avatar Equinor Holding Netherlands B.V. Mining
  • Location: ZUID-HOLLAND 
  • Founded: 2006-03-22
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    Annual Report on Form 20-F

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    Annual Report on Form 20-F Document last updated 24-03-2011 23:02 CET

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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 2010 6 2 Business overview and strategy 9 2.1 Our business 9 2.2 Our history 10 2.3 Statements on competitive position 11 2.4 New organisational structure as from January 2011 12 2.5 Strategy 13 2.5.1 Business environment 13 2.5.2 Industry context 15 2.5.3 A strategy for value creation and growth 16 2.5.4 DPN strategy 18 2.5.5 DPI strategy 19 2.5.6 DPNA strategy 19 2.5.7 MPR strategy 20 2.5.8 TPD strategy 20 2.5.9 EXP strategy 21 3 Operational review 22 3.1 E&P Norway 22 3.1.1 Introduction to E&P Norway 22 3.1.2 E&P Norway key events in 2010 23 3.1.3 The NCS portfolio 24 Core production areas 24 Potential producing areas 24 Portfolio management 25 3.1.4 Exploration on the NCS 25 3.1.5 Oil and gas reserves on the NCS 27 3.1.6 Production on the NCS 27 3.1.7 Development on the NCS 29 Fields under development on the NCS 29 Redevelopments on the NCS 30 3.1.8 Fields in production on the NCS 31 Operations North Sea 31 Operations West 32 Operations North 34 Partner-operated fields on the NCS 35 3.1.9 Decommissioning on the NCS 36 3.2 International E&P 37 3.2.1 Introduction to International E&P 37 3.2.2 International E&P key events in 2010 37 3.2.3 Our International E&P portfolio 38 3.2.4 International exploration activity 39 North America 40 Canada 40 The USA 41 Latin America 42 Brazil 42 Africa 43 Angola 43 East Africa 44 Egypt 44 Middle East and Asia 45 Indonesia 45 3.2.5 International oil and gas reserves 45 3.2.6 International production 46 3.2.7 International fields in development and production 49 North America 50 Canada 50 USA 52 Latin America 53 Brazil 54 Venezuela 54

  • Page 6 Sub-Saharan Africa 55 Angola 55 Nigeria 56 North Africa, Europe, Russia and Caspian 56 Algeria 57 Libya 58 United Kingdom 58 Ireland 58 Azerbaijan 59 Russia 59 The Middle East and Asia 60 Iraq 60 Iran 61 3.3 Natural Gas 62 3.3.1 Introduction to Natural Gas 62 3.3.2 Natural Gas key events in 2010 63 3.3.3 The gas market 63 3.3.4 Gas sales and marketing 64 3.3.5 Norway's gas transport system 66 3.3.6 Kårstø gas processing plant 69 3.3.7 Kollsnes gas processing plant 69 3.3.8 Gas sales agreements 70 3.4 Manufacturing & Marketing 71 3.4.1 Introduction to Manufacturing & Marketing 71 3.4.2 Manufacturing & Marketing key events 2010 71 3.4.3 Oil Sales, Trading and Supply 72 South Riding Point 72 3.4.4 Manufacturing 73 Mongstad 74 Kalundborg 76 Tjeldbergodden 77 Sture 77 3.5 Technology & New Energy 78 3.5.1 Introduction to Technology & New Energy 78 3.5.2 Technology & New Energy key events in 2010 78 3.5.3 Research and development initiatives 79 3.5.4 New energy 80 3.5.5 Technology implementation 81 3.6 Projects & Procurement 83 3.6.1 Introduction to Projects & Procurement 83 3.6.2 Projects & Procurement key events in 2010 83 3.6.3 Project development 83 3.7 Statoil Fuel & Retail 85 3.8 People and the group 86 3.8.1 Employees in Statoil 86 3.8.2 Equal opportunities 87 3.8.3 Unions and representatives 88 3.8.4 Organisational structure 89 3.9 Production volumes and price information 90 3.9.1 Entitlement production 90 3.9.2 Average production cost and sales prices 92 3.10 Proved oil and gas reserves 93 3.10.1 Operational statistics 96 3.10.2 Report of DeGolyer and MacNaughton 98 3.11 Regulation 99 3.11.1 The Norwegian licensing system 100 3.11.2 Gas sales and transportation 101 3.11.3 The EU Gas Directives 102 3.11.4 HSE regulation 102 3.11.5 Taxation of Statoil 103 3.11.6 The Norwegian State's participation 104 3.11.7 Marketing and sale of SDFI oil and gas 105 3.12 Competition 106 3.13 Property, plants and equipment 106 3.14 Related party transactions 106 3.15 Insurance 108 4 Financial analysis and review 109 4.1 Operating and financial review 2010 109 4.1.1 Sales volumes 110 4.1.2 Group profit and loss analysis 112 4.1.3 Group outlook 117 4.1.4 Segment performance and analysis 118 4.1.5 Exploration & Production Norway 120

  • Page 7 Profit and loss analysis 121 4.1.6 International Exploration & Production 123 Profit and loss analysis 124 4.1.7 Natural Gas 126 Profit and loss analysis 127 4.1.8 Manufacturing & Marketing 129 Profit and loss analysis 130 4.1.9 Statoil Fuel & Retail 132 Profit and loss analysis 132 4.1.10 Eliminations and other operations 133 4.1.11 Definitions of reported volumes 133 4.2 Liquidity and capital resources 134 4.2.1 Review of cash flows 134 4.2.2 Selected balance sheet information 137 4.2.3 Financial assets and liabilities 139 4.2.4 Principal contractual obligations 142 4.2.5 Investments 142 4.2.6 Impact of inflation 144 4.2.7 Critical accounting judgements 145 4.2.8 Off balance sheet arrangements 147 4.3 Non-GAAP measures 148 4.3.1 Return on average capital employed (ROACE) 148 4.3.2 Unit of production cost 149 4.3.3 Net debt to capital employed ratio 150 4.4 Accounting Standards (IFRS) 151 5 Risk review 152 5.1 Risk factors 152 5.1.1 Risks related to our business 152 5.1.2 Risks related to increased regulation and regulatory compliance 157 5.1.3 Risks related to ownership by the principal shareholder and its involvement in the SDFI 158 5.2 Risk management 160 5.2.1 Managing financial risk 160 5.2.2 Disclosures about market risk 165 5.3 Legal proceedings 166 6 Shareholder information 167 6.1 Dividend policy 168 6.1.1 Dividends 168 6.2 Equity securities purchased by issuer 170 6.2.1 Statoil's share savings plan 170 6.3 Information and communications 172 6.3.1 Investor contact 172 6.4 Market and market prices 173 6.4.1 Share prices 173 6.4.2 Fees related to Statoil's ADR program 174 6.5 Taxation 176 6.6 Exchange controls and other limitations 179 6.7 Exchange rates 179 6.8 Major shareholders 180 7 Corporate governance 182 7.1 Articles of association 183 7.2 Ethics Code of Conduct 184 7.3 General meeting of shareholders 184 7.4 Nomination committee 186 7.5 Corporate assembly 186 7.6 Board of directors 189 7.6.1 Audit committee 192 Audit committee financial expert 193 7.6.2 Compensation committee 193 7.6.3 HSE and Ethics Committee 194 7.7 Compliance with NYSE listing rules 195 7.8 Management 196 7.9 Compensation paid to governing bodies 199 7.10 Share ownership 202 7.11 Independent auditor 203 7.12 Controls and procedures 205 8 Consolidated financial statements 206 8.1 Notes to the Consolidated Financial Statements 214 8.1.1 Organisation 214 8.1.2 Significant accounting policies 214 8.1.3 Segments 224

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    8.1.4 Assets classified as held for sale 229 8.1.5 Business combinations 230 8.1.6 Asset acquisitions and disposals 230 8.1.7 Capital management 231 8.1.8 Financial risk management 231 8.1.9 Remuneration 236 8.1.10 Other expenses 237 8.1.11 Financial items 238 8.1.12 Income taxes 239 8.1.13 Earnings per share 241 8.1.14 Property, plant and equipment 242 8.1.15 Intangible assets 243 8.1.16 Equity accounted investments 244 8.1.17 Non-current financial assets 244 8.1.18 Inventories 245 8.1.19 Trade and other receivables 246 8.1.20 Current financial investments 246 8.1.21 Cash and cash equivalents 246 8.1.22 Transactions impacting shareholders equity 247 8.1.23 Non-current financial liabilities 248 8.1.24 Pensions and other non-current employee benefits 250 8.1.25 Asset retirement obligations, other provisions and other liabilities 255 8.1.26 Trade and other payables 256 8.1.27 Current financial liabilities 257 8.1.28 Leases 257 8.1.29 Other commitments and contingencies 259 8.1.30 Related parties 260 8.1.31 Financial instruments by category 261 8.1.32 Financial instruments: fair value measurement and sensitivity analysis of market risk 264 8.1.33 Subsequent events 271 8.1.34 Condensed consolidating financial information related to guaranteed debt securities issued by parent company 271 8.1.35 Supplementary oil and gas information (unaudited) 280 8.2 Report of independent registered public accounting firms 291 8.2.1 Report of Independent Registered Public Accounting firm 291 8.2.2 Report of Ernst & Young AS on Statoil's internal control over financial reporting 292 9 Terms and definitions 293 10 Forward looking statements 296 11 Signature page 297 12 Exhibits 298 13 Cross reference to Form 20-F 299

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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, 2010 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 2010 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 until its fiscal year ending December 31, 2011. 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 2010

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    1 Introduction 1.1 Key figures This section is a presentation of our performance in 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. Income Cash flow Return NOK billion NOK billion % 200 120 25 100 20 150 80 15 100 60 10 40 50 5 20 2006 2007 2008 2009 2010 2006 2007 2008 2009 2010 2006 2007 2008 2009 2010 Cash flow used in investing activities Return on average capital employed before adjustments Net income Net operating income Cash flow provided by operating activities Return on average capital employed and one-off effects Oil production/price Gas production/price Proved oil and gas reserves 1,000 bbl per day NOK/bbl bcm per year NOK/scm million boe 1400 600 60 7000 1200 50 6000 4 1000 5000 400 40 800 3 4000 30 600 2 3000 200 20 400 2000 1 200 10 1000 0 2006 2007 2008 2009 2010 2006 2007 2008 2009 2010 2006 2007 2008 2009 2010 Average liquids price Brent Blend Entitlement liquids production Average gas price Natural gas sales Liquids Natural gas Equity liquids production Serious incident frequency Total recordable injury frequency Carbon dioxide emissions million tonnes 3.5 6 18 3.0 5 15 2.5 4 2.0 12 3 1.0 9 2 1.5 6 0.5 1 3 2004 2005 2006 2007 2008 2009 2010 2004 2005 2006 2007 2008 2009 2010 2004 2005 2006 2007 2008 2009 2010 Statoil, Annual report on Form 20-F 2010 3

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    1.2 About the report Statoil's Annual Report on Form 20-F for the year ended 31 December 2010 ("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 2010

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    1.3 Financial highlights 2010 was an important year strategically for Statoil. We demonstrated value creation by executing agreements for the partial sale of our operated assets in Brazil and Canada, sanctioned nine projects and executed a successful IPO of our retail activities. Whilst production volumes were below our expectations in the second part of the year due to high maintenance, specific operational issues and reduced production permits, we continued 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 IFRS as adopted by the European Union (EU). For the year ended 31 December (in NOK billion, unless stated otherwise) 2010 2009 2008 2007 2006 Financial information Total revenues and other income 529.6 465.4 656.0 522.8 521.5 Net operating income 137.2 121.6 198.8 137.2 166.2 Net income 37.6 17.7 43.3 44.6 51.8 Cash flow provided by operating activities 80.8 73.0 102.5 93.9 88.6 Cash flow used in investing activities 76.2 75.4 85.8 75.1 57.2 Interest-bearing debt 111.5 104.1 75.3 50.5 54.8 Net interest-bearing debt 69.7 75.3 46.0 25.5 43.8 Total assets 643.0 562.8 579.2 483.1 458.8 Share Capital 8.0 8.0 8.0 8.0 8.0 Non-controlling interest (Minority Interest) 6.9 1.8 2.0 1.8 1.6 Total equity and minority interest 226.4 200.1 216.1 179.1 169.4 Net debt to capital employed 24.6 % 27.3 % 17.5 % 12.4 % 20.5 % Return on average capital employed after tax 15.4 % 10.5 % 21.0 % 17.7 % 22.6 % Operational information Equity oil and gas production (mboe/day) 1,888 1,962 1,925 1,839 1,780 Proved oil and gas reserves (mmboe) 5,325 5,408 5,584 6,010 6,101 Reserve replacement ratio (three-year average) 64% 64% 60% 81% 76% Production cost (NOK / boe equity volumes) 38.6 35.3 34.6 41.4 27.3 Share information Earnings per share for income attributable to equity holders of company basic and diluted 11.94 5.75 13.58 13.80 15.82 Share price at Oslo Stock Exchange on 31 December 138.60 144.80 113.90 169.00 165.25 Dividend paid per share NOK (1) 6.25 6.00 7.25 8.50 9.12 Dividend paid per share USD (2) 1.07 1.04 1.26 1.47 1.58 Weighted average number of ordinary shares outstanding 3,182,574,787 3,183,873,643 3,185,953,538 3,195,866,843 3,230,849,707 (1) See Shareholder information section for a description of how dividends are determined and information on share repurchases. The board of directors will propose the 2010 dividend for approval at the Annual General Meeting scheduled for 19 May 2011. (2) USD figure presented using the Central Bank of Norway 2010 year-end rate for Norwegian kroner, which was USD 1.00 = 5.86 NOK. The board of directors will propose the 2010 dividend for approval at the Annual General Meeting scheduled for 19 May 2011. Statoil, Annual report on Form 20-F 2010 5

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    1.4 A glance at 2010 Production volumes fell below expectations in the second half of the year due to high maintenance, specific operational issues and reduced production permits. Nevertheless, Statoil continued to deliver strong financial results and cash flows in 2010. January We signed an agreement with ConocoPhillips to take over a 25% interest in 50 licences in the Chukchi Sea near Alaska. Statoil was awarded shares in eight production licences on the Norwegian Continental Shelf (NCS), comprising six North Sea licences and two Norwegian Sea licences. We will be operator of six of the licences. In the third licence round for offshore wind parks in the UK, the Forewind consortium, of which Statoil is a member, was awarded the rights to develop Dogger Bank, which was the largest zone in the round. Lukoil and Statoil signed a contract relating to the West Qurna 2 field in Iraq. First oil is scheduled for the end of 2012 and full production is expected for a period of 13 years from 2017. February The Tyrihans field was awarded the prestigious Five Star Award at the Deep Offshore Technology conference in Houston, for being one of the five best offshore developments in the world during 2009. March We enhanced our shale gas position in the USA by signing a contract with Chesapeake that extended our net share of 2,400 square kilometres by a further 236 square kilometres in the Marcellus formation. Our two Peregrino oil platforms were towed into position off the coast of Brazil. First oil is expected towards the end of the first quarter 2011. We extended our portfolio in the US sector of the Gulf of Mexico. Statoil was the highest bidder on 21 licences. We signed an investment contract worth USD 6 billion with ACG partners relating to the development of the Chirag oil project in the Azeri sector of the Caspian Sea. Low-pressure production methods have increased oil recovery from the Oseberg field in the North Sea. We increased our share in the St. Malo development in the Gulf of Mexico to 21.5% by exercising our first option in connection with the sale of Devon's share of the development. We entered transport contracts with New Jersey and New York City for the transport and delivery of natural gas produced in the northern part of the Marcellus shale gas region in Pennsylvania (PA). April Norway and Russia reached agreement regarding the Barents Sea delimitation line, dividing the 175,000 square kilometre area into two more or less equal parts. It is believed that there could be considerable deposits of oil and gas in the area. Statoil launched a new technology plan designed to reduce CO2 emissions from oil sand production, with the intention of achieving reductions of more than 40% by 2025. Njord licence partners approved the development of the Njord North West flank, a development that will increase the total recoverable reserves and extend Njord's lifetime by up to two years. We announced that we had found oil and gas at the Fossekall prospect north of the Norne field in the Norwegian Sea. The Macondo accident in the Gulf of Mexico caused the loss of 11 lives and an extensive oil spill. US authorities imposed restrictions following the accident, leading to the temporary closure of two of our drilling operations in the area. May We signed a partnership agreement in which we sell a 40% stake in the Peregrino field in Brazil to the Sinochem Group. We will retain a 60% share and remain as operator on the field. The divestment is a natural step in our ongoing efforts to optimise our portfolio. 6 Statoil, Annual report on Form 20-F 2010

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    Statoil and EGL announced the transfer of a combined share of 15% in the Trans Adriatic Pipeline Project to E.ON Ruhrgas. The Trans Adriatic Pipeline will provide a link between the existing and planned pipeline systems for natural gas in South West Europe and the pipeline systems in West Europe. We signed an agreement for the transport of gas through a pipeline from the northern part of the Marcellus shale gas region in Pennsylvania to Niagara on the US-Canadian border. The agreement secures us access to a central, inter-state pipeline system. On 19 May a situation arose involving a change in pressure and the loss of drilling fluid in well C-06 on the Gullfaks C platform in the North Sea. We demobilised 89 employees to the Gullfaks A platform by helicopter. Our investigation and the report of the Petroleum Safety Authority Norway concluded that the planning of the drilling and completion operations in the well had been carried out with deficiencies in planning and risk assessment. Following this incident, we implemented a number of measures. June We signed a letter of intent with Sinochem Group of China to promote collaboration and the long-term share of experience between the two companies. The letter was signed after the Peregrino partnership agreement in which Sinochem signed an agreement to acquire a 40% share in Statoil's oilfield off the coast of Brazil. The first floating platform to be supplied with electricity from the mainland, Gjøa, was towed to its location on the west coast of Norway. The solution will reduce CO2 emissions by 210,000 tonnes of carbon dioxide per year. The plan for the development and operation of the Gudrun field in the North Sea was approved by the Norwegian parliament in June. We expect that the traditional steel jacket will be completed and installed in the summer of 2011 before well drilling commences in October 2011. Production start-up is planned for the first quarter of 2014. Work commenced on the Sheringham Shoal offshore wind farm in the UK, jointly owned by Statoil and Statkraft. The wind farm, scheduled to come on stream in 2011, will supply an estimated 200,000 UK households with electricity. Statoil and Poweo of France signed a 20-year agreement relating to the supply of natural gas to Poweo's planned 400 MW combined cycle gas turbine (CCGT) power station in Toul, France. The plan is for deliveries to commence on 1 October 2012. July We signed frame agreements for insulation, scaffolding and surface treatment on platforms, production ships and land facilities in Norway and Denmark. The contracts were worth a total of NOK 12 billion, including options. August We published details of our fast track developments that are aimed to make small fields more profitable and help maximise the potential of the NCS. The first projects are PanPandora, Katla, Vigdis Nordøst and Gygrid. We announced the discovery of oil and gas east of the Gudrun field. We announced a new organisational structure effective from 1 January 2011. The rationale behind the new organisation is to simplify our way of working by having fewer internal interfaces and better defined responsibilities, an increased global perspective and improved local presence close to important investments. Oil production commenced from the subsea field Morvin, tied back to Åsgard, in the North Sea. The field has a strategic significance for the further development and operation of our North Sea activity. September We signed an agreement with Nautical Petroleum, enhancing our offshore heavy oil portfolio. The deal involved the acquisition of 20.67% of Nautical Petroleum's share of the UK offshore licence P335 that includes the Mariner field. October The company's energy and retail business became a standalone company Statoil Fuel & Retail ASA (SFR), which was listed on the Oslo stock exchange on 22 October. Private and institutional investors showed considerable interest in shares in the new company. Statoil ASA retains a 54% ownership stake in SFR. The state-run Mexican oil company Petróleos Mexicanos (Pemex) and Statoil are collaborating to reduce gas flaring on the Tres Hermanos oil field in Mexico. It was announced in October that the project is registered under the UN's Clean Development Mechanism (CDM). We carried out an extensive oil spill protection exercise on Sørøya in West Finnmark, in northern Norway, together with Eni and Lundin, NOFO (Norsk oljevernforening for operatørselskap) and a local task force. The exercise confirmed that the emergency response preparations function as planned. We submitted our development plan for the Valemon field to the Ministry of Petroleum and Energy. The plan involves a new, unmanned platform in the North Sea planned to come on stream in 2014. Statoil, Annual report on Form 20-F 2010 7

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    We approved development of the major Jack/St. Malo fields in the deepwater Gulf of Mexico together with operator Chevron and our other partners. Start- up is expected in 2014. The seventh oil discovery in block 15/06 off the coast of Angola was announced, completing our minimum commitment to this area 18 months ahead of schedule. The well was tested for a rate of more than 6,000 barrels of light oil per day. We announced that we were boosting our land-based projects in the USA by acquiring a 67,000 net acre share of the Eagle Ford shale gas formation. Statoil and Talisman have formed a 50/50 joint venture with the aim of developing the resources in Eagle Ford. November We announced the formation of a partnership including the sale of a 40% stake in the company's oil sands project in Alberta, Canada, to Thai company PTT Exploration and Production. The contract, reducing our 100% stake to 60%, follows on from other transactions completed in 2010 designed to optimise the risk and strategy profile of our global portfolio. We submitted our application for new exploration licences in the Barents Sea and the Norwegian Sea in the 21st licensing round on the Norwegian continental shelf. It is expected that Norwegian authorities will allocate acreage here during the spring of 2011. Production on the Gjøa oil and gas field came on stream on 7 November. This development opens up for more activity in the far north of the North Sea. We announced that we would further concentrate our efforts to develop offshore wind turbines as part of our renewable energy strategy in the light of the rapid international developments within the offshore wind sector. December We signed a technology development agreement with Siemens with whom we will collaborate on wind power, subsea technology, electro technology and boosting energy efficiency. The Gas Advocacy Forum, a group of major gas players in Europe of which Statoil is a member, submitted a report to the EU Commission stating that Europe can achieve its target of an 80% reduction in carbon emissions by 2050 if natural gas is allowed to play a substantial role in the energy mix. Production started up on the Vega gas and condensate field south west of the Sogne coast in Norway. 8 Statoil, Annual report on Form 20-F 2010

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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 is present in 42 countries worldwide. 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 * Fixed assets Upstream assets Downstream Non-OECD Free float 18% 33% Norwegian continental shelf 48% OECD Norwegian State International 34% 67% *As per 31 December 2010 Distribution of shareholders Entitlement oil and gas production outside Norway accounted for 19.5% of our total production, which averaged 1,705 mmboe per day in 2010. 1.3% As of 31 December 2010, we had proved reserves of 2,124 mmbbl of oil and 509 bcm (equivalent to 9.1% 18.0 tcf) of natural gas, corresponding to aggregate proved reserves of 5,325 mmboe. 8.1% Norwegian state Norwegian 5.1% private owners We are present in 42 countries. As of 31 December 2010, there were approximately 30,400 UK employees in the Statoil group. Of this total, 10,400 were employees of the Statoil Fuel & Retail 9.4% Rest of Europe group, in which we held a 54% majority ownership interest as of 31 December 2010. US Rest of World We are among the world's largest net sellers of crude oil and condensate, and we are the second 67% largest supplier of natural gas to the European market. We also have substantial processing and refining activities. We are contributing to the development of new energy resources, have ongoing activities in the fields of wind power and biofuels and are at the forefront in relation to the implementation of technologies for carbon capture and storage (CCS). Oil and gas* 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. Gas Oil *Entitlement production Statoil, Annual report on Form 20-F 2010 9

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    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 geographical reach of Statoil's business. SwedenFinland Russia Norway Estonia Canada Denmark Latvia United Kingdom Lithuania Ireland Poland Netherlands Germany Kazakhstan Belgium Georgia United States Azerbaijan Turkey Turkmenistan China Iraq Iran Algeria The Bahamas Libya Egypt Saudi Mexico Arabia India Cuba United Arab Emirates Nigeria Venezuela Singapore Indonesia Tanzania Brazil Angola Mozambique Australia 110001_STN049007 See the section Business overview and strategy - New organisational structure as from January 2011, for the organisational structure of our business areas and staff functions up to and including 31 December 2010 and as from 1 January 2011. 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 a.s 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. The commencement of our operations focused primarily on exploration for and the production and development of oil and gas on the Norwegian continental shelf (NCS) as a partner. 10 Statoil, Annual report on Form 20-F 2010

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    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. In the 1980s, we saw substantial growth through the development of major 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 we 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, for example through 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, partially divesting and reducing our interest in the business relating to service stations. Although petroleum-related activities on the NCS and internationally have been the main part of our business, we increasingly participate in projects focusing on other forms of energy, such as wind power and CCS (carbon capture and storage), in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change. 2.3 Statements on competitive position Information about Statoil's competitive position relies on a range of sources, including analysts' 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 analysts' 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 present information based on other sources accurately, but we have not independently verified such information. Statoil, Annual report on Form 20-F 2010 11

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    2.4 New organisational structure as from January 2011 A new corporate structure was implemented with effect from 1 January 2011. The figure below provides an overview of the organisational structure of our business areas and staff functions up to and including 31 December 2010. Chief Executive Officer H e lg e L u n d Chief Financial Corporate Staffs Officer & Services Eldar Sœtre Helga Nes Exploration & International Natural Gas Manufacturing & Projects Technology & Production Exploration & Marketing New Energy Norway Production Øystein Michelsen Peter Mellbye Rune Bjørnson Jon Arnt Jacobsen Gunnar Myrebø Margareth Øvrum A new corporate structure was implemented with effect from 1 January 2011 (see the figure and descriptions below). The changes were made in order to simplify the organisation and clarify internal accountability. The following Strategy section reflects the organisation as from 1 January 2011. However, the rest of the presentation in this annual report on Form 20-F 2010 is based on the organisation as of 31 December 2010. 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 business areas Our Development and Production business areas encompass our worldwide upstream activities. Development and Production Norway (DPN) comprises our upstream activities on the Norwegian continental shelf (NCS), Development and Production North America (DPNA) comprises our upstream activities in North America, and Development and Production International (DPI) comprises our worldwide upstream activities that are not included in the DPN and DPNA business areas. Our upstream activities were previously included in the Exploration & Production Norway and International Exploration & Production business areas. Over the past few years, we have made large investments in North America. Establishing DPNA as a separate business area reflects the importance of the region to our business. 12 Statoil, Annual report on Form 20-F 2010

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    Marketing, Processing and Renewable Energy The activities previously included in Natural Gas, Manufacturing & Marketing and the New Energy unit of Technology & New Energy comprise Marketing, Processing and Renewable Energy (MPR). We expect that combining these activities will create synergies in operating our onshore plants and marketing and trading activities. Technology, Projects and Drilling The new business area Technology, Projects and Drilling (TPD) combines the activities previously included in the Technology unit of Technology & New Energy, the Projects & Procurement business area and the Drilling and Well unit of Exploration & Production Norway. Combining these activities simplifies work processes and significantly reduces the numbers of internal interfaces. Exploration Exploration is a new business area. Our exploration activities were previously part of Exploration & Production Norway and International Exploration & Production. We expect that a single global exploration business area will strengthen the deployment of resources to priority activities across the portfolio. Global Strategy and Business Development Global Strategy and Business Development (GSB) is also a new business area. GSB is responsible for setting the corporate strategy, business development, and merger and acquisition activities (M&A). 2.5 Strategy Statoil's long-term strategy builds on the company's vision: "Crossing Energy Frontiers". It continues the current strategic direction of creating shareholder value as an upstream-oriented and technology-based energy company. Our strategy of long-term value creation starts with our short-term deliveries in relation to operations and HSE. As we work towards our ambition of realising the full value potential of the Norwegian continental shelf (NCS), we are simultaneously developing international platforms for long-term growth and gradually building a position in renewable energy production. We operate in an industry that is becoming more complex. Access to resources is also becoming more challenging. In future, the pace of change will increase and the importance of quality in execution will be even higher - making safe and efficient operations more important than ever. 2.5.1 Business environment The recovery of the world economy continued through 2010, mainly driven by strong growth in the emerging economies. This led to a robust recovery in energy demand in most regions. Energy prices, which fell sharply during the second half of 2008, consolidated and partly recovered in 2009. With the exception of US natural gas prices, energy prices strengthened further in 2010. Macroeconomic outlook In 2008-2009, the world economy experienced its most severe recession since the Great Depression of the 1930s. However, both emerging economies and the hard-hit advanced economies started to recover during the second half of 2009. The recovery strengthened further during the first half of 2010, driven by restocking, continued policy stimuli and a strong pick-up in private demand in most regions. Growing by more than 10% in the first part of the year, the Chinese economy provided an important stimulus to the recovery of other regions. India, other emerging economies and Latin America have also witnessed strong economic growth. The pace of growth abated somewhat, however, during the second half of 2010, in both some advanced and emerging economies. In China a deliberate policy tightening to avoid overheating of the economy has ultimately led to somewhat lower growth, whereas private sector demand in several advanced countries only grew moderately. This reflects the process of deleveraging that both indebted household and the banking sectors in the USA and Europe are still undergoing. The sovereign debt crises in Europe and the volatility of the financial markets have added to the restrictions on bank lending, especially in Europe. After contracting by 1.9% in 2009, world GDP grew by about 3.6% in 2010. Statoil, Annual report on Form 20-F 2010 13

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    Historic oil and gas prices* The outlook for the world economy over the next few years will continue to be influenced by the adjustment processes within the various economies (internal rebalancing) and the re-adjustment of USD/bbl USD/mmBTU 140 18 unbalanced trade and capital flows between debt-ridden advanced economies and fast-growing 120 16 export-driven economies (external rebalancing). At the beginning of 2011, most advanced economies 14 are still facing major internal adjustment challenges. 100 12 80 10 60 8 These economies need to strengthen households' balance sheets, stabilise public debt, and repair and 6 reform their financial sectors. Governments' large budget deficits mean that fiscal policy will have to 40 4 be significantly tightened over the medium-term, which will partially limit the pace of economic 20 2 growth. By contrast, China and several other emerging economies face the challenge of restructuring 2004 2005 2006 2007 2008 2009 2010 2011 their economies from being reliant on export-led growth to becoming more consumption-oriented. European natural gas prices (NBP)(USD/mmBTU) US natural gas prices (NBP)(USD/mmBTU) Crude oil prices, Dated Brent (USD/bbl) However, China appears to be determined to move only cautiously in this direction, and the process of *As of 1 March 2010. Sources: Platts revaluation of the Chinese renminbi and other measures that could weaken its export machine will most likely be gradual. This cautiousness will slow the external rebalancing process and dampen the much needed stimulus to the advanced economies, and it could also spur rising protectionist sentiment in the USA and other regions. Ultimately, the development of the world economy will be strongly dependent on the domestic policies of key countries and the degree of international policy cooperation. Consequently, the medium-term outlook is still characterised by moderate economic growth and major uncertainty, with considerable downside risk. Energy markets and price developments After falling by 1.1% in 2009, global energy consumption recovered strongly in 2010 and, based on preliminary statistics, it has grown by more than 4-5%. Demand for oil, natural gas and coal increased, primarily in Asia and other emerging economies. Despite the robust demand, ready and available supplies prevented prices in most markets from rising significantly through 2010. Crude oil prices, which plunged during the recession, started to recover in the spring of 2009 and ended the year in the USD 75-80/bbl price range. Given ample oil stocks and spare Opec production capacity of more than 5 mbd, the market was mainly driven by expectations of a sustained macroeconomic recovery and a gradual tightening of the oil market over the medium-term. Costs of developing new oil production in high-cost areas were seen as a key benchmark in price determination. These underlying market dynamics prevailed throughout 2010. Crude oil prices fluctuated significantly during the year driven by changing perceptions about the sustainability of the world economic recovery. Prices strengthened considerably during the fourth quarter, partly supported by cold weather in the Northern hemisphere and ended the year in the USD 90-95/bbl range. US monetary policy, financial players' perceptions, portfolio optimisation and market positions continue to be important drivers for price determination. The average price of dated Brent in 2010 was USD 79.5/bbl, up from USD 61.6/bbl in 2009. Global oil demand, which fell by 1.1 mbd in 2009, recovered sharply during 2010, with a gain of about 2.7 mbd relative to 2009 - the second strongest annual growth in demand in the last 30 years. China accounted for almost 0.9 mbd of the total, but other emerging economies also contributed to the growth in global oil demand. North American oil demand increased for the first time since 2005. At the same time, non-Opec production and Opec NGL/condensate production continued to expand strongly, by 1.1mbd and 0.5 mbd, respectively, while Opec crude oil production edged up modestly. The Atlantic Basin product markets, which were severely hit by the economic recession, also partly recovered during 2010. Total products demand increased by 0.45 mbd in the USA, with the strongest growth in demand being for distillates/diesel and various products for broad industrial and household use. In the European markets, product demand, which fell by 0.9 mbd in 2009, consolidated in 2010, with transportation fuels seeing modest growth. However, these gains were offset by further contraction in demand for fuel oil. Global distillate and naphtha demand, driven by the Asian markets, accounted for the largest proportion of the growth in total products demand. With product stocks in the Atlantic Basin markets still at comfortable levels and with a high level of spare refining capacity, product price differentials (margins) generally remained relatively low, especially gasoline margins. In the US market, a large part of the growth in demand was met by non-refinery liquids and ethanol. European distillate margins improved moderately during 2010 from depressed levels in 2009. The 2008-2009 recession and the sharp increase in both US unconventional gas production and global LNG production all contributed to a significant over- supply of natural gas and sharply falling prices in all the main regional markets. However, prices consolidated around USD 5/MMBtu on the prospect of more balanced markets during autumn 2009. Despite a strong demand recovery, the Atlantic natural gas markets remained well supplied during 2010. In the first half of 2010, natural gas prices in Europe and North America fluctuated around the levels seen in 2009. The two markets moved in different directions throughout the year, however, reflecting differences in their competitive nature and supply pressures. In North America, natural gas demand, driven by the recovery of the economy and a strong weather effect, increased by more than 3.0%. However, resilient domestic gas production kept the market over-supplied throughout the year, pushing stock levels to record highs and putting downward pressure on natural gas prices. During most of the year, prices have fluctuated in the USD 3.50-5.00/MMBtu range. The expansion of unconventional gas, especially shale gas, continued at a fast pace. The trends suggest that North America will remain self-sufficient and basically disconnected from the other regional gas markets. 14 Statoil, Annual report on Form 20-F 2010

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    In Europe, by contrast, the combination of strong but volatile demand growth and restrained gas supplies gradually restored the balance in the market and put spot prices on a rising trend during 2010. After fluctuating around USD 4.50/MMBtu during spring, spot prices rose through the rest of the year, reaching USD 9.00/MMBtu by the end of the year. Demand growth, which was very strong during the first half of the year, softened during the summer months, but, driven by extremely cold weather, recovered in the last quarter. Rising coal prices, mainly driven by strong demand from Asia and especially China, have sustained natural gas's competitiveness. In the last part of the year, however, natural gas faced stronger competition from nuclear power and renewable energy in Germany and several other markets. Total European gas demand increased by about 6% from 2009. LNG imports from the Middle East and Africa continued to grow during 2010, but the moderation and flexibility of Russian exports served to balance the market and ensured a moderate tightening during the year. The strong demand from the Asian LNG markets has also played an important part in the rebalancing of the European gas market. European electricity prices fluctuated around EUR 50-60/MWh during 2005-08, reached a peak of almost EUR 100/MWh immediately after the start of the economic crisis, but fell to a low of EUR 30-40/MWh in the middle of the recession. After falling by 6% in 2009, European power demand is estimated to have grown by about 4% in the first half of 2010. This drove electricity prices gradually upwards to around EUR 50/MWh. Prices in the European carbon dioxide market, the EU Emissions Trading Scheme, are basically driven by the supply of allowances derived from the member countries' emission targets, and the demand for emission allowances, which is strongly influenced by activity levels in the industry and power sectors. Carbon prices tend to follow the same pattern as European energy prices. After recovering in the first half quarter of 2009, carbon prices fluctuated around EUR 13-15/tonne over the following 12 months. Since spring 2010, prices have fluctuated around the EUR 15/tonne level. The UN climate change negotiations had limited effect on the short to medium-term emissions trading market last year. Energy outlook The outlook for all energy markets over the next few years is fundamentally linked to the uncertain prospects for the world economy. The pace of growth in China and other fast-growing emerging economies is especially important in this context. Global growth in oil demand, which was very strong in 2010, is expected to be moderate over the next few years. On the supply side growth in non-Opec production and Opec NGL/condensate production is also expected to slow. In sum, these prospects mean that Opec's spare production capacity will gradually be reduced. Opec's crude production and marketing policies over the medium term will be affected by a potentially strong expansion of Iraqi oil production. However, a challenging political environment and infrastructure bottlenecks in Iraq indicate that the build-up of new production capacity will proceed relatively slowly. Since oil price formation is also influenced by financial players, the uncertain outlook for financial markets, geopolitical developments and the US dollar will also play a role. The short-term outlook for the Atlantic Basin products markets is driven by modest demand growth and the potential for product imports from several export refineries in the Middle East and Far East. The outlook for sustained overcapacity in refining in the Atlantic Basin may well lead to capacity closures in the mature OECD markets over the next few years. 2.5.2 Industry context General market conditions for the oil and gas industry improved throughout 2010. However, the industry is still challenged by limited access to new resources and increased international competition. In 2009, the oil and gas industry's margins were hit as a result of the financial turmoil. The lower oil and gas prices were accompanied by a moderate fall in supplier market costs. Companies reacted to the margin squeeze by adjusting capital expenditure plans, re-evaluating dividend policies and focusing strongly on cost control. This resulted in reduced demand in the supplier market and a further fall in supplier costs. Margins improved throughout 2010, as energy prices rebounded and the supplier markets in general experienced overcapacity and continued restrained prices (see chart). Several companies are following through with their announced portfolio restructuring programmes, however. Supplier market cost indicies Looking at longer-term trends, certain strategic challenges have affected the direction of the industry. A large part of the world's remaining conventional resources are held by countries with limited access for Price Index, 2000 = 100 500 international oil companies (IOCs), thus restricting IOCs access to new resources. In addition, the competition for international resources is intensifying, particularly with national oil companies 400 becoming more active in the international hunt for resources. To replace produced reserves and grow, IOCs have therefore gradually been pushed into looking for hydrocarbon resources in more remote 300 areas, in deeper waters and in more technologically challenging environments. As a result, 200 unconventional and deepwater hydrocarbons play an increasingly important part in the global production mix. This trend is likely to continue. 100 Unconventional gas in general, and shale gas in particular, has attracted much interest from different 2000 2002 2004 2006 2008 2010 players over the last few years. As US shale gas represents a relatively accessible resource with low NCS rig Engineering Sources: High-end steel Subsea ODS Petrodata, Statoil break-even prices, it is an attractive proposition for the IOCs. All the major IOCs have therefore endeavoured to position themselves in this business area. These resources have become a game changer for the US hydrocarbon supply structure; due to the increase in unconventional gas Statoil, Annual report on Form 20-F 2010 15

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    production. The USA is currently almost self-sufficient as regards gas and the expected volume of natural gas imports has dropped significantly. This has contributed to the depressed US gas prices, particularly compared with oil, and there has recently been increased interest in the industry in more liquid rich shale plays. In April 2010, the oil industry was impacted by one of the most serious accidents in its history, when the Deepwater Horizon rig exploded and caught fire in the US Gulf of Mexico, killing 11 people and causing a massive oil spill. The accident is expected to redefine important parts of the US offshore industry's technical requirements and industry practices, and similar repercussions are expected for global deepwater players. The US Department of the Interior's Bureau of Ocean Energy Management Regulation and Enforcement has already implemented significant new measures to address safety and operational issues, and companies and operators will face stricter operational requirements. Refining margins have improved somewhat over the last year, but there is still some overcapacity in the refining market. In October, Statoil formed a stand-alone company, Statoil Fuel & Retail ASA, comprising its energy and retail business, which successfully completed an initial public offering. This transaction is in line with the trend seen in recent years of large IOCs reducing their downstream positions. Increased concern about energy security and climate change has continued to fortify policy and long-term market drivers for commercial growth in renewables. While most renewable energy sources are currently more costly than fossil fuels, the competitive landscape is expected to shift over time as production costs for renewable energy decline and the cost of carbon emissions is increasingly reflected in power and fuel prices. Significant amounts of public and private funding are currently going into research, development and expansion of new technologies in order to make renewables and carbon capture and storage (CCS) more competitive. Wind power is one of the largest areas in renewable energy, with prospects of increasing production over time. Offshore wind, where Statoil has taken on several projects, is expected to take a significant share of the total wind market if several large countries are to achieve their renewable energy goals. 2.5.3 A strategy for value creation and growth Statoil's strategy is to profitably grow its long-term oil and gas production while gradually building a position in renewable energy production. Overall strategic direction Our overall long-term strategy as an upstream-oriented, technology-driven company is based on the following key components: Deliver on operations and HSE. Utilise our technology and management capabilities to capture the full potential of our positions on the Norwegian continental shelf (NCS). Deliver profitable international growth in the short and medium-term from existing positions, while creating new opportunities for long-term value creation. Use exploration as an important growth tool to secure long-term production capacity. Develop profitable midstream and downstream positions in support of our upstream activities. Minimise carbon emissions from, and the general environmental impact of, our upstream and midstream activities. Pursue selected business opportunities for renewable energy production and carbon capture and storage (CCS). Apply technology and innovate in order to create value and accelerate asset developments. Utilise organisational capabilities as a global energy company. Our growth strategy We are addressing the challenges of growing our production, reserves and resource base through efficiency improvements resulting from simplification and renewal of our organisation, and by continually reviewing our portfolio in light of global business opportunities. The Global Strategy and Business Development (GSB) business area has been created to bring together corporate strategy, business development and merger and acquisition activities in order to actively drive Statoil's corporate development. GSB will set a strong strategic direction and identify, develop and deliver opportunities for global growth for Statoil. This will be achieved through close collaboration within the group across geographical regions and business areas. As noted at the February 2011 Capital Market Update, Statoil is currently undertaking a strategy review with the aim of securing continued growth and value creation. Our growth strategy is based on exploration, focused business development, strategic acquisitions and divestments, and building long-term partnerships. Our aim is to increase the scale of our operations in terms of production, reserves and technological and geographical breadth, and to bring our resource base closer to production. We will continue to deliver profitable projects in a range of complex technical and stakeholder environments. Our short-term priorities are to conduct safe operations and to deliver production growth in line with our guidelines. 16 Statoil, Annual report on Form 20-F 2010

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    Safe and efficient operations are essential to our business. In order to prevent harm to people and the environment, all activities in Statoil are carried out with a strong focus on HSE. We seek to achieve this through long-term and systematic application of best practices across our activities. We are improving efficiency, for example on the NCS through the "fast-track" and "integrated operations" (IO) initiatives, as we continue to maximise the full value potential of our positions. By implementing the Statoil 2011 organisation, we aim to put ourselves in an even better position to become a global energy player. Combining company- wide activities in exploration (EXP), marketing, processing and renewables (MPR), technology, projects and drilling (TPD), and global strategy and business development (GSB) into individual business areas, and focusing development and production activity in three geographical business areas (DPN, DPNA, DPI), will allow us to systematically support the globalisation of Statoil, to better support business priorities, and to reinforce leadership and clarify accountability. Utilising our capabilities Gaining access to sufficient petroleum resources is increasingly challenging. We are seeking new opportunities in demanding areas that require the full use of our legacy of expertise in technology and management. We have experience and expertise that could give us a competitive advantage in the following four growth platforms: Deep water: we are active in six of the most interesting deepwater basins in the world - the Gulf of Mexico, Brazil, Angola, Nigeria, Norway and Indonesia. Harsh environments: we see the resource potential of the Arctic as particularly interesting, although it is a region that is not expected to deliver substantial results until the medium to longer term due to technical and environmental challenges. Heavy oil: we have positions in Norway, Canada, Brazil, Venezuela and the United Kingdom. Gas value chain: we are active in finding and delivering gas in many countries and have an extensive portfolio that includes conventional European gas, unconventional gas, e.g. US shale gas, and liquefied natural gas (LNG) Responding to the climate challenge Our ambition is to be an industry leader in carbon efficiency by having a low climate impact in all of the activities in which we are engaged. We aim to create value by seeking competitive low-carbon and energy-efficient solutions in all areas of our business. Responding effectively to the climate challenge as it impacts our activities will give us a competitive advantage in future. We are a leading industry player in CCS. Maximising value creation from upstream access opportunities We will use exploration as an important growth tool to secure long-term growth of reserves, production and value. This is consistent with maximising the long-term value of the NCS and with utilising our core expertise to build, mature and deliver profitable growth outside Norway. We will continue to optimise our exploration portfolio, balancing frontier, growth and infrastructure-led exploration. We will continue selective business development activities to optimise the portfolio. Maximising long-term value creation on the NCS We are maintaining our position as the main industry player on the NCS. We are working continuously to improve our HSE performance as well as our cost- efficiency and operational efficiency, and we are implementing measures for improved hydrocarbon recovery (IHR). We see a structural shift in our non- sanctioned project portfolio from a few large, complex projects to a high number of mainly smaller projects or sub-sea tie-backs. This requires a high level of standardised technical concepts as well as simplified development processes. Building and delivering profitable international growth Our strategy is to deliver profitable international growth in the short and medium term from existing positions, while creating new opportunities for long- term value creation. We will utilise our core expertise in areas such as deep water, harsh environments, heavy oil and the gas value chain to pursue attractive business opportunities around the world. In the longer term, we anticipate that Statoil's future growth will mainly take place outside the NCS and that our international asset base will enable us to grow and become more diversified, both in geographical terms and in terms of types of production. Our short to medium-term focus is on delivering and maturing a high-quality project portfolio on time and within budget. Developing profitable midstream and downstream positions Statoil's strategy is to develop projects and to produce oil and gas where we see a potential for attractive returns and added value. We have a strong upstream focus in terms of our total value and asset base, complemented by a midstream and downstream portfolio related to marketing, trading, refining and storage of oil and gas products. We endeavour to achieve synergies between upstream and midstream positions. Creating a platform for renewable energy production and CCS Our strategy for renewable energy production and carbon management is to utilise existing core capabilities and current business positions to create profitable positions in renewable energy, prioritising offshore wind projects while keeping track of opportunities in other areas through technology and selective investments. We are building a portfolio of wind farms, with the focus on offshore sites, and we are developing technology for large-scale deepwater offshore wind power generation. In this context, our participation in the Sheringham Shoal UK wind farm and the Forewind consortium on the Dogger Bank development are important projects for us. Off the south-west coast of Norway, we are piloting a prototype of the world's first full-scale floating wind turbine, Hywind, which is designed to be placed at water depths of between 120 and 700 metres. Statoil, Annual report on Form 20-F 2010 17

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    In addition, we are reducing emissions of greenhouse gases from fossil energy production through CCS. Using technological innovation and implementation as a key business enabler Technology is a key enabler in terms of Statoil realising its goals as an internationally competitive energy company. Our ambition is to attain distinctiveness and industrial leadership by aligning our technology and R&D efforts with our portfolio of activities, and vice versa. Based on our history of technological achievements, we actively endeavour to master demanding and critical developments within our priority activity areas. We prioritise technology efforts that add value to resources and that enable us to develop smarter solutions for energy exploration and production that are cost-efficient and environmentally benign. We are refining and standardising our technical requirements and work processes. Technology innovation and implementation is critical to success in many of our activities, such as enabling field development in frontier deepwater and Arctic areas, the production of heavy oil, exploration for hydrocarbons trapped below salt, and managing environmental and climate-related issues. In addition, in order to enable sustainable energy provision in the long term, we aim to remain competitive in a broad range of core and emerging technologies, such as floating offshore wind. 2.5.4 DPN strategy DPN's strategy is to realise the full potential of the Norwegian continental shelf (NCS). We aim to achieve this through safe and efficient operations, improving operational and drilling cost-efficiency, increasing recovery from existing fields, new developments, optimising use of existing infrastructure, and access to new acreage. Safe and efficient operations are essential to our business strategy Statoil aims to carry out all activities with strong focus on HSE in order to prevent harm to people and the environment and to ensure the quality of the work. The implementation of integrated operations (IO) is expected to increase economic value through higher production, higher regularity and cost reductions. Through our ongoing focus on integrated operations and common work processes on all our installations on the NCS, we aim to utilise best practices and optimise the use of our total resources to ensure safe and efficient operation. Upgrading and modification programmes for offshore installations are also planned with a view to maintaining safe and efficient operations. Maintaining a high production level Statoil aims to maintain a stable production level on the NCS during the period up until 2020. Due to the decline in the mature part of our portfolio, substantial new production is required. We aim to achieve this through several measures: Several fields on the NCS are maturing and production is declining. High priority will therefore be given to more efficient drilling operations, improved regularity and increased hydrocarbon recovery (IHR). High regularity is expected to be achieved through efficient well work, better reservoir management, the de-bottlenecking of export infrastructure and efficient turnarounds. Optimal development and exploitation of our producing fields is necessary in order to secure a solid foundation for future activities through exploration and continued maturation of the project portfolio. New field developments are generally more challenging than before, in terms of their complexity, smaller size and/or profitability. Due to their size and location, the majority of our discoveries will be developed as subsea tie-backs in order to utilise existing infrastructure. This requires a higher degree of standardisation and simplification of technical solutions. Active near-field exploration is a key factor in extending fields' lifetimes and initiating cost-effective tail-end production on fields that are in decline and/or have reached a critical point with respect to profitability. Access to new, high-quality exploration acreage is necessary in order to maintain a high production level in the longer term. Considering the long lead times for field developments, it is a prerequisite in the near term to open new acreage. Energy efficiency and carbon emissions Development and Production Norway (DPN) aims to maintain and strengthen the NCS's position as the most energy-efficient petroleum region in the world. We intend to push for energy efficiency in our day-to-day operations and evaluate new field developments in a long-term perspective with regard to energy and the environment. DPN also plans to put more effort into developing a more energy-efficient supply chain from a life-cycle perspective. Industry leader on the NCS We aim to maintain our position as a preferred operator on the NCS. The NCS is an arena for world-class innovation and technological development. Statoil is a leader in the deployment of new technology, such as drilling and subsea technology, new solutions for reducing costs and the use of new technology to develop discoveries. As the largest operator on the NCS, we are in the forefront of the development of optimal area solutions and the overall development of the shelf. 18 Statoil, Annual report on Form 20-F 2010

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    2.5.5 DPI strategy DPI's strategy is to build a large and profitable international E&P portfolio by delivering on existing projects and accessing new opportunities. Development and Production International (DPI) is responsible for the safe and efficient development and production of oil and gas resources worldwide (apart from Norway and North America). DPI will focus on four strategic growth areas - deep water, gas value chains, harsh environments and heavy oil - and access projects where Statoil can apply its core technological and organisational expertise to create value. Going forward, particular attention will be devoted to: We expect that delivering on operated projects - such as starting production from the Peregrino field in Brazil in 2011 and significantly progressing the development of the Mariner and Bressay fields in the UK - will mature DPI's resource base and further develop an organisational skill set and international operator experience. Driving production from key partner-operated positions, such as projects in Angola, Algeria and Azerbaijan, and continuing to be a value-adding partner in these projects by actively promoting effective technological improvements and sound operational practices. Maturing other large projects such as the Shtokman gas development in Russia and the West Qurna II field in Iraq, thereby actively utilising Statoil's experience. Optimising the portfolio to maximise value, and actively seeking new growth opportunities, striving for technical innovation, financial robustness and HSE excellence in all projects. In line with the corporate growth strategy, our growth strategy is based on exploration, focused business development, strategic acquisitions and divestments, and the building of long-term partnerships in order to increase the scale of our operations in terms of production, reserves and technological and geographical breadth and bring our resource base closer to production. DPI will continue to deliver profitable projects in a range of complex technical and stakeholder environments. 2.5.6 DPNA strategy DPNA's strategy is to build a balanced portfolio of profitable assets by delivering existing projects and accessing new growth opportunities. Development and Production North America (DPNA) is responsible for planning for the safe, efficient and profitable development and production of oil and gas resources in North America. DPNA's growth ambition is focused on Statoil's four strategic growth areas: deep water, gas value chains, heavy oil and harsh environments. Deep water Statoil is the third largest licence holder in the deepwater regions of the US Gulf of Mexico. Our ambition is to profitably grow Statoil's equity production, while being a leading company in relation to HSE, by moving existing discoveries to first oil. In the short term, the priority is to become fully compliant with any new offshore regulations and to secure new drilling permits to allow de-risking and value creation through exploration. DPNA is also focusing on the large yet-to-find potential of the deepwater regions of Mexico. Gas value chains Statoil's onshore shale gas positions in Marcellus and Eagle Ford offer competitive costs compared with other US gas supply sources. Our strategy is to continue to improve the joint ventures' operational performance, to maximise the value creation from existing acreage and to secure production growth together with our JV partners. Statoil plans to operate in these unconventional shale plays within 2-3 years. Heavy oil By entering the Canadian oil sands in 2007, Statoil positioned itself as a long-term player in the Canadian oil sands. With the Leismer Demonstration Project on stream, the plan is to add additional phases and to implement a technology plan aimed at increasing energy efficiency and bitumen recovery, driving down costs and carbon dioxide emissions. Harsh environments Our ambition in the East Coast Canada semi-arctic Jeanne D'Arc basin is to profitably grow Statoil's equity production through IOR in existing fields and through new field developments. East Coast Canada will have a special role as an Arctic Competence Centre. Statoil, Annual report on Form 20-F 2010 19

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    2.5.7 MPR strategy MPR's strategy is to maximise corporate value through safe, reliable and efficient operations, and through the development of profitable midstream, downstream and renewable energy business opportunities. Marketing, Processing and Renewable Energy (MPR) is responsible for the transportation, processing, storage and marketing of all hydrocarbons in Statoil's upstream portfolio, including refined products. Following the initial public offering of Statoil's energy and retail business in October 2010, the remaining parts of Statoil's midstream and downstream oil and gas value chains now have a more industrial end-user focus. Dynamic gas markets and the increasing complexity of Statoil's crude qualities call for close cooperation between Statoil's upstream business areas and MPR. An integrated value chain approach has already added significant value to key projects, such as Peregrino in Brazil (oil) and Marcellus in the USA (gas). For example, Statoil's upstream business areas and MPR had to work closely to find the most efficient solutions for the marketing of Peregrino crude oil. We have a flexible gas transportation system, with six different landing points on the European Continent/UK and flexibility in terms of gas deliveries from large gas-producing fields such as Troll and Oseberg. We plan to leverage our competitive position as a low cost supplier with significant flexibility, proximity to attractive markets and our LNG capabilities to capture opportunities and maximise shareholder value. Marketing MPR will continue to strengthen its global trading and marketing activities. We will increase our presence in strategic regions such as the Americas, while maintaining established market position in Europe. We will continue to develop business and infrastructure positions in order to secure reliable market access and competitive pricing for Statoil's products. Access to attractive infrastructure and efficient logistical solutions give our business a competitive edge both with respect to our own equity volumes, as well as third party volumes sourced globally. Processing The market outlook for the European refining industry is challenging and is expected to remain so in the mid-term. We aim to enhance the refineries competitive position by improving product yields, operational reliability and energy efficiency and by reducing costs while maintaining a high HSE performance. A strong focus on operations and performance is of the essence. MPR's ambition is to strengthen the interface between manufacturing and trading units and to add value through more pro-active integration of the operation of the Mongstad and Kalundborg refineries. The objective is to exploit synergies through crude feedstock optimisation, greater flexibility and exchange of products between the refineries. In the gas processing facilities, a high reliability and cost-efficient performance is fundamental for reliable and competitive deliveries of gas to Statoil's customers. Renewable Energy MPR's strategy for developing its business in renewable energy is founded on Statoil's overall expertise within oil and gas exploration, development and operations and, in particular, the extensive experience from offshore operations. This strategy has been employed in the growing offshore wind industry, where the company is engaged in a development project in the UK (Sheringham Shoal) and also has been awarded an additional large offshore development acreage in the UK (as part of a consortium). Statoil believes that technologies for CCS will provide attractive contributions in curbing greenhouse gas emissions to the atmosphere. MPR is engaged in ongoing efforts to develop a commercial CO2 storage concept, leveraging the unique and extensive experience Statoil has acquired from Sleipner and other fields that have been separating and injecting CO2 for years. 2.5.8 TPD strategy TPD's strategy is to create value by providing Statoil with safe and cost efficient drilling and project deliveries. Competitive solutions are key success factors in developing our global activities. Statoil's upstream development portfolio is substantial. In addition our portfolio is technically as well as geographically diverse. We have demonstrated excellent project execution skills, for example within the Peregrino project off the coast of Brazil. Furthermore, we have gained valuable experience from oil sands in Canada, where the Leismer project started production late 2010. We have also expanded our portfolio of unconventional gas projects in the US. Within renewable energy, a wind park with more than 80 windmills is being built off the east coast of England for the Sheringham Shoal project, thus gaining expertise in the execution of offshore wind projects. 20 Statoil, Annual report on Form 20-F 2010

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    TPD has made a significant effort associated with CO2 storage and carbon management to complete the construction of the Test Centre plant at Mongstad (TCM). Experience gained from TCM will be used to enhance new business opportunities with the potential of adding value to certain oil and gas activities across the company. (Future projects that will fall under strict CO2 regime or exposed for high CO2 costs will benefit from effective solutions for CO2 treatment and TCM experience will be valuable for project evaluation.) On the NCS many of our projects are related to redeveloping and upgrading existing fields and installations to prolong lifetime and increase recovery rates. A number of small satellite fields are being tied into existing hubs as this will significantly shorten the time from discovery to production. We are actively working to simplify development concepts and to standardise use of equipment and services. A key focus area is to enhance recovery from wells already drilled. Finally we are developing and implementing new technology with the aim of ensuring future growth both on the NCS and elsewhere. Our corporate technology strategy is driven by business challenges and aims to further strengthen our industry position. The technology strategy addresses which technologies to develop and implement to support the corporate strategic ambitions. The technology strategy promotes technologies that will increase competitiveness and enable the company to grow and to deliver world class development projects. We put emphasis on developing enabling- and new- technologies for frontier areas. An example of this is the choice of a subsea compression solution for the Åsgard field on the NCS. At the same time we put emphasis on standardising selected technologies, fast resource maturation and cost-efficient development solutions. Much of our technology development and deployment is carried out in close cooperation with national and international universities, research institutes and suppliers. Our performance is strongly dependent on our supplier's performance. We work closely with our suppliers in order to optimise our joint performance. 2.5.9 EXP strategy Statoil is committed to delivering value through exploration in several of the most important oil and gas provinces in the world. Exploration is an important growth tool for Statoil in order to secure long term growth of reserves, production and value. We are present in several of the most important oil and gas provinces in the world and will continue to optimise our portfolio, balancing infrastructure-led exploration, growth opportunities in mature areas and frontier exploration in new areas. Our exploration strategy remains focused on accessing more new quality acreage, including unconventional hydrocarbons and technologically challenging exploration resources. As of January 2011, Statoil merged all exploration activities into one business unit (EXP) in order to utilize competence, resources and technology more effectively across all exploration areas. Statoil will focus on managing the risks associated with exploration activities. We will influence our partners and contractors over the implementation of safe practices in all phases of our activities and strive for a continuous improvement in our operational performance. On the NCS further exploration is necessary for maximising the long term value of our portfolio beyond 2020, and we will collaborate across our producing areas to maximise value for the longer term by extending field lifetimes through near-field exploration. We participate in 213 licences in all licensed parts of the NCS and operate 157 of them. Access to new, prospective acreage is necessary in order to maintain a high production level in the longer term. Outside Norway we will expand our exploration portfolio managing risk and reward to deliver profitable growth. We are the third largest licence holder in the deepwater regions of the US Gulf of Mexico. In addition we currently have exploration licences in Canada, USA (Alaska), Africa (Angola, Algeria, Egypt, Libya, Mozambique, Nigeria and Tanzania), Asia (India, Indonesia and Iran*), Europe and the Caspian region (Azerbaijan, the Faroes, Greenland, Ireland, Norway and the UK), South America (Brazil, Cuba and Venezuela). *Statoil will not make any future investments in Iran under the present circumstances. For more information, see section Operational review - International E&P - International fields in development and production - The Middle East and Asia - Iran. Statoil, Annual report on Form 20-F 2010 21

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    3 Operational review Statoil's operational review follows the organisation of its operations, although certain disclosures about oil and gas reserves are based on geographical areas, as required by the SEC. Statoil prepared this operational review in accordance with the segment (business area) structure it used prior to 1 January 2011 (for more information, see section Business overview and strategy - New organisational structure as from January 2011). Each business area is presented individually, and underlying business clusters are included according to how the business area organises its operations. For further information on extractive activities, see the sections E&P Norway and International E&P, respectively. 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 areas. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa and the Americas. For further information on disclosures about oil and gas reserves and certain other supplementary disclosures based upon geographical areas as required by the SEC, see the sections Operational review - Production volumes and price information and Proved oil and gas reserves. 3.1 E&P Norway 3.1.1 Introduction to E&P Norway Exploration & Production Norway consists of our exploration, field development and operations activities on the Norwegian continental shelf (NCS). Exploration & Production Norway (EPN) is the operator of 44 developed fields on the NCS. Statoil's equity and entitlement production on the NCS was 1,374 mmboe per day in 2010, which was about 73% of Statoil's total production. Acting as operator, EPN is responsible for approximately 75% of all oil and gas production on the NCS. In 2010, our average daily production of oil and natural gas liquids (NGL) on the NCS was 705 mboe, while our average daily gas production on the NCS was 106.4 mmcm (3.8 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 213 licences on the NCS and are operator for 157 of them. As of 31 December 2010, EPN had proved reserves of 1,241 mmbbl of crude oil and 463 bcm (16.3 tcf) of natural gas, an aggregate total of 4,153 mmboe. 22 Statoil, Annual report on Form 20-F 2010

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    Barents Sea ! Norwegian Sea ! ! 110001_STN049012 North Sea (W) ! North Sea (SW) 3.1.2 E&P Norway key events in 2010 Activity levels in Exploration & Production Norway were high in 2010 with several new projects sanctioned including three fast track projects. Total entitlement liquids and gas prodution in 2010 amounted to 1,374 mboe per day. An extensive turnaround programme was completed in 2010. High discovery rate in 2010: 12 discoveries out of 17 exploration wells. Final investment decisions were made for the following projects: Gudrun Ekofisk Hotel Njord North West Flank Marulk Valemon Kristin LPP PanPandora Smørbukk North East Ekofisk South Eldfisk Production from four new fields added total capacity of approximately 70 mboe per day: Morvin Gjøa Vega Vega South Statoil, Annual report on Form 20-F 2010 23

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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 IOR projects. We also operate a significant number of exploration licences. 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 West, Operations North Sea, Operations North and Partner Operated Fields. The Operations West and Operations North Sea 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 whole NCS. The fields in each cluster use common infrastructure, such as production installations and oil and gas transport facilities where possible. 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 the 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. Potential producing areas In addition to the producing areas, we operate a significant number of exploration licences. The exploration acreage is located both in undeveloped frontier areas as well as close to infrastructure and producing fields. NCS By the end of 2010, the total licensed acreage on the NCS covered an area of 115,331 square kilometres divided between 401 licences. Statoil has interests in 213 licences, covering an acreage of 51,313 square kilometres and is operator for 157 of them. As a consequence of the continuous high- grading and alignment of the former Statoil and Hydro licence portfolios, the number of Statoil licences has been reduced by twelve and the total licenced acreage reduced by 9,086 square kilometres compared with 2009. Statoil has applied for acreage in the 21st licensing round. Awards are expected in the first half of 2011. Statoil also applied for acreage in The Awards in Predefined Areas 2010 (APA), awarded in January 2011. North Sea The total licensed acreage in the North Sea covers 56,831 square kilometres divided among 241 licences. Statoil has interests in 114 licences covering 19,516 square kilometres and is operator for 85 of them. One new licence has been awarded to Statoil as operator and three Statoil-operated licences and one partner-operated licence have been relinquished. In order to further minimise area fee costs, the licensed acreages in six more licences were reduced. Total relinquished acreage is 4,282 square kilometres. Norwegian Sea The total licensed acreage in the Norwegian Sea covers 41,282 square kilometres divided among 123 licences. Statoil has interests in 19,987 square kilometres divided between 73 licences and is operator for 52 of them, covering an area of 9,389 square kilometres. Eleven of the Statoil-operated licences and five of the partner-operated licences covering 6,300 and 6,968 square kilometres, respectively, are located in areas with a water depth greater than 500m. Five Statoil-operated and three partner-operated licences have been relinquished, and the licensed acreage in three licences was reduced. Total relinquished acreage is 3,807 square kilometres. Barents Sea The total licensed acreage in the Barents Sea covers 17,218 square kilometres divided among 40 licences. Statoil has interests in 11,809 square kilometres divided between 26 licences and is operator for 20 of them. One new licence was awarded and two licences were relinquished last year, all of them operated by Statoil. To further minimise area fee costs, the licensed acreages in six more licences were reduced. Total relinquished acreage is 997 square kilometres. 24 Statoil, Annual report on Form 20-F 2010

  • Page 33 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. Statoil signed several sales and purchase agreements (SPA) in 2010. Two SPAs were signed with Marathon Petroleum AS. In the first SPA, Statoil acquired an 8.2% participation interest in PL025, which contains the Gudrun development, for a consideration of 10% of PL187 and 12.5% of PL048E. A new SPA was therefore signed in which Statoil acquired all of Marathon Petroleum AS's participation interests in PL025 and PL 187 (the Gudrun development and the Sigrun and Brynhild discoveries) and in PL048E (the Eirin discovery) for cash consideration. An SPA was signed with PGNiG Norway AS in which it farms in 10% to PL326, the Gro discovery. We signed further SPAs with Concedo to acquire its 5% share of PL 348 containing the Gygrid discovery; with Petoro AS, a company owned by the Norwegian State that was formed to manage SDFI assets, to divest our 30% share in PL158 containing the Hasselmus discovery; and with TOTAL E&P Norge AS to divest our 21% share in PL043CS and PL043DS containing the Islay discovery. SPAs were also signed with TOTAL E&P Norge AS and ExxonMobil Exploration and Production Norway AS to carve out the Theta NE prospect from PL046, PL303 and PL078B, thus aligning the participation interests. Several transactions have also been carried out that involve the farming-in and farming-out of exploration licences. 3.1.4 Exploration on the NCS Statoil's 2010 exploration drilling activity on the NCS was reduced compared with the extensive exploration drilling campaigns carried out in 2008 and 2009. 17 exploration wells and four exploration extensions wells were completed in 2010 compared with the completion of 39 exploration wells in 2009 and also in 2008. In 2010, the focus has been on evaluating and maturing all the 2009 and 2008 well results. 12 of the 17 wells drilled for exploration purposes were wildcat wells drilled to test new prospects, and six of them were operated by Statoil. Five of the six Statoil-operated wildcat wells and three of the six partner-operated wildcat wells confirmed the presence of hydrocarbons. A major oil discovery was made in the central part of the North Sea in the Avaldsnes prospect, which is located on the Utsira High, a structural element separating the two Statoil-operated fields, Sleipner and Grane. Lundin is operator for the Avaldsnes licence, and Statoil has a 40% ownership share. The prospect evaluation prior to the drilling was based on a new geological play model for the area. The positive result, which proves the validity of this model, has increased the probability of success for similar prospects in a neighbouring Statoil-operated licence scheduled for drilling in 2011. Another discovery is Fossekall, located near the Norne field in the Norwegian Sea. Fossekall, which is operated by Statoil, will be developed as a tie-in to Norne together with Dompap, a discovery made in late 2008. Fossekall is now considered to be a fast track candidate with estimated production start-up in 2013. For further information about fast track projects, see section Operational review - Projects & Procurement - Project development. The Snadd North discovery was made in 2010 in the BP-operated Skarv-Idun area, where Statoil is a major partner (36.165%). Test production of the low carbon dioxide gas will start during the third quarter 2011 and last for 12-18 months. Afterwards, the partnership will evaluate the further development of both Snadd North and South. The drilling results from the two Shell-operated exploration wells in the Vøring basin are disappointing. The wildcat well located on the Dalsnuten prospect never penetrated any potential reservoir rock, and the appraisal well on the Gro structure proved the same marginal reservoir condition in this new segment as in the previous one. A re-evaluation of the prospects in this part of the Norwegian Sea is necessary before the next exploration well is drilled. In the Barents Sea, ENI, as operator for the first of four scheduled drilling operations, started the joint 2010/2011 drilling campaign for the Arctic-equipped "Polar Pioneer" rig. Operatorship will be transferred from ENI to Statoil in early 2011, and the second well will be drilled in the southern part of the Hammerfest basin. Statoil, Annual report on Form 20-F 2010 25

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    The Norwegian Minister of Petroleum and Energy has announced that there will be no drilling in any deepwater licenses granted from the NCS's 21st licensing round, scheduled to be completed in the first half of 2011, until the Norwegian Ministry of Petroleum and Energy has deeper knowledge about the accident that occurred on the BP-operated Macondo well in the deepwater Gulf of Mexico in April 2010, including possible implications for the Ministry's regulations. Although drilling on the NCS occurs mainly at a shallower depth and at lower pressure conditions than in the deepwater Gulf of Mexico, both Statoil and the Norwegian authorities are examining operations on the NCS in light of the accident in the Gulf of Mexico. The Norwegian Petroleum Safety Authority (PSA) is putting more focus on the ability of companies to effectively handle a potential blow-out event. This means, for example, that companies will have to demonstrate their ability to handle a potential blow-out and inform the PSA about how they plan to shut down a well in case of a blow-out before receiving permission to start drilling a new well. The PSA has also established a project team to systematise and assess experience gained and investigatory findings from the Macondo incident in order to secure lessons and improvements for the NCS. The table below shows Statoil's exploratory and development wells drilled on the NCS over the last three years. 2010 2009 2008 North Sea Statoil operated exploratory 10 23 13 Successful 7 18 8 Dry 3 5 5 Statoil operated development 59 72 75 Partner operated exploratory 6 1 4 Successful 4 1 2 Dry 2 0 2 Partner operated development 11 17 13 Norwegian Sea Statoil operated exploratory 2 10 15 Successful 2 8 12 Dry 0 2 3 Statoil operated development 14 19 13 Partner operated exploratory 3 4 0 Successful 2 3 0 Dry 1 1 0 Partner operated development 6 1 3 Barents Sea Statoil operated exploratory 0 1 7 Successful 0 1 5 Dry 0 0 2 Statoil operated development 0 0 0 Partner operated exploratory 0 0 0 Successful 0 0 0 Dry 0 0 0 Partner operated development 0 0 0 Totals Exploratory 21 39 39 Successful 15 31 27 Dry 6 8 12 Development 90 109 104 26 Statoil, Annual report on Form 20-F 2010

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    3.1.5 Oil and gas reserves on the NCS At the end of 2010, Statoil had a total of 1,241 mmbbl of proved oil reserves and 463 bcm (16.3 tcf) of proved natural gas reserves on the NCS. EPN, oil and gas reserves Measured in barrels of oil equivalents (boe), our NCS proved reserves consist of 30% oil and 70% natural gas, based on total NCS proved reserves of 4,153 mmboe. million boe 6,000 In 2010, final investment decisions were made for Valemon, Gudrun, Visund South and Marulk on the NCS, and contributed positively to the proved reserves balance. In addition, revision of proved reserves 4,000 for several of our producing fields contributed positively. 2,000 Proved developed reserves at year end were 3,394 mmboe, which is 82% of the proved reserves. Of the 2010 proved developed reserves, 950 mmboe are oil and 389 bcm (13.7 tcf) are natural gas. 2008 2009 2010 The following table shows our total NCS proved reserves as of 31 December for each of the last three years. Further information on reserves can be found in section Operational review - Proved oil and gas Gas Oil reserves and in note 35 - Supplementary oil and gas information - to our Consolidated Financial Statements. Oil/NGL Natural gas Total Year mmbbls bcm bcf mmboe 2010 Proved reserves end of year 1,241 463 16,343 4,153 of which, proved developed reserves 950 389 13,721 3,394 2009 Proved reserves end of year 1,351 480 16,938 4,369 of which, proved developed reserves 1,028 401 14,138 3,548 2008 Proved reserves end of year 1,396 498 17,581 4,529 of which, proved developed reserves 1,113 410 14,482 3,693 3.1.6 Production on the NCS In 2010, our total entitlement oil and NGL production in Norway was 257 mmbbl, and gas production was 38.8 bcm (1,372 bcf), which represents an aggregate of 1.374 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, Annual report on Form 20-F 2010 27

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    Statoil’s Licence Average daily Georgraphical equity interest On expiry Producing wells production in 2010 Business cluster area in %(1) Operator stream date Oil Gas mboe/day Operations North Sea Sleipner Øst The North Sea 59.60 Statoil 1993 2028 0 10 20.5 Sleipner Vest The North Sea 58.35 Statoil 1996 2028 0 20 76.8 Gungne The North Sea 62.00 Statoil 1996 2028 0 4 11.8 Troll Phase 1 (Gas) The North Sea 30.58 Statoil 1996 2030 0 39 162.8 Troll Phase 2 (Oil) The North Sea 30.58 Statoil 1995 2030(2) 117 0 36.7 Fram The North Sea 45.00 Statoil 2003 2024 9 0 29.2 Kvitebjørn The North Sea 58.55 Statoil 2004 2031 0 10 96.2 Visund The North Sea 53.20 Statoil 1999 2023 6 1 24.2 Vega The North Sea 60.00 Statoil 2010 2035 0 2 0.3 Vega Sør The North Sea 45.00 Statoil 2010 2024 2 0 0.1 Gjøa The North Sea 20.00 GDFSuez 2010 2028 3(17) 2 1.3 Grane The North Sea 36.66 Statoil 2003 2030(3) 25 0 54.7 Veslefrikk The North Sea 18.00 Statoil 1989 2015 17 0 2.5 Huldra The North Sea 19.88 Statoil 2001 2015 0 5 3.6 Glitne The North Sea 58.90 Statoil 2001 2013 6(4) 0 2.6 Heimdal The North Sea 29.87 Statoil 1985 2021(5) 0 3 1.2 Brage The North Sea 32.70 Statoil 1993 2015(6) 21 0 9.9 Vale The North Sea 28.85 Statoil 2002 2021 0 1(7) 0.1 Vilje The North Sea 28.85 Statoil 2008 2021 2 0 8.8 Volve The North Sea 59.60 Statoil 2008 2028 3 0 19.8 Total Operation North Sea 211 97 562.9 Operations West Statfjord Unit The North Sea 44.34 Statoil 1979 2026 68(8) 8 48.7 Statfjord Nord The North Sea 21.88 Statoil 1995 2026 7 0 1.7 Statfjord Øst The North Sea 31.69 Statoil 1994 2026(9) 7 0 5.5 Sygna The North Sea 30.71 Statoil 2000 2026(10) 3 0 0.3 Gullfaks The North Sea 70.00 Statoil 1986 2016 95 9 109.8 Snorre The North Sea 33.32 Statoil 1992 2015(11) 27 0 34.6 Tordis area The North Sea 41.50 Statoil 1994 2024 6 0 5.2 Vigdis area The North Sea 41.50 Statoil 1997 2024 14 0 15.1 Gimle The North Sea 65.13 Statoil 2006 2016 2 0 2.5 Oseberg The North Sea 49.30 Statoil 1988 2031 62 0 101.7 Tune The North Sea 50.00 Statoil 2002 2032 0 4 6.0 Total Operations West 291 21 331.3 Operations North Alve The Norwegian Sea 85.00 Statoil 2009 2029 0 1 19.2 Kristin The Norwegian Sea 55.30 Statoil 2005 2033(12) 12 0 41.9 Norne The Norwegian Sea 39.10 Statoil 1997 2026 9 0 14.2 Urd The Norwegian Sea 63.95 Statoil 2005 2026 3 0 4.6 Heidrun The Norwegian Sea 12.41 Statoil 1995 2024 29(13) 0 8.8 Åsgard The Norwegian Sea 34.57 Statoil 1999 2027 0 37 123.4 Mikkel The Norwegian Sea 43.97 Statoil 2003 2022(14) 0 3 22.6 Morvin The Norwegian Sea Statoil 2010 2027 1 0 4.6 Njord The Norwegian Sea 20.00 Statoil 1997 2021 & 2023(15) 6(16) 0 10.4 Tyrihans The Norwegian Sea 58.84 Statoil 2009 2029 4 0 42.1 Snøhvit The Barents Sea 33.53 Statoil 2007 2035 0 9 37.0 Yttergryta The Norwegian Sea 45.75 Statoil 2009 2027 0 1 4.5 Total Operations North 64 51 333.4 Partner Operated Fields Ormen Lange The Norwegian Sea 28.92 Shell 2007 2041 0 12 21.0 Ekofisk area The North Sea 7.60 ConocoPhillips 1971 2028 153 0 108.6 Ringhorne Øst The North Sea 14.82 ExxonMobil 2006 2030 3 0 2.9 Sigyn The North Sea 60.00 ExxonMobil 2002 2018 1 2 10.8 Enoch The North Sea 11.78 Talisman 2007 2018 1 0 2.1 Skirne The North Sea 10.00 Total 2004 2025 0 2 0.5 Total Partner Operated Fields 158 16 146.0 Total 724.0 185.0 1,373.7 (1) (9) Equity interest as of December 31, 2010. PL037 expires in 2026 and PL089 expires in 2024 (2) Troll Phase 2 (Oil) has 64 multi branched wells (10) PL037 expires in 2026 and PL089 expires in 2024 (3) Grane has 9 multi branched wells (11) PL089 expires in 2024 and PL057 expires in 2015 (4) Glitne 1 multi branched well (12) PL134B expires in 2027 and PL199 expires in 2033 (5) PL036 expires in 2021 and PL102 expires in 2025. The owner (13) 1 multi branched well (14) share of the topside facilities is 39,44%, however the owner share PL092 expires in 2020 and PL121 expires in 2022 (15) of the reservoir and production is 29,87%. PL107 expires in 2021 and PL132 expires in 2024 (6) PL185 expires in 2015 and PL053B and PL055 both expire in 2017 (16) 1 multi branched well (7) Vale 1 multi branched well (17) From 2011 Gjøa will be reported as a partner operated field (8) 89 single completed wells, 4 multiple completed wells 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 2010, 2009 and 2008. 28 Statoil, Annual report on Form 20-F 2010

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    For the year ended December 31, 2010 2009 2008 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 183 24 333 175 25 332 175 22 314 Operations North Sea 240 51 563 269 49 574 250 49 558 Operations West 246 14 331 297 14 385 355 19 477 Partner Operated Fields 36 18 146 43 18 158 43 11 112 Total 704 106 1,374 784 106 1,450 824 101 1,461 3.1.7 Development on the NCS The NCS is the backbone of our operations and the centre of innovation. We continue to explore and develop the NCS as operator and partner using the best available technology and increasingly standardised development solutions. Fields under development on the NCS The following fields are currently under development on the NCS. The Gudrun Field is located in the North Sea. The field will be developed 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 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. (Gassco AS is a company owned by the Norwegian state that operates the Norwegian natural gas transportation system, Gassled. Statoil's ownership interest in Gassco was 32.1% by year end 2010, and 22.5% from 1 January 2011). The plan for development and operation (PDO) was submitted to the Norwegian authorities in February 2010, and approved by the Norwegian authorities in June 2010. Production is estimated to start in 2014. The total investments are estimated to be NOK 19.6 billion. Statoil holds a 46.8% interest in Gudrun. Skarv is an oil and gas field located in the Norwegian Sea in which we have an interest of 36.165% and for which BP is the operator. The field is being developed with a floating production storage and offloading (FPSO) vessel and five subsea installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. Production is expected to start in August 2011. The total development cost is estimated by the operator, BP, to be NOK 36.8 billion. 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. The oil will be offloaded to shuttle tankers. Associated gas will initially be reinjected and later exported together with the gas cap. Statoil is the only partner in Goliat, with an interest of 35%. Eni is the operator. Production start-up is expected in late 2010. The operator has estimated the development costs for the field to be NOK 30.5 billion. Valemon, which is located in the North Sea, will be developed with a steel jacket platform with gas, condensate and water separation. Drilling will be performed using a jack-up rig. Rich gas will be transported via Huldrapipe to Heimdal for processing. Sales gas will be transported in Vesterled to St Fergus, or, alternatively, in Statpipe to Draupner. There will be a condensate tie-in to Kvitebjørn for stabilisation and further export in pipelines to Mongstad. Statoil holds an interest of 64.275% in the field. The PDO was submitted to the Norwegian authorities at the end of October 2010 and PDO approval is expected during the second quarter of 2011. The development cost of Valemon is currently estimated to be NOK 19.6 billion, and production start-up is estimated to take place during the fourth quarter 2014. Marulk, in which Statoil holds an interest of 50%, is a gas and condensate field located in the Norwegian Sea 25 kilometres southwest of Norne. The field was discovered in 1992. The final investment decision was taken early 2010 and the PDO was approved by the Norwegian authorities 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 Åsgard Transport System for processing to sales gas at Kårstø. Condensate will be stored and off-loaded commingled with the Norne crude. Production is estimated to start in the second quarter 2012. The operator estimates the total investments to be NOK 4 billion. The operator is Eni, but Statoil is carrying out the project work. The table below shows some key figures as at 31 December 2010 for our major development projects. Statoil, Annual report on Form 20-F 2010 29

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    Statoil’s Statoil’s share as at investment as at 31 December 31 December Production Plateau production Project 2010 2010 (1) start Statoil’s share (3) Lifetime in years Goliat (2) 35.000 % 10.7 2013 30,000 18 Gudrun 46.800 % 9.2 2014 40,000 12 (2) Skarv 36.165 % 13.7 2011 53,000 12 Marulk 50.000 % 1.9 2012 10,400 14 Valemon 64.275 % 12.6 2014 50,000 14 (1) Estimated in NOK billion (2) Partner operated project (3) Boe/day Redevelopments on the NCS The following projects are being developed on the NCS to extend the life of existing installations or to exploit new opportunities. The Snorre redevelopment project, which is defined as an increased oil recovery (IOR) project, will contribute to achieving the overall oil recovery ambition for the Snorre Unit and Vigdis. The project includes a water injection pipeline from Statfjord C to the Vigdis field. The Statfjord late life project converted Statfjord into a mainly gas-producing field by changing the drainage strategy. Gas exports to the UK through a new pipeline connected to the existing pipelines to Flags and St Fergus commenced in late 2007. Investments in the project are estimated to total NOK 21.5 billion. Troll Field projects include the Troll B gas injection project and the Troll A P12 pipeline project. The main goals of these projects are IOR from Troll B and enabling the Troll field to maintain an average gas export capacity of 120 million standard cubic metres per day and a long-term gas export capacity of 30 billion standard cubic metres per year. The Troll B Gas Injection project includes two gas injectors in the Troll West Gas Province south. Start-up is planned in 2011. The Troll A P12 project includes a new 62.5-kilometre 36-inch pipeline between Troll A and Kollsnes, modifications on Troll A and an interface with the Kollsnes plant. Start-up of the pipeline is planned in late 2011. The Troll C - O2 template, which will be located north-west of the Troll C platform, is defined as an IOR project. The O2 template will be tied back to the existing O1 template, which is tied back to Troll C. Drilling started in December 2009 and the first two wells started production in 2010. The Norne M template will be located in the southern area of the Norne field. The template will have four production well slots and will be connected to the existing infrastructure at the K template. Drilling started in March 2010 and production start-up is scheduled for April 2011. 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 early 2014. The main purpose of Kvitebjørn Precompression project is to increase and accelerate gas and condensate recovery by facilitating low pressure production. The project includes 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 is scheduled to start in May 2011 and production is planned to start in April 2012. 30 Statoil, Annual report on Form 20-F 2010

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    3.1.8 Fields in production on the NCS We continue to develop the NCS, delivering good results in a year that saw extensive turnarounds and several operational challenges. Operations North Sea Operations North Sea include a large part of Statoil's production activity on the NCS. Our focus is on increasing and prolonging production in the area, and we give priority to IOR and exploration and development of new fields. The main producing fields in the Operations North Sea area are Troll, Sleipner, Kvitebjørn, Visund, Grane, Brage, Veslefrikk, Huldra, Glitne, Volve and Heimdal. In addition, our new Vega field started production in December 2010. The area is dominated by natural gas production, with 57.5 of the equity production in 2010. The petroleum reserves are located below water depths of between 80 and 330 metres. In 2010, Statoil's share of the area's production was 240 mbbl of oil, condensate and NGL per day and Visund 323 mboe of gas per day, or 563 mboe per day in total. Vega Kvitebjørn Fram Brage is an oilfield east of Oseberg in the northern part of the North Sea. Huldra Troll The oil is piped to Oseberg and then through the pipeline in the Oseberg Sture Norway Transport System to the Sture terminal. A gas pipeline is tied back to ! ( Brage ! Kollsnes ( Statpipe. Bergen ! ( Fram is connected to the Troll C platform for processing. Oil production started in 2003, while gas exports started in October 2007. Vale Heimdal 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- Kårstø ! ( alone production system. Grane Stavanger ! ( Grane is the first field on the NCS to produce heavy crude oil. It is Statoil's Glitne Volve largest heavy oil field. The field is located to the east of the Balder field in 110001_STN056612 the northern part of the North Sea. Oil from Grane is piped to the Sture Sleipner terminal, where it is stored and shipped. Injection gas is imported to Grane by pipeline from the Heimdal facility. As a result, after around 25 years of oil production, Grane is producing injected gas as well. 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 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 approval is expected during the first quarter of 2011. Then the lifetime of the processing facility at the Heimdal Gas Centre will be extended, thereby 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 Kvitebjørn field by approximately 35 million standard cubic metres (mscm) of oil equivalent and thus increase the recovery rate from 55% to 70%. Work on production of the compressor has already started. The offshore installation is expected to take place from 2012 until completion in early 2014. 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 re-injected 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. The PDO for Gudrun was approved by the Norwegian authorities in June 2010, and the hydrocarbons will be piped to the Sleipner field. On Sleipner, the oil and gas from Gudrun will be further processed before the oil is transported to Kårstø together with the Sleipner condensate. The Troll Area comprises Troll, Fram and Vega. Troll is the largest gas field on the NCS and a major oilfield. The Troll Field Project submitted a new PDO in June 2008 for IOR in the area. The PDO was approved by Norwegian authorities in June 2009 and the project is well under way. Statoil, Annual report on Form 20-F 2010 31

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    The Vega field came on stream in December 2010. It consists of two licences, Vega South and Vega Central; Statoil has substantial ownership interests in both licences. Vega is a new production area for Statoil. The Vega field has been developed with three seabed templates, and gas and condensate are sent to the new Gjøa platform. For further information about the Gjøa platform, see Operational review - E&P Norway - Fields in production on the NCS - Partner operated fields on the NCS. 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 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. 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 used as a storage ship for crude oil before export. Gas is piped to the Sleipner A platform for final processing and export. Operations West The Operations West area contains light oil petroleum resources in a compact geographic area in which Statoil is the sole operator. The main producing fields in the Operations West area are Statfjord, Gullfaks, Snorre, Oseberg, Tordis and Vigdis. Statoil's share of the area's production in 2010 was 246 mbbl per day of oil, condensate and NGL, and 85 mboe per day of gas, or 331 mboe per day in total. Operations West is the leading oil-producing area on the NCS and, even after over 20 years of production, we believe there are still substantial opportunities for increased value creation. Snorre Vigdis Statoil has taken several initiatives to identify and implement measures to Statfjord increase and prolong production from the Operations West area. These Tordis initiatives involve IOR, and they have resulted in a prolongation of planned Gullfaks production beyond the current licence periods for several of the fields. Norway In 2010, Operation West performed two turnarounds without serious HSE incidents. Oseberg Bergen ! ( Gullfaks has been developed with three large concrete production platforms. Oil is loaded directly into 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 remotely controlled from the Guilfaks A and C platforms. 110001_STN049025 On 19 May, a well control incident occurred at well C-06A on Gullfaks C. The direct cause of the incident was leakage in a well casing. A thorough procedure to reinstall the second well barrier kept the platform shut down for two months. Statoil's internal investigation into the incident found that there were deficiencies in risk management and compliance with internal requirements for drill operation, planning and execution. The most important remedial measures identified by the internal investigation relate to risk analyses and acceptance criteria when complexity increases; supporting documentation, quality assurance and formal procedures in planning and decisionmaking; and greater involvement of technical expertise. A copy of Statoil's internal investigation report can be found at http://www.statoil.com/enINewsAndMediaINews/2010/Downloads/5Nov_20 I 0_%20Rapport_broennhendelse_Gullfaks%20C .pdf. 32 Statoil, Annual report on Form 20-F 2010

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    The Norwegian PSA also audited the planning of the well, and issued a report that concluded that overall serious deficiencies were identified in Statoil's planning of the well. Following its investigation, the Norwegian PSA issued an order requiring Statoil to review and assess compliance with the work processes established to safeguard the well construction process on Gullfaks, conduct an independent assessment of why measures adopted after prior similar incidents did not have the desired effect on Gullfaks and implement measures throughout Statoil based on the Norwegian PSA ordered review and assessments. Statoil is complying in all respects with the Norwegian PSA's order. A copy of the Norwegian PSA's report and related documentation can be found at http://www.ptil.no/news/notification-of-order-to-statoil-gullfaks-c-article7409-79.html?lang=enUS. Gullfaks C resumed drilling in July, but following our internal investigation, we shut down drilling operations for three wells in November to ensure that the drilling and well operations were being conducted in accordance with our procedures and the findings in our internal investigation. In late 2010, Statoil decided to shut in the Gullfaks South Brent reservoir for six months in order to maintain drillability for future wells. The Gimle field is a Gullfaks satellite field that is operated as a separate unit. Permanent production started in May 2006, converting the Gimle exploration well drilled from the Gullfaks C platform into a production well. By the end of 2010, Gimle consisted of two producers and one injector, all drilled as long- reach wells from the Gullfaks C platform. The Oseberg area includes the main Oseberg field 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. 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. 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 stabilised and exported to Gullfaks for storage and loading. The northern part of Borg is also produced via the Vigdis templates. The Snorre field has been developed with two platforms and one subsea production system connected to one of the platforms (Snorre A). Oil and gas is exported to Statfjord for final processing, storage and loading. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A Statfjord has been developed with three fully-integrated platforms supported by gravity base structures featuring 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. According to plan, Statfjord A will be shut down for production in 2016. Statoil, Annual report on Form 20-F 2010 33

  • Page 42 Operations North Our producing fields in the Operations North area are Åsgard, Mikkel, Yttergryta, Heidrun, Kristin, Tyrihans, Norne, Urd, Alve, Njord and Snøhvit. The Morvin field started production on 1 August 2010. Our share of the area's production in 2010 was 183 mbbl per day of oil, Snøhvit condensate and NGL, and 151 mboe per day of gas, or 334 mboe per day in total. Hammerfest ! ( The region is characterised by petroleum reserves located at water depths 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 Urd infrastructure. Norne Alve Heidrun The Heidrun platform is the largest concrete tension leg platform ever Sweden built. Heidrun was the first production platform in Operations North, with Yttergryta Åsgard Norway production start-up in 1995. Most of the oil from Heidrun is shipped by Morvin Kristin shuttle tankers to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for 110001_STN049026 Tyrihans Mikkel the methanol plant at Tjeldbergodden in Norway. Additional gas volumes Trondheim are exported through the Åsgard Transport System (ÅTS) to gas markets Njord ! ( ! ( in continental Europe. Tjeldbergodden Kristin is a gas and condensate field in the south-western section of the Operations North area. The Kristin development is the first high-temperature/high- pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir - 900 bar and 170 degrees Celsius, respectively - are higher than on any other developed field on the NCS. The stabilised condensate is exported to a joint Åsgard 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 July 2009, and the field was producing from five wells by the end of 2010. In addition, gas is injected into two injection wells via Åsgard B. Tyrihans is expected to be completed in 2011 with another three 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. A second producing well is scheduled to start in 2011. The field is produced through subsea facilities, with the well stream tied back to the Norne FPSO. Snøhvit is the first field 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 2010, Snøhvit was producing from nine wells. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore. Snøhvit re-injects carbon dioxide from the liquefied natural gas (LNG) plant into a separate well/reservoir. 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 and the USA in tankers. The first shipment took place in late 2007. The LNG plant has suffered from operational challenges, particulary in relation to problems with the heat exchangers, which are located in the heart of the 34 Statoil, Annual report on Form 20-F 2010

  • Page 43

    Snøhvit LNG Plant (Cold box). Their function is to bring the temperature down on the methane gas so that it liquidizes at -164 C. The heat exchangers use ethane and prophane as cooling medium as they condense at higher temperatures than methane. The cooling medium is sprayed over the spiral wounds which contains the methane gas. Hammerfest LNG has improved regularity and capacity in 2010. There has been one planned inspection shutdown lasting ten days and two unplanned production stops due to unforeseen process challenges. The Åsgard field contains 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 58 wells grouped in 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 at 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 planned production from four wells. The first three wells have been completed and were put into production by year end. The last well is expected to be completed during spring 2011. The well stream with oil and gas is tied back to Åsgard B for processing. Morvin is an important contributor to utilising the production capacity at Åsgard B. Partner-operated fields on the NCS Partner-operated fields account for a significant proportion of Statoil's oil and gas portfolio. With expected production start-up on Skarv in 2011, and on Marulk and Goliat in 2012, the importance of partner- operated fields in Statoil is increasing. The portfolio ranges from development projects to mature fields, and their complexity requires detailed knowledge of the areas involved. Ormen Lange, a deepwater gas field in the Norwegian Sea, is the second largest gas field on the NCS. Statoil has a 28.92% interest in the field. Statoil was operator for the development phase and 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 (Statoil's interest 7.604%), plus Tor (Statoil's interest 6.639%). Ekofisk has been upgraded with several new platforms over the years, the latest being the 2/4-M, which was installed in 2005. In early 2010 a final investment decision was made to construct a new Ekofisk accomodation and field centre platform. Several new projects are being studied: a new Ekofisk South drilling platform and redevelopments of Eldfisk and Tor. Final investment decisions were made in 2010 for Ekofisk South and Eldfisk. The new platforms are expected to extend the field life beyond the current licence period, which ends in 2028. 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 Statpipe. A final decision has been made to drill a fourth production well in late 2011, and a fifth production well is planned. Statoil has a 10% interest in the Skirne gas and condensate field, which is operated by Total. The field has two subsea templates with one well each. The well stream is transported to Heimdal for processing. From there, gas is transported in Vesterled or Statpipe. The condensate is transported from Brae to St Fergus in the UK. Statoil has an 11.78% interest in the Enoch field operated by Talisman. The field is a subsea development tied back to Brae A in the British sector. Production started in May 2007. Statoil, Annual report on Form 20-F 2010 35

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    Gjøa is located in the North Sea and has been developed with a subsea production system and a semi-submersible production platform. Statoil was the operator in the development phase, while GDF SUEZ took over as operator from production start-up in November 2010. Statoil will provide support and services to GDF SUEZ through a post-transfer agreement, and we continue to execute the drilling and completion of the production wells. Gas is exported via the 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 holds a 20% interest in Gjøa. 3.1.9 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). During the last three years, however, no Statoil-operated fields have been decommissioned. On partner-operated fields, there has been removal activity on Frigg and Ekofisk. For further information about decommissioning, see the note 25 to the Consolidated Financial Statements, Asset retirement obligations, other provisions and other liabilities. 36 Statoil, Annual report on Form 20-F 2010

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    3.2 International E&P 3.2.1 Introduction to International E&P Statoil is present in several of the most important oil and gas provinces in the world and International Exploration & Production will account for most of Statoil's future production growth. International Exploration & Production (INT) is responsible for exploration, development and production of oil and gas outside the Norwegian continental shelf. In 2010, the business area was engaged in production in 11 countries: Canada, the USA, Venezuela, Algeria, Angola, Libya, Nigeria, the UK, Azerbaijan, Russia and Iran. In 2010, INT produced 27 % of Statoil's total equity production of oil and gas, and INT's share is expected to increase significantly in the future. We have exploration licences in North America (Canada and the USA), South America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Mozambique, Nigeria and Tanzania), the European and Caspian area (the Faroes, Greenland, Ireland, the UK and Azerbaijan), and the Middle East and Asia (India, Iran and Indonesia). The main sanctioned development projects in which we are involved are in the USA and Angola. We believe we are well positioned for further growth through a substantial pre-sanctioned project portfolio, including a strengthened onshore USA position following the Eagle Ford acquisition. The map shows our exploration and production areas. Greenland Alaska ! Western Europe Russia ! ! Canada ! Caspian region USA ! ! ! North Africa Middle East ! ! ! ! ! ! West Africa South America ! East Africa Indonesia 110001_STN049013 ! Production as of 31.12.2010 Exploration 3.2.2 International E&P key events in 2010 International E&P's future growth ambitions have been further confirmed during 2010 through the sanctioning of a number of important projects. Equity production increased by 0.3% from 2009, to 514 mboe/day. Exploration activity has been significantly affected by the suspension of drilling activity in the US Gulf of Mexico (GoM). 18 exploration wells were completed during the year, with seven announcements of discoveries. Five wells were under evaluation at year end. Final investment decision has been made for a number of important projects during the year: Chirag Oil Project in Azerbaijan, which is a new phase in the Azeri-Chirag-Gunashli (ACG) development. Statoil, Annual report on Form 20-F 2010 37

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    CLOV in Block 17 in Angola BigFoot, Jack and St. Malo in the GoM In Salah Southern Fields in Algeria On 3 September, the Leismer Demonstration plant in Northern Alberta in Canada achieved its first steam. The first shipments by truck took place on 15 November. 3.2.3 Our International E&P portfolio To optimise our portfolio, we signed Joint Venture agreements with partners in Canada and in Peregrino off the coast of Brazil in 2010, while increasing our interest in several projects and broadening our US onshore gas portfolio with Eagle Ford. Statoil brought a partner into the Peregrino development in Brazil by agreeing to sell a 40% share to the Sinochem Group from China. The transaction is subject to governmental approvals in Brazil. We also brought a partner into our Canadian oil sands project by selling 40% share to PTT Exploration & Production PCL (PTTEP) from Thailand. The transaction was closed on January 2011. Major additions to our international portfolio in recent years include entry into the Marcellus shale gas play in the USA in 2008 and entry into the West Qurna 2 field in Iraq in late 2009. Statoil's main merger and acquistion (M&A) activities in 2010 and early 2011 are presented below. Acquisitions and licence rounds: In December 2009, Statoil and Lukoil submitted the winning bid for developing the West Qurna 2 field in Iraq's second licensing round. On 31 January 2010, Statoil and Lukoil signed a development and production contract for West Qurna 2 with the Iraqi authorities. The consortium of contractors consists of the Iraqi state's North Oil Company (25%), Lukoil (56.25%) and Statoil (18.75%). Lukoil is the operator for the project. The Preliminary Development Plan for West Qurna 2 was approved by Iraqi authorities in November 2010. In January 2010, we entered a deal with ConocoPhillips whereby we acquired a 25% interest in 50 leases in the Chukchi Sea in Alaska. The addition of these leases to the 16 previously acquired in Chukchi means we now have a sizable acreage portfolio to explore in the coming years. In January 2010, we increased our share in St. Malo in the US GoM from 6.25% to 21.5% by exercising our preemption rights. Statoil was awarded 21 deepwater leases in Central Lease Sale 213 in the US GoM in March 2010. Statoil increased its share in the Agbami field in Nigeria from 18.8%. to 20.2% with effect from 1 July 2010 as a result of an equity determination process. In September 2010, Statoil acquired 20.67% of Nautical Petroleum's interest in UK offshore licence P335, which contains the Mariner field. Statoil's share in Mariner after the transaction is 65.1%. The increased ownership interest in Mariner strengthens Statoil's position in offshore heavy oil, a core area in Statoil's international growth strategy. In October 2010, Statoil acquired 67,000 net acres in the Eagle Ford shale gas formation in Southwest Texas through agreements with Enduring Resources, LLC and Talisman Energy Inc.. This Eagle Ford position complements Statoil's existing US onshore portfolio, and entails supplying a different range of hydrocarbons to different markets. Statoil and Talisman have formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale. Talisman will operate the asset initially. Statoil will operate 50% of the acreage within three years of acquisition. The effective date of the transaction was 1 August 2010. In November 2010, Statoil was awarded operatorship of three new exploration licences on the UK continental shelf. Statoil was awarded 44.4% interest in one licence close to the Statoil-operated Mariner heavy oil discovery and 50% interest in two licences near the Faroe border. The commitments for the licence close to Mariner are a seismic survey and evaluation, while, for the two other licences, the commitment consists of reprocessing existing seismic surveys. In November 2010, Statoil was awarded interests in two large exploration blocks in the Baffin Bay bid round in Greenland, a 20.125% interest in block 5 and a 14.875% interest in block 8. Shell will be the operator for both blocks.These new frontier opportunities enhance our exploration portfolio. The commitment in the licences consists of acquiring seismic and carrying out a shallow core programme. In December 2010, Statoil was awarded interests in four new offshore licences in Canada: a majority share and operatorship in three licenses in the Flemish Pass Basin, and a 50% share in one licence in the Jeanne d'Arc Basin. The new acreage underlines Statoil's ambitions in the area. In January 2011 Sonangol announced that Statoil will be the operator of the Angolan pre-salt blocks 38 and 39 and be a participant in blocks 22, 25 and 40. Statoil will have 40% interest in blocks 38 and 39 and 20% interest in the other blocks. All blocks are in the Kwanza Basin offshore Angola. Formal granting of licences for all blocks is subject to the Angolan Ministry of Petroleum's decision of any appeal of the bid round jury's decision, and the successful negotiation of contractual terms including the terms of Production Sharing Agreements (PSAs). 38 Statoil, Annual report on Form 20-F 2010

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    Divestments and other reductions of Statoil's portfolio: With effect from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga production sharing agreement (PSA) with a 20% interest, thus reducing Statoil's share from 40% to 30%. Libyan State Oil Company (NOC) in Libya has renegotiated the PSA for Mabruk, and in January 2010, our equity share of production in Mabruk was reduced from 25.0% to 5.0% effective as of 1 January 2008. In May 2010, Statoil annouced entering a joint venture and the sale of 40% of the Peregrino field off the coast of Brazil to Sinochem Group. Statoil retains 60% ownership and operatorship of the field. Sinochem Group will pay a total of USD 3,070 million in cash. The divestment demonstrates substantial value creation on Statoil's part in the development phase and is a natural step in our continuous efforts to optimise our portfolio. Brazil will continue to be a key part of Statoil's international strategy. The transaction is subject to government approval in Brazil. In November 2010, Statoil announced the sale of a 40% interest in its Kai Kos Dehseh oil sands project in Alberta, Canada to PTTEP of Thailand. Statoil will retain 60% ownership and operatorship of the project. PTTEP paid a total of USD 2,280 million for the 40% interest. This transaction underlines the quality of our Canadian resources and demonstrates our ability to create value as an oil sands operator. The effective date of the transaction was 1 January 2011, pending governmental approvals which resulted in a closing date of 21 January 2011. 3.2.4 International exploration activity Statoil's strategy is to continuously access new exploration acreage with high resource potential and to maximise the number of high impact wells. We have exploration licences in North America (Canada and the USA), South America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Mozambique, Nigeria and Tanzania), Europe and the Caspian region (the Faroes, Greenland, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia). We have completed 18 wells in 2010, and six were ongoing at year end. Of the 18 wells, seven were announced as discoveries and five are currently under evaluation. We plan to drill about 20 wells in 2011. Statoil, Annual report on Form 20-F 2010 39

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    Areas with drilling or significant Statoil operated seismic activity in 2010: Chukchi Sea ! Canada Ireland !! ! UK ! Azerbaijan ! !! Egypt GoM ! Nigeria !! ! Angola Tanzania !! ! Brazil 110001_STN056270 Mozambique Exploration wells: ! Frontier ! Growth ! Near field ! Major seismic aquisitions The areas where we entered or had significant activity in 2010 are presented below. North America Canada Statoil is operator and partner in licences off the coast of Newfoundland, and we hold 1,129 square kilometres (279,053 acres) of oil sands leases in Alberta. Offshore Planning activities for the drilling of two Statoil-operated wells were initiated in 2010. As operator, we are planning to drill a well on our Mizzen discovery located in the Flemish Pass Basin and another on our Fiddlehead licence in the Jeanne d'Arc Basin in 2011/ 2012. In November 2010, re-entry drilling operations started on the Ballicatters M-96Z well. This well is operated by Suncor and Statoil has a 50% interest. In December 2010, Statoil was awarded interests in four new licences off the coast of Canada. The new acreage underlines the company's ambitions in the area. The licences include a significant discovery licence (SDL) and three exploration licences off the coast of Newfoundland. The licences were awarded through a land sale issue by the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB). These licences provide further growth opportunities near our Mizzen discovery in the Flemish Pass Basin and near existing infrastructure in the Jeanne d'Arc Basin, as well as more frontier opportunities. Statoil is operator and has a 65% interest in the SDL, which is an extension of Statoil's current Mizzen licence, and in the exploration licence located in the vicinity of the Mizzen SDL. Statoil is operator with a 75% interest in the exploration licence situated in the northern part of the Flemish Pass Basin and a partner with a 50% interest in the exploration licence located in the Jeanne d'Arc Basin. Oil sands We currently have an interest in 1,129 square kilometres (279,053 net acres) of oil sands leases located in the Athabasca region of Alberta. In order to determine the extent of the exploitable oil sands deposits in Alberta, a total of more than 650 wells were drilled in the region from 2003 to 2010. Extensive seismic surveys were also carried out during the same period. 40 Statoil, Annual report on Form 20-F 2010

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    In the 2009-2010 winter drilling programme, wells were drilled that are required for delineation, observation and water source or disposal purposes for near-term development phases. Additional drilling for delineation, observation, and water source or disposal purposes and further seismic surveys are under way at year end 2010 as part of the 2010-2011 winter drilling programme. Our oil sand activities are described in more detail in section Operational review - International E&P fields in development and production-North America- Canada. The USA We have significant activities in the USA, with more than 400 leases in the Gulf of Mexico and 66 in Alaska. Drilling activity was reduced in 2010 as a result of the Gulf of Mexico drilling moratorium. United States Houston ! ( 17 Hands (25%) Thunder Hawk (25%) Destin Dome Zia (35%) San Jacinto (26.67%) De Soto Canyon Lorien (30%) Mississippi Canyon Vito (25%) Knotty Head (25%) Tahiti (25%) Front Runner (25%) Spiderman (18.3%) East Breaks Garden Banks Green Canyon Lloyd Ridge Atwater Valley Caesar/Tonga (23.55%) Port Big Foot (27.5%) Isabel Keathley Canyon Henderson Alaminos Canyon Lund Julia (50%) Walker Ridge Heidelberg (12%) 110001_STN049027 Jack (25%) St Malo (21.5%) Map as of 31 December 2010 xxx Discoveries xxx Producing fields ( Office ! Licences with Statoil interests US Gulf of Mexico During 2010, we participated in seven exploration and appraisal wells, four of which had reached reservoir depth prior to the imposition of the drilling moratorium resulting from the Macondo incident. Appraisal and delineation activity on the Vito and Heidelberg discoveries has been suspended but is scheduled to resume in 2011. Statoil's operated drilling programme, consisting of the Tucker appraisal and Krakatoa exploration wells, was also suspended due to the drilling moratorium. We have endeavoured to reduce financial losses by using the Discoverer Americas, a drillship used in the Gulf of Mexico prior to the drilling moratorium, to drill an exploration well on our Egypt acreage and by sub-letting the Maersk Developer, a semi-submersible used in the Gulf of Mexico prior to the drilling moratorium, in the Gulf of Mexico. Meanwhile we continue to high grade our exploration portfolio and we expect to resume drilling in the Gulf of Mexico towards the end of the first half of 2011. As a result of the accident on the BP-operated Macondo well in the Gulf of Mexico in April 2010, a four-and-a-half-month moratorium on certain deepwater drilling in the Gulf of Mexico region was imposed, new regulatory initiatives were implemented and further changes and additions to laws and regulations are currently under review in the US. The future effects of this accident, including any new or additional regulations that may be adopted in response, are not fully known at this time. Although the drilling moratorium was lifted on 12 October 2010, operators may not re-commence drilling activity until they certify compliance with all rules and requirements, including availability of adequate blow-out response resources. The US Bureau of Ocean Energy Management, Regulation & Enforcement has stated that Statoil is one of thirteen operators that may not need to submit revised exploration plans or development operations coordination documentation in order to re-commence its drilling activity. Statoil has worked in recent months to comply with all rules and requirements, and we are in the Statoil, Annual report on Form 20-F 2010 41

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    process of completing the work necessary so that our two rigs that were drilling in the Gulf of Mexico prior to the drilling moratorium can resume drilling. We expect the drilling for Statoil in the Gulf of Mexico to resume towards the end of the first half of 2011. The first new permit for the drilling of a deepwater well (apart from water injection and side track wells) was issued at the end of February 2011. There remains industry-wide uncertainty around the pace at which new drilling activity will be restored. Statoil remains committed to deepwater exploration and development in the Gulf of Mexico and other deepwater basins around the world. See the section Risk review - Risk factors - Risks related to increased regulation and regulatory compliance and section Operational review - Regulation - HSE regulation. We were awarded 21 deepwater leases in Central Lease Sale 213 held in March 2010, including 14 with partner BHP Billiton. Alaska Statoil carried out a successful 3D seismic survey over our operated leases and the surrounding acreage in the Chukchi Sea, Alaska. More than 2,600 square kilometers of high quality seismic data were acquired during the ice-free season in August and September. There was extensive stakeholder engagement with local communities. There were no safety or environmental incidents. The data are now being interpreted. Statoil also participated in gathering extensive baseline science data in the Chukchi Sea this summer. Shale Gas Exploration activity related to onshore shale gas in the USA is presented in section Operational review-International E&P-International fields in development and production. Latin America Brazil We have interests in nine exploration licences in four different basins in waters off the coast of Brazil. We are the operator for four of the licences. We have completed one well in BM-C-33 and one in BM-ES-29. This BM-CAL-7 & 10 fulfilled our commitments in these licences. The second exploration period Camamu-Almada Basin in BM-C-33 has begun, and drilling of the commitment well started in November. In addition, we have one commitment well in Statoil-operated ! ! BM-CAL-10 and BM-C-47 and one in the partner-operated BM-CAL-7. Brasilia Rig capacity that will enable us to complete our commitment wells in BM- CAL-10 and BM-C-47, has been secured. Indra, in BM-ES-32, was Brazil announced as an oil discovery in December 2010. Espirito-Santo Basin BM-ES-32 Statoil will operate a total of three exploration wells in 2011. Two of them BM-ES-29 will be drilled in the Peregrino area. The objective of these wells is to prove Rio de Janeiro some of the upsides we believe are present in the Peregrino area. ! ( BM-C-7 Campos Basin BM-C-33 BM-C-47 The interests in three blocks that we won in the eighth round in the Santos Peregrino basin are pending award. 110001_STN056268 SM-1105, 1109 & 1233* Santos Basin * Bids won in 8th Round, pending government approval xxx Discoveries Licenses with Statoil interests ! ( Office ! ! Capital 42 Statoil, Annual report on Form 20-F 2010

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