UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWASHINGTON, DC 20549
 FORM
20-F/A Amendment
No. 1 (Mark One) ☐REGISTRATION
  STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT
  OF 1934ORX     ANNUAL REPORT
  PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended
  December 31, 2015OR☐TRANSITION REPORT PURSUANT TO
  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For
  the transition period from _________ to _________OR☐SHELL COMPANY REPORT PURSUANT TO
  SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Date of event
  requiring this shell company report _________Commission file number
  1-15200Statoil 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)
  Hans Jakob Hegge
  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
  RegisteredAmerican Depositary
  Shares
 New York Stock ExchangeOrdinary 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 CommissionSecurities registered or to be
  registered pursuant to Section 12(g) of the Act:NoneSecurities for which there
  is a reporting obligation pursuant to Section 15(d) of the Act:NoneIndicate
  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                                                                                      3,182,914,686
 3,188,647,103Indicate by check mark if
  the registrant is a well-known seasoned issuer, as defined in Rule 405 of the
  Securities Act.**X** Yes☐NoIf 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  **X** NoNote – 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.**X** Yes☐NoIndicate 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  
      **X**
 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 
  by the International Accounting Standards Board     **X**
 Other☐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   **X** No
 Statoil, Annual Report on Form 20-F
20151


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2Statoil, Annual Report on Form 20-F 2015


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Statoil, Annual Report on Form 20-F
20153


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2015 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 Statoil’s 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 Statoil’s corporate strategy ............................................................................................................................................................................................................................................. 10

2.3 Group outlook ....................................................................................................................................................................................................................................................................... 12

3 Business overview ...................................................................................................................................................................................................................................................................... 13

3.1 Our history ............................................................................................................................................................................................................................................................................. 13

3.2 Our business .......................................................................................................................................................................................................................................................................... 13

3.3 Our competitive position .................................................................................................................................................................................................................................................. 14

3.4 Corporate structure ............................................................................................................................................................................................................................................................ 14

3.5 Development and Production Norway (DPN) ........................................................................................................................................................................................................... 16

3.5.1 DPN overview .............................................................................................................................................................................................................................................................. 16

3.5.2 Fields in production on the NCS............................................................................................................................................................................................................................ 17

3.5.2.1 Operations North ............................................................................................................................................................................................................................................... 20

3.5.2.2 Operations Mid-Norway ................................................................................................................................................................................................................................. 20

3.5.2.3 Operations West ............................................................................................................................................................................................................................................... 20

3.5.2.4 Operations South .............................................................................................................................................................................................................................................. 21

3.5.2.5 Partner-operated fields ................................................................................................................................................................................................................................... 22

3.5.3 Exploration on the NCS ............................................................................................................................................................................................................................................ 22

3.5.4 Fields under development on the NCS ............................................................................................................................................................................................................... 23

3.5.5 Decommissioning on the NCS ............................................................................................................................................................................................................................... 24

3.6 Development and Production International (DPI) ................................................................................................................................................................................................... 25

3.6.1 DPI overview ................................................................................................................................................................................................................................................................ 25

3.6.2 International production ........................................................................................................................................................................................................................................... 26

3.6.2.1 North America .................................................................................................................................................................................................................................................... 28

3.6.2.2 South America .................................................................................................................................................................................................................................................... 29

3.6.2.3 Sub-Saharan Africa ........................................................................................................................................................................................................................................... 29

3.6.2.4 North Africa ......................................................................................................................................................................................................................................................... 30

3.6.2.5 Europe and Asia ................................................................................................................................................................................................................................................. 30

3.6.3 International exploration .......................................................................................................................................................................................................................................... 31

3.6.4 Fields under development internationally .......................................................................................................................................................................................................... 33

3.6.4.1 North America .................................................................................................................................................................................................................................................... 33

3.6.4.2 South America .................................................................................................................................................................................................................................................... 34

3.6.4.3 Sub-Saharan Africa ........................................................................................................................................................................................................................................... 34

3.6.4.4 North Africa ......................................................................................................................................................................................................................................................... 34

3.6.4.5 Europe and Asia ................................................................................................................................................................................................................................................. 34

3.7 Marketing, Midstream and Processing (MMP) .......................................................................................................................................................................................................... 36

3.7.1 MMP overview ............................................................................................................................................................................................................................................................. 36

3.7.2 Marketing and Trading ............................................................................................................................................................................................................................................. 37

3.7.2.1 Marketing and trading of gas and LNG ...................................................................................................................................................................................................... 37

3.7.2.2 Marketing and trading of liquids .................................................................................................................................................................................................................. 38

3.7.3 Asset Management .................................................................................................................................................................................................................................................... 38

3.7.3.1 Production plants ............................................................................................................................................................................................................................................... 38

3.7.3.2 Terminals and storage ..................................................................................................................................................................................................................................... 39

3.7.3.3 Pipelines ................................................................................................................................................................................................................................................................ 39

3.7.4 Processing and Manufacturing .............................................................................................................................................................................................................................. 40

3.8 Other Group .......................................................................................................................................................................................................................................................................... 42

3.8.1 New Energy Solutions (NES) .................................................................................................................................................................................................................................. 42

3.8.2 Global Strategy and Business Development (GSB) ........................................................................................................................................................................................ 43

3.8.3 Technology, Projects and Drilling (TPD) ............................................................................................................................................................................................................ 43

3.8.4 Corporate staffs and support functions ............................................................................................................................................................................................................. 44

3.9 Significant subsidiaries ...................................................................................................................................................................................................................................................... 45

3.10 Production volumes and prices .................................................................................................................................................................................................................................... 45

3.10.1 Entitlement production .......................................................................................................................................................................................................................................... 45

3.10.2 Sales prices ................................................................................................................................................................................................................................................................ 47

3.11 Proved oil and gas reserves .......................................................................................................................................................................................................................................... 48

2 Statoil, Annual Report on Form 20-F 2015

3.11.1 Development of reserves...................................................................................................................................................................................................................................... 52

3.11.2 Preparations of reserves estimates ................................................................................................................................................................................................................... 53

3.11.3 Operational statistics ............................................................................................................................................................................................................................................. 53

3.11.4 Delivery commitments ........................................................................................................................................................................................................................................... 55

3.12 Applicable laws and regulations .................................................................................................................................................................................................................................. 55

3.12.1 Norwegian petroleum laws and licensing system ........................................................................................................................................................................................ 55

3.12.2 Gas sales and transportation from the NCS .................................................................................................................................................................................................. 57

3.12.3 The Norwegian State's participation ................................................................................................................................................................................................................ 57

3.12.4 SDFI oil and gas marketing and sale ................................................................................................................................................................................................................. 57

3.12.5 HSE regulation .......................................................................................................................................................................................................................................................... 58

3.12.6 Taxation of Statoil .................................................................................................................................................................................................................................................. 58

3.13 Property, plant and equipment .................................................................................................................................................................................................................................... 60

3.14 Related party transactions ............................................................................................................................................................................................................................................ 60

3.15 Insurance ............................................................................................................................................................................................................................................................................. 60

3.16 People and the group ...................................................................................................................................................................................................................................................... 61

3.16.1 Employees in Statoil ............................................................................................................................................................................................................................................... 61

3.16.2 Equal opportunities ................................................................................................................................................................................................................................................. 62

3.16.3 Unions and representatives ................................................................................................................................................................................................................................. 62

3.17 Safety, security and sustainability .............................................................................................................................................................................................................................. 63

4 Financial review ........................................................................................................................................................................................................................................................................... 65

4.1 Operating and financial review ....................................................................................................................................................................................................................................... 65

4.1.1 Sales volumes .............................................................................................................................................................................................................................................................. 65

4.1.2 Group profit and loss analysis ................................................................................................................................................................................................................................ 66

4.1.3 Segment performance and analysis ..................................................................................................................................................................................................................... 70

4.1.4 DPN profit and loss analysis ................................................................................................................................................................................................................................... 72

4.1.5 DPI profit and loss analysis ..................................................................................................................................................................................................................................... 73

4.1.6 MMP profit and loss analysis .................................................................................................................................................................................................................................. 75

4.1.7 Other operations......................................................................................................................................................................................................................................................... 77

4.2 Liquidity and capital resources ....................................................................................................................................................................................................................................... 78

4.2.1 Review of cash flows ................................................................................................................................................................................................................................................. 78

4.2.2 Financial assets and debt ......................................................................................................................................................................................................................................... 79

4.2.3 Investments .................................................................................................................................................................................................................................................................. 81

4.2.4 Impact of reduced prices ......................................................................................................................................................................................................................................... 82

4.2.5 Principal contractual obligations ........................................................................................................................................................................................................................... 82

4.2.6 Off balance sheet arrangements........................................................................................................................................................................................................................... 83

4.3 Accounting Standards (IFRS) .......................................................................................................................................................................................................................................... 83

4.4 Non-GAAP measures ......................................................................................................................................................................................................................................................... 83

4.4.1 Return on average capital employed (ROACE) ................................................................................................................................................................................................ 83

4.4.2 Net debt to capital employed ratio ...................................................................................................................................................................................................................... 85

5 Risk review ..................................................................................................................................................................................................................................................................................... 86

5.1 Risk factors ............................................................................................................................................................................................................................................................................ 86

5.1.1 Risks related to our business .................................................................................................................................................................................................................................. 86

5.1.2 Legal and regulatory risks ........................................................................................................................................................................................................................................ 92

5.1.3 Risks related to state ownership ........................................................................................................................................................................................................................... 94

5.2 Risk management ................................................................................................................................................................................................................................................................ 95

5.2.1 Managing operational risk ....................................................................................................................................................................................................................................... 95

5.2.2 Managing financial risk ............................................................................................................................................................................................................................................. 95

5.2.3 Disclosures about market risk ................................................................................................................................................................................................................................ 97

5.3 Legal proceedings ............................................................................................................................................................................................................................................................... 97

6 Shareholder information ......................................................................................................................................................................................................................................................... 98

6.1 Dividend policy .................................................................................................................................................................................................................................................................. 100

6.1.1 Dividends .................................................................................................................................................................................................................................................................... 100

6.2 Shares purchased by issuer ........................................................................................................................................................................................................................................... 101

6.2.1 Statoil's share savings plan .................................................................................................................................................................................................................................. 101

6.3 Information and communications ............................................................................................................................................................................................................................... 102

6.3.1 Investor contact ....................................................................................................................................................................................................................................................... 102

6.4 Market and market prices .............................................................................................................................................................................................................................................. 103

6.4.1 Share prices ............................................................................................................................................................................................................................................................... 103

6.4.2 Statoil ADR programme fees .............................................................................................................................................................................................................................. 104

6.5 Taxation ............................................................................................................................................................................................................................................................................... 105

6.6 Exchange controls and limitations .............................................................................................................................................................................................................................. 108

6.7 Exchange rates .................................................................................................................................................................................................................................................................. 109

6.8 Major shareholders .......................................................................................................................................................................................................................................................... 110

7 Corporate governance ........................................................................................................................................................................................................................................................... 112

7.1 Articles of association .................................................................................................................................................................................................................................................... 112

Statoil, Annual Report on Form 20-F 2015 3

7.2 Code of Conduct............................................................................................................................................................................................................................................................... 113

7.3 General meeting of shareholders ................................................................................................................................................................................................................................ 114

7.4 Nomination committee................................................................................................................................................................................................................................................... 115

7.5 Corporate assembly ......................................................................................................................................................................................................................................................... 116

7.6 Board of directors ............................................................................................................................................................................................................................................................. 119

7.6.1 Audit committee ...................................................................................................................................................................................................................................................... 123

7.6.2 Compensation and executive development committee ............................................................................................................................................................................ 124

7.6.3 Safety, sustainability and ethics committee .................................................................................................................................................................................................. 124

7.7 Compliance with NYSE listing rules ........................................................................................................................................................................................................................... 125

7.8 Management ...................................................................................................................................................................................................................................................................... 127

7.9 Compensation to governing bodies ........................................................................................................................................................................................................................... 130

7.10 Share ownership ............................................................................................................................................................................................................................................................ 141

7.11 Independent auditor ..................................................................................................................................................................................................................................................... 141

7.12 Controls and procedures ............................................................................................................................................................................................................................................. 143

8 Consolidated financial statements Statoil ................................................................................................................................................................................................................... 144

8.1 Notes to the Consolidated financial statements ................................................................................................................................................................................................... 149

1 Organisation ...................................................................................................................................................................................................................................................................... 149

2 Significant accounting policies ................................................................................................................................................................................................................................... 149

3 Segments ............................................................................................................................................................................................................................................................................ 158

4 Acquisitions and disposals............................................................................................................................................................................................................................................ 161

5 Financial risk management ........................................................................................................................................................................................................................................... 162

6 Remuneration .................................................................................................................................................................................................................................................................... 165

7 Other expenses ................................................................................................................................................................................................................................................................ 166

8 Financial items .................................................................................................................................................................................................................................................................. 167

9 Income taxes ..................................................................................................................................................................................................................................................................... 168

10 Earnings per share ........................................................................................................................................................................................................................................................ 170

11 Property, plant and equipment ................................................................................................................................................................................................................................ 170

12 Intangible assets ........................................................................................................................................................................................................................................................... 173

13 Financial investments and non-current prepayments ..................................................................................................................................................................................... 175

14 Inventories ...................................................................................................................................................................................................................................................................... 175

15 Trade and other receivables ..................................................................................................................................................................................................................................... 176

16 Cash and cash equivalents ........................................................................................................................................................................................................................................ 176

17 Shareholders' equity .................................................................................................................................................................................................................................................... 176

18 Finance debt ................................................................................................................................................................................................................................................................... 177

19 Pensions ........................................................................................................................................................................................................................................................................... 178

20 Provisions ........................................................................................................................................................................................................................................................................ 182

21 Trade and other payables .......................................................................................................................................................................................................................................... 183

22 Leases ............................................................................................................................................................................................................................................................................... 184

23 Other commitments, contingent liabilities and contingent assets ............................................................................................................................................................. 184

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







EXPLANATORY
NOTE  Statoil ASA (“Statoil”) is filing this Amendment No. 1 on
Form 20-F/A (the “Form 20-F/A”) to amend its annual report on Form 20-F for the
fiscal year ended December 31, 2015 (the “2015 Form 20-F”) as originally
filed with the Securities and Exchange Commission (the “SEC”) on March 18,
2016. Due solely to an administrative error, certain of the information
included in the 2015 Form 20-F was inadvertently omitted or published in Norwegian.For the convenience of the reader, the Amendment sets forth the
original filing in its entirety, except that the following sections have been
amended: Section 1.2, Section 4.2.1, Section 7.9, Section 8.0 and Section 8.1. This Amendment does not contain any changes to data, disclosure or
footnotes as otherwise presented in the 2015 Form 20-F.Other than as expressly set forth above, this Form 20-F/A does not, and
does not purport to, revise, update, amend or restate the information presented
in any Item of the 2015 Form 20-F or reflect events that have occurred after
the filing of the 2015 Form 20-F.The 2015 Form 20-F continues to
speak as of the dates described therein. This amendment should be read in
conjunction with Statoil's filings made with the SEC subsequent to the 2015
Form 20-F, as information in such filings may update or supersede certain
information contained in the 2015 Form 20-F and in this Form 20-F/A. Statoil is filing as Exhibits 12.1 and 12.2 and 13.1 and 13.2 to
this Form 20-F/A, currently dated certifications required under Section 302 and
906 of the Sarbanes-Oxley Act of 2002.   4Statoil, Annual Report on Form 20-F 2015


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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 2015
("Annual Report on Form 
20-F") is available online atwww.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, US. You can also call the SEC at
1-800-SEC-0330 for further information about the public reference rooms and
their copy charges, or you can log on to www.sec.gov. The report can also be
downloaded from the SEC website at www.sec.gov.  Statoil discloses on its website at www.statoil.com/en/about/corporategovernance/statementofcorporategovernance/pages/default.aspx,
and in its Annual Report on Form 20-F (Item 16G) significant ways (if any) in
which its corporate governance practices differ from those mandated for US
companies under the New York Stock Exchange (the "NYSE") listing
standards.  Statoil, Annual Report on Form 20-F
20155


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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).  (in NOK
  billion, unless stated otherwise)
 For the year ended 31 December2015
 2014
 2013
 2012
 2011Financial informationTotal revenues and other
  income4)
 482.8
 622.7
 634.5
 718.2
 670.0Net operating income
 14.9
 109.5
 155.5
 206.6
 211.8Net income
 (37.3)
 22.0
 39.2
 69.5
 78.4Non-current finance debt
 264.0
 205.1
 165.5
 101.0
 111.6Net interest-bearing
  debt before adjustments
 122.0
 89.2
 58.0
 39.3
 71.0Total assets
 966.7
 986.4
 885.6
 784.4
 768.6Share capital
 8.0
 8.0
 8.0
 8.0
 8.0Non-controlling interest
 0.3
 0.4
 0.5
 0.7
 6.2Total equity
 355.1
 381.2
 356.0
 319.9
 285.2Net debt to capital
  employed ratio before adjustments
 25.6%
 19.0%
 14.0%
 10.9%
 19.9%Net debt to capital employed
  ratio adjusted
 26.8%
 20.0%
 15.2%
 12.4%
 21.1%Calculated ROACE based
  on Average Capital Employed before adjustments
 (8.0%)
 2.7%
 11.3%
 18.7%
 22.1%Operational informationEquity oil and gas
  production (mboe/day)
 1,971
 1,927
 1,940
 2,004
 1,850Proved oil and gas
  reserves (mmboe)
 5,060
 5,359
 5,600
 5,422
 5,426Reserve replacement
  ratio (three-year average)
 0.81
 0.97
 1.15
 1.01
 0.90Production cost equity
  volumes (NOK/boe, last 12 months)
 48
 49
 44
 42
 42Share information1)Diluted earnings per
  share NOK
 (11.8)
 6.87
 12.50
 21.60
 24.70Share price at Oslo Børs
  (Norway) on 31 December in NOK
 123.70
 131.20
 147.00
 139.00
 153.50Dividend per share NOK 2)
 7.62
 7.20
 7.00
 6.75
 6.50Dividend per share USD 2),3)
 1.07
 0.97
 1.15
 1.21
 1.08Weighted average number
  of ordinary shares outstanding (in thousands)
 3,179,443
 3,179,959
 3,180,684
 3,181,546
 3,182,1131)
 See section 6
  Shareholder information for a description of how dividends are determined and
  information on share repurchases.
  The board of directors
  will propose the total 2015 dividend for approval at the annual general
  meeting scheduled for 11 May 2016.2)
 Proposed cash dividend
  for 2015. For 2015, the NOK amount covers first quarter while the USD amount
  is for second, third and fourth quarter. Figure presented for 2015 using the
  Central Bank of Norway 2015 year end rate for Norwegian kroner, which was USD
  1.00 = 8.8090 NOK.3)
 Figures presented using
  the Central Bank of Norway year end rate for Norwegian kroner.4)
 Total revenues and other
  income for 2013 and 2012 are restated.
  6Statoil, Annual Report on Form 20-F 2015


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2 Strategy and market overview  The
profitability of the oil and gas industry continues to be challenged and Statoil’s
financial results in 2015 were influenced by the fall in oil prices.Stricter project prioritisation
and a comprehensive efficiency programme are showing progress and are expected
to continue to improve cash flow and profitability. Statoil proposes to the annual general meeting a scrip
dividend from the fourth quarter of 2015. Statoil’s strong financial
position provides a firm basis on which to balance capital investment and
dividends to shareholders, which Statoil expects to grow in line with its
long-term earnings.  Last year Statoil outlined plans to further strengthen its
competitiveness, and is now reinforcing its effort and commitment to deliver on
priorities of high value creation, increased efficiency and competitive
shareholder returns. Through Statoil`s flexibility in its investment programme Statoil
believes that it is well prepared for potential sustained market volatility and
uncertainty.  Statoil’s ambition to further reduce costs and improve efficiency
was presented at the capital markets update (CMU) on 6 February 2015. Then, the
company announced that it was targeting annual savings of USD 1.7 billion from
2016 (pre-tax) as measured against the cost base of 2013. Having already
realised $1.9 billion in savings (pre-tax), Statoil announced a new goal at the
CMU on 4 February 2016. The company will step up its efficiency programme by
50% with a goal to realise USD 2.5 billion in annual savings from 2016
(pre-tax), again as measured against the cost base of 2013.The step-up of $0.8
billion is expected to be divided by two-thirds capital expenditures (capex) and
one-third operational expenditures (opex).  Improvement programmes are Statoil’s response to the
industrial challenges characterised by high costs 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
section 10 Forward-Looking Statements for more information.  2.1 Statoil’s business environment 2.1.1 Market overview  Global economic GDP growth eased in 2015, to 2.4% from 2.6% in
2014. This largely reflects weakness in non-OECD economies where activity
decelerated over the year. Growth in OECD, on the other hand, held up
relatively well at around 2%, supporting overall economic growth and energy
demand.  The underlying fundamentals of the United States economy remain
sound and GDP growth ticked up slightly to 2.5% in 2015 from 2.4% in 2014. GDP
growth also accelerated nominally in the Eurozone to 1.5%, supported by low
energy prices, reduced fiscal headwinds, more monetary stimulus and a weak
euro. UK GDP growth slowed in 2015, but remains decent at 2.4%, whereas Japan
barely avoided its fourth recession in five years. Growth in emerging countries
slipped to 3.6% in 2015, reflecting both weakness in commodity prices and
domestic challenges. Deep recessions have emerged in Brazil and Russia, whilst
China continues on an intended path of gradual deceleration and consequent
structural reforms. Net commodity importers such as India are doing much
better, and India’s GDP growth rate outpaced China’s in 2015.  Several major forces are at play in the global economy and will
continue to affect demand, including soft commodity prices and persistently low
interest rates, 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 is expected to
continue to do so in 2016.  Global oil demand grew by a healthy 1.6 mmbbl per day in 2015,
driven by a colder than normal winter in the US and Northern Europe and the
lower prices of crude oil. Demand growth in absolute terms was highest in
China, despite 2015 being a challenging year for Chinese stock markets and the
Chinese economy in general. Non-Opec producers have proven to be resilient to
lower prices and grew production by 1.3 mmbbl per day in 2015 while Opec added
1.1 mmbbl per day to their production, mainly from Saudi Arabia and Iraq. This
has postponed the rebalancing between supply and demand and has led to a
continued drop in oil prices.  2015 saw moderate growth in gas supply and demand of 1.5%, which
is below the growth rates of the previous years. The United States is the main
driver behind the growth. Europe experienced a weather-driven increase in
demand as compared to 2014. Gas consumption declined in Japan and South Korea
due to weak power sector gas demand caused by the (re)start of coal and nuclear
power plants. Gas demand growth slowed in China and other emerging markets,
with more competitively priced oil products being one contributing factor. In
the United States, a Statoil, Annual Report on Form 20-F
20157


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multi-year wave of gas supply
growth came to an end in 2015, but demand could not keep up with supply growth,
and prices fell. A strong supply of pipeline gas to Europe and an emerging
oversupply of LNG have further depressed gas prices.    8Statoil, Annual Report on Form 20-F 2015


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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. The situation at the end of 2015, with high storage
levels and low prices, will continue to put pressure on international oil
companies to increase efficiency and reduce costs. This will contribute to a
gradual rebalancing of markets for oil and gas. The impact of this on price
levels and price developments is very uncertain.  2.1.2 Oil prices and refining margins  High volatility characterised the oil market in 2015, with the
price of Brent in a range between USD 66 per barrel in May to USD 35 per barrel
at the end of December. Refinery margins were well above normal levels due to
low crude prices throughout the year.  Oil prices The average price for dated Brent crude in 2015 was USD 53/bbl,
down 47% from 2014. The price was at USD 55/bbl in the beginning of 2015, on a
downward trajectory. A temporary low was reached at just above USD 45/bbl in
the middle of January before the prices started climbing again. A positive
market sentimentdrovethe price of dated Brent up in the second quarter. Signs of a
downturn in the Chinese economy and the nuclear deal between P5+1 and Iran
contributed to a declining market sentiment and prices fell again to a new low
in August. The price of dated Brent recovered somewhat again in the 3rd
quarter and in to the 4th quarter, before the 168th Opec
meeting on the 4th of December. No action was agreed by the Opec
member countries and the price of Brent went below USD 40/bbl for the first
time since the spring of 2009. The dated Brent price was USD 36/bbl on 31
December 2015, a year-end level not seen for a decade. The futures market for
Brent at the Intercontinental Exchange (ICE) was in contango throughout 2015. See
section 9 Terms and definitions for further details.  Although the conflict level in Syria increased further and the
armed conflict in Yemen added tension in the Middle East, geopolitical events
had less effect on the crude oil prices in 2015, compared with the previous
year.  Opec’s decision, in late 2014, to not balance the market, marked
the change of a 30-year old strategy. Subsequent to this the oil market was
highly volatile throughout 2015, while the participants endeavoured to find the
new price level of crude oil. Although oil demand increased by 1.6 mmbbl per
day, much due to a cold winter and low prices, the market remained oversupplied
throughout the whole year, with total supply growth of 2.4 mmbbl per day of
production. As a consequence, the global oil stocks were at historically high
levels by year-end.  2015 was an eventful year for North American (NA) crude. The price
of US WTI crude, as quoted at the Cushing tank farm in Oklahoma, averaged USD
49/bbl in 2015, down 47% from 2014. The price of WTI was USD 53/bbl at the
beginning of the year. On 31 December 2015 the WTI price was at USD 37/bbl,
roughly at par with first month Brent. With low crude prices through 2015, rig
counts have dropped and production growth has faltered. At the same time, crude
inventories have continued to grow, further weighing on crude prices. New
pipeline and crude distillation capacity, coupled with slower production
growth, have created a tighter balance for US light crude, easing the large
price discounts of inland crudes relative to Brent. The easing of discounts has
challenged the economics of more expensive transport solutions such as rail
relative to pipeline, such that crude by rail loadings have declined
dramatically during 2015. In late 2015, the US government passed legislation
allowing unrestricted export of crude oil for the first time since the 1970s.
While little impact is expected in the global market short term, given the
current oversupplied global crude market, unrestricted US crude exports
provides producers with greater access to higher value global crude markets and
could impact price differentials.  Refining margins Refinery margins in Northwest Europe, as calculated against dated
Brent crude, were well above normal in 2015. One reason for the strength was
the weak crude oil market, with dated Brent priced below the first forward
month at the ICE exchange throughout the year. Further, the price differentials
vs. Brent for the crude oils actually used were lower than last year. The other
main factor was a very strong gasoline market. Low price levels at the pump led
to rising demand in the US, and gasoline demand in Europe stopped falling.
Changes to the Chinese economy led to more emphasis on the consumer sector. New
car sales in China almost matched that of the US, and some 80% were net
additions to the fleet. Chinese gasoline demand therefore rose almost as much
as in the US, and strong growth was also seen in India and Pakistan. This
demand growth led to capacity constraints at refineries, in particular for
high-octane components. Europe, being in net surplus on gasoline, was able to
export more into these markets, with parts of it going as high-octane
components at strong price premiums. For naphtha, which is a feedstock both for
the petrochemical industry and for making gasoline, Asian demand for imports
from Europe rose through the year and gave very strong margins here. On the
other hand, new refineries in Asia and the Middle East were geared towards
diesel production. New diesel volumes exported to Europe led to rising inventory
levels here, despite a quite strong demand growth. The situation became
dramatic in the fourth quarter of 2015, when high refinery throughputs in order
to make enough gasoline and naphtha led to excess diesel production. This made
diesel tanks go full and the diesel margin decreased. LPG was oversupplied due
to high exports from the US. Heavy fuel oil was oversupplied due to declining
demand. However, against the low Brent crude oil prices, both products still
saw quite normal margins.   Statoil, Annual Report on Form 20-F
20159


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2.1.3
Natural gas prices  Natural gas prices fell during 2015 in most markets. European gas
prices reached the lowest level since early 2010. Reasons include weak demand,
good supplies and low prices for coal, oil and other competing fuels. Henry Hub
gas prices in the United States also declined during 2015, and the prices at
year-end were at the lowest level since the 1990s.  Gas prices - Europe European gas market prices averaged USD 6.5/mmBtu in 2015, down 20%
from 2014. EU gas consumption for heating purposes recovered in 2015 as
temperatures returned to more normal levels after a particularly mild winter in
2014. The use of gas for power generation increased in Southern Europe due to
high summer temperatures, but declined in other parts of Europe. High
availability of wind in 2015 and a steady growth in renewable generation
capacity made inroads in the overall need for gas-fired and other thermal power
plants in Europe.  Norwegian exports of pipeline gas reached record-levels of 108 bcm
in 2015. EU indigenous gas production fell by 10% to 125 bcm as the Dutch
government lowered existing production caps at the large Groningen field as a
response to earthquake activity. Russia exported more than 150 bcm of pipeline
gas to Europe in 2015, close to recent historical highs. Europe imported around
50 bcm LNG in 2015, more than in 2014, but still 35 bcm below the peak a few
years ago.  Gas prices - North America Firstquarter
prices centered on USD 3/mmBtu, while second and third quarter prices
fluctuated around USD 2.75/mmBtu, with weather-related ups and downs. However,
in the fourth quarter prices fell and reached USD 1.50/mmBtu at the end of the
year, as storage rose to new record highs and an El Niño weather event quashed
demand in the winter peak season. As a result, the Henry Hub average of USD
2.6/mmBtu was the lowest annual price in over a decade, down from USD 4.4/mmBtu
in 2014. US gas
producers responded to the falling prices by withdrawing rigs. Gas production
peaked at the end of the summer and supply has been falling since. Demand for
gas was strong in 2015, with natural gas for the first time exceeding coal use
in the power sector for most of the year. Global LNG prices Global prices for LNG have plummeted. Prices under
long-term LNG contracts to buyers in Asia are tracking oil prices with a lag,
and contract prices were typically down 40% from 2014. The price assessment for
spot LNG cargoes in Asia reached USD 7.5/mmBtu over the year compared to USD
14/mmBtu in 2014. LNG prices are now back to levels prior to the Fukushima
nuclear disaster in March 2011. The global LNG market has entered a period
where the growth of supplies from Australian, US and other liquefaction
projects could exceed demand.  2.2 Statoil’s
corporate strategy  Statoil
creates value by accessing, exploring, developing, and producing energy sources
globally, and by enhancing the value of such production through its mid- and
downstream positions.  Fundamental
changes are happening in the oil and gas industry. The industry faces new
challenges, such as increased pressure on margins, changing patterns of energy
supply and consumption, geopolitical instability and rising climate change
concerns.  Statoil's top
priorities remain to conduct safe and reliable operations with zero harm to
people and the environment, and to grow value through disciplined investments
and prudent financial management with competitive redistribution of capital to
shareholders. To succeed going forward in turning Statoil’s vision into
reality, Statoil pursues a strategy that will: ·Deepen and prolong
Statoil’s NCS position ·Grow material and
profitable international positions ·Pursue focused and
value-adding mid- and downstream activities ·Provide energy for
a low carbon future  In addition, Statoil
will research, develop, and deploy technology to create opportunities and
enhance the value of Statoil’s current and future assets.   10Statoil, Annual Report on Form 20-F 2015


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Deepen and prolong
Statoil’s NCS position For more than
40 years, Statoil has explored, developed and produced oil and gas from the
Norwegian continental shelf (NCS). Statoil aims to deepen and prolong its
position by accessing and maturing opportunities into valuable production. At
the same time Statoil plans to improve the reliability and lifespan of fields
already in production. ·Exploration:Statoil has proven to be a committed NCS explorer across mature, growth, and
frontier areas. In the last year, Statoil participated in 21 completed
exploration wells of which 10 were discoveries. Statoil announced discoveries
in the Aasta Hansteen area, the Krafla area, and the King Lear area. Statoil
applied for new acreage in the Barents Sea as part of the 23rd
licensing round and entered the Barents Sea Exploration Collaboration with four
other oil and gas explorers to address common operational challenges. Statoil
also applied for additional NCS licenses during the 2015 Awards in Predefined
Areas (APA) with the results awarded in 2016 ·Development:Statoil received approval from the Norwegian Ministry of Petroleum and Energy
for the plan for development and operation (PDO) for Johan Sverdrup Phase I and
awarded several related key contracts to suppliers. The development plan for
Johan Sverdrup Phase II, along with other projects, continues to be matured. In
2015, Statoil delayed the concept selection for Johan Castberg, Snorre 2040 and
Trestakk (sanctioned early 2016) to secure robust development solutions. Gina
Krog’s expected start-up is now 2017 with the steel jacket having been
installed and predrilling of the production wells started ·Production:Statoil began production from Valemon, Oseberg Delta 2, Gullfaks South Oil,
Smørbukk South Extension and the Lundin-operated Edvard Grieg field. Three
major projects to increase recovery have been delivered in 2015; at Troll A two
new gas compressors were installed, the Åsgard subsea compression, the world’s
first subsea gas compression plant, came on stream, and the world’s first
subsea wet gas compressor is nearing completion at Gullfaks  Statoil made
further portfolio adjustments to improve its NCS position. Statoil increased
its share in the Alfa Sentral project, which straddles the border of the NCS
and UK continental shelf (UKCS). Statoil’s equity share now stands at 24% in licence
P312 on the UKCS and 62% in licence PL046 on the NCS (Statoil-operated); the
two licenses together comprise the Alfa Sentral field. Statoil also farmed down
in the Gudrun field. Statoil remains the operator of the field.  The target to
reduce CO2 emissions on the NCS was increased to
1.2 million tonnes by 2020, which is up 50% from the initial target of 800,000
tonnes. The initial target was set in 2008 and is expected to be reached in
2016.  Grow material and profitable international
positions International
oil and gas production represents approximately 37% of Statoil’s equity
production and now stands at 739 kboe/d. Statoil will continue to explore,
develop, and produce oil and gas opportunities outside Norway to enhance
Statoil’s upstream portfolio. ·Exploration:Statoil is an active international explorer for oil and gas. In the last year,
Statoil participated in 18 completed exploration wells of which eight were
discoveries. Statoil focused in Canada, Tanzania, Brazil, the UK and the US
Gulf of Mexico. Statoil announced a gas discovery in Tanzania (Mdalasini-1).
Statoil accessed new acreage in Canada, New Zealand, Indonesia, Mozambique,
Russia, and the US Gulf of Mexico, and entered three new countries, Nicaragua,
South Africa, and Uruguay. Government approval is pending for the newly
acquired acreage in Mozambique, South Africa, and Uruguay. Statoil exited both
our operated and non-operated licenses in the Chukchi Sea (Alaska). Statoil
also closed its office in the Faroe Islands following the relinquishment of our
exploration acreage ·Development:In Europe, the partner-operated Corrib gas field in Ireland came on stream at
the end of 2015; meanwhile, Statoil postponed the Mariner field’s start-up date
to 2018. In the US Gulf of Mexico, the partner-operated Heidelberg project
entered its final stages in 2015 as it prepared for first oil in early 2016,
meanwhile Big Foot was postponed due to technical challenges in the final
project stage ·Production:Production has steadily increased from fields such as CLOV in Angola and
Jack/St. Malo in the US Gulf of Mexico. In the US, further optimisation of the
onshore portfolio targeting cost improvements has been on-going, including the
reorganisation of some of the activities to extract greater synergies  Statoil made
further portfolio adjustments to improve its international exploration
portfolio. Statoil sees value in gaining operatorships, and in 2015 Statoil
became the operator in BM-C-33 offshore Brazil, which contains the Pão de
Açúcar, Seat, and Gávea discoveries. Statoil also completed an agreement to
reduce Statoil’s average working interest in Statoil’s non-operated US southern
Marcellus onshore asset from 29% to 23%. In another transaction, Statoil
acquired an additional 13% interest in Statoil’s Eagle Ford joint venture and
became its sole operator.  Pursue focused
and value-adding mid- and downstream activities The prime
objective for Statoil’s mid- and downstream activities is to process and
transport its oil and gas production (including the Norwegian State’s
petroleum) competitively to premium markets, securing maximum value
realisation. The priorities are: ·High
regularity in midstream operation and continuous improvement within HSE,
efficiency and costs ·Market
Statoil’s equity production (crude oil, natural gas, related products) and the
State’s Direct Financial Interest (SDFI) volumes for maximum value creation ·Develop
the Asset Backed Trading model across commodities ·Maintain
the position as a leading European gas supplier ·A
capital lean asset structure  Strategic focus
is directed at optimising the value of Statoil’s flexible Norwegian gas
production assets that supply Europe and Statoil’s midstream activities in
North America, where Statoil’s onshore un-conventionals portfolio is
progressing and where margin capture is important. Statoil achieved strong
trading results across all commodities and robust refinery results through good
margins, cost reductions and high availability.  Statoil, Annual Report on Form 20-F
201511


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Strategic
progress in Statoil’s mid- and downstream portfolio has been made in 2015.
Export pipelines for the Utsira High and the Norwegian Sea (Polarled) were
installed. Statoil agreed to divest its 20% stake in the Trans Adriatic
Pipeline AG in 2015 following earlier divestments in 2014.  Providing
energy for a low carbon future Statoil recognises that opportunities are
increasingly available in producing low carbon energy. In 2015, Statoil created
a new business area, New Energy Solutions, to further access, develop, and produce
low carbon energy when and where it is deemed valuable. ·Development: In
the 4th quarter 2015, Statoil sanctioned Hywind Scotland Offshore
Floating Test Park in Scotland; Statoil’s ownership share is 100%. The park
will have a total installed capacity of 30 MW and planned production start-up
is 2017. The Dudgeon Offshore Wind Park sanctioned in 2014 is progressing as
planned towards start-up in 2017; Statoil’s ownership share is 35%. The park
will have a total installed capacity of 402 MW. The Forewind consortium,
comprising Statoil, Statkraft, RWE and SSE, all with a 25% owner stake,
continues to mature projects and has received consent for four 1.2 GW projects
in the Dogger Bank Area off the UK east coast ·Production:
Statoil is a non-operating partner in the Scira consortium (40% owner stake)
which produces electricity from the Sherringham Shoal wind park in the UK. The
park has an installed capacity of 317 MW  Research,
development, and deployment of technology to unlock opportunities and enhance
value Statoil
believes that technology is a critical success factor in the current business
environment. Statoil’s technology development activities aim to reduce field
development, drilling and operating costs, and CO2and other
greenhouse gas emissions.
Statoil’s technology efforts focus on the following priority areas: ·Business-critical
technologies: Upstream technologies are prioritised, primarily in the areas of
Exploration, Reservoir, Drilling and Well and Subsea production systems.
Statoil’s main focus has been on cost reduction, for example further
development of the steerable drilling liner system to reduce well construction
costs ·Strengthening
Statoil’s licence to operate: Statoil’s commitment to sustainability continues.
Statoil’s ongoing “Powering collaboration” agreement with GE aims to accelerate
the development of more sustainable energy solutions by addressing CO2
and methane emissions, water usage and energy optimisation of operations.
Statoil is also addressing energy efficiency of operating assets by, e.g.
implementing on-line water wash systems on gas turbines ·Expanding
Statoil’s capabilities: Statoil’s technical capabilities are expanding to meet
the challenges of the New Energy Solutions business area for renewable and low
carbon energy solutions. Technology development is conducted in-house, in
collaboration with suppliers and through venture activities. A key
technological focus area is finding more efficient ways of producing clean
energy, particularly by reducing costs in the areas of construction and
maintenance for both fixed and floating offshore wind applications  2.3
Group outlook  Statoil’s plans address the
current environment while continuing to invest in high-quality projects.
Statoil continues to reiterate its efforts and commitment to deliver on its
priorities of high value creation, increased efficiency and competitive
shareholder return.  ·Organic capital
expendituresfor
2016 (i.e. excluding acquisitions, capital leases and other investments with
significant different cash flow pattern) are estimated at around USD 13 billion ·Statoil intends to continue
to mature the large portfolio of exploration assets and estimates a totalexploration
activitylevel of around USD 2 billion for 2016, excluding signature
bonuses ·Statoil aims to deliverefficiency
improvementswith pre-tax cash flow effects of around USD 2.5 billion annually
from 2016 ·Statoil’s ambition is to
keep theunit of production costin the top quartile of Statoil`s peer
group ·For the period 2014 – 2017,organic production growth[7] is expected to come from new projects
resulting in around 1% CAGR (Compound Annual Growth Rate) from a 2014 level
rebased for divestments ·Theequity productionfor
2016 is estimated to be somewhat lower than the 2015 level [7] ·Scheduled maintenanceactivityis
estimated to reduce quarterly production by approximately 25 mboe per day in
the first quarter of 2016 of which the majority is liquids internationally. In
total, the maintenance is estimated to reduce equity production by around 60
mboe per day for the full fiscal year 2016, which is higher than the 2015
impact ·Indicative effects from
Production Sharing Agreement (PSA-effect) and US royaltiesare estimated to be around
135 mboe per day in 2016 based on an oil price of USD 40 per barrel and 165
mboe per day based on an oil price of USD 70 per barrel [4] ·Deferral of productionto 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 ·The board of directors
proposes to the annual general meeting (AGM) maintaining a dividend of USD
0.2201 per share for the fourth quarter 2015 and to introduce a two-year scrip
dividend programme foreligible shareholdersstarting from the fourth quarter 2015 ·With effect
from first quarter of 2016, Statoil will change toUSD as presentation currency 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. For further
information see section 10 Forward-Looking Statements.  12Statoil, Annual Report on Form 20-F 2015


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3Business
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, Statoil’s 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, Statoil was 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, Statoil has utilised their 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,
Statoil carried out an initial public offering of Statoil Fuel & Retail ASA
on the 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 also
participates 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. Statoil has business operations in more
than 30 countries and employs about 21,600 employees worldwide.  Statoil is the leading operator on the Norwegian continental shelf
(NCS) and also has substantial international activities. Statoil is present in
several of the most important oil and gas provinces in the world. In 2015, 37%
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.   Statoil, Annual Report on Form 20-F
201513


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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. In
addition, Statoil competes to develop wind energy opportunities.  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. Statoil believes it is 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.  Statoil has endeavoured
to be accurate in our presentation of information based on other sources, but
has not independently verified such information.  Improvement programmes Statoil’s ambition to further reduce cost and improve
efficiency was presented at the capital markets update (CMU) on 6 February 2015,
targeting annual savings of USD 1.7 billion from 2016. At the CMU on 4 February
2016, Statoil announced that it will step up its efficiency programme by 50%
with a goal to realise USD 2.5 billion in annual savings from 2016.  Improvement programmes are Statoil’s response to the
industrial challenge characterised by reducing prices for our products, 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 andProduction 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 USA (DPUSA) 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
United States (DPUSA) DPUSA
comprises our upstream activities in the USA and Mexico. DPUSA's ambition is to
develop a material and profitable position in the US and Mexico, including the
deep water regions of the Gulf of Mexico and unconventional oil and gas in the
US. In this connection, Statoil aims to further strengthen its capabilities in
deep water and unconventional oil and gas operations.  Marketing, Midstream and
Processing (MMP) MMP comprises
our marketing and trading of oil products and natural gas, transportation,
processing and manufacturing, and the development of oil and gas value chains.
MMP's ambition is to maximise value creation in Statoil's midstream, marketing
and renewable energy business.  Technology, Projects and
Drilling (TPD) 14Statoil, Annual Report on Form 20-F 2015


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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 costs in the
group down.    Statoil, Annual Report on Form 20-F
201515


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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.  New Energy Solutions (NES) NES reflects Statoil’s
aspirations to gradually complement its oil and gas portfolio with profitable
renewable energy and other low-carbon energy solutions.NES is
responsible for wind parks, carbon capture and storage as well as other
renewable energy and low-carbon energy solutions.  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 DPUSA business areas; Marketing, Midstream and Processing
(MMP); and Other.  The Other
reporting segment includes activities in New Energy Solutions (NES),
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.  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.  See note 3
Segmentsin theConsolidated financial statementfor more
details.  16Statoil, Annual Report on Form 20-F 2015


---

3.5 Development and Production Norway (DPN)  3.5.1
DPN overview  Development
and Production Norway (DPN) is responsible for field development and
operational activities on the Norwegian continental shelf (NCS). Statoil's equity and entitlement production on the NCS was 1,232 mboe per day
in 2015. That was about 68% of Statoil's total entitlement production and 62.5%
of Statoil's equity production.  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.
  
  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. DPN’s efforts in these core areas
  also focus on finding and developing smaller fields through the use of
  existing infrastructure and on increasing production by improving the
  recovery factor.
  
  DPN
  is also working to extend production from our existing fields through
  improved reservoir management and the application of new technology.
                   Statoil, Annual Report on Form 20-F
201517


---

Key
events and portfolio developments in 2015: ·In
January 2015, Statoil announced the start-up of production at the Valemon oil
and gas field in the North Sea ·Statoil
announced production start up on fast track projects at the Oseberg Delta in
February, Gullfaks Sør Olje in July and Smørbukk Sør Extension in September ·In
November the start up of production at the Edvard Grieg field was announced by
Lundin ·The
major redevelopment projects Åsgard Subsea compression and two new compressors
on the Troll A platform have started up ·A total
of seven turnarounds were planned to be performed during 2015. Four turnarounds
were carried out, and three turnarounds were deferred from 2015 to 2016 to
coordinate with other activities due to reduce production losses and reduce
costs ·Plan
for Development and Operations (PDO) for the Johan Sverdrup field and Gullfaks
Rimfaksdalen Fast track project were approved by the Ministry of Petroleum and
Energy (MPE) and the PDO for Oseberg Vestflanken 2 was submitted to the MPE ·An
extensive exploration drilling program in 2015 resulted in 21 completed wells,
of which 10 were discoveries. A total of 16 wells were Statoil operated ·Statoil
has delivered an extensive application for the 23rd concession round
and has been awarded interest in 24 licenses on the NCS in the Awards in
Predefined Areas (APA) 2015, 13 of those as operator and 11 as partner ·In
December Statoil announced that it farmed down to Repsol a 15% interest in the
Gudrun field. Statoil remains as operator and largest equity holder with a 36%
interest  The
profitability of our industry continues to be challenged.Statoil’s response to the
industrial challenge characterised by high costs and declining returns is
addressed inthe
section 2 Strategy and market overview.   3.5.2 Fields in production on the NCS  Statoil’s entitlement production at NCS was
about 68% of Statoil’s total entitlement production in 2015.  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 2015, 2014 and 2013. Field
areas are groups of fields operated as a single entity.  For the
  year ended December 31,2015
 
 2014
 
 2013Oil and
  NGL
 Natural
  gas
 
 
 Oil and
  NGL
 Natural
  gas
 
 
 Oil and
  NGL
 Natural
  gasArea
  production
 mbbl
 mmcm
 mboe/day
 
 mbbl
 mmcm
 mboe/day
 
 mbbl
 mmcm
 mboe/dayOperations North
 32
 7
 78
 
 36
 7
 80
 
 24
 5
 56Operations Mid
 113
 17
 218
 
 126
 17
 235
 
 126
 15
 222Operations West
 267
 51
 591
 
 264
 43
 535
 
 290
 48
 589Operations South
 134
 13
 214
 
 107
 11
 177
 
 94
 12
 167Partner Operated Fields
 50
 13
 132
 
 55
 16
 157
 
 58
 20
 182Total
 595
 101
 1,232
 
 588
 95
 1,184
 
 591
 99
 1,217
 18Statoil, Annual Report on Form 20-F 2015


---

The following table shows the NCS production by fields and field
areas in which Statoil was participating as of 31 December 2015.  Business
  cluster
 Geographical area
 Statoil's equity interest in %
 Operator
 On stream
 Licence expiry date
 
 Average daily production in 2015 mboe/dayOperations NorthSnøhvit
 The Barents
  Sea
 36.79
 Statoil
 2007
 2035
 
 47.1Norne
 The Norwegian
  Sea
 39.10
 Statoil
 1997
 2026
 
 5.9Alve
 The Norwegian
  Sea
 85.00
 Statoil
 2009
 2029
 
 10.6Urd
 The Norwegian
  Sea
 63.95
 Statoil
 2005
 2026
 
 14.2Total Operations North
 
 
 
 
 
 
 77.9Operations Mid-NorwayÅsgard
 The Norwegian
  Sea
 34.57
 Statoil
 1999
 2027
 
 92.1Morvin
 The Norwegian
  Sea
 64.00
 Statoil
 2010
 2027
 
 16.3Mikkel
 The Norwegian
  Sea
 43.97
 Statoil
 2003
 2020
 1)
 14.3Tyrihans
 The Norwegian
  Sea
 58.84
 Statoil
 2009
 2029
 
 49.6Kristin
 The Norwegian
  Sea
 55.30
 Statoil
 2005
 2033
 2)
 24.5Heidrun
 The Norwegian
  Sea
 13.04
 Statoil
 1995
 2024
 3)
 8.7Njord
 The Norwegian
  Sea
 20.00
 Statoil
 1997
 2021
 4)
 6.1Hyme
 The Norwegian
  Sea
 35.00
 Statoil
 2013
 2014
 5)
 6.2Total Operations
  Mid-Norway
 
 
 
 
 
 
 217.8Operations WestTroll Phase 1 (Gas)
 The North Sea
 30.58
 Statoil
 1996
 2030
 
 185.2Troll Phase 2 (Oil)
 The North Sea
 30.58
 Statoil
 1995
 2030
 
 38.2Fram
 The North Sea
 45.00
 Statoil
 2003
 2024
 
 16.9Fram H Nord
 The North Sea
 49.20
 Statoil
 2014
 2024
 
 2.3Oseberg
 The North Sea
 49.30
 Statoil
 1988
 2031
 
 86.4Tune
 The North Sea
 50.00
 Statoil
 2002
 2032
 6)
 1.9Gullfaks
 The North Sea
 51.00
 Statoil
 1986
 2036
 
 69.4Gimle
 The North Sea
 65.13
 Statoil
 2006
 2034
 7)
 2.6Kvitebjørn
 The North Sea
 39.55
 Statoil
 2004
 2031
 
 64.0Valemon
 The North Sea
 57.76
 Statoil
 2015
 2031
 
 16.4Visund
 The North Sea
 53.20
 Statoil
 1999
 2034
 
 48.5Grane
 The North Sea
 36.66
 Statoil
 2003
 2030
 
 45.8Volve
 The North Sea
 59.60
 Statoil
 2008
 2028
 
 10.0Veslefrikk
 The North Sea
 18.00
 Statoil
 1989
 2020
 8)
 3.1Total Operation West
 
 
 
 
 
 
 590.5Operations SouthSleipner Vest
 The North Sea
 58.35
 Statoil
 1996
 2028
 
 49.2Sleipner Øst
 The North Sea
 59.60
 Statoil
 1993
 2028
 
 44.4Gungne
 The North Sea
 62.00
 Statoil
 1996
 2028
 
 10.0Gudrun
 The North Sea
 36.00
 Statoil
 2014
 2028
 9)
 6.1Statfjord Unit
 The North Sea
 44.34
 Statoil
 1979
 2026
 
 42.6Statfjord Øst
 The North Sea
 31.69
 Statoil
 1994
 2026
 10)
 1.3Statfjord Nord
 The North Sea
 21.88
 Statoil
 1995
 2026
 
 1.2Sygna
 The North Sea
 30.71
 Statoil
 2000
 2026
 10)
 0.8Snorre
 The North Sea
 33.28
 Statoil
 1992
 2015
 11)
 35.6Vigdis area
 The North Sea
 41.50
 Statoil
 1997
 2024
 
 14.6Tordis area
 The North Sea
 41.50
 Statoil
 1994
 2024
 
 8.2Total Operations South
 
 
 
 
 
 
 214.0
 Statoil, Annual Report on Form 20-F
201519


---

Business
  cluster
 Geographical area
 Statoil's equity interest in %1)
 Operator
 On stream
 Licence expiry date
 
 Average daily production in 2015 mboe/dayPartner Operated FieldsOrmen Lange
 The Norwegian
  Sea
 25.35
 Shell
 2007
 2041
 12)
 47.8Skarv
 The Norwegian
  Sea
 36.17
 BP Norge AS
 2013
 2033
 13)
 46.8Ekofisk area
 The North Sea
 7.60
 ConocoPhillips
 1971
 2028
 
 14.3Marulk
 The North Sea
 50.00
 Eni Norge AS
 2012
 2025
 
 13.2Vilje
 The North Sea
 28.85
 Marathon Oil
 2008
 2021
 
 4.0Sigyn
 The North Sea
 60.00
 ExxonMobil
 2002
 2022
 
 3.8Ringhorne Øst
 The North Sea
 14.82
 ExxonMobil
 2006
 2030
 
 1.7Edvard Grieg
 The North Sea
 15.00
 Lundin Norway
  AS
 2015
 2035
 
 0.4Total Partner Operated
  Fields
 
 
 
 
 
 
 131.9Total
 
 
 
 
 
 
 1,232.0
  1)   PL092 expires in
  2020 and PL121 expires in 2022.
  2)   PL134B expires in
  2027 and PL199 expires in 2033.
  3)   PL095 expires in
  2024 and PL124 expires in 2025.
  4)  PL107 expires in 2021
  and PL132 expires in 2023.
  5)   PL348 expires in
  2029.
  6)   PL034 expires in
  2020. PL053 expires in 2031 and PL190 in 2032.
  7)   PL120B expires in
  2034 and PL050DS expires in 2023.
  8)   PL052 expires in
  2020 and PL053 in 2031.
  9)  The 2015 Statoil farm
  down transaction with Repsol completed 31 December 2015 (From ownership 51%
  to 36% at Gudrun field)
  10)  PL037 expires in
  2026 and PL089 expires in 2024.
  11)  PL089 expires in
  2024 and PL057 expires in 2016.
  12)  PL209/250 expires in
  2041 and PL208 expires in 2040.
  13)  PL212/262 expires in
  2033 and PL159 expires in 2029.The following
  sections provide information about the main producing assets. See section 4.1.4DPN profitand
  loss analysis for
  a discussion of results of operations for 2015, 2014 and 2013.
   20Statoil, Annual Report on Form 20-F 2015


---

3.5.2.1 Operations North  The main producing fields in the Operations
North area are Snøhvit and Norne.  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 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 and then processed at our Liquefied Natural
Gas (LNG) plant on Melkøya. The LNG are shipped to customers in Europe, Asia,
North and South America in tankers. TheCO2in 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 removedCO2is liquefied, transported
through a pipeline, and then injected into a storage reservoir in Snøhvit. The
LNG plant has produced according to plan in 2015, with high production
efficiency, improved HSE results and enhanced cost efficiency.As of 1 January
2016 responsibility for operation of Snøhvit onshore facilities is transferred
from DPN to MMP.  Norne is an oil field in
the Norwegian Sea. The field has been developed using a floating production,
storage and offloading vessel (FPSO) connected to subsea templates. Alve,
Marulk, Urd and Skuld are tie-in fields connected to the Norne FPSO.  3.5.2.2 Operations Mid-Norway  The main producing fields in the Operations
Mid-Norway area are Åsgard, Kristin, Tyrihans and Heidrun.  Operation Mid-Norway
operates in a mature part of the Norwegian Sea, and is a significant
contributor to Statoil’s equity production. Main focus is to capitalise
existing fields through profitable realisation of increased oil recovery and
successful implementation of new developments. There is still exploration
potential in the area and a targeted exploration effort is in execution.  The Åsgard field 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. In September 2015 Statoil started the world first subsea gas compressor
on Åsgard. The compressor increases the Åsgard recovery rate from 67% to 87% thereby
extending the reservoirs’ productive lives. Mikkel and Morvin are tie ins to
Åsgard.  Tyrihans is a subsea field
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.  Kristin 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.  Heidrun is developed with
a floating concrete tension leg platform. The oil is transferred to the
floating storage unit, Heidrun B, operated from June 2015.  The Njord field is located
in the Norwegian Sea and the field has been developed with a floating steel
platform unit, Njord A, with both drilling and processing facilities. The
subsea field Hyme is tied back to Njord A. As a result of structural
integrity issues Njord A was temporarily shut down and extensive reinforcement
work was completed through a long turnaround period from Sept 2013 to July 2014.
Since July 2014 conditional monitoring and precautionary evacuation in
forecasted bad weather conditions have been applied. In addition there is no
drilling activity. The Project “Njord Future” is established to secure long
term production for both the Njord and Hyme fields and to act as a tie-in host
candidate for discoveries in the area.  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. Itsmain focus is prolonging and increasing production through
increased oil recovery, exploration and new field developments.  Trollis 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. Fram and Fram H Nord are tie-ins to Troll C. Statoil, Annual Report on Form 20-F
201521


---

In October 2015 Troll
A finalised the third and fourth pre-compressor project as 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.  TheOsebergarea includes the Oseberg
Field Centre, Oseberg C, Oseberg East and Oseberg South production platforms.
Oil and gas from the satellites are transported in pipelines to the Oseberg
Field Centre for processing and transportation.  The Delta2 facilities project on Oseberg
Field Center was completed in 2015. Drilling operations related to the project
have been on-going throughout 2015 and were finalised in January 2016. The
Vestflanken2 project at Oseberg Field Center was sanctioned December 2015 with
drilling to be performed by the Cat-J rig on the new unmanned wellhead
platform, both under construction, with drilling expected to start third
quarter in 2017. The Tender Support Vessel (TSV) project at Oseberg Øst is
expected to commence drilling support operations in 2016.  Gullfakshas been developed with
three large concrete production platforms. 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.  Drilling of the new
Gullfaks South Increased Oil Recovery (GSO IOR) project wells is ongoing.
Operations on the satellites will continue with a mobile rig until September
2016 and plan for development and operation for Shetland/Lista was delivered in
second quarter of 2015.  The Gullfaks Rimfaksdalen (PDO)
was submitted in 2014 and production will start up in the fourth quarter of
2016. Drilling of wells was completed in 2015. The projects Gullfaks B Drilling
Upgrade and Gullfaks South IOR both started up in 2015.  Kvitebjørnis a gas and condensate
field. The field is developed with an integrated accommodation, drilling and
processing facility with a steel jacket.  TheValemonfield is a gas
and condensate field between Kvitebjørn and Gullfaks South. Valemon is built as
a normally not manned, fixed steel platform with separation facilities for gas,
condensate and water. The condensate is piped to Kvitebjørn for stabilisation and
from there to the Mongstad refinery near Bergen. The production started in
January 2015.  Visundis an oil and gas field
development that includes floating drilling, production and living quarter
units and two subsea templates, in the northern and southern parts of the field.  Graneis Statoil's largest
producing heavy oil field.The Svalin field is a tie-in to Grane platform.  TheHeimdalplatformsare a hub for the processing
and distribution of gas to the European gas markets. The hub consists of an
integrated steel platform and a riser platform. During 2015 Heimdal has plugged
and abandoned its production wells inthe main reservoir. Heimdal
will start production in 2016 from one new well drilled from the modular rig
which was temporarily installed for plugging and abandonment activity.  3.5.2.4 Operations South  The main producing fields in Operations South
are Sleipner, Gudrun, Statfjord and Snorre.  Operation South represents a mature oil and
gas province. However, it still remains a significant contributor to Statoil’s
equity production and new fields are under development in the area. Main focus
in the area is to capitalise on existing fields through profitable realisation
of increased oil potential and successful implementation of new developments.  Sleipnerconsists of
the Sleipner East, Gungne and Sleipner West gas and condensate fields. The gas
from Sleipner has a high level of CO. This is extracted at the field and
re-injected into a sand layer beneath the seabed to reduce carbon dioxide
emissions to the air. Sleipner also processes gas, condensate and oil from
Gudrun, Volve and Sigyn. The Gina Krog field, currently under development, will
also be tied back to Sleipner.  TheGudrunfield is a separate steel
jacket-based process platform for separation of oil and gas, with separate
pipelines transporting gas and partly stabilised oil from Gudrun to Sleipner.  Statfjordhas been
developed using three fully integrated platforms supported by gravity-based
structures with concrete storage cells and an offshore loading system.
Statfjord North, Statfjord Øst and Sygna are satellite fields have all been
developed using subsea templates tied back to Statfjord C.  TheSnorrefield has two
floating platforms and one subsea production system connected to the Snorre A
platform.In
addition, the satellite fields Tordis andVigdis are
part of Snorre business unit and are tied back to Gullfaks C and Snorre A,
respectively.   22Statoil, Annual Report on Form 20-F 2015


---

3.5.2.5 Partner-operated fields  Partner-operated fields account for
approximately 11% 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 Langeoperated 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.  Skarvis 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.  Ekofiskis operated by
ConocoPhillips. It consists of the Ekofisk, Eldfisk and Embla fields, and Tor.
The Eldfisk II project delivered a new PDQ platform early 2015 that will serve
as Eldfisk field center.  Edvard Griegis an oil field located
in the Utsira High Area. The field development includes a fixed steel jacket
with processing and export facilities. Edvard Grieg is operated by Lundin.
Production started on 28 November 2015 according to plan. Two wells were ready
at start-up. Drilling will continue and a total of 10 production wells and four
injection wells are planned.  3.5.3 Exploration on the NCS  Continued high exploration activity on the NCS  An extensive
drilling program in 2015 resulted in 21 completed wells, of which 10 were
discoveries. A total of 16 wells were Statoil operated.  Statoil has
delivered an application for the 23rd concession round on the NCS.
The round covers 57 blocks and parts of blocks, with three in the Norwegian Sea
and 54 in the Barents Sea. South-East Barents Sea is the first new exploration
acreage area opened on the NCS since 1994. Statoil and 15 other companies
cooperate in the Barents Sea Exploration Collaboration (BaSEC) project to find
common solutions for exploration operations in the Barents Sea and to ensure
cost-effectiveness and good safety standards.  Statoil has
been awarded interest in 24 licences in the Awards in Predefined Areas (APA)
round 2015 on the NCS, 13 of those as operator and 11 as partner. Statoil has
been awarded new licences in all three NCS provinces – North Sea, Norwegian Sea
and the Barents Sea.  In general,
Statoil’s exploration strategy on the NCS is reflected in its diverse
exploration portfolio, which ranges from frontier drilling to infra-structure
led exploration close to existing infrastructure.  The table
below shows the exploration and development wells drilled on the NCS in the
last three years.  2015
 2014
 2013North SeaStatoil operated
  exploratory
 11
 11
 11Partner operated exploratory
 3
 7
 10Norwegian SeaStatoil operated
  exploratory
 5
 0
 7Partner operated
  exploratory
 1
 1
 1Barents SeaStatoil operated
  exploratory
 0
 9
 2Partner operated
  exploratory
 1
 1
 4TotalsExploratory
 21
 29
 35Exploration extension
  wells
 3
 2
 7
 Statoil, Annual Report on Form 20-F
201523


---

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.  Area
 Square km
  (NCS Total)
 Square km
  (Statoil)
 Change vs
  2014
 Number of licenses
  (NCS Total)
 Number of
  licenses (Statoil equity)
 Number of
  licenses (Statoil operated)
 New licenses
  (Statoil equity)
 New licenses
  (Statoil operated)North Sea
 43,928
 13,884
 (1,006)
 304
 125
 95
 9
 7Norwegian Sea
 37,784
 12,581
 (1,681)
 144
 79
 55
 9
 4Barents Sea
 32,998
 13,802
 (135)
 63
 31
 19
 1
 -NCS total
 114,710
 40,267
 (2,822)
 511
 235
 169
 19
 11
  North Sea In the North Sea, Statoil participated in 14
exploration wells. Statoil operated ten of the exploration wells with seven
discoveries.  Norwegian Sea In the Norwegian Sea, Statoil participated in
six exploration wells. Statoil operated five of the exploration wells with
three discoveries.  Barents Sea No Statoil operated wells in 2015. One
partner operated well was completed in 2015.  3.5.4 Fields under development on the NCS  The main sanctioned development projects on
the NCS.  The table below shows some key figures as of
31 December 2015 for Statoil’s major development projects on the NCS.  Sanctioned
  projects
 Operator
 Statoil's equity share
 Time of sanctioning
 Production startAasta Hansteen
 Statoil
 51.00%
 2013
 2018Johan Sverdrup
 Statoil
 40.01%
 2015
 2019Gina Krog
 Statoil
 58.70%
 2012
 2017Ivar Aasen
 Det Norske
 41.47%
 2012
 2016Goliat
 Eni
 35.00%
 2009
 2016Martin Linge
 Total
 19.00%
 2011
 2016
  Johan Sverdrupis an oil
discovery in the southern part of the North Sea, approximately 140 km west of
Stavanger. A plan for development and operation was submitted in February 2015
and approved by the Norwegian authorities in August 2015. The Phase 1 of the
development will consist of 35 production and water injection wells and a field
center with four platforms: A living quarter platform, a wellhead platform with
permanent drilling facility, a processing platform and a riser and utility
platform. The crude oil will be exported to Mongstad through a 274 km long
dedicated pipeline, and the gas will be exported to the gas processing facility
at Kårstø through a 156 km long pipeline via a subsea connection to the
Statpipe pipeline. The expected production start-up is in the fourth quarter of
2019.  Aasta Hansteenis 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 2018.  Gina Krogis 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 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 Aasenis an oil and gas field
located in the Utsira High Area. The 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.  Goliatis 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 during first
quarter of 2016. 24Statoil, Annual Report on Form 20-F 2015


---

Martin Lingeis 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 2018.  Redevelopment
on the NCS - Improved oil recovery(IOR) In 2015 Statoil started the world’s first subsea gas compression
plant at the Åsgard field. Processing on the seabed, particularly gas
compression, is important for developing seabed solutions for areas of deeper
water and in colder and more challenging areas. Åsgard’s subsea compression,
the world’s first subsea gas compression plant, is one of Statoil's most
demanding technology projects. The compressors will increase recovery from the
Midgard reservoir on Åsgard from 67 percent to 87 percent, and from the Mikkel
reservoir from 59 percent to 84 percent, extending the operational life of the
fields up to 2032 and contributing to significant reduction in energy
consumption andCO2emissions over the fields’ lifetimes.  TheGullfaks subsea compressionproject the second largest subsea gas
compression project being developed 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, is expected to
lift the recovery rate from the Gullfaks South Brent reservoir from 62% to 74%.  TheSmørbukk South Extensionproject, in the Åsgard
field, is a world class project production from tight formations previously
regarded as infeasible. Production began in September 2015 through the
combination of wells with long well sections and “fishbones”, a new completion
technology implemented for the first time on the NCS, and further utilisation
of existing infrastructure at Åsgard.  Troll Afield’s two new topside
compressors started operating in October 2015. Installation of these
compressors is an important step to achieve the Troll field's long-term
production profile, which now extends to 2063. They are operated with power
from shore, which reduces the field’sCO2emissions significantly.  TheGullfaks South Oil (GSO)project started
production in July 2015 and will increase recovery from the Gullfaks area. It
includes two subsea templates, four production wells, two gas injectors, a gas
injection pipeline and umbilicals and power cables for pipeline heating. The
project utilise spare processing capacity and will extend the Gullfaks A
platform life beyond 2030.  The Gullfaks B
lifetime extensionproject aims at extending the drilling program on the Gullfaks B
platform until 2032. Operation started on August 2015. Many of the future wells
in Gullfaks B are water injection wells that will help maintain production from
all three of the platforms in the field through increased pressure support in
the reservoir. The drilling upgrade also provides the opportunity to connect to
smaller producers from the surrounding area.  TheOrmen Lange onshore
compression project 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.  These projects are all examples of Statoil’s efforts to maximise recovery
from existing fields. They have also opened opportunities for technology
application to realise volumes from other fields with similar conditions.  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
2013 - 2015. Permanent plugging and abandonment of the seven wells completed in
October 2014. All facilities/equipment were removed from the field in 2015.
Safety zones in the area have been repealed and national maps updated.  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 2019.  Yttergryta is
a subsea field with one production well that ceased production in 2013.
Permanent plugging of the well was 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 finalised by
second quarter 2016.  During 2015
there were permanent plugging and abandonment operations at Statfjord Øst,
Statfjord A, Sleipner and Tordis. In addition Åsgard decommissioned part of the
Midgard flowline loop in 2015.  For further
information about decommissioning see note 2Significant accounting policiesto the
Consolidated financial statements.  Statoil, Annual Report on Form 20-F
201525


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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 2015, DPI was engaged in production in 11 countries: Algeria,
Angola, Azerbaijan, Brazil, Canada, Ireland, Nigeria, Russia, the UK, the US,
and Venezuela. DPI produced 37% of Statoil's total equity production of oil and
gas in 2015.  As of 31 December 2015, Statoil has
exploration licenses in North America (Canada and US), South America and
sub-Saharan Africa (Angola, Brazil, Colombia, Mozambique, Nicaragua, Suriname,
South Africa and Tanzania), North Africa (Algeria and Libya), Europe and Asia
(Azerbaijan, Greenland, Indonesia, Myanmar, Russia and the UK) as well as
Oceania (Australia and New Zealand). The main development projects in which DPI
is involved are in Brazil, Canada, the UK, and the US.  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 section 5.1.1Risks related to our businessfor information regarding
sanctions towards Iran.  The map shows Statoil’s international producing
countries and additional countries where Statoil has discoveries and/or
exploration acreage.                               26Statoil, Annual Report on Form 20-F 2015


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Key events and portfolio
developments in 2015: ·Eight wells
(exploration and appraisal) were announced as discoveries in 2015, including
the Piri 2, Tangawizi 2 and Mdalasini (Statoil-operated) discoveries in
Tanzania ·Statoil accessed
new acreage in Lampyrus in Russia, Mozambique, Nicaragua, Flemish Pass basin
and Nova Scotia in East Coast Canada and South Africa ·In January, a
transaction with Southwestern Energy was closed. The agreement reduced
Statoil’s working interest in the non-operated US southern Marcellus onshore
asset from 29% to 23% ·Delay of Big Foot
development first oil in the US Gulf of Mexico.The operator Chevron expects first oil
in 2018. Initial plans called for production to start in late 2015, however,
installation was halted and the tension leg plarform (TLP) moved to sheltered
waters following damage to subsea installation tendons in late May 2015 ·In April, the Kizomba
Satellites Phase 2 project in Block 15 offshore Angola started production ·In April, Statoil
completed its sale of its remaining 15.5% interest in Shah Deniz and the South
Caucasus Pipeline (SCP) to the Malaysian oil and gas company PETRONAS. The
effective date was 1 January 2014 ·In August, the
Peregrino field offshore Brazil passed a significant milestone with 100 million
barrels of oil produced since production started in April 2011 ·On 30 December,
the Shell operated Corrib gas field in Ireland started production ·In December, Statoil
completed the sale of its 20% interest in Trans Adriatic Pipeline AG (TAP) to
the Italian gas infrastructure company Snam. TAP is an 882 km-long section of
the Southern Gas Corridor, linking Shah Deniz Stage 2 to gas markets in Europe ·In December,
transactions with Repsol were announced. As a result of these transactions, Statoil’s
working interest in the US Eagle Ford increased from 50% to 63% and Statoil
took full operatorship. In addition, Statoil will assume operatorship of the
BM-C-33 licence in Brazil’s Campos basin and acquire a 31% equity share in the
UK licence for Alfa Sentral, a field which spans the UK-Norway maritime border.
The transactions for BM-C-33 and Alfa Sentral are pending approval from relevant
government authorities ·In February 2016,
the In Salah Gas joint venture announced the start- up of operations at theIn
Salah Southern Fieldsproject in Algeria ·Significant
impairment losses on assets and oil and gas prospects and signature bonuses
were recognised in 2015, seesection
4.1.5DPI
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 high costs and declining returns is
addressed inthe
section 2 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 2015.  The following table shows DPI's average daily
entitlementproduction of liquids and natural gas for
the years ending 31 December 2015, 2014 and 2013. Entitlement production
figures are after deductions for production sharing and profit sharing. For US
assets entitlement production are expressed net of royalty interests. For all
other countries royalties paid in-cash are included in entitlement production
and royalties payable in-kind are excluded.  For the year ended 31 DecemberEntitlement
  production
 2015
 2014
 2013Oil and NGL (mboe per
  day)
 436
 383
 354Natural gas (mmcm per
  day)
 23
 26
 23Total (mboe per day)
 580
 546
 502
 Statoil, Annual Report on Form 20-F
201527


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The table below provides information about the fields that
contributed to production in 2015  Producing fields during
calendar year 2015  Field
 Statoil's equity interest in %
 Operator
 On stream
 Licence expiry date
 Average daily equity production mboe/day
 Average daily entitlement production mboe/dayNorth America
 
 
 
 
 282.3
 239.7US: Marcellus 1)
 Varies
 Statoil/others
 2008
 HBP2)
 115.7
 96.9US: Bakken 1)
 Varies
 Statoil/others
 2011
 HBP2)
 61.6
 49.3US: Eagle Ford 1)
 Varies
 Statoil
 2010
 HBP2)
 34.7
 26.6US: Tahiti
 25.00
 Chevron
 2009
 HBP2)
 16.9
 13.9US: Caesar Tonga
 23.55
 Anadarko
 2012
 HBP2)
 9.1
 8.7US: St. Malo
 21.50
 Chevron
 2014
 HBP2)
 7.6
 7.6US: Jack
 25.00
 Chevron
 2014
 HBP2)
 6.6
 6.6Canada: Leismer Demo
 100.00
 Statoil
 2010
 HBP2)
 19.9
 19.9Canada: Terra Nova
 15.00
 Suncor
 2002
 2022
 5.4
 5.4Canada:
  Hibernia/Hibernia southern extension3)
 Varies
 HMDC
 1997
 2027
 4.8
 4.8South America
 
 
 
 
 43.5
 43.5Brazil: Peregrino
 60.00
 Statoil
 2011
 2034
 43.5
 43.5Sub-Saharan Africa
 
 
 
 
 273.3
 197.8Angola, Block 17
 23.33
 Total
 2001
 2022-344)
 161.9
 113.9Angola, Block 15
 13.33
 ExxonMobil
 2004
 2026-324)
 41.8
 22.6Angola, Block 31
 13.33
 BP
 2012
 2031
 20.9
 19.0Angola: Block 4/055)
 20.00
 Sonangol
  P&P
 2009
 2026
 1.4
 1.3Nigeria: Agbami
 20.21
 Chevron
 2008
 2024
 47.3
 41.0North Africa
 
 
 
 
 49.6
 43.6Algeria: In Salah
 31.85
 Sonatrach/BP/Statoil
 2004
 2027
 32.5
 30.6Algeria: In Amenas
 45.90
 Sonatrach/BP/Statoil
 2006
 2022
 17.1
 13.3Libya: Mabruk
 12.50
 Mabruk Oil
  Operations
 1995
 2033
 0.0
 (0.0)6)Libya: Murzuq
 10.00
 Akakus Oil
  Operations
 2003
 2033
 0.0
 (0.2)6)Europe and Asia
 
 
 
 
 78.3
 43.9Azerbaijan: ACG
 8.56
 BP
 1997
 2024
 54.3
 24.2Azerbaijan: Shah Deniz 7)
 15.50
 BP
 2006
 2041
 12.0
 10.0Russia: Kharyaga
 30.00
 Total
 1999
 2032
 9.4
 7.1UK: Alba
 17.00
 Chevron
 1994
 2018
 2.5
 2.5UK: Jupiter
 30.00
 ConocoPhillips
 1995
 HBP2)
 0.1
 0.1Ireland: Corrib8)
 36.50
 Shell
 2015
 2031
 0.0
 0.0Total Development and
  Production International (DPI)
 
 
 727.0
 568.5Equity accounted
  productionVenezuela: Petrocedeño9)
 9.68
 Petrocedeño
 2008
 2033
 11.6
 11.6Total Development and
  Production International (DPI) including share of equity accounted production
 
 
 738.7
 580.21)
 Statoil’s actual working
  interest can vary depending on wells and area2)
 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 met3)
 Statoil's working
  interests are 5.0% in Hibernia and 9.0% in Hibernia southern extension4)
 Varies by field5)
 Statoil relinguished
  Block 4/05 in September 20156)
 Zero production in 2015,
  adjustment of 2014 volume7)
 Statoil divested the
  asset on 30 April 20158)
 New gas field which
  started production on 30 December 20159)
 Petrocedeño is a
  non-consolidated company and accounted for pursuant to the equity accounting
  method
 28Statoil, Annual Report on Form 20-F 2015


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The table below provides
information about production per country in 2015.  Country
 Average daily equity production mboe/day1)
 Average daily entitlement production mboe/dayNorth America
 282.3
 239.7US
 252.2
 209.6Canada
 30.1
 30.1South America
 43.5
 43.5Brazil
 43.5
 43.5Sub-Saharan Africa
 273.3
 197.8Angola
 226.0
 156.8Nigeria
 47.3
 41.0North Africa
 49.6
 43.6Algeria
 49.6
 43.9Libya
 0.0
 -0.3Europe and Asia
 78.3
 43.9Azerbaijan
 66.3
 34.2Russia
 9.4
 7.1UK
 2.6
 2.6Total Development and
  Production International (DPI)
 727.0
 568.5Equity accounted
  productionVenezuela: Petrocedeño2)
 11.6
 11.6Total Development and
  Production International (DPI) including share of equity accounted production
 738.7
 580.21)
 In PSA countries our
  share of capital expenditures and operational expenses are computed on the
  basis of equity production.2)
 Petrocedeño is accounted
  for pursuant to the equity accounting method.The following sections
  provide information about the main producing assets internationally. See
  section 4.1.5 DPI profit and loss analysis for a discussion of the results of
  operations for year end 2015.
 3.6.2.1 North America  Production in North America comprises the US and
Canada.  US Statoil is positioned
in the fast-growing US onshore oil and gas industry. Statoil has had strong
growth in production within US shale since entering the first play in 2008.  Statoil
entered theMarcellusshale gas play, located in the Appalachian region in
north east US, 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 410,000 acres. The most recent divestments occurred in 2014 with
Southwestern. The divested share represents approximately 30,000 acres.
Southwestern took over operatorship in this US southern Marcellus area through
a transaction with Chesapeake in December 2014.  Statoil
entered theBakkentight oil play through the acquisition of Brigham
Exploration Company in December 2011. Statoil's net acreage position in Bakken
and Three Forks shale formation at the endof 2015 was 249,000 acres.  Statoil
entered theEagle Fordshale 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 2010 and gradually took
over full operatorship of the Statoil operated acreage in 2013.As part of a
global transaction in December 2015 with Repsol, which acquired Talisman in May
2015, Statoil increased its working interest and took full operatorship of all
of the assets in the Eagle Ford Statoil, Annual Report on Form 20-F
201529


---

Shale. As a
consequence, Statoil has a total working interest of 63% representing an
addition of 15,000 net acres for a total of 72,000 leaseholds. Our joint
venture partner, Repsol, continues to hold 37% working interest.  Statoil is
positioned in the Gulf of Mexico for the following offshore developments:  TheTahitioil field is located in the Green Canyon area. The development includes a
floating spar facility. As of 31 December 2015, there werenine production
and three waterinjection wells in operation, and additional
wells will be phased in over time to fully develop the field.  TheCaesar Tongaoil field is located in the Green Canyon area. As of 31 December 2015, there
were six producing wells tied back to the Anadarko-operated Constitution spar
host, and additional production wells will be phased in over time.  The Jack and St. Malo oil
fields are located in the Walker Ridge area. The fields are subsea tie-backs to
the Chevron operated Walker Ridge Regional Host facility. First production was
achieved in December 2014.As of 31 December 2015,
there werethree wells producing on Jack and three wells producing for
St. Malo.Additional
production wells will be phased in over time.  Canada Statoil
entered the Alberta oil sands in 2007 through a corporate acquisition of North
American Oil Sands Corporation. In May, 2014, Statoil and PTTEP completed a
transaction to divide their respective interests in the Kai Kos Dehseh (KKD)
oil sands project with an effective date of 1 January 2013.  Following the
transaction with PTTEP, Statoil continues as operator and 100% working interest
owner for the Leismer and Corner projects 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 operation since 2010.
The in-situ technology known as SAGD (steam assisted gravity drainage), injects
steam into the oil bearing formation to recover bitumen which is then pumped to
the surface. Further oil sands development could involve expanding production
capacity of the Leismer facility and/or the greenfield development of the
Corner project. At this time, there are no near term plans to further develop
either project.  In addition,
we have interests in the Jeanne d'Arc Basin offshore the province of
Newfoundland and Labrador in the partner operated producing oil fields Terra
Nova, Hibernia and Hibernia Southern Extension. On 1 December 2015, Statoil's
interest in Hibernia Southern Extension was reduced from 10.5% to 9.0% due to a
redetermination process.  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 ThePeregrinofield 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. In August 2015, the Peregrino field passed a significant
milestone with 100 million barrels of oil produced since production start.  Venezuela Petrocedeñoproducesextra-heavy
crude oil from the Junin area in the Orinoco Belt. The oil is transported
through pipeline to a plant at the Jose Industrial Complex at the coast nearby
Puerta La Cruz where it is upgraded into a light crude and exported. For information related to Venezuela’s
financial risk see section 5.2.2 Managing financial risk.  3.6.2.3 Sub-Saharan Africa  Statoil's production activities in
Sub-Saharan Africa comprise Angola and Nigeria. Angola The deep water blocks 17, 15, 31 and 4/05
contributed with 40% of Statoil’s equity liquid production outside Norway in
2015. Each block is governed by a production sharing agreement (PSA) which sets
out the rights and obligations of the Parties, including mechanisms for sharing
of the production with the Angolan state oil company Sonangol.  Block 17 comprises production from four
FPSOs; CLOV, Dalia, Girassol and Pazflor.  Block 15 has production from four FPSOs: Kizomba
A, Kizomba B, Kizomba C-Mondo, and Kizomba C-Saxi Batuque. In April 2015, the Kizomba
Satellites phase 2 project, which consists of the fields Bavuka, Kakocha, and
Mondo South started production. The fields are developed with subsea wells and
infrastructure tied back to the Kizomba B and Mondo FPSO vessels.  30Statoil, Annual Report on Form 20-F 2015


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Block 31 has
production from the PSVM FPSO.  Statoil had production from the Gimboa FPSO
on Block 4/05 until the company exited the Block in September 2015.  The FPSOs serve as production hubs and
receive oil from a large number of wells and more than one field each. In 2015,
new wells were added and set into production on Block 15, Block 17 and Block
31.  Nigeria In Nigeria, Statoil has a 20.2% interest in
the Agbami deep water field which is located 110 km off the coast of the
Central Niger Delta region. The field is developed with subsea wells connected
to an FPSO. The Agbami field straddles the two licenses OML 127 and OML 128 and
is operated by Chevron under a Unit Agreement. Statoil has 53.85% interest in
OML 128.  For information related to the Agbami
redetermination process and the dispute between the Nigerian National Petroleum
Corporation and the partners in Oil Mining Lease (OML) 128 concerning certain
terms of the OML 128 Production Sharing Contract,see
section 5.3 Legal
proceedings and note 23 Other commitments and contingencies.  3.6.2.4 North Africa  Statoil had in 2015 production in North
Africa from Algeria.  Algeria The In Salah onshore gas
development, in which Statoil has a working interest of 31.85%, is Algeria's
third-largest gas development. A PSA including mechanisms for revenue sharing,
governs the rights and obligations of the Parties and establishes a joint
operatorship between Sonatrach, BP and Statoil. In February 2016, the In Salah
Gas joint venture announced the introduction of gas in the In Salah Southern
Fields processing facilities. Gas export from the project started in March. This
project, which is led by Statoil on behalf of the Joint Venture, will mature
the remaining fourdiscoveries into production. The southern fields (Gour Mahmoud,
In Salah, Garet el Befinat and Hassi Moumene) will tie in to existing
facilities in the northern fields.  The In Amenas
onshore development is the fourth-largest gas development in Algeria. It also
contains significant liquid volumes. The facilities are operated through a
joint operatorship between Sonatrach, BP and Statoil, where Statoil's share of
financing the investments (working interest) is 45.9%. A PSA, including
mechanisms for revenue sharing, governs the rights and obligations of the
Parties and establishes a joint operatorship between Sonatrach, BP and Statoil.  TheIn Amenas
plant has since April 2013 produced from two out of three trains. The
production has been relatively stable. The third train, which also was damaged
in the January 2013 terrorist attack, is expected to restart in the second
quarter of 2016.  Libya There has not been any oil
production from theMabrukor the Murzuq assets in 2015 due to the security situation in the
country.  3.6.2.5 Europe and Asia  Statoil's production in Europe and Asia
encompasses Azerbaijan, Russia, the United Kingdom and Ireland.  Azerbaijan TheAzeri-Chirag-Gunashli
(ACG)oil field in the Caspian Sea has production from 6
fixed platforms. The oil is transported through pipelines to the Sangachal
onshore terminal near Baku. From the terminal the oil is exported to the world
markets.  Statoil has an
8.7% stake in the 1,760 km Baku-Tbilisi-Ceyhan (BTC) oil pipeline that is used
to transport ACG oil to the southern Turkish port of Ceyhan.  In April 2015,
Statoil completed the sale of its remaining 15.5% interest inShah Denizand theSouth Caucasus Pipeline (SCP)to the
Malaysian oil and gas company PETRONAS.See note 4Acquisitions and dispositionsof the
Consolidated financial statements for further details.  Russia TheKharyagaoil
field is located onshore in the Timan Pechora basin in north-west Russia. The
field is governed by a PSA. For
information related to risk in Russia see section 5.1.1Risks related to our business.  United Kingdom Statoil, Annual Report on Form 20-F
201531


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TheAlbaoil
field is located in the central part of the UK North Sea.Jupiteris a gas field located in the southern part of the UK
North Sea. The decommissioning of the Jupiter wells is planned to start in
2016.  Ireland On 30 December 2015 production
started onCorribgas field off Ireland’s northwest coast. Corrib
consists of a subsea development with a pipeline to an onshore processing
terminal from which gas will be transported to the Irish market. The onshore
processing terminal is located approximately 9 km inland.  3.6.3 International exploration  Statoil continued with high international exploration activity in
2015.  In 2015 Statoil carried out significant international exploration
activity, as is shown by the company's involvement in 18 completed wells
(including both Statoil-operated and partner-operated activities). Eight wells
(exploration and appraisal) were announced as discoveries in the period,
including the Piri 2, Tangawizi 2 and Mdalasini (Statoil-operated) discoveries
in Tanzania.  The table below shows the exploratory wells drilled
internationally in the last three years.  2015
 2014
 2013North America
 - Statoil operated
 8
 3
 7- Partner operated
 0
 0
 4South
  America/sub-Saharan Africa
 - Statoil operated
 3
 8
 6- Partner operated
 5
 9
 4North Africa
 - Statoil operated
 0
 0
 0- Partner operated
 0
 0
 1Europe and Asia
 - Statoil operated
 2
 2
 0- Partner operated
 0
 1
 2Totals
 18
 23
 24
  The regions where Statoil had exploration activity in 2015 are
presented below.  North America  USStatoil
operated five wells in the Gulf of Mexico (Yeti-1, Yeti Side track, Yeti
Appraisal, Thorvald-1 and Power Nap). Yeti-1 and its side track were
discoveries, Yeti appraisal confirmed the volumes discovered. Power Nap is
ongoing at year end.  Statoil has
cancelled the contract for the Discoverer Americas rig in December 2015. Statoil
was in the current environment unable to secure additional activity for the rig
for the remainder of the contract period, ending in May 2016.  CanadaThe West Hercules rig arrived in Canada in November 2014, for a 550 days
drilling campaign, which continues into early-2016. The programme has focused
on appraisal and near field exploration wells in the greater Bay du Nord
discovery area, as well as select exploration prospects in the greater Flemish
Pass Basin.  Statoil and its partners were the successful bidders for six
exploration licences in the Flemish Pass Basin, offshore Newfoundland, and two
licences offshore Nova Scotia in East Coast Canada in 2015. Statoil will operate
seven of the eight leases awarded.  South America and sub-Saharan Africa  Angola KwanzaStatoil 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 a partner position
in Blocks 22, 25 and 40. The work program included eight commitment wells, two
Statoil operated and six partner operated. So far six wells have been
completed. In 2015 two partner operated wells were drilled, Umbundu in block
40, Catchimanha in Block 22. For more information see note 12Intangible assets.  BrazilAll exploratory well operations during 2015 were conducted on BM-C-33
license as part of Pão de Açucar and Seat appraisal activities. The Pão de
Açucar discovery was fully evaluated by drilling two wells (PdA-A1 and PdA-A2)
and performing a successful DST (Drill Stem Test) on 32Statoil, Annual Report on Form 20-F 2015


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PdA-A2.
The Seat-2 well was re-entered to perform a DST. In agreement with its licence
partners, Statoil will assume operatorship of the BM-C-33 licence subject to
receiving government approval.  Colombia Statoil has accessed three licences in 2014, representing access
at scale in relatively frontier acreage. In the COL-4 licence, an environmental
and social impact study has been completed.  Statoil farmed-in to a 10% equity share in the Tayrona licence and
a 20% share in the Gua Off licence in 2014. The Orca-1 well in the Tayrona
licence was announced as a gas discovery in 2014.  MozambiqueThe 5th licence round was announced during the third quarter of
2015. Statoil together with partners submitted a winning bid in the A5-A block
located in the Angoche area. Eni is the operator of the joint venture with 34%
participating interest. Statoil’s equity is 25.5%. Final award is expected
mid-2016 subject to successful negotiations.  Tanzania The Tanzania drilling campaign using the Discoverer Americas rig
was completed in 2015 after having drilled the Mdalasini prospect and the
Tangawizi-2 appraisal well. The discoveries of natural gas in Mdalasini-1,
Piri-1 and Giligiliani-1 have significantly increased the total in-place
volumes in Block 2.  South Africa Statoil completed a farm-in transaction in October 2015 with
ExxonMobil acquiring a 35% interest in the ER 12/3/154 Tugela South Exploration
Right. The Operator is Exxon with 40% equity. The farm-in represents a country
entry for Statoil into South Africa. Statoil intends to participate at an early
phase of exploration with a step-wise exploration programme.  Nicaragua In 2015, Statoil together with partner Empresa Nicaraguense del
Petroleo (Petronic) has been awarded four licences offshore the Nicaraguan
Pacific. Statoil is the operator with 85% equity with the Petronic holding the
remaining equity. 2D seismic data has been acquired and processed during 2015
and subsurface studies are underway.  North Africa  AlgeriaStatoil and Shell were awarded the Timissit licence in the Berkin basin onshore
Algeria in September 2014. Statoil is the operator with 30% equity.  The award represents an opportunity to test a potentially large
unconventional (shale) resource play.  The work commitment (up to the first exit point in 2018) is 3D
seismic and two vertical wells. Europe (excluding Norway), Asia and Australia UKIn
2014 Statoil was awarded interests in 12 exploration licences in the UK 28th
licensing round, nine 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 plays largely untested in UK waters. 11 of
the licences are in the North Sea and one is west of the Hebrides. In 2015 two
exploration wells were drilled. The Boatswain well in licence P1758 west of the
Mariner field was a discovery. The Wall well in licence P2067 was dry. Work now
continues to mature the broader UK exploration portfolio. Greenland Statoil, along with partners ConocoPhillips and Nunaoil, was
awarded block 6 in the East Greenland licence round in December 2013. Statoil
is the operator of the block. The licence has a 16-year exploration period.  Russia Statoil is engaged in a strategic cooperation with Rosneft Oil
Company (Rosneft) including a joint cooperation project aimed at undertaking
seismic surveys and geological exploration, appraisal, development and
production of potential hydrocarbons in four licences on the Russian
continental shelf - the Magadan 1, Lisyansky and Kashevarovsky licences in the
Sea of Okhotsk (south of the Arctic Circle), and the Perseevsky licence in the
Barents Sea (north of the Arctic Circle). Two exploration wells are to be
drilled in the Magadan 1 and Lisyansky licences in 2016. Additionally there are
two joint cooperation projects onshore; pilot drilling and testing of the
onshore heavy oil reservoir layer PK1 in the North Komsomolsky discovery, and
the Domanik Sediments Difficult-to-Extract Hydrocarbons Project, aimed at pilot
drilling and testing of the limestone Domanik formation in the Russian
Volga-Urals basin. For each of these projects, Rosneft holds the majority
interest, while Statoil holds a minority interest.  See section 5.1.1Risks related to our businessfor information regarding sanctions against
Russia.  Statoil, Annual Report on Form 20-F
201533


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AzerbaijanThe Joint Study Agreement (JSA) with SOCAR for the North Absheron area was
completed in 2014. Exploration screening and prospect evaluation is being
carried out on an ongoing basis for Azerbaijan offshore areas in order to
identify new access opportunities.  Indonesia Statoil signed the new offshore Aru Trough I PSC licence agreement
in May 2015. The licence is adjacent to Statoil’s existing exploration acreage
in the Aru and West Papua IV licences. This is a low-cost access route into a
frontier area with potential where Statoil is already present. This position
strengthens the optionality in Statoil’s long-term portfolio and secures
potential upsides from existing exploration acreage.  Myanmar Statoil and ConocoPhillips were awarded one exploration block
(AD-10) in the Myanmar waters of the Bay of Bengal in 2014. A production
sharing contract was signed in May 2015. Statoil (as operator) has completed
the IEE (Initial Environmental Examination) and has set up a country office in
Yangon.    34Statoil, Annual Report on Form 20-F 2015


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Australia In the Ceduna sub-basin in the Great Australian Bight, Statoil
holds 30% interest in four exploration licences with BP as operator.  In October 2014, Statoil obtained 100% equity share in an exploration
licence in the Exmouth Plateau in North Carnarvon basin.  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 work programme is designed to fully evaluate the prospectivity
of the licences in a step-wise manner within the 15-year licence time frame.
Statoil completed 2D seismic data early 2015. Following an analysis and
interpretation of this data, Statoil will decide whether to enter into the
second exploration phase by mid-2017.  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
licences are located in the East Coast and Pegasus basins, southeast off New
Zealand’s North Island. The partnership is committed to acquire 2D seismic and
3D seismic within the first exploration period.  Faroe Islands Following disappointing exploration activities, Statoil have
relinquished all licences. The Statoil office in Torshavn closed down in 2015.  3.6.4 Fields under development internationally  The sanctioned development projects in which
DPI is involved are in Algeria, Brazil, Canada, the UK, and the US.  This section covers selected
projects under development and significant pre-sanctioned projects.  Sanctioned
  projects
 Operator
 Statoil's equity share
 Time of sanctioning
 Production startUS: Julia
 Exxon Mobil
 50.00%
 2013
 2016US: Heidelberg
 Anadarko
 12.00%
 2013
 2016US: Stampede
 Hess
 25.00%
 2014
 2018US: Big foot
 Chevron
 27.50%
 2010
 2018Canada: Hebron
 Exxon Mobil
 9.01%
 2012
 2017Algeria: In Amenas
  Compression project
 Sonatrach/BP/Statoil
 45.90%
 2010
 2016UK, Mariner
 Statoil
 65.11%
 2012
 2018Brazil, Peregrino Phase
  II1)
 Statoil
 60.00%
 2015
 2019/201)
 Statoil made the
  investment decision on Peregrino Phase II project in December 2014 and
  submitted the Plan of Development to Brazilian authorities in January 2015.
 3.6.4.1 North America  Statoil has a number of significant ongoing
development projects in North America.  US Gulf of Mexico TheJuliaoil field is located in the Walker Ridge area of
the Gulf of Mexico near Jack and St Malo, and will be developed with subsea
wells tied back to the shared JSM host facility. First oil is expected within
mid-2016.  TheHeidelbergoil field is located in the Green Canyon
area. The development includes a Spar facility and first oil is expected within
early-2016.  TheStampedeoil field is located in the Green Canyon area.
The development includes a tension-leg platform (TLP) with downhole gas lift
and water injection from start of production. First oil is expected in 2018.  TheBig footoil field is located in Walker Ridge area. The
development includes a dry tree TLP with a drilling rig.The operator
Chevron expects first oil from Big Foot in 2018. Initial plans called for production
to start in late 2015, however, installation was halted and the TLP moved to
sheltered waters following damage to subsea installation tendons in late May
2015    Statoil, Annual Report on Form 20-F
201535


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US Onshore US Onshore
operations use hydraulic fracturing to liberate resources. Despite reduction in
investment and activity level in recent years in shale playsBakken,Eagle FordandMarcellus, production growth continues. The increase in onshore
production despite investment reduction is attributed to higher recovery per
well due to enhanced completion and improved operational efficiency.See section 3.6.2.1North Americafor further information.  Canada TheHebronfield is located in the Jeanne d'Arc basin offshore Newfoundland near the
partner-operated producing fields Terra Nova, Hibernia and Hibernia Southern
Extension. The Hebron field will be developed using a fixed gravity base
structure (GBS) and first oil is expected in 2017. Effective January 1, 2016,
Statoil’s interest in Hebron was reduced from 9.7% to 9.0% due to a
redetermination process.  Statoil has made oil discoveries in the
Flemish Pass offshore Newfoundland comprising theBay du Nordproject,
and work is on-going to assess options for developing this project. Statoil is
the operator of Bay du Nord and holds a 65% working interest.  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 Block 2 in Tanzania.  Tanzania Statoil has made several large gas
discoveries inBlock 2offshore
Tanzania.Statoil
is the operator of Block 2 and holds a 65% working interest. 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 Blocks 1, 3 and 4
operated by BG.  3.6.4.4 North Africa  In 2015, Statoil's field developments in the
North Africa were in Algeria.  The InAmenas Gas Compression project
in Algeria, which is led by BP, was sanctioned in late 2010. The compressors
are expected to come on stream in the fourth quarter of 2016. This will make it
possible to reduce wellhead pressure and maintain plateau production. The In
Amenas facilities are operated through a joint operatorship between Sonatrach,
BP and Statoil.  In February 2016, the In Salah Gas joint
venture announced the start- up of operations at the In Salah Southern Fields
project in Algeria. For more information see section 3.6.2.4 North
Africa.  3.6.4.5 Europe and Asia  In Europe and Asia, Statoil is participating in the planning and
development of projects in the UK  United Kingdom Statoil is the operator
for the Mariner heavy oil project. 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 expectsproduction startin 2018. 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 of Mariner East.  Following completion of
the farm down of 20.89% of P.726 (Mariner East) and 28.89% of P.979 (Mariner
South) by Statoil to JX Nippon in third quarter 2015, Statoilholds a 65.11% interestin all Mariner licences.  36Statoil, Annual Report on Form 20-F 2015


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Statoil is the
operator for, and holds an 81.6% interest inBressay. Bressay is
also a heavy oil discovery. In February 2016, Statoil decided to pause the
concept selection work on Bressay.  In November 2015, Statoil
completed the purchase of First Oil’s 24% equity share in the UK continental shelf
(UKCS) licence P312. This UK licence and licence PL046 on the NCS comprise theAlfa Sentral, a
gas and condensate field planned to be developed as a tie-back to the existing
Sleipner infrastructure on the NCS. A pre unit agreement is in place between
the UKCS and NCS Alfa Sentral Licenses, with an unitisation agreement to be
negotiated prior to the investment decision.  In February 2016, Statoil signed an agreement
with Talisman Sinopec North Sea Limited to acquire their 31% interest in
the UK Alfa Sentral Licence P312. The transaction is pendinggovernment approval. The transaction will increase
Statoil’s ownership interest from 24% to 55% when completed. JX remains
the operator with a 45% interest.  Statoil, Annual Report on Form 20-F
201537


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3.7 Marketing, Midstream and Processing (MMP)  3.7.1
MMP overview  Marketing,
Midstream and Processing (MMP) is responsible for marketing and trading of
crude oil, natural gas, gas liquids, refined products, for transportation and
processingof commodities and for operation of refineries, terminals and processing plants.  MMP markets
Statoil's own volumes, the Norwegian state's direct financial interest (SDFI)
equity production of crude oil and third-party volumes, approximately 50% of
all Norwegian liquids exports. MMP is also responsible for marketing SDFI’s gas.In total, Statoil is responsible for marketing approximately 70% of all
Norwegian gas exports.See
sections3.12.3The
Norwegian State’s participation and
3.12.4 SDFI
oil and gas marketing and sale for further details regarding the
Norwegian state’s direct financial interest. MMP
operates two refineries, two gas processing plants, one LNG plant (from 1
January 2016), one methanol plant and three crude oil terminals. In addition,
MMP is responsible for developing transportation solutions for natural gas,
liquids and crude oil from the Statoil assets including pipelines, shipping,
trucking and rail. In
2015, MMP sold36.9billion cubic metres
(bcm) of natural equity gas from the Norwegian continental shelf (NCS) on our
own behalf, in addition to approximately 37.2bcm of NCS gas on behalf of the
Norwegian state. Statoil's total US gas sales, including third-party gas,
amounted to 11.2 bcm in 2015. In 2015, MMP also sold 644 million barrels of
crude oil and condensate, approximately 15 million tonnes of natural gas
liquids (NGL), and approximately 1.2 million tonnes of methanol. Of the total
644 million barrels sold in 2015, approximately 50% represented Statoil equity
volumes, while approximately 37% of the total 15 million tonnes of NGL sold in
2015 were Statoil equity volumes. In
2015 the European gas market was characterised by falling prices due to record
supplies and stagnating demand. Statoil’s overall gas production increased
somewhat compared to 2014.In
the US 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. An oversupplied oil market globally has
resulted in weak oil prices in 2015.  Refinery
margins were higher than in 2014. Facilities have been operated with good
regularity. HSE results are at the same level as in 2014 for Serious Incident
Frequency (SIF) and Total Recordable Incident Frequency (TRIF), while there has
been an increase in number of oil and gas leakages mainly due technical and
operational issues. With effect from 1 June 2015, the Renewable Energy business
cluster was transferred from MMP to New Energy Solutions (NES). The remaining
businessactivities are
organised inthe following business clusters: Marketing and Trading; Asset Management and
Processing and Manufacturing.  Key
events in 2015: ·The operatorship
for Azerbaijan Gas Supply Company and the commercial operatorship for South
Caucasus Pipeline Company were transferred from Statoil toThe State Oil Company of
Azerbaijan Republic (SOCAR)
effective from 1 May 2015 following the completion of the sale of Statoil’s
shares to SOCAR, BP and PETRONAS in 2014 ·Following the
divestment of its share in the Shah Deniz gas field in Azerbaijan, Statoil
agreed to sell its 20% interest in Trans Adriatic Pipeline AG (TAP) to the
Italian gas infrastructure company Snam ·Edvard
Grieg oil pipeline and Utsira High gas pipeline became operational late 2015
and provide export of oil and gas for the Edvard Grieg field and in the future
also for the Ivar Aasen field currently under construction ·The 482 kilometer long
Polarled pipeline was laid at the Aasta Hansteen field at a depth of 1,260
meters in the Norwegian Sea ·Statoil
signed an agreement with Centrica in May to increase the volume of gas supplies
under an existing supply agreement. The gas supplied to the UK from the ten
year agreement will increase from 5 bcm/year to 7.3 bcm/year from October 2015 ·Statoil
extended gas supply agreement with UK’s SSE. Starting 1 October 2015, the gas
supplied from the six year agreement will increase from approximately 0.5
bcm/year to approximately 2.5 bcm/year  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 inthe
Section Strategy and market overview.  38Statoil, Annual Report on Form 20-F 2015


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3.7.2Marketing 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.  3.7.2.1 Marketing and trading
of gas and LNG  MMP 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, including the SFDI. The gas marketing and
trading business is conducted from Norway (Stavanger) and from offices in
Belgium, the UK, Germany and the US. Statoil transports and
markets approximately 70% of all NCS gas and continues to develop its position
in the US. A significant proportion
of Statoil's gas sales are sold under long-term contracts. These sales are
carried out with large industrial customers, power producers and local distribution
companies. Gas is also sold through short-term contracts and through trading on
European and US liquid marketplaces. In the US, gas is sold through bilateral
contracts. A few of Statoil’s
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 its 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. 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 terms of production and transportation systems. Combined with
its downstream assets this is used to optimise the value of the gas sold.  Europe The major export markets for gas from the NCS
are Germany, France, the UK, Belgium, the Netherlands, Italy and Spain. Our
longer term customers include large national or regional gas companies such as
ENGIE, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), RWE
and GasTerra.  Our European gas trading business conducts
activities with over 85 counterparties on all European liquid trading
locations. MMP is active on both physical and exchange markets such as Intercontinental
Exchange (ICE).  US The US is the world's largest and most liquid
gas market. Statoil Natural Gas LLC (SNG), a wholly-owned subsidiary, has a gas
marketing and trading 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 US over the
last few years. SNG has entered into gas
transportation agreements which enable Statoil to transport some of the
produced gas from the Northern Marcellus production area to Manhattan, NY and
to the US/Canadian border at Niagara, providing access to the greater Toronto
area in Canada. 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. LNG is sourced from the Snøhvit LNG facility in Norway. Due to
continuing low gas prices in the US, 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.  Algeria Statoil has a participating interest 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.  Statoil, Annual Report on Form 20-F
201539


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3.7.2.2 Marketing and trading of liquids  MMP 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 among
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 oil, condensate, NGLs as well as refined products. The main crude
oil market for Statoil is northwest Europe. Most of the crude oil volumes are
sold in the spot market, based on publicly quoted market prices. The liquids
marketing and trading business is responsible for commercial optimisation of
the Mongstad and Kalundborg refineries as well as crude terminals located at Mongstad,
Sture and South Riding Point in the Bahamas. MMP is also responsible for
Statoil's 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 Teesside terminals in addition to marketing
of condensate and LPG from the In Amenas field In Algeria. Statoil lifts
waterborne ethane from Kårstø and Teesside, condensate from Nyhamna, and
condensate and LPG volumes from Melkøya. In addition, MMP
markets 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. MMP also
markets equity volumes from DPI assets located in Canada, US, Brazil, Angola,
Nigeria, Algeria, Russia, Azerbaijan and UK, as well as third party volumes. Value is
maximised through the use of own and leased capacity 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.  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 an 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 processing 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. 40Statoil, Annual Report on Form 20-F 2015


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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, carbon dioxide
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 82,0% 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 a 65% ownership interest in Mongstad crude oil
terminal, while the State holds 35%. Crude oil is landed at Mongstad via two
pipelines from Troll and by crude tankers 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 via two pipelines
from the Oseberg and Grane areas 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, Grane blend 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. 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 2015 six out of
nine caverns were operational. Etzel Gas Lager Statoil Deutschland Storage GmbH holds a 23.7% stake in the Etzel
Gas Lager in North Germany which has a total of nineteen caverns and secures
regularity for gas deliveries from the NCS. Teesside terminal Statoil UK holds a 27.3% stake in the Teesside terminal, which
stabilises unstable oil from the Ekofisk area and several other Norwegian and
UK fields and recovers NGL.  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.  Statoil, Annual Report on Form 20-F
201541


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The total length of
Norway's gas pipelines is currently 8,100 kilometres, and most 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 in the Norwegian gas transportation system: Oseberg oil
transportation system, Grane oil pipeline, Kvitebjørn oil pipeline, Troll oil
pipeline I and II, Edvard Grieg oil pipeline,Utsira High gas pipeline, Valemon rich gas
pipeline, Haltenpipe,Norpipe and Mongstad gas pipeline.  Statoil Deutschland GmbH indirect holdsa 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 pipeline for fields in the Norwegian Sea. The project is
aligned with the Aasta Hansteen field development. Statoil is the operator and holds a 40% ownership share in the
Johan Sverdrup oil and gas pipelines. The pipelines will provide oil and gas
export for the Johan Sverdrup field and is scheduled to start-up in 2019. In the fourth quarter of 2015 Statoil entered into an agreement
with Snam to sell our 20% interest in the Trans Adriatic Pipeline (TAP). See note
4Acquistitions and
dispositionsfor further details. 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 US. 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 will transition to operator for 100% of the
midstream assets outside of theOak, Karnes, DeWitt and Bee (KDB)area with a
working interest of 63%. In the KDB area of Eagle Ford, Statoil has an
ownership interest of 25.2% in Edwards Lime Gathering LLC, which is operated by
Energy Transfer Partners L.P. 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.  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, Troll
and Edvard Grieg oil pipelines and Mongstad gas pipeline.  The following table shows operating statistics for the
plants at Mongstad, Kalundborg and Tjeldbergodden.  Throughput1)
 Distillation capacity2)
 On stream factor %3)
 Utilisation rate %4)Refinery
 2015
 2014
 2013
 2015
 2014
 2013
 2015
 2014
 2013
 2015
 2014
 2013Mongstad
 11.9
 9.2
 11.8
 9.3
 9.3
 9.3
 97.6
 93.4
 98.9
 93.4
 90.0
 95.0Kalundborg
 5.2
 4.5
 5.0
 5.4
 5.4
 5.4
 98.5
 91.8
 98.2
 91.0
 82.0
 86.5Tjeldbergodden
 0.92
 0.83
 0.79
 0.95
 0.95
 0.95
 98.5
 88.4
 94.4
 98.5
 97.1
 96.61)
 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.
  Higher than distillation
  capacity for Kalundborg, due to volumes of kero, naphta, gasoil and
  biodiesel-additive not going through the crude-/condensate units.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. 42Statoil, Annual Report on Form 20-F 2015


---

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 stabilised condensate. The dry gas is transported to
customers through the Gassled pipeline network via receiving terminals in
Europe. As of 1 January 2016
responsibility for operation of Snøhvit onshore facilities has been transferred
from DPN to MMP.  For further information about Statoil's operated onshore
facilities and pipelines see section 3.7.3Asset
Management.   Statoil, Annual Report on Form 20-F
201543


---

3.8
Other Group  The Other reporting segment includes
activities in New Energy Solutions (NES), Global Strategy and Business
Development (GSB), Technology, Projects and Drilling (TPD) and corporate staffs
and support functions.  3.8.1 New
Energy Solutions (NES)  The
NES business area reflects Statoil’s aspirations to gradually complement its
oil and gas portfolio with profitable renewable energy and other low-carbon
energy solutions. Offshore wind and carbon capture and storage have been key
focus areas in 2015.  In February 2016, Statoil launched a new energy investment fund
dedicated to investing in attractive and ambitious growth companies in
renewable energy, supporting its strategy of growth in new energy solutions.
The new fund, Statoil Energy Ventures, will invest up to USD 200 million over a
period of four to seven years.  Key
events in 2015: ·In October Statoil
made a final investment decision to build the world’s first floating offshore
wind park: The Hywind pilot park, to be located outside Peterhead in Scotland ·In June
Statoil announced that that it would establish NES as a new business area to
create new profitable solutions within renewable energy and other low-carbon
solutions, combining Statoil’s oil and gas portfolio, project delivery capacity
and ability to integrate technological solutions. As a starting point the
existing offshore wind portfolio constitutes the main activities in this area.The ambition is to grow and
potentially expand into other sources of renewable energy  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 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 annual production is
approximately 1.1 terawatt hours (TWh) and it has the capacity to provide power
to approximately 220,000 households.  Dudgeon
offshore wind project Statoil acquired a 70% share in the Dudgeon
offshore wind farm project in October 2012 together with Statkraft (30%). In
2014 Statoil reduced its share to 35%, bringing in Masdar as a new partner. The
project is located in the Greater Wash Area off the English east coast, not far
from Sheringham Shoal. A final investment decision for the 402 MW project
was made in July 2014. All construction contracts are awarded and construction
has started. The wind farm is expected to produce 1.7 TWh yearly from 67 turbines,
with the capacity to provide power for approximately 410,000 households. It is
expected to be in full operation by year end 2017.  Dogger Bank Statoil and Statkraft, together with RWE and
SSE, are partners in the Forewind consortium, each with a 25% equity stake. The
Dogger Bank area has a total consented capacity of 4.8 GW, and is potentially
the largest offshore wind farm development in the world. The consortium
received consent for four projects, each with a capacity of 1200 MW by the UK
Government in February and August 2015.  Hywind The world's first full-scale floating
offshore wind turbine has been in operation as a demonstration facility off the
coast of Karmøy for six years. Hywind's overall performance has exceeded
expectations and has experienced several storms with extreme wind of over 40m/s
and maximum waves of 19 m height without any damage influencing technical
integrity of the structure or turbine. Statoil is continuously working on
improving the operating model. Statoil`s strategy has been to utilise the
experience gained from this demo project to develop a floating wind park pilot,
which Statoil has achieved with Hywind Scotland.  Hywind Scotland pilot
project Hywind Scotland is a floating wind pilot park
using the Hywind concept developed and owned by Statoil. The business case is
to demonstrate cost-efficient and low risk solutions for commercial scale
parks. This will be done by verifying the use of larger Wind Turbine Generators
(WTG), optimising the design and demonstrating scale effects in a wind farm
layout. Statoil will install 5 Siemens 6.0MW turbines, a total capacity of
30MW. The project is located at Buchan Deep, approximately 25 km off Peterhead on
the West coast of Scotland. Production is expected to be 0.14 TWh/year.
The project was sanctioned in October 2015 and planned first deliveries to the
grid is fourth quarter 2017. This is the next step in our strategy towards
deployment of our first utility scale floating wind farms.    44Statoil, Annual Report on Form 20-F 2015


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Carbon capture and Storage (CCS) Since 1996 Statoil has proven experience in
CCS and has continued to develop competence through research engagement in the
Technical Centre Mongstad (TCM) and offshore operations in Sleipner and
Snøhvit. Statoil will seek to deploy our competence and experience in other CCS
projects, continue to evaluate opportunities to reduce carbon dioxide emissions
and explore carbon dioxide for enhanced oil recovery (EOR) possibilities.  3.8.2
Global Strategy and Business Development (GSB)  The
Global Strategy and Business Development (GSB) business area is Statoil’s
functional centre for strategy and business development.  GSB
is responsible for Statoil’s global strategy processes, and identifies,
develops and delivers inorganic business development opportunities.This is
achieved through close collaboration across geographic locations and business
areas. Statoil's strategy forms the basis for guiding the company’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:Shaping Statoil's strategic response to
sustainability issues, development of relevant policies and reporting on the
company's sustainability performance ·Business
Development Origination:
Identifying and originating business development opportunities, sharing
on-the-ground context and intelligence across the organisation ·Mergers,
Acquisitions and Divestments:Executing
of business development and merger/corporate acquisition/divestment options,
sharing deal activity context and intelligence across the organisation ·Project
Support and Execution:Commercial negotiation
support, commercial and technical valuation, business development best practice  3.8.3
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 2015: Statoil, Annual Report on Form 20-F
201545


---

·117 offshore wells
were delivered, including 29 exploration wells ·Drilling
efficiency has been significantly enhanced over the last three years. During
2015, the average number of metres drilled per day increased 25% from 2014 ·Valemon came on
stream: Statoil’s first platform to be controlled remotely from shore. Once
drilling is completed, the platform will transform into a normally unmanned
platform ·The first subsea
gas compression plant in the world was brought on line at Åsgard. Another
subsea gas compression plant is being developed at Gullfaks ·Fast-track
projects Oseberg Delta 2, Smørbukk South extension and Gullfaks South improved
oil recovery were brought on stream ·The construction
of the fast-track project Gullfaks Rimfaksdalen started ·Three major
pipelays were completed: Polarled gas pipeline, Edvard Grieg oil export
pipeline and Utsira high gas export pipeline ·The world’s
largest system for four-dimensional permanent reservoir monitoring was
installed at Snorre and Grane, improving the oil recovery rate. 700 kilometres
of seismic cables were installed on the seabed ·Two new
compressors were brought on line on the Troll A platform ·A new floating
storage vessel was brought into operation at Heidrun ·The development of
Aasta Hansteen, Gina Krog and Mariner fields continued through 2015 ·The construction
of the Johan Sverdrup project started. In 2015, contracts worth more than NOK
50 billion were awarded ·The plan for
development and operation of Oseberg Vestflanken 2 was submitted to the
Ministry of Petroleum and Energy. The field is being developed using an
unmanned wellhead platform, a new, cost-effective solution in Statoil’s field
development toolbox ·A decision was
made to develop Hywind Scotland pilot park. The commercial scale, floating wind
farm is being developed using Hywind, a floating wind turbine concept developed
and owned by Statoil. The construction of Dudgeon offshore wind farm progressed
through 2015 ·There has been a
certain overcapacity in the offshore rig portfolio owing to reduced demand and
increased efficiency ·18 specific and
profitable projects aimed at reducing the environmental footprint have been
established under the General Electric/Statoil powering collaboration, launched
in 2015 ·During 2015, 101
new technologies were developed. 20 selected high-value technologies were
implemented in 59 different locations, a 50% increase from 2014 ·Statoil has
captured significant market effects through renegotiating and rebidding most of
the agreement portfolio with suppliers during 2015  From 1 January
2016, Statoil has gathered all project expertise in TPD, into one integrated,
cost-effective Project Development organisation (PRD), to ensure lean and
effective execution and decision-making. From the same date, Technology
Excellence and Research, Development and Innovation were merged into one
integrated Research and Technology organisation (R&T), reinforcing
innovation and technology effectiveness.  TPD businessactivitieswere in 2015organised in the following business clusters:  Research, Development and Innovation
(RDI) RDI is responsible for carrying out research and technology
development to meet Statoil's business needs on short and long term.  RDI
is organised in four research programmes closely aligned with Statoil’s technology
strategy: Exploration, Mature area developments and improved oil recovery,
Frontier developments and Un-conventionals. 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 currently active in our operations in Rio de Janeiro (Brazil), Houston
and Austin (the US), 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 which coordinates cooperation with Norwegian and
international universities.  Technology Excellence (TEX) TEX is
globally responsible for delivering technical expertise to projects, business
developments and assets, and for implementing new technologies.  TEX is
responsible for driving simplification and standardisation and delivers
technological expertise within the areas of petroleum, subsea and marine,
facilities and operations, and safety and sustainability technologies enhancing
Statoil's operational performance. Technology development and implementation
are used to achieve corporate targets for production growth, improved
efficiency and regularity, reserve growth and reduced costs. Through Statoil
technology invest (STI), TEX supports innovators and entrepreneurs with
technology development and commercialisation activities.  Projects (PRO) PRO
is responsible for planning and executing all major facilities development,
modification and field decommissioning projects in Statoil.  The project
portfolio is diverse, ranging from major new field developments to both small
and large development projects on the NCS and internationally. During 2015,
around 50 projects were in the execution phase, and at year-end, 30 projects
were in the early phase. The proportion of larger projects in the portfolio has
increased over the last three years.  Drilling and Well (D&W) D&W is
responsible for providing cost-efficient well delivery, ensuring
fit-for-purpose drilling facilities and providing expertise and advice to
Statoil's global drilling and well operations.  46Statoil, Annual Report on Form 20-F 2015


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D&W
operated 35 rig years in 2015, compared to 40 in 2014, and delivered production
and exploration wells offshore on the NCS and Brazil, and exploration wells in
Canada, the Gulf of Mexico, Tanzania and the UK.  Procurement and Supplier Relations
(PSR) PSR
is responsible for global procurement 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 encourages and facilitates 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 has a strategy for increasing
diversity, competition and flexibility in the market to better utilise industry
capacity and expertise.  3.8.4 Corporate staffs and support functions  Corporate Staffsand 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.  Statoil, Annual Report on Form 20-F
201547


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3.9
Significant subsidiaries  The following table shows significant
subsidiaries and equity accounted companies as of 31 December 2015.  Our voting interest in each company is
equivalent to our equity interest.  Ownership in certain
  subsidiaries and other equity accounted companiesName
 in %
 Country of incorporation
 
 Name
 in %
 Country of incorporationStatholding AS
 100
 Norway
 
 Statoil Nigeria Deep
  Water AS
 100
 NorwayStatoil Angola Block 15
  AS
 100
 Norway
 
 Statoil Nigeria Outer
  Shelf AS
 100
 NorwayStatoil Angola Block
  15/06 Award AS
 100
 Norway
 
 Statoil Norsk LNG AS
 100
 NorwayStatoil Angola Block 17
  AS
 100
 Norway
 
 Statoil North Africa Gas
  AS
 100
 NorwayStatoil Angola Block 31
  AS
 100
 Norway
 
 Statoil North Africa Oil
  AS
 100
 NorwayStatoil Angola Block 38
  AS
 100
 Norway
 
 Statoil Orient AG
 100
 SwitzerlandStatoil Angola Block 39
  AS
 100
 Norway
 
 Statoil OTS AB
 100
 SwedenStatoil Angola Block 40
  AS
 100
 Norway
 
 Statoil Petroleum AS
 100
 NorwayStatoil Apsheron AS
 100
 Norway
 
 Statoil Shah Deniz AS
 100
 NorwayStatoil Azerbaijan AS
 100
 Norway
 
 Statoil Sincor AS
 100
 NorwayStatoil BTC Finance AS
 100
 Norway
 
 Statoil SP Gas AS
 100
 NorwayStatoil Coordination
  Centre NV
 100
 Belgium
 
 Statoil Tanzania AS
 100
 NorwayStatoil Danmark AS
 100
 Denmark
 
 Statoil Technology
  Invest AS
 100
 NorwayStatoil Deutschland GmbH
 100
 Germany
 
 Statoil UK Ltd
 100
 United KingdomStatoil do Brasil Ltda
 100
 Brazil
 
 Statoil Venezuela AS
 100
 NorwayStatoil Exploration
  Ireland Ltd.
 100
 Ireland
 
 Statoil Venture AS
 100
 NorwayStatoil Forsikring AS
 100
 Norway
 
 Statoil Metanol ANS
 82
 NorwayStatoil Færøyene AS
 100
 Norway
 
 Mongstad Refining DA
 79
 NorwayStatoil Hassi Mouina AS
 100
 Norway
 
 Mongstad Terminal DA
 65
 NorwayStatoil Indonesia Karama
  AS
 100
 Norway
 
 Tjeldbergodden
  Luftgassfabrikk DA
 51
 NorwayStatoil New Energy AS
 100
 Norway
 
 Naturkraft AS
 50
 NorwayStatoil Nigeria AS
 100
 Norway
 
 Vestprosess DA
 34
 Norway
  3.10 Production volumes and prices  The business overview is in accordance with
our segment's operations as of 31 December 2015, whereas certain disclosures on
oil and gas reserves are based on geographical areas as required by the
Securities and Exchange Commission (SEC).  For further
information about extractive activities, see sections 3.5Development and Production Norwayand
3.6Development and Production International,
respectively.  Statoil
prepares its disclosures for oil and gas reserves and certain other
supplemental oil and gas disclosures by geographical area, as required by the
SEC. The geographical areas are defined by country and continent. They are
Norway, Eurasia excluding Norway, Africa and the Americas.  For further
information about disclosures concerning oil and gas reserves and certain other
supplemental disclosures based on geographical areas as required by the SEC,
see section 3.11Proved oil and gas
reserves.  3.10.1 Entitlement production  This section describes our oil and gas
production and sales volumes.  48Statoil, Annual Report on Form 20-F 2015


---

The
following table shows Statoil's Norwegian and international entitlement
production of oil and natural gas for the periods indicated. The stated
production volumes are the volumes to which Statoil is entitled, pursuant to
conditions laid down in licence agreements and production-sharing agreements.
The production volumes are net of royalty oil paid in kind, and of gas used for
fuel and flaring. Our production is based on our proportionate participation in
fields with multiple owners and does not include production of the Norwegian
State's oil and natural gas. Production of an immaterial quantity of bitumen is
included as oil production. NGL includes both LPG and naphtha. The only field
containing more than 15% of total proved reserves based on oil equivalent
barrels is the Troll field. For further information on production volumes see
section 9 Terms and definitions.  For the year ended 31 DecemberEntitlement
  production
 2015
 2014
 2013NorwayOil and Condensate
  (mmbbls)
 174
 173
 174NGL (mmbbls)
 44
 42
 42Natural gas (bcf)
 1,306
 1,229
 1,264Combined oil,
  condensate, NGL and gas (mmboe)
 450
 434
 441Eurasia excluding NorwayOil and Condensate
  (mmbbls)
 13
 14
 15Natural gas (bcf)
 16
 56
 72Combined oil,
  condensate, NGL and gas (mmboe)
 16
 24
 28AfricaOil and Condensate
  (mmbbls)
 75
 64
 58NGL (mmbbls)
 3
 2
 1Natural gas (bcf)
 63
 38
 40Combined oil,
  condensate, NGL and gas (mmboe)
 88
 72
 66AmericasOil and Condensate
  (mmbbls)
 62
 55
 50NGL (mmbbls)
 7
 7
 4Natural gas (bcf)
 215
 242
 196Combined oil,
  condensate, NGL and gas (mmboe)
 107
 106
 89TotalOil and Condensate
  (mmbbls)
 324
 306
 298NGL (mmbbls)
 54
 51
 47Natural gas (bcf)
 1,600
 1,565
 1,571Combined oil,
  condensate, NGL and gas (mmboe)
 662
 635
 625Troll field 1)Oil and Condensate
  (mmbbls)
 14
 14
 14NGL (mmbbls)
 2
 2
 2Natural gas (bcf)
 386
 317
 304Combined oil,
  condensate, NGL and gas (mmboe)
 85
 73
 701)
 Note that Troll is also
  included in Norway stated above.
  Statoil, Annual Report on Form 20-F
201549


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3.10.2
Sales prices  The following tables present realised sales
prices.  Norway
 Eurasia
  excluding
  Norway
 Africa
 AmericasYear ended 31 December
  2015Average sales price oil
  and condensate in USD per bbl
 52.2
 50.7
 49.4
 39.4Average sales price NGL
  in USD per bbl
 30.1
 -
 26.2
 12.5Average sales price
  natural gas in NOK per Sm3
 2.2
 1.4
 1.7
 0.8Year ended 31 December
  2014Average sales price oil
  and condensate in USD per bbl
 98.3
 101.3
 95.6
 78.3Average sales price NGL
  in USD per bbl
 59.3
 -
 59.7
 37.3Average sales price
  natural gas in NOK per Sm3
 2.3
 1.3
 2.2
 1.0Year ended 31 December
  2013Average sales price oil
  and condensate in USD per bbl
 109.1
 110.5
 107.3
 89.1Average sales price NGL
  in USD per bbl
 67.4
 -
 69.7
 59.2Average sales price
  natural gas in NOK per Sm3
 2.4
 0.9
 2.1
 0.8
 50Statoil, Annual Report on Form 20-F 2015


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3.11 Proved oil and gas reserves  Proved oil
and gas reserves were estimated to be 5,060 mmboe at year end 2015, compared to
5,359 mmboe at the end of 2014.  Statoil's proved reserves are estimated and presented in
accordance with the Securities and Exchange Commission (SEC) Rule 4-10 (a) of
Regulation S-X, revised as of January 2009, and relevant Compliance and
Disclosure Interpretations (C&DI) and Staff Accounting Bulletins, as issued
by the SEC staff. For additional information, see section Proved oil and gas
reserves in note 2Significant accounting policiesto the Consolidated
financial statements. For further details on proved reserves, see alsonote 27Supplementary oil and gas information
(unaudited)in the Consolidated financial statements. 
  Changes
in proved reserves estimates are most commonly the result of revisions of
estimates due to observed production performance, extensions of proved areas through
drilling activities or the inclusion of proved reserves in new discoveries
through the sanctioning of new development projects. These are sources of
additions to proved reserves that are the result of continuous business
processes and can be expected to continue to add reserves in the future.  Proved
reserves can also be added or subtracted through the acquisition or disposal of
assets. Changes in proved reserves can also be due to factors outside
management control, such as changes in oil and gas prices. Lower oil and gas
prices normally allow less oil and gas to be recovered from the accumulations.
However for fields with production sharing agreements (PSAs) and similar
contracts a reduced oil price may result in higher entitlement to the produced volume.
These changes are included in the revisions category in the table below.  The
principles for booking proved gas reserves are limited to contracted gas sales
or gas with access to a robust gas market.  In Norway and the UK, Statoil
recognises reserves as proved when a development plan is submitted, as there is
reasonable certainty that such a plan will be approved by the regulatory
authorities. Outside these territories, reserves are generally booked as proved
when regulatory approval is received, or when such approval is imminent.
Reserves from new discoveries, upward revisions of reserves and purchases of
proved reserves are expected to contribute to maintaining proved reserves in
future years. Undrilled well locations onshore are generally booked as proved
undeveloped reserves when a development plan has been adopted and the well
locations are scheduled to be drilled within five years,  Approximately
89% of our proved reserves are located in OECD countries. Norway is by far the
most important contributor in this category, followed by the United States of
America (US), Canada, Ireland and the United Kingdom (UK).   Statoil, Annual Report on Form 20-F
201551


---

Of Statoil's total proved reserves, 9%
are related to production-sharing agreements (PSAs) in non-OECD countries such
as Azerbaijan, Angola, Algeria, Nigeria, Libya and Russia. Other non-OECD
reserves are related to concessions in Brazil and Venezuela, representing less
than 3% of Statoil's total proved reserves. These are included in proved
reserves in the Americas. Significant changes in our proved
  reserves in 2015 were:
  •Negative revisions due to lower
  commodity prices compared to last year, which resulted in a reduction of
  approximately 350 million boe. A large portion of this is related to
  undeveloped fields wherelower commodity prices resulted in earlier economic cut-off,
  such as the Mariner field in the UK which is under development and is
  expected to start production in 2018, and uneconomic undeveloped well
  locations onshore US.The
  negative revisions are partly offset by positive revisions due to better
  performance of producing fields, maturing of improved recovery projects, and
  reduced uncertainty due to further drilling and production experience. The
  net effect of the positive and negative revisions is a reduction of 42 million
  boe in 2015.The estimated reduction due to change in prices is a rough
  estimate derived by using last year’s prices on this year’s volume base. In
  the calculation no adjustments have been made for the possible effect on the
  activity level, operating cost or development cost. For more information
  regarding prices see section 27 Supplementary oil and gas
  information (unaudited)
  •Proved reserves from new discoveries
  have also been added through the sanctioning of new field development
  projects in 2015, Johan Sverdrup being the largest contributor. The new
  projects added a total of 476 million boe
  •Further drilling in the Bakken,
  Marcellus and Eagle Ford onshore plays in the US increased the proved
  reserves in 2015, and some of these additions are presented as extensions.
  Extension of proved area on existing field added a total of 150 million boe
  of new proved reserves in 2015
  •The net effect of purchase and sale
  reduced the reserves by 221 million boe in 2015
  •The 2015 entitlement production was
  662 million boe, an increase of 4.3% compared to 2014. New discoveries with
  proved reserves booked in 2015 are all expected to start production within a
  period of five years
  Summary of
proved reserves as of 31 December 2015  Reserves
  category
 Proved reservesOil and Condensate
 NGL
 Natural Gas
 Total oil and gas(mmboe)
 (mmboe)
 (bcf)
 (mmboe)DevelopedNorway
 505
 235
 10,664
 2,641Eurasia excluding Norway
 48
 -
 32
 53Africa
 248
 9
 206
 294Americas
 303
 45
 999
 526Total Developed proved
  reserves
 1,104
 290
 11,901
 3,515UndevelopedNorway
 711
 56
 2,278
 1,173Eurasia excluding Norway
 29
 -
 161
 57Africa
 30
 6
 160
 64Americas
 217
 12
 124
 251Total Undeveloped proved
  reserves
 987
 74
 2,723
 1,546Total proved reserves
 2,091
 364
 14,624
 5,060
 Statoil's proved reserves of bitumen in the Americas are included as oil in the
table above since they represent less than 2% of Statoil's proved reserves,
which is regarded as immaterial.  The basis for equivalents
is presented in the section Terms and definitions.    52Statoil, Annual Report on Form 20-F 2015


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Reserves
replacement The reserves replacement
ratio is defined as the sum of additions and revisions of proved reserves
divided by produced volumes in any given period. The following table presents
the changes in reserves in each category relating to the reserve replacement
ratio for the years 2015, 2014 and 2013.  For the year ended 31 December(million
  boe)
 2015
 2014
 2013Revisions and improved
  recovery
 (42)
 356
 395Extensions and
  discoveries
 627
 253
 523Purchase of
  petroleum-in-place
 13
 20
 14Sales of
  petroleum-in-place
 (235)
 (233)
 (131)Total reserve additions
 363
 395
 802Production
 (662)
 (635)
 (625)Net change in proved
  reserves
 (299)
 (240)
 177
 The reserves replacement ratio for 2015 was 0.55 compared to 0.62 in 2014. The
2015 reserves replacement ratio, excluding purchases and sales of petroleum in
place, was 0.88. The average replacement ratio for the last three years was 0.81,
or 1.10 excluding purchases and sales.  For the year ended 31 DecemberReserves
  replacement ratio (including purchases and sales)
 2015
 2014
 2013Annual
 0.55
 0.62
 1.28Three-year-average
 0.81
 0.97
 1.15
 The usefulness of the reserves replacement ratio is limited by the volatility
of oil prices, the influence of oil and gas prices on PSA reserve booking,
sensitivity related to the timing of project sanctions and the time lag between
exploration expenditure and the booking of reserves.  
 Proved reserves in Norway A total of 3,814
million boe is recognised as proved reserves in 58 fields and field development
projects on the NCS, representing 75% of Statoil's total proved reserves. Of
these, 54 fields and field areas are currently in production, 42 of which are
operated by Statoil. Four new field development projects added reserves during
2015, Johan Sverdrup, Oseberg Vestflanken 2, Fram C-Øst Brent and Opal
categorised as extensions and discoveries. Production experience, further
drilling and improved recovery on several of Statoil's producing fields in
Norway also contributed positively to the revisions of the proved reserves in
2015.  Sales of reserves are
related to the agreement with Repsol. This has reduced Statoil's share of
proved reserves on Gudrun.  Of the
proved reserves on the NCS, 2,641 million boe, or 69%, are proved developed
reserves. Of the total proved reserves in this area, 60% are gas reserves
related to large offshore gas fields such as Troll, Snøhvit, Oseberg, Ormen
Lange, Tyrihans, Visund, Aasta Hansteen and Åsgard and 40% are liquid reserves.      Statoil, Annual Report on Form 20-F
201553


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Proved reserves in Eurasia, excluding Norway In this area, Statoil
has proved reserves of 111 million boe related to four fields and field
developments in Azerbaijan, the UK, Ireland and Russia. Eurasia excluding
Norway represents 2% of Statoil's total proved reserves, Azerbaijan being the
main contributor with the Azeri-Chirag-Gunashli fields. All fields are
producing. The effect of the farm out of Shah Deniz reduced the proved reserves
at year end 2015.  Proved undeveloped
reserves were reduced due to negative revisions linked to lower commodity
prices resulting in earlier economic cut-off for the fields, primarily the Mariner
field in the UK which is under development and is expected to start production
in 2018.  Of the proved reserves
in Eurasia, 53 million boe or 48% are proved developed reserves. Of the total
proved reserves in this area, 69% are liquid reserves and 31% are gas reserves.         
 Proved reserves in Africa Statoil recognises
proved reserves of 358 million boe related to 29 fields and field developments
in several West and North African countries, including Algeria, Angola, Libya
and Nigeria. Africa represents 7% of Statoil's total proved reserves. Angola is
the primary contributor to the proved reserves in this area, with 24 of the 29
fields.  In Angola, Statoil has
proved reserves in three blocks, Block 15, Block 17 and Block 31, with
production from all blocks. During 2015 Statoil exited Block 4/05, Gimboa is
therefore removed from proved reserves this year.  All fields are in
production in Algeria and Nigeria. Murzuq and Mabruk are currently not
producing due to the unrest in Libya.  The disputed equity
determination at Agbami will potentially alter Statoil's equity share in this
field. The effect on the proved reserves will be included once the
redetermination is finalised and the effect is known.  Of the total proved
reserves in Africa, 294 million boe, or 82%, are proved developed reserves. Of
the total proved reserves in this area, 82% are liquid reserves and 18% are gas
reserves.   Proved reserves in the Americas
  In North and South America, Statoil has
  proved reserves equal to 777 million boe in a total of 17 fields and field
  development projects. This represents 15% of Statoil's total proved reserves.
  Ten of these fields are located in the US, seven of which are offshore field
  developments in the Gulf of Mexico and three are onshore tight reservoir
  assets. Five are located in Canada and two in South America.
  
  In the US, four of
  the seven fields in the Gulf of Mexico are in production. Field development
  is ongoing on Big Foot, Heidelberg and Stampede. The onshore tight reservoir
  assets Marcellus, Eagle Ford and Bakken are all in production. In Canada,
  proved reserves are related both to offshore field developments, and to the
  Leismer field in the Kai Kos Dehseh oil sands project in Alberta.
  
  Proved undeveloped
  reserves were reduced due to negative revisions linked to lower commodity
  prices, primarily resulting in undeveloped well locations onshore US becoming
  uneconomic.
  
  Several transactions
  were completed during 2015, both purchases and sales. The largest were the
  transaction with Southwestern Energy reducing the reserves in Marcellus, and
  the agreement with Repsol increasing the reserves in Eagle Ford. The
  transactions offset each other and the net effect on proved reserves is zero.
  54Statoil, Annual Report on Form 20-F 2015


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Of the total proved
reserves in the Americas, 526 million boe, or 68%, are proved developed
reserves. Of the total proved reserves in this area, 74% are liquid reserves
and 26% gas reserves.  3.11.1 Development of reserves  In 2015, approximately 438 million boe were
converted from undeveloped to developed proved reserves.  The start-up of production from Edvard Grieg,
Oseberg Delta 2 and Valemon in Norway together with Bavuca and Kakocha in
Angola and Corrib in Ireland increased the developed reserves by 69 million boe
during 2015. The rest of the converted volume is related to development
activities on producing fields.  Net
  proved reserves in million barrels oil equivalent
 Total
 Developed
 UndevelopedAt 31 December 2014
 5,359
 3,725
 1,635Revisions and improved
  recovery
 (42)
 96
 (138)Extensions and
  discoveries
 627
 -
 627Purchase of
  reserves-in-place
 13
 6
 7Sales of
  reserves-in-place
 (235)
 (88)
 (147)Production
 (662)
 (662)
 -Moved from undeveloped
  to developed
 -
 438
 (438)At 31 December 2015
 5,060
 3,515
 1,546
  The new development projects in Norway, added a total of 476
million boe of proved undeveloped reserves in 2015, the largest being Johan
Sverdrup. Further drilling in the Bakken, Marcellus and Eagle Ford onshore
plays in the US increased the proved area and added proved undeveloped
reserves. These additions are categorised as extensions and together with
extensions on existing fields and new discoveries this added a total of 627
million boe of proved undeveloped reserves.  Revision of estimate on
existing fields added 96 million boe proved developed reserves and reduced
proved undeveloped reserves by 138 million boe. These revisions are based on
new information available either from drilling of new wells or from production
experience, resulting in an improved understanding of the fields. The negative
revisions are mainly linked to lower commodity prices resulting in earlier
economic cut-off for the fields and undeveloped well locations becoming
uneconomic.  The net effect of the
transactions done in 2015, reduced the proved undeveloped reserves by 139
million boe.  Oil and Condensate
 NGL
 Natural gas
 Total(mmboe)
 (mmboe)
 (bcf)
 (mmboe)2015
 Proved reserves end of
  year
 2,091
 364
 14,624
 5,060Developed
 1,104
 290
 11,901
 3,515Undeveloped
 987
 74
 2,723
 1,5462014
 Proved reserves end of
  year
 1,942
 403
 16,919
 5,359Developed
 1,156
 310
 12,677
 3,725Undeveloped
 786
 93
 4,242
 1,6352013
 Proved reserves end of
  year
 1,877
 441
 18,416
 5,600Developed
 1,052
 330
 13,073
 3,711Undeveloped
 826
 111
 5,343
 1,888
  As of 31 December 2015,
the total proved undeveloped reserves amounted to 1,546 million boe, 76% of
which are related to fields in Norway. The Troll, Snøhvit, Visund, Grane and
Oseberg fields, which have continuous development activities, represent the
largest undeveloped assets in Norway together with fields not yet in
production, such as Johan Sverdrup, Aasta Hansteen, Gina Krogh, Ivar Aasen and
Goliat. The largest assets with respect to undeveloped proved reserves outside
Norway are Bakken and Stampede in the US, Peregrino in Brazil, Hebron in
Canada, Corrib in Ireland and In Salah in Algeria.  In 2015, Statoil incurred NOK 85 billion in
development costs relating to assets carrying proved reserves, NOK 70 billion
of which was related to proved undeveloped reserves.  Large fields with
continuous development activity may contain reserves that are expected to
remain undeveloped for five years or more. Examples are Johan Sverdrup, Troll, Snøhvit,
Gina Krogh and Aasta Hansteen in Norway. These are large field developments
with several billion dollars invested in complex infrastructure and with
continuous development that will require extensive, sustained drilling of wells
for a Statoil, Annual Report on Form 20-F
201555


---

long period of time. It is highly unlikely that
these field development projects will be prematurely terminated, since this
would result in a significant loss of capital.  Additional information
about proved oil and gas reserves is provided in note 27Supplementary oil and gas information (unaudited)to the
Consolidated financial statements.  3.11.2 Preparations of reserves estimates  Statoil's annual reporting process for proved reserves is
coordinated by a central team.  The corporate
reserves management (CRM) team consists of qualified professionals in
geosciences, reservoir and production technology and financial evaluation. The
team has anaverage
of more than 20 years' experience in the oil and gas industry. CRM reports to
the senior vice president of finance and control in the Technology, Drilling
and Projectsbusiness area and is thus independent of the Development &
Production business areas in Norway, North America and International. All the
reserves estimates have been prepared by Statoil's technical staff.  Although the
CRM team reviews the information centrally, each asset team is responsible for
ensuring that it is in compliance with the requirements of the SEC and
Statoil's corporate standards. Information about proved oil and gas reserves,
standardised measures of discounted net cash flows related to proved oil and
gas reserves and other information related to proved oil and gas reserves, is
collected from the local asset teams and checked by CRM for consistency and
conformity with applicable standards. The final numbers for each asset are
quality-controlled and approved by the responsible asset manager, before
aggregation to the required reporting level by CRM.  The aggregated
results are submitted for approval to the relevant business area management
teams and the corporate executive committee.  The person
with primary responsibility for overseeing the preparation of the reserves
estimates is the chair of the CRM team. The person who presently holds this
position has a bachelor's degree in earth sciences from the University of
Gothenburg, and a master's degree in petroleum exploration and exploitation from
Chalmers University of Technology in Gothenburg, Sweden. She has 30 years'
experience in the oil and gas industry, 29 of them with Statoil. She is a
member of the Society of Petroleum Engineering (SPE) and vice-chair of the
UNECE Expert Group on Resource Classification (EGRC).  DeGolyer and MacNaughton
report Petroleum
engineering consultants DeGolyer and MacNaughton have carried out an
independent evaluation of Statoil's proved reserves as of 31 December 2015. The
evaluation accounts for 100% of Statoil's proved reserves. The aggregated net
proved reserves estimates prepared by DeGolyer and MacNaughton do not differ
materially from those prepared by Statoil when compared on the basis of net
equivalent barrels.  Oil and Condensate
 NGL/LPG
 Sales Gas
 Oil EquivalentNet
  proved reserves at 31 December 2015
 (mmbbls)
 (mmbbl)
 (bcf)
 (mmboe)Estimated by Statoil
 2,091
 364
 14,624
 5,060Estimated by DeGolyer
  and MacNaughton
 2,159
 379
 14,309
 5,087
 A reserves
audit report summarising this evaluation is included as Exhibit 15 (a)(iv).  3.11.3 Operational statistics  Operational statistics include information
about acreage and the number of wells drilled.  Developed and
undeveloped acreage The table
below shows the total gross and net developed and undeveloped oil and gas
acreage, in which Statoil had interests at 31 December 2015.  A gross value
reflects wells or acreage in which Statoil has interests (presented as 100%).
The net value corresponds to the sum of the fractional working interests owned
in gross wells or acres.  Norway
 Eurasia excluding Norway
 Africa
 Americas
 Oceania
 TotalAt 31
  December 2015 (in thousands of acres)Developed and undeveloped
  oil and gas acreageAcreage developed
 - gross
 871
 90
 858
 494
 -
 2,312- net
 322
 21
 271
 114
 -
 729Acreage undeveloped
 - gross
 9,038
 41,146
 13,569
 23,075
 18,531
 105,359- net
 3,419
 17,495
 4,637
 10,073
 11,160
 46,784
 56Statoil, Annual Report on Form 20-F 2015


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The largest concentrations of developed acreage in Norway are in the Troll, Skarv,
Snøhvit, Ormen Lange and Oseberg areas. In Africa, the Algerian gas development
projects In Amenas and In Salah represent the largest concentrations of
developed acreage (gross and net).  Statoil's largest
undeveloped acreage concentration is in Russia with 18% of the total acreage
and 48% of the total acreage in Eurasia excluding Norway. In Russia, Statoil
participates in a joint venture with Rosneft. The net acreage given in the
table above represents Statoil’s share of the joint venture. The largest
concentration of undeveloped acreage in the Americas is Nicaragua, with 33% of
the total for this geographic area. In Africa, the largest acreage
concentration is in Angola, representing 56% of the total for this geographic
area.  Statoil holds acreage in
numerous concessions, blocks and leases. The terms and conditions regarding
expiration dates vary significantly from property to property. Work programs
are designed to ensure that the exploration potential of any property is fully
evaluated before expiration.  Acreage related to several
of these concessions, blocks and leases are scheduled to expire within the next
three years. Any acreage which has already been evaluated to be non-profitable
may be relinquished prior to the current expiration date. In other cases,
Statoil may decide to apply for an extension if more time is needed in order to
fully evaluate the potential of the properties. Historically, Statoil has
generally been successful in obtaining such extensions.  Most of the undeveloped
acreage that will expire within the next three years is related to early
exploration activities where no production is expected in the foreseeable
future. The expiration of these leases, blocks and concessions will therefore
not have any material impact on our reserves.  Productive oil
and gas wells The number of gross and
net productive oil and gas wells, in which Statoil had interests at 31 December
2015, are shown in the table below.  Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalAt 31
  December 2015Number of productive oil
  and gas wellsOil wells
 - gross
 821
 166
 468
 3,130
 4,585- net
 281.4
 24.2
 71.3
 706.4
 1,083.2Gas wells
 - gross
 189
 6
 85
 1,953
 2,233- net
 81.6
 1.9
 32.7
 486.3
 602.4
 The total gross number of productive wells as of end 2015 includes 383 oil
wells and 12 gas wells with multiple completions or wells with more than one
branch. Net productive and dry oil and gas wells drilled The following tables show
the net productive and dry exploratory and development oil and gas wells
completed or abandoned by Statoil in the past three years. Productive wells include
exploratory wells in which hydrocarbons were discovered, and where drilling or
completion has been suspended pending further evaluation. A dry well is one
found to be incapable of producing sufficient quantities to justify completion
as an oil or gas well.  Norway
 Eurasia excluding Norway
 Africa
 Americas
 Oceania
 TotalYear 2015Net productive and dry
  exploratory wells drilled
 10.2
 1.0
 2.5
 2.6
 -
 16.3- Net dry exploratory
  wells drilled
 4.6
 0.4
 0.5
 0.9
 -
 6.4- Net productive
  exploratory wells drilled
 5.6
 0.7
 2.0
 1.7
 -
 9.9Net productive and dry
  development wells drilled
 32.1
 4.1
 10.6
 228.8
 -
 275.6- Net dry development
  wells drilled
 3.6
 -
 4.3
 0.3
 -
 8.2- Net productive
  development wells drilled
 28.6
 4.1
 6.3
 228.5
 -
 267.4Year 2014Net productive and dry
  exploratory wells drilled
 12.0
 1.0
 4.7
 3.4
 3.6
 24.7- Net dry exploratory
  wells drilled
 3.4
 1.0
 2.7
 1.6
 3.6
 12.2- Net productive
  exploratory wells drilled
 8.6
 -
 2.0
 1.9
 -
 12.5Net productive and dry
  development wells drilled
 26.9
 2.7
 8.5
 386.1
 -
 424.2- Net dry development
  wells drilled
 3.5
 -
 1.1
 1.2
 -
 5.8- Net productive
  development wells drilled
 23.4
 2.7
 7.4
 384.9
 -
 418.4Year 2013Net productive and dry
  exploratory wells drilled
 19.3
 0.3
 2.2
 2.3
 -
 24.0- Net dry exploratory
  wells drilled
 7.3
 0.3
 2.2
 2.3
 -
 12.0- Net productive
  exploratory wells drilled
 12.0
 -
 -
 -
 -
 12.0Net productive and dry
  development wells drilled
 26.7
 2.3
 5.9
 321.9
 -
 356.7- Net dry development
  wells drilled
 1.7
 -
 0.7
 1.3
 -
 3.7- Net productive
  development wells drilled
 24.9
 2.3
 5.3
 320.6
 -
 353.1
 Statoil, Annual Report on Form 20-F
201557


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58Statoil, Annual Report on Form 20-F 2015


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Exploratory and
development drilling in process The following table shows the number of
exploratory and development oil and gas wells in the process of being drilled
by Statoil at 31 December 2015.  Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalAt 31
  December 2015Number of wells in
  progressDevelopment wells
 - gross
 68
 4
 13
 202
 287- net
 24.5
 0.3
 2.7
 67.7
 95.2Exploratory wells
 - gross
 1
 -
 -
 8
 9- net
 0.4
 -
 -
 5.4
 5.8
  3.11.4 Delivery commitments  This section describes the long-term NCS
commitments for the contract gas years 2015-2018.  On behalf of the Norwegian
State's direct financial interest (SDFI), Statoil is responsible for managing,
transporting and selling the Norwegian state's oil and gas from the Norwegian
continental shelf (NCS). These reserves are sold in conjunction with Statoil's
own reserves. As part of this arrangement, Statoil delivers gas to customers
under various types of sales contracts. In order to meet the commitments, we
utilise a field supply schedule that ensures the highest possible total value
for Statoil and SDFI's joint portfolio of oil and gas.  The majority
of our gas volumes in Norway are sold under long-term contracts with
take-or-pay clauses. Statoil's and SDFI's annual delivery commitments under
these agreements are expressed as the sum of the expected off-take under these
contracts. As of 31 December 2015, the long-term commitments from NCS for the
Statoil/SDFI arrangement totalled approximately 14.51 trillion cubic feet (tcf)
(411 bcm).  Statoil and SDFI's
delivery commitments, expressed as the sum of expected off-take for the gas
years 2015, 2016, 2017 and 2018, are 2.28, 1.89, 1.56 and 1.22 tcf (64.7, 53.5,
44.2 and 44.0 bcm), respectively. The remaining volumes are sold to large
industrial end users or on the short-term market.  Statoil's currently
developed gas reserves in Norway are more than sufficient to meet our share of
these commitments for the next three years.  3.12 Applicable laws and regulations Statoil operates in more than 30 countries and is exposed to, and committed to
compliance with, a number of laws and regulations globally.  This article
focuses primarily on Norwegian laws, taking into account that the majority of
Statoil’s production is produced on the NCS, the ownership structure of the
company and that Statoil is registered and has its headquarters in Norway.  3.12.1 Norwegian
petroleum laws and licensing system  The
principal laws governing Statoil’s petroleum activities in Norway are the
Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act.  Norway is not a member
of the European Union (EU), but Norway is a member of the European Free Trade
Association (EFTA). The EU and the EFTA Member States have entered into the
Agreement on the European Economic Area, referred to as the EEA Agreement,
which provides for the inclusion of EU legislation covering the four freedoms -
the free movement of goods, services, persons and capital - in the national law
of the EFTA Member States (except Switzerland). An increasing volume of
regulations affecting Statoil is adopted in the EU and then applied to Norway
under the EEA Agreement. As a Norwegian company operating within both EFTA and
the EU, Statoil’s business activities are subject to both the EFTA Convention
governing intra-EFTA trade and EU laws and regulations adopted pursuant to the
EEA Agreement.  For further
information about the jurisdictions in which Statoil operates, see sections 3Business overviewand5Risk review.  Under the
Petroleum Act, the Norwegian Ministry of Petroleum and Energy is responsible
for resource management and for administering petroleum activities on the NCS.
The main task of the Ministry of Petroleum and Energy is to ensure that
petroleum activities are conducted in accordance with the applicable
legislation, the policies adopted by the Norwegian Parliament (the Storting)
and relevant decisions of the Norwegian State. Statoil, Annual Report on Form 20-F
201559


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60Statoil, Annual Report on Form 20-F 2015


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The Storting's role in relation to major policy issues in the
petroleum sector can affect Statoil in two ways: firstly, when the Norwegian
State acts in its capacity as majority owner of Statoil shares and, secondly,
when the Norwegian State acts in its capacity as regulator: ·The Norwegian
State's shareholding in Statoil is managed by the Ministry of Petroleum and
Energy. The Ministry of Petroleum and Energy will normally decide how the
Norwegian State will vote on proposals submitted to general meetings of the
shareholders. However, in certain exceptional cases, it may be necessary for
the Norwegian State to seek approval from the Storting before voting on a
certain proposal. This will normally be the case if Statoil issues additional
shares and such issuance would significantly dilute the Norwegian State's
holding, or if such issuance would require a capital contribution from the
Norwegian State in excess of government mandates. A decision by the Norwegian
State to vote against a proposal on Statoil’s part to issue additional shares
would prevent Statoil from raising additional capital in this manner and could
adversely affect Statoil’s ability to pursue business opportunities. For more
information about the Norwegian State's ownership, see sections 5.1.3Risks
related to state ownershipand
6.8Major shareholders  ·The Norwegian State exercises
important regulatory powers over Statoil, as well as over other companies and
corporations on the NCS. As part of its business, Statoil or the partnerships
to which Statoil is a party, frequently need to apply for licences and other
approval of various kinds from the Norwegian State. In respect of certain
important applications, such as for the approval of major plans for the
operation and development of fields, the Ministry of Petroleum and Energy must
obtain the consent of the Storting before it can approve the relevant
partnership's application. This may take additional time and affect the content
of the decision. Although Statoil is majority-owned by the Norwegian State, it
does not receive preferential treatment with respect to licences granted by or
under any other regulatory rules enforced by the Norwegian State  The principal laws governing Statoil’s petroleum activities in
Norway and on the NCS are the Norwegian Petroleum Act of 29 November 1996 (the
"Petroleum Act") and the regulations issued thereunder, and the
Norwegian Petroleum Taxation Act of 13 June 1975 ( the "Petroleum Taxation
Act"). The Petroleum Act sets out the principle that the Norwegian State
is the owner of all subsea petroleum on the NCS, that exclusive right to
resource management is vested in the Norwegian State and that the Norwegian
State alone is authorised to award licences for petroleum activities as well as
determine its terms.Licensees are required to submit
a plan for development and operation (PDO) to the Ministry of Petroleum and
Energy for approval. For fields of a certain size, the Storting has to accept
the PDO before it is formally approved by the Ministry of Petroleum and Energy.Statoil is dependent on the Norwegian State for approval of its NCS exploration
and development projects and its applications for production rates for
individual fields.  Production licences are the most important type of
licence awarded under the Petroleum Act and are normally awarded for an initial
exploration period, which is typically six years, but which can be shorter. The
maximum period is ten years. During this exploration period, the licensees must
meet a specified work obligation set out in the licence. If the licensees
fulfil the obligations set out in the initial license period, they are entitled
to require that the licence be prolonged for a period specified at the time
when the licence is awarded, typically 30 years.  However, the Ministry of Petroleum and Energy is not
entitled to award Statoil a licence in an area until the Storting has decided
to open the area in question for exploration. The terms of the production
licences are decided by the Ministry of Petroleum and Energy. A production
licence grants the holder an exclusive right to explore for and produce
petroleum within a specified geographical area. The licensees become the owners
of the petroleum produced from the field covered by the licence. Production
licences are awarded to group of companies forming a joint venture at the
Ministry’s discretion. The members of the joint venture are jointly and
severally responsible to the Norwegian State for obligations arising from petroleum
operations carried out under the licence. The Ministry of Petroleum and Energy
decides the form of the joint operating agreements and accounting agreements.  The governing body of the joint venture is the
management committee. In licences awarded since 1996 where the state's direct
financial interest (SDFI) holds an interest, the Norwegian State, acting
through Petoro AS, may veto decisions made by the joint venture management
committee, which, in the opinion of the Norwegian State, would not be in compliance
with the obligations of the licence with respect to the Norwegian State's
exploitation policies or financial interests. This power of veto has never been
used.  Interests in production licences may be transferred
directly or indirectly subject to the consent of the Ministry of Petroleum and
Energy and the approval of the Ministry of Finance of a corresponding tax
treatment position. In most licences, there are no pre-emption rights in favour
of the other licensees. However, the SDFI, or the Norwegian State, as
appropriate, still holds pre-emption rights in all licences.  The day-to-day management of a field is the
responsibility of an operator appointed by the Ministry of Petroleum and
Energy. The operator is in practice always a member of the joint venture
holding the production licence, although this is not legally required. The
terms of engagement of the operator are set out in the joint operating
agreement. A change of operator requires the consent of the Ministry of
Petroleum and Energy. In special cases, the Ministry of Petroleum and Energy
can order a change of operator.  Licensees are required to submit a plan for
development and operation (PDO) to the Ministry of Petroleum and Energy for
approval. For fields of a certain size, the Storting has to accept the PDO
before it is formally approved by the Ministry of Petroleum and Energy.  If important public interests are at stake, the
Norwegian State may instruct Statoil and other licensees on the NCS to reduce
the production of petroleum. The last time the Norwegian State instructed a
reduction in oil production was in 2002.  A licence from the Ministry of Petroleum and Energy is
also required in order to establish facilities for the transportation and
utilisation of petroleum. Ownership of most facilities for the transportation
and utilisation of petroleum in Norway and on the NCS is organised in the form
of joint ventures. The participants' agreements are similar to the joint
operating agreements.    Statoil, Annual Report on Form 20-F
201561


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Licensees are
required to prepare a decommissioning plan before a production licence or a
licence to establish and use facilities for the transportation and utilisation
of petroleum expires or is relinquished, or the use of a facility ceases. On
the basis of the decommissioning plan, the Ministry of Petroleum and Energy
makes a decision as to the disposal of the facilities.  For an overview of Statoil’s activities and shares in
Statoil’s production licences on the NCS, see section 3.5Development and Production Norway (DPN).  3.12.2 Gas sales and transportation from the
NCS  Statoil markets gas from the NCS on its own
behalf and on the Norwegian State's behalf. Gas is transported through the
Gassled pipeline network to customers in the UK and mainland Europe.  Most of Statoil’s and the
Norwegian State's gas produced on the NCS is sold under gas contracts to customers
in the European Union (EU). The EU internal energy market has been high on the
European Commission's agenda, and this market has thus been subject to
continuous legislative initiatives. Such changes in EU legislation may affect
Statoil's marketing of gas.  The Norwegian gas transport
system, consisting of the pipelines and terminals through which licensees on
the NCS transport their gas, is owned by a joint venture called Gassled. The
Norwegian Petroleum Act of 29 November 1996 and the pertaining Petroleum
Regulation establish the basis for non- discriminatory third-party access to
the Gassled transport system. The ownership structure in Gassled and the
pertaining regulations are intended to ensure the effectiveness of the system
and to prevent conflicts of interest.  To ensure neutrality, the
petroleum regulations also stipulate that all booking and allocation of
capacity is administrated by Gassco AS, an independent system operator wholly
owned by the Norwegian State. Spare capacity is released and allocated to
shippers by Gassco based on standard procedures. Capacity that has already been
allocated to a shipper may also be transferred bilaterally between shippers.  The tariffs for the use of
capacity in the transport system are determined by applying a formula set out
in separate tariff regulations stipulated by the Ministry of Petroleum and
Energy. The tariffs are paid on the basis of booked capacity, not on the basis
of the volumes actually transported. The Ministry's main objective when setting
the tariffs is to ensure that the profits are extracted in the production
fields on the NCS and not in the transport system.  For further information see
section 3.7.3.3Pipelines.  3.12.3 The Norwegian State's participation  The Norwegian State's policy as a shareholder in Statoil has been
and continues to be to ensure that petroleum activities create the highest
possible value for the Norwegian State.  Initially, the Norwegian State's participation in petroleum
operations was largely organised through Statoil. In 1985, the Norwegian State
established the State's direct financial interest (SDFI) through which the
Norwegian State has direct participating interests in licences and petroleum
facilities on the NCS. As a result, the Norwegian State holds interests in a
number of licences and petroleum facilities in which Statoil also hold
interests. Petoro AS, a company wholly owned by the Norwegian State, was formed
in 2001 to manage the SDFI assets.  3.12.4 SDFI oil and gas marketing and sale  Statoil markets and sells the Norwegian State's oil and gas
together with Statoil’s own production. The arrangement has been implemented by
the Norwegian State.  At an
extraordinary general meeting held on 27 February 2001, the Norwegian State, as
sole shareholder, revised Statoil’s articles of association by adding a new
article that requires Statoil to continue to market and sell the Norwegian
State's oil and gas together with its own oil and gas. At an extraordinary
general meeting held on 25 May 2001, the Norwegian State, as sole shareholder,
approved an instruction to Statoil setting out specific terms for the marketing
and sale of the Norwegian State's oil and gas. This resolution is referred to
as the Owner's instruction.  The Norwegian
State has a coordinated ownership strategy aimed at maximising the aggregate
value of its ownership interests in Statoil and the Norwegian State's oil and
gas. This is reflected in the Owner's instruction. It contains a general
requirement that, in Statoil’s activities on the NCS, it must take account of
these ownership interests in decisions that could affect the execution of this
marketing arrangement.  The principal
provisions of the Owner's instruction are set out below.  Objectives 62Statoil, Annual Report on Form 20-F 2015


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The overall objective of
the marketing arrangement is to obtain the highest possible total value for
Statoil’s oil and gas and the Norwegian State's oil and gas, and to ensure an
equitable distribution of the total value creation between the Norwegian State
and Statoil.  Statoil’s
tasks Statoil’s main tasks under
the Owner's instruction are to market and sell the Norwegian State's oil and
gas and to carry out all the necessary related activities, other than those
carried out jointly with other licensees under production licences. This
includes, but is not limited to, responsibility for processing, transport and
marketing.  Costs The Norwegian State does
not pay Statoil a specific consideration for performing these tasks, but
reimburses its proportionate share of certain costs, which, under the Owner's
instruction, may be Statoil’s actual costs or an amount specifically agreed.  Price mechanisms Payment to the Norwegian
State for sales of the Norwegian State's natural gas, both to Statoil and to
third parties, is based either on the prices achieved, a net back formula or
market value. Statoil purchases all of the Norwegian State's oil and NGL.
Pricing of the crude oil is based on market-reflective prices. NGL prices are
based on either achieved prices, market value or market-reflective prices.  Lifting mechanism To ensure neutral
weighting between the Norwegian State's and Statoil’s own natural gas volumes,
a list has been established for deciding the lifting priority between each individual
field. The different fields are ranked in accordance with their assumed total
value creation for the Norwegian State and Statoil, assuming that all of the
fields meet our profitability requirements if we participate as a licensee and
the Norwegian State's profitability requirements if the State is a licensee.
Within each individual field in which both the Norwegian State and Statoil are
licensees, the Norwegian State and Statoil will deliver volumes and share
income in proportion to our respective participating interests.  The Norwegian State's oil
and NGL is lifted together with our oil and NGL in accordance with applicable
lifting procedures for each individual field and terminal.  Withdrawal or
amendment The Norwegian State may at
any time utilise its position as majority shareholder of Statoil to withdraw or
amend the owner's instruction.  3.12.5 HSE regulation  Statoil’s petroleum operations are subject to
extensive laws and regulations relating to health, safety and the environment
(HSE).  With
business operations in more than 30 countries, Statoil is subject to a wide
variety of HSE laws and regulations concerning its products, operations and
activities. Laws and regulations may be jurisdiction specific, but also
international regulations, conventions or treaties, as well as EU directives
and regulations, are relevant.  In Norway,
under the Norwegian Petroleum Act of 29 November 1996, Statoil’s oil and gas
operations must be conducted in compliance with a reasonable standard of care,
taking into consideration the safety of employees, the environment and the
economic values represented by installations and vessels. The Petroleum Act
specifically requires that petroleum operations be carried out in such a manner
that a high level of safety is maintained and developed in step with
technological developments. Statoil is also required at all times to have a
plan to deal with emergency situations in our petroleum operations. During an
emergency, the Norwegian Ministry of Labour/Norwegian Ministry of Fisheries and
Coastal Affairs/Norwegian Coastal Administration may decide that other parties
should provide the necessary resources, or otherwise adopt measures to obtain
the necessary resources, to deal with the emergency for the licensees' account.  As a result of
the Macondo incident, in 2011, the US Department of the Interior created two
new agencies to administer operations and activities in the Gulf of Mexico -
the Bureau of Safety and Environmental Enforcement (BSEE) and the Bureau of
Offshore Energy Management (BOEM). The department also issued new regulations
to address the respective roles of the new agencies. Application of these
regulations has the potential to affect Statoil’s operations in the US.
Similarly, the effects from implementing the EU offshore Safety Directive in
EU-member states' legislation will affect operations in relevant EU member
countries.  See also section 5.1Risk factors.  3.12.6 Taxation of Statoil  Statoil is subject to ordinary Norwegian
corporate income tax and to a special petroleum tax relating to its offshore
activities in Norway. Internationally, Statoil’s activities are mainly subject
to tax in the countries where it operates.  Statoil, Annual Report on Form 20-F
201563


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Taxation in
Norway Statoil's Norwegian
petroleum activities are subject to ordinary corporate income tax and to a
special petroleum tax. In addition, there are taxes on both carbon dioxide
emissions and emissions of nitrogen oxide (NOx).  Corporate
income tax Statoil’s profits, both
from offshore oil and natural gas activities and from onshore activities, are
subject to Norwegian corporate income tax. The standard corporate income tax
rate has been reduced from 27% in 2015 to 25% in 2016. Statoil’s profits are
computed in accordance with ordinary Norwegian corporate income tax rules,
subject to certain modifications that apply to companies engaged in petroleum
operations. Gross revenue from oil production is determined on the basis of
norm prices. Norm prices are decided on a daily basis by the Petroleum Price
Board, and published quarterly. The Petroleum Tax Act states that the norm
prices shall correspond to the prices that could have been obtained in a sale
of petroleum between independent parties in a free market.  The maximum rate of
depreciation of development costs relating to offshore production installations
and pipelines is 16.67% per year. Depreciation starts when the cost is
incurred. Exploration costs may be deducted in the year in which they are
incurred. Financial costs related to the offshore activity are calculated
directly based on a formula set out in the Petroleum Tax Act. The financial
costs deductible under the offshore tax regime are the total interest costs and
exchange gains and losses related to interest-bearing debt multiplied by 50% of
the tax values covered by the petroleum tax regime divided by the average
interest-bearing debt. All other financial costs and income are allocated to
the onshore tax regime.  Abandonment costs incurred
can be deducted as operating expenses. Provisions for future abandonment costs
are not tax deductible.  Any tax losses can be
carried forward indefinitely against subsequent income earned. 50% of losses
relating to activity conducted onshore in Norway can be deducted from NCS income
subject to the standard income tax rate (reduced from 27% in 2015 to 25% in
2016). Losses on foreign activities cannot be deducted from NCS income.  By using group
contributions between Norwegian companies in which Statoil holds more than 90%
of the shares and votes, tax losses and taxable income can be offset to a great
extent. Group distributions are not deductible from Statoil’s NCS income.  Dividends received are
subject to tax in Norway. The basis for taxation is 3% of the dividends
received, which is subject to the standard income tax rate (reduced from 27% in
2015 to 25% in 2016). Dividends received from Norwegian companies and from
similar companies resident in the EEA for tax purposes, in which the recipient
holds more than 90% of the shares and votes, are fully exempt from tax.
Dividends from companies resident in the EEA that are not similar to Norwegian
companies, companies in low-tax countries and portfolio investments outside the
EEA will, under certain circumstances, be subject to the standard income tax rate
(reduced from 27% in 2015 to 25% in 2016) based on the full amounts received.  Capital gains from the
realisation of shares are exempt from tax. Exceptions apply to shares held in
companies resident in low-tax countries or portfolio investments in companies
resident outside the EEA for tax purposes, where, under certain circumstances,
capital gains will be subject to the standard income tax rate (reduced from 27%
in 2015 to 25% in 2016) and capital losses will be deductible.  Special
petroleum tax A special petroleum tax is
levied on profits from petroleum production and pipeline transportation on the
NCS. The special petroleum tax rate has been increased from 51% in 2015 to 53%
in 2016. The special petroleum tax rate is applied to relevant income in
addition to the standard income tax rate, resulting in a 78% marginal tax rate
on income subject to the special petroleum tax. The basis for computing the
special petroleum tax is the same as for income subject to ordinary corporate
income tax, except that onshore losses are not deductible from the special
petroleum tax basis, and a tax-free allowance, or uplift, is granted at a rate
of 5.5% per year. The uplift is computed on the basis of the original
capitalised cost of offshore production installations. The uplift can be
deducted from taxable income for a period of four years, starting in the year
in which the capital expenditure is incurred. Unused uplift can be carried
forward indefinitely. For further information seenote 9 Income
taxes.  Taxation
outside Norway Statoil's international
petroleum activities are subject to tax pursuant to local legislation. Fiscal
regulation of Statoil’s upstream operations is generally based on corporate
income tax regimes and/or production sharing agreements (PSA). Royalties may
apply in either case. Statoil is subject to excess (or "windfall")
profit tax in some of the countries in which it produces crude oil or
condensate.  Production
sharing agreements (PSA) Under a PSA, the host
government typically retains the right to the hydrocarbons in place. The
contractor normally receives a share of the oil produced to recover its costs,
and is also entitled to an agreed share of the oil as profit ("profit
oil"). The state's share of profit oil typically increases based on a
success factor, such as surpassing certain specified internal rates of return,
production rates or accumulated production. The contractor is usually subject
to income tax on its own share of the profit oil. Normally, the contractors
carry the exploration costs and risk prior to a commercial discovery and are
then entitled to recover those costs during the production phase. Fiscal
provisions in a PSA are to a large extent negotiable and are unique to each
PSA.  Income tax
regimes Under an income
tax/royalty regime, companies are granted licences by the government to extract
petroleum, and the state may be entitled to royalties, which are generally
assessed on gross revenue from production, and a profit tax, which is generally
based on the company's net taxable income from production as defined in a
country's domestic tax legislation. In some countries, income from petroleum
activities is also 64Statoil, Annual Report on Form 20-F 2015


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subject to a special petroleum tax
in addition to ordinary corporate tax. In general, the fiscal terms surrounding
these licences are non-negotiable and the company is subject to legislative
changes in the tax laws.  Statoil, Annual Report on Form 20-F
201565


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3.13
Property, plant and equipment  Statoil has interests in real estate in many
countries throughout the world. However, no individual property is significant.  Statoil's head
office is located at Forusbeen 50, NO-4035, Stavanger, Norway and comprises
approximately 135,000 square metres of office space.In June 2015 Statoil
closed a sales transaction for the sale of the company’s head office building
in Stavanger, and at the same time, Statoil entered into a 15 year operating
lease agreement for the building. For more information see note 4Acquisitions and disposalsto the Consolidated
financial statements.  In October
2012, Statoil moved into a new 65,500-square-metre officebuilding located at Fornebu on the outskirts of Norway's capital Oslo. Statoil
as tenant has signed a long-term lease agreement with the owner of the office
building, IT-Fornebu AS. The new office building provides an environmentally
friendly workplace for up to 2,500 employees.  For a
description of our significant reserves and sources of oil and natural gas, see
note 27Supplementary oil and gas information
(unaudited)to the Consolidated financial statements.  3.14 Related party transactions  See note24 Related
parties to theConsolidated financial statements for information concerning
related parties.  3.15
Insurance  Statoil maintains insurance
coverage that includes coverage for physical damage to its oil and gas properties,
third-party liability, workers' compensation and employers' liability, general
liability, sudden pollution and other coverage.  Statoil's
insurance coverage includes deductibles that must be met prior to recovery.
Statoil's external insurance is subject to caps, exclusions and limitations,
and there is no assurance that such coverage will adequately protect Statoil
against liability from all potential consequences and damages.  Our
well control policies, which cover costs relating to well control incidents
(including pollution and clean-up costs) are subject to the following limits
for the two of the areas Statoil operates:  NCS ·NOK
2,500 million plus USD 1,500 million per incident for exploration wells ·NOK
2,000 million per incident for production wells  Gulf
of Mexico ·Local
well control limit (typically in the area of USD 300 million) plus USD 1,500
million per incident for exploration wells ·Local
well control limit (typically in the area of USD 300 million) for production
wells  The above limits assume a 100% ownership interest in a given well
and would scaled to be equivalent to our percentage ownership interest in a
given well. In addition to the well control insurance programmes, we have in
place a third-party liability insurance programme with a gross limit of USD 800
million per incident.  66Statoil, Annual Report on Form 20-F 2015


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3.16 People and the group  3.16.1 Employees in Statoil  The Statoil group employs approximately
21,600 employees. Of these, approximately 19,000 are employed in Norway and
approximately 2,600outside Norway.  Number of employees
 WomenPermanent
  employees and percentage of women in the Statoil group
 2015
 2014
 2013
 2015
 2014
 2013Norway
 18,977
 19,670
 20,336
 30%
 30%
 30%Rest of Europe
 855
 909
 935
 29%
 31%
 30%Africa
 98
 117
 140
 35%
 34%
 33%Asia
 97
 135
 140
 36%
 52%
 53%North America
 1,265
 1,375
 1,559
 35%
 34%
 35%South America
 289
 310
 303
 38%
 40%
 38%TOTAL
 21,581
 22,516
 23,413
 30%
 31%
 31%Non-OECD
 590
 677
 690
 40%
 40%
 39%
  Total workforce by
  region, employment type and new hires in the Statoil group in 2015Geographical
  Region
 Permanent employees
 Consultants
 Total Workforce1)
 Consultants (%)
 Part time (%)
 New hiresNorway
 18,977
 424
 19,401
 2%
 3%
 103Rest of Europe
 855
 99
 954
 10%
 1%
 70Africa
 98
 5
 103
 5%
 NA
 6Asia
 97
 5
 102
 5%
 NA
 2North America
 1,265
 112
 1,377
 8%
 0%
 142South America
 289
 3
 292
 1%
 0%
 8TOTAL
 21,581
 648
 22,229
 3%
 3%
 331Non-OECD
 590
 15
 605
 2%
 na
 191)
 Enterprise personnel,
  defined as third-party service providers who work at our onshore and offshore
  operations, are not included. These were roughly estimated to be around
  30,500 in 2015.
 Statoil works systematically with recruitment and development
programmes in order to build a diverse workforce by attracting, recruiting and
retaining people of both genders and different nationalities and age groups
across all types of positions.  In 2015, 19% of employees and 22% of our managerial staff held
nationalities other than Norwegian. Outside Norway, Statoil aims to increase
the number of people and managers who are locally recruited and to reduce the
long-term use of expats in business operations. In 2015, 73% of new hires in Statoil
were non-Norwegians and 35% were women.  In Statoil, the total turnover rate for 2015 was 3.6%. On 31
December 2015, the Statoil group employed 21.581 permanent employees and 3% of
the workforce worked part-time. In the annual organisational and working
environment survey, which continued to have a high response of 85%, our
employees reported an overall satisfaction of 4.6. This is a slight increase
from the score of 4.5 in 2014.  Our people performance data relates to permanent employees in our
direct employment. Statoil defines consultants as contracted personnel that are
mainly based in our offices. Temporary employees and enterprise personnel are
not included in the workforce table. Enterprise personnel are defined as third
party service providers and work on our on-shore and off-shore operations.
These were roughly estimated to be around 30,500 in 2015. The information about
people policies applies to Statoil ASA and its subsidiaries.   Statoil, Annual Report on Form 20-F
201567


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3.16.2 Equal opportunities  We are committed to building a workplace that promotes diversity
and inclusion through its people processes and practices.  We promote diversity among our employees. We try to create the
same opportunities for everyone and do not tolerate discrimination or
harassment of any kind in our workplace. In 2015, we continued to focus on
strengthening women in leadership and professional positions and on building
broad international experience in our workforce. Our commitment to diversity
and inclusion was demonstrated in the 2015 Global People Survey, where we
maintained our high score of 5.1 (6 being the highest) for the existence of
zero tolerance for discrimination and harassment within the workplace.  In 2015, the overall percentage of women in the company was 30%.
The percentage of women in the board of directors is 50% (67% among the
employee representatives and 43% among members elected by the shareholders). In
the corporate executive committee the female representation has increased from
last year’s 11% to 18% in 2015. We pay close attention to male-dominated
positions and discipline areas, and in 2015 the proportion of female engineers
remained stable at 27% in Statoil ASA. Among staff engineers with up to 20
years' experience, the proportion of women increased to 31%. We continue to
strive to increase the number of female managers through our development
programmes, and in 2015 despite the overall reduction of 181 leadership
positions, we increased the share of women in management by 0.5%. The
percentage of appointment of women in new leadership positions in 2015 was 36%.  At Statoil we reward our people on the basis of their performance,
giving equal emphasis to delivery and behaviour. Our reward approach is adapted
to local market conditions at the locations in which we operate and is
transparent, non-discriminatory and supports equal opportunities. Given the
same position, experience and performance, our employees will be at the same
remuneration level relative to the local market. This is demonstrated in the
salary ratio between women and men at different levels in Statoil ASA. In 2015
we have maintained a high ratio, with an average of 98%.  The intake of apprentices in Norway is an important part of the
company's recruitment of skilled workers and commitment to the education and
training of young technicians and operators in the oil and gas industry. In
2015, apprenticeships were given to 130 new students; of these 42 were female.
The total number of apprentices in Statoil is 282.  3.16.3 Unions and representatives  Statoil's cooperation with employee representatives and trade
unions is based on confidence, trust and continuous dialogue between management
and the people in various cooperative bodies.  In Statoil ASA,
70% of the employees in theparent company aremembers of a trade union. Work councils and working
environment committees are established where required by law or agreement. Town
hall meetings are also used for information and consultations in accordance
with requirements and usage in each country.  In Norway, the
formal basis for collaboration with labour unions is established in the Basic
Agreements between the Confederation of Norwegian Enterprise (NHO) and the
corresponding respective national labour confederations (unions).  Statoil promotes good employee and industrial relations practices
through various networks and forums, including IndustriALL Global Union
(IndustriAll) and International Labour Organisation (ILO).  In 2015, management and employee representatives collaborated closely,
in particular on the three corporate change initiatives Statoil technical
efficiency programme (STEP), Organisational efficiency programme (OE) and
Corporate Review 2015. In addition, the European Works Council continued to be
an important channel between the company and employees.  We collaborate with employee
representatives in the changeprocesses, and westrive
to find solutions that are satisfactory both for our employees and for the
company. To handle redundancies resulting from the ongoing change processes in
2015, we used measures such as internal deployment, severance packages and
early retirement.  68Statoil, Annual Report on Form 20-F 2015


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3.17 Safety, security and
sustainability  Statoil’s
ambition is to be an industry leader in safety, security and carbon efficiency.  Safety and security Statoil’s ambition is to ensure
safe and secure operations that protect people, the environment, communities
and assets. Statoil’s approach to safety and security entails preventing
accidents and incidents, avoiding oil spills, ensuring a healthy work
environment and developing a strong security culture.  Statoil
works closely with industry peers on incident prevention and emergency
preparedness. Through assurance activities, and by analysing Statoil’s own
incidents along with those of the industry at large, Statoil aims to ensure a
dynamic approach to safety and security performance management. A global oil
spill response system has been established, which includes close collaboration
with industry peers and national and local communities. Trained response teams
and sufficient equipment are ready to be mobilised when and where needed. Everyone working for Statoil,
and in the joint ventures controlled by Statoil, is required to comply with
Statoil’s safety, health and security standards. Statoil actively engages with
contractors and joint ventures to encourage the embedding of a strong safety
and security culture in the workforce.   Statoil
      usesserious incident frequency(SIF)
        as a key indicator to monitor safety performance. This indicator (number of
        serious incidents, including near misses, per million hours worked) combines
        actual consequences of incidents and the potential for incidents to develop
        into serious or major accidents. The SIF has significantly improved over the
        last years, from 1.1 incidents per million hours worked in 2011 to 0.6
        incidents per million hours worked in 2015.
    Total recordable
      injuries
      per million hours worked (TRIF) improved from 3.0 in 2014 to 2.7 in 2015. 
      The TRIF for Statoil’s employees was 2.3 and the TRIF for Statoil’s
      contractors was 2.8.
    
    Regrettably, there were three fatalitiesrelated to Statoil’s
      operations in 2015. One person died and two persons were injured as a result
      of a breaking wave that hit the drilling rig COSL Innovator on 30 December
      2015. Two separate road accidents in the USA resulted in two fatalities.
    
    Accidental oil
      spills
      were significantly reduced from 2014 to 2015. The total volume spilt was 23
      m3 in 2015, down from 125 m3 in 2014.
    
    Preventing oil and gas leakages
      is important to avoid major accidents. In 2015, the total number of serious
      leakages (leakages above 0.1kg/sec) increased to 21, up from 13 in 2014. All
      leakages are undergoing formal investigations and in-depth studies in order
      to capture learning and prevent similar incidents in the future.
 Security is a key issue for the oil and gas
industry because it operates in many unstable regions. At Statoil, security
risk is systematically assessed on a continuous basis in order to achieve
effective and proportionate security risk management. No security incidents
with major consequences for Statoil were recorded in 2015. The two-year
Security Improvement Programme, established to significantly raise security
capabilities and develop a stronger security culture, was finished on schedule
in 2015. A road map has been established to further strengthen our security
culture and capabilities by 2020.  Climate change Statoil recognises the
ambition to limit the average global temperature rise to below two degrees
centigrade compared to pre-industrial levels. The Paris agreement on climate
change negotiated at the UN Conference of Parties (COP21) in December 2015
provides the prospect of improved policy support around the world for
accelerating the shift to low carbon solutions. Statoil welcomes the agreement
and believes that the company is well positioned to play its part. Statoil’s approach to climate change entails
four key aspects: ·supporting
the development of viable global climate policies ·managing
climate risks and opportunities ·managing
emissions ·developing
low carbon energy solutions  Statoil carefully monitors and assesses the
potential impact of climate change. Both the corporate executive committee and
board of directors frequently discuss the business risks and opportunities
associated with climate change, including market, regulatory and physical risk
factors. Tools such as internal carbon pricing, scenario planning and stress
testing of projects against various oil and gas price assumptions, are used.
Statoil regularly assesses how the development of technologies and changes in
regulations, including the introduction of stringent climate policies, may
impact the oil price, the costs of developing new oil and gas assets, and the
demand for oil and gas.  Statoil, Annual Report on Form 20-F
201569


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Statoil’s efforts to
  reduce direct greenhouse gas (GHG) emissions includes improving energy
  efficiency; reducing methane emissions; eliminating routine flaring and
  scaling up carbon capture and storage.
  
  The
  production from Statoil-operated assets increased from 997 mmboe in 2014 to 1073 mmboe in 2015.[1]
  Thetotal direct GHG emissions
  from Statoil’s operated assets remained stable at 16.3 million tonnes CO2
  equivalents in 2015. GHG emissions include carbon dioxide (CO2)
  and methane (CH4), where CO2 constitutes the largest
  part (15.4 million tonnes in 2015).
  
  In 2015, Statoil established a 2020 carbon
  intensity target of 9 kg CO2/boe for its upstream activities.
  Statoil’s upstream carbon intensity was 10kg CO2/boe in 2015 –
  less than 60% of the industry average of 18kg as measured by the
  International Association of Oil and Gas Producers (Environmental Performance
  Indicators, 2014 data).
  
  Indirect (scope 2)
  GHG emissions
  were 0.3 million tonnes CO2 equivalents in 2015, using a location
  based emission factor. Scope 3 GHG emissions (emissions from the use of
  Statoil’s equity production) were estimated to 295 million tonnes CO2
  equivalents.
  
  Statoil’s operations in Europe are subject
  to emissions allowances according to the EU Emissions Trading System (EU
  ETS). Statoil’s Norwegian operations are subject to both the Norwegian
  offshore CO2 tax and EU ETS quotas. In 2015, Statoil paid some NOK
  4.0 billion in CO2 tax and quotas.
 In 2015, Statoil
announced a new business area for New Energy Solutions.Statoil’s approach to growth opportunities within renewables and new
energy solutions includes both commercial investments and research and
development (R&D). Statoil has made investments in offshore wind projects
and continues to be engaged in carbon capture and storage. A significant
proportion of Statoil’s R&D efforts address energy efficiency, carbon
capture and renewables. See section 3.8.1New Energy Solutions
(NES)for more information.  Environmental impact
and resource efficiency Statoil is committed to using resources
efficiently and strives to apply high standards for waste management, emissions
to air and impact on ecosystems – in all operations. Statoil’s fresh water
consumption decreased from 14.8 million cubic metres in 2014 to 14.5 million
cubic metres in 2015. Improving water efficiency in the onshore activities in
North America through means such as water recycling and substituting fresh
water with brackish water, is a priority.  Working with suppliers Statoil
is committed to using suppliers who operate consistently in accordance with
Statoil’s values and who maintain high standards of safety, security and
sustainability. These aspects are incorporated in all phases of the procurement
process. All potential suppliers must meet Statoil’s minimum requirements in
order to qualify as a supplier and these include safety, security and
sustainability criteria. After
awarding a contract, a supplier follow-up strategy is established, based on a
risk assessment. Statoil’s expectations regarding safety, security and
sustainability are communicated to the supplier in the contract start-up
meeting and throughout the contract period. Assurance activities are conducted,
such as follow-up meetings, verifications and audits to manage identified
risks. Supply chain personnel are trained in safety, security and
sustainability risk handling through classroom courses, e-learning courses and
awareness sessions. Human rights Statoil seeks to conduct its business in a way that is
consistent with the ten UN Guiding Principles on Business and Human Rights (the
UN Guiding Principles), the UN Global Compact principles and the Voluntary
Principles on Security and Human Rights. Statoil is committed to respecting
internationally recognised human rights as laid out in the International Bill
of Human Rights, the International Labour Organisation's 1998 Declaration on
Fundamental Rights and Principles at Work, and applicable standards of
international humanitarian law.  Throughout 2015, a stand-alone human rights policy was
developed, to give greater weight to Statoil’s long-standing commitment to
respect human rights. The policy was based on consultations and workshops with
relevant experts and stakeholders. A gap analysis has been initiated to
identify how Statoil’s human rights processes and practices need to further
evolve to reflect the new policy. Human rights aspects are integrated into
relevant internal management processes, tools and training. On-going
activities, business relationships and new business opportunities are assessed
for potential human rights impacts and aspects, following a risk-based
approach. In 2015, supplier verification practices were enhanced. Human rights
training is provided to employees based on risk and relevance.   [1]Climate and environmental performance data represent total figures from
Statoil-operated assets (operational control), except from scope 3 emissions,
which are calculated based on Statoil’s equity production.
 70Statoil, Annual Report on Form 20-F 2015


---

4 Financial
review   4.1 Operating and financial review   4.1.1 Sales volumes  Sales volumes include lifted entitlement
volumes, the sale of SDFI volumes and marketing of third-party volumes.  In addition to Statoil’s own volumes, we
market and sell oil and gas owned by the Norwegian State through the Norwegian
State's share in production licences. This is known as the State's Direct
Financial Interest or SDFI. For additional information, see section 3.12.4 SDFI oil
and gas marketing and sale. The following table shows the SDFI
and Statoil sales volume information on crude oil and natural gas for the
periods indicated. The Statoil natural gas sales volumes include equity volumes
sold by the MMP segment, natural gas volumes sold by the DPI segment and ethane
volumes.  For the year ended 31 DecemberSales
  Volumes1)
 2015
 2014
 2013Statoil:2)Crude oil (mmbbls)3)
 378
 353
 347Natural gas (bcf)
 1,645
 1,596
 1,622Combined oil and gas
  (mmboe)
 671
 637
 636Third party volumes:4)Crude oil (mmbbls)3)
 290
 304
 303Natural gas (bcf)
 304
 285
 434Combined oil and gas
  (mmboe)
 344
 355
 380SDFI assets owned by the
  Norwegian State:5)Crude oil (mmbbls)3)
 149
 148
 155Natural gas (bcf)1)
 1,400
 1,254
 1,351Combined oil and gas
  (mmboe)
 398
 371
 396Total:Crude oil (mmbbls)3)
 816
 805
 805Natural gas (bcf)
 3,348
 3,134
 3,407Combined oil and gas
  (mmboe)
 1,413
 1,363
 1,4121)
 The volumes in columns
  2014 and 2013 are updated to reflect total sales volumes of crude oil
  (mmbbls) and natural gas (bcf). Previously only volumes from MMP were
  disclosed.2)
 The Statoil volumes
  included in the table above are based on the assumption that volumes sold
  were equal to lifted volumes in the relevant year. Volumes lifted by DPI but
  not sold by MMP, and volumes lifted by DPN or DPI and still in inventory or
  in transit may cause these volumes to differ from the sales volumes reported
  elsewhere in this report by MMP.3)
 Sales volumes of crude
  oil include NGL and condensate. All sales volumes reported in the table above
  include internal deliveries to our manufacturing facilities.4)
 Third party volumes of
  crude oil include both volumes purchased from partners in our upstream
  operations and other cargos purchased in the market. The third party volumes
  are purchased either for sale to third parties or for our own use. Third
  party volumes of natural gas include third party LNG volumes related to our
  activities at the Cove Point regasification terminal in the US.5)
 The line item SDFI
  assets owned by the Norwegian State include sales of both equity production
  and third party gas.
 Statoil, Annual Report on Form 20-F
201571


---

72Statoil, Annual Report on Form 20-F 2015


---

4.1.2
Group profit and loss analysis  Net operating income was down by 86% in 2015,
impacted by significantly lower prices and increased net impairment losses.  For the year ended 31 DecemberOperational
  data
 2015
 2014
 2013
 15-14 change
 14-13 changePricesAverage Brent oil price
  (USD/bbl)
 55.3
 98.9
 108.7
 (44%)
 (9%)Development and
  Production Norway average liquids price (USD/bbl)
 48.2
 90.6
 101.0
 (47%)
 (10%)Development and
  Production International average liquids price (USD/bbl)
 42.9
 85.6
 98.4
 (50%)
 (13%)Group average liquids
  price (USD/bbl)
 45.9
 88.6
 100.0
 (48%)
 (11%)Group average liquids
  price (NOK/bbl) [1]
 370.7
 558.5
 587.8
 (34%)
 (5%)Transfer price natural
  gas (NOK/scm) [9]
 1.58
 1.57
 1.92
 1%
 (18%)Average invoiced gas
  prices - Europe (NOK/scm) [8]
 2.16
 2.28
 2.45
 (5%)
 (7%)Average invoiced gas
  prices - North America (NOK/scm) [8]
 0.79
 1.04
 0.83
 (24%)
 25%Refining reference
  margin (USD/bbl) [2]
 8.0
 4.7
 4.1
 70%
 15%Entitlement production
  (mboe per day)Development and
  Production Norway entitlement liquids production
 595
 588
 591
 1%
 (1%)Development and
  Production International entitlement liquids production
 436
 383
 354
 14%
 8%Group entitlement liquids
  production
 1,032
 971
 945
 6%
 3%Development and
  Production Norway entitlement gas production
 637
 595
 626
 7%
 (5%)Development and
  Production International entitlement gas production
 144
 163
 148
 (12%)
 10%Group entitlement gas
  production
 781
 758
 773
 3%
 (2%)Total entitlement
  liquids and gas production [3]
 1,812
 1,729
 1,719
 5%
 1%Equity production (mboe
  per day)Development and
  Production Norway equity liquids production
 595
 588
 591
 1%
 (1%)Development and
  Production International equity liquids production
 569
 538
 524
 6%
 3%Group equity liquids
  production
 1,165
 1,127
 1,115
 3%
 1%Development and
  Production Norway equity gas production
 637
 595
 626
 7%
 (5%)Development and
  Production International equity gas production
 170
 205
 200
 (17%)
 3%Group equity gas
  production
 806
 801
 825
 1%
 (3%)Total equity liquids and
  gas production [4]
 1,971
 1,927
 1,940
 2%
 (1%)Liftings (mboe per day)Liquids liftings
 1035
 967
 950
 7%
 2%Gas liftings
 802
 779
 792
 3%
 (2%)Total liquids and gas
  liftings
 1837
 1,746
 1,742
 5%
 0%Marketing, Midstream and
  Processing sales volumesCrude oil sales volumes
  (mmbl)
 829
 811
 809
 2%
 0%Natural gas sales
  Statoil entitlement (bcm)
 44.0
 43.1
 44.3
 2%
 (3%)Natural gas sales third-party
  volumes (bcm)
 8.6
 8.1
 12.3
 6%
 (34%)Production cost
  (NOK/boe, last 12 months)Production cost
  entitlement volumes
 52
 55
 50
 (5%)
 10%Production cost equity
  volumes
 48
 49
 44
 (2%)
 11%
  Total equity liquids and
gas production(see section 9Terms and
definitions)was 1,971 mboe, 1,927 mboe and 1,940 mboe per day in 2015, 2014
and 2013, respectively.  The 2% increase in total
equity production from 2014 to 2015 was primarily due to start-up and ramp-up
on various fields,higher gas sales from the NCSand improved operational performance.
Expected natural decline and reduced ownership shares as a result of divestments
and redeterminations partially offset the increase.  Statoil, Annual Report on Form 20-F
201573


---

The total equity
production in 2014 was slightly lower compared to 2013. Start-up and ramp-up of
production on various fields and higher production regularity compared to last
year were offset by expected natural decline and reduced ownership shares from
divestments.   Total entitlement liquids
and gas productionwas 1,812 mboe per day in 2015 compared to 1,729 mboe in 2014 and
1,719 mboe per day in 2013.  The total entitlement
production in 2015 was up 5% for the same reasons as described above. The
benefit oflower effect from production sharing agreements (PSA effect)
mainly driven by the reduction in prices, added to the increase in entitlement
production.
From 2013 to 2014 the development in total entitlement production was almost
flat for the same reasons as described above and the benefit from lower
PSA-effects.  The PSA effect was 116
mboe, 157 mboe and 182 mboe per day in 2015, 2014 and 2013, respectively.  Over time, the volumes
lifted and sold will equal our entitlement production, but they may be higher
or lower in any period due to differences between the capacity and timing of
the vessels lifting our volumes and the actual entitlement production during
the period, see section 9Terms and definitionsfor more information.  Income
  statement under IFRS
 For the year ended 31 December(in NOK
  billion)
 2015
 2014
 2013
 15-14 change
 14-13 change(restated)
 (restated)Revenues
 465.3
 606.8
 616.6
 (23%)
 (2%)Net income from equity
  accounted investments
 (0.3)
 (0.3)
 0.1
 2%
 >(100%)Other income
 17.8
 16.1
 17.8
 11%
 (10%)Total revenues and other
  income
 482.8
 622.7
 634.5
 (22%)
 (2%)Purchases [net of
  inventory variation]
 (211.2)
 (301.3)
 (306.9)
 (30%)
 (2%)Operating expenses and
  selling, general and administrative expenses
 (91.9)
 (80.2)
 (81.9)
 15%
 (2%)Depreciation,
  amortisation and net impairment losses
 (133.8)
 (101.4)
 (72.4)
 32%
 40%Exploration expenses
 (31.0)
 (30.3)
 (18.0)
 2%
 69%Net operating income
 14.9
 109.5
 155.5
 (86%)
 (30%)Net financial items
 (10.6)
 (0.0)
 (17.0)
 >100%
 (100%)Income before tax
 4.3
 109.4
 138.4
 (96%)
 (21%)Income tax
 (41.6)
 (87.4)
 (99.2)
 (52%)
 (12%)Net income
 (37.3)
 22.0
 39.2
 >(100%)
 (44%)
  Total revenues and other
incomeamounted to NOK 482.8 billion in 2015 compared to NOK 622.7 billion in
2014 and NOK 634.5 billion in 2013. Revenues are generated from both the sale
of lifted crude oil, natural gas and refined products produced and marketed by
Statoil, and from the sale of liquids and gas purchased from third parties. In
addition, we market and sell the Norwegian State's share of liquids from the
NCS. All purchases and sales of the Norwegian State's production of liquids are
recorded as Purchases [net of inventory variations] and Revenues, respectively,
while sales of the Norwegian State's share of gas from the NCS are recorded
net.   The 23% decrease in revenues from 2014
to 2015 was mainly due to the significant reduction in both liquids and gas
prices measured in NOK. Stronger refinery margins in 2015 and higher volumes of
both liquids and gas sold partially offset the decrease.  The 2% decrease in revenues from 2013 to
2014 was mainly due to decreased prices for
liquids and European gas and reduced volumes of liquids and gas sold, partly
offset increased US gas prices and the exchange rate development (USD/NOK). Also,
revenues in 2014 were positively impacted by gains from derivatives, mainly due
to a significant drop in the forward curve in the oil market.  Other incomewas NOK 17.8 billion in 2015 compared to NOK 16.1 billion in 2014
and NOK 17.8 billion in 2013. Other income in 2015 was mainly related to gains
from sales of certain ownership interest the Shah Deniz project (NOK 12.4
billion), the Trans Adriatic Pipeline (NOK 1.4 billion) and the Gudrun field
(NOK 1.2 billion). Also, gain from sales of office buildings in Norway (NOK 2.1
billion) impacted other income in 2015.  Other income in 2014 consisted of the gain from the sale of
certain ownership interests on the NCS to Wintershall (NOK 5.9 billion) and the
divestment of working interests in the Shah Deniz Project and South Caucasus
Pipeline (NOK 5.4 billion.) In addition, an arbitration settlement 74Statoil, Annual Report on Form 20-F 2015


---

(NOK 2.8 billion) following an arbitration ruling in
Statoil’s favour, impacted other income in 2014. In 2013, other income consisted
of gains from sale of certain ownership interests on the NCS to OMV (NOK 10.1
billion) and Wintershall (NOK 6.4 billion).  As a result of the factors explained above,total revenue
and other incomedecreased by 22% in 2015. In 2014, the decrease was 2%.  Purchases [net of inventory variation]include the cost of
liquids purchased from the Norwegian State, which is pursuant to the Owner's
instruction, and the cost of liquids and gas purchased from third parties. See
section 3.12.4SDFI oil and gas marketing
and salefor more details.  Purchases [net of
inventory variation] amounted to NOK 211.2 billion in 2015 compared to 301.3
billion in 2014 and NOK 306.9 billion in 2013. The 30% decrease from 2014 to 2015 was mainly related to the
significantlower
prices for liquids and gas and other oil products and awrite-down of
inventories from cost to market value of NOK 3.9 billion, partially offset by the
USD/NOK exchange rate development.The 2% decrease from 2013 to 2014 was mainly related tolower prices for liquids
and gas including the write-down of inventories from cost-to-market value of
NOK 4.0 billionand reduced third-party volumes. These effects were partially
offset by the USD/NOK exchange rate development.  Operating expenses and
selling, general and administrative expensesamounted to NOK 91.9
billion in 2015 compared to NOK 80.2 billion in 2014, and NOK 81.9 billion in
2013.  The 15% increase from 2014
to 2015 was mainly due to the USD/NOK exchange rate development in 2015 and
because a curtailment gain related to the change of pension plan was included
in 2014 (discussed below). Lower operation and maintenance costs, lower
royalties due to reduced liquids prices, lower transportation costs and
portfolio changes in addition to positive effects from on-going cost
initiatives, partially offset the increase. Excluding the USD/NOK exchange rate
development and the effect of the curtailment gain in 2014, operating expenses
and selling, general and administrative expenses decreased by 3%.  The 2% decrease from 2013
to 2014 was mainly due to a curtailment gain of NOK 3.5 billion recognised upon
the decision to change the company’s pension plan in Norway in 2014 and an
onerous contract provision of NOK 4.9 billion related to the Cove Point
terminal in the US recognised in 2013. These effects were offset by increased
expenses in 2014 mainly due to new fields coming on stream, onshore production
ramp-up and increased transportation costs in the NorthAmerica. In addition, the
exchange rate development (NOK/USD) increased the expenses in 2014 compared to
2013.  Depreciation, amortisation
and net impairment lossesamounted to NOK 133.8 billion in 2015 compared to NOK 101.4
billion in 2014 and NOK 72.4 billion in 2013. Included in these totals were net
impairment losses of NOK 47.8 billion, NOK 26.9 billion and NOK 7.0 billion for
2015, 2014 and 2013 respectively, related to the continuously falling commodity
prices.  Net impairment losses ofNOK 47.8 billionin 2015 were mainly related to unconventional onshore assets in
the USA and other conventional assets in the DPI segment (NOK 42.7 billion),
conventional offshore assets in the development phase in the DPN segment (NOK
8.7 billion) and a net impairment reversal of NOK 3.5 mainly related to a refinery
in the MMP segment. See note 11 Property, plant and equipment
to the Consolidated financial statements for further details.  Compared to 2014, the 32% increase in 2015 was mainly due to
increased impairment chargesprimarily as a result of the further declining long-term commodity
price assumptions in the first quarter of 2015.In addition, the USD/NOK exchange rate
development and start-up and ramp-up of production of several fields added to
the increase in depreciation. Reduced overall depreciation because of net
impairments of assets in both 2014 and 2015 with a corresponding lower basis
for depreciation partially offset the increase.  Depreciation, amortisation and net impairment losses increased by
40% in 2014 compared to 2013, mainly due to impairment losses related to
Statoil’s international operations, primarily driven by reduced short-term oil
price forecasts. Also, new investments, higher production and increased asset
retirement obligation, with a corresponding higher basis for depreciation,
partly offset by increased estimates of proved reserves, added to increased
depreciation costs in 2014 compared to 2013.  Exploration
  expenses
 For the year ended 31 December(in NOK
  billion)
 2015
 2014
 2013
 15-14 change
 14-13 changeExploration expenditures
  (activity)
 23.1
 23.9
 21.8
 (3%)
 10%Expensed, previously
  capitalised exploration expenditures
 1.7
 2.4
 1.9
 (28%)
 26%Capitalised share of
  current period's exploration activity
 (9.2)
 (7.3)
 (6.9)
 27%
 6%Impairments, net of
  reversals
 15.4
 11.3
 1.2
 36%
 >100%Exploration expenses
 31.0
 30.3
 18.0
 2%
 69%
  In 2015,exploration expenseswere
NOK 31.0 billion, a 2% increase compared to 2014 when exploration expenses were
NOK 30.3 billion. In 2013, exploration
expenses were NOK 18.0 billion  Statoil, Annual Report on Form 20-F
201575


---

Exploration
expenses were up 2% in 2015 mainly due to the USD/NOK exchange rate development
and increased impairment of exploration prospects and signature bonuses in 2015.
A lower level of drilling activity, a higher capitalisation rate and a lower
portion of previously capitalised expenditures being expensed in 2015,
partially offset the increase.  The increase in
exploration expenses in 2014 compared to 2013 was mainly due to increased
impairments of exploration prospects and signature bonuses internationally. Also,
the cancellation of a rig contract in 2014 impacted exploration expenses
negatively in 2014 compared to 2013.  As a result of the factors explained above,net operating incomewas NOK 14.9 billion in 2015, compared to NOK 109.5 billion in 2014. In 2013,
net operating income was NOK 155.5 billion.  Net financial itemswere negative NOK 10.6
billion in 2015, compared to NOK 0.0 billion in 2014 and negative NOK 17.0
billion in 2013. The decrease in 2015 was mainly related to loss of NOK 3.8
billion on derivatives related to the long term debt portfolio in 2015,
compared to a gain of NOK 5.8 billion in 2014, mainly due to changes in the
interest yield curves.  In 2014, net financial
items improved from negative NOK 17.0 billion in 2013 to NOK 0.0 billion mainly
due to a positive change in currency derivatives used for currency and liquidity
risk management as a result of changes in underlying currency positions and
strengthening of USD towards NOK of 22.2% in 2014 compared to a strengthening
of USD towards NOK of 9.3% in 2013. The improvement in 2014 also reflected a
positive change on interest rate swap positions related to interest rate
management of non-current bonds mainly due to decreased long term USD interest
rates by an average of 0.6%-points in 2014 compared to an increase in 2013 by
an average of 1.0%-points. These positive changes were partially offset by
increased interest and other finance expenses in 2014.  Income taxeswere NOK 41.6 billion in
2015,equivalent
to an effective tax rate of more than 100%, compared to NOK 87.4 billion,
equivalent to an effective tax rate of 79.9% in 2014. In 2013, income taxes
were NOK 99.2 billion, equivalent to an effective tax rate of 71.7%.  In 2015, aggregated accounting losses were recognised in countries
with higher than average tax rates, hence the “weighted average statutory tax
rate” was negative. Theeffective tax ratein 2015 was primarily
influenced by losses, mainly caused by impairments recognised in countries
where deferred tax assets could not be recognised (NOK 23.5 billion), partially
offset by tax exempted gains on sale of assets including Statoil’s interest in
the Shah Deniz project (NOK 3.7 billion) and the tax effect of foreign exchange
losses in entities that are taxable in other currencies than the functional
currency (NOK 5.8 billion). These losses are tax deductible, but do not impact
the Consolidated statement of income. Furthermore, the effective tax rate in
2015 was influenced by the de-recognition of deferred tax assets within the
Development and Production International segment, due to uncertainty related to
future taxable income (NOK 4.7 billion), as described in Note 9Income taxesto the Consolidated financial statements.  The effective tax rate in
2014 was primarily influenced by losses, mainly caused by impairments,
recognised in countries where deferred tax assets could not be recognised (NOK
12.1 billion), partially offset by tax exempted gains on sale of assets
including Norwegian continental shelf (NCS) and Statoil’s interest in the Shah
Deniz project (NOK 6.2 billion) and the tax effect of foreign exchange losses
in entities that are taxable in other currencies than the functional currency
(NOK 5.1 billion). These losses are tax deductible, but do not impact the
Consolidated statement of income. The effective tax rate in 2014 was also
influenced by the recognition of a non-cash tax income (NOK 2.0 billion)
following a verdict in the Norwegian Supreme Court in February 2014. The
Supreme Court voted in favour of Statoil in a tax dispute regarding the tax
treatment of foreign exploration expenditures.  The effective tax rate is calculated
as income taxes divided by income before taxes. Fluctuations in the effective
tax rates from year to year are principally the result of non-taxable items
(permanent differences) and changes in the relative composition of income
between Norwegian oil and gas production, taxed at a marginal rate of 78%, and
income from other tax jurisdictions. Other Norwegian income, including the
onshore portion of net financial items, is taxed at 27% (28% in 2013), and
income in other countries is taxed at the applicable income tax rates in those
countries.  In 2015,net incomewas negative
NOK 37.3 billion compared to positive NOK 22.0 billion in 2014 and NOK 39.2
billion in 2013.  The significant decrease
from 2014 to 2015 was mainly due to the drop in prices, leading to lower
earnings and impairment losses. Increased losses on net financial items related
to derivatives added to the decrease, which was partially offset by the
reduction in income taxes.  The 44% decrease in net
income from 2013 to 2014 was mainly due to lower prices, resulting in reduced
earnings and impairment losses. Increased exploration expenditures added to the
decrease, whilst lower income taxes partially offset the decrease.  The board of directors
proposes a dividend of USD 0.2201 per share for the fourth quarter 2015 and the
introduction of a two-year scrip dividend programme starting from the fourth
quarter 2015, subject to approval at the annual general meeting in line with
the authorisation from May 2015. The scrip programme will give shareholders the
option to receive quarterly dividends in cash or in newly issued shares in
Statoil, at a 5% discount for the fourth quarter 2015. The Norwegian
Government, as majority shareholder, supports the proposal and will seek the
Norwegian Parliament’s approval to vote in favour of the proposal at the annual
general meeting. The Norwegian government will match subscription of shares by
minority shareholders, and thereby maintain its ownership share at 67%
throughout the programme.See section 6.1Dividend policyfor more information.  Annual ordinary dividends
for 2015 amounted to an aggregate total of NOK 23.5 billion. Annual ordinary
dividends amounted to an aggregate total of NOK 22.9 billion and NOK 22.3
billion in 2014 and 2013, respectively. 76Statoil, Annual Report on Form 20-F 2015


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In 2014, following a
regular review process of Statoil’s 2012 Consolidated financial statements, the
Financial Supervisory Authority of Norway (the FSA), concluded that it had
identified three errors related to interpretation and application of IFRS
accounting principles for determination of cash generating units (CGUs) and impairment
evaluations. For two of the matters, Statoil accepted the FSA’s interpretations
and has applied such interpretations in preparing the Consolidated financial
statements. Statoil did not restate prior period financial statements as the
impact was immaterial. For the third matter, Statoil does not accept the FSA’s
conclusion. In accordance with due process for such matters under Norwegian
regulation, Statoil has appealed the order to the Norwegian Ministry of Finance,
and has been granted a stay in carrying out the FSA’s order pending the final
outcome of the appeal. See note 23Other
commitments, contingent liabilities and contingent assetsto the Consolidated
financial statements for further details.  With effect from first
quarter of 2016, Statoil will change to USD as presentation currency. The
change reflects the company`s underlying exposure to the USD as well as better
alignment of its reporting to peers.  Statoil, Annual Report on Form 20-F
201577


---

4.1.3
Segment performance and analysis  Internal transactions in oil and gas volumes
occur between our reporting segments before being sold in the market. The
pricing policy for internal transfers is based on estimated market prices.  We eliminate intercompany sales when
combining the results of reporting segments. Intercompany sales include transactions
recorded in connection with our oil and natural gas production in DPN or DPI
and also in connection with the sale, transportation or refining of our oil and
natural gas production in MMP.  DPN produces
oil and natural gas which is sold internally to MMP. A large share of the oil
produced by DPI is also sold from MMP. The remaining oil and gas from DPI is
sold directly in the market. For intercompany sales and purchases, Statoil has
established a market-based transfer pricing methodology for the oil and natural
gas that meets the requirements as to applicable laws and regulations.  Effective from
the fourth quarter of 2013, revenues generated by the upstream segment in the
United States are reported net of royalty interest. This change does not result
in a change in net operating income. Historical information has been aligned to
the current presentation, reflected in the following tables.  In 2015, the
average transfer price for natural gas was NOK 1.58 per scm. The average
transfer price was NOK 1.57 per scm in 2014 and NOK 1.92 in 2013. For oil
sold from DPN to MMP, the transfer price is the applicable market-reflective
price minus a cost recovery rate.  The following
table shows certain financial information for the four reporting segments,
including intercompany eliminations for each of the years in the three-year period
ending 31 December 2015. For additional information please refer to note 3Segmentsto the Consolidated financial statements.  For the year ended 31 December(in NOK billion)
 2015
 2014
 2013Development &
  Production NorwayTotal revenues and other
  income
 139.5
 182.2
 202.2Net operating income
 57.6
 111.7
 137.1Non-current segment
  assets1)
 244.1
 262.0
 247.6Development &
  Production InternationalTotal revenues and other
  income
 68.4
 85.2
 81.9Net operating income
 (66.9)
 (19.5)
 16.4Non-current segment
  assets1)
 330.1
 333.8
 286.5Marketing, Midstream and
  ProcessingTotal revenues and other
  income
 467.4
 597.3
 608.6Net operating income
 23.7
 16.2
 2.6Non-current segment
  assets1)
 49.2
 46.3
 39.3OtherTotal revenues and other
  income
 3.2
 0.3
 1.0Net operating income
 (0.8)
 (1.5)
 (1.1)Non-current segment
  assets1)
 6.1
 5.1
 5.6Eliminations2)Total revenues and other
  income
 (195.7)
 (242.3)
 (259.1)Net operating income
 1.2
 2.6
 0.4Non-current segment
  assets1)
 -
 -
 -Statoil groupTotal revenues and other
  income
 482.8
 622.7
 634.5Net operating income
 14.9
 109.5
 155.5Non-current segment
  assets1)
 629.5
 647.3
 578.91)
 Deferred tax assets,
  pension assets, equity accounted investments and non-current financial
  instruments are not allocated to segments.2)
 Includes elimination of
  inter-segment sales and related unrealised profits, mainly from the sale of
  crude oil and products.
  Inter-segment revenues
  are based upon estimated market prices.
 78Statoil, Annual Report on Form 20-F 2015


---

Statoil, Annual Report on Form 20-F
201579


---

The following tables show total revenues by geographic area.  2015
  Total revenues and other income by geographic area
 Crude oil
 Gas
 NGL
 Refined
  products
 Other
 Total sales(in NOK
  billion)Norway
 182.4
 86.9
 39.8
 45.4
 15.7
 370.1US
 29.9
 9.1
 4.3
 12.8
 7.7
 63.8Sweden
 0.0
 0.0
 0.0
 14.2
 1.0
 15.2Denmark
 0.0
 0.0
 0.0
 14.1
 0.1
 14.1Other
 10.8
 3.6
 0.1
 0.0
 5.4
 19.8Total revenues
  (excluding net income (loss)
  from equity accounted
  investments) and other income
 223.1
 99.6
 44.2
 86.5
 29.8
 483.1
  2014
  Total revenues and other income by geographic area
 Crude oil
 Gas
 NGL
 Refined
  products
 Other
 Total sales(in NOK
  billion)Norway
 256.2
 81.0
 55.0
 54.4
 18.7
 465.3US
 49.9
 13.8
 4.0
 14.8
 8.6
 91.2Sweden
 0.0
 0.0
 0.0
 16.5
 1.7
 18.2Denmark
 0.0
 0.0
 0.0
 19.1
 0.2
 19.3Other
 18.6
 4.4
 0.4
 0.0
 5.4
 28.8Total revenues
  (excluding net income (loss)
  from equity accounted
  investments and other income
 324.6
 99.3
 59.5
 104.8
 34.7
 622.9
  2013
  Total revenues and other income by geographic area
 Crude oil
 Gas
 NGL
 Refined
  products
 Other
 Total sales(in NOK
  billion)Norway
 238.0
 92.7
 61.7
 69.5
 14.0
 475.9US
 62.9
 13.5
 2.5
 10.9
 4.7
 94.5Sweden
 0.0
 0.0
 0.0
 17.2
 (0.1)
 17.1Denmark
 0.0
 0.0
 0.0
 21.3
 0.1
 21.4Other
 20.6
 4.2
 0.3
 0.0
 0.4
 25.5Total revenues
  (excluding net income (loss)
  from equity accounted
  investments and other income
 321.5
 110.4
 64.5
 118.9
 19.1
 634.4
  80Statoil, Annual Report on Form 20-F 2015


---

4.1.4
DPN profit and loss analysis  DPN net operating income was NOK 57.6 billion,
down 48% compared to 2014 mainly driven by the drop in liquids prices and
increased net impairment charges. Production of liquids and gas was up 3.9%.  The average
daily production of liquids and gas(see section9 Terms
and definitions) was 1,232 mboe, 1,183 mboe and 1,217 mboe per day in 2015, 2014
and 2013, respectively.  The average daily total
production of liquids and gas increased by 4% from 2014 to 2015, mainly due to
ramp up of new fields, increased gas sales and good operational performance,
partly offset by expected natural decline and divestments.  The average daily
production of liquids and gas decreased by 3% from 2013 to 2014. This decrease
was mainly due to expected natural decline and divestments, partially offset by
new fields in production and higher production regularity in 2014 compared to
2013.  Over time, the volumes
lifted and sold will equal entitlement production, but may be higher or lower
in any period due to differences between the capacities and timing of the
vessels lifting the volumes and the actual entitlement production during the
period. See section9Terms and definitionsfor more
information.  Income
  statement under IFRS
 For the year ended 31 December(in NOK
  billion)
 2015
 2014
 2013
 15-14 change
 14-13 changeRevenues
 138.1
 175.3
 188.9
 (21%)
 (7%)Net income from equity
  accounted investments
 0.0
 0.1
 0.1
 (62%)
 18%Other income
 1.4
 6.8
 13.2
 (79%)
 (48%)Total revenues and other
  income
 139.5
 182.2
 202.2
 (23%)
 (10%)Operating expenses and
  selling, general and administrative expenses
 (25.8)
 (25.2)
 (27.4)
 3%
 (8%)Depreciation,
  amortisation and net impairment losses
 (51.4)
 (40.0)
 (32.2)
 29%
 24%Exploration expenses
 (4.6)
 (5.4)
 (5.5)
 (14%)
 (2%)Net operating income
 57.6
 111.7
 137.1
 (48%)
 (19%)
  Total revenues and other incomewere NOK 139.5 billion in 2015, NOK 182.2
billion in 2014 and NOK 202.2 billion in 2013.  The 21% decrease inrevenuesfrom 2014 to 2015 was mainly due to reduced liquids prices. This was partly
offset by a positive exchange rate development (NOK/USD), increased lifted
volumes and increased gas prices. In addition, in 2015 a re-assessed valuation
estimate of earn-out derivatives resulted in an unrealised fair value loss on
derivatives and impacted revenues negatively.  The 7% decrease inrevenuesfrom 2013 to 2014 was mainly due to reduced gas and liquids prices and reduced
lifted volumes of both liquids and gas, mainly caused by divestments and
expected natural decline. This was partly offset by a positive exchange rate
development (NOK/USD). In 2013, a re-assessed valuation estimate of earn-out
derivatives resulted in an unrealised fair value loss on derivatives and
impacted revenues negatively.  Other income in 2015 was impacted by gains from the sale of certain
ownership interest on the NCS to Repsol of NOK 1.2 billion. Other income in
2014 was impacted by gains from the sale of certain ownership interests on the
NCS to Wintershall of NOK 5.9 billion. Other income in 2013 was impacted by
gains from sale of certain ownership interests on the NCS to OMV and
Wintershall (NOK 13.0 billion).  As a result of the factors explained above, total revenues and
other income decreased by 23% and 10% in 2015 and 2014, respectively.  Operating expenses and
selling, general and administrative expenseswere NOK 25.8 billion in
2015, compared to NOK 25.2 billion in 2014 and NOK 27.4 billion in 2013. In
2015, expenses increased compared to 2014 mainly due to gain related to changes
in pension scheme in 2014 and ramp up of new field during 2015. This waspartly offset by cost
improvements and reduced turnaround activity level on several fields. In 2014
expenses decreased compared to 2013 mainly due to a gain related to changes in
pension scheme and reduced operating costs at several fields due to divestments.
This was partly offset by increased environmental tax expenses, operating
preparations for new fields coming on stream and new fields commencing
production during 2014.  Depreciation, amortisation
and net impairment losseswere NOK 51.4 billion in 2015, compared to NOK 40.0 billion in
2014 and NOK 32.2 billion in 2013. The increase of 29% from 2014 to 2015 was
mainly due to a net impairment loss of NOK 8.6 billion in 2015 (primarily
resulting from the reduced oil price forecast), new fields commencing
production and ramp-up of new fields in 2015.The increase from 2013 to 2014 Statoil, Annual Report on Form 20-F
201581


---

was mainly due to increased investments, new fields
commencing production, increased asset retirement obligation with a
corresponding higher basis for depreciations and an impairment loss. These
effects were partly offset by reduced depreciation due to portfolio changes.  Exploration expenseswere NOK 4.6 billion in
2015, compared to NOK 5.4 billion in 2014 and NOK 5.5 billion in 2013. The
reduction from 2014 to 2015 was mainly due to lower drilling activity,a lower portion of
previously capitalised exploration expenditures being expensed in 2015, and
idle rig costs in 2014.The reduction from 2013 to 2014 was mainly due to lower drilling
activity and less field development work due to sanctioning of Johan Sverdrup,
offset by a higher portion of exploration expenditures capitalised in previous
periods being expensed in 2014.  Net operating incomein 2015 was NOK 57.6
billion, compared to NOK 111.7 billion in 2014 and NOK 137.1 billion in 2013.
The NOK 54.0 billion decrease from 2014 to 2015 was mainly due to lower prices
on liquids and increased depreciation and net impairment losses. The NOK 25.4
billion decrease from 2013 to 2014 was mainly due to lower prices on liquids
and gas and increased depreciation and net impairment losses.  4.1.5 DPI profit and loss analysis  DPI results in 2015 were heavily impacted by
lower prices and impairment losses. DPI delivered 6% growth in entitlement
production, averaging 580 mboe per day.  The average
daily equity liquidsand gas production (see section9Terms and definitions)was 739 mboe in 2015,
compared to 744 mboe in 2014 and 723 mboe in 2013. The decrease of 0.7% from
2014 to 2015 was driven primarily by the effect of the divestment of Shah Deniz
(Azerbaijan) and a portion of Marcellus (US), and natural decline, primarily at
mature fields in Angola. The decrease was partly offset by the ramp-up of
fields, mainly CLOV (Angola) and Jack/St. Malo (US).  The increase of 3% from
2013 to 2014 was driven primarily by the ramp-up of fields, including Marcellus
(US), CLOV and PSVM (Angola). The increase was partly offset by natural
decline, primarily at mature fields in Angola, and the effect of the farm-down
of Shah Deniz (Azerbaijan).  The average
daily entitlement production of liquids and gas(see section9Terms and definitions)was 580 mboe per day in 2015,
compared to 546 mboe per day in 2014 and 502 mboe per day in 2013. Entitlement
production in 2015 was up by 6% due to the benefit of lower effect from production
sharing agreements (PSA effect), mainly driven by the decrease in prices. The
increase from 2013 to 2014 was driven by increased equity production as
described above and a relatively lower PSA effect. The PSA effect was 116 mboe,
157 mboe and 182 mboe per day in 2015, 2014 and 2013, respectively.  Over time, the volumes
lifted and sold will equal our entitlement production, but they may be higher
or lower in any period due to differences between the capacity and timing of
the vessels lifting our volumes and the actual entitlement production during the
period. See section9Terms and definitionsfor more
information.  Income
  statement under IFRS
 For the year ended 31 December(in NOK billion)
 2015
 2014
 2013
 15-14 change
 14-13 changeRevenues
 57.0
 80.2
 78.1
 (29%)
 3%Net income from equity
  accounted investments
 (0.8)
 (0.8)
 (0.0)
 1%
 >100%Other income
 12.2
 5.8
 3.9
 >100%
 50%Total revenues and other
  income
 68.4
 85.2
 81.9
 (20%)
 4%Purchases [net of
  inventory]
 (0.1)
 (0.0)
 (0.1)
 >100%
 (85%)Operating expenses and
  selling, general and administrative expenses
 (27.3)
 (22.9)
 (21.0)
 19%
 9%Depreciation,
  amortisation and net impairment losses
 (81.6)
 (56.8)
 (31.9)
 44%
 78%Exploration expenses
 (26.3)
 (25.0)
 (12.5)
 6%
 100%Net operating income
 (66.9)
 (19.5)
 16.4
 >100%
 >(100%)
  DPI generatedtotal
revenues and other incomeof NOK 68.4 billion in 2015
compared to NOK 85.2 billion in 2014 and NOK 81.9 billion in 2013.  Revenuesin 2015 were negatively impacted by lower realised liquids and
gas prices, partly offset by a positive currency effect from the NOK/USD
development and an increase in lifted volumes. In addition, higher provisions
relating to commercial disputes in 2015 compared to 2014 added to the decrease
in total revenues. The increase from 2013 to 2014 was mainly caused by an
increase in lifted volumes. In addition, lower provisions relating to
commercial disputes in 2014 compared to 2013 positively impacted revenues. The
increase was partly offset by lower realised liquids and gas prices, partly
offset by a positive currency effect from the NOK/USD development.  82Statoil, Annual Report on Form 20-F 2015


---

Other incomein 2015 was positively
impacted by gains from sales of assets of NOK 12.2 billion in 2015 and NOK 5.8
billion in 2014, related primarily to the sale of ownership interest in the
Shah Deniz project and the South Caucasus Pipeline. Other income in 2014 was
also positively impacted by increased gains from sales of assets of NOK 2.3
billion.  As a result of the factors explained above, total revenues and
other income decreased by 20% in 2015. In 2014, total revenues and other income
increased by 4%.  Operating expenses and selling, general and administrative
expenseswere NOK 27.3 billion in 2015, compared to NOK 22.9 billion in
2014 and NOK 21.0 billion in 2013. The 19% increase from 2014 to 2015 was
mainly due to the currency effect from the NOK/USD development. Production
ramp-up on CLOV in Angola and start-up of the new fields Jack/St Malo in the US
in 2014 added to the increase. Reduced operations and maintenance costs, lower
royalties caused by lower prices and portfolio changes partially offset the
increase. Excluding the USD/NOK exchange rate development, operating expenses
and selling, general and administrative expenses decreased by 6%. The 9%
increase from 2013 to 2014 was mainly due to higher operating and
transportation expenses caused by production growth, primarily in North
America. In addition, operating expenses increased due to the start-up of CLOV
in 2014.  Depreciation, amortisation and net impairment losseswere NOK 81.6 billion in
2015, compared to NOK 56.8 billion in 2014 and NOK 31.9 billion in 2013. The
44% increase from 2014 to 2015 was primarily caused by net impairment losses of
NOK 42.7 billion in 2015, mainly related to unconventional onshore assets in
North America and certain conventional upstream assets within the DPI reporting
segment. The impairment losses resulted primarily from reduced short-term
forward prices in combination with reduced long-term oil price forecasts. In
addition, depreciation increased due to the NOK/USD development and higher production
from start-up and ramp-up on various fields (CLOV, Jack/St Malo). The increases
were partly offset by effect from net impairments in 2014 and 2015 and reduced
depreciation from higher reserves estimates.  The 78% increase from 2013 to 2014 was mainly due to net impairment
losses of NOK 23.8 billion in 2014, mainly related to the Kai Kos Dehseh oil
sands project in Canada, unconventional onshore assets in North America and
certain conventional upstream assets within the DPI reporting segment. The
impairment losses were primarily resulting from reduced short-term oil price
forecast. In addition, depreciation increased due to start-up and ramp-up of
production from various fields (CLOV, PSVM, Eagle Ford and Bakken). The
increases were partly offset by reduced depreciation from increased reserves
and divestment of assets. Exploration expenseswereNOK 26.3 billion in 2015, compared to NOK 25.0 billion in 2014 and
NOK 12.5 billion in 2013. The increase from 2014 to 2015 was mainly due to
increased impairments of oil and gas prospects in the Gulf of Mexico, partly
offset by a higher portion of exploration expenditure being capitalised in
2015.  Exploration expenses increased by NOK 12.5 billion from 2013 to
2014, primarily due to increased impairments of oil and gas prospects and
signature bonuses and write-offs of exploration expenditures, mainly in Angola
and the Gulf of Mexico. Also, the cancellation of a rig contract in 2014
impacted exploration expenses negatively in 2014.  Net operating incomein 2015 was negative NOK 66.9 billion, compared to negative NOK
19.5 billion in 2014 and positive NOK 16.4 billion in 2013. The negative
development from 2014 to 2015 was caused primarily by lower realised liquids
and gas prices and impairment losses, and also by higher depreciations and
higher operating expenses. The decrease from 2013 to 2014 was caused primarily
by impairment losses, and also by lower realised liquids and gas prices, higher
depreciations and higher operating expenses.  Statoil, Annual Report on Form 20-F
201583


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4.1.6
MMP profit and loss analysis  The 2015 results for MMP have been influenced byimproved refining margins, solid liquids trading results and
reversal of impairment losses from previous periods. The results were
negatively impacted by lower margins for the European gas sales.   
 Total natural gas sales volumes were 52.6 bcm in 2015
(1.86 tcf), 51.2 bcm in 2014 (1.80 tcf) and 56.6 bcm (2.00 tcf) in 2013. The 3%
increase in total gas volumes sold from 2014 to 2015 was related to higher
entitlement production on the NCS in addition to higher third party volumes in
Europe, partially offset by lower entitlement production internationally and
lower third party volumes in the US. The 9% decrease in gas volumes sold from
2013 to 2014 was mainly related to lower third party volumes primarily in the
US, and lower entitlement production on the NCS.  Third party natural gas sales volumes, as presented in the
chart do not include volumes sold on behalf of the Norwegian State's direct
financial interest (SDFI). MMP sold 37.2, 33.4 bcm and 35.0 bcm of NCS gas on
behalf of SDFI in 2015, 2014 and 2013, respectively.  In 2015, the average invoiced natural gas sales price in
Europe was NOK 2.16 per scm compared to NOK 2.28 per scm in 2014, a decrease of
5% mainly due to higher share of gas indexation in the gas contract portfolio
and effect from drop in oil product prices on oil indexed contracts. LNG has a
positive contribution on the European Gas price but less in 2015 as the LNG
prices decreased by 23% from 2014 to 2015. The average invoiced natural gas
sales price in Europe was approximately 7% lower in 2014 than in 2013, mainly
due to general decrease in gas market prices partially offset by improved price
premium vs. gas market prices in our gas contract portfolio. In 2015, the
average invoiced natural gas sales price in North Americas was NOK 0.80 per scm
compared to NOK 1.04 per scm in 2014, a decrease of 23% mainly due to a
generally weaker gas market partially offset by USD/NOK exchange rate
development. The average invoiced natural gas sales price in North Americas was
approximately 25% higher in 2014 than in 2013, mainly due to high market prices
in first quarter 2014 as a result of exceptionally cold weather in North East
combined with long term pipeline capacity agreements enabling access to premium
markets in Toronto and Manhattan.  All of Statoil's gas produced on the NCS is sold by MMP,
purchased from DPN at a market-based internal price reduced by a cost cover
element. Our average internal purchase price for gas was NOK 1.58 per scm in
2015, up 1% from NOK 1.57 per scm in 2014. Reduction in the market-based prices
is offset by decreased cost element from 2014 to 2015.  
 Average crude, condensate and NGL sales were 2.3 mmbbl
per day in 2015 of which approximately 1.07 mmbbl were sales of our equity
volumes, 0.79 mmbbl sales of third-party volumes and 0.41 mmbbl sales of
volumes purchased from SDFI. Our average sales volume was 2.2 mmbbl per day in
2014 and 2013. The average daily third-party volumes sold were 0.83 mmbbl in
2014 and 2013.  MMP’s refining margin remained at a high level throughout
2015 reflecting lower crude oil prices and a strong demand for gasoline both in
the US and China, while demand in Europe stopped falling. The outlook is that
margins will continue to depend on gasoline markets with anticipated further
growth in demand in Asia and with limited global capacity additions. Increasing
global diesel demand, however, is offset by even higher production capacity.
Statoil's refining reference margin was 8.0 USD/bbl in 2015, compared to 4.7
USD/bbl in 2014, an increase of 70%. The refining reference margin was 4.1
USD/bbl in 2013. 84Statoil, Annual Report on Form 20-F 2015


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Income statement under IFRS
 For the year ended 31 December(in NOK
  billion)
 2015
 2014
 2013
 15-14 change
 14-13 change(restated)
 (restated)Revenues
 465.3
 593.0
 607.7
 (22%)
 (2%)Net income from equity accounted
  investments
 0.4
 0.5
 0.1
 (6%)
 >100%Other income
 1.7
 3.8
 0.7
 (55%)
 >100%Total revenues and other
  income
 467.4
 597.3
 608.6
 (22%)
 (2%)Purchases [net of
  inventory]
 (406.5)
 (544.2)
 (565.2)
 (25%)
 (4%)Operating expenses and
  selling, general and administrative expenses
 (37.6)
 (33.2)
 (33.7)
 13%
 (2%)Depreciation,
  amortisation and net impairment losses
 0.4
 (3.6)
 (7.0)
 >(100%)
 (48%)Net operating income
 23.7
 16.2
 2.6
 47%
 >100%
  
 Total revenues and other
incomewere NOK 467.4
billion in 2015, compared to NOK 597.3 billion in 2014 and NOK 608.6 billion in
2013.  The
decrease in revenues from 2014 to 2015 was mainly due to decrease in crude and
gas prices, partially offset by higher volumes for crude, other oil products
and gas sold. The average crude price in USD declined by approximately 47% in
2015 compared to 2014, partially offset by weakening USD/NOK average daily
exchange rate by approximately 28% in 2015. Revenues in 2015 were positively impacted
by gains from derivatives, mainly due to significant drop in the forward curve
in the oil and gas market.  The
decrease in revenues from 2013 to 2014 was mainly due to decrease in gas and
crude prices plus lower volumes of gas sold. The average crude price in USD
declined by approximately 9% in 2014 compared to 2013, partially offset by
weakening USD/NOK average daily exchange rate by approximately 7% in 2014.
Revenues in 2014 were positively impacted by gains from derivatives, mainly due
to significant drop in the forward curve in the oil market.  Other incomein 2015 was positively impacted by
gain on sale of assets of NOK 1.7 billion. In 2014, other income was positively
impacted by the Sonatrach Arbitration Settlement of NOK 2.8 billion, following
an arbitration ruling in Statoil’s favour.  As a result of the factors explained above, total revenues and
other income decreased by 22% and 2% in 2015 and 2014, respectively.  Purchases [net of inventory]were NOK 406.5 billion in 2015,
compared to NOK 544.2 billion in 2014 and NOK 565.2 billion in 2013. The
decrease from 2014 to 2015 was mainly due to decrease in crude and gas prices
and lower volumes of crude, other oil products and gas sold. The decrease from
2013 to 2014 was mainly due to decrease in gas and crude prices, lower volumes
of gas sold and losses on storages due to a significant price reduction.  Operating expenses and selling,
general and administrative expenseswere NOK 37.6 billion in 2015, compared to NOK 33.2 billion in 2014 and NOK
33.7 billion in 2013. The increase from 2014 to 2015 was mainly due to negative
USD/NOK currency effects and onerous contract provisions of NOK 1.6 billion in
2015. This was partially offset by cost reduction due to improvement
initiatives. Excluding the USD/NOK exchange rate development, operating
expenses and selling, general and administrative expenses were at the same
level as last year.  The
Cove Point onerous contract provision of NOK 4.1 billion influenced expenses in
2013. Excluding that item, 2014 figures would show an increase in expenses as
compared to 2013. The increase was mainly caused by increased activity in the
US in addition to negative NOK/USD currency effects.  Depreciation, amortisation and net
impairment lossesamounted to an income of NOK 0.4 billion in 2015, compared to losses of NOK 3.6
billion in 2014 and NOK 7.0 billion in 2013. The decrease in depreciation,
amortisation and net impairment losses from 2014 to 2015 was mainly caused by
net reversal of impairment charges of NOK 3.5 billion in 2015. The reversal of
impairment was triggered by increased refinery margins and operational
improvements. The decrease in depreciation, amortisation and net impairment
losses from 2013 to 2014 was mainly as a result of impairment losses of the
refineries made in 2013.  Net operating incomewas NOK 23.7 billion, NOK 16.2
billion, NOK 2.6 billion in 2015, 2014 and 2013, respectively. The increase of
NOK 7.5 billion from 2014 to 2015 was mainly due to higher refining margins and
solid liquids trading results in addition to negative USD/NOK foreign exchange
rate development and net reversal of impairment charges of NOK 3.5 billion,
These increases were partially offset by the Sonatrach Arbitration Settlement
of NOK 2.8 billion in 2014 in Statoil’s favour, and lower margins for the
European gas sales.  Statoil, Annual Report on Form 20-F
201585


---

The increase of NOK 13.6 billion from
2013 to 2014 was mainly due to lower impairment losses in 2014 compared to
2013, the Sonatrach Arbitration Settlement of NOK 2.8 billion in 2014 in
Statoil’s favour, the onerous contract provision related to Cove Point of NOK
4.1 billion in 2013, and improved margins on gas in Europe including LNG
arbitrage and stronger contribution from US gas sales due to an exceptionally cold
winter in the North East US. Further, net operating income increased due to
improved refining margins and increased result related to ownership in
infrastructure. These increases were partially offset by losses on operational
storages in 2014 due to reduced prices.  4.1.7 Other operations  The Other reporting segment includes activities
within New Energy Solutions; Global Strategy and Business Development;
Technology, Projects and Drilling; and Corporate staffs and support functions.  In 2015, the Other reporting segment recorded
a net operating loss of NOK 0.8 billion compared to a net operating loss of NOK
1.5 billion in 2014 and a net operating loss of NOK 1.1 billion in 2013.  86Statoil, Annual Report on Form 20-F 2015


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4.2
Liquidity and capital resources  We believe that our established liquidity reserves,
credit rating and access to capital markets provide us with sufficient working
capital for our foreseeable requirements.   4.2.1 Review of cash flows  Statoil`s cash flows in 2015 reflect a high
investment level, continued portfolio optimisation and issuance of new debt
resulting in a small decrease in cash and cash equivalents and increase in short-term
financial investments.  CONSOLIDATED STATEMENT
  OF CASH FLOWSFull year(in NOK
  billion)
 Note
 2015
 2014
 2013Income before tax
 
 4.3
 109.4
 138.4Depreciation,
  amortisation and net impairment losses
 11, 12
 133.8
 101.4
 72.4Exploration expenditures
  written off
 12
 17.1
 13.7
 3.1(Gains) losses on
  foreign currency transactions and balances
 
 (0.4)
 (3.1)
 4.8(Gains) losses from
  dispositions
 4
 (17.3)
 (12.4)
 (17.6)(Increase) decrease in
  other items related to operating activities
 
 19.8
 3.9
 6.6(Increase) decrease in
  net derivative financial instruments
 25
 9.2
 (2.8)
 11.7Interest received
 
 2.9
 2.1
 2.1Interest paid
 
 (3.6)
 (3.4)
 (2.5)Cash flows provided by
  operating activities before taxes paid and working capital items
 
 165.8
 208.8
 218.8Taxes paid
 
 (65.7)
 (96.6)
 (114.2)(Increase) decrease in
  working capital
 
 8.9
 14.2
 (3.3)Cash flows provided by
  operating activities
 
 109.0
 126.5
 101.3Additions through
  business combinations
 4
 (3.5)
 0.0
 0.0Capital expenditures and
  investments
 
 (124.7)
 (122.6)
 (114.9)(Increase) decrease in
  financial investments
 
 (19.8)
 (12.7)
 (23.2)(Increase) decrease in
  other non-current items
 
 (0.3)
 0.8
 0.6Proceeds from sale of
  assets and businesses
 4
 33.2
 22.6
 27.1Cash flows used in
  investing activities
 
 (115.1)
 (112.0)
 (110.4)New finance debt
 18
 32.2
 20.6
 62.8Repayment of finance
  debt
 
 (11.4)
 (9.7)
 (7.3)Dividend paid
 17
 (22.9)
 (33.7)
 (21.5)Net current finance debt
  and other
 
 (5.5)
 (0.3)
 (7.3)Cash flows provided by
  (used in) financing activities
 
 (7.5)
 (23.1)
 26.6Net increase (decrease)
  in cash and cash equivalents
 
 (13.6)
 (8.6)
 17.5Effect of exchange rate
  changes on cash and cash equivalents
 
 7.1
 5.7
 2.9Cash and cash
  equivalents at the beginning of the period (net of overdraft)
 16
 82.4
 85.3
 64.9Cash and cash
  equivalents at the end of the period (net of overdraft)
 16
 75.9
 82.4
 85.3
 Statoil, Annual Report on Form 20-F
201587


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Cash flows provided by
operations The most significant drivers of cash flows
provided by operations were the level of production and prices for liquids and
natural gas that impact revenues, purchases [net of inventory], taxes paid and
changes in working capital items.  Cash flows provided by operating activitieswere NOK 109.0 billion in 2015 compared to NOK 126.5 billion in 2014,
which is a decrease of NOK 17.5 billion. Cash flows provided by operating
activities before taxes paid and working capital items were reduced by NOK 43.0
billion compared to 2014, driven by asignificant reduction in both liquids and gas prices measured in
NOK.The decrease was partially offset by positive changes in working
capital and lower taxes paid in 2015 compared to 2014.  Cash flows provided by operating activitieswere NOK 126.5 billion in 2014 compared to NOK 101.3 billion in 2013, an
increase of NOK 25.2 billion. Cash flows provided by operating activities
before taxes paid and working capital items were reduced by NOK 10.0 billion
compared to 2013, driven by decreased profitability mainly caused by lower
prices for liquids and European gas. The decrease was more than offset by
positive changes in working capital and lower taxes paid in 2014 compared to
2013.  Cash flows used
in investing activities Cash flows used in investing activitieswere NOK 115.1
billion in 2015 compared to NOK 112.0 billion in 2014, an increase of NOK 3.1
billion mainly due to increased capital expenditures, financial investments and
additions through business combinations, partially offset by higher proceeds
from sale of assets and businesses. The proceeds from sale of assets in 2015 of
NOK 33.2 billion were mainly related to the divestment of the remaining
interests in the Shah Deniz field and the South Caucasus pipeline, sale of office
buildings, sale of interest in the Marcellus onshore play, sale of interests in
Trans Adriatic pipeline AG and the sale of interests in licences on the NCS.  Cash flows used in investing activitieswere NOK 112.0
billion in 2014 compared to NOK 110.4 billion in 2013, an increase of NOK 1.6
billion mainly due to increased capital expenditures, partly offset by lower
investments in deposits with more than three months maturity. The proceeds from
sale of assets in 2014 of NOK 22.6 billion were mainly related to the
divestment of interests in the Shah Deniz field and the South Caucasus pipeline
and the sale of interests in licences on the NCS.  Cash flows
provided by (used in) financing activities Cash flows used in
financing activities were NOK 7.5 billion in 2015 and were mainly related to
payments of dividends NOK 22.9 and repayments of debt NOK 11.4, partially
offset by issuance of new debt of NOK 32.2 billion. Cash flows used in
financing activities were NOK 23.1 billion in 2014 and were mainly related to
payments of dividends and repayments of debt, partly offset by issuance of new
debt in November 2014 of NOK 20.6 billion. The amounts reported in 2013 were
influenced by debt issuances of NOK 62.8 billion in total.  4.2.2 Financial assets and debt  Statoil has a strong balance sheet and considerable financial
flexibility. The net debt ratio before adjustments was 25.6% at the end of
2015. Net interest-bearing debt before adjustments increased by NOK 32.8
billion in 2015 and was NOK 122.0 billion at the end of 2015.  Financial position and
liquidity Statoil's financial
position is strong although its net debt ratio before adjustments at year end
increased from 19.0% in 2014 to 25.6% in 2015. Net interest-bearing debt
increased from NOK 89.2 billion to NOK 122.0 billion. During 2015 Statoil's
total equity decreased from NOK 381.2 billion to NOK 355.1 billion, mainly due
to impairments recognised in 2015. Current level of net debt ratio is below
levels from previous periods of low prices. Cash flows provided by operating
activities were reduced in 2015 mainly due to lower prices and increased cash
flows used in investments. Statoil introduced USD as its dividend declaration
currency in the second quarter of 2015 announcement and has paid out four
quarterly dividends in 2015. For the fourth quarter of 2015 the board of
directorswill propose to the annual general meeting (AGM) to
maintain a dividend of USD 0.2201 per share for the fourth quarter 2015 and to introduce
a two-year scrip dividend programme starting from the fourth quarter 2015.For details see section 6.1.1
Dividends. Statoil
believes that, given its current liquidity reserves, including committed credit
facilities of USD 5.0 billion and its access to various capital markets,
Statoil will have sufficient capital available to meet its liquidity needs.  Funding needs
arise as a result of Statoil’s general business activity. Statoil generally
seek to establish financing at the corporate level. Project financing may be
used in cases involving joint ventures with other companies. Statoil aims to
have access at all times to a variety of funding sources in respect of markets
and instruments as well as maintaining relationships with a core group of
international banks that provide various kinds of banking services.  Statoil has credit ratings
from Moody's and Standard & Poor's (S&P). These ratings ensure
necessary predictability when it comes to funding access at attractive terms
and conditions. Our current long-term ratings are Aa2 and A+ from Moody's and S&P,
respectively. The S&P rating was revised from AA- on credit watch negative
to A+ with stable outlook on 22 February 2016. Moody’s placed Statoil and its
peers on review for downgrade on 22 January 2016. As of the date of this Annual
Report on Form 20-F, Moody`s review of Statoil’s rating had not yet concluded. Both
rating agency reviews have been triggered by low oil prices.The
short-term ratings are P-1 from Moody's and A-1 from S&P. In order to
maintain financial flexibility going forward, we intend to keep key financial
ratios at levels consistent with our objective of maintaining Statoil's
long-term credit rating at least within the single A category on a stand-alone
basis. 88Statoil, Annual Report on Form 20-F 2015


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The management
of financial assets and liabilities takes into consideration funding sources,
the maturity profile of non-current debt, interest rate risk, currency risk and
available liquid assets. Statoil’s borrowings are denominated in various
currencies and normally swapped into USD. In addition, interest rate
derivatives, primarily interest rate swaps are used, to manage the interest
rate risk of our long-term debt portfolio. The Group's central treasury unit
manages the funding and liquidity activities at Group level.  We have
diversified our cash investments across a range of financial instruments and
counterparties to avoid concentrating risk in any one type of investment or any
single country. As of 31 December 2015, approximately 6% of our liquid assets
were held in USD-denominated assets, 17% in NOK, 51% in EUR, 7% in DKK, 15% in
SEK, and 1% in GBP, before the effect of currency swaps and forward contracts.
Approximately 72% of our liquid assets were held in treasury bills and
commercial papers, 23% in time deposits, 3% in money market funds and 2% at
available bank deposits. As of 31 December 2015,approximately 3%of
our liquid assets were classified as restricted cash (including collateral
deposits).  Our general
policy is to keep a liquidity reserve in the form of cash and cash equivalents
or other current financial investments in our balance sheet, as well as
committed, unused credit facilities and credit lines in order to ensure that we
have sufficient financial resources to meet our short-term requirements.  Long-term
funding is raised when we identify a need for such financing based on our
business activities, cash flows and required financial flexibility or when
market conditions are considered to be favourable. Bond transactions were made in
2015 at very favourable terms, pre-funding longer-term commitments.  The group's
borrowing needs are usually covered through the issuing of short-, medium- and
long-term securities, including utilisation of a US Commercial Paper Programme
(programme limit USD 4.0 billion) and a Shelf Registration Statement
(unlimited) filed with the Securities and Exchange Commission (SEC) in the USA as
well as through issues under a Euro Medium-Term Note (EMTN) Programme (programme
limit updated to EUR 20.0 billion 5 February, 2016) listed on the London Stock
Exchange. Committed credit facilities and credit lines may also be utilised.
After the effect of currency swaps, the major part of our borrowings is in USD.  During 2015 Statoil issued bonds with
maturities from four to 20 years for a total amount of EUR 3.75 billion (NOK
32.1 billion). The bonds were issued in EUR and swapped into USD. All of the
bonds are unconditionally guaranteed by Statoil Petroleum AS. For more
information see
note 18Finance debt.  Statoil issued new debt securities in 2014 equivalent to NOK 20.5
billion and in 2013 equivalent to NOK 62.8 billion.  Financial indicatorsFinancial
  indicators
 For the year ended 31 December(in NOK
  billion)
 2015
 2014
 2013Gross interest-bearing
  financial liabilities1)
 284.5
 231.6
 182.5Net interest-bearing
  liabilities before adjustments
 122.0
 89.2
 58.0Net debt to capital
  employed ratio2)
 25.6%
 19.0%
 14.0%Net debt to capital
  employed ratio adjusted3)
 26.8%
 20.0%
 15.2%Cash and cash
  equivalents
 76.0
 83.1
 85.3Current financial
  investments
 86.5
 59.2
 39.2ROACE4)
 (8.0%)
 2.7%
 11.3%Ratio of earnings to
  fixed charges5)
 1.1
 9.4
 7.51)
 Defined as non-current
  and current finance debt.2)
 As calculated according
  to IFRS. Net debt to capital employed ratio is the net debt divided by
  capital employed. Net debt is interest-bearing debt less cash and cash
  equivalents and current financial investments. Capital employed is net debt,
  shareholders' equity and minority interest.3)
 In order to calculate
  the net debt to capital employed ratio adjusted, Statoil makes adjustments to
  capital employed as it would be reported under IFRS to adjust for project
  financing exposure that does not correlate to the underlying exposure and to
  add into the capital employed measure interest-bearing elements which are
  classified together with non-interest-bearing elements under IFRS. See
  section 4.4.2 Net debt to capital employed ratio below for a reconciliation
  of capital employed and a description of why Statoil makes use of this
  measure.4)
 ROACE is equal to net
  income adjusted for financial items after tax, divided by average capital
  employed over the last 12 months. See section 4.4.1 Return on average capital
  employed (ROACE) for a reconciliation of ROACE and a description of why
  Statoil makes use of this measure.5)
 Based on IFRS. For the
  purpose of these ratios, earnings consist of the income before (i) tax, (ii)
  minority interest, (iii) amortisation of capitalised interest and (iv) fixed
  charges (which have been adjusted for capitalised interest) and after
  adjustment for unremitted earnings from equity accounted entities. Fixed
  charges consist of interest (including capitalised interest) and estimated
  interest within operating leases.
  Gross
interest-bearing debt Statoil, Annual Report on Form 20-F
201589


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Gross
interest-bearing debt was NOK 284.5, NOK 231.6 billion and NOK 182.5 billion at
31 December 2015, 2014 and 2013, respectively. The NOK 52.9 billion increase
from 2014 to 2015 was due to an increase in non-current finance debt of NOK
58.9 billion, offset by a reduction in current finance debt of NOK 6.0 billion.
The NOK 49.0 billion increase from 2013 to 2014 was due to an increase in
current finance debt of NOK 9.4 billion and an increase in non-current finance
debt of NOK 39.6 billion. Our weighted average annual interest rate was 3.39%,
3.78% and 4.06% at 31 December 2015, 2014 and 2013, respectively. Our weighted
average maturity on finance debt was nine years at 31 December 2015, compared
to nine years at 
31 December 2014 and 10 years at 31 December 2013.  Net
interest-bearing debt Net interest-bearing debt
before adjustments were NOK 122.0 billion, NOK 89.2 billion and NOK 58.0
billion at 31 December 2015, 2014 and 2013, respectively. The increase of NOK 32.8
billion from 2014 to 2015 was mainly related to an increase in gross
interest-bearing debt of NOK 52.9 billion offset in part by an increase in cash
and cash equivalents and current financial investments of NOK 20.1 billion
mainly due to negative net cash flow in 2015. The increase of NOK 31.2 billion
from 2013 to 2014 was mainly related to an increase in gross interest-bearing
debt of NOK 49.0 billion offset in part by an increase in cash and cash
equivalents and current financial investments of NOK 17.9 billion.  The net debt to
capital employed ratio The net debt to capital
employed ratio before adjustments was 25.6%, 19.0% and 14.0% in 2015, 2014 and
2013 respectively.  The net debt to capital
employed ratio adjusted (non-GAAP financial measure, see footnote three above)
was 26.8%, 20.0% and 15.2% in 2015, 2014, and 2013, respectively. The 6.8
percentage points increase in net debt to capital employed ratio adjusted from
2014 to 2015 was related to the increase in net interest-bearing debt adjusted
of NOK 34.4 billion in combination with an increase in capital employed
adjusted of NOK 8.3 billion. The 4.8 percentage points increase in net debt to
capital employed ratio adjusted from 2013 to 2014 was related to an increase in
net interest-bearing debt adjusted of NOK 31.9 billion in combination with an
increase in capital employed adjusted of NOK 57.0 billion.  Cash, cash
equivalents and current financial investments Cash and cash equivalents
were NOK 76.0 billion, NOK 83.1 billion and NOK 85.3 billion at 31 December 2015,
2014 and 2013 respectively. See note 16Cash and cash
equivalentsto the Consolidated financial statements for information
concerning restricted cash. Current financial investments, which are part of
our liquidity management, amounted to NOK 86.5 billion, NOK 59.2 billion and
NOK 39.2 billion at 31 December 2015, 2014 and 2013, respectively.  4.2.3 Investments  Organic capital expenditures
(excluding acquisitions, capital leases and other investments with significant
different cash flow pattern) amounted to USD 14.7 billion, or NOK 118.8
billion, for the year ended 
31 December 2015.  Capital expenditures,
defined as additions to property, plant andequipment (including
capitalised financial leases), capitalised exploration expenditures, intangible
assets, long-term share investments and investments in equity accounted
companies, amounted to NOK 125.5 billion for the year ended 2015. The
capital expenditure level ended below original guidance due to reduced activity
level and increased efficiency. This was partly offset by the development in
the USDNOK exchange rate.  In 2014, capital expenditures
were NOK 125.1 billion compared to NOK 117.4 billion in 2013. The increase was
primarily related to higher activity level in Development and Production
International.  Organic capital
expenditures (excluding acquisitions, capital leases and other investments with
significant different cash flow pattern) amounted to NOK 118.8billion for the year ended 2015, or USD 14.7 billion.
In 2014, organic capital expenditures amounted to NOK 121.6 billion, or USD
19.6 billion.  The section describes our
estimated organic capital expenditure for 2016 relating to potential capital
expenditure requirements for the principal investment opportunities available
to us and other capital projects currently under consideration. The figure is
based on Statoil developing organically, and it excludes possible expenditures
relating to acquisitions. The expenditure estimates and descriptions of
investments in the segment descriptions below could therefore differ materially
from the actual expenditure. Organic capital expenditures are estimated to be
around USD 13 billion in 2016.  Statoil finances its capital
expenditures both internally and externally. For more information see section 4.2.2Financial assets and debt.  In Norway a substantial proportion of our 2016 capital
expenditures will be spent on ongoing development projects such as Johan
Sverdrup, Gina Krog and Aasta Hansteen, in addition to various extensions,
modifications and improvements on currently producing fields like Gullfaks,
Oseberg and Troll.  90Statoil, Annual Report on Form 20-F 2015


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Internationally
we currently estimate that a substantial proportion of our 2016 capital
expenditure will be spent on the following ongoing and planned development
projects: Mariner in UK and Julia, Stampede and Bakken in the US.  In midstream and downstream we currently
estimate that most of the 2016 capital expenditures will be spent on Polarled
and Johan Sverdrup export pipelines, in addition to processing and
transportation solutions related to Bakken, Marcellus and Eagle Ford in the US.  As illustrated in the
section 4.2.5Principal contractual
obligations,Statoil have committed to certain investments in the future. The
further into the future, the more flexibility we will have to revise
expenditure. This flexibility is partly dependent on the expenditure our
partners in joint ventures agree to commit to. A large part of the capital
expenditure for 2016 is committed.  Statoil may alter the
amount, timing or segmental or project allocation of our capital expenditures
in anticipation of or as a result of a number of factors outside our control.  Statoil, Annual Report on Form 20-F
201591


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4.2.4
Impact of reduced prices  Our results are affected by the development
in the price of raw materials and services that are necessary for the
development and operation of oil and gas producing assets.  Cost development in the prices of goods, raw
materials and services that are necessary for the development and operation of
oil and gas producing assets can vary considerably over time and between each
market segment.  The reduction in the oil price has been
driving a decrease in commodities prices. Prices in supplier markets have been
reduced and in several supplier market segmentsStatoil has achieved reduced rates compared to the 2013/2014 level. Such
savings have been achieved both in new and
renegotiated contracts.While some of the cost reductions relates to
capitalised expenditures and thus only affects our annual results through
decreased depreciation, certain elements of operating expenditures have also
been affected by this cost reduction.  See the analysis of profit and loss in
section 4.1 Operating
and financial review as well section 2.3 Group
Outlook.  4.2.5 Principal contractual obligations  The table summarises our principal
contractual obligations and other commercial commitments as of 
31December 2015.  The table includes contractual obligations,
but excludes derivatives and other hedging instruments as well as asset retirement
obligations, as these obligations for the most part are expected to lead to
cash disbursements more than five years in the future. Obligations payable by Statoil
to unconsolidated equity affiliates are included gross in the table. Where
Statoil includes both an ownership interest and the transport capacity cost for
a pipeline in the consolidated accounts, the amounts in the table include the
transport commitments that exceed Statoil's ownership share. See section 5.2.3 Disclosures
about market riskfor more information.  As at 31 December 2015Contractual
  obligations
 Payment due by period 1)(in NOK
  billion)
 Less than 1 year
 1-3 years
 3-5 years
 More than 5 years
 TotalUndiscounted non-current
  finance debt
 19.0
 72.0
 81.1
 207.5
 379.6Minimum operating lease
  payments
 25.6
 28.8
 17.6
 27.8
 99.8Nominal minimum other
  long-term commitments2)
 13.5
 24.6
 23.1
 77.9
 139.1Total contractual
  obligations
 58.1
 125.4
 121.8
 313.2
 618.51)
 "Less than 1
  year" represents 2015; "1-3 years" represents 2016 and 2017,
  "3-5 years" represents 2018 and 2019, while "More than 5
  years" includes amounts for later periods.2)
 For further information
  see note 23 Other commitments and contingencies to the Consolidated financial
  statements.
  Non-current finance debt
in the table represents principal payment obligations. For information on
interest commitments relating to long-term debt, reference is made to note 18Finance debtand note 22Leasesto the Consolidated financial statements.  Statoil had contractual commitments of NOK
62.3 billion at 31 December 2015. The contractual commitments reflect Statoil's
share and mainly comprise construction and acquisition of property, plant and
equipment.  Statoil’s projected
pension benefit obligation was NOK 60.1 billion, and the fair value of plan
assets amounted to NOK 45.2 billion as of 31 December 2015. Company
contributions are mainly related to employees in Norway. In 2014Statoil ASA
made a decision to change the company’s pension plan in Norway from a defined
benefit plan to a defined contribution plan. The actual transitioning to the
defined contribution plan took place in 2015, see note 19Pensionsto the Consolidated financial statements for more information.  92Statoil, Annual Report on Form 20-F 2015


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4.2.6
Off balance sheet arrangements  This section describes various agreements
that are not recognised in the balance sheet, such as operational leases and
transportation and processing capacity contracts.  We have entered into various agreements, such
as operational leases and transportation and processing capacity contracts,
that are not recognised in the balance sheet. For more information, see section
4.2.5 Principal
contractual obligationsand note 22 Leasesto the Consolidated financial statements.  Statoil is
party to certain guarantees, commitments and contingencies that, pursuant to
IFRS, are not necessarily recognised in the balance sheet as liabilities. See
note 23Other commitments and contingenciesto
the Consolidated financial statements for more information.  4.3 Accounting Standards (IFRS)  We prepare our Consolidated financial
statements in accordance with International Financial Reporting Standards
(IFRS) as adopted by the EU and as issued by the International Accounting
Standards Board.  We prepared
our first set of Consolidated financial statements pursuant to IFRS for 2007.
The IFRS standards have been applied consistently to all periods presented in
the Consolidated financial statements and when preparing an opening IFRS
balance sheet as of 1 January 2006 (subject to certain exemptions allowed by
IFRS 1) for the purpose of the transition to IFRS.  See note 2 Significant
accounting policiesto the Consolidated financial statements for a
discussion of key accounting estimates and judgements.  4.4
Non-GAAP measures  This
section describes the non-GAAP financial measures that are used in this report.  We are subject to SEC
regulations regarding the use of "non-GAAP financial measures" in
public disclosures. Non-GAAP financial measures are defined as numerical
measures that either exclude or include amounts that are not excluded or
included in the comparable measures calculated and presented in accordance with
generally accepted accounting principles, which in our case refers to IFRS.  The following financial
measures may be considered non-GAAP financial measures:  ·Return
on average capital employed (ROACE) ·Net
debt to capital employed ratio before adjustments ·Net
debt to capital employed ratio adjusted ·Organic
capital expenditures ·Production
cost per boe of entitlement volumes  For
information regarding Organic capital expenditures see section 4.2.3 Investments. For
information regarding Production cost per barrel of entitlement volumes see
note 27 Supplementary
oil and gas information (unaudited) to the Consolidated financial
statements.  4.4.1 Return on average capital employed
(ROACE)  We use ROACE to measure the return on capital
employed, regardless of whether the financing is through equity or debt.  In the group's view, this measure provides
useful information for both the group and investors about performance during
the period under evaluation. We make regular use of this measure to evaluate
our operations. Our use of ROACE should not be viewed as an alternative to
income before financial items, income taxes and minority interest, or to net
income, which are measures calculated in accordance with generally accepted
accounting principles or ratios based on these figures.  ROACE was
negative 8.0% in 2015 compared to 2.7% in 2014 and 11.3% in 2013. The decrease
from last year is due to the negative development in net income adjusted for
financial items, combined with an increase in average capital employed. Statoil, Annual Report on Form 20-F
201593


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Calculation of numerator and denominator
  used in ROACE calculation
 For the year ended 31 December(in NOK billion,
  except percentages)
 2015
 2014
 2013
 15-14 change
 14-13 changeNet income for the year
 (37.3)
 22.0
 39.2-Net financial items
 (10.6)
 (0.0)-Tax on financial items
 10.2
 9.2+Accretion expense net
  after tax
 (1.0)
 (1.1)+Net financial items
  adjusted after tax1)
 
 
 4.6Net income adjusted for
  financial Items after tax (A1)
 (37.9)
 11.8
 43.9
 >(100%)
 (73%)Capital employed before
  adjustments to net interest-bearing debt: 2)Year End 2015
 477.1Year End 2014
 470.4
 470.4Year End 2013
 
 414.0
 414.0Year End 2012
 
 
 359.2Sum of capital employed
  for two years (B1)
 947.5
 884.4
 773.2Calculated average
  capital employed:Average capital employed
  before adjustments to net interest-bearing debt (B1/2)
 473.8
 442.2
 386.6
 7%
 14%Calculated ROACE:Return on average
  capital employed (A1/(B1/2))
 (8.0%)
 2.7%
 11.3%
 >(100%)
 (77%)1)
 Calculation of financial
  items is revised for 2015 and 2014 ROACE definition. Net financial items
  after tax for 2013 includes financial items adjusted of negative NOK 4.6
  billion and tax on financial items of NOK 9.2 billion.2)
 Capital employed before
  adjustments for each year is reconciled in the table in the section 4.4.2 Net
  debt to capital employed ratio.
  94Statoil, Annual Report on Form 20-F 2015


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4.4.2
Net debt to capital employed ratio  In the Company's view, the calculated net
debt to capital employed ratio gives a more complete picture of the Group's current debt situation than gross
interest-bearing financial liabilities.  The calculation uses balance sheet items
relating to gross interest bearing financial liabilities and adjusts for cash,
cash equivalents and current financial investments. Certain adjustments are
made, since different legal entities in the Group lend to projects and others
borrow from banks. Project financing through an external bank or similar
institution will not be netted in the balance sheet and will over-report the
debt stated in the balance sheet in relation to the underlying exposure in the Group.
Similarly, certain net interest-bearing debts incurred from activities pursuant
to the Owners Instruction from the Norwegian State are set off against
receivables on the Norwegian State's direct financial interest (SDFI).  The net
interest-bearing debt adjusted for these two items is included in the average
capital employed.  The table
below reconciles the net interest-bearing liabilities adjusted, capital
employed and net debt to capital employed adjusted ratio with the most directly
comparable financial measure or measures calculated in accordance with IFRS.  For the year ended 31 DecemberCalculation
  of capital employed and net debt to capital employed ratio
 2015
 2014
 2013(in NOK
  billion, except percentages)Shareholders' equity
 354.7
 380.8
 355.5Non-controlling
  interests (Minority interest)
 0.3
 0.4
 0.5Total equity (A)
 355.1
 381.2
 356.0Current bonds, bank
  loans, commercial papers and collateral liabilities
 20.5
 26.5
 17.1Bonds, bank loans and
  finance lease liabilities
 264.0
 205.1
 165.5Gross interest-bearing
  financial liabilities (B)
 284.5
 231.6
 182.5Cash and cash
  equivalents
 76.0
 83.1
 85.3Current financial
  investments
 86.5
 59.2
 39.2Cash and cash
  equivalents and current financial investments (C)
 162.4
 142.3
 124.5Net interest-bearing
  liabilities before adjustments (B1) (B-C)
 122.0
 89.2
 58.0Other interest-bearing
  elements1)
 9.8
 8.0
 7.1Marketing instruction
  adjustment2)
 (1.9)
 (1.6)
 (1.3)Adjustment for project
  loan3)
 0.0
 (0.1)
 (0.2)Net interest-bearing
  liabilities adjusted (B2)
 129.9
 95.6
 63.6Calculation of capital
  employed:Capital employed before
  adjustments to net interest-bearing liabilities (A+B1)
 477.1
 470.4
 414.0Capital employed
  adjusted (A+B2)
 485.0
 476.7
 419.6Calculated net debt to
  capital employed:Net debt to capital
  employed before adjustments (B1/(A+B1)
 25.6%
 19.0%
 14.0%Net debt to capital
  employed adjusted (B2/(A+B2)
 26.8%
 20.0%
 15.2%1)
 Other interest-bearing
  elements are cash and cash equivalents adjustments regarding collateral
  deposits classified as cash and cash
  equivalents in the
  Consolidated balance sheet but considered as non-cash in the non-GAAP
  calculations as well as financial investments in Statoil Forsikring AS
  classified as current financial investments.2)
 Marketing instruction
  adjustment is an adjustment to gross interest bearing financial debt due to
  the SDFI part of the financial lease in the Snøhvit vessels that are included
  in Statoil's Consolidated balance sheet.3)
 Adjustment for project
  loan is adjustment to gross interest-bearing debt due to the BTC project loan
  structure.
  Statoil, Annual Report on Form 20-F
201595


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­­­­5 Risk review  Statoil’s overall risk management includes
identifying, evaluating and managing risk in all its activities to ensure safe
operations and to achieve Statoil’s corporate goals.  5.1 Risk factors  Statoil is exposed to a number of risks that
could affect its operational and financial performance. In this section, some
of the key risk factors are addressed.  5.1.1 Risks
related to our business  This section
describes the most significant potential risks relating to Statoil’s business: A
prolonged period of low oil and/or natural gas prices would have a material
adverse effect on Statoil. The prices of
oil and natural gas have fluctuated greatly in response to changes in many
factors. Currently, Statoil is in a situation where oil and natural gas prices
have declined substantially compared to levels seen over the last few years.
There are several reasons for this decline, but fundamental market forces
beyond the control of Statoil or other similar market participants have
impacted and can continue to impact oil and natural gas prices in the future.  Generally,
Statoil does not and will not have control over the factors that affect the
prices of oil and natural gas. These factors include: ·economic and
political developments in resource-producing regions ·global and
regional supply and demand ·the ability of the
Organisation of the Petroleum Exporting Countries (Opec) and/or other producing nations to influence global production
levels and prices ·prices of
alternative fuels that affect the prices realised under Statoil's long-term gas
sales contracts ·government
regulations and actions; including changes in energy and climate policies ·global economic
conditions ·war or other
international conflicts ·changes in
population growth and consumer preferences ·the price and
availability of new technology and ·weather conditions  It is
impossible to predict future price movements for oil and/or natural gas with
certainty. A prolonged period of low oil and natural gas prices will adversely
affect Statoil's business, the results of operations, financial condition,
liquidity and Statoil's ability to finance planned capital expenditure, including
possible reductions in capital expenditures which could lead to reduced reserve
replacement. In addition to the adverse effect on revenues, margins and
profitability from any fall in oil and natural gas prices, a prolonged period
of low prices or other indicators could, if deemed to have longer term impact,
lead to further reviews for impairment of the group's oil and natural gas
properties. Such reviews would reflect the management's view of long-term oil
and natural gas prices and could result in a charge for impairment that could
have a significant effect on the results of Statoil's operations in the period
in which it occurs. Changes in management’s view on long-term oil and/or
natural gas prices or further material reductions in oil, gas and/or product
prices could have an adverse impact on the economic viability of projects that
are planned or in development. Statoil’s
crude oil and natural gas reserves are only estimates and Statoil’s future
production, revenues and expenditures with respect to its reserves may differ
materially from these estimates. The
reliability of proved reserve estimates depends on: ·the quality and
quantity of Statoil’s geological, technical and economic data ·the production
performance of Statoil’s reservoirs ·extensive engineering
judgments and ·whether the
prevailing tax rules and other government regulations, contracts and oil, gas
and other prices will remain the same as on the date estimates are made  Proved
reserves are calculated based on the U.S. Securities and Exchange Commission
(SEC) requirements and may therefore differ substantially from Statoil’s view
on expected reserves.  Many of the
factors, assumptions and variables involved in estimating reserves are beyond
Statoil’s control and may prove to be incorrect over time. The results of
drilling, testing and production after the date of the estimates may require
substantial upward or downward revisions in Statoil’s reserve data. The prices
used for proved reserves are defined by the SEC and are calculated based on a 12
month un-weighted arithmetic average of the first-day-of-the-month price for
each month during the reporting year, leading to a forward price strongly
linked to last 96Statoil, Annual Report on Form 20-F 2015


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year’s price environment. Fluctuations
in oil and gas prices will have a direct impact on Statoil’s proved reserves.
For fields governed by production sharing agreements (PSAs), a lower price may
lead to higher entitlement to the production and increased reserves for those
fields. Adversely, a lower price environment may also lead to lower activity
resulting in reduced reserves. For PSAs these two effects may to some degree
offset each other. In addition a low price environment may result in earlier
shutdown due to uneconomic production. This will affect both PSAs and fields
with concession types of agreement. Exploratory
drilling involves numerous risks, including the risk that Statoil will
encounter no commercially productive oil or natural gas reservoirs. This could
materially adversely affect Statoil's results. Statoil's exploration activities
include accessing new acreage and maturing resources through high risk
exploration drilling activities. These risks include risks associated with the
execution of drilling and seismic operations and those associated with maturing
unproven resources.  New acreage is
primarily acquired through concessions, bidding rounds and acquisitions.
Geological interpretations and successful exploration drilling and appraisal
work leads to maturing and commercially attractive resources. Additionally,
Statoil also needs to be focused on optimising its rig capacity by thoughtful
deployment and redeployment. Given these risks and operational requirements,
Statoil may not effectively acquire acreage, successfully conduct its drilling
and appraisal work or optimise its rig capacity, which could result in a
material adverse effect on the results of its operations and financial
condition. Exploration activities involve the risk of accidents and
environmental incidents. Exploration activities also involve technical
challenges related to operating in harsh environments as well as
technologically demanding subsurface/geological challenges which Statoil may
not effectively manage. If
Statoil fails to acquire or discover and develop additional reserves, its
reserves and production will decline materially from their current levels. Successful
implementation of Statoil's group strategy for value growth is critically
dependent on sustaining its long-term reserve replacement. If upstream
resources are not progressed to proved reserves in a timely manner, Statoil’s
reserve base and thereby future production will gradually decline and future
revenue will be reduced.  Statoil's
future production is highly dependent on its success in acquiring or finding
and developing additional reserves adding value. If unsuccessful, future total
proved reserves and production will decline.  If the low
price environment continues for a substantial time, this may result in
undeveloped acreage not being considered economically viable and consequently
discovered resources not being matured to reserves. This may also lead to
exploration areas not being explored for new resources and subsequently not
being matured for development resulting in less future proved reserves.
Successful implementation of Statoil’s improvement initiatives may partly
offset this effect to some degree making new exploration areas and undeveloped
acreage more economically attractive for exploration and development.  In a number of
resource-rich countries, national oil companies control a significant
proportion of oil and gas reserves that remain to be developed. To the extent
that national oil companies choose to develop their oil and gas resources
without the participation of international oil companies, or if Statoil is unable
to develop partnerships with national oil companies, its ability to find and
acquire or develop additional reserves will be more limited. Statoil
is exposed to a wide range of health, safety and environmental risks that could
result in significant losses. Exploration
for, and the development, production, processing and transportation of oil and
natural gas can be hazardous and technical integrity failures, operational
failures, natural disasters or other occurrences can result in: loss of life,
oil spills, gas leaks, loss of containment of hazardous materials, water
contamination, blowouts, cratering, fires and equipment failure, among other
things.  The risks
associated with Statoil's activities are affected by the difficult geographies,
climate zones and environmentally sensitive regions in which Statoil operates.
All modes of transportation of hydrocarbons - including road, rail, sea or
pipeline - are particularly susceptible to a loss of containment of
hydrocarbons and other hazardous materials, and, given the high volumes
involved, these could represent a significant risk to people and the
environment. Offshore operations and transportation are subject to marine
perils, including severe storms and other adverse weather conditions and vessel
collisions. Onshore operations and transportation are subject to adverse
weather conditions and accidents. Both onshore and offshore operations and
transportation are subject to interruptions, restrictions or termination by
government authorities based on safety, environmental or other considerations.  Policy and
regulatory change due to rising climate change concerns, and the physical
effects of climate change, could impact Statoil’s business. Statoil
expects and is preparing for policy and regulatory changes targeted at reducing
greenhouse gas emissions of its upstream operations/activities. Statoil expects
greenhouse gas emission costs to increase from current levels beyond 2020 and
to have a wider geographical range than today. There is continuing uncertainty over
these regulatory and policy developments, including the mechanisms that will be
employed, and the level of global co-ordination and hence efficiency and
uniformity of measures. This in turn leads to uncertainty over the eventual
long-term implications to development project cost or operating cost and
constraints. As an example, new technological solutions could be required. This
could result in increased cost or longer lead times, or have an impact on
investment decisions for future projects. Climate related policy changes may
also reduce access to prospective geographical areas in the future and affect
the demand for and prices of Statoil's products.  Statoil, Annual Report on Form 20-F
201597


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Regulatory
changes and other factors may encourage the development of low-carbon energy
technologies such as renewable energy which could impact the demand for oil and
gas, particularly in specific regions. As an example, development of battery
technologies could allow more intermittent renewables to be used in the power
sector. This could especially impact Statoil's gas sales, particularly if
subsidies of renewable energy in Europe were to increase.  Statoil
carefully monitors and assesses the potential impact of climate change.
Developments in climate change could have a significant impact on Statoil's financial
performance, profitability and outlook, whether directly through changes in
taxation and regulation, or indirectly through changes in consumer behaviour.  Statoil hasassessed the sensitivity of
its project portfolio (equity production and expected production from accessed
exploration acreage)against
the assumptions regarding commodity and carbon prices in the International
Energy Agency’s (IEA) Current Policies scenario, the IEA New Policies scenario
and the IEA 450 scenario, as laid out in their “World Economic Outlook 2015”
report. The assessment demonstrated that the IEA’s “450 ppm scenario”, which is
compatible with a global warming of maximum of two degrees Celsius with more
than 50% probability, could have a negative impact of approximately 5% on
Statoil’s net present value compared to Statoil’s internal planning assumptions
as of December 2015.This
assessment is based on Statoil’s and the IEA’s assumptions which may not be
accurate and which are likely to change over time as new information becomes
available. Accordingly, there can be no assurance that the assessment,
which is presented in Statoil ASA’s 2015 Sustainability report, is a reliable
indicator of the actual impact of climate change on Statoil.  It is not
possible to predict the exact magnitude of the physical impact of climate
change on Statoil's operations. However, effects of climate change could result
in less stable weather patterns, which would result in more severe storms and
other weather conditions that could interfere with Statoil's operations.
Changes in physical climate parameters could impact the costs of Statoil's
operations, for example through restrained water availability and prolonged
droughts, or through increasing frequency of other extreme weather events.  Statoil
is exposed to risks as a result of its hydraulic fracturing usage. Statoil's
US operations use hydraulic fracturing which is subject to a range of
applicable federal, state and local laws, including those discussed under the
heading "Legal and Regulatory Risks". Fracturing is an important and
common practice that is used to stimulate production of crude oil and/or
natural gas from dense subsurface rock formations. Statoil's hydraulic
fracturing and fluid handling operations are designed and operated to minimise
the risk, if any, of subsurface migration of hydraulic fracturing fluids and
spillage or mishandling of hydraulic fracturing fluids, however, a proven case
of subsurface migration of hydraulic fracturing fluids or a case of spillage or
mishandling of hydraulic fracturing fluids during these activities could
potentially subject Statoil to civil and/or criminal liability and the
possibility of substantial costs, including environmental remediation,
depending on the circumstances of the underground migration, spillage, or
mishandling, the nature and scope of the underground migration, spillage, or
mishandling, and the applicable laws and regulations.  In
addition, various states and local governments have implemented, or are
considering, increased regulatory oversight of hydraulic fracturing through
additional permit requirements, operational restrictions, disclosure
requirements and temporary or permanent bans. New or further changes in laws
and regulations imposing reporting obligations on, or otherwise banning or
limiting, the hydraulic fracturing process could make it more difficult to
complete oil and natural gas wells in shale formations, cause operational
delays, increase costs of regulatory compliance or in exploration and
production, which could adversely affect Statoil's US onshore business and the
demand for fracturing services. Statoil
is exposed to security threats that could have
a materially adverse effect on Statoil's results of operations and financial
condition. Although Statoil has security barriers,
policies and risk management processes in
places which are designed to
protect its assets against a range of security threats, no assurances can be made that such
attacks will not occur and adversely impact its operations. Security threats
such as acts of terrorism
and cyber-attacks against Statoil's production and exploration facilities,
offices, pipelines, means of transportation or computer systems or breaches of
Statoil's security system, could result in significant losses. Failure to manage
the foregoing risks could result in injury or loss of life, damage to the
environment, damage to or the destruction of wells and production facilities,
pipelines and other property.
Statoil could face, among other things, regulatory action, legal liability,
damage to its reputation, a significant reduction
in revenues, an increase in costs, a shutdown of operations and a loss of its
investments in affected areas. Statoil does not purchase cyber risks insurance
because the available insurance products do not provide satisfactory coverage. Statoil's
crisis management systems may prove inadequate. Statoil has
crisis management plans and capability to deal with emergencies at every level
of its operations. If Statoil does not respond or is perceived not to have
responded in an appropriate manner to either an external or internal crisis,
its business, operations and reputation could be severely affected. For
Statoil's most important activities, it has also developed business continuity
plans to carry on or recover operations following a disruption or incident.
Inability to restore or replace critical capacity to an agreed level within an
agreed time frame could prolong the impact of any disruption and could severely
affect Statoil's business and operations.  Statoil
encounters competition from other oil and gas companies in all areas of its
operations. Some of
Statoil's larger, financially stronger competitors may be able to pay more to
gain access to resources, while its smaller competitors may be able to move
faster and gain earlier access than Statoil. Gaining access to profitable
resources either through the acquisition of licences, exploratory prospects or
producing properties is key to ensuring the long-term health and sustainability
of the business and Statoil's failure to do so could have an adverse impact on
its performance.  Technology is
a key competitive advantage in Statoil's industry and a larger company may be
able to invest more in developing or acquiring intellectual property rights to
technology that Statoil may require. Should Statoil's innovation lag behind the
industry, its performance could be impeded. 98Statoil, Annual Report on Form 20-F 2015


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Statoil's development projects and production
activities involve many uncertainties and operating risks that can prevent
Statoil from realising profits and cause substantial losses. Oil and gas
projects may be curtailed, delayed or cancelled for many reasons, including
equipment shortages or failures, natural hazards, unexpected drilling
conditions or reservoir characteristics, irregularities in geological
formations, accidents, mechanical and technical difficulties or challenges due
to new technology. This is particularly relevant because of the physical
environments in which some of Statoil’s projects are situated. Many of
Statoil's development and production projects are located in deep waters or
other harsh environments - such as the Gulf of Mexico in the US, the Flemish
Pass in Canada or the Barents Sea in Norway, or have challenging field
characteristics such as its heavy oil projects in Brazil (Peregrino), Norway
(Grane) and the UK (Mariner). In US onshore, low regional prices may cause
certain areas to be unprofitable and the company may curtail production until
prices recover. There is therefore a risk that Statoil undertakes development
projects that do not yield expected returns, especially in the current
environment of decreasing oil and gas prices combined with the relatively high
levels of tax and government take in several jurisdictions, including Norway.  Capital
expenditures in the oil and gas industry have increased over the last few years
due to a high activity level and more complex and capital intensive development
projects. This, combined with prolonged low oil and gas prices, could reduce
the returns and erode the profitability of some of Statoil's projects and
capital programs.  As
a response to these challenges, Statoil will need at all times to evaluate
profitability and robustness of projects and consider postponing or stopping
projects, adjusting strategies and targets or withdrawing from certain
geographical areas. Statoil
faces challenges in achieving its strategic objective of successfully
exploiting profitable growth opportunities. An important
element of Statoil's strategy is to continue to pursue attractive and
profitable growth opportunities available to it by both enhancing and
repositioning its asset portfolio and expanding into new markets. The
opportunities that Statoil is actively pursuing may involve the acquisition of
businesses or properties that complement or expand its existing portfolio. The
challenges related to the renewal of Statoil's upstream portfolio is growing
due to increasing global competition for access to opportunities.  Statoil's
ability to successfully implement this strategy will depend on a variety of
factors, including its ability to: ·identify
acceptable opportunities ·negotiate
favourable terms ·develop new market
opportunities or acquire properties or businesses promptly and profitably ·integrate acquired
properties or businesses into Statoil's operations ·arrange financing,
if necessary and ·comply with legal
regulations  As Statoil
pursues business opportunities in new and existing markets, it anticipates
significant investments and costs in connection with the development of such opportunities.
Statoil may incur or assume unanticipated liabilities, losses or costs
associated with assets or businesses acquired. Any failure by Statoil to
successfully pursue and exploit new business opportunities could result in
financial losses and inhibit growth. Any such new projects Statoil acquires
will require additional capital expenditure and will increase the cost of its
discoveries and development. These projects may also have different risk
profiles than Statoil's existing portfolio. These and other effects of such
acquisitions could result in Statoil having to revise either or both of
Statoil's forecasts with respect to unit production costs and production.  In addition,
the pursuit of acquisitions or new business opportunities could divert financial
and management resources away from Statoil's day-to-day operations to the
integration of acquired operations or properties. Statoil may require
additional debt or equity financing to undertake or consummate future
acquisitions or projects, and such financing may not be available on terms
satisfactory to Statoil, if at all, and it may, in the case of equity, be
dilutive to Statoil's earnings per share. The
profitability of Statoil’s oil and gas production may be affected by limited
transportation infrastructure when a field is in a remote location. Statoil's
ability to exploit economically any discovered petroleum resources beyond its
proved reserves will depend, among other factors, on the availability of the
infrastructure required to transport oil and gas to potential buyers at a
commercially acceptable price. Oil is transported by vessels, rail or pipelines
to refineries, and natural gas is usually transported by pipeline or by vessels
(for liquid natural gas) to processing plants and end users. Statoil may not be
successful in its efforts to secure transportation and markets for all of its
potential production.  Statoil is
exposed to security threats on its information systems and digital
infrastructure that could harm its assets and operations. Statoil’s
security barriers protect its information systems and digital infrastructure
from being compromised by unauthorised parties. Failure to maintain and develop
these barriers may affect the confidentiality, integrity and availability of
its information systems and digital infrastructure, including those critical to
Statoil’s operations. Threats to Statoil’s information systems could result in
significant financial damage to Statoil. Threats to Statoil’s industrial
control systems are not limited by geography as Statoil’s digital
infrastructure is accessible globally, and incidents in the industry in recent
years have shown that parties who are able to circumvent barriers aimed at
securing industrial control systems are capable and willing to perform attacks
that destroy, disrupt or otherwise compromise operations. Such attacks could
result in material losses or loss of life with consequent financial
implications. Some
of Statoil's international interests are located in regions where political,
social and economic instability could adversely impact Statoil’s business. Statoil has
assets and operations located in politically, socially and economically diverse
regions around the world where potential developments such as expropriation,
nationalisation of property, unilateral change of contracts or regulations,
civil strife, strikes, political unrest, war, terrorism, border disputes,
guerrilla activities, insurrections, piracy and the imposition of international
sanctions or other events Statoil, Annual Report on Form 20-F
201599


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could occur. Political
risks and security threats require continuous monitoring. Adverse and hostile
actions against Statoil's staff, its facilities, its transportation systems and
its digital infrastructure (cybersecurity) could cause harm to people and
disrupt Statoil's operations and further business opportunities in these or
other regions, lead to a decline in production and otherwise adversely affect
Statoil's business. This could have a materially adverse effect on Statoil's
results of operations and its financial condition.  100Statoil, Annual Report on Form 20-F 2015


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Statoil's operations are subject to dynamic political
and legal factors in the countries in which it operates. Statoil has
assets in a number of countries with emerging or transitioning economies that,
in part or in whole, lack well-functioning and reliable legal systems, where
the enforcement of contractual rights is uncertain or where the governmental
and regulatory framework is subject to unexpected change. Statoil's exploration
and production activities in these countries are often undertaken together with
national oil companies and are subject to a significant degree of state
control. In recent years, governments and national oil companies in some
regions have begun to exercise greater authority and impose more stringent
conditions on companies engaged in exploration and production activities.
Intervention by governments in such countries can take a wide variety of forms,
including:  ·restrictions on
exploration, production, imports and exports ·the awarding or
denial of exploration and production interests ·the imposition of
specific seismic and/or drilling obligations ·price and exchange
controls ·tax or royalty
increases, including retroactive claims ·nationalisation or
expropriation of Statoil's assets ·unilateral
cancellation or modification of Statoil's licence or contractual rights ·the renegotiation
of contracts ·payment delays and ·currency exchange
restrictions or currency devaluation  The likelihood
of these occurrences and their overall effect on Statoil vary greatly from
country to country and are hard to predict. If such risks materialise, they
could cause Statoil to incur material costs and/or cause Statoil's production
to decrease, potentially having a materially adverse effect on Statoil's
operations or financial condition. Statoil
is exposed to potentially adverse changes in the tax regimes of each
jurisdiction in which Statoil operates. Statoil has
business operations in many countries around the world. Changes in the tax laws
of the countries in which Statoil operates could have a material adverse effect
on its liquidity and results of operations. Statoil
faces foreign exchange risks that could adversely affect the results of Statoil’s
operations. Statoil's
business faces foreign exchange risks and this is managed with USD as the base
currency. Statoil has a large percentage of its revenues and cash receipts
denominated in USD and sales of gas and refined products are mainly denominated
in EUR and GBP. Further, Statoil pays a large portion of its income taxes, and
a share of our operating expenses and capital expenditures, in NOK. The
majority of Statoil's long term debt has USD exposure.  Statoil
is exposed to risks relating to trading and supply activities. Statoil is
engaged in substantial trading and commercial activities in the physical
markets. Statoil also uses financial instruments such as futures, options,
over-the-counter (OTC) forward contracts, market swaps and contracts for
differences related to crude oil, petroleum products, natural gas and
electricity in order to manage price volatility. Statoil also uses financial
instruments to manage foreign exchange and interest rate risk. Although Statoil
believes it has established appropriate risk management procedures, trading
activities involve elements of forecasting, and Statoil bears the risk of
market movements, the risk of losses if prices develop contrary to
expectations, and the risk of default by counterparties. Non-compliance
with anti-bribery, anti-corruption and other applicable laws, including failure
to meet Statoil’s ethical requirements, exposes Statoil to legal liability and
damage to its reputation, business and shareholder value. Statoil has
activities in countries which present corruption risks and which may have weak
legal institutions, lack of control and transparency. In addition, governments
play a significant role in the oil and gas sector, through ownership of
resources, participation, licensing and local content which leads to a high
level of interaction with public officials. Statoil is, through its
international activities, subject to anti-corruption and bribery laws in
multiple jurisdictions, including the Norwegian Penal code, the US Foreign Corrupt
Practices Act and the UK Bribery Act. A violation of any applicable
anti-corruption and bribery laws could expose Statoil to investigations from
multiple authorities, and any violations of laws may lead to criminal and/or
civil liability with substantial fines. Incidents of non-compliance with
applicable anti-corruption and bribery laws and regulations and the Statoil
Code of Conduct could be damaging to Statoil's reputation, competitiveness and
shareholder value.  Statoil’s
insurance coverage may not provide adequate protection. Statoil
maintains insurance coverage that includes coverage for physical damage to its
oil and gas properties, third-party liability, workers' compensation and
employers' liability, general liability, sudden pollution and other coverage.
Statoil's insurance coverage includes deductibles that must be met prior to
recovery. Statoil's external insurance is subject to caps, exclusions and
limitations, and there is no assurance that such coverage will adequately
protect Statoil against liability from all potential consequences and damages.  Statoil's
efficiency change agenda may impact the development of Statoil's business and
its financial results. In 2014,
Statoil announced an extensive efficiency change strategy in order to improve
efficiency across the organisation in light of the decline in oil and gas
prices. Two programmes were launched, the Statoil Technical Efficiency
Programme (STEP) and the organisational efficiency programme (OE). There is a
risk of Statoil not being able to define and implement the activities related
to cost savings without adversely effecting Statoil’s business goals or
achieving the necessary cost savings and increases in efficiency  Statoil may
fail to secure the right level of workforce competence and capacity over the
short and medium term Statoil, Annual Report on Form 20-F
2015101


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The
external uncertainty of the future of the oil industry in light of reduced oil
and natural gas prices and climate policy changes, creates a risk in ensuring a
robust workforce through industry cycles. The oil industry is a long term
business and needs to take a long term perspective on workforce capacity and
competence. Given the current extensive change agenda there is a risk that
Statoil will fail to secure the right level of workforce competence and capacity.  Statoil’s
activities in certain countries may be affected by international sanctions. Statoil, like
other major international energy companies, has a geographically diverse
portfolio of reserves and operational sites, which may expose its business and
financial affairs to political and economic risks, including operations in
areas subject to international sanctions or with sanctioned entities.  Russia Statoil holds
a 30% non-operating interest in a production sharing agreement related to the
Kharyaga field in the Nenets Autonomous Area in the Russian Federation. The
Kharyaga field produces conventional oil from the Timan Pechora basin onshore
in North West Russia. Statoil is further engaged in a strategic cooperation
with Rosneft Oil Company (Rosneft) including a joint cooperation project aimed
at undertaking seismic surveys and geological exploration, appraisal,
development and production of potential hydrocarbons in four licences on the
Russian continental shelf - the Magadan 1, Lisyansky and Kashevarovsky licences
in the Sea of Okhotsk (south of the Arctic Circle), and the Perseevsky licence
in the Barents Sea (north of the Arctic Circle). Additionally there are two
joint cooperation projects onshore; pilot drilling and testing of the onshore
heavy oil reservoir layer PK1 in the North Komsomolsky discovery, and the
Domanik Sediments Difficult-to-Extract Hydrocarbons Project, aimed at pilot
drilling and testing of the limestone Domanik formation in the Russian
Volga-Urals basin. For each of these projects, Rosneft holds the majority
interest, while Statoil holds a minority interest.  Sanctions
imposed by Norway, the EU and the USA target, among others, Russia’s financial
and energy sectors, including certain companies such as Rosneft and various
affiliates, and specific activities related to oil exploration and production
in the Arctic offshore area, and in deepwater or shale formation projects.
Aspects of those measures affect Statoil’s business activities in Russia. The
continued progress and financing of the joint projects are, in part, dependent
on Statoil and the joint ventures securing various governmental authorisations
and clarifications from such governmental authorities also going forward.
Statoil continues to pursue the above-described projects within the limitations
of current sanctions. However, due to current and possible future sanctions,
there is no certainty that the projects can be progressed and concluded as
initially planned.  Iran Certain
countries, including Iran, have been identified by the US government as state
sponsors of terrorism.  Historically,
Statoil held interests in the Iranian South Pars offshore phase 6, 7 and 8 gas
development project in the Persian Gulf. Statoil was also an owner of a
significant interest in the Anaran block and held a 100% interest in the
Khorramabad exploration block – both in Iran. Due to the increase of
international sanctions against Iran, Statoil in 2009 voluntarily offered
officials from the US State Department information about its Iranian business
activity. In October 2010 the US State Department announced under the
Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010
(CISADA), Statoil to be eligible to avoid retaliatory measures relating to its
activities in Iran, due to Statoil’s pledge to end its investments in Iran’s
energy sector.  Following the
January 2016 sanctions relief, offered Iran by the US in accordance with the
Joint Comprehensive Plan of Action entered into by Iran and the P5+1, secondary
US nuclear sanctions on Iran have been scaled back. Despite this, other
secondary and primary US sanctions on Iran remain in place. Since 2010,
Statoil’s activities
relating to Iran have consisted of closing its historic projects in an orderly
and compliant manner consistent with applicable sanctions. This has also
included efforts to settle, to the extent possible, outstanding tax and social
security obligations and recovery rights related to the above mentioned
projects. Statoil has at regular intervals kept both relevant Norwegian as well
as US authorities updated of such continued efforts.  A company
found to have violated US sanctions against Iran could become subject to
various types of sanctions, including (but not limited to) denial of US bank
loans, restrictions on the importation of goods produced by the sanctioned
entity, the prohibition on property transactions by the sanctioned entity in
which the property is subject to the jurisdiction of the United States and
prohibition of transfers of credit or payments via financial institutions in
which the sanctioned entity has any interest.  General The
legislation and rules governing sanctions are complex, constantly evolving and
may not be consistent across jurisdictions. Changes in any of these laws or policies
or the implementation thereof can be unpredictable. Statoil's business is
dynamic and the above facts accordingly, may change over time. Moreover, the
description does not fully reflect all parts of Statoil's business where a
particular focus on sanctions compliance might be warranted. Lastly, it should
be understood that Statoil in the future could also decide to take part in
additional business activity also involving sanctioned targets in various parts
of the world whilst still remaining compliant with applicable sanctions laws.
Statoil is committed to doing business in compliance with all applicable laws,
however there can be no assurance that Statoil or affiliates of Statoil or
their respective officers, directors, employees or agents are not in violation
of such laws. Any such violation could result in substantial civil and/or
criminal penalties and might materially adversely affect Statoil's business and
results of operations or financial condition.  Statoil is
also aware of initiatives by certain US states and institutional investors,
such as pension funds, to adopt or consider adopting laws, regulations or
policies requiring, among other things, divestment from, reporting of interests
in, or agreements not to make future investments in, companies that do business
with countries that, among other things, are designated as state sponsors of
terrorism. These policies could have an adverse impact on investments by
certain investors in Statoil’s securities.  102Statoil, Annual Report on Form 20-F 2015


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Disclosure
Pursuant to Section 13 (r) of the Exchange Act The Iran Threat Reduction
and Syria Human Rights Act of 2012 ("ITRA") created a new subsection
(r) in Section 13 of the Exchange Act which requires a reporting issuer to
provide disclosure if the issuer or any of its affiliates engaged in certain
enumerated activities relating to Iran, including activities involving the
Government of Iran. Statoil is providing the following disclosure pursuant to
Section 13(r).  Statoil is a party to
agreements with the National Iranian Oil Company (NIOC), namely, a Development
Service Contract for South Pars Gas Phases 6, 7 & 8 (offshore part), an
Exploration Service Contract for the Anaran Block and an Exploration Service
Contract for the Khorramabad Block, which are located in Iran. Statoil's operational
obligations under these agreements have terminated and the licenses have been
abandoned.  The cost recovery program
for these contracts was completed in 2012, except for the recovery of tax and
obligations to the Social Security organisation (SSO). Statoil's activity in
Iran during 2015 was focused on a final settlement with the Iranian tax
authorities and the SSO relating to the above mentioned agreements. During 2015
Statoil paid the equivalent of USD 3.20 million in tax and SSO to Iranian
authorities in local currency (Iranian Rials), from which USD 0.04 million has
been booked as expenses in 2015 and the rest have been reversed from previous
years’ accruals. Also during 2015 Statoil paid USD 0.02 million stamp duty to
Iran Tax Organisation.The
funds utilised for these purposes were held by Statoil in EN Bank (Iran).  During 2015 Statoil also
received the equivalent of USD 0.48 million as insurance payment related to its
legacy South Pars business. Also this insurance payment has been booked as
revenue in 2015.  During 2015 NIOC, on
behalf of Statoil, paid a tax obligation of USD 1.6 million equivalent in
Iranian Rial to the local tax authorities. The amount was settled towards
recoverable costs from NIOC to Statoil. Statoil is not involved in any other activities
in Iran.  Since 2009 Statoil has
transparently and regularly provided information about its Iran related
activity to the US State Department as well as to the Norwegian Ministry of
Foreign Affairs. In a letter from the US State Department of 1November 2010,
Statoil was informed that the company was not considered to be a company of
concern based on its previous Iran-related activities.  Statoil generated no net
profit from the aforementioned activity in 2015. Payments of the above
mentioned nature are expected to be made also in 2016, in relation to Statoil’s
continued winding-down efforts.  In addition, Statoil has in the course of 2015 paid four annual
patent fees in Iran of in total EUR 347 (appr. USD 420). The payment of these
patent fees will be discontinued in 2016.  5.1.2 Legal
and regulatory risks  This section discusses potential legal and
regulatory risks related to the legal context of our business operations, such
as having to comply with new laws and regulations.  Compliance
with health, safety and environmental laws and regulations that apply to
Statoil's operations could materially increase its costs. The enactment of such
laws and regulations in the future is uncertain.  Statoil
incurs, and expects to continue to incur, substantial capital, operating,
maintenance and remediation costs relating to compliance with increasingly
complex laws and regulations for the protection of the environment and human
health and safety, including: ·costs as a result
of stricter climate regulations and a higher price on greenhouse gas emissions ·costs of
preventing, controlling, eliminating or reducing certain types of emissions to
air and discharges to the sea, including costs incurred in connection with
government action to address the risk of spills and concerns about the impacts
of climate change ·remediation of
environmental contamination and adverse impacts caused by Statoil's activities
or accidents at various facilities owned or previously owned by Statoil and at
third-party sites where Statoil's products or waste have been handled or
disposed of ·compensation of
persons and/or entities claiming damages as a result of Statoil's activities or
accidents and ·costs in
connection with the decommissioning of drilling platforms and other facilities  For example,
under the Norwegian Petroleum Act of 29 November 1996, as a holder of licences
on the Norwegian continental shelf (NCS), Statoil is subject to statutory
strict liability in respect of losses or damage suffered as a result of pollution
caused by spills or discharges of petroleum from petroleum facilities covered
by any of Statoil's licences. This means that anyone within the state or the
delineation of the NCS who suffers losses or damage as a result of pollution
caused by operations in any of Statoil's NCS licence areas can claim
compensation from Statoil without having to demonstrate that the damage is due
to any fault on Statoil's part.  Furthermore,
in countries where Statoil operates or expects to operate in the near future, new
laws and regulations, the imposition of stricter requirements on licences,
increasingly strict enforcement of or new interpretations of existing laws and
regulations, the aftermath of operational catastrophes in which Statoil or
members of its industry are involved or the discovery of previously unknown
contamination may require future expenditure in order to, among other things: Statoil, Annual Report on Form 20-F
2015103


---

·modify operations ·install pollution
control equipment ·implement
additional safety measures ·perform site
clean-ups ·curtail or cease
certain operations ·temporarily shut
down Statoil's facilities ·meet technical
requirements ·increase
monitoring, training, record-keeping and contingency planning and ·establish
credentials in order to be permitted to commence drilling  Compliance
with laws, regulations and obligations relating to climate change and other
environmental regulations could result in substantial capital expenditure,
reduced profitability as a result of changes in operating costs, and adverse
effects on revenue generation and strategic growth opportunities. Statoil
regularly assesses how changes in regulations, including introduction of
stringent climate policies, may impact the oil price, the costs of developing
new oil and gas assets, and the demand for oil and gas.  Statoil's
operations in Norway are subject to emissions taxes as well as emissions
allowances granted for Statoil's larger European operations under the EU
Emissions Trading System. The agreed strengthening of the European Union's
emission trading scheme may result in a significant reduction in the total
emissions from relevant energy and industry installations which includes
Statoil’s installations at the NCS. The price of the emissions allowances is
also expected to increase significantly towards 2030. At the 21st Conference of
Parties (COP21) in Paris in December 2015, 195 countries adopted a new
universally applicable climate agreement, to be effective from 2020. The
Norwegian Parliament decided that Norway should negotiate with the European
Union to develop the terms for a collective delivery of 40% reductions in
greenhouse gas emissions by 2030 compared to 1990. Individual countries’
climate plans, the so-called ‘Intended Nationally Determined Contributions’,
are to be strengthened every five years. The implications for the industry are
not yet clear, however requirements to reduce emissions could imply increased
costs.  The EU Fuel
Quality Directive 2009/30/EC and its Implementation Directive 2015/652/EU
require fuel suppliers to reduce their carbon intensity for transportation
fuels by 6% in 2020 compared to the baseline of 2010. Fuel suppliers can use
biofuels, low carbon fuels (i.e. natural gas), charging of electric vehicles
and upstream emission reductions to achieve the target. Member States may set penalties
on fuels suppliers for not achieving the target. The EU Commission will submit
a non-legislative guidance document before April 2017 which will propose common
principles on verification and accounting of upstream emissions reductions. The
regulation could indirectly impact Statoil if it results in incentives for
service station companies to increase the share of biofuels on behalf of fossil
fuels.  In the US,
the Environmental Protection Agencyhas taken steps to regulate greenhouse gas emissions under
theClean Air Actauthority by proposing a Clean Power Plan (CPP). The
plan aims to reduce emissions from the US power sector by setting performance
standards for power plants. The regulation, if approved, could stimulate
increased gas demand. In 2015, the EPA also proposed new source performance
standards, in addition to those issued in 2012,targeting volatile organic compound emissions, that are
intended to further reduce oil and gas methane emissions. This could imply
additional costs for oil and gas producers.  Statoil
incorporates a cost for carbon in the assessment of all new projects. This
guides Statoil's strategy and its investment decisions. For investment
decisions pertaining to oil and gas projects in Norway, Statoil includes an
internal cost of USD 64 per tonne of CO2-equivalent (based on the
average annual exchange rate in 2015), based on the cost of the Norwegian CO2tax. In 2014, Statoil began to apply an internal cost of USD 50 per tonne
of CO2-equivalent in its investment decisions for all new oil and
gas projects outside of Norway.  Many of
Statoil's mature fields are producing increasing quantities of water with oil
and gas. Statoil's ability to dispose of this water in environmentally
acceptable ways may have an impact on its oil and gas production. Statoil's
investments in North American onshore producing assets will be subject to
evolving regulations which are common to all energy companies with investments
in this region. This could affect Statoil's operations and profitability with
respect to these operations.  If Statoil
does not succeed in overcoming the perceived trade-off between global access to
energy and the protection or improvement of the natural environment, Statoil
could fail to live up to its aspirations of zero or minimal damage to the
environment and of contributing to human progress.  Statoil is
exposed to risk of supervision, review and sanctions for violations of
regulatory laws at the supranational and national level. These include, among
others, competition and antitrust laws and financial and trading. Statoil's
products are marketed and traded worldwide and therefore subject to competition
and antitrust laws at the supranational and national level in multiple
jurisdictions. Statoil is exposed to investigations from competition and
antitrust authorities, and violations of the applicable laws and regulations
may lead to substantial fines. In December 2015, the European Commission
announced that it currently will not pursue its investigation against Statoil
and certain other oil and gas producers concerning alleged crude oil price
manipulation. The investigation had been on-going since May 2013 when the EFTA
Surveillance Authority conducted an unannounced inspection at Statoil's head
office in Stavanger, Norway, on behalf of the European Commission. The
authorities suspected participation by several companies, including Statoil, in
anti-competitive practices and/or market manipulation related to Platts
Market-On-Close price assessment process.  Statoil is
also exposed to financial review from financial supervisory authorities such as
the Norwegian Financial Supervisory Authority (FSA) and the US Securities and
Exchange Commission (the SEC). Reviews performed by these authorities could
result in changes to previous accounts and future accounting policies. On 10
March 2014, the FSA concluded a review of Statoil's 2012 financial statements.
Statoil has accepted two of the FSA's conclusions following this review but has
appealed the third to the Norwegian Ministry of Finance. 104Statoil, Annual Report on Form 20-F 2015


---

Statoil is
listed on both the Oslo Børs and New York Stock Exchange (NYSE), and is
registered with the SEC. Statoil is required to comply with the continuing
obligations of these regulatory authorities, and violation of these obligations
may result in imposition of fines or other sanctions.  The Norwegian
Petroleum Supervisor (Ptil) supervises all aspects of Statoil's operations,
from exploration drilling through development and operation, to cessation and
removal. Its regulatory authority covers the whole NCS as well as
petroleum-related plants on land in Norway. Statoil is exposed to supervision
from Ptil, and such supervision could result in audit reports, orders and
investigations.  The formation
of a competitive internal gas market within the European Union (EU) and the
general liberalisation of European gas markets could adversely affect Statoil's
business. The continuing
liberalisation of EU gas markets following legislative instruments rolled out
in 2011 and the implementation of these legislative instruments by member
states, could create new business opportunities for Statoil, but could also
affect Statoil's market position or result in a reduction in prices in
Statoil's gas sales contracts. Statoil's exposure to hub gas prices has
increased and correspondingly increased Statoil’s exposure to price volatility.
Statoil continually monitors its contractual obligations and makes efforts to
negotiate the most competitive pricing and other conditions available in the
market.  The EU-wide
quantity of carbon allowances issued each year under the Emission Trading
Scheme (ETS) for greenhouse gas emission allowances began to decrease in a
linear manner in 2013. The ETS can have a positive or negative impact on
Statoil, depending on the price of carbon, which will consequently have an
impact on the development of gas-fired power generation in the EU. Until now,
the carbon price has been too low to replace coal with gas fired generation
capacity. This effect has been worsened by heavy subsidising of renewables
which has caused gas fired power plants to shut down. Current EU climate and
energy policies do not address this problem, but there is a tendency towards
more market based subsidies in the new guidelines on environment and energy
aid.  Political and
economic policies of the Norwegian State could affect Statoil’s business. The Norwegian
State plays an active role in the management of NCS hydrocarbon resources. In
addition to its direct participation in petroleum activities through the
State's direct financial interest (SDFI) and its indirect impact through
legislation, such as tax and environmental laws and regulations, the Norwegian
State, among other things, awards licences for exploration, production and
transportation, approves exploration and development projects and applications
for production rates for individual fields and may, if important public
interests are at stake, also instruct Statoil and other oil companies to reduce
petroleum production. Furthermore, in the production licences in which the SDFI
holds an interest, the Norwegian State has the power to direct petroleum
licences' actions in certain circumstances.  If the
Norwegian State were to take additional action under its activities on the NCS
or to change laws, regulations, policies or practices relating to the oil and
gas industry, Statoil's NCS exploration, development and production activities
and the results of its operations could be affected.  5.1.3 Risks related to state ownership  This section discusses some of the potential risks relating to
Statoil’s business that could derive from the Norwegian State's majority
ownership and from Statoil’s involvement in the SDFI.  The interests of Statoil’s majority shareholder, the Norwegian
State, may not always be aligned with the interests of Statoil’s other
shareholders, and this may affect Statoil’s decisions relating to the NCS. The Norwegian Parliament, known as the Storting, and the Norwegian
State have resolved that the Norwegian State's shares in Statoil and the SDFI's
interest in NCS licences must be managed in accordance with a coordinated
ownership strategy for the Norwegian State's oil and gas interests. Under this
strategy, the Norwegian State has required Statoil to continue to market the
Norwegian State's oil and gas together with Statoil's own oil and gas as a
single economic unit.  Pursuant to this coordinated ownership strategy, the Norwegian
State requires Statoil, in its activities on the NCS, to take account of the
Norwegian State's interests in all decisions that may affect the development
and marketing of Statoil's own and the Norwegian State's oil and gas.  The Norwegian State directly held 67% of Statoil's ordinary shares
as of 31 December 2015. Based on the Norwegian Public Limited Companies Act,
the Norwegian State effectively has the power to influence the outcome of any
vote of shareholders due to the percentage of Statoil's shares it owns,
including amending its articles of association and electing all non-employee
members of the corporate assembly. The employees are entitled to be represented
by up to one-third of the members of the board of directors and one-third of
the corporate assembly.  The corporate assembly is responsible for electing Statoil's board
of directors. It also makes recommendations to the general meeting concerning
the board of directors' proposals relating to the company's annual accounts,
balance sheet, allocation of profit and coverage of loss. The interests of the
Norwegian State in deciding these and other matters and the factors it
considers when casting its votes, especially under the coordinated ownership
strategy for the SDFI and Statoil's shares held by the Norwegian State, could
be different from the interests of Statoil's other shareholders.  Statoil, Annual Report on Form 20-F
2015105


---

If the Norwegian State's
coordinated ownership strategy is not implemented and pursued in the future,
then Statoil's mandate to continue to sell the Norwegian State's oil and gas
together with its own oil and gas as a single economic unit is likely to be
prejudiced. Loss of the mandate to sell the SDFI's oil and gas could have an adverse
effect on Statoil's position in the markets in which it operates.  For further information about the mandate to sell the Norwegian
State's oil and gas see section 3.12.4 SDFI oil and gas marketing and sale.  106Statoil, Annual Report on Form 20-F 2015


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5.2 Risk management  Statoil’s overall risk management approach includes identifying,
evaluating and managing risk in all its activities. In order to achieve optimal
corporate solutions, Statoil bases its risk management on an enterprise-wide
risk management approach.  Statoil
defines risk as a deviation from a specified reference value and the
uncertainty associated with it. A positive deviation is defined as an upside
risk, while a negative deviation is a downside risk. The reference value is
most commonly a forecast, percentile or target. Statoil has an enterprise risk
management (ERM) approach, which means that:  •focus
is on the value impact for Statoil •risk is
managed to make sure that Statoil’s operations are safe and in compliance with
Statoils’ requirements and •focus
is on risk and reward at all levels in the organisation  Statoil’s
corporate risk committee (CRC) is headed by the chief financial officer and its
members include representatives of the principal business areas. It is an
enterprise risk management advisory body that primarily advises the chief
financial officer, but also the business areas' management on specific issues.
The CRC assesses and advises on measures aimed at managing the overall risk to
the group, and it proposes appropriate measures to adjust risk at the corporate
level. The CRC is also responsible for reviewing and developing Statoil’s risk
policies. The committee meets regularly during the year to support Statoil’s
risk management strategies, including hedging and trading strategies, as well
as risk management methodologies. It regularly receives risk information that
is relevant to it from Statoil’s corporate risk department.  Risk
is managed in the business line and is an integrated part of any manager’s
responsibility. However, some risks are managed at corporate level to avoid
sub-optimisation. This includes oil and natural gas price risks, interest and
currency risks, risk dimension in the strategy work, prioritisation processes
and capital structure discussions.  The
following section describes in some detail the market risks to which Statoil is
exposed and how Statoil manages these risks.  5.2.1 Managing operational risk  Statoil manages risk in order to ensure safe
operations and to achieve its corporate goals in compliance with its
requirements.  All risks are related to Statoil's value chain, which denotes the
value that is added in each step - from access, maturing, project execution and
operation to market. In addition to the economic impact these risks could have
on Statoil's cash flows, Statoil has have a strong focus on avoiding HSE and
integrity-related incidents (such as accidents, fraud and corruption). Most of
the risks are managed by the principal business area line managers. Some
operational risks are insurable and insured by Statoil’s captive insurance
company operating in the Norwegian and international insurance markets.  Statoil’s risk management process is based on ISO31000 Risk
management – principles and guidelines. The process provides a standardised
framework and methodology for assessing and managing risk. A standardisation of
the process across the entire enterprise allows for comparable risk levels and
efficiency in decisions and it enables the organisation to create sustainable
value while avoiding incidents. The process ensures that risks are identified,
analysed, evaluated and managed. Risk adjusting actions are subject to a cost
benefit evaluation (except certain safety related risks which are subject to
specific regulations).  5.2.2 Managing financial risk  Theresults of Statoil’s operations depend on a
number of factors, most significantly those that affect the price it receives
for the products.  Statoil has developed policies aimed at
managing the financial volatility inherent in some of the business exposures.
In accordance with these policies, Statoil enters into various financial and
commodity-based transactions (derivatives). While the policies and mandates are
set at the company level, the business areas are responsible for marketing and
trading commodities are also responsible for managing commodity-based price
risks. Interest, liquidity, liability and credit risks are managed by the
company's central finance department.  The factors that influence the results of
Statoil’s operations include: the level of crude oil and natural gas prices,
trends in the exchange rate between the USD, in which the trading price of
crude oil is generally stated, EUR and GBP where Statoil has a large share of
its natural gas sales, and NOK, in which its accounts are reported and a
substantial proportion of the costs are incurred; Statoil’s oil and natural gas
production volumes, which in turn depend on entitlement volumes under PSAs and
available petroleum reserves, and Statoil’s own, as well as Statoil, Annual Report on Form 20-F
2015107


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partners' expertise and cooperation in recovering oil
and natural gas from those reserves; and changes in Statoil’s portfolio of
assets due to acquisitions and disposals.  Statoil’s results will also be affected by
trends in the international oil industry, including possible actions by
governments and other regulatory authorities in the jurisdictions in which
Statoil operates, or possible or continued actions by members of the
Organization of Petroleum Exporting Countries (Opec) and/or other producing
nations that affect price levels and volumes, refining margins, the cost of
oilfield services, supplies and equipment, competition for exploration
opportunities and operatorships, and deregulation of the natural gas markets,
all of which may cause substantial changes to existing market structures and to
the overall level and volatility of prices and price differentials.  The following table shows the yearly averages
for quoted Brent Blend crude oil prices, natural gas average sales prices,
refining reference margins and the USDNOK exchange rates for 2015, 2014 and
2013.  Yearly
  average
 2015
 2014
 2013Crude oil (USD/bbl Brent
  blend)
 55.3
 98.9
 108.7Average invoiced gas
  prices - Europe (NOK/scm)
 2.16
 2.28
 2.45Refining reference
  margin (USD/bbl)
 8.0
 4.7
 4.1USDNOK average daily
  exchange rate
 8.07
 6.30
 5.88
     The
  illustration shows the indicative full-year effect on the financial result for
  2016 given certain changes in the crude oil price, natural gas contract prices
  and the USD/NOK exchange rate. The estimated price sensitivity of Statoil’s
  financial results to each of the factors has been estimated based on the
  assumption that all other factors remain unchanged.  Significant
downward adjustments of Statoil’s commodity price assumptions will result in
impairment losses on certain producing and development assets in the portfolio.
Subsequent to year end 2015, commodity prices have continued to be volatile.
See note
11 Property,
plant and equipment and note 12 Intangible
assets to the Consolidated financial statements for sensitivity
analysis related to impairment losses.  Statoil
assesses oil and gas price hedging opportunities on a regular basis as a tool
with regard to financial robustness and flexibility.  Fluctuating
foreign exchange rates can have a significant impact on the operating results.
Statoil’s revenues and cash flows are mainly denominated in or driven by USD,
while a large portion of the operating expenses, capital expenditures and
income taxes payable accrue in NOK. Statoil seeks to manage this currency
mismatch by issuing or swapping non-current financial debt in USD. This
long-term funding policy is an integrated part of our total risk management
programme. Statoil also engages in foreign currency management in order to
cover the non-USD needs, which are primarily in NOK. In general, an increase in
the value of USD in relation to NOK can be expected to increase Statoil’s
reported earnings.  Historically, Statoil’s revenues have largely been
generated by the production of oil and natural gas on the NCS. Norway imposes a
78% marginal tax rate on income from offshore oil and natural gas activities (a
symmetrical tax system). For more information see section 3.12.6 Taxation
of Statoil.  Statoil’s
earnings volatility is moderated as a result of the significant proportion of
its Norwegian offshore income that is subject to a 78% tax rate in profitable
periods, and the significant tax assets generated by its Norwegian offshore
operations in any loss-making periods. Most of the taxes Statoil pays are paid
to the Norwegian State. Dividends received in Norway are 97% exempt from tax,
with the remaining 3% taxed at the ordinary rate of 27%. For dividends received
from companies in a low-tax jurisdiction within the European Economic Area
(EEA), the 97% exemption only applies if real business activities are conducted
in that jurisdiction. Dividends received from companies in non-EEA countries
are 97% exempt if the Norwegian recipient has held at least 10% of the shares
for a minimum of two years and the foreign country is not a low-tax
jurisdiction.  Government
fiscal policy is an issue in several of the countries in which Statoil
operates, such as, but not limited to, Algeria, Angola, Nigeria, Brazil, the
USA and Venezuela. However, Statoil’s exposure in Venezuela is low. For
instance, government fiscal policy could require royalties in cash or in kind,
increased tax rates, increased government participation and changes in terms
and conditions as defined in various production or income-sharing contracts.
Statoil’s financial statements are based on currently enacted regulations and
on any current claims from tax authorities regarding past events. Developments
in government fiscal policy may have a negative effect on future net income.  Financial risk management Statoil's business activities naturally expose the group
to financial risk. The group's approach to risk management includes
identifying, evaluating and managing risk in all activities using a top-down
approach for the purpose of avoiding sub-optimisation and utilising
correlations observed from a group perspective. Summing up the different market
risks without including the correlations will overestimate Statoil’s total 108Statoil, Annual Report on Form 20-F 2015


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market risk. For this reason, Statoil utilises
correlations between all of the most important market risks, such as oil and
natural gas prices, product prices, currencies and interest rates, to calculate
the overall market risk and thereby utilise the natural hedges embedded in its
portfolio. This approach also reduces the number of unnecessary transactions,
which reduces transaction costs and avoids sub-optimisation.  In order to achieve the above effects, Statoil has
centralised trading mandates (financial positions taken to achieve financial
gains, in addition to established policies) so that all major/strategic
transactions are coordinated through the CRC. Local trading mandates are
therefore relatively small.  Statoil's
activities expose the company to the following financial risks: market risks
(including commodity price risk, interest rate risk and currency risk),
liquidity risk and credit risk. For a discussion of financial risk management see
note 5 Financial risk management in the Consolidated financial statements.  5.2.3 Disclosures about market risk  Statoil uses financial instruments to manage
commodity price risks, interest rate risks, currency risks and liquidity risks.
Significant amounts of assets and liabilities are accounted for as financial
instruments.  See note 25 Financial instruments: fair
value measurement and sensitivity analysis of market risk in the
Consolidated financial statements, for details of the nature and extent of such
positions, and for qualitative and quantitative disclosures of the risks
associated with these instruments.  5.3 Legal proceedings  Statoil is involved in a number of
proceedings globally concerning matters arising in connection with the conduct
of its business.  Statoil is currently not aware of any
regulatory, judicial or arbitration proceedings or claims that it believes may
have, or have had in the recent past, individually or in the aggregate,
significant effects on Statoil’s financial position or profitability or on the
results of its operations or liquidity. This includes the legal proceedings
described hereafter:  Agbami redetermination, Nigeria: Through its ownership in OML 128 in Nigeria,
Statoil is party to an ownership interest redetermination process for the
Agbami field. In October 2015 Statoil received the expert’s final ruling which
implies a reduction of 5.17 percentage points in Statoil’s equity interest in
the field from 20.21% to 15.04%. In 2013, Statoil initiated arbitration
proceedings to set aside interim decisions made by the expert in the
redetermination process, but this was declined by the arbitration tribunal in
its November 2015 judgment. Statoil has initiated proceedings before the
Federal High Court in Lagos to set aside the arbitration award, and also
intends to initiate a new arbitration to set aside the expert’s final ruling.  As of 31 December 2015 Statoil has made a
provision of NOK 9.5 billion, net of tax, which reflects a reduction of 5.17
percentage points in Statoil’s equity interest in the Agbami field.  Royalty Litigation, US Onshore: Statoil is currently defending multiple, but individually
immaterial, royalty litigations and arbitrations, some on behalf of large
classes of mineral owners, relating to its operated and non-operated positions
in the Marcellus and Eagle Ford shale plays. Mineral owners in these
proceedings generally allege that Statoil has breached their oil and gas leases
by first paying royalty on the basis of an impermissibly-low unit price, and
second taking prohibited and/or excessive deductions for post-production costs.
The cases are in various procedural stages and are typical disputes for oil
companies in the US onshore business. None of the litigations or arbitrations
is currently set for trial or final hearing.  In the ordinary course of business, companies
in the Statoil group are subject to a number of other loss contingencies
arising from litigation and claims raised by governmental and private parties,
for instance contractors, tax authorities, land owners for on-shore activities
and buyers of Statoil’s products.  See also note 9 Income taxes and note 23 Other
commitments and contingencies in Consolidated financial statements.  Statoil, Annual Report on Form 20-F
2015109


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6 Shareholder
information  Statoil is the largest company listed on the
Oslo Børs, where it trades under the ticker code STL. Statoil is also listed on
the New York Stock Exchange under the ticker code STO.  STATOIL
  SHARE
 2015
 2014
 2013
 2012
 2011Shareprice STL (low)
  (NOK)
 116.30
 120.00
 147.70
 162.40
 160.50Shareprice STL (average)
  (NOK)
 137.59
 166.41
 123.00
 133.80
 113.70Shareprice STL (high)
  (NOK)
 160.80
 194.80
 136.72
 146.97
 139.60Shareprice STL
  (year-end) (NOK)
 123.70
 131.20
 147.00
 139.00
 153.50Market value year-end
  (NOK billion)
 394
 418
 468
 443
 490Daily turnover (million
  shares)
 5.1
 3.7
 3.0
 4.3
 8.9Ordinary earnings per
  share (EPS) (NOK)
 -11.80
 6.87
 12.50
 21.60
 24.70P/E1)
 -10.48
 19.10
 11.76
 6.44
 6.21Ordinary dividend per
  share (NOK)2)
 1.80
 7.20
 7.00
 6.75
 6.50Ordinary dividend per
  share (USD)2)
 0.6603Growth in ordinary
  dividend per share3)
 NA
 2.9%
 3.7%
 3.8%
 4.0%Dividend per share (NOK)4)
 7.62
 7.20
 7.00
 6.75
 6.50Dividend per share (USD)4)
 0.86
 0.97
 1.15
 1.21
 1.08Pay-out ratio5)
 -65%
 105%
 56%
 31%
 26%Dividend yield6)
 6.2%
 5.5%
 4.8%
 4.9%
 4.2%Ordinary shares
  outstanding, weighted average
 3,179,442,977
 3,179,958,780
 3,180,683,828
 3,181,546,060
 3,182,112,843Ordinary shares
  outstanding, year-end
 3,188,647,103
 3,188,647,103
 3,188,647,103
 3,188,647,103
 3,188,647,1031)
 Share price at year end
  divided by EPS.2)
 Proposed cash dividend
  for 2015. For 2015, the NOK amount covers first quarter while the USD amount
  is for second, third and fourth quarter. See section 6.1 Dividend policy.3)
 Excluding special
  dividend and share buy-back.4)
 Conversions between NOK
  and USD are conducted by applying the year end exchange rate for the
  respective year.5)
 Total dividend per share
  in NOK divided by EPS.6)
 Total dividend per share
  in NOK divided by year end share price.
 110Statoil, Annual Report on Form 20-F 2015


---

As of 31
  December 2015, Statoil represented 14.68% of the total value of all companies
  registered on the Oslo Børs, with a market value of NOK 394 billion.
  
  Statoil's
  share price closed at NOK 123.70 at the end of 2015.
  
  Taking into
  consideration the total dividend paid out in 2015 of NOK 7.20 per share,
  which includes four quarterly payments of NOK 1.80 per share for the third
  and fourth quarter of 2014 and first and second quarter of 2015, the total
  return was negative NOK 0.30 per share.The graph above, "Quote
  history", shows the development of the Statoil share price compared to
  the oil price and the Oslo Børs Benchmark Index (OSEBX). The board
  of directors proposes a dividend of USD 0.2201 per share for the fourth
  quarter 2015, for approval by the annual general meeting on 11 May 2016.
  Diluted earnings per share amounted to negative
  NOK 11.80,
  compared to positive NOK 6.87 in 2014.
  
  The turnover
  of shares is a measure of traded volumes. On average, 5.1 million Statoil
  shares were traded on the Oslo Børs every day in 2015 compared to 3.7 million
  shares in 2014. In 2015, Statoil shares accounted for 15% of the total market
  value traded throughout the year (see illustration), compared to 12% in 2014.
  
  Statoil ASA
  has one class of shares, and each share confers one vote at the general
  meeting. Statoil ASA had 3,188,647,103ordinary
  shares outstanding at year end.
  As
  of 31 December 2015, Statoil had 91,774 shareholders registered in the
  Norwegian Central Securities Depository (VPS), down from 92,692 shareholders
  at 31 December 2014.
   Statoil, Annual Report on Form 20-F
2015111


---

6.1
Dividend policy  It is Statoil's ambition to grow the annual
cash dividend measured in USD per share in line with long-term underlying earnings.  Statoil’s board approves first, second and
third quarter interim dividends, based on an authorisation from the annual
general meeting (AGM), while the AGM approves the fourth quarter dividend and the
implicit the total dividend based on a proposal from the board. When deciding
the interim dividends and recommending the total annual dividend level, the
board will take into consideration expected cash flow, capital expenditure
plans, financing requirements and appropriate financial flexibility. In
addition to cash dividend, Statoil might buy back shares as part of total
distribution of capital to the shareholders. The shareholders at the AGM may
vote to reduce, but may not increase, the fourth quarter dividend proposed by
the board of directors. It is Statoil’s intention to have this authorisation
approved at the AGM. Statoil announces dividend payments in connection with
quarterly results. Payment of quarterly dividends is expected to take place
approximately four months after the announcement of each quarterly dividend.  The board of directors updated the dividend
policy in 2015 to reflect USD as the declaration currency.  The board of directors proposes to the AGM a
dividend of USD 0.2201 per share for the fourth quarter 2015 and the
introduction of a two-year scrip dividend programme for eligible shareholders
starting from the fourth quarter 2015. The scrip programme will give
shareholders the option to receive quarterly dividends in cash or in newly
issued shares in Statoil at a 5% discount for the fourth quarter 2015. The
Norwegian Government, as majority shareholder, supports the proposal and will
seek the Norwegian Parliament’s approval to vote in favour of the proposal at
the AGM. The Norwegian government intends to match subscription of shares by
minority shareholders, and thereby maintain its ownership share at 67%
throughout the programme.  6.1.1 Dividends  In 2014 Statoil implemented quarterly
dividend payments and from second quarter 2015 Statoil implemented USD as
dividend declaration currency.  Although we currently intend to pay quarterly
dividends on our ordinary shares, we cannot give an assurance that dividends
will be paid, or predict the amount of any dividends. Future dividends will
depend on a number of factors prevailing at the time our board of directors
considers any dividend payment. The following table shows the cash dividend
amounts to all shareholders since 2010 on a per share basis and in aggregate.  Ordinary dividend per share
 
 
 Ordinary dividend per shareFiscal
  year
 Curr.
 Q1
 
 Curr.
 Q2
 
 Curr.
 Q3
 
 Curr.
 Q4
 
 Curr.2011
 
 
 
 
 
 
 
 
 
 
 
 
 NOK
 6.50002012
 
 
 
 
 
 
 
 
 
 
 
 
 NOK
 6.75002013
 
 
 
 
 
 
 
 
 
 
 
 
 NOK
 7.00002014
 NOK
 1.8000
 
 NOK
 1.8000
 
 NOK
 1.8000
 
 NOK
 1.8000
 
 NOK
 7.20002015
 NOK
 1.8000
 
 
 
 
 
 
 
 
 
 
 NOK
 1.80002015
 
 
 
 USD
 0.2201
 
 USD
 0.2201
 
 USD
 0.2201
 
 USD
 0.6603
  Statoil commenced quarterly dividends in 2014. During 2015 Statoil
paid four quarterly dividends. The third quarter 2014 dividend was paid out in
February 2015, the fourth quarter 2014 dividend was paid out in May 2015, the
first quarter 2015 dividend was paid out in August 2015 and the second quarter
2015 dividend was paid out in November 2015. The third quarter 2015 dividend
was paid out in February 2016. The proposed fourth quarter 2015 dividend will
be considered at the annual general meeting 11 May 2016. The Statoil share will
be traded ex dividend 12 May 2016 and if approved, the dividend will be
disbursed around late June 2016. For US ADR holders, the ex-dividend date will
be 12 May 2016 and expected payment date for ADR holders will be in June 2016.  From the second quarter 2015 Statoil implemented declaring
dividends in USD. As from the third quarter 2015 only dividend in USD per share
will be announced. Dividends in NOK per share will be communicated four
business days after record date for shareholders at Oslo Børs. Since we will declare
dividends in USD, exchange rate fluctuations will affect the amounts in NOK
received by shareholders on the OsloBørs.  Share repurchase In addition to a cash dividend, Statoil may buy back shares as
part of its total distribution of capital to its shareholders. For the period
2013-2015, the board of directors was authorised by the annual general meeting
of Statoil to repurchase Statoil shares in the market for subsequent annulment.
We have not undertaken any share repurchase based on this authorisation.  112Statoil, Annual Report on Form 20-F 2015


---

It is Statoil’s intention
to renew this authorisation at the annual general meeting. Statoil intends to
use share buybacks more actively going forward, based on balance sheet strength
considerations.   Statoil, Annual Report on Form 20-F
2015113


---

6.2
Shares purchased by issuer  Shares are acquired in the market for
transfer to employees under the share savings scheme in accordance with the
limits set by the board of directors. No shares were repurchased in the market
for the purpose of subsequent annulment in 2015.  6.2.1 Statoil's share savings plan  Since 2004, Statoil has had a share savings plan for employees of
the company. The purpose of this plan is to strengthen the business culture and
encourage loyalty through employees becoming part-owners of the company.  Through regular salary deductions, employees can invest up to 5%
of their base salary in Statoil shares. In addition, the company contributes
20% of the total share investment made by employees in Norway, up to a maximum
of NOK 1,500 per year (approximately USD 170). This company contribution is a
tax-free employee benefit under current Norwegian tax legislation. After a
lock-in period of two calendar years, one extra share will be awarded for each
share purchased. Under current Norwegian tax legislation, the share award is a
taxable employee benefit, with a value equal to the value of the shares and
taxed at the time of the award.  The board of directors is authorised to acquire Statoil shares in
the market on behalf of the company. The authorisation may be used to acquire
own shares for a total nominal value of up to NOK 35 million. Shares acquired
under this authorisation may only be used for sale and transfer to employees of
the Statoil group as part of the company's share savings plan as approved by
the board of directors. The minimum and maximum amount that may be paid per
share is NOK 50 and 500, respectively.  The authorisation is valid until the next annual general meeting,
but not beyond 30 June 2016. This authorisation replaces the previous authorisation
to acquire Statoil's own shares for implementation of the share savings plan
granted by the annual general meeting 14 May 2014.It is Statoil’s intention
to renew this authorisation at the annual general meeting. Statoil intends to
use share buybacks more actively going forward, based on balance sheet strength
considerations.  The nominal value of each share is NOK 2.50. With a maximum
overall nominal value of NOK 35 million, the authorisation for the repurchase
of shares in connection with the group's share savings plan covers the repurchase
of no more than 14 million shares.  Period
  in which shares were repurchased
 Number of shares repurchased
 Average price per share in NOK
 Total number of shares purchased as part of programme
 Maximum number of shares that may yet be purchased under the
  programme authorisation1)Jan-15
 713,771
 130.6301
 4,713,258
 6,286,742Feb-15
 628,251
 149.5611
 5,341,509
 5,658,491Mar-15
 700,062
 134.5595
 6,041,571
 4,958,429Apr-15
 598,244
 157.0929
 6,639,815
 4,360,185May-15
 605,625
 154.6826
 7,245,440
 3,754,560Jun-15
 664,037
 140.9826
 664,037
 13,335,963Jul-15
 661,604
 141.2402
 1,325,641
 12,674,359Aug-15
 707,278
 132.0766
 2,032,919
 11,967,081Sep-15
 781,215
 119.1604
 2,814,134
 11,185,866Oct-15
 661,646
 140.4563
 3,475,780
 10,524,220Nov-15
 717,182
 129.8833
 4,192,962
 9,807,038Dec-15
 750,203
 123.5585
 4,943,165
 9,056,835Jan-16
 878,834
 102.6997
 5,821,999
 8,178,001Feb-16
 745,858
 117.5826
 6,567,857
 7,432,143TOTAL
 9,813,810 2)
 132.4013 3)1)
 The authorisation to
  repurchase a maximum of 11 million shares with a maximum overall nominal
  value of NOK 27.5 million for repurchase of shares in connection with the
  share savings plan was given by the annual general meeting on 14 May 2014.
  The authorisation was maintained by the annual general meeting on 19 May 2015
  at a maximum of 14 million shares with a maximum overall nominal value of 35
  million forrepurchase of shares, valid until 30 June 2016.2)
 All shares repurchased
  have been purchased in the open market and pursuant to the authorisation
  mentioned above.3)
 Weighted average price
  per share.
  114Statoil, Annual Report on Form 20-F 2015


---

6.3
Information and communications  Updated information about
Statoil's financial performance and future prospects forms the basis for
assessing the value of the company.  Information provided to
the stock market must be transparent and ensure equal treatment of all
shareholders, and it must aim to provide shareholders with correct, clear,
relevant and timely information that forms the basis for assessing the value of
the company.  Statoil shares are listed on the OsloBørs, and its
American Depositary Receipts (ADRs) are listed on the New York Stock Exchange.
We distribute share price-sensitive information through the international wire
services, the OsloBørsin Norway, the Securities and Exchange Commission in the US, and
our websiteStatoil.com.  Our registrar manages our
shares listed on the OsloBørs on our behalf and provides the connection to the Norwegian
Central Securities Depository (VPS). Important services provided by the
registrar are investor services for private shareholders, the disbursement of
dividends and assistance at our general meetings. DnB Bank is currently the
account registrar for Statoil.  6.3.1 Investor contact  Our investor relations staff function (IR)
coordinates the dialogue with our shareholders. We place great emphasis on
ensuring that relevant and timely information is distributed to the capital
markets. Given the size and diversity of our shareholder base, the
opportunities for direct shareholder interaction are limited. Our
"Investor Centre" web pages are therefore specially designed for
investors and analysts who wish to follow the company's progress -Statoil.com/IR. We broadcast our quarterly
presentations and other relevant presentations by management directly on the
internet, and the related reports are made available together with other
relevant information on our website. Ticker Codes: OsloBørs: STL New York Stock Exchange:
STO Reuters: STL.OL Bloomberg: STL NO Financial calendar for 2016  04 February
 Fourth quarter
  results and strategy update16 February
 Q3 2015 ADS
  trading ex-dividend17 February
 Q3 2015
  ordinary share trading ex-dividend26 February
 Q3 2015
  ordinary share dividend payment04 March
 Q3 2015 ADS
  dividend payment18 March
 Publication annual
  report 201527 April
 First quarter
  201611 May
 Annual
  general meeting12 May
 Q4 2015 ADS
  trading ex-dividend12 May
 Q4 2015
  ordinary share trading ex-dividendJune
 Q4 2015
  ordinary share dividend paymentJune
 Q4 2015 ADS
  dividend payment27 July
 Second
  quarter 2016end August
 Q1 2016 ADS
  trading ex-dividendend August
 Q1 2016
  ordinary share trading ex-dividendend August
 Q1 2016
  ordinary share dividend paymentearly September
 Q1 2016 ADS
  dividend payment27 October
 Third quarter
  2016end November
 Q2 2016 ADS
  trading ex-dividendend November
 Q2 2016
  ordinary share trading ex-dividendend November
 Q2 2016
  ordinary share dividend paymentearly December
 Q2 2016 ADS
  dividend payment
  Statoil, Annual Report on Form 20-F
2015115


---

6.4
Market and market prices  The principal trading market for our ordinary
shares is the Oslo Børs. The ordinary shares are also listed on the New York
Stock Exchange, trading in the form of American Depositary Shares (ADS).  Statoil's shares have been listed on the Oslo
Børst since our initial public offering on 18 June 2001. The ADSs traded on the
New York Stock Exchange are evidenced by American Depositary Receipts (ADR),
and each ADS represents one ordinary share. Statoil has a sponsored ADR
facility with Deutsche Bank Trust Company Americas as depositary.  6.4.1 Share prices  These are the reported high and low
quotations at market closing for the ordinary shares on the Oslo Børs and New
York Stock Exchange for the periods indicated.  They are derived from the Oslo Børs Daily
Official List, and the highest and lowest sales prices of the ADSs as reported
on the New York Stock Exchange composite tape.  NOK per ordinary share
 
 USD per ADSShare
  price
 High
 Low
 
 High
 LowYear ended 31 December2011
 160.50
 113.70
 
 29.58
 20.162012
 162.40
 133.80
 
 28.92
 22.152013
 147.70
 123.00
 
 27.00
 20.142014
 194.80
 120.00
 
 31.91
 15.822015
 160.80
 116.30
 
 21.31
 13.42Quarter endedMonday, March 31, 2014
 171.30
 146.40
 
 28.51
 23.37Monday, June 30, 2014
 194.80
 164.90
 
 31.91
 27.60Tuesday, September 30,
  2014
 191.00
 171.90
 
 31.01
 26.93Tuesday, December 31,
  2014
 173.70
 120.00
 
 26.79
 15.82Tuesday, March 31, 2015
 149.80
 125.80
 
 19.62
 16.25Tuesday, June 30, 2015
 160.80
 140.10
 
 21.31
 17.59Wednesday, September 30,
  2015
 141.40
 116.30
 
 17.56
 13.85Wednesday, December 30,
  2015
 145.60
 118.70
 
 17.74
 13.42March, up until 8 March
  2016
 133.80
 97.90
 
 15.94
 11.38Month ofSeptember 2015
 126.80
 116.80
 
 15.31
 13.85October 2015
 144.70
 126.40
 
 17.74
 14.83November 2015
 145.60
 129.70
 
 17.06
 14.90December 2015
 135.70
 118.70
 
 15.70
 13.42January 2016
 123.50
 97.90
 
 13.96
 11.38February 2016
 127.10
 108.00
 
 14.56
 12.49March up until 8 March
  2016
 133.80
 127.30
 
 15.94
 14.78
 116Statoil, Annual Report on Form 20-F 2015


---

6.4.2 Statoil ADR programme fees  Fees
and charges payable by a holder of ADSs.  As
depositary from 31 January 2013, Deutsche Bank Trust Company Americas collects
its fees for the delivery and surrender of ADSs directly from investors
depositing shares or surrendering ADSs for the purpose of withdrawal, or from
intermediaries acting for them. The depositary collects fees from investors by
deducting the fees from the amounts distributed or by selling a portion of
distributable property to pay the fees. The depositary may refuse to provide
fee-attracting services until its fees for those services are paid.  The
charges of the depositary payable by investors are as follows:  Persons
  depositing or withdrawing shares must pay:
 For:USD
  5.00 (or less) per 100 ADSs (or portion of 100 ADSs)
 ·Issuance
  of ADSs, including issuances resulting from a distribution of shares or
  rights or other property·Cancellation
  of ADSs for the purpose of withdrawal, including if the deposit agreement
  terminatesUSD
  0.02(or less) per ADS, subject to the company's consent
 ·Any
  cash distribution to ADS registered holdersUSD
  0.05 (or less) per ADS, subject to the company's consent
 ·For
  the operation and maintenance costs in administering the ADR programA
  fee equivalent to the fee that would be payable if securities distributed to
  you had been shares and the shares had been deposited for issuance of ADSs
 ·Distribution
  of securities distributed to holders of deposited securities which are
  distributed by the Depositary to ADS registered holdersRegistration
  or transfer fees
 ·Transfer
  and registration of shares on our share register to or from the name of the
  Depositary or its agent when you deposit or withdraw sharesExpenses
  of the Depositary
 ·Cable,
  telex and facsimile transmissions (as provided in the deposit agreement)·Converting
  foreign currency to US dollarsTaxes
  and other governmental charges the Depositary or the custodian have to pay on
  any ADS or share underlying an ADS, for example, stock transfer taxes, stamp
  duty or withholding taxes
 ·As
  necessaryAny
  charges incurred by the Depositary or its agents for servicing the deposited
  securities
 ·As
  necessary
    Reimbursements and payments made and fee
waivers granted by the depositary The depositary has agreed to reimburse
certain company expenses related to the company's ADR programme and incurred by
the company in connection with the programme. In the year ended 31 December
2015, the depositary reimbursed approximately USD 1.43 million to the companyin relation to certain expenses including investor
relations expenses, expenses related to the maintenance of the ADR programme,
legal counsel fees, printing and ADR certificates.  The depositary has also agreed to waive fees
for costs associated with the administration of the ADR programme, and it has
paid certain expenses directly to third parties on behalf of the company. The
expenses paid to third parties include expenses relating to reporting services
and access charges to its online platform, re-registration costs borne by the
custodian. For the year ended 31 December 2015, the depositary paid expenses of
approximately USD 69,576 directly to third parties. Statoil, Annual Report on Form 20-F
2015117


---

6.5 Taxation  This
section describes the material Norwegian tax consequences that apply to
shareholders resident in Norway and to non-resident shareholders in connection
with the acquisition, ownership and disposal of shares and American Depositary
Shares (ADS). The term “shareholder” refers to both holders of shares and
holders of ADSs, unless otherwise explicitly stated.  Norwegian
tax matters The
outline does not provide a complete description of all tax regulations that
might be relevant (i.e. for investors to whom special regulations may be
applicable), and is based on current law and practice. Shareholders should
consult their professional tax adviser for advice about individual tax
consequences. Taxation of dividends Corporate
shareholders (i.e. limited liability companies and similar entities) residing
in Norway for tax purposes are generally subject to tax in Norway on dividends
received from Norwegian companies. The basis for taxation is 3% of the
dividends received, which is subject to the standard income tax rate. The
standard income tax rate has been reduced from 27% in 2015 to 25% in 2016.  Individual
shareholders resident in Norway for tax purposes are subject to the standard
income tax rate (reduced from 27% in 2015 to 25% in 2016) in Norway for
dividend income exceeding a basic tax free allowance. However, in 2016 dividend
income exceeding the basic tax free allowance is grossed up with a factor of
1.15 before taken to taxation, resulting in an effective tax rate of 28.75%
(25% x 1.15). The tax free allowance is computed for each individual share or
ADS on the basis of the cost price of that share or ADS multiplied by a
risk-free interest rate. The risk-free interest rate will be determined every
income year. Any part of the calculated allowance for one year that exceeds the
dividend distributed for the share or ADS ("unused allowance") may be
carried forward and set off against future dividends received for (or gains
upon the realisation of, see below) the same share or ADS. Any unused allowance will also be added to
the basis for computation of the allowance for the same share or ADS the
following year.  Non-resident
shareholders are as a rule subject to withholding tax at a rate of 25% on
dividends distributed by Norwegian companies. This withholding tax does not
apply to corporate shareholders in the EEA area that document that they are
genuinely established and carry on genuine economic business activity within
the EEA area, provided that Norway is entitled to receive information from the
state of residence pursuant to a tax treaty or other international treaty. If
no such treaty exists with the state of residence, the shareholder may instead
present confirmation issued by the tax authorities of the state of residence
verifying the documentation. Individual shareholders resident for tax purposes
in the EEA area may apply to the Norwegian tax authorities for a refund if the
tax withheld by the distributing company exceeds the tax that would have been
levied on individual shareholders resident in Norway.  The
withholding rate of 25% is often reduced in tax treaties between Norway and
other countries. Generally, the treaty rate does not exceed 15% and, in cases
where a corporate shareholder holds a qualifying percentage of ownership in the
distributing company, the withholding tax rate on dividends may be further
reduced. The withholding tax rate in the tax treaty between the United States
and Norway is currently 15% in all cases. It is the responsibility of the
distributing company to deduct the withholding tax when dividends are paid to
non-resident shareholders.  The
reduced withholding rate will generally only apply to dividends paid on shares
held by shareholders who are able to properly demonstrate to the company that
they are entitled to the benefits of the tax treaty.  For
holders of shares and ADSs deposited with Deutsche Bank Trust Company Americas
(Deutsche Bank), documentation establishing that the holder is eligible for the
benefits under the tax treaty with Norway, may be provided to Deutsche Bank.
Deutsche Bank has been granted permission by the Norwegian tax authorities to
receive dividends from us for redistribution to a beneficial owner of shares
and ADSs at the applicable treaty withholding rate.  Dividends
paid to shareholders (either directly or through a depositary) who have not
provided the relevant documentation to the relevant party that they are
eligible for the reduced rate, will be subject to withholding tax of 25%. The
beneficial owners will in this case have to apply to the Central Office -
Foreign Tax Affairs (COFTA) for a refund of the excess amount of tax withheld.  According
to information provided by the Central Office of Foreign Tax Affairs (COFTA),
an application for a refund of withholding tax from shareholders must contain
the following:  1.Full
name, address and tax identification number of the claimant. 2.Payment
details, including name of account holder, either a Norwegian bank account
number or IBAN and SWIFT/BIC code. The IBAN account must be able to receive NOK
as the refund will be transferred in NOK. 3.A
specification of the Norwegian company(ies) involved, the exact amount of
shares, the date of each dividend payment, the dividend per share, the total
dividend payment, the Norwegian withholding tax rate, and the reclaimed amount.
All amounts must be given in NOK. 4.Documentation
that confirms the claimant’s residency. 118Statoil, Annual Report on Form 20-F 2015


---

·A claim according to a tax
treaty must contain a Certificate of Residence issued by the competent local
tax authorities with reference to the claimant's tax identification number. The
certificate of residence must state that the claimant was resident according to
the tax treaty with Norway during the year when the decision to distribute the
dividend was made. The confirmation must be in original. The Certificate of
Residence must mention solely the claimant’s name ·A claim
according to the tax exemption method cf. tax act section 2-38 must contain
confirmation that the claimant is registered and based within the EEA and genuinely
established in that country 5.A
credit advice, certifying that the claimant has received the dividends and has
been subject to Norwegian withholding tax on the dividends. The credit advice
must fill the following criteria: ·It must
document the chain of transactions, including information about the foreign
custodian/bank/clearing central registered in Norway that initially received
the dividends. If the dividends have been paid through a chain of transactions,
each transaction must be documented with a credit advice issued to the initial
receiver ·It must
be issued by the bank that credits the claimant the dividend payment. It must
contain the following details: ·Name of
the payment recipient, i.e. the claimant ·Name
and ISIN of the stock etc ·The
exact amount of shares ·The
gross amount and withholding tax in NOK ·The
ex-date, the record date and the pay-date ·The
dividend per share Please note that the credit advice must specify that the
dividend payment has been subject to withholding tax, not just tax. This
clarification will be a definite requirement on claims made from 1 January 2014
onward. 6.Power
of attorney/attestation, a general power of attorney from the beneficial owner
to authorise the claimant to claim a refund. The power of attorney does not need to mention the
specific dividend payments. Still, COFTA requires that the claimant makes a
spreadsheet listing the names of the companies from which the dividends were
received, with the dates and the amounts of withholding tax. This spreadsheet
should accompany the application and has to be approved and signed by the
beneficial owner. Please note that only one refund claim can be made
regarding each dividend payment, and applications for the same claim must not
be filed several times, neither directly nor via custodians. 7.A claim
should also contain general information about the claimant as regards legal,
corporate and taxable aspects. Please note that only the beneficial owner may
apply for a refund of withholding tax. An entity that is acting on behalf of
someone else as either trustee or investment manager, and who is as such the
registered or indirect owner of the dividends, is not entitled to a refund.
Neither is an entity that receives the dividend payments and passes them
directly on to other entities/persons entitled to a refund.  In
some cases COFTA may request further, and more specific, information about the
claim for refund and the claimant. An assessment of the entity and of the
validity of the claim is made in each individual case.  The
application should be sent to the following address: Central Office Foreign Tax
Affairs/Sentralskattekontoret for utenlandssaker, Postboks 8031, 4068
Stavanger, NORWAY  Corporate
shareholders that carry on business activities in Norway, and whose shares or
ADSs are effectively connected with such activities are not subject to
withholding tax. For such shareholders, 3% of the received dividends are
subject to the standard income tax rate (reduced from 27% in 2015 to 25% in
2016). Taxation on the realisation
of shares and ADSs Corporate
shareholders resident in Norway for tax purposes are not subject to tax in
Norway on gains derived from the sale, redemption or other disposal of shares
or ADSs in Norwegian companies. Capital losses are not deductible.  Individual
shareholders residing in Norway for tax purposes are subject to tax in Norway
on the sale, redemption or other disposal of shares or ADSs. Gains or losses in
connection with such realisation are included in the individual's ordinary
taxable income in the year of disposal, which is subject to the standard income
tax rate, being reduced from 27% in 2015 to 25% in 2016. However, in 2016 the
taxable gain or deductible loss is grossed up with a factor of 1.15 before
included in the ordinary taxable income, resulting in an effective tax rate of
28.75% (25% x 1.15).  The
taxable gain or deductible loss (before gross up) is calculated as the sales
price adjusted for transaction expenses minus the taxable basis. A
shareholder's tax basis is normally equal to the acquisition cost of the shares
or ADSs. Any unused allowance pertaining to a share may be deducted from a
taxable gain on the same share or ADS, but may not lead to or increase a
deductible loss. Furthermore, any unused allowance may not be set off against
gains from the realisation of the other shares or ADSs.  If
the shareholder disposes of shares or ADSs acquired at different times, the
shares or ADSs that were first acquired will be deemed to be first sold (the
"FIFO" principle) when calculating the taxable gain or loss.  A
corporate shareholder or an individual shareholder who ceases to be tax
resident in Norway due to domestic law or tax treaty provisions may, in certain
circumstances, become subject to Norwegian exit taxation on capital gains related
to shares or ADSs.  Shareholders
not residing in Norway are generally not subject to tax in Norway on capital
gains, and losses are not deductible on the sale, redemption or other disposal
of shares or ADSs in Norwegian companies, unless the shareholder carries on
business activities in Norway and such shares or ADSs are or have been
effectively connected with such activities. Statoil, Annual Report on Form 20-F
2015119


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Wealth
tax The
shares or ADSs are included in the basis for the computation of wealth tax
imposed on individuals resident in Norway for tax purposes. Norwegian limited
companies and certain similar entities are not subject to wealth tax. The
current marginal wealth tax rate is 0.85% of the value assessed. The assessment
value of listed shares (including ADSs) is 100% of the listed value of such
shares or ADSs on 1 January in the assessment year.  Non-resident
shareholders are not subject to wealth tax in Norway for shares and ADSs in
Norwegian limited companies unless the shareholder is an individual and the
shareholding is effectively connected with the individual's business activities
in Norway. Inheritance tax and gift
tax No
inheritance or gift tax is imposed in Norway. Transfer tax No
transfer tax is imposed in Norway in connection with the sale or purchase of
shares or ADSs.  United States tax matters This
section describes the material United States federal income tax consequences
for US holders (as defined below) of owning shares or ADSs. It only applies to
you if you hold your shares or ADSs as capital assets for tax purposes. This
section does not apply to you if you are a member of a special class of holders
subject to special rules, including: ·dealers
in securities ·traders
in securities that elect to use a mark-to-market method of accounting for their
securities holdings ·tax-exempt
organisations ·life
insurance companies ·persons
liable for alternative minimum tax ·persons
that actually or constructively own 10% or more of the voting stock of Statoil ·persons
that hold shares or ADSs as part of a straddle or a hedging or conversion
transaction ·persons
that purchase or sell shares or ADSs as part of a wash sale for tax purposes or ·persons
whose functional currency is not USD  This
section is based on the Internal Revenue Code of 1986, as amended, its legislative
history, existing and proposed regulations, published rulings and court
decisions, and the Convention between the United States of America and the
Kingdom of Norway for the Avoidance of Double Taxation and the Prevention of
Fiscal Evasion with Respect to Taxes on Income and Property (the ''Treaty'').
These laws are subject to change, possibly on a retroactive basis. In addition,
this section is based in part upon the representations of the depositary and
the assumption that each obligation in the deposit agreement and any related
agreement will be performed in accordance with its terms. For United States
federal income tax purposes, if you hold ADRs evidencing ADSs, you will
generally be treated as the owner of the ordinary shares represented by those ADRs.
Exchanges of shares for ADRs and ADRs for shares will not generally be subject
to United States federal income tax.  If
a partnership holds the shares or ADSs, the United States federal income tax
treatment of a partner will generally depend on the status of the partner and
the tax treatment of the partnership. A partner in a partnership holding the
shares or ADSs should consult its tax adviser with regard to the United States
federal income tax treatment of an investment in the shares or ADSs.  You
are a ''US holder'' if you are a beneficial owner of shares or ADSs and you are
for United States federal income tax purposes: ·a
citizen or resident of the United States; ·a
United States domestic corporation; ·an
estate whose income is subject to United States federal income tax regardless
of its source; or ·a trust
if a United States court can exercise primary supervision over the trust's
administration and one or more United States persons are authorised to control
all substantial decisions of the trust.  You
should consult your own tax adviser regarding the United States federal, state
and local and Norwegian and other tax consequences of owning and disposing of
shares and ADSs in your particular circumstances.  Taxation of dividends If
you are a US holder, the gross amount of any dividend paid by Statoil out of
its current or accumulated earnings and profits (as determined for United
States federal income tax purposes) is subject to United States federal income
taxation. If you are a non-corporate US holder, dividends paid to you will be
eligible to be taxed at the preferential rates applicable to long-term capital
gains as long as, in the year that you receive the dividend, the shares or ADSs
are readily tradable on an established securities market in the United States
or Statoil is eligible for benefits under the Treaty. To qualify for the
preferential rates, you must hold the shares or ADSs for more than 60 days
during the 121-day period beginning 60 days before the ex-dividend date and
meet certain other requirements. Furthermore, these tax consequences would be
different if Statoil were to be treated as a PFIC as discussed below.  You must include any Norwegian tax withheld from the
dividend payment in this gross amount even though you do not in fact receive
the amount withheld as tax. The dividend is taxable for you when you, in the
case of shares, or the depositary, in the case of ADSs, receive the dividend,
actually or constructively. The dividend will not be eligible for the
dividends-received deduction generally allowed to United States corporations in
respect of dividends received from other United States corporations.  120Statoil, Annual Report on Form 20-F 2015


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The amount of the dividend distribution that you must
include in your income as a US holder will be the value in USD of the payments
made in NOK determined at the spot NOK/USD rate on the date the dividend
distribution is includible in your income, regardless of whether or not the
payment is in fact converted into USD. Distributions in excess of current and
accumulated earnings and profits, as determined for United States federal
income tax purposes, will be treated as a non-taxable return of capital to the
extent of your tax basis in the shares or ADSs and, to the extent in excess of
your tax basis, will be treated as capital gain.  Subject
to certain limitations, the 15% Norwegian tax withheld in accordance with the
Treaty and paid to Norway will be creditable or deductible against your United
States federal income tax liability. Special rules apply when determining the
foreign tax credit limitation with respect to dividends that are subject to the
preferential rates. To the extent that a refund of the tax withheld is
available to you under Norwegian law, the amount of tax withheld that is
refundable will not be eligible for credit against your United States federal
income tax liability. Dividends will be income from sources outside the United
States and will generally, depending on your circumstances, be either
''passive'' or ''general'' income for purposes of computing the foreign tax credit
allowable to you.  Any
gain or loss resulting from currency exchange rate fluctuations during the
period from the date you include the dividend payment in income until the date
you convert the payment into USD will generally be treated as ordinary income
or loss and will not be eligible for the special tax rate. Such gain or loss
will generally be income or loss from sources within the United States for
foreign tax credit limitation purposes.  Taxation of capital gains Subject
to the PFIC rules discussed below, if you are a US holder and you sell or
otherwise dispose of your shares or ADSs, you will generally recognise a
capital gain or loss for United States federal income tax purposes equal to the
difference between the value in USD of the amount that you realise and your tax
basis, determined in USD, in your shares or ADSs. A capital gain of a
non-corporate US holder is generally taxed at preferential rates if the
property is held for more than one year. The gain or loss will generally be
income or loss from sources within the United States for foreign tax credit
limitation purposes.  If
you receive any foreign currency on the sale of shares or ADSs, you may
recognise ordinary income or loss from sources within the United States as a
result of currency fluctuations between the date of the sale of the shares or
ADSs and the date the sales proceeds are converted into USD. You should consult
your own tax adviser regarding how to account for payments made or received in
a currency other than USD.  PFIC rules We
believe that the shares and ADSs should not be treated as stock of a PFIC for
United States federal income tax purposes, but this conclusion is a factual
determination that is made annually and thus may be subject to change. If we
were to be treated as a PFIC, unless a US holder elects to be taxed annually on
a mark-to-market basis with respect to the shares or ADSs, a gain realised on
the sale or other disposition of the shares or ADSs would in general not be
treated as a capital gain. Instead, if you are a US holder, you would be
treated as if you had realised such gain and certain "excess
distributions" ratably over your holding period for the shares or ADSs.
Amounts allocated to the year in which the gain is realised or the “excess
distribution” is received or to a taxable year before we were classified as a
PFIC would be subject to tax at ordinary income tax rates, and amounts
allocated to all other years would be taxed at the highest tax rate in effect
for each such year to which the gain or distribution was allocated, together
with an interest charge in respect of the tax attributable to each such year.
With certain exceptions, the shares or ADSs will be treated as stock in a PFIC
if we were a PFIC at any time during the period you held the shares or ADSs.
Dividends that you receive from us will not be eligible for the preferential
tax rates if we are treated as a PFIC with respect to you, either in the
taxable year of the distribution or the preceding taxable year, but will
instead be taxable at rates applicable to ordinary income.  Tax Filings You
should consult your own advisers regarding any tax filing or reporting
obligations that arise out of the acquisition, ownership or disposition of
shares or ADSs. Failure to comply with certain US tax filing or reporting
obligations can cause you to be subject to significant penalties.  6.6 Exchange controls and limitations  Under Norwegian foreign exchange controls currently in effect,
transfers of capital to and from Norway are not subject to prior government
approval.  An exception applies to the physical transfer of payments in
currency exceeding certain thresholds, which must be declared to the Norwegian
custom authorities.  This means that non-Norwegian resident shareholders may receive
dividend payments without Norwegian exchange control consent as long as the
payment is made through a licensed bank or other licensed payment institution.  There are no restrictions affecting the rights of non-Norwegian
residents or foreign owners to hold or vote for our shares.  Statoil, Annual Report on Form 20-F
2015121


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6.7
Exchange rates  The table below shows the high, low, average
and end-of-period exchange rates for the Norwegian krone for USD 1.00 as
announced by Norges Bank (Norway's central bank).  The average is computed using the monthly
average exchange rates announced by Norges Bank during the period indicated.  For the
  year ended 31 December
 Low
 High
 Average
 End of Period2011
 5.2369
 6.0315
 5.6059
 5.99272012
 5.5349
 6.1471
 5.8172
 5.56642013
 5.4438
 6.2154
 5.8753
 6.08372014
 5.8611
 7.6111
 6.3011
 7.43322015
 7.3593
 8.8090
 8.0637
 8.8090
  Low
 High2015September
 8.0891
 8.5783October
 8.0524
 8.5700November
 8.4636
 8.6929December
 8.4842
 8.80902016January
 8.6641
 8.9578February
 8.5111
 8.7294March (up to and
  including 8 March 2016)
 8.5441
 8.6791
  On 8March
2016, the exchange rate announced by the Norges Bank for the Norwegian krone
was USD 1.00 = NOK 8.5496.  Fluctuations in the exchange rate between the
Norwegian krone and the US dollar will affect the amounts in US dollars
received by holders of American Depositary Shares (ADSs) on the conversion of
dividends, if any, paid in Norwegian kroner on the ordinary shares, and they
may affect the US dollar price of the ADSs on the New York Stock Exchange. 122Statoil, Annual Report on Form 20-F 2015


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6.8 Major
shareholders  The Norwegian State is the largest shareholder in Statoil, with a
direct ownership interest of 67%. Its ownership interest is managed by the
Norwegian Ministry of Petroleum and Energy.  Pursuant to the
  exchange ratio agreed in connection with the merger with Hydro's oil and gas
  activities, the State's ownership interest in the merged company was 62.5%,
  or 1,992,959,739 shares, on 1 October 2007. In accordance with the Norwegian
  parliament's decision of 2001 concerning a minimum state shareholding in
  Statoil of two-thirds, the Government built up the State's ownership interest
  in Statoil by buying shares in the market during the period from June 2008 to
  March 2009. In March 2009, the Government announced that the State's direct
  ownership interest had reached 67%, and the Government's direct purchase of
  Statoil shares was completed.
  
  As of 31 December
  2015, the Norwegian State had a 67% direct ownership interest in Statoil and
  a 3.23% indirect interest through the National Insurance Fund (Folketrygdfondet),
  totaling 70.23%.
  
  The
  Norwegian State is the only person or entity known to us to own beneficially,
  directly or indirectly, more than 5% of our outstanding shares. We have not
  been notified of any other beneficial owner of 5%or more of our ordinary
  shares as of 31 December 2015.
  Statoil has one class of shares, and each
  share confers one vote at the general meeting. The Norwegian State does not
  have any voting rights that differ from the rights of other ordinary
  shareholders. Pursuant to the Norwegian Public Limited Liability Companies
  Act, a majority of at least two-thirds of the votes cast as well as of the
  votes represented at a general meeting is required to amend our articles of
  association. As long as the Norwegian State owns more than one-third of our
  shares, it will be able to prevent any amendments to our articles of
  association. Since the Norwegian State, acting through the Norwegian Minister
  of Petroleum and Energy, has in excess of two-thirds of the shares in the
  company, it has sole power to amend our articles of association. In addition,
  as majority shareholder, the Norwegian State has the power to control any
  decision at general meetings of our shareholders that requires a majority
  vote, including the election of the majority of the corporate assembly, which
  has the power to elect our board of directors and approve the dividend
  proposed by the board of directors.
  The Norwegian State endorses the principles
  set out in "The Norwegian Code of Practice for Corporate
  Governance", and it has stated that it expects companies in which the
  State has ownership interests to adhere to the code. The principle of
  ensuring equal treatment of different groups of shareholders is a key element
  in the State's own guidelines. In companies in which the State is a
  shareholder together with others, the State wishes to exercise the same
  rights and obligations as any other shareholder and not act in a manner that
  has a detrimental effect on the rights or financial interests of other
  shareholders. In addition to the principle of equal treatment of
  shareholders, emphasis is also placed on transparency in relation to the
  State's ownership and on the general meeting being the correct arena for
  owner decisions and formal resolutions.
  Statoil, Annual Report on Form 20-F
2015123


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Shareholders at December 2015
 Number of Shares
 Ownership in %1
 Government of Norway
 2,136,393,559
 67.00%2
 Folketrygdfondet
 103,124,812
 3.20%3
 SAFE Investment Company
  Limited
 32,256,434
 1.00%4
 BlackRock Institutional
  Trust Company, N.A.
 31,513,618
 1.00%5
 INVESCO Asset Management
  Limited
 26,461,451
 0.80%6
 Schroder Investment
  Management Ltd. (SIM)
 23,330,607
 0.70%7
 The Vanguard Group, Inc.
 19,539,470
 0.60%8
 Allianz Global Investors
  GmbH
 18,371,484
 0.60%9
 KLP Forsikring
 16,642,798
 0.50%10
 Storebrand
  Kapitalforvaltning AS
 14,448,698
 0.50%11
 BlackRock Investment
  Management, LLC
 13,995,472
 0.40%12
 Epoch Investment
  Partners, Inc.
 13,815,430
 0.40%13
 State Street Global
  Advisors (US)
 13,670,590
 0.40%14
 DNB Asset Management AS
 13,641,273
 0.40%15
 Fidelity Worldwide
  Investment (UK) Ltd.
 11,886,480
 0.40%16
 Acadian Asset Management
  LLC
 11,578,950
 0.40%17
 TIAA-CREF
 11,231,159
 0.40%18
 T. Rowe Price
  Associates, Inc.
 11,003,874
 0.30%19
 APG Asset Management
 10,436,861
 0.30%20
 AXA Investment Managers
  UK Ltd.
 10,075,894
 0.30%Source: Data collected
  by third party, authorized by Statoil, December 2015
 124Statoil, Annual Report on Form 20-F 2015


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7 Corporate governance  Statoil's
objective is to create long-term value for its shareholders through the
exploration for and production, transportation, refining and marketing of
petroleum and petroleum-derived products and other forms of energy.  In
pursuing its corporate objective, Statoil is committed to the highest standard
of governance and to cultivating a values-based performance culture that
rewards exemplary ethical practices, respect for the environment and personal
and corporate integrity. Statoil believes that there is a link between
high-quality governance and the creation of shareholder value.  The
work of the board of directors is based on the existence of a clearly defined
division of roles and responsibilities between the shareholders, the board of
directors and the company's management.  Statoil’s
governing structures and controls help to ensure that Statoil runs its business
in a profitable manner for the benefit of shareholders, employees and other
stakeholders in the societies in which Statoil operates.  The following principles underline Statoil’s approach to
corporate governance: ·All
shareholders will be treated equally ·Statoil
will ensure that all shareholders have access to up-to-date, reliable and
relevant information about its activities ·Statoil
will have a board of directors that is independent (as defined by Norwegian
Standards) of the group's management. The board focuses on preventing conflicts
of interest between shareholders, the board of directors and the company's
management ·The
board of directors will base its work on the principles for good corporate governance
applicable at all times  Corporate
governance in Statoil is subject to regular review and discussion by the board
of directors.  Statoil's
board of directors endorses the "Norwegian Code of Practice for Corporate
Governance". The company's compliance with, and deviations from, the
code's recommendations are commented on in a separate corporate governance
statement issued by Statoil’s board of directors. This statement, which
contains further details on the corporate governance of Statoil, is available
at www.statoil.com/cg.  7.1 Articles of association  The articles of association and the Norwegian
Public Limited Liability Companies Act form the legal framework for Statoil's
operations.  Statoil's current articles of association
wereadopted at theannual general meeting of shareholders on 14 May 2013.  Summary of Statoil’s
articles of association:  Name of the company The registered name is Statoil ASA. Statoil
is a Norwegian public limited company.  Registered office Statoil’s registered office is in Stavanger,
Norway, registered with the Norwegian Register of Business Enterprises under
number 923 609 016.  Object of the company The object of Statoil is, either by itself or
through participation in or together with other companies, to engage in the
exploration, production, transportation, refining and marketing of petroleum
and petroleum-derived products, and other forms of energy, as well as other
business.  Share capital Statoil’s share capital is NOK
7,971,617,757.50 divided into 3,188,647,103 ordinary shares.  Nominal value of shares The nominal value of each ordinary share is
NOK 2.50.  Board of directors Statoil’s articles of association provide
that the board of directors shall consist of nine to 11 directors. The board,
including the chair and the deputy chair, shall be elected by the corporate
assembly for a period of up to two years.  Corporate assembly Statoil has a corporate assembly comprising
18 members who are normally elected for a term of two years. The general
meeting elects 12 members with four deputy members, and six members with deputy
members are elected by and from among the employees. Statoil, Annual Report on Form 20-F
2015125


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General meetings of
shareholders Statoil’s annual general meeting is held no
later than 30 June each year.  The meeting will consider the annual report
and accounts, including the distribution of any dividend, and any other matters
required by law or the articles of association.  Documents relating to matters to be dealt
with at general meetings do not need to be sent to all shareholders if the
documents are accessible on Statoil’s website. A shareholder may nevertheless
request that such documents be sent to him/her.  Shareholders may vote in writing, including
through electronic communication, for a period before the general meeting. In
order to practise advance voting, the board of directors must stipulate
applicable guidelines. Statoil's board of directors adopted guidelines for such
advance voting in March 2012, and these guidelines are described in the notices
of the annual general meetings.  Marketing of petroleum on
behalf of the Norwegian State Statoil’s articles of association provide
that Statoil is responsible for marketing and selling petroleum produced under
the SDFI's shares in production licences on the Norwegian continental shelf
(NCS) as well as petroleum received by the Norwegian State paid as royalty
together with its own production. Statoil’s general meeting adopted an
instruction in respect of such marketing on 25 May 2001, as most recently amended
by authorisation of the annual general meeting on 19 May 2011.  Nomination committee The tasks of the nomination committee are to
make recommendations to the general meeting regarding the election of and fees
for shareholder-elected members and deputy members of the corporate assembly,
to make recommendations to the corporate assembly regarding the election of and
fees for shareholder-elected members of the board of directors, to make
recommendations to the corporate assembly regarding the election of the chair
and the deputy chair of the board and to make recommendations to the general
meeting regarding the election of and fees for members of the nomination
committee.  The general meeting may adopt instructions
for the nomination committee.  The full articles of association are
available at Statoil.com/articlesofassociation.  7.2 Code of Conduct  Ethics – Statoil’s approach Statoil believes that responsible and ethical behavior is a
necessary condition for a sustainable business. Statoil’s Code of Conduct (the
Code) is based on its values and reflects Statoil’s commitment to high ethical
standards in all its activities.  Our Code of Conduct The Code describes Statoil’s code of business practice and the
requirements to expected behavior in areas such as anti-corruption, fair
competition, human rights and non-discrimination working environments with
equal opportunity. The Code applies to Statoil’s board members, employees and
hired personnel.  Statoil seeks to work with others who share its commitment to
ethics and compliance, and Statoil manages its risks through in-depth knowledge
of suppliers, business partners and markets. Statoil expects its suppliers and
business partners to comply with applicable laws, respect internationally
recognised human rights and adhere to ethical standards which are consistent
with Statoil’s ethical requirements when working for or together with Statoil.
In joint ventures and entities where Statoil does not have control, Statoil
makes good faith efforts to encourage the adoption of ethics and
anti-corruption policies and procedures that are consistent with itss
standards. Anyone working for Statoil who does not comply with the Code faces
disciplinary action, up to and including summery dismissal or termination of
their contract. Training and Certifying the Code Code of Conduct training and comprehensive trainings on specific
issues, including anti-corruption and anti-trust, is carried out to explain how
the Code applies and to describe the tools that Statoil has made available to
address risk.  All Statoil employees have to annually confirm electronically that
they understand and will comply with the Code (Code certification). The Code
certification reminds the individuals of their duty to comply with Statoil’s
values and ethical requirements and creates an environment with open dialog on
ethical issues, both internally and externally.  Anti-corruption compliance programme Statoil is against all forms of corruption including bribery,
facilitation payments and trading in influence and has a company-wide
anti-corruption compliance programme which implements its zero-tolerance
policy. The programme includes mandatory procedures designed to comply with
applicable laws and regulations and training on relevant issues such as gifts,
hospitality and conflicts of interest. Compliance officers, who are responsible
for ensuring that ethics and anti-corruption considerations are integrated into
Statoil’s business activities, constitute an important part of the programme.  126Statoil, Annual Report on Form 20-F 2015


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In 2015, Statoil focused
on the systematic support and follow up of its compliance officers in the
business units and on strengthening the compliance officer network within
Statoil. Further, the Statoil Code of Conduct was subject to a comprehensive
review, and was updated and made more user-friendly.  In 2016 , the new Code
will be rolled out and implemented.  Speak Up Statoil is committed to maintain an open dialog on ethical issues.
The Code requires those who have a question or suspect misconduct to raise
their concern either through internal channels or through Statoil’s external
Ethics Helpline. Employees are encouraged to discuss their concerns with their
supervisor. Statoil recognises that raising a concern is not always easy so
there are have several internal channels for taking concerns forward, including
through human resources or the ethics and compliance function in the legal
department. Concerns can also be expressed through the externally operated
Ethics Helpline which is available 24/7, and allows for anonymous reporting and
two-way communication through the use of a pin-code. Statoil has a
non-retaliation policy for anyone who reports in good faith.  More information about Statoil’s policies and requirements related
to the Code of Conduct is available on Statoil.com/ethics.  7.3
General meeting of shareholders ﻿ The
general meeting of shareholders is Statoil’s supreme corporate body. The
objective of the general meeting is to ensure shareholder democracy and all
shareholders are encouraged to participate in person or by proxy.  The
general meeting of shareholders is Statoil’s supreme corporate body. The 2016 annual
general meeting (AGM) is scheduled for 11 May 2016 in Stavanger, Norway, with
simultaneous transmission by webcast through our website. The AGM is conducted
in Norwegian, with simultaneous English translation during the webcast.  The
main framework for convening and holding Statoil's AGM is as follows:  Pursuant
to Statoil’s articles of association, the AGM must be held by the end of June
each year. Notice of the meeting and documents relating to the AGM are
published on Statoil's website and notice is sent to all shareholders with
known addresses at least 21 days prior to the meeting. All shareholders who are
registered in the Norwegian Central Securities Depository (VPS) will receive an
invitation to the AGM. Other documents relating to Statoil's AGMs will be made
available on Statoil's website. A shareholder may nevertheless request that
documents that relate to matters to be dealt with at the AGM be sent to
him/her.  Shareholders
are entitled to have their proposals dealt with at the AGM if the proposal has
been submitted in writing to the board of directors in sufficient time to
enable it to be included in the notice of meeting, i.e. no later than 28 days
before the meeting. Shareholders who are unable to attend may vote by proxy.  As
described in the notice of the general meeting, shareholders may vote in
writing, including through electronic communication, for a period before the
general meeting.  The
deadline for registration for the AGM in Statoil is the day before the AGM is
due to take place.  The
AGM is normally opened and chaired by the chair of the corporate assembly. If
there is a dispute concerning individual matters and the chair of the corporate
assembly belongs to one of the disputing parties, or is for some other reason
not perceived as being impartial, another person will be appointed to chair the
AGM. This is in order to ensure impartiality in relation to the matters to be
considered. As Statoil has a large number of shareholders with a wide
geographical distribution, Statoil offers shareholders the opportunity to
follow the AGM by webcast.  The
following matters are decided at the AGM: ·Approval
of the board of directors' report, the financial statements and any dividend
proposed by the board of directors and recommended by the corporate assembly ·Election
of the shareholders' representatives to the corporate assembly and approval of
the corporate assembly's fees ·Election
of the nomination committee and approval of the nomination committee's fees ·Election
of the external auditor and approval of the auditor's fee ·Any
other matters listed in the notice convening the AGM  All
shares carry an equal right to vote at general meetings. Resolutions at general
meetings are normally passed by simple majority. However, Norwegian company law
requires a qualified majority for certain resolutions, including resolutions to
waive preferential rights in connection with any share issue, approval of a
merger or demerger, amendment of the articles of association or authorisation
to increase or reduce the share capital. Such matters require the approval of
at least two-thirds of the aggregate number of votes cast as well as two-thirds
of the share capital represented at the general meeting.  If
shares are registered by a nominee in the Norwegian Central Securities
Depositary (VPS), cf. section 4-10 of the Norwegian Public Limited Liability
Companies Act, and the beneficial shareholder wants to vote for their shares,
the beneficial shareholder must re-register the shares in a separate VPS
account in their own name prior to the general meeting. If the holder can prove
that such steps have been taken and that the Statoil, Annual Report on Form 20-F
2015127


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holder
has a de facto shareholder interest in the company, the holder may, in the
company's opinion, vote for the shares. Decisions regarding voting rights for
shareholders and proxy holders are made by the person opening the meeting,
whose decisions may be reversed by the general meeting by simple majority vote.  The
minutes of the AGM are made available on Statoil’s website immediately after
the AGM.  As
regards to extraordinary general meetings (EGM), an EGM will be held in order
to consider and decide a specific matter if demanded by the corporate assembly,
the chair of the corporate assembly, the auditor or shareholders representing
at least 5% of the share capital. The board must ensure that an EGM is held
within a month of such demand being submitted.  In
the following, certain types of resolutions by the general meeting of
shareholders are outlined:  New share issues If
Statoil issues any new shares, including bonus shares, the articles of
association must be amended. This requires the same majority as other
amendments to the articles of association. In addition, under Norwegian law, the
shareholders have a preferential right to subscribe for new shares issued by Statoil.
The preferential right to subscribe for an issue may be waived by a resolution
of a general meeting passed by the same percentage majority as required to
approve amendments to the articles of association. The general meeting may,
with a majority as described above, authorise the board of directors to issue
new shares, and to waive the preferential rights of shareholders in connection
with such share issues. Such authorisation may be effective for a maximum of
two years, and the par value of the shares to be issued may not exceed 50% of
the nominal share capital when the authorisation was granted.  The
issuing of shares through the exercise of preferential rights to holders who
are citizens or residents of the USA may require Statoil to file a registration
statement in the USA under US securities laws. If Statoil decides not to file a
registration statement, these holders may not be able to exercise their
preferential rights.  Right of redemption and repurchase of shares Statoil’s
articles of association do not authorise the redemption of shares. In the
absence of authorisation, the redemption of shares may nonetheless be decided upon
by a general meeting of shareholders by a two-thirds majority on certain
conditions. However, such share redemption would, for all practical purposes,
depend on the consent of all shareholders whose shares are redeemed.  A
Norwegian company may purchase its own shares if authorisation to do so has
been granted by a general meeting with the approval of at least two-thirds of
the aggregate number of votes cast as well as two-thirds of the share capital
represented at the general meeting. The aggregate par value of such treasury
shares held by the company must not exceed 10% of the company's share capital,
and treasury shares may only be acquired if, according to the most recently
adopted balance sheet, the company's distributable equity exceeds the
consideration to be paid for the shares. Pursuant to Norwegian law,
authorisation by the general meeting cannot be granted for a period exceeding
18 months.  Distribution of assets on liquidation Under
Norwegian law, a company may be wound up by a resolution of the company's
shareholders at a general meeting passed by both a two-thirds majority of the
aggregate votes cast and a two-thirds majority of the aggregate share capital
represented at the general meeting. The shares are ranked equally in the event
of a return on capital by the company upon winding up or otherwise.  7.4
Nomination committee  Pursuant
to Statoil's articles of association, the nomination committee shall consist of
four members who are shareholders or representatives of shareholders.  The
committee is independent of both the board of directors and the company's
management.  The
duties of the nomination committee are to submit recommendations to: ·the
annual general meeting for the election of shareholder-elected members and
deputy members of the corporate assembly, and the remuneration of members of
the corporate assembly ·the
annual general meeting for the election and remuneration of members of the
nomination committee ·the
corporate assembly for the election of shareholder-elected members of the board
of directors and remuneration of the members of the board of directors and ·the
corporate assembly for the election of the chair and deputy chair of the
corporate assembly  Using
a form on Statoil’s website, shareholders can propose candidates for the board
of directors, the corporate assembly and the nomination committee.  The
members of the nomination committee are elected by the annual general meeting.
The chair of the nomination committee and one other member are elected from
among the shareholder-elected members of the corporate assembly. Members of the
nomination committee are normally elected for a term of two years. 128Statoil, Annual Report on Form 20-F 2015


---

Personal
deputy members for one or more of the nomination committee's members may be
elected in accordance with the same criteria as described above. A deputy
member only meets for the member if the appointment of that member terminates
before the term of office has expired.  The
members of the nomination committee are: ·Olaug
Svarva (chair), Managing director at Folketrygdfondet ·Tom
Rathke, Group executive vice president Wealth Management at DnB ·Elisabeth
Berge, Secretary general, Norwegian Ministry of Petroleum and Energy (personal
deputy for Elisabeth Berge is Bjørn Ståle Haavik, Director at the Norwegian
Ministry of Petroleum and Energy) ·Tone
Lunde Bakker, Global head of cash management at Danske Bank  The
nomination committee held 19 ordinary meetings and three telephone meetings in
2015.  The
instructions for the nomination committee, including the rules of procedure,
are available at Statoil.com/nominationcommittee.  7.5 Corporate assembly  Pursuant to the Norwegian Public Limited
Liability Companies Act, companies with more than 200 employees must elect a
corporate assembly unless otherwise agreed between the company and a majority
of its employees. Statoil, Annual Report on Form 20-F
2015129


---

Name
 Occupation
 Place of residence
 Year of birth
 Position
 Family relations to corporate executive committee, board or
  corporate assembly members
 Share ownership for members as of 31.12.2015
 Share ownership for members as of 08.03.2016
 First time elected
 Expiration date of current termOlaug Svarva
 Managing
  director, Folketrygdfondet
 Oslo
 1957
 Chair,
  Shareholder-elected
 No
 0
 0
 2007
 2016Idar Kreutzer
 CEO, Finance
  Norway (FNO)
 Oslo
 1962
 Deputy chair,
  Shareholder-elected
 No
 0
 0
 2007
 2016Karin Aslaksen
 Head of HR
  department, the National Police Directorate of Norway
 Hosle
 1959
 Shareholder-elected
 No
 0
 0
 2008
 2016Greger Mannsverk
 Managing
  director, Kimek AS
 Kirkenes
 1961
 Shareholder-elected
 No
 0
 0
 2002
 2016Steinar Olsen
 CEO, Jemso
  A/S
 Stavanger
 1949
 Shareholder-elected
 No
 0
 0
 2007
 2016Tone Cathrine Lunde
  Bakker
 Global head
  of cash management at Danske Bank
 Oslo
 1962
 Shareholder-elected
 No
 0
 0
 2014
 2016Ingvald Strømmen
 Dean at
  Norwegian University of Science and Technology (NTNU)
 Ranheim
 1950
 Shareholder-elected
 No
 0
 0
 2006
 2016Rune Bjerke
 President and
  CEO, DNB ASA
 Oslo
 1960
 Shareholder-elected
 No
 0
 0
 2007
 2016Barbro Hætta
 Medical
  doctor, University Hospital of North Norway
 Harstad
 1972
 Shareholder-elected
 No
 0
 0
 2010
 2016Siri Kalvig
 Associate
  professor, University of Stavanger
 Stavanger
 1970
 Shareholder-elected
 No
 0
 0
 2010
 2016Terje Venold
 Independent
  advisor with various directorships
 Bærum
 1950
 Shareholder-elected
 No
 500
 500
 2014
 2016Kjersti Kleven
 Co-owner of
  John Kleven AS
 Ulsteinvik
 1967
 Shareholder-elected
 No
 0
 0
 2014
 2016Brit Gunn Ersland
 Union
  representative, Tekna. Specialist Reservoir Tech.
 Bergen
 1960
 Employee-elected
 No
 1,567
 1,802
 2011
 2017Steinar Kåre Dale
 Union
  representative, NITO, SR Analyst
 Mongstad
 1961
 Employee-elected
 No
 2,424
 2,710
 2013
 2017Per Martin Labråten
 Union
  representative, Industri Energi. Production technician
 Brevik
 1961
 Employee-elected
 No
 599
 803
 2007
 2017Anne K.S. Horneland
 Union
  representative, Industri Energi
 Hafrsfjord
 1956
 Employee-elected
 No
 4,575
 4,902
 2006
 2017Jan-Eirik Feste
 Union
  representative, YS
 Lindås
 1952
 Employee-elected
 No
 862
 1,088
 2008
 2017Hilde Møllerstad
 Union
  representative, Tekna/NITO
 Oslo
 1966
 Employee-elected
 No
 2,595
 3,034
 2013
 2017Per Helge Ødegård
 Union
  representative, Lederne. Discipl resp operation process
 Porsgrunn
 1963
 Employee-elected,
  observer
 No
 816
 1,023
 1994
 2017Dag-Rune Dale
 Union
  representative, Industri Energi, Safety officer
 Kollsnes
 1963
 Employee-elected,
  observer
 No
 2,787
 3,058
 2013
 2017Sun Lehmann
 Union
  representative, Tekna
 Trondheim
 1972
 Employee-elected,
  observer
 No
 2,867
 3,237
 2015
 2017Total
 
 
 
 
 
 19,592
 22,157
 130Statoil, Annual Report on Form 20-F 2015


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An election of the employee-elected members of the corporate
assembly was held early 2015. Effective as of 28 April 2015, Brit Gunn Ersland
was elected as new member (from the former position as an observer), Sun
Lehmann was elected as a new observer and Oddvar Karlsen, Jorunn Birkeland and
Sten Atle Jølle were elected as new deputy members of the corporate assembly.
Eldfrid Irene Hognestad (member) left the corporate assembly as of the same
date. The number of deputy members for the employee-elected members of the
corporate assembly was also reduced from 17 to 11 deputy members.  Pursuant to Statoil's articles of
association, the corporate assembly normally consists of 18 members. Twelve
members with four deputy members are nominated by the nomination committee and
elected at the general meeting of shareholders, and six members, three
observers and deputy members are elected by and from among the employees. Such
employees are non-executive personnel.  Members of the corporate assembly are
normally elected for a term of two years. Members of the board of directors and
the general manager cannot be members of the corporate assembly, but they are
entitled to attend and to speak at meetings of the corporate assembly unless
the corporate assembly decides otherwise in individual cases.  The duties of the corporate assembly are
defined in section 6-37 of the Norwegian Public Limited Liability Companies
Act. The corporate assembly elects the board of directors and the chair of the
board. Its responsibilities also include overseeing the board and the CEO's
management of the company, making decisions on investments of considerable
magnitude in relation to the company's resources and making decisions involving
the rationalisation or reorganisation of operations that will entail major
changes in or reallocation of the workforce.  Statoil's corporate assembly held four
ordinary meetings in 2015.  All members of the corporate assembly live in
Norway. Members of the corporate assembly do not have service contracts with
the company or its subsidiaries providing for benefits upon termination of
office.  Statoil, Annual Report on Form 20-F
2015131


---

7.6 Board of directors ﻿﻿﻿﻿﻿﻿﻿﻿﻿﻿ Pursuant
to Statoil's articles of association, the board of directors consists of
between nine and 11 members. The management is not represented on the board.  At
present, Statoil's board of directors consists of 10 members. As required by
Norwegian company law, the company's employees are entitled to be represented
by three board members. There are no board member service contracts that
provide for benefits upon termination of office. Statoil's board of directors
has determined that, in its judgment, all of the shareholder representatives on
the board, except for Wenche Agerup, are considered independent.  The
board of directors of Statoil ASA is responsible for the overall management of
the Statoil group, and for supervising the group's activities in general. The
board of directors handles matters of major importance or of an extraordinary
nature. However, it may require the management to refer any matter to it. The
board of directors appoints the president and chief executive officer (CEO),
and stipulates the job instructions, powers of attorney and terms and
conditions of employment for the president and CEO.  The
board of directors has three sub-committees - the "audit committee",
"the safety, sustainability and ethics committee", and "the
compensation and executive development committee".  The
board held eight ordinary board meetings and four extraordinary meetings in
2015. Average attendance at these board meetings was 95.9%. Members of the board of directors as of 31 December 2015: Øystein
      Løseth
  Øystein Løseth
    Position:Shareholder-elected chair
      of the board and chair of the board's compensation and executive committee.
    Born: 1958
    Term of office:Member of the board of
      directors of Statoil ASA since 1 October 2014, and since 1 July 2015, also chair
      of the board and chair of the board’s compensation and executive development
      committee. Up for election in 2016.
    Independent: Yes
    Other directorships:Chair of the board of
      Eidsiva Energi AS.
    Number of shares in
      Statoil ASA as of 31 December 2015:1,000
    Loans from Statoil:None
    Experience: In the period 2010 - 2014, Løseth
      was the CEO and before that First Senior Executive Vice President (since
      2009), of Vattenfall AB. In the period 2003 – 2009, Løseth worked for NUON, a
      Dutch energy company, first as Division Managing Director, then as a Managing
      Director and the CEO, from 2006 and 2008 respectively. From 2002 to 2003,
      Løseth was the Head of Production, Business Development and R&D of
      Statkraft. In addition, he has other extensive management experience from
      Statkraft and Statoil, within strategy and business development among others.Education:Løseth
    graduated as M.Sc. from the Norwegian University of Science and Technology
    and has a degree in Economics from BI Norwegian School of Management in
    Bergen.
    Family
      relations:No
        family relations to other members of the board, members of the corporate
        executive committee or the corporate assembly.
    Other matters:In 2015, Løseth
      participated in eight ordinary board meetings, four extraordinary board
      meetings, three meetings of the compensation and executive development
      committee, four meetings of the audit committee and one meeting in the
      safety, sustainability and ethics committee.Løseth is a Norwegian
        citizen and resident in Norway.Roy
  Franklin
 Roy Franklin
   Born:1953
   Position:Shareholder-elected
     deputy chair of the board, chair of the board’s safety, sustainability and
     ethics committee and member of the board’s audit committee.
   Term of office: Deputy chair of the board of
     Statoil ASA from 1 July 2015. Franklin was also previously a member of the
     board of StatoilHydro from October 2007 and Statoil from November 2009 until
     June 2013. Up for election in 2016.
   Independent:Yes
   Other directorships:Non-executive chair of
     the board of Keller Group plc, a London-based international engineering
     company and Cuadrilla Resources Holdings Limited, a privately held UK company
     focusing on unconventional energy sources. Board member of the Australian oil
     and gas company Santos Ltd, the private equity firm Kerogen Capital Ltd and
     the London-based international engineering company Amec Foster Wheeler.
   Number of shares in Statoil ASA as of 31 December 2015:None
   Loans from Statoil ASA:None
   Experience:Franklin has broad experience
     from management positions in several countries, including positions with BP,
     Paladin Resources plc and Clyde Petroleum plc.Education:Franklin has a Bachelor
      of Science in Geology from the University of Southampton, UK.
    Family relations:No family relations to
      other members of the board, members of the corporate executive committee or
      the corporate assembly.
    Other matters:In 2015, Franklin
      participated in four ordinary board meetings, three meetings of the audit
      committee and two meetings of the safety, sustainability and ethics
      committee. Franklin is a UK citizen and resident in UK.Bjørn
  Tore Godal
 Bjørn Tore Godal
   Born:1945
   Position:Shareholder-elected
     member of the board, the board's compensation and executive development
     committee and the board's safety, sustainability and ethics committee.
   Term of office: Member of the board of Statoil ASA
     from 1 September 2010. Up for election in 2016.
   Independent:Yes
   Other directorships:Chair of the Council of
     the Norwegian Defence University College (NDUC), and vice chair of the board
     of the Fridtjof Nansen Institute (FNI).
   Number of shares in Statoil ASA as of 31 December 2015:None
   Loans from Statoil ASA:None
   Experience:Godal was a member of
     the Norwegian parliament for 15 years during the period 1986-2001. At various
   times, he served as minister for
     trade and shipping, minister for defense, and minister of foreign affairs for
     a total of eight
   years between 1991 and 2001. From
     2007-2010, Godal was special adviser for international energy and climate
     issues at the Norwegian Ministry of Foreign Affairs. From 2003-2007, Godal
     was Norway's ambassador to Germany and from 2002-2003 he was senior adviser
     at the department of political science at the University of Oslo.Education:Godal has a bachelor of
      arts degree in political science, history and sociology from the University
      of Oslo.
    Family relations:No family relations to
      other members of the board, members of the corporate executive committee or
      the corporate assembly.
    Other matters:In 2015, Godal
      participated in eight ordinary board meetings, three extraordinary board
      meetings, seven meetings of the compensation and executive development
      committee and five meetings of the safety, sustainability and ethics
      committee. Godal is a Norwegian citizen and resident in Norway.Jakob
  Stausholm
 Jakob Stausholm
   Born:1968
   Position:Shareholder-elected member of the
     board and chair of the board's audit committee.
   Term of office:Member of the board of Statoil ASA
     since July 2009. Up for election in 2016.
   Independent:Yes
   Other directorships:No
   Number of shares in Statoil ASA as of 31 December 2015:50,000
   Loans
     from Statoil:None
   Experience:Chief strategy and transformation
     officer of Maersk Line, the largest container shipping company in the world
     and part of A.P. Moller - Maersk Group. From 2008 to 2011, Stausholm was
     chief financial officer of the global facility services provider ISS A/S.
     Before joining ISS's corporate executive committee, he was employed by the
     Shell Group for 19 years and held a number of management positions, including
     vice president finance for the group's exploration and production in Asia and
     thePacific, chief internal auditor and CFO of group subsidiaries.
   Education: M.Sc. in economics from the
     University of Copenhagen.Family relations: No family relations to other
      members of the board, members of the corporate executive committee or the
      corporate assembly.
    Other matters: In 2015, Stausholm participated in
      eight ordinary board meetings, four extraordinary board meetings and six
      meetings of the audit committee. Stausholm is a Danish citizen and resident
      in Denmark.Maria
  Johanna Oudeman
 Maria Johanna Oudeman
   Born: 1958
   Position:Shareholder-elected member of the
     board and member of the board’s compensation and executive development
     committee.
   Term of office:Member of the board of
     Statoil ASA since 15 September 2012. Up for election in 2016.
   Independent:Yes
   Other directorships:Oudeman is a member of
     the boards of Solvay SA, Het Concertgebouw, Rijksmuseum and SHV Holdings.
   Number of shares in Statoil ASA as
     of 31 December 2015:
       None
   Loans from Statoil:None
   Experience: Oudeman is the
     President of Utrecht University in the Netherlands, one of Europe's leading
   universities.
     From 2010 to 2013, Oudeman was a member of the Executive Committee of Akzo
     Nobel, responsible for HR and Organisational Development. Akzo Nobel is the
     world's largest paint and coatings company and
     major producer of specialty chemicals, with operations in more than 80
     countries. Before joining Akzo Nobel, she was ExecutiveDirector Strip Products Division at
      Corus Group, now Tata Steel Europe. Oudeman has extensive experience as a
      line manager in the steel industry and considerable international business
      experience.
    Education: Oudeman has a law
      degree from Rijksuniversiteit Groningen in the Netherlands and an MBA in
      business administration from the University of Rochester, New York, USA and
      Erasmus University, Rotterdam, the Netherlands.
    Family relations:No family relations to
      other members of the board, members of the corporate executive committee or
      the corporate assembly.
    Other
      matters:
        In 2015, Oudeman participated in eight ordinary board meetings, four extraordinary
        board meetings, six meetings of the compensation and executive development
        committee and one meeting of the board’s safety, sustainability and ethics
        committee. Oudeman is a Dutch citizen and resident in the Netherlands.Rebekka
  Glasser Herlofsen
 Rebekka Glasser Herlofsen
   Born:1970
   Position:Shareholder-elected member of the
     board and the board's audit committee.
   Term of office:Member of the board of Statoil ASA
     since 19 March 2015 Up for election in 2016.
   Independent:Yes
   Other directorships:Member of the board of directors of
     DNV holding, DNV Foundation, DNV GL and member of the committee for tax and
     capital in the Norwegian Shipowners’ Association.
   Number of shares in Statoil ASA as of 31 December 2015:None
   Loans
     from Statoil:None
   Experience:Since 2012, Herlofsen has been the
     Chief Financial Officer in the Norwegian shipping company Torvald Klaveness.
     She has broad financial and strategic experience from several corporations
     and board directorships. Herlofsen’s professional career began in the leading
     Nordic Investment Bank, Enskilda Securities, where she worked with corporate
     finance from 1995 to 1999 in Oslo and London. During the next ten years
     Herlofsen worked in the Norwegian shipping comp any Bergesen d.y. ASA (later
     BW Group). During her period with Bergesen d.y. ASA/BW Group Herlofsen held
     leading positions within M&A, strategy and corporate planning and was
     part of the group management team.Education:MSc in Economics and Business
      Administration (Siviløkonom) and Certified Financial Analyst Program, the
      Norwegian School of Economics (NHH). Breakthrough Program for Top Executives
      at IMD business school, Switzerland.
    Family relations: No family relations to other
      members of the board, members of the corporate executive committee or the
      corporate assembly.
    Other matters: In 2015, Herlofsen participated in
      six ordinary board meetings, one extraordinary board meeting and four
      meetings of the audit committee. Herlofsen is a Norwegian citizen and
      resident in Norway.Wenche
  Agerup
 Wenche Agerup
   Born:1964
   Position:Shareholder-elected member of the
     board, the board’s compensation and executive development committee and the
     board's safety, sustainability and ethics committee.
   Term of office:Member of the board of Statoil ASA
     since 21 August 2015. Up for election in 2016.
   Independent:No.
   Pursuant
     to the NYSE rules, a director will not be considered independent under the
     NYSE rules if the director is, or was within the past three years, an
     executive officer of another company at which any of the listed company's
     current executive officers are, or were within the past three years, members
     of the compensation committee. This rule also applies to foreign listed
     companies. Agerup was a member of Norsk Hydro ASA’s management team while Irene
     Rummelhoff, Executive Vice President of New Energy Solutions in Statoil, was
     member of the board’s compensation committee in Norsk Hydro. Agerup is
     therefore deemed as a non-independent board member in Statoil for a period of
     three years from 31 December 2014, i.e. until 31 December 2017.
   Other directorships:Agerup is a member of the board of
     the seismic company TGS ASA.
   Number of shares in Statoil ASA as of 31 December 2015:2,423Loans
      from Statoil:None
    Experience: Agerup is an Executive Vice
      President and the Chief Corporate Affairs Officer in Telenor ASA. Agerup was
      the Executive Vice President for Corporate Staffs and the General Counsel of
      Norsk Hydro ASA from 2010 to 31 December 2014. She has held various executive
      roles in Hydro since 1997, including within the company’s M&A-activities,
      the business area Alumina, Bauxite and Energy, as a plant manager at Hydro’s
      metal plant in Årdal and as a project director for a Joint Venture in
      Australia where Hydro cooperated with the Australian listed company UMC.
    Education:MA in Law from the University of
      Oslo, Norway (1989) and a Master of Business Administration from Babson
      College, USA (1991).
    Family relations: No family relations to other
      members of the board, members of the corporate executive committee or the
      corporate assembly.
    Other matters: In 2015, Agerup participated in
      three ordinary board meetings, three meetings of the compensation and
      executive development committee and two meetings of the safety,
      sustainability and ethics committee. Agerup is a Norwegian citizen and
      resident in Norway.Lill-Heidi Bakkerud
 Lill-Heidi Bakkerud
   Born:1963
   Position:Employee-elected member
     of the board and member of the board's safety, sustainability and ethics
     committee.
   Term of office:Member of the board of
     Statoil ASA from 1998 to 2002, and again since 2004. Up for election in 2017.
   Independent:No
   Other directorships:Bakkerud is a member of
     the executive committee of the Industry Energy (IE) trade union and holds a
     number of offices as a result of this.
   Number of shares in Statoil ASA as of 31 December 2015:330Loans
         from Statoil:None
   Experience:Bakkerud has worked as a process
     technician at the petrochemical plant in Bamble and on the Gullfaks field in
     the North Sea. She is now a full-time employee representative as the leader
     of the union Industri Energi’s Statoil branch.
   Education:Bakkerud has a craft certificate as
     a process/chemistry worker.
   Family relations:No family relations to other
     members of the board, members of the corporate executive committee or the
     corporate assembly.Other matters:In 2015, Bakkerud participated in
      eight ordinary board meetings, four extraordinary board meetings and five
      meetings of the safety, sustainability and ethics committee. Bakkerud is a
      Norwegian citizen and resident in Norway.Ingrid
  Elisabeth di Valerio
 Ingrid Elisabeth di Valerio
   Born:1964
   Position:Employee-elected member of the board
     and member of the board's audit committee.
   Term of office:Member of board of directors of Statoil
     ASA from 1 July 2013. Up for election in 2017.
   Independent:No
   Other directorships:Board member of First Scandinavia,
     Montanus AS and member of Tekna's central nomination committee.
   Number of shares held in Statoil ASA as of 31 December
     2015:
       2,845
   Loans from Statoil: None
   Experience: Di Valerio has been employed by
     Statoil since 2005, and works within materials discipline for Technology,
     Projects & Drilling. Di Valerio was the union Tekna's main representative
     in Statoil from 2008 to 2013. She also sat on Tekna's central committee from
     2005 to 2013.
   Education: Chartered engineer (mathematics
     and physics) from the Norwegian University of Science and Technology in
     Trondheim (NTNU).Familiy relations:No family relationships to other
      board members, members of the corporate executive committee or the corporate
      assembly.
    Other: In 2015, di Valerio participated in eight ordinary
      board meetings, four extraordinary board meetings and six meetings of the
      audit committee. Di Valerio is a Norwegian citizen and resident in Norway.Stig
  Lægreid
 Stig Lægreid
   Born: 1963
   Position:Employee-elected member of the board
     and member of the board's safety, sustainability and ethics committee.
   Term of office:Member of the board of directors of
     Statoil ASA from 1 July 2013. Up for election in 2017.
   Independent:No
   Other directorships: Member of The Norwegian society
     for Engineers and Technologists’ (NITO) negotiation committee for private
     sector.
   Number of shares held in Statoil ASA as of 31 December
     2015:
       1,519
   Loans from Statoil: None
   Experience:Employed in ÅSV and Norsk Hydro
     since 1985. Mainly occupied as project engineer and constructor for
     production of primary metals until 2005 and from 2005 as weight estimator for
     platform design. He is now a full-time employee representative as the leader
     of the union NITO, Statoil.
   Education: Bachelor degree, mechanical
     construction from OIH.Family relations:No family relationships to other
      board members, members of the corporate executive committee or the corporate
      assembly.
    Other: In 2015, Lægreid participated in eight ordinary board
      meetings, four extraordinary board meetings and five meetings of the safety,
      sustainability and ethics committee. Lægreid is a Norwegian citizen and
      resident in Norway.
    
    In
      addition, there are four employee-elected deputy members of the board who
      attend board meetings in the event an employee-elected member of the board is
      unable to attend.
 132Statoil, Annual Report on Form 20-F 2015


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Statoil, Annual Report on Form 20-F
2015133


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7.6.1 Audit committee ﻿﻿﻿﻿ The
board of directors elects at least three of its members to serve on the board
of directors' audit committee and appoints one of them to act as chair. The
employee-elected members of the board of directors may nominate one audit
committee member.  At
year-end 2015, the audit committee members were Jakob Stausholm (chair), Roy
Franklin, Rebekka Herlofsen and Ingrid di Valerio (employee-elected board
member).  The
audit committee is a sub-committee of the board of directors, and its objective
is to act as a preparatory body in connection with the board's supervisory
roles with respect to financial reporting and the effectiveness of the
company's internal control system. It also attends to other tasks assigned to
it in accordance with the instructions for the audit committee adopted by the
board of directors. The audit committee is instructed to assist the board of
directors in its supervising of matters such as: ·Monitoring
the financial reporting process, including oil and gas reserves, fraudulent
issues and reviewing the implementation of accounting principles and policies ·Monitoring
the effectiveness of the company's internal control, internal audit and risk
management systems ·Maintaining
continuous contact with the statutory auditor regarding the annual and
consolidated accounts ·Reviewing
and monitoring the independence of the company's internal auditor and the
independence of the statutory auditor, reference is made to the Norwegian
Auditors Act chapter 4, and, in particular, whether services other than audits
provided by the statutory auditor or the audit firm are a threat to the
statutory auditor's independence  The
audit committee supervises implementation of and compliance with the group's
Code of Conduct in relation to financial reporting.  The
internal audit function reports directly to the board of directors and to the
chief executive officer.  Under
Norwegian law, the external auditor is appointed by the shareholders at the
annual general meeting based on a proposal from the corporate assembly. The audit
committee issues a statement to the annual general meeting relating to the
proposal.  The
audit committee meets at least five times a year, and it meets separately with
the internal auditor and the external auditor on a regular basis.  The
audit committee is also charged with reviewing the scope of the audit and the
nature of any non-audit services provided by external auditors. The external
auditors report directly to the audit committee on a regular basis.  The
audit committee is tasked with ensuring that the company has procedures in
place for receiving and dealing with complaints received by the company
regarding accounting, internal control or auditing matters, and procedures for
the confidential and anonymous submission, via the group's ethics helpline, by
company employees of concerns regarding accounting or auditing matters, as well
as other matters regarded as being in breach of the group's Code of Conduct, a
material violation of an applicable US federal or state securities law, a
material breach of fiduciary duties or a similar material violation of any
other US or Norwegian statutory provision. The audit committee is designated as
the company's qualified legal compliance committee for the purposes of section
307 of the Sarbanes-Oxley Act of 2002.  In
the execution of its tasks, the audit committee may examine all activities and
circumstances relating to the operations of the company. In this regard, the
audit committee may request the chief executive officer or any other employee
to grant it access to information, facilities and personnel and such assistance
as it requests. The audit committee is authorised to carry out or instigate
such investigations as it deems necessary in order to carry out its tasks and
it may use the company's internal audit or investigation unit, the external
auditor or other external advice and assistance. The costs of such work will be
covered by the company.  The
audit committee is only responsible to the board of directors for the execution
of its tasks. The work of the audit committee in no way alters the
responsibility of the board of directors and its individual members, and the
board of directors retains full responsibility for the audit committee's tasks.  The
audit committee held six meetings in 2015. There was 96.3% attendance at the
committee's meetings. ﻿﻿﻿﻿ The board of directors has
decided that a member of the audit committee, Jakob Stausholm, qualifies as an
"audit committee financial expert", as defined in Item 16A of Form 20-F. The
board of directors has also concluded that Jakob Stausholm, Roy Franklin and
Rebekka Herlofsen are independent within the meaning of Rule 10A-3 under the
Securities Exchange Act.  The
committee's mandate is available atStatoil.com/auditcommittee.   134Statoil, Annual Report on Form 20-F 2015


---

7.6.2
Compensation and executive development committee  The compensation and executive development
committee is a sub-committee of the board of directors that assists the board
in matters relating to management compensation and leadership development.  The main responsibilities of the compensation
and executive development committee are:  (1) as a preparatory body for the board, to
make recommendations to the board in all matters relating to principles and the
framework for executive rewards, remuneration strategies and concepts, the
CEO's contract and terms of employment, and leadership development, assessments
and succession planning;  (2) to be informed about and advise the
company's management in its work on Statoil's remuneration strategy for senior
executive and in drawing up appropriate remuneration policies for senior
executives; and  (3) to review Statoil's remuneration policies
in order to safeguard the owners' long-term interests.  The committee consists of up to four board
members. At year-end 2015, the committee members were Øystein Løseth (chair),
Bjørn Tore Godal, Maria Johanna Oudeman and Wenche Agerup. All of the committee
members are non-executive directors. All members, except for Wenche Agerup, are
independent.  The committee held seven meetings in 2015 and
attendance was 96%.  For a more detailed description of the
objective and duties of the compensation committee, please see the instructions
for the compensation committee available atStatoil.com/compensationcommittee.  7.6.3 Safety, sustainability and ethics
committee  The safety, sustainability and ethics
committee is a sub-committee of the board of directors that assists the board
in matters relating to safety, sustainability and ethics.  The safety, sustainability and ethics
committee (the committee) is chaired by Roy Franklin and the other members are
Bjørn Tore Godal, Wenche Agerup, Stig Lægreid (employee-elected board member)
and Lill-Heidi Bakkerud (employee-elected board member).  In its business activities, Statoil is
committed to comply with applicable laws and regulations and to act in an
ethical, environmental, safe and socially responsible manner. The committee has
been established to support our commitment in this regard, and it assists the
board of directors in its supervision of the company's safety, sustainability
and ethics policies, systems and principles with the exception of aspects
related to “financial matters”.  Establishing and maintaining a committee
dedicated to safety, sustainability and ethics is intended to ensure that the
board of directors has a strong focus on and knowledge of these complex,
important and constantly evolving areas. The committee acts as a preparatory
body for the board of directors and, among other things, monitors and assesses
the effectiveness, development and implementation of policies, systems and
principles in the areas of safety, sustainability and ethics, with the
exception of aspects related to “financial matters”.  The committee held five meetings in 2015, and
attendance was 100%.  For a more detailed description of the
objective, duties and composition of the committee, please see the instructions
for the committee available at Statoil.com/ssecommittee.  Statoil, Annual Report on Form 20-F
2015135


---

7.7
Compliance with NYSE listing rules Statoil's primary listing is on the Oslo Børs, but Statoil is also registered
as a foreign private issuer with the US Securities and Exchange Commission and
listed on the New York Stock Exchange.  American Depositary Shares represent the
company's ordinary shares listed on the New York Stock Exchange (NYSE). While
Statoil's corporate governance practices follow the requirements of Norwegian
law, Statoil is also subject to the NYSE's listing rules.  As a foreign private issuer, Statoil is
exempted from most of the NYSE corporate governance standards that domestic US
companies must comply with. However, Statoil is required to disclose any
significant ways in which its corporate governance practices differ from those
applicable to domestic US companies under the NYSE rules. A statement of
differences is set out below:  Corporate governance
guidelines The NYSE rules require domestic US companies
to adopt and disclose corporate governance guidelines. Statoil's corporate
governance principles are developed by the management and the board of
directors, in accordance with the Norwegian Code of Practice for Corporate
Governance and applicable law. Oversight of the board of directors and
management is exercised by the corporate assembly.  Director independence The NYSE rules require domestic US companies
to have a majority of "independent directors". The NYSE definition of
an "independent director" sets out five specific tests of
independence and also requires an affirmative determination by the board of
directors that the director has no material relationship with the company.  Pursuant to Norwegian company law, Statoil's
board of directors consists of members elected by shareholders and employees.
Statoil's board of directors has determined that, in its judgment, all of the
shareholder-elected directors, except one, are independent. In making its
determinations of independence, the board focuses inter alia on there not being
any conflicts of interest between shareholders, the board of directors and the
company's management, but it does not explicitly make its determination based
on the NYSE's five specific tests. The directors elected from among Statoil's
employees would not be considered independent under the NYSE rules because they
are employees of Statoil. None of the employee-elected directors is an
executive officer of the company.  For further information about the board of
directors see section 7.6 Board of directors.  Board committees Pursuant to Norwegian company law, managing
the company is the responsibility of the board of directors. Statoil has an
audit committee, a safety, sustainability and ethics committee and a
compensation and executive development committee. They are responsible for
preparing certain matters for the board of directors. The audit committee and
the compensation and executive development committee operate pursuant to
charters that are broadly comparable to the form required by the NYSE rules.
They report on a regular basis to, and are subject to, continuous oversight by
the board of directors. For further information about the board’s
sub-committees, see sections 7.6.1 Audit Committee,7.6.2 Compensation
and executive development committee and 7.6.3Safety, sustainability and ethics committee.  Statoil complies with the NYSE rule regarding
the obligation to have an audit committee that meets the requirements of Rule
10A-3 of the US Securities Exchange Act of 1934.  As required by Norwegian company legislation,
the members of Statoil's audit committee include an employee-elected director.
Statoil relies on the exemption provided for in Rule 10A-3(b)(1)(iv)(C) from
the independence requirements of the US Securities Exchange Act of 1934 with
respect to the employee-elected director. Statoil does not believe that its
reliance on this exemption will materially adversely affect the ability of the
audit committee to act independently or to satisfy the other requirements of
Rule 10A-3 relating to audit committees. The other members of the audit
committee meet the independence requirements under Rule 10A-3.  Among other things, the audit committee
evaluates the qualifications and independence of the company's external
auditor.However, in accordance with Norwegian law, the auditor is
elected by the annual general meeting of the company's shareholders.    136Statoil, Annual Report on Form 20-F 2015


---

Statoil does
not have a nominating/corporate governance sub-committee formed from its board
of directors. Instead, the roles prescribed for a nominating/corporate
governance committee under the NYSE rules are principally carried out by the
corporate assembly and the nomination committee which is elected by the general
meeting of shareholders. NYSE rules require the compensation committee of US
companies to comprise independent directors under the NYSE rules, recommend
senior management remuneration and make a determination on the independence of
advisors when engaging them. Statoil, as foreign private issuer, is exempt from
complying with these rules and is permitted to follow its home country
regulations. Statoil considers all its compensation committee members to be
independent, cf. the discussion on director independence above. Statoil's
compensation committee makes recommendations to the board about management
remuneration, including that of the CEO. The compensation committee assesses
its own performance and has the authority to hire external advisors. The
nomination committee, which is elected by the general meeting of shareholders,
recommends to the corporate assembly the candidates and remuneration of the
board of directors. Also, the nomination committee recommends to the general
meeting of shareholders the candidates and remuneration of the corporate assembly
and the nomination committee.  Shareholder approval of
equity compensation plans The NYSE rules require that, with limited
exemptions, all equity compensation plans must be subject to a shareholder
vote. Under Norwegian company law, although the issuance of shares and
authority to buy back company shares must be approved by Statoil's annual
general meeting of shareholders, the approval of equity compensation plans is
normally reserved for the board of directors. Statoil, Annual Report on Form 20-F
2015137


---

7.8 Management  The
president and CEO has overall responsibility for day-to-day operations in
Statoil and appoints the corporate executive committee (CEC). Each of the
members of the CEC is head of a separate business area or staff function.  The
president and CEO has overall responsibility for day-to-day operations in
Statoil. The president and CEO is responsible for developing Statoil's business
strategy and presenting it to the board of directors for decision, for the
execution of the business strategy and for cultivating a performance-driven,
value-based culture.  The
president and CEO appoints the corporate executive committee. Members of the
CEC have a collective duty to safeguard and promote Statoil's corporate
interests and to provide the president and CEO with the best possible basis for
deciding the company's direction, making decisions and executing and following
up business activities. In addition, each of the CEC members is head of a
separate business area or staff function. Members of Statoil's corporate executive committee as of
31 December 2015: Eldar
  Sætre, President and CEO
 Eldar Sætre
  Born:1956
  Position:President and chief
  executive officer of Statoil ASA since 15 October 2014.
  External offices:Member of the board of
  Strømberg Gruppen AS and Trucknor AS.
  Number of shares in
  Statoil ASA as of 31 December 2015:39,130
  Loans from Statoil:NoneExperience:Sætre joined Statoil in
  1980. Executive vice president and CFO from October 2003 until December 2010.
  Executive vice president for Marketing, Midstream and Processing (MMP) from
  2011 until 2014.
  Education:MA in business economics
  from the Norwegian School of Economics and Business Administration (NHH) in
  Bergen.
  Family relations:No family relations to
  other members of the CEC, members of the board or the corporate assembly.
  Other
  matters:Sætre
  is a Norwegian citizen and resident in Norway.Hans
  Jakob Hegge, Chief financial
   officer (CFO)
 Hans Jakob Hegge
  Born:1969Position:Executive vice president
  and chief financial officer (CFO) of Statoil ASA since 1 August 2015.
  External offices:None
  Number of shares in
  Statoil ASA as of 31 December 2015:22,854
  Loans from Statoil:None
  Experience:Hegge has held several
  managerial positions in Statoil, including Senior Vice President (SVP) for
  Operations North in Development and Production Norway (DPN) (2013-2015), SVP
  for Operations East (2011-2013) in DPN, SVP for Operational Development in
  DPN (2009-2011) and SVP for Global Business Services in Chief Financial
  Officer area (CFO) (2005-2009). From 1995 to 2004 he held various positions
  in DPN, Natural Gas business area and corporate functions in Statoil.
  Education:Master of Science degree
  from the Norwegian School of Economics and Business Administration (NHH).
  Family relations:No family relations to other members
  of the CEC, members of the board or the corporate assembly.Other
  matters:Hegge is
  a Norwegian citizen and resident in Norway.Anders
  Opedal, Chief operating 
  officer (COO)
 Anders Opedal
  Born:1968Position:Executive vice president
  and chief operating officer (COO) of Statoil ASA since 1 April 2015.
  External offices:None
  Number of shares in
  Statoil ASA as of 31 December 2015:14,511
  Loans from Statoil:None
  Experience:Opedal joined Statoil in
  1997 as a petroleum engineer in the Statfjord operations. He has held a range
  of positions in Drilling and well, Procurement and projects. In 2011 Opedal
  took on the role as Senior Vice President for Projects in Technology,
  Projects and Drilling (TPD) responsible for Statoil’s approximately NOK 300
  billion project portfolio. Before joining Statoil, Opedal worked for
  Schlumberger and Baker Hughes.
  Education:MBA from Heriot-Watt
  University and an engineering degree from NTH.
  Family relations:No family relations to other members
  of the CEC, members of the board or the corporate assembly.Other
  matters:Opedal
  is a Norwegian citizen and resident in Norway.
 138Statoil, Annual Report on Form 20-F 2015


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Lars Christian Bacher, Executive vice president
  Development and Production International (DPI)
 Lars Christian Bacher
  Born: 1964Position: Executive vice
  president of Statoil ASA since 1 September 2012.External
  offices:
  None
  Number of shares in
  Statoil ASA as of 31 December 2015: 21,116Loans
  from Statoil ASA:None
  Experience:Bacher joined Statoil in 1991 and
  has held a number of leading positions in Statoil, including that of platform
  manager on the Norne and Statfjord fields on the Norwegian continental shelf.
  He was in charge of the merger process involving the offshore installations
  of Norsk Hydro and Statoil. Bacher has also been senior vice president for
  Gullfaks operations and subsequently for the Tampen area. His most recent
  position, which he held from September 2009, was as senior vice president for
  Statoil's Canadian operations in Development & Production USA (DPUSA).
  Education: Master of science in chemical
  engineering from the Norwegian Institute of Technology (NTH). He also holds a
  master's degree in finance from the Norwegian School of Economics and
  Business Administration (NHH).
  Family relations: No family relations to other
  members of the corporate executive committee, the board of directors or      
  the corporate assembly.
  Other matters: Bacher is a Norwegian citizen and
  resident in Norway.Torgrim
  Reitan,Executive
  vice 
  president Development and Production 
  USA (DPUSA)
 Torgrim Reitan
  Born:1969Position:Executive vice president
  of Statoil ASA since 1 January 2011.
  External offices:None
  Number of shares in
  Statoil ASA as of 31 December 2015:28,482
  Loans from Statoil:None
  Experience:From 1 January 2011 to 1
  August 2015 Reitan held the position as executive vice president and chief
  financial officer of Statoil (CFO). He has held several managerial positions
  in Statoil, including senior vice president (SVP) in trading and operations
  in the Natural Gas business area (2009 - 2010), SVP in performance management
  and analysis (2007 - 2009) and SVP in performance management, tax and M&A
  (2005 - 2007). From 1995 to 2004, Reitan held various positions in the
  Natural Gas business area and corporate functions in Statoil.
  Education:Master of science degree
  from the Norwegian School of Economics and Business Administration (NHH).
  Family relations:No family relations to other members
  of the CEC, members of the board or the corporate assembly.Other
  matters:Reitan
  is a Norwegian citizen and resident in the United States.John
  Knight, Executive vice president 
  Global Strategy and Business 
  Development (GSB)
 John KnightBorn:1958
  Position:Executive vice president
  of Statoil ASA since 1 January 2011.
  External offices:Member on the advisory
  board of the Columbia University Center on Global Energy Policy in New York. 
  Chair of ONS16 Conference Committee in Stavanger, Norway and member on the
  advisory board of Imperial College Business School MsC Climate Change
  Management and Finance in London.
  Numbers of shares in
  Statoil ASA as of 31 December 2015: 85,731
  Loans from Statoil ASA:None
  Experience:Knight held several
  central managerial positions in International Operations in Statoil since
  2002, mainly in business development. Between 1987 and 2002, Knight held
  various positions in energy investment banking. From 1977 to 1987, he
  qualified and worked as a barrister/lawyer, and was employed by Shell
  Petroleum in London during the period 1985-1987.
  Education:Knight has first and
  post-graduate degrees in law from Cambridge University and the Inns of Court
  School of Law in London.
  Family relations:No family relations to
  other members of the CEC, members of the board or the corporate assembly.
  Other matters:Knight is a British citizen and
  resident in England.Tim
  Dodson. Executive vice president, Exploration (EXP)
 Tim DodsonBorn:1959Position:Executive vice president
  of Statoil ASA since 1 January 2011.
  External offices:NoneNumber
  of shares in Statoil ASA as of 31 December 2015: 28,614
  Loans from Statoil ASA:None
  Experience:Dodson has worked in Statoil since
  1985 and held central management positions in the company, including the
  positions of senior vice president for global exploration, Exploration &
  Production Norway and the technology arena.
  Education:Master of science in geology and
  geography from the University of Keele.
  Family relations:No family relations to other
  members of the CEC, members of the board or the corporate assembly.
  Other matters:Dodson is a British citizen and
  resident in Norway.
 Statoil, Annual Report on Form 20-F
2015139


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Margareth Øvrum. Executive vice
  president
  Technology, Projects and
  Drilling (TPD)
 Margareth Øvrum
  Born:1958
  Position:Executive vice president
  of Statoil ASA since September 2004.
  External offices:Member of the board of
  Atlas Copco AB (Sweden) and Alfa Laval (Sweden).
  Number of shares in
  Statoil ASA as of 31 December 2015:42,621
  Loans from Statoil:None
  Experience:Øvrum has worked for
  Statoil since 1982 and has held central management positions in the company,
  including the position of executive vice president for health, safety and the
  environment and executive vice president for Technology & Projects. Øvrum
  was the company's first female platform manager, on the Gullfaks field. She
  was senior vice president for operations for Veslefrikk and vice president of
  operations support for the Norwegian continental shelf.
  Education:Master's degree in
  engineering (sivilingeniør) from the Norwegian Institute of Technology (NTH)
  in Trondheim, specialising in technical physics.
  Family relations:No family relations to
  other members of the CEC, members of the board or the corporate assembly.
  Other matters:Øvrum is a Norwegian citizen and
  resident in Norway.Arne
  Sigve Nylund, Executive vice
  president
  Development and production Norway (DPN)
 Arne Sigve Nylund
  Born:1960
  Position:Executive vice president
  of Statoil ASA since 1 January 2014.
  External offices:Member of the board of
  directors of The Norwegian Oil & Gas Association (Norsk Olje & Gass).
  Number of shares in
  Statoil ASA as of 31 December 2015: 9,261
  Loans from Statoil:None
  Experience:Employed by Mobil
  Exploration Inc. from 1983-1987. Since 1987, Nylund has held several central
  management positions in Statoil ASA.
  Education:Mechanical engineer from
  Stavanger College of Engineering with further qualifications in operational
  technology from Rogaland Regional College/University of Stavanger (UiS).
  Business graduate of the Norwegian School of Business and Management (NHH).
  Family relations:No family relations to
  other members of the CEC, members of the board or the corporate assembly.
  Other matters:Nylund is a Norwegian citizen and is
  resident in Norway.Jens
  Økland, executive vice president Marketing, Midstream and Processing (MMP)
 Jens Økland
  Born:1969
  Position:Executive vice president
  of Statoil ASA since 1 June 2015.
  External offices:None
  Number of shares in
  Statoil ASA as of 31 December 2015:10,735
  Loans from Statoil ASA:None
  Experience:Økland joined Statoil in
  1994 and has mainly worked in the midstream and downstream sectors. Before
  becoming executive vice president of MMP, Økland worked as vice president of
  operations for the Åsgard area in Development and Production Norway. Åsgard
  ranks among the largest developments on the Norwegian continental shelf,
  supplying about 11 billion cubic metres of gas annually to Europe. Previously
  Økland was senior vice president of Statoil’s natural gas portfolio and supply
  business in North America, marketing and developing infrastructure solutions
  for equity and non-equity production. Before heading up Statoil’s downstream
  gas division in North America, he had senior marketing and business
  development positions within natural gas in Europe mainly focusing on
  Germany, Statoil’s largest gas market.
  Education:MSc in business from BI
  Norwegian Business School.
  Family relations:No family relations to
  other members of the CEC, members of the board or the corporate assembly.
  Other matters:Økland is a Norwegian citizen and
  resident in Norway.Irene
  Rummelhoff, executive vice
  president New Energy
  Solutions (NES)
 Irene Rummelhoff
  Born:1967
  Position:Executive vice president
  of Statoil ASA since 1 June 2015.
  External offices:Member of the board of
  directors of Norsk Hydro ASA.
  Number of shares in
  Statoil ASA as of 31 December 2015:17,082
  Loans from Statoil ASA:None
  Experience:Rummehoff joined Statoil
  in 1991. She has held a number of management positions within international
  business development, exploration, and the downstream business in Statoil.
  Education:Master’s degree in
  petroleum geosciences from the Norwegian Institute of Technology (NTH).
  Family relations:No family relations to
  other members of the CEC, members of the board or the corporate assembly.
  Other matters:Rummehoff is a Norwegian citizen and
  resident in Norway.
 140Statoil, Annual Report on Form 20-F 2015


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Statoil, Annual Report on Form 20-F
2015141


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Statoil has granted loans to the Statoil-employed spouse
of certain of the Executive Vice Presidents as part of its general loan
arrangement for Statoil employees. Employees in salary grade 12 or higher may
take out a car loan from Statoil in accordance with standardised provisions set
by the company. The standard maximum car loan is limited to the cost of the
car, including registration fees, but not exceeding NOK 300,000. Employees
outside the collective labour area are entitled to a car loan up to NOK 575,000
(vice presidents and senior vice presidents) or NOK 475,000 (other positions).
The car loan is interest-free, but the tax value, "interest
advantage", must be reported as salary. Permanent employees in Statoil ASA
may also apply for a consumer loan up to NOK 300.000. The interest rate on
consumer loans is corresponding to the standard rate in effect at any time for “reasonable
loans” from employer as decided by the Norwegian Ministry of Finance, i.e. the
lowest rate an employer may offer without triggering taxation of the advantage
for the employee.  142Statoil, Annual Report on Form 20-F 2015


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7.9
Compensation to governing bodies  This section describes the compensation to
the board of directors, the corporate executive committee and the corporate
assembly.  In 2015, the aggregate compensation to the
corporate assembly was NOK 1,047,143, to the members of the board of directors
NOK 5,950,035 and to the members of the corporate executive committee NOK 87,763,000
(all in rounded figures).  The members of the corporate assembly and the
board of directors have an annual, fixed remuneration, except for deputy
members who receive remuneration per meeting. In addition, board members
resident outside of Scandinavia or outside of Europe receive additional travel
fees (based on two different travel fee rates) per board meeting attended. The
shareholder-elected and employee-elected members of the corporate assembly and
the board are entitled to the same remuneration rates.  Detailed information about the individual
compensation to the members of the board of directors and members of the
corporate executive committee in 2015 is provided in the tables below.  Members
  of the board (figures in NOK thousand)
 Board
  of directors
 Audit
  committee
 Compensation and executive development committee
 SSE
  committee
 Total
  remunerationØystein Løseth1)
 557
 65
 65
 -
 687Svein Rennemo2)
 357
 -
 53
 -
 410Grace Reksten Skaugen3)
 98
 -
 27
 -
 125Jakob Stausholm
 373
 207
 -
 -
 580Bjørn Tore Godal
 373
 -
 84
 93
 550Lill Heidi Bakkerud
 373
 -
 -
 84
 457Maria Johanna Oudeman
 503
 -
 84
 -
 587Catherine Hughes4)
 198
 -
 -
 37
 235James Mulva5)
 307
 65
 -
 -
 373Stig Lægreid
 373
 -
 -
 84
 457Ingrid Elisabeth di
  Valerio
 373
 134
 -
 -
 507Roy Franklin6)
 261
 68
 -
 65
 394Wenche Agerup7)
 138
 -
 31
 31
 200Rebekka Glasser
  Herlofsen8)
 296
 91
 -
 -
 387Total
 4,580
 631
 344
 395
 5,9501) Chair of the board
  from 1 July 20152) Chair of the board
  until and including 30 June 2015 (resigned)3) Deputy chair until and
  including 18 March 2015 (resigned)4) Member until and
  including 15 April 2015 (resigned)5) Member until and
  including 30 June 2015 (resigned)6) Deputy chair from 1
  July 20157) Member from 21 August
  20158) Member from 19 March
  2015
 Statoil, Annual Report on Form 20-F
2015143


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Fixed remunerationMembers
  of corporate
  executive
  committee                                                                                                    
  in 2015 (figures in NOK thousand)1)
 Fixed pay2)
 Cash allowance3)
 LTI 4)
 Annual
  variable pay5)
 Taxable
  benefits
 Taxable
  compensation
 Non-taxable
  benefits
  in kind
 Estimated
  pension
  cost6)
 Estimated present
  value of pension
  obligation7). 8)Eldar Sætre9), 11)
 7,748
 0
 2,492
 3,504
 421
 14,165
 0
 0
 79,699Hans Jakob Hegge9)
 1,349
 44
 302
 324
 7
 2,025
 0
 273
 7,753Torgrim Reitan9),
  10)
 1,881
 0
 0
 1,022
 337
 3,239
 0
 979
 12,727Torgrim Reitan - CFO9)
 1,890
 0
 761
 0
 117
 2,769
 0
 0
 0Lars Christian Bacher
 3,266
 0
 739
 843
 377
 5,226
 437
 872
 14,191Timothy Dodson
 3,695
 0
 803
 789
 148
 5,435
 321
 1,109
 33,022Margareth Øvrum
 3,805
 0
 867
 1,241
 152
 6,066
 127
 0
 48,435Arne Sigve Nylund
 3,345
 0
 725
 1,352
 146
 5,568
 0
 833
 28,586Jens Økland9)
 1,684
 41
 394
 526
 11
 2,655
 0
 354
 5,669Tor Martin Anfinnsen9)
 1,298
 0
 281
 584
 104
 2,266
 0
 390
 22,576Irene Rummelhoff9)
 1,563
 38
 365
 395
 11
 2,371
 0
 386
 7,585Anders Opedal9)
 2,323
 44
 544
 761
 11
 3,682
 0
 547
 7,540William Maloney8),
  9)
 3,933
 0
 4,625
 4,625
 1,226
 14,410
 138
 698
 0John Knight2), 8)
 8,695
 0
 3,468
 3,468
 1,231
 16,863
 0
 0
 0
  1)All figures in the
table are presented on accrual basis. 2)Fixed
pay consists of base salary, holiday allowance and other administrative
benefits.John Knight's
fixed pay also includes a cash supplement that replaces his defined
contribution pension plan. 3)Cash allowance in
lieu of pension accrual above 12 G (the base amount in the national insurance
scheme). 4)The
fixed long-term incentive (LTI) element implies an obligation to invest the net
amount in Statoil shares.A
lock-in period of 3 years applies for the investment. The LTI element is
presented the year it is granted for the members of the corporate executive
committee employed by Statoil ASA. Members of the corporate executive committee
employed by non-Norwegian subsidiaries have a LTI scheme deviating from the
model used in the parent company. A net amount equivalent to the annual
variable pay is used for purchasing Statoil shares. 5)Annual variable
pay includes holiday allowance for corporate executive committee (CEC) members
resident in Norway. 6)Estimated pension
cost for CEC members under defined benefit plans (Eldar Sætre, Timothy Dodson,
Margareth Øvrum, Arne Sigve Nylund and Tor Martin Anfinnsen) is calculated
based on actuarial assumptions and pensionable salary (mainly base salary) at
31 December 2014 and is recognised as pension cost in the statement of income
for 2015. The other CEC members have defined contribution plans including
notional contribution plans and the contributions in the reporting period are
recognised as pension cost in the statement of income. Payroll tax is not
included. For further information, see note 19 Pensions. 7)Torgrim Reitan,
Lars Christian Bacher, Hans Jakob Hegge, Jens Økland, Irene Rummelhoff and
Anders Opedal were transferred to a defined contribution plan from 1 April
2015. Paid-up policies and rights letters issued in 2015 related to the defined
benefit plans as well as the notional contribution plans are included in the
present value of pension obligation at 31 December 2015. Estimated present
value of pension obligation for the rest of the members of CEC employed by
Statoil ASA, are presented with the defined benefit obligation. 8)William
Maloney and John Knight's remuneration is in local currency US Dollar and
British Pound, respectively. For John Knight the figures in the table are
presented in NOK, using average currency rates in 2015. For William Maloney the
average currency rates for the period 1 January to 30 September 2015 are used. The
change in currency rates during the year, such as strengthening of USD and GBP
versus NOK, impacts the development from 2014 to 2015.  William Maloney’s
variable compensation is paid in 2015. 9)Eldar
Sætre resumed role as acting chief executive officer (CEO) from 15 October 2014
until 3 February 2015. The 4 February Eldar Sætre was appointed as CEO on a
permanent basis. Tor Martin Anfinnsen acted as executive vice president for Marketing,
Midstream and Processing (MMP) from 15 October 2014 until 31 May 2015. Jens
Økland was appointed executive vice president for MMP from 1 June 2015. William
Maloney resigned as executive vice president for Development and Production
North America (DPNA) July 31 and was followed by Torgrim Reitan who started as
executive vice president for Development and Production USA (DPUSA) 1August
2015. Hans Jakob Hegge was appointed executive vice president and chief
financial officer from 1. August 2015.Irene
Rummelhoff was appointed executive vice president for the newly established
business area New Energy Solutions (NES) on 1 June 2015. Anders Opedal was appointed
on 1 April 2015 in the new position chief operating officer (COO). 10)Compensation and benefitincluding
standard international assignment terms for Torgrim Reitan during his tenure as
executive vice president in DPUSA, commencing 1 August 2015. 11)Fixed pay for Eldar Sætre includes fixed remuneration element of
NOK 1 815 000 not included in pensionable salary  There
are no loans from the company to members of the corporate executive committee.  Former
chief executive officer Helge Lund has in 2015 paid back NOK 5 033 491 in
LTI bonus received in 2012, 2013 and 2014. He has received compensations and
benefits that amount to NOK 2.7 million in 2015. The amount is related to base
salary for the period 1 January to 8 February 2015 and final settlement payments
such as holiday allowance earned in 2014 and 2015.  144Statoil, Annual Report on Form 20-F 2015


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Fixed remunerationMembers
  of corporate
  executive
  committee                                                                                                    
  in 2014 (figures in NOK thousand)1)
 Fixed pay3)
 LTI6)
 Annual
  variable pay7)
 Taxable
  benefits
  in kind
 Taxable
  compensation
 Non-taxable
  benefits
  in kind
 Estimated
  pension
  cost8)
 Estimated present
  value of pension
  obligation4), 9)Helge Lund4), 5),
  9)
 5,640
 2,165
 -
 249
 8,054
 199
 6,008
 73,944Torgrim Reitan9)
 3,283
 761
 1,066
 126
 5,237
 -
 879
 16,339Lars Christian Bacher9)
 3,256
 739
 1,034
 363
 5,393
 428
 685
 15,879Timothy Dodson
 3,496
 803
 1,124
 175
 5,597
 313
 1,343
 32,689Margareth Øvrum
 3,779
 867
 1,457
 250
 6,352
 98
 1,349
 48,701Arne Sigve Nylund5)
 2,984
 725
 1,421
 108
 5,239
 -
 773
 26,646Eldar Sætre - CEO5)
 1,370
 -
 689
 35
 2,094
 -
 989
 46,769Eldar Sætre - MMP
 2,685
 858
 901
 143
 4,588
 -
 -
 -Tor Martin Anfinnsen5)
 817
 -
 239
 90
 1,147
 -
 234
 22,196William Maloney2),
  8)
 4,333
 2,167
 2,167
 960
 9,627
 166
 713
 -John Knight2), 3)
 7,132
 2,845
 2,845
 1,133
 13,955
 -
 -
 -
  1)All
figures in the table are presented on accrual basis. 2)William
Maloney and John Knight's remuneration is in local currency US Dollar and
British Pound, respectively. The figures in the table are presented in NOK,
using average currency rates in 2014. 3)Fixed
pay consist of base salary, holiday allowance and any other administrative
benefits.The figures are
presented on accrual basis. John Knight's fixed pay also includes a cash
supplement that replaces his defined contribution pension plan in 2014. 4)Helge
Lund resigned from his position as CEO of Statoil 15 October 2014. Helge Lund has received
salary and benefits that amounts to NOK 1.8 million in 2014 after his
resignation as chief executive officer, not included in the table above.The pension liability listed in the
table above represents the estimated present value of his pension obligation as
of 31 December 2014. In line with the company’s LTI policy, resignation during
the lock-in period is regarded as a non-fulfilment of the LTI obligations.
Following his resignation Helge Lund was obliged to pay back to Statoil a total
of NOK 5 033 491, calculated based on the value of the locked shares
acquired under the LTI program. 5)Following
Helge Lund’s resignation, Eldar Sætre resumed role as acting CEO with immediate
effect on 15 October 2014, and Tor Martin Anfinnsen replaced Eldar Sætre as
acting executive vice president for Marketing, Midstream and Processing (MMP).
Arne Sigve Nylund replaced Øystein Michelsen from January 2014. 6)The
fixed long-term incentive (LTI) element implies an obligation to invest the net
amount in Statoil shares.A
lock-in period of 3 years applies for the investment. The LTI element is
presented the year it is granted for the members of the corporate executive
committee employed by Statoil ASA. Members of the corporate executive committee
employed by non-Norwegian subsidiaries have a LTI scheme deviating from the
model used in the parent company. A net amount equivalent to the annual
variable pay is used for purchasing Statoil shares, and the figures are
presented on accrual basis. 7)Annual
variable pay includes holiday allowance, and is presented on accrual basis. 8)Estimated
pension cost is calculated based on actuarial assumptions and pensionable salary
(mainly base salary) at 31 December 2013 and is recognised as pension cost in
the statement of income for 2014.Payroll
tax is not included. William Maloney is employed by a non-Norwegian entity and
his pension cost reflects the payment under the entity's defined contribution
plan made in 2014. 9)Torgrim
Reitan and Lars Christian Bacher was transferred to a defined contribution plan
from 1 April 2015, and the Estimated present value of pension obligation per 31
December 2014 reflects this change. Estimated present value of pension
obligationrelated to
Helge Lund, Torgrim Reitan and Lars Christian Bacher, are based on the
estimated value of paid-up policies and rights letters to be issued in 2015,
related to Helge Lund's resignation and the termination of Torgrim Reitan and
Lars Christian Bacher's defined benefit pension plan. Estimated present value
of pension obligation for the rest of the members of the corporate executive
committee employed by Statoil ASA, are presented with the defined benefit
obligation. Statoil, Annual Report on Form 20-F
2015145


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1Remuneration
policy and concept for the accounting year 2016 Reference
is made to the document “Statement on remuneration for Statoil’s Corporate
Executive Committee”, which is available atwww.statoil.com, for a detailed description of the
remuneration and remuneration policy for executive management applicable for
the years 2015 and 2016. The main elements of Statoil’s executive remuneration
are described in the paragraphs below.  1.1Policy and principles The
board of directors has in 2015 decided to introduce several new elements to the
company’s executive remuneration concept. The revised governmental guidelines
on executive remuneration
as of 13 February 2015 (“2015 governmental guidelines”) entailed adjustments
with impact on the company’s executive remuneration concept. Changes to the
pension system and the long-term incentive scheme are implemented to align with
the 2015 governmental guidelines on executive remuneration. In addition the
company has initiated improvements to strengthen the link between executive
remuneration and the company’s overall performance and results.  The
changes include: ·a cap on pension
contribution at the maximum limit in the tax-favoured joint pension schemes in
Norway (currently 12 G[2]) ·adjustment to the
long-term incentive scheme (LTI) ·a company
performance modifier ·a threshold for
variable pay  These changes
are described in section 1.2-1.5 below. The company
performance modifier is subject to approval by the 2016 annual general meeting
(AGM) cf. section 5.  Other than
described in this section, the company’s established remuneration principles
and concepts as described in previous years Statements on remuneration and
other employment terms for Statoil’s corporate executive committee will be
continued in the accounting year 2016.  The
remuneration concept is an integrated part of our values based performance
framework. It has been designed to: ·reflect our global
competitive market strategy and local market conditions ·strengthen the
common interests of employees in the Statoil group and its shareholders ·be in accordance
with statutory regulations and good corporate governance ·be fair,
transparent and non-discriminatory ·equally reward and
recognise “what” we deliver and “how” we deliver ·differentiate on
the basis of responsibilities and performance ·reward both short-
and long-term contributions and results  1.2Cap on pension contribution at the
maximum limit in the tax-favoured joint pension schemes in Norway In the White
Paper no. 27 (2013- 2014) the Government announced changes to its policy
relating to pension contribution in companies where the State has majority
ownership. The State would no longer support pension contribution above 12 G.
This policy change was manifested in 2015 governmental guidelines on executive
remuneration. In order to align with the 2015 governmental guidelines, Statoil
ASA has introduced a cap at 12 G for pension contribution for new members of
the corporate executive committee appointed after the effective date of the
2015 governmental guidelines.  In lieu of
pension contribution for income above 12 G, new internal members of the
corporate executive committee will be eligible for compensation. The
compensation level will be dependent on the candidate’s pension terms and base
salary level and will be in the range of 15 – 20% of his/her base salary.  1.3Adjustments to the long-term incentive
scheme in Statoil ASA According to the 2015 governmental
guidelines, the long-term incentive (LTI) scheme is defined as variable remuneration.
Earlier this was part of the fixed remuneration and included in the basis for
calculating the participants’ annual variable pay. This practice will be
discontinued with the effect from earning year 2016. TheLTI scheme as variable
remuneration will have a maximum annual grant at 30% of the participants’ fixed
remuneration c.f. section 1.6 below.  1.4Threshold The board of
directors has decided to introduce a threshold in the reward concept as a
pre-requisite for the payment of variable pay and grant of long-term incentive
(LTI). The threshold will have effect on the long-term incentive grant in 2016
provided this is not impeded by obligations in individual agreements.From the earning year 2016
the threshold will be applied on annual variable pay payments in 2017 and
onwards.The threshold
is based on Statoil group’s full-year adjusted earnings after tax, requiring
that a minimum level of earnings must be achieved for any payments to be made.
This minimum level has been set at USD 2 billion. Earnings between USD 2 and
3.3 will result in bonus payments reduced by 50%.  Above USD 3.3 billion the
threshold is fully achieved and variable pay payments are not affected. Prior
to application of the threshold an  assessment  of the company’s overall
performance in relation to the adjusted earnings results shall be made by the
board of directors based on recommendations by the board compensation and
executive development committee.   [2]The base amount in the Norwegian
national insurance scheme, currently NOK 90,068
 146Statoil, Annual Report on Form 20-F 2015


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1.5Company performance modifier Subject to
approval by the 2016 annual general meeting, a company performance modifier is
introducedin
the calculations for variable pay schemes from 2016 with subsequent impact on
variable pay from 2017 onwards.The
company performance modifier determines the proportion of the bonus factor that
will be paid, ranging from 50% to 150%. Company performance is assessed against
two equally weighted measures: relative total shareholder return (TSR) and
relative return on average capital employed (RoACE).  1.6The remuneration concept for the
corporate executive committee Statoil’s
remuneration concept for the corporate executive committee consists of the
following main elements: ·Fixed remuneration
(base salary) and as applicable cash compensation ·Variable pay
(annual variable pay (AVP) and long-term Incentive (LTI)) ·Benefits
(primarily pension, insurance and share savings plan)  Fixed
remuneration consists of base salary, and as applicable cash compensation. The
cash compensation is applied in lieu of pension contribution above 12 G as
described in section 1.2 above or as a fixed remuneration to be competitive in
the market.  The variable
pay elements for members of the corporate executive committee in the parent
company are: ·annual variable
pay scheme which has a maximum potential of 50% of fixed remuneration ·LTI scheme with a
maximum grant of 30% of fixed remuneration. The LTI grant level is
differentiated related to position level. The obligation to invest the net LTI
amount in Statoil shares and keep for a lock in period of 3 years will be
continued.  The annual
variable pay will be subject to the company performance modifier ref. section
1.5 above. Irrespective of the performance modifier results, the annual
variable pay will have a maximum at 50% of the fixed remuneration.  The main
benefit programmes applicable to senior executives are the general pension
scheme, the insurance scheme and the employee share savings plan.In 2015 Statoil implemented
a defined contribution scheme as the new general pension scheme. With the
exception of employees who were 15 years or less from regular retirement age at
31th December 2014, all employees have been transferred to the new scheme. The
employees exempted from transfer will retain the defined benefit scheme.  Deviations
from the general principles outlined below pertaining to one current member and
one former member of the corporate executive committee, implemented with effect
as of 1 January 2011, are described in the statement on executive remuneration.These
deviations have also been described in previous statements on remuneration and
other employment terms for Statoil’s corporate executive committee.   Statoil, Annual Report on Form 20-F
2015147


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The main elements of Statoil’s
executive remuneration are described in more detail in the table below.  Main Elements - Statoil Executive RemunerationRemuneration Element
 Objective
 Award level
 Performance criteriaBase Salary
 Attract and retain the
  right high-performing individuals providing competitive but not
  market-leading terms.
 We offer base salary
  levels which are aligned with the individual's responsibility and performance
  at a level which is competitive in the markets in which we operate.
 The evaluation of performance
  is based on the fulfilment of pre-defined goals; see element Annual Variable
  Pay below. The base salary is normally subject to annual review.Long-Term Incentive
  (LTI)
 Strengthen the alignment
  of top management and shareholder interests and retention of key employees.
 The LTI system is a,
  monetary compensation calculated as a portion of the participant’s base
  salary; with a maximum annual grant at 30% of fixed remuneration. On behalf
  of the participant, the company acquires shares equivalent to the net annual
  amount. The grant is subject to a three year lock-in period and then released
  for the participant’s disposal. Deviations applicable for executive vice
  presidents employed outside the parent company are described in the statement
  on executive remuneration. The threshold principles will apply for the annual
  grant.
 In Statoil ASA, LTI is a
  variable remuneration element, Participation in the LTI scheme and the size
  of the annual LTI element are reflective of the level and impact of the
  position and not directly linked to the incumbent’s performance.Annual Variable Pay
 Drive and reward
  individuals for annual achievement of business objectives and how results are
  delivered. Ensure link between individual variable pay and company’s overall
  financial performance.
 Members of the corporate
  executive committee are entitled to an annual variable pay ranging from 0–50%
  of their fixed remuneration. Target value is 25% (target value reflects fully
  satisfactory goal achievement).
  Deviations applicable
  for members of the corporate executive committee employed outside the parent
  company are described in the statement on executive remuneration. The
  deviation will in 2016 apply for one executive vice president employed by
  Statoil Global Employment Company Ltd. in London.
  The threshold principles
  and the company modifier (subject to AGM approval) will apply.
 Achievement of annual
  performance goals (how and what to deliver), in order to create long-term and
  sustainable shareholder value. Assessment of goals related to selected KPI’s
  from the balanced scorecard will impact the variable remuneration for the
  members of the corporate executive committee.Pension & Insurance
  Schemes
 Provide competitive
  postemployment and other benefits.
 The general occupational
  pension plan is a defined contribution scheme with a contribution level of
  7%/22% below/above 7,1 G. The defined benefit scheme will be retained by a
  grandfathered group of employees. The benefit scheme has a pension level
  amounting to 66 per cent of the pensionable salary conditional on a minimum
  of 30 years of service. Pension from the national insurance scheme is taken
  into account when estimating the pension. In order to draw a full pension
  from Statoil’s defined benefit scheme the employment with the company needs
  to be maintained until the pensionable age.
  For new internal members
  of the corporate executive committee a cap for pension contribution at 12 G
  is established.
 N/AEmployee Share Savings
  Plan
 Align and strengthen
  employee and shareholder interests and remunerate for long term commitment
  and value creation.
 Offer to purchase
  Statoil shares in the market limited to 5% of annual base salary.
 If shares are kept for
  two calendar years of continued employment, the participants will be
  allocated bonus shares proportionate to their purchase.
  148Statoil, Annual Report on Form 20-F 2015


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1.7.Base salary
and remuneration mix 2016 Due to the current challenges facing
our industry with falling oil and gas prices, decreasing margins and
unsustainable cost levels, a salary freeze will be implemented for members of
the corporate executive committee and other leaders and senior professionals in
2016.  The
graphs below illustrate the chief executive officer’s remuneration mix for 2016
and a typical remuneration mix for executive vice presidents. The chief
executive officer’s total remuneration package includes an additional fixed
remuneration element compared to the executive vice presidents, and the
executive vice presidents remuneration package includes, as applicable, a cash
compensation in lieu of pension contribution above 12 G due to the implemented
cap, see section 1.2 Cap
on pension contribution at the maximum limit in the tax-favoured joint pension
schemes in Norway above;
please see further details of the chief executive officer’s terms and
conditions in section 1.11 Terms and conditions for president and chief
executive officer, Eldar  Sætre.                        Figure
1: Illustrates chief executive officer remuneration mix for 2016. CEO’s pension
was fully accrued by 31 December 2014. Figure
2: Illustrates an example of a typical remuneration mix for an executive vice
president in Statoil with a cap on pension contribution.  1.8.Pension and
insurance schemes Members
of the corporate executive committee are part of the general pension scheme in
Statoil ASA. The chief executive officer and three executive vice presidents
have individual early retirement pension agreement with the company.  The
chief executive officer and one of the executive vice presidents have
individual pension terms according to a previous standard arrangement
implemented in October 2006. Subject to specific terms those executives are
entitled to a pension amounting to 66 per cent of pensionable salary and a
retirement age of 62. When calculating the number of years of membership in
Statoil’s general pension plan, these agreements
grant the right to an
extra contribution time corresponding to half a year of extra membership for
each year the individual has served as executive vice president.  In
addition, two members of the corporate executive committee have individually
agreed retirement age of 65 and an early retirement pension level amounting to
66% of pensionable salary.  The
individual pension terms for executive vice presidents outlined above are
results of commitments according to previous established agreements.  Following
a board decision 7 February 2012, the company’s standard pension arrangements for executive
vice presidents deviating from Statoil ASA’s general pension plan have been
discontinued and have not been applied for new appointments to the corporate
executive committee.  As
described in section 1.2, a cap on pension contribution for income above 12 G
was in 2015 implemented for new members of the Corporate Executive Committee.
The cap is applied to four executives vice presidents appointed after 13
February 2015.  Members of the
corporate executive committee appointed before 13 February 2015, will maintain
their pension contribution above 12 G based on obligations in established
agreements.  Pension
accruals for pensionable salary above 12 G are recognised as an unfunded
defined benefit pension plan, i.e. not funded in a separate legal entity.  Statoil, Annual Report on Form 20-F
2015149


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In addition to the pension benefits
outlined above, the executive vice presidents in the parent company are offered
disability and dependents’ benefits in accordance with Statoil’s general
pension plan. Members of the corporate executive committee are covered by the
general insurance schemes applicable within Statoil.  150Statoil, Annual Report on Form 20-F 2015


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1.9.Severance pay arrangements The
chief executive officer and the executive vice presidents are entitled to a
severance payment equivalent to six months’ salary, commencing at the time of
expiry of a six months’ notice period, when the resignation is at the request
from the company.The
same amount of severance payment is also payable if the parties agree that the
employment should be discontinued and theexecutive
vice presidentgives
notice pursuant to a written agreement with the company.Any other payment earned by the
executive vice president during the period of severance payment will be fully
deducted. This relates to earnings from any employment or business activity
where the executive vice president has active ownership.  The entitlement to severance payment
is conditional on the chief executive officer or the executive vice president
not being guilty of gross misconduct, gross negligence, disloyalty or other
material breach of his/her duties.  As a general
rule, the chief executive
officer’s/executive vice president’s own
notice will not instigate any severance payment.  1.10.Other benefits Statoil
has a share savings plan available to all employees including members of the
corporate executive committee. The share savings plan entails an offer to
purchase Statoil shares in the market limited to five per cent of annual gross
salary. If the shares are kept for two full calendar years of continued
employment the employees will be allocated bonus shares proportionate to their
purchase. Shares to be used for sale and transfer to employees are acquired by
Statoil in the market, in accordance with the authorisation from the annual
general meeting.  The
members of the corporate executive committee have benefits in kind such as
company car and electronic communication.  1.11.Terms and
conditions for president and chief executive officer, Eldar Sætre Effective
4 February 2015 Statoil’s board of directors appointed Eldar Sætre as president and chief executive officer
of Statoil, following an
acting period since 15 October 2014. The chief executive officer’s annual base salary is NOK 5,700,000.
Furthermore, the CEO is entitled to an additional fixed remuneration element of
NOK 2,000,000 not included in the pensionable income.  The
chief executive officer will participate in an annual variable pay scheme with
a target level of 25%, and participation to the Company’s 2016 LTI scheme with
a value of 30% (gross) of base salary. The pension terms remain unchanged
according to previously established pension agreement, as described in section
1.8 above.  2.Performance management, assessment and
results essential for variable pay  2.1.Performance
management, assessment and results essential for variable pay for 2015 Individual
salary and annual variable pay reviews are based on the performance evaluation
in our performance management system.  Performance
is evaluated in two dimensions; “What” we deliver and “How” we deliver. Goals
on “How” we deliver are based on our core values and leadership principles and
address the behaviour required and expected in order to achieve our delivery
goals.  “What”
we deliver (business delivery) is defined through the company’s performance
framework “Ambition to Action”, which addresses strategic objectives, key
performance Indicators (KPIs) and actions across the five perspectives; Safety,
Security and Sustainability, People and Leadership, Operations, Market and
Results. Generally, Statoil believes in setting ambitious targets to inspire
and drive strong performance.  In
2015, the main objectives and KPIs for each perspective were as outlined below.
Each perspective was in addition supported by comprehensive plans and actions.
It is only the KPI’s for Results that will affect variable remuneration for
members of the corporate executive committee.  Statoil, Annual Report on Form 20-F
2015151


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Strategic objectives
 2015 assessmentSafety, 
  Security and Sustainability
 The strategic objectives
  and actions address security and sustainability (Safety - see the Results
  perspective below)
 There were no serious
  well incidents, whereas the number of oil and gas leakages was above target.
  TotalCO2reduction
  was better than targeted and future ambitions have been increased.People and organisation
 The strategic objectives
  and actions address high performing leaders and teams, and global and
  cost-effective capabilities
 Employee engagement
  increased from 2014, during a time with extensive organisational efficiency
  programmes. Leadership renewal across the organisation was better than
  targeted.Operations
 The strategic objectives
  and actions address reliable and cost-efficient operations, and value-driven
  technology development.
 Production came in well
  above target, partly driven by continued improvements in production
  efficiency and optimised gas production from our flexible gas fields. Unit
  production cost is now the lowest among industry peers. Unit finding cost
  increased due to lower than expected exploration results.Market
 The strategic objectives
  and actions address stakeholder trust, value chain optimisation and portfolio
  and project management.
 The organic Reserve
  Replacement Ratio (RRR) ended somewhat below the target of 1, while total RRR
  was well below due to divestments and a number of projects being postponed to
  maintain financial flexibility and improve project profitability. Project cost
  efficiency versus peers continued to improve.Results
 The strategic objectives
  and actions address shareholder return, financial robustness, value creation
  from exploration, cost & capital discipline and for 2015 also Safety.
 Relative
  Total Shareholder Return (TSR) improved and ended on 6th against
  an industry peer group of 12. Relative RoACE also ended 6th but
  fell as a result of high exposure to upstream margins. Capex ended well below
  initially guided levels. The cash flow improvement programme delivered well
  above target. The serious incident frequency of 0,6 was unchanged from
  2014.Board assessment of the chief executive officer’s performance
  In its assessment of the chief executive officer’s performance,
  and consequently his merit and annual pay for 2015, the board has put
  emphasis on the solid delivery on the cashflow improvement programme as well
  as CAPEX reductions and TSR. Serious incident frequency also continues to
  improve from 2014.
  Before
final conclusions of the performance assessments are drawn, sound judgement and
hindsight information are applied. Measured KPI results are reviewed against
their strategic contribution, sustainability and significant changes in
assumptions.  This
balanced approach, which involves a broad set of goals defined in relation to
both “What” and “How” dimensions and an overall performance evaluation, is
viewed to significantly reduce the likelihood that remuneration policies may
stimulate excessive risk-taking or have other material adverse effects.  2.2Key performance indicators for the
chief executive officer for 2016 For the
accounting year 2016 the CEO’s variable remuneration for 2016 and base salary
merit increase as of 1 January 2017 will be based on assessment of results on
the following KIPs:  Safety,
Security and Sustainability ·CO2intensity for the upstream portfolio ·Serious Incident
Frequency (actual)  Market ·Capex (capital
expenditure)  Results ·Relative Total
Shareholder Return ·Relative RoACE ·Cash flow
improvement programme  3.Execution
of the remuneration policy and principles in 2015  3.1Deviations
from the governmental guidelines on variable compensation 2015 Two members of the executive committee had in
2015 variable pay schemes deviating from the description in section 1.6 above.
One of the executives was employed by Statoil Gulf Services LLC in Houston and
resigned from the company 31 July 2015. He was entitled to a variable pay
scheme with a maximum of 100% for AVP and LTI, respectively. The other is still
employed by Statoil Global Employment Company Ltd. in London and his variable
pay scheme entail a framework for variable pay of 75% of his base salary for
each of the elements annual variable pay and LTI, and is performance based. Hiscontract also includes a
provision for severance payment of 12 months’ base salary.  152Statoil, Annual Report on Form 20-F 2015


---

The board’s overall assessment is that
the extended framework implemented with effect from 1 January 2011 for the
variable pay schemes for these executives
is necessary due to local market conditions, but not market leading for
positions at this level at the respective locations.  3.2Changes to the Corporate Executive
Committee in 2015 In
addition to the appointment of Eldar Sætre as president and chief executive
officer, several changes have in 2015 been implemented to the organisational
structure and the composition of the corporate executive committee. A new corporate staff and support
function, chief operating officer (COO), was established from 1 April 2015, and
Anders Opedal was appointed as executive vice president and COO.  New
energy Solution (NES) was established as a new business area 1 June 2015 with
Irene Rummelhoff as the executive vice president. Jens Økland was appointed
executive vice president in MMP from 1 June 2015 succeeding Tor Martin
Anfinnsen’s acting period.  William
Maloney, executive vice president Development and Production North America
(DPNA), resigned from the company 31 July 2015. An adjustment to the DPNA
organisation is implemented and this business area is renamed to Development
and Production USA (DPUSA)[3]. Torgrim
Reitan assumed responsibility as executive vice president in DPUSA as of 1
August 2015. Hans Jakob Hegge succeeded Torgrim Reitan as CFO from 1 august
2015.  3.3Changes to individual terms in 2015 Following
former president and chief
executive officer Helge
Lund’s resignation a termination agreement was entered into. Helge Lund’s
termination date was 9 February 2015. Helge Lund received base salary and
benefits compensation up until this date. He did not receive variable pay for
the performance year 2014. The LTI scheme and share savings plan was closed in
accordance with the company policy, and a repayment of NOK 5,033,491 was made by
Helge Lund to Statoil ASA according to the LTI agreement. The company issued a
paid-up policy and pension right letters for his pension accruals, in
accordance with his individual pension agreement.  4.Thedecision-making process The
decision-making process for implementing or changing remuneration policies and
concepts, and the determination of salaries and other remuneration for
corporate executive
committee, are in accordance with the provisions of the Norwegian public
limited liability companies act sections 5-6 and 6-16 a and the board’s rules
of procedure. The board’s rules of procedure are available atwww.statoil.com/board.  The board of
directors has appointed a designated compensation and executive development
committee. The compensation and executive development committee is a
preparatory body for the board. The committee’s main objective is to assist the
board of directors in its work relating to the terms of employment for
Statoil’s chief executive officer and the main principles and strategy for the
remuneration and leadership development of our senior executives. The board of
directors determines the chief executive officer’s salary and other terms of
employment.  The
compensation and executive development committee answers to the board of
Statoil ASA for the performance of its duties. The work of the committee in no
way alters the responsibilities of the board of directors or the individual
board members.  For
further details about the roles and responsibilities of the compensation and
executive development committee, please refer to the committee’s instructions
available atwww.statoil.com/compensationcommittee.  5.Company
performance modifier  Introduction It is
recommended to introduce a company performance modifier to be applied in
calculation of variable pay. The relative total shareholder return is
recommended as one of the criteria in the company modifier. Thus, the case is
submitted to the annual general
meeting for approval, pursuant to the provisions in the Public Limited
Companies Act § 5-6 third paragraph last sentence ref. § 6-16 a, first
paragraph third sentence number 3.  Background Statoil has
implemented annual variable pay schemes (AVP) for members of the corporate
executive committee. The schemes are described in section 1.6 of this
statement. Other executives, managers and employees in defined professional
positions are also eligible for individual variable pay according to the
company’s guidelines.  The company’s
current annual variable pay scheme is entirely based on the individual
participants’ performance. Statoil has not implemented a company performance
modifier for the variable pay schemes. The prevalent trend in the market is to
ensure that variable remuneration is aligned with the company’s performance.
The governmental guidelines on executive remuneration also underline that
“there shall be a clear connection between the variable salary and the
performance of the company.”  Proposal Based on this,
it is proposed to strengthen the link between the company’s overall financial
results and the individual variable pay by introducing a company performance
modifier. The company performance is planned to be assessed against two equally
weighted measures: relative total shareholder return (TSR) and relative return
on average capital employed (RoACE). TSR and RoACEhave historically  [3]Transfer of responsibility for the company’s business
in Canada from Development and Production North America (DPNA) to Development
and Production International (DPI)
 Statoil, Annual Report on Form 20-F
2015153


---

constituted
important performance indicators at the company’s scorecard and are currently
also applied in the corporate performance management system.   154Statoil, Annual Report on Form 20-F 2015


---

The
results of both of these corporate performance measures are compared to our
peers and our relative position determined. A position of first quartile means
that Statoil is amongst the top scoring quartile of peer companies. A position
of fourth quartile means Statoil is in the bottom performing quartile. In years
with strong deliveries on relative TSR and RoACE, the matrix will result in the
variable pay being modified with a factor higher than one and, correspondingly,
lower than one in weak years. By applying relative numbers, the effect of
fluctuating oil price will be reduced.  The
combination of ratings for both measures, will act as a ‘multiplier’ according
to the matrix displayed below.  The plan is
  to introduce the company performance modifier in calculation of annual
  variable pay for members of Statoil’s corporate executive committee. Further
  application of the company performance modifier in Long-term incentive
  schemes will also be assessed and decided if deemed appropriate. In Long-term
  incentive schemes a three years average result for the modifier will typically
  be applied. The company also plan to implement the modifier in variable pay
  schemes for employees in positions below the corporate executive level.
  
  The annual
  variable pay for members of the corporate executive committee will be within
  a framework of 50% of the fixed remuneration irrespective of the result of
  the modifier.Any
  deviations from this framework for members of the corporate executive
  committee will be explicitly explained in the board’s annual Statements on
  remuneration and other employment terms for Statoil’s corporate executive
  committee.
  
  A
  complete statement on remuneration and other employment terms for Statoil’s
  corporate executive committee is available atwww.statoil.com.
    Statoil, Annual Report on Form 20-F
2015155


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7.10
Share ownership  This section describes the number of Statoil
shares owned by the members of the board of directors, the corporate assembly
and the corporate executive committee.  The number of Statoil shares owned by the
members of the board of directors and the executive committee and/or owned by
their close associates is shown below. Individually, each member of the board
of directors and the corporate executive committee owned less than 1% of the
outstanding Statoil shares.  As of 31 December
 As of 8 MarchOwnership
  of Statoil shares (including share ownership of «close associates»)
 2015
 2016Members of the corporate
  executive committeeEldar Sætre
 39,130
 40,024Hans Jakob Hegge
 22,854
 23,908Anders Opedal
 14,511
 14,511Lars Christian Bacher
 21,116
 22,308Torgrim Reitan
 28,482
 29,435John Knight
 85,731
 87,565Tim Dodson
 28,614
 29,438Margareth Øvrum
 42,621
 44,033Arne Sigve Nylund
 9,261
 9,261Jens Økland
 10,735
 11,386Irene Rummelhoff
 17,082
 17,639Members of the board of
  directorsØystein Løseth
 1,000
 1,000Roy Franklin
 0
 0Bjørn Tore Godal
 0
 0Jakob Stausholm
 50,000
 50,000Maria Johanna Oudeman
 0
 0Rebekka Glasser
  Herlofsen
 0
 0Wenche Agerup
 2,423
 2,423Lill-Heidi Bakkerud
 330
 330Ingrid Elisabeth di
  Valerio
 2,845
 3,165Stig Lægreid
 1,519
 1,807
  Individually, each member of the corporate
assembly owned less than 1% of the outstanding Statoil shares as of 31 December
2015 and as of 8 March 2016. In aggregate, members of the corporate assembly
owned a total of 19,592 shares as of 31 December 2015 and a total of 22,157 shares
as of 8 March 2016. Information about the individual share ownership of the members
of the corporate assembly is presented in the sectionCorporate governance - Corporate assembly.  The voting rights of members of the board of
directors, the corporate executive committee and the corporate assembly do not
differ from those of ordinary shareholders.  7.11 Independent auditor  This section provides details about the independent auditor, the
remuneration of the auditor and policies and procedures relating to the
auditor.  Our independent registered public accounting firm (independent
auditor) is independent in relation to Statoil and is elected by the general
meeting of shareholders. The independent auditor's fee must be approved by the
general meeting of shareholders.  Pursuant to the instructions for the board's audit committee
approved by the board of directors, the audit committee is responsible for
ensuring that the company is subject to an independent and effective external
and internal audit.  Every year, the independent auditor presents a plan to the audit
committee for the execution of the independent auditor's work.  The independent auditor attends the meeting of the board of
directors that deals with the preparation of the annual accounts. 156Statoil, Annual Report on Form 20-F 2015


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The independent auditor participates in meetings of the audit
committee.  When evaluating the independent auditor, emphasis is placed on the
firm's qualifications, capacity, local and international availability and the
size of the fee.  The audit committee evaluates and makes a recommendation to the
board of directors, the corporate assembly and the general meeting of
shareholders regarding the choice of independent auditor. The committee is
responsible for ensuring that the independent auditor meets the requirements in
Norway and in the countries where Statoil is listed. The independent auditor is
subject to the provisions of US securities legislation, which stipulates that a
responsible partner may not lead the engagement for more than five consecutive
years.  The audit committee considers all reports from the independent
auditor before they are considered by the board of directors. The audit
committee holds regular meetings with the independent auditor without the
company's management being present.  The audit committee's policies and procedures for pre-approval In its instructions for the audit committee, the board of
directors has delegated authority to the audit committee to pre-approve
assignments to be performed by the independent auditor. Within this pre-approval,
the audit committee has issued further guidelines. The audit committee has
issued guidelines for the management's pre-approval of assignments to be
performed by the independent auditor.  All audit-related and other services provided by the independent
auditor must be pre-approved by the audit committee. Provided that the types of
services proposed are permissible under SEC guidelines, pre-approval is usually
granted at a regular audit committee meeting. The chair of the audit committee
has been authorised to pre-approve services that are in accordance with
policies established by the audit committee that specify in detail the types of
services that qualify. It is a condition that any services pre-approved in this
manner are presented to the full audit committee at its next meeting. Some
pre-approvals can therefore be granted by the chair of the audit committee if
an urgent reply is deemed necessary.  Remuneration of the independent auditor in 2015 In the annual Consolidated financial statements and in the parent
company's financial statements, the independent auditor's remuneration is split
between the audit fee and the fee for audit-related and other services. The
chair presents the breakdown between the audit fee and the fee for
audit-related and other services to the annual general meeting of shareholders.  The following table sets out the aggregate fees related to
professional services rendered by Statoil's principal accountant KPMG AS, for
the fiscal year 2015, 2014 and 2013.  Auditor's
  remuneration
 For the year ended 31 December(in NOK
  million, excluding VAT)
 2015
 2014
 2013Audit fee
 49
 45
 38Audit related fee
 14
 8
 8Tax fee
 0
 0
 0Other service fee
 0
 0
 0Total
 63
 53
 46
  All fees included in the table were approved
by the board's audit committee.  Audit feeis defined as
the fee for standard audit work that must be performed every year in order to
issue an opinion on Statoil's Consolidated financial statements, on Statoil's
internal control over annual reporting and to issue reports on the statutory
financial statements. It also includes other audit services, which are services
that only the independent auditor can reasonably provide, such as the auditing
of non-recurring transactions and the application of new accounting policies,
audits of significant and newly implemented system controls and limited reviews
of quarterly financial results.  Audit-related feesinclude other
assurance and related services provided by auditors, but not limited to those
that can only reasonably be provided by the external auditor who signs the
audit report, that are reasonably related to the performance of the audit or
review of the company's financial statements, such as acquisition due
diligence, audits of pension and benefit plans, consultations concerning
financial accounting and reporting standards.  Other services
feesinclude services provided by the auditors within the framework of
the Sarbanes-Oxley Act, i.e. certain agreed procedures.  Of total
increase in audit and audit related fees, NOK 3.2 million is due to currency
effects, equivalent to 5%.  In addition to the figures in the table
above, the audit fees and audit-related fees relating to Statoillated fees relating to Statoil-160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160160operated
licences paid to KPMG for the years 2015, 2014 and 2013 amounted to NOK 7
million, NOK 6 million and NOK 6 million, respectively.  Statoil, Annual Report on Form 20-F
2015157


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7.12
Controls and procedures  This section describes controls and
procedures relating to our financial reporting.  Evaluation of disclosure
controls and procedures The management, with theparticipation
of our chief executive officer and chief financial officer, has evaluated the
effectiveness of the design and operation of our disclosure controls and
procedurespursuant to Exchange Act Rule 13a-15(b) as of the end of the
period covered by the Form 20-F. Based on that evaluation, the chief executive
officer and chief financial officer have concluded that these disclosure
controls and procedures are effective at a reasonable level of assurance.  In order to facilitate the evaluation, the
disclosure committee reviews material disclosures made by Statoil for any
errors, misstatements and omissions. The disclosure committee is chaired by the
chief financial officer. It consists of the heads of investor relations,
accounting and financial compliance, performance management and risk, tax and the
general counsel and it may be supplemented by other internal and external
personnel. The head of the internal audit is an observer at the committee's
meetings.  In designing and evaluating our disclosure
controls and procedures, our management, with the participation of the chief
executive officer and chief financial officer, recognised that any controls and
procedures, no matter how well designed and operated, can only provide
reasonable assurance that the desired control objectives will be achieved, and
that the management must necessarily exercise judgment when evaluating the
cost-benefit aspects of possible controls and procedures. Because of the
limitations inherent in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and any instances of fraud
in the company have been detected.  The management's report on
internal control over financial reporting The management of Statoil ASA is responsible for
establishing and maintaining adequate internal control over financial
reporting. Our internal control over financial reporting is a process designed,
under the supervision of the chief executive officer and chief financial
officer, to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of Statoil's financial statements for external
reporting purposes in accordance with International Financial Reporting
Standards (IFRS) as adopted by the European Union (EU). The accounting policies
applied by the group also comply with IFRS as issued by the International
Accounting Standards Board (IASB).  The management has assessed the effectiveness
of internal control over financial reporting based on the Internal Control -
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). Based on this assessment, the management has
concluded that Statoil's internal control over financial reporting as of 31
December 2015 was effective.  Statoil's internal control over financial
reporting includes policies and procedures that pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect transactions
and dispositions of assets, provide reasonable assurance that transactions are
recorded in the manner necessary to permit the preparation of financial
statements in accordance with IFRS, and that receipts and expenditures are only
carried out in accordance with the authorisation of the management and
directors of Statoil; and provide reasonable assurance regarding the prevention
or timely detection of any unauthorised acquisition, use or disposition of
Statoil's assets that could have a material effect on our financial statements.  Because of its inherent limitations, internal
control over financial reporting may not prevent or detect all misstatements.
Moreover, projections of any evaluation of the effectiveness of internal
control to future periods are subject to a risk that controls may become
inadequate because of changes in conditions and that the degree of compliance
with the policies or procedures may deteriorate.  The effectiveness of internal control over
financial reporting as of 31 December 2015 has been audited by KPMG AS, an
independent registered public accounting firm that also audits the Consolidated
financial statements included in this annual report. Their audit report on the
internal control over financial reporting is included in section 8 in the Consolidated
financial statements in this report.  No changes occurred in our internal control
over financial reporting during the period covered by Form 20-F that have
materially affected, or are reasonably likely to materially affect, our
internal control over financial reporting.  We continuously make improvement to our
internal control environment.    158Statoil, Annual Report on Form 20-F 2015


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8 Consolidated
financial statements Statoil  CONSOLIDATED STATEMENT
  OF INCOMEFull year2015
 2014
 2013(in NOK
  billion)
 NoteRevenues
 
 465.3
 606.8
 616.6Net income from equity
  accounted investments
 
 (0.3)
 (0.3)
 0.1Other income
 4
 17.8
 16.1
 17.8Total revenues and other
  income
 3
 482.8
 622.7
 634.5Purchases [net of
  inventory variation]
 
 (211.2)
 (301.3)
 (306.9)Operating expenses
 
 (84.5)
 (72.9)
 (74.1)Selling, general and
  administrative expenses
 
 (7.5)
 (7.3)
 (7.8)Depreciation, amortisation
  and net impairment losses
 11, 12
 (133.8)
 (101.4)
 (72.4)Exploration expenses
 12
 (31.0)
 (30.3)
 (18.0)Net operating income
 3
 14.9
 109.5
 155.5Net financial items
 8
 (10.6)
 (0.0)
 (17.0)Income before tax
 
 4.3
 109.4
 138.4Income tax
 9
 (41.6)
 (87.4)
 (99.2)Net income
 
 (37.3)
 22.0
 39.2Attributable to equity
  holders of the company
 
 (37.5)
 21.9
 39.9Attributable to
  non-controlling interests
 
 0.2
 0.1
 (0.6)Basic earnings per share
  (in NOK)
 10
 (11.80)
 6.89
 12.53Diluted earnings per
  share (in NOK)
 10
 (11.80)
 6.87
 12.50
   Statoil, Annual Report on Form 20-F
2015159


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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOMEFull year(in NOK
  billion)
 Note
 2015
 2014
 2013Net income
 
 (37.3)
 22.0
 39.2Actuarial gains (losses)
  on defined benefit pension plans
 19
 10.1
 (0.0)
 (5.9)Income tax effect on
  income and expense recognised in OCI
 
 (2.8)
 0.9
 1.5Items that will not be
  reclassified to the Consolidated statement of income
 
 7.3
 0.9
 (4.4)Currency translation
  adjustments1)
 
 27.4
 41.6
 22.9Items that may be
  subsequently reclassified to the Consolidated statement of income
 
 27.4
 41.6
 22.9Other comprehensive
  income
 
 34.7
 42.5
 18.5Total comprehensive
  income
 
 (2.6)
 64.5
 57.7Attributable to the
  equity holders of the company
 
 (2.8)
 64.4
 58.3Attributable to
  non-controlling interests
 
 0.2
 0.1
 (0.6)
  1)Currency
translation adjustments of NOK 27.4 billion in 2015 are net of accumulated
currency translation gains of NOK 3.3 billion reclassified to the Consolidated
statement of income related to the sale of interests in the Shah Deniz project,
the South Caucasus Pipeline and the Trans Adriatic Pipeline AG. See note 4Acquisitions
and dispositions.   160Statoil, Annual Report on Form 20-F 2015


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CONSOLIDATED BALANCE SHEETAt 31 December(in NOK
  billion)
 Note
 2015
 2014ASSETSProperty, plant and
  equipment
 11
 546.2
 562.1Intangible assets
 12
 83.3
 85.2Equity accounted
  investments
 
 7.3
 8.4Deferred tax assets
 9
 17.8
 12.9Pension assets
 19
 11.3
 8.0Derivative financial
  instruments
 25
 23.8
 29.9Financial investments
 13
 20.6
 19.6Prepayments and
  financial receivables
 13
 8.5
 5.7Total non-current assets
 
 718.7
 731.7Inventories
 14
 22.0
 23.7Trade and other
  receivables
 15
 58.8
 83.3Derivative financial
  instruments
 25
 4.8
 5.3Financial investments
 13
 86.5
 59.2Cash and cash
  equivalents
 16
 76.0
 83.1Total current assets
 
 248.0
 254.8Total assets
 
 966.7
 986.4EQUITY AND LIABILITIESShareholders’ equity
 
 354.7
 380.8Non-controlling
  interests
 
 0.3
 0.4Total equity
 17
 355.1
 381.2Finance debt
 18, 22
 264.0
 205.1Deferred tax liabilities
 9
 65.4
 71.5Pension liabilities
 19
 26.2
 27.9Provisions
 20
 109.4
 117.2Derivative financial
  instruments
 25
 11.3
 4.5Total non-current
  liabilities
 
 476.3
 426.2Trade and other payables
 21
 82.2
 100.7Current tax payable
 
 24.1
 39.6Finance debt
 18
 20.5
 26.5Dividends payable
 17
 6.2
 5.7Derivative financial
  instruments
 25
 2.3
 6.6Total current
  liabilities
 
 135.3
 179.0Total liabilities
 
 611.7
 605.2Total equity and
  liabilities
 
 966.7
 986.4
 Statoil, Annual Report on Form 20-F
2015161


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CONSOLIDATED STATEMENT OF CHANGES IN EQUITY(in NOK
  billion)
 Share capital
 Additional paid-in capital
 Retained earnings
 Currency translation adjustments
 Shareholders' equity
 Non-controlling interests
 Total equityAt 31 December 2012
 8.0
 40.6
 270.8
 (0.2)
 319.2
 0.7
 319.9Net income for the
  period
 
 
 39.9
 
 39.9
 (0.6)
 39.2Other comprehensive
  income
 
 
 (4.4)
 22.9
 18.5
 
 18.5Total comprehensive
  income
 
 
 
 
 
 
 57.7Dividends
 
 
 (21.5)
 
 (21.5)
 
 (21.5)Other equity
  transactions
 
 (0.3)
 (0.3)
 
 (0.6)
 0.4
 (0.2)At 31 December 2013
 8.0
 40.3
 284.5
 22.7
 355.5
 0.5
 356.0Net income for the
  period
 
 
 21.9
 
 21.9
 0.1
 22.0Other comprehensive
  income
 
 
 0.9
 41.6
 42.5
 
 42.5Total comprehensive
  income
 
 
 
 
 
 
 64.5Dividends
 
 
 (39.4)
 
 (39.4)
 
 (39.4)Other equity
  transactions
 
 (0.1)
 0.4
 
 0.3
 (0.2)
 0.1At 31 December 2014
 8.0
 40.2
 268.4
 64.3
 380.8
 0.4
 381.2Net income for the
  period
 
 
 (37.5)
 
 (37.5)
 0.2
 (37.3)Other comprehensive
  income1)
 
 
 7.3
 27.4
 34.7
 
 34.7Total comprehensive
  income
 
 
 
 
 
 
 (2.6)Dividends
 
 
 (23.1)
 
 (23.1)
 
 (23.1)Other equity transactions
 
 (0.1)
 (0.0)
 
 (0.1)
 (0.3)
 (0.4)At 31 December 2015
 8.0
 40.1
 215.1
 91.6
 354.7
 0.3
 355.1
  1)Currency
translation adjustments of NOK 27.4 billion in 2015 are net of accumulated
currency translation gains of NOK 3.3 billion reclassified to the Consolidated
statement of income related to the sale of interests in the Shah Deniz project,
the South Caucasus Pipeline and the Trans Adriatic Pipeline AG. See note 4 Acquisitions
and dispositions.  Refer
to note 17 Shareholders' equity.  162Statoil, Annual Report on Form 20-F 2015


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CONSOLIDATED STATEMENT OF CASH FLOWSFull year(in NOK billion)
 Note
 2015
 2014
 2013Income before tax
 
 4.3
 109.4
 138.4Depreciation,
  amortisation and net impairment losses
 11, 12
 133.8
 101.4
 72.4Exploration expenditures
  written off
 12
 17.1
 13.7
 3.1(Gains) losses on foreign
  currency transactions and balances
 
 (0.4)
 (3.1)
 4.8(Gains) losses from
  dispositions
 4
 (17.3)
 (12.4)
 (17.6)(Increase) decrease in
  other items related to operating activities
 
 19.8
 3.9
 6.6(Increase) decrease in
  net derivative financial instruments
 25
 9.2
 (2.8)
 11.7Interest received
 
 2.9
 2.1
 2.1Interest paid
 
 (3.6)
 (3.4)
 (2.5)Cash flows provided by
  operating activities before taxes paid and working capital items
 
 165.8
 208.8
 218.8Taxes paid
 
 (65.7)
 (96.6)
 (114.2)(Increase) decrease in
  working capital
 
 8.9
 14.2
 (3.3)Cash flows provided by
  operating activities
 
 109.0
 126.5
 101.3Additions through
  business combinations
 4
 (3.5)
 0.0
 0.0Capital expenditures and
  investments
 
 (124.7)
 (122.6)
 (114.9)(Increase) decrease in
  financial investments
 
 (19.8)
 (12.7)
 (23.2)(Increase) decrease in
  other non-current items
 
 (0.3)
 0.8
 0.6Proceeds from sale of
  assets and businesses
 4
 33.2
 22.6
 27.1Cash flows used in
  investing activities
 
 (115.1)
 (112.0)
 (110.4)New finance debt
 18
 32.2
 20.6
 62.8Repayment of finance
  debt
 
 (11.4)
 (9.7)
 (7.3)Dividend paid
 17
 (22.9)
 (33.7)
 (21.5)Net current finance debt
  and other
 
 (5.5)
 (0.3)
 (7.3)Cash flows provided by
  (used in) financing activities
 
 (7.5)
 (23.1)
 26.6Net increase (decrease)
  in cash and cash equivalents
 
 (13.6)
 (8.6)
 17.5Effect of exchange rate
  changes on cash and cash equivalents
 
 7.1
 5.7
 2.9Cash and cash
  equivalents at the beginning of the period (net of overdraft)
 16
 82.4
 85.3
 64.9Cash and cash
  equivalents at the end of the period (net of overdraft)
 16
 75.9
 82.4
 85.3
  Cash and cash equivalentsincluded a bank
overdraft of NOK 0.1 billion at 31 December 2015, a bank overdraft of NOK 0.7
billion at 31 December 2014 and a bank overdraft that was rounded to zero
at 31 December 2013. Interest paidin cash flows
provided by operating activities is excluding capitalised interest of NOK 3.2 billion
at 31 December 2015, NOK 1.6 billion at 
31 December 2014 and NOK 1.1 billion at 31 December 2013. Capitalised interest
is included in Capital expenditures and investments in cash flows used in
investing activities.  Statoil, Annual Report on Form 20-F
2015163


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8.1
Notes to the Consolidated financial statements  1 Organisation  Statoil ASA, originally Den Norske Stats Oljeselskap AS, was
founded in 1972 and is incorporated and domiciled in Norway. The address of its
registered office is Forusbeen 50, N-4035 Stavanger, Norway.  Statoil ASA is listed on the Oslo Børs (Norway) and the New York
Stock Exchange (USA).  The Statoil group's business consists principally of the
exploration, production, transportation, refining and marketing of petroleum
and petroleum-derived products and other forms of energy.  All the Statoil group's oil and gas activities and net assets on
the Norwegian continental shelf are owned by Statoil Petroleum AS, a 100% owned
operating subsidiary. Statoil Petroleum AS is co-obligor or guarantor of
certain debt obligations of Statoil ASA.  The Consolidated financial statements of Statoil for the full year
2015 were authorised for issue in accordance with a resolution of the board ofdirectors on 9 March2016.  2 Significant accounting policies  Statement
of compliance The
Consolidated financial statements of Statoil ASA and its subsidiaries (Statoil)
have been prepared in accordance with International Financial Reporting
Standards (IFRSs) as adopted by the European Union (EU) and also comply with
IFRSs as issued by the International Accounting Standards Board (IASB),
effective at 31 December 2015.  Basis
of preparation The financial
statements are prepared on the historical cost basis with some exceptions, as
detailed in the accounting policies set out below. These policies have been
applied consistently to all periods presented in these Consolidated financial
statements. Certain amounts in the comparable years have been restated to
conform to current year presentation. The subtotals and totals in some of the
tables may not equal the sum of the amounts shown due to rounding.  Operating
related expenses in the Consolidated statement of income are presented as a
combination of function and nature in conformity with industry practice. Purchases
[net of inventory variation] and Depreciation, amortisation and net
impairment losses are presented in separate lines by their
nature, while Operating
expensesandSelling,
general and administrative expenses
as well as Exploration
expenses are presented on a functional basis. Significant
expenses such as salaries, pensions, etc. are presented by their nature in the
notes to the Consolidated financial statements.  Standards
and amendments to standards, issued but not yet adopted At the date of
these Consolidated financial statements, the following standards and amendments
to standards applicable to Statoil have been issued, but were not yet
effective: ·IFRS 15 Revenue
from Contracts with Customers, issued in May 2014 and, following
an amendment to the standard issued in September 2015, effective from 1 January
2018, covers the recognition of such revenue in the financial statements and
related disclosure and will replace IAS 18Revenue. The standard requires identification
of the performance obligations for the transfer of goods and services in each
contract with customers. Revenue will be recognised upon satisfaction of the
performance obligations in the amounts that reflect the consideration to which
the company expects to be entitled in exchange for those goods and services.
The standard requires adoption either on a retrospective basis or on the basis
of the cumulative effect on retained earnings. Statoil is still in the process
of evaluating the potential impact of IFRS 15, and has not yet determined its
adoption date or its implementation method for the standard ·The amendment to
IFRS 11 Accounting
for Acquisitions of Interests in Joint Operations, issued in May
2014 and effective from 1 January 2016, establishes requirements for the
accounting for acquisitions of interests in joint operations in which the
activity constitutes a business. The amendment is to be applied prospectively.
Statoil has adopted the amendment on the effective date ·IFRS 9 Financial
Instruments, issued in its final form in July 2014 and effective
from 1 January 2018, will replace IAS 39 Financial Instruments: Recognition
and Measurement. IFRS 9 introduces a new model for classification
and measurement of financial assets and financial liabilities, a reformed
approach to hedge accounting, and a more forward-looking impairment model. The
standard’s transition provisions partly require retrospective adoption, and
partly prospective adoption. Statoil is in the process of evaluating the
potential impact of IFRS 9, and has not yet determined its adoption date for
the standard  164Statoil, Annual Report on Form 20-F 2015


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·The amendments to
IFRS 10 Consolidated
Financial Statements and IAS 28 Investments in Associates and Joint
Ventures, issued in September 2014 and, following an amendment
issued in December 2015, effective from a future date to be determined by the
IASB, establish requirements for the accounting for sales or contributions of
assets between an investor and its associate or joint venture. Whether or not
the assets are housed in a subsidiary, a full gain or loss will be recognised
in the statement of income when the transaction involves assets that constitute
a business, whereas a partial gain or loss will be recognised when the
transaction involves assets that do not constitute a business. The amendments
are to be applied prospectively. Statoil has not determined an adoption date
for the amendments ·IFRS 16Leases, issued in January 2016 and effective
from 1 January 2019, covers the recognition of leases and related disclosure in
the financial statements, and will replace IAS 17Leases. In the financial statement of
lessees, the new standard requires recognition of all contracts that qualify
under its definition of a lease as right-of-use assets and lease liabilities in
the balance sheet, while lease payments are to be reflected as interest expense
and reduction of lease liabilities. The right-of-use assets are to be
depreciated in accordance with IAS 16Property, Plant and Equipmentover
the shorter of each contract’s term and the assets’ useful life. The standard
consequently implies a significant change in lessees’ accounting for leases
currently defined as operating leases under IAS 17, both as regards impact on
the balance sheet and the statement of income. IFRS 16 defines a lease as a
contract that conveys the right to control the use of an identified asset for a
period of time in exchange for consideration. While this definition is not
dissimilar to that of IAS 17, it would have required further evaluation of each
contract to determine whether all leases included in Note 22Leasesof
these financial statements, or contracts currently not defined as leases, would
qualify as leases under the new standard. The standard introduces new
requirements both as regards establishing the term of a lease and the related
discounted cash flows that determine the amount of a lease liability to be
recognised. The standard requires adoption either on a full retrospective
basis, or retrospectively with the cumulative effect of initially recognising
the standard as an adjustment to retained earnings at the date of initial
application, and if so with a number of practical expedients in transitioning
existing leases at the time of initial application. Statoil is in the early
phase of evaluating the impact of IFRS 16, and has not yet determined its adoption
date, its implementation method, or the expected impact of the standard on the
Consolidated financial statements  ·The disclosure
initiative amendments to IAS 7 Statement of Cash Flows, issued in January 2016
and effective from 1 January 2017, establishes certain additional requirements
as to disclosure of changes in financing liabilities. Statoil will implement
the amendments on the effective date  Other
standards and amendments to standards, issued but not yet effective, are either
not expected to impact Statoil’s Consolidated financial statements materially,
or are not expected to be relevant to Statoil's Consolidated financial
statements upon adoption.  Basis
of consolidation The
Consolidated financial statements include the accounts of Statoil ASA and its
subsidiaries and include Statoil’s interest in
jointly controlled and equity accounted investments.  Subsidiaries Entities are
determined to be controlled by Statoil, and consolidated in Statoil's financial
statements, when Statoil has power over the entity, ability to use that power
to affect the entity's returns, and exposure to, or rights to, variable returns
from its involvement with the entity.  All
intercompany balances and transactions, including unrealised profits and losses
arising from Statoil's internal transactions, have been eliminated in full.
Non-controlling interests are presented separately within equity in the balance
sheet.  Joint
operations and similar arrangements, joint ventures and associates A joint
arrangement is present where Statoil holds a long-term interest which is
jointly controlled by Statoil and one or more other venturers under a contractual
arrangement in which decisions about the relevant activities require the
unanimous consent of the parties sharing control. Such joint arrangements are
classified as either joint operations or joint ventures.  The parties to
a joint operation have rights to the assets and obligations for the
liabilities, relating to their respective share of the joint arrangement. In
determining whether the terms of contractual arrangements and other facts and
circumstances lead to a classification as joint operations, Statoil in
particular considers the nature of products and markets of the arrangement and
whether the substance of their agreements is that the parties involved have
rights to substantially all the arrangement's assets. Statoil accounts for the
assets, liabilities, revenues and expenses relating to its interests in joint
operations in accordance with the principles applicable to those particular
assets, liabilities, revenues and expenses. Normally this leads to accounting
for the joint operation in a manner similar to the previous proportionate
consolidation method.  Those of
Statoil's exploration and production licence activities that are within the
scope of IFRS 11Joint Arrangementshave been classified as joint
operations. A considerable number of Statoil's unincorporated joint exploration
and production activities are conducted through arrangements that are not
jointly controlled, either because unanimous consent is not required among all
parties involved, or no single group of parties has joint control over the
activity. Licence activities where control can be achieved through agreement
between more than one combination of involved parties are considered to be
outside the scope of IFRS 11, and these activities are accounted for on a
pro-rata basis using Statoil's ownership share. In determining whether each
separate arrangement related to Statoil's unincorporated joint exploration and
production licence activities is within or outside the scope of IFRS 11,
Statoil considers the terms of relevant licence agreements, governmental
concessions and other legal arrangements impacting how and by whom each
arrangement is controlled. Subsequent changes in the ownership shares and
number of licence participants, transactions involving licence shares, or
changes in the terms of relevant agreements may lead to changes in Statoil's
evaluation of control and impact a licence arrangement's classification in
relation to IFRS 11 in Statoil, Annual Report on Form 20-F
2015165


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Statoil's Consolidated
financial statements. Currently there are no significant differences in
Statoil's accounting for unincorporated licence arrangements whether in scope
of IFRS 11 or not.  Joint
ventures, in which Statoil has rights to the net assets, are accounted for
using the equity method.  Investments in
companies in which Statoil has neither control nor joint control, but has the
ability to exercise significant influence over operating and financial
policies, are classified as associates and are accounted for using the equity
method.  Statoil
as operator of joint operations and similar arrangements Indirect
operating expenses such as personnel expenses are accumulated in cost pools.
These costs are allocated on an hours incurred basis to operating segments and
Statoil operated joint operations under IFRS 11 and to similar arrangements
(licences) outside the scope of IFRS 11. Costs allocated to the other partners'
share of operated joint operations and similar arrangements reduce the costs in
the Consolidated statement of income. Only Statoil's share of the statement of
income and balance sheet items related to Statoil operated joint operations and
similar arrangements are reflected in the Consolidated statement of income and
the Consolidated balance sheet.  Reportable
segments Statoil
identifies its operating segments on the basis of those components of Statoil
that are regularly reviewed by the chief operating decision maker, Statoil's
corporate executive committee (CEC). Statoil combines operating segments when
these satisfy relevant aggregation criteria.  Statoil's
accounting policies as described in this note also apply to the specific
financial information included in reportable segments related disclosure in
these Consolidated financial statements.  Foreign
currency translation In preparing
the financial statements of the individual entities, transactions in foreign
currencies (those other than functional currency) are translated at the foreign
exchange rate at the dates of the transactions. Monetary assets and liabilities
denominated in foreign currencies are translated to the functional currency at
the foreign exchange rate at the balance sheet date. Foreign exchange
differences arising on translation are recognised in the Consolidated statement
of income as foreign exchange gains or losses within Net
financial items. Foreign exchange differences arising from the
translation of estimate-based provisions, however, generally are accounted for
as part of the change in the underlying estimate and as such may be included
within the relevant operating expense or income tax sections of the Consolidated
statement of income depending on the nature of the provision. Non-monetary
assets that are measured at historical cost in a foreign currency are
translated using the exchange rate at the date of the transactions.  Presentation
currency For the
purpose of the Consolidated financial statements, the statement of income, the
balance sheet and the cash flows of each entity are translated from the
functional currency into the presentation currency, Norwegian kroner (NOK). The
assets and liabilities of entities whose functional currencies are other than
NOK, including Statoil's parent company Statoil ASA whose functional currency
is United States dollar (USD), are translated into NOK at the foreign exchange
rate at the balance sheet date. The revenues and expenses of such entities are
translated using the foreign exchange rates on the dates of the transactions.
Foreign exchange differences arising on translation from functional currency to
presentation currency are recognised separately in Other comprehensive income
(OCI). The cumulative amount of such translation differences relating to an
entity and previously recognised in OCI, is reclassified to the Consolidated
statement of income and reflected as a part of the gain or loss on disposal of
that entity.  Business
combinations Determining
whether an acquisition meets the definition of a business combination requires
judgement to be applied on a case by case basis. Acquisitions are assessed
under the relevant IFRS criteria to establish whether the transaction
represents a business combination or an asset purchase. Depending on the
specific facts, acquisitions of exploration and evaluation licences for which a
development decision has not yet been made, have largely been concluded to
represent asset purchases.  Business
combinations, except for transactions between entities under common control,
are accounted for using the acquisition method of accounting. The acquired
identifiable tangible and intangible assets, liabilities and contingent
liabilities are measured at their fair values at the date of the acquisition.
Acquisition costs incurred are expensed under Selling, general and administrative
expenses.  Revenue
recognition Revenues
associated with sale and transportation of crude oil, natural gas, petroleum
products and other merchandise are recognised when risk passes to the customer,
which is normally when title passes at the point of delivery of the goods,
based on the contractual terms of the agreements.  Revenues from
the production of oil and gas properties in which Statoil shares an interest
with other companies are recognised on the basis of volumes lifted and sold to
customers during the period (the sales method). Where Statoil has lifted and
sold more than the ownership interest, an accrual is recognised for the cost of
the overlift. Where Statoil has lifted and sold less than the ownership
interest, costs are deferred for the underlift.  Revenue is
presented net of customs, excise taxes and royalties paid in-kind on petroleum
products. Revenue is presented gross of in-kind payments of amounts
representing income tax.  166Statoil, Annual Report on Form 20-F 2015


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Sales
and purchases of physical commodities, which are not settled net, are presented
on a gross basis as Revenues and Purchases
[net of inventory variation] in the statement of income.
Activities related to trading and commodity-based derivative instruments are
reported on a net basis, with the margin included in Revenues.  Transactions
with the Norwegian State Statoil markets and sells the Norwegian
State's share of oil and gas production from the Norwegian continental shelf
(NCS). The Norwegian State's participation in petroleum activities is organised
through the State's direct financial interest (SDFI). All purchases and sales
of the SDFI's oil production are classified as Purchases [net of inventory variation]
and Revenues,
respectively. Statoil sells, in its own name, but for the Norwegian State's
account and risk, the State's production of natural gas. These sales and
related expenditures refunded by the Norwegian State are presented net in the
Consolidated financial statements. Employee
benefits Wages,
salaries, bonuses, social security contributions, paid annual leave and sick
leave are accrued in the period in which the associated services are rendered
by employees of Statoil.  Research
and development Statoil
undertakes research and development both on a funded basis for licence holders
and on an unfunded basis for projects at its own risk. Statoil's own share of
the licence holders' funding and the total costs of the unfunded projects are
considered for capitalisation under the applicable IFRS requirements.
Subsequent to initial recognition, any capitalised development costs are
reported at cost less accumulated amortisation and accumulated impairment
losses.  Income
tax Income tax in
the Consolidated statement of income comprises current and deferred tax
expense.Income taxis recognised in the Consolidated
statement of income except when it relates to items recognised in OCI.  Current tax
consists of the expected tax payable on the taxable income for the year and any
adjustment to tax payable for previous years. Uncertain tax positions and
potential tax exposures are analysed individually, and the best estimate of the
probable amount for liabilities to be paid (unpaid potential tax exposure
amounts, including penalties) and for assets to be received (disputed tax
positions for which payment has already been made) in each case is recognised
within current tax or deferred tax as appropriate. Interest income and interest
expenses relating to tax issues are estimated and recognised in the period in
which they are earned or incurred, and are presented within Net
financial items in the Consolidated statement of income. Uplift
benefit on the NCS is recognised when the deduction is included in the current
year tax return and impacts taxes payable.  Deferred tax
assets and liabilities are recognised for the future tax consequences
attributable to differences between the carrying amounts of existing assets and
liabilities and their respective tax bases, subject to the initial recognition
exemption. The amount of deferred tax is based on the expected manner of
realisation or settlement of the carrying amount of assets and liabilities,
using tax rates enacted or substantively enacted at the balance sheet date. A
deferred tax asset is recognised only to the extent that it is probable that
future taxable income will be available against which the asset can be
utilised. In order for a deferred tax asset to be recognised based on future
taxable income, convincing evidence is required, taking into account the
existence of contracts, production of oil or gas in the near future based on
volumes of proved reserves, observable prices in active markets, expected
volatility of trading profits, expected currency rate movements and similar
facts and circumstances.  Oil
and gas exploration, evaluation and development expenditures Statoil uses
the successful efforts method of accounting for oil and gas exploration costs.
Expenditures to acquire mineral interests in oil and gas properties and to
drill and equip exploratory wells are capitalised as exploration and evaluation
expenditures within Intangible assets until the well is
complete and the results have been evaluated, or there is any other indicator
of a potential impairment. Exploration wells that discover potentially economic
quantities of oil and natural gas remain capitalised as intangible assets
during the evaluation phase of the find. This evaluation is normally finalised
within one year after well completion. If, following the evaluation, the
exploratory well has not found potentially commercial quantities of
hydrocarbons, the previously capitalised costs are evaluated for derecognition
or tested for impairment. Geological and geophysical costs and other
exploration and evaluation expenditures are expensed as incurred.  Capitalised
exploration and evaluation expenditures, including expenditures to acquire
mineral interests in oil and gas properties, related to offshore wells that
find proved reserves are transferred from exploration expenditures and
acquisition costs - oil and gas prospects (Intangible assets) to Property,
plant and equipmentat the time of sanctioning of the
development project. For onshore wells where no sanction is required, the
transfer of acquisition cost – oil and gas prospects (Intangible
assets) to Property, plant and equipment occurs at the
time when a well is ready for production.  For
exploration and evaluation asset acquisitions (farm-in arrangements) in which
Statoil has made arrangements to fund a portion of the selling partner's
(farmor's) exploration and/or future development expenditures (carried
interests), these expenditures are reflected in the Consolidated financial
statements as and when the exploration and development work progresses. Statoil
reflects exploration and evaluation asset dispositions (farm-out arrangements)
on a historical cost basis with no gain or loss recognition.  A gain or loss
related to a post-tax based disposition of assets on the NCS includes the
release of tax liabilities previously computed and recognised related to the
assets in question. The resulting gross gain or loss is recognised in full in Other
income in the Consolidated statement of income.  Statoil, Annual Report on Form 20-F
2015167


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Consideration
from the sale of an undeveloped part of an onshore asset reduces the carrying
amount of the asset. The part of the consideration that exceeds the carrying
amount of the asset, if any, is reflected in the Consolidated statement of
income underOther income.  Exchanges
(swaps) of exploration and evaluation assets are accounted for at the carrying
amounts of the assets given up with no gain or loss recognition.  Property,
plant and equipment Property,
plant and equipmentis
reflected at cost, less accumulated depreciation and accumulated impairment
losses. The initial cost of an asset comprises its purchase price or
construction cost, any costs directly attributable to bringing the asset into
operation, the initial estimate of an asset retirement obligation, if any,
exploration costs transferred from intangible assets and, for qualifying
assets, borrowing costs.Property,
plant and equipmentinclude costs relating to expenditures incurred under the terms of profit
sharing agreements (PSAs) in certain countries, and which qualify for recognition
as assets of Statoil. State-owned entities in the respective countries,
however, normally hold the legal title to such PSA-based property, plant and
equipment.  Exchanges of
assets are measured at the fair value of the asset given up, unless the fair
value of neither the asset received nor the asset given up is measurable with
sufficient reliability.  Expenditure on
major maintenance refits or repairs comprises the cost of replacement assets or
parts of assets, inspection costs and overhaul costs. Where an asset or part of
an asset is replaced and it is probable that future economic benefits
associated with the item will flow to Statoil, the expenditure is capitalised.
Inspection and overhaul costs, associated with regularly scheduled major maintenance
programs planned and carried out at recurring intervals exceeding one year, are
capitalised and amortised over the period to the next scheduled inspection and
overhaul. All other maintenance costs are expensed as incurred.  Capitalised
exploration and evaluation expenditures, development expenditure on the
construction, installation or completion of infrastructure facilities such as
platforms, pipelines and the drilling of production wells, and field-dedicated
transport systems for oil and gas are capitalised as producing oil and gas
properties within Property,
plant and equipment. Such capitalised costs, when designed for
significantly larger volumes than the reserves from already developed and
producing wells, are depreciated using the unit of production method based on
proved reserves expected to be recovered from the area during the concession or
contract period. Depreciation of production wells uses the unit of production
method based on proved developed reserves, and capitalised acquisition costs of
proved properties are depreciated using the unit of production method based on
total proved reserves. In the rare circumstances where the use of proved
reserves fails to provide an appropriate measure of depreciation, a more
appropriate reserve estimate is used. Depreciation of other assets and
transport systems used by several fields is calculated on the basis of their
estimated useful lives, normally using the straight-line method. Each part of
an item ofproperty,
plant and equipmentwith
a cost that is significant in relation to the total cost of the item is
depreciated separately. For exploration and production assets, Statoil has
established separate depreciation categories which as a minimum distinguish
between platforms, pipelines and wells.  The estimated
useful lives of property, plant and equipment are reviewed on an annual basis,
and changes in useful lives are accounted for prospectively. An item of property, plant and
equipmentis derecognised
upon disposal or when no future economic benefits are expected to arise from
the continued use of the asset. Any gain or loss arising on derecognition of
the asset (calculated as the difference between the net disposal proceeds and
the carrying amount of the item) is included in Other income or Operating
expenses, respectively, in the period the item is derecognised.  Leases Leases for
which Statoil assumes substantially all the risks and rewards of ownership are
reflected as finance leases. When an asset leased by a joint operation or
similar arrangement to which Statoil is a party qualifies as a finance lease,
Statoil reflects its proportionate share of the leased asset and related
obligations. Finance leases are classified in the Consolidated balance sheet
within Property,
plant and equipment and Finance debt. All other
leases are classified as operating leases, and the costs are charged to the
relevant operating expense related caption on a straight line basis over the
lease term, unless another basis is more representative of the benefits of the
lease to Statoil.  Statoil
distinguishes between lease and capacity contracts. Lease contracts provide the
right to use a specific asset for a period of time, while capacity contracts
confer on Statoil the right to and the obligation to pay for certain volume
capacity availability related to transport, terminal use, storage, etc. Such
capacity contracts that do not involve specified assets or that do not involve
substantially all the capacity of an undivided interest in a specific asset are
not considered by Statoil to qualify as leases for accounting purposes.
Capacity payments are reflected as Operating expenses in
the Consolidated statement of income in the period for which the capacity
contractually is available to Statoil.  Intangible
assets including goodwill Intangible
assets are stated at cost, less accumulated amortisation and accumulated
impairment losses. Intangible assets include acquisition cost for oil and gas
prospects, expenditures on the exploration for and evaluation of oil and
natural gas resources, goodwill and other intangible assets.  Intangible
assets relating to expenditures on the exploration for and evaluation of oil
and natural gas resources are not amortised. When the decision to develop a
particular area is made, its intangible exploration and evaluation assets are
reclassified to Property,
plant and equipment.  168Statoil, Annual Report on Form 20-F 2015


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Goodwill
is initially measured at the excess of the aggregate of the consideration
transferred and the amount recognised for any non-controlling interest over the
fair value of the identifiable assets acquired and liabilities assumed in a
business combination at the acquisition date. Goodwill acquired is allocated to
each cash generating unit, or group of units, expected to benefit from the
combination's synergies. Following initial recognition, goodwill is measured at
cost less any accumulated impairment losses.  Financial
assets Financial
assets are initially recognised at fair value when Statoil becomes a party to
the contractual provisions of the asset. For additional information on fair
value methods, refer to the Measurement of fair values section below. The
subsequent measurement of the financial assets depends on which category they
have been classified into at inception.  At initial
recognition, Statoil classifies its financial assets into the following three
main categories: Financial investments at fair value through profit or loss,
loans and receivables, and available-for-sale (AFS) financial assets. The first
main category, financial investments at fair value through profit or loss,
further consists of two sub-categories: Financial assets held for trading and
financial assets that on initial recognition are designated as fair value
through profit and loss. The latter approach may also be referred to as the
fair value option.  Cash
and cash equivalentsinclude cash in hand, current balances with banks and similar institutions, and
short-term highly liquid investments that are readily convertible to known
amounts of cash, are subject to an insignificant risk of changes in fair value
and have a maturity of three months or less from the acquisition date.  Trade
receivables are carried at the original invoice amount less a provision for
doubtful receivables which is made when there is objective evidence that
Statoil will be unable to recover the balances in full.  A significant
part of Statoil's investments in treasury bills, commercial papers, bonds and
listed equity securities is managed together as an investment portfolio of
Statoil's captive insurance company and is held in order to comply with
specific regulations for capital retention. The investment portfolio is managed
and evaluated on a fair value basis in accordance with an investment strategy
and is accounted for using the fair value option with changes in fair value
recognised through profit or loss.  Financial
assets are presented as current if they contractually will expire or otherwise
are expected to be recovered within 12 months after the balance sheet date, or
if they are held for the purpose of being traded. Financial assets and
financial liabilities are shown separately in the Consolidated balance sheet,
unless Statoil has both a legal right and a demonstrable intention to net
settle certain balances payable to and receivable from the same counterparty,
in which case they are shown net in the balance sheet.  Inventories Inventories
are stated at the lower of cost and net realisable value. Cost is determined by
the first-in first-out method and comprises direct purchase costs,cost of production, transportation
and manufacturing expenses.  Impairment Impairment
of property, plant and equipment and intangible assets other than goodwill Statoil
assesses individual assets or groups of assets for impairment whenever events
or changes in circumstances indicate that the carrying value of an asset may
not be recoverable. Assets are grouped into cash generating units (CGUs) which
are the smallest identifiable groups of assets that generate cash inflows that
are largely independent of the cash inflows from other groups of assets.
Normally, separate CGUs are individual oil and gas fields or plants. Each
unconventional asset play is considered a single CGU when no cash inflows from
parts of the play can be reliably identified as being largely independent of
the cash inflows from other parts of the play. In impairment evaluations, the
carrying amounts of CGUs are determined on a basis consistent with that of the
recoverable amount. In Statoil's line of business, judgement is involved in
determining what constitutes a CGU. Development in production, infrastructure
solutions, markets, product pricing, management actions and other factors may
over time lead to changes in CGUs such as the division of one original CGU into
several.  In assessing
whether a write-down of the carrying amount of a potentially impaired asset is
required, the asset's carrying amount is compared to the recoverable amount.
The recoverable amount of an asset is the higher of its fair value less cost of
disposal and its value in use. Fair value less cost of disposal is determined
based on comparable recent arm’s length market transactions, or based on
Statoil’s estimate of the price that would be received for the asset in an
orderly transaction between market participants. Value in use is determined using
a discounted cash flow model. The estimated future cash flows applied are based
on reasonable and supportable assumptions and represent management's best
estimates of the range of economic conditions that will exist over the
remaining useful life of the assets, as set down in Statoil's most recently
approved long-term forecasts. Statoil uses an approach of regular updates of
assumptions and economic conditions in establishing the long-term forecasts
which are reviewed by corporate management and updated at least annually. For
assets and CGUs with an expected useful life or timeline for production of
expected reserves extending beyond 5 years, the forecasts reflect expected
production volumes for oil and natural gas, and the related cash flows include
project or asset specific estimates reflecting the relevant period. Such
estimates are established on the basis of Statoil's principles and assumptions
consistently applied.  In performing
a value-in-use-based impairment test, the estimated future cash flows are
adjusted for risks specific to the asset and discounted using a real post-tax
discount rate which is based on Statoil's post-tax weighted average cost of
capital (WACC). The use of post-tax discount rates in determining value in use
does not result in a materially different determination of the need for, or the
amount of, impairment that would be required if pre-tax discount rates had been
used.  Unproved oil
and gas properties are assessed for impairment when facts and circumstances
suggest that the carrying amount of the asset may exceed its recoverable
amount, and at least once a year. Exploratory wells that have found reserves,
but where classification of those Statoil, Annual Report on Form 20-F
2015169


---

reserves as proved
depends on whether major capital expenditure can be justified or where the
economic viability of that major capital expenditure depends on the successful
completion of further exploration work, will remain capitalised during the
evaluation phase for the exploratory finds. Thereafter it will be considered a
trigger for impairment evaluation of the well if no development decision is
planned for the near future and there are no concrete plans for future drilling
in the licence.  An assessment
is made at each reporting date as to whether there is any indication that
previously recognised impairment losses may no longer be relevant or may have
decreased. If such an indication exists, the recoverable amount is estimated. A
previously recognised impairment loss is reversed only if there has been a
change in the estimates used to determine the asset’s recoverable amount since
the last impairment loss was recognised. If that is the case, the carrying
amount of the asset is increased to its recoverable amount. That increased
amount cannot exceed the carrying amount that would have been determined, net
of depreciation, had no impairment loss been recognised for the asset in prior
years.  Impairment
losses and reversals of impairment losses are presented in the Consolidated
statement of income as Exploration expenses or Depreciation,
amortisation and net impairment losses, on the basis of their
nature as either exploration assets (intangible exploration assets) or
development and producing assets (property, plant and equipment and other
intangible assets), respectively.  Impairment
of goodwill Goodwill is reviewed for impairment
annually or more frequently if events or changes in circumstances indicate that
the carrying value may be impaired. Impairment is determined by assessing the
recoverable amount of the CGU, or group of units, to which the goodwill
relates. Where the recoverable amount of the CGU, or group of units, is less
than the carrying amount, an impairment loss is recognised. Once recognised,
impairments of goodwill are not reversed in future periods. Financial
liabilities Financial liabilities are initially recognised
at fair value when Statoil becomes a party to the contractual provisions of the
liability. The subsequent measurement of financial liabilities depends on which
category they have been classified into. The categories applicable for Statoil
are either financial liabilities at fair value through profit or loss or
financial liabilities measured at amortised cost using the effective interest
method. The latter applies to Statoil's non-current bank loans and bonds.  Financial
liabilities are presented as current if the liability is due to be settled
within 12 months after the balance sheet date, or if they are held for the
purpose of being traded. Financial liabilities are derecognised when the
contractual obligations expire, are discharged or cancelled. Gains and losses
arising on the repurchase, settlement or cancellation of liabilities are
recognised either in interest income and other financial items or in interest
and other finance expenses within Net financial items.  Derivative
financial instruments Statoil uses
derivative financial instruments to manage certain exposures to fluctuations in
foreign currency exchange rates, interest rates and commodity prices. Such
derivative financial instruments are initially recognised at fair value on the
date on which a derivative contract is entered into and are subsequently
re-measured at fair value through profit and loss. The impact of
commodity-based derivative financial instruments is recognised in the
Consolidated statement of income underRevenues, as such derivative
instruments are related to sales contracts or revenue-related risk management
for all significant purposes. The impact of other financial instruments is
reflected underNet financial items.  Derivatives
are carried as assets when the fair value is positive and as liabilities when
the fair value is negative. Derivative assets or liabilities expected to be
recovered, or with the legal right to be settled more than 12 months after the
balance sheet date are classified as non-current, with the exception of
derivative financial instruments held for the purpose of being traded.  Contracts to
buy or sell a non-financial item that can be settled net in cash or another
financial instrument, or by exchanging financial instruments, as if the
contracts were financial instruments, are accounted for as financial
instruments. However, contracts that are entered into and continue to be held
for the purpose of the receipt or delivery of a non-financial item in
accordance with Statoil's expected purchase, sale or usage requirements, also
referred to as own-use, are not accounted for as financial instruments. This is
applicable to a significant number of contracts for the purchase or sale of
crude oil and natural gas, which are recognised upon delivery.  Derivatives
embedded in other financial instruments or in non-financial host contracts are
recognised as separate derivatives and are reflected at fair value with
subsequent changes through profit and loss, when their risks and economic characteristics
are not closely related to those of the host contracts, and the host contracts
are not carried at fair value. Where there is an active market for a commodity
or other non-financial item referenced in a purchase or sale contract, a
pricing formula will, for instance, be considered to be closely related to the
host purchase or sales contract if the price formula is based on the active
market in question. A price formula with indexation to other markets or
products will however result in the recognition of a separate derivative. Where
there is no active market for the commodity or other non-financial item in
question, Statoil assesses the characteristics of such a price related embedded
derivative to be closely related to the host contract if the price formula is
based on relevant indexations commonly used by other market participants. This
applies to a number of Statoil's long-term natural gas sales agreements.  Pension
liabilities Statoil has
pension plans for employees that either provide a defined pension benefit upon
retirement or a pension dependent on defined contributions and related returns.
A portion of the contributions are provided for as notional contributions, for
which the liability increases with a promised notional return, set equal to the
actual return of assets invested through the ordinary defined contribution
plan. For defined benefit 170Statoil, Annual Report on Form 20-F 2015


---

plans, the benefit to be
received by employees generally depends on many factors including length of
service, retirement date and future salary levels.  Statoil's
proportionate share of multi-employer defined benefit plans are recognised as
liabilities in the balance sheet to the extent that sufficient information is
available and a reliable estimate of the obligation can be made.  Statoil's net
obligation in respect of defined benefit pension plans is calculated separately
for each plan by estimating the amount of future benefit that employees have
earned in return for their services in the current and prior periods. That
benefit is discounted to determine its present value, and the fair value of any
plan assets is deducted. The discount rate is the yield at the balance sheet
date, reflecting the maturity dates approximating the terms of Statoil's
obligations. The discount rate for the main part of the pension obligations has
been established on the basis of Norwegian mortgage covered bonds, which are
considered high quality corporate bonds. The cost of pension benefit plans is
expensed over the period that the employees render services and become eligible
to receive benefits. The calculation is performed by an external actuary.  The net
interest related to defined benefit plans is calculated by applying the
discount rate to the opening present value of the benefit obligation and
opening present value of the plan assets, adjusted for material changes during
the year. The resulting net interest element is presented in the statement of
income as part of net pension cost within Net operating income.
The difference between estimated interest income and actual return is
recognised in the Consolidated statement of comprehensive income.  Past service
cost is recognised when a plan amendment (the introduction or withdrawal of, or
changes to, a defined benefit plan) or curtailment (a significant reduction by
the entity in the number of employees covered by a plan) occurs, or when
recognising related restructuring costs or termination benefits. The obligation
and related plan assets are re-measured using current actuarial assumptions,
and the gain or loss is recognised in the statement of income.  Actuarial
gains and losses are recognised in full in the Consolidated statement of
comprehensive income in the period in which they occur, while actuarial gains
and losses related to provision for termination benefits are recognised in the
Consolidated statement of income in the period in which they occur. Due to the
parent company Statoil ASA's functional currency being USD, the significant
part of Statoil's pension obligations will be payable in a foreign currency
(i.e. NOK). As a consequence, actuarial gains and losses related to the parent
company's pension obligation include the impact of exchange rate fluctuations.  Contributions
to defined contribution schemes are recognised in the statement of income in
the period in which the contribution amounts are earned by the employees.  Notional
contribution plans, reported in the parent company Statoil ASA, are recognised
as pension liabilities with the actual value of the notional contributions and
promised return at reporting date. Notional contributions and changes in fair
value of notional assets are recognised in the statement of income as periodic
pension cost.  Periodic
pension cost is accumulated in cost pools and allocated to operating segments
and Statoil operated joint operations (licences) on an hours incurred basis and
recognised in the statement of income based on the function of the cost.  Onerous
contracts Statoil
recognises as provisions the net obligation under contracts defined as onerous.
Contracts are deemed to be onerous if the unavoidable cost of meeting the
obligations under the contract exceeds the economic benefits expected to be
received in relation to the contract. A contract which forms an integral part
of the operations of a CGU whose assets are dedicated to that contract, and for
which the economic benefits cannot be reliably separated from those of the CGU,
is included in impairment considerations for the applicable CGU.  Asset
retirement obligations (ARO) Provisions for
ARO costs are recognised when Statoil has an obligation (legal or constructive)
to dismantle and remove a facility or an item of property, plant and equipment
and to restore the site on which it is located, and when a reliable estimate of
that liability can be made. The amount recognised is the present value of the
estimated future expenditures determined in accordance with local conditions
and requirements. Cost is estimated based on current regulations and
technology, considering relevant risks and uncertainties. The discount rate
used in the calculation of the ARO is a risk-free rate based on the applicable
currency and time horizon of the underlying cash flows, adjusted for a credit
premium which reflects Statoil's own credit risk. Normally an obligation arises
for a new facility, such as an oil and natural gas production or transportation
facility, upon construction or installation. An obligation may also crystallise
during the period of operation of a facility through a change in legislation or
through a decision to terminate operations, or be based on commitments
associated with Statoil's ongoing use of pipeline transport systems where
removal obligations rest with the volume shippers. The provisions are
classified under Provisions
in the Consolidated balance sheet. Some of the refining and process operations
are deemed to have indefinite lives, and in consequence, no ARO has been
recognised for their plants.  When a provision
for ARO cost is recognised, a corresponding amount is recognised to increase
the related property, plant and equipment and is subsequently depreciated as
part of the costs of the facility or item of property, plant and equipment. Any
change in the present value of the estimated expenditure is reflected as an
adjustment to the provision and the corresponding property, plant and
equipment. When a decrease in the ARO provision related to a producing asset
exceeds the carrying amount of the asset, the excess is recognised as a
reduction ofDepreciation, amortisation and net impairment lossesin the
Consolidated statement of income. When an asset has reached the end of its
useful life, all subsequent changes to the ARO provision are recognised as they
occur inOperating expensesin the Consolidated statement of Statoil, Annual Report on Form 20-F
2015171


---

income. Removal provisions associated with Statoil's
role as shipper of volumes through third party transport systems are expensed
as incurred.  Measurement
of fair values Quoted prices
in active markets represent the best evidence of fair value and are used by
Statoil in determining the fair values of assets and liabilities to the extent
possible. Financial instruments quoted in active markets will typically include
commercial papers, bonds and equity instruments with quoted market prices
obtained from the relevant exchanges or clearing houses. The fair values of
quoted financial assets, financial liabilities and derivative instruments are
determined by reference to mid-market prices, at the close of business on the
balance sheet date.  Where there is
no active market, fair value is determined using valuation techniques. These
include using recent arm's-length market transactions, reference to other
instruments that are substantially the same, discounted cash flow analysis, and
pricing models and related internal assumptions. In the valuation techniques,
Statoil also takes into consideration the counterparty and its own credit risk.
This is either reflected in the discount rate used or through direct adjustments
to the calculated cash flows. Consequently, where Statoil reflects elements of
long-term physical delivery commodity contracts at fair value, such fair value
estimates to the extent possible are based on quoted forward prices in the
market and underlying indexes in the contracts, as well as assumptions of
forward prices and margins where observable market prices are not available.
Similarly, the fair values of interest and currency swaps are estimated based
on relevant quotes from active markets, quotes of comparable instruments, and
other appropriate valuation techniques.  Critical
accounting judgements and key sources of estimation uncertainty Critical judgements in applying accounting policies The following
are the critical judgements, apart from those involving estimations (see
below), that Statoil has made in the process of applying the accounting
policies and that have the most significant effect on the amounts recognised in
the financial statements:  Revenue recognition - gross versus net
presentation of traded SDFI volumes of oil and gas production As described
under Transactions with the Norwegian State above, Statoil markets and sells
the Norwegian State's share of oil and gas production from the NCS. Statoil
includes the costs of purchase and proceeds from the sale of the SDFI oil
production in Purchases
[net of inventory variation] and Revenues, respectively.
In making the judgement, Statoil considered the detailed criteria for the recognition
of revenue from the sale of goods and, in particular, concluded that the risk
and reward of the ownership of the oil had been transferred from the SDFI to
Statoil.  Statoil sells,
in its own name, but for the Norwegian State's account and risk, the State's
production of natural gas. These gas sales, and related expenditures refunded
by the State, are shown net in Statoil's Consolidated financial statements. In
making the judgement, Statoil considered the same criteria as for the oil
production and concluded that the risk and reward of the ownership of the gas
had not been transferred from the SDFI to Statoil.   Key sources of estimation uncertainty The
preparation of the Consolidated financial statements requires that management
make estimates and assumptions that affect reported amounts of assets,
liabilities, income and expenses. The estimates and associated assumptions are
based on historical experience and various other factors that are believed to
be reasonable under the circumstances, the result of which form the basis of
making the judgements about carrying values of assets and liabilities that are
not readily apparent from other sources. Actual results may differ from these
estimates. The estimates and underlying assumptions are reviewed on an on-going
basis considering the current and expected future market conditions.  Statoil is
exposed to a number of underlying economic factors which affect the overall
results, such as liquids prices, natural gas prices, refining margins, foreign
exchange rates and interest rates as well as financial instruments with fair
values derived from changes in these factors. In addition, Statoil's results
are influenced by the level of production, which in the short term may be
influenced by, for instance, maintenance programmes. In the long term, the
results are impacted by the success of exploration and field development
activities.  The matters
described below are considered to be the most important in understanding the
key sources of estimation uncertainty that are involved in preparing these
Consolidated financial statements and the uncertainties that could most
significantly impact the amounts reported on the results of operations,
financial position and cash flows.  Proved oil and gas reserves Proved oil and
gas reserves may materially impact the Consolidated financial statements, as
changes in the proved reserves, for instance as a result of changes in prices,
will impact the unit of production rates used for depreciation and
amortisation. Proved oil and gas reserves have been estimated by internal
qualified professionals on the basis of industry standards and governed by
criteria established by regulations of the U.S. Securities Exchange Commission
(SEC), which require the use of a price based on a 12-month average for reserve
estimation, and which are to be based on existing economic conditions and
operating methods and with a high degree of confidence (at least 90%
probability) that the quantities will be recovered. The Financial Accounting
Standards Board (FASB) requirements for supplemental oil and gas disclosures
align with the SEC regulations. Reserves estimates are based on subjective
judgements involving geological and engineering assessments of in-place
hydrocarbon volumes, the production, historical recovery and processing yield
factors and installed plant operating capacity. For future development
projects, proved reserves estimates are included only where there is a
significant commitment to project funding and execution and when relevant
governmental and regulatory approvals have been secured or are reasonably
certain to be secured. The reliability of these estimates at any point in time
depends on both the quality and quantity of the technical and economic data and
the efficiency of extracting and processing the hydrocarbons. An independent
third party has evaluated Statoil's proved reserves estimates, and the results 172Statoil, Annual Report on Form 20-F 2015


---

of this evaluation do not differ materially from
Statoil's estimates. Proved oil and gas reserves are those quantities of oil
and gas, which, by analysis of geoscience and engineering data, can be
estimated with reasonable certainty to be economically producible from a given
date forward, from known reservoirs, and under existing economic conditions,
operating methods and government regulations. Unless evidence indicates that
renewal is reasonably certain, estimates of economically producible reserves
only reflect the period before the contracts providing the right to operate
expire. The project to extract the hydrocarbons must have commenced, or the
operator must be reasonably certain that it will commence within a reasonable
time.  Expected oil and gas reserves Expected oil
and gas reserves may materially impact the Consolidated financial statements,
as changes in the expected reserves, for instance as a result of changes in
prices, will impact asset retirement obligations and impairment testing of
upstream assets, which in turn may lead to changes in impairment charges
affecting operating income. Expected oil and gas reserves are the estimated
remaining, commercially recoverable quantities, based on Statoil's judgement of
future economic conditions, from projects in operation or justified for
development. Recoverable oil and gas quantities are always uncertain, and the
expected value is the weighted average, or statistical mean, of the possible
outcomes. Expected reserves are therefore typically larger than proved reserves
as defined by the SEC rules. Expected oil and gas reserves have been estimated
by internal qualified professionals on the basis of industry standards and are
used for impairment testing purposes and for calculation of asset retirement
obligations. Reserves estimates are based on subjective judgements involving
geological and engineering assessments of in-place hydrocarbon volumes, the
production, historical recovery and processing yield factors, installed plant
operating capacity and operating approval limits. The reliability of these
estimates at any point in time depends on both the quality and quantity of the
technical and economic data and the efficiency of extracting and processing the
hydrocarbons.  Exploration and leasehold acquisition
costs Statoil
capitalises the costs of drilling exploratory wells pending determination of
whether the wells have found proved oil and gas reserves. Statoil also
capitalises leasehold acquisition costs and signature bonuses paid to obtain
access to undeveloped oil and gas acreage. Judgements as to whether these
expenditures should remain capitalised or written down due to impairment losses
in the period may materially affect the operating income for the period.  Impairment/reversal of impairment Statoil has
significant investments in property, plant and equipment and intangible assets.
Changes in the circumstances or expectations of future performance of an
individual asset may be an indicator that the asset is impaired, requiring the
carrying amount to be written down to its recoverable amount. Impairments are
reversed if conditions for impairment are no longer present. Evaluating whether
an asset is impaired or if an impairment should be reversed requires a high
degree of judgement and may to a large extent depend upon the selection of key
assumptions about the future.  Unproved oil and
gas properties are assessed for impairment when facts and circumstances suggest
that the carrying amount of the asset may exceed its recoverable amount, and at
least annually. If, following evaluation, an exploratory well has not found
proved reserves, the previously capitalised costs are tested for impairment.
Subsequent to the initial evaluation phase for a well, it will be considered a
trigger for impairment testing of a well if no development decision is planned
for the near future and there is no concrete plan for future drilling in the
licence.  Impairment of
unsuccessful wells is reversed, as applicable, to the extent that conditions
for impairment are no longer present.  Estimating
recoverable amounts involves complexity in estimating relevant future cash
flows, based on assumptions about the future, discounted to their present
value. Impairment testing requires long-term assumptions to be made concerning
a number of often volatile economic factors such as future market prices,
refinery margins, currency exchange rates and future output, discount rates and
political and country risk among others, in order to establish relevant future
cash flows. Impairment testing frequently also requires judgement regarding
probabilities and probability distributions as well as levels of sensitivity
inherent in the establishment of recoverable amount estimates. Long-term
assumptions for major economic factors are made at a group level, and there is
a high degree of reasoned judgement involved in establishing these assumptions,
in determining other relevant factors such as forward price curves, in
estimating production outputs and in determining the ultimate terminal value of
an asset.  Employee retirement plans When
estimating the present value of defined benefit pension obligations that
represent a long-term liability in the Consolidated balance sheet, and
indirectly, the period's net pension expense in the Consolidated statement of
income, management make a number of critical assumptions affecting these
estimates. Most notably, assumptions made about the discount rate to be applied
to future benefit payments and plan assets, the expected rate of pension
increase and the annual rate of compensation increase, have a direct and
potentially material impact on the amounts presented. Significant changes in
these assumptions between periods can have a material effect on the
Consolidated financial statements.  Asset retirement obligations Statoil has
significant obligations to decommission and remove offshore installations at
the end of the production period. It is difficult to estimate the costs of
these decommissioning and removal activities, which are based on current
regulations and technology, and consider relevant risks and uncertainties. Most
of the removal activities are many years into the future, and the removal
technology and costs are constantly changing. The estimates include assumptions
of the time required and the day rates for rigs, marine operations and heavy
lift vessels that can vary considerably depending on the assumed removal
complexity. As a result, the initial recognition of the liability and the
capitalised cost associated with decommissioning and removal obligations, and
the subsequent adjustment of these balance sheet items, involve the application
of significant judgement. Statoil, Annual Report on Form 20-F
2015173


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Derivative financial instruments When not
directly observable in active markets, the fair value of derivative contracts
must be computed internally based on internal assumptions as well as directly
observable market information, including forward and yield curves for
commodities, currencies and interest rates. Changes in internal assumptions,
forward and yield curves could materially impact the internally computed fair
value of derivative contracts, particularly long-term contracts, resulting in a
corresponding impact on income or loss in the Consolidated statement of income.  Income
tax Every year
Statoil incurs significant amounts of income taxes payable to various
jurisdictions around the world and recognises significant changes to deferred
tax assets and deferred tax liabilities, all of which are based on management's
interpretations of applicable laws, regulations and relevant court decisions.
The quality of these estimates is highly dependent upon management's ability to
properly apply at times very complex sets of rules, to recognise changes in
applicable rules and, in the case of deferred tax assets, management's ability
to project future earnings from activities that may apply loss carry forward
positions against future income taxes.  3 Segments  With effect from the third quarter of 2015 Statoil implemented a
new corporate structure. Statoil's operations are now managed through the
following operating segments: Development and Production Norway (DPN), Development
and Production USA (DPUSA), Development and Production International (DPI),
Marketing, Midstream and Processing (MMP),New Energy Solutions (NES)and Other.  The development and production operating segments are responsible
for the commercial development of the oil and gas portfolios within their
respective geographical areas: DPN on the Norwegian continental shelf, DPUSA
including offshore and onshore activities in the USA and Mexico, and DPI
worldwide outside of DPN and DPUSA.  Exploration activities are managed by a separate business unit,
which has the global responsibility across the group for discovery and
appraisal of new resources. Exploration activities are allocated to and
presented in the respective development and production operating segments.  The MMP segment is responsible for marketing and trading of oil
and gas commodities (crude, condensate, gas liquids, products, natural gas and
liquefied natural gas), electricity and emission rights, as well as
transportation, processing and manufacturing of the above mentioned
commodities, operations of refineries, terminals, processing and power plants.  The NES segment is responsible for wind parks, carbon capture and
storage as well as other renewable energy and low-carbon energy solutions.  Statoil reports its business through reporting segments which
correspond to the operating segments, except for the operating segments DPI and
DPUSA which have been aggregated into one reporting segment, Development and
Production International. This aggregation has its basis in similar economic
characteristics, the nature of products, services and production processes, the
type and class of customers, the methods of distribution and regulatory
environment. The new operating segment NES is reported in the segment Other in
2015 due to its immateriality.  The Other reporting segment includes activities within New Energy
Solutions, Global Strategy and Business Development, Technology, Projects and
Drilling and Corporate Staffs and Services.  The eliminations section includes the elimination of inter-segment
sales and related unrealised profits, mainly from the sale of crude oil and
products. Inter-segment revenues are based upon estimated market prices.  Segment data for the years ended 31 December 2015, 2014 and 2013
is presented below. The measurement basis of segment profit isNet operating income. In the tables below, deferred tax assets, pension assets and
non-current financial assets are not allocated to the segments. Also, the line
additions to PP&E, intangibles and equity accounted investments is
excluding movements due to changes in asset retirement obligations.  (in NOK billion)
 Development and
  Production Norway
 Development and
  Production International
 Marketing, Midstream and
  Processing
 Other
 Eliminations
 TotalFull year 2015Revenues third party and
  other income
 (0.9)
 15.3
 465.5
 3.1
 -
 483.1Revenues inter-segment
 140.4
 53.9
 1.5
 0.0
 (195.7)
 (0.0)Net income (loss) from
  equity accounted investments
 0.0
 (0.8)
 0.4
 0.0
 -
 (0.3)Total revenues and other
  income
 139.5
 68.4
 467.4
 3.2
 (195.7)
 482.8Purchases [net of
  inventory variation]
 (0.0)
 (0.1)
 (406.5)
 (0.0)
 195.4
 (211.2)Operating and SG&A
  expenses
 (25.8)
 (27.3)
 (37.6)
 (2.8)
 1.5
 (91.9)Depreciation,
  amortisation and net impairment losses
 (51.4)
 (81.6)
 0.4
 (1.1)
 0.0
 (133.8)Exploration expenses
 (4.6)
 (26.3)
 0.0
 0.0
 0.0
 (31.0)Net operating income
 57.6
 (66.9)
 23.7
 (0.8)
 1.2
 14.9Additions to PP&E,
  intangibles and equity accounted investments
 50.6
 65.4
 7.3
 2.2
 0.0
 125.5Balance sheet
  informationEquity accounted
  investments
 0.0
 2.9
 1.9
 2.4
 -
 7.3Non-current segment
  assets
 244.1
 330.1
 49.2
 6.1
 -
 629.5Non-current assets, not
  allocated to segments
 
 
 
 
 
 82.0Total non-current assets
 
 
 
 
 
 718.7
 174Statoil, Annual Report on Form 20-F 2015


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(in NOK billion)
 Development and
  Production Norway
 Development and
  Production International
 Marketing, Midstream and
  Processing
 Other
 Eliminations
 TotalFull year 2014Revenues third party and
  other income
 9.0
 18.6
 595.0
 0.4
 -
 622.9Revenues inter-segment
 173.2
 67.3
 1.8
 0.0
 (242.3)
 (0.0)Net income (loss) from
  equity accounted investments
 0.1
 (0.8)
 0.5
 (0.0)
 -
 (0.3)Total revenues and other
  income
 182.2
 85.2
 597.3
 0.3
 (242.3)
 622.7Purchases [net of
  inventory variation]
 (0.0)
 (0.0)
 (544.2)
 (0.0)
 242.9
 (301.3)Operating and SG&A
  expenses
 (25.2)
 (22.9)
 (33.2)
 (0.9)
 2.0
 (80.2)Depreciation,
  amortisation and net impairment losses
 (40.0)
 (56.8)
 (3.6)
 (1.0)
 -
 (101.4)Exploration expenses
 (5.4)
 (25.0)
 (0.0)
 0.0
 -
 (30.3)Net operating income
 111.7
 (19.5)
 16.2
 (1.5)
 2.6
 109.5Additions to PP&E,
  intangibles and equity accounted investments
 55.1
 61.4
 7.8
 0.8
 -
 125.1Balance sheet
  informationEquity accounted
  investments
 0.2
 4.8
 3.2
 0.2
 -
 8.4Non-current segment
  assets
 262.0
 333.8
 46.3
 5.1
 -
 647.3Non-current assets, not
  allocated to segments
 
 
 
 
 
 76.0Total non-current assets
 
 
 
 
 
 731.7
 Statoil, Annual Report on Form 20-F
2015175


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(in NOK billion)
 Development and
  Production Norway
 Development and
  Production International
 Marketing, Midstream and
  Processing
 Other
 Eliminations
 TotalFull year 2013Revenues third party and
  other income
 9.4
 16.5
 607.5
 1.0
 -
 634.4Revenues inter-segment
 192.7
 65.4
 1.0
 0.1
 (259.1)
 0.0Net income (loss) from
  equity accounted investments
 0.1
 (0.0)
 0.1
 (0.0)
 -
 0.1Total revenues and other
  income
 202.2
 81.9
 608.6
 1.0
 (259.1)
 634.5Purchases [net of
  inventory variation]
 0.0
 (0.1)
 (565.2)
 (0.0)
 258.4
 (306.9)Operating and SG&A
  expenses
 (27.4)
 (21.0)
 (33.7)
 (0.8)
 1.1
 (81.9)Depreciation,
  amortisation and net impairment losses
 (32.2)
 (31.9)
 (7.0)
 (1.3)
 0.0
 (72.4)Exploration expenses
 (5.5)
 (12.5)
 (0.0)
 (0.0)
 0.0
 (18.0)Net operating income
 137.1
 16.4
 2.6
 (1.1)
 0.4
 155.5Additions to PP&E, intangibles
  and equity accounted investments
 57.3
 52.9
 5.9
 1.3
 -
 117.4Balance sheet
  informationEquity accounted
  investments
 0.2
 4.8
 2.3
 0.2
 -
 7.4Non-current segment
  assets
 247.6
 286.5
 39.3
 5.6
 -
 578.9Non-current assets, not
  allocated to segments
 
 
 
 
 
 60.5Total non-current assets
 
 
 
 
 
 646.8
  See note 4Acquisitions and
dispositionsfor information on transactions that affect the different
segments.  See note 11Property, plant and
equipmentfor information on impairment losses that affected the different
segments.  See note 12Intangible assetsfor information on impairment
losses that affected primarily the DPI segment.  See note 23Other commitments,
contingent liabilities and contingent assetsfor information on
contingencies that have influenced the DPI and MMP segments.  Revenues by geographical areas Statoil has business operations in more than 30 countries. When
attributing revenues third party and other income to the country of the legal
entity executing the sale, Norway constitutes 76% and the USA constitutes 13%. 176Statoil, Annual Report on Form 20-F 2015


---

Non-current assets by countryAt 31 December(in NOK
  billion)
 2015
 2014
 2013Norway
 277.4
 289.6
 269.6USA
 180.9
 182.9
 159.2Angola
 47.1
 51.3
 45.9Brazil
 30.6
 29.5
 24.5UK
 25.4
 19.7
 13.6Canada
 20.0
 17.6
 19.9Algeria
 12.6
 11.8
 9.0Azerbaijan
 12.5
 23.6
 19.0Other countries
 30.3
 29.5
 25.6Total non-current assets1)
 636.7
 655.6
 586.3
  1)Excluding
deferred tax assets, pension assets and non-current financial assets.  Revenues by product type(in NOK
  billion)
 2015
 2014
 2013Crude oil
 223.1
 324.6
 321.5Natural gas
 99.6
 99.3
 110.4Refined products
 86.5
 104.8
 118.9Natural gas liquids
 44.2
 59.5
 64.5Other
 12.0
 18.6
 1.3Total revenues
 465.3
 606.8
 616.6
  4 Acquisitions and disposals  2015 Sale of interests in the
Marcellus onshore play In January 2015Statoil closed
an agreement with Southwestern Energy, entered into in the fourth quarter 2014,reducing
Statoil’s average working interest in the non-operated southern Marcellus
onshore play from 29% to 23%. The transaction was recognised in theDevelopment and Production
International (DPI)segment with no impact on the Consolidated statement of income.
Proceeds from the sale were NOK 2.8 billion.  Sale of interests in the
Shah Deniz project and the South Caucasus Pipeline In April 2015 Statoil
closed an agreement with Petronas, entered into in October 2014, to sell its
remaining 15.5% interest in the Shah Deniz project and the South Caucasus
Pipeline. Statoil recognised a total gain of NOK 12.4 billion. The gain was
presented in the line item Other income in the Consolidated statement of
income. In the segment reporting, the gain was recognised in the DPI and the
Marketing, Midstream and Processing (MMP) segments, with NOK 12.3 billion and
NOK 0.1 billion, respectively.The part of the transaction recognised in the DPI segment was tax
exempt under the rules in Norway and Azerbaijan.Total proceeds from the sale were NOK 20.3
billion, of which NOK 0.7 billion was received in 2014 and NOK 19.6 billion in
2015.  Sale of head office
building In June 2015 Statoil
closed a transaction withColony Capital, Inc.for the sale of the company’s head office building in Stavanger
through the sale of shares in the company Forusbeen 50 AS. At the same time,
Statoil entered into a 15 year operating lease agreement for the building. A
gain of NOK 1.5 billion was recognised in the Other segment. The gain was
presented in the line item Other income in the Consolidated statement of
income. Proceeds from the sale were NOK 2.3 billion.  Sale of office buildings In December 2015 Statoil
closed a transaction with TRD Campus AS for the sale of the company’s office
buildings in Trondheim and Stjørdal through the sale of shares in the companies
Strandveien 4 AS and Arkitekt Ebbelsvei 10 AS. At the same time Statoil entered
into 15 year operating lease agreements for the buildings. A gain of NOK 0.6
billion was recognised in the Other segment. The gain was presented in the line
item Other income in the Consolidated statement of income. Proceeds from the
sale were NOK 1.7 billion.  Sale of interests in the
Trans Adriatic Pipeline AG Statoil, Annual Report on Form 20-F
2015177


---

In December 2015 Statoil closed an agreement with Italian gas
structure company Snam SpA to sell its 20% interest in Trans Adriatic Pipeline
AG. A gain of NOK 1.4 billion was recognised in the MMP segment. The gain was
tax exempt and presented in the line item Other income in the Consolidated
statement of income. Total proceeds from the sale were NOK 2.0 billion.  Sale of interests in the
Gudrun field and acquisition of interests in Eagle Ford In December 2015 Statoil
closed an agreement with Repsol to sell a 15% interest in the Gudrun field on
the Norwegian continental shelf (NCS).Statoil
remains the operator and largest equity holder with a 36% interest.Statoil recognised a total
gain of NOK 1.2 billion in theDevelopment and Production Norway (DPN) segment. The gain was presented in the
line itemOther
incomein the
Consolidated statement of income.The transaction was tax exempt under the Norwegian petroleum tax
legislation.Proceeds
from the sale were NOK 1.9 billion.  Simultaneously Statoil
closed an agreement to acquire an additional13% interest in the Eagle Ford formation with the same party.
Statoil’s total interest in the Eagle Ford shale play after the acquisition is
63%, and Statoil also became the sole operator. The acquisition was accounted
for as a business combination using the acquisition method. The acquisition and
valuation date for the purchase price allocation was 30 December 2015. The fair
value of net identifiable assets was NOK 3.5 billion. The acquisition was recognised in the DPI and MMP reporting
segments with the fair value of net identifiable assets of NOK 2.4 billion and
NOK 1.1 billion, respectively. The totalpurchase priceof the business combination was NOK 3.5 billion.No goodwill was
recognised.  2014 Sale of interests in the Shah Deniz project
and the South Caucasus Pipeline In March 2014 Statoil closed an agreement
with BP and in May 2014 Statoil closed an agreement with SOCAR, both entered
into in December 2013, to divest a 3.33% working interest and a 6.67% working
interest, respectively, in the Shah Deniz project and the South Caucasus
Pipeline. Statoil recognised a total gain of NOK 5.4 billion, presented in the
line item Other
income in the Consolidated statement of income. In the segment
reporting, the gain has been presented in the DPI segment and the MMP segment
with NOK 5.2 billion and NOK 0.2 billion, respectively. The part of the
transaction recognised in the DPI segment was tax exempt under the rules in
Norway and Azerbaijan. Proceeds from the sale were NOK 8.2 billion.  Kai Kos Dehseh oil sands swap agreement In May 2014 Statoil and its partner PTTEP
closed an agreement to swap the two parties' respective interests in the Kai
Kos Dehseh oil sands project in Alberta, Canada. Statoil paid a balancing cash
consideration of NOK 2.5 billion and assumed a net liability of NOK 0.3
billion. Subsequent to the closing, Statoil continues as 100% owner of the
Leismer and Corner projects, while PTTEP owns 100% of the Thornbury,
Hangingstone and South Leismer areas. The transaction has been recognised in
the DPI segment resulting in an increase in Property, plant and equipment
of NOK 4.6 billion, including a transfer from Intangible assets of NOK 1.8
billion, and with no impact on the Consolidated statement of income.  Sale of interests in licences on the
Norwegian continental shelf In December 2014 Statoil closed an agreement
with Wintershall to sell certain ownership interests in licences on the NCS. A
gain of NOK 5.9 billion has been recognised in the DPN segment. The gain has
been presented in the line item Other income in the
Consolidated statement of income. The transaction was tax exempt under the
rules in the Norwegian petroleum tax legislation, and the gain included a
release of related deferred tax liabilities. Proceeds from the sale were NOK
8.7 billion (USD 1.25 billion).  2013 Sale of interests in exploration and
production licences on the Norwegian continental shelf to Wintershall In July 2013 a sales transaction with
Wintershall of certain ownership interests in licences on the NCS was closed.
Statoil recognised a gain of NOK 6.4 billion. The gain has been presented in
the line itemOther incomein the
Consolidated statement of income. In the segment reporting, the gain has been
presented in the DPN segment in revenues third party and other income.The
transaction was tax exempt under the rules in the Norwegian petroleum tax legislation.
Proceeds from the sale were NOK 4.7 billion.  Sale of interests in
exploration and production licences on the Norwegian continental shelf and the
United Kingdom continental shelf to OMV In October 2013 a sales transaction with OMV
to sell certain ownership interests in licences on the NCS and United Kingdom
continental shelf was closed. Statoil recognised a gain of NOK 10.1 billion.
The gain has been presented in the line itemOther incomein the Consolidated
statement of income. In the segment reporting, the gain has been presented in
the DPN segment and in the DPI segment in revenues third party and other income
with NOK 6.6 billion and NOK 3.5 billion, respectively. The part of the
transaction covering assets on the NCS was tax exempt under the rules in the
Norwegian petroleum tax legislation. Proceeds from the sale were NOK 15.9
billion.  5 Financial risk management  General information relevant to financial risks Statoil's
business activities naturally expose Statoil to financial risk. Statoil's
approach to risk management includes assessing and managing risk in
all activities using a holistic risk approach. Statoil utilises correlations
between the most important market risks, such as oil and natural gas prices,
refined oil product prices, currencies, and interest rates, to calculate the
overall market risk and thereby take into account the natural hedges inherent
in Statoil's portfolio. Adding the different market risks without considering
these correlations would overestimate Statoil's total market risk. This
approach allows Statoil to reduce the number of risk management transactions
and thereby reduce transaction costs and avoid sub-optimisation. 178Statoil, Annual Report on Form 20-F 2015


---

An
important element in risk management is the use of centralised trading
mandates. All major strategic transactions are required to be coordinated through
Statoil's corporate risk committee. Mandates delegated to the trading
organisations within crude oil, refined products, natural gas and electricity
are relatively
small compared to the total market risk of Statoil.  The
corporate risk committee, which is headed by the chief financial officer and
includes representatives from the principal business segments, is responsible
for defining, developing and reviewing Statoil's risk policies. The chief
financial officer, assisted by the committee, is also responsible for
overseeing and developing Statoil's Enterprise Risk Management and proposing
appropriate measures to adjust risk at the corporate level. The committee meets
at least six times per year and regularly reviews risk information relevant to Statoil.  Financial risks Statoil's
activities expose Statoil to the following financial risks: ·Market
risk (including commodity price risk, currency risk and interest rate risk) ·Liquidity
risk ·Credit
risk  Market risk Statoil
operates in the worldwide crude oil, refined products, natural gas, and
electricity markets and is exposed to market risks including fluctuations in
hydrocarbon prices, foreign currency rates, interest rates, and electricity
prices that can affect the revenues and costs of operating, investing and
financing. These risks are managed primarily on a short-term basis with a focus
on achieving the highest risk-adjusted returns for Statoil within the given
mandate. Long-term exposures are managed at the corporate level, while
short-term exposures are managed according to trading strategies and mandates
approved by Statoil's corporate risk committee.  In the
marketing of commodities Statoil has established guidelines for entering into
derivative contracts in order to manage commodity price, foreign currency rate,
and interest rate risks. Statoil uses both financial and commodity-based
derivatives to manage the risks in revenues, financial items and the present
value of future cash flows.  For
more information on sensitivity analysis of market risk see note 25 Financial
instruments: fair value measurement and sensitivity analysis of market risk.  Commodity
price risk Statoil’s
most important long term commodity risk (oil and natural gas) is related to
future market prices as Statoil ́s risk policy is to be exposed to both
upside and downside price movements. To manage short-term commodity risk,
Statoil enters into commodity- based derivative contracts, including futures,
options, over-the-counter (OTC) forward contracts, market swaps and contracts
for differences related to crude oil, petroleum products, natural gas and
electricity.  Derivatives
associated with crude oil and refined oil products are traded mainly on the
Inter Continental Exchange (ICE) in London, the New York Mercantile Exchange
(NYMEX), the OTC Brent market, and crude and refined products swap markets.
Derivatives associated with natural gas and electricity are mainly OTC physical
forwards and options, NASDAQ OMX Oslo forwards and futures traded on the NYMEX
and ICE.  The
term of crude oil and refined oil products derivatives is usually less than one
year, and the term for natural gas and electricity derivatives is usually three
years or less. For
more detailed information about Statoil's commodity based derivative financial
instruments, see note 25 Financial instruments: fair value measurement and
sensitivity analysis of market risk.  Currency
risk Statoil's operating results and cash
flows are affected by foreign currency fluctuations and the most significant
currency is Norwegian Krone (NOK) against United States Dollar (USD). Statoil
manages its currency risk from operating activities with USD as the base
currency. Foreign exchange risk is managed at corporate level in accordance
with established policies and mandates.  Statoil's cash flows from operating
activities deriving from oil and gas sales, operating expenses and capital
expenditures are mainly in USD, but taxes and dividends to shareholders on the Oslo
Børs are in NOK. Accordingly, Statoil's currency management is primarily linked
to mitigate currency risk related to tax and dividend payments in NOK. This
means that Statoil regularly purchases substantial NOK amounts on a forward
basis using conventional derivative instruments.  Interest
rate risk Bonds are normally issued at fixed
rates in a variety of local currencies (among others USD, Euro and Great
Britain Pound). Bonds may be converted to floating USD bonds by using interest
rate and currency swaps. Statoil manages its interest rates exposure on its
bond debt based on risk and reward considerations from an enterprise risk
management perspective. This means that the fix/floating mix on interest rate
exposure may vary from time to time. For more detailed information about
Statoil's long-term debt portfolio see note 18 Finance
debt.  Liquidity risk Statoil, Annual Report on Form 20-F
2015179


---

Liquidity risk is the risk
that Statoil will not be able to meet obligations of financial liabilities when
they become due. The purpose of liquidity management is to
make certain that Statoil has sufficient funds available at all times to cover
its financial obligations.  Statoil manages liquidity and funding
at the corporate level, ensuring adequate liquidity to cover Statoil's
operational requirements. Statoil has a high focus and attention on credit and liquidity
risk. In order to secure necessary financial flexibility, which includes
meeting the financial obligations, Statoil maintains a conservative liquidity management
policy. To identify future long-term financing needs, Statoil carries out
three-year cash forecasts at least monthly.  The main cash outflows are the
quarterly dividend payments and Norwegian petroleum tax payments paid six times
per year. If the monthly cash flow forecast shows that the liquid assets one
month after tax and dividend payments will fall below the defined policy level,
new long-term funding will be considered.  Short-term funding needs will normally
be covered by the USD 4.0 billion US Commercial Papers Programme (CP) which is
backed by a revolving credit facility of USD 5.0 billion, supported
by 21 core banks, maturing in 2020.The facility
supports secure access to funding, supported by the best available short-term
rating. As at 31 December 2015 it has not been drawn.  Statoil raises debt in all major
capital markets (USA, Europe and Asia) for long-term funding purposes. The policy
is to have a smooth maturity profile with repayments not exceeding five percent
of capital employed in any year for the nearest five years. Statoil's
non-current financial liabilities have a weighted average maturity of approximately nine
years.  For
more information about Statoil's non-current financial liabilities, see note 18
Finance
debt.  The table below shows a maturity
profile, based on undiscounted contractual cash flows, for Statoil's financial
liabilities.  At 31 December(in NOK billion)
 2015
 2014Due within 1 year
 104.9
 131.4Due between 1 and 2
  years
 73.7
 43.3Due between 3 and 4
  years
 86.9
 81.3Due between 5 and 10
  years
 93.8
 90.5Due after 10 years
 115.5
 84.3Total specified
 474.7
 430.8
  Credit risk Credit
risk is the risk that Statoil's customers or counterparties will cause Statoil financial loss
by failing to honour their obligations. Credit risk arises from credit
exposures with customer accounts receivables as well as from financial investments, derivative
financial instruments and deposits with financial institutions.  Key
elements of the credit risk management approach include: ·A
global credit risk policy ·Credit
mandates ·An
internal credit rating process ·Credit
risk mitigation tools ·A continuous
monitoring and managing of credit exposures  Prior
to entering into transactions with new counterparties, Statoil's credit policy
requires all counterparties to be formally identified and approved. In
addition, all sales, trading and financial counterparties are assigned internal
credit ratings as well as exposure limits. Once established, all counterparties
are re-assessed regularly and continuously monitored. Counterparty risk
assessments are based on a quantitative and qualitative analysis of recent
financial statements and other relevant business information like past payment
performance, the counterparties' size and business diversification. The
internal credit ratings reflect Statoil's assessment of the counterparties'
credit risk. Exposure limits are determined based on assigned internal credit
ratings combined with other factors, such as expected transaction and industry
characteristics. Credit mandates define acceptable credit risk thresholds and
are endorsed by management.  Statoil
uses risk mitigation tools to reduce or control credit risk both on a
counterparty and portfolio level. The main tools include bank and parental
guarantees, prepayments and cash collateral.  180Statoil, Annual Report on Form 20-F 2015


---

Statoil has pre-defined
limits for the absolute credit risk level allowed at any given time on
Statoil's portfolio as well as maximum credit exposures for individual
counterparties. Statoil monitors the portfolio on a regular basis and
individual exposures against limits on a daily basis. The total credit exposure
portfolio of Statoil is geographically diversified among a number of
counterparties within the oil and energy sector, as well as larger oil and gas
consumers and financial counterparties. The majority of Statoil's credit
exposure is with investment grade counterparties.   Statoil, Annual Report on Form 20-F
2015181


---

The following table contains the carrying amount of
Statoil's financial receivables and derivative financial instruments split by
Statoil's assessment of the counterparty's credit risk. There are no
significant receivables that are past due or impaired. Only non-exchange traded
instruments are included in derivative financial instruments.  (in NOK
  billion)
 Non-current financial receivables
 Trade and other receivables
 Non-current derivative financial instruments
 Current derivative financial instrumentsAt 31 December 2015Investment grade, rated
  A or above
 0.0
 14.6
 11.9
 2.0Other investment grade
 3.3
 27.5
 11.9
 2.4Non-investment grade or
  not rated
 2.4
 9.3
 0.0
 0.3Total financial asset
 5.8
 51.4
 23.8
 4.8At 31 December 2014Investment grade, rated
  A or above
 0.0
 20.1
 15.2
 2.4Other investment grade
 0.0
 36.5
 11.8
 2.7Non-investment grade or
  not rated
 2.7
 17.2
 2.9
 0.2Total financial asset
 2.7
 73.7
 29.9
 5.3
  At 31 December 2015, NOK 10.2
billion of cash was held as collateral to mitigate a portion of Statoil's
credit exposure. At 31 December 2014 NOK 12.9 billion was held as collateral.
The collateral cash is received as a security to mitigate credit exposure
related to positive fair values on interest rate swaps, cross currency swaps
and foreign exchange swaps. Cash is called as collateral in accordance with the
master agreements with the different counterparties when the positive fair
values for the different swap agreements are above an agreed threshold.  Under the terms of various
master netting agreements for derivative financial instruments as of 31
December 2015, NOK 7.0 billion presented as liabilities do not meet the
criteria for offsetting. At 31 December 2014, NOK 5.2 billion was not offset.
The collateral received and the amounts not offset from derivative financial
instrument liabilities, reduce the credit exposure in the derivative financial
instruments presented in the table above as they will offset each other in a
potential default situation for the counterparty.  6 Remuneration  Full year(in NOK
  billion, except average number of employees)
 2015
 2014
 2013Salaries1)
 22.5
 23.3
 23.5Pension costs
 6.8
 3.4
 4.6Payroll tax
 3.4
 3.5
 3.4Other compensations and
  social costs
 2.5
 2.4
 2.5Total payroll costs
 35.2
 32.5
 34.0Average number of
  employees2)
 22,300
 23,300
 23,600
  1)Salaries include
bonuses, severance packages and expatriate costs in addition to base pay. 2)Part time employees
amount to 3%, 2% and 3% for the years 2015, 2014 and 2013 respectively.  Total payroll
expenses are accumulated in cost-pools and partly charged to partners of Statoil operated licences on an hours incurred basis.  For further
information on pension costs, see note 19 Pensions.   182Statoil, Annual Report on Form 20-F 2015


---

Compensation to the board of directors
(BoD) and the corporate executive committee (CEC) Remuneration
to members of the BoD and the CEC during the year was as follows:  Full year(in NOK
  million)1)
 2015
 2014
 2013Current employee
  benefits
 92.2
 73.2
 74.5Post-employment benefits
 6.4
 13.0
 13.0Other non-current
  benefits
 0.1
 0.0
 0.1Share based payment
  benefits
 1.3
 1.1
 1.1Total
 100.2
 87.3
 88.7
  1)All figures in the
table are presented on accrual basis.  At
31 December 2015, 2014 and 2013 there are no loans to the members of the BoD or
the CEC.  Share-based compensation Statoil's
share saving plan provides employees with the opportunity to purchase Statoil
shares through monthly salary deductions and a contribution by Statoil. If the
shares are kept for two full calendar years of continued employment, following
the year of purchase, the employees will be allocated one bonus share for each
one they have purchased.  Estimated compensation expense including the contribution
by Statoil for purchased shares, amounts vested for bonus shares granted and
related social security tax was NOK 0.5 billion, NOK 0.6 billion and NOK 0.6
billion related to the 2015, 2014 and 2013 programs, respectively. For the 2016
program (granted in 2015) the estimated compensation expense is NOK 0.5 billion.
At 31 December 2015 the amount of compensation cost yet to be expensed throughout
the vesting period is NOK 1.2 billion.  7 Other expenses  Auditor's remunerationFull year(in NOK
  million, excluding VAT)
 2015
 2014
 2013Audit fee
 49
 45
 38Audit related fee
 14
 8
 8Tax fee
 0
 0
 0Other service fee
 0
 0
 0Total
 63
 53
 46
  Of total increase in audit
and audit related fees, NOK 3.2 million is due to currency effects, equivalent
to 5%.  In addition to the figures
in the table above, the audit fees and audit related fees related to Statoil operated
licences amount to NOK 7 million, NOK 6 million and NOK 6 million for 2015,
2014 and 2013, respectively.  Research and
development expenditures Research and development
(R&D) expenditures were NOK 2.7 billion, NOK 3.0 billion and NOK 3.2
billion in 2015, 2014 and 2013, respectively. R&D expenditures are partly
financed by partners of Statoil operated licences. Statoil's share of the
expenditures has been recognised as expense in the Consolidated statement of
income.  Statoil, Annual Report on Form 20-F
2015183


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8 Financial items  Full year(in NOK
  billion)
 2015
 2014
 2013Foreign exchange gains
  (losses) derivative financial instruments
 4.4
 (1.5)
 (4.1)Other foreign exchange
  gains (losses)
 (6.5)
 (0.7)
 (4.5)Net foreign exchange
  gains (losses)
 (2.1)
 (2.2)
 (8.6)Dividends received
 0.3
 0.3
 0.1Gains (losses) financial
  investments
 0.4
 1.1
 1.9Interest income
  financial investments
 0.6
 0.7
 0.6Interest income
  non-current financial receivables
 0.2
 0.1
 0.1Interest income current
  financial assets and other financial items
 1.7
 1.8
 0.9Interest income and
  other financial items
 3.2
 4.0
 3.6Interest expense bonds
  and bank loans and net interest on related derivatives
 (5.7)
 (4.3)
 (1.5)Interest expense finance
  lease liabilities
 (0.2)
 (0.3)
 (0.2)Capitalised borrowing
  costs
 3.2
 1.6
 1.1Accretion expense asset
  retirement obligations
 (3.9)
 (3.7)
 (3.2)Gains (losses)
  derivative financial instruments
 (3.8)
 5.8
 (7.4)Interest expense current
  financial liabilities and other finance expense
 (1.2)
 (0.8)
 (0.8)Interest and other
  finance expenses
 (11.7)
 (1.8)
 (12.0)Net financial items
 (10.6)
 (0.0)
 (17.0)
  Statoil's main financial items relate to assets and liabilities
categorised in the held for trading category and the amortised cost category.
For more information about financial instruments by category see note 25Financial instruments: fair value measurement and sensitivity
analysis of market risk.  The lineitem interest expense
bonds and bank loansand net interest on related derivatives primarily includes
interest expenses of NOK 8.6 billion, NOK 6.8 billion and NOK 5.4 billion from
the financial liabilities at amortised cost category. This was partly offset by
net interest on related derivatives from the held for trading category, NOK 2.6
billion, NOK 2.5 billion and NOK 3.9 billion for 2015, 2014 and 2013,
respectively.  The line item gains (losses) derivative financial instruments
primarily includes fair value loss from the held for trading category of NOK 4.0
billion, a gain of NOK 5.7 billion and a loss of NOK 7.6 billion for 2015, 2014
and 2013, respectively.  Foreign exchange gains (losses) derivative financial instruments
include fair value changes of currency derivatives related to liquidity and
currency risk. The line item foreign exchange gains (losses) includes a net
foreign exchange loss of NOK 9.7 billion, a loss of NOK 13.4 billion and a loss
of NOK 4.3 billion from the held for trading category for 2015, 2014 and 2013,
respectively.  184Statoil, Annual Report on Form 20-F 2015


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9
Income taxes  Significant components
  of income tax expenseFull year(in NOK
  billion)
 2015
 2014
 2013Current income tax
  expense in respect of current year
 52.0
 89.6
 111.6Prior period adjustments
 0.7
 (1.9)
 1.3Current income tax
  expense
 52.7
 87.6
 112.9Origination and reversal
  of temporary differences
 (12.3)
 (0.6)
 (13.4)Change in tax
  regulations
 0.7
 0.1
 0.1Prior period adjustments
 0.4
 0.3
 (0.4)Deferred tax expense
 (11.1)
 (0.2)
 (13.7)Income tax expense
 41.6
 87.4
 99.2
  During the normal course of its business,
Statoil files tax returns in many different tax regimes. There may be differing
interpretation of applicable tax laws and regulations regarding some of the matters
in the tax returns. It may in certain cases take several years to complete the
discussions with the relevant tax authorities or to reach a resolution of the
tax positions through litigations. Statoil has provided for probable income tax
related assets and liabilities based on best estimates reflecting consistent
interpretations of the applicable laws and regulations.  Reconciliation of
  nominal statutory tax rate to effective tax rateFull year(in NOK
  billion)
 2015
 2014
 2013Income before tax
 4.3
 109.4
 138.4Calculated income tax at
  statutory rate1)
 (8.5)
 31.2
 42.4Calculated Norwegian
  Petroleum tax2)
 33.4
 62.8
 71.7Tax effect uplift2)
 (6.8)
 (6.4)
 (5.2)Tax effect of permanent
  differences regarding divestments
 (3.7)
 (6.2)
 (12.0)Tax effect of permanent
  differences caused by functional currency different from tax currency
 (5.8)
 (5.1)
 (0.4)Tax effect of other
  permanent differences
 (0.2)
 2.2
 (3.7)Change in unrecognised
  deferred tax assets
 28.2
 8.7
 3.9Change in tax
  regulations3)
 0.7
 0.1
 0.1Prior period adjustments
 1.1
 (1.7)
 0.9Other items including
  currency effects
 3.2
 1.7
 1.5Income tax expense
 41.6
 87.4
 99.2Effective tax rate
 969.3%
 79.9%
 71.7%
  1)The
weighted average of statutory tax rates was -198.9% in 2015, 28.5% in 2014 and
30.7% in 2013. The negative weighted average of statutory tax rates for 2015
(198.9%) and the decrease in weighted average tax rates from 2014 to 2015 is
mainly caused by losses, impairments and provisions in entities with higher
than average statutory tax rates. The decrease from 2013 to 2014 was due to
changes in the geographic mix of income, and a decrease in the Norwegian
statutory tax rate from 28% to 27%. 2)When computing
the petroleum tax of 51% (53% from 2016) on income from the Norwegian
continental shelf, an additional tax-free allowance, or uplift, is granted at a
rate of 5.5% per year on the basis of the original capitalised cost of offshore
production installations. For investments made prior to 5 May 2013, the rate is
7.5% per year. Transitional rules apply to investments from 5 May 2013 covered
by among others Plans for development and operation (PDOs) or Plans for
installation and operation (PIOs) submitted to the Ministry of Oil and Energy
prior to 5 May 2013. The uplift may be deducted from taxable income for a
period of four years, starting in the year in which the capital expenditure is
incurred. Unused uplift may be carried forward indefinitely. At year end 2015
and 2014, unrecognised uplift credits amounted to NOK 20.6 billion and NOK 21.1
billion, respectively. 3)The
increase from 2014 to 2015 is mainly related to change in deferred taxes caused
by a reduction in Norwegian statutory tax rate from 27% to 25% effective from
2016. Statoil, Annual Report on Form 20-F
2015185


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Deferred tax assets and liabilities comprise(in NOK
  billion)
 Tax losses carried forward
 Property, plant and equipment
  and Intangible assets
 Asset removal obligation
 Pensions
 Derivatives
 Other
 TotalDeferred tax at 31
  December 2015Deferred tax assets
 41.8
 1.6
 61.5
 5.1
 0.1
 7.0
 117.1Deferred tax liabilities
 (0.0)
 (147.4)
 0.0
 (0.0)
 (8.2)
 (9.1)
 (164.6)Net asset (liability) at
  31 December 2015
 41.8
 (145.7)
 61.5
 5.1
 (8.1)
 (2.1)
 (47.6)Deferred tax at 31
  December 2014Deferred tax assets
 36.7
 4.6
 73.3
 7.0
 0.2
 13.4
 135.3Deferred tax liabilities
 (0.0)
 (172.6)
 0.0
 0.0
 (12.9)
 (8.4)
 (193.8)Net asset (liability) at
  31 December 2014
 36.7
 (167.9)
 73.3
 7.0
 (12.7)
 4.9
 (58.6)
  Changes in net deferred
  tax liability during the year were as follows:(in NOK
  billion)
 2015
 2014
 2013Net deferred tax
  liability at 1 January
 58.6
 62.8
 77.3Charged (credited) to
  the Consolidated statement of income
 (11.1)
 (0.2)
 (13.7)Other comprehensive
  income
 2.8
 (0.9)
 (1.5)Translation differences
  and other
 (2.7)
 (3.0)
 0.7Net deferred tax
  liability at 31 December
 47.6
 58.6
 62.8
  Deferred tax assets and liabilities are offset to the extent that the deferred
taxes relate to the same fiscal authority, and there is a legally enforceable
right to offset current tax assets against current tax liabilities. After
netting deferred tax assets and liabilities by fiscal entity, deferred taxes
are presented on the balance sheet as follows: At 31 December(in NOK
  billion)
 2015
 2014Deferred tax assets
 17.8
 12.9Deferred tax liabilities
 65.4
 71.5
  Deferred tax assets are
recognised based on the expectation that sufficient taxable income will be
available through reversal of taxable temporary differences or future taxable
income. At year end 2015 and 2014 the deferred tax assets of NOK 17.8 billion and
NOK 12.9 billion, respectively, were primarily recognised in Norway, Angola and
the UK. Unrecognised deferred
  tax assetsAt 31 December2015
 2014(in NOK
  billion)
 Basis
 Tax
 Basis
 TaxDeductible temporary
  differences
 21.6
 8.9
 11.0
 3.2Tax losses carried
  forward
 126.2
 46.7
 52.5
 18.0Total
 147.8
 55.6
 63.5
 21.2
  The movement in
tax value of unrecognised deferred tax assets in the table above compared to
reported change in unrecognised deferred tax assets in the table Reconciliation
of nominal statutory tax rate to effective tax rate is mainly caused by
currency effects. Approximately
11% of the unrecognised carry forward tax losses can be carried forward
indefinitely. The majority of the remaining part of the unrecognised tax losses
expire after 2026. The unrecognised deductible temporary differences do not
expire under the current tax legislation. Deferred tax assets have not been
recognised in respect of these items because currently there is insufficient
evidence to support that future taxable profits will be available to secure
utilisation of the benefits. 186Statoil, Annual Report on Form 20-F 2015


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Total unrecognised deferred tax assets relates to:At 31 December(in NOK
  billion)
 2015
 2014US
 39.3
 12.3Angola
 5.7
 0.0Ireland
 2.5
 1.8Canada
 2.4
 1.9Netherlands
 1.7
 1.4Other
 4.0
 3.8Total
 55.6
 21.2
  10 Earnings per share  The weighted average number of ordinary
shares is the basis for computing the basic and diluted earnings per share as
disclosed in the Consolidated statement of income. The dilutive effect relates
to treasury shares.  At 31 December(in
  millions)
 2015
 2014
 2013Weighted average number
  of ordinary shares
 3,179.4
 3,180.0
 3,180.7Weighted average number
  of ordinary shares, diluted
 3,188.8
 3,188.9
 3,188.9Earnings per share for
  income attributable to equity holders of the company:Basic (NOK)
 -11.80
 6.89
 12.53Diluted (NOK)
 -11.80
 6.87
 12.50
  11 Property, plant and equipment  (in NOK
  billion)
 Machinery, equipment and transportation equipment, including
  vessels
 Production plants and oil and gas assets
 Refining and manufacturing plants
 Buildings and land
 Assets under development
 TotalCost at 31 December 2014
 26.1
 1,037.5
 64.6
 10.1
 164.7
 1,303.0Additions and transfers
 0.4
 79.3
 5.0
 0.6
 10.1
 95.5Disposals at cost2)
 (0.2)
 (13.2)
 (8.0)
 (3.5)
 (9.3)
 (34.2)Effect of changes in
  foreign exchange
 4.2
 70.3
 4.1
 1.0
 13.2
 92.8Cost at 31 December 2015
 30.5
 1,174.0
 65.7
 8.2
 178.7
 1,457.1Accumulated depreciation
  and impairment losses at 31 December 2014
 (20.1)
 (656.7)
 (48.2)
 (4.8)
 (11.1)
 (740.9)Depreciation
 (1.4)
 (81.9)
 (2.2)
 (0.4)
 0.0
 (85.9)Impairment losses and transfers
 0.0
 (27.5)
 (0.5)
 (0.0)
 (20.8)
 (48.7)Reversal of impairment
  losses
 0.0
 0.8
 4.0
 0.1
 0.2
 5.0Accumulated depreciation
  and impairment disposed assets2)
 0.0
 6.6
 2.6
 1.5
 (0.0)
 10.8Effect of changes in
  foreign exchange
 (3.4)
 (40.9)
 (3.1)
 (0.5)
 (3.2)
 (51.1)Accumulated depreciation
  and impairment losses at 31 December 2015
 (24.9)
 (799.5)
 (47.4)
 (4.1)
 (34.9)
 (910.8)Carrying amount at 31
  December 2015
 5.6
 374.4
 18.3
 4.0
 143.8
 546.2Estimated useful lives
  (years)
 3-20
 1)
 15 - 20
 20 - 33
 Statoil, Annual Report on Form 20-F
2015187


---

(in NOK billion)
 Machinery, equipment and transportation equipment, including
  vessels
 Production plants and oil and gas assets
 Refining and manufacturing plants
 Buildings and land
 Assets under development
 TotalCost at 31 December 2013
 21.1
 869.9
 60.2
 8.4
 135.5
 1,095.1Additions and transfers
 1.0
 108.4
 2.0
 0.7
 23.8
 135.9Disposals at cost
 (0.1)
 (8.5)
 (1.4)
 (0.0)
 (8.9)
 (18.9)Effect of changes in
  foreign exchange
 4.1
 67.7
 3.8
 1.1
 14.3
 91.0Cost at 31 December 2014
 26.1
 1,037.5
 64.6
 10.1
 164.7
 1,303.0Accumulated depreciation
  and impairment losses at 31 December 2013
 (15.5)
 (540.1)
 (44.9)
 (3.8)
 (3.3)
 (607.7)Depreciation
 (1.2)
 (71.0)
 (1.8)
 (0.3)
 (0.0)
 (74.4)Impairment losses
 (0.3)
 (16.1)
 (1.2)
 (0.2)
 (7.1)
 (24.8)Reversal of impairment
  losses
 0.0
 0.3
 1.8
 0.0
 0.2
 2.3Accumulated depreciation
  and impairment disposed assets
 0.1
 5.7
 (0.2)
 0.0
 (0.0)
 5.7Effect of changes in
  foreign exchange
 (3.2)
 (35.4)
 (2.0)
 (0.5)
 (1.0)
 (42.0)Accumulated depreciation
  and impairment losses at 31 December 2014
 (20.1)
 (656.7)
 (48.2)
 (4.8)
 (11.1)
 (740.9)Carrying amount at 31
  December 2014
 6.0
 380.8
 16.4
 5.3
 153.6
 562.1Estimated useful lives
  (years)
 3-20
 1)
 15 - 20
 20 - 33
  1)Depreciation
according to unit of production method, see note 2 Significant
accounting policies. 2)Includes
NOK 5.8 billion related to a change in the classification of Statoil’s
investment in the Sheringham Shoal Windfarm (Scira Offshore Energy Ltd) from
joint operation (pro-rata line by line consolidation) to joint venture (equity
method) following changes in the joint operating agreements. The carrying amount of
assets transferred to Property, plant and equipmentfrom Intangible
assetsin
2015 and 2014 amounted to NOK 2.7 billion and NOK 9.5 billion, respectively. ImpairmentsDuring
2015 and 2014, Statoil recognised total net impairment losses of NOK 63.3
billion and NOK 38.2 billion respectively onProperty,
plant and equipmentandIntangible assets.  (in NOK
  billion)
 Property, plant and equipment
 Intangible assets3)
 TotalAt 31 December 2015Producing and
  development assets1)
 43.8
 9.8
 53.5Goodwill1)
 0.0
 4.2
 4.2Acquisition costs
  related to oil and gas prospects2)
 0.0
 5.6
 5.6Total net impairment
  losses recognised
 43.8
 19.6
 63.3At 31 December 2014Producing and
  development assets1)
 22.5
 6.0
 28.5Goodwill1)
 0.0
 4.2
 4.2Acquisition costs
  related to oil and gas prospects2)
 0.0
 5.5
 5.5Total net impairment
  losses recognised
 22.5
 15.7
 38.2
  1)Producing
and development assets and goodwill are subject to impairment assessment under
IAS 36. The total net impairment losses recognised under IAS 36 in 2015 and
2014 amount to NOK 57.7 billion and NOK 32.7 billion, respectively, including
impairment of acquisition costs - oil and gas prospects (intangible assets). 2)Acquisition
costs related to exploration activities,subject to impairment assessment under the successful efforts
method. 3)See
note 12Intangible
assets. 188Statoil, Annual Report on Form 20-F 2015


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In assessing
the need for impairment of the carrying amount of a potentially impaired asset,
the asset's carrying amount is compared to its recoverable amount. The
recoverable amount is the higher of fair value less cost of disposal (FVLCOD) and estimated value in use (VIU). The
base discount rate for VIU calculations is 6.5% real after tax. The discount
rate is derived from Statoil's weighted average cost of capital. A derived
pre-tax discount rate would generally be in the range of 8-12%, depending on
asset specific characteristics, such
as specific tax treatments, cash flow profiles and economic life. The rates are
not changed from last year. For certain assets a pre-tax discount rate could be
outside this range, mainly due to special tax elements (for example permanent
differences) affecting the pre-tax equivalent. See note 2 Significant
accounting policiesfor further
information regarding impairment on property, plant and equipment.  (in NOK
  billion)
 Impairment method
 Carrying amount before impairment
 Carrying amount after impairment
 Net impairment lossAt 31 December 2015Development and
  Production Norway
 VIU
 14.5
 11.0
 3.5Development and
  Production International
 VIU
 219.5
 171.2
 48.3Marketing, Midstream and
  Processing
 VIU
 5.2
 8.7
 (3.5)Development and
  Production Norway
 FVLCOD
 22.9
 17.7
 5.2Development and
  Production International
 FVLCOD
 4.2
 0.0
 4.2Marketing, Midstream and
  Processing
 FVLCOD
 0.0
 0.0
 0.0Total
 
 266.3
 208.6
 57.7At 31 December 2014Development and Production
  Norway
 VIU
 5.2
 2.9
 2.3Development and
  Production International
 VIU
 187.9
 168.4
 19.5Marketing, Midstream and
  Processing
 VIU
 8.8
 7.9
 0.9Development and
  Production Norway
 FVLCOD
 18.3
 18.3
 0.0Development and
  Production International
 FVLCOD
 25.4
 15.4
 10.0Marketing, Midstream and
  Processing
 FVLCOD
 0.0
 0.0
 0.0Total
 
 245.6
 212.9
 32.7
  During 2015 net impairment losses of NOK 57.7 billion were
recognised, on producing and development assets and goodwill, primarily due to
declining commodity price forecasts (primarily oil). The recoverable amount of
assets tested for impairment was mainly based on VIU estimates on the basis of
internal forecasts on costs, production profiles and commodity prices. For
short term commodity prices, observed forward oil and gas price curves for the
first two to three yearshave
been used. Long term commodity price forecasts are based on internal price
forecasts. The FVLCOD have partly been established through comparisons with
observed market transactions and bids, and partly through internally prepared
net present value estimates using assumed market participant assumptions.
During 2014 impairment losses of NOK 32.7 billion were recognised on producing
and development assets and goodwill.  Development and Production
Norway (DPN) In the DPN segment net
impairment losses of NOK 8.7 billion were recognised in 2015, which were mainly
related to conventional offshore assets in the development phase. The net
impairment losses were triggered by reduction in commodity price reductions and
project delays. In 2014 impairment losses of NOK 2.3 billion were recognised.  Development and Production
International (DPI) In the DPI segment net impairment
losses of NOK 52.5 billion were recognised in 2015 of which NOK 28.3 billion
related to unconventional onshore assets in USA, including NOK 4.2 billion of
goodwill allocated to these assets. NOK 24.1 billion related to other
conventional assets which were not considered significant on an individual cash
generating unit level. Impairment losses of NOK 42.7 billion were recognised asDepreciation,
amortisation and net impairment lossesand NOK 9.8 billion asExploration expenses, based on the impaired asset’s nature.In 2014 impairment losses
of NOK 29.5 billion were recognised.  The net impairment losses
related to the unconventional onshore assets in North America, were mainly a
result from reduced long term commodity price assumptions partly offset by
operational performance improvements and cost reductions. The net impairment
losses related to other conventional assets were primarily related to reduced
commodity price assumptions, but also included an impairment loss related to an
asset under development in the Gulf of Mexico due to installation damages and a
consequential start-up delay.  Marketing, Midstream and
Processing (MMP) The MMP segment recognised
a net impairment reversal of NOK 3.5 in 2015 mainly related to a refinery. The
reversal of impairment was triggered by increased refinery margins and
operational improvements.In 2014 net impairment losses of NOK 0.9 billion were recognised.    Statoil, Annual Report on Form 20-F
2015189


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Sensitivities Throughout 2015 and
subsequent to year end, commodity prices have continued to be volatile.
Significant downward adjustments of Statoil’s commodity price assumptions would
result in impairment losses on certain producing and development assets in
Statoil’s portfolio. The table below presents an estimate of the carrying
amount of producing and development assets, that would be subject to impairment
assessment if a further decline in commodity price forecasts over the lifetime
of the assets were 20%. The sensitivity has been established on the assumption
that all other factors would remain unchanged.  Carrying amount of producing
  and development assets which would be subject to impairment assessment
  assuming an additional decline in commodity price forecasts of 20%:(in NOK
  billion)
 Development and Production Norway
 Development and Production International
 Marketing, Midstream and Processing
 TotalCarrying amount subject
  to impairment assessment in 2015 (after impairment)1)
 48
 230
 9
 287Sensitivity: commodity
  price decline by 20%2)
 52
 253
 N/A
 305
  1)Relates
to assets subject to impairment assessment under IAS 36. As a result of these
impairment assessments, Statoil recognised a net impairment loss of NOK 57.7
billion and 32.7 billion in 2015 and 2014 respectively, as described above. 2)The
sensitivity which is reflected in this line, relates to the carrying amount of
assets subject to impairment assessment under IAS 36. Exploration and
evaluation assets accounted for under IFRS 6 are not included.  The
information in the table above is for indicative purposes only. A significant
and prolonged decline in commodity prices would affect other assumptions, e.g.
cost level, currency etc. A general decline in commodity price assumptions of
20% would result in mitigating actions by Statoil by optimising the respective
business plans in order to reduce the exposure to changes in the macro
environment. Considering the substantial uncertainties related to other
relevant assumptions that would be triggered by a significant and prolonged
decline in commodity price forecasts, Statoil does not disclose the expected
impairment amount.  12 Intangible assets  (in NOK
  billion)
 Exploration expenses
 Acquisition costs - oil and gas prospects
 Goodwill
 Other
 TotalCost at 31 December 2014
 22.9
 53.4
 12.1
 3.4
 91.8Additions
 9.5
 4.5
 0.0
 (0.2)
 13.8Disposals at cost
 (0.5)
 (2.3)
 (0.1)
 (0.2)
 (3.0)Transfers
 (0.7)
 (2.0)
 0.0
 (0.0)
 (2.7)Expensed exploration
  expenditures previously capitalised
 (1.7)
 (15.4)
 0.0
 0.0
 (17.1)Effect of changes in
  foreign exchange
 3.1
 7.7
 1.7
 0.5
 13.0Cost at 31 December 2015
 32.6
 45.9
 13.8
 3.6
 95.8Accumulated depreciation
  and impairment losses at 31 December 2014
 
 
 (5.2)
 (1.4)
 (6.6)Amortisation and
  impairments for the year
 
 
 (4.2)
 (0.0)
 (4.2)Effect of changes in
  foreign exchange
 
 
 (1.5)
 (0.2)
 (1.8)Accumulated depreciation
  and impairment losses at 31 December 2015
 
 
 (10.9)
 (1.6)
 (12.5)Carrying amount at 31
  December 2015
 32.6
 45.9
 2.8
 2.0
 83.3
 190Statoil, Annual Report on Form 20-F 2015


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(in NOK billion)
 Exploration expenses
 Acquisition costs - oil and gas prospects
 Goodwill
 Other
 TotalCost at 31 December 2013
 20.3
 58.6
 10.5
 3.1
 92.4Additions
 7.1
 1.5
 0.0
 (0.0)
 8.7Disposals at cost
 (0.9)
 (0.7)
 (0.0)
 (0.3)
 (1.8)Transfers
 (4.1)
 (5.5)
 0.0
 0.0
 (9.5)Expensed exploration
  expenditures previously capitalised
 (2.7)
 (11.1)
 0.0
 0.0
 (13.7)Effect of changes in
  foreign exchange
 3.1
 10.5
 1.7
 0.6
 15.7Cost at 31 December 2014
 22.9
 53.4
 12.1
 3.4
 91.8Accumulated depreciation
  and impairment losses at 31 December 2013
 
 
 0.0
 (0.9)
 (0.9)Amortisation and
  impairments for the year
 
 
 (4.2)
 (0.3)
 (4.5)Effect of changes in
  foreign exchange
 
 
 (1.0)
 (0.2)
 (1.2)Accumulated depreciation
  and impairment losses at 31 December 2014
 
 
 (5.2)
 (1.4)
 (6.6)Carrying amount at 31
  December 2014
 22.9
 53.4
 6.9
 2.0
 85.2
  The useful
lives of intangible assets are assessed to be either finite or indefinite.
Intangible assets with finite useful lives are amortised systematically over
their estimated economic lives, ranging between 10-20 years. During 2015, intangible
assets were impacted by impairments of acquisition costs related to exploration
activities of NOK 5.6 billion primarily as a result from dry wells and uncommercial
discoveries in Angola and the Gulf of Mexico. Additionally, Statoil recognised
impairments of NOK 9.8 billion primarily related to unconventional onshore
assets in USA and goodwill related to US onshore assets of NOK 4.2 billion. Impairment losses and reversals of impairment
losses are presented as Exploration expenses and Depreciation,
amortisation and net impairment losseson the basis
of their nature as exploration assets (intangible assets) and other intangible
assets, respectively. The impairment losses and reversal of impairment losses
are based on recoverable amount estimates triggered by changes in reserve
estimates, cost estimates and market conditions. See note 11 Property,
plant and equipment for more information on the basis for
impairment assessments.  The table below shows
  the aging of capitalised exploration expenditures.(in NOK
  billion)
 2015
 2014Less than one year
 12.8
 9.2Between one and five
  years
 16.9
 11.4More than five years
 2.9
 2.3Total
 32.6
 22.9
  The table below shows
  the components of the exploration expenses.Full year(in NOK
  billion)
 2015
 2014
 2013Exploration expenditures
 23.1
 23.9
 21.8Expensed exploration
  expenditures previously capitalised
 17.1
 13.7
 3.1Capitalised exploration
 (9.2)
 (7.3)
 (6.9)Exploration expenses
 31.0
 30.3
 18.0
  Statoil, Annual Report on Form 20-F
2015191


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13
Financial investments and non-current prepayments  Non-current financial
  investmentsAt 31 December(in NOK
  billion)
 2015
 2014Bonds
 12.4
 11.6Listed equity securities
 6.3
 6.6Non-listed equity
  securities
 1.8
 1.4Financial investments
 20.6
 19.6
  Bonds and listed equity securities relate to investment portfolios
which are held by Statoil's captive insurance company and accounted for using
the fair value option. Non-current prepayments
  and financial receivablesAt 31 December(in NOK
  billion)
 2015
 2014Financial receivables
  interest bearing
 6.7
 3.7Prepayments and other non-interest
  bearing receivables
 1.8
 2.0Prepayments and
  financial receivables
 8.5
 5.7
  Financial receivables interest bearing
primarily relate to project financing of equity accounted company and loans to
employees.  Current financial
  investmentsAt 31 December(in NOK
  billion)
 2015
 2014Time deposits
 19.1
 9.8Interest bearing securities
 67.4
 49.4Financial investments
 86.5
 59.2
  At 31 December
2015 currentFinancial investmentsinclude NOK 6.0
billion investment portfolios which are held by Statoil's captive insurance
company and accounted for using the fair value option. The corresponding
balance at 31 December 2014 was NOK 6.0 billion. For information about financial instruments
by category, see note 25Financial instruments: fair value measurement and sensitivity
analysis of market risk.  14 Inventories  At 31 December(in NOK
  billion)
 2015
 2014Crude oil
 10.7
 10.1Petroleum products
 5.1
 6.0Other
 6.3
 7.7Inventories
 22.0
 23.7
  Other inventory consists of natural gas,
spare parts and operational materials, including drilling and well equipment.  The write-down of inventories from cost to
net realisable value amounted to an expense of NOK 3.9 billion and NOK 4.0
billion in 2015 and 2014, respectively.  192Statoil, Annual Report on Form 20-F 2015


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15
Trade and other receivables  At 31 December(in NOK
  billion)
 2015
 2014Trade receivables
 39.3
 57.8Current financial
  receivables
 6.5
 6.9Joint venture
  receivables
 5.1
 8.5Equity accounted
  investments and other related party receivables
 0.5
 0.5Total financial trade
  and other receivables
 51.4
 73.7Non-financial trade and other
  receivables
 7.4
 9.6Trade and other
  receivables
 58.8
 83.3
  For more information about the credit quality
of Statoil's counterparties, see note 5 Financial risk management.
For currency sensitivities, see note 25 Financial instruments: fair value
measurement and sensitivity analysis of market risk.  16 Cash and cash equivalents  At 31 December(in NOK
  billion)
 2015
 2014Cash at bank available
 9.2
 13.5Time deposits
 13.2
 32.5Money market funds
 4.0
 3.6Interest bearing
  securities
 44.8
 30.6Restricted cash,
  including margin deposits
 4.8
 2.9Cash and cash
  equivalents
 76.0
 83.1
  Restricted cash at 31 December 2015 and 2014
includes collateral deposits related to trading activities of NOK 3.6 billion
and NOK 2.0 billion, respectively. Collateral deposits are related to certain
requirements set out by exchanges where Statoil is participating. The terms and
conditions related to these requirements are determined by the respective
exchanges.  17 Shareholders' equity  At 31 December 2015 and 2014, Statoil's share capital of NOK
7,971,617,757.50 comprised 3,188,647,103 shares at a nominal value of NOK 2.50.  Statoil ASA has only one class of shares and all shares have
voting rights. The holders of shares are entitled to receive dividends as and
when declared and are entitled to one vote per share at general meetings of the
company.  Dividends declared and paid per share were
NOK 1.80 for each of the first two quarters of 2015. From and including the
third quarter of 2015, dividend is declared in USD. Interim dividends of USD
0.2201 per share for the third quarter of 2015 were declared in the fourth
quarter of 2015 and have been recognised as a liability in the Consolidated
financial statements. This amount will be paid in the first quarter of 2016.  The board of directors will propose to the
annual general meeting to maintain a dividend of USD 0.2201 per share for the
fourth quarter 2015 and the introduction of a two-year scrip dividend programme
starting from the fourth quarter 2015. The scrip programme will give
shareholders the option to receive quarterly dividends in cash or in newly
issued shares in Statoil, at a 5% discount for the fourth quarter 2015.  In 2014 dividends of NOK 7.20 were paid and NOK
7.00 for 2013.  During 2015 a total of 4,057,902treasury shares were purchased for NOK 0.6 billion and 3,203,968
treasury shares were allocated to employees participating in the share saving
plan. In 2014 a total of 3,381,488 treasury shares were purchased for NOK 0.6
billion and 2,960,972 treasury shares were allocated to employees participating
in the share saving plan. At 31 December 2015 Statoil had 11,009,183treasury shares and at 31
December 2014 10,155,249 treasury shares, all of which are related to Statoil's
share saving plan. For further information, see note 6Remuneration.  Statoil, Annual Report on Form 20-F
2015193


---

18
Finance debt  Capital management The main objectives of Statoil's capital
management policy are to maintain a strong financial position and to ensure
sufficient financial flexibility. One of the key ratios in the assessment of
Statoil's financial robustness is net interest-bearing debt adjusted (ND) to capital
employed adjusted (CE).  At 31 December(in NOK
  billion)
 2015
 2014Net interest-bearing
  debt adjusted (ND)
 129.9
 95.6Capital employed
  adjusted (CE)
 485.0
 476.7Net debt to capital
  employed adjusted (ND/CE)
 26.8%
 20.0%
  ND is defined as Statoil's interest bearing
financial liabilities less cash and cash equivalents and current financial
investments, adjusted for collateral deposits and balances held by Statoil's
captive insurance company (an increase of NOK 9.6 billion and NOK 8.0 billion
for 2015 and 2014, respectively), balances related to the SDFI (a decrease of
NOK 1.9 billion and NOK 1.6 billion for 2015 and 2014, respectively) and
project financing exposure that does not correlate to the underlying exposure
(unchanged and decrease of NOK 0.1 billion for 2015 and 2014, respectively). CE
is defined as Statoil's total equity (including non-controlling interests) and
ND.  Non-current finance debtFinance debt measured at
  amortised costWeighted average interest rates in %1)
 Carrying amount in NOK billion at 31 December
 Fair value in NOK billion at 31 December2)2015
 2014
 2015
 2014
 2015
 2014Unsecured bondsUnited States Dollar
  (USD)
 3.51
 3.50
 182.9
 154.4
 190.5
 165.0Euro (EUR)
 2.28
 3.99
 63.4
 37.6
 66.0
 43.8Great Britain Pound
  (GBP)
 6.08
 6.08
 18.0
 15.9
 23.8
 22.3Norwegian kroner (NOK)
 4.18
 4.18
 3.0
 3.0
 3.3
 3.5Total
 
 
 267.3
 210.9
 283.7
 234.7Unsecured loansJapanese yen (JPY)
 4.30
 4.30
 0.7
 0.6
 0.8
 0.9Secured bank loansUnited States Dollar
  (USD)
 -
 4.20
 -
 0.1
 -
 0.1Norwegian kroner (NOK)
 3.11
 3.11
 0.5
 0.3
 0.5
 0.3Finance lease
  liabilities
 
 
 5.1
 5.4
 5.0
 5.6Total
 
 
 6.3
 6.5
 6.3
 6.9Total finance debt
 
 
 273.6
 217.4
 289.9
 241.6Less current portion
 
 
 9.7
 12.3
 9.7
 12.3Non-current finance debt
 
 
 264.0
 205.1
 280.2
 229.3
  1)Weighted
average interest rates are calculated based on the contractual rates on the
loans per currency at 31 December and do not include the effect of swap
agreements. 2)The
fair value of the non-current financial liabilities is determined using a
discounted cash flow model and is classified at level 2 in the fair value
hierarchy. Interest rates used in the model are derived from the LIBOR and
EURIBOR forward curves and will vary based on the time to maturity for the
non-current financial liabilities. The credit premium used is based on
indicative pricing from external financial institutions.  Unsecured bonds amounting
to NOK 182.9 billion are denominated in USD and unsecured bonds amounting to
NOK 70.1 billion are swapped into USD. Two bonds denominated in EUR amounting
to NOK 14.3 billion are not swapped. The table does not include the effects of 194Statoil, Annual Report on Form 20-F 2015


---

agreements entered into to swap the various currencies
into USD. For further information see note 25 Financial
instruments: fair value measurement and sensitivity analysis of market risk. Substantially all unsecured
bond and unsecured bank loan agreements contain provisions restricting future
pledging of assets to secure borrowings without granting a similar secured
status to the existing bondholders and lenders. The
secured bank loan in NOK has been secured by real estate and land with a total
book value of NOK 0.6 billion.  In 2015 Statoil issued
  the following bonds:Issuance
  date
 Amount in EUR billion
 Interest rate in %
 Maturity date17 February 2015
 1.00
 1.625
 February 203517 February 2015
 1.25
 1.250
 February 202717 February 2015
 1.00
 0.875
 February 202317 February 2015
 0.50
 floating
 August
  2019
  Out of
Statoil's total outstanding unsecured bond portfolio, 48 bond agreements
contain provisions allowing Statoil to call the debt prior to its final
redemption at par or at certain specified premiums if there are changes to the
Norwegian tax laws. The carrying amount of these agreements is NOK 264 billion
at the 31 December 2015 closing exchange rate. For more information about the revolving
credit facility, maturity profile for undiscounted cash flows and interest rate
risk management, see note 5 Financial risk management.  Non-current finance debt
  maturity profileAt 31 December(in NOK
  billion)
 2015
 2014Year 2 and 3
 54.9
 27.3Year 4 and 5
 43.0
 44.2After 5 years
 166.1
 133.5Total repayment of
  non-current finance debt
 264.0
 205.1Weighted average
  maturity (years)
 9
 9Weighted average annual interest
  rate (%)
 3.39
 3.78
 More information regarding finance lease liabilities is provided in note 22Leases.  Current finance debtAt 31 December(in NOK
  billion)
 2015
 2014Collateral liabilities
 10.2
 12.9Non-current finance debt
  due within one year
 9.7
 12.3Other including bank overdraft
 0.6
 1.3Total current finance
  debt
 20.5
 26.5Weighted average
  interest rate (%)
 1.90
 2.12
  Collateral liabilities relate mainly to cash
received as security for a portion of Statoil's credit exposure.  19 Pensions  The Norwegian
companies in the group are subject to the requirements of the Mandatory Company
Pensions Act, and the company's pension scheme follows the requirements of the
Act. Statoil ASA and a number of its subsidiaries have
defined contribution plans. The period's contributions are recognised in the
Consolidated statement of income as pension cost for the period.  Statoil, Annual Report on Form 20-F
2015195


---

In 2014 Statoil
ASA made a decision to change the company’s main pension plan in Norway from a
defined benefit plan to a defined contribution plan. The actual transitioning
to the defined contribution plan took place in 2015. At the same time paid-up policies
for the rights vested in the defined benefit plan were issued.Employees with
less than 15 years of future service before their regular retirement age
retained the existing defined benefit plans. For onshore employees between 37
and 51 years of age and offshore employees between 35 and 49 years of age a
compensation plan has been established. The defined contribution plan in Norway
is managed by an insurance company (Storebrand).  The new pension plans in Statoil ASA includes
unfunded elements. These notional contribution plans are regulated equal to the
return on asset for the main contribution plan and are valued at fair value and
recognised as pension liabilities. See note 2 Significant accounting policies
for more information about the accounting treatment of the notional contribution
plans reported in Statoil ASA.  In addition to
the closed pension plans in Statoil ASA, some of its subsidiaries have defined
benefit plans. The defined benefit plans in Norway are managed and financed
through Statoil Pensjon (Statoil's pension fund - hereafter "Statoil
Pension"). Statoil Pension is an independent pension fund that covers the
employees in Statoil's Norwegian companies. The purpose of Statoil Pension is
to provide retirement and disability pension to members and survivor’s pension
to spouses, registered partners, cohabitants and children. The pension fund's
assets are kept separate from the company's and group companies' assets.
Statoil Pension is supervised by the Financial Supervisory Authority of Norway
("Finanstilsynet") and is licensed to operate as a pension fund. The Norwegian
National Insurance Scheme ("Folketrygden") provides pension payments
(social security) to all retired Norwegian citizens. Such payments are
calculated by references to a base amount ("Grunnbeløpet" or
"G") annually approved by the Norwegian Parliament. Statoil's plan
benefits are generally based on a minimum of 30 years of service and 66% of the
final salary level, including an assumed benefit from the Norwegian National
Insurance Scheme. Due to national
agreements in Norway, Statoil is a member of both the previous agreement-based
early retirement plan (“AFP”) and the AFP scheme applicable from 1 January
2011. Statoil paid a premium for both AFP schemes until 31 December 2015. After
that date, premiums are only due on the latest AFP scheme. The premium in the latest
scheme is calculated on the basis of the employees' income between 1 and 7.1 G.
The premium is payable for all employees until age 62. Pension from the latest
AFP scheme will be paid from the AFP plan administrator to employees for their
full lifetime. Statoil has determined that its obligations under this
multi-employer defined benefit plan can be estimated with sufficient
reliability for recognition purposes. Accordingly, the estimated proportionate
share of the latest AFP plan has been recognised as a defined benefit
obligation. The present
values of the defined benefit obligation, except for the notional contribution
plan, and the related current service cost and past service cost are measured
using the projected unit credit method. The assumptions for salary increases,
increases in pension payments and social security base amount are based on
agreed regulation in the plans, historical observations, future expectations of
the assumptions and the relationship between these assumptions. At 31 December
2015 the discount rate for the defined benefit plans in Norway was established
on the basis of seven years' mortgage covered bonds interest rate extrapolated
on a yield curve which matches the duration of Statoil's payment portfolio for
earned benefits. Social security
tax is calculated based on a pension plan's net funded status and is included
in the defined benefit obligation. Statoil has more than one
defined benefit plan, but the disclosure is made in total since the plans are
not subject to materially different risks. Pension plans outside Norway are not
material and as such not disclosed separately.  Net pension cost(in NOK
  billion)
 2015
 2014
 2013Current service cost
 3.0
 4.7
 4.0Interest cost
 1.5
 3.1
 2.5Interest (income) on
  plan asset
 (1.2)
 (2.6)
 (2.1)Losses (gains) from
  curtailment, settlement or plan amendment
 2.0
 (1.9)
 0.01)Actuarial (gains) losses
  related to termination benefits
 (0.0)
 (0.2)
 0.0Notional contributions
 0.3
 0.0
 0.0Defined benefit plans
 5.7
 3.2
 4.4Defined contribution
  plans
 1.1
 0.2
 0.2Total net pension cost
 6.8
 3.4
 4.6
  196Statoil, Annual Report on Form 20-F 2015


---

1)In 2015 and 2014
Statoil ASA offered early retirement (termination benefits) to a defined group
of employees above the age of 58 years. The expenses of NOK 1.4 billion and NOK
1.6 billion respectively were recognised in the Consolidated statement of
income. In addition, a plan amendment effect related to the changed pension
scheme in Norway resulted in a recognition in the Consolidated statement of
income of a loss of NOK 0.6 billion in 2015 and a gain of NOK 3.5 billion in
2014. The plan amendment effect was recalculated in 2015 due to actual
transitioning from a defined benefit to a defined contribution plan took place
in 2015 and all information was not available when calculating the effect in
2014.  Pension cost
includes associated social security tax and is partly charged to partners of Statoil
operated licences. Statoil, Annual Report on Form 20-F
2015197


---

(in NOK billion)
 2015
 2014Defined benefit
  obligations (DBO)Defined benefit
  obligations at 1 January
 65.0
 79.4Current service cost
 3.0
 4.7Interest cost
 1.5
 3.1Actuarial (gains) losses
  - Demographic assumptions
 0.0
 (0.1)Actuarial (gains) losses
  - Financial assumptions
 (6.0)
 4.8Actuarial (gains) losses
  - Experience
 (3.1)
 (2.1)Benefits paid
 (1.9)
 (2.0)Losses (gains) from
  curtailment, settlement or plan amendment1)
 2.2
 (2.9)Paid-up policies
 (1.2)
 (20.4)Foreign currency
  translation
 0.3
 0.3Changes in notional
  contribution liability
 0.3
 0.0Defined benefit
  obligations at 31 December
 60.1
 65.0Fair value of plan
  assetsFair value of plan
  assets at 1 January
 45.1
 62.3Interest income
 1.2
 2.6Return on plan assets
  (excluding interest income)
 0.6
 0.9Company contributions
 0.3
 0.1Benefits paid
 (0.6)
 (0.7)Paid-up policies and
  personal insurance
 (1.7)
 (20.4)Foreign currency
  translation
 0.3
 0.3Fair value of plan
  assets at 31 December
 45.2
 45.1Net pension liability at
  31 December
 (14.9)
 (19.9)Represented by:Asset recognised as
  non-current pension assets (funded plan)
 11.3
 8.0Liability recognised as
  non-current pension liabilities (unfunded plans)
 (26.2)
 (27.9)DBO specified by funded
  and unfunded pension plans
 60.1
 65.0Funded
 33.9
 37.2Unfunded
 26.2
 27.9Actual return on assets
 1.8
 3.5
  1)A loss of NOK 0.1
billion in 2015 and a gain of NOK 0.9 billion in 2014, related to the plan
amendment, has been recognised againstProperty, plant and
equipment.  As part of the
change of Statoil ASA’s main pension plan in Norway the estimated assets
related to paid-up policies and personal insurance (new disability pension and
children pension from 2015) and liabilities related to paid-up policies have
been excluded from the amounts in the table above.  Actuarial losses and
  gains recognised directly in Other comprehensive income (OCI)(in NOK
  billion)
 2015
 2014
 2013Net actuarial (losses)
  gains recognised in OCI during the year
 9.7
 0.2
 (5.5)Actuarial (losses) gains
  related to currency effects on net obligation and foreign exchange
  translation
 0.4
 (0.2)
 (0.4)Tax effects of actuarial
  (losses) gains recognised in OCI
 (2.8)
 0.9
 1.2Recognised directly in
  OCI during the year net of tax
 7.3
 0.9
 (4.7)Cumulative actuarial
  (losses) gains recognised directly in OCI net of tax
 (7.2)
 (14.5)
 (15.4)
  198Statoil, Annual Report on Form 20-F 2015


---

The net
actuarial gain in 2015 is mainly related to an updated assessment of the
discount rate and expected rate of pension increase to be used for pension
obligations in Norway.  The line item net actuarial (losses) gains
recognised in OCI during the year in 2014 includes actuarial loss charged to
partners of Statoil operated licences.  The line item actuarial (losses) gains
related to currency effects on net obligation and foreign exchange translation
includes the translation of the net pension obligation in NOK to the functional
currency USD for the parent company, Statoil ASA, and the translation of the
net pension obligation from the functional currency USD to Statoil's
presentation currency NOK.  Actuarial assumptionsAssumptions used to determine benefit costs in %
 Assumptions used to determine benefit obligations in %2015
 2014
 2015
 2014Discount rate
 2.50
 4.00
 2.75
 2.50Rate of compensation
  increase
 2.25
 3.50
 2.25
 2.25Expected rate of pension
  increase
 1.50
 2.50
 1.00
 1.50Expected increase of
  social security base amount (G-amount)
 2.25
 3.25
 2.25
 2.25Weighted-average
  duration of the defined benefit obligation
 
 
 17.1
 19.1
  The assumptions
presented are for the Norwegian companies in Statoil which are members of
Statoil's pension fund. The defined benefit plans of other subsidiaries are
immaterial to the consolidated pension assets and liabilities. Expected
attrition at 31 December 2015 was 0.4% and 0.1% for employees between 50-59
years and 60-67 years, respectively. Expected attrition at 31 December 2014 was
2.1%, 2.2%, 1.3%, 0.5% and 0.2% for the employees under 30 years, 30-39 years,
40-49 years, 50-59 years and 60-67 years, respectively. For population
in Norway, the mortality table K2013, issued by The Financial Supervisory
Authority of Norway, is used as the best mortality estimate. Disability
tables for plans in Norway developed by the actuary were implemented in 2013
and represent the best estimate to use for plans in Norway. Sensitivity
analysis The table below presents an estimate of the
potential effects of changes in the key assumptions for the defined benefit
plans. The following estimates are based on facts and circumstances as of 31
December 2015. Actual results may materially deviate from these estimates.  Discount rate
 Expected rate of compensation increase
 Expected rate of pension increase
 Mortality assumption(in NOK
  billion)
 0.50%
 -0.50%
 0.50%
 -0.50%
 0.50%
 -0.50%
 + 1 year
 - 1 yearChanges in:Defined benefit
  obligation at 31 December 2015
 (4.3)
 5.0
 1.1
 (1.0)
 3.5
 (3.1)
 2.0
 (2.2)Service cost 2016
 (0.2)
 0.2
 0.1
 (0.0)
 0.1
 (0.1)
 0.1
 (0.1)
  The sensitivity
of the financial results to each of the key assumptions has been estimated
based on the assumption that all other factors would remain unchanged. The
estimated effects on the financial result would differ from those that would
actually appear in the Consolidated financial statements because the
Consolidated financial statements would also reflect the relationship between
these assumptions.   Statoil, Annual Report on Form 20-F
2015199


---

Pension assets The plan assets
related to the defined benefit plans were measured at fair value. Statoil
Pension invests in both financial assets and real estate. Real estate
properties owned by Statoil Pension amounted to NOK 3.4 billion and NOK 3.2
billion of total pension assets at 31 December 2015 and 2014, respectively, and
are rented to Statoil companies. The table below presents the portfolio
weighting as approved by the board of Statoil Pension for 2015. The portfolio
weight during a year will depend on the risk capacity.  Pension assets on investments classes
 Target portfolio weight(in %)
 2015
 2014Equity securities
 38.3
 40.1
 31 - 43Bonds
 40.3
 38.7
 36 - 48Money market instruments
 14.9
 13.4
 0 - 29Real estate
 5.0
 4.8
 5 - 10Other assets
 1.5
 3.0Total
 100.0
 100.0
  In 2015 100% of
the equity securities, 38% of bonds and 100% of money market instruments had
quoted market prices in an active market (level 1). In 2014 100% of the equity
securities, 38% of bonds and 86% of money market instruments had quoted market
prices in an active market. Statoil does not have any equity securities, bonds
or money market instruments classified in level 3. Real Estate is classified as
level 3. For definition of the various levels, see note 25Financial instruments: fair value measurement and sensitivity
analysis of market risk. No company contribution is expected to be
paid to Statoil Pension in 2016.  20 Provisions  (in NOK
  billion)
 Asset retirement obligations
 Claims and litigations
 Other
  provisions
 TotalNon-current portion at
  31 December 2014
 107.4
 3.5
 6.3
 117.2Current portion at 31
  December 2014 reported as trade and other payables
 1.4
 13.6
 2.1
 17.0Provisions at 31
  December 2014
 108.8
 17.1
 8.4
 134.2New or increased provisions
 4.2
 6.1
 4.4
 14.8Decrease in the
  estimates
 (16.2)
 (2.2)
 (3.3)
 (21.7)Amounts charged against
  provisions
 (2.2)
 (4.6)
 (0.9)
 (7.7)Effects of change in the
  discount rate
 (6.8)
 0.0
 (0.1)
 (7.0)Reduction due to
  divestments
 (1.0)
 0.0
 (0.1)
 (1.1)Accretion expenses
 3.9
 0.0
 0.0
 3.9Reclassification and
  transfer
 (0.6)
 0.0
 (0.3)
 (0.8)Currency translation
 4.8
 2.7
 0.9
 8.4Provisions at 31
  December 2015
 95.0
 19.1
 9.0
 123.0Current portion at 31
  December 2015 reported as trade and other payables
 1.3
 9.2
 2.8
 13.4Long term interest
  bearing provisions at 31 December 2015 reported as finance debt
 0.0
 0.0
 0.2
 0.2Non-current portion at
  31 December 2015
 93.7
 9.8
 6.0
 109.4
 200Statoil, Annual Report on Form 20-F 2015


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Expected timing of cash outflows(in NOK
  billion)
 Asset retirement obligations
 Other
  provisions, including claims and litigations
 Total2016 - 2020
 12.2
 24.7
 36.92021 - 2025
 16.9
 0.8
 17.72026 - 2030
 16.1
 0.2
 16.32031 - 2035
 25.5
 0.7
 26.3Thereafter
 24.2
 1.6
 25.8At 31 December 2015
 95.0
 28.1
 123.0
  Statoil’s
estimated asset retirement obligations (ARO) have reduced mainly due to a
reduction in cost estimates for plugging and abandonment. Changes in ARO are
reflected withinProperty, plant and
equipmentandProvisionsin the
Consolidated balance sheet. The timing of cash outflows related to ARO
primarily depends on when the production ceases at the various facilities. The claims and
litigations category mainly relates to expected payments on unresolved claims.
The timing and amounts of potential settlements in respect of these are
uncertain and dependent on various factors that are outside management's
control. See also
comments on provisions in note 23Other
commitments, contingent liabilities and contingent assets. The other
provisions category relates to expected payments on onerous contracts,
cancellation fees and other. For further information of methods applied
and estimates required, see note 2 Significant accounting policies.  21 Trade and other payables  At 31 December(in NOK
  billion)
 2015
 2014Trade payables
 18.1
 21.8Non-trade payables and
  accrued expenses
 20.8
 25.2Joint venture payables
 22.8
 28.9Equity accounted
  investments and other related party payables
 5.5
 6.6Total financial trade
  and other payables
 67.2
 82.5Current portion of
  provisions and other payables
 15.0
 18.1Trade and other payables
 82.2
 100.7
  Included in current portion of provisions and
other payables are certain provisions that are further described in note 23 Other
commitments, contingent liabilities and contingent assets. For
information regarding currency sensitivities, see note 25 Financial
instruments: fair value measurement and sensitivity analysis of market risk.
For further information on payables to equity accounted investments and other
related parties, see note 24 Related parties.  Statoil, Annual Report on Form 20-F
2015201


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22
Leases  Statoil leases
certain assets, notably drilling rigs, vessels and office buildings. In 2015, net
rental expenditures were NOK 27.7 billion (NOK 22.9 billion in 2014 and NOK
17.4 billion in 2013) consisting of minimum lease payments of NOK 32.6 billion
(NOK 28.4 billion in 2014 and NOK 21.2 billion in 2013) reduced with sublease
payments received of NOK 4.9 billion (NOK 5.5 billion in 2014 and NOK 3.8
billion in 2013). Net rental expenditures in 2015 include rig cancellation
payments of NOK 1.6 billion. No material contingent rent payments have been
expensed in 2015, 2014 or 2013. The information in the table below shows
future minimum lease payments due and receivable under non-cancellable operating
leases at 31 December 2015:  Operating leases(in NOK
  billion)
 Rigs
 Vessels
 Other
 Total
 Sublease
 Net total2016
 18.2
 5.0
 2.4
 25.6
 (2.6)
 23.02017
 11.1
 3.8
 1.8
 16.7
 (0.9)
 15.82018
 7.3
 3.2
 1.6
 12.1
 (0.7)
 11.32019
 6.1
 2.5
 1.3
 9.9
 (0.7)
 9.22020
 4.2
 2.2
 1.3
 7.8
 (0.7)
 7.0Thereafter
 9.0
 6.6
 12.2
 27.8
 (1.4)
 26.4Total future minimum
  lease payments
 55.9
 23.3
 20.6
 99.8
 (7.1)
 92.7
  Statoil had
certain operating lease contracts for drilling rigs at 31 December 2015. The
remaining significant contracts' terms range from one month to eight years. Certain
contracts contain renewal options. Rig lease agreements are for the most part
based on fixed day rates.Certain rigs have been subleased in whole or for part of the
lease term mainly to Statoil operated licenses on the Norwegian continental
shelf. These leases are shown gross as operating leases in the table above. Statoil has a
long-term time charter agreement with Teekay for offshore loading and
transportation in the North Sea. The contract covers the lifetime of applicable
producing fields and at year end 2015 includes three crude tankers. The
contract's estimated nominal amount was approximately NOK 7.0 billion at year
end 2015, and it is included in the category vessels in the table above. The category other
includes future minimum lease payments to related parties of NOK 4.3 billion regarding
the lease of one office building located in Bergen and owned by Statoil`s
pension fund (“Statoil Pension”). These operating lease commitments extend to
the year 2034. NOK 3.2 billion of the total is payable after 2020. Statoil had finance lease liabilities of NOK
4.9 billion at 31 December 2015. The nominal minimum lease payments related to
these finance leases amount to NOK 6.5 billion. Property, plant and equipmentincludes NOK 6.8 billion for finance leases that have been capitalised at
year end (NOK 5.7 billion in 2014), mainly presented in the category machinery,
equipment and transportation equipment, including vessels in note 11 Property,
plant and equipment.  23 Other commitments, contingent liabilities
and contingent assets  Contractual commitments Statoil had contractual commitments of NOK
62.3 billion at 31 December 2015. The contractual commitments reflect Statoil's
share and mainly comprise construction and acquisition of property, plant and
equipment.  As a condition
for being awarded oil and gas exploration and production licences, participants
may be committed to drill a certain number of wells. At the end of 2015,
Statoil was committed to participate in 32 offshore wells, with an average
ownership interest of approximately 33%. Statoil's share of estimated
expenditures to drill these wells amounts to NOK 7.7 billion. Additional wells
that Statoil may become committed to participating in depending on future
discoveries in certain licences are not included in these numbers. Other long-term
commitments Statoil has
entered into various long-term agreements for pipeline transportation as well
as terminal use, processing, storage and entry/exit capacity commitments and
commitments related to specific purchase agreements. The agreements ensure the
rights to the capacity or volumes in question, but also impose on Statoil the
obligation to pay for the agreed-upon service or commodity, irrespective of
actual use. The contracts' terms vary, with durations of up to 30 years. Take-or-pay
contracts for the purchase of commodity quantities are only included in the
table below if their contractually agreed pricing is of a nature that will or
may deviate from the obtainable market prices for the commodity at the time of
delivery. 202Statoil, Annual Report on Form 20-F 2015


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Obligations payable by Statoil to entities accounted for as
associates and joint ventures are included gross in the table below.
Obligations payable by Statoil to entities accounted for as joint operations
(for example pipelines) are included net (i.e. gross commitment less Statoil’s
ownership share). Nominal minimum other long-term commitments
at 31 December 2015:  (in NOK
  billion)2016
 13.52017
 12.82018
 11.82019
 12.22020
 10.9Thereafter
 77.9Total
 139.1
  Of the reported other long-term commitments, NOK 17.5 billion
relates to pipeline commitments where the construction of these pipelines is
pending governmental approval.  Contingent liabilities and contingent assets During the annual audits
of Statoil's participation in Block 4, Block 15, Block 17 and Block 31 offshore
Angola, the Angolan Ministry of Finance has assessed additional profit oil and
taxes due on the basis of activities that currently include the years 2002 up
to and including 2012. Statoil disputes the assessments and is pursuing these
matters in accordance with relevant Angolan legal and administrative
procedures. On the basis of the assessments and continued activity on the four
blocks up to and including 2015, the exposure for Statoil at year end 2015 is
estimated to NOK 11.6 billion (USD 1.3 billion), the most significant part of
which relates to profit oil elements. Statoil has provided in the Consolidated
financial statements for its best estimate related to the assessments,
reflected in the Consolidated statement of income mainly as a revenue
reduction, with additional amounts reflected as interest expenses and tax
expenses, respectively. Through its ownership in OML 128 in Nigeria, Statoil is party to
an ownership interest redetermination process for the Agbami field. In October
2015, Statoil received the Expert’s final ruling which implies a reduction of
5.17percentage pointsin Statoil’s equity interest in the field. Statoil had previously
initiated arbitration proceedings to set aside interim decisions made by the
Expert, but this was declined by the arbitration tribunal in its November 2015
judgment. Statoil has initiated proceedings before the Federal High Court in
Lagos to set aside the arbitration award and also intends to initiate a new
arbitration to set aside the Expert’s final ruling. As of 31 December 2015,Statoil has recognised a
provision of NOK 9.5 billion (USD 1.1 billion), net of tax, which reflects a
reduction of 5.17percentage pointsin Statoil’s equity interest in the Agbami field. The provision
is reflected within Provisions
in the Consolidated balance sheet.  Some long-term gas sales agreements contain price review clauses.
Certain counterparties have requested arbitration in connection with price
review claims. The related exposure for Statoil has been estimated to an amount
equivalent to approximately NOK 3.6 billion for gas delivered prior to year end
2015. Statoil has provided for its best estimate related to these contractual
gas price disputes in the Consolidated financial statements, with the impact to
the Consolidated statement of income reflected as revenue adjustments.  There is a dispute between the Nigerian National Petroleum
Corporation (NNPC) and the partners (Contractor) in Oil Mining Lease (OML) 128
of the unitised Agbami field concerning interpretation of the terms of the OML
128 Production Sharing Contract (PSC). The dispute relates to the allocation
between NNPC and Contractor of cost oil, tax oil and profit oil volumes. NNPC
has claimed that since the start of production from Agbami, Contractor has lifted
excess volumes compared to the PSC terms, and consequently NNPC has increased
its lifting of oil. The Contractor disputed NNPC's position and initiated
arbitration in the matter in accordance with the terms of the PSC. In 2015 the
Arbitral Tribunal ruled in favour of Contractor’s interpretation of the PSC on
the main points. The Contractor is currently proceeding to enforce the
favourable decision by the means available in the Nigerian legal system, while
NNPC on its hand has initiated litigation concerning certain objections to the
arbitration award. The Nigerian Federal Inland Revenue Service is also
contesting the legality of the arbitration process as far as resolving tax
related disputes goes, and is actively pursuing this view through the channels
of the Nigerian legal system. Statoil’s stake in the dispute at year end 2015
is mainly related to oil volumes previously lifted by NNPC contrary to the PSC
terms. NNPC has so far kept on its overlifting contrary to the award. Following
the arbitration award, Statoil’s previous provision related to NNPC’s claim has
been reversed with the effect mainly reflected as revenue in the Consolidated
statement of income.  In 2014, following a regular review process of Statoil’s 2012
Consolidated financial statements, the Financial Supervisory Authority of
Norway (the FSA) ordered Statoil to:”Change its future accounting practices for redetermination of CGUs
containing onerous contracts. Correct the described error by establishing a
separate onerous contract provision for the Cove Point capacity contract in a
financial period prior to Q1 2013. The correction shall be presented in the
next periodic financial report. Information about the circumstances shall be
given in notes to the accounts.”Statoil appealed the order and has been granted a stay in
carrying out the FSA’s order pending the final outcome of the appeal. The
appeal is currently being assessed by the Norwegian Ministry of Finance and not
yet concluded. If the outcome of the appeal would require implementing the
FSA’s order, a provision would be recognised againstNet operating incomein an earlier reporting period than 2013. As the contracts were
fully provided for in 2013, there would be no impact on equity at 31 December
2013 or thereafter. The actual amount to be provided in an earlier period would
depend on the period in which the provision would be recorded. The FSA order
does not specify which period prior to the first quarter 2013 would be relevant
for the provision to be recognised. Statoil’s reading is that 2011 would be
most relevant. Statoil, Annual Report on Form 20-F
2015203


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There would be no impact on the 2015
and 2014 financial statements, however, the comparative amounts included
therein for 2013Net operating incomeandNet incomewould be NOK 5.6 billion and NOK 5.0 billion higher,
respectively.  During the normal course
of its business, Statoil is involved in legal proceedings, and several other
unresolved claims are currently outstanding. The ultimate liability or asset,
in respect of such litigation and claims cannot be determined at this time.
Statoil has provided in its Consolidated financial statements for probable
liabilities related to litigation and claims based on its best estimate.
Statoil does not expect that its financial position, results of operations or
cash flows will be materially affected by the resolution of these legal
proceedings. Statoil is actively
pursuing the above disputes through the contractual and legal means available
in each case, but the timing of the ultimate resolutions and related cash
flows, if any, cannot at present be determined with sufficient reliability. Provisions related to claims are reflected within note 20 Provisions.  24 Related parties  Transactions with
the Norwegian State The Norwegian
State is the majority shareholder of Statoil and also holds major investments
in other Norwegian companies. As of 31 December 2015 the Norwegian State had an
ownership interest in Statoil of 67.0% (excluding Folketrygdfondet, the Norwegian
national insurance fund, of 3.2%). This ownership structure means that Statoil
participates in transactions with many parties that are under a common
ownership structure and therefore meet the definition of a related party. All
transactions are considered to be on an arm's length basis. Total purchases
of oil and natural gas liquids from the Norwegian State amounted to NOK 60.0
billion, NOK 86.4 billion and NOK 92.5 billion in 2015, 2014 and 2013,
respectively. Total purchases of natural gas regarding the Tjeldbergodden
methanol plant from the Norwegian State amounted to NOK 0.6 billion, NOK 0.5
billion and NOK 0.5 billion in 2015, 2014 and 2013, respectively. In addition,
Statoil ASA sells in its own name, but for the Norwegian State’s account and
risk, the Norwegian State’s gas production. These transactions are presented
net. For further information please see note 2Significant accounting policies. The most significant
items included in the line item equity accounted investments and other related
party payables in note 21Trade and other payables, are amounts
payable to the Norwegian State for these purchases. Other
transactions In relation to
its ordinary business operations Statoil enters into contracts such as pipeline
transport, gas storage and processing of petroleum products, with companies in which
Statoil has ownership interests. Such transactions are carried out on an arm's
length basis and are included within the applicable captions in the
Consolidated statement of income. Gassled and certain other infrastructure
assets are operated by Gassco AS, which is an entity under common control by
the Norwegian Ministry of Petroleum and Energy. Gassco’s activities are
performed on behalf of and for the risk and reward of pipeline and terminal
owners, and capacity payments flow through Gassco to the respective owners.
Statoil payments that flowed through Gassco in this respect amounted to NOK 7.2
billion, NOK 7.4 billion and NOK 7.3 billion in 2015, 2014 and 2013,
respectively. For information
concerning certain lease arrangements with Statoil Pension, see note 22Leases. Related party transactions with management
are presented in note 6 Remuneration.Management
remuneration for 2015 is presented in note 5 Remunerationin
the financial statements of the parent company, Statoil ASA.  204Statoil, Annual Report on Form 20-F 2015


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25
Financialinstruments: fair value measurement and sensitivity
analysis of market risk  Financial instruments by
category The following tables
present Statoil's classes of financial instruments and their carrying amounts
by the categories as they are defined in IAS 39Financial Instruments: Recognition and Measurement. All financial
instruments' carrying amounts are measured at fair value or their carrying
amounts reasonably approximate fair value except non-current financial
liabilities.See
note 18Finance debtfor
fair value information of non-current bonds, bank loans and finance lease liabilities. See note 2 Significant accounting policies for further
information regarding measurement of fair values.  Fair value through profit or loss(in NOK
  billion)
 Note
 Loans and receivables
 Available for sale
 Held for trading
 Fair value option
 Non-financial assets
 Total carrying amountAt 31 December 2015AssetsNon-current derivative financial
  instruments
 
 0.0
 0.0
 23.8
 0.0
 0.0
 23.8Non-current financial
  investments
 13
 0.0
 1.8
 0.0
 18.7
 0.0
 20.6Prepayments and
  financial receivables
 13
 5.8
 0.0
 0.0
 0.0
 2.8
 8.5Trade and other
  receivables
 15
 51.4
 0.0
 0.0
 0.0
 7.4
 58.8Current derivative
  financial instruments
 
 0.0
 0.0
 4.8
 0.0
 0.0
 4.8Current financial
  investments
 13
 19.1
 0.0
 61.4
 6.0
 0.0
 86.5Cash and cash
  equivalents
 16
 27.1
 0.0
 48.8
 0.0
 0.0
 76.0Total
 
 103.4
 1.9
 138.8
 24.7
 10.1
 278.8Fair value through profit or loss(in NOK
  billion)
 Note
 Loans and receivables
 Available for sale
 Held for trading
 Fair value option
 Non-financial assets
 Total carrying amountAt 31 December 2014AssetsNon-current derivative
  financial instruments
 
 0.0
 0.0
 29.9
 0.0
 0.0
 29.9Non-current financial
  investments
 13
 0.0
 1.4
 0.0
 18.2
 0.0
 19.6Prepayments and
  financial receivables
 13
 2.7
 0.0
 0.0
 0.0
 2.9
 5.7Trade and other
  receivables
 15
 73.7
 0.0
 0.0
 0.0
 9.6
 83.3Current derivative
  financial instruments
 
 0.0
 0.0
 5.3
 0.0
 0.0
 5.3Current financial
  investments
 13
 9.8
 0.0
 43.4
 6.0
 0.0
 59.2Cash and cash
  equivalents
 16
 48.9
 0.0
 34.2
 0.0
 0.0
 83.1Total
 
 135.2
 1.4
 112.8
 24.2
 12.6
 286.2
 Statoil, Annual Report on Form 20-F
2015205


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(in NOK billion)
 Note
 Amortised cost
 Fair value through profit or loss
 Non-financial liabilities
 Total carrying amountAt 31 December 2015LiabilitiesNon-current finance debt
 18
 264.0
 0.0
 0.0
 264.0Non-current derivative
  financial instruments
 
 0.0
 11.3
 0.0
 11.3Trade and other payables
 21
 66.8
 0.0
 15.4
 82.2Current finance debt
 18
 20.5
 0.0
 0.0
 20.5Dividend payable
 
 6.2
 0.0
 0.0
 6.2Current derivative
  financial instruments
 
 0.0
 2.3
 0.0
 2.3Total
 
 357.5
 13.6
 15.4
 386.5(in NOK
  billion)
 Note
 Amortised cost
 Fair value through profit or loss
 Non-financial liabilities
 Total carrying amountAt 31 December 2014LiabilitiesNon-current finance debt
 18
 205.1
 0.0
 0.0
 205.1Non-current derivative
  financial instruments
 
 0.0
 4.5
 0.0
 4.5Trade and other payables
 21
 82.5
 0.0
 18.1
 100.7Current finance debt
 18
 26.5
 0.0
 0.0
 26.5Dividend payable
 
 5.7
 0.0
 0.0
 5.7Current derivative
  financial instruments
 
 0.0
 6.6
 0.0
 6.6Total
 
 319.8
 11.1
 18.1
 349.1
  Fair value hierarchy The following table summarises each class of financial instruments
which are recognised in the Consolidated balance sheet at fair value, split by
Statoil's basis for fair value measurement.  (in NOK
  billion)
 Non-current financial investments
 Non-current derivative financial instruments - assets
 Current financial investments
 Current derivative financial instruments - assets
 Cash equivalents
 Non-current derivative financial instruments - liabilities
 Current derivative financial instruments - liabilities
 Net fair valueAt 31 December 2015Level 1
 10.5
 0.0
 4.8
 0.0
 0.0
 0.0
 0.0
 15.3Level 2
 8.2
 15.5
 62.6
 4.3
 48.8
 (10.8)
 (2.3)
 126.3Level 3
 1.8
 8.3
 0.0
 0.4
 0.0
 (0.5)
 0.0
 10.1Total fair value
 20.6
 23.8
 67.4
 4.8
 48.8
 (11.3)
 (2.3)
 151.7At 31 December 2014Level 1
 11.1
 0.0
 4.0
 0.0
 0.0
 0.0
 0.0
 15.1Level 2
 7.0
 17.2
 45.5
 4.7
 34.2
 (4.5)
 (6.6)
 97.4Level 3
 1.4
 12.7
 0.0
 0.6
 0.0
 0.0
 (0.0)
 14.7Total fair value
 19.6
 29.9
 49.4
 5.3
 34.2
 (4.5)
 (6.6)
 127.3
  Level 1, fair value based
on prices quoted in an active market for identical assets or liabilities,
includes financial instruments actively traded and for which the values
recognised in the Consolidated balance sheet are determined based on observable
prices on identical instruments. For Statoil this category will, in most cases,
only be relevant for investments in listed equity securities and government
bonds. Level 2, fair value based
on inputs other than quoted prices included within level 1, which are derived
from observable market transactions, includes Statoil's non-standardised
contracts for which fair values are determined on the basis of price inputs
from observable market 206Statoil, Annual Report on Form 20-F 2015


---

transactions. This will
typically be when Statoil uses forward prices on crude oil, natural gas,
interest rates and foreign exchange rates as inputs to the valuation models to
determining the fair value of its derivative financial instruments. Level 3, fair value based
on unobservable inputs, includes financial instruments for which fair values
are determined on the basis of input and assumptions that are not from
observable market transactions. The fair values presented in this category are
mainly based on internal assumptions. The internal assumptions are only used in
the absence of quoted prices from an active market or other observable price
inputs for the financial instruments subject to the valuation. The fair value of certain
earn-out agreements and embedded derivative contracts are determined by the use
of valuation techniques with price inputs from observable market transactions
as well as internally generated price assumptions and volume profiles. The
discount rate used in the valuation is a risk-free rate based on the applicable
currency and time horizon of the underlying cash flows adjusted for a credit
premium to reflect either Statoil's credit premium, if the value is a
liability, or an estimated counterparty credit premium if the value is an
asset. In addition a risk premium for risk elements not adjusted for in the
cash flow may be included when applicable. The fair values of these derivative
financial instruments have been classified in their entirety in the third
category within current derivative financial instruments and non-current
derivative financial instruments - assets in the table above. Another
reasonable assumption, that could have been applied when determining the fair
value of these contracts, would be to extrapolate the last observed forward
prices with inflation. If Statoil had applied this assumption, the fair value
of the contracts included would have decreased by approximately NOK 4.6 billion
at end of 2015 and decreased by NOK 3.5 billion at end of 2014 and impacted the
Consolidated statement of income with corresponding amounts. The reconciliation of the changes in fair value during 2015 and
2014 for all financial assets classified in the third level in the hierarchy
are presented in the following table.  (in NOK
  billion)
 Non-current financial investments
 Non-current derivative financial instruments - assets
 Current derivative financial instruments - assets
 Non-current derivative financial instruments liabilities
 Total amountFull year 2015Opening balance
 1.4
 12.7
 0.6
 0.0
 14.8Total gains and losses
  recognised- in statement of income
 (0.0)
 (3.6)
 0.4
 (0.5)
 (3.6)- in other comprehensive
  income
 0.0
 0.0
 0.0
 0.0
 0.0Purchases
 0.2
 0.0
 0.0
 0.0
 0.2Settlement
 (0.0)
 (0.9)
 (0.6)
 0.0
 (1.5)Foreign currency
  translation differences
 0.2
 0.1
 (0.0)
 (0.0)
 0.2Closing balance
 1.8
 8.3
 0.4
 (0.5)
 10.1Full year 2014Opening balance
 0.9
 12.0
 1.3
 0.0
 14.2Total gains and losses
  recognised- in statement of income
 (0.0)
 0.3
 0.6
 0.0
 0.9- in other comprehensive
  income
 0.0
 0.0
 0.0
 0.0
 0.0Purchases
 0.3
 0.0
 0.0
 0.0
 0.3Sales
 0.0
 0.4
 0.0
 0.0
 0.4Settlement
 (0.0)
 0.0
 (1.3)
 0.0
 (1.3)Foreign currency
  translation differences
 0.2
 0.1
 (0.0)
 0.0
 0.3Closing balance
 1.4
 12.7
 0.6
 0.0
 14.8
  The assets within level 3 during 2015 have had a net decrease in
the fair value of NOK 4.7 billion. Of the NOK 3.1 billion recognised in the
Consolidated statement of income during 2015, NOK 2.8 billion is related to
changes in fair value of certain earn-out agreements. Related to the same
earn-out agreements, NOK 1.5 billion included in the opening balance for 2015
has been fully realised as the underlying volumes have been delivered during
2015 and the amount is presented as settled in the above table.  Substantially all gains and losses recognised in the Consolidated
statement of income during 2015 are related to assets held at the end of 2015.  Sensitivity analysis of market risk  Commodity price risk The table below contains the fair value and related commodity
price risk sensitivities of Statoil's commodity based derivatives contracts.
For further information related to the type of commodity risks and how Statoil
manages these risks, see note 5 Financial risk management.  Statoil's assets and liabilities resulting from commodity based
derivatives contracts consist of both exchange traded and non-exchange traded
instruments, including embedded derivatives that have been bifurcated and
recognised at fair value in the Consolidated balance sheet. Statoil, Annual Report on Form 20-F
2015207


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Price risk sensitivities at the end of 2015 have been calculated
assuming a reasonably possible change of 30% in crude oil, refined products,
electricity and natural gas prices. At the end of 2014 an assumption of 40% was
used in the calculation and viewed as reasonable possible changes.  Since none of the derivative financial instruments included in the
table below are part of hedging relationships, any changes in the fair value
would be recognised in the Consolidated statement of income.  (in NOK
  billion)
 - 30% sensitivity
 30% sensitivityAt 31 December 2015Crude oil and refined
  products net gains (losses)
 1.0
 (0.6)Natural gas and
  electricity net gains (losses)
 3.0
 (3.0)(in NOK
  billion)
 - 40% sensitivity
 40% sensitivityAt 31 December 2014Crude oil and refined
  products net gains (losses)
 (1.7)
 1.8Natural gas and
  electricity net gains (losses)
 0.7
 (0.7)
  Currency risk Currency risk
constitutes significant financial risk for Statoil. In accordance with approved
strategies and mandates total exposure is managed at a portfolio level on a
regular basis. For further information related to the currency risk and how
Statoil manages these risks, see note 5Financial risk
management. The following currency risk sensitivity has
been calculated by assuming an 11% reasonably possible change in the main
foreign exchange rates that Statoil is exposed to. At the end of 2014 a change
of 9% in the foreign exchange rates were viewed as reasonably possible changes.
An increase in the foreign exchange rates means that the transaction currency
has strengthened in value. The estimated gains and the estimated losses
following from a change in the foreign exchange rates would impact the
Consolidated statement of income.  (in NOK
  billion)
 - 11% sensitivity
 11% sensitivityAt 31 December 2015USD net gains (losses)
 15.4
 (15.4)NOK net gains (losses)
 (14.8)
 14.8(in NOK
  billion)
 - 9% sensitivity
 9% sensitivityAt 31 December 2014USD net gains (losses)
 8.1
 (8.1)NOK net gains (losses)
 (8.3)
 8.3
  Interest rate risk Interest rate risk
constitutes significant financial risk for Statoil. In accordance with approved
strategies and mandates total exposure is managed at a portfolio level on a
regular basis. For further information related to the interest risks and how
Statoil manages these risks, see note 5Financial risk management. The following interest
rate risk sensitivity has been calculated by assuming a change of 0.9
percentage points as reasonably possible changes in the interest rates at the
end of 2015. At the end of 2014 a change of 0.8 percentage points in the
interest rates was viewed as reasonably possible changes. The estimated gains
following from a decrease in the interest rates and the estimated losses
following from an interest rate increase would impact the Consolidated
statement of income. 208Statoil, Annual Report on Form 20-F 2015


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(in NOK billion)
 - 0.9 percentage points sensitivity
 0.9 percentage points sensitivityAt 31 December 2015Interest rate net gains
  (losses)
 10.7
 (10.7)(in NOK
  billion)
 - 0.8 percentage points sensitivity
 0.8 percentage points sensitivityAt 31 December 2014Interest rate net gains
  (losses)
 7.1
 (7.1)
  26 Condensed consolidated financial information
related to guaranteed debt securities  Statoil
Petroleum AS, a 100% owned subsidiary of Statoil ASA, is the co-obligor of
certain existing debt securities of Statoil ASA that are registered under the
US Securities Act of 1933 ("US registered debt securities"). As
co-obligor, Statoil Petroleum AS fully, unconditionally and irrevocably assumes
and agrees to perform, jointly and severally with Statoil ASA, the payment and
covenant obligations for these US registered debt securities. In addition,
Statoil ASA is also the co-obligor of a US registered debt security of Statoil
Petroleum AS. As co-obligor, Statoil ASA fully, unconditionally and irrevocably
assumes and agrees to perform, jointly and severally with Statoil Petroleum AS,
the payment and covenant obligations of that security. In the future, Statoil
ASA may from time to time issue future US registered debt securities for which
Statoil Petroleum AS will be the co-obligor or guarantor. The following
financial information on a condensed consolidated basis provides financial
information about Statoil ASA, as issuer and co-obligor, Statoil Petroleum AS,
as co-obligor and guarantor, and all other subsidiaries as required by SEC Rule
3-10 of Regulation S-X. The condensed consolidated information is prepared in
accordance with Statoil's IFRS accounting policies as described in note 2 Significant
accounting policies, except that investments in subsidiaries and jointly
controlled entities are accounted for using the equity method as required by
Rule 3-10. The following is condensed consolidated
financial information for the full year 2015, 2014 and 2013, and as of 31
December 2015 and 2014.  CONDENSED CONSOLIDATED
  STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOMEStatoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupFull
  year 2015 (in NOK billion)Revenues and other
  income
 316.0
 165.6
 165.6
 (164.1)
 483.1Net income from equity
  accounted companies
 (33.7)
 (66.1)
 (0.4)
 99.9
 (0.3)Total revenues and other
  income
 282.3
 99.5
 165.2
 (64.2)
 482.8Total operating expenses
 (316.4)
 (101.0)
 (215.7)
 165.2
 (467.9)Net operating income
 (34.1)
 (1.5)
 (50.5)
 101.0
 14.9Net financial items
 (22.5)
 (0.8)
 1.1
 11.6
 (10.6)Income before tax
 (56.6)
 (2.3)
 (49.3)
 112.6
 4.3Income tax
 7.5
 (42.7)
 (6.4)
 (0.1)
 (41.6)Net income
 (49.1)
 (45.0)
 (55.7)
 112.5
 (37.3)Other comprehensive
  income
 46.3
 18.3
 56.4
 (86.3)
 34.7Total comprehensive
  income
 (2.8)
 (26.7)
 0.7
 26.2
 (2.6)
 Statoil, Annual Report on Form 20-F
2015209


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CONDENSED CONSOLIDATED STATEMENT OF INCOME AND OTHER
  COMPREHENSIVE INCOMEStatoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupFull
  year 2014 (in NOK billion)Revenues and other
  income
 411.1
 210.8
 213.7
 (212.7)
 622.9Net income from equity
  accounted companies
 21.6
 (32.7)
 (0.2)
 11.0
 (0.3)Total revenues and other
  income
 432.8
 178.1
 213.4
 (201.6)
 622.7Total operating expenses
 (417.8)
 (89.1)
 (222.4)
 216.0
 (513.2)Net operating income
 15.0
 89.0
 (8.9)
 14.4
 109.5Net financial items
 (12.6)
 0.0
 (0.4)
 12.9
 (0.0)Income before tax
 2.4
 89.0
 (9.3)
 27.3
 109.4Income tax
 6.6
 (81.3)
 (11.5)
 (1.2)
 (87.4)Net income
 9.0
 7.7
 (20.8)
 26.0
 22.0Other comprehensive
  income
 55.4
 26.0
 70.5
 (109.3)
 42.5Total comprehensive
  income
 64.4
 33.7
 49.7
 (83.3)
 64.5
  CONDENSED CONSOLIDATED
  STATEMENT OF INCOME AND OTHER COMPREHENSIVE INCOMEStatoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupFull
  year 2013 (in NOK billion)Revenues and other
  income
 416.7
 228.8
 212.1
 (223.2)
 634.4Net income from equity
  accounted companies
 55.0
 (8.0)
 (0.2)
 (46.6)
 0.1Total revenues and other
  income
 471.7
 220.8
 211.9
 (269.8)
 634.5Total operating expenses
 (418.3)
 (85.5)
 (199.0)
 223.6
 (479.1)Net operating income
 53.5
 135.3
 12.9
 (46.2)
 155.5Net financial items
 (27.7)
 (1.0)
 5.9
 5.7
 (17.0)Income before tax
 25.8
 134.3
 18.8
 (40.5)
 138.4Income tax
 8.1
 (95.3)
 (11.7)
 (0.2)
 (99.2)Net income
 33.9
 39.0
 7.1
 (40.7)
 39.2Other comprehensive
  income
 24.2
 5.0
 27.6
 (38.2)
 18.5Total comprehensive
  income
 58.1
 44.0
 34.7
 (78.9)
 57.7
 210Statoil, Annual Report on Form 20-F 2015


---

CONDENSED CONSOLIDATED BALANCE SHEETStatoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupAt 31
  December 2015 (in NOK billion)ASSETSProperty, plant,
  equipment and intangible assets
 5.6
 261.2
 363.0
 (0.3)
 629.5Equity accounted
  companies
 472.5
 181.0
 3.8
 (650.1)
 7.3Other non-current assets
 38.4
 8.9
 34.7
 0.0
 82.0Non-current receivables
  from subsidiaries
 123.1
 0.0
 0.2
 (123.3)
 0.0Total non-current assets
 639.6
 451.1
 401.7
 (773.8)
 718.7Current receivables from
  subsidiaries
 10.9
 20.4
 120.1
 (151.4)
 (0.0)Other current assets
 130.8
 8.9
 36.3
 (3.9)
 172.1Cash and cash
  equivalents
 65.8
 0.8
 9.4
 0.0
 76.0Total current assets
 207.5
 30.1
 165.7
 (155.3)
 248.0Total assets
 847.2
 481.2
 567.4
 (929.1)
 966.7EQUITY AND LIABILITIESTotal equity
 354.7
 184.1
 463.4
 (647.2)
 355.1Non-current liabilities
  to subsidiaries
 0.1
 120.9
 2.3
 (123.3)
 0.0Other non-current
  liabilities
 303.2
 126.5
 47.9
 (1.2)
 476.3Total non-current
  liabilities
 303.3
 247.4
 50.1
 (124.5)
 476.3Other current
  liabilities
 52.5
 38.6
 50.3
 (6.0)
 135.3Current liabilities to
  subsidiaries
 136.7
 11.1
 3.6
 (151.4)
 0.0Total current
  liabilities
 189.1
 49.7
 53.9
 (157.4)
 135.3Total liabilities
 492.4
 297.1
 104.0
 (281.9)
 611.7Total equity and
  liabilities
 847.2
 481.2
 567.4
 (929.1)
 966.7
 Statoil, Annual Report on Form 20-F
2015211


---

CONDENSED CONSOLIDATED BALANCE SHEETStatoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupAt 31
  December 2014 (in NOK billion)ASSETSProperty, plant,
  equipment and intangible assets
 5.9
 276.4
 365.3
 (0.4)
 647.3Equity accounted
  companies
 490.0
 140.5
 7.5
 (629.6)
 8.4Other non-current assets
 34.8
 13.0
 28.2
 0.0
 76.0Non-current receivables
  from subsidiaries
 68.6
 0.4
 0.2
 (69.2)
 0.0Total non-current assets
 599.3
 430.3
 401.2
 (699.2)
 731.7Current receivables from
  subsidiaries
 16.1
 50.3
 89.0
 (155.4)
 0.0Other current assets
 116.7
 14.2
 46.8
 (6.0)
 171.6Cash and cash
  equivalents
 71.5
 0.6
 11.0
 0.0
 83.1Total current assets
 204.4
 65.0
 146.7
 (161.4)
 254.8Total assets
 803.8
 495.4
 547.9
 (860.6)
 986.4EQUITY AND LIABILITIESTotal equity
 380.8
 215.1
 412.4
 (627.1)
 381.2Non-current liabilities
  to subsidiaries
 0.1
 66.3
 2.7
 (69.2)
 0.0Other non-current
  liabilities
 238.2
 144.9
 45.3
 (2.3)
 426.2Total non-current
  liabilities
 238.4
 211.2
 48.0
 (71.4)
 426.2Other current
  liabilities
 68.1
 60.0
 57.6
 (6.7)
 179.0Current liabilities to
  subsidiaries
 116.5
 9.1
 29.8
 (155.4)
 0.0Total current
  liabilities
 184.6
 69.1
 87.4
 (162.1)
 179.0Total liabilities
 423.0
 280.3
 135.5
 (233.5)
 605.2Total equity and
  liabilities
 803.8
 495.4
 547.9
 (860.6)
 986.4
 212Statoil, Annual Report on Form 20-F 2015


---

CONDENSED CONSOLIDATED CASH FLOW STATEMENTStatoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupFull
  year 2015 (in NOK billion)Cash flows provided by
  (used in) operating activities
 23.5
 64.7
 37.4
 (16.6)
 109.0Cash flows provided by
  (used in) investing activities
 (44.8)
 (141.3)
 (46.9)
 117.9
 (115.1)Cash flows provided by
  (used in) financing activities
 9.9
 76.7
 7.2
 (101.3)
 (7.5)Net increase (decrease)
  in cash and cash equivalents
 (11.5)
 0.1
 (2.3)
 0.0
 (13.6)Effect of exchange rate
  changes on cash and cash equivalents
 5.7
 0.1
 1.3
 0.0
 7.1Cash and cash
  equivalents at the beginning of the period (net of overdraft)
 71.5
 0.6
 10.3
 0.0
 82.4Cash and cash
  equivalents at the end of the period (net of overdraft)
 65.8
 0.8
 9.3
 0.0
 75.9Statoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupFull
  year 2014 (in NOK billion)Cash flows provided by
  (used in) operating activities
 18.6
 73.2
 56.9
 (22.2)
 126.5Cash flows provided by
  (used in) investing activities
 (16.9)
 (59.4)
 (55.5)
 19.8
 (112.0)Cash flows provided by
  (used in) financing activities
 (11.0)
 (13.2)
 (1.3)
 2.4
 (23.1)Net increase (decrease)
  in cash and cash equivalents
 (9.3)
 0.6
 0.1
 0.0
 (8.6)Effect of exchange rate
  changes on cash and cash equivalents
 3.8
 0.1
 1.9
 0.0
 5.8Cash and cash
  equivalents at the beginning of the period (net of overdraft)
 77.0
 0.0
 8.3
 0.0
 85.3Cash and cash
  equivalents at the end of the period (net of overdraft)
 71.5
 0.7
 10.3
 0.0
 82.5Statoil ASA
 Statoil Petroleum AS
 Non-guarantor subsidiaries
 Consolidation adjustments
 The Statoil groupFull
  year 2013 (in NOK billion)Cash flows provided by
  (used in) operating activities
 64.3
 69.9
 39.6
 (72.6)
 101.3Cash flows provided by
  (used in) investing activities
 (46.9)
 (46.0)
 (87.4)
 69.9
 (110.4)Cash flows provided by (used
  in) financing activities
 (0.6)
 (23.9)
 48.5
 2.7
 26.6Net increase (decrease)
  in cash and cash equivalents
 16.8
 0.0
 0.7
 0.0
 17.5Effect of exchange rate
  changes on cash and cash equivalents
 2.7
 0.0
 0.2
 0.0
 2.9Cash and cash
  equivalents at the beginning of the period (net of overdraft)
 57.4
 0.0
 7.5
 0.0
 64.9Cash and cash
  equivalents at the end of the period (net of overdraft)
 77.0
 0.0
 8.3
 0.0
 85.3
  Statoil, Annual Report on Form 20-F
2015213


---

27
Supplementary oil and gas information (unaudited)  In accordance with Financial Accounting Standards Board Accounting
Standards Codification "Extractive Activities - Oil and Gas" (Topic
932), Statoil is reporting certain supplemental disclosures about oil and gas
exploration and production operations. While this information is developed with
reasonable care and disclosed in good faith, it is emphasised that some of the
data is necessarily imprecise and represents only approximate amounts because
of the subjective judgement involved in developing such information.
Accordingly, this information may not necessarily represent the present
financial condition of Statoil or its expected future results.  For further information regarding the reserves estimation
requirement, see note 2Significant accounting
policies-
Critical accounting judgements and key sources of estimation uncertainty -
Proved oil and gas reserves.  No new events have occurred since 31 December 2015 that would
result in a significant change in the estimated proved reserves or other
figures reported as of that date.  The disputed equity
determination at Agbami will potentially alter Statoil's equity share in this
field. The effect on the proved reserves will be included once the
redetermination is finalised and the effect is known.  Oil and gas reserve
quantities Statoil's oil and gas reserves have been estimated by its
qualified professionals in accordance with industry standards under the
requirements of the U.S. Securities and Exchange Commission (SEC), Rule 4-10 of
Regulation S-X. Statements of reserves are forward-looking statements.  The determination of these reserves is part of an ongoing process
subject to continual revision as additional information becomes available.
Estimates of proved reserve quantities are imprecise and change over time as
new information becomes available. Moreover, identified reserves and contingent
resources that may become proved in the future are excluded from the
calculations.  Statoil's proved reserves are recognised under various forms of
contractual agreements, including production sharing agreements (PSAs) where
Statoil's share of reserves can vary due to commodity prices or other factors.
Reserves from agreements such as PSAs and buy back agreements are based on the
volumes to which Statoil has access (cost oil and profit oil), limited to
available market access. At 31 December 2015, 9% of total proved reserves were
related to such agreements (15% of total oil, condensate and natural gas
liquids (NGL) reserves and 3% of total gas reserves). This compares with 12%
and 14% of total proved reserves for 2014 and 2013, respectively. Net
entitlement oil and gas production from fields with such agreements was 104
million boe during 2015 (95 million boe for 2014 and 93 million boe for 2013).
Statoil participates in such agreements in Algeria, Angola, Azerbaijan, Libya,
Nigeria and Russia.  Statoil is recording, as proved reserves, volumes equivalent to
our tax liabilities under negotiated fiscal arrangements (PSAs) where the tax
is paid on behalf of Statoil. Reserves are net of royalty oil paid in kind and
quantities consumed during production.  Rule 4-10 of Regulation S-X requires that the appraisal of
reserves is based on existing economic conditions, including a 12-month average
price prior to the end of the reporting period, unless prices are defined by
contractual arrangements. The proved reserves at year end 2015 have been
determined based on a Brent blend price equivalent of USD 54.17/bbl, compared
to USD 101.27/bbl and USD 108.02/bbl for 2014 and 2013 respectively. The volume
weighted average gas price for proved reserves at year end 2015 was 1.76
NOK/Sm3. The comparable gas price used to determine gas reserves at year end
2014 and 2013 was 1.90 NOK/Sm3 and 2.13 NOK/Sm3.The volume weighted
average NGL price for proved reserves at year end 2015 was USD 30.56/boe. The
corresponding NGL price used to determine NGL reserves at year end 2014 and
2013 was USD 57.03/boe and USD 62.32/boe. The significant decrease in commodity
prices affects the profitable reserves to be recovered from accumulations
resulting in reduced reserves.The negative revisions due to price are in general a result of
earlier economic cut-off. For fields with a production-sharing type of
agreement this is to some degree offset by higher entitlement to the reserves. These
changes are all included in the revision category in the tables below, giving a net
reduction of Statoil’s proved reserves at year end.  From the Norwegian continental shelf (NCS), Statoil is responsible
for managing, transporting and selling the Norwegian State's oil and gas on
behalf of the Norwegian State's direct financial interest (SDFI). These
reserves are sold in conjunction with the Statoil reserves. As part of this
arrangement, Statoil delivers and sells gas to customers in accordance with
various types of sales contracts on behalf of the SDFI. In order to fulfil the
commitments, Statoil utilises a field supply schedule which provides the
highest possible total value for the joint portfolio of oil and gas between
Statoil and the SDFI.  Statoil and the SDFI receive income from the joint natural gas
sales portfolio based upon their respective share in the supplied volumes. For
sales of the SDFI natural gas, to Statoil and to third parties, the payment to
the Norwegian State is based on achieved prices, a net back formula calculated
price or market value. All of the Norwegian State's oil and NGL is acquired by
Statoil. The price Statoil pays to the SDFI for the crude oil is based on
market reflective prices. The prices for NGL are either based on achieved
prices, market value or market reflective prices.  The regulations of the owner's instruction, as described above,
may be changed or withdrawn by the Statoil ASA's general meeting. Due to this
uncertainty and the Norwegian State's estimate of proved reserves not being
available to Statoil, it is not possible to determine the total quantities to
be purchased by Statoil under the owner's instruction.  214Statoil, Annual Report on Form 20-F 2015


---

Topic 932 requires the
presentation of reserves and certain other supplemental oil and gas disclosures
by geographical area, defined as country or continent containing 15% or more of
total proved reserves. Norway contains 75% of total proved reserves at 31
December 2015 and no other country contains reserves approaching 15% of total
proved reserves. Accordingly, management has determined that the most meaningful
presentation of geographical areas would be Norway and the continents of
Eurasia (excluding Norway), Africa and Americas.  The following tables reflect the estimated proved reserves of oil
and gas at 31 December 2012 through 2015, and the changes therein.  Consolidated companies
 Equity accounted
 TotalNorway
 Eurasia excluding Norway
 Africa
 Americas
 Subtotal
 Americas
 TotalNet proved oil and
  condensate reserves in million barrels oil equivalentAt 31 December 2012
 968
 193
 281
 395
 1,837
 82
 1,919Revisions and improved
  recovery
 133
 16
 40
 18
 207
 (16)
 191Extensions and
  discoveries
 19
 47
 8
 34
 108
 0
 108Purchase of
  reserves-in-place
 13
 0
 0
 0
 13
 0
 13Sales of
  reserves-in-place
 (40)
 (15)
 0
 (2)
 (57)
 0
 (57)Production
 (174)
 (15)
 (58)
 (46)
 (294)
 (4)
 (298)At 31 December 2013
 918
 227
 271
 399
 1,815
 63
 1,877Revisions and improved
  recovery
 143
 10
 85
 (4)
 235
 (3)
 232Extensions and
  discoveries
 3
 0
 5
 145
 153
 0
 153Purchase of
  reserves-in-place
 0
 0
 0
 20
 20
 0
 20Sales of
  reserves-in-place
 (5)
 (27)
 (2)
 0
 (34)
 0
 (34)Production
 (173)
 (14)
 (64)
 (51)
 (301)
 (4)
 (306)At 31 December 2014
 886
 196
 296
 508
 1,887
 55
 1,942Revisions and improved
  recovery
 71
 (68)
 57
 (54)
 5
 (5)
 0Extensions and
  discoveries
 437
 0
 0
 74
 511
 0
 511Purchase of
  reserves-in-place
 0
 0
 0
 4
 4
 0
 4Sales of
  reserves-in-place
 (4)
 (38)
 0
 (1)
 (43)
 0
 (43)Production
 (174)
 (13)
 (75)
 (57)
 (319)
 (4)
 (324)At 31 December 2015
 1,216
 76
 278
 474
 2,045
 46
 2,091
  Proved reserves of bitumen in Americas,
representing less than 2% of Statoil's proved reserves, is included as oil in
the table above. Statoil, Annual Report on Form 20-F
2015215


---

Consolidated companies
 Equity accounted
 TotalNorway
 Eurasia excluding Norway
 Africa
 Americas
 Subtotal
 Americas
 TotalNet proved NGL reserves
  in million barrels oil equivalentAt 31 December 2012
 405
 0
 18
 47
 469
 0
 469Revisions and improved
  recovery
 25
 0
 (0)
 4
 28
 0
 28Extensions and
  discoveries
 1
 0
 0
 10
 11
 0
 11Purchase of
  reserves-in-place
 0
 0
 0
 0
 0
 0
 0Sales of
  reserves-in-place
 (21)
 0
 0
 0
 (21)
 0
 (21)Production
 (42)
 0
 (1)
 (4)
 (47)
 0
 (47)At 31 December 2013
 368
 0
 16
 56
 441
 0
 441Revisions and improved
  recovery
 (2)
 0
 1
 5
 4
 0
 4Extensions and
  discoveries
 3
 0
 0
 18
 21
 0
 21Purchase of
  reserves-in-place
 0
 0
 0
 0
 0
 0
 0Sales of reserves-in-place
 (10)
 0
 0
 (2)
 (12)
 0
 (12)Production
 (42)
 0
 (2)
 (7)
 (51)
 0
 (51)At 31 December 2014
 318
 0
 15
 69
 403
 0
 403Revisions and improved
  recovery
 7
 0
 3
 (20)
 (10)
 0
 (10)Extensions and
  discoveries
 11
 0
 0
 16
 27
 0
 27Purchase of
  reserves-in-place
 0
 0
 0
 4
 4
 0
 4Sales of
  reserves-in-place
 (1)
 0
 0
 (5)
 (5)
 0
 (5)Production
 (44)
 0
 (3)
 (7)
 (54)
 0
 (54)At 31 December 2015
 291
 0
 15
 57
 364
 0
 364
   216Statoil, Annual Report on Form 20-F 2015


---

Consolidated companies
 Equity accounted
 TotalNorway
 Eurasia excluding Norway
 Africa
 Americas
 Subtotal
 Americas
 TotalNet proved gas reserves
  in billion standard cubic feetAt 31 December 2012
 15,003
 575
 341
 1,107
 17,027
 0
 17,027Revisions and improved
  recovery
 391
 187
 27
 382
 987
 0
 987Extensions and
  discoveries
 920
 1,236
 0
 112
 2,268
 0
 2,268Purchase of reserves-in-place
 5
 0
 0
 0
 5
 0
 5Sales of
  reserves-in-place
 (295)
 (3)
 0
 (2)
 (300)
 0
 (300)Production
 (1,264)
 (72)
 (40)
 (196)
 (1,571)
 0
 (1,571)At 31 December 2013
 14,761
 1,923
 328
 1,404
 18,416
 0
 18,416Revisions and improved
  recovery
 439
 32
 8
 197
 676
 0
 676Extensions and
  discoveries
 79
 0
 0
 364
 443
 0
 443Purchase of
  reserves-in-place
 0
 0
 0
 0
 0
 0
 0Sales of
  reserves-in-place
 (355)
 (681)
 0
 (15)
 (1,051)
 0
 (1,051)Production
 (1,229)
 (56)
 (38)
 (242)
 (1,565)
 0
 (1,565)At 31 December 2014
 13,694
 1,218
 299
 1,708
 16,919
 0
 16,919Revisions and improved
  recovery
 385
 (18)
 129
 (676)
 (180)
 0
 (180)Extensions and
  discoveries
 179
 0
 0
 318
 497
 0
 497Purchase of
  reserves-in-place
 0
 0
 0
 31
 31
 0
 31Sales of
  reserves-in-place
 (10)
 (991)
 0
 (42)
 (1,043)
 0
 (1,043)Production
 (1,306)
 (16)
 (63)
 (215)
 (1,600)
 0
 (1,600)At 31 December 2015
 12,942
 193
 366
 1,123
 14,624
 0
 14,624
   Statoil, Annual Report on Form 20-F
2015217


---

Consolidated companies
 Equity accounted
 TotalNorway
 Eurasia excluding Norway
 Africa
 Americas
 Subtotal
 Americas
 TotalNet proved reserves in
  million barrels oil equivalentAt 31 December 2012
 4,046
 296
 360
 639
 5,340
 82
 5,422Revisions and improved
  recovery
 227
 49
 44
 90
 411
 (16)
 395Extensions and
  discoveries
 183
 268
 8
 64
 523
 0
 523Purchase of
  reserves-in-place
 14
 0
 0
 0
 14
 0
 14Sales of
  reserves-in-place
 (113)
 (15)
 0
 (2)
 (131)
 0
 (131)Production
 (441)
 (28)
 (66)
 (85)
 (621)
 (4)
 (625)At 31 December 2013
 3,916
 569
 346
 705
 5,537
 63
 5,600Revisions and improved
  recovery
 219
 16
 87
 36
 359
 (3)
 356Extensions and
  discoveries
 20
 0
 5
 227
 253
 0
 253Purchase of
  reserves-in-place
 0
 0
 0
 20
 20
 0
 20Sales of
  reserves-in-place
 (78)
 (148)
 (2)
 (5)
 (233)
 0
 (233)Production
 (434)
 (24)
 (72)
 (102)
 (631)
 (4)
 (635)At 31 December 2014
 3,644
 413
 364
 882
 5,304
 55
 5,359Revisions and improved
  recovery
 146
 (72)
 83
 (194)
 (37)
 (5)
 (42)Extensions and
  discoveries
 480
 0
 0
 146
 627
 0
 627Purchase of
  reserves-in-place
 0
 0
 0
 13
 13
 0
 13Sales of
  reserves-in-place
 (6)
 (215)
 0
 (13)
 (235)
 0
 (235)Production
 (450)
 (16)
 (88)
 (103)
 (658)
 (4)
 (662)At 31 December 2015
 3,814
 111
 358
 731
 5,014
 46
 5,060
  Proved reserves of bitumen in Americas,
representing less than 2% of Statoil's proved reserves, is included as oil in
the table above. 218Statoil, Annual Report on Form 20-F 2015


---

Consolidated companies
 Equity accounted
 TotalNorway
 Eurasia excluding Norway
 Africa
 Americas
 Subtotal
 Americas
 TotalNet proved oil and
  condensate reserves in million barrels oil equivalentAt 31 December 2012Developed
 547
 79
 221
 164
 1,010
 38
 1,049Undeveloped
 421
 114
 61
 231
 827
 44
 870At 31 December 2013Developed
 548
 63
 197
 212
 1,020
 32
 1,052Undeveloped
 370
 164
 74
 187
 795
 30
 826At 31 December 2014Developed
 559
 63
 243
 267
 1,133
 24
 1,156Undeveloped
 327
 133
 52
 242
 754
 32
 786At 31 December 2015Developed
 505
 48
 248
 282
 1,083
 21
 1,104Undeveloped
 711
 29
 30
 192
 962
 25
 987Net proved NGL reserves
  in million barrels oil equivalentAt 31 December 2012Developed
 296
 0
 11
 27
 334
 0
 334Undeveloped
 109
 0
 7
 20
 135
 0
 135At 31 December 2013Developed
 287
 0
 10
 34
 330
 0
 330Undeveloped
 82
 0
 7
 22
 111
 0
 111At 31 December 2014Developed
 258
 0
 9
 42
 310
 0
 310Undeveloped
 60
 0
 6
 27
 93
 0
 93At 31 December 2015Developed
 235
 0
 9
 45
 290
 0
 290Undeveloped
 56
 0
 6
 12
 74
 0
 74Net proved gas reserves
  in billion standard cubic feetAt 31 December 2012Developed
 12,073
 343
 226
 567
 13,210
 0
 13,210Undeveloped
 2,931
 232
 115
 540
 3,817
 0
 3,817At 31 December 2013Developed
 11,580
 467
 209
 817
 13,073
 0
 13,073Undeveloped
 3,181
 1,455
 120
 586
 5,343
 0
 5,343At 31 December 2014Developed
 11,227
 312
 191
 946
 12,677
 0
 12,677Undeveloped
 2,467
 906
 108
 762
 4,242
 0
 4,242At 31 December 2015Developed
 10,664
 32
 206
 999
 11,901
 0
 11,901Undeveloped
 2,278
 161
 160
 124
 2,723
 0
 2,723Net proved oil,
  condensate, NGL and gas reserves in million barrels oil equivalentAt 31 December 2012Developed
 2,994
 140
 272
 292
 3,698
 38
 3,737Undeveloped
 1,052
 155
 88
 347
 1,642
 44
 1,686At 31 December 2013Developed
 2,898
 146
 244
 392
 3,679
 32
 3,711Undeveloped
 1,018
 423
 103
 314
 1,858
 30
 1,888At 31 December 2014Developed
 2,818
 119
 287
 477
 3,701
 24
 3,725Undeveloped
 826
 295
 78
 405
 1,603
 32
 1,635At 31 December 2015Developed
 2,641
 53
 294
 505
 3,494
 21
 3,515Undeveloped
 1,173
 57
 64
 226
 1,521
 25
 1,546
  Statoil, Annual Report on Form 20-F
2015219


---

The conversion
rates used are 1 standard cubic meter = 35.3 standard cubic feet, 1 standard
cubic meter oil equivalent = 6.29 barrels of oil equivalent (boe) and 1,000
standard cubic meter gas = 1 standard cubic meter oil equivalent.  Capitalised cost related
  to oil and gas producing activitiesConsolidated companiesAt 31 December(in NOK
  billion)
 2015
 2014
 2013Unproved properties
 117.5
 97.5
 83.8Proved properties,
  wells, plants and other equipment
 1,327.1
 1,178.8
 984.1Total capitalised cost
 1,444.6
 1,276.3
 1,068.0Accumulated
  depreciation, impairment and amortisation
 (873.1)
 (687.2)
 (543.7)Net capitalised cost
 571.5
 589.1
 524.3
  Net capitalised cost related to equity accounted investments as of
31 December 2015 was NOK 8.8 billion, NOK 7.2 billion in 2014 and NOK 5.9
billion in 2013. The reported figures are based on capitalised costs within
the upstream segments in Statoil, in line with the description below for result
of operations for oil and gas producing activities.  Expenditures incurred in
  oil and gas property acquisition, exploration and development activitiesThese expenditures
  include both amounts capitalised and expensed.Consolidated companies(in NOK
  billion)
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalFull year 2015Exploration expenditures
 6.4
 1.7
 3.0
 12.0
 23.1Development costs
 47.1
 11.4
 10.5
 29.0
 98.1Acquired proved
  properties
 0.0
 0.0
 0.0
 0.7
 0.7Acquired unproved
  properties
 0.0
 0.7
 0.7
 3.1
 4.5Total
 53.5
 13.7
 14.3
 44.8
 126.3Full year 2014Exploration expenditures
 7.0
 2.5
 7.3
 7.1
 23.9Development costs
 52.2
 13.4
 13.3
 22.7
 101.7Acquired proved
  properties
 0.0
 0.0
 0.0
 4.7
 4.7Acquired unproved
  properties
 0.0
 0.0
 0.0
 2.3
 2.3Total
 59.3
 15.9
 20.6
 36.8
 132.5Full year 2013Exploration expenditures
 7.9
 3.8
 2.7
 7.4
 21.8Development costs
 51.8
 8.5
 11.6
 26.4
 98.3Acquired proved
  properties
 2.2
 0.0
 0.0
 0.0
 2.2Acquired unproved
  properties
 0.0
 0.4
 0.0
 1.8
 2.2Total
 61.9
 12.7
 14.3
 35.6
 124.5
  Expenditures incurred in development
activities related to equity accounted investments was NOK 0.4 billion in 2015,
NOK 1.6 billion in 2014 and NOK 0.4 billion in 2013.  Results of operation for
oil and gas producing activities As required by
Topic 932, the revenues and expenses included in the following table reflect
only those relating to the oil and gas producing operations of Statoil. The result of
operations for oil and gas producing activities contains the two upstream
reporting segments Development and Production Norway (DPN) and Development and
Production International (DPI) as presented in note 3Segments.Production cost is based on operating 220Statoil, Annual Report on Form 20-F 2015


---

expenses
related to production of oil and gas. From the operating expenses certain
expenses such as; transportation costs, accruals for over/underlift position,
royalty payments and diluent costs are excluded. These expenses and mainly upstream
business administration are included as other expenses in the tables below.
Other revenues mainly consist of gains and losses from sales of oil and gas
interests and gains and losses from commodity based derivatives within the
upstream segments. Income tax expense is calculated on the basis
of statutory tax rates adjusted for uplift and tax credits. No deductions are
made for interest or other elements not included in the table below.  Consolidated companies(in NOK
  billion)
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalFull year 2015Sales
 0.4
 2.0
 (0.6)
 1.6
 3.5Transfers
 140.1
 3.8
 27.7
 22.2
 193.9Other revenues
 (1.0)
 12.3
 0.0
 0.1
 11.4Total revenues
 139.5
 18.2
 27.2
 23.9
 208.7Exploration expenses
 (4.6)
 (1.7)
 (5.1)
 (19.5)
 (31.0)Production costs
 (21.1)
 (1.3)
 (5.4)
 (6.4)
 (34.2)Depreciation,
  amortisation and net impairment losses
 (51.4)
 (6.4)
 (20.1)
 (55.1)
 (133.0)Other expenses
 (4.7)
 (1.3)
 (1.9)
 (11.1)
 (19.0)Total costs
 (81.9)
 (10.7)
 (32.6)
 (92.0)
 (217.2)Results of operations
  before tax
 57.6
 7.4
 (5.4)
 (68.2)
 (8.5)Tax expense
 (38.8)
 1.8
 (5.4)
 (0.2)
 (42.6)Results of operations
 18.8
 9.2
 (10.8)
 (68.3)
 (51.1)Net income from equity
  accounted investments
 0.0
 0.3
 0.0
 (1.0)
 (0.8)
  Consolidated companies(in NOK
  billion)
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalFull year 2014Sales
 1.8
 4.3
 5.0
 3.9
 15.0Transfers
 172.6
 6.1
 32.6
 28.6
 239.9Other revenues
 7.7
 5.7
 0.7
 (1.0)
 13.1Total revenues
 182.1
 16.1
 38.3
 31.4
 268.1Exploration expenses
 (5.4)
 (2.6)
 (9.2)
 (13.2)
 (30.3)Production costs
 (23.0)
 (1.5)
 (4.6)
 (5.3)
 (34.4)Depreciation,
  amortisation and net impairment losses
 (40.0)
 (4.9)
 (14.1)
 (37.9)
 (96.9)Other expenses
 (2.2)
 (1.2)
 0.4
 (10.6)
 (13.6)Total costs
 (70.5)
 (10.1)
 (27.5)
 (67.0)
 (175.2)Results of operations
  before tax
 111.6
 6.0
 10.9
 (35.6)
 92.9Tax expense
 (74.8)
 (0.5)
 (8.4)
 (0.4)
 (84.0)Results of operations
 36.8
 5.5
 2.5
 (36.0)
 8.8Net income from equity
  accounted investments
 (0.0)
 1.0
 0.0
 (1.7)
 (0.7)
 Statoil, Annual Report on Form 20-F
2015221


---

Consolidated companies(in NOK
  billion)
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalFull year 2013Sales
 0.3
 4.0
 3.9
 4.1
 12.3Transfers
 192.5
 7.4
 30.9
 27.1
 257.9Other revenues
 9.3
 3.9
 0.2
 0.4
 13.8Total revenues
 202.1
 15.3
 35.0
 31.6
 284.0Exploration expenses
 (5.5)
 (3.4)
 (1.6)
 (7.5)
 (18.0)Production costs
 (22.1)
 (1.5)
 (3.9)
 (3.9)
 (31.4)Depreciation,
  amortisation and net impairment losses
 (32.2)
 (2.4)
 (13.3)
 (16.2)
 (64.1)Other expenses
 (5.3)
 (1.6)
 (0.5)
 (9.7)
 (17.1)Total costs
 (65.1)
 (8.9)
 (19.3)
 (37.3)
 (130.6)Results of operations
  before tax
 137.0
 6.4
 15.7
 (5.7)
 153.4Tax expense
 (90.9)
 (2.0)
 (8.1)
 (1.0)
 (102.0)Results of operations
 46.1
 4.4
 7.6
 (6.7)
 51.4Net income from equity
  accounted investments
 0.1
 0.3
 0.0
 (0.3)
 0.1
  Average
  production cost in NOK per boe based on entitlement volumes
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 Total2015
 47
 79
 61
 62
 522014
 53
 64
 64
 52
 552013
 50
 53
 59
 46
 51
  Production cost per boe is calculated as the production
costs in the result of operations table, divided by the produced entitlement
volumes (mboe) for the corresponding period.  Standardised measure of discounted future net cash flows relating
to proved oil and gas reserves The table below shows the standardised measure of future net cash
flows relating to proved reserves. The analysis is computed in accordance with
Topic 932, by applying average market prices as defined by the SEC, year end
costs, year end statutory tax rates and a discount factor of 10% to year end
quantities of net proved reserves. The standardised measure of discounted
future net cash flows is a forward-looking statement.  Future price changes are limited to those provided by existing
contractual arrangements at the end of each reporting year. Future development
and production costs are those estimated future expenditures necessary to
develop and produce year-end estimated proved reserves based on year-end cost
indices, assuming continuation of year-end economic conditions. Pre-tax future
net cash flow is net of decommissioning and removal costs. Estimated future
income taxes are calculated by applying the appropriate year-end statutory tax
rates. These rates reflect allowable deductions and tax credits and are applied
to estimated future pretax net cash flows, less the tax basis of related
assets. Discounted future net cash flows are calculated using a discount rate
of 10% per year. Discounting requires a year-by-year estimate of when future
expenditures will be incurred and when reserves will be produced. The
standardised measure of discounted future net cash flows prescribed under Topic
932 requires assumptions as to the timing and amount of future development and
production costs and income from the production of proved reserves. The
information does not represent management's estimate or Statoil's expected
future cash flows or the value of its proved reserves and therefore should not
be relied upon as an indication of Statoil's future cash flow or value of its
proved reserves. 222Statoil, Annual Report on Form 20-F 2015


---

(in NOK billion)
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalAt 31 December 2015Consolidated companiesFuture net cash inflows
 1,288.7
 43.9
 137.3
 189.7
 1,659.5Future development costs
 (156.1)
 (10.8)
 (10.7)
 (41.5)
 (219.0)Future production costs
 (441.5)
 (22.2)
 (54.9)
 (102.6)
 (621.3)Future income tax
  expenses
 (455.7)
 (0.9)
 (25.3)
 (6.4)
 (488.4)Future net cash flows
 235.4
 9.9
 46.3
 39.2
 330.810% annual discount for
  estimated timing of cash flows
 (96.6)
 (3.3)
 (11.1)
 (15.8)
 (126.8)Standardised measure of
  discounted future net cash flows
 138.8
 6.6
 35.2
 23.4
 203.9Equity accounted
  investmentsStandardised measure of
  discounted future net cash flows
 0,0
 0,0
 0,0
 1.1
 1.1Total standardised
  measure of discounted future net cash flows including equity accounted
  investments
 138.8
 6.6
 35.2
 24.5
 205.1(in NOK
  billion)
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalAt 31 December 2014Consolidated companiesFuture net cash inflows
 1,467.9
 203.4
 213.6
 323.0
 2,207.9Future development costs
 (166.8)
 (59.9)
 (12.3)
 (51.7)
 (290.8)Future production costs
 (439.8)
 (91.6)
 (58.3)
 (142.7)
 (732.4)Future income tax
  expenses
 (606.8)
 (8.1)
 (48.6)
 (34.0)
 (697.5)Future net cash flows
 254.5
 43.8
 94.4
 94.6
 487.310% annual discount for
  estimated timing of cash flows
 (99.7)
 (27.8)
 (28.1)
 (41.9)
 (197.6)Standardised measure of
  discounted future net cash flows
 154.7
 16.0
 66.3
 52.7
 289.8Equity accounted
  investmentsStandardised measure of
  discounted future net cash flows
 0,0
 0,0
 0,0
 5.1
 5.1Total standardised
  measure of discounted future net cash flows including equity accounted
  investments
 154.7
 16.0
 66.3
 57.8
 294.8(in NOK
  billion)
 Norway
 Eurasia excluding Norway
 Africa
 Americas
 TotalAt 31 December 2013Consolidated companiesFuture net cash inflows
 1,700.2
 273.7
 205.2
 257.5
 2,436.6Future development costs
 (200.0)
 (80.8)
 (16.0)
 (38.9)
 (335.7)Future production costs
 (471.3)
 (125.4)
 (54.8)
 (104.3)
 (755.8)Future income tax
  expenses
 (740.9)
 (12.2)
 (50.0)
 (24.0)
 (827.1)Future net cash flows
 288.0
 55.3
 84.4
 90.3
 518.010% annual discount for
  estimated timing of cash flows
 (120.8)
 (39.7)
 (27.6)
 (41.3)
 (229.4)Standardised measure of
  discounted future net cash flows
 167.2
 15.6
 56.8
 49.0
 288.6Equity accounted
  investmentsStandardised measure of discounted
  future net cash flows
 0,0
 0,0
 0,0
 4.8
 4.8Total standardised
  measure of discounted future net cash flows including equity accounted
  investments
 167.2
 15.6
 56.8
 53.8
 293.4
 Statoil, Annual Report on Form 20-F
2015223


---

Changes in the standardised measure of discounted future net
  cash flows from proved reserves(in NOK
  billion)
 2015
 2014
 2013Consolidated companiesStandardised measure at
  beginning of year
 289.8
 288.6
 252.8Net change in sales and
  transfer prices and in production (lifting) costs related to future
  production
 (313.7)
 (98.3)
 (24.0)Changes in estimated
  future development costs
 (4.5)
 (32.3)
 (54.9)Sales and transfers of
  oil and gas produced during the period, net of production cost
 (168.0)
 (232.6)
 (243.2)Net change due to
  extensions, discoveries, and improved recovery
 30.1
 23.1
 10.6Net change due to
  purchases and sales of minerals in place
 (7.4)
 (25.1)
 (33.9)Net change due to
  revisions in quantity estimates
 76.4
 126.1
 126.5Previously estimated development
  costs incurred during the period
 84.6
 99.6
 95.1Accretion of discount
 71.0
 77.3
 81.4Net change in income
  taxes
 145.7
 63.3
 78.2Total change in the
  standardised measure during the year
 (85.8)
 1.2
 35.8Standardised measure at
  end of year
 203.9
 289.8
 288.6Equity accounted
  investmentsStandardised measure at
  end of year
 1.1
 5.1
 4.8Standardised measure at
  end of year including equity accounted investments
 205.1
 294.8
 293.4
  In the table above, each
line item presents the sources of changes in the standardised measure value on
a discounted basis, with the accretion of discount line item reflecting the
increase in the net discounted value of the proved oil and gas reserves due to
the fact that the future cash flows are now one year closer in time.  28 Subsequent events  In the first quarter of 2016 Statoil acquired
11.93% of the shares and votes in Lundin Petroleum AB for a total purchase
price of SEK 4.6 billion. The shares will be accounted for as a non-current
financial investment (available-for-sale) at fair value.     224Statoil, Annual Report on Form 20-F 2015


---

8.2
Report of Independent Registered Public Accounting firm  8.2.1Report of
Independent Registered Public Accounting firm  Report of
Independent Registered Public Accounting Firm  To the board of directors
and shareholders of Statoil ASA  We have audited the accompanying
consolidated balance sheets of Statoil ASA and subsidiaries as of 31 December
2015 and 2014 and the related consolidated statements of income, comprehensive
income, changes in equity and cash flows for each of the years in the
three-year period ended 31 December 2015. These consolidated financial
statements are the responsibility of Statoil ASA’s management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.  We conducted our audits in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.  In our opinion, the
consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Statoil ASA and
subsidiaries as of 31 December 2015 and 2014, and the results of their
operations and their cash flows for each of the years in the three-year period
ended 31 December 2015, in conformity with International Financial Reporting
Standards as issued by the International Accounting Standards Board and
International Financial Reporting Standards as adopted by the European Union.  We also have audited, in
accordance with the standards of the Public Company Accounting Oversight Board
(United States), Statoil ASA’s internal control over financial reporting as of
31 December 2015, based on criteria established in Internal Control –
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO), and our report dated 9 March 2016 expressed
an unqualified opinion on the effectiveness of Statoil ASA’s internal control
over financial reporting.  /s/ KPMG AS    Trondheim, Norway 9 March 2016  Statoil, Annual Report on Form 20-F
2015225


---

8.2.2 Report of KPMG on
Statoil's internal control over financial reporting  Report of Independent Registered Public
Accounting Firm  To
the board of directors and shareholders of Statoil ASA  We
have audited Statoil ASA’s internal control over financial reporting as of 31
December 2015, based on criteria established inInternal
Control — Integrated Framework (2013)issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). Statoil ASA’s management is responsible for maintaining
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting, included in the
accompanyingManagement's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on
Statoil ASA’s internal control over financial reporting based on our audit.  We
conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of
internal control based on the assessed risk. Our audit also included performing
such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.  A
company's internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control
over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the company's assets that could have a material effect on the financial
statements.  Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.  In
our opinion, Statoil ASA maintained, in all material respects, effective
internal control over financial reporting as of 31 December 2015, based on
criteria established inInternal Control — Integrated Framework (2013)issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO).  We
also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheets of
Statoil ASA and subsidiaries as of 31 December 2015 and 2014 and the related
consolidated statements of income, comprehensive income, changes in equity and
cash flows for each of the years in the three-year period ended 31 December
2015, and our report dated 9 March 2016 expressed an unqualified opinion on
those consolidated financial statements.  /s/
KPMG AS   Trondheim,
Norway
9 March 2016 226Statoil, Annual Report on Form 20-F 2015


---

9 Terms and definitions Organisational abbreviations ·ACG -
Azeri-Chirag-GunashliX ·ACQ -
Annual contract quantity ·AFP -
Agreement-based early retirement plan ·AGM -
Annual general meeting ·ÅTS -
Åsgard transport system ·APA -
Awards in pre-defined areas ·ARO -
Asset retirement obligation ·BTC -
Baku-Tbilisi-Ceyhan pipeline ·CCS -
Carbon capture and storage ·CH4 -
Methane ·CO2 - Carbon dioxide ·DKK -
Danish Krone ·DPI -
Development and Production International ·DPN -
Development and Production Norway ·DPUSA -
Development and Production USA ·DST -
Drill Stem Test ·D&W
- Drilling and Well ·EEA -
European Economic Area ·EFTA -
European Free Trade Association ·EMTN -
Euro medium-term note ·EU -
European Union ·EU ETS
- EU Emissions Trading System ·EUR -
Euro ·EXP -
Exploration ·FPSO -
Floating production, storage and offload vessel ·GAAP -
Generally Accepted Accounting Principals ·GBP -
British Pound ·GBS -
Gravity-based structure ·GDP -
Gross domestic product ·GHG -
Greenhouse gas ·GSB -
Global Strategy and Business Development ·HSE -
Health, safety and environment ·HTHP -
High-temperature/high pressure ·IASB -
International Accounting Standards Board ·ICE -
Intercontinental Exchange ·IEA -
International Energy Agency ·IFRS -
International Financial Reporting Standards ·IOR -
Improved oil recovery ·LNG -
Liquefied natural gas ·LPG -
Liquefied petroleum gas ·MMP -
Marketing, Midstream and Processing ·MPE -
Norwegian Ministry of Petroleum and Energy ·MW -
Mega watt ·NCS -
Norwegian continental shelf ·NES –
New Energy Solutions ·NIOC -
National Iranian Oil Company ·NOK -
Norwegian kroner ·NOx-
Nitrogen oxide ·OECD -
Organisation of Economic Co-Operation and Development ·OML -
Oil mining lease ·OPEC -
Organization of the Petroleum Exporting Countries ·OTC -
Over-the-counter ·OTS -
Oil trading and supply department ·P5+1 –
UN Security Council`s five permanent members ·PDO -
Plan for development and operation ·PDQ –
Production drilling quarters ·PIO -
Plan for installation and operation ·PRD -
Project Development organisation ·PSA -
Production sharing agreement ·PSR - Procurement
and Supplier Relations ·RDI -
Research, Development and Innovation Statoil, Annual Report on Form 20-F
2015227


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·R&D
- Research and development ·ROACE -
Return on average capital employed ·RRR -
Reserve replacement ratio ·SAGD -
Steam-assisted gravity drainage ·SCP -
South Caucasus Pipeline System ·SDFI -
Norwegian State's Direct Financial Interest ·SEC -
Securities and Exchange Commission ·SEK -
Swedish Krona ·SFR -
Statoil Fuel & Retail ·SIF -
Serious Incident Frequency ·TAP -
Trans Adriatic Pipeline AG ·TEX -
Technology Excellence ·TLP -
Tension leg platform ·TPD -
Technology, projects and drilling ·TRIF -
Total recordable injuries per million hours worked ·TSP -
Technical service provider ·UKCS -
UK continental shelf ·USD -
United States dollar ·WTG -
Wind Turbine Generators  Metric abbreviations etc. ·bbl - barrel ·mbbl - thousand
barrels ·mmbbl - million
barrels ·boe - barrels of
oil equivalent ·mboe - thousand
barrels of oil equivalent ·mmboe - million
barrels of oil equivalent ·mmcf - million
cubic feet ·MMBtu - million
british thermal units ·bcf - billion cubic
feet ·tcf - trillion
cubic feet ·scm - standard
cubic metre ·mcm - thousand
cubic metres ·mmcm - million
cubic metres ·bcm - billion
cubic metres ·mmtpa - million
tonnes per annum ·km - kilometre ·ppm - part per
million ·one billion - one
thousand million  Equivalent measurements are based upon ·1 barrel equals
0.134 tonnes of oil (33 degrees API) ·1 barrel equals 42
US gallons ·1 barrel equals
0.159 standard cubic metres ·1 barrel of oil
equivalent equals 1 barrel of crude oil ·1 barrel of oil
equivalent equals 159 standard cubic metres of natural gas ·1 barrel of oil
equivalent equals 5,612 cubic feet of natural gas ·1 barrel of oil
equivalent equals 0.0837 tonnes of NGLs ·1 billion standard
cubic metres of natural gas equals 1 million standard cubic metres of oil equivalent ·1 cubic metre
equals 35.3 cubic feet ·1 kilometre equals
0.62 miles ·1 square kilometre
equals 0.39 square miles ·1 square kilometre
equals 247.105 acres ·1 cubic metre of
natural gas equals 1 standard cubic metre of natural gas ·1,000 standard
cubic meter gas equals 1 standard cubic meter oil equivalent ·1,000 standard
cubic metres of natural gas equals 6.29 boe ·1 standard cubic
foot equals 0.0283 standard cubic metres ·1 standard cubic
foot equals 1000 British thermal units (btu) ·1 tonne of NGLs
equals 1.9 standard cubic metres of oil equivalent ·1 degree Celsius
equals minus 32 plus five-ninths of the number of degrees Fahrenheit     228Statoil, Annual Report on Form 20-F 2015


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Miscellaneous terms ·Appraisal well: A
well drilled to establish the extent and the size of a discovery ·Backwardation and
contango are terms used in the crude oil market. Contango is a condition where
forward prices exceed spot prices, so the forward curve is upward sloping.
Backwardation is the opposite condition, where spot prices exceed forward
prices, and the forward curve slopes downward ·Biofuel: A solid,
liquid or gaseous fuel derived from relatively recently dead biological
material and is distinguished from fossil fuels, which are derived from long
dead biological material ·BOE (barrels of
oil equivalent): A measure to quantify crude oil, natural gas liquids and
natural gas amounts using the same basis. Natural gas volumes are converted to
barrels on the basis of energy content ·Clastic reservoir
systems: The integrated static and dynamic characteristics of a hydrocarbon
reservoir formed by clastic rocks of a specific depositional sedimentary
succession and its seal ·Condensates: The
heavier natural gas components, such as pentane, hexane, iceptane and so forth,
which are liquid under atmospheric pressure – also called natural gasoline or
naphtha ·Crude oil, or oil:
Includes condensate and natural gas liquids ·Development: The
drilling, construction, and related activities following discovery that are
necessary to begin production of crude oil and natural gas fields ·Downstream: The
selling and distribution of products derived from upstream activities ·Equity and
entitlement volumes of oil and gas: Equity volumes represent volumes produced
under a production sharing agreement (PSA) that correspond to Statoil's
percentage ownership in a particular field. Entitlement volumes, on the other
hand, represent Statoil's share of the volumes distributed to the partners in
the field, which are subject to deductions for, among other things, royalties
and the host government's share of profit oil. Under the terms of a PSA, the amount
of profit oil deducted from equity volumes will normally increase with the
cumulative return on investment to the partners and/or production from the
licence. The distinction between equity and entitlement is relevant to most PSA
regimes, whereas it is not applicable in most concessionary regimes such as
those in Norway, the UK, Canada and Brazil. The overview of equity production
provides additional information for readers, as certain costs described in the
profit and loss analysis were directly associated with equity volumes produced
during the reported years ·Heavy oil: Crude
oil with high viscosity (typically above 10 cp), and high specific gravity. The
API classifies heavy oil as crudes with a gravity below 22.3° API. In addition
to high viscosity and high specific gravity, heavy oils typically have low
hydrogen-to-carbon ratios, high asphaltene, sulphur, nitrogen, and heavy-metal
content, as well as higher acid numbers ·High grade:
Relates to selectively harvesting goods, to cut the best and leave the rest. In
reference to exploration and production this entails strict prioritisation and
sequencing of drilling targets ·Hydro: A reference
to the oil and energy activities of Norsk Hydro ASA, which merged with Statoil
ASA ·IOR (improved oil
recovery): Actual measures resulting in an increased oil recovery factor from a
reservoir as compared with the expected value at a certain reference point in
time. IOR comprises both of conventional and emerging technologies ·Liquids: Refers to
oil, condensates and NGL ·LNG (liquefied
natural gas): Lean gas - primarily methane - converted to liquid form through
refrigeration to minus 163 degrees Celsius under atmospheric pressures ·LPG (liquefied
petroleum gas): Consists primarily of propane and butane, which turn liquid
under a pressure of six to seven atmospheres. LPG is shipped in special vessels ·Midstream:
Processing, storage, and transport of crude oil, natural gas, natural gas
liquids and sulphur ·Naphtha:
inflammable oil obtained by the dry distillation of petroleum ·Natural gas:
Petroleum that consists principally of light hydrocarbons. It can be divided
into 1) lean gas, primarily methane but often containing some ethane and smaller quantities of
heavier hydrocarbons (also called sales gas) and 2) wet gas, primarily ethane,
propane and butane as well as smaller amounts of heavier hydrocarbons;
partially liquid under atmospheric pressure ·NGL (natural gas
liquids): Light hydrocarbons mainly consisting of ethane, propane and butane
which are liquid under pressure at normal temperature ·Oil sands: A
naturally occurring mixture of bitumen, water, sand, and clay. A heavy viscous
form of crude oil ·Oil and gas value
chains: Describes the value that is being added at each step from 1) exploring;
2) developing; 3) producing; 4) transportation and refining; and 5) marketing
and distribution ·Organic capital
expenditures: Capital expenditures excluding acquisitions, capital leases and
other investments with significant different cash flow pattern ·Petroleum: A
collective term for hydrocarbons, whether solid, liquid or gaseous.
Hydrocarbons are compounds formed from the elements hydrogen (H) and carbon (C). The proportion of
different compounds, from methane and ethane up to the heaviest components, in
a petroleum find varies from discovery to discovery. If a reservoir primarily
contains light hydrocarbons, it is described as a gas field. If heavier
hydrocarbons predominate, it is described as an oil field. An oil field may
feature free gas above the oil and contain a quantity of light hydrocarbons,
also called associated gas Statoil, Annual Report on Form 20-F
2015229


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·Proved reserves:
Reserves claimed to have a reasonable certainty (normally at least 90%
confidence) of being recoverable under existing economic and political
conditions, and using existing technology. They are the only type the US
Securities and Exchange Commission allows oil companies to report ·Refining reference
margin: Is a typical average gross margin of our two refineries, Mongstad and
Kalundborg. The reference margin will differ from the actual margin, due to
variations in type of crude and other feedstock, throughput, product yields,
freight cost, inventory etc ·Rig year: A
measure of the number of equivalent rigs operating during a given period. It is
calculated as the number of days rigs are operating divided by the number of
days in the period ·Upstream: Includes
the searching for potential underground or underwater oil and gas fields,
drilling of exploratory wells, subsequent operating wells which bring the
liquids and or natural gas to the surface ·VOC (volatile
organic compounds): Organic chemical compounds that have high enough vapour
pressures under normal conditions to significantly vaporise and enter the
earth's atmosphere (e.g. gasses formed under loading and offloading of crude
oil)  230Statoil, Annual Report on Form 20-F 2015


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10
Forward-looking statements  ﻿﻿﻿﻿This Annual
Report on Form 20-F contains certain forward-looking statements that involve
risks and uncertainties, in particular in the sections "Business
overview" and "Strategy and market overview". In some cases, we
use words such as "aim", "ambition", "anticipate",
"believe", "continue", "could",
"estimate", "expect", "intend",
"likely", "objective", "outlook",
"may", "plan", "schedule", "seek",
"should", "strategy", "target", "will",
"goal" and similar expressions to identify forward-looking
statements. All statements other than statements of historical fact, including,
among others, statements regarding future financial position, results of
operations and cash flows; future financial ratios and information; future
financial or operational portfolio or performance; future market position and
conditions; future credit rating; business strategy; growth strategy; sales,
trading and market strategies; research and development initiatives and
strategy; market outlook and future economic projections and assumptions;
competitive position; projected regularity and performance levels; expectations
related to our recent transactions and projects, such as the sale of interests
in the Shah Deniz project and the South Caucasus Pipeline,  interests in the Marcellus
onshore play in the US, interests in Trans Adriatic Pipeline, interests in
Gudrun and acquisition of interests in Eagle Ford in the US, the UK Mariner
project, the Peregrino phase II project in Brazil, in addition to the Johan
Sverdrup and Aasta Hansteen projects on the NCS, discoveries on the NCS and
internationally; our ownership share in Gassled; completion and results of
acquisitions, disposals and other contractual arrangements; reserve
information; recovery factors and levels; future margins; projected returns;
future levels or development of capacity, reserves or resources; future decline
of mature fields; planned turnarounds and other maintenance; plans for
cessation and decommissioning; oil and gas production forecasts and reporting;
growth, expectations and development of production, projects, pipelines or
resources; estimates related to production and development levels and dates;
operational expectations, estimates, schedules and costs; exploration and
development activities, plans and expectations; projections and expectations
for upstream and downstream activities; expectations relating to licences; oil,
gas, alternative fuel and energy prices and volatility; oil, gas, alternative
fuel and energy supply and demand; renewable energy production, industry
outlook and carbon capture and storage; organisational structure and policies;
planned responses to climate change; technological innovation, implementation,
position and expectations; future energy efficiency; projected operational
costs or savings; our ability to create or improve value; future sources of
financing; exploration and project development expenditure; our goal of safe
and efficient operations; effectiveness of our internal policies and plans; our
ability to manage our risk exposure; our liquidity levels and management;
estimated or future liabilities, obligations or expenses; expected impact of
currency and interest rate fluctuations; expectations related to contractual or
financial counterparties; capital expenditure estimates and expectations;
projected outcome, impact or timing of HSE regulations; HSE goals and
objectives of management for future operations; expectations related to
regulatory trends; impact of PSA effects; projected impact or timing of
administrative or governmental rules, standards, decisions, standards or laws
(including taxation laws); projected impact of legal claims against us; plans
for capital distribution and amounts of dividends are forward-looking
statements. You should not place undue reliance on these forward-looking
statements. Our actual results could differ materially from those anticipated
in the forward-looking statements for many reasons, including the risks
described above in "Risk review", and in "Operational
review", and elsewhere in this Annual Report on Form 20-F.  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. There are a number of factors that
could cause actual results and developments to differ materially from those
expressed or implied by these forward-looking statements, including levels of
industry product supply, demand and pricing; exchange rate and interest rate
fluctuations; the political and economic policies of Norway and other
oil-producing countries; EU directives; general economic conditions; political
and social stability and economic growth in relevant areas of the world;
Euro-zone uncertainty; global political events and actions, including war,
terrorism and sanctions; security breaches, including breaches of our digital
infrastructure (cybersecurity); changes or uncertainty in or non-compliance
with laws and governmental regulations; the timing of bringing new fields on
stream; an inability to exploit growth opportunities; material differences from
reserves estimates; unsuccessful drilling; an inability to find and develop
reserves; ineffectiveness of crisis management systems; adverse changes in tax
regimes; the development and use of new technology, particularly in the
renewable energy sector; geological or technical difficulties; operational
problems; operator error; inadequate insurance coverage; the lack of necessary
transportation infrastructure when a field is in a remote location and other
transportation problems; the actions of competitors; the actions of field
partners; the actions of the Norwegian state as majority shareholder;
counterparty defaults; natural disasters, adverse weather conditions, climate
change, and other changes to business conditions; failure to meet our ethical
and social standards; an inability to attract and retain personnel and other
factors discussed elsewhere in this report.  Although we believe that the expectations
reflected in the forward-looking statements are reasonable, we cannot assure
you that our future results, level of activity, performance or achievements
will meet these expectations. Moreover, neither we nor any other person assumes
responsibility for the accuracy and completeness of the forward-looking
statements. Unless we are required by law to update these statements, we will
not necessarily update any of these statements after the date of this Annual
Report, either to make them conform to actual results or changes in our expectations.  Statoil, Annual Report on Form 20-F
2015231


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11 Signature
page  ﻿﻿The registrant hereby
certifies that it meets all of the requirements for filing on Form 20-F/A and
that it has duly caused and authorised the undersigned to sign this Annual
Report on its behalf.   STATOIL ASA (Registrant)   By: /s/   Hans Jakob Hegge Name:     Hans Jakob Hegge Title:       Executive Vice President and
Chief Financial Officer   Dated:  12 April 2016  232Statoil, Annual Report on Form 20-F 2015


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12 Exhibits   The following exhibits are filed
as part of this Amendment No. 1:  Exhibit
  no
 DescriptionExhibit 1
 Articles of Association
  of Statoil ASA, as amended, effective from 14 May 2013 (English
  translation).*Exhibit 4(a)(i)
 Technical Services
  Agreement between Gassco AS and Statoil Petroleum AS, dated November 24,
  2010.*Exhibit 4(c)
 Employment agreement
  with Eldar Sætre as of 4 February 2015.*Exhibit 7
 Calculation of ratio of
  earnings to fixed charges.*Exhibit 8
 Subsidiaries (see
  section 3.9 Significant subsidiaries included in this Annual Report).*Exhibit 12.1
 Rule 13a-14(a)
  Certification of Chief Executive Officer.**Exhibit 12.2
 Rule 13a-14(a)
  Certification of Chief Financial Officer.**Exhibit 13.1
 Rule 13a-14(b)
  Certification of Chief Executive Officer. 1) **Exhibit 13.2
 Rule 13a-14(b)
  Certification of Chief Financial Officer. 1) **Exhibit 15(a)(i)
 Consent of KPMG AS.*Exhibit 15(a)(ii)
 Consent of DeGolyer and
  MacNaughton.*Exhibit 15(a)(iii)
 Report of DeGoyler and
  MacNaughton.*1)
 Furnished only.*
 Previously filed with
  the Original Form 20-F on March 18, 2016.**
 Filed or furnished with
  this Amendment No. 1.
  The total amount of long-term debt securities
of the Registrant and its subsidiaries authorised under any one instrument does
not exceed 10% of the total assets of Statoil ASA and its subsidiaries on a
consolidated basis. The company agrees to furnish copies of any or all such
instruments to the Securities and Exchange Commission upon request.  Statoil, Annual Report on Form 20-F
2015233


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13 Cross
reference to Form 20-F  SectionsItem 1.
 Identity
  of Directors, Senior Management and Advisers
 N/AItem 2.
 Offer
  Statistics and Expected Timetable
 N/AItem 3.
 Key
  InformationA.
  Selected Financial Data
 1.2;
  4.1.2; 6; 6.1.1; 6.7B.
  Capitalisation and Indebtedness
 N/AC.
  Reasons for the Offer and Use of Proceeds
 N/AD. Risk
  Factors
 5.1Item 4.
 Information
  on the CompanyA.
  History and Development of the Company
 3.1;
  3.2; 4.1.4; 4.1.5; 4.2.3; 8.1.4B.
  Business Overview
 2; 3;
  4.1.1; 4.1.3C.
  Organisational Structure
 3.1;
  3.4; 3.9D.
  Property, Plants and Equipment
 3.5 -
  3.7; 3.13; 4.2.3; 8.1.11; 8.1.22Oil and
  Gas Disclosures
 3.10.1;
  3.10.2; 3.11; 3.11.1; 3.11.2; 3.11.3; 3.11.4; 8.1.27; Exhibit 15(a)(iv)Item 4A.
 Unresolved
  Staff Comments
 NoneItem 5.
 Operating
  and Financial Review and ProspectsA.
  Operating Results
 3.12;
  4.1; 4.2.4; 5.2.1; 8.1.25B.
  Liquidity and Capital Resources
 4.2;
  4.2.1; 4.2.2; 4.2.5; 5.2.1; 5.2.2; 8.1.5; 8.1.16; 8.1.18; 8.1.25C.
  Research and development, Patents and Licenses, etc.
 3.8.3;
  8.1.7D. Trend
  Information
 2; 3.3;
  3.5.1; 3.5.3; 3.5.4; 3.6; 3.7.1; 3.11; 3.12.5; 4.2; 5; 8.1.23E.
  Off-Balance Sheet Arrangements
 4.2.5;
  4.2.6; 8.1.22; 8.1.23F.
  Tabular Disclosure of Contractual Obligations
 4.2.5G. Safe Harbor
 10Item 6.
 Directors,
  Senior Management and EmployeesA.
  Directors and Senior Management
 7.6; 7.8B.
  Compensation
 7.9;
  8.1.19C. Board
  Practices
 7.5;
  7.6; 7.8D.
  Employees
 3.16.1;
  3.16.3E. Share
  Ownership
 6.2.1;
  7.6; 7.8; 7.10Item 7.
 Major
  Shareholders and Related Party TransactionsA. Major
  Shareholders
 6.8B.
  Related Party Transactions
 3.14;
  8.1.24C.
  Interests of Experts and Counsel
 N/AItem 8.
 Financial
  InformationA.
  Consolidated Statements and Other Financial Information
 4.1.3;
  5.3; 6.1; 8B.
  Significant Changes
 8.1.27Item 9.
 The
  Offer and ListingA. Offer
  and Listing Details
 6.4B. Plan
  of Distribution
 N/AC.
  Markets
 6; 6.4;
  7.7D.
  Selling Shareholders
 N/AE.
  Dilution
 N/AF.
  Expenses of the Issue
 N/AItem 10.
 Additional
  InformationA. Share
  Capital
 N/AB.
  Memorandum and Articles of Association
 6.1;
  6.8; 7.1; 7.3; 7.10; 8.1.17C.
  Material Contracts
 N/AD.
  Exchange Controls
 6.6E.
  Taxation
 6.5F.
  Dividends and Paying Agents
 N/AG.
  Statements by Experts
 N/AH.
  Documents On Display
 1.1I.
  Subsidiary Information
 N/AItem 11.
 Quantitative
  and Qualitative Disclosures About Market Risk
 5;
  8.1.5; 8.1.25Item 12.
 Description
  of Securities Other than Equity Securities
 5;
  8.1.5; 8.1.25A. Debt
  Securities
 N/AB.
  Warrants and Rights
 N/AC. Other
  Securities
 N/AD.
  American Depositary Shares
 6.4.2Item 13.
 Defaults,
  Dividend Arrearages and Delinquencies
 NoneItem 14.
 Material
  Modifications to the Rights of Security Holders and Use of Proceeds
 NoneItem 15.
 Controls
  and Procedures
 7.12;
  8.2.2Item
  16A.
 Audit
  Committee Financial Expert
 7.6.1Item
  16B.
 Code of
  Ethics
 7.2Item
  16C.
 Principal
  Accountant Fees and Services
 7.1Item
  16D.
 Exemptions
  from the Listing Standards for Audit Committees
 7.7Item
  16E.
 Purchases
  of Equity Securities by the Issuer and Affiliated Purchases
 6.2Item
  16F.
 Changes
  in Registrant’s Certifying Accountant
 N/AItem
  16G.
 Corporate
  Governance
 7.7Item 17.
 Financial
  Statements
 N/AItem 18.
 Financial
  Statements
 8Item 19.
 Exhibits
 12
 234Statoil, Annual Report on Form 20-F 2015