20-F 1 sto_20-f17.htm STATOIL ANNUAL REPORT ON FORM 20-F  

 

 

 

 

 

 

 

 

2017

                         

Annual Report

on Form 20-F

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

 

                                                   FORM 20-F

(Mark One)

    REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

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

        For the fiscal year ended December 31, 2017

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

3,323,167,853

 

 

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   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)

 

x Yes   ☐  No

 

 

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

Large accelerated filer                  Accelerated filer   ☐                 Non-accelerated filer   ☐         Emerging growth company☐ 

 

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check

mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial

accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐ 

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards

Board to its Accounting Standards Codification after April 5, 2012.

 

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    

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   No

 

 

                       

Statoil, Annual Report on Form 20-F 2017    1


Table of contents

 

INTRODUCTION

 

Message from Chair of the board

3

Chief executive letter

5

Statoil at a glance

6

About the report

9

 

 

STRATEGIC REPORT

 

2.1 Strategy and market overview

10

2.2 Business overview

15

2.3 E&P Norway - Exploration & Production Norway

21

2.4 E&P International - Exploration & Production International

28

2.5 MMP - Marketing, Midstream and Processing

37

2.6 Other group

40

2.7 Corporate

44

2.8 Operational performance

49

2.9 Financial review

64

2.10 Liquidity and capital resources

74

2.11 Risk review

79

2.12 Safety, security and sustainability

91

2.12 Our people

96

 

 

CORPORATE GOVERNANCE

 

3.1 Introduction

100

3.2 General meeting of shareholders

103

3.3 Nomination committee

104

3.4 Corporate assembly

105

3.5 Board of directors

109

3.6 Management

118

3.7 Compensation of governing bodies

125

3.8 Share ownership

133

3.9 External auditor

134

3.10 Risk management and internal controls

136

 

 

FINANCIAL STATEMENTS AND SUPPLEMENTS

 

4.1 Consolidated financial statements of the Statoil group

139

4.2 Supplementary oil and gas information

204

 

 

ADDITIONAL INFORMATION

 

5.1 Shareholder information

217

5.2 Use and reconciliation of Non-GAAP financial measures

229

5.3 Legal proceedings

234

5.6 Terms and abbreviations

235

5.7 Forward-looking statements

238

5.8 Signature page

239

5.9 Exhibits

240

5.10 Cross reference to Form 20-F

241

2   Statoil, Annual Report on Form 20-F 2017    


 

 


DEAR fellow investor

 

 

2017 has been a good year for Statoil, both operationally and financially. We have seen significant positive impacts from the improvements, and have benefitted from an upturn in the oil and gas market. And we have delivered on the sharpened strategy we launched in February 2017.

 

The 2017 net operating income ended positive with USD 13.8 billion, up from close to zero in 2016. Statoil continues to deliver on the improvement ambitions, and demonstrates strong operational performance. A free cash flow[1]  of USD 3.1 billion made Statoil cash-flow neutral well below 50 USD per barrel.

 

Strong safety performance is essential to Statoil’s license to operate. The serious incident frequency for 2017 improved compared to 2016, however, it is key to remember that safety results must be delivered every day. The board of directors is working closely with the administration to ensure that forceful safety efforts and continued leadership focus are maintained.

 

We have seen a gradual rebalancing of the oil market and recovering prices. However, we should still be prepared for volatility. Key influencing factors are; geopolitical developments, OPEC policies, US shale response and the price impact of short-term trading activities. For the board of directors, it is essential that Statoil is a robust and resilient company, well equipped for different scenarios.

 

Statoil remains committed to competitive capital distribution. For the fourth quarter 2017 we propose to the annual general meeting (AGM) a dividend of 0.23 USD per share, an increase of 4.5%. This is in line with the dividend policy of increasing the dividend in line with long-term underlying earnings. In addition, Statoil has ended its two-year scrip programme as planned. We also see an emerging scope for share buy-backs, dependent on macro outlook and portfolio developments. However, the near-term priority is to strengthen the balance sheet.

 

Statoil has increased its production guiding while at the same time reducing capital expenditures. The improvements delivered over the last years have materially improved the financial position and competitiveness. This is reflected in operations and the next generation portfolio with a break-even price of 21 USD per barrel.

 

Statoil made 14 discoveries from 28 wells drilled in 2017, and have secured access to attractive new acreage, like in Argentina and Turkey, and strengthened the portfolio with acquisitions like Carcará North, Roncador in Brazil and Martin Linge in Norway.

Statoil is striving to further develop a distinct and competitive portfolio, driven by the strategy always safe, high value, low carbon. Statoil will leverage industrial strengths; operational excellence, world class recovery, leading project delivery, premium market access and digital leader, to develop long-term value on the Norwegian continental shelf, develop new growth options internationally and increase value creation in the marketing and midstream business.

 

The company continues to build a material industrial position in new energy solutions. Within offshore wind Statoil is competitive and well positioned. Statoil is now the operator of three offshore wind farms, and has also entered its first solar project through the acquisitions of a 43.75% share in the Apodi asset in Brazil.

 

Responding to the climate challenge and preparing Statoil for a low carbon future is an integrated part of the strategy. Concrete actions to reduce greenhouse gas emissions in the operations have been implemented, and we are taking further steps to gradually build a more carbon resilient portfolio.

 

The board of directors believes the company is well prepared to deal with the current market situation and has the competence, capacity and leadership capabilities necessary to create new business opportunities and long-term value for our shareholders.

 

After the closing of the year, the board has decided to recommend to the AGM to change the company name from Statoil to Equinor. Our strategy remains firm, and the change is a natural follow up of the strategic development from a focused oil and gas to a broad energy company. The board sees the new name as a continuation of the company’s proud history, and a commitment to value creation also in a low carbon future.

 

I would like to thank all employees for their dedication and commitment to Statoil and our shareholders for their continued investment.

 

 

Jon Erik Reinhardsen

Chair of the board

 


[1] See section 5.2 Use and reconciliation of non-GAAP financial measures

Statoil, Annual Report on Form 20-F 2017    3


 



 

 

 

 

 

 

  


4   Statoil, Annual Report on Form 20-F 2017    


 


DEAR fellow SHAREHOLDER

 

 

As we have started a new year with new opportunities, it is useful to reflect briefly on the past. In 2017, we presented our strategy: always safe, high value, low carbon, and we set clear ambitions for the future. We have delivered above and beyond our ambitious targets, and Statoil is now a stronger, more resilient and more competitive company.

 

The safety of our people and integrity of our operations remains our top priority. Over the past decade we have steadily improved our safety results. Following some negative developments in 2016, we reinforced our efforts, and last year we again saw a positive development. For the year as a whole, our serious incident frequency came in at 0.6. We will use this as inspiration and continue our efforts. The “I am safety”-program, launched across the company is an important part of these efforts.

 

We must always be prepared for volatility in our markets. Our improvement work started when prices were still high, and we have used the downturn to reset the company. Today we are a much more robust and resilient company. We have taken down the break-even price of our next generation portfolio by more than 20% during last year to USD 21 per barrel.

 

Last year we said we would be cash flow positive at USD 50 per barrel in 2017. We did even better, and were cash flow positive well below USD 50. At an average Brent oil price of 54 per barrel, we generated USD 3.1 billion in free cash flow[2]. We tripled our adjusted earnings to USD 12.6 billion, and our net operating income was up from close to zero in 2016 to USD 13.8 billion last year. A negative net income in 2016 is turned to a positive result of USD 4.6 billion.

 

The organic capital expenditures ended at USD 9.4 billion[3], well below the USD 11 billion initially guided. The reduction is mainly due to solid improvements and continued strict capital discipline.

 

We continue to transform our cost base and value creation potential. With USD 1.3 billion in additional improvements in 2017, Statoil has realised annual efficiencies of USD 4.5 billion from 2013. In 2017 we also achieved a record high reserve replacement ratio (RRR) of 150% and all time high production. Looking forward the potential is solid towards 2020, with expected increase in annual production of 3-4%, strong cash generation and growing returns.

    

We have used the down-turn well, but the real test is taking place now, as prices are recovering. I have seen how easy it is for an organisation to start relaxing when prices recover. In Statoil we are determined and will not allow that to happen. We intend to reduce drilling costs further and sustain the 2017 unit of production costs in 2020.

 

In Statoil we believe the winners in the energy transition will be the producers which can deliver at low cost and with low carbon emissions. We also believe there are attractive business opportunities in the transition to a low-carbon economy.

 

Co2-emissions from our oil and gas production were reduced with an additional 10% per barrel last year. In the fall 2017 we started production from Dudgeon, and the floating windfarm Hywind. Today, we operate three offshore wind projects in the UK, delivering competitive returns. Statoil will continue its journey from a focused oil and gas to a broad energy company.

 

I believe Statoil is set to increase returns and grow our cash flow in the years to come. We are delivering on our strategy, investing in high-return opportunities, strengthening our balance sheet – and have increased the capital distribution. I look forward to further developing Statoil in 2018.

 

This year’s AGM will mark a historic moment for us. The board of directors recommends changing the company name from Statoil to Equinor. “Equi” is the starting point for words like equal, equality and equilibrium. “Nor” is signalling a company proud of its origin.

 

The name says something important about us as a company. What we stand for, where we come from and how we see the future. How we see people - and how we view energy.

 

The strategy we presented last year remains firm. And we think the name has potential to strengthen our attractiveness with investors, partners and not the least the new generation of talents we need to realise our strategy and reach our ambitions.

 

 

Eldar Sætre

President and Chief Executive Officer

Statoil ASA

 


[2] See section 5.2 Use and reconciliation of non-GAAP financial measures

[3] IFRS capital expenditures for 2017 were USD 10.8 billion

Statoil, Annual Report on Form 20-F 2017    5


 

Statoil at a glance

 

Our history

Statoil was founded as Den Norske Stats Oljeselskap AS, the Norwegian State Oil company in 1972. Statoil became listed on

the Oslo Børs (Norway) and New York Stock Exchange (US) in June 2001. Statoil merged with Hydro’s oil and gas division in October 2007. Statoil is an international energy company present in more than 30 countries around the world, including several of the world’s most important oil and gas provinces. Our headquarter is located in Stavanger, Norway and we have 20.245 employees worldwide. We create value through safe and efficient operations, innovative solutions and technology. Statoil’s competitiveness is founded on our values-based performance culture, with a strong commitment to transparency, collaboration and continuous efficiency improvements.

 

The board of directors of Statoil have proposed to change the name of the company to Equinor. The new name supports the company’s strategy and development as a broad energy company.  The suggested name change will be proposed to the shareholders in a resolution to the annual general meeting on 15 May 2018.

 

Our vision

Our vision rests on three pillars: Competitive at all times, transforming the oil and gas industry and providing energy for a low-carbon future.

 

Our strategy

Statoil is an energy company committed to long-term value

creation in a low carbon future. Statoil will develop and maximise the value of its unique Norwegian continental shelf position, its international oil and gas business and its growing new energy business; focusing on safety, cost and carbon efficiency. Statoil is a values-based company where empowered people collaborate to shape the future of energy.

                                     

Our values

Our values embody the spirit and energy of Statoil at its best. They help us set direction and they guide our decisions,

actions and the way we interact with others. Our values express the ideals we strive to live up to every day.

Statoil’s values are: Open, Collaborative, Courageous and Caring.

 

Our activities

Statoil is engaged in exploration, development and production of oil and gas in addition to renewables. We are the leading operator on the Norwegian continental shelf and have substantial international activities. We sell crude oil and is a major supplier of natural gas. Processing, refining, offshore wind and carbon capture and storage is also part of our operations. Our activities are managed through eight business areas, staffs and support divisions and we have operations in both North and South America, Africa, Asia, Europe and Oceania, as well as in Norway.

 

Our shareholders

The Norwegian State is the largest shareholder in Statoil, with a direct ownership interest of 67%. Its ownership interest is managed by the Ministry of Petroleum and Energy. US investors hold 11%, Norwegian private owners hold 8%, other European investors hold 8%, UK investors hold 3% and others hold 2%.

 

Statoil announces dividends on a quarterly basis. It is Statoil's ambition to grow the annual cash dividend, measured in USD per share, in line with long-term underlying earnings.

 

 

 

6   Statoil, Annual Report on Form 20-F 2017    


 

 

 

 

 

Statoil, Annual Report on Form 20-F 2017    7


 

Key figures

 

(in USD million, unless stated otherwise)

  For the year ended 31 December

2017

2016

2015

2014

2013

 

 

 

 

 

 

 

Financial information

 

 

 

 

 

Total revenues and other income1)

61,187

45,873

59,642

99,264

108,318

Operating expenses

(8,763)

(9,025)

(10,512)

(11,657)

(12,669)

Net operating income/(loss)

13,771

80

1,366

17,878

26,572

Net income/(loss)

4,598

(2,902)

(5,169)

3,887

6,713

Non-current finance debt

24,183

27,999

29,965

27,593

27,197

Net interest-bearing debt before adjustments

15,437

18,372

13,852

12,004

9,542

Total assets

111,100

104,530

109,742

132,702

145,572

Total equity

39,885

35,099

40,307

51,282

58,513

Net debt to capital employed ratio before adjustments 2)

27.9%

34.4%

25.6%

19.0%

14.0%

Net debt to capital employed ratio adjusted 2)

29.0%

35.6%

26.8%

20.0%

15.2%

ROACE 3)

8.2%

(0.4%)

4.1%

8.7%

11.8%

 

 

 

 

 

 

 

Operational data

 

 

 

 

 

Equity oil and gas production (mboe/day)

2,080

1,978

1,971

1,927

1,940

Proved oil and gas reserves (mmboe)

5,367

5,013

5,060

5,359

5,600

Reserve replacement ratio (annual)

1.50

0.93

0.55

0.62

1.28

Reserve replacement ratio (three-year average)

1.00

0.70

0.81

0.97

1.15

Production cost equity volumes (USD/boe)

4.8

5.0

5.9

7.6

7.5

Average Brent oil price (USD/bbl)

54.2

43.7

52.4

98.9

108.7

 

 

 

 

 

 

 

Share information 4)

 

 

 

 

 

Diluted earnings per share (in USD)

1.40

(0.91)

(1.63)

1.21

2.14

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

175.20

158.40

123.70

131.20

147.00

Share price at New York Stock Exchange (USA) on 31 December (in USD)

21.42

18.24

13.96

17.61

24.13

Dividend paid per share (in USD) 5)

0.88

0.88

1.07

0.97

1.15

Weighted average number of ordinary shares outstanding (in millions)

3,268

3,195

3,179

3,180

3,181

 

 

 

 

 

 

 

1)

Total revenues and other income for 2013 are restated.

2)

See section 5.2 Use and reconciliation of non-gaap financial measures for net debt to capital employed ratio.

3)

Calculated ROACE based on Adjusted earnings after tax and capital employed. See section 5.2 Use and reconciliation of non-gaap financial measures.

4)

See section 5.1 Shareholder information for a description of how dividends are determined and information on share repurchases.

5)

Dividends for the third and fourth quarter 2016 and the first and second quarter 2017 were paid in 2017. From and including the third quarter of 2015, dividends were declared in USD. Dividends in previous periods were declared in NOK. Figures for 2015 and earlier periods are presented using the Central Bank of Norway year end rates for Norwegian kroner.

 

8   Statoil, Annual Report on Form 20-F 2017    


 

About the report

 

This document constitutes the Annual report on Form 20-F in accordance with the US Securities and Exchange Act of 1934 applicable to foreign private issuers, for Statoil ASA for the year ended 31 December 2017. A cross reference to the Form 20-F requirements are set out in section 5.10 in this report. The Annual report on Form 20-F and other related documents are filed with the US Securities and Exchange Commission (the SEC). The Annual report and Form 20-F are filed with the Norwegian Register of company accounts.

 

The Statoil Annual report and Form 20-F may be downloaded from Statoil’s website at [Statoil.com/annualreport2017]. References to this document or other documents on Statoil’s website are included as an aid to their location and are not incorporated by reference into this document. All SEC filings made available electronically by Statoil may be obtained from the SEC at 100 F Street, N.E., Washington D.CC. 20549, United States or on the SEC’s website at www.sec.gov

 

 

Statoil, Annual Report on Form 20-F 2017    9


2.1 Strategy and market overview

 

Statoil’s business environment

Market overview

In 2017 the world economy delivered the highest growth rate of the past six years. The world’s major economies are growing close to historical trends or above, and the emerging economies are recovering from their economic deceleration in 2016. The US economy is on a strong footing, with GDP growth estimated at 2.2% in 2017. Consumer spending, supported by higher employment, is the main driver of US growth. The Eurozone also showed robust growth estimated at 2.5%, thanks to private consumption and low inflation. In the UK, growth decelerated, with expected GDP growth at 1.8% due to uncertainty around the Brexit process. Chinese GDP growth has been reported at 6.9% in 2017, based on strong government policy stimulus, delivering an improvement in the growth rate for the first time since 2010. The Japanese economy performed relatively well, with an estimated growth rate of 1.8%, driven by a tight labour market, corporate earnings and a conducive external environment. As a notable exception, India at 6.5% growth, delivered below expectations as the economy had to adapt to the Goods and Services Tax and still felt the effects of demonetisation. Reduced inflationary pressure and appreciating currencies in Russia and Brazil have allowed central banks to cut interest rates, contributing to the countries’ economic recovery.

 

Looking forward, a robust demand picture and solid economic fundamentals should allow the expansion to continue. Among the risks that might affect such growth are geopolitical events and a too-fast monetary policy tightening from the central banks in key economies.

 

Global oil demand grew by 1.5 mmbbl per day in 2017 and global supply grew by 0.4 mmbbl per day. Decreasing oil prices in the first half of the year triggered both Opec and non-Opec countries to collectively honour their commitments to cut production. This resulted in stock draws and facilitated a gradual rebalancing of the market.

 

Overall, quarterly average European gas prices are up year-on-year throughout 2017. The first half of 2017 saw a downward trend in gas prices. However, in the second half of 2017, markets strengthened with demand growth in Asia leaving less LNG availability to serve a tight European market.

 

Oil prices and refining margins

A decreasing oil price in the first half of 2017 was followed by a strong second half with prices moving in an upward trajectory, closing the year at USD 66.5 per barrel. Refinery margins had a solid year fueled by strong demand in most products.

 

Oil prices
As in the previous two years, high volatility characterised the oil market. The average price for dated Brent crude in 2017 was USD 54.2 per barrel, up USD 10.5 per barrel from 2016. A relatively flat oil price fluctuating around USD 55 per barrel in the first couple of months was followed by a period of high volatility. Lingering worries about oversupply combined with surging output in Libya and Nigeria created a bearish sentiment with dated Brent bottoming out at USD 45 per barrel in late June. However, higher-than-expected demand and moderating global supply during the second half of 2017 put upward pressure on the commodity price. By the end of the third quarter, the price had reached almost USD 57 per barrel. Renewed buying interest in China and falling global stock piles facilitated continued rebalancing of the market throughout the fourth quarter. The upward pressure on the dated Brent oil price was strengthened even further by rising global geopolitical uncertainty, pushing prices to a two-year high of USD 62 per barrel in the first half of November. The Opec meeting in late November concluded with an agreement to extend oil supply cuts throughout 2018, with an option to review the deal in June. This gave support to the oil price through the last month of the year. Dated Brent was USD 66.5 per barrel on 31 December 2017. The futures market for Brent at the International Exchange Rate (ICE) was in contango until September before it shifted to backwardation and remained so for the rest of the year.

 

Over the course of 2017, global geopolitical unrest has been on the rise and received more attention as the market has become tighter.

 

US shale oil production has increased throughout 2017 due to continued productivity gains and cost reductions. The US is now delivering about 5 mmbbl per day of shale oil, with the Permian and Eagle Ford shale oil basins accounting for about two-thirds of the volumes. US crude oil exporters started to move cargoes toward high-growth markets in Asia as they capitalised on the favorable price differential. Development of Gulf Coast export capacity and crude price differentials are key determinants for future export levels.

 

Refining margins
Refining margins in Europe were strong in 2017. The moderate stock build in the first quarter of the year was followed by large draws in the next quarter due to strong demand. On the light end side, gasoline margins saw a moderate increase through the first half of the

 

10   Statoil, Annual Report on Form 20-F 2017    


 

year. High demand and strong prices for LPG, driven by changes in China’s energy mix, made the petrochemical industry take more naphtha, leaving less of the feedstock for making gasoline, eventually pushing prices. Stock draws in the US and strong demand in Europe supported diesel margins. The major impact of hurricane Harvey caused refining margins to peak by the end of the third quarter. A stronger physical crude oil market towards the end of the year put downward pressure on margins.

 

Natural gas prices

The upward trend in gas prices seen in the second half of 2016 continued into the first quarter of 2017, before taking a dip in second quarter 2017. The fourth quarter of 2017 experienced a robust price recovery.

 

Gas prices – Europe

NBP prices hit a decade low of USD 3 per mmBtu in August 2016, and increased towards an average of USD 5.7 per mmBtu in fourth quarter 2016. The climb continued into January 2017, averaging USD 6.6 per mmBtu, before falling throughout first and second quarter 2017 to USD 4.5 per mmBtu in June. Pipeline supply from the Norwegian Continental Shelf and Russia were at record highs of 117 bcm and 194 bcm respectively in 2017. However, the North-West Europe gas market has since late September 2017 been driven by a bullish combination of continued French nuclear outages, rallying coal prices, low hydro levels in Southern Europe and lower LNG availability in the Atlantic basin. The market tightened further due to the Rough storage shut-in and the new Groningen output ceiling, closing 2017 at USD 7.8 per mmBtu and resulting in an annual average of USD 5.8 per mmBtu.   

 

Gas prices – North America

The Henry Hub price remained stable throughout 2017, averaging USD 3 per mmBtu for the year. Prices peaked early in the year at USD 3.3 per mmBtu on seasonal uplift, before warmer weather weakened the market. Storage inventories have been consistently lower than levels last year, a main driver as to why prices are up year-on-year. The lack of a significant mid-year cooling related to demand peak left summer prices lower than normal and lower than the spring prices. In fourth quarter 2017, robust production growth has limited upside price risks and put a premium on winter heating loads as the market weighs new pipeline takeaway capacity slowly coming online in the Northeast.  

 

Global LNG prices

LNG prices in Asia ended 2016 at USD 9 per mmBtu. From here, monthly prices fell throughout first quarter 2017 and stabilised at USD 5.5 per mmBtu in second quarter 2017. The second half of the year experienced robust price recovery to an average of USD 9.4 per mmBtu in fourth quarter 2017, resulting in an annual average of USD 7.1 per mmBtu. Despite new LNG supply from Australia and the US, a marked pick-up in consumption across Asia has affected the market. Increased coal-to-gas switching to curb air pollution was seen in China. In South Korea and Taiwan gas stepped in for reduced nuclear capacity.

 

Statoil’s corporate strategy

Statoil is an energy company committed to long-term value creation in a low carbon future. Statoil will develop and maximise the value of its unique Norwegian continental shelf (NCS) position, its international oil and gas business and its growing new energy business, focusing on safety, value and carbon efficiency. Statoil is a values-based company where empowered people collaborate to shape the future of energy. 

 

Statoil's top priority in 2017 continued to be to conduct safe, secure and reliable operations with zero harm to people and the environment.

 

In 2017 Statoil launched its sharpened strategy. Geopolitical shifts, challenges in liquids resource replenishments, market cyclicality, structural changes to costs and increasing momentum towards low carbon implies uncertainty and volatility. To be prepared, Statoil is focusing on building a more resilient, diverse and option-rich portfolio, delivered by an agile organisation that embraces change and empowers its people. To deliver on the sharpened strategy, “always safe, high value, low carbon”, Statoil will continue to build opportunities to optimise its portfolio around the following portfolio areas:

 

·          Norwegian continental shelf – Build on unique position to maximise and develop long-term value

·          International oil & gas – Deepen core areas and develop growth options

·          New energy solutions – Create a material new industrial position

·          Midstream and marketing – Secure premium market access and grow value creation through cycles

The following strategic principles guide Statoil in actively shaping its future portfolio:

 

·          Cash generation capacity at all times – Generating positive cash flows from operations, even at low oil and gas prices, in order to sustain dividend and investment capacity through the economic cycles

·          Capex flexibility – Having sufficient flexibility in organic capital expenditure to be able to respond to market downturns and avoid value destructive measures

·          Capture value from cycles – Ensuring the ability and capacity to act counter-cyclically to capture value through the cycles

Statoil, Annual Report on Form 20-F 2017    11


 

·          Low-carbon advantage – Maintaining competitive advantage as a leading company in carbon efficient oil and gas production, while building a low-carbon business to capture new opportunities in the energy transition

In order to deliver on the strategy, Statoil has identified four key strategic enablers that will continue to support the business’s needs:

 

·          Safe and secure operations

·          Technology, digitalisation and innovation

·          Empowered people

·          Stakeholder engagement

Statoil has a target to implement CO2 emission reduction measures equivalent to 3 million tonnes annually from its emissions between 2017 and 2030 and continues to make progress towards this goal. A significant portfolio of projects and initiatives has been established through 2017 with variable maturity to accomplish the 2030 commitments. Further communication on this can be found in Statoil’s 2017 Sustainability Report.

 

Norwegian continental shelf – Build on unique position to maximise and develop long-term value

For more than 40 years, Statoil has explored, developed and produced oil and gas from the 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 efficiency, reliability, carbon emissions and lifespan of fields already in production. The NCS represents approximately two thirds of Statoil’s equity production at 1,334 mboe per day in 2017.

 

Exploration: Statoil continues to be a committed NCS explorer across mature, growth and frontier areas. In 2017, Statoil participated in 17 exploration wells on the NCS, resulting in 10 commercial discoveries. Statoil was awarded 31 licences in mature areas in Norway’s Awards for Predefined Areas (APA) 2017 round (result announced January 2018), 17 as operator and 14 as a non-operating partner

Development: Statoil has submitted five plans for development and operation in 2017: Njord, Bauge and Trestakk in the Norwegian Sea, Johan Castberg in the Barents Sea and Snorre Expansion Project in the North Sea. Johan Sverdrup Phase 1 is proceeding as scheduled and the pre-sanction for Johan Sverdrup Phase 2 was approved by the partners in the first quarter of 2017. The Aasta Hansteen project continued as planned and the Oseberg H Unmanned Wellhead Platform was installed in 2017.

Production: Gina Krog came on-stream in 2017. Statoil opened the Valemon onshore control room, enabling remote control.

Statoil will take over operatorship and equity in the Martin Linge field and Garantiana discovery. Two Cat J rigs, Askeladden and Askepott, were delivered to Statoil ready for digitalised operations at Gullfaks and Oseberg.

 

International oil and gas – Deepen core areas and develop growth options

International oil and gas production represented approximately one third of Statoil’s equity production at 745 mboe per day in 2017. Statoil will continue to explore, develop, and produce oil and gas opportunities outside Norway as part of deepening its international core areas, the US onshore operations and Brazil, and developing future growth options.

 

Exploration: Statoil continues to explore internationally for oil and gas. Statoil participated in 11 exploration wells internationally, four of which were discoveries. Statoil added exploration acreage in Brazil, South Africa, UK, Suriname and the US Gulf of Mexico and entered one new country, Argentina.

Development: Statoil continued to strengthen its strategic partnership with Petrobras in Brazil, continuing construction on Peregrino Phase II and improving the project economics. Offshore UK, Mariner A has been installed and is currently in the hook-up and commissioning phase.

Production: Alongside operator BP and other partners, Statoil has signed the agreement for a licence  extension by 25 years until 2049 for Azeri-Chirag Guneshli (ACG) with the Azerbaijan government and SOCAR. Statoil and BP, with Sonatrach, also extended the In Amenas Production Sharing Contract (PSC) by five years, from 2022 to 2027.

Statoil completed its divestment from the Canadian oil sands.

 

In Brazil, a 25% share in the producing Roncador field was acquired. Statoil also strengthened its position in the BM-S-8 licence, which includes the Carcara discovery, by acquiring QGEP’s interest and successfully bidding on the open acreage to the North, before farming down to ExxonMobil and Petrogal.

 

In the United States, Statoil continued to focus on increasing and sustaining the profitability of existing assets in the portfolio, which led to continued progress towards the targets of lowering its US portfolio net operating income break-even to below USD 50 per barrel and increasing production by 50% from 2014 to 2018.

 

 

New energy solutions – Create a material new industrial position

 

12   Statoil, Annual Report on Form 20-F 2017    


 

Statoil’s ambition is to maintain its advantage as a leading company in carbon efficient oil and gas production while building a low-carbon business to capture new opportunities in the energy transition. Statoil continues to explore new business opportunities in offshore wind, solar, carbon capture and storage (CCS) as well as other potential new energy markets. Statoil expects 15-20% of its investments to be directed towards new energy solutions by 2030.

 

Develop opportunities: Progress continues on the Arkona offshore wind farm operated by partner E.On. Statoil continues to evaluate a potential Norwegian carbon and capture storage as well as the feasibility of natural gas-to-hydrogen projects. In the United States, Statoil continues to mature the New York Wind Energy Area lease as “Empire Wind”. 

 

Operate assets: In 2017, Statoil completed and opened the Dudgeon Offshore Wind Park. Hywind Scotland, the world’s first floating wind farm, also started production.

 

Statoil completed a re-organisation of the Dogger Bank consortium Forewind in the UK, splitting ownership of three of the four projects 50/50 with partner SSE and with Innogy (RWE) taking sole ownership of the remaining project. In December Statoil submitted a bid in the non-subsidy Dutch offshore wind tender for Hollanse Kust Zuid I & II. Statoil also initiated its first move into solar by acquiring 50% of the ongoing Apodi solar project in Brazil from Scatec Solar.

 

Midstream and marketing – Secure premium market access and grow value creation through cycles

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 main focus has been on:

 

·          Safe, secure and efficient operations

·          Minimising carbon emissions and intensity

·          Securing flow assurance and premium market access for Statoil’s equity production and the State’s Direct Financial Interest (SDFI) volumes

·          Building and maintaining resilience through asset backed trading, value chain positioning and counter-cyclical actions

·          Focus on regional piped gas value chains and pursue selective trading positions in LNG

In 2017, Statoil chartered the ultra-large crude carrier (ULCC) TI Europe as part of its asset backed trading strategy. Statoil decided to phase out the Mongstad combined heat and power by end 2018 and commissioned the Polarled pipeline. Statoil continued work towards integrating digital solutions into decision making, shipping activities, and energy trading.

 

Strategy enablers

 

Safe and secure operations: Safety and security is Statoil’s top priority. In 2017, Statoil initiated and continued several measures to reinforce safety work in all areas including continuous co-operation with partners and suppliers. The primary efforts launched in 2017 were focused on safety (I am Safety), security (2020 Security Roadmap), and IT security (New Information Technology Strategy) and are described in the chapter "Safeguarding people, the environment and assets: Safety and security.”

 

Technology, digitalisation and innovation: Statoil's technology strategy provides long-term guidance for technology development and implementation. In 2017, Statoil launched its digital roadmap and established its Digital Centre of Excellence and Digital Academy. Statoil, in partnership with Techstars, established an energy-focused accelerator in Oslo.

 

Empowered people: Statoil promotes a culture of collaboration, innovation and safety, guided by its values. Statoil has continued to develop its employees and attract talents to deliver on the future-fit portfolio ambition.

 

Stakeholder engagement: Statoil engages with stakeholders to secure industrial legitimacy, its social contract, trust and strategic support from stakeholders. This engagement extends to internal and external collaboration, partnerships, and other co-operation with suppliers, partners, governments, NGOs and communities in which Statoil operates.

 

Group outlook

Statoil’s plans address the current business 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.

 

Statoil, Annual Report on Form 20-F 2017    13


 

·          Organic capital expenditures[4] for 2018 are estimated at around USD 11 billion

·          Statoil intends to continue to mature its large portfolio of exploration assets and estimates a total exploration activity level of around USD 1.5 billion for 2018, excluding signature bonuses

·          Statoil’s ambition is to keep the unit of production cost in the top quartile of its peer group

·          For the period 2017 – 2020, production growth is expected to be around 3-4% CAGR (Compound Annual Growth Rate)

·          Production for 2018 is estimated to be 1-2% above the 2017 level

·          Scheduled maintenance activity is estimated to reduce equity production by around 30 mboe per day for the full year of 2018

 

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. Deferral of production to create future value, gas off-take, timing of new capacity coming on stream, operational regularity, activity level, development in the prices of goods, raw materials and services that are used in the development and operation of oil and gas producing assets, contractor performance, as well as uncertainty around the closing of the announced transactions represent the most significant risks related to the foregoing guidance. For further information, see section 5.7 Forward-Looking Statements.

 

  

 


[4] See section 5.2 for non-GAAP measures


 

2.2 BUSINESS OVERVIEW

 

History

On 18 September 1972, Statoil was formed by a decision of the Norwegian parliament and incorporated as a limited liability company under the name Den norske stats oljeselskap AS. Being a company owned 100% by the Norwegian State, Statoil's initial role was to be the government's commercial instrument in the development of the oil and gas industry in Norway. Growing in parallel with the Norwegian oil and gas industry, Statoil’s operations have primarily been focused on exploration, development and production of oil and gas on the Norwegian continental shelf (NCS).

 

During the 1980s, Statoil grew substantially through the development of the NCS. Statoil also became a major player in the European gas market by entering into 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. This line of business was fully divested in 2012.

 

In 2001, Statoil was listed on the Oslo and New York stock exchanges and became a public limited company under the name Statoil ASA, 67% majority owned by the Norwegian State. Since then, substantial investments both on the NCS and internationally, have grown our business. The merger with Hydro's oil and gas division on 1 October 2007 further strengthened Statoil’s ability to fully realise the potential of the NCS. Enhanced utilisation of expertise to design and manage operations in various environments have expanded our upstream activities outside our traditional area of offshore production. This includes the development of heavy oil and shale gas projects and projects that focus on other forms of energy, especially on offshore wind, but also on solar and carbon capture and storage.

 

The board of directors of Statoil have proposed to change the name of the company to Equinor. The new name supports the company’s strategy and development as a broad energy company.  The suggested name change will be proposed to the shareholders in a resolution to the annual general meeting on 15 May 2018.

 

Activities

Statoil is an international energy company primarily engaged in oil and gas exploration and production activities, organised under the laws of Norway and subject to the provisions of the Norwegian Public Limited Liability Companies Act. In addition to being the leading operator on the NCS, Statoil has also substantial international activities and is present in several of the most important oil and gas provinces in the world. Our activities span operations in more than 30 countries and employs 20,245 employees worldwide.

 

Our access to crude oil in the form of equity, governmental and third-party volumes makes Statoil a large seller of crude oil, and Statoil is the second-largest supplier of natural gas to the European market. Processing, refining, offshore wind and carbon capture and storage is also part of our operations.

 

Statoil’s registered office is at Forusbeen 50, 4035 Stavanger, Norway and the telephone number of its registered office is +47 51 99 00 00.

 

Our competitive position

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. When acquiring assets and licences for exploration, development and production and in refining, marketing and trading of crude oil, natural gas and related products, Statoil competes with other integrated oil and gas companies.

 

Statoil's ability to remain competitive will depend, among other things, on continuous focus on reducing costs and improving efficiency. It will also depend on technological innovation to maintain long-term growth in reserves and production, the ability to seize opportunities in new areas and utilise new opportunities for digitalisation.

 

The information about Statoil's competitive position in the strategic report is based on a number of sources; e.g. 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.

 

Continuous improvements

Statoil focus on continuously efficiency improvements as a response to the industrial challenge that has emerged over the recent years characterised by reducing prices for our products and declining returns. More specifically, the ambition is to realise positive

Statoil, Annual Report on Form 20-F 2017    15


 

production effects and capital expenditures and operating costs savings to improve financial results and cash-flows. In 2017, Statoil realised efficiency improvements of USD 1.3 billion on top of the already achieved USD 3.2 billon since 2013.

 

Establishment of Digital Centre of Excellence

In 2017 Statoil accelerated the digitalisation efforts by establishing a Digital Centre of Excellence and launching a digital road map. The goal is to significantly increase our utilisation of data, sophisticated analytics and robotics. In addition, Statoil aims to improve safety, reduce our carbon footprint and increase profitability. Statoil see potential by utilising data across IT applications and organisational boundaries. Combining data and learning across Statoil’s disciplines could provide a better basis for decision-making, new business opportunities, and increased collaboration externally with our partners, suppliers and other lines of business.

 

CORPORATE STRUCTURE

Business areas

Statoil's operations are managed through the following eight business areas:

 

Development & Production Norway (DPN)

DPN manages Statoil’s upstream activities on the NCS and explores for and extracts crude oil, natural gas and natural gas liquids. The business area’s ambition is to continue Statoil’s leading position on the NCS and ensure maximum value creation through continuously improved HSE and operational performance.

 

Development & Production International (DPI)

DPI manages Statoil’s worldwide upstream activities excluding the DPN and Development & Production USA (DPUSA) business areas. It explores for and extracts crude oil, natural gas and natural gas liquids. DPI's ambition is to build a large and profitable international production portfolio comprising activities ranging from accessing new opportunities to delivering on profitable projects in a range of complex environments.

 

Development & Production USA (DPUSA)

DPUSA manages Statoil’s 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.

 

Marketing, Midstream & Processing (MMP)

MMP manages Statoil’s marketing and trading activities related to oil products and natural gas, transportation, processing and manufacturing, and the development of oil and gas. MMP seeks to maximise value creation in Statoil's midstream and marketing business.

 

Technology, Projects & Drilling (TPD)

TPD is responsible for the global project portfolio, well delivery, new technologies and sourcing across Statoil. TPD seeks to provide safe and secure, efficient and cost-competitive global well and project delivery, technological excellence, and research and development. Cost-competitive procurement is an important contributory factor for maximising value for Statoil.

 

Exploration (EXP)

EXP manages Statoil’s worldwide exploration activities with the aim of positioning 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  long-term goal to complement our oil and gas portfolio with profitable renewable energy and other low-carbon energy solutions. NES is responsible for wind farms and carbon capture and storage as well as other renewable energy and low-carbon energy solutions.

 

Global Strategy & Business Development (GSB)

GSB develops the corporate strategy and manages business development and merger and acquisition activities for Statoil. The ambition of the GSB business area is to closely link corporate strategy, business development and merger and acquisition activities to actively drive Statoil's corporate development.

Reporting segments

With effect as of the third quarter 2017, segment names have been changed for the reporting segments DPN and DPI. New names are Exploration & Production Norway (E&P Norway) and Exploration & Production International (E&P International), respectively. There are no changes to other reporting segments, and business area’s names remain unchanged.

 

16   Statoil, Annual Report on Form 20-F 2017    


 

Statoil reports its business in the following reporting segments:

·          E&P Norway reporting segment – Exploration & Production Norway – the DPN business area

·          E&P International reporting segment – Exploration & Production International, which combines the DPI and the DPUSA business areas

·          MMP reporting segment - Marketing, Midstream & Processing – the MMP business area

·          Other – which includes activities in NES, TPD, GSB and Corporate and support functions

 

Activities relating to the EXP business area are fully allocated to - and presented in - the relevant exploration and production reporting segment. Activities relating to the TPD and GSB business areas are partly allocated to - and presented in - the relevant exploration and production reporting segments.

Presentation

In the following sections in the report, the operations are reported according to the reporting segment. Underlying activities or business clusters are presented according to how the reporting segment organises its operations. See note 3 Segments  to the Consolidated financial statements for further details.

 

As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based on geographic areas. Statoil’s geographical areas are defined by country and continent and consist of Norway, Eurasia excluding Norway, Africa, US and Americas excluding US.

 

SEGMENT REPORTING

Internal transactions in oil and gas volumes occur between our reporting segments before being sold in the market. The pricing policy for internal transfers is based on estimated market prices. For further information, see section 2.8 Operational performance under Production volumes and prices.

 

We eliminate intercompany sales when combining the results of reporting segments. Intercompany sales include transactions recorded in connection with our oil and natural gas production in the E&P Norway and the E&P International reporting segments, and also in connection with the sale, transportation or refining of our oil and natural gas production in the MMP reporting segment. Certain types of transportation costs are reported in both the MMP and the DPUSA business areas.

 

The DPN business area produces oil and natural gas which is sold internally to the MMP business area. A large share of the oil produced by the DPI and DPUSA business areas is also sold through the MMP business area. The remaining oil and gas from the DPI and the DPUSA business areas is sold directly in the market. For intercompany sales and purchases, Statoil has established a market-based transfer pricing methodology for the oil and natural gas that meets the requirements for applicable laws and regulations.

 

In 2017, the average transfer price for natural gas was USD 4.33 per mmbtu. The average transfer price was USD 3.42 per mmbtu in 2016 and USD 5.17 in 2015. For oil sold from DPN to MMP, the transfer price is the applicable market-reflective price minus a cost recovery rate.

The following table shows certain financial information for the four reporting segments, including intercompany eliminations for each of the years in the three-year period ending 31 December 2017. For additional information, see note 3 Segments to the Consolidated financial statements.

 

Segment performance

  For the year ended 31 December

(in USD million)

2017

2016

2015

 

 

 

 

 

Exploration & Production Norway

 

 

 

Total revenues and other income

17,692

13,077

17,339

Net operating income/(loss)

10,485

4,451

7,161

Non-current segment assets1)

30,278

27,816

27,706

 

 

 

 

 

Exploration & Production International

 

 

 

Total revenues and other income

9,256

6,657

8,200

Net operating income/(loss)

1,341

(4,352)

(8,729)

Non-current segment assets1)

36,453

36,181

37,475

 

 

 

 

 

Marketing, Midstream & Processing

 

 

 

Total revenues and other income

59,071

44,979

58,106

Net operating income/(loss)

2,243

623

2,931

Non-current segment assets1)

5,137

4,450

5,588

 

 

 

 

 

Other

 

 

 

Total revenues and other income

87

39

354

Net operating income/(loss)

(239)

(423)

(129)

Non-current segment assets1)

390

352

690

 

 

 

 

 

Eliminations 2)

 

 

 

Total revenues and other income

(24,919)

(18,880)

(24,357)

Net operating income/(loss)

(59)

(219)

133

Non-current segment assets1)

-

-

-

 

 

 

 

 

Statoil group

 

 

 

Total revenues and other income

61,187

45,873

59,642

Net operating income/(loss)

13,771

80

1,366

Non-current segment assets1)

72,258

68,799

71,458

 

 

 

 

 

1)

Deferred tax assets, pension assets and non-current financial assets are not allocated to segments.

2)

Includes elimination of inter-segment sales and related unrealised profits, mainly from the sale of crude oil and products.

Inter-segment revenues are based upon estimated market prices.

 

 

 

Statoil, Annual Report on Form 20-F 2017    17


 

18   Statoil, Annual Report on Form 20-F 2017    


 

The following tables show total revenues by country.

 

2017 Total revenues and other income by country

Crude oil

Natural gas

Natural gal liquids

Refined

products

Other

Total sales

(in USD million)

 

 

 

 

 

 

 

Norway

23,087

9,741

4,948

6,463

1,026

45,264

USA

5,726

1,237

668

1,497

1,237

10,365

Sweden

0

0

0

1,268

10

1,277

Denmark

0

0

0

2,195

12

2,208

Other

706

442

31

0

705

1,884

 

 

 

 

 

 

 

Total revenues (excluding net income (loss)

from equity accounted investments and other income

29,519

11,420

5,647

11,423

2,991

60,999



 

2016 Total revenues and other income by country

Crude oil

Natural gas

Natural gas liquids

Refined

products

Other

Total sales

(in USD million)

 

 

 

 

 

 

 

Norway

20,544

7,973

3,580

4,135

(497)

35,735

US

3,073

957

455

1,110

867

6,463

Sweden

0

0

0

1,379

(53)

1,326

Denmark

0

0

0

1,518

14

1,532

Other

690

272

1

0

(26)

936

 

 

 

 

 

 

 

Total revenues (excluding net income (loss)

from equity accounted investments and other income

24,307

9,202

4,036

8,142

305

45,993



 

2015 Total revenues and other income by country

Crude oil

Natural gas

Natural gas liquids

Refined

products

Other

Total sales

(in USD million)

 

 

 

 

 

 

 

Norway

22,741

10,811

4,932

5,644

1,454

45,582

US

3,718

1,133

532

1,605

933

7,922

Sweden

0

0

0

1,762

115

1,877

Denmark

0

0

0

1,750

8

1,759

Other

1,347

446

17

0

722

2,532

 

 

 

 

 

 

 

Total revenues (excluding net income (loss)

from equity accounted investments and other income

27,806

12,390

5,482

10,761

3,232

59,671

 

 

 

 

 

 

 

 

 

 

 

 

 

 

RESEARCH AND DEVELOPMENT

Statoil is a technology-intensive company and research and development is an integral part of our strategy. Our technology strategy is about prioritising technology for value creation that enables us to achieve growth and access, and sets the direction for technology development and implementation for the future. Our focus is on low cost, low carbon solutions and re-using standardised technologies.

 

We continuously research, develop and deploy innovative technologies to create opportunities and enhance the value of Statoil’s current and future assets. Statoil’s technology development activities aim to reduce field development, drilling and operating costs, and CO2 and other greenhouse gas emissions. We utilise a range of tools for the development of new technologies:

 

·          In-house research and development

·          Cooperation with academia and research institutes

·          Collaborative development projects with our major suppliers

·          Project related development as part of our field development activities

·          Direct investment in technology start-up companies through our Statoil Technology Invest venture activities

·          Invitation to open innovation challenges as part of Statoil Innovate

 

Statoil, Annual Report on Form 20-F 2017    19


 

Research and development expenditures were USD 307 million in 2017, USD 298 million in 2016 and USD 344 million in 2015,


20   Statoil, Annual Report on Form 20-F 2017    


 

2.3 E&P Norway
– exploration & production NORWAY

 


OVERVIEW

The Exploration & Production Norway (E&P Norway) reporting segment is responsible for exploration, field development and operations on the NCS which includes the North Sea, the Norwegian Sea and the Barents Sea. E&P Norway aims to ensure safe and efficient operations and to maximise the value potential from the NCS. For proved reserves development see Development of reserves in Proved oil and gas reserves in section 2.8 Operational performance.

 

For 2017, E&P Norway reports NCS production from 38 Statoil operated fields, 10 partner operated fields, and equity accounted production from Lundin Petroleum AB.

 

 

Statoil, Annual Report on Form 20-F 2017    21


 

 

 

Key events and portfolio developments in 2017:

·          In March, the decision was made to proceed with the Johan Sverdrup phase 2 development, awarding FEED contracts. Investment decision and submission of Plan for Development and Operation is expected in the second half of 2018

·          On 26 March, the Flyndre field came on stream with Maersk Oil UK Ltd as operator

·          On 27 March, Statoil submitted the revised Plan for Development and Operation for the Njord field, and Plan for Development and Operation for the Bauge field. Both submitted plans were subsequently approved on 20 June 2017

·          On 15 April, the Norwegian authorities approved the Plan for Development and Operation of the Trestakk discovery on the Halten Bank in the Norwegian Sea

·          On 30 June, the Gina Krog field went on stream

·          On 1 July, Statoil assumed operatorship of the Sigyn field in the North Sea

·          In July, Statoil and partners decided to develop the Snefrid Nord gas discovery. The field will be tied back to Aasta Hansteen

·          On 28 July, the Byrding field came on stream

·          In September, Statoil achieved NCS climate target two years ahead of schedule

·          In October, Barents drilling campaign concludes with the Kayak find of commercial size

·          In November, opening of the Valemon control room, the first platform in Statoil’s portfolio remotely-controlled from land

·          On 27 November, Statoil announced the decision to buy Total’s equity stakes and to assume the operatorships of the Martin Linge field and the Garantiana discovery. The transactions are expected to be finalised in late March 2018

·          On 5 December, Statoil submitted the Plan for Development and Operation for the Johan Castberg field in the Barents Sea

·          In December, Cat J rigs Askeladden and Askepott preparing arrival at the Gullfaks and Oseberg fields. Drilling is expected to start in early 2018

·          On 21 December, Statoil submitted the Plan for Development and Operation of the Snorre Expansion project, increasing the recovery from the Snorre field by close to 200 million barrels

  

 

Fields in production on the NCS

The table below shows E&P Norway's average daily entitlement production for the years ending 31 December 2017, 2016 and 2015. Production in 2017 increased due to higher flex gas off-take, contributions from new fields and fewer turnarounds.

 

Average daily entitlement production

  For the year ended 31 December

 

2017

 

2016

 

2015

 

Oil and NGL

Natural gas

 

 

Oil and NGL

Natural gas

 

 

Oil and NGL

Natural gas

 

Area production

mbbl/day

mmcm/day

mboe/day

 

mbbl/day

mmcm/day

mboe/day

 

mbbl/day

mmcm/day

mboe/day

 

 

 

 

 

 

 

 

 

 

 

 

Statoil operated fields

 505  

 100  

 1,136  

 

 511  

 86  

 1,049  

 

 545  

 88  

 1,100  

Partner operated fields

 70  

 17  

 179  

 

 70  

 17  

 177  

 

 50  

 13  

 132  

Equity accounted production

 19  

 -    

 19  

 

 8  

 -    

 8  

 

 -    

 -    

 -    

 

 

 

 

 

 

 

 

 

 

 

 

Total

 594  

 118  

 1,334  

 

 589  

 103  

 1,235  

 

 595  

 101  

 1,232  

22   Statoil, Annual Report on Form 20-F 2017    


 

The following tables show the NCS entitlement production by fields in which Statoil was participating during the year ended 31 December 2017.

 

Average daily entitlement production

Geographical area

Statoil's equity interest in %

 

On stream 

Licence expiry date

 

Average production in 2017 mboe/day

 

 

Field

 

 

 

 

 

 

 

 

 

Statoil operated fields

 

 

 

  

  

 

  

Troll Phase 1 (Gas)

The North Sea

30.58

 

1996

2030

 

200

Oseberg

The North Sea

49.30

 

1988

2031

 

101

Gullfaks 

The North Sea

51.00

 

1986

2036

 

96

Åsgard 

The Norwegian Sea

34.57

 

1999

2027

 

93

Visund 

The North Sea

53.20

 

1999

2034

 

67

Kvitebjørn

The North Sea

39.55

 

2004

2031

 

54

Tyrihans

The Norwegian Sea

58.84

 

2009

2029

 

54

Grane

The North Sea

36.61

 

2003

2030

 

47

Snøhvit

The Barents Sea

36.79

 

2007

2035

 

44

Troll Phase 2 (Oil)

The North Sea

30.58

 

1995

2030

 

39

Sleipner Vest

The North Sea

58.35

 

1996

2028

 

39

Statfjord Unit

The North Sea

44.34

 

1979

2026

 

38

Gudrun

The North Sea

36.00

 

2014

2028

 

35

Snorre 

The North Sea

33.28

 

1992

2018

1)

28

Valemon

The North Sea

53.78

 

2015

2031

 

26

Mikkel 

The Norwegian Sea

43.97

 

2003

2024

 

21

Fram 

The North Sea

45.00

 

2003

2024

 

20

Kristin

The Norwegian Sea

55.30

 

2005

2033

2)

19

Alve

The Norwegian Sea

85.00

 

2009

2029

 

17

Gina Krog

The North Sea

58.70

 

2017

2032

 

15

Urd

The Norwegian Sea

63.95

 

2005

2026

 

12

Heidrun 

The Norwegian Sea

13.04

 

1995

2024

3)

11

Vigdis area 

The North Sea

41.50

 

1997

2024

 

10

Sleipner Øst

The North Sea

59.60

 

1993

2028

 

9

Tordis area 

The North Sea

41.50

 

1994

2024

 

9

Morvin

The Norwegian Sea

64.00

 

2010

2027

 

8

Sigyn

The North Sea

60.00

 

2002

2022

4)

6

Norne

The Norwegian Sea

39.10

 

1997

2026

 

5

Gungne 

The North Sea

62.00

 

1996

2028

 

4

Statfjord Nord

The North Sea

21.88

 

1995

2026

 

2

Heimdal

The North Sea

29.44

 

1985

2021

 

2

Veslefrikk 

The North Sea

18.00

 

1989

2020

5)

2

Byrding

The North Sea

70.00

 

2017

2024

 

2

Statfjord Øst

The North Sea

31.69

 

1994

2026

6)

1

Sygna 

The North Sea

30.71

 

2000

2026

7)

1

Fram H Nord

The North Sea

49.20

 

2014

2024

8)

0

Gimle 

The North Sea

65.13

 

2006

2034

9)

0

Sindre

The North Sea

52.34

 

2017

2023

 

0

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Statoil operated fields

 

 

 

 

1,136

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Statoil, Annual Report on Form 20-F 2017    23


 

Average daily entitlement production

Geographical area

Statoil's equity interest in %

Operator 

On stream 

Licence expiry date

 

Average production in 2017 mboe/day

 

 

Field

 

 

 

 

 

 

 

 

 

Partner operated fields

 

 

 

 

 

 

 

Ormen Lange

The Norwegian Sea

25.35

A/S Norske Shell

2007

2041

10)

74

Skarv

The Norwegian Sea

36.16

Aker BP ASA

2013

2033

11)

39

Ivar Aasen

The North Sea

41.47

Aker BP ASA

2016

2029

12)

21

Goliat

The Barents Sea

35.00

Eni Norge AS

2016

2042

 

15

Ekofisk area 

The North Sea

7.60

ConocoPhillips Skandinavia AS

1971

2028

 

14

Marulk

The Norwegian Sea

50.00

Eni Norge AS

2012

2025

 

10

Vilje

The North Sea

28.85

Aker BP ASA

2008

2021

 

3

Ringhorne Øst

The North Sea

14.82

Point Resources AS

2006

2030

 

1

Enoch

The North Sea

11.78

Repsol Sinopec UK Ltd.

2007

2024

 

0

Flyndre

The North Sea

0.47

Maersk Oil UK Ltd.

2017

2028

 

0

 

 

 

 

 

 

 

 

Total partner operated fields

 

 

 

 

179

 

 

 

 

 

 

 

 

Equity accounted production

 

 

 

 

 

 

 

Lundin Petroleum AB

 

20.10

Lundin Petroleum AB

 

 

 

19

 

 

 

 

 

 

 

 

Total E&P Norway including share of equity accounted production

 

 

1,334

 

1)  PL089 expires in 2024 and PL057 expires in 2018.

2)  PL134D expires in 2027 and PL199 expires in 2033.

3)  PL095 expires in 2024 and PL124 expires in 2025.

4)  Transfer of operatorship from ExxonMobil to Statoil on 1 July 2017.

5)  PL052 expires in 2020 and PL053 in 2031.

6)  PL037 expires in 2026 and PL089 expires in 2024.

7)  PL037 expires in 2026 and PL089 expires in 2024.

8)  PL090G expires in 2024 and PL248E expires in 2035.

9)  PL120B expires in 2034 and PL050DS expires in 2023.

10)  PL209/250 expires in 2041 and PL208 expires in 2040.

11)  PL212/262 expires in 2033 and PL159 expires in 2029.

12)  PL001B, PL457BS and PL242 expire in 2036. PL 338BS expire in 2029.

 

 

 

 

  

Main producing fields on
the NCS


Statoil operated fields

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

 

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 to the Oseberg Field Centre for processing and transportation.

Gullfaks was developed with three platforms. Since production started on Gullfaks in 1986, several satellite fields have been developed with subsea wells that are remotely controlled from the Gullfaks A and C platforms.

 

24   Statoil, Annual Report on Form 20-F 2017    


 

The Åsgard field includes the Åsgard A production and storage ship for oil, the Åsgard B semi-submersible floating production platform for gas and condensate, and the Åsgard C storage vessel for oil and condensate. Åsgard C is also storage for oil produced at Kristin and Tyrihans. In 2015 Statoil started the world first subsea gas compressor train on Åsgard, and the second train was started in February 2016. Mikkel and Morvin are tie-ins to Åsgard. The Trestakk development will be a tie-in to Åsgard A with production start planned for 2019.

 

Visund is an oil and gas field that includes a floating drilling, production and living quarter unit and two subsea templates.

 

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

 

Partner-operated fields

Ormen Lange operated by A/S Norske Shell, is a deepwater gas field in the Norwegian Sea. The well stream is transported to an onshore processing and export plant at Nyhamna. Gassco AS became operator of Nyhamna JV from 1 October 2017, with Shell as technical service provider.

 

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

 

Ivar Aasen  is operated by Aker BP ASA. It is an oil and gas field located in the North Sea. 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.

 

Goliat  is operated by Eni Norge AS. It is the first oil field developed in the Barents Sea. The field consists of subsea wells tied back to a circular floating production, storage and offloading vessel (FPSO). The oil is offloaded to shuttle tankers.

 

Ekofisk is operated by ConocoPhillips Skandinavia AS. It consists of the Ekofisk, Tor, Eldfisk and Embla fields.  

 

Marulk is operated by Eni Norge AS. It is a gas- and condensate field developed as a tie-back to the Norne FPSO.

 

Exploration on the NCS

Statoil holds exploration acreage and actively explores for new resources in all three regions on the NCS, the Norwegian Sea, the North Sea and the Barents Sea.

Statoil was awarded 31 licences (17 as operator) in the Awards for Predefined Areas (APA) round 2017 for mature areas and completed several farm-in transactions with other companies.

Throughout 2017, as part of the industry initiative Barents Sea Exploration Collaboration (BaSEC), Statoil and its partners have drilled 6 wells in the Barents Sea and are planning to continue drilling wells in the area also in 2018.

In 2017 Statoil and its partners completed 17 exploratory wells and made 10 commercial and 3 non-commercial discoveries in Norway. In 2018 Statoil expects to complete 25-30 exploration wells on the NCS, with exploration near existing infrastructure to be the core of the activity plan.

 

 

 

 

  

 

 

Exploratory wells drilled1)

2017

2016

2015

 

 

 

 

North Sea

 

 

 

Statoil operated

5

9

11

Partner operated

1

2

3

Norwegian Sea

 

 

 

Statoil operated

5

2

5

Partner operated

0

0

1

Barents Sea

 

 

 

Statoil operated

5

0

0

Partner operated

1

1

1

Total (gross)

17

14

21

 

1) Wells completed during the year, including appraisals of earlier discoveries.

 

Statoil, Annual Report on Form 20-F 2017    25


 

 

Fields under development on the NCS

Statoil’s major development projects on the NCS as of 31 December 2017:

 

Oseberg Vestflanken 2 (Statoil 49.3%, operator) is the development of the oil and gas structures Alfa, Gamma and Kappa. The well stream will be routed to the Oseberg field centre through a new pipeline. The discoveries will be developed using an unmanned wellhead platform. Production is expected to start in mid-2018.

 

Aasta Hansteen  (Statoil 51%, operator) is a deep-water gas discovery in the Norwegian Sea. The field development includes three subsea templates tied in to a floating processing unit with gas export through a new pipeline, Polarled, to Nyhamna and further export through the Langeled pipeline. The Aasta Hansteen processing unit can also serve as a hub for other potential discoveries in the area. On 11 November 2017, the drilling of the first well of the Aasta Hansteen field development commenced. The topside and substructure were integrated in December 2017 in Norway. Production is expected to start in second half of 2018.

 

Johan Sverdrup (Statoil 40.03%, operator, with additional 4.54% indirect interest held through Lundin)  is an oil discovery in the North Sea. Phase 1 of the development will consist of 35 production and water injection wells and a field centre with four platforms: A living quarter platform, a wellhead platform with permanent drilling facility, a processing platform and a riser and utility platform. Crude oil will be exported to Mongstad through a 274 km designated pipeline, and gas will be exported to the gas processing facility at Kårstø through a 156 km pipeline via a subsea connection to the Statpipe pipeline. As at the end of 2017, eight production wells and nine water injection wells have been drilled. Production is expected to start late fourth quarter 2019.

 

Utgard (Statoil 38.44% interest in the Norwegian and 38% in the UK sector, operator) is a gas and condensate discovery in the North Sea. The development includes two wells in a standard subsea concept, with one drilling target on each side of the UK-Norwegian maritime border. Gas and condensate will be piped through a new pipeline to the Sleipner field for processing and further transportation to market.  In January 2017, the Plan for Development and Operation and the field development plan were approved by the Norwegian and UK authorities. Production is expected to start in fourth quarter 2019.

 

Trestakk (Statoil 59.1%, operator) is an oil discovery with associated gas on Haltenbanken. It will be developed as a subsea tie-back to Åsgard A, comprising one subsea template and one satellite with three producers and two injectors. In March 2017, the Plan for Development and Operation was approved by the Norwegian authorities. Production is expected to start in 2019.

 

Martin Linge (Statoil 19%, and upon consummation of the acquisition from Total, 70%) is an oil and gas field operated by Total, near the British sector of the North Sea. The reservoir is complex with gas under high pressure and high temperatures. In late November 2017, Statoil and Total announced that Statoil will purchase Total’s interest (51%) and assume the operatorship of Martin Linge, with an effective date, upon consummation, of January 1, 2018. The transaction is subject to certain conditions and is expected to close in late March 2018. The development includes a fixed steel jacket platform with processing and export facilities, with electric power to be supplied from Kollsnes. Total, the current operator, expects production to start in 2019.

 

Njord future (Statoil 20%, operator) is a development to enable safe, reliable and efficient exploitation of the Njord and Hyme oil discoveries through to 2040. The development comprises an upgrade of the Njord A platform, an optimal oil export solution and drilling of 10 new wells. The Plan for Development and Operation was approved on 20 June 2017. Production is expected to start in late 2020.

 

Snorre expansion (Statoil 33.28%, operator) is a development to produce the remaining commercial oil reserves on the Snorre field. The Plan for Development and Operation of the field was submitted to the Norwegian authorities on 21 December 2017. The concept consists of six subsea templates, with four well slots each. Each slot will have the possibility for either production or injection. 24 wells will be drilled, 12 production wells and 12 injection wells. Production is expected to start in 2021.

 

Johan Castberg (Statoil 50%, operator) is the development of the three oil discoveries Skrugard, Havis and Drivis, located some 140 kilometres northwest of Hammerfest. The development includes a production vessel and a subsea development with 30 wells, ten subsea templates and two satellite structures. The Plan for Development and Operation of the field was submitted to the Norwegian authorities on 5 December 2017. Production is expected to start in 2022.





26   Statoil, Annual Report on Form 20-F 2017    


 

 

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.

 

Huldra ceased production in September 2014, after 13 years in production. The permanent plugging and abandonment of wells was finalised in 2017, and removal of platform is planned for in 2019.

 

Volve ceased production in September 2016, after more than eight years in production. The permanent plugging of wells was finalised during 2016, and the removal of subsea facilities is expected to be completed in 2018.

 

During 2017, there were permanent plugging and abandonment operations at Statfjord, Heidrun, Veslefrikk, Troll, Åsgard, Njord, Visund, Skuld and Tune. The partner-operated fields Ekofisk and Ormen Lange also had ongoing plugging and abandonment activities.

 

For further information about decommissioning, see note 2 Significant accounting policies to the Consolidated financial statements.

 

Statoil, Annual Report on Form 20-F 2017    27


 

2.4 E&P International – exploration & PRODUCTION INTERNATIONAL

 

E&P International overview

Statoil is present in several of the most important oil and gas provinces in the world. Exploration & Production International (E&P International) reporting segment covers development and production of oil and gas outside the Norwegian continental shelf (NCS).

 

E&P International is present in nearly 30 countries and had production in 12 countries in 2017. E&P International produced 36% of Statoil's total equity production of oil and gas in 2017. For information about proved reserves development see section 2.8 Operational performance under Proved oil and gas reserves.

 

The map shows the countries where E&P International has activity.


Key events and portfolio developments in 2017 and early 2018:


28   Statoil, Annual Report on Form 20-F 2017    


 

·         In January 2017, the plan for development and operation for the Utgard field was approved by the Norwegian and UK authorities. The Utgard field spans the UK-Norway maritime border. For more information, see Fields under development on the NCS in section 2.3 E&P Norway

·        In February, the In Amenas Gas Compression project in Algeria came into operation

·        On 31 January, the transaction to divest Statoil’s 100% owned Kai Kos Dehseh (KKD) oil sands projects in the Canadian province of Alberta to Athabasca Oil Corporation (AOC) was completed. The transaction covers the producing Leismer asset and the undeveloped Corner project, along with a number of contracts associated with Leismer’s production. Following this transaction, Statoil no longer owns or operates any oil sands assets. As part of the transaction, Statoil will own just below 20% of AOC’s shares, and this will be managed as a financial investment. For more information about the transaction see note 4 Acquisitions and divestments to the Consolidated financial statements

·         In March, Statoil was awarded 13 leases in US Gulf of Mexico

·         In March, Statoil was awarded six new licences, five as operator, in the 29th Offshore Licensing Round in UK

·         In April, Statoil acquired an additional 14% working interest in existing Statoil-operated unconventional onshore assets in the Appalachian  region from Northwood Energy Corporation.

·         In April, the Vito (Statoil 37%, Shell operator) offshore discovery received approval for its concept development and selection

·         In May, the Stampede (Statoil 25%, Hess operator) asset’s offshore platform was successfully installed; and subsea work was completed and all three wells were ready at year end 2017. Production commenced with first oil in January 2018.

·         In June, Statoil signed a swap agreement with BP regarding exploration permits in the Great Australian Bight and became operator and 100% equity interest holder in exploration permits EPP39 and EPP40 while Statoils equity interest in EPP37 and EPP38 were transferred to BP

·         In July, Statoil and Queiroz Galvão Exploração e Produção (QGEP) signed an agreement for Statoil to acquire QGEP’s 10% interest in the Statoil operated BM-S-8 licence in Brazil, thereby increasing Statoil’s interest in the licence to 76%. The transaction was completed in December.  For more information about the transaction see note 4 Acquisitions and divestments to the Consolidated financial statements  

·         In September, Statoil completed transactions in South Africa for exploration rights, one with ExxonMobil Exploration and Production South Africa acquiring an interest in Transkei Algoa and one with OK Energy Ltd. to acquire interest and operatorship in East Algoa. 

·         In October, Statoil, as part of a consortium with ExxonMobil and Galp, presented the winning bid for the  Carcará North block in the Santos basin in Brazil. The award closed in December 2017. Statoil is the operator and has 40% interest. 
In addition, Statoil, ExxonMobil and Galp have agreed on subsequent transactions in the adjacent
BM-S-8 block to align equity interests across the two blocks that together comprise the Carcará oil discovery. Upon consummation and subject to government approval, Statoil will have a 36.5% interest in BM-S-8 and a 40% interest in Carcará North and will be the operator of the unitised Carcará field development.  For more information about the transactions see note 4 Acquisitions and divestments to the Consolidated financial statements

·        Statoil and the international partners in the ACG licence (Azeri-Chirag-Gunashli fields) in Azerbaijan have secured an extension of oil production of 25 years from 2024 under an extended and amended PSA, which was ratified by the Azeri Parliament on 31 October. As part of the agreement, Statoil's interest in the field has been adjusted from 8.56% to 7.27%, effective from 1 January 2017

·         On 27 November, the Hebron oil field (Statoil 9%, ExxonMobil operator) offshore Canada started production

·         In December, Statoil and Petrobras signed an agreement that Statoil will acquire a 25% interest in Roncador, a producing oil field in the Campos Basin in Brazil. Petrobras retains operatorship and a 75% interest. The field produced around 280 mboe per day in 2017. The effective date for the Roncador transaction is 1 January 2018. Closing is subject to government approval. For more information about the transactions see note 4 Acquisitions and divestments to the Consolidated financial statements

·         In December, Statoil and the other partners BP and Sonatrach in the In Amenas licence in Algeria secured a licence extension of 5 years from 2022 through an amended and restated Production Sharing Agreement (PSA). Closing is subject to government approval  

 

INTERNATIONAL PRODUCTION

Entitlement production volumes are Statoil’s share of the volumes distributed to the partners according to production sharing agreement (PSA) (see section 5.6  Terms and abbreviations). For US assets entitlement production is 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.
Equity production represent volumes that correspond to Statoil’s percentage ownership in a particular field and is larger than Statoil’s entitlement production if the field is governed by a PSA.

 

Statoil's equity production outside Norway was 36% of Statoil's total equity production of oil and gas in 2017. Statoil's entitlement production outside Norway was about 31% of Statoil's total entitlement production in 2017.

 

The following table shows E&P International's average daily entitlement production of liquids and natural gas for the years ending 31 December 2017, 2016 and 2015.  

 

Statoil, Annual Report on Form 20-F 2017    29


 

Average daily entitlement production

For the year ended 31 December

 

2017

 

2016

 

2015

 

Oil and NGL

Natural gas

 

 

Oil and NGL

Natural gas

 

 

Oil and NGL

Natural gas

 

Production area

mboe/day

mmcm/day

mboe/day

 

mboe/day

mmcm/day

mboe/day

 

mboe/day

mmcm/day

mboe/day

 

 

 

 

 

 

 

 

 

 

 

 

Americas

 186  

 19  

 304  

 

 189  

 18  

 299  

 

 177  

 17  

 283  

Africa

 197  

 6  

 233  

 

 203  

 5  

 232  

 

 211  

 5  

 241  

Eurasia

 26  

 3  

 46  

 

 32  

 3  

 50  

 

 36  

 1  

 44  

Equity accounted production

 5  

 -    

 5  

 

 10  

 -    

 10  

 

 12  

 -    

 12  

Total

 415  

 27  

 588  

 

 435  

 25  

 592  

 

 436  

 23  

 580  

30   Statoil, Annual Report on Form 20-F 2017    


 

The table below provides information about the fields that contributed to production in 2017. Equity production per field is included in this table.

 

Field

Country

Statoil's equity interest in %

Operator 

On stream 

 

Licence expiry date

Average daily equity production in 2017 mboe/day

 

 

 

 

 

 

 

 

 

 

 

Americas

 

 

 

 

 

 

349.5

Appalachian1) 2)

US

Varies

Statoil/others

2008

 

HBP3)

128.4

Bakken 1)

US

Varies

Statoil/others

2011

 

HBP3)

57.0

Peregrino

Brazil

60.00

Statoil

2011

 

2034

39.9

Eagle Ford 1)

US

Varies

Statoil/others

2010

 

HBP3)

34.3

Tahiti

US

25.00

Chevron

2009

 

HBP3)

24.9

St. Malo

US

21.50

Chevron

2014

 

HBP3)

18.1

Caesar Tonga

US

23.55

Anadarko

2012

 

HBP3)

11.0

Hibernia/Hibernia Southern Extension 4)

Canada

Varies

HMDC

1997

 

HBP3)

10.4

Jack

US

25.00

Chevron

2014

 

HBP3)

8.3

Julia

US

50.00

ExxonMobil

2016

 

HBP3)

6.4

Terra Nova

Canada

15.00

Suncor

2002

 

HBP3)

4.6

Heidelberg

US

12.00

Anadarko

2016

 

HBP3)

4.5

Leismer

Canada

100.00

Statoil

2010

 

HBP3)

1.8

Hebron

Canada

9.01

ExxonMobil

2017

 

HBP3)

0.2

 

 

 

 

 

 

 

 

 

Africa

 

 

 

  

 

  

310.0

Block 17

Angola

23.33

Total

2001

 

2022-345)

139.6

Agbami

Nigeria

20.21

Chevron

2008

 

2024

47.6

In Salah

Algeria

31.85

Sonatrach/BP/Statoil

2004

 

2027

39.1

Block 15

Angola

13.33

ExxonMobil

2004

 

2026-325)

37.4

In Amenas

Algeria

45.90

Sonatrach/BP/Statoil

2006

 

2022

23.6

Block 31

Angola

13.33

BP

2012

 

2031

18.9

Murzuq

Libya

10.00

Akakus Oil Operations

2003

 

2035

3.7

 

 

 

 

 

 

 

 

 

Eurasia

 

 

 

 

 

 

80.8

ACG 6)

Azerbaijan

7.27

BP

1997

 

2049

49.1

Corrib

Ireland

36.50

Shell

2015

 

2031

20.0

Kharyaga

Russia

30.00

Zarubezhneft

1999

 

2031

9.4

Alba

UK

17.00

Chevron

1994

 

HBP3)

2.3

 

 

 

 

 

 

 

 

 

Total E&P International

 

 

 

740.4

 

 

 

 

 

 

 

 

 

Equity accounted production

 

 

 

 

 

 

 

Petrocedeño 7)

Venezuela

9.67

Petrocedeño

2008

 

2033

4.9

 

 

 

 

 

 

 

 

 

Total E&P International including share of equity accounted production

 

 

745.3

 

 

 

 

 

 

 

 

 

1)

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

2)

Appalachian basin contains Marcellus and Utica formations.

3)

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

4)

Statoil's equity interests are 5.0% in Hibernia and 9.26% in Hibernia South Extension. Effective 1 May 2017, Statoil’s interest in Hibernia South Extension increased from 9.03% to 9.26% due to an equity reset trigger defined in the joint operating agreement.

5)

Licence expiry varies by field.

6)

As of 1 November 2017, Statoil's share of ACG  equity production has been adjusted from 8.56% to 7.27% due to ratified lincence extension.

7)

As of 30 June 2017, the 9.67% ownership share in the heavy oil project Petrocedeño in Venezuela was reclassified from an equity accounted investment to a non-current financial investment. Statoil has as of this date stopped including production and reserves from Petrocedeño in financial reporting. Petrocedeño project (former Sincor project) was established in 2008. Sincor project started production in 2001.

 

Statoil, Annual Report on Form 20-F 2017    31


Americas

USA

Statoil has had strong growth in production and continues to optimise its portfolio within US shale, through acreage acquisition and divestments, since entering the first play in 2008. DPUSA contributed with 14% of Statoil’s equity production in 2017.

 

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. In 2012, Statoil became an operator in the Marcellus, through the purchase of additional acreage in the states of West Virginia and Ohio. In 2016, Statoil divested its operated assets in West Virginia. During 2017, Statoil has continued to develop its operatorship in the Appalachian basin assets in Ohio. Within the operated acreage in this basin, Statoil is developing two formations: Marcellus and Utica, with special focus on the latter. In addition, on April 2017, Statoil acquired an interest in existing Statoil operated assets in the Appalachian from Northwood Energy Corporation. Statoil's net acreage position in Appalachian at the end of 2017 was around 255,000 net acres.

 

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 formations at the end of 2017 was around 235,000 net acres. Statoil has a total working interest of approximately 70% in Bakken  and is the asset’s operator.

 

Statoil entered the Eagle Ford shale formation located in southwest Texas in 2010. In 2013, Statoil became operator for 50% of the Eagle Ford acreage. As part of a global transaction in December 2015 with Repsol, Statoil increased its working interest and became operator of all of the assets in the Eagle Ford Shale. As a result, Statoil has a total working interest of 63%. Our joint venture partner, Repsol, continues to hold 37% working interest. Statoil's net acreage position in Eagle Ford at the end of 2017 was around 70,000 net acres.

 

US gathering system

Statoil’s participates in gathering and facilities for initial processing of oil and gas in the Bakken Eagle Ford and Appalachian Basin assets in the US. This includes crude and natural gas gathering systems, fresh water supply systems, salt water gathering and disposal wells, oil and gas treatment and processing facilities to provide flow assurance for Statoil’s upstream production. Midstream assets in Bakken  are owned and operated 100% by Statoil. In Eagle Ford, Statoil is the 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 Appalachian Basin, Statoil has operated assets in Appalachian Basin South in Monroe Country Ohio to gather Marcellus  production, while Utica  production is gathered by Eureka Hunter, a third party.  In the Appalachian Basin 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 which include Williams Energy and Alta Gas.

 

In January 2016, the responsibility for the US gathering system was transferred from MMP to E&P International.

 

Statoil is, also, positioned in the US Gulf of Mexico for the following offshore developments:

 

The Tahiti oil field is located in the Green Canyon area and is produced through a floating spar facility. As of 31 December 2017, there were twelve production 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 2017, there were seven 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. As of 31 December 2017, there were five wells producing on Jack and eight wells producing for St. Malo. Additional production wells will be phased in over time.

 

The Julia oil field is located in the Walker Ridge area of the US Gulf of Mexico near Jack and St Malo. First oil was in April 2016 and four wells are currently online. Additional production wells may be drilled based on reservoir performance.

 

The Heidelberg oil field is located in the Green Canyon area and is produced through a floating spar facility. As of 31 December 2017, there were five producing wells in operation.

 

In addition to these fields, on December 2016, Statoil became operator of the Titan offshore platform, at the request of the U.S Bureau of Safety and Environmental Enforcement (BSEE), following the bankruptcy of Bennu Oil & Gas. In addition to the platform itself, Statoil also purchased the export pipelines with capacity to Shell’s Mars system (oil) and William’s Discovery Gas system (gas). Production has been shut in since November 2016; however, plans are currently in place to have the Titan platform re-instate production in 2018. Prior to being shut in, Titan was producing approximately 3,000 boepd from three nearby fields: Telemark (AT63), in which Statoil holds no interest; and Mirage (MC941) and Morgus (MC942), both of which Statoil now has operating rights and holds record title. Acquiring the platform and assets allows Statoil to effectively manage its abandonment obligations and capture value.

 

32   Statoil, Annual Report on Form 20-F 2017    


 

Canada 

Statoil has interests in the Jeanne d'Arc Basin offshore the province of Newfoundland and Labrador in the partner operated producing oil fields Terra Nova, Hebron, Hibernia and Hibernia Southern Extension.

 

The Hebron field started production in November 2017.  The Hebron field consists of a fixed gravity base structure (GBS) with drilling capabilities and storage for oil. Oil is off-loaded to shuttle tankers.

  

In January 2017, Statoil completed the transaction to fully divest to Athabasca Oil Corporation the assets and 123,200 net acres of oil sands leases in Alberta which form the Kai Kos Dehseh project.   

 

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 oil is produced from two wellhead platforms with drilling capability and it is processed on the Peregrino FPSO and offloaded to shuttle tankers. Statoil holds a 60% ownership interest in the field and is operator.

 

Africa

Angola

The deep water blocks 17, 15 and 31 contributed with 36% of Statoil’s equity liquid production outside Norway in 2017. Each block is governed by a PSA which sets out the rights and obligations of the participants, including mechanisms for sharing of the production with the Angolan state oil company Sonangol.

 

Block 17 has 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.

 

Block 31 has production from the PSVM FPSO.

 

The FPSOs serve as production hubs and each receives oil from more than one field and a large number of wells. In 2017, new wells were added and set into production on blocks 15 and 17.  

 

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 licences 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 (PSC), see note 23 Other commitments, contingent liabilities and contingent assets to the Consolidated financial statements.


Algeria

The In Salah onshore gas development is a joint operatorship between Sonatrach, BP and Statoil. The Northern fields have been operating since 2004. The Southern fields project, which has been led by Statoil, started production from two fields (Garet el Befinat and Hassi Moumene) in March 2016. The remaining two fields (Gour Mahmoud and In Salah) started production in July and November 2017, respectively).  The Southern fields are tied back into the Northern fields’ existing facilities.

  

The In Amenas onshore development is a gas development which contains significant liquid volumes. The In Amenas infrastructure includes a gas processing plant with three trains. The production facility is connected to the Sonatrach distribution system. The facilities are operated through a joint operatorship between Sonatrach, BP and Statoil. The In Amenas Gas Compression project, which was led by BP, came into operation in February 2017. The compressors have made it possible to increase production and thereby utilise the capacity of all three trains.
In December, Statoil and the rest of the In Amenas partners secured a licence extension of 5 years beyond 2022. Extension is subject to government approval.

 

Separate PSAs including mechanisms for revenue sharing, govern the rights and obligations of the Parties and establish joint operatorships between Sonatrach, BP and Statoil for In Salah and In Amenas.

 

Eurasia

Production consists mainly of the output from the Azeri-Chirag-Gunashli (ACG) oil field in the Caspian Sea, the Corrib gas field off Ireland’s northwest coast, and the Kharyaga oil field onshore in the Timan Pechora basin in north-west Russia.

 

Statoil, Annual Report on Form 20-F 2017    33


 

The ACG licence has in 2017 been extended until the end of 2049 through an amended and restated PSA. The ACG New Platform project is an additional production platform in the ACG contract area and work is ongoing to optimise the chosen concept.  

 

INTERNATIONAL EXPLORATION

Statoil reduced exploration drilling activity outside Norway in 2017 and prioritised new access efforts and prospect maturation to support an increased drilling activity in 2018 and onwards. 


Brazil is one of Statoil’s core exploration areas. In 2017 Statoil has strengthened its position in the Carcará oil discovery through portfolio transactions and through the second pre-salt offshore licensing round.

 

In 2017 Statoil has established a position onshore in Argentina in the Neuquén Basin through joint exploration venture with YPF regarding the Bajo del Toro block and through 5th bidding round for Bajo del Toro Este block.

 

In South-Africa in 2017 Statoil acquired participating interests in two additional offshore frontier blocks, including one operatorship through a transaction with ExxonMobil Exploration and Production South Africa.

Statoil was awarded 13 leases in US Gulf of Mexico in 2017 and is strengthening its position in the area.

In 2017 Statoil has signed agreements to enter two additional offshore exploration licences, Block 59 and 60, in the Guyana basin in Suriname. This is in line with our global exploration strategy of accessing early in basins with high exploration potential.

Statoil was awarded six licences, five as operator and one as partner, in the 29th Offshore Licensing Round on the UK continental shelf. These awards are a result of a strategic decision by Statoil to explore in prolific but mature basins. Statoil has drilled four exploration wells in the UK in 2017, resulting in one commercial discovery on Verbier.

After fulfilling the study period work program, Statoil has closed its office in Yangon in Myanmar and relinquished the AD-10 licence, as it now assesses the potential for commercially viable discovery to be low.

Including the four exploration wells drilled and one commercial discovery in the UK in 2017 Statoil and its partners completed 11 exploratory wells and made a total of four commercial discoveries internationally. In 2018 Statoil’s international exploration drilling activity will comprise growth opportunities in basins where Statoil already is established with discoveries and producing fields in Brazil, Turkey and the UK, as well as new frontier opportunities such as Argentina. Statoil expects to complete 8 to 10 exploration wells internationally in 2018.

 

 

Exploratory wells drilled1)

2017

2016

2015

 

 

 

 

Americas

 

 

 

Statoil operated

2

5

8

Partner operated

4

2

2

Africa

 

 

 

Statoil operated

0

0

3

Partner operated

0

0

3

Other regions

 

 

 

Statoil operated

4

0

2

Partner operated

1

2

0

Total (gross)

11

9

18

 

 

 

 

1) Wells completed during the year, including appraisals of earlier discoveries.

 

FIELDS UNDER DEVELOPMENT INTERNATIONALLY

This section covers all the sanctioned projects.

 

Americas

USA
The Stampede oil field (Statoil 25%, Hess operator) is located in the Green Canyon area of the Gulf of Mexico. The development

34   Statoil, Annual Report on Form 20-F 2017    


 

includes a tension-leg platform (TLP) with downhole gas lift and water injection from start of production. In May, the offshore platform was successfully installed. The preparations for start-up of production progressed: subsea work was completed and all three wells were ready at year end 2017. Production commenced with first oil in January 2018

 

TVEX (Statoil 25%, Chevron operator) is an extension to Tahiti field, targeting shallower reservoirs above the existing main Tahiti reservoir, which is located in the Green Canyon area of the Gulf of Mexico. Start of production is expected in the fourth quarter of 2018.

 

The Big Foot oil field (Statoil 27.5%, Chevron operator) is located in Walker Ridge area of the Gulf of Mexico. The development includes a dry tree TLP with a drilling rig. The Big Foot project’s offshore installation was completed on March 2018. First oil estimated date is during the second half of 2018.

 

US Onshore operations use hydraulic fracturing to recover resources. Despite reduction in investment and activity level in recent years in shale plays Bakken, Eagle Ford and Appalachian Basin (Marcellus and Utica), production growth continues. The increase in onshore production is mainly attributed to higher recovery per well due to enhanced completion and improved operational efficiency.

Brazil

Peregrino phase II (Statoil 60%, operator) includes the Peregrino South and Southwest discoveries. The development consists of one wellhead platform tied back to the existing floating production, storage and offloading vessel. Project execution started in April 2016. In September 2016, the plan for development was formally approved by the Brazilian national agency of petroleum, natural gas and biofuels (ANP). Production is expected to start in late 2020.

Eurasia
United Kingdom

Mariner (Statoil 65.11%, operator) is a heavy oil development in the UK. The field development includes a production, drilling and living quarter platform based on a steel jacket. Oil will be exported by offshore loading from a floating storage unit. The development includes a possible future subsea tie-in of Mariner East, a small heavy oil discovery. Mariner topsides were successfully installed in August 2017, and offshore hook-up and commissioning is currently ongoing. Production from Mariner is expected to start in second half of 2018.



DISCOVERIES WITH POTENTIAL DEVELOPMENT

This section covers selected pre-sanction projects.

 

Americas

USA
The Vito project (Statoil 37%, Shell operator) is a light weight semi-submersible platform with a single eight-well subsea manifold, in the Mississippi Canyon area of the Gulf of Mexico. The deep wells (32,000 feet) will have down hole gas lift to assist the production. Production is estimated to start by the end of the second quarter of 2021.
In April 2017, its concept development and selection  was approved.

 

Canada

Statoil has made oil discoveries in the Flemish Pass offshore Newfoundland comprising the Bay du Nord project (Statoil 65%, operator), and work is ongoing to assess options for developing Bay du Nord.

 

Brazil

Statoil is operator with 35% equity interest in licence BM-C-33 in the Campos basin. We are evaluating options for developing the discoveries in the licence.  

 

The pre-salt oil discovery Carcará straddles block BM-S-8 and the Carcara North block in the Santos basis. In 2017 Statoil obtained a 40% interest in Carcara North and Statoil has 76% interest in BM-S-8. Statoil has announced agreements to reduce its interest in BM-S-8 to 36.5% and Statoil will be the operator of both Carcara North and BM-S-8 for a unitised field development. Closing of these transactions and unitization of the field is subject to government approval. This, together with the announced agreement with Petrobras to acquire 25% in the producing oil field Roncador in the Campos basin, will strengthen our position in Brazil, one of Statoil’s core areas due to its large resource base and excellent fit with our technology and capabilities

Africa

Tanzania

Statoil has made several large gas discoveries in Block 2 (Statoil 65%, operator) offshore Tanzania during 2012-2015. The licence is located in the Indian Ocean 100 km off the southern part of Tanzania. Work is ongoing to assess options for developing the


 

discoveries, including the construction of an onshore LNG plant jointly with the co-venturers in Blocks 1 and 4 which are operated by Shell Tanzania.

Eurasia
Russia

In September 2017, Rosneft and Statoil signed the shareholders and operating agreement (SOA) for the North Komsomolskoye project. The parties will establish a Russian limited joint venture company where Statoil will own 33.33%. North Komsomolskoye is a conventional, but complex viscous oil field located onshore Western Siberia in Russia. Statoil and Rosneft have agreed to start test production in North Komsomolskoye with the aim to better understand the reservoir and lay the ground for a potential future full field development decision. For information about risks related to our activity in Russia see section 2.11 Risk review under Risks related to our business.

  

 

36   Statoil, Annual Report on Form 20-F 2017    


 

2.5 MMP - MARKETING, MIDSTREAM & PROCESSING



 

MMP overview

The Marketing, Midstream & Processing (MMP) reporting segment is responsible for marketing, trading, processing and transporting of crude oil and condensate, natural gas, NGL and refined products, including operation of Statoil operated refineries, terminals and processing plants. In addition, MMP is responsible for power and emissions trading and for developing transportation solutions for natural gas, liquids and crude oil from Statoil assets including pipelines, shipping, trucking and rail. The business activities within MMP are organised in the following business clusters: Marketing and Trading, Asset Management and Processing and Manufacturing.

 

MMP handles Statoil's and the Norwegian state's direct financial interest (SDFI) equity production of crude oil and NGL, and third-party volumes. This represents approximately 50% of all Norwegian liquids exports. MMP is also responsible for marketing Statoil’s and SDFI’s gas together with third-party gas. This represents approximately 70% of all Norwegian gas exports. See the Norwegian state’s participation and SDFI oil and gas marketing and sale in Applicable laws and regulations in section 2.7 Corporate.

 

Key events in 2017:

·          The export of Statoil piped gas was record high at 41.0 bcm

·          Decision to phase out combined heat and power plant at Mongstad was made in February

·          Statoil awarded long-term contracts for two offshore loading shuttle tankers and two LPG carriers. The fuel efficiency features built into these vessels will reduce operational costs and climate emissions

·          Polarled pipeline was commissioned in May and will transport gas from the NCS to the Nyhamna gas processing plant, which has been upgraded to process and export the new volumes

  

Marketing and trading of gas and LNG

Statoil’s gas marketing and trading business is conducted from Norway and from offices in Belgium, the UK, Germany, the USA and Singapore.

 

Europe

The major export markets for gas from the NCS are Germany, France, the UK, Belgium, the Netherlands, Italy and Spain. LNG from the Snøhvit field, combined with third party LNG cargoes, allow Statoil to reach global gas markets. The majority of gas is sold to counterparties through bilateral sales agreements and the remaining volumes are sold over the trading desk through all the main European trading hubs. The bilateral sales are mainly carried out with large industrial customers, power producers and local distribution companies. A few of Statoil’s long-term gas contracts contain contractual price review mechanisms that can be triggered by the buyer or seller as regulated by the contracts. For the ongoing price-reviews, Statoil provides in its financial statements for probable liabilities based on Statoil’s best judgement. For further information, see Note 23 to the Consolidated financial statements.

Statoil is active on both physical and exchange markets such as the Intercontinental Exchange (ICE). Statoil expects to continue to optimise the market value of gas volumes through a mix of bilateral contracts and trading via its production and transportation systems and downstream assets.    

 

USA 

Statoil Natural Gas LLC (SNG), a wholly-owned subsidiary, has a gas marketing and trading organisation in Stamford, Connecticut that markets natural gas to local distribution companies, industrial customers and power generators. SNG also markets equity production volumes from the Gulf of Mexico, Eagle Ford and the Appalachian Basin and transports some of the Appalachian production to New York City and to Niagara, providing access to the greater Toronto area.

 

In addition, SNG has long-term capacity contracts at the Cove Point LNG re-gasification terminal, that enables sourcing of LNG from the Snøhvit LNG facility in Norway. Due to low gas prices in the US compared to global LNG prices over the last years, almost all of Statoil's LNG cargoes have been diverted away from the US and delivered into higher priced markets in Europe, South-America and Asia.

 

Marketing and trading of liquids

MMP is responsible for the sale of Statoil's and the SDFI’s crude oil and NGL, in addition to commercial optimisation of the refineries and terminals. The liquids marketing and trading business is conducted from Norway, the UK, Singapore, the US and Canada. The main crude oil market for Statoil is northwest Europe.

 

Statoil, Annual Report on Form 20-F 2017    37


 

MMP also markets equity volumes from E&P International assets located in Canada, the US, Brazil, Angola, Nigeria, Algeria, Azerbaijan and the UK, as well as third party volumes. Value is maximised through marketing, physical and financial trading and through optimisation of own and leased capacity such as refineries, processing, terminals, storages, pipelines, railcars and vessels.

  

Manufacturing

Statoil owns and is operator of the Mongstad refinery in Norway including the Mongstad Heat and Power Plant (MHPP). The refinery is a medium sized refinery built in 1975, 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, to the crude oil terminal at Sture and the gas processing plant at Kollsnes through an NGL/condensate pipeline, and to Kollsnes by a gas pipeline. MHPP produces heat and power from gas received from Kollsnes and from the refinery. It has capacity of approximately 280 megawatts of electric power and 350 megawatts of process heat. Following termination of the existing gas agreement between the Troll licence and Statoil Refining Norway AS, the normal operation of the power plant will be phased out.

 

Statoil has an ownership interest of 34% in Vestprosess, which transports and processes NGL and condensate. The Vestprosess pipeline connects the Kollsnes and Sture plants to Mongstad. Operatorship of Vestprosess is transferred to Gassco 1 January 2018, with Statoil as technical service provider.

 

Statoil owns 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 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.

 

Statoil has an ownership interest of 82% in the methanol plant at Tjeldbergodden. It receives natural gas from the Norwegian Sea through the Haltenpipe pipeline. In addition, Statoil holds a 50.9% ownership interest in the air separation unit Tjeldbergodden Luftgassfabrikk DA.

 

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

2017

2016

2015

2017

2016

2015

2017

2016

2015

2017

2016

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Mongstad

12.1

9.8

11.9

9.3

9.3

9.3

97.5

94.4

97.6

94.7

93.9

93.4

Kalundborg

5.5

5.0

5.2

5.4

5.4

5.4

99.7

98.0

98.5

90.4

91.0

91.0

Tjeldbergodden

0.94

0.76

0.92

0.95

0.95

0.95

99.4

94.8

98.5

99.4

94.8

98.5

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1)

Actual throughput of crude oils, condensates, NGL, feed and blendstock, measured in million tonnes.

Throughput may be higher than distillation capacity for plants because volumes of fuel oil, NGL, kero, naphta, gasoil and bio-diesel additive may not go through the crude-/condensate distillation unit.

2)

Nominal crude oil and condensate distillation capacity, and methanol production capacity, measured in million tonnes.

3)

Composite reliability factor for all processing units, excluding turnarounds.

4)

Composite utilisation rate for all processing units, based on throughput and capacity.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Terminals and storage

Statoil has a 65% ownership interest in Mongstad crude oil terminal. Crude oil is landed at Mongstad through pipelines from the NCS and by crude tankers from the market. The Mongstad terminal has a storage capacity of 9.4 million barrels of crude oil.

 

The Sture crude oil terminal receives crude oil through pipelines from 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.

 

Statoil operates the South Riding Point Terminal, which is located on Grand Bahamas Island and consists of two shipping berths and ten storage tanks, with a storage capacity of 6.75 million barrels of crude oil. The terminal has facilities to blend crude oils, including heavy oils. The South Riding Point terminal was hit by Hurricane Matthew in 2016 with extensive damage to the Sea Island and the offshore berth unloading/loading facility. The reconstruction work is expected to be finalised in 2018.

 

Statoil UK holds one third share of the interests in the Aldbrough Gas Storage in UK, which is operated by SSE Hornsea Ltd.

 

Statoil Deutschland Storage GmbH holds a 23.7% stake in the Etzel Gas Lager in the northern part of Germany which has a total of 19 caverns and secures regularity for gas deliveries from the NCS.

 

38   Statoil, Annual Report on Form 20-F 2017    


 

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.

 

 

 

  




Pipelines

Statoil is a significant shipper in the NCS gas pipeline system. 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. Statoil’s current ownership share in Gassled is 5%. See Gas sales and transportation from the NCS in section 2.7 Corporate for further information.

 

Statoil is the technical service provider (TSP) for the Kårstø and Kollsnes gas processing plants in accordance with the technical service agreement between Statoil and Gassco AS, included as Exhibit 4(a)(i) to Form 20-F. Statoil also performs the TSP role for the majority of the Gassco operated gas pipeline infrastructure.

 

In addition, MMP manages 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 and the Haltenpipe, Norpipe and Mongstad gas pipeline. 

 

Statoil holds 30.1% interest in the Nyhamna gas processing plant in Aukra via the recently established Nyhamna Joint Venture. The venture is operated by Gassco.

 

The Polarled pipeline connects fields in the Norwegian Sea with the Nyhamna gas processing plant. Transportation through the pipeline will commence at Aasta Hansteen production start. Statoil transferred the operatorship for the Polarled pipeline to Gassco on 1 May 2017.

 

The Johan Sverdrup oil and gas export pipelines are under construction and will provide export from the Johan Sverdrup field.

 

  

 

Statoil, Annual Report on Form 20-F 2017    39


 

2.6 OTHER GROUP

 

The Other reporting segment includes activities in New Energy Solutions (NES), Global Strategy & Business Development (GSB), Technology, Projects & Drilling (TPD) and corporate staffs and support functions.

 

New Energy Solutions (NES)

The NES business area reflects Statoil’s aspirations to gradually complement its oil and gas portfolio with profitable renewable energy and other low-carbon energy solutions. Offshore wind, solar and carbon capture and storage have been key strategic focus areas in 2017.

 

As per end of 2017, Statoil’s share of the offshore wind production capacity is around 290 megawatt (MW) in production and around 190 MW under development.

 

Key events in 2017:

·          Construction completed with full capacity for wind production from Dudgeon wind farm and Hywind Scotland during fourth quarter of 2017.

·          Increased UK presence through increasing ownership in the Dogger Bank offshore wind projects.

·          Assumed role as operator for the Sheringham Shoal wind farm in April 2017.

·          Acquired 43.75% of the Apodi solar asset in Brazil, operated by Scatec. The acquisition was made through a 40% share from Scatec Solar and 3.75% from ApodiPar. The Apodi solar project started construction during fourth quarter of 2017.

·          Awarded the role as operator of the Carbon capture and storage project for the FEED study. Partners Shell and Total have 33.33% each.

·          The existing 5-year agreement for the Technology Centre Mongstad for testing of different CO2 capture technologies expired in August 2017. Statoil, Total, Shell and Gassnova (Norwegian State-owned entity) have agreed to continue operations for three years. Statoil’s equity share has been reduced from 20% to 7.5% (in line with other industrial partners).

 

The Sheringham Shoal offshore wind farm (Statoil 40%, operator) located off the coast of Norfolk, UK, was formally opened in September 2012. The wind farm is in full production with 88 turbines and an installed capacity of 317 MW. The wind farm's annual production is approximately 1.1 terawatt hours (TWh) and it has the capacity to provide power to approximately 220,000 households. Statoil took over the role as operator of Sheringham Shoal from the second quarter of 2017.

 

The Dudgeon offshore wind farm (Statoil 35%, operator) is located in the Greater Wash area off the English east coast, a short distance from Sheringham Shoal. A final investment decision for the 402 MW project was made in July 2014 and the project was inaugurated in November 2017. The wind farm is expected to produce 1.7 TWh yearly from 67 turbines, with the capacity to provide power for around 410,000 households.

 

 


 Dudgeon Offshore Wind.

Photo: Ole Jørgen Bratland

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

40   Statoil, Annual Report on Form 20-F 2017    


 

 

 

The Dogger Bank area has a total consented capacity of 4.8 GW and is potentially the largest offshore wind farm development in the world. In February and August 2015, the consortium received consent from the UK authorities for four projects, each with a capacity of 1200 MW. Statoil and Statkraft, together with RWE and SSE, were partners in the Forewind consortium, each with a 25% equity stake. The consortium has gone through a major reorganisation during 2017. Statoil and SSE bought Statkraft’s shares in March 2017 and a project split followed in August 2017, Innogy (RWE) now owns Project 3 (Teesside B) 100%, and Statoil and SSE have entered into a shareholders’ agreement for Projects 1, 2 and 4 with a 50/50 ownership of the Creyke Beck A and B, and Teesside A projects.

 

The Arkona offshore wind farm (Statoil 50%, operated by e.on) is being developed in the German part of the Baltic Sea, and the operations and maintenance base will be located in Sassnitz on the island of Rügen. A final investment decision for the up to 385 MW project was made in April 2016. During 2017 the installation of the substructures was completed, and Arkona is expected to be in full operation in 2019. The wind farm is expected to provide power to approximately 400,000 German households from 60 turbines.

 

The Hywind Scotland pilot wind park (Statoil 75%, operator) is a floating wind pilot park using the Hywind concept, developed and owned by Statoil. The project is located at Buchan Deep, approximately 25 km off Peterhead on the east coast of Scotland. Statoil completed the project during 2017 and has installed 5 Siemens 6 MW turbines. Production is expected to be 0.14 TWh/year, powering around 20,000 households. This is the next step in Statoil’s strategy towards deployment of the first utility large scale floating wind farms.

 

Statoil was the winner of the New York Wind energy area lease, following the December 2016 BOEM lease sale, with a winning bid of USD 42.5 million. The lease is 321 km2, large enough to support one or more offshore wind developments with a total capacity of more than 1 GW. The lease is located approximately 20 km directly south of Long Island. The project has been named “Empire Wind” and is being further matured towards a plan for development during 2018.

 

Since 1996, Statoil has proven experience in carbon capture and storage (CCS) and has continued to develop competence through research engagement at Technology Centre Mongstad, the world’s largest facility for testing and improving CO2 capture. In addition, our offshore oil and gas operations at Sleipner and Snøhvit represent two of the world’s largest CCS units. Statoil will seek to deploy its competence and experience in other CCS projects, both to reduce carbon dioxide emissions and to drive new opportunities, including enhanced oil recovery (EOR) possibilities and carbon neutral value chains based on hydrogen. Statoil has, on behalf of the Norwegian Ministry of Petroleum and Energy, performed a feasibility study for establishing a CO2 storage facility in the Norwegian Sea. In 2017 the Ministry of Petroleum and Energy awarded Statoil the lead role to assess a full CCS value chain project covering both storage and transportation from three industrial sources in Norway. Statoil, Shell and Total are partners in the project with equal shares of one-third each.

 

In February 2016, Statoil launched the Statoil Energy ventures fund, a new energy investment fund dedicated to investing in attractive and ambitious growth companies in low carbon energy, supporting Statoil’s strategy of growth in new energy solutions. The Statoil Energy Ventures Fund will invest up to USD 200 million over a period of four to seven years.

 

As of the date of this report, the fund has utilised less than a quarter of the total Statoil venture fund through four direct investments in four different segments, and is a limited partner in one financial venture capital fund.  

 

Global Strategy & Business Development (GSB)

The Global Strategy & Business Development (GSB) business area is Statoil’s functional centre for strategy and business development. GSB is responsible for Statoil’s global strategy processes and identifies and delivers inorganic business development opportunities, including corporate mergers and acquisitions. This is achieved through close collaboration across geographic locations and business areas. Statoil's strategy forms the basis for guiding the company’s business development focus.

 

GSB also hosts several corporate functions, including Statoil’s Corporate Sustainability function, which is shaping the company’s strategic response to sustainability issues and reporting on Statoil’s sustainability performance.

 

 

Statoil, Annual Report on Form 20-F 2017    41


 

Corporate staffs and support functions

Corporate Staffs and support functions comprise the non-operating activities supporting Statoil, and include headquarters and central functions that provide business support such as finance and control, corporate communication, safety, audit, legal services and people and leadership.

 

Technology, Projects & Drilling (TPD)

The Technology, Projects & Drilling (TPD) business area is responsible for global project development, well delivery, technology development and procurement in Statoil.

 

Research & Technology (R&T) is responsible for research and technology development to meet Statoil's business needs on short and long term, for delivering technical expertise to business development, projects and assets, and for implementing new technologies.

 

Project development (PRD) is responsible for planning and executing major facilities development, brownfield and field decommissioning projects where Statoil is the operator.

 

Drilling and Well (D&W) is responsible for providing cost-efficient well delivery and well operations, fit-for-purpose drilling facilities and providing expertise and advice to Statoil's global drilling and well operations.

 

Procurement and Supplier Relations (PSR) is responsible for global procurement aligned with Statoil’s business needs.

 

 

 

 

42   Statoil, Annual Report on Form 20-F 2017    


 

The table below displays major projects operated by Statoil, as well as projects operated by Statoil’s licence partners. More information about ongoing projects are given in the E&P Norway, E&P International, MMP and NES sections. In our world-class portfolio, an additional 35-40 projects are in the early phase, maturing towards sanction.

 

Project startups and completions 2017

Statoil's interest

Operator

Area

Type

 

 

 

 

 

Hebron

9.01%

ExxonMobil

Jeanne d'Arc Basin, off coast of Newfoundland and Labrador, Canada

Oil

In Salah Southern fields

31.85%

Sonatrach/BP/Statoil

Algeria

Oil and gas

Dudgeon offshore wind farm

35.00%

Statoil

North Sea, off English coast

Wind

Hywind Scotland pilot wind park

75.00%

Statoil

North Sea, off Scottish coast

Wind

Gina Krog

58.70%

Statoil

North Sea

Oil and gas

Gullfaks C subsea compression

51.00%

Statoil

North Sea

Improved gas recovery

Byrding

70.00%

Statoil

North Sea

Oil and associated gas

Polarled

37.10%

Statoil

Norwegian Sea

Export pipeline for gas

 

 

 

 

 

Ongoing projects with expected startups and completions 2018-2022

Statoil's interest

Operator

Area

Type

 

 

 

 

 

Tahiti vertical expansion

25.00%

Chevron

Gulf of Mexico

Oil

Stampede

25.00%

Hess

Gulf of Mexico

Oil

Big Foot

27.50%

Chevron

Gulf of Mexico

Oil

Peregrino phase II

60.00%

Statoil

Campos basin, off coast of Rio de Janeiro, Brazil

Oil

Arkona offshore wind farm

50.00%

E.ON

Baltic Sea, off German coast

Wind

Mariner

65.11%

Statoil

North Sea

Oil

Oseberg Vestflanken 2

49.30%

Statoil

North Sea

Oil and gas

Troll B gas module

30.58%

Statoil

North Sea

Increased processing capacity

Martin Linge

19.00%

Total

North Sea

Oil and gas

 - Total's share, Statoil to take over in late March 2018

51.00%

 

 

 

Johan Sverdrup

40.03%

Statoil

North Sea

Oil and associated gas

 - held through Lundin

4.54%

 

 

 

Johan Sverdrup export pipelines, JoSEPP

40.03%

Statoil

North Sea

Oil and gas export pipelines

 - held through Lundin

4.54%

 

 

 

Utgard Norwegian sector

38.44%

Statoil

North Sea

Gas and condensate

    UK sector

38.00%

 

 

 

Trestakk

59.10%

Statoil

North Sea

Oil and associated gas

Huldra decommissioning

19.87%

Statoil

North Sea

Field decommissioning

Njord future

20.00%

Statoil

North Sea

Oil

Snorre expansion

33.28%

Statoil

North Sea

Oil

Aasta Hansteen

51.00%

Statoil

Norwegian Sea

Gas

Snefrid Nord

51.00%

Statoil

Norwegian Sea

Gas

Johan Castberg

50.00%

Statoil

Norwegian Sea

Oil

 

Statoil, Annual Report on Form 20-F 2017    43


 

2.7 CORPORATE

 

APPLICABLE LAWS AND REGULATIONS

Statoil operates in more than 30 countries and is exposed to, and committed to compliance with, a number of laws and regulations globally.

 

This article focuses primarily on Norwegian laws specific for Statoil`s core activities, taking into account that the majority of Statoil’s production is produced on the NCS, the ownership structure of the company and that Statoil is registered and has its headquarters in Norway.

 

Norwegian petroleum laws and licensing system

The principal laws governing Statoil’s petroleum activities in Norway are the Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act.

 

Norway is not a member of the European Union (EU), but Norway is a member of the European Free Trade Association (EFTA). The EU and the EFTA Member States have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, which provides for the inclusion of EU legislation in the national law of the EFTA Member States (except Switzerland). Statoil’s business activities are subject to both the EFTA Convention and EU laws and regulations adopted pursuant to the EEA Agreement.

 

For further information about the jurisdictions in which Statoil operates, see sections 2.2 Business overview and 2.11 Risk review

 

Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy (“MPE”) is responsible for resource management and for administering petroleum activities on the NCS. The main task of the MPE is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Norwegian Parliament (the Storting) and relevant decisions of the Norwegian State. 

 

The Storting's role in relation to major policy issues in the petroleum sector can affect Statoil in two ways: firstly, when the Norwegian State acts in its capacity as majority owner of Statoil shares and, secondly, when the Norwegian State acts in its capacity as regulator:

·          The Norwegian State's shareholding in Statoil is managed by the Ministry of Petroleum and Energy. The MPE will normally decide how the Norwegian State will vote on proposals submitted to general meetings of the shareholders. However, in certain exceptional cases, it may be necessary for the Norwegian State to seek approval from the Storting before voting on a certain proposal. This will normally be the case if Statoil issues additional shares and such issuance would significantly dilute the Norwegian State's holding, or if such issuance would require a capital contribution from the Norwegian State in excess of government mandates. A decision by the Norwegian State to vote against a proposal on Statoil’s part to issue additional shares would prevent Statoil from raising additional capital in this manner and could adversely affect Statoil’s ability to pursue business opportunities. For more information about the Norwegian State's ownership, see Risks related to state ownership in section 2.11 Risk review and Major shareholders in section 5.1 Shareholder information

·          The Norwegian State exercises important regulatory powers over Statoil, as well as over other companies and corporations on the NCS. As part of its business, Statoil or the partnerships to which Statoil is a party, frequently need to apply for licences and other approval of various kinds from the Norwegian State. Although Statoil is majority-owned by the Norwegian State, it does not receive preferential treatment with respect to licences granted by or under any other regulatory rules enforced by the Norwegian State

 

The principal laws governing Statoil’s petroleum activities in Norway and on the NCS are the Norwegian Petroleum Act of 29 November 1996 (the "Petroleum Act") and the regulations issued thereunder, and the Norwegian Petroleum Taxation Act of 13 June 1975 (the "Petroleum Taxation Act"). The Petroleum Act sets out the principle that the Norwegian State is the owner of all subsea petroleum on the NCS, that exclusive right to resource management is vested in the Norwegian State and that the Norwegian State alone is authorised to award licences for petroleum activities as well as determine its terms. Licensees are required to submit a plan for development and operation (PDO) to the MPE for approval. For fields of a certain size, the Storting has to accept the PDO before it is formally approved by the MPE. Statoil is dependent on the Norwegian State for approval of its NCS exploration and development projects and its applications for production rates for individual fields.

 

Production licences are the most important type of licence awarded under the Petroleum Act and are normally awarded for an initial exploration period, which is typically six years, but which can be shorter. The maximum period is ten years. During this exploration period, the licensees must meet a specified work obligation set out in the licence. If the licensees fulfil the obligations set out in the initial licence period, they are entitled to require that the licence be prolonged for a period specified at the time when the licence is awarded, typically 30 years.

 

44   Statoil, Annual Report on Form 20-F 2017    


 

The terms of the production licences are decided by the Ministry of Petroleum and Energy. A production licence grants the holder an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the licence. Production licences are awarded to group of companies forming a joint venture at the Ministry’s discretion. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the licence. The Ministry of Petroleum and Energy decides the form of the joint operating agreements and accounting agreements.

 

The governing body of the joint venture is the management committee. In licences awarded since 1996 where the state's direct financial interest (SDFI) holds an interest, the Norwegian State, acting through Petoro AS, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the licence with respect to the Norwegian State's exploitation policies or financial interests. This power of veto has never been used.

 

Interests in production licences may be transferred directly or indirectly subject to the consent of the MPE and the approval of the Ministry of Finance of a corresponding tax treatment position. In most licences, there are no pre-emption rights in favour of the other licensees. However, the SDFI, or the Norwegian State, as appropriate, still holds pre-emption rights in all licences.

 

The day-to-day management of a field is the responsibility of an operator appointed by the MPE. The operator is in practice always a member of the joint venture holding the production licence, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement.

 

If important public interests are at stake, the Norwegian State may instruct Statoil and other licensees on the NCS to reduce the production of petroleum. The last time the Norwegian State instructed a reduction in oil production was in 2002.

 

A licence from the MPE is also required in order to establish facilities for the transportation and utilisation of petroleum. Ownership of most facilities for the transportation and utilisation of petroleum in Norway and on the NCS is organised in the form of joint ventures. The participants' agreements are similar to joint operating agreements for production.

 

Licensees are required to prepare a decommissioning plan before a production licence or a licence to establish and use facilities for the transportation and utilisation of petroleum expires or is relinquished, or the use of a facility ceases. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities.

 

For an overview of Statoil’s activities and shares in Statoil’s production licences on the NCS, see section 2.3 E&P Norway.

 

Gas sales and transportation from the NCS

Statoil markets gas from the NCS on its own behalf and on the Norwegian State's behalf. Gas is transported through the Gassled pipeline network to customers in the UK and mainland Europe.

 

Most of Statoil’s and the Norwegian State's gas produced on the NCS is sold under gas contracts to customers in the European Union (EU), and changes in EU legislation may affect Statoil's marketing of gas.

 

The Norwegian gas transport system, consisting of the pipelines and terminals through which licensees on the NCS transport their gas, is owned by a joint venture called Gassled. The Norwegian Petroleum Act of 29 November 1996 and the pertaining Petroleum Regulation establish the basis for non- discriminatory third-party access to the Gassled transport system.

 

The tariffs for the use of capacity in the transport system are determined by applying a formula set out in separate tariff regulations stipulated by the Ministry of Petroleum and Energy. The tariffs are paid on the basis of booked capacity, not on the basis of the volumes actually transported.

 

For further information, see section 2.5 MMP – Marketing, Midstream and Processing under Pipelines.

 

The Norwegian State's participation

The Norwegian State's policy as a shareholder in Statoil has been and continues to be to ensure that petroleum activities create the highest possible value for the Norwegian State.

 

In 1985, the Norwegian State established the State's direct financial interest (SDFI) through which the Norwegian State has direct participating interests in licences and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licences and petroleum facilities in which Statoil also hold interests. Petoro AS, a company wholly owned by the Norwegian State, was formed in 2001 to manage the SDFI assets.

 

 

Statoil, Annual Report on Form 20-F 2017    45


 

SDFI oil and gas marketing and sale

Statoil markets and sells the Norwegian State's oil and gas together with Statoil’s own production. The arrangement has been implemented by the Norwegian State.

 

At an extraordinary general meeting held on 25 May 2001, the Norwegian State, as sole shareholder, approved an instruction to Statoil setting out specific terms for the marketing and sale of the Norwegian State's oil and gas. This resolution is referred to as the Owner's instruction.

 

Statoil is obliged under the Owner's instruction to jointly market and sell the Norwegian State's oil and gas as well as Statoil’s own oil and gas. The overall objective of the marketing arrangement is to obtain the highest possible total value for Statoil’s oil and gas and the Norwegian State's oil and gas, and to ensure an equitable distribution of the total value creation between the Norwegian State and Statoil.

 

The Norwegian State may at any time utilise its position as majority shareholder of Statoil to withdraw or amend the marketing instruction

 

HSE regulation

Statoil’s petroleum operations are subject to extensive laws and regulations relat