039 | ||||||||||||||
Other receivables | – | – | 1,729 | – | 1,729 | |||||||||||||||
Derivative financial instruments | – | – | 3,965 | – | 3,965 | |||||||||||||||
Prepayments | – | – | 1,407 | – | 1,407 | |||||||||||||||
Deferred tax assets | – | – | 516 | – | 516 | |||||||||||||||
Defined benefit pension plan surpluses | – | 1,071 | 319 | – | 1,390 | |||||||||||||||
12,394 | 104,011 | 164,006 | (112,096 | ) | 168,315 | |||||||||||||||
Current assets | ||||||||||||||||||||
Loans | – | – | 249 | – | 249 | |||||||||||||||
Inventories | 221 | – | 22,384 | – | 22,605 | |||||||||||||||
Trade and other receivables | 18,529 | 30,707 | 35,852 | (55,557 | ) | 29,531 | ||||||||||||||
Derivative financial instruments | – | – | 4,967 | – | 4,967 | |||||||||||||||
Prepayments | 8 | 2 | 1,743 | – | 1,753 | |||||||||||||||
Current tax receivable | – | – | 209 | – | 209 | |||||||||||||||
Cash and cash equivalents | (22 | ) | 28 | 8,333 | – | 8,339 | ||||||||||||||
18,736 | 30,737 | 73,737 | (55,557 | ) | 67,653 | |||||||||||||||
Total assets | 31,130 | 134,748 | 237,743 | (167,653 | ) | 235,968 | ||||||||||||||
Current liabilities | ||||||||||||||||||||
Trade and other payables | 4,662 | 2,374 | 83,725 | (55,557 | ) | 35,204 | ||||||||||||||
Derivative financial instruments | – | – | 4,681 | – | 4,681 | |||||||||||||||
Accruals | – | 27 | 6,175 | – | 6,202 | |||||||||||||||
Finance debt | 55 | – | 9,054 | – | 9,109 | |||||||||||||||
Current tax payable | 172 | – | 2,292 | – | 2,464 | |||||||||||||||
Provisions | – | – | 1,660 | – | 1,660 | |||||||||||||||
4,889 | 2,401 | �� | 107,587 | (55,557 | ) | 59,320 | ||||||||||||||
Non-current liabilities | ||||||||||||||||||||
Other payables | 229 | 4,254 | 4,627 | (5,912 | ) | 3,198 | ||||||||||||||
Derivative financial instruments | – | – | 3,474 | – | 3,474 | |||||||||||||||
Accruals | – | 74 | 629 | – | 703 | |||||||||||||||
Finance debt | – | – | 25,518 | – | 25,518 | |||||||||||||||
Deferred tax liabilities | 1,872 | 149 | 16,641 | – | 18,662 | |||||||||||||||
Provisions | 1,048 | – | 11,922 | – | 12,970 | |||||||||||||||
Defined benefit pension plan and other post-retirement benefit plan deficits | – | – | 10,010 | – | 10,010 | |||||||||||||||
3,149 | 4,477 | 72,821 | (5,912 | ) | 74,535 | |||||||||||||||
Total liabilities | 8,038 | 6,878 | 180,408 | (61,469 | ) | 133,855 | ||||||||||||||
Net assets | 23,092 | 127,870 | 57,335 | (106,184 | ) | 102,113 | ||||||||||||||
Equity | ||||||||||||||||||||
BP shareholders’ equity | 23,092 | 127,870 | 56,835 | (106,184 | ) | 101,613 | ||||||||||||||
Minority interest | – | – | 500 | – | 500 | |||||||||||||||
Total equity | 23,092 | 127,870 | 57,335 | (106,184 | ) | 102,113 | ||||||||||||||
226 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||
For the year ended 31 December | 2010 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Net cash provided by operating activities | 829 | 32,111 | (4,584 | ) | (14,740 | ) | 13,616 | |||||||||||||
Net cash used in investing activities | (752 | ) | (29,325 | ) | 26,117 | – | (3,960 | ) | ||||||||||||
Net cash (used in) provided by financing activities | (56 | ) | (2,810 | ) | (11,034 | ) | 14,740 | 840 | ||||||||||||
Currency translation differences relating to cash and cash equivalents | – | – | (279 | ) | – | (279 | ) | |||||||||||||
(Decrease) increase in cash and cash equivalents | 21 | (24 | ) | 10,220 | – | 10,217 | ||||||||||||||
Cash and cash equivalents at beginning of year | (22 | ) | 28 | 8,333 | – | 8,339 | ||||||||||||||
Cash and cash equivalents at end of year | (1 | ) | 4 | 18,553 | – | 18,556 | ||||||||||||||
$ million | ||||||||||||||||||||
For the year ended 31 December | 2009 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Net cash provided by operating activities | 1,022 | 14,514 | 47,466 | (35,286 | ) | 27,716 | ||||||||||||||
Net cash used in investing activities | (935 | ) | (4,227 | ) | (12,971 | ) | – | (18,133 | ) | |||||||||||
Net cash used in financing activities | (99 | ) | (10,270 | ) | (34,468 | ) | 35,286 | (9,551 | ) | |||||||||||
Currency translation differences relating to cash and cash equivalents | – | – | 110 | – | 110 | |||||||||||||||
(Decrease) increase in cash and cash equivalents | (12 | ) | 17 | 137 | – | 142 | ||||||||||||||
Cash and cash equivalents at beginning of year | (10 | ) | 11 | 8,196 | – | 8,197 | ||||||||||||||
Cash and cash equivalents at end of year | (22 | ) | 28 | 8,333 | – | 8,339 | ||||||||||||||
$ million | ||||||||||||||||||||
For the year ended 31 December | 2008 | |||||||||||||||||||
Issuer | Guarantor | |||||||||||||||||||
BP | Eliminations | |||||||||||||||||||
Exploration | Other | and | ||||||||||||||||||
(Alaska) Inc. | BP p.l.c. | subsidiaries | reclassifications | BP group | ||||||||||||||||
Net cash provided by operating activities | 1,105 | 12,665 | 41,600 | (17,275 | ) | 38,095 | ||||||||||||||
Net cash used in investing activities | (896 | ) | – | (21,871 | ) | – | (22,767 | ) | ||||||||||||
Net cash used in financing activities | (209 | ) | (12,898 | ) | (14,677 | ) | 17,275 | (10,509 | ) | |||||||||||
Currency translation differences relating to cash and cash equivalents | – | – | (184 | ) | – | (184 | ) | |||||||||||||
(Decrease) increase in cash and cash equivalents | – | (233 | ) | 4,868 | – | 4,635 | ||||||||||||||
Cash and cash equivalents at beginning of year | (10 | ) | 244 | 3,328 | – | 3,562 | ||||||||||||||
Cash and cash equivalents at end of year | (10 | ) | 11 | 8,196 | – | 8,197 | ||||||||||||||
BP Annual Report and Form 20-F 2010 227
Table of Contents
(i) | The area of the reservoir considered as proved includes: |
(A) | The area identified by drilling and limited by fluid contacts, if any; and | ||
(B) | Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. |
(ii) | In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. | |
(iii) | Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. | |
(iv) | Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: |
(A) | Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or programme was based; and | ||
(B) | The project has been approved for development by all necessary parties and entities, including governmental entities. |
(v) | Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. |
(i) | Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. | |
(ii) | Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. | |
(iii) | Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty. |
(i) | Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and | |
(ii) | Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. |
228 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiariesa | ||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb j | ||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs | ||||||||||||||||||||||||||||||||||||||||
Proved properties | 36,161 | 7,846 | 67,724 | 278 | 6,047 | 27,014 | – | 11,497 | 3,088 | 159,655 | ||||||||||||||||||||||||||||||
Unproved properties | 787 | 179 | 5,968 | 1,363 | 220 | 2,694 | – | 1,113 | 1,149 | 13,473 | ||||||||||||||||||||||||||||||
36,948 | 8,025 | 73,692 | 1,641 | 6,267 | 29,708 | – | 12,610 | 4,237 | 173,128 | |||||||||||||||||||||||||||||||
Accumulated depreciation | 27,688 | 3,515 | 33,972 | 216 | 3,282 | 13,893 | – | 4,569 | 1,205 | 88,340 | ||||||||||||||||||||||||||||||
Net capitalized costs | 9,260 | 4,510 | 39,720 | 1,425 | 2,985 | 15,815 | – | 8,041 | 3,032 | 84,788 | ||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb j | ||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc | ||||||||||||||||||||||||||||||||||||||||
Proved | – | – | 655 | 1 | – | – | – | 1,121 | – | 1,777 | ||||||||||||||||||||||||||||||
Unproved | – | 519 | 1,599 | 1,200 | – | – | – | 151 | – | 3,469 | ||||||||||||||||||||||||||||||
– | 519 | 2,254 | 1,201 | – | – | – | 1,272 | – | 5,246 | |||||||||||||||||||||||||||||||
Exploration and appraisal costsd | 401 | 13 | 1,096 | 78 | 68 | 607 | 7 | 316 | 120 | 2,706 | ||||||||||||||||||||||||||||||
Development | 726 | 816 | 3,034 | 251 | 414 | 3,003 | – | 1,244 | 187 | 9,675 | ||||||||||||||||||||||||||||||
Total costs | 1,127 | 1,348 | 6,384 | 1,530 | 482 | 3,610 | 7 | 2,832 | 307 | 17,627 | ||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December | ||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese | ||||||||||||||||||||||||||||||||||||||||
Third parties | 1,472 | 58 | 1,148 | 90 | 1,896 | 3,158 | – | 1,272 | 1,398 | 10,492 | ||||||||||||||||||||||||||||||
Sales between businesses | 3,405 | 1,134 | 18,819 | 453 | 1,574 | 4,353 | – | 6,697 | 929 | 37,364 | ||||||||||||||||||||||||||||||
4,877 | 1,192 | 19,967 | 543 | 3,470 | 7,511 | – | 7,969 | 2,327 | 47,856 | |||||||||||||||||||||||||||||||
Exploration expenditure | 82 | (2 | ) | 465 | 25 | 9 | 189 | 7 | 51 | 17 | 843 | |||||||||||||||||||||||||||||
Production costs | 1,018 | 152 | 2,867 | 240 | 445 | 938 | 9 | 365 | 124 | 6,158 | ||||||||||||||||||||||||||||||
Production taxes | 52 | – | 1,093 | 2 | 249 | – | – | 3,764 | 109 | 5,269 | ||||||||||||||||||||||||||||||
Other costs (income)f | (316 | ) | 76 | 3,502 | 129 | 209 | 130 | 76 | 90 | 195 | 4,091 | |||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 897 | 209 | 3,477 | 95 | 575 | 1,771 | – | 829 | 168 | 8,021 | ||||||||||||||||||||||||||||||
Impairments and (gains) losses on sale of businesses and fixed assets | (1 | ) | – | (1,441 | ) | (2,190 | ) | (3 | ) | (427 | ) | 341 | k | – | – | (3,721 | ) | |||||||||||||||||||||||
1,732 | 435 | 9,963 | (1,699 | ) | 1,484 | 2,601 | 433 | 5,099 | 613 | 20,661 | ||||||||||||||||||||||||||||||
Profit (loss) before taxationg | 3,145 | 757 | 10,004 | 2,242 | 1,986 | 4,910 | (433 | ) | 2,870 | 1,714 | 27,195 | |||||||||||||||||||||||||||||
Allocable taxes | 1,333 | 530 | 3,504 | 610 | 1,084 | 1,771 | (23 | ) | 813 | 410 | 10,032 | |||||||||||||||||||||||||||||
Results of operations | 1,812 | 227 | 6,500 | 1,632 | 902 | 3,139 | (410 | ) | 2,057 | 1,304 | 17,163 | |||||||||||||||||||||||||||||
Exploration and Production segment replacement cost profit before interest and tax | ||||||||||||||||||||||||||||||||||||||||
Exploration and production activities – subsidiaries (as above) | 3,145 | 757 | 10,004 | 2,242 | 1,986 | 4,910 | (433 | ) | 2,870 | 1,714 | 27,195 | |||||||||||||||||||||||||||||
Midstream activities – subsidiariesh | 23 | 42 | (347 | ) | 3 | 49 | (26 | ) | 4 | (23 | ) | (13 | ) | (288 | ) | |||||||||||||||||||||||||
Equity-accounted entitiesi | – | 4 | 27 | 171 | 614 | 63 | 2,613 | 487 | – | 3,979 | ||||||||||||||||||||||||||||||
Total replacement cost profit before interest and tax | 3,168 | 803 | 9,684 | 2,416 | 2,649 | 4,947 | 2,184 | 3,334 | 1,701 | 30,886 | ||||||||||||||||||||||||||||||
a | These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. They do not include any costs relating to the Gulf of Mexico oil spill. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs, purchases and sales taxes. |
f | Includes property taxes, other government take and the fair value loss on embedded derivatives of $309 million. The UK region includes a $822 million gain offset by corresponding charges primarily in the US, relating to the group self-insurance programme. |
g | Excludes the unwinding of the discount on provisions and payables amounting to $313 million which is included in finance costs in the group income statement. |
h | Midstream activities exclude inventory holding gains and losses. |
i | The profits of equity-accounted entities are included after interest and tax. |
j | Excludes balances associated with assets held for sale. |
k | This amount represents the write-down of our investment in Sakhalin. A portion of these costs was previously reported within capitalized costs of equity accounted entities with the remainder previously reported as a loan, which was not included in the disclosures of oil and natural gas exploration and production activities. |
BP Annual Report and Form 20-F 2010 229
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)a | ||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs | ||||||||||||||||||||||||||||||||||||||||
Proved properties | – | – | – | 142 | 103 | – | 14,486 | 3,192 | – | 17,923 | ||||||||||||||||||||||||||||||
Unproved properties | – | – | – | 1,284 | – | – | 652 | – | – | 1,936 | ||||||||||||||||||||||||||||||
– | – | – | 1,426 | 103 | – | 15,138 | 3,192 | – | 19,859 | |||||||||||||||||||||||||||||||
Accumulated depreciation | – | – | – | – | – | – | 6,300 | 2,674 | – | 8,974 | ||||||||||||||||||||||||||||||
Net capitalized costs | – | – | – | 1,426 | 103 | – | 8,838 | 518 | – | 10,885 | ||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc | ||||||||||||||||||||||||||||||||||||||||
Proved | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Unproved | – | – | – | – | 9 | – | 66 | – | – | 75 | ||||||||||||||||||||||||||||||
– | – | – | – | 9 | – | 66 | – | – | 75 | |||||||||||||||||||||||||||||||
Exploration and appraisal costsd | – | – | – | – | 2 | – | 94 | – | – | 96 | ||||||||||||||||||||||||||||||
Development | – | – | – | 49 | 549 | – | 1,416 | 355 | – | 2,369 | ||||||||||||||||||||||||||||||
Total costs | – | – | – | 49 | 560 | – | 1,576 | 355 | – | 2,540 | ||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December | ||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese | ||||||||||||||||||||||||||||||||||||||||
Third parties | – | – | – | – | 2,268 | – | 5,610 | 87 | – | 7,965 | ||||||||||||||||||||||||||||||
Sales between businesses | – | – | – | – | – | – | 3,432 | 460 | – | 3,892 | ||||||||||||||||||||||||||||||
– | – | – | – | 2,268 | – | 9,042 | 547 | – | 11,857 | |||||||||||||||||||||||||||||||
Exploration expenditure | – | – | – | – | 22 | – | 40 | – | – | 62 | ||||||||||||||||||||||||||||||
Production costs | – | – | – | – | 316 | – | 1,602 | 184 | – | 2,102 | ||||||||||||||||||||||||||||||
Production taxes | – | – | – | – | 911 | – | 3,567 | – | – | 4,478 | ||||||||||||||||||||||||||||||
Other costs (income) | – | – | – | 67 | 75 | – | 3 | (2 | ) | – | 143 | |||||||||||||||||||||||||||||
Depreciation, depletion and amortization | – | – | – | – | 269 | – | 954 | 363 | – | 1,586 | ||||||||||||||||||||||||||||||
Impairments and losses on sale of businesses and fixed assets | – | – | – | – | – | – | 43 | – | – | 43 | ||||||||||||||||||||||||||||||
– | – | – | 67 | 1,593 | – | 6,209 | 545 | – | 8,414 | |||||||||||||||||||||||||||||||
Profit (loss) before taxation | – | – | – | (67 | ) | 675 | – | 2,833 | 2 | – | 3,443 | |||||||||||||||||||||||||||||
Allocable taxes | – | – | – | – | 260 | – | 475 | 33 | – | 768 | ||||||||||||||||||||||||||||||
Results of operations | – | – | – | (67 | ) | 415 | – | 2,358 | (31 | ) | – | 2,675 | ||||||||||||||||||||||||||||
Exploration and production activities – equity-accounted entities after tax (as above) | – | – | – | (67 | ) | 415 | – | 2,358 | (31 | ) | – | 2,675 | ||||||||||||||||||||||||||||
Midstream and other activities after taxf | – | 4 | 27 | 238 | 199 | 63 | 255 | 518 | – | 1,304 | ||||||||||||||||||||||||||||||
Total replacement cost profit after interest and tax | – | 4 | 27 | 171 | 614 | 63 | 2,613 | 487 | – | 3,979 | ||||||||||||||||||||||||||||||
a | These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs and sales taxes. |
f | Includes interest, minority interest and the net results of equity-accounted entities of equity-accounted entities. |
230 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiariesa | ||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs | ||||||||||||||||||||||||||||||||||||||||
Proved properties | 35,096 | 6,644 | 64,366 | 3,967 | 8,346 | 24,476 | – | 10,900 | 2,894 | 156,689 | ||||||||||||||||||||||||||||||
Unproved properties | 752 | – | 5,464 | 147 | 198 | 2,377 | – | 733 | 1,039 | 10,710 | ||||||||||||||||||||||||||||||
35,848 | 6,644 | 69,830 | 4,114 | 8,544 | 26,853 | – | 11,633 | 3,933 | 167,399 | |||||||||||||||||||||||||||||||
Accumulated depreciation | 26,794 | 3,306 | 31,728 | 2,309 | 4,837 | 12,492 | – | 4,798 | 1,038 | 87,302 | ||||||||||||||||||||||||||||||
Net capitalized costs | 9,054 | 3,338 | 38,102 | 1,805 | 3,707 | 14,361 | – | 6,835 | 2,895 | 80,097 | ||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc | ||||||||||||||||||||||||||||||||||||||||
Proved | 179 | – | (17 | ) | – | – | – | – | 306 | – | 468 | |||||||||||||||||||||||||||||
Unproved | (1 | ) | – | 370 | 1 | – | 18 | – | – | 10 | 398 | |||||||||||||||||||||||||||||
178 | – | 353 | 1 | – | 18 | – | 306 | 10 | 866 | |||||||||||||||||||||||||||||||
Exploration and appraisal costsd | 183 | – | 1,377 | 79 | 78 | 712 | 8 | 315 | 53 | 2,805 | ||||||||||||||||||||||||||||||
Development | 751 | 1,054 | 4,208 | 386 | 453 | 2,707 | – | 560 | 277 | 10,396 | ||||||||||||||||||||||||||||||
Total costs | 1,112 | 1,054 | 5,938 | 466 | 531 | 3,437 | 8 | 1,181 | 340 | 14,067 | ||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December | ||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese | ||||||||||||||||||||||||||||||||||||||||
Third parties | 2,239 | 68 | 972 | 99 | 1,525 | 1,846 | – | 636 | 785 | 8,170 | ||||||||||||||||||||||||||||||
Sales between businesses | 2,482 | 809 | 15,100 | 484 | 1,409 | 5,313 | – | 6,257 | 726 | 32,580 | ||||||||||||||||||||||||||||||
4,721 | 877 | 16,072 | 583 | 2,934 | 7,159 | – | 6,893 | 1,511 | 40,750 | |||||||||||||||||||||||||||||||
Exploration expenditure | 59 | – | 663 | 80 | 16 | 219 | 8 | 49 | 22 | 1,116 | ||||||||||||||||||||||||||||||
Production costs | 1,243 | 164 | 2,821 | 284 | 395 | 908 | 15 | 361 | 70 | 6,261 | ||||||||||||||||||||||||||||||
Production taxes | (3 | ) | – | 649 | 1 | 220 | – | – | 2,854 | 72 | 3,793 | |||||||||||||||||||||||||||||
Other costs (income)f | (1,259 | ) | 51 | 2,353 | 145 | 184 | 144 | 76 | 967 | 178 | 2,839 | |||||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1,148 | 185 | 3,857 | 170 | 697 | 2,041 | – | 757 | 96 | 8,951 | ||||||||||||||||||||||||||||||
Impairments and (gains) losses on sale of businesses and fixed assets | (122 | ) | (7 | ) | (208 | ) | – | (11 | ) | (1 | ) | – | (702 | )j | – | (1,051 | ) | |||||||||||||||||||||||
1,066 | 393 | 10,135 | 680 | 1,501 | 3,311 | 99 | 4,286 | 438 | 21,909 | |||||||||||||||||||||||||||||||
Profit (loss) before taxationg | 3,655 | 484 | 5,937 | (97 | ) | 1,433 | 3,848 | (99 | ) | 2,607 | 1,073 | 18,841 | ||||||||||||||||||||||||||||
Allocable taxes | 1,568 | 76 | 1,902 | (58 | ) | 916 | 1,517 | (25 | ) | 682 | 2 | 6,580 | ||||||||||||||||||||||||||||
Results of operations | 2,087 | 408 | 4,035 | (39 | ) | 517 | 2,331 | (74 | ) | 1,925 | 1,071 | 12,261 | ||||||||||||||||||||||||||||
Exploration and Production segment replacement cost profit before interest and tax | ||||||||||||||||||||||||||||||||||||||||
Exploration and production activities – subsidiaries (as above) | 3,655 | 484 | 5,937 | (97 | ) | 1,433 | 3,848 | (99 | ) | 2,607 | 1,073 | 18,841 | ||||||||||||||||||||||||||||
Midstream activities – subsidiariesh j | 925 | 17 | 719 | 833 | 17 | (27 | ) | (37 | ) | 518 | (315 | ) | 2,650 | |||||||||||||||||||||||||||
Equity-accounted entitiesi | – | 5 | 29 | 134 | 630 | 56 | 1,924 | 531 | – | 3,309 | ||||||||||||||||||||||||||||||
Total replacement cost profit before interest and tax | 4,580 | 506 | 6,685 | 870 | 2,080 | 3,877 | 1,788 | 3,656 | 758 | 24,800 | ||||||||||||||||||||||||||||||
a | These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs, purchases and sales taxes. Sales between businesses and third party sales have been amended in the US without net effect to total sales. |
f | Includes property taxes, other government take and the fair value gain on embedded derivatives of $663 million. The UK region includes a $783 million gain offset by corresponding charges primarily in the US, relating to the group self-insurance programme. |
g | Excludes the unwinding of the discount on provisions and payables amounting to $308 million which is included in finance costs in the group income statement. |
h | Midstream activities exclude inventory holding gains and losses. |
i | The profits of equity-accounted entities are included after interest and tax. |
j | Includes the gain on disposal of upstream assets associated with our sale of our 46% stake in LukArco (see Note 5). |
BP Annual Report and Form 20-F 2010 231
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)a | ||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs | ||||||||||||||||||||||||||||||||||||||||
Proved properties | – | – | – | – | 5,789 | – | 13,266 | 2,259 | – | 21,314 | ||||||||||||||||||||||||||||||
Unproved properties | – | – | – | 1,378 | 197 | – | 737 | – | – | 2,312 | ||||||||||||||||||||||||||||||
– | – | – | 1,378 | 5,986 | – | 14,003 | 2,259 | – | 23,626 | |||||||||||||||||||||||||||||||
Accumulated depreciation | – | – | – | – | 2,084 | – | 5,550 | 1,739 | – | 9,373 | ||||||||||||||||||||||||||||||
Net capitalized costs | – | – | – | 1,378 | 3,902 | – | 8,453 | 520 | – | 14,253 | ||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc | ||||||||||||||||||||||||||||||||||||||||
Proved | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Unproved | – | – | – | – | 31 | – | 10 | – | – | 41 | ||||||||||||||||||||||||||||||
– | – | – | – | 31 | – | 10 | – | – | 41 | |||||||||||||||||||||||||||||||
Exploration and appraisal costsd | – | – | – | – | 21 | – | 77 | 3 | – | 101 | ||||||||||||||||||||||||||||||
Development | – | – | – | 30 | 538 | – | 1,182 | 246 | – | 1,996 | ||||||||||||||||||||||||||||||
Total costs | – | – | – | 30 | 590 | – | 1,269 | 249 | – | 2,138 | ||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December | ||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese | ||||||||||||||||||||||||||||||||||||||||
Third parties | – | – | – | – | 1,977 | – | 4,919 | 351 | – | 7,247 | ||||||||||||||||||||||||||||||
Sales between businesses | – | – | – | – | – | – | 2,838 | – | – | 2,838 | ||||||||||||||||||||||||||||||
– | – | – | – | 1,977 | – | 7,757 | 351 | – | 10,085 | |||||||||||||||||||||||||||||||
Exploration expenditure | – | – | – | – | 23 | – | 37 | – | – | 60 | ||||||||||||||||||||||||||||||
Production costs | – | – | – | – | 354 | – | 1,428 | 159 | – | 1,941 | ||||||||||||||||||||||||||||||
Production taxes | – | – | – | – | 702 | – | 2,597 | – | – | 3,299 | ||||||||||||||||||||||||||||||
Other costs (income) | – | – | – | – | (69 | ) | – | 12 | (2 | ) | – | (59 | ) | |||||||||||||||||||||||||||
Depreciation, depletion and amortization | – | – | – | – | 281 | – | 1,073 | 274 | – | 1,628 | ||||||||||||||||||||||||||||||
Impairments and losses on sale of businesses and fixed assets | – | – | – | – | – | – | 72 | – | – | 72 | ||||||||||||||||||||||||||||||
– | – | – | – | 1,291 | – | 5,219 | 431 | – | 6,941 | |||||||||||||||||||||||||||||||
Profit (loss) before taxation | – | – | – | – | 686 | – | 2,538 | (80 | ) | – | 3,144 | |||||||||||||||||||||||||||||
Allocable taxes | – | – | – | – | 270 | – | 501 | – | – | 771 | ||||||||||||||||||||||||||||||
Results of operations | – | – | – | – | 416 | – | 2,037 | (80 | ) | – | 2,373 | |||||||||||||||||||||||||||||
Exploration and production activities – equity-accounted entities after tax (as above) | – | – | – | – | 416 | – | 2,037 | (80 | ) | – | 2,373 | |||||||||||||||||||||||||||||
Midstream and other activities after taxf | – | 5 | 29 | 134 | 214 | 56 | (113 | ) | 611 | – | 936 | |||||||||||||||||||||||||||||
Total replacement cost profit after interest and tax | – | 5 | 29 | 134 | 630 | 56 | 1,924 | 531 | – | 3,309 | ||||||||||||||||||||||||||||||
a | These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs, purchases and sales taxes. |
f | Includes interest, minority interest and the net results of equity-accounted entities of equity-accounted entities. |
232 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiariesa | ||||||||||||||||||||||||||||||||||||||||
Capitalized costs at 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Gross capitalized costs | ||||||||||||||||||||||||||||||||||||||||
Proved properties | 34,614 | 5,507 | 59,918 | 3,517 | 7,934 | 21,563 | – | 10,689 | 2,581 | 146,323 | ||||||||||||||||||||||||||||||
Unproved properties | 626 | – | 5,006 | 165 | 134 | 2,011 | – | 465 | 1,018 | 9,425 | ||||||||||||||||||||||||||||||
35,240 | 5,507 | 64,924 | 3,682 | 8,068 | 23,574 | – | 11,154 | 3,599 | 155,748 | |||||||||||||||||||||||||||||||
Accumulated depreciation | 26,564 | 3,125 | 28,511 | 2,141 | 4,217 | 10,451 | – | 4,395 | 945 | 80,349 | ||||||||||||||||||||||||||||||
Net capitalized costs | 8,676 | 2,382 | 36,413 | 1,541 | 3,851 | 13,123 | – | 6,759 | 2,654 | 75,399 | ||||||||||||||||||||||||||||||
The group’s share of equity-accounted entities’ net capitalized costs at 31 December 2008 was $13,393 million. | ||||||||||||||||||||||||||||||||||||||||
Costs incurred for the year ended 31 Decemberb | ||||||||||||||||||||||||||||||||||||||||
Acquisition of propertiesc | ||||||||||||||||||||||||||||||||||||||||
Proved | – | – | 1,374 | 2 | – | – | – | 136 | – | 1,512 | ||||||||||||||||||||||||||||||
Unproved | 4 | – | 2,942 | – | – | – | – | 41 | – | 2,987 | ||||||||||||||||||||||||||||||
4 | – | 4,316 | 2 | – | – | – | 177 | – | 4,499 | |||||||||||||||||||||||||||||||
Exploration and appraisal costsd | 137 | – | 862 | 33 | 90 | 838 | 12 | 269 | 49 | 2,290 | ||||||||||||||||||||||||||||||
Development | 907 | 695 | 4,914 | 309 | 768 | 2,966 | – | 859 | 349 | 11,767 | ||||||||||||||||||||||||||||||
Total costs | 1,048 | 695 | 10,092 | 344 | 858 | 3,804 | 12 | 1,305 | 398 | 18,556 | ||||||||||||||||||||||||||||||
The group’s share of equity-accounted entities’ costs incurred in 2008 was $3,259 million: in Russia $1,921 million, South America $1,039 million, and Rest of Asia $299 million. | ||||||||||||||||||||||||||||||||||||||||
Results of operations for the year ended 31 December | ||||||||||||||||||||||||||||||||||||||||
Sales and other operating revenuese | ||||||||||||||||||||||||||||||||||||||||
Third parties | 3,865 | 105 | 1,526 | 147 | 3,339 | 3,745 | – | 1,186 | 860 | 14,773 | ||||||||||||||||||||||||||||||
Sales between businesses | 4,374 | 1,416 | 22,094 | 1,237 | 2,605 | 6,022 | – | 11,249 | 1,171 | 50,168 | ||||||||||||||||||||||||||||||
8,239 | 1,521 | 23,620 | 1,384 | 5,944 | 9,767 | – | 12,435 | 2,031 | 64,941 | |||||||||||||||||||||||||||||||
Exploration expenditure | 121 | 1 | 305 | 32 | 30 | 213 | 14 | 140 | 26 | 882 | ||||||||||||||||||||||||||||||
Production costs | 1,357 | 150 | 3,002 | 289 | 429 | 875 | 18 | 485 | 62 | 6,667 | ||||||||||||||||||||||||||||||
Production taxes | 503 | – | 2,603 | 2 | 358 | – | – | 5,510 | 110 | 9,086 | ||||||||||||||||||||||||||||||
Other costs (income)f | (28 | ) | (43 | ) | 3,440 | 343 | 198 | (122 | ) | 196 | 2,064 | 226 | 6,274 | |||||||||||||||||||||||||||
Depreciation, depletion and amortization | 1,049 | 199 | 2,729 | 181 | 730 | 2,120 | – | 788 | 87 | 7,883 | ||||||||||||||||||||||||||||||
Impairments and losses on sale of businesses and fixed assets | – | – | 308 | 2 | 4 | 8 | – | 219 | – | 541 | ||||||||||||||||||||||||||||||
3,002 | 307 | 12,387 | 849 | 1,749 | 3,094 | 228 | 9,206 | 511 | 31,333 | |||||||||||||||||||||||||||||||
Profit (loss) before taxationg | 5,237 | 1,214 | 11,233 | 535 | 4,195 | 6,673 | (228 | ) | 3,229 | 1,520 | 33,608 | |||||||||||||||||||||||||||||
Allocable taxes | 2,280 | 883 | 3,857 | 205 | 2,218 | 2,672 | (36 | ) | 984 | 513 | 13,576 | |||||||||||||||||||||||||||||
Results of operations | 2,957 | 331 | 7,376 | 330 | 1,977 | 4,001 | (192 | ) | 2,245 | 1,007 | 20,032 | |||||||||||||||||||||||||||||
The group’s share of equity-accounted entities’ results of operations (including the group’s share of total TNK-BP results) in 2008 was a profit of $2,793 million after deducting interest of $355 million, taxation of $1,217 million and minority interest of $169 million. | ||||||||||||||||||||||||||||||||||||||||
Exploration and Production segment replacement cost profit before interest and tax | ||||||||||||||||||||||||||||||||||||||||
Exploration and production activities | ||||||||||||||||||||||||||||||||||||||||
Subsidiaries (as above) | 5,237 | 1,214 | 11,233 | 535 | 4,195 | 6,673 | (228 | ) | 3,229 | 1,520 | 33,608 | |||||||||||||||||||||||||||||
Equity-accounted entities | (1 | ) | – | 1 | 40 | 304 | (1 | ) | 2,259 | 191 | – | 2,793 | ||||||||||||||||||||||||||||
Midstream activitiesh i | 743 | 16 | 490 | 673 | 274 | 112 | – | (272 | ) | (129 | ) | 1,907 | ||||||||||||||||||||||||||||
Total replacement cost profit before interest and tax | 5,979 | 1,230 | 11,724 | 1,248 | 4,773 | 6,784 | 2,031 | 3,148 | 1,391 | 38,308 | ||||||||||||||||||||||||||||||
a | These tables contain information relating to oil and natural gas exploration and production activities. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola. The group’s share of equity-accounted entities’ activities are excluded from the tables and included in the footnotes, with the exception of Abu Dhabi production taxes, which are included in the results of operations above. |
b | Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. |
c | Includes costs capitalized as a result of asset exchanges. |
d | Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred. |
e | Presented net of transportation costs, purchases and sales taxes. Sales between businesses and third party sales have been amended in the US without net effect to total sales. |
f | Includes property taxes, other government take and the fair value loss on embedded derivatives of $102 million. The UK region includes a $499 million gain offset by corresponding charges primarily in the US, relating to the group self-insurance programme. |
g | Excludes the unwinding of the discount on provisions and payables amounting to $285 million which is included in finance costs in the group income statement. |
h | Includes a $517 million write-down of our investment in Rosneft based on its quoted market price at the end of the year. |
i | Midstream activities exclude inventory holding gains and losses. |
BP Annual Report and Form 20-F 2010 233
Table of Contents
million barrels | ||||||||||||||||||||||||||||||||||||||||
Crude oila | 2010 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | USe | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 403 | 83 | 1,862 | 11 | 49 | 422 | – | 182 | 58 | 3,070 | ||||||||||||||||||||||||||||||
Undeveloped | 291 | 184 | 1,211 | 1 | 56 | 454 | – | 334 | 57 | 2,588 | ||||||||||||||||||||||||||||||
694 | 267 | 3,073 | 12 | 105 | 876 | – | 516 | 115 | 5,658 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | 20 | 3 | (45 | ) | 1 | (1 | ) | (62 | ) | – | (62 | ) | – | (146 | ) | |||||||||||||||||||||||||
Improved recovery | 100 | 9 | 133 | – | 17 | 14 | – | 145 | 3 | 421 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | 33 | 6 | – | – | – | – | 38 | – | 77 | ||||||||||||||||||||||||||||||
Discoveries and extensions | 31 | 1 | 80 | – | – | 19 | – | – | – | 131 | ||||||||||||||||||||||||||||||
Productionb j | (50 | ) | (15 | ) | (211 | ) | (2 | ) | (19 | ) | (87 | ) | – | (43 | ) | (12 | ) | (439 | ) | |||||||||||||||||||||
Sales of reserves-in-place | – | – | (117 | ) | (11 | ) | – | (15 | ) | – | – | – | (143 | ) | ||||||||||||||||||||||||||
101 | 31 | (154 | ) | (12 | ) | (3 | ) | (131 | ) | – | 78 | (9 | ) | (99 | ) | |||||||||||||||||||||||||
At 31 December 2010c g | ||||||||||||||||||||||||||||||||||||||||
Developed | 364 | 77 | 1,729 | – | 44 | 371 | – | 269 | 48 | 2,902 | ||||||||||||||||||||||||||||||
Undeveloped | 431 | 221 | 1,190 | – | 58 | 374 | – | 325 | 58 | 2,657 | ||||||||||||||||||||||||||||||
795 | 298 | 2,919 | – | 102 | 745 | – | 594 | 106 | 5,559 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 407 | – | 2,351 | 363 | – | 3,121 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 405 | 9 | 1,198 | 120 | – | 1,732 | ||||||||||||||||||||||||||||||
– | – | – | – | 812 | 9 | 3,549 | 483 | – | 4,853 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | 4 | 3 | 248 | (20 | ) | – | 235 | |||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 33 | – | 269 | – | – | 302 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 1 | – | – | – | – | 1 | ||||||||||||||||||||||||||||||
Production | – | – | – | – | (35) | i k | – | (313 | ) | (69 | ) | – | (417 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | – | – | (3 | ) | – | – | (3 | ) | ||||||||||||||||||||||||||||
– | – | – | – | 3 | 3 | 201 | (89 | ) | – | 118 | ||||||||||||||||||||||||||||||
At 31 December 2010d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 408 | – | 2,388 | 370 | – | 3,166 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 407 | 12 | 1,362 | 24 | – | 1,805 | ||||||||||||||||||||||||||||||
– | – | – | – | 815 | h | 12 | 3,750 | 394 | – | 4,971 | ||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 403 | 83 | 1,862 | 11 | 456 | 422 | 2,351 | 545 | 58 | 6,191 | ||||||||||||||||||||||||||||||
Undeveloped | 291 | 184 | 1,211 | 1 | 461 | 463 | 1,198 | 454 | 57 | 4,320 | ||||||||||||||||||||||||||||||
694 | 267 | 3,073 | 12 | 917 | 885 | 3,549 | 999 | 115 | 10,511 | |||||||||||||||||||||||||||||||
At 31 December 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 364 | 77 | 1,729 | – | 452 | 371 | 2,388 | 639 | 48 | 6,068 | ||||||||||||||||||||||||||||||
Undeveloped | 431 | 221 | 1,190 | – | 465 | 386 | 1,362 | 349 | 58 | 4,462 | ||||||||||||||||||||||||||||||
795 | 298 | 2,919 | – | 917 | 757 | 3,750 | 988 | 106 | 10,530 | |||||||||||||||||||||||||||||||
a | Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Excludes NGLs from processing plants in which an interest is held of 29 thousand barrels a day. |
c | Includes 643 million barrels of NGLs. Also includes 22 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 18 million barrels of NGLs. Also includes 254 million barrels of crude oil in respect of the 7.03% minority interest in TNK-BP. |
e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 78 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
f | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
g | Includes 70 million barrels relating to assets held for sale at 31 December 2010. Amounts by region are: 6 million barrels in US; 30 million barrels in South America; and 34 million barrels in Rest of Asia. |
h | Includes 801 million barrels relating to assets held for sale at 31 December 2010. |
i | Includes 4 million barrels of crude oil sold relating to production since classification of equity-accounted entities as held for sale. |
j | Includes 15 million barrels of crude oil sold relating to production from assets held for sale at 31 December 2010. Amounts by region are: 2 million barrels in US; 6 million barrels in South America; and 7 million barrels in Rest of Asia. |
k | Includes 35 million barrels of crude oil sold relating to production from assets held for sale at 31 December 2010. |
234 BP Annual Report and Form 20-F 2010
Table of Contents
billion cubic feet | ||||||||||||||||||||||||||||||||||||||||
Natural gasa | 2010 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,602 | 49 | 9,583 | 716 | 3,177 | 1,107 | – | 1,579 | 3,219 | 21,032 | ||||||||||||||||||||||||||||||
Undeveloped | 670 | 397 | 5,633 | 453 | 7,393 | 1,454 | – | 249 | 3,107 | 19,356 | ||||||||||||||||||||||||||||||
2,272 | 446 | 15,216 | 1,169 | 10,570 | 2,561 | – | 1,828 | 6,326 | 40,388 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | (8 | ) | (5 | ) | (1,854 | ) | (11 | ) | 2 | 3 | – | (142 | ) | (191 | ) | (2,206 | ) | |||||||||||||||||||||||
Improved recovery | 152 | 6 | 830 | – | 512 | 18 | – | 83 | 58 | 1,659 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | 31 | 97 | 1 | – | – | – | 17 | – | 146 | ||||||||||||||||||||||||||||||
Discoveries and extensions | 26 | – | 739 | 9 | 19 | 1,378 | – | – | – | 2,171 | ||||||||||||||||||||||||||||||
Productionb i | (191 | ) | (8 | ) | (861 | ) | (77 | ) | (953 | ) | (229 | ) | – | (228 | ) | (288 | ) | (2,835 | ) | |||||||||||||||||||||
Sales of reserves-in-place | (6 | ) | – | (424 | ) | (1,033 | ) | – | (51 | ) | – | – | – | (1,514 | ) | |||||||||||||||||||||||||
(27 | ) | 24 | (1,473 | ) | (1,111 | ) | (420 | ) | 1,119 | – | (270 | ) | (421 | ) | (2,579 | ) | ||||||||||||||||||||||||
At 31 December 2010c f | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,416 | 40 | 9,495 | 58 | 3,575 | 1,329 | – | 1,290 | 3,563 | 20,766 | ||||||||||||||||||||||||||||||
Undeveloped | 829 | 430 | 4,248 | – | 6,575 | 2,351 | – | 268 | 2,342 | 17,043 | ||||||||||||||||||||||||||||||
2,245 | 470 | 13,743 | 58 | 10,150 | 3,680 | – | 1,558 | 5,905 | 37,809 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)e | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 1,252 | – | 1,703 | 80 | – | 3,035 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 1,010 | 165 | 519 | 13 | – | 1,707 | ||||||||||||||||||||||||||||||
– | – | – | – | 2,262 | 165 | 2,222 | 93 | – | 4,742 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | (141 | ) | 10 | 382 | 2 | – | 253 | |||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 291 | – | – | 12 | – | 303 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 23 | – | – | – | – | 23 | ||||||||||||||||||||||||||||||
Productionb | – | – | – | – | (168) | h j | – | (244 | ) | (17 | ) | – | (429 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | – | – | (1 | ) | – | – | (1 | ) | ||||||||||||||||||||||||||||
– | – | – | – | 5 | 10 | 137 | (3 | ) | – | 149 | ||||||||||||||||||||||||||||||
At 31 December 2010d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 1,075 | – | 1,900 | 71 | – | 3,046 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 1,192 | 175 | 459 | 19 | – | 1,845 | ||||||||||||||||||||||||||||||
– | – | – | – | 2,267 | g | 175 | 2,359 | 90 | – | 4,891 | ||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,602 | 49 | 9,583 | 716 | 4,429 | 1,107 | 1,703 | 1,659 | 3,219 | 24,067 | ||||||||||||||||||||||||||||||
Undeveloped | 670 | 397 | 5,633 | 453 | 8,403 | 1,619 | 519 | 262 | 3,107 | 21,063 | ||||||||||||||||||||||||||||||
2,272 | 446 | 15,216 | 1,169 | 12,832 | 2,726 | 2,222 | 1,921 | 6,326 | 45,130 | |||||||||||||||||||||||||||||||
At 31 December 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,416 | 40 | 9,495 | 58 | 4,650 | 1,329 | 1,900 | 1,361 | 3,563 | 23,812 | ||||||||||||||||||||||||||||||
Undeveloped | 829 | 430 | 4,248 | – | 7,767 | 2,526 | 459 | 287 | 2,342 | 18,888 | ||||||||||||||||||||||||||||||
2,245 | 470 | 13,743 | 58 | 12,417 | 3,855 | 2,359 | 1,648 | 5,905 | 42,700 | |||||||||||||||||||||||||||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Includes 204 billion cubic feet of natural gas consumed in operations, 166 billion cubic feet in subsidiaries, 38 billion cubic feet in equity-accounted entities and excludes 14 billion cubic feet of produced non-hydrocarbon components which meet regulatory requirements for sales. |
c | Includes 2,921 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 137 billion cubic feet of natural gas in respect of the 5.89% minority interest in TNK-BP. |
e | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
f | Includes 740 billion cubic feet relating to assets held for sale at 31 December 2010. Amounts by region are: 158 billion cubic feet in US; 205 billion cubic feet in South America; and 377 billion cubic feet in Rest of Asia. |
g | Includes 1,819 billion cubic feet relating to assets held for sale at 31 December 2010. |
h | Includes 12 billion cubic feet of gas sales relating to production since classification of equity-accounted entities as held for sale. |
i | Includes 133 billion cubic feet of gas (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010. Amounts by region are: 23 billion cubic feet in US; 27 billion cubic feet in South America; and 83 billion cubic feet in Rest of Asia. |
j | Includes 141 billion cubic feet of gas (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010. |
BP Annual Report and Form 20-F 2010 235
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million barrels | ||||||||
Bitumena | 2010 | |||||||
Rest of | ||||||||
North | ||||||||
America | Total | |||||||
Equity-accounted entities (BP share) | ||||||||
At 1 January 2010 | ||||||||
Developed | – | – | ||||||
Undeveloped | – | – | ||||||
– | – | |||||||
Changes attributable to | ||||||||
Revisions of previous estimates | – | – | ||||||
Improved recovery | – | – | ||||||
Purchases of reserves-in-place | – | – | ||||||
Discoveries and extensions | 179 | 179 | ||||||
Production | – | – | ||||||
Sales of reserves-in-place | – | – | ||||||
179 | 179 | |||||||
At 31 December 2010 | ||||||||
Developed | – | – | ||||||
Undeveloped | 179 | 179 | ||||||
179 | 179 | |||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
236 BP Annual Report and Form 20-F 2010
Table of Contents
million barrels of oil equivalent | ||||||||||||||||||||||||||||||||||||||||
Total hydrocarbonsa | 2010 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌──South──┐ | ┌──Africa──┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | USe | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | �� | |||||||||||||||||||||||||||||||||||||||
Developed | 680 | 91 | 3,514 | 135 | 596 | 613 | – | 455 | 612 | 6,696 | ||||||||||||||||||||||||||||||
Undeveloped | 406 | 253 | 2,183 | 79 | 1,331 | 704 | – | 376 | 593 | 5,925 | ||||||||||||||||||||||||||||||
1,086 | 344 | 5,697 | 214 | 1,927 | 1,317 | – | 831 | 1,205 | 12,621 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | 18 | 2 | (364 | ) | (2 | ) | (1 | ) | (61 | ) | – | (87 | ) | (33 | ) | (528 | ) | |||||||||||||||||||||||
Improved recovery | 126 | 10 | 276 | – | 105 | 17 | – | 160 | 13 | 707 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | 38 | 22 | – | – | – | – | 41 | – | 101 | ||||||||||||||||||||||||||||||
Discoveries and extensions | 36 | 1 | 207 | 2 | 4 | 257 | – | – | – | 507 | ||||||||||||||||||||||||||||||
Productionb f l | (83 | ) | (16 | ) | (359 | ) | (15 | ) | (183 | ) | (127 | ) | – | (83 | ) | (61 | ) | (927 | ) | |||||||||||||||||||||
Sales of reserves-in-place | (1 | ) | – | (190 | ) | (189 | ) | – | (24 | ) | – | – | – | (404 | ) | |||||||||||||||||||||||||
96 | 35 | (408 | ) | (204 | ) | (75 | ) | 62 | – | 31 | (81 | ) | (544 | ) | ||||||||||||||||||||||||||
At 31 December 2010c i | ||||||||||||||||||||||||||||||||||||||||
Developed | 608 | 84 | 3,366 | 10 | 660 | 600 | – | 491 | 662 | 6,481 | ||||||||||||||||||||||||||||||
Undeveloped | 574 | 295 | 1,923 | – | 1,192 | 779 | – | 371 | 462 | 5,596 | ||||||||||||||||||||||||||||||
1,182 | 379 | 5,289 | 10 | 1,852 | 1,379 | – | 862 | 1,124 | 12,077 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)g | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 623 | – | 2,645 | 377 | – | 3,645 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 580 | 37 | 1,287 | 122 | – | 2,026 | ||||||||||||||||||||||||||||||
– | – | – | – | 1,203 | 37 | 3,932 | 499 | – | 5,671 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | (20 | ) | 6 | 314 | (19 | ) | – | 281 | ||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 83 | – | 269 | 2 | – | 354 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | 179 | 4 | – | – | – | – | 183 | ||||||||||||||||||||||||||||||
Productionb f | – | – | – | – | (64) | k m | – | (354 | ) | (73 | ) | – | (491 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | – | – | (4 | ) | – | – | (4 | ) | ||||||||||||||||||||||||||||
– | – | – | 179 | 3 | 6 | 225 | (90 | ) | – | 323 | ||||||||||||||||||||||||||||||
At 31 December 2010d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 593 | – | 2,716 | 382 | – | 3,691 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | 179 | 613 | 43 | 1,441 | 27 | – | 2,303 | ||||||||||||||||||||||||||||||
– | – | – | 179 | 1,206 | j | 43 | 4,157 | 409 | – | 5,994 | ||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share)h | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 680 | 91 | 3,514 | 135 | 1,219 | 613 | 2,645 | 832 | 612 | 10,341 | ||||||||||||||||||||||||||||||
Undeveloped | 406 | 253 | 2,183 | 79 | 1,911 | 741 | 1,287 | 498 | 593 | 7,951 | ||||||||||||||||||||||||||||||
1,086 | 344 | 5,697 | 214 | 3,130 | 1,354 | 3,932 | 1,330 | 1,205 | 18,292 | |||||||||||||||||||||||||||||||
At 31 December 2010 | ||||||||||||||||||||||||||||||||||||||||
Developed | 608 | 84 | 3,366 | 10 | 1,253 | 600 | 2,716 | 873 | 662 | 10,172 | ||||||||||||||||||||||||||||||
Undeveloped | 574 | 295 | 1,923 | 179 | 1,805 | 822 | 1,441 | 398 | 462 | 7,899 | ||||||||||||||||||||||||||||||
1,182 | 379 | 5,289 | 189 | 3,058 | 1,422 | 4,157 | 1,271 | 1,124 | 18,071 | |||||||||||||||||||||||||||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Excludes NGLs from processing plants in which an interest is held of 29 thousand barrels of oil equivalent a day. |
c | Includes 643 million barrels of NGLs. Also includes 526 million barrels of oil equivalent in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 18 million barrels of NGLs. Also includes 278 million barrels of oil equivalent in respect of the minority interest in TNK-BP. |
e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 78 million barrels of oil equivalent upon which a net profits royalty will be payable. |
f | Includes 35 million barrels of oil equivalent of natural gas consumed in operations, 28 million barrels of oil equivalent in subsidiaries, 7 million barrels of oil equivalent in equity-accounted entities and excludes 2 million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales. |
g | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
h | Includes 1,311 million barrels of oil equivalent (197 million barrels of oil equivalent for subsidiaries and 1,114 million barrels of oil equivalent for equity-accounted entities) associated with properties currently held for sale where the disposal has not yet been completed. |
i | Includes 197 million barrels of oil equivalent relating to assets held for sale at 31 December 2010. Amounts by region are: 34 million barrels of oil equivalent in US; 64 million barrels of oil equivalent in South America; and 99 million barrels of oil equivalent in Rest of Asia. |
j | Includes 1,114 million barrels of oil equivalent relating to assets held for sale at 31 December 2010. |
k | Includes 6 million barrels of oil equivalent sold relating to production since classification of equity-accounted entities as held for sale. |
l | Includes 38 million barrels of oil equivalent (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010. Amounts by region are: 6 million barrels of oil equivalent in US; 11 million barrels of oil equivalent in South America; and 21 million barrels of oil equivalent in Rest of Asia. |
m | Includes 59 million barrels of oil equivalent (excluding gas consumed in operations) relating to production from assets held for sale at 31 December 2010. |
BP Annual Report and Form 20-F 2010 237
Table of Contents
million barrels | ||||||||||||||||||||||||||||||||||||||||
Crude oila | 2009 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | USe | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 410 | 81 | 1,717 | 11 | 47 | 464 | – | 195 | 56 | 2,981 | ||||||||||||||||||||||||||||||
Undeveloped | 119 | 194 | 1,273 | 1 | 55 | 496 | – | 488 | 58 | 2,684 | ||||||||||||||||||||||||||||||
529 | 275 | 2,990 | 12 | 102 | 960 | – | 683 | 114 | 5,665 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | 7 | (1 | ) | 165 | 2 | 18 | (121 | ) | – | (128 | ) | 3 | (55 | ) | ||||||||||||||||||||||||||
Improved recovery | 42 | 7 | 82 | – | 7 | 32 | – | 31 | 2 | 203 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | 1 | – | – | – | – | – | – | 1 | – | 2 | ||||||||||||||||||||||||||||||
Discoveries and extensions | 184 | – | 73 | – | – | 114 | – | – | 7 | 378 | ||||||||||||||||||||||||||||||
Productionb | (61 | ) | (14 | ) | (237 | ) | (2 | ) | (22 | ) | (109 | ) | – | (45 | ) | (11 | ) | (501 | ) | |||||||||||||||||||||
Sales of reserves-in-place | (8 | ) | – | – | – | – | – | – | (26 | ) | – | (34 | ) | |||||||||||||||||||||||||||
165 | (8 | ) | 83 | – | 3 | (84 | ) | – | (167 | ) | 1 | (7 | ) | |||||||||||||||||||||||||||
At 31 December 2009c | ||||||||||||||||||||||||||||||||||||||||
Developed | 403 | 83 | 1,862 | 11 | 49 | 422 | – | 182 | 58 | 3,070 | ||||||||||||||||||||||||||||||
Undeveloped | 291 | 184 | 1,211 | 1 | 56 | 454 | – | 334 | 57 | 2,588 | ||||||||||||||||||||||||||||||
694 | 267 | 3,073 | 12 | 105 | 876 | – | 516 | 115 | 5,658 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 399 | – | 2,227 | 499 | – | 3,125 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 409 | 11 | 944 | 199 | – | 1,563 | ||||||||||||||||||||||||||||||
– | – | – | – | 808 | 11 | 3,171 | 698 | – | 4,688 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | 2 | (2 | ) | 590 | (28 | ) | – | 562 | ||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 50 | – | 8 | – | – | 58 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 3 | – | 87 | – | – | 90 | ||||||||||||||||||||||||||||||
Production | – | – | – | – | (37 | ) | – | (307 | ) | (71 | ) | – | (415 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | (14 | ) | – | – | (116 | ) | – | (130 | ) | |||||||||||||||||||||||||||
– | – | – | – | 4 | (2 | ) | 378 | (215 | ) | – | 165 | |||||||||||||||||||||||||||||
At 31 December 2009d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 407 | – | 2,351 | 363 | – | 3,121 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 405 | 9 | 1,198 | 120 | – | 1,732 | ||||||||||||||||||||||||||||||
– | – | – | – | 812 | 9 | 3,549 | 483 | – | 4,853 | |||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 410 | 81 | 1,717 | 11 | 446 | 464 | 2,227 | 694 | 56 | 6,106 | ||||||||||||||||||||||||||||||
Undeveloped | 119 | 194 | 1,273 | 1 | 464 | 507 | 944 | 687 | 58 | 4,247 | ||||||||||||||||||||||||||||||
529 | 275 | 2,990 | 12 | 910 | 971 | 3,171 | 1,381 | 114 | 10,353 | |||||||||||||||||||||||||||||||
At 31 December 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 403 | 83 | 1,862 | 11 | 456 | 422 | 2,351 | 545 | 58 | 6,191 | ||||||||||||||||||||||||||||||
Undeveloped | 291 | 184 | 1,211 | 1 | 461 | 463 | 1,198 | 454 | 57 | 4,320 | ||||||||||||||||||||||||||||||
694 | 267 | 3,073 | 12 | 917 | 885 | 3,549 | 999 | 115 | 10,511 | |||||||||||||||||||||||||||||||
a | Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Excludes NGLs from processing plants in which an interest is held of 26 thousand barrels a day. |
c | Includes 819 million barrels of NGLs. Also includes 23 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 20 million barrels of NGLs. Also includes 243 million barrels of crude oil in respect of the 6.86% minority interest in TNK-BP. |
e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 68 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
f | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
238 BP Annual Report and Form 20-F 2010
Table of Contents
billion cubic feet | ||||||||||||||||||||||||||||||||||||||||
Natural gasa | 2009 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,822 | 61 | 9,059 | 659 | 3,316 | 1,050 | – | 1,102 | 1,887 | 18,956 | ||||||||||||||||||||||||||||||
Undeveloped | 582 | 402 | 5,473 | 468 | 7,434 | 1,382 | – | 1,308 | 4,000 | 21,049 | ||||||||||||||||||||||||||||||
2,404 | 463 | 14,532 | 1,127 | 10,750 | 2,432 | – | 2,410 | 5,887 | 40,005 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | (114 | ) | (8 | ) | 549 | 43 | 322 | 270 | – | (231 | ) | 22 | 853 | |||||||||||||||||||||||||||
Improved recovery | 34 | – | 550 | 5 | 322 | 49 | – | 82 | 75 | 1,117 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | 159 | – | – | – | – | – | – | 31 | – | 190 | ||||||||||||||||||||||||||||||
Discoveries and extensions | 150 | – | 496 | 94 | 105 | 59 | – | – | 531 | 1,435 | ||||||||||||||||||||||||||||||
Productionb | (243 | ) | (9 | ) | (907 | ) | (100 | ) | (929 | ) | (249 | ) | – | (241 | ) | (189 | ) | (2,867 | ) | |||||||||||||||||||||
Sales of reserves-in-place | (118 | ) | – | (4 | ) | – | – | – | – | (223 | ) | – | (345 | ) | ||||||||||||||||||||||||||
(132 | ) | (17 | ) | 684 | 42 | (180 | ) | 129 | – | (582 | ) | 439 | 383 | |||||||||||||||||||||||||||
At 31 December 2009c | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,602 | 49 | 9,583 | 716 | 3,177 | 1,107 | – | 1,579 | 3,219 | 21,032 | ||||||||||||||||||||||||||||||
Undeveloped | 670 | 397 | 5,633 | 453 | 7,393 | 1,454 | – | 249 | 3,107 | 19,356 | ||||||||||||||||||||||||||||||
2,272 | 446 | 15,216 | 1,169 | 10,570 | 2,561 | – | 1,828 | 6,326 | 40,388 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)e | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 1,498 | – | 1,560 | 176 | – | 3,234 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 1,023 | 182 | 653 | 111 | – | 1,969 | ||||||||||||||||||||||||||||||
– | – | – | – | 2,521 | 182 | 2,213 | 287 | – | 5,203 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | (26 | ) | (17 | ) | 204 | (19 | ) | – | 142 | |||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 314 | – | 1 | 4 | – | 319 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 6 | – | 23 | – | – | 29 | ||||||||||||||||||||||||||||||
Productionb | – | – | – | – | (165 | ) | – | (219 | ) | (25 | ) | – | (409 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | (388 | ) | – | – | (154 | ) | – | (542 | ) | |||||||||||||||||||||||||||
– | – | – | – | (259 | ) | (17 | ) | 9 | (194 | ) | – | (461 | ) | |||||||||||||||||||||||||||
At 31 December 2009d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 1,252 | – | 1,703 | 80 | – | 3,035 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 1,010 | 165 | 519 | 13 | – | 1,707 | ||||||||||||||||||||||||||||||
– | – | – | – | 2,262 | 165 | 2,222 | 93 | – | 4,742 | |||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,822 | 61 | 9,059 | 659 | 4,814 | 1,050 | 1,560 | 1,278 | 1,887 | 22,190 | ||||||||||||||||||||||||||||||
Undeveloped | 582 | 402 | 5,473 | 468 | 8,457 | 1,564 | 653 | 1,419 | 4,000 | 23,018 | ||||||||||||||||||||||||||||||
2,404 | 463 | 14,532 | 1,127 | 13,271 | 2,614 | 2,213 | 2,697 | 5,887 | 45,208 | |||||||||||||||||||||||||||||||
At 31 December 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,602 | 49 | 9,583 | 716 | 4,429 | 1,107 | 1,703 | 1,659 | 3,219 | 24,067 | ||||||||||||||||||||||||||||||
Undeveloped | 670 | 397 | 5,633 | 453 | 8,403 | 1,619 | 519 | 262 | 3,107 | 21,063 | ||||||||||||||||||||||||||||||
2,272 | 446 | 15,216 | 1,169 | 12,832 | 2,726 | 2,222 | 1,921 | 6,326 | 45,130 | |||||||||||||||||||||||||||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Includes 195 billion cubic feet of natural gas consumed in operations, 164 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities and excludes 16 billion cubic feet of produced non-hydrocarbon components which meet regulatory requirements for sales. |
c | Includes 3,068 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 131 billion cubic feet of natural gas in respect of the 5.79% minority interest in TNK-BP. |
e | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
BP Annual Report and Form 20-F 2010 239
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million barrels of oil equivalent | ||||||||||||||||||||||||||||||||||||||||
Total hydrocarbonsa | 2009 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | USe | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 724 | 91 | 3,279 | 126 | 617 | 645 | – | 385 | 382 | 6,249 | ||||||||||||||||||||||||||||||
Undeveloped | 219 | 264 | 2,217 | 81 | 1,337 | 734 | – | 714 | 747 | 6,313 | ||||||||||||||||||||||||||||||
943 | 355 | 5,496 | 207 | 1,954 | 1,379 | – | 1,099 | 1,129 | 12,562 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | (13 | ) | (2 | ) | 260 | 9 | 74 | (74 | ) | – | (168 | ) | 7 | 93 | ||||||||||||||||||||||||||
Improved recovery | 48 | 7 | 177 | 1 | 63 | 40 | – | 45 | 15 | 396 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | 28 | – | – | – | – | – | – | 6 | – | 34 | ||||||||||||||||||||||||||||||
Discoveries and extensions | 210 | – | 158 | 17 | 18 | 124 | – | – | 98 | 625 | ||||||||||||||||||||||||||||||
Productionb f | (102 | ) | (16 | ) | (393 | ) | (20 | ) | (182 | ) | (152 | ) | – | (86 | ) | (44 | ) | (995 | ) | |||||||||||||||||||||
Sales of reserves-in-place | (28 | ) | – | (1 | ) | – | – | – | – | (65 | ) | – | (94 | ) | ||||||||||||||||||||||||||
143 | (11 | ) | 201 | 7 | (27 | ) | (62 | ) | – | (268 | ) | 76 | 59 | |||||||||||||||||||||||||||
At 31 December 2009c | ||||||||||||||||||||||||||||||||||||||||
Developed | 680 | 91 | 3,514 | 135 | 596 | 613 | – | 455 | 612 | 6,696 | ||||||||||||||||||||||||||||||
Undeveloped | 406 | 253 | 2,183 | 79 | 1,331 | 704 | – | 376 | 593 | 5,925 | ||||||||||||||||||||||||||||||
1,086 | 344 | 5,697 | 214 | 1,927 | 1,317 | – | 831 | 1,205 | 12,621 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)g | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 658 | – | 2,495 | 529 | – | 3,682 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 586 | 42 | 1,057 | 218 | – | 1,903 | ||||||||||||||||||||||||||||||
– | – | – | – | 1,244 | 42 | 3,552 | 747 | – | 5,585 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | (2 | ) | (5 | ) | 625 | (32 | ) | – | 586 | |||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 104 | – | 8 | 1 | – | 113 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 4 | – | 92 | – | – | 96 | ||||||||||||||||||||||||||||||
Productionb f | – | – | – | – | (66 | ) | – | (345 | ) | (75 | ) | – | (486 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | (81 | ) | – | – | (142 | ) | – | (223 | ) | |||||||||||||||||||||||||||
– | – | – | – | (41 | ) | (5 | ) | 380 | (248 | ) | – | 86 | ||||||||||||||||||||||||||||
At 31 December 2009d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 623 | – | 2,645 | 377 | – | 3,645 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 580 | 37 | 1,287 | 122 | – | 2,026 | ||||||||||||||||||||||||||||||
– | – | – | – | 1,203 | 37 | 3,932 | 499 | – | 5,671 | |||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 724 | 91 | 3,279 | 126 | 1,275 | 645 | 2,495 | 914 | 382 | 9,931 | ||||||||||||||||||||||||||||||
Undeveloped | 219 | 264 | 2,217 | 81 | 1,923 | 776 | 1,057 | 932 | 747 | 8,216 | ||||||||||||||||||||||||||||||
943 | 355 | 5,496 | 207 | 3,198 | 1,421 | 3,552 | 1,846 | 1,129 | 18,147 | |||||||||||||||||||||||||||||||
At 31 December 2009 | ||||||||||||||||||||||||||||||||||||||||
Developed | 680 | 91 | 3,514 | 135 | 1,219 | 613 | 2,645 | 832 | 612 | 10,341 | ||||||||||||||||||||||||||||||
Undeveloped | 406 | 253 | 2,183 | 79 | 1,911 | 741 | 1,287 | 498 | 593 | 7,951 | ||||||||||||||||||||||||||||||
1,086 | 344 | 5,697 | 214 | 3,130 | 1,354 | 3,932 | 1,330 | 1,205 | 18,292 | |||||||||||||||||||||||||||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Excludes NGLs from processing plants in which an interest is held of 26 thousand barrels of oil equivalent a day. |
c | Includes 819 million barrels of NGLs. Also includes 552 million barrels of oil equivalent in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 20 million barrels of NGLs. Also includes 266 million barrels of oil equivalent in respect of the minority interest in TNK-BP. |
e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 68 million barrels of oil equivalent upon which a net profits royalty will be payable. |
f | Includes 34 million barrels of oil equivalent of natural gas consumed in operations, 29 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities and excludes 3 million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales. |
g | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
240 BP Annual Report and Form 20-F 2010
Table of Contents
million barrels | ||||||||||||||||||||||||||||||||||||||||
Crude oila | 2008 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | USe | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 414 | 105 | 1,882 | 13 | 102 | 256 | – | 121 | 44 | 2,937 | ||||||||||||||||||||||||||||||
Undeveloped | 123 | 169 | 1,265 | 1 | 202 | 350 | – | 372 | 73 | 2,555 | ||||||||||||||||||||||||||||||
537 | 274 | 3,147 | 14 | 304 | 606 | – | 493 | 117 | 5,492 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | 16 | (11 | ) | (212 | ) | 1 | 7 | 264 | – | 194 | 5 | 264 | ||||||||||||||||||||||||||||
Improved recovery | 39 | 28 | 182 | – | 8 | 18 | – | 43 | 3 | 321 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | 64 | – | 5 | 173 | – | – | – | 242 | ||||||||||||||||||||||||||||||
Productionb | (63 | ) | (16 | ) | (191 | ) | (3 | ) | (23 | ) | (101 | ) | – | (47 | ) | (11 | ) | (455 | ) | |||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | (199 | ) | – | – | – | – | (199 | ) | ||||||||||||||||||||||||||||
(8 | ) | 1 | (157 | ) | (2 | ) | (202 | ) | 354 | – | 190 | (3 | ) | 173 | ||||||||||||||||||||||||||
At 31 December 2008c | ||||||||||||||||||||||||||||||||||||||||
Developed | 410 | 81 | 1,717 | 11 | 47 | 464 | – | 195 | 56 | 2,981 | ||||||||||||||||||||||||||||||
Undeveloped | 119 | 194 | 1,273 | 1 | 55 | 496 | – | 488 | 58 | 2,684 | ||||||||||||||||||||||||||||||
529 | 275 | 2,990 | 12 | 102 | 960 | – | 683 | 114 | 5,665 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 328 | – | 2,094 | 574 | – | 2,996 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 243 | – | 1,137 | 205 | – | 1,585 | ||||||||||||||||||||||||||||||
– | – | – | – | 571 | – | 3,231 | 779 | – | 4,581 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | (3 | ) | 11 | 217 | (1 | ) | – | 224 | ||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 62 | – | – | – | – | 62 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | 199 | – | – | – | – | 199 | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 13 | – | 26 | – | – | 39 | ||||||||||||||||||||||||||||||
Production | – | – | – | – | (34 | ) | – | (302 | ) | (80 | ) | – | (416 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | – | – | (1 | ) | – | – | (1 | ) | ||||||||||||||||||||||||||||
– | – | – | – | 237 | 11 | (60 | ) | (81 | ) | – | 107 | |||||||||||||||||||||||||||||
At 31 December 2008d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 399 | – | 2,227 | 499 | – | 3,125 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 409 | 11 | 944 | 199 | – | 1,563 | ||||||||||||||||||||||||||||||
– | – | – | – | 808 | 11 | 3,171 | 698 | – | 4,688 | |||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 414 | 105 | 1,882 | 13 | 430 | 256 | 2,094 | 695 | 44 | 5,933 | ||||||||||||||||||||||||||||||
Undeveloped | 123 | 169 | 1,265 | 1 | 445 | 350 | 1,137 | 577 | 73 | 4,140 | ||||||||||||||||||||||||||||||
537 | 274 | 3,147 | 14 | 875 | 606 | 3,231 | 1,272 | 117 | 10,073 | |||||||||||||||||||||||||||||||
At 31 December 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 410 | 81 | 1,717 | 11 | 446 | 464 | 2,227 | 694 | 56 | 6,106 | ||||||||||||||||||||||||||||||
Undeveloped | 119 | 194 | 1,273 | 1 | 464 | 507 | 944 | 687 | 58 | 4,247 | ||||||||||||||||||||||||||||||
529 | 275 | 2,990 | 12 | 910 | 971 | 3,171 | 1,381 | 114 | 10,353 | |||||||||||||||||||||||||||||||
a | Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Excludes NGLs from processing plants in which an interest is held of 19 thousand barrels a day. |
c | Includes 807 million barrels of NGLs. Also includes 21 million barrels of crude oil in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 36 million barrels of NGLs. Also includes 216 million barrels of crude oil in respect of the 6.80% minority interest in TNK-BP. |
e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 54 million barrels upon which a net profits royalty will be payable over the life of the field under the terms of the BP Prudhoe Bay Royalty Trust. |
f | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
BP Annual Report and Form 20-F 2010 241
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billion cubic feet | ||||||||||||||||||||||||||||||||||||||||
Natural gasa | 2008 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 2,049 | 63 | 10,670 | 608 | 3,075 | 990 | – | 1,270 | 1,135 | 19,860 | ||||||||||||||||||||||||||||||
Undeveloped | 553 | 410 | 4,705 | 421 | 7,973 | 1,410 | – | 1,269 | 4,529 | 21,270 | ||||||||||||||||||||||||||||||
2,602 | 473 | 15,375 | 1,029 | 11,048 | 2,400 | – | 2,539 | 5,664 | 41,130 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | 23 | (8 | ) | (2,063 | ) | 51 | (456 | ) | 142 | – | – | 361 | (1,950 | ) | ||||||||||||||||||||||||||
Improved recovery | 77 | 9 | 1,322 | 16 | 159 | 6 | – | 108 | 2 | 1,699 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | 183 | – | – | – | – | – | – | 183 | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | 549 | 125 | 948 | 82 | – | 37 | – | 1,741 | ||||||||||||||||||||||||||||||
Productionb | (298 | ) | (11 | ) | (834 | ) | (94 | ) | (946 | ) | (198 | ) | – | (274 | ) | (140 | ) | (2,795 | ) | |||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | (3 | ) | – | – | – | – | (3 | ) | ||||||||||||||||||||||||||||
(198 | ) | (10 | ) | (843 | ) | 98 | (298 | ) | 32 | – | (129 | ) | 223 | (1,125 | ) | |||||||||||||||||||||||||
At 31 December 2008c | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,822 | 61 | 9,059 | 659 | 3,316 | 1,050 | – | 1,102 | 1,887 | 18,956 | ||||||||||||||||||||||||||||||
Undeveloped | 582 | 402 | 5,473 | 468 | 7,434 | 1,382 | – | 1,308 | 4,000 | 21,049 | ||||||||||||||||||||||||||||||
2,404 | 463 | 14,532 | 1,127 | 10,750 | 2,432 | – | 2,410 | 5,887 | 40,005 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)e | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 1,478 | – | 808 | 187 | – | 2,473 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 831 | – | 353 | 113 | – | 1,297 | ||||||||||||||||||||||||||||||
– | – | – | – | 2,309 | – | 1,161 | 300 | – | 3,770 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | (96 | ) | 182 | 1,273 | (2 | ) | – | 1,357 | ||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 301 | – | – | 11 | – | 312 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | 3 | – | – | – | – | 3 | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 192 | – | – | – | – | 192 | ||||||||||||||||||||||||||||||
Productionb | – | – | – | – | (188 | ) | – | (221 | ) | (22 | ) | – | (431 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | – | – | – | – | – | – | ||||||||||||||||||||||||||||||
– | – | – | – | 212 | 182 | 1,052 | (13 | ) | – | 1,433 | ||||||||||||||||||||||||||||||
At 31 December 2008d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 1,498 | – | 1,560 | 176 | – | 3,234 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 1,023 | 182 | 653 | 111 | – | 1,969 | ||||||||||||||||||||||||||||||
– | – | – | – | 2,521 | 182 | 2,213 | 287 | – | 5,203 | |||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 2,049 | 63 | 10,670 | 608 | 4,553 | 990 | 808 | 1,457 | 1,135 | 22,333 | ||||||||||||||||||||||||||||||
Undeveloped | 553 | 410 | 4,705 | 421 | 8,804 | 1,410 | 353 | 1,382 | 4,529 | 22,567 | ||||||||||||||||||||||||||||||
2,602 | 473 | 15,375 | 1,029 | 13,357 | 2,400 | 1,161 | 2,839 | 5,664 | 44,900 | |||||||||||||||||||||||||||||||
At 31 December 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 1,822 | 61 | 9,059 | 659 | 4,814 | 1,050 | 1,560 | 1,278 | 1,887 | 22,190 | ||||||||||||||||||||||||||||||
Undeveloped | 582 | 402 | 5,473 | 468 | 8,457 | 1,564 | 653 | 1,419 | 4,000 | 23,018 | ||||||||||||||||||||||||||||||
2,404 | 463 | 14,532 | 1,127 | 13,271 | 2,614 | 2,213 | 2,697 | 5,887 | 45,208 | |||||||||||||||||||||||||||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Includes 193 billion cubic feet of natural gas consumed in operations, 149 billion cubic feet in subsidiaries, 44 billion cubic feet in equity-accounted entities and excludes 17 billion cubic feet of produced non-hydrocarbon components which meet regulatory requirements for sales. |
c | Includes 3,108 billion cubic feet of natural gas in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 131 billion cubic feet of natural gas in respect of the 5.92% minority interest in TNK-BP. |
e | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
242 BP Annual Report and Form 20-F 2010
Table of Contents
million barrels of oil equivalent | ||||||||||||||||||||||||||||||||||||||||
Total hydrocarbonsa | 2008 | |||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | USe | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 767 | 116 | 3,722 | 118 | 631 | 427 | – | 340 | 240 | 6,361 | ||||||||||||||||||||||||||||||
Undeveloped | 219 | 239 | 2,077 | 74 | 1,576 | 593 | – | 591 | 853 | 6,222 | ||||||||||||||||||||||||||||||
986 | 355 | 5,799 | 192 | 2,207 | 1,020 | – | 931 | 1,093 | 12,583 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | 20 | (12 | ) | (569 | ) | 10 | (71 | ) | 289 | – | 194 | 67 | (72 | ) | ||||||||||||||||||||||||||
Improved recovery | 52 | 30 | 410 | 3 | 36 | 18 | – | 61 | 4 | 614 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | 32 | – | – | – | – | – | – | 32 | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | 158 | 22 | 168 | 187 | – | 7 | – | 542 | ||||||||||||||||||||||||||||||
Productionb f | (115 | ) | (18 | ) | (334 | ) | (20 | ) | (186 | ) | (135 | ) | – | (94 | ) | (35 | ) | (937 | ) | |||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | (200 | ) | – | – | – | – | (200 | ) | ||||||||||||||||||||||||||||
(43 | ) | – | (303 | ) | 15 | (253 | ) | 359 | – | 168 | 36 | (21 | ) | |||||||||||||||||||||||||||
At 31 December 2008c | ||||||||||||||||||||||||||||||||||||||||
Developed | 724 | 91 | 3,279 | 126 | 617 | 645 | – | 385 | 382 | 6,249 | ||||||||||||||||||||||||||||||
Undeveloped | 219 | 264 | 2,217 | 81 | 1,337 | 734 | – | 714 | 747 | 6,313 | ||||||||||||||||||||||||||||||
943 | 355 | 5,496 | 207 | 1,954 | 1,379 | – | 1,099 | 1,129 | 12,562 | |||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)g | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 583 | – | 2,233 | 606 | – | 3,422 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 386 | – | 1,199 | 224 | – | 1,809 | ||||||||||||||||||||||||||||||
– | – | – | – | 969 | – | 3,432 | 830 | – | 5,231 | |||||||||||||||||||||||||||||||
Changes attributable to | ||||||||||||||||||||||||||||||||||||||||
Revisions of previous estimates | – | – | – | – | (20 | ) | 42 | 436 | (1 | ) | – | 457 | ||||||||||||||||||||||||||||
Improved recovery | – | – | – | – | 115 | – | – | 2 | – | 117 | ||||||||||||||||||||||||||||||
Purchases of reserves-in-place | – | – | – | – | 200 | – | – | – | – | 200 | ||||||||||||||||||||||||||||||
Discoveries and extensions | – | – | – | – | 46 | – | 26 | – | – | 72 | ||||||||||||||||||||||||||||||
Productionb f | – | – | – | – | (66 | ) | – | (341 | ) | (84 | ) | – | (491 | ) | ||||||||||||||||||||||||||
Sales of reserves-in-place | – | – | – | – | – | – | (1 | ) | – | – | (1 | ) | ||||||||||||||||||||||||||||
– | – | – | – | 275 | 42 | 120 | (83 | ) | – | 354 | ||||||||||||||||||||||||||||||
At 31 December 2008d | ||||||||||||||||||||||||||||||||||||||||
Developed | – | – | – | – | 658 | – | 2,495 | 529 | – | 3,682 | ||||||||||||||||||||||||||||||
Undeveloped | – | – | – | – | 586 | 42 | 1,057 | 218 | – | 1,903 | ||||||||||||||||||||||||||||||
– | – | – | – | 1,244 | 42 | 3,552 | 747 | – | 5,585 | |||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
At 1 January 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 767 | 116 | 3,722 | 118 | 1,214 | 427 | 2,233 | 946 | 240 | 9,783 | ||||||||||||||||||||||||||||||
Undeveloped | 219 | 239 | 2,077 | 74 | 1,962 | 593 | 1,199 | 815 | 853 | 8,031 | ||||||||||||||||||||||||||||||
986 | 355 | 5,799 | 192 | 3,176 | 1,020 | 3,432 | 1,761 | 1,093 | 17,814 | |||||||||||||||||||||||||||||||
At 31 December 2008 | ||||||||||||||||||||||||||||||||||||||||
Developed | 724 | 91 | 3,279 | 126 | 1,275 | 645 | 2,495 | 914 | 382 | 9,931 | ||||||||||||||||||||||||||||||
Undeveloped | 219 | 264 | 2,217 | 81 | 1,923 | 776 | 1,057 | 932 | 747 | 8,216 | ||||||||||||||||||||||||||||||
943 | 355 | 5,496 | 207 | 3,198 | 1,421 | 3,552 | 1,846 | 1,129 | 18,147 | |||||||||||||||||||||||||||||||
a | Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Excludes NGLs from processing plants in which an interest is held of 29 thousand barrels of oil equivalent a day. |
c | Includes 807 million barrels of NGLs. Also includes 557 million barrels of oil equivalent in respect of the 30% minority interest in BP Trinidad and Tobago LLC. |
d | Includes 36 million barrels of NGLs. Also includes 239 million barrels of oil equivalent in respect of the minority interest in TNK-BP. |
e | Proved reserves in the Prudhoe Bay field in Alaska include an estimated 54 million barrels of oil equivalent upon which a net profits royalty will be payable. |
f | Includes 33 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 8 million barrels of oil equivalent in equity-accounted entities and excludes 3 million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales. |
g | Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities. |
BP Annual Report and Form 20-F 2010 243
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌─Australasia─┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
At 31 December 2010 | ||||||||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa | 73,100 | 25,800 | 264,800 | 200 | 29,300 | 70,800 | – | 52,500 | 42,300 | 558,800 | ||||||||||||||||||||||||||||||
Future production costb | 25,700 | 9,800 | 111,400 | 200 | 6,800 | 14,000 | – | 13,400 | 12,800 | 194,100 | ||||||||||||||||||||||||||||||
Future development costb | 7,400 | 2,500 | 24,300 | – | 6,100 | 14,600 | – | 9,900 | 3,100 | 67,900 | ||||||||||||||||||||||||||||||
Future taxationc | 19,900 | 8,100 | 41,900 | – | 8,200 | 14,100 | – | 7,000 | 6,200 | 105,400 | ||||||||||||||||||||||||||||||
Future net cash flows | 20,100 | 5,400 | 87,200 | – | 8,200 | 28,100 | – | 22,200 | 20,200 | 191,400 | ||||||||||||||||||||||||||||||
10% annual discountd | 9,800 | 2,300 | 45,500 | – | 3,300 | 11,900 | – | 8,200 | 10,300 | 91,300 | ||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowse | 10,300 | 3,100 | 41,700 | – | 4,900 | 16,200 | – | 14,000 | 9,900 | 100,100 | ||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f | ||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa | – | – | – | 9,700 | 45,500 | – | 110,500 | 31,000 | – | 196,700 | ||||||||||||||||||||||||||||||
Future production costb | – | – | – | 4,500 | 19,200 | – | 80,900 | 26,500 | – | 131,100 | ||||||||||||||||||||||||||||||
Future development costb | – | – | – | 2,000 | 4,300 | – | 11,000 | 2,800 | – | 20,100 | ||||||||||||||||||||||||||||||
Future taxationc | – | – | – | 800 | 7,500 | – | 3,900 | 200 | – | 12,400 | ||||||||||||||||||||||||||||||
Future net cash flows | – | – | – | 2,400 | 14,500 | – | 14,700 | 1,500 | – | 33,100 | ||||||||||||||||||||||||||||||
10% annual discountd | – | – | – | 2,400 | 8,700 | – | 6,100 | 700 | – | 17,900 | ||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsgh | – | – | – | – | 5,800 | – | 8,600 | 800 | – | 15,200 | ||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities | ||||||||||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsj | 10,300 | 3,100 | 41,700 | – | 10,700 | 16,200 | 8,600 | 14,800 | 9,900 | 115,300 | ||||||||||||||||||||||||||||||
$ million | ||||||||||||
Equity-accounted | Total subsidiaries and | |||||||||||
Subsidiaries | entities (BP share) | equity-accounted entities | ||||||||||
Sales and transfers of oil and gas produced, net of production costs | (26,600 | ) | (4,900 | ) | (31,500 | ) | ||||||
Development costs for the current year as estimated in previous year | 10,400 | 2,000 | 12,400 | |||||||||
Extensions, discoveries and improved recovery, less related costs | 9,600 | 1,600 | 11,200 | |||||||||
Net changes in prices and production cost | 52,800 | 1,900 | 54,700 | |||||||||
Revisions of previous reserves estimates | (9,200 | ) | 200 | (9,000 | ) | |||||||
Net change in taxation | (13,400 | ) | (300 | ) | (13,700 | ) | ||||||
Future development costs | (4,300 | ) | (1,400 | ) | (5,700 | ) | ||||||
Net change in purchase and sales of reserves-in-place | (1,500 | ) | – | (1,500 | ) | |||||||
Addition of 10% annual discount | 7,500 | 1,500 | 9,000 | |||||||||
Total change in the standardized measure during the yeari | 25,300 | 600 | 25,900 | |||||||||
a | The marker prices used were Brent $79.02/bbl, Henry Hub $4.37/mmBtu. |
b | Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. |
c | Taxation is computed using appropriate year-end statutory corporate income tax rates. |
d | Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. |
e | Minority interest in BP Trinidad and Tobago LLC amounted to $1,200 million. |
f | The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. |
g | Minority interest in TNK-BP amounted to $600 million. |
h | No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. |
i | Total change in the standardized measure during the year includes the effect of exchange rate movements. |
j | Includes future net cash flows for assets held for sale at 31 December 2010. |
244 BP Annual Report and Form 20-F 2010
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
At 31 December 2009 | ||||||||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa | 50,800 | 17,700 | 204,000 | 4,900 | 26,400 | 58,400 | – | 36,100 | 32,500 | 430,800 | ||||||||||||||||||||||||||||||
Future production costb | 20,000 | 8,000 | 91,300 | 2,700 | 6,700 | 12,000 | – | 9,200 | 11,000 | 160,900 | ||||||||||||||||||||||||||||||
Future development costb | 5,000 | 2,500 | 24,900 | 1,000 | 5,600 | 12,200 | – | 6,400 | 3,100 | 60,700 | ||||||||||||||||||||||||||||||
Future taxationc | 12,900 | 3,700 | 27,300 | 200 | 5,800 | 11,300 | – | 4,700 | 4,500 | 70,400 | ||||||||||||||||||||||||||||||
Future net cash flows | 12,900 | 3,500 | 60,500 | 1,000 | 8,300 | 22,900 | – | 15,800 | 13,900 | 138,800 | ||||||||||||||||||||||||||||||
10% annual discountd | 5,800 | 1,600 | 29,500 | 500 | 3,200 | 9,800 | – | 6,300 | 7,300 | 64,000 | ||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowse | 7,100 | 1,900 | 31,000 | 500 | 5,100 | 13,100 | – | 9,500 | 6,600 | 74,800 | ||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)f | ||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa | – | – | – | – | 37,700 | – | 96,700 | 30,000 | – | 164,400 | ||||||||||||||||||||||||||||||
Future production costb | – | – | – | – | 17,000 | – | 65,200 | 25,200 | – | 107,400 | ||||||||||||||||||||||||||||||
Future development costb | – | – | – | – | 4,000 | – | 10,200 | 3,100 | – | 17,300 | ||||||||||||||||||||||||||||||
Future taxationc | – | – | – | – | 5,200 | – | 4,300 | 100 | – | 9,600 | ||||||||||||||||||||||||||||||
Future net cash flows | – | – | – | – | 11,500 | – | 17,000 | 1,600 | – | 30,100 | ||||||||||||||||||||||||||||||
10% annual discountd | – | – | – | – | 6,800 | – | 7,900 | 800 | – | 15,500 | ||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsg h | – | – | – | – | 4,700 | – | 9,100 | 800 | – | 14,600 | ||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities | ||||||||||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flows | 7,100 | 1,900 | 31,000 | 500 | 9,800 | 13,100 | 9,100 | 10,300 | 6,600 | 89,400 | ||||||||||||||||||||||||||||||
$ million | ||||||||||||
Equity-accounted | Total subsidiaries and | |||||||||||
Subsidiaries | entities (BP share) | equity-accounted entities | ||||||||||
Sales and transfers of oil and gas produced, net of production costs | (18,900 | ) | (3,400 | ) | (22,300 | ) | ||||||
Development costs for the current year as estimated in previous year | 11,700 | 2,100 | 13,800 | |||||||||
Extensions, discoveries and improved recovery, less related costs | 8,500 | 1,600 | 10,100 | |||||||||
Net changes in prices and production cost | 37,200 | 5,900 | 43,100 | |||||||||
Revisions of previous reserves estimates | (4,300 | ) | (200 | ) | (4,500 | ) | ||||||
Net change in taxation | (10,600 | ) | (1,600 | ) | (12,200 | ) | ||||||
Future development costs | (600 | ) | 900 | 300 | ||||||||
Net change in purchase and sales of reserves-in-place | (100 | ) | (900 | ) | (1,000 | ) | ||||||
Addition of 10% annual discount | 4,700 | 900 | 5,600 | |||||||||
Total change in the standardized measure during the yeari | 27,600 | 5,300 | 32,900 | |||||||||
a | The marker prices used were Brent $59.91/bbl, Henry Hub $3.82/mmBtu. |
b | Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future decommissioning costs are included. |
c | Taxation is computed using appropriate year-end statutory corporate income tax rates. |
d | Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. |
e | Minority interest in BP Trinidad and Tobago LLC amounted to $1,300 million. |
f | The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. |
g | Minority interest in TNK-BP amounted to $600 million. |
h | No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs. |
i | Total change in the standardized measure during the year includes the effect of exchange rate movements. |
BP Annual Report and Form 20-F 2010 245
Table of Contents
$ million | ||||||||||||||||||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||
┌────Europe───┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
At 31 December 2008 | ||||||||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
Future cash inflowsa | 36,400 | 13,800 | 165,800 | 6,400 | 26,300 | 40,400 | – | 31,400 | 24,200 | 344,700 | ||||||||||||||||||||||||||||||
Future production costb | 18,100 | 6,300 | 80,400 | 2,700 | 7,200 | 11,600 | – | 11,800 | 10,700 | 148,800 | ||||||||||||||||||||||||||||||
Future development costb | 3,300 | 2,900 | 25,600 | 1,300 | 7,200 | 10,900 | – | 7,500 | 3,200 | 61,900 | ||||||||||||||||||||||||||||||
Future taxationc | 7,300 | 2,300 | 17,500 | 500 | 5,500 | 6,600 | – | 2,400 | 2,800 | 44,900 | ||||||||||||||||||||||||||||||
Future net cash flows | 7,700 | 2,300 | 42,300 | 1,900 | 6,400 | 11,300 | – | 9,700 | 7,500 | 89,100 | ||||||||||||||||||||||||||||||
10% annual discountd | 2,200 | 1,200 | 21,000 | 1,000 | 2,900 | 5,500 | – | 4,200 | 3,900 | 41,900 | ||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowse | 5,500 | 1,100 | 21,300 | 900 | 3,500 | 5,800 | – | 5,500 | 3,600 | 47,200 | ||||||||||||||||||||||||||||||
Equity-accounted entities (BP share)g | ||||||||||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowsh | – | – | – | – | 3,600 | – | 4,800 | 900 | – | 9,300 | ||||||||||||||||||||||||||||||
Total subsidiaries and equity-accounted entities | ||||||||||||||||||||||||||||||||||||||||
Standardized measure of discounted future net cash flowse | 5,500 | 1,100 | 21,300 | 900 | 7,100 | 5,800 | 4,800 | 6,400 | 3,600 | 56,500 | ||||||||||||||||||||||||||||||
$ million | ||||
2008 | ||||
Sales and transfers of oil and gas produced, net of production costs | (43,600 | ) | ||
Development costs for the current year as estimated in previous year | 9,400 | |||
Extensions, discoveries and improved recovery, less related costs | 4,400 | |||
Net changes in prices and production cost | (146,800 | ) | ||
Revisions of previous reserves estimates | 1,200 | |||
Net change in taxation | 69,400 | |||
Future development costs | (7,400 | ) | ||
Net change in purchase and sales of reserves-in-place | (200 | ) | ||
Addition of 10% annual discount | 14,600 | |||
Total change in the standardized measure during the year of subsidiariesf | (99,000 | ) | ||
a | The year-end marker prices used were 2008 Brent $36.55/bbl, Henry Hub $5.63/mmBtu. |
b | Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on year-end cost levels and assume continuation of existing economic conditions. Future decommissioning costs are included. |
c | Taxation is computed using appropriate year-end statutory corporate income tax rates. |
d | Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities. |
e | Minority interest in BP Trinidad and Tobago LLC amounted to $900 million at 31 December 2008. |
f | Total change in the standardized measure during the year includes the effect of exchange rate movements. |
g | The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of those entities. |
h | Minority interest in TNK-BP amounted to $300 million at 31 December 2008. |
246 BP Annual Report and Form 20-F 2010
Table of Contents
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Subsidiaries | ||||||||||||||||||||||||||||||||||||||||
Crude oilb | thousand barrels per day | |||||||||||||||||||||||||||||||||||||||
2010 | 137 | 40 | 594 | 7 | 54 | 246 | – | 119 | 32 | 1,229 | ||||||||||||||||||||||||||||||
2009 | 168 | 40 | 665 | 8 | 61 | 304 | – | 123 | 31 | 1,400 | ||||||||||||||||||||||||||||||
2008 | 173 | 43 | 538 | 9 | 66 | 277 | – | 128 | 29 | 1,263 | ||||||||||||||||||||||||||||||
Natural gasc | million cubic feet per day | |||||||||||||||||||||||||||||||||||||||
2010 | 472 | 15 | 2,184 | 202 | 2,544 | 556 | – | 574 | 785 | 7,332 | ||||||||||||||||||||||||||||||
2009 | 618 | 16 | 2,316 | 263 | 2,492 | 621 | – | 610 | 514 | 7,450 | ||||||||||||||||||||||||||||||
2008 | 759 | 23 | 2,157 | 245 | 2,532 | 484 | – | 696 | 381 | 7,277 | ||||||||||||||||||||||||||||||
Equity-accounted entities (BP share) | ||||||||||||||||||||||||||||||||||||||||
Crude oilb | thousand barrels per day | |||||||||||||||||||||||||||||||||||||||
2010 | – | – | – | – | 98 | – | 856 | 191 | – | 1,145 | ||||||||||||||||||||||||||||||
2009 | – | – | – | – | 101 | – | 840 | 194 | – | 1,135 | ||||||||||||||||||||||||||||||
2008 | – | – | – | – | 92 | – | 826 | 220 | – | 1,138 | ||||||||||||||||||||||||||||||
Natural gasc | million cubic feet per day | |||||||||||||||||||||||||||||||||||||||
2010 | – | – | – | – | 399 | – | 640 | 30 | – | 1,069 | ||||||||||||||||||||||||||||||
2009 | – | – | – | – | 392 | – | 601 | 42 | – | 1,035 | ||||||||||||||||||||||||||||||
2008 | – | – | – | – | 454 | – | 564 | 39 | – | 1,057 | ||||||||||||||||||||||||||||||
a | Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and sales arrangements independently. |
b | Crude oil includes natural gas liquids and condensate. |
c | Natural gas production excludes gas consumed in operations. |
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Number of productive wells at 31 December 2010 | ||||||||||||||||||||||||||||||||||||||||
Oil wellsa – gross | 251 | 84 | 2,709 | 7 | 3,705 | 596 | 20,235 | 1,889 | 13 | 29,489 | ||||||||||||||||||||||||||||||
– net | 130 | 32 | 1,121 | 3 | 2,063 | 454 | 9,081 | 424 | 2 | 13,310 | ||||||||||||||||||||||||||||||
Gas wellsb – gross | 281 | – | 23,041 | 366 | 498 | 106 | 63 | 639 | 68 | 25,062 | ||||||||||||||||||||||||||||||
– net | 138 | – | 12,581 | 285 | 167 | 42 | 31 | 284 | 13 | 13,541 | ||||||||||||||||||||||||||||||
a | Includes approximately 3,989 gross (1,730 net) multiple completion wells (more than one formation producing into the same well bore). |
b | Includes approximately 2,623 gross (1,673 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well. |
BP Annual Report and Form 20-F 2010 247
Table of Contents
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
Oil and natural gas acreage at 31 December 2010 | Thousands of acres | |||||||||||||||||||||||||||||||||||||||
Developed – gross | 346 | 65 | 6,920 | 198 | 1,738 | 497 | 2,282 | 2,434 | 162 | 14,642 | ||||||||||||||||||||||||||||||
– net | 189 | 21 | 4,184 | 157 | 471 | 195 | 885 | 935 | 35 | 7,072 | ||||||||||||||||||||||||||||||
Undevelopeda – gross | 1,311 | 186 | 6,970 | 7,185 | 12,434 | 21,373 | 32,137 | 18,366 | 7,330 | 107,292 | ||||||||||||||||||||||||||||||
– net | 775 | 79 | 4,663 | 4,380 | 6,398 | 16,072 | 15,475 | 8,955 | 2,796 | 59,593 | ||||||||||||||||||||||||||||||
a | Undeveloped acreage includes leases and concessions. |
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||||||||||
Exploratory | ||||||||||||||||||||||||||||||||||||||||
Productive | – | 0.2 | 39.3 | – | 1.3 | 1.2 | 10.5 | 2.8 | 0.3 | 55.6 | ||||||||||||||||||||||||||||||
Dry | 0.7 | – | 0.3 | – | 0.9 | 1.4 | 4.0 | – | – | 7.3 | ||||||||||||||||||||||||||||||
Development | ||||||||||||||||||||||||||||||||||||||||
Productive | 6.4 | 1.2 | 260.0 | 31.7 | 105.7 | 18.9 | 364.3 | 53.3 | – | 841.5 | ||||||||||||||||||||||||||||||
Dry | 1.7 | – | 0.5 | – | 1.2 | 2.7 | – | 2.4 | – | 8.5 | ||||||||||||||||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||||||||||
Exploratory | ||||||||||||||||||||||||||||||||||||||||
Productive | 0.1 | – | 47.2 | – | 3.0 | 4.5 | 7.0 | 5.3 | 0.6 | 67.7 | ||||||||||||||||||||||||||||||
Dry | 0.2 | – | 4.2 | – | – | 1.4 | 4.5 | 6.0 | 0.2 | 16.5 | ||||||||||||||||||||||||||||||
Development | ||||||||||||||||||||||||||||||||||||||||
Productive | 9.3 | 1.5 | 403.8 | 17.9 | 135.4 | 20.8 | 293.0 | 45.8 | 1.6 | 929.1 | ||||||||||||||||||||||||||||||
Dry | – | – | 3.3 | – | – | 0.5 | 4.0 | 0.4 | 0.6 | 8.8 | ||||||||||||||||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||||||||||
Exploratory | ||||||||||||||||||||||||||||||||||||||||
Productive | 0.8 | – | 2.4 | – | 4.4 | 4.3 | 12.5 | 0.5 | 0.6 | 25.5 | ||||||||||||||||||||||||||||||
Dry | – | 0.5 | 0.9 | 0.1 | 0.4 | 2.6 | 23.0 | 0.5 | 0.4 | 28.4 | ||||||||||||||||||||||||||||||
Development | ||||||||||||||||||||||||||||||||||||||||
Productive | 6.6 | 0.5 | 379.8 | 28.3 | 112.5 | 18.6 | 10.0 | 45.4 | 4.5 | 606.2 | ||||||||||||||||||||||||||||||
Dry | 0.2 | – | 1.1 | 0.9 | 2.9 | 1.5 | 19.5 | 2.1 | – | 28.2 | ||||||||||||||||||||||||||||||
┌────Europe────┐ | ┌────North────┐ | ┌─South─┐ | ┌─Africa─┐ | ┌────Asia────┐ | ┌Australasia┐ | Total | ||||||||||||||||||||||||||||||||||
America | America | |||||||||||||||||||||||||||||||||||||||
Rest of | ||||||||||||||||||||||||||||||||||||||||
Rest of | North | Rest of | ||||||||||||||||||||||||||||||||||||||
UK | Europe | US | America | Russia | Asia | |||||||||||||||||||||||||||||||||||
At 31 December 2010 | ||||||||||||||||||||||||||||||||||||||||
Exploratory | ||||||||||||||||||||||||||||||||||||||||
Gross | 1.0 | – | 211.0 | 3.0 | 1.0 | 3.0 | 11.0 | 3.0 | – | 233.0 | ||||||||||||||||||||||||||||||
Net | 0.2 | – | 45.2 | 1.5 | – | 1.6 | 5.5 | 1.2 | – | 55.2 | ||||||||||||||||||||||||||||||
Development | ||||||||||||||||||||||||||||||||||||||||
Gross | 11.0 | – | 375.0 | – | 23.0 | 34.0 | 88.0 | 20.0 | – | 551.0 | ||||||||||||||||||||||||||||||
Net | 5.5 | – | 140.6 | – | 9.5 | 10.8 | 39.7 | 6.6 | – | 212.7 | ||||||||||||||||||||||||||||||
248 BP Annual Report and Form 20-F 2010
Table of Contents
(Registrant)
D.J. Jackson
Company Secretary
BP Annual Report and Form 20-F 2010 249