avatar Equinor Holding Netherlands B.V. Mining

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    ANNUAL REPORT on Form 20-F


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    ANNUAL REPORT on Form 20-F


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    Annual Report on Form 20-F Cover Page 1 1 Introduction 3 1.1 Key figures 3 1.2 About the report 4 1.3 Financial highlights 5 1.4 A glance at 2011 6 2 Business overview and strategy 9 2.1 Our business 9 2.2 Our history 11 2.3 Our competitive position 12 2.4 Organisational structure 12 2.5 Strategy 13 2.5.1 Our business environment 13 2.5.2 Our corporate strategy 14 2.5.3 Our technology 16 3 Operational review 18 3.1 Development and Production Norway (DPN) 18 3.1.1 Introduction to DPN 18 3.1.2 DPN key events in 2011 19 3.1.3 The NCS portfolio 20 3.1.3.1 Core production areas 20 3.1.3.2 Portfolio management 20 3.1.4 Exploration on the NCS 21 3.1.5 Development on the NCS 23 3.1.5.1 NCS fields under development 23 3.1.5.2 Redevelopments on the NCS 25 3.1.6 Fields in production on the NCS 25 3.1.6.1 Production on the NCS 26 3.1.6.2 Operations South 28 3.1.6.3 Operations North Sea West 29 3.1.6.4 Operations North Sea East 31 3.1.6.5 Operations North 32 3.1.6.6 Partner-operated fields 33 3.1.7 Decommissioning on the NCS 34 3.2 Development and Production International (DPI) 35 3.2.1 Introduction to DPI 35 3.2.2 DPI key events in 2011 36 3.2.3 The DPI portfolio 36 3.2.4 International exploration 37 3.2.4.1 North America 39 3.2.4.1.1 Canada 39 3.2.4.1.2 USA 40 3.2.4.2 South America and sub-Saharan Africa 41 3.2.4.2.1 Brazil 41 3.2.4.2.2 Angola 42 3.2.4.2.3 East Africa 43 3.2.4.3 Middle East and North Africa 43 3.2.4.4 Europe and Asia 44 3.2.4.4.1 Indonesia 44 3.2.5 International production 45 3.2.6 International fields 47 3.2.6.1 North America 48 3.2.6.1.1 Canada 48 3.2.6.1.2 USA 49 3.2.6.2 South America and sub-Saharan Africa 51 3.2.6.2.1 Brazil 51 3.2.6.2.2 Venezuela 51 3.2.6.2.3 Angola 52 3.2.6.2.4 Nigeria 53 3.2.6.3 Middle East and North Africa 53 3.2.6.3.1 Algeria 54 3.2.6.3.2 Iran 54 3.2.6.3.3 Libya 55 3.2.6.3.4 Iraq 55 3.2.6.4 Europe and Asia 56 3.2.6.4.1 Azerbaijan 56


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    3.2.6.4.2 Russia 57 3.2.6.4.3 United Kingdom 57 3.2.6.4.4 Ireland 58 3.3 Marketing, Processing and Renewable Energy (MPR) 59 3.3.1 Introduction to MPR 59 3.3.2 MPR key events 2011 59 3.3.3 Natural Gas 60 3.3.3.1 Natural Gas 60 3.3.3.2 The gas market 61 3.3.3.3 Gas sales and marketing 62 3.3.3.4 Norway's gas transport system 64 3.3.3.5 Kårstø gas processing plant 67 3.3.3.6 Kollsnes gas processing plant 67 3.3.3.7 Gas sales agreements 68 3.3.4 Crude oil, liquids and products 69 3.3.4.1 Crude oil, liquids and products 69 3.3.4.2 The oil market 69 3.3.4.3 Marketing and trading 70 3.3.4.4 Terminals 71 3.3.5 Processing and manufacturing 71 3.3.5.1 Processing and manufacturing 71 3.3.5.2 Mongstad 72 3.3.5.3 Kalundborg 74 3.3.5.4 Tjeldbergodden 75 3.3.5.5 Sture 75 3.3.6 Renewable energy 76 3.4 Statoil Fuel & Retail (SFR) 77 3.4.1 Introduction to SFR 77 3.4.2 SFR key events in 2011 77 3.4.3 The fuel and retail market 77 3.5 Technology, Projects and Drilling (TPD) 79 3.5.1 Introduction to TPD 79 3.5.2 TPD key events in 2011 80 3.5.3 Research and development 80 3.5.4 Technology excellence 81 3.5.5 Projects 82 3.5.6 Drilling and well 84 3.5.7 Procurement 84 3.6 Global Strategy and Business Development (GSB) 86 3.6.1 Introduction to GSB 86 3.6.2 GSB key events in 2011 87 3.7 Significant subsidiaries 89 3.8 Production volumes and prices 90 3.8.1 Entitlement production 90 3.8.2 Production costs & sales prices 92 3.9 Proved oil and gas reserves 93 3.9.1 Development of reserves 96 3.9.2 Preparations of reserves estimates 97 3.9.3 Operational statistics 98 3.9.4 Delivery commitments 100 3.10 Applicable laws and regulations 101 3.10.1 The Norwegian licensing system 101 3.10.2 Gas sales and transportation 103 3.10.3 HSE regulation 104 3.10.4 Taxation of Statoil 105 3.10.5 The Norwegian State's participation 106 3.10.6 SDFI oil & gas marketing & sale 106 3.11 Competition 108 3.12 Property, plants and equipment 108 3.13 Related party transactions 109 3.14 Insurance 110 3.15 People and the group 111 3.15.1 Employees in Statoil 111 3.15.2 Equal opportunities 112 3.15.3 Unions and representatives 113 4 Financial analysis and review 114 4.1 Operating and financial review 2011 114 4.1.1 Sales volumes 115 4.1.2 Group profit and loss analysis 117 4.1.3 Group outlook 122 4.1.4 Segment performance and analysis 123 4.1.5 Development and Production Norway (DPN) 125 4.1.5.1 DPN profit and loss analysis 126


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    4.1.6 Development and Production International (DPI) 128 4.1.6.1 DPI profit and loss analysis 129 4.1.7 Marketing, Processing and Renewable Energy (MPR) 131 4.1.7.1 MPR profit and loss analysis 132 4.1.8 Fuel & Retail (SFR) 135 4.1.8.1 SFR profit and loss analysis 135 4.1.9 Other operations 136 4.1.10 Definitions of reported volumes 137 4.2 Liquidity and capital resources 138 4.2.1 Review of cash flows 138 4.2.2 Selected balance sheet information 141 4.2.3 Financial assets and liabilities 143 4.2.4 Principal contractual obligations 146 4.2.5 Investments 146 4.2.6 Impact of inflation 148 4.2.7 Critical accounting judgements 148 4.2.8 Off balance sheet arrangements 151 4.3 Non-GAAP measures 152 4.3.1 Return on average capital employed (ROACE) 152 4.3.2 Unit of production cost 153 4.3.3 Net debt to capital employed ratio 155 4.4 Accounting Standards (IFRS) 156 5 Risk review 157 5.1 Risk factors 157 5.1.1 Risks related to our business 157 5.1.2 Legal and regulatory risks 162 5.1.3 Risks related to state ownership 163 5.2 Risk management 165 5.2.1 Managing financial risk 165 5.2.2 Disclosures about market risk 170 5.3 Legal proceedings 171 6 Shareholder information 172 6.1 Dividend policy 174 6.1.1 Dividends 174 6.2 Shares purchased by issuer 176 6.2.1 Statoil's share savings plan 176 6.3 Information and communications 178 6.3.1 Investor contact 178 6.4 Market and market prices 179 6.4.1 Share prices 179 6.4.2 Statoil ADR programme fees 180 6.5 Taxation 182 6.6 Exchange controls and limitations 186 6.7 Exchange rates 187 6.8 Major shareholders 188 7 Corporate governance 190 7.1 Articles of association 190 7.2 Ethics Code of Conduct 192 7.3 General meeting of shareholders 193 7.4 Nomination committee 195 7.5 Corporate assembly 195 7.6 Board of directors 198 7.6.1 Audit committee 201 7.6.1.1 Audit committee financial expert 202 7.6.2 Compensation committee 203 7.6.3 HSE and ethics committee 203 7.7 Compliance with NYSE listing rules 204 7.8 Management 205 7.9 Compensation paid to governing bodies 208 7.10 Share ownership 212 7.11 Independent auditor 213 7.12 Controls and procedures 215 8 Consolidated financial statements Statoil 216 8.1 Notes to the Consolidated financial statements 224 8.1.1 Organisation 224 8.1.2 Significant accounting policies 224 8.1.3 Accounting policy change for jointly controlled entities 236 8.1.4 Segments 239 8.1.5 Business development 244 8.1.6 Capital management 247


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    8.1.7 Financial risk management 248 8.1.8 Remuneration 252 8.1.9 Other expenses 253 8.1.10 Financial items 254 8.1.11 Income taxes 255 8.1.12 Earnings per share 258 8.1.13 Property, plant and equipment 259 8.1.14 Intangible assets 262 8.1.15 Investments in associated companies 264 8.1.16 Non-current financial assets and prepayments 265 8.1.17 Inventories 265 8.1.18 Trade and other receivables 266 8.1.19 Current financial investments 266 8.1.20 Cash and cash equivalents 266 8.1.21 Transactions impacting shareholders equity 267 8.1.22 Bonds, bank loans and finance lease liabilities 268 8.1.23 Pensions and other non-current employee benefits 270 8.1.24 Asset retirement obligations, other provisions and other liabilities 276 8.1.25 Trade and other payables 277 8.1.26 Bonds, bank loans, commercial papers and collateral liabilities 277 8.1.27 Leases 277 8.1.28 Other commitments and contingencies 279 8.1.29 Related parties 281 8.1.30 Financial instruments by category 282 8.1.31 Financial instruments: fair value measurement and sensitivity analysis of market risk 286 8.1.32 Condensed consolidating financial information related to guaranteed debt securities 293 8.1.33 Supplementary oil and gas information (unaudited) 302 8.2 Report of Independent Registered Public Accounting firm 316 8.2.1 Report of Independent Registered Public Accounting firm 316 8.2.2 Report of Ernst & Young AS on Statoil's internal control over financial reporting 317 9 Terms and definitions 318 10 Forward looking statements 321 11 Signature page 322 12 Exhibits 323 13 Cross reference to Form 20-F 324


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    Cover Page UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 20-F (Mark One) REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934 OR  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2011 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _________ to _________ OR SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report _________ Commission file number 1-15200 Statoil ASA (Exact Name of Registrant as Specified in Its Charter) N/A (Translation of Registrant’s Name Into English) Norway (Jurisdiction of Incorporation or Organization) Forusbeen 50, N-4035, Stavanger, Norway (Address of Principal Executive Offices) Torgrim Reitan Chief Financial Officer Statoil ASA Forusbeen 50, N-4035 Stavanger, Norway Telephone No.: 011-47-5199-0000 Fax No.: 011-47-5199-0050 (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 American Depositary Shares New York Stock Exchange Ordinary shares, nominal value of NOK 2.50 each New York Stock Exchange* *Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission Securities registered or to be registered pursuant to Section 12(g) of the Act: None Statoil, Annual report on Form 20-F 2011 1


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    Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report. Ordinary shares of NOK 2.50 each 3,188,647,103 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes No If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes  No Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections. Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).** Yes No **This requirement does not apply to the registrant in respect of this filing. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer  Accelerated filer Non-accelerated filer Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: U.S. GAAP International Financial Reporting Standards as issued Other by the International Accounting Standards Board  If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. Item 17 Item 18 If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No 2 Statoil, Annual report on Form 20-F 2011


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    1 Introduction 1.1 Key figures This section presents our performance in the following important areas: Income, cash flow, return, proved reserves, oil production and price, gas production and price, serious incidents, total recordable injuries and carbon dioxide emissions. For the year ended 31 December (1) For more detailed information, see Financial Highlights. 2011 2010 2009 (in NOK billion, unless stated otherwise) (restated) (restated) Net operating income 211.8 137.3 121.7 Cash flows provided by operations 111.5 80.8 73.1 Net debt to capital employed adjusted 21.1 % 25.5 % 27.6 % Calculated ROACE based Average Capital Employed before Adjustments 22.1 % 12.6 % 10.6 % Total equity liquids and gas production (mboe per day) 1,850 1,888 1,962 Proved oil and gas reserves (mmboe) 5,426 5,325 5,408 Production cost equity volumes (NOK/boe, last 12 months) 43.1 38.60 35.30 Proposed dividend per share NOK 6.50 6.25 6.00 (1) Data for the years ended 31 December 2008 and 2007 have been omitted because such financial information cannot be provided on a restated basis without unreasonable effort or expense. The board of directors will propose the 2011 dividend for approval at the Annual General Meeting scheduled for 15 May 2012. Income Cash Flow Return NOK billion NOK billion % 250 120 25 200 100 20 80 150 15 60 100 10 40 50 20 5 2009 2010 2011 2009 2010 2011 2009 2010 2011 Cash flows used in investing activities Calculated ROACE based on Average Capital Net income Net operating income Cash flows provided by operations Employed before adjustments Statoil, Annual report on Form 20-F 2011 3


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    Proved oil and gas reserves Oil production/price Natural gas volumes and prices million boe mboe per day NOK/bbl NOK per bcm NOK/scm 7,000 1,500 800 60 3 6,000 50 5,000 600 1,000 40 2 4,000 400 30 3,000 500 20 1 2,000 200 1,000 10 0 2006 2007 2008 2009 2010 2011 2006 2007 2008 2009 2010 2011 2006 2007 2008 2009 2010 2011 Average liquids price Brent Blend Natural gas Liquids Entitlement liquids production Average gas price Natural gas sales Equity liquids production Serious incident frequency Total recordable injury frequency Carbon dioxide emissions 4 7 20 6 3 5 15 4 2 10 3 1 2 5 1 2003 2004 2005 2006 2007 2008 2009 2010 2011 2003 2004 2005 2006 2007 2008 2009 2010 2011 2003 2004 2005 2006 2007 2008 2009 2010 2011 1.2 About the report Statoil's Annual Report on Form 20-F for the year ended 31 December 2011 ("Annual Report on Form 20-F") is available online at www.statoil.com. Statoil is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, Statoil files its Annual Report on Form 20-F and other related documents with the Securities and Exchange Commission, the SEC. It is also possible to read and copy documents that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C. 20549, USA. You may also call the SEC at 1-800-SEC-0330 for further information about the public reference rooms and their copy charges, or you may log on to www.sec.gov. The report can also be downloaded from the SEC website at www.sec.gov. Statoil discloses on its website at http://www.statoil.com/en/about/corporategovernance/statementofcorporategovernance/pages/default.aspx, and in its Annual Report on Form 20-F (Item 16G) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under the New York Stock Exchange (the "NYSE") listing standards. 4 Statoil, Annual report on Form 20-F 2011


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    1.3 Financial highlights In 2011, Statoil delivered record net operating income. The value-creating Peregrino, Leismer and Gassled transactions, combined with strong oil and gas prices throughout the year, contributed to the strong financial results. In 2011, production volumes were in line with expectations. Production start-up of new fields and ramp-up of production on existing fields combined with strong oil and gas prices enabled Statoil to deliver strong financial results and cash flows. Statoil publishes financial data in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU). For the year ended 31 December (1) 2011 2010 2009 (in NOK billion, unless stated otherwise) (restated) (restated) Financial information Total revenues and other income 670.2 529.9 465.4 Net operating income 211.8 137.3 121.7 Net income 78.4 37.6 17.7 Cash flows provided by operations 111.5 80.8 73.1 Cash flow used in investing activities 88.7 76.5 75.1 Bonds, bank loans and finance lease liabilities 111.6 99.8 96.0 Net interest-bearing liabilities before adjustments 71.0 69.5 71.8 Net interest-bearing liabilities adjusted 76.0 77.4 76.5 Total assets 768.6 643.3 563.1 Share capital 8.0 8.0 8.0 Non-controlling interest 6.2 6.9 1.8 Total equity 285.2 226.4 200.1 Net debt to capital employed ratio before adjustments 19.9 % 23.5 % 26.4 % Net debt to capital employed ratio adjusted 21.1 % 25.5 % 27.6 % Calculated ROACE based on Average Capital Employed before adjustments 22.1 % 12.6 % 10.6 % Operational information Equity oil and gas production (mboe/day) 1,850 1,888 1,962 Proved oil and gas reserves (mmboe) 5,426 5,325 5,408 Reserve replacement ratio (three-year average) 92% 64% 64% Production cost equity volumes (NOK/boe, last 12 months) 43.1 38.6 35.3 Share information Earnings per share for income attributable to equity holders of the company diluted 24.70 11.94 5.74 Share price at Oslo Stock Exchange on 31 December 153.50 138.60 144.80 Dividend paid per share NOK (2) 6.50 6.25 6.00 Dividend paid per share USD (3) 1.08 1.07 1.04 Weighted average number of ordinary shares outstanding 3,182,112,843 3,182,574,787 3,183,873,643 (1) Data for the years ended 31 December 2008 and 2007 have been omitted because such financial information cannot be provided on a restated basis without unreasonable effort or expense. (2) See Shareholder information section for a description of how dividends are determined and information on share repurchases. The board of directors will propose the 2011 dividend for approval at the Annual General Meeting scheduled for 15 May 2012. (3) USD figure presented using the Central Bank of Norway 2011 year-end rate for Norwegian kroner, which was USD 1.00 = 5.99 NOK. The board of directors will propose the 2011 dividend for approval at the Annual General Meeting scheduled for 15 May 2012. Statoil, Annual report on Form 20-F 2011 5


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    1.4 A glance at 2011 Statoil delivered strong financial results and cash flows in 2011. We presented a technology-focused upstream strategy, further streamlined the portfolio, and delivered historic exploration results. January Effective from 1 January 2011, we have reported our business through the following reporting segments: Development and Production Norway; Development and Production International; Marketing, Processing and Renewable Energy; Fuel & Retail; Other. We were awarded interests in 11 production licenses on the NCS, and will be operator for eight of these licenses. One of the operatorships is in the Barents Sea, one in the Norwegian Sea and six are in the North Sea. In Angola, the national oil company Sonangol announced that Statoil had been selected for operatorship and participation in several offshore pre-salt blocks. We announced first oil production from the Leismer Demonstration Project in Canada. Statoil's oil sands leases are located in north-east Alberta. February Statoil's internal investigation into the gas leakage on the Gullfaks B platform in the North Sea on 4 December 2010 was concluded and the report presented to the Petroleum Safety Authority Norway. March Statoil and ExxonMobil agreed to explore three Faroese offshore licenses jointly. The Norwegian government decided to gather more facts relevant to a possible future impact assessment for Lofoten and Vesterålen. At the same time the government decided not to carry out an impact assessment for the duration of the current Norwegian parliament. The Vega field in the North Sea and the Tyrihans subsea field in the Norwegian Sea were officially opened. The fields are expected to make important contributions to our production on the NCS. At a ceremony in Bangkok, Statoil signed a memorandum of understanding (MoU) with PTT Exploration and Production of Thailand. Under the MoU, the companies will seek to cooperate in the areas of conventional and unconventional resources and liquefied natural gas (LNG) in a global setting. In the Statfjord A operating plans, Statoil assumed that production shutdown may take place in 2014. Therefore we outlined a draft programme for an impact analysis of platform removal, including a description of plans for cessation and decommissioning. Statoil received the investigation report from the Petroleum Safety Authority Norway on the Gullfaks B gas leak on 4 December 2010. Statoil published its own investigation of the incident in February. Two new fast-track development projects were launched on the NCS, namely Gamma/Harepus and Snorre B template. Statoil and KazMunayGas signed a heads of agreement (HoA) on the Abay block in the Kazakhstani sector of the Caspian Sea. Under the HoA, the parties will conduct an evaluation of the hydrocarbon potential of the Abay block. April Statoil, along with partners Eni Norway and Petoro, made a significant oil discovery on the Skrugard prospect in the Barents Sea. The discovery was one of the most important finds on the NCS of the decade, and opened a new oil province that could provide additional resource growth. We started oil production on the Peregrino field offshore Brazil. This marked a safe and efficient start-up of Statoil's largest international operatorship to date. A new oil find was made by Statoil immediately adjacent to the Peregrino field in the Campos Basin offshore Brazil. May Statoil released its inaugural 2010 Canadian Oil Sands Report Card, containing performance indicators for the Leismer Demonstration Project (LDP) and surrounding Kai Kos Dehseh leases in northern Alberta and our actions to improve environmental performance as the leases are developed. Statoil farmed in to three offshore exploration licenses in Indonesia, significantly expanding our presence in the country. Statoil and Petrobras signed a letter of intent to expand the cooperation between the companies in respect of exploration, and to assess how the two companies can benefit from operational synergies. 6 Statoil, Annual report on Form 20-F 2011


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    Statoil's first fast-track project - Visund South - moved ahead as planned. The seabed template commenced its journey out to the field located south of Gullfaks in the North Sea. Statoil and Sintef, an independent research organisation in Scandinavia, signed a new and comprehensive research framework agreement. June Statoil decided to divest a 24.1% direct and indirect stake in the Gassled natural gas transportation infrastructure joint venture for a consideration of NOK 17.35 billion. Following this transaction, Statoil will continue to own 5.0% in the joint venture. The plan for development and operation of the Valemon gas and condensate field in the North Sea was approved by the Norwegian parliament. Production start-up is expected in 2014. Statoil celebrated its 10th anniversary as a listed company. We presented a technology-focused upstream strategy. Statoil signed two agreements for the sale of the major part of Statoil's onshore wind power activities in Norway, enabling the group to focus more of its efforts on offshore wind projects. July Statoil and Gassnova invited suppliers to take part in a technology qualification program for full-scale carbon capture at Mongstad. Statoil awarded the contract for construction of two new drilling rigs specifically designed for use on mature fields on the NCS. August The steel support structure for the Gudrun platform came into place on the North Sea field, completing the first phase of the extensive installation work carried out there. Statoil and partners Petoro AS, Det norske oljeselskap ASA and Lundin Norway AS made a significant oil discovery on the Aldous Major South prospect (PL 265) in the North Sea. Communication between the Aldous and Avaldsnes (PL 501) oil discoveries in the North Sea was confirmed, indicating that this is one field. September Statoil and its partners in the Troll license decided to invest NOK 11 billion in two new compressors on Troll A. The compressors would enable the production of gas from the field at commercial volumes until 2063. Lundin Norway AS, as operator for license PL501 located in the North Sea, announced increased estimated recoverable resources within the Avaldsnes discovery in production license PL501. Statoil confirmed a significant upside potential and that it would continue to collect and analyze data before concluding on updated estimates. October Statoil called off the search for a 48-year-old man reported missing on the Visund platform in the North Sea on Thursday 6 October. An extensive search of the seabed around the platform had been unsuccessful. Statoil and Brigham Exploration Company announced that they had entered into a merger agreement for Statoil to acquire all of the outstanding shares of Brigham through an all-cash tender offer. The total equity value was approximately USD 4.4 billion. The US unconventional plays hold a substantial resource base and represent an increasingly important part of future energy supplies. Statoil, together with partners Petoro AS, Det norske oljeselskap ASA and Lundin Norway AS, confirmed significant additional volumes in its appraisal well in the Aldous Major South discovery (PL265) in the North Sea. November Statoil signed an agreement to acquire Hess's 3.26% ownership in the Barents Sea Snøhvit Unit and adjacent production licenses. Statoil, Chevron Canada and Repsol E&P Canada were named successful bidders for exploration rights on two land parcels in the Flemish Pass Basin, offshore Newfoundland and Labrador, Canada. Statoil raised a total of USD 1.75 billion of debt in the capital markets. The transactions are expected to increase the financial flexibility of the company. Statoil acquired a 30% participating interest from Tullow Oil in block 47 offshore Suriname. Statoil decided to farm down three and exit five assets on the NCS for a total consideration of USD 1.625 billion. The buyer is Centrica, a UK-based energy company and an established NCS player. Statoil, Annual report on Form 20-F 2011 7


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    Statoil and Centrica entered into a long-term gas sales agreement for the delivery of 5 billion cubic metres (bcm) per year from 2015 to 2025 to the UK market. Statoil was awarded the operatorship and a substantial working interest in a large offshore exploration license in eastern Indonesia. December Statoil and Brigham Exploration Company announced that more than 92.2 percent of the outstanding shares of Brigham's common stock had been tendered to Statoil (excluding shares purchased by Statoil from Brigham). Statoil has since effected a short-form merger under Delaware law. Statoil increased its sponsorship of the FIRST® (For Inspiration and Recognition of Science and Technology) LEGO League, involving the building of LEGO- based robots by young students. As part of the group's Heroes of Tomorrow sponsorship programme, the agreement represents the group's first global sponsorship agreement. Statoil announced broad efforts to identify the direct and underlying causes of the Gullfaks C well control event on 19 May 2010. This was in response to post-incident orders from the Petroleum Safety Authority Norway. 8 Statoil, Annual report on Form 20-F 2011


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    2 Business overview and strategy 2.1 Our business Statoil is an integrated energy company that is primarily engaged in oil and gas exploration and production activities. Statoil's headquarters are in Norway, and the company has business operations in 41 countries and territories. Statoil ASA is a public limited liability company organised under the laws of Norway and subject to the provisions of the Norwegian act relating to public limited liability companies (the Norwegian Public Limited Companies Act). Statoil is the leading operator on the Norwegian continental shelf (NCS). It is also expanding its international activities. Ownership structure* Non-current assets* Total assets Corporate, mid- Free float and downstream 33 % 18 % Non-OECD OECD DPN 48 % Norwegian state DPI 67 % 34 % *as of 31 December 2011 *as of 31 December 2011 Distribution of shareholders Entitlement oil and gas production outside Norway accounted for 19.6% of our total production, which averaged 1,650 mmboe per day in 2011. 1.4% As of 31 December 2011, we had proved reserves of 2,276 mmbbl of oil and 3,150 bcm (equivalent 10.2 Norwegian to 17,681 tcf) of natural gas, corresponding to aggregate proved reserves of 5,426 mmboe. 7.4% government Norwegian 5.0% private owners UK 8.9% Rest of Europe US 67% Rest of World Statoil, Annual report on Form 20-F 2011 9


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    Entitlement production of liquids and gas We have business operations in 41 countries and territories. As of 31 December 2011, there were 31,715 employees in the Statoil group. Of this total, 10,385 were employees of the Statoil Fuel & Retail group, in which we held a 54% majority ownership interest as of 31 December 2011. We are among the world's largest net sellers of crude oil and condensate, and we are the second- largest supplier of natural gas to the European market. We also have substantial processing and Gas Liquids refining operations. We are contributing to the development of new energy resources, have ongoing 42.8 % 57.3 % activities in the areas of offshore wind and biofuels, and are at the forefront of the implementation of technology for carbon capture and storage (CCS). In further developing our international business, we intend to utilise our core expertise in areas such as deep water, heavy oil, harsh environments and gas value chains in order to exploit new opportunities and develop high-quality projects. Business address Our business address is Forusbeen 50, N-4035 Stavanger, Norway. Our telephone number is +47 51 99 00 00. Our largest locations in terms of the number of employees are in Stavanger, Bergen and Oslo, Norway. The Statoil group, the main business areas and staff functions are presented in the following sections of this report. The figure below provides an overview of the countries and territories in which Statoil has business operations. Greenland Norway Faeroe Sweden Islands Russia Estonia Canada Denmark Latvia Lithuania Ireland Poland Germany Kazakhstan United Kingdom Belgium Netherlands Turkmenistan United States Turkey Azerbaijan China Iraq Iran Algeria Libya Egypt Mexico Bahamas India Cuba United Arab Emirate Venezuela Nigeria Suriname Singapore Indonesia Tanzania Brazil Angola Mozambique 120001_STN065251 10 Statoil, Annual report on Form 20-F 2011


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    2.2 Our history Statoil was formed in 1972 by a decision of the Norwegian Storting (parliament). It was listed on the stock exchanges in Oslo and New York in 2001. Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap AS on 18 September 1972. As a company wholly owned by the Norwegian State, Statoil's role was to be the government's commercial instrument in the development of the oil and gas industry in Norway. In 2001, the company became a public limited company listed on the Oslo and New York stock exchanges, and it changed its name to Statoil ASA. On 1 October 2007, the oil and gas division of Norsk Hydro ASA was merged with Statoil, and the company was given the temporary name of StatoilHydro. On 1 November 2009, the company changed its name back to Statoil. We have grown in parallel with the Norwegian oil and gas industry, which dates back to the late 1960s. Initially, our operations primarily focused on exploration for and the production and development of oil and gas on the Norwegian continental shelf (NCS) as a partner. In the 1970s, we commenced our own operations, made important discoveries and began oil refining operations, which have been of great importance to the further development of the NCS. We grew substantially in the 1980s through the development of large fields on the NCS (Statfjord, Gullfaks, Oseberg, Troll and others). We also became a major player in the European gas market by securing large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, we were involved in manufacturing and marketing in Scandinavia and established a comprehensive network of service stations. The 1990s were characterised by substantial improvements in the production performance of our large fields. This was the result of intense technological development on the NCS. We laid the foundation for future improvements by becoming a leading company in the fields of floating production facilities and subsea development. The company grew strongly, expanded in new product markets and increased its commitment to international exploration and production. Since 2000, our business has grown as a result of substantial investments on the NCS and internationally. Our ability to fully realise the potential of the NCS was strengthened through the merger with Hydro's oil and gas division, which also bolstered our global competitiveness. In recent years, we have utilised our expertise to design and manage operations in various environments in order to grow our upstream activities outside our traditional area of offshore production. This includes the development of heavy oil and shale gas projects. In October 2010, we successfully carried out an initial public offering (IPO) of Statoil Fuel & Retail ASA on the Oslo stock exchange (Oslo Børs), partially divesting and reducing our interest in the business relating to service stations. 2011 was a very significant year for Statoil. It started with the implementation of a new organisational model and reporting segments. Throughout the year, we delivered strong financial results and cash flows as a result of strong production in line with expectations and high gas and liquids prices. We delivered historic exploration results, particularly through the Skrugard prospect in the Barents Sea the Johan Sverdrup discovery in the North Sea and the Peregrino South discovery in Brazil. We also started oil production on the large Peregrino field off the coast of Brazil - Statoil's largest international operatorship to date. We further streamlined our portfolio in 2011. On the divestment side, Statoil decided to divest a 24.1% direct and indirect stake in the Gassled natural gas transportation infrastructure joint venture, and entered into an agreement to farm down three and exit five assets on the NCS. On the acquisition side, Statoil and Brigham Exploration Company announced an agreement for Statoil to acquire all of the outstanding shares in Brigham. The transaction was completed in 2011. The US unconventional plays constitute a substantial resource base and represent an increasingly important part of future energy supplies. Statoil has progressively developed industrial capabilities through early entrance into the Marcellus and Eagle Ford shale plays. Entering the Bakken and Three Forks tight oil plays and taking on operatorship is a significant new step for Statoil. We aim to position ourselves as a leading player in the fast-growing US onshore oil and gas industry. Although petroleum-related activities on the NCS and internationally have accounted for the bulk of our business, we are increasingly participating in projects that focus on other forms of energy - such as offshore wind and carbon capture and storage (CCS) - in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change. Statoil, Annual report on Form 20-F 2011 11


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    2.3 Our competitive position Information about Statoil's competitive position relies on a range of sources, including analyst reports, independent market studies and our internal assessments of our market share. The information about Statoil's competitive position in the business overview and strategy, and operational review sections is based on a number of sources - including investment analyst reports, independent market studies, and our internal assessments of our market share based on publicly available information about the financial results and performance of market players. We have endeavoured to be accurate in our presentation of information based on other sources, but have not independently verified such information. 2.4 Organisational structure A new corporate structure was implemented with effect from 1 January 2011. The changes were made in order to simplify the organisation, enhance value creation and clarify internal accountability. The figure below illustrates the new corporate structure: Statoil's Corporate Executive Committee and the respective business areas and staff functions Chief Executive Officer Helge Lund Chief Financial Corporate Staffs Officer & Services Stavanger Stavanger Torgrim Reitan Tove Stuhr Sjøblom Development & Development & Development & Marketing, Technology, Exploration Global Strategy & Production Production Production Processing and Projects & Drilling Business Norway International North America Renewable Energy Development Stavanger Oslo Houston Stavanger Stavanger Oslo London Øystein Michelsen Peter Mellbye Bill Maloney Eldar Sætre Margareth Øvrum Tim Dodson John Knight Development and Production Norway (DPN) DPN comprises our upstream activities on the Norwegian continental shelf (NCS). DPN aims to continue its leading role and ensure maximum value creation on the NCS. Through excellent HSE and improved operational performance and cost, DPN strives to maintain and strengthen Statoil's position as a world- leading operator of producing offshore fields. DPN seeks to open new acreage and to mature improved oil recovery and exploration prospects. New and existing fields are primarily developed using an industrial approach, where speed of delivery and cost improvements through standardisation and repeated use of proven solutions are key elements. Development and Production International (DPI) DPI comprises our worldwide upstream activities that are not included in the DPN and DPNA business areas. DPI's ambition is to build a large and profitable international production portfolio covering activities ranging from accessing new opportunities to delivering on existing projects and managing a production portfolio. DPI endeavours to ensure the delivery of profitable projects in a range of complex technical and stakeholder environments, and it manages a broad non-operated production portfolio that will be complemented with operated positions. 12 Statoil, Annual report on Form 20-F 2011


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    Development and Production North America (DPNA) DPNA comprises our upstream activities in North America. DPNA's ambition is to develop a material and profitable position in North America, including the deepwater regions of the Gulf of Mexico and unconventional oil and gas and oil sands in the USA and Canada. In doing this, we aim to further strengthen our capabilities in deep water, unconventional gas operations and carbon-efficient oil sands extraction. Marketing, Processing and Renewable Energy (MPR) MPR comprises our marketing and trading of oil products and natural gas; transportation, processing and manufacturing; the development of oil and gas value chains; and renewable energy. MPR's ambition is to maximise value creation in Statoil's midstream, marketing and renewable energy business. Technology, Projects and Drilling (TPD) TPD's ambition is to provide safe, efficient and cost-competitive global well and project delivery, technology excellence and R&D. Cost-competitive procurement is an important contributory factor, although group-wide procurement services are also expected to help to drive down costs in the group. Exploration (EXP) EXP's ambition is to position Statoil as one of the leading global exploration companies. This is achieved through accessing high potential new acreage in priority basins, globally prioritising and drilling more significant wells in growth and frontier basins, delivering near-field exploration on the NCS and other select areas, and achieving step-change improvements in performance. Global Strategy and Business Development (GSB) GSB sets the corporate strategy, business development, and merger and acquisition activities (M&A) for Statoil. The ambition of the new GSB business area is to closely link corporate strategy, business development and M&A activities to actively drive Statoil's corporate development. Reporting segments After implementing the new corporate structure 1 January 2011, Statoil has reported its business in five reporting segments: Development and Production Norway (DPN); Development and Production International (DPI), which combines the DPI and DPNA business areas; Marketing, Processing and Renewable Energy (MPR); Fuel & Retail (SFR); and Other. See note 4 Segments, to the consolidated financial statements for additional information. Activities relating to the Exploration business area are allocated to and presented in the respective development and production segments. The Other reporting segment includes activities in TPD, GSB, Corporate Staffs and Services, and activities related to the CFO. After the successful listing on the Oslo Stock Exchange in October 2010, Statoil's remaining ownership share in the listed company Statoil Fuel & Retail ASA, is 54%. SFR is fully consolidated in Statoil's financial statements, and is reported as seperate reporting segment followed up by the CFO area. SFR is a leading road transportation fuel retailer that is present in eight countries in Scandinavia, and Central and Eastern Europe. SFR is also involved in the sale of stationary energy, marine fuel, aviation fuel, lubricants and chemicals. As of December 2011, SFR had a network of 2,305 service stations in its eight countries of operations. Statoil Fuel & Retail ASA also markets refined products directly to consumer and industrial markets. 2.5 Strategy Statoil's vision is "Crossing Energy Frontiers". It guides our long-term strategy as an upstream-oriented and technology-based energy company. At the heart of our strategy is a strong focus on operations and HSE. We operate in an industry that is becoming increasingly complex. Access to and competition for resources is becoming more challenging. The pace of change will continue to increase in the future and the importance of quality in execution will be even higher - making safe and efficient operations more important than ever. 2.5.1 Our business environment While the current global economic situation is fragile, non-OECD economies are still growing at an impressive rate. This factor should play a large role in keeping global energy demand high in the future. Since the 2008 financial crisis, OECD countries have struggled to stage a stable and sustained recovery. Key economies are hampered by high sovereign debt and large deficits. Households and businesses remain very cautious, and a rebalancing of public and private balance sheets in the OECD will take time. Non-OECD economies, on the other hand, have remained relatively robust, growing at about three times the pace of the OECD average. Global oil demand climbed slightly in 2011 as growth in non-OECD markets offset the decline in the OECD markets. In spite of muted demand, prices hovered around USD 110/bbl for much of 2011, in contrast to the period 2008-2009, when demand contraction led prices to fall to below USD 40/bbl. Statoil, Annual report on Form 20-F 2011 13


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    The ramp-up in prices as demand rebounded in 2010 reflected growing concern about future capacity additions, which, along with actual supply-side shocks, continued to play a role in maintaining high prices in 2011. In gas markets, 2011 was marked by a 9% increase in LNG imports to Asia in the wake of the Fukushima tragedy. This increase contrasted with stagnant North American and declining European demand. The recovery in gas demand following the 2008-2009 recession heralded a new paradigm in pricing as continued aggressive development of unconventional gas in North America broke the link between Henry Hub and UK National Balancing Point (NBP) and Asian LNG prices. Henry Hub was below USD 4/MMBtu for much of 2011, whereas the UK NBP price was closer to USD 10/MMBtu, and Asian LNG prices were even higher, reflecting the willingness of buyers there to pay an energy security premium. Given OECD weakness and non-OECD robustness, Statoil expects the world economy to grow by 3.1% annually over the coming 10 years, with an OECD annual average of 2.1% and a non-OECD annual average of 5.4%. This anticipated economic development pattern means increasing economic gravitation towards the East, at the expense of the West. Solid non-OECD growth is expected to support energy demand over the next 10 years. In the period from 2011 to 2020, internal Statoil research suggests that growth in oil demand will average 1.0% (~0.8 mbpd) annually and will - along with continued concern about upstream capacity - support oil prices close to the levels seen recently. Statoil expects non-OPEC capacity to rise by only 0.3-0.4 mbpd per year on average going forward, which means increased demand for OPEC liquids and reduced OPEC spare capacity. Statoil's internal research suggests that gas demand in Europe and North America will increase by 1-2% per year in the period up to 2020, while Asian demand will grow at around 5% per year in the same period. Both Europe and Asia will rely more on imported LNG to meet demand, which will probably result in upward pressure on prices. This contrasts with the situation in North America, where continued development of shale gas is expected to maintain downward pressure on prices in the short to medium term. The current global economic situation is fragile, and the actual development path could be either more subdued or more buoyant than currently anticipated. As a result, energy prices could vary considerably in the short to medium term. Production to reserve growth remains a key challenge for international oil companies, as it has been over the last five to ten years. We believe Statoil's compound average growth rate in the last decade (2.7%) is highly competitive. Access to new resources has been made more difficult as a result of increasing competition and tighter fiscal conditions in many resource-holding countries. Corporate responses to this situation have been varying mixes of moves into unconventional assets such as shale gas, increased focus on exploration, and the rationalisation of asset portfolios to strengthen balance sheets and reposition for growth. Going forward, the decline of legacy fields and the increasingly technically challenging nature of new field developments are expected to put upward pressure on capital and operational expenditures. Together with depressed equity markets and tightening credit, this will put a strain on the liquidity of many industry players in the years ahead and may trigger industry restructuring. 2.5.2 Our corporate strategy Statoil aims to grow and enhance value through its technology-focused upstream strategy, supplemented by selective positions in the midstream and in low-carbon technologies. Statoil made sound strategic progress in 2011. First, a major reorganisation was implemented at the beginning of the year, then an updated strategy was presented to investors in June. Statoil's immediate priorities remain to conduct safe, reliable operations with zero harm to people and the environment, and to deliver production growth. To succeed going forward we are focusing strategically on the following: Revitalising Statoil's legacy position on the NCS Building offshore clusters Developing into a leading exploration company Stepping up our activity in unconventional resources Creating value from a superior gas position Continuing portfolio management to enhance value creation Utilising oil and gas expertise and technology to open new renewable energy opportunities. Revitalising Statoil's legacy position on the NCS The NCS remains a prolific and productive oil and gas province where only half of the resources have been produced. The Skrugard discovery in the spring of 2011 and Havis discovery in early 2012 have increased expectations of the exploration potential of the Barents Sea. Furthermore, the Aldous/Avaldsnes discoveries have stimulated efforts to make additional new large discoveries in the more mature North Sea. Between now and 2020, Statoil aims to bring on stream new production from a combination of developments of smaller discoveries, increased oil recovery (IOR) projects and the development of larger discoveries. 14 Statoil, Annual report on Form 20-F 2011


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    Current plans put the number of IOR projects at approximately 100. Future oil price expectations will extend the economic lifetime of most of the major fields, and thereby reduce the time criticality of many of the IOR projects. This will allow for greater flexibility in determining the optimal timing of these projects. A number of larger field developments are currently in the project pipeline. They include the Luva, Dagny, Skrugard and Aldous/Avaldsnes fields, which are expected to contribute considerably to Statoil's total production over the period 2016-2020. Of the approximately 40 smaller field development projects identified on the NCS, Statoil currently has nine projects in its fast-track development portfolio. Plans for development and operation have already been submitted for five of them (Skuld, Hyme, Stjerne, Vigdis North-East and Visund South) and two more (Visund North and Vilje South) have received licence approval. Fast-track developments are expected to contribute approximately 100,000 barrels of oil equivalent per day (boepd) by 2014. Building offshore clusters Statoil's international oil and gas production has increased from 100,000 to 500,000 boepd over the last decade. The company has established a presence in 41 countries and built a strong international portfolio of assets. These countries include some of the most attractive basins in the industry - such as the USA (Gulf of Mexico [GoM] and onshore), Brazil, Angola and Azerbaijan (Caspian). Based on its efforts over the last 15-20 years, Statoil is now in a position to build at least three to five offshore clusters in select areas over the next eight to ten years. Offshore clusters are areas that make a material contribution to total production, where Statoil is the operator and has a mix of assets in different stages of development, and where we possess considerable expertise, both below and above ground. Through the cluster focus, our goal is to achieve greater economies of scale, capture synergies and thereby increase profitability. The first oil from the Peregrino field in Brazil was produced in 2011. We continue to work on ramping up Peregrino production, and, in the time ahead, we will focus on further developing the Peregrino area and maturing the existing exploration portfolio. In Angola, we are working to optimise the non-operated portfolio, and to explore the significant pre-salt acreage we were awarded in 2011 (18,400 square kilometres). This is an exciting new play with parallels to the Brazilian pre-salt acreage. In the GoM, Statoil was one of the first oil companies to be issued a permit to resume drilling after the Macondo incident. Here, besides managing our non- operated production, we are stepping up our efforts to mature, high grade and drill the best prospects in our drilling programme, and we continue to focus on developing improved subsurface capabilities in order to increase recovery rates. Developing into a leading exploration company 2011 has been a good year for exploration for Statoil. In fact, the company made the single biggest oil discovery worldwide in 2011 (Johan Sverdrup in the North Sea). To replicate this success we aim to balance the strengthening of our exploration portfolio in offshore clusters (North Sea, Angola, Brazil, the Caspian and the GoM) with frontier exploration and more high-impact wells to unlock new plays (e.g. the Norwegian Sea, Barents Sea and other Arctic areas, Tanzania and Indonesia). More specifically, we will focus on: A select set of basins - including frontier regions Drilling more significant wells Securing access to exploration acreage early and at scale and low cost through innovation and new ways of cooperation Reducing drilling costs Stepping up our activity in unconventional resources The Brigham acquisition in the fourth quarter of 2011 is the most recent example of our ambition to step up our position in North American unconventional resources. Building on our Alberta, Canada Kai Kos Deh Seh oil sands project - where we announced the first oil production at the Leismer Demonstration Project in January 2011 and reached one million barrels of accumulated oil production in June 2011 - our unconventional resources portfolio is now diverse, and it also includes leases in the shale gas and oil basins of Marcellus, Eagle Ford and Bakken across the USA. Statoil, Annual report on Form 20-F 2011 15


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    Our priorities in unconventional resources include: Delivering on production plans Developing and executing a technology roadmap for unconventional resources Filling in our current upstream positions Further building for the long term through early access to land. By 2020, we anticipate that North American production of unconventional resources will contribute in excess of 12% of Statoil's total oil and gas production. Creating value from a superior gas position The dynamics of the gas markets in Europe are changing. There is a development towards a more liberalised market with new players and increased competition. Compared to our peers, the proximity of our reserves, the flexibility of our production and transportation systems and our commercial experience in gas sales and trading, puts us in a unique position in relation to the changes in the European gas market. In the short term, we are making considerable efforts to maximise the value of our gas in this market. In the medium to long term, our strategic thinking is directed towards the continued promotion of gas as an important part of meeting European objectives for energy security and emission reductions. Statoil has a pan-European perspective that includes North Africa (Algeria), the Caspian and LNG options, in addition to gas from the NCS. We strongly believe that natural gas is the most cost-effective bridge to a low-carbon economy. Beyond Europe, Statoil's planned midstream gas and liquids activities in North America are progressing in step with the building of our upstream unconventional resources business. These activities encompass a mix of capacity commitments, ownership and/or operation of gathering, transportation and storage facilities, marketing alliances and trading operations. They are considered important in terms of both flow assurance and margin capture. Continuing portfolio management to enhance value creation By being proactive, we intend to further enhance our portfolio in the years ahead so that it will ultimately be more valuable, more robust and more sustainable beyond 2020. The strategic focus in these endeavours will be to access exploration acreage and unconventional reserves, secure operatorships, build cluster positions, manage asset maturity, de-risk positions and demonstrate the intrinsic value of the portfolio. The transactions signed and/or closed in 2011 (the Gassled farm-down, Brigham acquisition, Snøhvit farm-up, Valemon/Hild swap, the acquisition of Marcellus and Eagle Ford in-fill acreage and the NCS asset package sale to Centrica) further underpin our ability to redeploy capital and create value. Utilising oil and gas expertise and technology to open new renewable energy opportunities Climate change and growing demand for clean energy are creating new renewable and low-carbon technology business opportunities. Our core capabilities and expertise put us in a position to seize these opportunities in two specific areas: offshore wind, and carbon capture and storage (CCS). Our first priority in offshore wind will be to complete the Sheringham Shoal development in the UK. Beyond Sheringham Shoal, our aim is to utilise the experience gained to develop new projects. In addition, work also continues on developing the proprietary Hywind floating offshore wind concept. Whether at Sheringham Shoal or through Hywind, our overall ambition is to play an active role in reducing costs in order to make offshore wind profitable on a stand- alone basis. CCS represents a key technology for reducing carbon emissions. We have become a world leader in the development and application of CCS, and we intend to build on our carbon storage experience (Sleipner, In Salah and Snøhvit projects) to position ourselves for a future commercial CCS business. We are maturing two carbon capture projects at present - the large-scale Technology Centre Mongstad testing facility and the full-scale Carbon Capture Mongstad plant. 2.5.3 Our technology We continually develop and deploy innovative technologies to achieve safe and efficient operations, and deliver on our strategic objectives. We have also defined four business-critical aspirations that we will strive to achieve over the next decade. We believe that technology is a critical success factor in the business environment within which we operate. This environment is characterised by an increasingly broad and complex opportunity set, stricter demands on our licence to operate and tougher competition. In this context, technology is increasingly important for resource access, value creation and growth. Our track record has demonstrated our ability to overcome significant technical challenges through the development and deployment of innovative technologies. At present, we are an industry leader in subsurface production and multiphase pipeline transportation. 16 Statoil, Annual report on Form 20-F 2011


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    Statoil's technology strategy is based on three main principles: Prioritising business-critical technologies Strengthening our licence to operate Expanding our capabilities Prioritising business-critical technologies Four business-critical technology aspirations need to be met in order to deliver on our strategic objectives for 2020: We need to be an industry leader in seismic imaging and interpretation based on proprietary technology in order to increase our discovery rates. We need to achieve breakthrough performance on reservoir characterisation and recovery to maximise value. We need a step change in well construction efficiency to drill more cost-effective wells. We need to develop and operate "longer, deeper and colder" subsea technologies in order to increase production and recovery. Large-scale subsea compression and complete subsea production factories are the goal by 2015 and 2020, respectively. Strengthening our licence to operate To secure our licence to operate, we must continuously focus on technologies for safe, reliable and efficient operations, as well as supporting integrity management. We are committed to developing and implementing energy-efficient and environmentally sustainable solutions. Expanding our capabilities Succeeding in a highly competitive environment will require more than just a strong focus and heavy investments. It will require the ability to build on competitive advantages, stimulate innovation and take a long-term view on selected potentially high-impact technology ventures. To do this, we will: Specify asset-specific requirement and execution plans to introduce new solutions Provide incentives for and reward those ventures that solve complex technical problems through innovative solutions, particularly when combined with prudent risk management Continuously adapt our collaborative way of working with partners and suppliers on a global basis. Statoil, Annual report on Form 20-F 2011 17


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    3 Operational review Statoil's operational review follows the segments resulting from the new corporate structure implemented on 1 January 2011. However, certain disclosures about oil and gas reserves are based on geographical areas, as required by the SEC. The new corporate structure is presented in the section Organisational structure. In this chapter, the operations of each reporting segment are presented. Underlying activities or business clusters are presented according to how the reporting segment organises its operations. However, the Exploration operating segment's activities, which include group discoveries and the appraisal of new exploration resources, are presented as part of the various development and production reporting segments (Development and Production Norway and Development and Production International). The operating segments TPD and GSB are included in the reporting segment Other. As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based upon geographical area. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa and the Americas. For further information about disclosures concerning oil and gas reserves and certain other supplementary disclosures based upon geographical area as required by the SEC, see the sections Operational review - Production volumes and price information and Operational review - Proved oil and gas reserves. 3.1 Development and Production Norway (DPN) 3.1.1 Introduction to DPN Development and Production Norway (DPN) consists of our field development and operational activities on the Norwegian continental shelf (NCS). Development and Production Norway is the operator of 44 developed fields on the NCS. Statoil's equity and entitlement production on the NCS was 1.316 mmboe per day in 2011, which was about 71% of Statoil's total production. Acting as operator, DPN is responsible for approximately 72% of all oil and gas production on the NCS. In 2011, our average daily production of oil and natural gas liquids (NGL) on the NCS was 693 mboe, while our average daily gas production on the NCS was 99.1 mmcm (3.5 bcf). We have ownership interests in exploration acreage throughout the licensed parts of the NCS, both within and outside our core production areas. We participate in 227 licences on the NCS and are operator for 171 of them. As of 31 December 2011, Statoil had a total of 1,369 mmbbl of proved Åsgard B oil reserves and 444 bcm (15.7 tcf) of proved natural gas reserves on the NCS. 18 Statoil, Annual report on Form 20-F 2011


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    Barents Sea Hammerfest Harstad Norwegian Sea Trondheim North Sea(W) 110001_STN065256 Bergen Oslo Stavanger North Sea(SW) Office 3.1.2 DPN key events in 2011 Activity levels in Development and Production Norway were high in 2011 with several new projects sanctioned - including eight fast-track projects. Total entitlement liquids and gas production in 2011 amounted to 1,316 mmboe per day An extensive turnaround programme was completed in 2011 Final investment decisions were made for the following projects: Ormen Lange northern field development* Stjerne Vigdis North-East Hyme Åsgard subsea compression Njord low pressure production Snorre A drilling upgrade Veslefrikk rig upgrade Troll 3rd & 4th compressor Skuld Vilje South Sleipner TKK Visund Nord Svalin M Hild* * Partner-operated assets Statoil, Annual report on Form 20-F 2011 19


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    3.1.3 The NCS portfolio Our NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea. We are extending production from existing fields through improved reservoir management and increased oil recovery (IOR) projects. We also operate a significant number of exploration licences. 3.1.3.1 Core production areas Statoil's NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea. We have organised our production operations into four business clusters - Operations South, Operations North Sea West, Operations North Sea East and Operations North. The Operations South and Operations North Sea West and East clusters cover our licences in the North Sea. Operations North covers our licences in the Norwegian Sea and in the Barents Sea, while partner-operated fields cover the entire NCS and are included internally in the Operations South business cluster. When possible, the fields in each cluster use common infrastructure, such as production installations and oil and gas transport facilities. This reduces the investments required to develop new fields. Our efforts in these core areas will also focus on finding and developing smaller fields through the use of existing infrastructure and on increasing production by improving the recovery factor. We are making active efforts to extend production from our existing fields through improved reservoir management and the application of new technology. 3.1.3.2 Portfolio management Statoil takes an active approach to portfolio management on the NCS. By continuously managing our portfolio, we create value by optimising our positions in core areas and new growth areas in accordance with our strategies and targets The highlights from 2011 are as follows: Statoil has further optimised its portfolio on the Norwegian continental shelf (NCS) by strengthening its position in growth areas through acquiring an additional interest in Snøhvit. In parallel, the company has high-graded parts of its portfolio by divesting interests and exiting certain less strategic fields. Statoil farmed down in three fields (Kvitebjørn, Heimdal, Valemon) and exited five (Skirne-Byggve, Fulla, Frigg-Gamma-Delta, Vale and Rind). These divestments are principally carried out through a transaction with Centrica that is expected to be closed in the 2012. For further details regarding the above-mentioned transactions see the section Global Strategy and Business Development (GSB) - GSB key events in 2011. 20 Statoil, Annual report on Form 20-F 2011


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    3.1.4 Exploration on the NCS 2011 was one of the best exploration years ever for Statoil on the NCS. We made two Statoil-operated important oil discoveries during the year - the Aldous discovery (PL265) in the North Sea and the Skrugard discovery (PL532) in the Barents Sea. The number of exploration wells increased from 17 exploration wells and four exploration extensions completed in 2010 to 25 exploration wells and four exploration extensions of production wells completed in 2011. This increase is mainly due to the maturation of targets based on new knowledge gained from the extensive 2008 and 2009 drilling campaigns and new acreage awarded in the Norwegian government's 20th concession round. The 2011 portfolio has been well-balanced and split between infrastructure-led exploration (ILX) and growth/frontier wells (higher volume potential). Eighteen of the 25 wells were wildcats drilled to test new prospects, and 15 of the wildcats were operated by us. Eleven of the 15 Statoil-operated wildcat wells were discoveries, while the three The Ramford Vanguard partner-operated wildcat wells were dry. The Aldous Major South discovery in PL265 on the Utsira Height in the Sleipner area is situated 140 kilometres west of Stavanger and 35 kilometres south of the Grane field. The discovery was made in sandstone from the Jurassic age in a reservoir of very high quality. The licence was awarded to Statoil as operator in 2001. The partners are Petoro, Det norske and Lundin. Five wells have been drilled in the licence, four of which have encountered hydrocarbons. All the wells have contributed valuable information and understanding of the geological history of the area. The PL265 partnership will consider further exploration drilling to clarify the potential and optimal development solution. The Avaldsnes discovery was made in PL501 in 2010, with Lundin as operator and Statoil and Mærsk as partners. Avaldsnes and Aldous are connected, and it is important going forward to gain a good understanding of the reservoir distribution between the two licences. The new name for the Aldous/ Avaldsnes development is Johan Sverdrup, and Statoil is aiming for a rapid development with the ambition of starting production in 2017. The Skrugard discovery is located about 250 kilometres off the coast from the Melkøya LNG plant in Hammerfest. The well proved to have excellent reservoir parameters, and the volume discovered is large enough for a new stand-alone development in the Barents Sea. One new wildcat well in this licence was spudded in late 2011 on the Havis prospect, with a discovery in early 2012. Following that, an appraisal well on the Skrugard discovery is being drilled after the Havis well in Q1 2012. In addition to the Johan Sverdrup and Skrugard discoveries, we have made several commercial discoveries in the North Sea, such as Krafla, Krafla West, Opal and Rutil. These wells were drilled to add resources to our existing production installations. The Opal and Rutil discoveries are labelled fast-track candidates, which means that their development phases and production start-ups can be expedited. We did not drill any wells in the Norwegian Sea deepwater region in 2011. The focus has been on interpreting and gaining an understanding of the 2010 well results in order to choose the right target for the next exploration well. We were awarded 11 licences in the 21st concession round on the NCS - eight as operator and three as a partner. Four of our operatorships were awarded in the Barents Sea and four in the Norwegian Sea. All of the new licences in the Norwegian Sea are concentrated in the Luva area and fit well with the strategy for the area. In the Barents Sea, there is a strong focus on the licences surrounding the Skrugard discovery and the Hoop area, which is classified as a high-potential frontier area. We have also been awarded interests in 11 production licences in the 2011 Awards for Pre-defined Areas (APA) on the NCS, eight of which are operatorships. In the North Sea, we will be operator in eight of the nine licences awarded, and we will participate as partner in one or two licences in the Norwegian Sea. In June, the maritime border delimitation agreement was ratified by the Norwegian and Russian foreign ministers. The area is still immature. The Norwegian Ministry of Petroleum and Energy and the Norwegian Petroleum Directorate have completed the first phase of seismic acquisition in the Barents Sea East and have announced that they will complete phase two for the resolved area in 2012. Statoil, Annual report on Form 20-F 2011 21


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    The table below shows our exploratory and development wells drilled on the NCS in the last three years. 2011 2010 2009 North Sea Statoil operated exploratory 13 5 23 Statoil operated development 61 59 72 Partner operated exploratory 5 7 1 Partner operated development 12 11 17 Norwegian Sea Statoil operated exploratory 2 2 10 Statoil operated development 14 14 19 Partner operated exploratory 2 3 4 Partner operated development 6 6 1 Barents Sea Statoil operated exploratory 2 0 1 Statoil operated development 0 0 0 Partner operated exploratory 1 0 0 Partner operated development 0 0 0 Totals Exploratory 25 17 39 Exploration extension wells 4 4 2 Development wells 93 90 109 Potential producing areas In addition to producing areas, Statoil operates a significant number of exploration licences. The exploration acreage is located both in undeveloped frontier areas and near infrastructure and producing fields. Square km Square km Change vs Number of licenses Number of licenses Number of licenses New licenses New licenses Area (NCS Total) (Statoil) 2010 (NCS Total) (Statoil equity) (Statoil Op.) (Statoil equity) (Statoil operated) NCS total 126,879 48,244 (3,069) 444 227 171 27 20 North Sea 51,505 15,728 (3,788) 255 117 91 10 8 Norwegian Sea 49,709 19,893 (95) 136 79 57 10 7 Barents Sea 25,625 12,623 814 53 31 23 7 5 North Sea In addition to the Johan Sverdrup development on the Utsira High, there are firm plans to explore other significant prospects and growth opportunities in the North Sea. Future discoveries will most likely be tied in to existing infrastructure; however, stand-alone developments will also be considered if the volumes are sufficient. The total area in which we participate has been reduced by about 4,000 square kilometres during 2011 as a result of relinquishments. Norwegian Sea In the Norwegian Sea, the Luva discovery in the Vøring area has passed the concept selection phase, and the project is targeted for a final investment decision and submission of a plan for development and operation within the year. The establishment of new infrastructure in this area will create a need for additional tie-in volumes, and there are plans to drill more deepwater wells in the coming years. Barents Sea Statoil participated in three wildcat wells and was operator for two of them. The Skrugard discovery proved to have excellent reservoir parameters and the proved reserves are sufficient to build new infrastructure in the Barents Sea and open up a new production area. There are several other promising prospects 22 Statoil, Annual report on Form 20-F 2011


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    in the area, and there are firm plans to further explore this area. The newly awarded licences in the Hoop area 200 kilometres north-east of the Skrugard discovery could have the potential to create new producing areas in future. 3.1.5 Development on the NCS The NCS is the backbone of our operations. We continue to explore and develop the NCS as an operator and partner, using the best available technology and increasingly standardised development solutions. 3.1.5.1 NCS fields under development The following fields are currently under development on the NCS, and they include both traditional and fast- track processes. The Gudrun field is located in the North Sea. The field will be developed Goliat with a separate steel jacket-based process platform for separation of the oil and gas. Gas and partly stabilised oil will be transported in separate Hammerfest pipelines from Gudrun to Sleipner. Gas will be further transported through the Gassled system, while oil will be transported together with Sleipner condensate by pipeline to the Gassco-operated Kårstø plant near Haugesund. The plan for development and operation (PDO) was approved by the Norwegian authorities in June 2010. Production is estimated to start Skuld in 2014. The total investments are estimated to amount to NOK 18.5 billion. On 15 December 2010, Statoil signed an agreement with Marathon Petroleum Norge to buy their 20% share of the production Marulk licences covering the Gudrun field. As a consequence of this, Statoil's share in the development is now 75%, effective from 1 April 2011. Skarv The jacket for the processing platform has been constructed by Aker Verdal. It was successfully installed in its field location in the last week of July 2011. Conductor driving was subsequently performed, and drilling of the first production well started on 6 September, four weeks ahead of Hyme schedule. A total of seven production wells will be drilled and completed prior to production start-up. Trondheim Visund Valemon, which is located in the North Sea, will be developed with a steel Vigdis jacket platform with gas, condensate and water separation. Drilling will be performed using a jack-up rig. Rich gas will be transported via the Huldra pipeline to Heimdal for processing. Sales gas will be transported in Valemon Vesterled to St Fergus, or, alternatively, in the Statpipe pipeline to Draupner. There will be a condensate tie-in to Kvitebjørn for stabilisation Bergen and further export in pipelines to Mongstad. The PDO for the Valemon Oslo field development, submitted to the Norwegian Ministry of Petroleum and 120001_STN069844 Stjerne Energy (MPE) in October 2010 was approved by the Norwegian parliament Vilje Stavanger on 10 June 2011. The development cost of Valemon is currently estimated to be NOK 19.8 billion, and production start-up is estimated to take place Gudrun during the fourth quarter of 2014. Statoil's ownership interest in Valemon is per 31.12.2011 64.275%. In October 2011, a sales agreement was made with Centrica Resources (Norge) AS for a 13% share of Valemon, reducing Statoil's ownership interest to 53.775%. This transaction is expected to be closed in the second quarter of 2012. Contracts for the construction of the steel jacket (Heerema Vlissingen), for transportation and installation of the jacket (Heerema Marine Contractors) and a contract for the tie-in modifications on Kvitebjørn (Bergen Group Rosenberg) have all been awarded. In addition, the contract for drilling production wells has been awarded to Seadrill Offshore AS. The drilling rig West Elara is to be used for this operation. Visund South is located in the Tampen area of the North Sea. The field was discovered in early 2009. Statoil is the operator, with an ownership interest of 53.2%. The PDO was formally submitted to the MPE on 21 January 2011, and it was approved by the Norwegian parliament on 10 June 2011. The development cost is currently estimated to be NOK 5.6 billion. The field will be developed with a subsea template tied back to the Gullfaks C platform. The template has been constructed by FMC Technologies. It was installed on the field in June 2011. Production drilling commenced on 11 September. Production is scheduled to start in the fourth quarter of 2012. Statoil, Annual report on Form 20-F 2011 23


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    Hyme is an oil discovery in the Halten area of the Norwegian Sea, about 15 kilometres east of the Njord field. Statoil is operator and holds a 35% ownership interest in the discovery. The PDO for the field, which was submitted to the MPE on 12 May 2011, was approved by the MPE on 28 June. The development cost is currently estimated to be NOK 4,8 billion. The selected development concept includes a subsea template that will be tied back to the Njord A platform, one multilateral production well and one water injection well. Production start-up is scheduled for the first quarter of 2013. Stjerne is an oil discovery in the Oseberg area, located 13 kilometres south west of the Oseberg South platform. Statoil is the operator and holds a 49.3% ownership interest. The discovery was made in March 2009 and it is being developed as a one-template subsea tie-in to the Oseberg South platform, with two oil production wells and two water injection wells for pressure support. The PDO for the field was submitted to the MPE on 2 May 2011 and approved by the MPE on 16 September 2011. The development cost is currently estimated to be NOK 5.5 billion. Production start-up is scheduled for the first quarter of 2013. Vigdis North-East is an oil discovery made in 2009 approximately seven kilometres south west of the Snorre A platform in the Tampen area of the North Sea. Statoil is the operator and holds a 41.5% ownership interest. Vigdis North-East will be developed with a subsea template tied in to the Vigdis B subsea template. The oil will be processed on the Snorre A platform. The field will be developed with three oil production wells and one well for water injection. The PDO was submitted to the MPE on 12 April 2011 and approved by the MPE on 16 September 2011. The development cost is currently estimated to be NOK 4.5 billion. Production start-up is scheduled for December 2012. Skuld is a development project covering the Dompap and Fossekall oil discoveries north east of the Norne field in the Norwegian Sea. Dompap was discovered in 2009 and Fossekall in April 2010. Statoil is operator and holds a 63.955% ownership interest in the development. The Skuld development concept contains of one subsea template at Dompap and two subsea templates on Fossekall, and a total of six oil production wells and three water injection wells. The subsea installations will be tied back to the Norne floating production storage and offloading vessel (FPSO) through a production flowline. The PDO for the development was submitted to the MPE 26 September 2011, and sanctioned 20 January 2012. The development cost is currently estimated to be NOK 10.6 billion. Production start-up is scheduled for early 2013. Vilje South is a southern extension of the Vilje field, located north of Heimdal in the North Sea. Vilje South is described as a possible upside in the Vilje PDO (named Mygg). The development cost is currently estimated to be NOK 1.1 billion. Statoil is the operator and holds a 28.853% ownership interest. Vilje South will be developed as a single stand-alone subsea satellite well tied back to the existing subsea facility on Vilje, with production start-up scheduled for the third quarter 2013. Skarv is an oil and gas field located in the Norwegian Sea in which Statoil has an interest of 36.165%, with BP as operator and E.ON Ruhrgas & PGNiG as the other partners. The field is being developed with an FPSO vessel and five subsea multi-well installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. The operator currently expects production to start in the second quarter of 2012. The total development cost at the investment decision was estimated to be NOK 32 billion by the operator BP. The PDO for Goliat was submitted in February 2009 and approved by the Norwegian authorities in June the same year. Goliat is the first oilfield to be developed in the Barents Sea. The field is being developed with subsea wells tied back to a circular FPSO vessel. The oil will be offloaded to shuttle tankers. The Goliat development is operated by Eni, which has an interest of 65%. Statoil is the only partner, with an interest of 35%. The operator expects production start-up to occur in late 2013. The operator has estimated the development costs for the field to be NOK 31 billion. Marulk, in which Statoil holds an interest of 50%, is a gas and condensate field located in the Norwegian Sea 25 kilometres south west of Norne. The field was discovered in 1992. The final investment decision was taken in early 2010 and proved reserves were booked in 2010. The PDO was approved by the MPE in July 2011.The field is a subsea development with two wells tied back to Norne. Rich gas will be transported through the Norne pipeline and the Åsgard Transport System for processing to sales gas at Kårstø. Condensate will be stored and offloaded commingled with the Norne crude. Production is estimated to start in the second quarter of 2012. The operator estimates the total investments to be NOK 4 billion. The operator is Eni, but Statoil is carrying out the project work. 24 Statoil, Annual report on Form 20-F 2011


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    Key figures The table below shows some key figures as of 31 December 2011 for our major development projects. Statoil’s share at Statoil Equity Project Operator 31 december 2011 Production Start Capacity (boepd) Skarv BP 36.17 2012 50.000 Marulk Eni 50.00 2012 10.000 Skuld Statoil 63.95 2013 35.000 Goliat Eni 35.00 2013 30.000 Valemon Statoil 64.28 2014 50.000 Gudrun Statoil 75.00 2014 65.000 3.1.5.2 Redevelopments on the NCS The following projects are being developed on the NCS to extend the life of existing installations, increase oil recovery and exploit new profitable opportunities. The Gullfaks B water injection upgrade project includes replacement of the pipeline from Gullfaks A to Gullfaks B, upgrading of the existing water injection system and increased water injection capacity on Gullfaks B. The project is expected to be completed in the first half of 2013. The main purpose of the Kvitebjørn pre-compression project is to increase and accelerate gas and condensate recovery by facilitating low-pressure production. The project includes the installation of a turbine-driven compressor in a new module on the platform. Start-up is scheduled for December 2013. The Njord North-West Flank project will enable Njord A to drill and produce from the NWF reservoir. Drilling started in October 2011 and production is scheduled to start in November 2012. The Troll A 3rd and 4th pre-compressor project is described in the original PDO for the Troll field. The purpose of the project is to increase gas production by installing two extra pre-compressors on the Troll A platform. This will enable low-pressure production from the Troll East and West gas provinces. The project was sanctioned by the licence partners in the fourth quarter 2011. The investment costs are estimated to be NOK 11 billion. The expected completion date is the fourth quarter 2015. Statoil's ownership interest in the project is 30.584%. The Troll field is located in the northern part of the North Sea. The Åsgard subsea compression project will install compact subsea compressors in the Midgard part of the Åsgard fields. The purpose of the project is to increase the recoverable reserves by introducing subsea compression of the wellstream. The Åsgard subsea compression project will implement a significant amount of new subsea technology, and will be the first implementation of subsea gas compression. The PDO was submitted to the Norwegian Ministry of Petroleum and Energy (MPE) in August 2011, and approval by the authorities is expected in early 2012. The investment cost for the project is estimated to be NOK 14 billion. The expected completion date is early 2015. Statoil holds a 34.57% ownership interest in the project. 3.1.6 Fields in production on the NCS We continued developing the NCS in 2011, and delivered strong results in a year marked with extensive turnarounds and operational challenges. Statoil, Annual report on Form 20-F 2011 25


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    3.1.6.1 Production on the NCS In 2011, our total entitlement oil and NGL production in Norway was 252 mmbbl, and gas production was 36.2 bcm (1,287 bcf), which represents an aggregate of 1.316 mmboe per day. The following table shows the NCS production fields and field areas in which we are currently participating. Field areas are groups of fields operated as a single entity. Statoil’s Licence Average daily Geographical equity interest On expiry production in 2011 Business cluster area in %(1) Operator stream date mboe/day Operations North Alve The Norwegian Sea 85.00 Statoil 2009 2029 18.6 Kristin The Norwegian Sea 55.30 Statoil 2005 2027 (2) 41.0 Norne The Norwegian Sea 39.10 Statoil 1997 2026 13.1 Urd The Norwegian Sea 63.95 Statoil 2005 2026 3.5 Heidrun The Norwegian Sea 38.57 Statoil 1995 2024 (3) 28.3 Åsgard The Norwegian Sea 34.57 Statoil 1999 2027 120.4 Mikkel The Norwegian Sea 43.97 Statoil 2003 2020 (4) 22.4 Morvin The Norwegian Sea 64.00 Statoil 2010 2027 17.2 Njord The Norwegian Sea 20.00 Statoil 1997 2021 (5) 8.5 Tyrihans The Norwegian Sea 58.84 Statoil 2009 2029 54.9 Snøhvit The Barents Sea 33.53 Statoil 2007 2035 30.6 Yttergryta The Norwegian Sea 45.75 Statoil 2009 2027 4.2 Total Operations North 362.7 Operations North Sea West Kvitebjørn The North Sea 58.55 Statoil 2004 2031 100.7 Visund The North Sea 53.20 Statoil 1999 2023 12.1 Gullfaks The North Sea 70.00 Statoil 1986 2016 72.6 Gimle The North Sea 65.13 Statoil 2006 2016 2.2 Grane The North Sea 36.66 Statoil 2003 2030 50.8 Veslefrikk The North Sea 18.00 Statoil 1989 2015 2.3 Huldra The North Sea 19.88 Statoil 2001 2015 2.3 Glitne The North Sea 58.90 Statoil 2001 2013 2.0 Heimdal The North Sea 29.87 Statoil 1985 2021 (6) 0.8 Brage The North Sea 32.70 Statoil 1993 2015 (7) 7.6 Vale The North Sea 28.85 Statoil 2002 2021 0.2 Vilje The North Sea 28.85 Statoil 2008 2021 8.8 Volve The North Sea 59.60 Statoil 2008 2028 10.0 Total Operation North Sea West 272.5 Operations North Sea East Troll Phase 1 (Gas) The North Sea 30.58 Statoil 1996 2030 132.2 Troll Phase 2 (Oil) The North Sea 30.58 Statoil 1995 2030 38.8 Fram The North Sea 45.00 Statoil 2003 2024 27.4 Vega Unit The North Sea 54.00 Statoil 2010 2035 (8) 16.1 Oseberg The North Sea 49.30 Statoil 1988 2031 87.1 Tune The North Sea 50.00 Statoil 2002 2032 4.0 Total Operation North Sea East 305.7 26 Statoil, Annual report on Form 20-F 2011


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    Statoil’s Licence Average daily Geographical equity interest On expiry production in 2011 Business cluster area in %(1) Operator stream date mboe/day Operations South (ex Partner Operated Fields) Statfjord Unit The North Sea 44.34 Statoil 1979 2026 34.0 Statfjord Nord The North Sea 21.88 Statoil 1995 2026 1.0 (9) Statfjord Øst The North Sea 31.69 Statoil 1994 2024 2.5 (10) Sygna The North Sea 30.71 Statoil 2000 2024 0.3 (11) Snorre The North Sea 33.32 Statoil 1992 2015 31.9 Tordis area The North Sea 41.50 Statoil 1994 2024 9.6 Vigdis area The North Sea 41.50 Statoil 1997 2024 16.1 Sleipner Øst The North Sea 59.60 Statoil 1993 2028 18.2 Sleipner Vest The North Sea 58.35 Statoil 1996 2028 85.2 Gungne The North Sea 62.00 Statoil 1996 2028 10.9 Total Operations South (ex Partner Operated Fields) 209.7 Partner Operated Fields Ormen Lange The Norwegian Sea 28.92 Shell 2007 2041 115.7 Gjøa The North Sea 20.00 GDFSuez 2010 2028 15.4 Ekofisk area The North Sea 7.60 ConocoPhillips 1971 2028 18.4 Ringhorne Øst The North Sea 14.82 ExxonMobil 2006 2030 2.5 Sigyn The North Sea 60.00 ExxonMobil 2002 2018 11.5 Enoch The North Sea 11.78 Talisman 2007 2018 0.3 Skirne The North Sea 10.00 Total 2004 2025 1.7 Total Partner Operated Fields 165.6 Total Operations South 375.3 Total 1,316.2 (1) (7) Equity interest as of December 31, 2011. PL185 expires in 2015 and PL053B and PL055 both (2) PL134B expires in 2027 and PL199 expires in 2033 expire in 2019 (3) (8) The equity interest was 12.41% in January and February 2011, Vega, with equity interest of 60%, and Vega Sør, 49.17% share for oil production in the period March - September with equity interest of 45%, unitised to Vega Unit (9) 2011 and 38.56% in the period October - December 2011 PL037 expires in 2026 and PL089 expires in 2024 (4) (10) PL092 expires in 2020 and PL121 expires in 2022 PL037 expires in 2026 and PL089 expires in 2024 (5) (11) PL107 expires in 2021 and PL132 expires in 2023 PL089 expires in 2024 and PL057 expires in 2015 (6) PL036 expires in 2021 and PL102 expires in 2025. The owner share of the topside facilities is 39.44%, however the owner share of the reservoir and production is 29.87%. Statoil, Annual report on Form 20-F 2011 27


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    The following table shows our average daily entitlement production of oil, including NGL and condensates, and natural gas for each of the years ending 31 December 2011, 2010 and 2009. For the year ended December 31, 2011 2010 2009 Oil and NGL Natural gas Oil and NGL Natural gas Oil and NGL Natural gas Area production mbbl mmcm mboe mbbl mmcm mboe mbbl mmcm mboe Operations North 214 24 363 183 24 333 175 25 332 Operations North Sea West 177 15 273 228 17 336 269 17 378 Operations North Sea East 147 25 306 138 32 337 159 26 320 Operations South (ex Partner Operated Fields) 112 16 210 119 16 220 138 20 261 Partner Operated Fields 43 19 165 36 18 147 43 18 158 Total 693 99 1,316 704 106 1,374 784 106 1,450 3.1.6.2 Operations South Operations South includes a large part of Statoil's production activity on the NCS. The main producing fields in the Operations South area are Statfjord, Snorre, Tordis, Vigdis, Sleipner and partner-operated fields. Statoil's share of the area's production in 2011 was 155 mbbl per day of oil, condensate and NGL, and 220 mboe per day of gas, or 375 mboe per day in total. Of this, partner-operated assets (see the section Partner- operated fields) accounted for 43 mbbl per day of oil, condensate and Snorre NGL, and 122 mboe per day of gas, or 165 mboe per day in total. Even after over 30 years of production from this area, we believe that there are Vigdis Florø still substantial opportunities for increased value creation. Statfjord Statoil has taken several initiatives to identify and implement measures to increase and prolong production from the Operations South area. These Tordis initiatives involve IOR, and they have resulted in a prolongation of planned production beyond the current licence period for several of the fields. Mongstad Sture The Snorre field has been developed with two platforms and one subsea Kollsnes production system connected to one of the platforms (Snorre A). Oil and Bergen gas are exported to Statfjord for final processing, storage and loading. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A. The PL 089 licence includes the Vigdis, Borg and Tordis fields. The Tordis field and the southern part of the Borg field have been developed with seven subsea satellites and two templates that are tied back to Gullfaks C, where the oil and gas are processed and stored for offshore loading and export. Kårstø The Vigdis field was developed in 1997 with three subsea templates with a well stream through pipelines connected to Snorre A, where the oil is Stavanger stabilised and exported to Gullfaks for storage and loading. The northern Sleipner part of Borg is also produced via the Vigdis templates. The PDO for the 120001_STN069285 Vigdis North-East Fast Track Project was approved by the MPE in September 2011, and production start-up is planned for the fourth quarter of 2012. 28 Statoil, Annual report on Form 20-F 2011


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    Statfjord has been developed with three fully integrated platforms supported by gravity base structures with concrete storage cells. Each platform is tied to offshore loading systems for loading oil into tankers. Associated gas is piped through the Tampen link to the UK or, alternatively, to the Kårstø gas processing plant and then on to continental Europe. Three satellite fields (Statfjord North, Statfjord East and Sygna) have been developed, each of them tied back to the Statfjord C platform. In 2005, an amended PDO was approved by the Norwegian authorities for the late-life production period for Statfjord. The Norwegian authorities granted a licence extension for the Statfjord area from 2009 to 2026. The plan is that Statfjord A production will be shut down in 2016. Sleipner consists of the Sleipner East, Gungne and Sleipner West gas and condensate fields. Condensate from the Sleipner field is transported to the gas processing plant at Kårstø. The gas from Sleipner has a high level of carbon dioxide. It is extracted on the field and reinjected into a sand layer beneath the seabed to reduce carbon dioxide emissions to the air. We are currently exploring several prospects and discoveries in the Sleipner area that can potentially be tied in to Sleipner. Production from the Beta West structure in Sleipner West, which was discovered in 2009, was approved by the Norwegian Petroleum Directorate (NPD) in April 2011. The hydrocarbons from Gudrun will be piped to the Sleipner field. Oil and gas will be processed at Sleipner. The oil will be transported to Kårstø together with the Sleipner condensate, and the gas will be exported together with the Sleipner gas directly into the Gassled transportation system. 3.1.6.3 Operations North Sea West Operations North Sea West includes a large part of Statoil's mature production activity on the NCS. Our main focus is on increasing and prolonging production in the area, giving priority to increased oil recovery, exploration and new field development. The main producing fields in the Operations North Sea West area are Gullfaks, Kvitebjørn, Visund, Grane, Brage, Gimle, Veslefrikk, Huldra, Glitne, Volve and Heimdal. Visund The petroleum reserves are located below water depths of between 80 and 335 metres. In 2011, Statoil's share of the area's production was Florø Kvitebjørn 177 mbbl of oil, condensate and NGL per day and 96 mboe of gas per day, Gimle or 273 mboe per day in total. Veslefrikk The Gimle field is a Gullfaks satellite field that is operated as a separate Gullfaks unit. Permanent production started in May 2006, with the Gimle exploration well drilled from the Gullfaks C platform being converted into a Mongstad Huldra production well. By the end of 2010, Gimle consisted of two producers and Sture one injector, all drilled as long-reach wells from the Gullfaks C platform. Kollsnes Brage Bergen Brage is an oilfield east of Oseberg in the northern part of the North Sea. The oil is piped to Oseberg and then through the pipeline in the Oseberg Transport System to the Sture terminal. A gas pipeline is tied back to the Statpipe pipeline. Vilje Glitne is an oilfield located about 40 kilometres north-west of Sleipner East. Glitne is the smallest field development on the NCS to use a stand- Heimdal alone production system. Kårstø Grane is the first field on the NCS to produce heavy crude oil. It is Statoil's Grane largest producing heavy oil field. The field is located to the east of the Balder field in the northern part of the North Sea. Oil from Grane is piped Glitne Stavanger to the Sture terminal, where it is stored and shipped. Injection gas is imported to Grane by pipeline from the Heimdal facility. As a result, after 120001_STN069285 Volve around 25 years of oil production, Grane is producing injected gas as well. Gullfaks has been developed with three large concrete production platforms. Oil is loaded directly onto custom-built shuttle tankers on the field. Associated gas is piped to the Kårstø gas processing plant and then on to continental Europe. Five satellite fields - Gullfaks South, Rimfaks, Gullveig, Gulltopp and Skinfaks - have been developed with subsea wells that are remotely controlled from the Gullfaks A and C platforms. Oil production from Gullfaks is gradually increasing after a well control incident at well C-06 A on Gullfaks C in May 2010. Oil production is currently significantly higher than was expected in January 2011. This is the result of active reservoir management and partially restored water injection, which is now Statoil, Annual report on Form 20-F 2011 29


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    optimised according to strict operational criteria. Production drilling operations have also been initiated on Gullfaks satellites, and two drilling rigs are now in operation. The repair of integrity-weakened wells is ongoing according to plan. Statoil received the Petroleum Safety Authority Norway's investigation report on the gas leak that occured on Gullfaks B in December 2010. Statoil published its own investigation of the incident in February 2011. The gas leak occurred in connection with the resetting of piping after maintenance of a choke valve in the wellhead area on the North Sea platform. Heimdal is a gas field located in the northern part of the North Sea. Heimdal mainly operates as a processing centre for other fields. Huldra, Skirne and Vale deliver gas to Heimdal, and gas from Oseberg is also transported via Heimdal. The plan for development and operation (PDO) for Valemon was submitted in October 2010. Gas from this field will be carried via the existing pipeline from Huldra to Heimdal. The PDO was approved on 9 June 2011. The lifetime of the processing facility at the Heimdal Gas Centre will thereby be extended, enabling us to maintain important processing capacity in the area. Pre-compression plans for the Kvitebjørn field are expected to increase the production of gas and condensate from the field by approximately 35 million standard cubic metres (mscm) of oil equivalent, thereby increasing the recovery rate from 55% to 70%. Work on production of the compressor has already started. Offshore installation is expected to take place from 2012 until completion in early 2014. Veslefrikk is an oilfield located north of Oseberg in the northern part of the North Sea. Huldra is located in the Viking Graben and developed by a normally unmanned platform that is remotely controlled from the Veslefrikk field. Oil from Veslefrikk is exported through the Oseberg Transportation System, while gas is exported to Kårstø. Veslefrikk also processes condensate from Huldra. The first oil flowed from the Vilje field to the Alvheim FPSO on 1 August 2008. The Vilje field, which is linked to the Alvheim field, is located in the northern part of the North Sea, north of the Heimdal field. The Visund oilfield is located to the east of the Snorre field in the northern part of the North Sea. The field contains oil and gas in several tilted fault blocks with separate pressure and liquid systems. The oil is piped to Gullfaks A for storage and export. Gas is exported to the Kvitebjørn gas pipeline and on to Kollsnes. In April 2011, we had an incident with the Coflon risers that resulted in the risers having to be replaced and production being reduced. Three new risers were installed by November, making it possible to actively prioritise between wells in order to resume full production. Volve is an oilfield located in the southern part of the North Sea approximately eight kilometres north of Sleipner East. The development is based on production from the Mærsk Inspirer jack-up rig, with Navion Saga being used as a storage ship for crude oil before export. Gas is piped to the Sleipner A platform for final processing and export. 30 Statoil, Annual report on Form 20-F 2011


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    3.1.6.4 Operations North Sea East Operations North Sea East is a major gas area that also contains significant quantities of oil. The area includes the Troll, Fram, Vega, Oseberg and Tune fields. Statoil is committed to the development of the area, and important investments have been approved in 2011. They include the investment decision to install two new compressors in Troll A for NOK 11 billion and the fast-track development of Stjerne on Oseberg for NOK 5.4 billion. Both the Oseberg and Troll areas have significant prospective potential and new IOR projects are under evaluation.In 2011, Statoil's share of the area's Vega Florø production was 147 mbbl of oil, condensate and NGL per day and 159 mboe of gas per day, or 306 mboe per day in total. Fram The Troll area comprises Troll, Fram and Vega. Troll is the largest gas field Troll on the NCS and a major oilfield. Mongstad The Troll field is split into three hydrocarbon-bearing regions: the Troll Oseberg area West Oil Province (TWOP), Troll West Gas Province (TWGP) and Troll Sture Kollsnes East (TE). Oil-producing wells on TWOP and TWGP-South are tied into the Bergen Troll B platform, while oil wells on TWGP-North are tied into the Troll C platform. Most of Troll A's gas exports are produced on the giant condeep Troll A platform, which is located in the western part of the Troll East structure at a water depth of approximately 300 metres. Some gas is exported from Troll West as well. There is some limited communication between Troll East and Troll West. Fram consists of Fram West and Fram East, both of which were awarded under the PLO90 production licence permit. Fram West is an oilfield with Kårstø two subsea templates connected to Troll C. On Troll C, the gas is separated and exported via Troll A, while the rest is reinjected into the reservoir. Fram East produces from the F-East Sognefjord, C-West Stavanger Sognefjord and C-West Etive reservoirs. The drainage strategy for the Sognefjord reservoirs is pressure maintenance through water injection. 120001_STN069287 The Vega field came on stream in December 2010. It consists of three provinces called Vega North, Vega Central and Vega South, which were previously organised under two licences and are now unitised into the Vega Unit. The production from Vega is sent to Gjøa and processed there. The Vega gas is sent to a processing facility at St Fergus (Scotland). NGL/oil production from Vega is exported through a pipeline from Gjøa that is connected to Troll oilpipe II, which transports oil and condensate to the Mongstad refinery. The Oseberg area includes the main Oseberg field, which has been developed with field centre installations and the Oseberg C production platform, and two satellite fields - Oseberg East and Oseberg South - developed with production platforms. In addition, the Tune field and Oseberg West Flank have been developed with subsea installations and tied back to the Oseberg field centre. Oil and gas from the satellites are piped to the Oseberg field centre for processing and transportation. Oil is exported to shore through the Oseberg transportation system, and gas is exported through the Oseberg gas transportation system to Heimdal and on to market. Statoil, Annual report on Form 20-F 2011 31


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    3.1.6.5 Operations North Our producing fields in the Operations North area are Åsgard, Mikkel, Yttergryta, Heidrun, Kristin, Tyrihans, Norne, Urd, Alve, Njord, Snøhvit and Morvin. Our share of the area's production in 2011 was 214 mbbl per day of oil, condensate and NGL, and 149 mboe per day of gas, or 363 mboe per day in total. Snøhvit The region is characterised by petroleum reserves located at water depths Hammerfest of between 250 and 500 metres. The reserves are partly under high pressure and at high temperatures. These conditions have made development and production more difficult, challenging the participants to develop new types of platforms and new technology, such as floating processing systems with subsea production templates. We plan to increase efficiency by further coordinating our operations in the area and by stemming the decline in production from the mature fields through increased seismic activity and well maintenance. In addition, we intend to expand our activities by utilising our installed production and transportation capacity before building new infrastructure. The Heidrun platform is the largest concrete tension leg platform ever built. Heidrun was the first production platform in Operations North, with Norne Norway production start-up in 1995. Most of the oil from Heidrun is shipped by shuttle tanker to our Mongstad crude oil terminal for onward Urd transportation to customers. Gas from Heidrun provides the feedstock for Alve the methanol plant at Tjeldbergodden in Norway. Additional gas volumes Heidrun Sweden are exported through the Åsgard Transport System (ÅTS) to gas markets Åsgard in continental Europe. Morvin Yttergryta Kristin is a gas and condensate field in the south west section of the Operations North area. The Kristin development is the first high- Kristin Mikkel temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir - 900 bar and Tyrihans Trondheim 110001_STN065265 170 degrees Celsius, respectively - are higher than on any other developed field on the NCS. The stabilised condensate is exported to a joint Åsgard Njord Tjeldbergodden and Kristin storage vessel, and the rich gas is transported to shore via the ÅTS to the gas processing facility at Kårstø. Tyrihans started producing oil and gas in 2009, and the field was producing from seven wells by the end of 2011. In addition, gas is injected into two injection wells via Åsgard B. The Tyrihans development project is expected to be completed in 2012 with another two wells. All production volumes are processed on the Kristin platform. Njord consists of two installations. Njord A is a platform with drilling facilities and a production plant for oil and gas. Njord B is a storage vessel for oil. The Njord field has produced oil since 1997, and gas export started in late 2007 via ÅTS and Kårstø. The Norne field has been developed with a production and storage ship tied to subsea templates. This ship has processing facilities on deck and storage tanks for oil. Processed crude oil can be transferred over the stern to shuttle tankers. Norne is connected to gas markets in continental Europe through a link with ÅTS. The Urd fields, Svale and Stær, are located ten and five kilometres north of the Norne field, respectively. The fields are produced through subsea facilities, with the well stream tied back to the Norne FPSO. The Alve field, which consists of one producing well and a subsea template, was started up in March 2009. The field is produced through subsea facilities, with the well stream tied back to the Norne FPSO. Snøhvit is the first field to be developed in the Barents Sea. Twenty wells are expected to produce natural gas from three gas reservoirs: Snøhvit, Askeladd and Albatross. By the end of 2011, Snøhvit was producing from nine wells, filling the plant capacity. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore. Snøhvit reinjects carbon dioxide from the liquefied natural gas (LNG) plant into a separate well/reservoir. 32 Statoil, Annual report on Form 20-F 2011


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    The natural gas, which is transported to shore through a 143-kilometre-long pipeline, is landed on Melkøya, where it is processed at our LNG plant. This plant is Europe's largest export factory for LNG, which is shipped to customers in Europe, the USA and Asia in tankers. The first shipment took place in late 2007. The LNG plant has also suffered from operational challenges in 2011, particularly in relation to problems with the heat exchangers, which are located in the heart of the LNG Plant (cold box). Their function is to bring down the temperature of the methane gas so that it liquidises at -164 degrees Celsius (see section Gas Sales and Marketing - LNG for more information). Snøhvit carried out a major turnaround in 2011 after which regularity has been high. A new 24-hour production record for Snøhvit was set on 6 August 2011, corresponding to 109% of the original design capacity of the plant. The Åsgard field comprises three fields: Smørbukk, Smørbukk South and Midgard. The field was developed with the Åsgard A production ship for oil, the Åsgard B semi-submersible floating production platform for gas and the Åsgard C storage vessel. The subsea production installations are among the most extensive in the world, with a total of 17 seabed templates. The Åsgard B platform is the largest floating gas processing centre in the world, and Åsgard A is one of the largest floating production ships ever built. The Åsgard development links the Haltenbanken area to Norway's gas transport system in the North Sea. Gas from the field is piped through the ÅTS to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany. Oil produced at the Åsgard A vessel and condensate from the Åsgard C storage vessel are shipped from the field in shuttle tankers. Mikkel is a gas and condensate field. Production from two seabed templates is tied to the subsea installation on Midgard for onward transportation to the Åsgard B gas processing platform. Yttergryta produces from a single well, and the well stream is tied back to Åsgard B for processing. Morvin started production on 1 August 2010. The field consists of two seabed templates with production from four wells. The last well was completed in spring 2011. The well stream with oil and gas is tied back to Åsgard B for processing. Morvin makes an important contribution to utilising the production capacity on Åsgard B. 3.1.6.6 Partner-operated fields Our partner-operated fields account for a significant proportion of our oil and gas portfolio. They range from development projects to mature fields. Production is expected to start up on Skarv and Marulk in 2012. Ormen Lange, a deepwater gas field in the Norwegian Sea, is the second-largest gas field on the NCS. Statoil has a 28.916% interest in the field. Statoil was operator for the development phase, while Norske Shell became the operator for the production phase that began at the end of 2007. Statoil continues to execute the approved, but not yet completed subsea compression pilot. The selected development is an extensive subsea development at depths ranging from 850 to 1,100 metres. The well stream is transported to an onshore processing and export plant at Nyhamna. The gas is then transported through a dry gas pipeline, Langeled, via Sleipner to Easington in the UK. Ekofisk was the first developed field complex to come into operation on the NCS. ConocoPhillips is the operator. It consists of the Ekofisk, Eldfisk and Embla fields (in which Statoil has an interest of 7.604%), plus Tor (in which Statoil has an interest of 6.639%). Ekofisk has been upgraded with several new platforms over the years, the latest being the 2/4-M drilling platform, which was installed in 2005. In early 2010, a final investment decision was made to build a new Ekofisk accommodation and field centre platform. With 550 beds, it will be the largest in the world. Investment decisions were made in 2010 for a new Ekofisk South project consisting of a new drilling platform with subsea water injection facilities and the redevelopment of Eldfisk, which consists of a new drilling and process platform. The new facilities are expected to extend the field life considerably beyond the current licence period, which ends in 2028. Redevelopment of Tor is under evaluation. Sigyn, operated by ExxonMobil and in which Statoil has a 60% interest, is a gas and condensate field located 12 kilometres south east of the Sleipner A installation. The gas is exported from Sleipner A and the condensate is delivered to Kårstø. The development consists of three production wells on one subsea template, with two pipelines and one umbilical connecting it to the Sleipner A platform. Statoil has a 14.82% interest in the ExxonMobil-operated Ringhorne East field. The unitised field started production in March 2006. Three production wells have been drilled from the Ringhorne facility. Oil is transported via Ringhorne to Balder for offshore loading. Gas is exported via Jotun into the Statpipe pipeline. A fourth and fifth production well are planned to be drilled in 2012. Statoil has an 11.78% interest in the Enoch field, which is operated by Talisman. The field is a subsea development tied back to Brae A in the British sector. Production started in May 2007. Gjøa, which is located in the North Sea, has been developed with a subsea production system and a semi-submersible production platform. Statoil was the operator during the development phase, while GDF SUEZ took over as operator from production start-up in November 2010. Statoil continues to execute the drilling and completion of the production wells into 2012. Gas is exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus, and oil is exported via the Troll 2 pipeline to the Statoil-operated Mongstad refinery near Bergen. The Gjøa platform processes and exports volumes from both the Gjøa field and the neighbouring Vega fields. The platform is supplied with land-based electricity from Mongstad. Statoil has a 20% interest in Gjøa. Statoil, Annual report on Form 20-F 2011 33


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    3.1.7 Decommissioning on the NCS No Statoil-operated fields have been decommissioned during the last three years. The Norwegian government has laid down strict procedures for the removal and disposal of offshore oil and gas installations under the Convention for the Protection of the Marine Environment of the Northeast Atlantic (the OSPAR Convention). No Statoil-operated fields have been decommissioned during the last three years, however. On partner-operated fields, there has been removal activity on Frigg and Ekofisk. In 2011, Statoil commenced execution of the Troll-Oseberg Gas injection (TOGI) decommissioning project. For further information about decommissioning, see note 24 to the consolidated financial statements, Asset retirement obligations, other provisions and other liabilities. 34 Statoil, Annual report on Form 20-F 2011


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    3.2 Development and Production International (DPI) 3.2.1 Introduction to DPI Statoil is present in several of the most important oil and gas provinces in the world, and Development and Production International (DPI) is expected to account for most of the company's future production growth. Development and Production International is responsible for the development and production of oil and gas outside the Norwegian continental shelf (NCS). In 2011, the reporting segment was engaged in production in 12 countries: Canada, the USA, Brazil, Venezuela, Angola, Nigeria, Iran, Algeria, Libya, Azerbaijan, Russia and the UK. In 2011, DPI produced 28.9% of Statoil's total equity production of oil and gas. Statoil has exploration licences in North America (Gulf of Mexico, Canada and Alaska), South America and sub-Saharan Africa (Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania), Middle East and North Africa (Libya and Iran) and Europe and Asia (the Faeroes, Greenland, the UK, Azerbaijan and Indonesia). The main sanctioned development projects in which DPI is involved are in the USA, Angola and Canada. We are well positioned for further growth through a substantial pre-sanctioned project portfolio, including a strengthened onshore US position through the acquisition of Brigham Exploration Company which was closed in December 2011. The map shows Statoil's international exploration and production areas. Greenland Alaska Western Europe Russia Canada Caspian region USA North Africa Middle East West Africa Indonesia East Africa South America 120001_STN065266 Production as of 31.12.2011 Exploration Statoil, Annual report on Form 20-F 2011 35


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    3.2.2 DPI key events in 2011 International development and production continued to grow in 2011 through the start-up of several important projects. Equity production increased by 3.9% from 2010, to 534 mboe per day: On 27 January, Statoil announced the first oil from the Leismer Demonstration Project in Canada. On 9 April, the Statoil-operated Peregrino offshore field in Brazil started production. On 25 June, the Hibernia Southern Extension, located off the coast of Canada, delivered its first oil. On 24 August, the start-up of the Pazflor development in Angola was announced. Strong ramp-up from US onshore was driven by a large number of new wells and better than expected well performance in Marcellus. The final investment decision was made for In Salah Southern Fields in Algeria and the Schiehallion Redevelopment in the UK. The acquisition of Brigham Exploration Company, which was finalised in December 2011, gives Statoil strategic exposure to US unconventional plays, which are believed to contain a substantial resource base and represent an increasingly important part of future energy supplies. The Peregrino South well in Brazil added significant volumes to the overall Peregrino field resource base. Drilling in the US Gulf of Mexico recommenced after the moratorium. Statoil is the operator there that was awarded most permits for new exploration wells by year-end (four), and it was the first operator to start a new exploration well. New licences in the Kwanza Basin in Angola established Statoil as a leading player in the pre-salt trend, with potential for significant new resources. New acreage was accessed in Canada, Indonesia and Suriname. 3.2.3 The DPI portfolio To enhance our US growth and commitment to shale plays in 2011, we acquired Brigham Exploration Company and increased our acreage in Marcellus and Eagle Ford. Acquisitions In December 2011, we acquired 100% of the outstanding shares of Brigham Exploration Company. The acquisition adds production of approximately 21 mboe per day (as of December) to Statoil's production and gives us access to 1,500 square kilometres (375,000 acres) in the Bakken and Three Forks formations in the Williston Basin. In addition to the Bakken acquisition, we continue to deepen our existing positions. In the liquids-rich Eagle Ford, we have increased our acreage from 67,000 to 87,974 net acres. Similarly, we have deepened our position in Marcellus, with continued acreage acquisitions in the northern dry gas core and south-west liquids-rich area. The total Marcellus acreage has increased from 665,000 net acres to 689,000 net acres. Divestments and other reductions of Statoil's international portfolio On 14 April 2011, Statoil's formation of a joint venture and sale of 40% of the Peregrino field off the coast of Brazil to the Sinochem Group was formally closed. The deal, which was first announced on 21 May 2010, has obtained all required government approvals from the Brazilian and Chinese authorities. Statoil retains 60% ownership and operatorship of the field. With effect from January 2011, Statoil formed a joint venture with PTTEP of Thailand in its oil sands business and, as part of that transaction, sold PTTEP a 40% interest in the leases in Alberta, Canada. Statoil retains 60% ownership and operatorship of the oil sands project. 36 Statoil, Annual report on Form 20-F 2011


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    3.2.4 International exploration Statoil supports its international growth ambitions by accessing material acreage positions early in the exploration phase. Further focus is placed on drilling an increasing number of wells with significant discovery potential. We have exploration licences in North America (Gulf of Mexico, Canada and Alaska), South America and sub-Saharan Africa (Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania), Middle East and North Africa (Libya and Iran), and Europe and Asia (the Faroes, Greenland, the UK, Azerbaijan and Indonesia). We completed 16 wells in 2011. Five were announced as discoveries: the Mukuvo and Lira discoveries in Angola, the Gavea and Peregrino South discovery in Brazil and the Logan discovery in GoM. There were five dry wells, while six wells are currently under evaluation. We plan to drill around 20 wells in 2012. In Angola, Statoil was awarded operatorship in two new blocks and partnership in three new blocks in 2011. These blocks are all in the Angola pre-salt play. Statoil acquired interests in six new licences in Indonesia in 2011. Brigham Together with Chevron and Repsol, we were named successful bidders in Canada for exploration rights on two land parcels in the Flemish Pass Basin, off the coast of Newfoundland and Labrador. Statoil will be the operator of both licences, with a 50% interest. During the second half of 2011, our exploration activities in the Gulf of Mexico returned to levels similar to before the Macondo incident, which Statoil was not involved in, and two Statoil-operated wells have been completed. We entered Suriname in 2011 through a farm-in agreement with Tullow. We have acquired a 30% working interest in block 47, with a commitment to participate in a seismic survey. Our two licences in Egypt - El Dabaa and Ras el-Hekma - expired in 2011, after we had completed the work programme to which we were committed. We drilled one well in the El Dabaa licence, which was dry. Final closure is ongoing. We reduced our share in three of our licences in the Faroes during 2011, selling 49% in License 006, and 50% in License 009 and License 011 to ExxonMobil. We retain a 50% interest and operatorship in each of these licenses. Statoil, Annual report on Form 20-F 2011 37


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    Areas with drilling or significant Statoil-operated seismic activity in 2011 Chukchi Sea Canada UK Azerbaijan Egypt GoM Indonesia Angola Brazil Mozambique 120001_STN068233 Exploration wells: Frontier Growth Near field Major seismic aquisitions The areas where we had significant activity in 2011 are presented below: Exploratory wells in Eurasia (excl. Norway), Americas and Africa 2011 2010 2009 Eurasia (Excl. Norway) 2 1 3 Statoil operated exploratory Partner operated exploratory 2 1 3 Americas 10 8 8 Statoil operated exploratory 7 0 0 Partner operated exploratory 3 8 8 Africa 4 9 17 Statoil operated exploratory 1 3 Partner operated exploratory 3 9 14 Totals 16 18 28 38 Statoil, Annual report on Form 20-F 2011


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    3.2.4.1 North America Statoil has significant activities in the USA, with approximately 300 exploration leases in the Gulf of Mexico (GoM) and 66 in Alaska. We are also an operator and partner in exploration licences off the coast of Newfoundland in Canada. 3.2.4.1.1 Canada Statoil is operator and partner in exploration licences off the coast of Newfoundland (11,138 square kilometres). In 2011, Statoil operated a well on the Fiddlehead prospect in the Jeanne d'Arc Basin and an appraisal well on the Mizzen discovery in the Flemish Pass Basin. The drilling operations were completed successfully and safely. Statoil successfully completed a 1,600 square-kilometre seismic 3D programme on the EL1123 licence, Cupids. We also participated in the Suncor Energy-operated Ballicatters discovery in the Jeanne d'Arc Basin. We have strengthened our offshore position in Canada and our Arctic portfolio through agreements with Chevron Canada and Repsol E&P Canada. The agreements involve three major basins off the coast of Canada: the Flemish Pass and Orphan basins off the coast of Newfoundland, and the Beaufort Sea located in Canada's high north. These new joint ventures over large land blocks in deep water represent important strategic steps for Statoil in the offshore sector in Canada, providing us with access to large potential resources and increasing the Leismer optionality of our exploration portfolio. Statoil Canada, Chevron Canada and Repsol E&P Canada were named successful bidders for exploration rights on two land parcels in the Flemish Pass Basin, off the coasts of Newfoundland and Labrador. Statoil will be the operator of both licences with a 50% interest. Chevron Canada will have a 40% interest and Repsol E&P Canada 10%. This offers promising growth opportunities near the Statoil-operated Mizzen discovery. Statoil intends to continue exploration activities in 2012, with one Statoil-operated well and one partner-operated well. Statoil, Annual report on Form 20-F 2011 39


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    3.2.4.1.2 USA Statoil has significant activities in the USA, with approximately 300 exploration leases in the Gulf of Mexico (GoM) and 66 in Alaska. Drilling activity has returned to a level similar to that before the Macondo incident. 17 Hands (25%) United States Houston Thunder Hawk (25%) San Jacinto (26.67%) Zia (35%) Spiderman (18.3%) Vito (25%) Lorien (30%) Knotty Head (25%) Tahiti (25%) Front Runner (25%) St Malo (21.5%) Q (50%) Caesar/Tonga (23.55%) Julia (50%) Heidelberg (12%) Jack (25%) 120001_STN065268 Big Foot (27.5%) Map as of 31 December 2011 xxx Discoveries xxx Producing fields Office Licences with Statoil interests US Gulf of Mexico Statoil's exploration activities in the GoM have returned to levels similar to before the Macondo incident. Statoil operated the Cobra Paleogene well in the Alaminos Canyon and the Logan Paleogene well in Walker Ridge. The Logan well discovered hydrocarbons, and evaluations are ongoing to assess volumes and commerciality. Statoil participated in the Deep Blue appraisal well (Noble is the operator) and is currently participating in the Kakuna exploration well (Nexen is the operator) and the Heidelberg appraisal well (Anadarko is the operator). Upon completion of the Heidelberg well in early 2012, Statoil intends to commence drilling of the Bioko Paleogene prospect, which has already been awarded a permit. Exploration activity in the Gulf of Mexico in 2012 is expected to include Marcellus shale gas three Statoil-operated exploration wells and participation in approximately four partner-operated wells. In 2011, Statoil secured a cross assignment in the Bioko prospect with ConocoPhillips, and, together we farmed down a participation interest in the Bioko well to Shell. Statoil also succeeded in swapping interests in the Kilchurn/Innsbruck prospects with Marathon. 40 Statoil, Annual report on Form 20-F 2011


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    Alaska Statoil opened an office in Anchorage, Alaska to support operations and activities off the Alaskan coast. Statoil carried out a successful geotechnical programme of high-resolution seismic and soil borings on our operated leases for well location planning and permitting activities. There was extensive stakeholder engagement with local communities and there were no safety or environmental incidents. Statoil continued to participate in gathering extensive baseline science data in the Chukchi Sea and signed an agreement with the National Oceanic and Atmospheric Administration (NOAA) for environmental cooperation in the Arctic. Shale Activity related to US onshore shale is presented below in the International fields - North America section. 3.2.4.2 South America and sub-Saharan Africa We have exploration licences in Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania. 3.2.4.2.1 Brazil Statoil has interests in seven exploration licences in four different basins off the coast of Brazil, and it is the operator for four of the licences. In 2011, we completed two Statoil-operated wells in the Campos Basin, plus three sidetracks in BM-C-47. The second well and third sidetrack were drilled in BM-C-7. All wells and sidetracks proved oil and added significant reserves to the greater Peregrino area. We participated in the Gavea and Pão de Açucar exploration wells in BM- C-33, which were both discoveries. Pão de Açucar was announced in February 2012 as a significant discovery, and its development potential together with Gavea is under evaluation by the partnership. BM-C-33 is located in the Campos Basin. In the Camamu-Almada basin, located outside Salvador, we farmed down 10% of the Petrobras-operated licence BM-CAL-7 and 15% of the Statoil-operated BM-CAL-10 to Gran Tierra. During 2011, we drilled one well in BM-CAL-10, which was dry. Peregrino Statoil, Annual report on Form 20-F 2011 41


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    Statoil also participated in one licence in the Espirito Santo basin, BM-ES-32, where the Indra discovery is located. BM-ES-29 was relinquished in 2011 after we had completed the committed work BM-CAL-7 & 10 programme. The interests in three blocks that we won in the eighth round in the Santos Basin are pending award. Camamu-Almada Basin In 2012, Statoil expects to operate one appraisal well and take part in at Brasilia least two non-operated exploration wells. Espirito-Santo Basin Brazil BM-ES-32 Indra Campos Basin Rio de Janeiro BM-C-7 Gavea BM-C-47 BM-C-33 120001_STN068235 SM-1105, 1109 & 1233* Peregrino Santos Basin Licenses with Statoil interests Office Capital 3.2.4.2.2 Angola Statoil holds interests in blocks 4/05, 15, 15/06, 17, 22, 25, 31, 38, 39 and 40 in Angola. In December 2011, Statoil was awarded licences for the operatorship of and participation in several pre-salt blocks off the coast of Angola. Statoil was awarded the following blocks as operator: Block 38, 6,298 square kilometres, with a 55% share (partners are Sonangol P&P and China Sonangol) Block 39, 7,800 square kilometres, with a 55% share (partners are Sonangol P&P and Total) Statoil was awarded the following blocks as partner: Block 22, 5,180 square kilometres, with a 20% share (Repsol is operator, Sonangol P&P is partner) Block 25, 4,825 square kilometres, with a 20% share (Total is operator, Sonangol P&P and BP is partner) Block 40, 7,588 square kilometres, with a 20% share (Total is operator, Sonangol P&P is partner) Gimboa We are engaged in extensive exploration activity in Angola. A number of wells were drilled in 2011, and more are expected to be drilled in and after 2012. We have interests varying from 5% to 50% in four blocks. In Block 4/05, which is operated by Sonangol and assisted by Statoil, we completed the remaining commitment exploration well in January 2011. In Block 31, which is operated by BP, a total of 31 exploration wells have been drilled. We are working to mature existing discoveries into future developments on the remaining acreage. In Block 15/06, which is operated by ENI, several exploration and appraisal wells have been drilled this year. 42 Statoil, Annual report on Form 20-F 2011


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    In Block 15, work is being initiated to mature existing discoveries as tie-ins to existing infrastructure. In Block 17, appraisal drilling was carried out in 2011 and is expected to continue into 2012. Block 34 was relinquished in 2011 after completion of the committed work programme. 3.2.4.2.3 East Africa Statoil is the operator for two large frontier offshore blocks in the East Africa region - block 2 in Tanzania and area 2 and 5 in Mozambique. The blocks have water depths of between 1,000 and 3,000 metres. Tanzania Block 2 Tanzania (5,500 square kilometres): Statoil is the operator with a 65% share, while ExxonMobil is a partner and has a 35% share. Statoil announced in February 2012 that it had made a significant gas discovery in the Zafarani exploration well. This well fulfills our commitment in the current exploration phase. Following the completion of this well, we intend to drill an exploration well on the Lavani prospect. Tanzania Petroleum Development Corporation (TPDC) has the right to a 10% working interest in case of a development phase. Mozambique Area 2&5 Mozambique (7,800 square kilometres): Statoil is the operator with a 90% interest. The area consists of two blocks under one licence agreement. The state oil company Empresa Nacional de Hidrocarbonetos (ENH) has a 10% interest. We entered the third exploration phase on 1 June 2011 with one well commitment. A 3D survey was started in mid-November 2011. It was completed in early January 2012. 3.2.4.3 Middle East and North Africa We have exploration licences in Libya and Iran. However, the company will not make any future investments in Iran under the present circumstances (see the section International Fields - Middle East and North Africa - Iran). Our two licences in Egypt, El Dabaa and Ras el-Hekma, expired in 2011, after completion of the committed work programme. We drilled one well in the El Dabaa licence, which was dry. Final closing is ongoing. Statoil, Annual report on Form 20-F 2011 43


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    3.2.4.4 Europe and Asia We have exploration licences in the Faroes, Greenland, the UK, Azerbaijan and Indonesia. 3.2.4.4.1 Indonesia Statoil has interests in eight production-sharing contract (PSC) licences in Indonesia. We operate Karama and Halmahera II, and are partners in Kuma, North Ganal, North Makassar, West Papua IV, Obi and Halmahera Kofiau. Philippines North Makassar PSC Malaysia Halmahera II PSC Singapore Kuma PSC Obi PSC Halmahera-Kofiau PSC Indonesia North Ganal PSC Papua West Papua IV PSC New Jakarta Karama PSC Guinea East Timor 120001_STN068236 Licenses with Statoil interests Office We acquired interests in six licences during 2011. The North Ganal and North Makassar PSCs are located in the North Makassar Strait. The West Papua IV, Obi, Halmahera Kofiau and Halmahera II PSCs are located in the eastern part of Indonesia. We are the operator of Halmahera II PSC. Eni is the operator of North Ganal PSC, while Niko Resources is the operator of the remaining licences. We have a commitment to drill one well in the North Makassar PSC and one in the North Ganal PSC. We only have commitments to conduct seismic surveys in the other PSC. One well in the Kuma PSC was drilled in 2011 and the result is still under evaluation. A seismic acquisition programme was started in 2011 and is expected to continue into 2012. Three wells in the Karama PSC and one well in the North Makassar PSC are planned to be drilled during 2012. 44 Statoil, Annual report on Form 20-F 2011

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