0001140625-16-000107.txt : 20160412 0001140625-16-000107.hdr.sgml : 20160412 20160412172204 ACCESSION NUMBER: 0001140625-16-000107 CONFORMED SUBMISSION TYPE: 20-F PUBLIC DOCUMENT COUNT: 46 CONFORMED PERIOD OF REPORT: 20160412 FILED AS OF DATE: 20160412 DATE AS OF CHANGE: 20160412 FILER: COMPANY DATA: COMPANY CONFORMED NAME: STATOIL ASA CENTRAL INDEX KEY: 0001140625 STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911] IRS NUMBER: 000000000 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 20-F SEC ACT: 1934 Act SEC FILE NUMBER: 001-15200 FILM NUMBER: 161567929 BUSINESS ADDRESS: STREET 1: FORUSBEEN 50 CITY: STAVANGER NORWAY STATE: Q8 ZIP: N 4035 BUSINESS PHONE: 47 51 99 00 00 MAIL ADDRESS: STREET 1: FORUSBEEN 50 CITY: STAVANGER STATE: Q8 ZIP: N 4035 FORMER COMPANY: FORMER CONFORMED NAME: STATOILHYDRO ASA DATE OF NAME CHANGE: 20071005 FORMER COMPANY: FORMER CONFORMED NAME: STATOIL ASA DATE OF NAME CHANGE: 20010515 20-F 1 sto_20-f15A.htm STATOIL ANNUAL REPORT ON FORM 20-F  

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, 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 1934

OR

X     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

        For the fiscal year ended December 31, 2015

OR

    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

        For the transition period from _________ to _________

OR

    SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

        Date of event requiring this shell company report _________

Commission file number 1-15200

Statoil ASA

(Exact Name of Registrant as Specified in Its Charter)

N/A

(Translation of Registrant’s Name Into English)

Norway

(Jurisdiction of Incorporation or Organization)

Forusbeen 50, N-4035, Stavanger, Norway

(Address of Principal Executive Offices)

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 Registered

American Depositary Shares

New York Stock Exchange

Ordinary shares, nominal value of NOK 2.50 each

New York Stock Exchange

 

*Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission

 

Securities registered or to be registered pursuant to Section 12(g) of the Act:      None 

 

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:      None 

 

 

 

 

 

 

 

 

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

 

Ordinary shares of NOK 2.50 each                                                                                      3,182,914,686

3,188,647,103

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

X Yes   ☐  No

 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

 

Yes   X No

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

 

 

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

X Yes   ☐  No

 

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).**

 

Yes   ☐  No

**This requirement does not apply to the registrant in respect of this filing.

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer   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 2015    1


 

 

  

2   Statoil, Annual Report on Form 20-F 2015    


 

 

Statoil, Annual Report on Form 20-F 2015    3


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.

  

 

4   Statoil, Annual Report on Form 20-F 2015    


 

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 at
www.statoil.com

 

Statoil is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these

requirements, Statoil files its Annual Report on Form 20-F and other related documents with the Securities and Exchange Commission (the SEC). It is also

possible to read and copy documents that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C.

20549, 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 2015    5


 

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 December

2015

2014

2013

2012

2011

 

 

 

 

 

 

 

Financial information

 

 

 

 

 

Total revenues and other income4)

482.8

622.7

634.5

718.2

670.0

Net operating income

14.9

109.5

155.5

206.6

211.8

Net income

(37.3)

22.0

39.2

69.5

78.4

Non-current finance debt

264.0

205.1

165.5

101.0

111.6

Net interest-bearing debt before adjustments

122.0

89.2

58.0

39.3

71.0

Total assets

966.7

986.4

885.6

784.4

768.6

Share capital

8.0

8.0

8.0

8.0

8.0

Non-controlling interest

0.3

0.4

0.5

0.7

6.2

Total equity

355.1

381.2

356.0

319.9

285.2

Net 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 information

 

 

 

 

 

Equity oil and gas production (mboe/day)

1,971

1,927

1,940

2,004

1,850

Proved oil and gas reserves (mmboe)

5,060

5,359

5,600

5,422

5,426

Reserve replacement ratio (three-year average)

0.81

0.97

1.15

1.01

0.90

Production cost equity volumes (NOK/boe, last 12 months)

48

49

44

42

42

 

 

 

 

 

 

 

Share information1)

 

 

 

 

 

Diluted earnings per share NOK

(11.8)

6.87

12.50

21.60

24.70

Share price at Oslo Børs (Norway) on 31 December in NOK

123.70

131.20

147.00

139.00

153.50

Dividend per share NOK 2)

7.62

7.20

7.00

6.75

6.50

Dividend per share USD 2),3)

1.07

0.97

1.15

1.21

1.08

Weighted average number of ordinary shares outstanding (in thousands)

3,179,443

3,179,959

3,180,684

3,181,546

3,182,113

 

 

 

 

 

 

 

1)

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.

 

6   Statoil, Annual Report on Form 20-F 2015    


 

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 2015    7


 

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.

 

 

 

8   Statoil, Annual Report on Form 20-F 2015    


 

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 sentiment drove the 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 2015    9


 

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

First quarter 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.

 

 

10   Statoil, Annual Report on Form 20-F 2015    


 

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 2015    11


 

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 CO2 and 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 expenditures for 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 total exploration activity level of around USD 2 billion for 2016, excluding signature bonuses

·      Statoil aims to deliver efficiency improvements with pre-tax cash flow effects of around USD 2.5 billion annually from 2016

·      Statoil’s ambition is to keep the unit of production cost in 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

·      The equity production for 2016 is estimated to be somewhat lower than the 2015 level [7]

·      Scheduled maintenance activity  is 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 royalties are 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 production to create future value, gas off-take, timing of new capacity coming on stream and operational regularity represent the most significant risks related to the production guidance

·      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 for  eligible shareholders starting from the fourth quarter 2015  

·       With effect from first quarter of 2016, Statoil will change to USD 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

 

12   Statoil, Annual Report on Form 20-F 2015    


 

3  Business overview

 

3.1 Our history

 

Statoil was formed in 1972 by a decision of the Norwegian parliament and listed on the stock exchanges in Oslo and New York in 2001.

 

Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap AS on 18 September 1972. As a company wholly owned by the Norwegian State, Statoil's role was to be the government's commercial instrument in the development of the oil and gas industry in Norway.

 

In 2001, the company became a public limited company listed on the Oslo and New York stock exchanges, and it changed its name to Statoil ASA.

 

Statoil has grown in parallel with the Norwegian oil and gas industry, which dates back to the late 1960s. Initially, 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 2015    13


 

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 and Production Norway (DPN)

DPN comprises our upstream activities on the Norwegian continental shelf (NCS). DPN aims to continue its leading role and ensure maximum value creation on the NCS. Through excellent HSE and improved operational performance and cost, DPN strives to maintain and strengthen Statoil's position as a world- leading operator of producing offshore fields. DPN seeks to open new acreage and to mature improved oil recovery and exploration prospects. New and existing fields are primarily developed using an industrial approach, in which speed of delivery and cost improvements through standardisation and repeated use of proved solutions are key elements.

 

Development and Production International (DPI)

DPI comprises our worldwide upstream activities that are not included in the DPN and Development and Production 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)

14   Statoil, Annual Report on Form 20-F 2015    


 

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 2015    15


 

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 Segments  in the Consolidated financial statement for more details.

 

16   Statoil, 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 2015    17


 

 

 

 

 

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 in the 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

 

2013

 

Oil and NGL

Natural gas

 

 

Oil and NGL

Natural gas

 

 

Oil and NGL

Natural gas

 

Area production

mbbl

mmcm

mboe/day

 

mbbl

mmcm

mboe/day

 

mbbl

mmcm

mboe/day

 

 

 

 

 

 

 

 

 

 

 

 

Operations North

 32  

 7  

 78  

 

 36  

 7  

 80  

 

 24  

 5  

 56  

Operations Mid

 113  

 17  

 218  

 

 126  

 17  

 235  

 

 126  

 15  

 222  

Operations West

 267  

 51  

 591  

 

 264  

 43  

 535  

 

 290  

 48  

 589  

Operations South

 134  

 13  

 214  

 

 107  

 11  

 177  

 

 94  

 12  

 167  

Partner Operated Fields

 50  

 13  

 132  

 

 55  

 16  

 157  

 

 58  

 20  

 182  

 

 

 

 

 

 

 

 

 

 

 

 

Total

 595  

 101  

 1,232  

 

 588  

 95  

 1,184  

 

 591  

 99  

 1,217  

18   Statoil, 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/day

 

 

 

 

 

 

 

 

 

 

Operations North

 

 

 

  

  

 

  

Snøhvit

The Barents Sea

36.79

Statoil

2007

2035

 

47.1

Norne

The Norwegian Sea

39.10

Statoil

1997

2026

 

5.9

Alve

The Norwegian Sea

85.00

Statoil

2009

2029

 

10.6

Urd

The Norwegian Sea

63.95

Statoil

2005

2026

 

14.2

 

 

 

 

 

 

 

 

Total Operations North

 

 

 

  

  

 

77.9

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operations Mid-Norway

 

 

 

  

  

 

  

Åsgard 

The Norwegian Sea

34.57

Statoil

1999

2027

 

92.1

Morvin

The Norwegian Sea

64.00

Statoil

2010

2027

 

16.3

Mikkel 

The Norwegian Sea

43.97

Statoil

2003

2020

1)

14.3

Tyrihans

The Norwegian Sea

58.84

Statoil

2009

2029

 

49.6

Kristin

The Norwegian Sea

55.30

Statoil

2005

2033

2)

24.5

Heidrun 

The Norwegian Sea

13.04

Statoil

1995

2024

3)

8.7

Njord

The Norwegian Sea

20.00

Statoil

1997

2021

4)

6.1

Hyme

The Norwegian Sea

35.00

Statoil

2013

2014

5)

6.2

 

 

 

 

 

 

 

 

Total Operations Mid-Norway

 

 

 

 

 

 

217.8

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operations West

 

 

 

 

 

 

 

Troll Phase 1 (Gas)

The North Sea

30.58

Statoil

1996

2030

 

185.2

Troll Phase 2 (Oil)

The North Sea

30.58

Statoil

1995

2030

 

38.2

Fram 

The North Sea

45.00

Statoil

2003

2024

 

16.9

Fram H Nord

The North Sea

49.20

Statoil

2014

2024

 

2.3

Oseberg

The North Sea

49.30

Statoil

1988

2031

 

86.4

Tune

The North Sea

50.00

Statoil

2002

2032

6)

1.9

Gullfaks 

The North Sea

51.00

Statoil

1986

2036

 

69.4

Gimle 

The North Sea

65.13

Statoil

2006

2034

7)

2.6

Kvitebjørn

The North Sea

39.55

Statoil

2004

2031

 

64.0

Valemon

The North Sea

57.76

Statoil

2015

2031

 

16.4

Visund 

The North Sea

53.20

Statoil

1999

2034

 

48.5

Grane

The North Sea

36.66

Statoil

2003

2030

 

45.8

Volve

The North Sea

59.60

Statoil

2008

2028

 

10.0

Veslefrikk 

The North Sea

18.00

Statoil

1989

2020

8)

3.1

 

 

 

 

 

 

 

 

Total Operation West

 

 

 

 

 

 

590.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operations South

 

 

 

  

  

 

  

Sleipner Vest

The North Sea

58.35

Statoil

1996

2028

 

49.2

Sleipner Øst

The North Sea

59.60

Statoil

1993

2028

 

44.4

Gungne 

The North Sea

62.00

Statoil

1996

2028

 

10.0

Gudrun

The North Sea

36.00

Statoil

2014

2028

9)

6.1

Statfjord Unit

The North Sea

44.34

Statoil

1979

2026

 

42.6

Statfjord Øst

The North Sea

31.69

Statoil

1994

2026

10)

1.3

Statfjord Nord

The North Sea

21.88

Statoil

1995

2026

 

1.2

Sygna 

The North Sea

30.71

Statoil

2000

2026

10)

0.8

Snorre 

The North Sea

33.28

Statoil

1992

2015

11)

35.6

Vigdis area 

The North Sea

41.50

Statoil

1997

2024

 

14.6

Tordis area 

The North Sea

41.50

Statoil

1994

2024

 

8.2

 

 

 

 

 

 

 

 

Total Operations South

 

 

 

 

 

 

214.0

Statoil, Annual Report on Form 20-F 2015    19


 

 

Business cluster

Geographical area

Statoil's equity interest in %1)

Operator 

On stream 

Licence expiry date

 

Average daily production in 2015 mboe/day

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Partner Operated Fields

 

 

 

 

 

 

 

Ormen Lange

The Norwegian Sea

25.35

Shell

2007

2041

12)

47.8

Skarv

The Norwegian Sea

36.17

BP Norge AS

2013

2033

13)

46.8

Ekofisk area 

The North Sea

7.60

ConocoPhillips

1971

2028

 

14.3

Marulk

The North Sea

50.00

Eni Norge AS

2012

2025

 

13.2

Vilje

The North Sea

28.85

Marathon Oil

2008

2021

 

4.0

Sigyn 

The North Sea

60.00

ExxonMobil

2002

2022

 

3.8

Ringhorne Øst

The North Sea

14.82

ExxonMobil

2006

2030

 

1.7

Edvard Grieg

The North Sea

15.00

Lundin Norway AS

2015

2035

 

0.4

 

 

 

 

 

 

 

 

Total Partner Operated Fields

 

 

 

 

 

 

131.9

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

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 4.1.4 DPN profit and loss analysis for a discussion of results of operations for 2015, 2014 and 2013.

  

 

20   Statoil, 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. The CO2 in the feed-gas from Snøhvit and Albatross is removed due to freezing constraints in the process system. To reduce carbon dioxide emissions to the air the removed CO2 is liquefied, transported through a pipeline, and then injected into a storage reservoir in Snøhvit. The LNG plant 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. Its main focus is prolonging and increasing production through increased oil recovery, exploration and new field developments.

 

Troll is the largest gas field on the NCS and a major oil field. The Troll field is split into three hydrocarbon-bearing regions connected to three platforms: Troll A, B and C. The Troll gas is mainly exported and produced at the Troll A platform, while oil is mainly produced at Troll B and C. Fram and Fram H Nord are tie-ins to Troll C.

Statoil, Annual Report on Form 20-F 2015    21


 

 

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.

 

The Oseberg area 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.

 

Gullfaks has 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.

   

Kvitebjørn is a gas and condensate field. The field is developed with an integrated accommodation, drilling and processing facility with a steel jacket.

 

The Valemon field 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.

 

Visund is 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.

 

Grane  is Statoil's largest producing heavy oil field. The Svalin field is a tie-in to Grane platform.

 

The Heimdal platforms are 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 in the 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.

 

Sleipner consists 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.

 

The Gudrun field 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.

 

Statfjord has 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.

 

The Snorre field has two floating platforms and one subsea production system connected to the Snorre A platform. In addition, the satellite fields Tordis and Vigdis are part of Snorre business unit and are tied back to Gullfaks C and Snorre A, respectively.

  

 

22   Statoil, 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 Lange operated by Shell, is a deepwater gas field in the Norwegian Sea. The well stream is transported to an onshore processing and export plant at Nyhamna.

 

Skarv is an oil and gas field located in the Norwegian Sea, with BP as operator. The field development includes a floating production, storage and offloading vessel (FPSO) and five subsea multi-well installations.

 

Ekofisk is 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 Grieg is 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

2013

 

 

 

 

 

North Sea

 

 

 

Statoil operated exploratory

11

11

11

Partner operated exploratory

3

7

10

 

 

 

 

 

Norwegian Sea

 

 

 

Statoil operated exploratory

5

0

7

Partner operated exploratory

1

1

1

 

 

 

 

 

Barents Sea

 

 

 

Statoil operated exploratory

0

9

2

Partner operated exploratory

1

1

4

 

 

 

 

 

Totals

 

 

 

Exploratory

21

29

35

Exploration extension wells

3

2

7

 

 

 

 

 

Statoil, Annual Report on Form 20-F 2015    23


 

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  

 7  

 

Norwegian Sea

 37,784  

 12,581  

 (1,681) 

 144  

 79  

 55  

 9  

 4  

 

Barents 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 start

 
 

 

 

 

 

 

 

Aasta Hansteen

Statoil

51.00%

2013

2018

 

Johan Sverdrup

Statoil

40.01%

2015

2019

 

Gina Krog

Statoil

58.70%

2012

2017

 

Ivar Aasen

Det Norske

41.47%

2012

2016

 

Goliat

Eni

35.00%

2009

2016

 

Martin Linge

Total

19.00%

2011

2016

 

 

Johan Sverdrup is 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 Hansteen  is a deep water gas discovery in the Norwegian Sea. The development concept includes three subsea templates tied in to a floating processing unit with gas export through a new pipeline, Polarled, to Nyhamna and further exportation through the Langeled pipeline. The Aasta Hansteen processing unit can also serve as a hub for other potential discoveries in the area. Expected production start-up is in 2018.

 

Gina Krog is an oil and gas discovery in the North Sea approximately 30 kilometres north of the Sleipner field. The field development concept includes a steel-jacket platform. Oil will be exported via offshore loading from a floating storage unit. Due to the high condensate content, the rich gas will be exported via Sleipner, where it will be further processed. The development concept also includes gas injection in order to maximise the recovery factor for the field. The development concept includes a total of 15 wells. Expected production start-up is in 2017.

 

Ivar Aasen is 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.

 

Goliat is the first oil field to be developed in the Barents Sea. The field is being developed by means of subsea wells tied back to a circular floating production, storage and offloading vessel (FPSO). The oil will be offloaded to shuttle tankers. The Goliat development is operated by Eni who expects production start-up during first quarter of 2016.

24   Statoil, Annual Report on Form 20-F 2015    


 

 

Martin Linge is an oil and gas field, operated by Total, near the British sector in the North Sea. The reservoir is complex with gas under high pressure and high temperatures. The development includes a platform as a fixed steel jacket with processing and export facilities. Electrical power will be supplied from Kollsnes. The operator expects production start-up in 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 and CO2 emissions over the fields’ lifetimes.

 

The Gullfaks subsea compression project 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%.

 

The Smørbukk South Extension project, 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 A field’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’s CO2 emissions significantly.

 

The Gullfaks 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 extension project 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.

 

The Ormen 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 2 Significant accounting policies to the Consolidated financial statements.

 

Statoil, Annual Report on Form 20-F 2015    25


 

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 5.1.1 Risks related to our business for information regarding sanctions towards Iran.

 

The map shows Statoil’s international producing countries and additional countries where Statoil has discoveries and/or exploration acreage.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

26   Statoil, Annual Report on Form 20-F 2015    


 

 

 

 


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 the In Salah Southern Fields project in Algeria

·        Significant impairment losses on assets and oil and gas prospects and signature bonuses were recognised in 2015, see section 4.1.5 DPI profit and loss analysis for further details

 

The profitability of our industry continues to be challenged. Statoil’s response to the industrial challenge characterised by high costs and declining returns is addressed in the 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 entitlement production 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 December

Entitlement production

2015

2014

2013

 

 

 

 

Oil and NGL (mboe per day)

436

383

354

Natural gas (mmcm per day)

23

26

23

Total (mboe per day)

580

546

502

 

 

 

 

Statoil, Annual Report on Form 20-F 2015    27


 

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/day

 
 
 

 

 

 

 

 

 

 

 

 

North America

 

 

 

 

282.3

239.7

 

US: Marcellus 1)

Varies

Statoil/others

2008

HBP2)

115.7

96.9

 

US: Bakken 1)

Varies

Statoil/others

2011

HBP2)

61.6

49.3

 

US: Eagle Ford 1)

Varies

Statoil

2010

HBP2)

34.7

26.6

 

US: Tahiti

25.00

Chevron

2009

HBP2)

16.9

13.9

 

US: Caesar Tonga

23.55

Anadarko

2012

HBP2)

9.1

8.7

 

US: St. Malo

21.50

Chevron

2014

HBP2)

7.6

7.6

 

US: Jack

25.00

Chevron

2014

HBP2)

6.6

6.6

 

Canada: Leismer Demo

100.00

Statoil

2010

HBP2)

19.9

19.9

 

Canada: Terra Nova

15.00

Suncor

2002

2022

5.4

5.4

 

Canada: Hibernia/Hibernia southern extension3)

Varies

HMDC

1997

2027

4.8

4.8

 

 

 

 

 

 

 

 

 

 

South America

  

  

  

  

43.5

43.5

 

Brazil: Peregrino

60.00

Statoil

2011

2034

43.5

43.5

 

 

 

 

 

 

 

 

 

 

Sub-Saharan Africa

 

 

  

  

273.3

197.8

 

Angola, Block 17

23.33

Total

2001

2022-344)

161.9

113.9

 

Angola, Block 15

13.33

ExxonMobil

2004

2026-324)

41.8

22.6

 

Angola, Block 31

13.33

BP

2012

2031

20.9

19.0

 

Angola: Block 4/055)

20.00

Sonangol P&P

2009

2026

1.4

1.3

 

Nigeria: Agbami

20.21

Chevron

2008

2024

47.3

41.0

 

 

 

 

 

 

 

 

 

 

North Africa

 

 

  

  

49.6

43.6

 

Algeria: In Salah

31.85

Sonatrach/BP/Statoil

2004

2027

32.5

30.6

 

Algeria: In Amenas

45.90

Sonatrach/BP/Statoil

2006

2022

17.1

13.3

 

Libya: 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

43.9

 

Azerbaijan: ACG

8.56

BP

1997

2024

54.3

24.2

 

Azerbaijan: Shah Deniz 7)

15.50

BP

2006

2041

12.0

10.0

 

Russia: Kharyaga

30.00

Total

1999

2032

9.4

7.1

 

UK: Alba

17.00

Chevron

1994

2018

2.5

2.5

 

UK: Jupiter

30.00

ConocoPhillips

1995

HBP2)

0.1

0.1

 

Ireland: Corrib8)

36.50

Shell

2015

2031

0.0

0.0

 

 

 

 

 

 

 

 

 

 

Total Development and Production International (DPI)

 

 

727.0

568.5

 

 

 

 

 

 

 

 

 

 

Equity accounted production

 

 

 

 

 

 

 

Venezuela: Petrocedeño9)

9.68

Petrocedeño

2008

2033

11.6

11.6

 

 

 

 

 

 

 

 

 

 

Total Development and Production International (DPI) including share of equity accounted production

 

 

738.7

580.2

 

 

 

 

 

 

 

 

 

 

1)

Statoil’s actual working interest can vary depending on wells and area

 

2)

Held by Production (HBP): A company’s right to own and operate an oil and gas lease is perpetuated beyond its original primary term, as long thereafter as oil and gas is produced in paying quantities. In the case of Canada, besides continue being in production status, other regulatory requirements must be met

 

3)

Statoil's working interests are 5.0% in Hibernia and 9.0% in Hibernia southern extension

 

4)

Varies by field

 

5)

Statoil relinguished Block 4/05 in September 2015

 

6)

Zero production in 2015, adjustment of 2014 volume

 

7)

Statoil divested the asset on 30 April 2015

 

8)

 New gas field which started production on 30 December 2015

 

9)

Petrocedeño is a non-consolidated company and accounted for pursuant to the equity accounting method

 

28   Statoil, Annual Report on Form 20-F 2015    


 

The table below provides information about production per country in 2015.

 

Country

Average daily equity production mboe/day1)

Average daily entitlement production mboe/day

 
 
 

 

 

 

 

 

North America

282.3

239.7

 

US

252.2

209.6

 

Canada

30.1

30.1

 

 

 

 

 

 

South America

43.5

43.5

 

Brazil

43.5

43.5

 

 

 

 

 

 

Sub-Saharan Africa

273.3

197.8

 

Angola

226.0

156.8

 

Nigeria

47.3

41.0

 

 

 

 

 

 

North Africa

49.6

43.6

 

Algeria

49.6

43.9

 

Libya

0.0

-0.3

 

 

 

 

 

 

Europe and Asia

78.3

43.9

 

Azerbaijan

66.3

34.2

 

Russia

9.4

7.1

 

UK

2.6

2.6

 

 

 

 

 

 

Total Development and Production International (DPI)

 727.0  

 568.5  

 

 

 

 

 

 

Equity accounted production

 

 

 

Venezuela: Petrocedeño2)

11.6

11.6

 

 

 

 

 

 

Total Development and Production International (DPI) including share of equity accounted production

 738.7  

 580.2  

 

 

 

 

 

 

1)

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 the Marcellus shale 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 the Bakken tight 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 end of 2015 was 249,000 acres.

 

Statoil entered the Eagle Ford shale formation located in southwest Texas in 2010. Through agreements with Enduring Resources LLC and Talisman Energy Inc., Statoil acquired 67,000 net acres. In 2013, Statoil became operator for 50% of the Eagle Ford acreage in 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 2015    29


 

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:

 

The Tahiti oil field is located in the Green Canyon area. The development includes a floating spar facility. As of 31 December 2015, there were nine production and three water injection wells in operation, and additional wells will be phased in over time to fully develop the field.

 

The Caesar Tonga oil 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 were three 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 

The Peregrino field is a heavy oil field located in the Campos Basin, about 85 kilometres off the coast of Rio de Janeiro. The field came on stream in 2011.The oil is produced from two wellhead platforms with drilling capability and it is processed on the Peregrino FPSO. Statoil holds a 60% ownership interest in the field and is operator. In August 2015, the Peregrino field passed a significant milestone with 100 million barrels of oil produced since production start.

 

Venezuela

Petrocedeño produces extra-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.

 

30   Statoil, Annual Report on Form 20-F 2015    


 

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 four discoveries 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.

 

The In 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 the Mabruk or 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

The Azeri-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 in Shah Deniz and the South Caucasus Pipeline (SCP) to the Malaysian oil and gas company PETRONAS. See note 4  Acquisitions and dispositions  of the Consolidated financial statements for further details.

 

Russia

The Kharyaga oil 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 5.1.1 Risks related to our business.

 

United Kingdom

Statoil, Annual Report on Form 20-F 2015    31


 

The  Alba  oil field is located in the central part of the UK North Sea.  Jupiter  is 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 on Corrib gas 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

2013

 

 

 

 

 

North America

- Statoil operated

8

3

7

 

- Partner operated

0

0

4

South America/sub-Saharan Africa

- Statoil operated

3

8

6

 

- Partner operated

5

9

4

North Africa

- Statoil operated

0

0

0

 

- Partner operated

0

0

1

Europe and Asia

- Statoil operated

2

2

0

 

- Partner operated

0

1

2

 

 

 

 

 

 

Totals

18

23

24



The regions where Statoil had exploration activity in 2015 are presented below.

 

North America

 

US
Statoil 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.

 

Canada
The 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 Kwanza
Statoil acquired a solid acreage position in the pre-salt play of the Kwanza Basin in 2011 with the operatorship in Block 38 and 39 and 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 12
Intangible assets.

 

Brazil
All 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

32   Statoil, Annual Report on Form 20-F 2015    


 

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.

 

Mozambique
The 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

 

Algeria
Statoil 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

UK
In 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 5.1.1 Risks related to our business for information regarding sanctions against Russia.  

 

Statoil, Annual Report on Form 20-F 2015    33


 

Azerbaijan
The 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.

 

 

 

34   Statoil, Annual Report on Form 20-F 2015    


 

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 start

 
 

 

 

 

 

 

 

 

US: Julia

Exxon Mobil

50.00%

2013

2016

 

US: Heidelberg

Anadarko

12.00%

2013

2016

 

US: Stampede

Hess

25.00%

2014

2018

 

US: Big foot

Chevron

27.50%

2010

2018

 

Canada: Hebron

Exxon Mobil

9.01%

2012

2017

 

Algeria: In Amenas Compression project

Sonatrach/BP/Statoil

45.90%

2010

2016

 

UK, Mariner

Statoil

65.11%

2012

2018

 

Brazil, Peregrino Phase II1)

Statoil

60.00%

2015

2019/20

 

 

 

 

 

 

 

 

1)

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

The Julia oil 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.

 

The Heidelberg oil field is located in the Green Canyon area. The development includes a Spar facility and first oil is expected within early-2016.

 

The Stampede oil 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.

 

The Big foot oil 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 2015    35


 

US Onshore

US Onshore operations use hydraulic fracturing to liberate resources. Despite reduction in investment and activity level in recent years in shale plays Bakken, Eagle Ford and Marcellus, 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 3.6.2.1 North America for further information.

 

Canada

The Hebron field 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 the Bay du Nord project, 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 in Block 2 offshore 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 In Amenas Gas Compression project in Algeria, which is led by BP, was sanctioned in late 2010. The compressors are expected to come on stream in 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 expects production start in 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, Statoil holds a 65.11% interest in all Mariner licences.

 

36   Statoil, Annual Report on Form 20-F 2015    


 

Statoil is the operator for, and holds an 81.6% interest in Bressay. 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 the Alfa 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 pending government 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 2015    37


 

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 processing of 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 sections 3.12.3  The 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 sold 36.9 billion 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 business activities are organised in the 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 to The 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 in the Section Strategy and market overview.   

 

38   Statoil, Annual Report on Form 20-F 2015    


 

3.7.2 Marketing and Trading

 

The Marketing and Trading business cluster (MT) is responsible for the marketing and trading of all the products from Statoil’s upstream, processing and refining business.

 

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 2015    39


 

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.

40   Statoil, Annual Report on Form 20-F 2015    


 

 

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 2015    41


 

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 holds a 30.8% stake in the Norddeutche Erdgas Transversale (NETRA) overland gas transmission pipeline.

Pipelines under construction

Statoil is the operator and holds a 37.1% ownership share in the Polarled project which will secure a gas export 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 4 Acquistitions and dispositions for 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 the Oak, 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

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mongstad

 11.9  

 9.2  

 11.8  

 9.3  

 9.3  

 9.3  

 97.6  

 93.4  

 98.9  

 93.4  

 90.0  

 95.0  

Kalundborg

 5.2  

 4.5  

 5.0  

 5.4  

 5.4  

 5.4  

 98.5  

 91.8  

 98.2  

 91.0  

 82.0  

 86.5  

Tjeldbergodden

0.92

0.83

0.79