avatar Equinor Holding Netherlands B.V. Mining
  • Location: ZUID-HOLLAND 
  • Founded: 2006-03-22
  • Website:

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    2014 Annual Report on Form 20-F The Annual Report on Form 20-F is our SEC filing for the fiscal year ended December 31, 2014, as submitted to the US Securities and Exchange Commission. © Statoil 2015 STATOIL ASA BOX 8500 NO-4035 STAVANGER NORWAY TELEPHONE: +47 51 99 00 00 www.statoil.com Cover photo: Harald Pettersen


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    2014 Annual Report on Form 20-F 1 Introduction ................................................................................................................................................................................................................................................................................................ 6 1.1 About the report ............................................................................................................................................................................................................................................................................... 6 1.2 Key figures and highlights............................................................................................................................................................................................................................................................. 7 2 Strategy and market overview ..........................................................................................................................................................................................................................................................8 2.1 Our business environment ............................................................................................................................................................................................................................................................ 8 2.1.1 Market overview ...................................................................................................................................................................................................................................................................... 8 2.1.2 Oil prices and refining margins .......................................................................................................................................................................................................................................... 9 2.1.3 Natural gas prices.................................................................................................................................................................................................................................................................10 2.2 Our corporate strategy ...............................................................................................................................................................................................................................................................10 2.3 Our technology ...............................................................................................................................................................................................................................................................................12 2.4 Group outlook .................................................................................................................................................................................................................................................................................13 3 Business overview ................................................................................................................................................................................................................................................................................14 3.1 Our history........................................................................................................................................................................................................................................................................................14 3.2 Our business ....................................................................................................................................................................................................................................................................................14 3.3 Our competitive position............................................................................................................................................................................................................................................................15 3.4 Corporate structure ......................................................................................................................................................................................................................................................................15 3.5 Development and Production Norway (DPN) ...................................................................................................................................................................................................................17 3.5.1 DPN overview ........................................................................................................................................................................................................................................................................17 3.5.2 Fields in production on the NCS ....................................................................................................................................................................................................................................18 3.5.2.1 Operations North ........................................................................................................................................................................................................................................................21 3.5.2.2 Operations Mid-Norway ..........................................................................................................................................................................................................................................21 3.5.2.3 Operations West .........................................................................................................................................................................................................................................................22 3.5.2.4 Operations South ........................................................................................................................................................................................................................................................23 3.5.2.5 Partner-operated fields ............................................................................................................................................................................................................................................23 3.5.3 Exploration on the NCS .....................................................................................................................................................................................................................................................24 3.5.4 Fields under development on the NCS .......................................................................................................................................................................................................................25 3.5.5 Decommissioning on the NCS ........................................................................................................................................................................................................................................27 3.6 Development and Production International (DPI) ...........................................................................................................................................................................................................28 3.6.1 DPI overview .........................................................................................................................................................................................................................................................................28 3.6.2 International production ....................................................................................................................................................................................................................................................29 3.6.2.1 North America.............................................................................................................................................................................................................................................................31 3.6.2.2 South America..............................................................................................................................................................................................................................................................32 3.6.2.3 Sub-Saharan Africa ....................................................................................................................................................................................................................................................32 3.6.2.4 North Africa...................................................................................................................................................................................................................................................................33 3.6.2.5 Europe and Asia..........................................................................................................................................................................................................................................................34 3.6.3 International exploration..................................................................................................................................................................................................................................................34 3.6.4 Fields under development internationally ................................................................................................................................................................................................................37 3.6.4.1 North America.............................................................................................................................................................................................................................................................37 3.6.4.2 South America ............................................................................................................................................................................................................................................................38 3.6.4.3 Sub-Saharan Africa ...................................................................................................................................................................................................................................................38 3.6.4.4 North Africa .................................................................................................................................................................................................................................................................38 3.6.4.5 Europe and Asia..........................................................................................................................................................................................................................................................38 3.7 Marketing, Processing and Renewable Energy (MPR) ...................................................................................................................................................................................................40 3.7.1 MPR overview ........................................................................................................................................................................................................................................................................40 3.7.2 Marketing and Trading.......................................................................................................................................................................................................................................................41 3.7.2.1 Marketing and trading of gas.................................................................................................................................................................................................................................41 3.7.2.2 Marketing and trading of liquids...........................................................................................................................................................................................................................42 3.7.3 Asset Management .............................................................................................................................................................................................................................................................42 3.7.3.1 Production plants ........................................................................................................................................................................................................................................................43 3.7.3.2 Terminals and storage ..............................................................................................................................................................................................................................................43 3.7.3.3 Pipelines ..........................................................................................................................................................................................................................................................................44 3.7.4 Processing and Manufacturing .......................................................................................................................................................................................................................................45 3.7.5 Renewable Energy ................................................................................................................................................................................................................................................................46 3.8 Other Group .....................................................................................................................................................................................................................................................................................47 3.8.1 Global Strategy and Business Development (GSB)..............................................................................................................................................................................................47 3.8.2 Technology, Projects and Drilling (TPD) ..................................................................................................................................................................................................................47 3.8.3 Corporate staffs and support functions ....................................................................................................................................................................................................................48 3.9 Significant subsidiaries ................................................................................................................................................................................................................................................................49 3.10 Production volumes and prices.............................................................................................................................................................................................................................................49 3.10.1 Entitlement production ...................................................................................................................................................................................................................................................49 3.10.2 Production costs and sales prices ..............................................................................................................................................................................................................................51 Statoil, Annual Report on Form 20-F 2014 1


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    3.11 Proved oil and gas reserves....................................................................................................................................................................................................................................................52 3.11.1 Development of reserves...............................................................................................................................................................................................................................................55 3.11.2 Preparations of reserves estimates ...........................................................................................................................................................................................................................56 3.11.3 Operational statistics.......................................................................................................................................................................................................................................................57 3.11.4 Delivery commitments ....................................................................................................................................................................................................................................................59 3.12 Applicable laws and regulations...........................................................................................................................................................................................................................................59 3.12.1 The Norwegian licensing system................................................................................................................................................................................................................................60 3.12.2 Gas sales and transportation ........................................................................................................................................................................................................................................61 3.12.3 HSE regulation ....................................................................................................................................................................................................................................................................62 3.12.4 Taxation of Statoil ............................................................................................................................................................................................................................................................62 3.12.5 The Norwegian State's participation ........................................................................................................................................................................................................................64 3.12.6 SDFI oil and gas marketing and sale .........................................................................................................................................................................................................................64 3.13 Property, plant and equipment .............................................................................................................................................................................................................................................65 3.14 Related party transactions......................................................................................................................................................................................................................................................65 3.15 Insurance ........................................................................................................................................................................................................................................................................................65 3.16 People and the group................................................................................................................................................................................................................................................................66 3.16.1 Employees in Statoil .........................................................................................................................................................................................................................................................66 3.16.2 Equal opportunities...........................................................................................................................................................................................................................................................67 3.16.3 Unions and representatives ..........................................................................................................................................................................................................................................67 4 Financial review .....................................................................................................................................................................................................................................................................................68 4.1 Operating and financial review ................................................................................................................................................................................................................................................68 4.1.1 Sales volumes ........................................................................................................................................................................................................................................................................68 4.1.2 Group profit and loss analysis .........................................................................................................................................................................................................................................70 4.1.3 Segment performance and analysis .............................................................................................................................................................................................................................73 4.1.4 DPN profit and loss analysis ............................................................................................................................................................................................................................................76 4.1.5 DPI profit and loss analysis ..............................................................................................................................................................................................................................................77 4.1.6 MPR profit and loss analysis ............................................................................................................................................................................................................................................79 4.1.7 Other operations ..................................................................................................................................................................................................................................................................81 4.1.8 Definitions of reported volumes ....................................................................................................................................................................................................................................81 4.2 Liquidity and capital resources ................................................................................................................................................................................................................................................82 4.2.1 Review of cash flows...........................................................................................................................................................................................................................................................82 4.2.2 Financial assets and debt ..................................................................................................................................................................................................................................................83 4.2.3 Investments.............................................................................................................................................................................................................................................................................85 4.2.4 Impact of inflation ................................................................................................................................................................................................................................................................86 4.2.5 Principal contractual obligations....................................................................................................................................................................................................................................87 4.2.6 Off balance sheet arrangements ...................................................................................................................................................................................................................................87 4.3 Accounting Standards (IFRS)....................................................................................................................................................................................................................................................88 4.4 Non-GAAP measures ...................................................................................................................................................................................................................................................................88 4.4.1 Return on average capital employed (ROACE) .......................................................................................................................................................................................................88 4.4.2 Unit of production cost ......................................................................................................................................................................................................................................................90 4.4.3 Net debt to capital employed ratio...............................................................................................................................................................................................................................91 5 Risk review................................................................................................................................................................................................................................................................................................92 5.1 Risk factors .......................................................................................................................................................................................................................................................................................92 5.1.1 Risks related to our business ...........................................................................................................................................................................................................................................92 5.1.2 Legal and regulatory risks .................................................................................................................................................................................................................................................98 5.1.3 Risks related to state ownership.................................................................................................................................................................................................................................100 5.2 Risk management .......................................................................................................................................................................................................................................................................101 5.2.1 Managing operational risk .............................................................................................................................................................................................................................................101 5.2.2 Managing financial risk ...................................................................................................................................................................................................................................................101 5.2.3 Disclosures about market risk......................................................................................................................................................................................................................................103 5.3 Legal proceedings ......................................................................................................................................................................................................................................................................103 6 Shareholder information ................................................................................................................................................................................................................................................................104 6.1 Dividend policy ............................................................................................................................................................................................................................................................................106 6.1.1 Dividends ..............................................................................................................................................................................................................................................................................106 6.2 Shares purchased by issuer ....................................................................................................................................................................................................................................................107 6.2.1 Statoil's share savings plan ...........................................................................................................................................................................................................................................107 6.3 Information and communications ........................................................................................................................................................................................................................................108 6.3.1 Investor contact .................................................................................................................................................................................................................................................................108 6.4 Market and market prices .......................................................................................................................................................................................................................................................109 6.4.1 Share prices .........................................................................................................................................................................................................................................................................109 6.4.2 Statoil ADR programme fees .......................................................................................................................................................................................................................................110 6.5 Taxation..........................................................................................................................................................................................................................................................................................111 6.6 Exchange controls and limitations .....................................................................................................................................................................................................................................114 2 Statoil, Annual Report on Form 20-F 2014


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    6.7 Exchange rates.............................................................................................................................................................................................................................................................................115 6.8 Major shareholders ....................................................................................................................................................................................................................................................................116 7 Corporate governance.....................................................................................................................................................................................................................................................................118 7.1 Articles of association ..............................................................................................................................................................................................................................................................118 7.2 Ethics Code of Conduct ...........................................................................................................................................................................................................................................................119 7.3 General meeting of shareholders ........................................................................................................................................................................................................................................120 7.4 Nomination committee ...........................................................................................................................................................................................................................................................121 7.5 Corporate assembly...................................................................................................................................................................................................................................................................122 7.6 Board of directors.......................................................................................................................................................................................................................................................................125 7.6.1 Audit committee ................................................................................................................................................................................................................................................................129 7.6.2 Compensation and executive development committee ...................................................................................................................................................................................130 7.6.3 Safety, sustainability and ethics committee ..........................................................................................................................................................................................................130 7.7 Compliance with NYSE listing rules....................................................................................................................................................................................................................................131 7.8 Management.................................................................................................................................................................................................................................................................................132 7.9 Compensation paid to governing bodies ..........................................................................................................................................................................................................................135 7.10 Share ownership ......................................................................................................................................................................................................................................................................143 7.11 Independent auditor ...............................................................................................................................................................................................................................................................143 7.12 Controls and procedures ......................................................................................................................................................................................................................................................145 8 Consolidated financial statements Statoil ...........................................................................................................................................................................................................................146 8.1 Notes to the Consolidated financial statements ..........................................................................................................................................................................................................151 1 Organisation ................................................................................................................................................................................................................................................................................151 2 Significant accounting policies ............................................................................................................................................................................................................................................151 3 Segments ......................................................................................................................................................................................................................................................................................160 4 Acquisitions and dispositions ...............................................................................................................................................................................................................................................163 5 Financial risk management ....................................................................................................................................................................................................................................................164 6 Remuneration ..............................................................................................................................................................................................................................................................................167 7 Other expenses ..........................................................................................................................................................................................................................................................................168 8 Financial items ............................................................................................................................................................................................................................................................................168 9 Income taxes................................................................................................................................................................................................................................................................................169 10 Earnings per share ..................................................................................................................................................................................................................................................................171 11 Property, plant and equipment .........................................................................................................................................................................................................................................171 12 Intangible assets .....................................................................................................................................................................................................................................................................174 13 Financial investments and non-current prepayments .............................................................................................................................................................................................176 14 Inventories .................................................................................................................................................................................................................................................................................176 15 Trade and other receivables ..............................................................................................................................................................................................................................................177 16 Cash and cash equivalents .................................................................................................................................................................................................................................................177 17 Shareholders' equity..............................................................................................................................................................................................................................................................177 18 Finance debt .............................................................................................................................................................................................................................................................................178 19 Pensions......................................................................................................................................................................................................................................................................................180 20 Provisions ...................................................................................................................................................................................................................................................................................183 21 Trade and other payables ...................................................................................................................................................................................................................................................184 22 Leases ..........................................................................................................................................................................................................................................................................................184 23 Other commitments, contingent liabilities and contingent assets....................................................................................................................................................................185 24 Related parties .........................................................................................................................................................................................................................................................................186 25 Financial instruments: fair value measurement and sensitivity analysis of market risk ...........................................................................................................................187 26 Condensed consolidated financial information related to guaranteed debt securities............................................................................................................................191 27 Supplementary oil and gas information (unaudited) ...............................................................................................................................................................................................196 28 Subsequent events.................................................................................................................................................................................................................................................................206 8.2 Report of Independent Registered Public Accounting firm ......................................................................................................................................................................................207 8.2.1 Report of Independent Registered Public Accounting firm.............................................................................................................................................................................207 8.2.2 Report of KPMG on Statoil's internal control over financial reporting ......................................................................................................................................................208 9 Terms and definitons .......................................................................................................................................................................................................................................................................209 10 Forward-looking statements .....................................................................................................................................................................................................................................................212 11 Signature page .................................................................................................................................................................................................................................................................................213 12 Exhibits .................................................................................................................................................................................................................................................................................................214 13 Cross reference to Form 20-F ..................................................................................................................................................................................................................................................215 Statoil, Annual Report on Form 20-F 2014 3


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    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, 2014 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 Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None 4 Statoil, Annual Report on Form 20-F 2014


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    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 Statoil, Annual Report on Form 20-F 2014 5


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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 2014 ("Annual Report on Form 20-F") is available online at www.statoil.com. Statoil is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, Statoil files its Annual Report on Form 20-F and other related documents with the Securities and Exchange Commission (the SEC). It is also possible to read and copy documents that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C. 20549, USA. You 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. 6 Statoil, Annual Report on Form 20-F 2014


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    1.2 Key figures and highlights 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) 2014 2013 2012 2011 2010 Financial information Total revenues and other income3) 622.7 634.5 718.2 670.0 529.9 Net operating income 109.5 155.5 206.6 211.8 137.3 Net income 22.0 39.2 69.5 78.4 37.6 Non-current finance debt 205.1 165.5 101.0 111.6 99.8 Net interest-bearing debt before adjustments 89.2 58.0 39.3 71.0 69.5 Total assets 986.4 885.6 784.4 768.6 643.3 Share capital 8.0 8.0 8.0 8.0 8.0 Non-controlling interest 0.4 0.5 0.7 6.2 6.9 Total equity 381.2 356.0 319.9 285.2 226.4 Net debt to capital employed ratio before adjustments 19.0% 14.0% 10.9% 19.9% 23.5% Net debt to capital employed ratio adjusted 20.0% 15.2% 12.4% 21.1% 25.5% Calculated ROACE based on Average Capital Employed before adjustments 2.7% 11.3% 18.7% 22.1% 12.6% Operational information Equity oil and gas production (mboe/day) 1,927 1,940 2,004 1,850 1,888 Proved oil and gas reserves (mmboe) 5,359 5,600 5,422 5,426 5,325 Reserve replacement ratio (three-year average) 0.97 1.15 1.01 0.90 0.60 Production cost equity volumes (NOK/boe, last 12 months) 49 44 42 42 38 Share information Diluted earnings per share NOK 6.87 12.50 21.60 24.70 11.94 Share price at Oslo Stock Exchange on 31 December in NOK 131.20 147.00 139.00 153.50 138.60 Dividend paid per share NOK 1) 7.20 7.00 6.75 6.50 6.25 Dividend paid per share USD 2) 0.97 1.15 1.21 1.08 1.07 Weighted average number of ordinary shares outstanding (in thousands) 3,179,959 3,180,684 3,181,546 3,182,113 3,182,575 (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 2014 dividend for approval at the Annual General Meeting scheduled for 19 May 2015. (2) USD figure presented using the Central Bank of Norway 2014 year-end rate for Norwegian kroner, which was USD 1.00 = 7.43 NOK. The board of directors will propose the 2014 dividend for approval at the Annual General Meeting scheduled for 19 May 2015. (3) Total revenues and other income for 2013 and 2012 are restated. See note 2 Significant accounting policies to the Consolidated financial statements for further details. Statoil, Annual Report on Form 20-F 2014 7


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    2 Strategy and market overview Our strategy for value creation and long-term growth remains firm. However, the profitability of the oil and gas industry continues to be challenged and Statoil’s financial results in 2014 were influenced by the fall in oil prices. Stricter project prioritisation and a comprehensive efficiency programme are showing progress and will improve cash flow and profitability. Our strong financial position provides a firm basis on which to balance capital investment and dividends to shareholders, which we expect to grow in line with our long term earnings. Last year we outlined the plan to strengthen Statoil’s competitiveness, and we now reinforce our efforts and commitment to deliver on our priorities of high value growth, increased efficiency and competitive shareholder returns. Through our significant flexibility in our investment programme we believe we are well prepared for potential sustained market volatility and uncertainty. Statoil’s ambition to reduce costs and improve efficiency was presented at the capital markets update (CMU) on 7 February 2014, targeting annual savings of USD 1.3 billion from 2016. At the CMU on 6 February 2015, Statoil announced that it will step up its efficiency programme by 30% with a goal to realise USD 1.7 billion in annual savings from 2016. Improvement programmes are Statoil’s response to the industrial challenges characterised by escalating cost and declining returns. More specifically, the ambition is to realise positive production effects and cost savings to improve Statoil’s financial results and cash-flows. 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. 2.1 Our business environment 2.1.1 Market overview Global economic growth picked up only marginally in 2014, to 2.7% from 2.6% in 2013. Growth in OECD has been gaining momentum, driven by the United States. Non-OECD activity slowed in 2014, but remains decent and supportive of overall economic growth and energy demand. While growth in the United States and the United Kingdom has strengthened as labor markets heal and monetary policy remains very expansive, the recovery has been hesitant in the Eurozone and Japan. Growth in emerging countries slipped to 4.2% in 2014, reflecting both weak external demand and domestic challenges. China is still growing at a healthy pace, but continues on an intended path of gradual deceleration. Several major forces are at play in the global economy and will continue to affect demand: soft commodity prices; persistently low interest rates, alongside increasingly divergent monetary policies across major economies, and weak world trade. In particular, the sharp decline in oil prices since mid-2014 has supported global economic activity and will continue to do so in 2015. Continued recovery in the United States, a gradual acceleration of activity in the Eurozone, and receding headwinds to growth among slower-growing emerging economies are expected to lift global growth in 2015 to 3%, according to Statoil’s own research. This rate, which is in line with historic trend growth, is likely to be sustained over the next 10 years, comprising 2% annual growth in the OECD economies and 5% annual growth in non-OECD economies. This means that the globally weighted, geographical point of economic gravity continues to move gradually eastwards and southwards relative to the OECD economies in Europe and North America. The growing populations in emerging economies represent a strong long-term driver of economic development and energy demand. Global oil demand grew by 0.7 mmbbl per day in 2014. A slowdown in Chinese oil demand growth and weaker fundamentals in Europe and Japan were the main reasons behind the five-year low result. Statoil's research suggests that the annual growth in oil demand will average 1.1 mmbbl per day over the medium-term. Positive growth in non-OPEC supply, in particular from North America, tight oil and other liquids, will continue to put a downward pressure on prices while OPEC maintains its production of 30 mmbbl per day. The weakening of the fundamentals in global oil markets and the slow recovery of the OECD economies and emerging markets are expected to continue to affect markets in 2015. However, prices below USD 50/bbl are expected to lead to a significant reduction in shale oil production growth and the building of global commercial oil stocks will turn to stock draws in the second half of 2015. Due to a general increase in energy demand and the competitiveness of gas in terms of cost and environmental effects, global gas demand is expected to grow. However, the increase in demand will be impacted by energy and climate policies in key regions and countries. Statoil's research suggests that gas demand will increase by 1% and 2% in Europe and in North America, respectively, during the rest of the current decade, whereas Asia will see a growth of 5% in the same period. Both Europe and Asia will have to depend on imports of LNG, which will help sustain a robust price level. In North America, where a revolution in the shale industry has led to increase in proved reserves and production rates have led to historically low prices, prices are expected to gradually increase as the market situation normalises, though the level will remain below that of European and Asian gas prices. 8 Statoil, Annual Report on Form 20-F 2014


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    The global economic situation continues to be fragile, with development partly driven by uncertain political environments in key countries and regions, in addition to normal supply and demand factors. Consequently, energy prices could continue to fluctuate 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 for long-term success. We believe Statoil's production development is competitive, but industry challenges exist. Increasing competition, tighter fiscal conditions, and high costs pose challenges to accessing new profitable resources. It is anticipated that international oil companies, including Statoil, will pursue a number of measures as a response. Some examples include seeking to diversify portfolios across multiple resource types (onshore and offshore, conventional and unconventional), increasing exploration activities, engaging in active portfolio management, and seeking to improve the profitability of projects and existing assets through cost efficiency programmes. Going forward, upward pressure on capital and operational expenditures is still expected as companies combat the decline of legacy fields and tackle increasing technical challenges when developing new fields, even if adjustments in the industry undertaken as a response to lower prices could modify this pressure somewhat over the medium-term. Companies that are at the forefront of efficient resource management, as well as the effective development and utilisation of new technology, will be best equipped to meet these challenges. 2.1.2 Oil prices and refining margins After more than three years of relatively stable prices, 2014 saw the price of Brent crude climb to USD 115 per barrel in June before dropping to USD 55 per barrel at the end of December. Refinery margins increased due to declining crude prices during the second half of the year. Oil prices The average price for dated Brent crude in 2014 was USD 98.95/bbl, down almost USD 10/bbl from 2013. Prices fluctuated between approximately USD 106/bbl and approximately USD 110/bbl from January to June, when they increased to an annual high of USD 115.31/bbl in mid-June. From here the prices fell steadily down to USD 100/bbl in mid-August. Here the price hovered for a couple of weeks before breaking through the temporary floor of USD 100/bbl early September and falling steadily to approximately USD 77/bbl in late November. The 166th annual OPEC meeting was held on 27 November and gained a lot of attention. The decision not to cut OPEC production immediately sent the prices downwards, the Brent price ended on a 5 year low of USD 54.98/bbl on 31 December. The futures market for Brent at the Intercontinental Exchange (ICE) was generally in backwardation up until early July when the situation shifted into contango where it remained for the rest for the year. See the section Terms and definitions for further details. The price of US WTI crude, as quoted at the Cushing tank farm in Oklahoma, averaged USD 93.28/bbl in 2014, down approximately USD 3/bbl from 2013. The price increased from USD 95.57/bbl at the beginning of the year to USD 103.72/bbl in mid-February. The price fluctuated around USD 100/bbl through May before following the increasing Brent in June when rising sharply to USD 107.53/bbl. From here the price of WTI fell, and while following the Brent price downwards the decrease was periodically slower, closing the differential between WTI and Brent. The WTI price halted at a temporary floor in mid-August at a level around USD 95/bbl, before breaking through and falling rapidly with the Brent towards year-end. On 31 December the WTI price was at USD 53.05/bbl, with approximately USD 2/bbl differential to Brent Geopolitically, the unrest in Libya continued to play a part in 2014. Political instability and frequent attacks on oil installations by local militia led to production outages during the first half of the year. Political tension in the Ukraine in March and April led to an upward pressure on oil prices due to uncertainty. The EU and the US later imposed sanctions on Russia for their invasion of the Ukraine. In mid-June the jihadist rebel group ISIS bombed the Kirkuk-Ceyhan pipeline in Northern Iraq, marking the start of a campaign that would last throughout 2014. This fuelled concerns for supply disruptions from Iraq. As these fears receded the prices fell during late summer. The growth in shale oil production in the US came as a surprise to the market and during the third quarter it became clear that there was a growing supply of oil. The paper market of crude oil saw investors leaving in an attempt to secure profit, and the pressure subsequently transferred to the physical market. Refinery maintenance in most regions of the world coincided in that quarter, reducing demand for crude. The concerns over China’s new policies affecting demand growth materialized. The growth in Europe was still slow and with some countries on the borderline of recession there was not much support for the oil price. Oil producing and exporting countries were looking to OPEC to intervene and cut their production in order to stabilize the price, but at the meeting in November, OPEC decided to maintain their current production and the prices continued their free fall. OPEC’s decision to let the market set the price of crude oil marked the change of a 30-year old price regime that may lead to higher volatility in crude prices in the years to come. The US market was not immune to global oil market dynamics during 2014. Just as Brent crude declined significantly since peaking in June, WTI suffered similar declines. However, due to increased pipeline capacity between Cushing, OK and the US Gulf Coast, Cushing crude stocks declined significantly over 2014, leading to a narrower differential between WTI and Brent. Additional pipeline capacity entering the market in 2014 continued to ease the pipeline logistics constraints between northern US and West Texas producing areas and coastal demand regions. While there were no fundamental change in the US government’s stance regarding crude exports, crude and condensate exports, primarily to Canada, increased to levels not seen since the 1980s. These exports provided a welcome relief for producers seeking access to higher value waterborne crude markets. Refinery margins Refinery margins in Northwest Europe, as calculated against dated Brent crude, were rather weak during the first quarter. This was due in part to a mild winter. There was also specific strength in the Brent market caused by trade in Forties crude, a component in the Brent, Forties, Oseberg, Ekofisk (BFOE) system that sets dated Brent. Refineries saw better margins from Russian Urals crude. Margins stayed rather weak through the second quarter, due to an Statoil, Annual Report on Form 20-F 2014 9


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    overflow of diesel imports from Russia and the US Gulf. On the other hand, naphtha margins were quite strong on export opportunities into Asia. In the third quarter, margins improved significantly, mainly driven by gasoline. This was in particular caused by a lack of octane components, some of which had been exported separately to China. Also, the physical Brent market started to weaken, and price differentials for other crudes came off vs. Brent. These factors continued into the fourth quarter, resulting in margins above normal in November. A major reason for this strength was that China ran its vast refining capacity at low utilization rates. They seemed to run only to cover domestic diesel demand, which was stalling. That allowed for exports from Europe for lighter products like gasoline, naphtha and LPG, for which there was demand growth. Europe saw two new refinery closures, one in Italy and one in the UK. European diesel demand was strong, partly due to an upcoming shift from heavy fuel oil to diesel as shipping fuel in the North Sea and Baltics from 1 January 2015. Stationary fuels like heating oil and heavy fuel oil experienced further declines. 2.1.3 Natural gas prices Natural gas prices in Europe have fallen in 2014 as a result of weak demand and a healthy supply picture boosted by increased LNG availability, due to a weakened Asian Spot LNG market. In North America prices in 2014 averaged 17% higher than in 2013. Gas prices - Europe The European natural gas price level was 20% lower in 2014 as prices averaged USD 8.2/mmbtu compared to USD 10.3/mmbtu in 2013. Gas consumption in EU28 declined by 12%. Domestic European production excluding Norway fell from 152 bcm to 137 bcm. Norwegian pipeline exports were at 102 bcm roughly the same as last year. Total European LNG imports (Turkey and Israel excluded) were with 53 bcm at the same level as last year's imports. The level of re-exports increased by 63%. Total liquefaction was at 329 bcm in line the production seen in the past 3 previous years. The demand growth in Asian countries, which only resulted in a marginal increase in import of LNG, is no longer strong enough to offset the declining consumption trend in Europe. A possible restart of some Japanese nuclear power plants this year could further weaken Asian demand growth. Further increase in renewable power generation capacity impacted the power markets and gas-to-power demand fell. However, the gas-to-power segment is now close to a floor minimum level. Gas prices - North America Supply growth has been a regular feature of the natural gas market in recent years, but in 2014 demand was able to absorb that supply, keeping storage below normal levels. Average cash prices were boosted to over USD 4/mmbtu for the first time since 2010. The race between demand and supply growth favored demand early in 2014, but shifted toward supply for the remainder of the year. Production growth was the fastest in years, as 34 bcm was added at the wellhead. South Marcellus became the fastest growing supply basin. Cold weather in the first quarter started the year on a bullish note, driving Henry Hub prices above USD 5/mmbtu and lowering inventories to the lowest in a decade. Once the winter was over, supply growth and rebuilding stocks were the main story for 2014. The trends of 2014 continued into 2015, with a weak start, with strong supply and inventories close to normal at the start of the year. By 2016 and later this decade a number of factors are expected to be more bullish: LNG export projects are expected to start up, gas should make gains at coal's expense in the power sector, industrial demand is expected to rise and the supply side will need to turn to incrementally higher cost reserves. North American gas prices are expected to appreciate as a result, though remaining below Asian and European levels. 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 top priorities remain to conduct safe and reliable operations with zero harm to people and the environment, and to deliver profitable production growth through disciplined investments and prudent financial management with competitive redistribution of capital to shareholders. To succeed going forward we continue to focus strategically on the following: • Sustaining leading exploration company performance • Taking out the full value potential of the Norwegian continental shelf (NCS) • Strengthening our global offshore positions • Maximising the value of our onshore positions • Creating enhanced value from midstream solutions • Continuing portfolio management to enhance value creation • Utilising oil and gas expertise and technology to open up new renewable energy opportunities 10 Statoil, Annual Report on Form 20-F 2014


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    Sustaining leading exploration company performance Results from the 2014 exploration programme are a product of our focus on three exploration strategy pillars: • Early access at scale: We focused on accessing frontier acreage over the last few years and have been an early mover in several areas. In 2014, we accessed significant acreage positions in Algeria, Australia, Colombia, New Zealand and Norway; access to new acreage in Myanmar and New Zealand are pending final approval from the respective host governments. • Deepen core positions: We secured more acreage in potential clusters such as Brazil, the US Gulf of Mexico, and the UK continental shelf, where Statoil was awarded 12 licences. On the NCS, we continue to deepen our position by acreage Award in the Predefined Areas (APA) and to test new opportunities and maintain high focus on growth and infrastructure lead exploration (ILX) wells with significant potential. • Drill significant targets: We continued to focus on drilling large targets, leading to the Piri-1 discovery, the fifth high-impact discovery and seventh overall in Tanzania’s Block 2. The exploration collaboration with Rosneft in Russia has continued. Sanctions have affected the progress of our projects, however we are in continuous dialogue with authorities to ensure that we remain sanctions compliant. See section Risk review – Risk factors – Risk related to our business for further details. To sustain leading exploration performance long-term, we aim to deepen positions in prolific basins, actively pursue play-opening opportunities, and balance a continued high activity level with selective access and focus on efficiency and capital discipline. Taking out the full value potential of the Norwegian continental shelf (NCS) The NCS remains a prolific and productive oil and gas province where only half of the resources have been produced. In 2014 Statoil began production from the Gudrun field and three fast track projects (Svalin, Fram H-Nord and Vilje Sør). Valemon came on stream in the North Sea on 3 January 2015. We submitted the Plan for Development and Operations (PDO) of the Gullfaks Rimfaksdalen project in December 2014 and of the Johan Sverdrup project in February 2015. Over the next ten years, Statoil aims to bring on stream new production from a combination of: • Developments of larger discoveries, including the Aasta Hansteen, Gina Krog, Gullfaks Rimfaksdalen, Johan Castberg and Johan Sverdrup projects, which are expected to contribute considerably to Statoil's future production. • Developments of a number of smaller discoveries close to established infrastructure. • Development of high value oil recovery (IOR) projects, delivering towards Statoil’s ambition of 60% average oil recovery on Statoil-operated NCS oil fields. In addition to IOR, improving operational performance and continued high production efficiency are measures to increase the value potential of Statoil’s operated assets. Strengthening our global offshore positions Statoil's international oil and gas production has increased from around 100,000 boe to around 740,000 boe per day since the year 2000. Statoil has established a presence in a number of 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 and value creation, 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. Our potential clusters are located in some of the most attractive basins in the industry, including: • Brazil; where Peregrino is already operational. In the future, we will focus on further developing the Peregrino area and maturing our exploration portfolio. The PDO for the Peregrino Phase II project was submitted to Brazilian authorities in January 2015. • Angola; where exploration potential remains and where we already have non-operated production. Statoil has taken a time-out in the Kwanza exploration drilling programme, as a consequence a rig contract was cancelled. Regarding non-operated production, the CLOV project (Block 17) was commissioned. • Tanzania; which emerged as a new potential cluster in 2012, and where we made two additional discoveries in 2014. Planning of an LNG plant is being progressed with our partners. • East Coast Canada; emerged as a new potential cluster in 2013 with two discoveries including the significant discovery Bay du Nord; further prospects will be tested in the Flemish Pass and adjacent areas. Statoil already has non-operated production in East Coast Canada. • US Gulf of Mexico; where exploration potential remains and where we already have non-operated production. Investment decision was taken for the Stampede project located in the “Grand Canyon” region while oil and natural gas production started from the partner-operated Jack/St-Malo project. Maximising the value of our onshore positions Our onshore positions are dominated by our diverse unconventional resources portfolio in North America. It includes operated and non-operated leases in the shale gas and tight oil basins of Marcellus, Eagle Ford and Bakken in the US. In addition, we became the 100% owner and operator for two Kai Kos Dehseh (KKD) lease areas, Leismer and Corner, in the Athabasca region in Alberta, Canada after agreeing to swap oil sands assets with PTTEP in 2014. We postponed making an investment decision on the Corner expansion project. Statoil, Annual Report on Form 20-F 2014 11


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    Our priorities in the unconventional resources space include: • Delivering a safe and profitable production ramp-up • Taking care of the communities we are entrusted with • Leveraging rapid application of new technology to maximise value creation • High grading acreage holdings to strengthen current upstream positions • Demonstrating operational excellence and world class stakeholder management • Striving for seamless value chain integration and superior price realisation Creating enhanced value from midstream solutions 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 European gas reserves are located close to the European markets, we have flexible production capabilities and transportation systems, and our commercial experience in gas sales and trading has a proved 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 towards 2050. The strategic focus in these endeavours will be to provide financial flexibility, access exploration acreage and unconventional resources, secure operatorships, build cluster positions, manage asset maturity, de-risk positions and demonstrate the intrinsic value of the portfolio. Announced transactions in 2014 include the sale of interests in licences on the NCS to Wintershall, farming down a portion of our non-operated US southern Marcellus acreage to Southwestern, sale of a 10% interest in the Shah Deniz project and the South Caucasus Pipeline to BP and SOCAR and sale of the remaining interests in the Shah Deniz field and South Caucasus Pipeline to PETRONAS. These transactions further underpin our ability to release capital for profitable redeployment. 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 value chains. In 2014, we sanctioned the Dudgeon Offshore Windfarm off the coast of Norfolk, UK. In addition, we continued 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. Developing competences within carbon value chains represents a key opportunity for reducing carbon emissions and building new business models in the transition to a low carbon world. Statoil continues to build competence and experience in carbon capture, transportation, storage and utilisation by our engagements in the world-class Technology Centre Mongstad CO2 test site. 2.3 Our technology We continuously develop and deploy innovative technologies to ensure safe and efficient operations and to deliver on our strategic objectives. We believe that technology is a critical success factor in the business environment where we operate. In addition to requiring capital efficiency, this environment is characterised by a 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 and value creation. Our technology development activities aim to reduce field development, drilling and operating costs. We utilise a range of tools for the development of new technologies where choice of tool is dependent on strategic importance of technology for us and our position related to Intellectual property. Our toolbox includes: • In-house research and development (R&D) • Collaborative development projects with our major suppliers • Project related development as part of our field development activities • Direct investment in technology start-up companies through our Statoil technology invest venture activities • Invitation to open innovation challenges as part of Statoil Innovate 12 Statoil, Annual Report on Form 20-F 2014


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    Our track record demonstrates our ability to overcome significant technical challenges through the development and deployment of innovative technologies. 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 we have increased our focus on upstream technologies, primarily in the areas of Exploration, Reservoir and Drilling and Well. Strengthening our licence to operate - in order to maintain our licence to operate we continuously focus on technologies for safe, reliable and efficient operations. As part of our focus on sustainability issues we are committed to developing and implementing energy-efficient and environmentally sustainable solutions. Expanding our capabilities - success in a highly competitive environment requires the ability to build on our competitive advantages, stimulate innovation and take a long-term view on selected potentially high-impact technology ventures. Of particular importance is our collaborative way of working with partners and suppliers on a global basis. In 2014 we qualified a record number of new technologies for internal use and implementation on our operating assets. In addition we met our target for implementation of proved technologies with high value creation impact across multiple assets. 2.4 Group outlook Our plans address the current environment while continuing to invest in high-quality projects. We reinforce our efforts and commitment to deliver on our priorities of high value growth, increased efficiency and competitive shareholder return. • Organic capital expenditures for 2015 (i.e. excluding acquisitions, capital leases and other investments with significant different cash flow pattern), are estimated at around USD 18 billion, compared to USD 19.6 billion in 2014. • Statoil will continue to mature the large portfolio of exploration assets and estimates a total exploration activity level at around USD 3.2 billion for 2015, excluding signature bonuses. • Statoil expects to deliver efficiency improvements with pre-tax cash flow effects of around USD 1.7 billion from 2016. • Our ambition is to maintain ROACE (Return on Average Capital Employed) at 2013 level adjusted for price and currency level, and to keep our unit of production cost in the top quartile of our peer group. • For the period 2014 - 2016 organic production growth is expected to come from new projects resulting in around 2% CAGR (Compound Annual Growth Rate) from a 2014 level rebased for divestments. • The equity production development for 2015 is estimated to be around 2% CAGR from a 2014 level rebased for divestments. • Scheduled maintenance activity is estimated to reduce equity production by around 45 mboe per day for the full year 2015, of which the majority is liquids. • Indicative PSA (Production Sharing Agreement) effect and US royalties are estimated to around 160 mboe per day in 2015 based on an oil price of USD 60 per barrel and 190 mboe per day based on an oil price of USD 100 per barrel. • Deferral of gas production to create future value, gas off-take, timing of new capacity coming on stream and operational regularity represent the most significant risks related to the production guidance. 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. Statoil, Annual Report on Form 20-F 2014 13


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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. Statoil has grown in parallel with the Norwegian oil and gas industry, which dates back to the late 1960s. Initially, our operations were primarily focused on exploration, development and production of oil and gas on the Norwegian continental shelf (NCS), as a partner. In the 1970s, Statoil commenced its own operations, made important discoveries and began oil refining operations, which have been of great importance to the further development of the NCS. Statoil grew substantially in the 1980s through the development of large fields on the NCS (Statfjord, Gullfaks, Oseberg, Troll and others). Statoil 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, all of the remaining shares in Statoil Fuel & Retail ASA were divested. Statoil is also 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. 3.2 Our business Statoil is a technology-driven energy company primarily engaged in oil and gas exploration and production activities. Statoil ASA is a public limited liability company organised under the laws of Norway and subject to the provisions of 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's head office is located in Stavanger, Norway. We have business operations in more than 30 countries and have more than 22,500 employees worldwide. 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 2014, 39% of Statoil's equity production came from international activities and the company also holds operatorships internationally. Our access to crude oil in the form of equity, governmental and third party volumes makes Statoil a large net crude oil seller, and Statoil is the second- largest supplier of natural gas to the European market. Processing and refining are also part of our operations. Statoil is also 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's business address is Forusbeen 50, N-4035 Stavanger, Norway. Its telephone number is +47 51 99 00 00. 14 Statoil, Annual Report on Form 20-F 2014


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    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. Improvement programmes Statoil’s ambition to reduce cost and improve efficiency was presented at the capital markets update (CMU) on 7 February 2014, targeting annual savings of USD 1.3 billion annual per year from 2016. At the CMU on 6 February 2015, we announced that we will step up our efficiency programme by 30% with a target to realise USD 1.7 billion in annual savings from 2016. Improvement programmes are Statoil’s response to the industrial challenge characterised by escalating cost and declining returns. More specifically, the ambition is to realise positive production effects and capex and operating cost savings to improve financial results and cash-flows. 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 proved 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, unconventional oil and gas, and oil sands in the US and Canada. In this connection, we aim to further strengthen our capabilities in deepwater and unconventional oil and gas operations. 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 research and development. 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. Statoil, Annual Report on Form 20-F 2014 15


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    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 (M&A) activities 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 Statoil reports 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); and Other. The Other reporting segment includes activities in Technology, Projects and Drilling (TPD), Global Strategy and Business Development (GSB) and Corporate staffs and support functions. Activities relating to the Exploration (EXP) 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 areas. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa, and the Americas. 16 Statoil, Annual Report on Form 20-F 2014


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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). In 2014 we had 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 1,184 mboe per day in 2014. That was about 68% of Statoil's total entitlement production and 61% of Statoil's equity production. In 2014, our daily production of oil and natural gas liquids (NGL) on the NCS was 588 mboe, and our average daily gas production on the NCS was 95 mmcm (3.3 bcf). Acting as operator, Statoil is responsible for approximately 70% of all oil and gas production on the NCS. DPN has organised the production operations into four business clusters: Operations North (Barents Sea) located in Harstad, Operations Mid- Norway (Norwegian Sea) located in Stjørdal near Trondheim, Operations West (North Sea) located in Bergen and Operation South (North Sea) located in Stavanger. Partner-operated fields cover the entire NCS and are internally included in the Operations South business cluster. On 1 July 2014, DPN merged the former business clusters: Operations North Sea West and Operations North Sea East into Operations West. 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 working 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. Statoil, Annual Report on Form 20-F 2014 17


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    Key events and portfolio developments in 2014: • Statoil was awarded interests in 11 production licences in the Awards in Predefined Areas 2014 (APA 2014) on the NCS and will be the operator in seven of the licences. • In April 2014, Statoil announced the start-up of production at the Gudrun oil and gas field in the North Sea. • Statoil announced production start-up on fast track projects Svalin M in March and Svalin C in September, Vilje Sør in April and Fram H Nord in September 2014. • 17 turnarounds were carried out according to plan during 2014. • Huldra production was permanently shut down 3 September. The field will be fully decommissioned prior to 2021. • In November 2014, Statoil, together with the licence partners, decided to adjust the project plan of the Snorre 2040- project by delaying the planned date for the decision making point DG2 from March 2015 to October 2015. • Plan for Development and Operations (PDO) for the Gullfaks Rimfaksdalen Fast track project was submitted to the Ministry of Petroleum and Energy (MPE) on 16 December 2014. • An extensive exploration drilling program in 2014 resulted in 29 completed wells, of which 20 Statoil acted as operator with 14 discoveries. • The Johan Sverdrup partners have agreed to recommend Statoil as operator for all phases of the field. The PDO for phase 1 of the project was submitted to the MPE in February 2015. • The 2014 sales transaction with Wintershall for farm down in Aasta Hansteen, Asterix and Polarled and the sale of the non-core Vega and Gjøa fields on NCS was closed in December. Through this transaction Statoil was able to monetise a portion of its investment in the Aasta Hansteen field development project, while retaining the operatorship and a 51% equity share. The profitability of our industry continues to be challenged. Statoil’s response to the industrial challenge characterised by escalating cost and declining returns is addressed in the section Strategy and market overview. 3.5.2 Fields in production on the NCS In 2014, our total production of entitlement liquids and gas was 1,184 mboe per day, compared to 1,217 mboe per day in 2013. 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 2014, 2013 and 2012. Field areas are groups of fields operated as a single entity. For the year ended December 31, 2014 2013 2012 Oil and NGL Natural gas Oil and NGL Natural gas Oil and NGL Natural gas Area production mbbl mmcm mboe/day mbbl mmcm mboe/day mbbl mmcm mboe/day Operations North 36 7 80 24 5 56 22 6 60 Operations Mid 126 17 235 126 15 222 158 17 266 Operations West 264 43 535 290 48 589 303 55 651 Operations South 107 11 177 94 12 167 93 13 177 Partner Operated Fields 55 16 157 58 20 182 49 21 181 Total 588 95 1,184 591 99 1,217 624 113 1,335 18 Statoil, Annual Report on Form 20-F 2014


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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 2014. Field areas are groups of fields operated as a single entity. Average daily Statoil's equity Licence expiry production in Business cluster Geographical area interest in % (1) Operator On stream date 2014 mboe/day Operations West Kvitebjørn The North Sea 39.55 Statoil 2004 2031 65.5 Visund The North Sea 53.20 Statoil 1999 2034 34.8 Gullfaks The North Sea 51.00 Statoil 1986 2036 75.2 (2) Gimle The North Sea 65.13 Statoil 2006 2034 0.7 Grane The North Sea 36.66 Statoil 2003 2030 36.0 (3) Veslefrikk The North Sea 18.00 Statoil 1989 2020 2.9 (4) Huldra The North Sea 19.88 Statoil 2001 2015 0.9 Volve The North Sea 59.60 Statoil 2008 2028 8.3 Troll Phase 1 (Gas) The North Sea 30.58 Statoil 1996 2030 152.8 Troll Phase 2 (Oil) The North Sea 30.58 Statoil 1995 2030 39.3 Fram The North Sea 45.00 Statoil 2003 2024 21.1 Fram H Nord The North Sea 49.20 Statoil 2014 2024 1.3 (5) Vega Unit The North Sea 0.00 Statoil 2010 2035 13.9 Oseberg The North Sea 49.30 Statoil 1988 2031 77.8 (6) Tune The North Sea 50.00 Statoil 2002 2032 3.9 Total Operation West 534.6 Operations North Alve The Norwegian Sea 85.00 Statoil 2009 2029 13.1 Norne The Norwegian Sea 39.10 Statoil 1997 2026 5.9 Urd The Norwegian Sea 63.95 Statoil 2005 2026 19.5 Snøhvit The Barents Sea 36.79 Statoil 2007 2035 41.7 Total Operations North 80.2 Operations South Statfjord Unit The North Sea 44.34 Statoil 1979 2026 35.9 Statfjord Nord The North Sea 21.88 Statoil 1995 2026 1.1 (7) Statfjord Øst The North Sea 31.69 Statoil 1994 2026 1.4 (7) Sygna The North Sea 30.71 Statoil 2000 2026 0.2 (8) Snorre The North Sea 33.32 Statoil 1992 2015 31.1 Tordis area The North Sea 41.50 Statoil 1994 2024 5.6 Vigdis area The North Sea 41.50 Statoil 1997 2024 16.6 Sleipner Øst The North Sea 59.60 Statoil 1993 2028 10.4 Sleipner Vest The North Sea 58.35 Statoil 1996 2028 50.8 Gungne The North Sea 62.00 Statoil 1996 2028 6.6 Gudrun The North Sea 51.00 Statoil 2014 2028 17.5 Total Operations South 177.1 Statoil, Annual Report on Form 20-F 2014 19


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    Average daily Statoil's equity Licence expiry production in Business cluster Geographical area interest in % (1) Operator On stream date 2014 mboe/day Operations Mid-Norway (9) Njord The Norwegian Sea 20.00 Statoil 1997 2021 4.3 (10) Hyme The Norwegian Sea 35.00 Statoil 2013 2014 3.0 Tyrihans The Norwegian Sea 58.84 Statoil 2009 2029 52.2 (11) Heidrun The Norwegian Sea 13.04 Statoil 1995 2024 9.6 Åsgard The Norwegian Sea 34.57 Statoil 1999 2027 95.6 (12) Mikkel The Norwegian Sea 43.97 Statoil 2003 2020 15.7 (13) Kristin The Norwegian Sea 55.30 Statoil 2005 2033 23.7 Morvin The Norwegian Sea 64.00 Statoil 2010 2027 25.3 (14) Yttergryta The Norwegian Sea 45.75 Statoil 2009 2027 5.5 Total Operations Mid-Norway 234.9 Partner Operated Fields (15) Skarv The Norwegian Sea 36.17 BP Norge AS 2013 2033 46.3 (16) Ormen Lange The Norwegian Sea 25.35 Shell 2007 2041 68.5 Vilje The North Sea 28.85 Marathon Oil 2008 2021 5.3 (6) Gjøa The North Sea 0.00 GDFSuez 2010 2028 5.2 Ekofisk area The North Sea 7.60 ConocoPhillips 1971 2028 14.2 Ringhorne Øst The North Sea 14.82 ExxonMobil 2006 2030 1.8 Sigyn The North Sea 60.00 ExxonMobil 2002 2022 3.3 Marulk The North Sea 50.00 Eni Norge AS 2012 2025 12.2 Total Partner Operated Fields 156.9 Total 1,183.6 (1) (8) Equity interest as of 31 December 2014. PL089 expires in 2024 and PL057 expires in 2015. (2) (9) PL120B expires in 2034 and PL050DS expires in 2023. PL107 expires in 2021 and PL132 expires in 2023. (3) (10) PL052 expires in 2020 and PL053 in 2031. Application for license extension for PL348 to 2033 is under (4) preparation. Production shut down September 3, 2014. (11) (5) PL095 expires in 2024 and PL124 expires in 2025. The 2014 Statoil farm out transaction with Wintershall completed (12) 1 December 2014. (Full exit Gjøa PL153 and 153B and Vega PL248 PL092 expires in 2020 and PL121 expires in 2022. 248B and 090C). Transfer of Vega operatorship from Statoil to (13) PL134B expires in 2027 and PL199 expires in 2033. Wintershall. Subject to government approval. (14) (6) PL062 expires in 2027 and PL159 expires in 2029, however, PL034 expires in 2020. PL053 expires in 2031 and PL190 in 2032. Yttergryta has shut down and volumes in 2014 are redelivery of (7) PL037 expires in 2026 and PL089 expires in 2024. commercial volumes from Smørbukk CO2 blending. (15) PL212/262 expires in 2033 and PL159 expires in 2029. (16) PL209/250 expires in 2041 and PL208 expires in 2040. The following sections provide information about the main producing assets. See the section Financial review - Operating and financial review - DPN profit and loss analysis for a discussion of results of operations for 2014, 2013, and 2012. 20 Statoil, Annual Report on Form 20-F 2014


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    3.5.2.1 Operations North The main producing field in the Operations North area is the Snøhvit field. The region spans from 66 degrees north in the Norwegian Sea to 70 degrees north in the Barents Sea, the latter at the same latitude as the frozen seas in Alaska. The Norwegian Sea region is characterised by petroleum reserves located at water depths between 340 and 380 metres. In the Barents Sea the petroleum reserves are located at water depths between 310 and 340 meters. The Gulf Stream keeps the sea free of ice all year round, but winter storms can make surface installations difficult to operate. Snøhvit (Statoil interest 36.79%) was the first field developed in the Barents Sea. It is one of the first major developments using onshore production facilities. All offshore installations are subsea. The natural gas is transported to shore through a 143 km long pipeline and then processed at our Liquefied Natural Gas (LNG) plant on Melkøya. The LNG was shipped to customers in Europe, Asia, North and South America in tankers. The CO2 in the feed-gas from Snøhvit and Albatross is removed due to freezing constraints in the process system. To reduce carbon dioxide emissions to the air the removed CO2 is liquefied, transported through a pipeline, and then injected into a storage reservoir in Snøhvit. The LNG plant produced according to plan in 2014. A turnaround was performed according to plan in the period of May 2nd to June 13th. The Snøhvit licence has implemented the improvement project "Closing the Gap." The main objectives for the project are focus on increased production efficiency and plant integrity, improved HSE results, enhanced cost efficiency and intensified expertise throughout the Snøhvit organisation. Norne (Statoil interest 39.10%) is an oil field located about 80 kilometres north of Heidrun in the Norwegian Sea. The field has been developed using a floating production, storage and offloading vessel (FPSO) connected to subsea templates. Gas is exported through a dedicated pipeline to the Åsgard Transport System (ÅTS) and further to Kårstø. Alve, Marulk, Urd and Skuld are tie-in fields connected to the Norne FPSO. Skuld (Statoil interest 63.95%) is a Statoil operated field located outside the Norne FPSO and consists of the Fossekall and Dompap reservoirs. Skuld is one of the largest fast-track developments, and production start-up was March 2013. The field is currently producing from the Fossekall and Dompap reservoirs. 3.5.2.2 Operations Mid-Norway The main producing fields in the Operations Mid-Norway area are Åsgard, Morvin, Kristin and Tyrihans. 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. The Åsgard field development (Statoil interest 34.57%) includes the Åsgard A production and storage ship for oil, the Åsgard B semi-submersible floating production platform for gas, and the Åsgard C storage vessel for condensate. Gas from the field is piped through the ÅTS to the processing plant at Kårstø. 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 developed with two subsea templates tied back to Åsgard B. Morvin (Statoil interest 64.00%) is developed with two subsea templates. The well stream of oil and gas is tied back to Åsgard B for processing. Heidrun (Statoil interest 13.04%) is developed with a floating concrete tension leg platform. The oil is transferred to shuttle tankers at the field and shipped to Mongstad in Norway and Tetney in the UK. Gas from Heidrun transported in an own pipe line provides the feedstock for the methanol plant at Tjeldbergodden in Norway. Additional gas volumes are exported through the ÅTS to the gas processing facility at Kårstø. 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 Åsgard C storage vessel, and the rich gas is transported via the ÅTS to the gas processing facility at Kårstø. Tyrihans (Statoil interest 58.84%) is a subsea development with five templates. The well stream of oil and gas is tied back to Kristin for processing. Tyrihans receives seawater injection from Kristin and gas injection from Åsgard B. The Njord field (Statoil interest 20.00%) has been developed with a floating steel platform, Njord A, which has an integrated deck with drilling and processing facilities, as well as living quarters. The oil is transported from a storage vessel, Njord B, with shuttle tankers. The gas is transported through the ÅTS to Kårstø. The Njord A platform was kept shut down after a planned turnaround in September 2013 due to structural integrity issues. Designing the necessary reinforcements and planning of prefabrication as well as installation started in November 2013. Extensive reinforcement work was carried out Statoil, Annual Report on Form 20-F 2014 21


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    during first half of 2014, and production was temporary resumed in July 2014. The temporary production period is expected to last until medio 2016, there will not be any drilling activity in this period. The project “Njord Future” has been established to secure long term production from Njord and Hyme. Hyme (Statoil interest 35.00%) was developed as a fast track project with a standard subsea template with four well slots. Hyme has one production well and one water injection well, both tied to the Njord facilities, and started production in the first quarter of 2013. 3.5.2.3 Operations West The main producing fields in the Operations West area are Troll, Oseberg, Gullfaks, Kvitebjørn, Visund and Grane Operation West produces approximately half of Statoil’s equity production in Norway. Our main focus is on increasing and prolonging production in the area, giving priority to increased oil recovery, exploration and new field developments. Troll (Statoil interest 30.58%) is the largest gas field on the NCS and a major oil field. 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. Oil is transported in pipelines to Mongstad. The condensate is separated from the gas, and transported by pipeline to the Sture and Mongstad terminals. The gas is transported to the gas treatment plant at Kollsnes and the dry gas is then transported in Zeepipe pipelines to Germany. In February 2014, Troll replaced two inoperative electric motors driving the Troll A export compressors with an interim motor. The permanent replacement for the motor was installed and became operational early October 2014. 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 to the Sture Terminal, and gas is exported through the Oseberg gas transportation system to Heimdal and from there to the market. The drilling upgrade project at Oseberg Field Center was completed in 2014 after a long drilling stop. Drilling operations recommenced in the summer of 2014. All platforms in the Oseberg area had a turnaround in the spring with startup in May 2014. The Tender Support Vessel (TSV) project at Oseberg Øst was sanctioned and is expected to arrive in the summer of 2015. Gullfaks (Statoil interest 51.00%) has been developed with three large concrete production platforms. Oil is stored at the Gullfaks A and C platforms before being loaded 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. Oil and gas production was as expected in 2014. Currently, drilling of the new Gullfaks South Increased Oil Recovery (GSO IOR) project wells is ongoing. Operations on the satellites will continue with two mobile rigs until August 2015. Replacing of the offshore loading buoys was finalized in 2014. The Gullfaks Rimfaksdalen Plan for development and operation (PDO) was submitted in 2014. The projects Gullfaks C Subsea compressor, Gullfaks B Drilling Upgrade and Gullfaks South IOR are all planned to be finalized in 2015. Turnarounds at Gullfaks A and B in May/June 2014 where conducted on time and cost. A turnaround on Gullfaks C is planned in 2015. Kvitebjørn (Statoil interest 39.55%) is a gas and condensate field, where gas and condensate from the Kvitebjørn platform are transported through pipelines to Kollsnes and Mongstad, respectively. The Kvitebjørn platform processing has been expanded by a compressor module, and re-compression of the gas is expected to increase the expected production of gas and condensate, thereby increasing the recovery rate from the reservoir. Start-up of the module was in September 2014. Visund (Statoil interest 53.20%) is an oil and gas field development that includes a floating drilling, production and living quarter units and two subsea templates, in the northern and southern parts of the field. Production from the Visund South template started in the fourth quarter of 2012 and production from the Visund North template started in the fourth quarter of 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. In January 2014 gas import was re-opened for injection in the reservoir with the aim of reducing pressure decline. The Svalin field development (Statoil interest 57.0 %) is one of Statoil’s fast track projects, with production start-up in 2014. Statoil is operator, while Petoro and ExxonMobil are patners. The field has a tie back to the Grane platform. Svalin M is a well drilled from the Grane platform, while Svalin C is a sub- sea solution with a six kilometer long flowline to the Grane platform. The Heimdal platforms (Statoil interest 29.44%) where preparing for the reception of rich gas from the Valemon field during the fourth quarter of 2014 and are therefore being upgraded for lifetime extension. Valemon conceded production in January 2015. In parallel, a modular drilling rig has been successfully installed in order to plug and abandon all 12 wells at the Heimdal main reservoir. 22 Statoil, Annual Report on Form 20-F 2014


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    Volve (Statoil interest 59.60%) has successfully increased the proven reserve via a drilling program in 2014. This tail end field managed to plan and approve a well within six weeks, and production is now expected to run to the first quarter in 2016. Rich gas is transported to Sleipner A for further export and the oil is exported by tankers. The Veslefrikk field (Statoil interest 18.00%) has future challenges mainly related to mature new economic drilling targets, secure time-right gas blow down in Veslefrikk late life, run safe and efficient operations and keep continuous focus on cost control. As there are a limited number of prospects with limited volume potential, smart exploration drilling is required. Oil is transported through the Oseberg Transport system to the Sture Terminal and gas export is transported through the Gassled system to Kårstø. Huldra (Statoil interest 19.88 %) production was ceased on 3 September 2014. The platform has produced gas and condensate for six extra years compared to the original plan. Since the field came on stream on 21 November 2001 it has produced a total of 17,5 GSm³ of wet gas and has a recovery rate of 80%. The Huldrapipe has been handed over to the Valemon Project for tie-in of the Valemon pipe to Heimdal. Fram (Statoil interest 45.00%) is an oilfield with two deposits; Fram Vest and Fram Øst both with two subsea templates tie-backed to Troll C. A PDO exemption for development of Fram H-Nord was approved by the authorities in 2013. However, production start-up of the fast track project Fram H-Nord (statoil interest 49.20%), a separate 4 –slot template tied into existing A2 Fram Vest template started 6 September 2014. As part of the transaction with Wintershall, a farm-down in Vega has been completed. Statoil's interest in Vega (PL090C, PL248 and PL248B) has decreased from 24% to 0%. 3.5.2.4 Operations South The main producing fields in Operations South are Sleipner, Gudrun, Snorre and Statfjord. Operations South produces from the satellite fields Tordis and Vigdis, which are tied into Gullfaks C and Snorre A, as well as the 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. Sleipner also process gas, condensate and oil from Gudrun, Volve and Sigyn. The Gina Krog field, which is under development, will also be tied back to Sleipner. Unstable condensate is mixed with other liquids on Sleipner A and sent to Kårstø for processing. Dry gas is exported to UK of to the continent via Gasled gas export system. The Gudrun (Statoil interest 51.00%) oil and gas field is located in the North Sea. During 2013, Statoil sold 24% of its interest share in the field to OMV, effective from 1 Nov 2013, thus reducing the interest share from 75% to 51%. Production was started on the 7th of April 2014. The total investments are NOK 20 billion. The field development includes a separate steel jacket-based process platform for separation of the oil and gas. Gas and partly stabilised oil are transported in separate pipelines from Gudrun to Sleipner. The Snorre field development (Statoil interest 33.32%) involves two floating platforms and one subsea production system connected to the Snorre A platform. 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 using three fully integrated platforms supported by gravity-based structures with concrete storage cells and an offshore loading system. The Statfjord A lifetime is 2020, while Statfjord B and Statfjord C will continue production to 2025. The Statfjord Late Life Project was completed in 2012 to enable a drainage strategy that will produce remaining gas reserves through water production/pressure depletion. The Statfjord satellites consist of Statfjord North (Statoil interest 21.88%), Statfjord East (Statoil interest 31.69%) and Sygna (Statoil interest 30.71%). These satellites, which have all been developed using subsea templates tied back to Statfjord C, are expected to produce to 2025. 3.5.2.5 Partner-operated fields Partner-operated fields account for approximately 13% of our total oil and gas production on the NCS. The main producing fields are Ormen Lange, Skarv and Ekofisk. Statoil's partner operated fields NCS portfolio is organised under Operations South. Ormen Lange (Statoil interest 25.35%), 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. Statoil, Annual Report on Form 20-F 2014 23


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    Skarv (Statoil interest 36.17%) is an oil and gas field located in the Norwegian Sea, with BP as operator. The field development includes a floating production, storage and offloading vessel (FPSO) and five subsea multi-well installations. Oil is exported by offshore loading, and gas is exported via the ÅTS. The field was put into production 31 December 2012. All wells were drilled and had come on stream by November 2013. Ekofisk is operated by ConocoPhillips. It consists of the Ekofisk, Eldfisk and Embla fields (Statoil interest 7.60%), and Tor (Statoil interest 6.64%). Production started in October 2013 for the new Ekofisk South projects 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. 3.5.3 Exploration on the NCS The exploration activity was high on the NCS in 2014. An extensive drilling program in 2014 resulted in 29 completed exploration wells, of which Statoil acted as operator for 20, with 15 discoveries. In 2014 Statoil was the operator of the industry project for joint 3D seismic acquisition in the south-east Barents Sea. The south-east Barents Sea is the first new area to be opened on the NCS since 1994, and is one of Statoil’s focus areas in the upcoming 23rd licensing round. In addition, Statoil was awarded interests in 11 production licenses (seven as operator) in the Awards in Predefined Areas (APA) round, of which seven licenses will be Statoil operated. In general, the exploration program reflects the diversified exploration portfolio on the NCS, which includes targeting growth prospects, new opportunities in frontier areas, as well as selected prospects in mature areas that can be tied into existing infrastructure. The table below shows the exploration and development wells drilled on the NCS in the last three years. 2014 2013 2012 North Sea Statoil operated exploratory 11 11 7 Statoil operated development 96 85 59 Partner operated exploratory 7 10 7 Partner operated development 11 20 12 Norwegian Sea Statoil operated exploratory 0 7 1 Statoil operated development 14 19 18 Partner operated exploratory 1 1 2 Partner operated development 0 3 7 Barents Sea Statoil operated exploratory 9 2 2 Partner operated exploratory 1 4 0 Partner operated development 4 3 0 Totals Exploratory 29 35 19 Exploration extension wells 2 7 1 Development wells 125 130 96 24 Statoil, Annual Report on Form 20-F 2014


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    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 (NCS Square km licenses (NCS licenses (Statoil licenses (Statoil New licenses New licenses Area Total) (Statoil) Change vs 2013 Total) equity) operated) (Statoil equity) (Statoil operated) North Sea 51,452 14,890 (210) 315 127 97 8 4 Norwegian Sea 46,790 14,262 (2,084) 144 71 49 3 2 Barents Sea 37,901 13,937 (2,676) 70 33 21 1 1 NCS total 136,143 43,089 (4,970) 529 231 167 12 7 North Sea In the North Sea, Statoil participated in 17 completed exploration wells and two exploration extension wells. Statoil operated 10 of the exploration wells with nine discoveries. Key discovery wells are Askja East, Valemon North and D-Structure. In 2015 Statoil plans to further drill in the King Lear area in order to clarify the remaining potential and to pursue exploration efforts around existing infrastructure. Norwegian Sea In the Norwegian Sea, Statoil participated in two exploration wells, which was partner operated. Further deepwater exploration drilling is expected around the Aasta Hansteen area. Barents Sea Ten wells were completed in the Barents Sea in 2014, with Statoil operating nine of which six were announced as discoveries (Kramsnø, Atlantis, Mercury, Pingvin, Isfjell, and Drivis). The Drivis well is contributing with new volumes to the Johan Castberg field development. In addition, the drilling campaign in the Hoop area has contributed with valuable information of the area and tested different plays. Statoil has been the operator of the industry project for joint 3D seismic acquisition in the south-east Barents Sea. An important priority in 2015 will be preparations for the 23rd licensing round. Statoil delivered its nomination for the 23rd round to the Norwegian authorities at the beginning of January 2014 and is preparing for the upcoming application round. 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 2014 for our major development projects on the NCS. Statoil's share at 31 Statoil equity capacity Project Operator December 2014 Production start (mboe per day) Aasta Hansteen Statoil 51.00% 2017 67 Valemon Statoil 53.78% 2015 50 Gina Krog Statoil 58.70% 2017 50 Ivar Aasen Det Norske 41.47% 2016 30 Goliat Eni 35.00% 2015 30 Martin Linge Total 19.00% 2016 18 Edvard Grieg Lundin 15.00% 2015 14 Aasta Hansteen (Statoil interest 51.00%) is a deep water 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 can also serve as a hub for other potential discoveries in the area. Expected production start-up is in 2017. Valemon (Statoil interest 53.78%), which is located in the North Sea, is being developed using 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 production started on 3 January 2015. Gina Krog (Statoil interest 58.7%) is an oil and gas discovery in the North Sea approximately 30 kilometres north of the Sleipner field. 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 Statoil, Annual Report on Form 20-F 2014 25


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    content, the rich gas will be exported via Sleipner, where it 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. Expected production start-up is in 2017. Ivar Aasen (Statoil interest 41.47%) is an oil and gas field located in the Utsira High Area. Its development includes 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, The operator expects production start-up in the fourth quarter of 2016. Goliat (Statoil interest 35.00%) is the first oil field to be developed in the Barents Sea. The field is being developed by means of subsea wells tied back to a circular floating production, storage and offloading vessel (FPSO). The oil will be offloaded to shuttle tankers. The Goliat development is operated by Eni who expects production start-up in the second half of 2015. Martin Linge (Statoil interest 19.00%) is an oil and gas field, operated by Total, near the British sector in the North Sea. The reservoir is complex with gas under high pressure and high temperatures. The development includes a platform as a fixed steel jacket with processing and export facilities. Electrical power will be supplied from Kollsnes. The operator expects production start up in 2016. Edvard Grieg (Statoil interest 15.00%) is an oil field located in the Utsira High Area. Its development will include a fixed steel jacket with processing and export facilities. Edvard Grieg is operated by Lundin. The operator expects production start-up in the fourth quarter of 2015. Statoil entered into an agreement with Wintershall, including acquisition of shares in the Edvard Grieg licence. The transaction was closed 31 July 2013. Fast-track projects are all relatively small projects, yielding high returns. This 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 to reduce costs by 30%. In Statoil's opinion, the initiative has led to cost-efficient development solutions for this kind of discoveries. 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 2014, twelve projects have been sanctioned, of which six started production in 2012 and 2013, and three during 2014. In addition, several other smaller discovery candidates are being considered for future fast-track development. Redevelopment on the NCS - Improved oil recovery (IOR) Statoil has delivered substantial additional value creation on the NCS through world leading recovery rates and the company’s ambition of 60% oil recovery from its operated oilfields on the NCS represents a stretch target well above international benchmarks. IOR projects are important in terms of infrastructure utilization and lifetime, additional value creation and as a source to competence and experience to be used in new business opportunities. In order to deliver on this target we are actively working 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, an upgrade of the existing water injection system, and increased water injection capacity on Gullfaks B. The project was completed in January 2014. 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 was achieved in June 2014. 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 low-pressure production started in July 2014. The Heidrun low-pressure production is a similar project on the Heidrun field. This project was completed in September 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 expected completion date is the fourth quarter of 2015. Subsea compression innovation and technology development are essential to improved oil and gas recovery and to extend 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 towards our ambition of installing the elements for a "subsea factory". Subsea processing is a key in gaining access to resources in Arctic areas and deep water assets. 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 completion of the development is currently expected to take place in 2015. Gullfaks subsea compression is the second largest subsea gas compression project planned by Statoil on the NCS. Subsea gas compression will have a significant impact on the Gullfaks field as this technology, combined with conventional low-pressure production, will help increase the recovery rate from the Gullfaks South Brent reservoir from 62% to 74%. This project is scheduled for completion in 2015. The Ormen Lange onshore compression project was being executed as part of the overall expansion of the Nyhamna facility to handle third-party gas entering the plant through the new Polarled pipeline. The two 37 MW onshore compressors are scheduled for start-up in July 2017. 26 Statoil, Annual Report on Form 20-F 2014


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    The Ormen Lange infield Compression project was in April 2014 terminated ahead of DG2 due to negative economics. The recovery ambition will remain in the Long Range Plan of the License with 2025 as new start-up date. 3.5.5 Decommissioning on the NCS Under the Petroleum Act, the Norwegian government has imposed strict procedures for removal and disposal of offshore oil and gas installations. The Convention for the Protection of the Marine Environment of the Northeast Atlantic (OSPAR) stipulates similar procedures. Glitne ceased production in February 2013 and decommissioning of the field has been ongoing during 2013 and 2014. Permanent plugging and abandonment of the seven wells was completed in October 2014. Glitne commenced production in 2001 as a marginal field and achieved a production that was double the original reserve estimate. Huldra ceased production in September 2014, after 13 years in production. Permanent plugging and abandonment of six wells is planned for 2016 and the plan is that the Huldra topside facilities will be removed in 2018. Yttergryta is a subsea field with one production well that ceased production in 2013. Permanent plugging of the well is ongoing at year end 2014 and is planned to be completed early in 2015. On Heimdal a modular drilling rig has been successfully installed in order to plug and abandon all 12 wells at the Heimdal main reservoir. The plug and abandonment project started in the fourth quarter 2014, and is scheduled to be carried out by second quarter 2016, For further information about decommissioning, see note 2 Significant accounting policies to the consolidated financial statements. Statoil, Annual Report on Form 20-F 2014 27


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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. Development and Production International (DPI) is responsible for all development and production of oil and gas outside the Norwegian continental shelf (NCS). In 2014, DPI was engaged in production in 11 countries: Algeria, Angola, Azerbaijan, Brazil, Canada, Libya, Nigeria, Russia, the UK, the US, and Venezuela. DPI produced 39% of Statoil's total equity production of oil and gas in 2014. As of 31 December 2014, Statoil has exploration licences in North America (Alaska, Canada, and the Gulf of Mexico), South America and sub-Saharan Africa (Angola, Brazil, Colombia, Suriname, and Tanzania), the Middle East and North Africa (Azerbaijan, Algeria and Libya), Europe and Asia (the Faroe Islands, Greenland, Indonesia, Russia and the UK) as well as Oceania (Australia and New Zealand). Statoil also has representative offices in Kazakhstan, Mexico and United Arab Emirates. Statoil closed its office in Iran in 2013 but has residual payment obligations for tax and social security under legacy contracts in Iran. These will be dealt with in accordance with all applicable sanctions. See Risks - Risks related to our business for information regarding sanctions towards Iran. The main development projects in which DPI is involved are in Angola, Azerbaijan, Brazil, Canada, Ireland, the UK, and the US. The map shows Statoil's international exploration and production areas. 28 Statoil, Annual Report on Form 20-F 2014


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    Key events and portfolio developments in 2014: • In February, BHP Billiton notified the Stampede partners of their election to withdraw from the project. Statoil now has an additional 5% interest in the project so Statoil’s interest increased from 20% to 25%. Statoil together with co-owners announced it has sanctioned the Stampede project in October 2014. • Over the course of 2014, Statoil has reduced its ownership interest from 25.5% to 15.5% in Shah Deniz in Azerbaijan and South Caucasus Pipeline (SCP). In March 2014 Statoil closed the sale of 3.33% to BP, and in May 2014 Statoil closed the sale of 6.67% to SOCAR thereby completing the 10% farm down in Shah Deniz and SCP. The effective date was 1 January 2014. • Statoil and its partner, PTTEP in the Kai Kos Dehseh (KKD) oil sands project in Alberta, Canada, completed the agreement in May to divide their respective interests in the KKD oil sands project in northeast Alberta, Canada with an effective date 1 January 2013. • The CLOV oil project in Block 17, Angola, started production in June 2014. • In September 2014, Statoil closed the sale of its 5% interest in Block 15/06 offshore Angola to the concessionaire Sonangol E.P. The effective date was 1 January 2013. • In September, Statoil announced a postponement of the Corner field development at the KKD oil sands project in Alberta, Canada. • In October 2014, Statoil signed an agreement with the Malaysian oil and gas company PETRONAS to divest its remaining 15.5% interest in Shah Deniz and the SCP. The effective date of the transaction is 1 January 2014. Statoil expects that the transaction will be closed in the first half of 2015, pending government approval and other conditions. • The oil fields Jack and St. Malo in the U.S. started production in December. • In December, Statoil announced an agreement to reduce its working interest in the non-operated US southern Marcellus onshore asset from 29% to 23%, following a USD 394 million transaction with Southwestern Energy. The transaction was closed in the first quarter of 2015. • Eleven wells (exploration and appraisal) were announced as discoveries in 2014, including the Seat 2 discovery in Brazil and the Piri and Giligiliani (Statoil-operated) discoveries in Tanzania, totalling five Statoil high-impact discoveries offshore in Tanzania over the last two years. • Time-out in the Kwanza exploration drilling programme, as a consequence a rig contract was cancelled. • In 2014 Statoil, accessed five new basins in Algeria, Colombia, Myanmar, Australia and New Zealand and has also secured new acreage through 12 new exploration licences awarded in the UK 28th licensing round (9 as operator) and 10 leases in the Central US Gulf of Mexico lease sales. • Significant impairment losses on assets and oil and gas prospects and signature bonuses were recognised in 2014, see section Financial review – Operational and financial review – DPI profit and loss analysis for further details. The profitability of our industry continues to be challenged. Statoil’s response to the industrial challenge characterised by escalating cost and declining returns is addressed in the section Strategy and market overview. 3.6.2 International production Statoil's entitlement production outside Norway was about 32% of Statoil's total entitlement production in 2014. The following table shows DPI's average daily entitlement production of liquids and natural gas for the years ending 31 December 2014, 2013 and 2012. Entitlement production figures are after deductions for royalties paid in kind, production sharing and profit sharing. As of fourth quarter 2013, entitlement production from the upstream segment in the US is presented net of royalties. For the year ended 31 December Entitlement production 2014 2013 2012 Oil and NGL (mboe per day) 403 373 342 Natural gas (mmcm per day) 29 26 20 Total (mboe per day) 586 539 470 Total - net of US royalties (mboe per day) 546 502 443 Statoil, Annual Report on Form 20-F 2014 29


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    The table below provides information about the fields that contributed to production in 2014 Producing fields during calendar year 2014 Average daily Average daily entitlement Statoil's equity Licence expiry equity production production Field interest in % Operator On stream date mboe/day mboe/day (1) North America 268.1 227.1 Canada: Hibernia/Hibernia tie-in (2) Varies HMDC 1997 2027 5.9 5.9 Canada: Leismer Demo 60.00 Statoil 2010 HBP (3) 13.7 13.7 Canada: Terra Nova 15.00 Suncor 2002 2022 6.9 6.9 USA: Bakken (4) Varies Statoil/others 2011 HBP 53.6 42.8 USA: Caesar Tonga 23.55 Anadarko 2012 HBP 6.8 6.6 USA: Eagle Ford (4) Varies Talisman/Statoil 2010 HBP 34.5 25.9 USA: Jack 25.00 Chevron 2014 HBP 0.2 0.2 USA: Marcellus (4) Varies Chesapeake/Statoil 2008 HBP 128.8 110.7 USA: St. Malo 21.50 Chevron 2014 HBP 0.2 0.2 USA: Tahiti 25.00 Chevron 2009 HBP 17.4 14.2 South America 56.4 56.4 Brazil: Peregrino 60.00 Statoil 2011 2034 44.7 44.7 Venezuela: Petrocedeño (5) 9.68 Petrocedeño 2008 2033 11.7 11.7 Sub-Saharan Africa 254.7 166.6 Angola: Block 4/05 20.00 Sonangol P&P 2009 2026 1.5 1.3 Angola, Block 15 13.33 ExxonMobil 2004 2026-32 (6) 43.6 19.3 Angola, Block 17 23.33 Total 2001 2022-34 (6) 139.1 85.8 Angola, Block 31 13.33 BP 2012 2031 22.2 20.2 Nigeria: Agbami 20.21 Chevron 2008 2024 48.3 40.0 North Africa 57.5 31.0 Algeria: In Amenas 45.90 Sonatrach/BP/Statoil 2006 2022 17.7 10.4 Algeria: In Salah 31.85 Sonatrach/BP/Statoil 2004 2027 36.3 18.5 Libya: Mabruk 12.50 Total 1995 2033 0.9 0.7 Libya: Murzuq 10.00 Repsol 2003 2033 2.6 1.5 Europe and Asia 106.9 64.4 UK: Alba 17.00 Chevron 1994 2018 2.6 2.6 UK: Jupiter 30.00 ConocoPhillips 1995 HBP Azerbaijan: ACG 8.56 BP 1997 2024 54.6 19.7 Azerbaijan: Shah Deniz 18.51 (7) BP 2006 2041 40.4 36.1 Russia: Kharyaga 30.00 Total 1999 2032 9.2 6.0 Total Development and Production International (DPI) 743.6 545.5 (1) In 2013, Statoil changed its policy for reporting U.S. entitlement volumes from including royalty volumes to excluding royalty volumes. (2) Hibernia and Hibernia tie-in (Statoil working interest 5% and 10.5% respectively) (3) 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 continue being in production status, other regulatory requirements must be met. (4) Statoil’s actual working interest can vary depending on wells and area. (5) Petrocedeño is a non-consolidated company and accounted for pursuant to the equity accounting method. (6) Varies by field. (7) Time weighted average. Statoil reduced its holding from 25.5% to 15.5% in 2014, and has signed an agreement to divest its remaining stake. 30 Statoil, Annual Report on Form 20-F 2014


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    The table below provides information about production per country in 2014. Average daily Average daily entitlement equity production production Country mboe/day (1) mboe/day (2) North America 268.1 227.1 Canada 26.6 26.6 USA 241.5 200.5 South America 44.7 44.7 Brazil 44.7 44.7 Sub-Saharan Africa 254.7 166.6 Angola 206.4 126.6 Nigeria 48.3 40.0 North Africa 57.5 31.0 Algeria 54.0 28.8 Libya 3.5 2.2 Europe and Asia 106.9 64.4 Azerbaijan 95.0 55.9 Russia 9.2 6.0 UK 2.6 2.6 Total Development and Production International (DPI) 732 534 Equity accounted production Venezuela: Petrocedeño (3) 11.7 11.7 Total Development and Production International (DPI) including share of equity accounted production 744 546 (1) In PSA countries our share of capital expenditures and operational expenses are computed on the basis of equity production. (2) In 2013, Statoil changed its policy for reporting U.S. entitlement volumes from including royalty volumes to excluding royalty volumes. (3) Petrocedeño is accounted for pursuant to the equity accounting method. The following sections provide information about the main producing assets internationally. See section Financial review - Operating and financial review - DPI profit and loss analysis for a discussion of the results of operations for year end 2014. 3.6.2.1 North America Production in North America comprises Canada and the USA. Canada Statoil entered the Alberta oil sands in 2007 through a corporate acquisition of North American Oil Sands Corporation, and subsequently farmed down 40% of our interest in the Kai Kos Dehseh (KKD) oil sands project to PTTEP in January 2011. In January 2014, Statoil and PTTEP agreed to divide their respective interests in the KKD oil sands project with an effective date of 1 January 2013. The completion of the transaction was subject to customary regulatory approvals in Canada and was closed in May, 2014. Following the transaction with PTTEP, Statoil continues as operator and 100% working interest owner for the Leismer and Corner projects (see section Development and Production International – Fields under development – North America) which together comprise 123,200 net acres of oil sands leases in Alberta. The Leismer Demonstration Plant (LDP) is the first phase of the KKD development and has been in production since 2011. In addition, we have interests in the Jeanne d'Arc Basin offshore the province of Newfoundland and Labrador in the partner operated producing fields Hibernia and Hibernia tie-in (Statoil interest 5% and 10.5% respectively), Terra Nova (Statoil interest 15%) and in the Hebron development project (Statoil interest 9.7%). Statoil, Annual Report on Form 20-F 2014 31


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    USA Statoil has had a strong growth in production within US shale since entering the first play in 2008, up to its current level of 242 mboe per day in 2014. 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. Statoil has continued to acquire acreage within the play, with a net acreage position of 519,000 acres, including 91,000 net acres acquired in December 2012 where it is now operating. Divestments of non-core acreage have also taken place during 2014 to high-grade our portfolio. The most recent high grading occurred in a transaction with Southwestern. The divested share represents approximately 30,000 acres and 4,000 barrels of oil equivalent per day. Southwestern has taken over operatorship in this US southern Marcellus onshore area through a transaction with Chesapeake in December 2014. Marcellus provides Statoil with a long-life gas asset and considerable optionality in relation to the timing of drilling and production from these leases. Price development and continued improvement in operational efficiency are important variables in determining development plans. Statoil entered the Eagle Ford shale formation (located in southwest Texas) in 2010. Through agreements with Enduring Resources LLC and Talisman Energy Inc., Statoil acquired 67,000 net acres. In 2013, Statoil became operator for 50% of the Eagle Ford acreage, in line with the agreement with Talisman Energy Inc. from 2010. The transfer to operatorship was conducted as a phased process in order to maintain high HSE standards, and operational and business continuity. Statoil gradually took over operatorship, starting from the first quarter 2013, to obtain full operatorship of the Statoil operated acreage by the start of the third quarter of 2013. As a result of a few minor transactions, Statoil's net acreage position at the end of 2014 was 59,000 acres. Statoil entered the Bakken and Three Forks tight oil plays through the acquisition of Brigham Exploration Company in December 2011. Statoil is positioning as a leading player in the fast-growing US onshore oil and gas industry, which is in line with the strategic direction it has set out. Statoil has developed industrial capabilities step-by-step through early entrance into Marcellus and Eagle Ford. Taking on first operatorship through Bakken represented a new significant step for Statoil. Statoil's net acreage position in Bakken at the end of 2014 was 265,000 acres. In deepwater Gulf of Mexico, the Tahiti oil field (Statoil interest 25%) is operated by Chevron. The field is located in the Green Canyon area. There are currently eight producing wells and two water injectors connected to a floating facility, and the field development plan includes additional production and injection wells which will be phased in over time. The Caesar Tonga oil field (Statoil interest 23.55%) is operated by the Anadarko Petroleum Company. The field is located in the Green Canyon area. There are currently four producing wells tied back to the Anadarko-operated Constitution spar host. At the end of 2014, a fifth well had been drilled and completed in the first quarter of 2015. The oil fields for Jack (Statoil interest 25%) and St. Malo (Statoil interest 21.5%) (JSM) are located in Walker Ridge. The fields are tiebacks to the JSM floating production unit and both are operated by Chevron. First production was achieved in December 2014. Currently there is one well producing on Jack and a second production well for St. Malo came online in the first quarter of 2015. 3.6.2.2 South America Statoil's production activities in South America comprise the Peregrino operatorship in Brazil and the Petrocedeño project in Venezuela. 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 wellhead platforms with drilling capability and it is processed on the Peregrino FPSO. Statoil holds a 60% ownership interest in the field and is operator. Venezuela 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. 3.6.2.3 Sub-Saharan Africa Statoil's production activities in Sub-Saharan Africa comprise the Agbami project in Nigeria and four Angolan offshore blocks. Angola The Angolan continental shelf is the largest contributor to Statoil's oil production outside Norway. The production comes from Block 4/05, Block 15, Block 17 and Block 31. 32 Statoil, Annual Report on Form 20-F 2014


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    Block 17 comprises production from four FPSOs; CLOV, Dalia, Girassol and Pazflor. The CLOV project, consisting of the Cravo, Lirio, Orchidea and Violeta fields, came on stream in June 2014 and production was ramped up to design capacity of 160 mboe/d in 2014 ahead of schedule. Block 17 is operated by Total, and Statoil holds a 23.3% interest. Block 15 has production from four FPSOs: Kizomba A, Kizomba B, Kizomba C-Mondo, and Kizomba C-Saxi Batuque. Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil, and Statoil holds a 13.3% interest. Block 4/05 has production from the Gimboa FPSO. Sonangol P&P is the operator for block 4/05 and Statoil holds a 20% interest. Block 31 has production from the PSVM FPSO. BP is the operator for Block 31 and Statoil holds a 13.3% interest. 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 of Nigeria is still debating the Petroleum Industry Bill (PIB), which will most likely increase the government take if passed. The timing and outcome of the bill are uncertain. Together with our partner Chevron, we have initiated arbitration against the national oil company NNPC concerning the interpretation of certain clauses in Oil Mining Licence (OML) 128 production sharing contract which covers Statoil's part of the Agbami field. (see note 23 Other commitments and contingencies in the Consolidated financial statements). Through our ownership in OML 128 in Nigeria, Statoil is party to an ownership interest redetermination process for the Agbami field, for which the outcome is uncertain (see note 23 Other commitments and contingencies in the Consolidated financial statements). 3.6.2.4 North Africa Statoil had in 2014 production in North Africa from Algeria and Libya. Algeria 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%. 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 plant has since April 2013 produced from two out of three trains. The production has been stable. The third train, which was damaged in the January 2013 terror attack, is expected to restart in 2015. The In Salah onshore gas development in which Statoil has a working interest of 31.9% is Algeria's third-largest gas development. A contract of association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil. In late August 2014 Statoil and its partners in Algeria completed the return of personnel to ordinary operations at In Salah and In Amenas. This was a stepwise and thorough process with implementation of new security measures and validation of their effectiveness. When all requirements for a return were in place, Statoil made the decision to return to the In Amenas facility. Statoil will continue to monitor the threat picture in Algeria and take appropriate action if necessary. Libya 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. 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. The unrest in Libya has continued in 2014. The fields Mabruk and Murzuq have been affected with outage in production at various points in time. Statoil expects that this can continue to be the situation. (The production from Libya is not a significant part of total international production). Statoil continues to be represented in Tripoli through a small office manned by local staff. Statoil, Annual Report on Form 20-F 2014 33


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    3.6.2.5 Europe and Asia Statoil's 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) oil field and a 15.5% share in the Shah Deniz gas and condensate field. BP is the operator for both fields. The Chirag Oil Project, the sixth platform on the ACG oil field, came on stream in late January 2014. It has a design capacity of 185 mboe per day. Statoil has an 8.7% stake in the 1,760 km Baku-Tbilisi-Ceyhan (BTC) oil 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 15.5% share in the South Caucasus Pipeline (SCP) , which transports the Shah Deniz gas from Azerbaijan through Georgia to the eastern Turkish border. Statoil is the commercial operator of the SCP Company, responsible for commercial operations relating to SCP. Statoil also runs the Azerbaijan Gas Sales Company, which was established to manage gas allocation and sales to customers in Azerbaijan, Georgia and Turkey. Statoil has in 2014 reduced its ownership interest from 25.5% to 15.5% in Shah Deniz and SCP. In March 2014 Statoil closed the sale of 3.33% to BP, and in May 2014 Statoil closed sale of 6.67% to SOCAR thereby completing the 10% farm down in Shah Deniz and SCP. The effective date was 1 January 2014. In October 2014 Statoil signed an agreement with the Malaysian oil and gas company PETRONAS to divest its remaining 15.5% interest in Shah Deniz and SCP. The effective date of the transaction is 1 January 2014. Statoil expects that the transaction will be closed in the first half of 2015, pending government approval and other conditions. Russia Statoil has a 30% share in the Kharyaga oil field 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. United Kingdom In the UK, Statoil is a partner in two production licences. The Alba oil field (Statoil interest 17%) is located in the central part of the UK North Sea and is operated by Chevron. Jupiter (Statoil interest 30%) is a gas field located in the southern part of the UK North Sea, operated by ConocoPhillips. 3.6.3 International exploration Statoil continues with high international exploration activity in 2014. In 2014 Statoil carried out significant international exploration activity, as is shown by the company's involvement in 23 completed wells (including both Statoil-operated and partner-operated activities). 11 wells (exploration and appraisal) were announced as discoveries in the period, including the Piri and Giligiliani (Statoil-operated) discoveries in Tanzania, which adds up to five Statoil discoveries offshore in Tanzania the last two years. A total of five wells were reported dry, while seventeen wells were under evaluation at the year end. The table below shows the exploratory wells drilled internationally in the last three years. 2014 2013 2012 North America - Statoil operated 3 7 3 - Partner operated 0 4 6 South America/sub-Saharan Africa - Statoil operated 8 6 5 - Partner operated 9 4 7 - Partner operated 0 1 1 Europe and Asia - Statoil operated 2 0 3 - Partner operated 1 2 2 Totals 23 24 27 34 Statoil, Annual Report on Form 20-F 2014


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    The regions where Statoil had exploration activity in 2014 are presented below. North America USA Statoil operated two wells in the Gulf of Mexico (Martin and Perseus exploration wells). Martin was a technical discovery, but not commercial, while Perseus did not encounter any hydrocarbons. Statoil still has a number of promising prospects in its Gulf of Mexico portfolio and is aiming to continue its drilling activities in 2015, with the Maersk Developer, which is on contract through November 2015. Statoil is currently drilling the Yeti prospect. Canada The West Hercules arrived in Canada in November 2014, for a 550 days drilling campaign. The rig has drilled a well and a sidetrack on the Bay de Verde structure adjacent to Bay du Nord. At year end, data acquisition was ongoing in the side track. The rig will continue the appraisal programme throughout most of 2015, and drill some new prospects in the Flemish Pass Basin. The drilling programme is an important investment to support our goal in becoming a producing operator offshore Newfoundland. South America and sub-Saharan Africa Angola Statoil acquired a solid acreage position in the pre-salt play of the Kwanza Basin in 2011 with the operatorship in Block 38 and 39 and partner position in Blocks 22, 25 and 40. Seismic 3D surveys were acquired in 2012 and the first well Dilolo-1 was spudded in Block 39 in the second quarter of 2014. After completion of Dilolo-1 the drillship Stena Carron moved to Block 38 to drill Jacare-1 in the third quarter of 2014. Both of these wells were dry. Based on disappointing well results and the need for further evaluation, Statoil decided to terminate the rig contract with Stena Carron. Drilling activities were also carried out in partner operated blocks, with Puma-1 in Block 25. Repsol spudded the Locosso-1 well in Block 22 in the second quarter of 2014 and the well was completed in November. Brazil In December 2014 acquisition of 10000km2 of 3D seismic over the 11th bid round blocks was concluded, Statoil operated this campaign on behalf of all the partners. Acquisition was initiated in May 2014, and the final data are expected to be delivered in the second quarter of 2016. The exploration appraisal activities in BM-ES-22A and BM-C-33 continued, comprising the conclusion of the São Bernardo DST and Montanhês well in the former, and the completion of SEAT-2, SEAT-2 DST (temporarily suspended) and drilling of Pao-A1 appraisal wells in the latter. The decision on the way forward on these appraisals is pending further appraisal well drilling and analysis. After drilling the Juxia well in block C-M-530, licence BM-C-47, the decision was made to relinquish the block. The well was P&A as dry. In the BM-C-7 licence, part of the C-M-529 block will be unitised to Peregrino Phase II which developed as a result of the 2011 Peregrino South well discovery. In J-3, the Lua Nova appraisal remains suspended. The environmental licencing process for this license is expected to last another 1-2 years. Mozambique The Rovuma area 2 & 5 was relinquished with effect from June 2014. The 5th licence round started in October 2014. The outcome of the licence round is expected to be announced during the second quarter of 2015. Statoil will keep the office in Mozambique until we know the outcome of the licence round. Tanzania Four exploration wells have been drilled so far in 2014. The discoveries of natural gas in Piri-1 and Giligiliani-1 have significantly increased the total in- place volumes in Block 2. Binzari -1 and Kungumanga-1 resulted in a technical discovery and a dry well. Relating to the Zafarani-1 discovery made in 2012 two successful production tests have been conducted in the Zafarani-2 appraisal well followed by the second and last appraisal well, Zafarani-3. Also Piri-2 will be drilled in 2014 (ongoing operation at year end). In May 2013, Statoil acquired a 12% working interest in Block 6 from operator Petrobras Tanzania Ltd. This block has now been relinquished. Middle East and North Africa Azerbaijan The Joint Study Agreement (JSA) with SOCAR for the 170 thousand square kilometer North Absheron area was completed in 2014. A new JSA with SOCAR was signed in November 2014, covering the Karabakh- Ashrafi -Dan Ulduzu areas with an approximate duration of 2 years. Exploration screening and prospect evaluation is being carried out on an ongoing basis for Azerbaijan offshore areas in order to identify new access opportunities. Algeria Statoil and Shell were awarded the 2730 km2 Timissit Permit Licence in the Illizi-Ghadames Basin onshore Algeria in September 2014. Statoil will be the operator with 30% equity, Shell will hold 19% equity and the remaining 51% will be held by Sonatrach. The award represents an opportunity to test a potentially large shale resource play. Statoil, Annual Report on Form 20-F 2014 35


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    Europe (excluding Norway), Asia and Australia UK In 2014 Statoil was awarded interests in 12 exploration licences in the UK 28th licensing round, 9 as operator. Significant positions have been taken both in mature parts of the Central North Sea, such as in the vicinity of the Mariner and Bressay projects, and in relation to play largely untested in UK waters. 11 of the licences are in the North Sea and the remaining one is west of the Hebrides. In terms of size, this additional acreage constitutes almost 8000 Km² and thus represents access at scale. Statoil also participated in the drilling of North Sea exploration well Kookaburra in block 28/15 in the first quarter of 2014. The well was dry. Statoil is planning to drill two exploration wells in 2015 in acreage acquired in the previous UK licensing round, and sees the potential for maturing several additional drilling candidates also on the 28th round acreage. Greenland Statoil, along with partners ConocoPhillips and Nunaoil, was awarded block 6 in the East Greenland licence round in December 2013. Statoil will be operator of the block. The licence has a 16-year exploration period. The first work to be carried out will be seismic acquisition, after which a decision on further work will be made. Statoil previously carried out both shallow core drilling and scientific work in the area to understand the operating environment. In West Greenland (Baffin Bay), Statoil has decided to withdraw from its positions in the Shell-operated Anu and Napu licences as well as the Cairn- operated Pitu licence. The decision to exit is based on a review of the value potential in the licences and gaged against other options in the portfolio. Faroe Islands In 2014, Statoil drilled the Brugdan II well in licence 006 and the Sula Stelkur well in licence 008. Both wells were dry. Due to disappointing well results Statoil have now made the decision to relinquish three licences, whilst retaining license 008. Russia In June 2013, Statoil and Rosneft signed agreements that complete the contractual framework of their joint venture to explore offshore frontier areas in the Sea of Okhotsk and in the Barents Sea. An acquisition of 2D seismic data in the Sea of Okhotsk was completed in September 2013. The requirements for the four offshore licences operated by the Rosneft-Statoil joint-venture include the drilling of six exploration wells in the period from 2016 to 2021. In December 2013, Statoil and Rosneft signed the shareholders and operating agreement for a joint venture to assess the feasibility of commercial production from the Domanik limestone formation. The pilot programme will include data acquisition, and the drilling and hydraulic fracturing of pilot wells in twelve licence blocks in the Samara region. See the section Risks – Risks related to our business for information regarding sanctions towards Russia imposed in 2014. Indonesia The Cikar-1 well in the West Papua IV licence was temporarily suspended by the operator Niko in March 2013. Statoil is currently evaluating several follow-up opportunities in this licence and the neighbouring Aru licence. 2D seismic data acquisition in the Statoil-operated Halmahera II PSC was completed in July 2013 and data processing is ongoing. Statoil is constantly working on optimizing its portfolio in Indonesia and has therefore withdrawn from the Obi and the North Makassar Strait PSC. All firm well commitments were fulfilled in North Makassar Strait, the West Papua IV, the Kuma, and Karama PSCs. Australia In the Ceduna sub-basin in the Great Australian Bight, Statoil holds 30% in four exploration permits with BP as Operator. Currently the partnership is preparing for a drilling campaign starting in 2016. Ongoing licence activities includes maturation of further drilling candidates in the 24 000 Km² permit area. Statoil drilled five wells onshore South Georgina in 2014. Hydrocarbons were encountered, but testing of two wells gave no hydrocarbon flow to surface. Based on the data collected Statoil has concluded that there is no remaining prospectivity within the four permits and decided to exit the licences. In October 2014, Statoil obtained 100% equity share in an exploration permit in the Exmouth Plateau in North Carnarvon basin. The permit covers an area of 13700 Km² and water depth is around 1500 m. Statoil has committed to collect 2000 line kilometres of 2D seismic and 3,500 Km² of 3D seismic data within three years. Based on analysis of this information, Statoil will decide on further steps. New Zealand Statoil is operator with 100% equity share in petroleum exploration permits 55781 and 57057 in the Reinga Basin offshore Northland’s west coast. The licences were awarded in the New Zealand Block Offer 2013 and 2014 respectively. The permits cover 11670 Km² and are located approximately 100 km from shore to the west of New Zealand's North Island, in water depths ranging from 1000m to 2000m. The work programme is designed to fully evaluate the prospectivity of the licences in a step-wise manner within the 15-year permit timeframe. Statoil is committed to collect new 2D seismic data and to undertake seafloor surveys within the first three years. Following an analysis and interpretation of this data, Statoil will decide on further steps. In the New Zealand Block Offer 2014 Statoil was also awarded 50% working interest in blocks 57083, 57085 and 57087 with Chevron as operator. The permits are located in the East Coast and Pegasus basins, southeast off New Zealand’s North Island. The permits cover more than 25000 Km² and sit in water depths between 800m and 3000m. The initial phase of the project will consist of data collection. 36 Statoil, Annual Report on Form 20-F 2014


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    3.6.4 Fields under development internationally The main sanctioned development projects in which DPI is involved are in Angola, Azerbaijan, Brazil, Canada, Ireland, the UK and the USA. This section covers selected projects under development and significant pre-sanctioned projects. Statoil's share at 31 Sanctioned projects* Operator December 2014 Time of sanctioning Production start USA: Big Foot Chevron 27.50% 2010 2015 USA: Heidelberg Anadarko 12.00% 2013 2016 USA: Julia Exxon Mobil 50.00% 2013 2016 USA: Stampede Hess 25.00% 2014 2018 Canada: Hebron Exxon Mobil 9.70% 2012 2017 Ireland: Corrib Shell 36.50% 2001 2015 Algeria: In Salah Southern Fields Sonatrach/BP/Statoil 31.85% 2010 2015 Angola: Block 15, Kizomba Satellites phase 2 Esso Angola 13.33% 2013 2015 Algeria: In Amenas Compression project Sonatrach/BP/Statoil 45.90% 2010 2016 UK, Mariner Statoil 65.10% 2012 2017 Azerbaijan: Shah Deniz phase 2 ** BP 15.50% 2013 2018 Brazil, Peregrino Phase II *** Statoil 60.00% 2015 2019 * Not exhaustive ** Statoil has signed an agreement to divest its remaining 15.5% in Shah Deniz. Transaction expected to be closed in the first half of 2015. *** Statoil made the investment decision on Peregrino phase 2 project in December 2014 and submitted the Plan of Development to Brazilian authorities in Jan. 2015. 3.6.4.1 North America Statoil has a number of significant ongoing development projects in North America. USA Gulf of Mexico 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 currently scheduled for 2015, delayed from the fourth quarter of 2014. The project made the necessary progress in 2014 but the start-up is delayed as a result of delayed installation due to loop currents offshore. Discovered in 2007, Statoil has a 50% working interest in the Julia field located in Walker Ridge area of the Gulf of Mexico, which comprises five blocks. Julia is one of the major discoveries in the Paleogene. Exxon Mobil is the operator and the field will be developed with subsea wells tied back to the Jack-St. Malo production platform. First oil is expected for mid-2016. Statoil has a 12% interest in Heidelberg located in Green Canyon block 859. Heidelberg is operated by Anadarko Petroleum Corp. and was sanctioned in April 2013. Project development includes a SPAR and subsea trees. First oil from Heidelberg is scheduled for mid-2016. USA Onshore In addition to offshore development projects, North America production growth is also boosted significantly by the continued ramp-up from the shale plays Bakken, Eagle Ford and Marcellus (see section Business overview – Development and Production International (DPI) – International Production – North America for further information). Canada Statoil is the operator of the KKD Oil Sands Partnership. The first phase, the Leismer Demonstration Project, came on stream in early 2011. In 2014, Statoil decided to postpone the Corner project at the KKD oil sands project in Alberta, Canada. As a consequence, an impairment loss related to the KKD asset has been recognised. See section Financial review – Operational and financial review – DPI profit and loss analysis for further details. Offshore Newfoundland, 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. First oil is expected in 2017. The Hebron field will be developed using a fixed gravity base structure (GBS). Statoil, Annual Report on Form 20-F 2014 37


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    3.6.4.2 South America In January 2015 Statoil submitted the Plan of Development (PoD) for Peregrino Phase II project in Brazil. In December 2014, Statoil approved the investment decision for the development of the second phase of the Peregrino oil field. In January 2015 the PoD was submitted to the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) for approval. Peregrino Phase II project includes the Peregrino South and South West discoveries. The development consists of one wellhead platform tied back to the existing FPSO. 3.6.4.3 Sub-Saharan Africa In Sub-Saharan Africa, Statoil is participating in the planning and development of projects in Angola and Tanzania. Angola In Block 15, the Kizomba Satellites phase 2 project, which consists of the fields Bavuka, Kakocha, and Mondo South, is expected to start production in 2015. The project includes subsea tiebacks to existing Kizomba B and Mondo FPSO vessels. Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil, with Statoil holding a 13.3% interest in this block. Tanzania Statoil has made several large gas discoveries offshore Tanzania in Block 2. Work is on-going to assess options for developing the discoveries, including the construction of an onshore LNG plant jointly with the co-venturers in Block’s 1, 3 and 4. Statoil is the operator of Block 2 and holds a 65% working interest. 3.6.4.4 North Africa In 2014, Statoil's field development in the North Africa was focused on Algeria. The In Salah Southern Field Development Project in Algeria was sanctioned in late 2010. This project, which is led by Statoil on behalf of the Joint Venture, will mature the remaining four discoveries into production and it is currently scheduled to come on stream in 2015. 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. Statoil's working interest is 31.9%. 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 2016. This will make it possible to reduce wellhead pressure and increase production from the reservoir. The In Amenas facilities are operated through a joint operatorship between Sonatrach, BP and Statoil. Statoil has a 45.9% working interest in In Amenas. The Hassi Mouina exploration licence expired in 2012. The licence is not declared commercial and the process of relinquishment therefore started in 2014. 3.6.4.5 Europe and Asia In Europe and Asia, Statoil is participating in the planning and development of projects in Azerbaijan, the UK, Russia, and Ireland Azerbaijan In December 2013, Statoil and its partners in the Shah Deniz consortium made the final investment decision for the development of the Stage 2 development of the Shah Deniz gas field in Azerbaijan and expansion of the South Caucasus Pipeline (SCP) through Azerbaijan and Georgia. The stage 2 project includes offshore drilling and completion of 26 subsea wells, and the construction of two bridge-linked platforms. First gas from stage 2 is targeted for late 2018. Statoil has a 15.5% interest in Shah Deniz. The South Caucasus Pipeline (SCP) through Azerbaijan and Georgia, the Trans Anatolian Gas Pipeline (TANAP) across Turkey, and the Trans Adriatic Pipeline (TAP) across Greece, Albania and into Italy will together create a new Southern Gas Corridor to Europe. Statoil holds a 15.5% share in SCP and a 20% share in TAP AG, the owner of the Trans Adriatic Pipeline (TAP). Statoil will not participate as an investor in TANAP. Statoil has in 2014 reduced its ownership interest from 25.5% to 15.5% in Shah Deniz and SCP. In March 2014 Statoil closed the sale of 3.33% to BP, and in May 2014 Statoil closed sale of 6.67% to SOCAR thereby completing the 10% farm down in Shah Deniz and SCP. The effective date is 1 January 2014. 38 Statoil, Annual Report on Form 20-F 2014


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    In October 2014 Statoil signed an agreement with the Malaysian oil and gas company PETRONAS to divest its remaining 15.5% interest in Shah Deniz and the South Caucasus Pipeline (SCP). The effective date of the transaction is 1 January 2014. Statoil expects that the transaction will be closed in the first half of 2015, pending government approval and other conditions. United Kingdom Statoil is the operator for the Mariner heavy oil project and holds a 65.1% interest. In December 2012, Statoil made the investment decision to develop the Mariner oil field. 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 2017. The field development plan for Mariner includes a possibility of a future subsea tie-in of Mariner East, a small heavy oil discovery. Statoil is the operator and holds an 86% interest. Statoil is the operator for, and holds an 81.6% interest in Bressay. Bressay is also a heavy oil discovery. Investment decision on Bressay has been postponed and alternative development solutions are currently under evaluation. Postponement of Bressay will not affect or delay the Mariner project. Ireland Statoil has a 36.5% interest in the Corrib gas field operated by Shell, which is being developed as a subsea tie back to an onshore processing facility. The onshore processing terminal is located approximately 9 km inland. The field is expected to start production in 2015. . Statoil, Annual Report on Form 20-F 2014 39


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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, power, emissions, 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, approximately 50 % of all Norwegian liquids exports. MPR is also responsible for marketing SDFI’s gas. See section 3.12.5 The Norwegian State’s participation and 3.12.6 SDFI oil and gas marketing and sale for further details regarding the Norwegian state’s direct financial interest. In total, Statoil is responsible for marketing approximately 70% of all Norwegian gas exports. MPR operates two refineries, two gas processing plants, one methanol plant and three crude oil terminals. In addition, MPR is responsible for developing transportation solutions for natural gas, liquids and crude oil from the Statoil assets including pipelines, shipping and rail. Furthermore, Statoil is responsible for developing a profitable renewable energy position. In 2014, we sold 34.5 billion cubic metres (bcm) of natural equity gas from the Norwegian continental shelf (NCS) on our own behalf, in addition to approximately 33.4 bcm of NCS gas on behalf of the Norwegian state. That makes Statoil the second-largest gas supplier to Europe after Gazprom. Statoil's total US gas sales, including third-party gas, amounted to 12.6 bcm in 2014. In 2014, we also sold 642 million barrels of crude oil and condensate, approximately 14 million tonnes of natural gas liquids (NGL), and approximately 1.2 million tonnes of methanol. Our access to crude oil in the form of equity, governmental and third party volumes makes Statoil a large net crude oil seller. Of the total 642 million barrels sold in 2014, approximately 46% represented Statoil equity volumes, while approximately 39% of the total 14 million tonnes of NGL sold in 2014 were Statoil equity volumes. In 2014 the European gas market was characterised by decreasing demand and falling prices resulting in lower sales volumes compared to 2013. In the U.S. the cold winter in North East US and Canada created large regional arbitrage margins. The LNG market showed continued regional price differences and geographical arbitrage margins. Refinery margins were higher than in 2013. The operation of facilities has been stable. HSE results show an improvement from 2013 for most parameters, but there has been a slight increase in the Serious Incident Frequency compared to 2013. With effect from 1 May 2014, the MPR business activities were organised in the following business clusters: Marketing and Trading; Asset Management; Processing and Manufacturing; and Renewable Energy. This structure is followed in the discussion of MPR's business activities below. Key events in 2014: • Statoil completed the sale of a 10% share of its 25.5% holdings in the Shah Deniz project and the SCP Company with effect from 1 January 2014. The 3.33% transaction with BP was closed in March 2014 and the 6.67% transaction with SOCAR was closed in May 2014. • Statoil signed an agreement with Malaysian company PETRONAS to divest its remaining 15.5% share in Shah Deniz and the SCP Company with effect from 1 January 2014. The transaction will be closed in the first half of 2015, pending governmental approval and other conditions. • Statoil divested a 35% stake in the Dudgeon Offshore Wind Project in U.K to Masdar Abu Dhabi Future Energy Co. Statoil retains a 35% stake and remains operator of the project. • Statoil and Statkraft have agreed with UK Green Investment Bank to divest 20 % of the shares in Scira, each with 10 % reduced equity. • Statoil farmed down 13.255% ownership share in Polarled to Wintershall effective 1 January 2014. The project is aligned with the Aasta Hansteen field development. The profitability of our industry continues to be challenged. Statoil’s response to the industrial challenge characterised by escalating cost and declining returns is addressed in the section Strategy and market overview. 40 Statoil, Annual Report on Form 20-F 2014


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    3.7.2 Marketing and Trading The Marketing and Trading business cluster (MT) is responsible for the marketing and trading of all the products from Statoil’s upstream, processing and refining business and represents one of the larger players in the European oil and gas market. 3.7.2.1 Marketing and trading of gas MT Gas 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, Marketing and Trading of Gas (MT Gas) is responsible for marketing gas related to the Norwegian state's direct financial interest (SDFI). MT Gas business is conducted from Norway (Stavanger) and from offices in Belgium, the UK, Germany, Azerbaijan and the US. Statoil transports and markets approximately 70% of all NCS gas and has a growing US gas position. A significant proportion of Statoil's gas sales contracts are sold under long-term contracts that typically run for 10 to 20 years or more. These sales are carried out with large industrial customers, power producers and local distribution companies. In addition gas is sold through short-term contracts and trading on European liquid marketplaces both in the UK and on the European Continent. In the USA, gas is sold through a mix of contracts and trading on liquid marketplaces. Most of the 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. Statoil is currently in price reviews with some of our customers. 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 as a response to customer needs and in order to capture new business opportunities as the markets become more liberalised and liquid. Statoil has flexibility in the production and transportation system. Combined with downstream assets this is used to optimise the value of the gas. Europe The major export markets for gas from the NCS are Germany, France, the UK, Belgium, Italy, the Netherlands and Spain. Our main customers are large national or regional gas companies such as GdF Suez, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), RWE and GasTerra. We are also expanding our marketing of gas to large industrial customers, power producers and local distribution companies, in addition to making spot-market sales. Our European gas trading business conducts activities on almost all trading hubs within Europe, mainly focused on the UK gas market National Balancing Point (NBP), and on the Title Transfer Facility (TTF) in the Netherlands, which have become significant markets in terms of size and are the most liquid market places in Europe. USA USA 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 organization in Stamford, Connecticut, that markets natural gas to local distribution companies, industrial customers and power generators. SNG also markets the gas equity production from Statoil's assets in the US Gulf of Mexico. 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 USA over the last few years. SNG has entered into gas transportation agreements with Tennessee Gas Pipeline (a subsidiary of Kinder Morgan Inc), and Texas Eastern Transmission (a subsidiary of Spectra Energy Corp), for a total capacity of approx. 2 bcm per year, approx. 205,000 MMBtu/day, enabling Statoil to transport gas from the Northern Marcellus production area to Manhattan, NY. This commenced service on 1 November 2013 for a term of 20 years. SNG has also entered into a gas transportation agreement with the National Fuel Gas Supply Corporation for a total capacity of 3.2 bcm per year, approx. 320,000 MMBtu/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 1st November 2012 for a term of 20 years. In addition SNG has long-term capacity contracts with Dominion Resources Inc., which owns the Cove Point LNG re-gasification terminal in Maryland, with a total capacity of 10.4 bcm per year. Statoil, Annual Report on Form 20-F 2014 41


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    LNG is sourced from the Snøhvit LNG facility in Norway. Due to continuing low gas prices in the USA, most of Statoil's LNG cargoes have been diverted away from the US and delivered into higher-priced markets in Europe, South-America and Asia. Azerbaijan Statoil has completed farm down transactions with BP and SOCAR for the sale of 3.33% and 6.67% respectively in the Shah Deniz Gas Value Chain in first half of 2014. In October 2014 Statoil signed an agreement with Petronas for the divestment of its remaining 15.5% shares. The transaction will be closed in first half of 2015, but effective as from 1 January 2014, pending governmental approval and other conditions. Until closing, Statoil will continue as the commercial operator for gas transportation as well as the operator of marketing and sales of gas from stage 1 of the Shah Deniz gas/condensate field. In addition to the operatorships, Statoil has led the Gas Commercial Committee and has played a key role in the gas export negotiation committee selling the gas from stage 2. Azerbaijan, Georgia and Turkey constitute the market outlets for the stage 1 gas, with Turkey as the main market. Statoil’s operatorships will be transferred to a successor operator in first half of 2015. The project will commence production in 2018 and deliver 16 bcm of gas annually at plateau to customers in Turkey, Bulgaria, Greece and Italy. Algeria Statoil has ownership interests in the In Salah gas field, Algeria's third-largest gas development. The field is operated by a joint venture constituted by Statoil, BP and Sonatrach. Statoil receives its income from gas which is sold under long-term contracts to Europe. 3.7.2.2 Marketing and trading of liquids MPR is responsible for the sale of the group's and the Norwegian state's direct financial interest (SDFI) production of crude oil and natural gas liquids. Statoil is one of the world's major net sellers of crude oil. The company operates from sales offices in Stavanger, Oslo, London, Singapore, Stamford and Calgary and markets and trades crude oils, condensates, NGLs as well as refined products. 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. MT Liquids 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, liftings of LPG from Kårstø, Mongstad, Braefoot Bay and Teeside terminals in addition to condensate and LPG from the In Amenas field In Algeria. We lift waterborne ethane from Kårstø and Teesside, condensate from Nyhamna, and condensate and LPG volumes from Melkøya. In addition, we market equity crude oil, condensate and NGL production from Statoil's unconventional assets in North America. They include the Alberta oil sands, Bakken, Eagle Ford, and Marcellus. Unconventional volumes were mostly sold in the spot market based on publicly quoted prices. Production from Eagle Ford is primarily transported by pipeline while the most part of crude oil from Bakken is transported to the best paying markets by rail. MT Liquids also markets equity volumes from DPI assets located in Canada, USA, Brazil, Angola, Nigeria, Algeria, Russia, Azerbaijan and UK. Marketing activities are also optimised through the use of lease contracts and long-term agreements for the utilisation of third-party assets such as terminals, storages, pipelines, railcars and vessels. 3.7.3 Asset Management The Asset Management business cluster (AM) is the owner of all mid- and downstream assets in Statoil, ranging from refineries to pipelines, storage terminals, shipping activities and other infrastructure lease commitments. AM is responsible for securing flow assurance for gas and oil in order to bring production to the markets. This includes management and development of existing assets and contracts as well as being responsible for Statoil’s mid and downstream investment projects. Furthermore AM ensures that the Marketing and Trading business cluster (MT) has efficient access to assets for trading purposes. 42 Statoil, Annual Report on Form 20-F 2014


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    3.7.3.1 Production plants AM is the owner of Statoil`s two refineries in Norway and Denmark and a combined heat and power plant in Norway. AM manages Statoil`s majority ownership share of a methanol production plant, as well as Statoil`s minority share in a NGL and condensate processing facility. Mongstad Statoil holds 100% ownership and is operator of the Mongstad refinery in Norway. The refinery was built in 1975, and significantly expanded and upgraded in the late 1980s. In addition it has been subject to considerable investments over the last 15 years in order to meet new product specifications and to improve energy efficiency. The refinery is a medium-sized, modern refinery, with a crude oil and condensate distillation capacity of 226,000 barrels per day. The refinery 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, making it an attractive site for landing and processing of hydrocarbons. In addition to the refinery, the main facilities at Mongstad consist of a crude oil terminal (Mongstad terminal), an NGL process unit and terminal (Vestprosess), and a combined heat and power plant (Mongstad Heat and Power Plant). 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. Statoil is the owner of Mongstad Heat and Power Plant, which produces electrical heat and power from gas received from Kollsnes and from the refinery. The combined heat and power plan 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. Kalundborg Statoil holds 100% ownership and is operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 108,000 barrels per day. The Kalundborg refinery is a small, CO2 efficient and 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 one gasoline and one gas oil pipeline to the terminal at Hedehusene near Copenhagen, and most of its products are sold locally. 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% in 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. 3.7.3.2 Terminals and storage AM has ownership in two crude oil terminals in Norway. AM also operates the South Riding Point crude oil terminal in the Bahamas Mongstad terminal Statoil has 65% ownership interest in Mongstad crude oil terminal, while the State holds 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 Mongstad terminal has a storage capacity of 9.4 million barrels of crude oil. The terminal supports Statoil's global trading, blending and trans-shipment of crude. It is an important tool in the marketing of North Sea crude. Sture terminal The Sture crude oil 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. South Riding Point terminal AM operates the South Riding Point Terminal, which is located on Grand Bahamas Island, and consists of two shipping berths and ten storage tanks of crude oil, with a storage capacity of 6.75 million barrels 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. The terminal is intended to both support our global trading activity and improve our handling capacity for heavy oils. The terminal is an integral part of our marketing of equity volumes of heavy oil. Statoil, Annual Report on Form 20-F 2014 43


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    Aldbrough Gas Storage Statoil UK holds one third share of the interests in the Aldbrough Gas Storage in UK, operated by SSE Hornsea Ltd. At the end of 2014 seven out of nine caverns were operational. Etzel Gas Lager Statoil Deutschland Storage GmbH holds a 23.7% stake in the Etzel Gas Lager. 3.7.3.3 Pipelines AM is responsible for Statoil’s ownership in pipelines globally as well as gathering and initial processing in the US. Pipelines in operations Statoil is a significant shipper in the NCS gas pipeline 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. The total length of Norway's gas pipelines is currently 8,100 kilometres, 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 access. The Gassled system is operated by the independent system operator Gassco AS, which is wholly owned by the Norwegian state. When new gas infrastructure facilities are merged into Gassled, the ownership interests are adjusted to reflect each owner's relative interest. Hence, Statoil's future ownership interest in Gassled may change. AM is managing Statoil’s current 5 % ownership share in Gassled. In addition AM manage Statoil’s ownership in the following pipelines outside the Norwegian gas transportation system: Oseberg oil transportation system, Grane oil pipeline, Kvitebjørn oil pipeline, Troll oil pipeline I and II, Valemon rich gas pipeline, and Mongstad gas pipeline. Statoil Deutschland GmbH indirect holds a 30.8% stake in the Norddeutche Erdgas Transversale (NETRA) overland gas transmission pipeline. Pipelines under construction Statoil is the operator and holds a 37.1% ownership share in the Polarled Project which will secure a gas export solution for fields in the Norwegian Sea. Statoil farmed down 13.255% ownership share to Wintershall effective 1 January 2014. The project is aligned with the Aasta Hansteen field development. Statoil is the operator and holds a 30.9% ownership share in the Utsira High Gas Pipeline. The pipeline will provide gas export for the Edvard Grieg and Ivar Aasen fields and is scheduled for start-up in 2015. Statoil is the operator and holds a 25.6% ownership share in the Edvard Grieg Oil Pipeline. The pipeline will provide oil export for the Edvard Grieg and Ivar Aasen fields and is scheduled for start-up in 2015. Statoil is the operator and holds a 40% ownership share in the Johan Sverdrup Oil and Gas Pipeline. The pipelines will provide oil and gas export for the Johan Sverdrup field and is scheduled to start-up in 2019. Statoil holds a 20% ownership share in the Trans Adriatic Pipeline (TAP) which will transport Caspian natural gas to Europe. Connecting with the Trans Anatolian Pipeline (TANAP) at the Greek-Turkish border, TAP will cross Northern Greece, Albania and the Adriatic Sea before coming ashore in Southern Italy to connect to the Italian natural gas network. The project is currently in its implementation phase and is preparing for construction of the pipeline, which is planned to begin in 2016. US gathering system AM is responsible for Statoil’s participation in gathering and facilities for initial processing of oil and gas in the Bakken, Eagle Ford and Marcellus assets in the USA. This includes crude and natural gas gathering systems, fresh water supply systems, salt water disposal wells, oil and gas treatment and processing facilities to provide flow assurance for Statoil’s upstream production. Midstream assets in Bakken are owned and operated 100% by Statoil. In Eagle Ford, Statoil is operator of approximately 50% of midstream assets. For Marcellus Statoil has operated assets in Marcellus South while in the Marcellus non- operated areas both in the North and South, Statoil’s working interest ranges from 16.25% to 32.5% depending on gathering system and number of JV partners. 44 Statoil, Annual Report on Form 20-F 2014


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    3.7.4 Processing and Manufacturing The Processing and Manufacturing business cluster (PM) is responsible for the operation of all of Statoil's onshore facilities in Norway and Denmark except for Snøhvit related facilities, and a substantial part of the oil- and gas pipelines on the NCS. This includes the following Statoil operated plants and pipelines: the refineries at Mongstad and Kalundborg, the methanol production plant at Tjeldbergodden, Oseberg transportation system including the Sture Terminal, Vestprosess, Mongstad Terminal, the Grane, Kvitebjørn and Troll oil pipelines and Mongstad gas pipeline. The following table shows operating statistics for the plants at Mongstad, Kalundborg and Tjeldbergodden. Throughput (1) Distillation capacity (2) On stream factor % (3) Utilisation rate % (4) Refinery 2014 2013 2012 2014 2013 2012 2014 2013 2012 2014 2013 2012 Mongstad 9.2 11.8 11.9 9.3 9.3 9.4 93.4 98.9 95.2 90.0 95.0 92.7 Kalundborg 4.5 5.0 4.9 5.4 5.4 5.4 91.8 98.2 94.4 82.0 86.5 88.9 Tjeldbergodden 0.83 0.79 0.81 0.95 0.95 0.95 88.4 94.4 86.4 97.1 96.6 97.5 (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. In addition PM 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. PM also performs the TSP role for the larger share of the Gassco operated gas pipeline infrastructure. 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 developed to receive gas from the Troll field. Kollsnes now also receives gas from the Visund, Kvitebjørn and Fram fields. 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 stabilized condensate. The dry gas is transported to customers through the Gassled pipeline network via receiving terminals in Europe. For further information about Statoil's operated onshore facilities and pipelines, see the section Business overview - Marketing, Processing and Renewable Energy – Asset Management. 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. 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% in 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. Statoil, Annual Report on Form 20-F 2014 45


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    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, located off the coast of Norfolk, UK, was formally opened in September 2012. The wind farm is in full production with 88 turbines and an installed capacity of 317 megawatt (MW). Following the divestment in 2014, it is now owned 40% by Statkraft, a Norwegian wholly state- owned company, 40% by Statoil and 20% by the UK Green Investment Bank (GIB). The wind farm's estimated annual production is 1.1 terawatt hours (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 five years. The overall performance of Hywind has exceeded expectations. A project, investigating the possibility of installing a 30 MW test farm in Scotland is ongoing. According to current plans, the project is scheduled to make a final investment decision in 2015, and be operational in 2017. Dudgeon offshore wind project Statoil acquired a 70% shareholding in the Dudgeon offshore wind farm project in October 2012 together with Statkraft (30%). In 2014 Statoil reduced its shareholding to 35%. This project is located in the Greater Wash Area off the English east coast, not far from Sheringham Shoal. A final investment decision was made July 2014 for the 402MW project. All key construction contracts are awarded and construction has started. The wind farm is expected to have a production of 1.7 TWh from 67 turbines providing power for approximately 410,000 households. It is expected fully operational by year end 2017. Dogger Bank Statoil was awarded a 25% share in the UK Third Round Dogger Bank concession in 2010 together with partners Rheinisch-Westfalische Elektrizitatswerke (RWE), Scottish and Southern Energy (SSE) and Statkraft. The joint venture (Forewind) is currently undertaking environmental studies and preparing applications for consent to build offshore wind farms. The applications for the first two projects (each 1.2 GW) have been confirmed by the UK authorities to be sufficiently matured, and a final decision is expected in the first half of 2015. Work on the remaining applications continues. Production could start towards the end of the decade. Carbon capture and Storage (CCS) CCS is an important technology for Statoil to protect the value of our natural gas resources in case of emission regulations and/or high carbon taxes on use of natural gas. Statoil has since 1996 gained experience in CCS and has continued to develop the competence through its research engagement in the Technical Centre Mongstad (TCM). Statoil will seek to deploy its competence and experience in other CCS projects, continue to evaluate opportunities to reduce own CO2 emissions and explore CO2 for EOR possibilities. 46 Statoil, Annual Report on Form 20-F 2014


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    3.8 Other Group The Other reporting segment includes activities in Global Strategy and Business Development (GSB); Technology, Projects and Drilling (TPD); and corporate staffs and support functions. 3.8.1 Global Strategy and Business Development (GSB) The Global Strategy and Business Development (GSB) business area is Statoil’s functional head for strategy and business Development. GSB sets the strategic direction for Statoil and identifies, develops and delivers business opportunities. 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 strategy and analysis: Managing corporate strategy development processes, competitor intelligence, industry analysis. • Political Analysis: Monitoring political developments nationally, regionally and globally. The unit assesses geopolitical issues and trends impacting our business, political risk related to specific countries and projects, and changes to the broader security threat picture. • Corporate Sustainability: Setting out Statoil's strategic response to sustainability issues, the development of relevant policies and reporting on the company's sustainability performance. • Business Development Origination: Early screening of business development opportunities, sharing on-the-ground context and intelligence across the organization. • Mergers, Acquisitions and Divestments: Merger/corporate acquisition/divestment options, interfacing with investment bankers, sharing deal activity context and intelligence across the organisation. • Project Support and Execution: Commercial negotiation support, commercial and technical valuation, business development best practice. 3.8.2 Technology, Projects and Drilling (TPD) Technology, Projects and Drilling (TPD) business area is responsible for delivering projects and wells and providing global support on standards and procurement. TPD is also responsible for developing Statoil as a technology company. Key events in 2014: • Completed 103 offshore wells, including 33 exploration wells • Delivered the Gudrun and the Valemon projects to DPN • Delivered three new fast-track projects: Fram H-North, Svalin and Oseberg Delta2 to DPN • Established country office in South Korea • Delivered a high number of new technologies in 2014 - a total of 40 high impact and 69 first-use, which is an increase from 2013 • Some overcapacity in the rig fleet due to reduced demand and increased efficiency • Opened a new increased oil recovery (IOR) research centre at Statoil’s research centre in Trondheim (Norway) in June. It is one of the most advanced in the world and will play a key role in Statoil’s efforts to improve recovery from our fields on the NCS and internationally The TPD's business activities are organised in the following business clusters: Research, Development and Innovation Research, Development and Innovation (RDI) is responsible for carrying out research and technology development to meet Statoil's business needs in a short-and long term perspective. RDI is organised in four research programmes closely aligned with Statoils technology strategy: Exploration, mature area developments and IOR, Frontier developments and unconventionals. In addition, there are two other units - Innovation and projects. RDI has four research centres in Norway with world leading laboratories and large-scale test facilities. Internationally, RDI is present close to our operations in Rio de Janeiro (Brazil), Houston and Austin (the US), Calgary and St. Johns (Canada) and Beijing (China). Cooperation with external environments plays an important role for R&D in Statoil and RDI has an Academia programme that coordinates cooperation with Norwegian and international universities. Technology Excellence Technology Excellence (TEX) is globally responsible for delivering technical expertise to projects, business developments and assets, and for implementing new technology and the corporate technology strategy. Statoil, Annual Report on Form 20-F 2014 47


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    TEX's technological expertise in areas such as petroleum , subsea and marine, facilities and operations, and safety and sustainability technologies, contributes to enhancing Statoil's operational performance. Technology development and implementation are used to promote and achieve corporate targets for production growth, increased regularity, reserve growth, and reduced costs and improved efficiency. TEX is responsible for increasing the level of standardisation and supports innovators and entrepreneurs with technology development and commercialisation activities. Projects Projects (PRO) is responsible for planning and executing all major facilities development, modification and field decommissioning projects in Statoil. The project portfolio comprises around 50 projects in the early phase and 70 in the execution phase. The project portfolio is diverse, ranging from major new field developments to both small and large development projects on the NCS and internationally. The share of larger projects in the portfolio has increased over the last few years. 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 operated 42 rig years in 2014 compared to 44 in 2013, and delivered production and exploration wells offshore on the NCS and Brazil, and exploration wells in Angola, Canada, Gulf of Mexico, Tanzania and Faroe Islands. Procurement and Supplier Relations Procurement and Supplier Relations (PSR) is responsible for procurement on a global basis that is aligned with Statoil’s business needs, and for managing Statoil's supply chain. Statoil's procurements originate from approximately 12,000 active suppliers. The procurement process is based on competition and the principles of openness, non-discrimination and equality. PSR encourage and facilitate collaboration with suppliers through communication and by managing supplier relations. By maintaining strong relations with high-quality suppliers, Statoil aims to ensure lasting long-term competitive advantages. PSR have a strategy for increasing diversity, competition and flexibility in the markets in order to better utilise industry capacity and expertise. 3.8.3 Corporate staffs and support functions Corporate Staffs and support functions comprise the non-operating activities supporting Statoil. They include headquarters and central functions that provide business support such as corporate communication, safety, audit, legal services and people and organisation. 48 Statoil, Annual Report on Form 20-F 2014

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