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    ANNUAL REPORT /2012 Annual Report on Form 20-F


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    ANNUAL REPORT /2012 Annual Report on Form 20-F The Annual Report on Form 20-F is our SEC filing for the fiscal year ended December 31, 2012, as submitted to the US Securities and Exchange Commission. The complete edition of our Annual Report is available online at www.statoil.com/2012 © Statoil 2013 STATOIL ASA BOX 8500 NO-4035 STAVANGER NORWAY TELEPHONE: +47 51 99 00 00 www.statoil.com Cover photo: Ole Jørgen Bratland


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    Annual report on Form 20-F Cover Page 1 1 Introduction 3 1.1 About the report 3 1.2 Key figures and highlights 4 2 Strategy and market overview 5 2.1 Our business environment 5 2.1.1 Market overview 5 2.1.2 Oil prices and refining margins 6 2.1.3 Natural gas prices 6 2.2 Our corporate strategy 7 2.3 Our technology 9 2.4 Group outlook 10 3 Business overview 11 3.1 Our history 11 3.2 Our business 12 3.3 Our competitive position 12 3.4 Corporate structure 13 3.5 Development and Production Norway (DPN) 14 3.5.1 DPN overview 14 3.5.2 Fields in production on the NCS 15 3.5.2.1 Operations North 17 3.5.2.2 Operations North Sea West 18 3.5.2.3 Operations North Sea East 19 3.5.2.4 Operations South 19 3.5.2.5 Partner-operated fields 20 3.5.3 Exploration on the NCS 20 3.5.4 Fields under development on the NCS 22 3.5.5 Decommissioning on the NCS 23 3.6 Development and Production International (DPI) 24 3.6.1 DPI overview 24 3.6.2 International production 25 3.6.2.1 North America 27 3.6.2.2 South America and sub-Saharan Africa 28 3.6.2.3 Middle East and North Africa 29 3.6.2.4 Europe and Asia 29 3.6.3 International exploration 30 3.6.4 Fields under development internationally 32 3.6.4.1 North America 32 3.6.4.2 South America and sub-Saharan Africa 33 3.6.4.3 Middle East and North Africa 33 3.6.4.4 Europe and Asia 33 3.7 Marketing, Processing and Renewable Energy (MPR) 35 3.7.1 MPR overview 35 3.7.2 Natural Gas 35 3.7.2.1 Gas sales and marketing 36 3.7.2.2 The Norwegian gas transportation system 38 3.7.2.3 Processing 38 3.7.3 Crude oil, liquids and products 39 3.7.3.1 Marketing and trading 39 3.7.3.2 Processing and transportation 39 3.7.4 Processing and manufacturing 40 3.7.5 Renewable energy 42 3.8 Statoil Fuel & Retail 43 3.9 Other Group 44 3.9.1 Global Strategy and Business Development (GSB) 44 3.9.2 Technology, Projects and Drilling (TPD) 44 3.9.3 Corporate Staffs and Services 46 3.10 Significant subsidiaries 47 3.11 Production volumes and prices 48 3.11.1 Entitlement production 49 3.11.2 Production costs and sales prices 50 3.12 Proved oil and gas reserves 51 3.12.1 Development of reserves 54 3.12.2 Preparations of reserves estimates 55 3.12.3 Operational statistics 56 3.12.4 Delivery commitments 58


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    3.13 Applicable laws and regulations 59 3.13.1 The Norwegian licensing system 59 3.13.2 Gas sales and transportation 61 3.13.3 HSE regulation 61 3.13.4 Taxation of Statoil 62 3.13.5 The Norwegian State's participation 63 3.13.6 SDFI oil and gas marketing and sale 63 3.14 Property, plants and equipment 65 3.15 Related party transactions 65 3.16 Insurance 65 3.17 People and the group 66 3.17.1 Employees in Statoil 66 3.17.2 Equal opportunities 67 3.17.3 Unions and representatives 67 4 Financial review 68 4.1 Operating and financial review 2012 68 4.1.1 Sales volumes 68 4.1.2 Group profit and loss analysis 70 4.1.3 Segment performance and analysis 74 4.1.4 DPN profit and loss analysis 77 4.1.5 DPI profit and loss analysis 79 4.1.6 MPR profit and loss analysis 81 4.1.7 Other operations 83 4.1.8 Definitions of reported volumes 84 4.2 Liquidity and capital resources 85 4.2.1 Review of cash flows 85 4.2.2 Financial assets and liabilities 86 4.2.3 Investments 88 4.2.4 Impact of inflation 90 4.2.5 Principal contractual obligations 90 4.2.6 Off balance sheet arrangements 91 4.3 Accounting Standards (IFRS) 91 4.4 Non-GAAP measures 92 4.4.1 Return on average capital employed (ROACE) 92 4.4.2 Unit of production cost 93 4.4.3 Net debt to capital employed ratio 94 5 Risk review 95 5.1 Risk factors 95 5.1.1 Risks related to our business 95 5.1.2 Iran-related activity 100 5.1.3 Legal and regulatory risks 100 5.1.4 Risks related to state ownership 102 5.2 Risk management 103 5.2.1 Managing financial risk 103 5.2.2 Disclosures about market risk 105 5.3 Legal proceedings 105 6 Shareholder information 106 6.1 Dividend policy 108 6.1.1 Dividends 108 6.2 Shares purchased by issuer 110 6.2.1 Statoil's share savings plan 110 6.3 Information and communications 111 6.3.1 Investor contact 111 6.4 Market and market prices 112 6.4.1 Share prices 112 6.4.2 Statoil ADR programme fees 113 6.5 Taxation 115 6.6 Exchange controls and limitations 119 6.7 Exchange rates 119 6.8 Major shareholders 120 7 Corporate governance 122 7.1 Articles of association 122 7.2 Ethics Code of Conduct 124 7.3 General meeting of shareholders 125 7.4 Nomination committee 127 7.5 Corporate assembly 127 7.6 Board of directors 130 7.6.1 Audit committee 134 7.6.2 Compensation committee 135 7.6.3 HSE and ethics committee 135


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    7.7 Compliance with NYSE listing rules 136 7.8 Management 137 7.9 Compensation paid to governing bodies 141 7.10 Share ownership 147 7.11 Independent auditor 148 7.12 Controls and procedures 150 8 Consolidated financial statements Statoil 151 8.1 Notes to the Consolidated financial statements 156 8.1.1 Organisation 156 8.1.2 Significant accounting policies 156 8.1.3 Change in accounting policy 165 8.1.4 Segments 166 8.1.5 Acquisitions and dispositions 170 8.1.6 Financial risk management 172 8.1.7 Remuneration 175 8.1.8 Other expenses 176 8.1.9 Financial items 176 8.1.10 Income taxes 177 8.1.11 Earnings per share 179 8.1.12 Property, plant and equipment 180 8.1.13 Intangible assets 182 8.1.14 Non-current financial assets and prepayments 183 8.1.15 Inventories 184 8.1.16 Trade and other receivables 184 8.1.17 Current financial investments 184 8.1.18 Cash and cash equivalents 185 8.1.19 Shareholders' equity 185 8.1.20 Bonds, bank loans and finance lease liabilities 185 8.1.21 Pensions 187 8.1.22 Provisions 192 8.1.23 Trade and other payables 193 8.1.24 Bonds, bank loans, commercial papers and collateral liabilities 193 8.1.25 Leases 193 8.1.26 Other commitments and contingencies 194 8.1.27 Related parties 195 8.1.28 Financial instruments: fair value measurement and sensitivity analysis of market risk 196 8.1.29 Condensed consolidating financial information related to guaranteed debt securities 202 8.1.30 Supplementary oil and gas information (unaudited) 208 8.2 Report of Independent Registered Public Accounting firm 218 8.2.1 Report of Independent Registered Public Accounting Firm 218 8.2.2 Report of Independent Registered Public Accounting Firm 219 8.2.3 Report of KPMG on Statoil's internal control over financial reporting 220 9 Terms and definitions 221 10 Forward looking statements 224 11 Signature page 225 12 Exhibits 226 13 Cross reference to Form 20-F 227


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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, 2012 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 2012 1 Document last updated 21-03-2013 18:38 CET


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    Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report. Ordinary shares of NOK 2.50 each 3,188,647,103 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes No If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes  No Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections. Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes No Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).** Yes No **This requirement does not apply to the registrant in respect of this filing. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer  Accelerated filer Non-accelerated filer Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: U.S. GAAP International Financial Reporting Standards as issued Other by the International Accounting Standards Board  If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. Item 17 Item 18 If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No 2 Statoil, Annual report on Form 20-F 2012


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    1 Introduction 1.1 About the report Statoil's Annual Report on Form 20-F for the year ended 31 December 2012 ("Annual Report on Form 20-F") is available online at www.statoil.com/2012. 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 can also call the SEC at 1-800-SEC-0330 for further information about the public reference rooms and their copy charges, or you can 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 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. Statoil, Annual report on Form 20-F 2012 3


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    1.2 Key figures and highlights Statoil's financial results and cash flows were solid in 2012. Production was up 8%, important strategic progress was made and the balance sheet was further strenghtened. Statoil publishes financial data in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU). For the year ended 31 December (in NOK billion, unless stated otherwise) 2012 2011 2010 2009 2008 Financial information Total revenues and other income 723.4 670.2 529.9 465.4 656.0 Net operating income 206.6 211.8 137.3 121.7 198.8 Net income 69.5 78.4 37.6 17.7 43.3 Bonds, bank loans and finance lease liabilities 101.0 111.6 99.8 96.0 75.3 Net interest-bearing liabilities before adjustments 39.3 71.0 69.5 71.8 46.0 Total assets 784.4 768.6 643.3 563.1 579.2 Share capital 8.0 8.0 8.0 8.0 8.0 Non-controlling interest 0.7 6.2 6.9 1.8 2.0 Total equity 319.9 285.2 226.4 200.1 216.1 Net debt to capital employed ratio before adjustments 10.9% 19.9% 23.5% 26.4% 17.8% Net debt to capital employed ratio adjusted 12.4% 21.1% 25.5% 27.6% 18.8% Calculated ROACE based on Average Capital Employed before adjustments 18.7% 22.1% 12.6% 10.6% 21.0% Operational information Equity oil and gas production (mboe/day) 2,004 1,850 1,888 1,962 1,925 Proved oil and gas reserves (mmboe) 5,422 5,426 5,325 5,408 5,584 Reserve replacement ratio (three-year average) 1.0 0.9 0.6 0.6 0.6 Production cost equity volumes (NOK/boe, last 12 months) 42 42 38 35 35 Share information Diluted earnings per share NOK 21.60 24.70 11.94 5.74 13.58 Share price at Oslo Stock Exchange on 31 December in NOK 139.00 153.50 138.60 144.80 113.90 Dividend paid per share NOK (1) 6.75 6.50 6.25 6.00 7.25 Dividend paid per share USD (2) 1.21 1.08 1.07 1.04 1.26 Weighted average number of ordinary shares outstanding (in thousands) 3,181,546 3,182,113 3,182,575 3,183,874 3,185,954 (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 2012 dividend for approval at the Annual General Meeting scheduled for 14 May 2013. (2) USD figure presented using the Central Bank of Norway 2012 year-end rate for Norwegian kroner, which was USD 1.00 = 5.57 NOK. The board of directors will propose the 2012 dividend for approval at the Annual General Meeting scheduled for 14 May 2013. 4 Statoil, Annual report on Form 20-F 2012


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    2 Strategy and market overview 2.1 Our business environment 2.1.1 Market overview Recovery following the 2008 financial crisis has been muted and fragile. Growth in OECD economies has been low, which has dampened economic activity in the non-OECD area. Nevertheless, non-OECD expansion continues at a relatively solid pace and supports global economic growth and energy demand. It became clear in 2012 that the OECD countries' economic recovery from the aftermath of the financial crisis in 2008 will be a long process, involving a fine balance between fiscal tightening and growth stimulus. Debt levels and fiscal deficits are high in key OECD economies and must be brought onto a sustainable path in order to avoid increasing debt servicing costs. At the same time, growth is critical to achieving such a reduction. Statoil therefore believes that it is important to avoid austerity measures that dampen growth too much. Achieving both is a difficult balancing act. Fortunately for global growth and also for global energy demand, growth has persisted in non-OECD economies, which means export opportunities for competitive OECD producers. In total, however, global economic growth was significantly lower in 2012 than in 2011. The current trends of low growth in the OECD economies and continued development in non-OECD countries are expected to continue, with expected global economic growth of around 3% annually over the next 10 years, comprising 2% annual growth in the OECD economies and 5.2% annual growth in non-OECD economies. This means that the global weighted geographical point of economic gravity continues to move gradually eastwards and southwards relative to the OECD economies in Europe and North America. Energy-dependent growth in the non-OECD economies is expected to contribute to growth in global energy demand over the next decade, including oil demand. Statoil's research suggests that annual growth in global oil demand will average 0.9% (~0.8 mbd). As a result of increases in tight oil production and an expected increase in Iraqi production, among other factors, this will mean a medium-term weakening of fundamentals in the global oil market as measured by Opec spare capacity. In the longer term, Statoil expects increased demand for Opec liquids and thereby a larger market share for Opec. Medium-term price development depends on the balance between moderately weakening fundamentals, marginal costs and geopolitical uncertainty premiums due to supply risks. Global gas demand is expected to increase due to the general increase in energy demand, but also due to the increasing competitiveness of gas in terms of costs and environmental effects. Growth in gas demand is therefore also very dependent on energy and climate policies in key countries and regions. Statoil's internal research suggests that gas demand in Europe and North America will increase by 1-2% per year until 2020, while Asian demand will grow by 4-5% per year in the same period. Both Europe and Asia will depend on imported LNG to meet demand, which will contribute to keeping prices at robust levels. The very low gas prices in North America, which are caused by the development of the shale gas industry, are expected to gradually increase as the market situation normalises, but to remain below European and Asian gas prices. The global economic situation continues to be fragile, with development in large part driven by uncertain political environments in key countries and regions, in addition to normal supply and demand factors. Consequently, energy prices could vary considerably in the short to medium term. Production to reserve growth continues to remain a key challenge for international oil companies. Balancing the need for short-term production growth with long-term reserve growth is key to long-term success. We believe Statoil's average production growth rate is highly competitive, especially in combination with our recent exploration results. Increasing competition, tighter fiscal conditions and increasing costs pose challenges for access to new profitable resources. It is anticipated that oil companies, including Statoil, will continue to respond to these challenges with varying changes in their portfolios, including access to unconventional oil and gas assets, increasing exploration activities and cost and portfolio management actions. Going forward, fighting decline of legacy fields and increasing technical challenges in new field developments are expected to put upward pressure on capital and operational expenditure. Companies that are at the forefront of efficient resource management and effective development and utilisation of new technology will be best equipped to meet these challenges. Statoil, Annual report on Form 20-F 2012 5


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    2.1.2 Oil prices and refining margins The year 2012 saw strong prices for Brent crude and significant volatility. The refinery margin improved significantly compared to 2011. Oil prices The average price for Brent crude in 2012 was close to USD 111.53/bbl, slightly above the 2011 average of USD 111.41/bbl. The 2011 average represented a record-high price for crude, and 2012 set a new record. During the first quarter, Brent prices gradually rose from around USD 110/bbl to USD 130/bbl. Prices then dropped through most of the second quarter before they bottomed out below USD 90/bbl in late June. However, the market quickly recovered and stabilised; prices stayed within a narrow range between USD 105 and 115/bbl through most of the second half-year. With the exception of a few days in June, the market has been in fairly strong backwardation (see section Terms and definitions) throughout 2012. The WTI price started 2012 at around USD 103/bbl and peaked at the end of February at USD 109/bbl. After a strong start, the WTI price began to drop at the beginning of May and bottomed out around USD 78/bbl at the end of June. It recovered during the third quarter, peaking at USD 97/bbl before it stabilised in the range of USD 85-92/bbl. The 2012 average was close to USD 96/bbl. Geopolitical factors were the main driver for oil prices in 2012. Although Libyan oil production was approaching pre-civil war levels by early spring, a string of production disruptions in smaller producing countries, such as Sudan, South Sudan, Yemen and later Syria, kept oil supplies curtailed. From the start of the year, the tensions between the Western powers and Iran over Tehran's nuclear programme intensified. Fear of potential air strikes explained much of the strength in prices during early spring. Markets were increasingly worried that the Straits of Hormuz would be blocked in the event of an armed conflict, which could mean that almost 20% of global oil supplies would be unable to exit the Persian Gulf. In addition, a ban was imposed on all imports of Iranian crudes to EU countries, and US sanctions on any bank or financial intermediary that is found to be dealing with the Iranian regime were enacted. As a result, Iranian exports gradually dwindled from almost 2 mb/d in December 2011 to around 1 mb/d in the fourth quarter of 2012. Saudi Arabia responded to this strong market by producing more oil, touching previous all-time-high production levels around 10 mboe per day during spring 2012. This coincided with the period of the year with lowest demand, and led to an oversupply of crude and briefly brought prices below USD 90/bbl in June. Prices quickly recovered, however, and Brent stabilised at levels near USD 110/bbl for the remainder of the year. Market fundamentals tightened rapidly as a result of seasonally stronger oil demand, the growing effect of sanctions on Iran, and significant supply loss from field maintenance and weather-related shutdowns in the North Sea, Brazil and the Caspian region. Persistently high Saudi output meant that the effective Opec spare capacity stayed low throughout the year. Rising concern about both short and long-term stability in the Middle East as a result of the Syrian civil war provided price support. The market for crude oil has remained strong despite weak economic growth performance, especially in the developed world. Growth in oil demand is well below earlier years. Global growth in oil demand in 2012 was about 0.7 million barrels per day (mb/d) or 0.8%, even lower than the weak growth experienced in 2011. Furthermore, the debt crisis in the Eurozone, the lacklustre recovery in the US and slowing growth in China opened up a major downside risk. Refinery margin The refinery margin improved significantly in 2012 due to refinery maintenance in Northwest Europe and the east coast of the USA. The lower capacity in the Atlantic Basin contributed especially to high margins during the second and third quarter of 2012. Statoil's refining reference margin was USD 5.5/bbl in 2012 compared to 2.3 in 2011, an increase of 138%. The refining reference margin was USD 3.9/bbl in 2010. 2.1.3 Natural gas prices Natural gas prices in Europe were 5% higher on average in 2012 than they were in 2011, despite weaker demand. In North America, prices have fallen to their lowest levels of the decade. Gas prices - Europe Natural gas prices in Europe were 5% higher on average in 2012 than they were in 2011, despite weaker demand. The continued economic problems in Europe resulted in subdued demand. However, the supply situation was tight across Europe because of declining domestic production and Europe's increased reliance on imported gas. 6 Statoil, Annual report on Form 20-F 2012


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    Coal and carbon prices weakened further in 2012 which has reinforced coal's competitive position relative to gas in power generation. Increased renewable generation, especially in Germany, has also displaced gas demand. Falling gas generation combined with weaker industrial and residential demand has seen overall demand fall by 3% in Europe. The availability of LNG imports to Europe has been constrained due to the strong demand in Asia. Imports of LNG to Europe fell by 25% and imports to Asia rose by 11% in 2012. Following the Fukushima disaster, only two of Japan's 54 nuclear reactors are in operation, so Japan has been reliant on fuel imports, especially LNG, to replace the lost nuclear output. Further potential upside pressure is expected from nuclear outages in South Korea. Gas prices - North America The year 2012 was a year of extremes in the North American gas market, having set three records: warmest winter, largest coal-to-gas switching, and highest domestic production. Setting the stage for the year, the mild winter coupled with production growth of 4% compared to 2011 led to record storage inventories coming out of the winter withdrawal season. As a result, prices have fallen to their lowest levels of the decade, averaging just USD 2.60 per million British thermal unit (MMBtu) to date in 2012, down 35% from USD 3.74 per MMBtu in 2011. One of the warmest summers ever recorded helped to balance the market. In addition to the increased cooling demand, the low gas prices drove gas to outcompete coal for power generation. In 2012, gas demand for power increased by 50 Bcm/a compared to 2011, helping to substantially reduce the oversupply in the US market. In addition, the low price environment and reduced demand for imported gas in the US has reduced incentives for drilling Canadian gas, leading to a 10 Bcm/a decline in production. Looking ahead, the number of gas rigs has fallen over 50% to just 420 rigs, suggesting a potential future decline in domestic production going forward. Initial signs of a tightening market are present, which is something not seen since 2009. However, low-cost supply remains abundant, which could serve to slow or prevent any increase in price. The very low gas prices in North America are expected to gradually increase as the market situation normalises, but to remain below European and Asian gas prices. 2.2 Our corporate strategy Statoil aims to grow and enhance value through its technology-focused upstream strategy, supplemented by selective positions in the midstream and in low-carbon technologies. Statoil's immediate priorities remain to conduct safe, reliable operations with zero harm to people and the environment, and to deliver profitable production growth. To succeed going forward we continue to focus strategically on the following: Revitalising Statoil's legacy position on the Norwegian continental shelf (NCS) Building offshore clusters Developing into a leading exploration company Increasing our activity in unconventional resources Creating value from a superior gas position Continuing portfolio management to enhance value creation Utilising oil and gas expertise and technology to open new renewable energy opportunities. Revitalising Statoil's legacy position on the NCS The NCS remains a prolific and productive oil and gas province where only half of the resources have been produced. The Havis discovery in 2012 has increased expectations of the exploration potential of the Barents Sea. Furthermore, the Johan Sverdrup discovery and appraisal have stimulated efforts to make additional discoveries in the more mature North Sea. Between now and 2020, Statoil aims to bring on stream new production from a combination of: Developments of larger discoveries, including Aasta Hansten, Gina Krog (formerly Dagny), Skrugard/Havis and Johan Sverdrup fields, which are expected to contribute considerably to Statoil's total production towards the end of this decade. Developments of a number of smaller discoveries in our fast-track portfolio. High activity on improved oil recovery (IOR) projects. Statoil's ambition is to increase oil recovery on the NCS to 60% over time. Building offshore clusters Statoil's international oil and gas production has increased from around 100,000 boe to around 650,000 boe per day since the year 2000. Statoil has established a presence in many countries and built a strong portfolio of assets outside Norway. To further enhance the materiality of our international portfolio, we are focusing on potential offshore clusters. Clusters are areas that make a material contribution to total production, where Statoil holds operatorships and has a mix of assets in different stages of development, and where we possess considerable expertise, both below and above ground. Through the cluster focus, our goal is to achieve greater economies of scale, capture synergies and thereby increase profitability. Statoil, Annual report on Form 20-F 2012 7


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    Our potential clusters are located in some of the most attractive basins in the industry, including: Brazil; where we continue to work on ramping up Peregrino production. In the future, we will focus on further developing the Peregrino area and maturing the existing exploration portfolio. In 2012, we extended our exploration portfolio and made several new discoveries. Angola; where we are working to optimise our non-operated portfolio. In 2012, Pazflor was successfully ramped up and the PSVM (the Plutao, Saturno, Venus and Marte oilfields) project came on stream in December. We continue to mature our exploration acreage, gathering seismic data for parts of our pre-salt acreage that was awarded in 2011. Tanzania; which emerged as a new potential cluster in 2012, and where we have made several large gas discoveries. Developing into a leading exploration company We had a successful year of exploration due to our dedicated focus on the three exploration strategy pillars: Early access at scale: We have focused on access to frontier acreage over the last few years and have been an early mover in several areas. The ongoing negotiations with Rosneft for access to three blocks in the Sea of Okhotsk and one block in the Russian Barents Sea represent a potential breakthrough for future exploration success in Russia. Exploit core positions: We have secured more acreage in potential clusters such as the US Gulf of Mexico. Furthermore, on the NCS, we have maintained high focus on growth and ILX wells with significant potential. Acreage applications in both the awards in predefined areas (APA) and 22nd license round have given Statoil access to promising new high-value prospects. Drill more significant wells: We made several significant discoveries in 2012, including in Norway (Havis and King Lear), Tanzania (Zafarani and Lavani) and in Brazil (Pão de Açúcar). To replicate this success, we aim to continue balancing our exploration portfolio in potential offshore clusters with frontier exploration and more high-impact wells to unlock new plays. Stepping up our activity in unconventional resources Our unconventional resources portfolio is diverse. It includes leases in the shale gas and oil basins of Marcellus, Eagle Ford and Bakken in the US. In addition, we are maturing our Alberta, Canada Kai Kos Deh Seh and Corner oil sands projects. In 2012, we secured operational control over leases in Eagle Ford and Marcellus to further enhance our control over these assets. Our priorities in unconventional resources include: Delivering profitable ramp up Developing and executing a technology development programme for unconventional resources Expanding acreage holdings around our current upstream positions Further building for the long term through early access to land that can be developed in due course Creating value from a superior gas position The dynamics of the gas markets in Europe are changing. There is a development towards a more liberalised market with new players and increased competition. Our gas reserves are located close to the markets, we have flexible production capabilities and transportation systems, and our commercial experience in gas sales and trading has a proven track record. This puts us in a unique position to take advantage of the evolving European gas markets. In the short term, we are making considerable efforts to maximise the value of our gas in this market. In the medium to long term, we will continue to promote gas as an important part of meeting European objectives for energy security and emission reductions. We strongly believe that natural gas is the most cost-effective bridge to a low-carbon economy. Beyond Europe, our planned midstream gas and liquids activities in North America are progressing in step with the building of our upstream unconventional resources business. These activities encompass a mix of capacity commitments, ownership and/or operation of gathering, transportation and storage facilities, marketing alliances and trading operations. They are considered important to meet our goals for flow assurance and margin capture. Continuing portfolio management to enhance value creation By being proactive, we intend to further enhance our portfolio in the years ahead, so that it will ultimately be more valuable, more robust and more sustainable beyond 2020. The strategic focus in these endeavours will be to access exploration acreage and unconventional reserves, secure operatorships, build cluster positions, manage asset maturity, de-risk positions and demonstrate the intrinsic value of the portfolio. Transactions in 2012 include the NCS asset package sale to Centrica and the divestment of Statoil Fuel and Retail (both transactions are closed) and Wintershall (pending governmental approval). They further underpin our ability to redeploy capital and create value. Utilising oil and gas expertise and technology to open new renewable energy opportunities Growing demand for clean energy is creating new renewable and low-carbon technology business opportunities. Our core capabilities and expertise put us in a position to seize these opportunities in two specific areas: offshore wind and carbon capture and storage (CCS). 8 Statoil, Annual report on Form 20-F 2012


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    In 2012, we commissioned the offshore wind Sheringham Shoal development in the UK. We acquired another UK offshore wind development project, Dudgeon, to utilise the experience we had gained to develop this and other new projects. In addition, work is continuing on developing the proprietary Hywind floating offshore wind concept. Our ambition is to play an active role in reducing costs and making offshore wind profitable, ultimately without government subsidies or support. CCS represents a key technology for reducing carbon emissions. We have become a world leader in the development and application of CCS, and we intend to build on our carbon storage experience (the Sleipner, In Salah and Snøhvit projects) to position ourselves for a future commercial CCS business. We are maturing two carbon capture projects at present - the large-scale Technology Centre Mongstad testing facility and the full-scale Carbon Capture Mongstad plant. 2.3 Our technology We continually develop and deploy innovative technologies to achieve safe and efficient operations and deliver on our strategic objectives. We have defined four business-critical aspirations that we will strive to achieve over the next decade. We believe that technology is a critical success factor in the business environment within which we operate. This environment is characterised by an increasingly broad and complex opportunity set, stricter demands on our licence to operate and tougher competition. In this context, technology is increasingly important for resource access, value creation and growth. Our track record demonstrates our ability to overcome significant technical challenges through the development and deployment of innovative technologies. At present, we believe we are an industry leader in subsurface production and multiphase pipeline transportation. Our technology strategy, "Putting technology to work", supports our business strategy and strengthens our position as a technology-driven upstream company. It is based on three main principles: Prioritising business-critical technologies Strengthening our licence to operate Expanding our capabilities Prioritising business-critical technologies In order to deliver on our strategic objectives for 2020, we strive to meet four business-critical technology goals: To be an industry leader in seismic imaging and interpretation based on proprietary technology in order to increase our discovery rates To achieve breakthrough performance on reservoir characterisation and recovery to maximise value A step change in well construction efficiency to drill more cost-effective wells To develop and operate "longer, deeper and colder" subsea technologies in order to increase production and recovery, and pave the way for Statoil's future "subsea factory" Strengthening our licence to operate In order to secure our licence to operate, we must continuously focus on technologies for safe, reliable and efficient operations, as well as supporting integrity management. We are committed to developing and implementing energy-efficient and environmentally sustainable solutions. Expanding our capabilities Succeeding in a highly competitive environment will require more than just a strong focus and heavy investments. It will require the ability to build on competitive advantages, stimulate innovation and take a long-term view on selected potentially high-impact technology ventures. To do this, we will: Specify asset-specific requirements and execution plans to introduce new solutions Provide incentives for and reward those ventures that solve complex technical problems through innovative solutions, particularly when combined with prudent risk management Continuously adapt our collaborative way of working with partners and suppliers on a global basis Statoil, Annual report on Form 20-F 2012 9


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    2.4 Group outlook Statoil's defined ambition is to grow equity production towards 2020. Equity production in 2013 is estimated to be lower than the 2012 level. Organic capital expenditures for 2013 are estimated at around USD 19 billion. Organic capital expenditures for 2013 (i.e. excluding acquisitions and capital leases) are estimated at around USD 19 billion. Statoil will continue to mature its large portfolio of exploration assets and expects to complete around 50 wells in 2013, with a total exploration activity level of around USD 3.5 billion, excluding signature bonuses. Our ambition for unit of production cost continues to be in the top quartile of our peer group. Planned maintenance is expected to have a negative impact of around 45 mboe per day on equity production for the full year 2013, most of which consists of liquids. Statoil's defined ambition is to grow equity production towards 2020. The growth is expected to come from new projects. The growth towards 2020 will not be linear, and equity production in 2013 is estimated to be lower than the 2012 level. The impact on production of the closing of the Wintershall transaction will be around 40 mboe per day. Growth in US onshore gas production is expected to be around 25 mboe lower per day than previously assumed. In Europe, as part of the value-over-volume strategy, the company produced somewhat higher gas volumes in 2012 than previously assumed, which reduces the estimated 2013 gas production by approximately 15 mboe per day. The deferral of gas production to create value, gas off-take, timing of new capacity coming on stream and operational regularity represent the most significant risks related to the production guidance. In addition, the recent terror attack gives rise to uncertainty about production from In Amenas in Algeria. These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties, because they relate to events and depend on circumstances that will occur in the future. See the section Forward-looking statements for more information. 10 Statoil, Annual report on Form 20-F 2012


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    3 Business overview 3.1 Our history Statoil was formed in 1972 by a decision of the Norwegian parliament and listed on the stock exchanges in Oslo and New York in 2001. Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap AS on 18 September 1972. As a company wholly owned by the Norwegian State, Statoil's role was to be the government's commercial instrument in the development of the oil and gas industry in Norway. In 2001, the company became a public limited company listed on the Oslo and New York stock exchanges, and it changed its name to Statoil ASA. We have grown in parallel with the Norwegian oil and gas industry, which dates back to the late 1960s. Initially, our operations primarily focused on exploration for and the production and development of oil and gas on the Norwegian continental shelf (NCS) as a partner. In the 1970s, we commenced our own operations, made important discoveries and began oil refining operations, which have been of great importance to the further development of the NCS. We grew substantially in the 1980s through the development of large fields on the NCS (Statfjord, Gullfaks, Oseberg, Troll and others). We also became a major player in the European gas market by securing large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, we were involved in manufacturing and marketing in Scandinavia and established a comprehensive network of service stations. 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 on 1 October 2007. In recent years, we have utilised our expertise to design and manage operations in various environments in order to grow our upstream activities outside our traditional area of offshore production. This includes the development of heavy oil and shale gas projects. In 2010, we carried out an initial public offering of Statoil Fuel & Retail ASA on the Oslo stock exchange (Oslo Børs), partially divesting and reducing our interest in the business relating to service stations. In 2012, we sold all of our remaining shares in Statoil Fuel & Retail ASA. We are participating in projects that focus on other forms of energy, such as offshore wind and carbon capture and storage, in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change. Statoil, Annual report on Form 20-F 2012 11


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    3.2 Our business Statoil is an upstream, technology-driven energy company that is primarily engaged in oil and gas exploration and production activities. Statoil's headquarters are in Norway. We have business operations in 35 countries and territories and have approximately 23,000 employees 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 Liability Companies Act). The Norwegian State is the largest shareholder in Statoil ASA, with a direct ownership interest of 67%. Statoil is the leading operator on the Norwegian continental shelf (NCS) and is also expanding its international activities. Statoil is present in several of the most important oil and gas provinces in the world. In 2012, 33% of Statoil's equity production came from international activities and the company also holds operatorships internationally. The company is among the world's largest net sellers of crude oil and condensate, and the second-largest supplier of natural gas to the European market. Statoil also has substantial processing and refining operations. The company is contributing to the development of new energy resources, has ongoing activities in offshore wind, and is at the forefront of the implementation of technology for carbon capture and storage (CCS). In further developing our international business, we intend to utilise our core expertise in areas such as deep waters, heavy oil, harsh environments and gas value chains in order to exploit new opportunities and develop high-quality projects. Statoil's business address is Forusbeen 50, N-4035 Stavanger, Norway. Its telephone number is +47 51 99 00 00. 3.3 Our competitive position There is intense competition in the oil and gas industry for customers, production licences, operatorships, capital and experienced human resources. Statoil competes with large integrated oil and gas companies, as well as with independent and state-owned companies, for the acquisition of assets and licences for the exploration, development and production of oil and gas, and for the refining, marketing and trading of crude oil, natural gas and related products. Key factors affecting competition in the oil and gas industry are oil and gas supply and demand, exploration and production costs, global production levels, alternative fuels, and environmental and governmental regulations. Statoil's ability to remain competitive will depend, among other things, on the company's management continuing to focus on reducing unit costs and improving efficiency, and maintaining long-term growth in reserves and production through continuing technological innovation. It will also depend on our ability to seize international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. We believe that we are in a position to compete effectively in each of our business segments. The information about Statoil's competitive position in the business overview and strategy, and operational review sections is based on a number of sources. They include investment analyst reports, independent market studies, and our internal assessments of our market share based on publicly available information about the financial results and performance of market players. We have endeavoured to be accurate in our presentation of information based on other sources, but have not independently verified such information. 12 Statoil, Annual report on Form 20-F 2012


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    3.4 Corporate structure Statoil's operations are managed through the following business areas: Development and Production Norway (DPN) DPN comprises our upstream activities on the Norwegian continental shelf (NCS). DPN aims to continue its leading role and ensure maximum value creation on the NCS. Through excellent HSE and improved operational performance and cost, DPN strives to maintain and strengthen Statoil's position as a world- leading operator of producing offshore fields. DPN seeks to open new acreage and to mature improved oil recovery and exploration prospects. New and existing fields are primarily developed using an industrial approach, in which speed of delivery and cost improvements through standardisation and repeated use of proven solutions are key elements. Development and Production International (DPI) DPI comprises our worldwide upstream activities that are not included in the DPN and Development and Production North America (DPNA) business areas. DPI's ambition is to build a large and profitable international production portfolio comprising activities ranging from accessing new opportunities to delivering on existing projects and managing a production portfolio. DPI endeavours to ensure the delivery of profitable projects in a range of complex technical and stakeholder environments, and it manages a broad non-operated production portfolio that will be complemented with operated positions. Development and Production North America (DPNA) DPNA comprises our upstream activities in North America. DPNA's ambition is to develop a material and profitable position in North America, including the deepwater regions of the Gulf of Mexico and unconventional oil and gas and oil sands in the US and Canada. In this connection, we aim to further strengthen our capabilities in deep water, unconventional gas operations and carbon-efficient oil sands extraction. Marketing, Processing and Renewable Energy (MPR) MPR comprises our marketing and trading of oil products and natural gas, transportation, processing and manufacturing, the development of oil and gas value chains, and renewable energy. MPR's ambition is to maximise value creation in Statoil's midstream, marketing and renewable energy business. Technology, Projects and Drilling (TPD) TPD's ambition is to provide safe, efficient and cost-competitive global well and project delivery, technological excellence and R&D. Cost-competitive procurement is an important contributory factor, although group-wide procurement services are also expected to help to drive down costs in the group. Exploration (EXP) EXP's ambition is to position Statoil as one of the leading global exploration companies. This is achieved through accessing high potential new acreage in priority basins, globally prioritising and drilling more significant wells in growth and frontier basins, delivering near-field exploration on the NCS and other select areas, and achieving step-change improvements in performance. Global Strategy and Business Development (GSB) GSB sets the corporate strategy, business development and merger and acquisition activities (M&A) for Statoil. The ambition of the GSB business area is to closely link corporate strategy, business development and M&A activities to actively drive Statoil's corporate development. Reporting segments After implementing the new corporate structure on 1 January 2011, Statoil has reported its business in the following reporting segments: Development and Production Norway (DPN); Development and Production International (DPI), which combines the DPI and DPNA business areas; Marketing, Processing and Renewable Energy (MPR); Fuel & Retail (FR) (until 19 June 2012, when the segment was sold); and Other. The Other reporting segment includes activities in TPD, GSB and corporate staffs and services. Activities relating to the Exploration business area are allocated to, and presented in, the respective development and production segments. On 19 June 2012, Statoil ASA sold its 54% shareholding in Statoil Fuel & Retail ASA (SFR). Up until this transaction SFR was fully consolidated in the Statoil group with a 46% non-controlling interest and reported as a separate reporting segment (FR). The FR segment marketed fuel and related products principally to retail consumers. Following the sale of Statoil Fuel & Retail ASA (SFR), the FR segment ceased to exist. Presentation In the following sections, the operations of each reporting segment are presented. Underlying activities or business clusters are presented according to how the reporting segment organises its operations. The Exploration business area's activities, which include group discoveries and the appraisal of new exploration resources, are presented as part of the various development and production reporting segments (Development and Production Norway, and Development and Production International). As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based on geographical area. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa, and the Americas. Statoil, Annual report on Form 20-F 2012 13


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    3.5 Development and Production Norway (DPN) 3.5.1 DPN overview Development and Production Norway (DPN) consists of our exploration, field development and operational activities on the Norwegian continental shelf (NCS). We have 42 Statoil-operated assets in the North Sea, the Norwegian Sea and the Barents Sea, and we also operate a significant number of exploration licences. Statoil's equity and entitlement production on the NCS was 1,335 mboe per day in 2012. That was about 73% of Statoil's total entitlement production and 67% of Statoil's equity production. In 2012, our daily production of oil and natural gas liquids (NGL) on the NCS was 624 mboe, while our average daily gas production on the NCS was 113 mmcm (4.0 bcf). Acting as operator, Statoil is responsible for approximately 71% of all oil and gas production on the NCS. Barents Sea Hammerfest Harstad Norwegian Sea Trondheim 130003_STN083279 Bergen Oslo Stavanger North Sea ( ! Statoil offices In 2012, DPN organised the production operations into four business clusters: Operations North, Operations North Sea West, Operations North Sea East and Operations South. The Operations South and Operations North Sea West and East clusters cover our licences in the North Sea. Operations North covers our licences in the Norwegian Sea and in the Barents Sea, while partner-operated fields cover the entire NCS and are included internally in the Operations South business cluster. From 1 January 2013, DPN has split the business cluster Operations North into two independent business clusters: Operations North (located in Harstad) and Operations Mid-Norway (located in Stjørdal, near Trondheim). This is a strategically important milestone in relation to expanding our business in the northern region of Norway. The (new) Operations North cluster will include producing assets such as Snøhvit and Norne as well as strategically important fields under development in the Barents Sea. The Operations Mid-Norway business cluster will follow up Statoil's activity in the Norwegian Sea as well as fields under development in this region. When possible, the fields in each cluster use common infrastructure, such as production installations and oil and gas transport facilities. This reduces the investments required to develop new fields. Our efforts in these core areas will also focus on finding and developing smaller fields through the use of existing infrastructure and on increasing production by improving the recovery factor. We are making active efforts to extend production from our existing fields through improved reservoir management and the application of new technology. 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. 14 Statoil, Annual report on Form 20-F 2012


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    Key events and portfolio developments in 2012: Production start-up of Visund South, the first fast-track project in production on the NCS, and Skarv (operated by BP). The agreement with Centrica to sell interests in certain licences on the NCS was closed in April 2012. The transaction was recognised in the second quarter of 2012. The gain from the transaction is NOK 7.5 billion. Statoil entered into an agreement with Wintershall to exit the Brage licence and transfer the operatorship to Wintershall, farm down in the Gjøa licence - including the Vega and Vega South satellite fields - and enter the Edvard Grieg licence. The cash consideration amounts to USD 1.45 billion. The transaction is expected to be closed during the second half of 2013. The transaction is subject to governmental approval. Major discoveries in the Havis prospect in the Barents Sea and King Lear in the North Sea. Extensive appraisal drilling still ongoing in the Johan Sverdrup area; several successful appraisal wells were drilled during 2012. Ten planned turnarounds were finalised during 2012. High project activity; investment decisions were made to develop 20 projects (including IOR projects). Submitted plan for development and operation (PDO) for Gina Krog (formerly Dagny), Aasta Hansteen and Ivar Aasen (operated by Det Norske) to the Norwegian Ministry of Petroleum and Energy. Approved PDO for the Svalin fast-track project in the North Sea. 3.5.2 Fields in production on the NCS In 2012, our total production of entitlement liquids and gas was 1,335 mboe per day, compared to 1,316 mboe per day in 2011. The following table shows DPN's average daily entitlement production of oil, including NGL and condensates, and natural gas for the years ending 31 December 2012, 2011 and 2010. Field areas are groups of fields operated as a single entity. For the year ended 31 December 2012 2011 2010 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 180 23 326 214 24 363 183 24 333 Operations North Sea West 163 16 264 177 15 273 228 17 336 Operations North Sea East 140 39 387 147 25 306 138 32 337 Operations South (ex Partner Operated Fields) 93 13 177 112 16 210 119 16 220 Partner Operated Fields 49 21 181 43 19 165 36 18 147 Total 624 113 1,335 693 99 1,316 704 106 1,374 Statoil, Annual report on Form 20-F 2012 15


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    The following table shows the NCS production by fields and field areas in which we were participating as of 31 December 2012. Field areas are groups of fields operated as a single entity. Statoil’s Licence Average daily Georgraphical equity interest On expiry production in 2012 Business cluster area in %(1) Operator stream date mboe/day Operations North Åsgard The Norwegian Sea 34.57 Statoil 1999 2027 124.0 Tyrihans The Norwegian Sea 58.84 Statoil 2009 2029 52.9 Snøhvit The Barents Sea 33.53 Statoil 2007 2035 36.7 Kristin The Norwegian Sea 55.30 Statoil 2005 2033 (2) 31.8 Mikkel The Norwegian Sea 43.97 Statoil 2003 2022 (3) 21.6 Morvin The Norwegian Sea 64.00 Statoil 2010 2027 21.5 Alve The Norwegian Sea 85.00 Statoil 2009 2029 13.2 Norne The Norwegian Sea 39.10 Statoil 1997 2026 6.5 Heidrun The Norwegian Sea 12.41 Statoil 1995 2024 (4) 6.3 Njord The Norwegian Sea 20.00 Statoil 1997 2021 & 2023 (5) 4.6 Yttergryta The Norwegian Sea 45.75 Statoil 2009 2027 3.7 Urd The Norwegian Sea 63.95 Statoil 2005 2026 3.6 Total Operations North 326.4 Operations North Sea West Gullfaks The North Sea 70.00 Statoil 1986 2016 90.9 Kvitebjørn The North Sea 58.55 Statoil 2004 2031 85.6 Grane The North Sea 36.66 Statoil 2003 2030 44.2 Visund The North Sea 53.20 Statoil 1999 2023 11.9 Gimle The North Sea 65.13 Statoil 2006 2016 6.7 Vilje The North Sea 28.85 Statoil 2008 2021 6.7 Volve The North Sea 59.60 Statoil 2008 2028 6.3 Brage The North Sea 32.70 Statoil 1993 2015 (6) 5.3 Veslefrikk The North Sea 18.00 Statoil 1989 2015 3.2 Huldra The North Sea 19.88 Statoil 2001 2015 2.0 Glitne The North Sea 58.90 Statoil 2001 2013 1.0 Vale The North Sea 28.85 Statoil 2002 2021 0.2 Heimdal The North Sea 29.44 Statoil 1985 2021 (7) 0.0 Total Operation North Sea West 264.0 Operations North Sea East Troll Phase 1 (Gas) The North Sea 30.58 Statoil 1996 2030 181.0 Troll Phase 2 (Oil) The North Sea 30.58 Statoil 1995 2030 48.8 Oseberg The North Sea 49.30 Statoil 1988 2031 110.6 Fram The North Sea 45.00 Statoil 2003 2024 23.9 Vega Unit The North Sea 54.00 Statoil 2010 2035 (6) 20.1 Tune The North Sea 50.00 Statoil 2002 2032 2.6 Total Operation North Sea East 387.0 16 Statoil, Annual report on Form 20-F 2012


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    Statoil’s Licence Average daily Georgraphical equity interest On expiry production in Business cluster area in %(1) Operator stream date 2012 mboe/day Operations South (ex Partner Operated Fields) Sleipner West The North Sea 58.35 Statoil 1996 2028 74.0 Sleipner East The North Sea 59.60 Statoil 1993 2028 15.4 Gungne The North Sea 62.00 Statoil 1996 2028 9.3 Statfjord Unit The North Sea 44.34 Statoil 1979 2026 31.6 (8) Statfjord Øst The North Sea 31.69 Statoil 1994 2026 2.8 Statfjord Nord The North Sea 21.88 Statoil 1995 2026 0.7 (8) Sygna The North Sea 30.71 Statoil 2000 2026 0.3 (9) Snorre The North Sea 33.32 Statoil 1992 2015 26.2 Vigdis area The North Sea 41.50 Statoil 1997 2024 14.4 Tordis area The North Sea 41.50 Statoil 1994 2024 1.8 Total Operations South (ex Partner Operated Fields) 176.5 Partner Operated Fields Ormen Lange The Norwegian Sea 28.92 Shell 2007 2041 120.1 (6) Gjøa The North Sea 20.00 GDFSuez 2010 2028 24.7 Ekofisk area The North Sea 7.60 ConocoPhillips 1971 2028 16.4 Sigyn The North Sea 60.00 ExxonMobil 2002 2018 9.2 Marulk The North Sea 11.78 Eni Norge AS 2012 2025 5.7 Ringhorne Øst The North Sea 14.82 ExxonMobil 2006 2030 2.5 Vilje The North Sea 28.85 Marathon Oil 2008 2021 2.0 Skirne The North Sea 10.00 Total 2004 2025 0.5 Total Partner Operated Fields 181.1 Total Operations South (incl Partner Operated Fields) 357.6 Total 1,335.0 (1) Equity interest as of 31 December 2012. down in the Gjøa licence, including the Vega and Vega South satellite (2) PL134B expires in 2027 and PL199 expires in 2033. fields (Vega Unit). Closing of the transaction is expected to take place (3) PL092 expires in 2020 and PL121 expires in 2022. during the second half of 2013. The transaction is subject to govern- (4) Re-determination at Heidrun with makeup periods in 2012. Statoil mental approval. (7) owner shares: Jan-Feb: 38.5644%; Mar-Jun: 13.27633%; Jun: PL036 expires in 2021 and PL102 expires in 2025. The owner 13.11821%; Jul-Dec: 0%. share of the topside facilities is 39.44%, however the owner share (5) PL107 expires in 2021 and PL132 expires in 2024. of the reservoir and production is 29.44%. (6) (8) In 2012, Statoil entered an agreement with Wintershall to exit the PL037 expires in 2026 and PL089 expires in 2024. (9) Brage licence and transfer the operatorship to Whitershall, farm PL089 expires in 2024 and PL057 expires in 2015. The following sections provide information about the main producing assets. See the section Financial review - Operating and financial review 2012 - DPN profit and loss analysis for a discussion of results of operations for 2012, 2011 and 2010. 3.5.2.1 Operations North The main producing fields in the Operations North area are Åsgard, Heidrun, Kristin, Tyrihans, Snøhvit, Mikkel and Njord. The region is characterised by petroleum reserves located at water depths of between 250 and 500 metres. The reserves are partly under high pressure and at high temperatures. These conditions have made development and production more difficult, challenging the participants to develop new types of platforms and new technology, such as floating processing systems with subsea production templates. Statoil, Annual report on Form 20-F 2012 17


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    The Åsgard field (Statoil interest 34.57%) 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. Gas from the field is piped through the Åsgard Transport System (ÅTS) to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany and from there on to the European gas market. Oil produced at the Åsgard A vessel and condensate from the Åsgard C storage vessel are shipped from the field in shuttle tankers. Mikkel (Statoil interest 43.97%) is a gas and condensate field. The production is transported to the Åsgard B gas processing platform. Morvin (Statoil interest 64.00%) is an important contributor to utilising production capacity on Åsgard B. The well stream of oil and gas is tied back to Åsgard B for processing. Most of the oil from Heidrun (Statoil interest 13.04%) is shipped by shuttle tanker to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for the methanol plant at Tjeldbergodden in Norway. Additional gas volumes are exported through the Åsgard Transport System (ÅTS) to gas markets in continental Europe. Kristin (Statoil interest 55.30%) is a gas and condensate field. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir are among the highest of all developed fields 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 (Statoil interest 58.84%) was producing from nine wells by the end of 2012. In addition, gas is injected into two injection wells via Åsgard B. The Tyrihans development project was completed in 2012. Snøhvit (Statoil interest 33.53%) is the first field to be developed in the Barents Sea. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore. 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. The LNG was shipped to customers in Europe, the US and Asia in tankers in 2012. The LNG plant suffered operational challenges in 2012, mainly in relation to the pre-treatment systems on Melkøya. In the immediate future, the Snøhvit licence will focus on optimising and upgrading the existing LNG facility (Train I) and further developing Snøhvit through planning and mobilising for an improvement project. The main objectives of the project are to find a long-term solution to increase production efficiency and gas export flexibility, thereby ensuring optimal LNG export from the facilities. The owners in the Snøhvit licence have decided to stop work on a possible capacity increase of the onshore facility on Melkøya. The licence has concluded that the current gas discoveries do not provide a sufficient basis for further capacity expansion. 3.5.2.2 Operations North Sea West Operations North Sea West includes a large part of Statoil's mature production activity on the NCS. Our main focus is on increasing and prolonging production in the area, giving priority to increased oil recovery, exploration and new field development. The main producing fields in the area are Gullfaks, Kvitebjørn and Grane. Kvitebjørn (Statoil interest 58.55%). The Kvitebjørn platform processing facilities will be expanded by a compressor module. Re-compression of the gas is expected to increase the expected production of gas and condensate, thereby increasing the recovery rate from 56% to an estimated 71%. Offshore installation of the compressor module will take place in 2013. Gullfaks (Statoil interest 70.00%) has been developed with three large concrete production platforms. Oil is loaded directly onto custom-built shuttle tankers on the field. Associated gas is piped to the Kårstø gas processing plant and then on to continental Europe. Since production started on Gullfaks in 1986, five satellite fields have been developed with subsea wells that are remotely controlled from the Gullfaks A and C platforms. In late 2010, there was a strong reduction in water injection on Gullfaks with subsequent reduced production in order to maintain the pressure balance. Oil production has gradually increased during recent years. The increased production in 2012 is due to new production wells in the satellites' area and better performance than anticipated on the main field as a result of optimised reservoir management. The drilling operations on the satellites will continue with two mobile rigs in 2013. Several large projects have been approved on Gullfaks in 2012. The most notable are the Gullfaks South IOR (improved oil recovery) project, consisting of two well templates and six wells, the Gullfaks C subsea gas precompression project and the Gullfaks B drilling upgrade. The high activity level is expected to continue in 2013. Grane (Statoil interest 36.66%) is Statoil's largest producing heavy oil field. Oil from Grane is piped to the Sture terminal, where it is stored and shipped. Heimdal (Statoil interest 29.44%). The Heimdal Gas Centre in production licence PL036 is a hub for the processing and distribution of gas. It consists of an integrated steel platform and a riser platform. 18 Statoil, Annual report on Form 20-F 2012


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    In May 2012, Statoil experienced a large gas leak at the Heimdal platform. During a routine operation, a valve was overloaded, causing gas to flow into the surrounding area. There were no injuries to personnel, and all emergency procedures were followed successfully. In Statoil's own investigation report, the gas leak was classified as very serious. The Petroleum Safety Authority (PSA) also conducted an investigation into the incident and concluded that it had major accident potential. PSA has given Statoil notification of an order based on its investigation. Statoil implemented four immediate measures after the incident. These measures involve improving the technical design and updating system drawings, as well as improvements in planning and risk assessment. Glitne (Statoil interest 58.90%) came on stream in 2001, and the intention was to produce for 26 months. The production period has been significantly extended over the years, and in 2012, twelve years later, the partnership decided to shut down the field. There will be production volumes from Glitne until the shutdown process is started during the first quarter of 2013. The decommissioning on the field is expected to be carried out during the period from the second half of 2013 until 2015, and it is considered to be relatively uncomplicated compared to other larger fields. Due to the concept, which is a floating production ship, the shutdown and final disposal costs are estimated to be in the range of NOK 2 billion. The total production from Glitne has amounted to 55 million barrels of oil, which is more than double the original estimate. 3.5.2.3 Operations North Sea East Operations North Sea East is a major gas area that also contains significant quantities of oil. The main producing fields in the area are Troll and Oseberg. These fields are among the largest producing fields on the Norwegian continental shelf (NCS). Many significant investment decisions were taken during 2012, including the Fram H-Nord fast-track development project. In 2012, Oseberg was awarded the Norwegian Petroleum Directorate's prize for improved oil recovery (IOR) for its work on increasing recovery by means of gas injection. Both the Oseberg and Troll areas have significant prospective potential and several IOR projects are under evaluation. Troll (Statoil interest 30.58%) is the largest gas field on the NCS and a major oilfield. The Troll field is split into three hydrocarbon-bearing regions connected to three platforms: Troll A, B and C. The Troll gas is mainly exported and produced at the Troll A platform, while oil is mainly produced at Troll B and C. The Oseberg area (Statoil interest 49.30%) includes the Oseberg Field Centre, Oseberg C, Oseberg East and Oseberg South production platforms. 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 from there to the market. 3.5.2.4 Operations South The main producing fields in Operations South are Sleipner, Snorre and Statfjord. Operations South also produces from the satellite fields Tordis and Vigdis, which are tied into Gullfaks C and Snorre A, as well as Statfjord satellites, which are tied into the Statfjord C platform. Sleipner consists of the Sleipner East (Statoil interest 59.60%), Gungne (Statoil interest 62.00%) and Sleipner West (Statoil interest 58.35%) gas and condensate fields. 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. The Gudrun field is under development. It will be tied into Sleipner. The Snorre field (Statoil interest 33.32%) has been developed with two floating platforms and one subsea production system connected to one of the platforms (Snorre B). Oil and gas from the Snorre field are exported to Statfjord for final processing, storage and loading. Statfjord (Statoil interest 44.34%) has been developed with three fully integrated platforms supported by gravity-based structures with concrete storage cells and an offshore loading system. The Norwegian authorities have granted a licence extension for the Statfjord area from 2020 until 2026. The current plan is that Statfjord A production will shut down by the end of 2016, while Statfjord B and Statfjord C will continue production until 2025. The Statfjord satellites consist of Statfjord North (Statoil interest 21.88%), Statfjord East (31.69%) and Sygna (30.71%). These satellites are all developed with subsea templates tied back to Statfjord C and they are expected to produce until 2025. Statoil, Annual report on Form 20-F 2012 19


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    3.5.2.5 Partner-operated fields Partner-operated fields account for approximately 14% of our total oil and gas production on the NCS. The main producing fields are Ormen Lange, Ekofisk and Gjøa. The organisation that is responsible for follow-up of Statoil's total portfolio of partner-operated fields on the NCS is organised under Operations South and located in Stavanger. Ormen Lange (Statoil interest 28.916%), operated by Shell, is a deepwater gas field in the Norwegian Sea. 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 is operated by ConocoPhillips. It consists of the Ekofisk, Eldfisk and Embla fields (Statoil interest 7.60%), and Tor (Statoil interest 6.64%). Investment decisions were made in 2010 for a new Ekofisk South project consisting of a new drilling platform with subsea water injection facilities and the redevelopment of Eldfisk. The projects are progressing according to plan and are expected to extend the field life considerably beyond the current licence period, which ends in 2028. Gjøa (Statoil interest 20.00%) is operated by GDF SUEZ. Gjøa has been developed with a subsea production system and a semi-submersible production platform. Gas is exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus, and oil is exported via the Troll 2 pipeline to the Statoil-operated Mongstad refinery near Bergen. The platform is supplied with land-based electricity from Mongstad. On 22 October, Statoil entered into an agreement with Wintershall, including a farm down in the Gjøa licence from 20% to 5% effective from 1 January 2013, pending government approval. Skarv (Statoil interest 36.17%) is an oil and gas field located in the Norwegian Sea, with BP as operator. The field has been developed with an FPSO vessel and five subsea multi-well installations. Oil is exported by offshore loading, and gas is exported via the Åsgard Transport System (ÅTS). The field was put into production on 31 December 2012 and it is currently ramping up production. 3.5.3 Exploration on the NCS The successful exploration results achieved in 2011 continued into 2012. The successful exploration results achieved in 2011 continued into 2012, with another major oil discovery in the Barents Sea, Havis, in the vicinity of the Skrugard well. A successful appraisal well was drilled on the Skrugard discovery, confirming the resources and quality of the reservoir. A major gas/condensate discovery was made in the southern part of the North Sea, at King Lear. In 2012, comprehensive appraisal continued of the giant Johan Sverdrup discovery, previously named Aldous/Avaldsnes. Appraisal drilling confirmed the resource potential and will continue in 2013. Statoil was awarded ownership interests in 14 production licences in the 2012 annual awards of pre-defined areas (APA), including seven operatorships. In the North Sea, we will be the operator in five of eight licences awarded, and in one of four licences in the Norwegian Sea, while we will operate one of two licences in the Barents Sea. In the 22nd licencing round the main focus was on the Barents Sea, and awards are expected in the third quarter of 2013. 20 Statoil, Annual report on Form 20-F 2012


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    The table below shows the exploration and development wells drilled on the NCS in the last three years. The number decreased from 25 exploration wells and four exploration extensions completed in 2011 to 19 exploration wells and one exploration extension of production wells completed in 2012. The planned number of wells for 2012 was of the same order as for 2011, but due to the late arrival of contracted drilling rigs, three wells have been postponed until 2013. 2012 2011 2010 North Sea Statoil operated exploratory 8 13 5 Statoil operated development 59 61 59 Partner operated exploratory 6 5 7 Partner operated development 12 12 11 Norwegian Sea Statoil operated exploratory 1 2 2 Statoil operated development 18 14 14 Partner operated exploratory 2 2 3 Partner operated development 7 6 6 Barents Sea Statoil operated exploratory 2 2 0 Statoil operated development 0 0 0 Partner operated exploratory 0 1 0 Partner operated development 0 0 0 Totals Exploratory 19 25 17 Exploration extension wells 1 4 4 Development wells 96 93 90 Potential producing areas In addition to producing areas, Statoil operates a significant number of exploration licences. Exploration takes place in undeveloped frontier areas as well as near existing infrastructure and producing fields. Number of Number of Number of Square km Square km Change vs licenses licenses licenses New licenses New licenses Area (NCS Total) (Statoil) 2011 (NCS Total) (Statoil equity) (Statoil Op.) (Statoil equity) (Statoil Op.) NCS total 128,939 41,009 (7,235) 466 225 172 14 7 North Sea 55,043 16,427 699 290 125 99 8 5 Norwegian Sea 52,669 15,084 (4,809) 126 71 52 4 1 Barents Sea 21,227 9,498 (3,125) 50 29 21 2 1 North Sea In the North Sea, Statoil participated in 14 exploration wells and operated eight of them. Six of the Statoil-operated wells and three of the partner-operated wells were announced as discoveries. The main activity in this area has been the appraisal of the Johan Sverdrup discovery. One of the wells confirmed additional resources in a separate segment on the northern flank of the discovery. The appraisal drilling will continue in 2013. Statoil made another major discovery in the mature Central Graben area in the southern part of the North Sea. Gas and condensate were confirmed in the King Lear prospect in Block 2/4, located between the producing Ula and Ekofisk fields. Several other prospects have been identified within Block 2/4. These prospects are high temperature/high pressure prospects and are expected to be drilled in the coming years. Rig capacity has been secured for further exploration drilling in 2014. Statoil, Annual report on Form 20-F 2012 21


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    In the North Sea, both the number of licences with a Statoil share and the size of the licensed acreage increased in 2012. Norwegian Sea Exploration activity was limited in the Norwegian Sea in 2012, and there was a net reduction of Statoil equity acreage from 2011 to 2012. This reflects an optimisation of the portfolio based on costs compared to expected prospectivity. The number of licences with a Statoil share also decreased. Statoil drilled one well in the Norne area, Jette, which was a non-commercial discovery. In addition, two partner-operated wells were drilled. One of them was a minor gas discovery, located approximately five kilometres east of the Marulk field. Barents Sea In the Barents Sea, the main area for exploration activities has been the Statoil-operated Skrugard licence in the Bjørnøya South basin. Statoil has drilled two wells as operator for the Skrugard licence, and made another major discovery at the Havis prospect. The drilling of the first appraisal well at the major Skrugard discovery last year confirmed the size and the reservoir quality. A drilling campaign of nine wells will start in the Barents Sea in 2013. Four of them will be located in the Skrugard area, three in the Hoop area and two in the Snøhvit area. 3.5.4 Fields under development on the NCS A number of fields are currently under development on the NCS, including traditional, fast-track and redevelopment projects. The table below shows some key figures as of 31 December 2012 for our major development projects on the NCS. Statoil’s share at Statoil equity capacity Project Operator 31 December 2012 Production start (mboe per day) Aasta Hansteen Statoil 75.00% 2017 100 Gudrun Statoil 75.00% 2014 65 Valemon Statoil 53.78% 2014 50 Gina Krog (formerly Dagny) Statoil 58.46% 2017 50 Ivar Aasen Det Norske 50.00% 2016 40 Goliat Eni 35.00% 2014 30 Aasta Hansteen (Statoil interest 75%) is a deepwater gas discovery in the Norwegian Sea. The development concept includes three subsea templates tied in to a floating processing unit with gas export through a new pipeline, Polarled, to Nyhamna and further exportation through the Langeled pipeline. The Aasta Hansteen processing unit will also serve as a hub for other potential discoveries in the area. The plan for development and operation (PDO) for the field was submitted to the Norwegian Ministry of Petroleum and Energy in January 2013. Expected production start-up is 2017. The Gudrun (Statoil interest 75%) oil and gas field is located in the North Sea. Production is scheduled to start in 2014. The total investments are estimated to amount to NOK 18.2 billion. 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. Production drilling started in September 2011. It is being performed by the jack-up rig West Epsilon. A total of seven production wells will be drilled and completed prior to production start-up. Valemon, which is located in the North Sea, is being developed with a steel jacket platform with gas, condensate and water separation. Production drilling started in the third quarter of 2012, and it is being performed using the jack-up rig West Elara. The field development costs are estimated to be NOK 20.5 billion, and production start-up is expected to take place during the fourth quarter of 2014. Statoil's ownership interest in Valemon is 53.78% after the transaction with Centrica Resources Norway. Gina Krog (formerly Dagny) (Statoil interest 58.46%) is an oil and gas discovery in the North Sea some 30 km north of the Sleipner field. In December 2011, the licence partners approved Statoil's proposed concept solution for Gina Krog. The field development concept includes a steel-jacket platform. Oil will be exported via offshore loading from a floating storage unit. Due to the high condensate content, the rich gas will be exported via Sleipner, where the rich gas will be further processed. The development concept also includes gas injection in order to maximise the recovery factor for the field. The development concept includes a total of 15 wells. The project was sanctioned in the fourth quarter of 2012. Ivar Aasen is an oil and gas field located in the Utsira High Area. It will be developed with a fixed steel jacket with partial processing and living quarters tied in as a satellite to Edvard Grieg for further processing and export. The Ivar Aasen development is operated by Det norske, and Statoil holds an interest of 50%. The operator expects production start-up in the fourth quarter of 2016. 22 Statoil, Annual report on Form 20-F 2012


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    Goliat is the first oilfield to be developed in the Barents Sea. The field is being developed with subsea wells tied back to a circular FPSO vessel. The oil will be offloaded to shuttle tankers. The Goliat development is operated by Eni, and Statoil holds an interest of 35%. The operator expects production start-up in the third quarter of 2014. The operator has estimated the development costs for the field to be NOK 36.7 billion. Fast-track projects are all relatively small projects, yielding high returns. The initiative was taken in order to address time criticality and cost challenge issues relating to Statoil's portfolio of smaller discoveries and prospects close to existing infrastructure. By rationalising the time and resources used, improving collaboration and deploying standard equipment, the goal is to shorten the normal period between discovery and production to only 2.5 years and reduce costs by 30%. In Statoil's opinion, the initiative has led to cost-efficient development solutions for this kind of discovery. The main challenge experienced in the execution phase has been the timely availability of rigs for production drilling. Statoil's fast-track project development initiative is progressing well. As of 31 December 2012, ten projects have been sanctioned and are currently in the execution phase, while several other fast-track candidates are being considered. Redevelopment on the NCS - Improved oil recovery (IOR) The main purpose of maturing IOR projects is to extend the lifetime of existing installations, increase oil recovery and exploit new profitable opportunities. During 2012, Statoil set a very ambitious target of increasing the average recovery rate from our fields on the NCS from 50% to an estimated 60% by 2020. There is a therefore high activity on maturing IOR projects on the NCS, and the following projects are some of the largest currently being developed: The Gullfaks B water injection upgrade project includes the 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 2013. The main purpose of the Kvitebjørn pre-compression project is to increase and accelerate gas and condensate recovery by facilitating low-pressure production. Start-up is scheduled for December 2013. Kristin low-pressure production is an IOR project that aims to increase production from the Kristin and Tyrihans fields on Haltenbanken by installing a new low-pressure compressor on the Kristin platform. The expected date of completion is mid-2014. The Troll A third and fourth pre-compressor project is described in the original PDO for the Troll field. The purpose of the project is to increase gas production by installing two extra pre-compressors on the Troll A platform. The investment costs are estimated to be NOK 10.2 billion and the expected completion date is the fourth quarter of 2015. Subsea compression innovation and technology development are essential to improved oil and gas recovery and extending the life of the fields on the NCS. The development of subsea compression and processing is a central part of Statoil's technology strategy for long-term production growth. Subsea gas compression is an important step on the road towards our ambition of installing the elements for a "subsea factory". Subsea processing is key to gaining access to resources in Arctic areas and deepwater assets. The Åsgard subsea compression is one of Statoil's most demanding technology projects aimed at improved recovery. The project will install compact subsea compressors in the Midgard part of the Åsgard fields. The purpose of the project is to increase the recoverable reserves significantly by introducing innovative subsea compression of the well stream. The PDO was approved on 27 March 2012. The investment cost for the project is estimated to be NOK 16.5 billion and completion of the development is currently expected to take place in 2015. The Gullfaks subsea compression project is the second large subsea gas compression project planned by Statoil on the NCS. Subsea gas compression will have a great effect on the Gullfaks field. With the help of this subsea technology, combined with conventional low-pressure production, the recovery rate from the Gullfaks South Brent reservoir can be increased from 62% to 74%. The project is scheduled for completion in 2015. 3.5.5 Decommissioning on the NCS Statoil completed the first shutdown and removal project on the NCS in 2012. 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). In 2012, Statoil completed the Troll Oseberg Gas Injection (TOGI) cessation project, the first shutdown and removal project on the NCS. In 2013, Statoil will carry out shutdown of the Glitne field. The decommissioning of the field is expected to be completed in the period 2013-2015. (For further details regarding the Glitne field, see the section Business overview - Development and Production Norway - Fields in production on the NCS - Operations North Sea West). For further information about decommissioning, see note 2 Significant accounting policies to the Consolidated financial statements. Statoil, Annual report on Form 20-F 2012 23


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    3.6 Development and Production International (DPI) 3.6.1 DPI overview Statoil is present in several of the most important oil and gas provinces in the world, and DPI is expected to account for most of Statoil's future production growth. Development and Production International (DPI) is responsible for all development and production of oil and gas outside the Norwegian continental shelf (NCS). On 16 January 2013, Statoil, together with partners BP and Sonatrach, was hit by a terrorist attack at the In Amenas gas production facility in Algeria. Five Statoil colleagues lost their lives in the attack. Statoil has initiated an investigation to determine the relevant chain of events before, during and after the attack in order to provide the company with a basis for making further improvements to its security, risk assessment and emergency preparedness. In 2012, the reporting segment was engaged in production in 11 countries: Algeria, Angola, Azerbaijan, Brazil, Canada, Libya, Nigeria, Russia, the UK, the US, and Venezuela. In 2012, DPI produced 33% of Statoil's total equity production of oil and gas. Statoil has in 2012 been engaged in cost recovery in connection with previous investments in Iran, and some of this is reported as production. Statoil still maintains an office in Teheran that addresses the closing of employment benefit issues and payment of remaining taxes related to previous investments. As of 31 December 2012, Statoil has exploration licences in North America (Alaska, Canada, and the Gulf of Mexico), South America and sub-Saharan Africa (Angola, Brazil, Mozambique, Suriname, and Tanzania), North Africa (Libya), and Europe and Asia (Azerbaijan, the Faroe Islands, Germany, Greenland, India, Indonesia, and the UK). The Iran licences have expired. Statoil also has representative offices in Kazakhstan, Mexico, Turkmenistan, and the United Arab Emirates. The main sanctioned development projects in which DPI is involved are in Angola, Canada, the UK, and the US. We are well positioned for further growth through a substantial pre-sanctioned project portfolio, including a strengthened US onshore position as a result of the acquisition of 69,933 operated net acres in Marcellus in December 2012, where Statoil will become the operator, and the Eagle Ford operatorship, which will start in 2013. The map shows Statoil's international exploration and production areas. Greenland Alaska ! ( Russia ! ( ! ( Canada Caspian region ! ( ! ( USA ! ( ! ( North Africa ! ( ! ( ! ( ! ( Middle East West Africa ! ( ! ( Indonesia East Africa ! ( South America ! ( 130003_STN083284 ! Production 31 December 2012 Exploration 24 Statoil, Annual report on Form 20-F 2012


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    Key events and portfolio developments in 2012: Equity production increased by 25% from 2011, to 669 mboe per day in 2012: Gulf of Mexico field Caesar Tonga started production on 7 March 2012. The Kizomba Satellites Phase 1 in Angola started production on 18 May. PSVM in Angola started production on 6 December. In May 2012, Statoil's exit from the West Qurna 2 project in Iraq was formally approved by the Iraqi authorities. We signed a cooperation agreement with Rosneft in May 2012 to jointly explore offshore frontier areas off Russia and Norway and to conduct joint technical studies on two onshore Russian assets. Several agreements detailing the cooperation have since been signed and work is ongoing to complete the remaining agreements. The frame agreement for Shtokman (Russia) expired on 30 June 2012. On 2 August 2012, Statoil divested the Front Runner and Thunder Hawk producing fields in the Gulf of Mexico. We made the final investment decision to go ahead with the UK Mariner field in December 2012. We strengthened our portfolio through significant discoveries off the coasts of Tanzania and Brazil, confirming the potential of previous significant offshore discoveries off Brazil. We were awarded seven exploration licences on the UK continental shelf in 2012. Statoil will be the operator for two of the licences and our working interest varies from 20% to 60%. We were the high bidder on 26 leases in the 2012 Gulf of Mexico lease sale. With the additions, we will control more than 340 leases in the Gulf of Mexico. In December 2012, we acquired 25% in the BM-ES-22A licence in Brazil through an agreement with Vale SA. The acquisition is pending government approval and other conditions. We acquired 69,933 operated net acres in Marcellus on 18 December 2012. We and our partners sanctioned the Hebron field located in East Coast Canada in December 2012. 3.6.2 International production Statoil's entitlement production outside Norway was about 26% of Statoil's total entitlement production in 2012. The following table shows DPI's average daily entitlement production of liquids and natural gas for the years ending 31 December 2012, 2011 and 2010. Entitlement production figures are after deductions for royalties paid in kind, production sharing and profit sharing. For the year ended 31 December Entitlement production 2012 2011 2010 Oil and NGL (mboe per day) 342 252 263 Natural gas (mmcm per day) 20 13 11 Total (mboe per day) 470 334 332 Statoil, Annual report on Form 20-F 2012 25


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    The table below provides information about the fields that contributed to production in 2012. Average daily Average daily equity entitlement Statoil’s Licence production production equity interest On expiry in 2012 in 2012 Field in %(1) Operator stream date mboe/day mboe/day North America Canada: Hibernia 5.00 HMDC 1997 2027 6.8 6.8 Canada: Terra Nova 15.00 Suncor 2002 2022 3.5 3.5 Canada: Leismer Demo 60.00 Statoil 2010 HBP(2) 9.8 9.8 USA: Lorien 30.00 Noble 2006 Sold 2012 0.1 0.1 USA: Front Runner 25.00 Murphy Oil 2004 Sold 2012 1.7 1.7 USA: Spiderman Gas 18.33 Anadarko 2007 HBP 4.3 4.3 USA: Zia 35.00 Devon 2003 HBP 0.1 0.1 USA: Marcellus shale gas(3) Varies Chesapeake/Statoil 2008 HBP 61.5 61.5 USA: Eagle Ford shale gas(3) Varies Talisman 2010 HBP 14.4 14.4 USA: Tahiti 25.00 Chevron 2009 HBP 23.4 23.4 USA: Thunder Hawk 25.00 Murphy Oil 2009 Sold 2012 0.8 0.8 USA: Bakken(3) Varies Statoil/others 2011 HBP 36.3 36.3 USA: Caesar Tonga 23.55 Anadarko 2012 HBP 8.7 8.7 Total North America 171.4 171.4 South America and sub-Saharan Africa Brazil: Peregrino 60.00 Statoil 2011 2034 36.8 36.8 Venezuela: Petrocedeño(4) 9.68 Petrocedeño 2008 2032 12.3 12.3 Angola: Girassol/Jasmim 23.33 Total 2001 2022 28.9 9.1 Angola: Dalia 23.33 Total 2006 2024 52.1 15.3 Angola: Rosa 23.33 Total 2007 2027 15.7 5.8 Angola: Pazflor 23.33 Total 2011 2030 45.0 39.9 Angola: Kizomba A 13.33 ExxonMobil 2004 2026 14.8 4.7 Angola: Kizomba B 13.33 ExxonMobil 2005 2027 15.3 4.7 Angola: Kizomba Satellites phase 1 13.33 ExxonMobil 2012 2032 4.9 4.4 Angola: Marimba 13.33 ExxonMobil 2007 2027 2.3 0.5 Angola: Mondo 13.33 ExxonMobil 2008 2029 7.7 0.8 Angola: Saxi-Batuque 13.33 ExxonMobil 2008 2029 9.2 2.6 Angola: PSVM 13.33 BP 2012 2031 0.7 0.6 Angola: Block 4/05 20.00 Sonangol P&P 2009 2026 2.6 2.4 Nigeria: Agbami 20.21 Chevron 2008 2024 47.0 40.4 Total South America and sub-Saharan Africa 295.3 180.5 Middle East and North Africa Algeria: In Salah 31.85 Sonatrach/BP/Statoil 2004 2027 44.7 20.2 Algeria: In Amenas 45.90 Sonatrach/BP/Statoil 2006 2022 21.8 12.1 Iran: South Pars 37.00 POGC 2008 2012 4.1 4.1 Libya: Mabruk 12.50 Total 1995 2028 3.3 3.0 Libya: Murzuq 10.00 Repsol 2003 2032 9.9 5.7 Total Middle East and North Africa 83.8 45.0 Europe and Asia Azerbaijan: ACG 8.56 BP 1997 2024 56.9 20.1 Azerbaijan: Shah Deniz 25.50 BP 2006 2031 45.1 40.8 Russia: Kharyaga 30.00 Total 1999 2032 9.6 5.5 UK: Alba 17.00 Chevron 1994 2018 3.8 3.8 UK: Jupiter 30.00 ConocoPhillips 1995 2013 0.2 0.2 UK: Schiehallion 5.88 BP 1998 2017 2.6 2.6 Total Europe and Asia 118.2 72.9 Total Development and Production International (DPI) 668.7 469.8 (1) Equity interest as of 31 December 2012. (2) Held by Production (HBP): A company’s right to own and operate an oil and gas lease is perpetuated beyond its original primary term, as long thereafter as oil and gas is produced in paying quantities. In the case of Canada, besides continuing being in production status, other regulatory requirements must be met. (3) Statoil’s actual working interest can vary depending on wells and area. (4) Petrocedeño is a non-consolidated company. 26 Statoil, Annual report on Form 20-F 2012


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    The table below provides information about production per country in 2012. Average daily equity Average daily entitlement Country production mboe/day production mboe/day North America 171.4 171.4 Canada 20.1 20.1 USA 151.3 151.3 South America and sub-Saharan Africa 283.0 168.1 Brazil 36.8 36.8 Angola 199.2 90.9 Nigeria 47.0 40.4 Middle East and North Africa 83.8 45.0 Algeria 66.5 32.3 Iran 4.1 4.1 Libya 13.3 8.7 Europe and Asia 118.2 72.9 Azerbaijan 102.0 60.8 Russia 9.6 5.5 UK 6.6 6.6 Total Development and Production International (DPI) 656 457 Equity accounted production Venezuela: Petrocedeño 12.3 12.3 Total Development and Production International (DPI) including share of equity accounted production 669 470 The following sections provide information about the main producing assets internationally. See section 4 Financial review for a discussion of the results of operations for 2012, 2011 and 2010. 3.6.2.1 North America Production in North America comprises Canada and the USA. The Bakken shale investment became a key contributor to our portfolio in 2012, while in March, the Gulf of Mexico saw the start-up of Caesar Tonga, one of a number of key development projects. Canada In 2007, we acquired 100% of the shares in North American Oil Sands Corporation and operatorship of 1,129 square kilometres (279,053 net acres) of oil sands leases in the Athabasca region of Alberta that comprise the Kai Kos Dehseh (KKD) project. In January 2011, we formed a joint venture with PTTEP of Thailand and, as part of that transaction, sold them a 40% interest in KKD Oil Sands Partnership. The Leismer Demonstration Project is the first phase of the KKD development. It has been operational since early 2011. The project achieved peak production of 20 mboe per day in 2012, and production ramp-up and operational performance have been successful. In addition, we have interests in the offshore Jeanne d'Arc basin off Canada's east coast in the producing fields Hibernia (Statoil interest 5%) and Terra Nova (Statoil interest 15%). Statoil, Annual report on Form 20-F 2012 27


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    USA Statoil entered the Marcellus shale gas play (located in the Appalachian region in north east USA) in 2008 through a partnership with Chesapeake Energy Corporation, acquiring 32.5% of Chesapeake's 1.8 million acres in Marcellus. We have continued to acquire acreage within the play, with a net acreage position of 756,363 acres (including 69,933 net acres acquired in 2012) at the end of 2012. The closing date for the 2012 transactions was 18 December 2012 (with 1 September 2012 as the effective date), on which date Statoil became the operator of record for the assets. In order to ensure an orderly transfer of tasks from the sellers to Statoil, transition services agreements (TSAs) have been established. Marcellus provides Statoil with a long-life gas asset with considerable optionality in relation to the timing of drilling and production from these leases. Statoil entered the Eagle Ford shale formation (located in south west Texas) in 2010. Through agreements with Enduring Resources LLC and Talisman Energy Inc., Statoil acquired 67,000 net acres. In 2013, Statoil will become operator for 50% of the Eagle Ford acreage, in line with the agreement with Talisman Energy Inc. from 2010. The transfer of operatorship will be conducted in phases in order to maintain high HSE standards, and operational and business continuity. This process will commence in the first quarter of 2013 and will be finalised by the end of 2013. Statoil's net acreage position at the end of 2012 was 73,124 acres. Statoil entered the Bakken and Three Forks tight oil plays through the acquisition of Brigham Exploration Company in December 2011. We are positioning ourselves as a leading player in the fast-growing US onshore oil and gas industry, which is in line with the strategic direction we have set out. Statoil has developed industrial capabilities step-by-step through early entrance into Marcellus and Eagle Ford. Taking on our first operatorship through Bakken represented a new significant step for us. Statoil's net acreage position at the end of 2012 was 347,164 acres. The Tahiti oilfield (Statoil interest 25%) is operated by Chevron. The field is located in the Green Canyon area of the deepwater Gulf of Mexico. It consists of seven wells in three locations connected to a floating facility. The Caesar Tonga oilfield (Statoil interest 23.6%) is operated by Anadarko Petroleum. The field is located in the Green Canyon area. It consists of three wells tied back to the Anadarko-operated Constitution spar host. The field started production on 7 March 2012. 3.6.2.2 South America and sub-Saharan Africa Production activities in South America and sub-Saharan Africa comprise the Peregrino operatorship in Brazil, the Petrocedenõ project in Venezuela, the Agbami project in Nigeria, and four Angolan offshore blocks. Brazil The Peregrino field is a heavy oil field located in the Campos Basin, about 85 kilometres off the coast of Rio de Janeiro. The field came on stream in 2011. The oil is produced from two well head platforms with drilling capability and it is processed on the Peregrino FPSO. Statoil holds a 60% ownership interest in the field and is the operator. Venezuela Statoil has a 9.7% interest in Petrocedeño, one of the largest extra-heavy crude oil projects in Venezuela. The field is located onshore in the Orinoco Belt area. Petrocedeño, S.A, which is owned by project partners PDVSA, Total and Statoil, operates the field with related facilities and markets the products. The Petrocedeño plant is still operating below design capacity. A recovery programme is ongoing to improve the situation. Angola The Angolan continental shelf is the largest contributor to Statoil's production outside Norway. The main producing fields are Dalia, Pazflor, Girassol/Jasmim and Rosa. Block 17 comprises production from three large FPSOs; Girassol, Dalia and Pazflor. Block 17 is operated by Total, and Statoil holds a 23.3% interest. Block 15 has production from the Kizomba A, Kizomba B, Kizomba C-Mondo and Kizomba C-Saxi Batuque FPSOs. In addition, one satellite, Marimba, is producing through a subsea tie-back to the Kizomba A FPSO. In 2012, the Kizomba Satellites phase 1, consisting of the Clochas and Mavacola discoveries, came into production, producing both over the Kizomba A and the Kizomba B FPSO. Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil, and Statoil holds a 13.3% interest in Block 15. Block 4/05 includes the Gimboa field, which is produced over the Gimboa FPSO. Sonangol P&P is the operator for block 4/05 and Statoil holds a 20% interest. Block 31 came into production in December 2012 with the start-up of the PSVM FPSO. BP is the operator for Block 31 and Statoil holds a 13.3% interest. 28 Statoil, Annual report on Form 20-F 2012


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    Nigeria In Nigeria, Statoil has a 20.2% interest in the country's largest deepwater producing field, Agbami, where Chevron is the operator. The National Assembly is still debating the Petroleum Industry Bill (PIB), which will most likely increase the government take if passed. Timing and outcome are uncertain. Together with our partner Chevron, we have initiated arbitration with the national oil company NNPC concerning the interpretation of certain clauses in the production-sharing contract (PSC) that governs our share of Agbami. 3.6.2.3 Middle East and North Africa Statoil's production in the Middle East and North Africa in 2012 took place in Algeria and Libya. Algeria The In Salah onshore gas development in which Statoil has a 31.9% interest is Algeria's third-largest gas development. The field is currently producing at plateau level of around 130 mboe per day. A contract of association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil. In the In Salah Gas Compression Project, gas compression facilities were installed on the three existing northern fields in 2010 in order to maintain production rates from the fields. The In Amenas onshore development is the fourth-largest gas development in Algeria. It contains significant liquid volumes. The facilities are operated through a joint operatorship between Sonatrach, BP and Statoil, where Statoil's share of the investments (working interest) is 45.9%. On 16 January 2013, Statoil, together with partners BP and Sonatrach, were hit by a terrorist attack at the In Amenas gas production facility. Five Statoil colleagues lost their lives in the attack. Statoil has initiated an investigation to determine the relevant chain of events before, during and after the attack in order to provide the company with a basis for making further improvements to its security, risk assessment and emergency preparedness. On 22 February, limited production from the plant recommenced, but the effect of the attack on production in 2013 remains uncertain. Statoil will not return personnel until the necessary security conditions have been established. Libya In February 2011, following the Libyan civil war, Statoil's Libyan operations were suspended and Statoil's offices in Tripoli were temporarily closed. Statoil's office in Tripoli was reopened on 20 March 2012. Statoil is a partner in two licences, Murzuq and Mabruk. Statoil has a 10% share of investments (working interest) in the NC 186 licence in the Murzuq field, which is operated by Akakus Oil Operations, with Repsol as the lead partner for the international oil companies. Murzuq resumed production in November 2011. Statoil has a 12.5% share of investments (working interest) in the C-17 licence in the Mabruk field, which is operated by Mabruk Oil Operations. Total is the lead partner for the international oil companies in the C-17 licence Mabruk. Mabruk resumed production in January 2012. 3.6.2.4 Europe and Asia Production in Europe and Asia encompasses Azerbaijan, Russia and the United Kingdom. Azerbaijan Statoil has an 8.6% stake in the Azeri-Chirag-Gunashli (ACG) oilfield and a 25.5% share in the Shah Deniz gas and condensate field. BP is the operator for both fields. Statoil has an 8.7% stake in the 1,760-km Baku-Tbilisi-Ceyhan (BTC) pipeline that is used to transport most of the ACG oil and Shah Deniz condensate to the southern Turkish port of Ceyhan, enabling liquids to be shipped to the world's markets. Statoil has a 25.5% share in the South Caucasus Pipeline, which transports the Shah Deniz gas from Azerbaijan through Georgia to the eastern Turkish border. Statoil is the commercial operator of the South Caucasus Pipeline Company, responsible for commercial operations relating to the South Caucasus Pipeline. Statoil also runs the Azerbaijan Gas Sales Company, which has been established to manage gas allocation and sales to customers in Azerbaijan, Georgia and Turkey. Russia Statoil has a 30% share in the Kharyaga oilfield onshore in the Timan Pechora basin in north-west Russia. The field is being developed in phases under a production sharing agreement (PSA), and it is operated by Total. Statoil, Annual report on Form 20-F 2012 29


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    United Kingdom In the UK, Statoil is a partner in three production licences. The Alba oilfield (Statoil interest 17%) is located in the central part of the UK North Sea and is operated by Chevron. The Schiehallion oilfield (Statoil interest 5.9%) is located west of the Shetland Islands and is operated by BP. Jupiter (Statoil interest 30%) is a gas field located in the southern part of the UK North Sea, and ConocoPhillips is the operator of the field. 3.6.3 International exploration Statoil has significant international exploration activity, and the company was involved in 27 wells that were completed in 2012. Statoil has significant international exploration activity, and we were involved in 27 wells that were completed in 2012 (including both Statoil-operated and partner-operated activity). Nine wells (exploration and appraisal) were announced as discoveries in the period, including the Pão de Açúcar discovery (operated by Repsol), and the Zafarani and Lavani (Statoil-operated) discoveries in Tanzania. A total of 12 wells were reported dry, while six wells were under evaluation at year end. Statoil signed a cooperation agreement with Rosneft in May 2012 to jointly explore offshore frontier areas in Russia and Norway and to conduct joint technical studies on two onshore Russian assets. The offshore licences are Perseevsky (located in the Russian part of the Central Barents Sea) and Kashevarovsky, Lisyansky and Magadan-1 (all in the Sea of Okhotsk). The onshore licences are North-Komsomolskoye (West Siberia) and Stavropol (Stavropol region). Several agreements detailing the cooperation have since been signed, and work is ongoing to conclude the remaining agreements. The table below shows the exploratory wells drilled internationally in the last three years. The lifting of the Gulf of Mexico moratorium and increased activity in several countries, particularly Indonesia and Tanzania, have led to the completion of more international wells than in previous years. 2012 2011 2010 North America -Statoil operated 3 2 0 -Partner operated 6 4 5 South America/sub-saharan Africa -Statoil operated 5 3 0 -Partner operated 7 4 10 Middle East and North-Africa -Statoil operated 0 1 0 -Partner operated 1 0 2 Europe and Asia -Statoil operated 3 0 0 -Partner operated 2 2 1 Totals 27 16 18 The regions where Statoil had exploration activity in 2012 are presented below. North America USA Statoil has significant activities in the USA, with approximately 340 (as of 31 December 2012) exploration leases in the Gulf of Mexico (GoM) and 66 in Alaska - about 19,500 and 1,500 square kilometres respectively. The group was successful in the Department of the Interior's GoM Central Region lease sale, winning 26 leases in 2012. Statoil was among the most active explorers in the GoM in 2012, serving as the operator for three completed wells: Kilchurn and the Kilchurn sidetrack, which are under evaluation, and Bioko (dry). In addition, the group was involved in three partner-operated wildcat wells and three appraisal wells. In 2012, Statoil's exploration activities in the GoM have returned to a level similar to that prior to the Macondo incident. Canada Off the coast of Canada, Statoil is operator and partner in 12 exploration licences (ELs), including both off the coast of Newfoundland and in the Beaufort Sea. Statoil is also operator for four significant discovery licences (SDLs) off the coast of Newfoundland. In 2012, Statoil was awarded two licences in the Flemish Pass basin and entered the Orphan basin as a partner in line with its early access at scale strategy. Statoil also entered the Beaufort Sea as part of the group's overall move into Arctic exploration. In 2012, Statoil and partners Chevron Canada and Repsol E&P Canada acquired 3D seismic data in preparation for future drilling activities. 30 Statoil, Annual report on Form 20-F 2012


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    South America and sub-Saharan Africa Angola Statoil has interests in five blocks in the Congo basin and five blocks in the Kwanza basin (pre-salt licences), with participating interests varying from 5% to 55%. Acquisition of a 26,000-square-kilometre 3D survey in the Kwanza basin (covering Blocks 24, 25, 38, 39 and 40) started on 1 January 2012. The priority area in Block 39 was completed in June and fast-track products were delivered in December of the same year, while acquisition of a larger area continued until January 2013. Brazil Statoil holds acreage in the Campos basin and in the frontier Espírito Santo, Jequitinhonha and Camamu-Almada basins. In December, Statoil acquired 25% of the BM-ES-22A licence in Brazil through an agreement with Vale SA. The transaction is subject to approval by Brazilian authorities and other conditions prior to closing. Two wells were announced as discoveries in 2012: the Pão de Açúcar discovery (operated by Repsol) and the Peregrino South appraisal discovery (Statoil- operated) in Brazil. Tanzania Statoil operates Block 2 and holds a 65% working interest. Two exploration wells have been drilled in 2012, proving significant volumes of gas in the Zafarani and Lavani prospects. Moreover, a successful appraisal well on Lavani was announced in 2012. In March 2013 the Tangawizi exploration well was announced as discovery, proving further significant gas volumes. More prospects in the block will be tested in 2013. Ghana Statoil acquired first acreage in Ghana by taking a 35% share in a deepwater licence operated by Hess. The driver for Statoil entering this licence was to test a new play. Hydrocarbons were found in a proven play, but the discovery was considered too small to compete with other ongoing projects. Statoil has divested its share in this block. Mozambique In 2012, Statoil farmed down a 25% working interest in its exploration licence off the coast of Mozambique in the Rovuma basin. Statoil operates the licence and retains a 65% working interest after the farm down. The licence covers 7,800 square kilometres with a water depth that varies between 300 and 2,400 metres. The partnership is now preparing to spud the first well. Suriname Statoil has a 30% share in Block 47 in a frontier area in the Guyana Basin. The acquisition of 3,000 square kilometres of 3D seismic was finalised in September 2012. Middle East and North Africa Statoil has exploration licences in Libya, but there was no activity in 2012 due to the unrest in the country. We participated in one appraisal well on the Hassi Farida discovery in Algeria. Europe and Asia (excluding Norway) UK Statoil was awarded seven exploration licences on the UK continental shelf in 2012. We have committed to drilling three wells in one licence and to acquiring or reprocessing seismic in the other licences. Statoil will be the operator for two of the licences and our working interest varies from 20% to 60%. The licences are situated in the Catcher area on the Western Platform and in the Faroe-Shetland basin. Faroe Islands Statoil operates five licences in the Faroe Islands, with working interests ranging from 40% to 50%. Drilling of the Brugdan II well started in 2012, but it was decided to temporarily suspend drilling operations due to the expected bad weather in the winter season. Drilling will resume at a later stage. We also acquired 3D seismic data for two licences in 2012. L010 expired at the beginning of March 2013. Greenland Statoil is a partner in three licences off the coast of West Greenland, with interests ranging from 15% to 31%; 3D seismic data was acquired in Blocks 5 and 8 in 2012. All commitments in the current exploration period have been fulfilled. Indonesia Statoil has interests in eight production-sharing contract (PSC) licences in Indonesia. Our working interests in the licences vary from 19% to 80%, and we operate Halmahera II. Our working interest in the Aru PSC was acquired in 2012, and we committed to acquiring 3D seismic data. The Karama licence has been relinquished. Statoil, Annual report on Form 20-F 2012 31


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    Germany Statoil entered the Rhein and Ruhr licences through a farm-in agreement with Wintershall in 2012. Statoil has a 49% interest in the licences. The licences target unconventional gas exploration and the commitments are to drill four shallow wells in addition to shooting 300 kilometres of 2D seismic. 3.6.4 Fields under development internationally The main sanctioned development projects in which DPI is involved are in the USA, Angola and the UK. We believe we are well positioned for further growth through a substantial pre-sanctioned project portfolio. This section covers projects under development. Significant pre-sanctioned projects, including some discoveries in the early evaluation phase, are also presented. Statoil’s share at Time of Sanctioned projects coming on stream 2013-2014 * 31 December 2012 Operator sanctioning Production start Azerbaijan: Chiraq oil project 8.56% BP 2010 2013 Algeria: In Salah Southern Fields 31.85% Sonatrach/BP/Statoil 2010 2014 Angola: CLOV 23.33% Total 2010 2014 USA: Big Foot 27.50% Chevron 2010 2014 USA: Jack 25.00% Chevron 2010 2014 USA: St. Malo 21.50% Chevron 2010 2014 Canada: Hibernia South Extension 10.50% Exxon Mobil 2011 2014 * Not exhaustive 3.6.4.1 North America Statoil has significant ongoing development projects in North America. Caesar Tonga (Statoil interest 23.6%) in the US, operated by Anadarko Petroleum, is expected to add one producing well with a tie back to the Anadarko- operated Constitution Spar host in the second quarter of 2013. Tahiti Phase 2 (Statoil interest 25%) in the US, operated by Chevron, will add two producing and three water-injection wells. Injection from the first two water-injection wells started in the first quarter 2012, while first oil from two additional producers is expected in the second half of 2013. Statoil has a 25% working interest in the Jack oilfield and a 21.5% working interest in St. Malo, located in Walker Ridge. The two fields are operated by Chevron and will be developed jointly with subsea wells connected to a centrally located production platform. First oil is expected in late 2014. Statoil has a 27.5% interest in Big Foot located in Walker Ridge block 29. Big Foot is operated by Chevron and will be developed with a dry tree tension leg platform with a drilling rig. First oil from Big Foot is scheduled for mid-2014. Discovered in 2007, Julia (Statoil interest 50%) is one of the major discoveries in the Paleogene, with a significant in-place volume. After judicial proceedings and a settlement, a Suspension of Production was issued for the Julia Unit by the Bureau of Safety and Environmental Enforcement (BSEE) in January 2012. The operator ExxonMobil has restarted the project and is making progress in accordance with the agreed schedule. First oil is expected by mid-2016. In Canada, Statoil has a 60% interest and is the operator of the KKD Oil Sands Partnership. Statoil is maturing the Corner and Leismer Expansion projects to the concept selection phase. The first phase, the Leismer Demonstration Project, came on stream in early 2011. Statoil has a 10.5% interest in the Exxon-operated Hibernia South Extension (a satellite of Hibernia) and all wells are expected to be online in 2014. On Canada's east coast, Statoil has a 9.7% interest in the Exxon-operated Hebron field located in the Jeanne d'Arc basin near the other partner-operated fields Terra Nova and Hibernia. The Hebron partners sanctioned the project in 2012. First oil is expected in 2017. 32 Statoil, Annual report on Form 20-F 2012


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    3.6.4.2 South America and sub-Saharan Africa In 2012, South America and sub-Saharan Africa had several ongoing field development projects in Angola. In Block 17, Angola, the CLOV project, consisting of the Cravo, Lirio, Orchidea and Violeta discoveries, was approved in 2010. The first oil is expected in 2014. CLOV will be produced over a new FPSO. Block 17 is operated by Total, and Statoil holds a 23.3% interest. In Block 15, Angola, the Kizomba Satellites phase 2 consists of the discoveries Bavuka, Kakocha, and Mondo South. All major development contracts for the Kizomba Satellites Phase 2 Project have been approved by the contracting group and Sonangol, and the project is progressing according to plan. First oil is scheduled for 2016. Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil, with Statoil holding a 13.3% interest in this block. In Block 15/06, Angola, development of the discoveries that was approved in 2012, Sangos, N'Goma and Cinguvu, is currently ongoing. Block 15/06 is operated by Eni, and Statoil's interest is 5%. 3.6.4.3 Middle East and North Africa In 2012, Statoil's field development in the Middle East and North Africa was focused on Algeria, and we left the West Qurna 2 project in Iraq. The In Salah Southern Field Development Project in Algeria was sanctioned in late 2010. In January 2011, Statoil announced that the development plan was approved. This project will mature the remaining four discoveries into production and it is scheduled to come on stream in 2014. The southern fields will tie in to existing facilities in the northern fields. A contract of association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil. The In Amenas Gas Compression Project in Algeria, which is led by BP, was sanctioned in late 2010. The compressors are expected to come on stream in 2014. This will make it possible to reduce well head pressure and maintain the contractual production commitment. The In Amenas facilities are operated through a joint operatorship between Sonatrach, BP and Statoil. The Hassi Mouina exploration phase was extended until September 2012. We still aim to develop the field, but need to reach agreement with the Algerian authorities on technical and commercial terms. In May 2012, Statoil's exit from the West Qurna 2 project in Iraq was formally approved by the Iraqi authorities. Statoil's 18.75% share was subsequently transferred to Lukoil. Statoil became a partner in this project after a technical service agreement was signed with the Iraqi authorities in early 2010. 3.6.4.4 Europe and Asia In Europe and Asia, Statoil is participating in the planning and development of projects in Azerbaijan, Russia, the United Kingdom and Ireland. Azerbaijan The Chirag Oil Project, the sixth platform on the ACG oilfield, was sanctioned by the ACG partnership in 2010. It has a design capacity of 185 mboe per day. BP is the operator for this project. First production from this project is scheduled for late 2013. The concept for the Shah Deniz Stage 2 field development was agreed by the partners in late 2010. Project development operator BP estimates annual production from Shah Deniz Stage 2 to be 16 bcm of gas per year and about 100 mboe per day of condensate. The current plan is to make a final investment decision in 2013. That would mean first gas from the Shah Deniz Stage 2 in 2018. United Kingdom Statoil is the operator for the Mariner heavy oil project and has a 65.1% interest. In December 2012, Statoil made the investment decision to develop the Mariner oilfield development. The field development plan was approved by the UK authorities in February 2013. The concept selected includes a production, drilling and quarters platform based on a steel jacket, with a floating storage unit. Statoil expects first oil in early 2017. The field development plan for Mariner includes the subsea tie-in of Mariner East, a small heavy oil discovery. We are the operator and increased our equity to 92% in June 2012 through an equity swap with OMV. Statoil, Annual report on Form 20-F 2012 33


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    Statoil is the operator for and holds an 81.6% interest in Bressay. Bressay is also a heavy oil discovery for which concept selection was approved in March 2013. Rosebank is a heavy oil project operated by Chevron. In 2012, the partners reached concept selection, an FPSO. Statoil has a 30% share in this project. Ireland Statoil has a 36.5% interest in the Corrib gas field operated by Shell, which is under development. According to the operator, outstanding work at the onshore processing terminal will be completed by summer 2013. Commissioning is planned for 2014. First gas from Corrib will depend on the duration of the tunnelling work and/or the timing of permits required for the operation of the field. 34 Statoil, Annual report on Form 20-F 2012


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    3.7 Marketing, Processing and Renewable Energy (MPR) 3.7.1 MPR overview Marketing, Processing and Renewable Energy (MPR) is responsible for the marketing and trading of crude oil, natural gas, liquids and refined products, for transportation and processing, and for developing business opportunities in renewables. MPR markets Statoil's own volumes and the Norwegian state's direct financial interest (SDFI) equity production of crude oil, in addition to third-party volumes. MPR is also responsible for marketing gas supplies relating to the SDFI. In total, we are responsible for marketing approximately 70% of all Norwegian gas exports. MPR is responsible for running two refineries, two gas processing plants, one methanol plant and three crude oil terminals. We are also responsible for developing a profitable renewable energy position. In 2012, we sold 41.3 billion cubic metres (bcm) of natural gas from the Norwegian continental shelf (NCS) on our own behalf, in addition to approximately 39.9 bcm of NCS gas on behalf of the Norwegian State. Statoil's total European gas sales, including third-party gas, amounted to 87.5 bcm in 2012, 43.2 bcm of which was gas sold on behalf of the Norwegian State. That makes us the second-largest gas supplier to Europe. The largest supplier is Gazprom. In 2012, we also sold 714 million barrels of crude oil and condensate, approximately 15 million tonnes of refined oil products from our own refineries, and 14 million tonnes of natural gas liquids (NGL). Tjeldbergodden produced approximately 807,000 tonnes of methanol. Our international trading activities make us one of the world's largest net crude oil sellers. In 2012, the gas market was characterised by high market prices and good customer off-take. Refinery margins and trading margins were higher than in 2011. The operation of facilities has been stable, and HSE results are within our target for the year. The MPR business activities are organised in the following business clusters: Natural gas; Crude oil, liquids and products; Processing and manufacturing; and Renewable energy. This structure is followed in the further discussions of MPR's business activities. Key events in 2012: Statoil started transporting Bakken crude from North Dakota in the US to the market by rail. Statoil and Wintershall entered into a 10-year gas sales agreement for the delivery of a total of 45 billion cubic metres (bcm) to the German and other north west European markets. The Sheringham Shoal offshore wind farm (owned equally by Statoil and Statkraft through the joint venture company Scira Offshore Energy Limited) was officially opened. Together with Statkraft, we acquired the Dudgeon offshore wind farm project (off the UK coast) through the acquisition of all the shares in Dudgeon Offshore Wind Limited. Statoil will hold a 70% share in the company 3.7.2 Natural Gas The natural gas (NG) business cluster is responsible for Statoil's marketing and trading of natural gas worldwide, for power and emissions trading and for overall gas supply planning and optimisation. In addition, NG is responsible for marketing gas related to the Norwegian state's direct financial interest (SDFI) and for managing Statoil's asset ownership in gas infrastructure, such as the processing and transportation system for Norwegian gas (Gassled) and gathering and processing in the Marcellus shale gas play. NG's business is conducted from Norway (Stavanger) and from offices in Belgium, the UK, Germany, Turkey, Azerbaijan and the US (Houston and Stamford). Statoil, Annual report on Form 20-F 2012 35


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    NG is a significant shipper in the NCS pipeline system owned by Gassled, which is the world's largest offshore gas pipeline transportation system. This network links gas fields on the Norwegian continental shelf (NCS) with processing plants on the Norwegian mainland and with terminals at six landing points located in France, Germany, Belgium and the UK. This gives us access to customers throughout Europe. By the end of 2012, Statoil had a 5% ownership interest in the Gassled transportation system. 3.7.2.1 Gas sales and marketing We transport and market approximately 70% of all NCS gas and have a growing US gas position. In Europe, the gas is sold through long-term contracts with major European utilities, and a growing proportion is sold directly and on traded markets. The direct sales take place with large industrial customers, power producers and local distribution companies, and through short-term contracts and trading on European liquid marketplaces, both in the UK and on the European continent. In the US, gas is sold through a mix of contracts and trading in liquid marketplaces. Due to the relatively large size of the NCS gas fields and the extensive cost of developing new fields and gas transportation pipelines, a large proportion of Statoil's gas sales contracts are long-term contracts that typically run for 10 to 20 years or more. Most of the traditional long-term gas contracts contain contractual price review mechanisms that can be triggered by the buyer or seller at regular intervals, or under certain given circumstances. As a result of recent ongoing gas market developments in many regions in Europe, Statoil has used the price reviews to agree structural solutions for the long term with several of its customers. Key characteristics are a gradual transition from oil indexation towards gas hub- related pricing, as well as a reduction in some volume commitments and of the buyers' daily and annual flexibility. Statoil expects to continue to optimise the market value of the gas delivered to Europe through a mix of long-term contracts and short-term marketing and trading opportunities. This is done both in response to customer needs and in order to capture new business opportunities as the markets become more liberalised. Europe The major export markets for gas from the NCS are Germany, France, the UK, Belgium, Italy, the Netherlands and Spain. Most of the gas is sold through long-term contracts. Our main customers are large national or regional gas companies such as E.ON Ruhrgas, GdF Suez, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), RWE and GasTerra. We are also growing our marketing of gas to large industrial customers, power producers and wholesalers in addition to spot market sales. Our group-wide gas trading activity is mainly focused on the UK gas market NBP (National Balancing Point UK), which is a significant market in terms of size and the most liberalised market in Europe. We are also increasing our activity in continental marketplaces in France, the Netherlands, Belgium and Germany. Statoil has end-user sales business based in Belgium and the UK, serving major customers in Belgium, the UK, the Netherlands, Germany and France. Statoil UK holds a one-third stake in Aldbrough Gas Storage, operated by SSE Hornsea Ltd. During 2012 all nine caverns came into full commercial operation. In Germany, we hold a 30.8% stake in the Norddeutche Erdgas Transversale (Netra) overland gas transmission pipeline and a 23.7% stake in Etzel Gas Lager. USA The US is the world's largest and most liquid gas market. Statoil Natural Gas LLC (SNG), a wholly owned subsidiary, has a gas marketing and trading organisation in Stamford, Connecticut that markets natural gas to local distribution companies, industrial customers and power generators. SNG has two long-term capacity contracts with Dominion Resources Inc., which owns the Cove Point LNG re-gasification terminal in Maryland, with a total capacity of 10.9 bcm per year. The long-term capacity agreement was renegotiated in December 2010 and, as a consequence, Statoil's commitments relating to the re-gasification capacity at Cove Point (CPX) have been significantly reduced. Through Statoil, SDFI pays for a share of the capacity at the Cove Point re-gasification terminal, downstream pipeline capacity and storage capacity. LNG is sourced from the Snøhvit LNG facility in Norway and from third-party suppliers. Market demand for LNG has shown a weaker trend since June 2012, compared to the first half of 2012. However, the latest market signals indicate a positive upward trend. Due to continued low prices in the US, no LNG cargoes have been delivered to the US. Statoil's LNG cargoes have been diverted away from the US market into higher-priced markets in Europe, South America and Asia. 36 Statoil, Annual report on Form 20-F 2012


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    Statoil's entry into the Marcellus and the Eagle Ford shale gas plays has resulted in a significant increase in the volume of gas marketed and traded by Statoil in the US in recent years. SNG also markets the gas equity production from Statoil's assets in the US Gulf of Mexico. SNG has entered into gas transportation agreements with Tennessee Gas Pipeline (a subsidiary of El Paso Corp) and Texas Eastern Transmission (a subsidiary of Spectra Energy Corp) for a total capacity of 2 billion cubic metres (bcm) per year, approximately 200,000 mcf/day, enabling Statoil to transport gas from the Northern Marcellus production area to Manhattan, NY, with an expected in-service date in late 2013. SNG has entered into a gas transportation agreement with National Fuel Gas Supply Corporation for a total capacity of 3.2 billion cubic metres (bcm) per year, approximately 320,000 mcf/day, enabling Statoil to transport gas from the Northern Marcellus production area to the US/Canadian border at Niagara, providing access to the greater Toronto area in Canada. The National Fuel pipeline commenced service on 1 November 2012. Azerbaijan Statoil has an ownership interest in the Shah Deniz gas/condensate field in Azerbaijan and is the commercial operator for gas transportation as well as the operator of marketing and sales of gas from Shah Deniz stage 1. In addition, Statoil heads up the Gas Commercial Committee and plays a key role in the gas export negotiation committee for the Shah Deniz stage 2 project. Azerbaijan, Georgia and Turkey are part of the gas sales portfolio for stage 1, in which Turkey constitutes the main market. For the stage 2 development of Shah Deniz, the current plan is to make a final investment decision in 2013. In June 2012, the governments of Turkey and Azerbaijan signed an inter-governmental agreement relating to the development of an independent pipeline for the transit of gas across Turkey. During the first half of 2012, the Shah Deniz consortium reduced the number of competing pipelines for the further transportation of gas into the European markets to one in the Italian corridor and one in the corridor towards Baumgarten, Austria. Together with key partners in Shah Deniz, Statoil is preparing to resume negotiations with potential buyers in Europe in order to be able to conclude the sale of gas from Shah Deniz stage 2 and the pipeline route to Europe by mid-2013. Algeria Statoil has ownership interests in the In Salah and In Amenas gas fields, Algeria's third-largest and fourth-largest gas developments, respectively. All of the gas produced is sold under long-term contracts, mainly to Europe. Statoil, Annual report on Form 20-F 2012 37


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    3.7.2.2 The Norwegian gas transportation system Over the last 30 years, the Norwegian gas pipeline system has been developed into an integrated system connecting gas-producing fields on the Norwegian continental shelf (NCS) with receiving terminals in Europe via processing plants on the Norwegian mainland. The total length of Norway's gas pipelines is currently 8,100 kilometres, Norne and all gas pipelines on the NCS that are accessed by third-party customers are owned by a single joint venture, Gassled, with regulated third-party Heidrun access. The Gassled system is operated by the independent system Halt Åsgard operator Gassco AS, which is wholly owned by the Norwegian State. Statoil e is the technical service provider (TSP) for Gassco with respect to the npip Kristin Kårstø and Kollsnes processing terminals, as well as for most of the gas e rt nspo Tjeldbergodden pipeline and platform infrastructure system. tra Ormen Lange ard Nyhamna Faroe Is. In 2011, Statoil divested 24.1% of its ownership interest in Gassled, and Åsg the ownership interest is now 5.0%. The divestment did not affect Statoil's Statfjord position as the largest shipper in Gassled. Norway k lin Heimdal Kollsnes en When new gas infrastructure facilities are merged into Gassled, the mp 2A Ta e 2 pe ownership interests are adjusted in relation to the relative value of the pip eepi S AG B Kårstø assets and each owner's relative interest. Hence, Statoil's future ownership Z FL led er e interest in Gassled may change as a result of the inclusion of new pip st Zee Ve at St infrastructure. Sleipner Draupner St. Fergus Ekofisk dele Europ Denmark Lang ip e II Eu ro pip pi No pe Franpipe r I Zeepipe 1 e Easington Dornum Emden United Kingdom Netherlands 130003_STN087313 Germany Zeebrugge Dunkerque Belgium 3.7.2.3 Processing Statoil is the technical service provider (TSP) for the operation, maintenance and further development of large parts of the gas infrastructure on the NCS on behalf of the operator Gassco. Kollsnes gas processing plant Statoil is the responsible technical service provider (TSP) for the operation, maintenance and further development of the Kollsnes gas processing plant on behalf of the operator Gassco. The processing that takes place at Kollsnes involves separating out the NGL and compressing the dry gas for export via the Gassled pipeline network to receiving terminals in Europe. The Kollsnes plant was initially intended to receive gas from the Troll field only. Kollsnes now also receives gas from the Visund, Kvitebjørn and Fram fields. These volumes are processed through the NGL plant. Kårstø gas processing plant Statoil is the responsible TSP for the operation, maintenance and further development of the Kårstø gas processing plant on behalf of the operator Gassco. 38 Statoil, Annual report on Form 20-F 2012


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    Kårstø processes rich gas and condensate from the NCS received via the Statpipe pipeline, the Åsgard Transport pipeline and the Sleipner condensate pipeline. Products produced at Kårstø include ethane, propane, iso-butane, normal butane, naphtha and stabilised condensate. When all of these products have been separated from the rich gas, the remaining dry gas is sent to customers through the Gassled pipeline network to receiving terminals in Europe. The Kårstø processing plant has been undergoing comprehensive upgrading in order to meet safety and technical requirements, and future needs. The Kårstø Expansion Project (KEP) is intended to make the Kårstø facilities more robust and ensure safe and efficient operation. The total project investment is estimated to be approximately NOK 6 billion. It is expected to be completed in 2013. 3.7.3 Crude oil, liquids and products The crude oil, liquids and products (CLP) business cluster adds value through the processing and sale of the group's and the Norwegian state's direct financial interest (SDFI) production of crude oil and natural gas liquids. CLP is responsible for the group's transportation, marketing and trading of crude oil, natural gas liquids and refined products, including methanol. CLP is also responsible for the commercial operation of the two refineries at Mongstad, Norway and Kalundborg, Denmark, and for the commercial operation of the crude oil terminals at Mongstad, Norway and at South Riding Point, Bahamas. In addition, CLP is responsible for managing Statoil's asset ownership in gathering and processing of Eagle Ford shale gas and Bakken tight oil. In 2012, CLP sold 714 million barrels of crude oil and condensate, approximately 15 million tonnes of refined oil products from our own refineries and 14 million tonnes of natural gas liquids (NGL). 3.7.3.1 Marketing and trading Statoil is one of the world's major net sellers of crude oil, operating from sales offices in Stavanger, Oslo, London, Singapore, Stamford and Calgary and marketing and trading crude oil, condensate, NGL and refined products. Statoil markets its own volumes and the Norwegian state's direct financial interest (SDFI) equity production of crude oil and NGL, in addition to third-party volumes. In 2012, MPR sold 714 million barrels of crude and condensate, including supplies to our own refineries, while NGL volumes were 171 million barrels. The main crude oil market for Statoil is north-west Europe. In addition, volumes are sold to North America and Asia. Most of the crude oil volumes are sold in the spot market based on publicly quoted market prices. Of the total 714 million barrels sold in 2012, approximately 38% were Statoil's own equity volumes. Of the total 171 million barrels of NGL sold in 2012, approximately 39% were Statoil's own equity volumes. The CLP business cluster is responsible for optimising commercial utilisation of the crude terminal located at Mongstad and the South Riding Point crude oil terminal in the Bahamas. We are also responsible for Statoil's crude and liquefied petroleum gas (LPG) liftings at the Sture terminal, as well as Statoil's naphtha lifting from Kårstø and Braefoot Bay, and liftings of LPG from Kårstø, Mongstad, Braefoot Bay and Teeside terminals. We lift waterborne ethane from Kårstø, and Teesside Condensate and LPG volumes from Melkøya. CLP also lifts equity LPG and condensate from Algeria. In addition, we market equity crude oil, condensate and NGL production from Statoil's unconventional assets in North America. They include Alberta oil sands, Bakken, Eagle Ford, and Marcellus. Unconventional volumes were mostly sold in the spot market based on publicly quoted prices. Marketing activities are also optimised through lease contracts and long-term agreements for the utilisation of third-party assets. 3.7.3.2 Processing and transportation We operate the Mongstad terminal and share ownership of it with Petoro. We also hold the lease for the South Riding Point crude oil terminal in the Bahamas, which includes crude oil storage and blending as well as loading and unloading facilities. South Riding Point The terminal, which is located on Grand Bahamas Island, consists of two shipping berths and ten storage tanks of crude oil. The terminal has been upgraded to also enable the blending of crude oils, including heavy oils. The blending is carried out onshore and from ship to ship at the jetty. Statoil, Annual report on Form 20-F 2012 39


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    The terminal is intended to both support our global trading ambitions and improve our handling capacity for heavy oils. We also expect the blending facilities and full terminal capacity to strengthen our marketing and trading positions in the North American market. The terminal is an integral part of our marketing of equity volumes of heavy oil. Mongstad terminal Statoil operates the Mongstad terminal, which has storage capacity of 9.4 million barrels of crude oil. Statoil has an ownership interest of 65%, while Petoro has 35%. Crude oil is landed at Mongstad via two pipelines from Troll, by dedicated vessels from Heidrun and by crude vessels from the market. The terminal supports Statoil's global trading, blending and transshipment of crude. It is an important tool in the marketing of North Sea crude. 3.7.4 Processing and manufacturing The processing and manufacturing business cluster is responsible for the operation of all of Statoil's onshore facilities in Norway except for Snøhvit. This includes the refineries at Mongstad and Kalundborg, the methanol production plant at Tjeldbergodden and the gas processing plants at Kårstø and Kollsnes. Processing and manufacturing is also responsible for the operation of the Oseberg Transportation System and, until 1 November 2012, it was responsible for the oil terminal at South Riding Point in the Bahamas. In addition, we own 10% of production capacity at the Shell-operated refinery in Pernis in the Netherlands, which has a crude oil distillation capacity of 400,000 barrels per day. Processing and manufacturing performs the role of technical service provider (TSP) for the Kårstø and Kollsnes gas processing plants in accordance with the technical service agreement between Statoil and the operator Gassco. Processing and manufacturing also performs the TSP role for Transport Net (Norway's gas transport system) and, until 1 November 2012, it was TSP for the oil terminal at South Riding Point, Bahamas. For further information about Kårstø, Kollsnes, Transport Net and South Riding Point, see the sections Business overview - Marketing, Processing and Renewable Energy - Natural Gas and Crude oil, liquids and products, respectively. The following table shows operating statistics for the plants at Mongstad, Kalundborg and Tjeldbergodden. All data for year ended 31 December Throughput (1) Distillation capacity (2) On stream factor % (3) Utilisation rate % (4) Refinery 2012 2011 2010 2012 2011 2010 2012 2011 2010 2012 2011 2010 Mongstad 11.9 11.3 9.9 9.4 9.3 8.7 95.2 98.4 97.3 92.7 89.9 82.7 Kalundborg 4.9 4.4 4.8 5.4 5.4 5.5 94.4 93.24 97.2 88.8 95.9 86.6 Tjeldbergodden 0.81 0.86 0.8 0.95 0.95 0.95 86.4 97.2 95.0 97.5 97.3 96.9 (1) Actual throughput of crude oils, condensates, NGL, feed and blendstock, measured in million tonnes. Higher than distillation capacity for Mongstad due to high volumes of fuel oil and NGL not going through the crude distillation unit. (2) Nominal crude oil and condensate distillation capacity, and methanol production capacity, measured in million tonnes. (3) Composite reliability factor for all processing units, excluding turnarounds. (4) Composite utilisation rate for all processing units, stream day utilisation. Mongstad Statoil is the majority owner (79%) and operator of the Mongstad refinery in Norway, which has a crude oil and condensate distillation capacity of 240,000 barrels per day. The Mongstad refinery is a medium-sized, modern refinery. It is linked to offshore fields, the Sture crude oil terminal and the Kollsnes gas processing plant, making it an attractive site for landing and processing hydrocarbons. The Mongstad refinery, which was built in 1975, was significantly expanded and upgraded in the late 1980s. It has been subject to considerable investment over the last 15 years in order to meet new product specifications and improved energy efficiency. A medium-sized, modern refinery, it is directly linked to offshore fields through two crude oil pipelines, through a natural gas liquids (NGL)/condensate pipeline to the crude oil terminal at Sture and the gas processing plant at Kollsnes, and by a gas pipeline to Kollsnes. 40 Statoil, Annual report on Form 20-F 2012


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    In addition to the refinery, the main facilities at Mongstad consist of a crude oil terminal, an NGL process unit and terminal (Vestprosess), and a combined heat and power plant (CHP). Statoil owns 65% of the crude terminal. A large proportion of its crude oil comes via two direct pipelines from the Troll field. The storage capacity is 9.4 million barrels of crude. Statoil owns 34% of Vestprosess, which transports and processes NGL and condensate. The Vestprosess pipeline connects the Kollsnes and Sture plants to Mongstad. The NGL is fractionated in the Vestprosess NGL unit to produce naphtha, propane and butane. The CHP plant is 100% owned by Dong Generation Norge AS. It produces electric heat and power from gas received from Troll and from the refinery. The CHP plant started commercial operation in 2010 and improved the Mongstad refinery's energy efficiency. It has a capacity of approximately 280 megawatts of electric power and 350 megawatts of process heat. The plant is operated by Dong Energy. Together with the Norwegian government, Statoil is involved in several projects that aim to develop solutions for carbon capture and storage (CCS) at Mongstad. See the section Business overview - Marketing, Processing and Renewable Energy - Renewable energy for further information. For the year ended 31 December Mongstad product yields and feedstock 2012 2011 2010 LPG 402 3% 378 3% 360 4% Gasoline/naphtha 5,174 43% 4,829 43% 4,258 43% Jet/kerosene 896 7% 783 7% 681 7% Gasoil 4,445 37% 4,234 37% 3,539 36% Fuel oil 224 2% 183 2% 231 2% Coke/sulphur 171 2% 228 2% 174 2% Fuel, flare & loss 639 6% 684 6% 620 6% Total throughput (1) 11,951 100% 11,320 100% 9,863 100% Troll, Heidrun (FOB crude oils) 6,385 53% 6,751 60% 4,516 46% Other North Sea crude oils (CIF crude oil) 2,056 17% 1,777 16% 2,452 25% Other crude oils 609 5% 274 2% Residue 1,185 10% 1,278 11% 1,523 15% Other fuel and blendstock 1,716 15% 1,239 11% 1,372 14% Total feedstock 11,951 100% 11,320 100% 9,863 100% (1) Changes in throughput and yields are partly due to maintenance shutdowns (e.g. major turnarounds in 2010). Kalundborg Statoil is the sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118,000 barrels per day. The Kalundborg refinery is a small but flexible oil refinery. While this enables it to produce a variety of products, its main products are low-sulphur gasoline and diesel for markets in Denmark and Sweden. The refinery is connected via two pipelines (one gasoline and one gas oil) to the terminal at Hedehusene near Copenhagen, and most of its products are therefore sold locally. Kalundborg's refined products are also supplied to other markets in north- western Europe, mainly to Scandinavia. Statoil, Annual report on Form 20-F 2012 41


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    For the year ended 31 December Kalundborg product yields and feedstock 2012 2011 2010 LPG 74 1% 60 1% 80 2% Gasoline/naphtha 1,511 31% 1,399 32% 1,461 31% Jet/kerosene (2) 0% 39 1% 141 3% Gasoil 2,448 50% 1,980 46% 2,124 44% Fuel oil 709 14% 683 16% 756 16% Coke/sulphur 5 0% 6 0% 7 0% Fuel, flare & loss 190 4% 177 4% 186 4% Total throughput (1) 4,935 100% 4,344 100% 4,755 100% Condensates: Ormen Lange, Snøhvit, Sleipner 750 15% 594 14% 754 16% Other North Sea crude oils 3,036 62% 2,854 66% 3,492 73% Other fuel and blendstocks 366 7% 280 6% 234 5% Other crudes 782 16% 617 14% 275 6% Total feedstocks 4,935 100% 4,344 100% 4,755 100% (1) Changes in throughput and yields are partly due to maintenance shutdowns (e.g. major turnaround in 2010). The refinery's reliability (on-stream factor) was good in 2012 and on a par with its best years. The throughput in 2012 was lower due to a planned maintenance turnaround. The product yield from the refinery is well positioned in relation to the expected future structure of demand in the European market. Tjeldbergodden The methanol plant at Tjeldbergodden, the largest in Europe, receives natural gas from the Heidrun field in the Norwegian Sea through the Haltenpipe pipeline. Statoil has an ownership interest of 81.7% of Statoil Metanol ANS at Tjeldbergodden. In addition, Statoil holds a 50.9% ownership interest in Tjeldbergodden Luftgassfabrikk DA, which is one of the largest air separation units (ASU) in Scandinavia. Sture The Sture terminal receives crude oil in two pipelines from the Oseberg area and the Grane field in the North Sea. The terminal is part of the Oseberg Transportation System (Statoil interest 36.2%). The processing facilities at Sture stabilise Oseberg crude oil and recover LPG mix (propane and butane) and naphtha. Oseberg Blend and Grane crude qualities and LPG mix are exported. LPG and naphtha are also transported through the Vestprosess pipeline to Mongstad. 3.7.5 Renewable energy Our renewable energy business focuses on developing business in areas where we have a competitive edge as a result of our offshore oil and gas expertise. Offshore wind and carbon capture and storage are key areas. Sheringham Shoal The Sheringham Shoal wind farm was formally opened in September 2012. The wind farm is now in full production with 88 turbines and an installed capacity of 317MW. It is owned jointly with Statkraft. The estimated annual production is 1.1 TWh and it will provide power for approximately 220,000 households. Hywind The Hywind demonstration facility off the coast of Karmøy in Norway - featuring the world's first full-scale floating offshore wind turbine - has been in operation for three years. The overall performance of Hywind has exceeded expectations. Projects have now been initiated to investigate the possibility of installing the Hywind test pilot scheme in both the US and the UK. In October 2012, Statoil signed an agreement with Hitachi Zosen for a feasibility study of the use of Hywind technology off the coast of Japan. 42 Statoil, Annual report on Form 20-F 2012


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    Dudgeon (new offshore wind project) Statoil acquired a 70% shareholding in the Dudgeon wind farm project in October 2012 together with Statkraft (30%). This project is located in the Greater Wash Area off the English east coast, not far from Sheringham Shoal. The project has received consent, and engineering studies are currently being undertaken to optimise the development concept. The development is expected to be slightly larger than Sheringham Shoal (production of 1.25 TWh, providing power for 250,000 households) and, pending a final investment decision, it could be fully operational in 2017. Dogger Bank Statoil was awarded a 25% share in the UK Third Round Dogger Bank concession in 2010 together with partners RWE, SSE and Statkraft. The joint venture ("Forewind") is currently undertaking environmental studies and preparing applications for consent for the first two projects (each 1.2 GW). These applications are expected to be submitted to the UK planning authorities in the first half of 2013. Production could start towards the end of the decade. Full-scale carbon capture Mongstad (CCM) The Norwegian government and Statoil are planning a full-scale post combustion carbon dioxide capture project in conjunction with the combined heat and power (CHP) station at Mongstad. At full capacity, the volume of captured carbon dioxide from the CHP plant is expected to be around 1.2 million tonnes annually. The full-scale carbon capture plant is a mega-project due to its size, complexity and the uniqueness of the novel technology involved. Five vendors are currently participating in a process for qualification of their capture technology. Through the Mongstad project, Statoil is supporting the realisation of a complete value chain for carbon capture, transport and storage. A final investment decision for this project is planned in 2016. 3.8 Statoil Fuel & Retail Statoil Fuel & Retail (SFR) is a road transportation fuel retailer with a presence in eight countries across Scandinavia and central and eastern Europe. SFR was established in May 2010 as a separate legal entity within the Statoil group. In October 2010, Statoil ASA transferred all activities relating to the fuel and retail business to SFR. Following an initial public offering, the shares of SFR were listed on the Oslo Stock Exchange (Oslo Børs) in October 2010. Up until June 2012, Statoil ASA was the majority shareholder in SFR, holding 54% of the shares. On 19 June 2012, Statoil ASA sold its remaining 54% shareholding in SFR to Alimentation Couche-Tard for a cash consideration of NOK 8.3 billion. Up until this transaction, SFR was fully consolidated in the Statoil group with a 46% non-controlling interest. Following the sale of SFR, the fuel and retail segment ceased to exist, but the fuel supply agreement between Statoil and SFR continues. Sales of fuel from the MPR segment to SFR are presented as external sales in the MPR segment as of 20 June 2012. Statoil, Annual report on Form 20-F 2012 43


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    3.9 Other Group The Other reporting segment includes activities in Global Strategy and Development (GSB); Technology, Projects and Drilling (TPD); and Corporate Staffs and Services. 3.9.1 Global Strategy and Business Development (GSB) Global Strategy and Business Development (GSB) brings together Statoil's corporate strategy, business development and merger and acquisition activities to actively drive growth and corporate development. GSB sets the strategic direction for Statoil and identifies, develops and delivers opportunities for global growth. This is achieved through close collaboration across geographic locations and business areas. Statoil's strategy plays an important role in guiding Statoil's business development focus. GSB's business activities are organised in the following areas: Corporate mergers and acquisitions: responsible for initiating and executing corporate mergers, acquisitions and divestments Corporate strategy and analysis: responsible for corporate strategy development processes, competitor intelligence, industry analysis and the running of Statoil's strategic advisory council Business development execution: responsible for business development project execution, technical evaluation and commercial analysis Until 1 December 2012, the new ventures unit in GSB was responsible for pursuing unconventional resource growth. It established new ventures in Australia, the United States and Germany. As a result of these efforts, the unit became involved in the maturation and drilling of exploration acreage and was consequently moved to a different business area responsible for exploration. 3.9.2 Technology, Projects and Drilling (TPD) Technology, Projects and Drilling (TPD) is an internal function that is responsible for delivering projects and wells and providing global support on standards and procurement. TPD is also responsible for promoting Statoil as a technology company. Research, development and innovation The research, development and innovation (RDI) business cluster is responsible for carrying out research to meet Statoil's business needs. Statoil's RDI portfolio was reorganised in August 2012. The new structure of Statoil's research unit is driven by our ambition to become a world-leading research organisation. RDI is organised in four programmes: Unconventionals, Frontier developments, Mature area developments & IOR, and Exploration. They cover the main upstream building blocks where Statoil is growing. The RDI organisation operates and further develops laboratories and large-scale test facilities, and it has an academia programme that addresses cooperation with universities and research institutes. Statoil has four research centres in Norway, a heavy oil technology centre in Canada and representatives in offices in Beijing (China), Rio de Janeiro (Brazil), Houston (US) and St. John's (Canada), close to many of our international operations. RDI expenditure was approximately NOK 2.1 billion, NOK 2.2 billion and NOK 2.8 billion for the years 2010, 2011 and 2012, respectively. Cooperation with external partners such as academic institutions, RDI institutes and suppliers is crucial in relation to technology. Selected technology advances and important milestones in 2012: Significant increase in the Arctic research activities. Established a programme for unconventional resources, demonstrating the drive to adapt and be at the forefront of future technology challenges. Construction of the IOR (Improved Oil Recovery) centre at Rotvoll (2,000 square metres) has started. A technology centre devoted to develop IOR technologies will help us to reach the 60% IOR ambition on the NCS. Mongstad Technology Centre opened in May 2012. The Mongstad Technology Centre is unique in the global context with its capacity to capture up to 100,000 tonnes of carbon annually from two different exhaust gas streams, using two different capturing technologies. Technology excellence The technology excellence (TEX) business cluster is responsible for delivering technical expertise to projects, business developments and assets globally, and for new technology and the corporate technology strategy. TEX's technological expertise in areas such as petroleum technology, subsea and marine technology, facilities and operations technology, and HSE enhances Statoil's operational performance. Technology development and implementation are used to promote and achieve corporate targets for production growth, 44 Statoil, Annual report on Form 20-F 2012


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    increased regularity, reserve growth, reduced costs and improved drilling efficiency. Technology excellence also supports innovators and entrepreneurs in connection with technology development and commercialisation activities. Selected technology advances and important milestones in 2012: Enhanced recovery through subsea compression on the Gullfaks South field. This technological leap forward represents an important milestone in the efforts to improve recovery from this and other gas fields. Remote-controlled hot tap operation world record at Åsgard. For the first time, remote-controlled machines and an underwater welding robot installed a new tie-in point on a live gas pipeline, without the pipeline being prepared in advance. TVCM - Tordis Vigdis Control System Modifications. Statoil has for the first time replaced the control system in older wells on subsea fields, resulting in significantly longer lifetime for such fields. Fast Model Update (FMU): new technology has made building maintenance and the running of reservoir models much more efficient. The high focus on developing new technology has resulted in an increased number of technologies being ready for implementation. Projects Projects (PRO) is responsible for planning and executing all major facilities development, modification and field decommissioning projects in Statoil. PRO aims for world-class project performance, delivering cost-efficient projects on time and in accordance with high HSE standards and agreed quality standards. PRO continues to emphasise competitive cost and quality in design and execution, to drive performance and be prepared to face the fierce competition of the future. Considerable effort is put into setting the direction of the key drivers in Statoil's projects in the early phase, when the impact on value creation is higher. Experience transfer from fast-track projects is essential, in particular in relation to simplification and swift implementation of improvements. Fast-track projects are subsea tie-in projects in which standardised solutions are used to shorten the time from discovery to production from five to 2.5 years, thus reducing execution costs. PRO keeps up the momentum in simplification and standardisation to ensure lean and agile project development. Substantial economies of scale are achieved through management and procurement strategies across projects. PRO continues to emphasise the development of cross-functional expertise and learning across projects, prerequisites for staying lean and capitalising on synergies. Statoil has an attractive project portfolio comprising around 100 projects in the early phase and 50 in the execution phase. The project portfolio is diverse, ranging from major new field developments to both small and large redevelopment projects on the Norwegian continental shelf (NCS) and internationally. The first field decommissioning projects on the NCS are in progress. Important milestones in 2012: Start-up of Sheringham shoal offshore wind farm, located close to the planned Dudgeon offshore wind power project. Marulk and the first fast-track project, Visund South, started production in 2012. Completion of Mongstad technology centre, Mongstad delayed coker revamp and Åsgard gas transfer. The challenging replacement of risers on Visund, Snorre B and Njord was successfully completed. Oseberg C drilling facility upgrade, Oseberg D heat recovery steam generator and Peregrino salt and sulphate removal were completed. The Troll A living quarters extension was completed, and Troll A 3&4 compressor progressed through 2012. The cutting-edge technology project, Åsgard subsea compression, received the Offshore Northern Seas Conference (ONS) 2012 innovation award for making a technological leap in subsea processing. Gudrun and Valemon continued to progress throughout 2012. The following projects entered the execution phase in 2012: Aasta Hansteen, Gina Krog (formerly Dagny), Mariner and the gas infrastructure project Polarled, Gullfaks subsea compression and the fast-track projects Gullfaks South improved oil recovery, Svalin and Fram H-North, Gullfaks B drilling upgrade, the Snorre and Grane permanent monitoring system, Gullfaks B drilling facilities upgrade and Statfjord B/C fire and gas safety automation system upgrade. Drilling and well Drilling and well (D&W) is responsible for providing cost-efficient well deliveries, ensuring fit-for-purpose drilling facilities and providing expertise and advice to Statoil's global drilling and well operations. D&W focuses on industrialisation of our drilling operations by exploiting new technologies for intelligent and safe well construction. D&W will continue to aim for enhanced operational excellence, and the outlook going forward indicates continuous strong growth in activity. We experienced good HSE results and significant efforts have been made to further develop the compliance and leadership culture in parallel with simplifying and improving our work processes. Statoil, Annual report on Form 20-F 2012 45

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