Prospectus Statoil

Home , Antero Resources, Golden Ocean Group, Goliat field, Heavy crude oil, Langeled pipeline, Occupied

PROSPECTUS

STATOIL ASA

Offering and listing of up to 160,000,000 Shares in connection with payment of Dividend to Existing Shareholders

The information contained in this prospectus (the "Prospectus") relates to the offer and listing on Oslo Børs (the "Oslo Stock Exchange") by Statoil ASA ("Statoil ASA" or the "Company", and, taken together with its consolidated subsidiaries "Statoil") of up to 160,000,000 new shares in the Company (the "Dividend Shares"), each with a nominal value of NOK 2.50 (the "Dividend Issue") in connection with payment of the Dividend (as defined below). The subscription price for each of the Dividend Shares is expected to be announced on or about 12 September 2016 and will be equal to the volume-weighted average share price over the last two trading days on Oslo Stock Exchange of the subscription period for the Dividend Issue, with a deduction for a discount of 5% (the "Subscription Price").

On 11 May 2016, the general meeting of the Company approved a two year scrip dividend programme commencing from the fourth quarter 2015 (the "Scrip Dividend Programme") and authorised the board of directors of the Company to (i) distribute dividend based on the approved annual accounts for 2015 and (ii) to increase the share capital in connection with payment of dividend for first quarter to third quarter 2016. In accordance with authorisations granted by the general meeting, the board of directors of the Company (the "Board of Directors") resolved on 26 April 2016, to distribute a dividend of USD 0.2201 (NOK 1.8255) per share for the first quarter 2016 (the "Dividend") to the holders of the Company’s shares (the "Shares") as of expiry of 9 August 2016 (the "Existing Shareholders"), as registered with the Company’s shareholder register with the Norwegian Central Securities Depositary (Nw. Verdipapirsentralen) (the "VPS") as of expiry of 11 August 2016 (the "Record Date"). Pursuant to the resolution of the Board of Directors, Existing Shareholders may choose whether to receive all or parts of their Dividend with a deduction of any applicable withholding tax (the "Net Dividend") in either cash or Dividend Shares, or as a combination thereof. This Prospectus relates to the issuance of Dividend Shares to the Existing Shareholders who elect to receive all or part of their Net Dividend in Dividend Shares.

The settlement in Dividend Shares will be carried out by set-off between the total Subscription Price for the subscribed Dividend Shares and the claim of the Net Dividend the Existing Shareholder is entitled to. The part of the Net Dividend that is not used for subscription of Dividend Shares, will be paid in cash. Existing Shareholders who do not elect to receive their Net Dividend in Dividend Shares by the end of the Subscription Period will be paid their Net Dividend in cash, without any action on their part.

Number of Dividend Shares ...... Up to 160,000,000

Subscription Period...... From 09:00 hours (CEST) on 29 August 2016 to 23:59 hours (CEST) on 9 September 2016

The subscription period commences at 09:00 hours (CEST) on 29 August 2016 and expires at 23:59 hours (CEST) on 9 September 2016 (the "Subscription Period"). Each Existing Shareholder will be entitled to subscribe for a number of Dividend Shares equal to its total Net Dividend, divided by the Subscription Price and rounded down to the nearest whole number of shares. Over-subscription and subscription of Dividend Shares other than by Existing Shareholders will not be permitted. For the purposes of determining eligibility for participation in the Dividend Issue, the Company will look solely to its register of shareholders as of the expiry of the Record Date.

Existing Shareholders who do not subscribe for Dividend Shares will experience a dilution of its shareholding; see Section 6.2 "Dilution".

The issue of the Dividend Shares is expected to take place on or about 22 September 2016, and the delivery of the Dividend Shares to investors’ VPS-accounts is expected to take place on or about 23 September 2016. Trading in the Dividend Shares on the Oslo Stock Exchange is expected to commence on or about 26 September 2016 under the trading symbol "STL".

The distribution of this Prospectus and the offer and subscription of Dividend Shares by Existing Shareholders located in or resident of other jurisdictions than Norway may be restricted by law. For further information see Section 16 "Selling and transfer restrictions".

Investing in the Shares, including the Dividend Shares, involves a high degree of risk, see Section 2 "Risk factors".

27 August 2016 IMPORTANT INFORMATION This Prospectus has been prepared in connection with the offering of Dividend Shares of the Company through the Dividend Issue and the admission of the Dividend Shares to trading on the Oslo Stock Exchange, as described herein. For the definitions of terms used throughout this Prospectus, see Section 20 "Definitions" of this Prospectus. This Prospectus has been prepared in order to provide information about Statoil and its business in connection with the offering and listing of the Dividend Shares in the Dividend Issue. As this Dividend Issue is addressed to the Company's existing shareholders, the level of disclosure in this Prospectus is proportionate to this type of issue cf. EC Commission Regulation EC/809/2004 article 26a (3). This Prospectus has been prepared to comply with the Norwegian Securities Trading Act of 29 June 2007 no. 75 (the "Norwegian Securities Trading Act") and related secondary legislation, including the EC Commission Regulation EC/809/2004 implementing Directive 2003/71/EC of the European Parliament and of the Council of 4 November 2003 (and amendments thereto, including the 2010 PD Amending Directive) regarding information contained in prospectuses, and as implemented in Norway (the "EU Prospectus Directive"). The Financial Supervisory Authority of Norway (Nw.: Finanstilsynet) (the "Norwegian FSA") has reviewed and approved this Prospectus on 27 August 2016 in accordance with sections 7–7 and 7-8 of the Norwegian Securities Trading Act. The Norwegian FSA has not controlled or approved the accuracy or completeness of the information included in this Prospectus. The approval by the Norwegian FSA only relates to the information included in accordance with pre-defined disclosure requirements. The Norwegian FSA has not made any form of control or approval relating to corporate matters described in or referred to in this Prospectus. No competent authority or any other regulatory body outside of Norway has approved or disapproved the distribution of Dividend Shares, or authorized the publication, or passed upon the adequacy, of this Prospectus. Any representation to the contrary may be a criminal offense. Any offer of Dividend Shares in any member state of the European Economic Area ("EEA") which has implemented the EU Prospectus Directive (each, a "Relevant Member State") other than Norway will be made pursuant to an exemption under the EU Prospectus Directive from the requirement to publish a prospectus for offers of securities. This Prospectus has been prepared solely in the English language. However, a summary in Norwegian has been prepared in Section 19 "Norwegian summary." The Company has engaged DNB Bank ASA as receiving agent in the Dividend Issue (the "Receiving Agent"). The distribution of this Prospectus and the offering and subscription of the Dividend Shares in certain jurisdictions may be restricted by law. This Prospectus does not constitute an offer of, or an invitation to subscribe for or purchase any of the Dividend Shares in any jurisdiction in which such offer or invitation to subscribe or purchase would be unlawful. Accordingly, neither this Prospectus nor any advertisement or any other offering material may be distributed or published in any jurisdiction except under circumstances that will result in compliance with any applicable laws and regulations. The Company requires persons in possession of this Prospectus to inform themselves about and to observe any such restrictions. For more information regarding restrictions in relation to the Dividend Issue pursuant to this Prospectus, see Section 16 "Selling and transfer restrictions". This Prospectus and the terms and conditions of the Dividend Issue as set out herein and any offers and sales of Dividend Shares hereunder shall be governed by and construed in accordance with Norwegian law. The courts of Norway, with Stavanger as legal venue, shall have exclusive jurisdiction to settle any dispute which may arise out of or in connection with the Dividend Issue or this Prospectus. In making an investment decision, prospective investors must rely on their own examination, and analysis of, and enquiry into Statoil and the terms of the Dividend Issue, including the merits and risks involved. Neither the Company nor the Receiving Agent, or any of their respective representatives or advisers, is making any representation to any subscriber, offeree or purchaser of the Dividend Shares regarding the legality of an investment in the Dividend Shares by such subscriber, offeree or purchaser under the laws applicable to such subscriber, offeree or purchaser. Each investor should consult with his or her own advisors as to the legal, tax, business, financial and related aspects of a subscription of the Dividend Shares. All sections of the Prospectus should be read in context with the information included in Section 4 "General information". The Company has furnished the information in this Prospectus in order to provide a presentation of Statoil and to inform the Existing Shareholder about the Dividend Shares and the Dividend Issue. Unless otherwise indicated, the source of information included in this Prospectus is the Company. TABLE OF CONTENTS

1 SUMMARY ...... 1

2 RISK FACTORS ...... 8 2.1 Risks relating to Statoil and the industry in which Statoil operates ...... 8 2.2 Financial risks ...... 18 2.3 Risks related to the Shares and the Dividend Issue ...... 20

3 RESPONSIBILITY FOR THE PROSPECTUS ...... 22

4 GENERAL INFORMATION ...... 23 4.1 Other important investor information ...... 23 4.2 Financial information ...... 23 4.3 Industry and market data ...... 23 4.4 Confirmation regarding sources ...... 24 4.5 Mineral reporting standards ...... 24 4.6 Equivalent measures ...... 26 4.7 USD/NOK exchange rates ...... 27 4.8 Cautionary note regarding forward-looking statements ...... 27

5 TERMS OF THE DIVIDEND ISSUE ...... 29 5.1 The Dividend Issue ...... 29 5.2 Resolutions to undertake and implement the Dividend Issue ...... 30 5.3 Subscription Price ...... 31 5.4 Subscription Period ...... 31 5.5 Record Date for Existing Shareholders ...... 31 5.6 Entitlement to subscription of Dividend Shares ...... 32 5.7 Subscription procedures ...... 32 5.8 Financial intermediaries ...... 33 5.9 Allocation of Dividend Shares ...... 34 5.10 Settlement of the Dividend Shares ...... 34 5.11 Existing Shareholders subject to withholding tax ...... 34 5.12 Delivery; VPS registration; admission to trading ...... 34 5.13 Rights conferred by the Shares ...... 35 5.14 Selling and transfer restrictions ...... 35 5.15 Participation of the Norwegian State and members of the Management, the Corporate Assembly and the Board of Directors in the Dividend Issue ...... 35 5.16 Interests of natural and legal persons in the Dividend Issue ...... 35 5.17 Governing law and jurisdiction ...... 35

6 USE OF THE PROCEEDS; REASONS FOR THE DIVIDEND ISSUE ...... 37 6.1 Use of the proceeds ...... 37 6.2 Dilution ...... 37

7 DIVIDEND AND DIVIDEND POLICY ...... 38 7.1 Dividend policy ...... 38 7.2 Dividend history ...... 38 7.3 Share repurchase ...... 39 7.4 Legal constraints on the distribution of dividend ...... 39 7.5 Manner of dividend payments...... 39

8 INDUSTRY AND MARKET OVERVIEW ...... 40 8.1 Introduction ...... 40 8.2 Market overview ...... 41 8.3 Crude oil markets ...... 42 8.4 Natural gas markets ...... 45 8.5 Response to market situation ...... 48

9 THE BUSINESS OF STATOIL AND MINERAL RESERVES ...... 49 9.1 Introduction of Statoil ...... 49 9.2 Development and Production Norway (DPN) ...... 52 9.3 Development and Production International (DPI) ...... 64 9.4 Expected economic lifetime ...... 82 9.5 Proved oil and gas reserves ...... 84 9.6 Applicable laws and regulations for Norway ...... 98 9.7 Applicable regulations and taxation outside Norway ...... 104 9.8 Material contracts ...... 111 9.9 Dependency on licences, patents etc...... 112 9.10 Legal and arbitration proceedings ...... 112

10 FINANCIAL INFORMATION ...... 114 10.1 Capitalisation and indebtedness ...... 114 10.2 Working capital statement ...... 115 10.3 Summary of investments ...... 115 10.4 Financing of capital expenditures ...... 121 10.5 Improved efficiency ...... 121 10.6 Significant changes ...... 122 11 BOARD OF DIRECTORS, MANAGEMENT, EMPLOYEES AND CORPORATE GOVERNANCE ...... 123 11.1 Introduction ...... 123 11.2 Board of Directors ...... 123 11.3 Management ...... 128 11.4 Corporate Assembly ...... 132 11.5 Incentive schemes ...... 137 11.6 Shareholding and share options ...... 138 11.7 Conflicts of interests etc...... 138

12 RELATED PARTY TRANSACTIONS ...... 139 12.1 Transactions with the Norwegian State ...... 139 12.2 Other transactions ...... 139

13 CORPORATE INFORMATION; SHARES AND SHARE CAPTAL; SHAREHOLDERS ...... 140 13.1 Incorporation; registration number; registered office and other Company information ...... 140 13.2 Share capital and share capital history ...... 140 13.3 Shareholder rights ...... 140 13.4 Legal structure ...... 140 13.5 Major shareholders ...... 141 13.6 Authorisation to distribute dividend based on approved annual accounts for 2015 ...... 142 13.7 Authorisation to increase the share capital and to issue Shares ...... 142 13.8 Authorisation to acquire Statoil ASA shares in the market to continue operation of the share savings plan for employees ...... 143 13.9 Authorisation to acquire Statoil ASA shares in the market for subsequent annulment ...... 143 13.10 The Articles of Association ...... 143 13.11 Certain aspects of Norwegian law ...... 144

14 TAXATION ...... 148 14.1 Norwegian shareholders ...... 148 14.2 Non-Norwegian Shareholders ...... 149 14.3 VAT and transfer taxes etc...... 150 14.4 Inheritance Tax ...... 150

15 SECURITIES TRADING IN NORWAY ...... 151 15.1 Introduction ...... 151 15.2 Trading and settlement ...... 151 15.3 Information, control and surveillance ...... 151 15.4 The VPS and transfer of shares...... 152 15.5 Shareholder register – Norwegian law ...... 152 15.6 Foreign investment in shares listed in Norway ...... 152 15.7 Disclosure obligations ...... 152 15.8 Insider trading ...... 153 15.9 Mandatory offer requirement ...... 153 15.10 Compulsory acquisition ...... 154 15.11 Foreign exchange controls ...... 154

16 SELLING AND TRANSFER RESTRICTIONS ...... 155 16.1 General ...... 155 16.2 European Economic Area ...... 156 16.3 United Kingdom ...... 156 16.4 Germany ...... 157 16.5 France ...... 157 16.6 Switzerland ...... 157 16.7 Canada...... 158 16.8 Singapore ...... 158 16.9 Japan ...... 158 16.10 Hong Kong ...... 158

17 INCORPORATION BY REFERENCE AND DOCUMENTS ON DISPLAY ...... 160 17.1 Cross reference table ...... 160 17.2 Documents on display ...... 160

18 ADDITIONAL INFORMATION ...... 161 18.1 Independent auditors ...... 161 18.2 Receiving Agent...... 161 18.3 Legal advisor...... 161

19 NORWEGIAN SUMMARY ...... 162

20 DEFINITIONS ...... 169

APPENDICES

Appendix A ARTICLES OF ASSOCIATION A1

Appendix B SUBSCRIPTION FORM IN ENGLISH B1

Appendix C SUBSCRIPTION FORM IN NORWEGIAN C1 1 SUMMARY Summaries are made up of disclosure requirements known as "Elements". These Elements are numbered in Sections A– E (A.1 – E.7) below. This summary contains all the Elements required to be included in a summary for this type of securities and the Company. Because some Elements are not required to be addressed, there may be gaps in the numbering sequence of the Elements. Even though an Element may be required to be inserted in the summary because of the type of securities and issuer, it is possible that no relevant information can be given regarding the Element. In this case a short description of the Element is included in the summary with the mention of "not applicable".

Section A – Introduction and Warnings

A.1 Warning This summary should be read as introduction to the Prospectus; any decision to invest in the securities should be based on consideration of the Prospectus as a whole by the investor; where a claim relating to the information contained in the Prospectus is brought before a court, the plaintiff investor might, under the national legislation of the Member States, have to bear the costs of translating the Prospectus before the legal proceedings are initiated; and civil liability attaches only to those persons who have tabled the summary including any translation thereof, but only if the summary is misleading, inaccurate or inconsistent when read together with the other parts of the prospectus or it does not provide, when read together with the other parts of the Prospectus, key information in order to aid investors when considering whether to invest in such securities.

A.2 Warning Not applicable. No consent is granted by the Company for the use of the Prospectus for subsequent resale or final placement of the Shares.

Section B - Issuer

B.1 Legal and commercial Statoil ASA name

B.2 Domicile and legal form, The Company is a Norwegian public limited liability company legislation and country of incorporated in Norway under the Norwegian public limited liability incorporation companies act ("Norwegian Public Limited Liability Companies Act"), with business registration number 923 609 016. The Company's registered office is at Forusbeen 50, 4035 Stavanger, Norway.

B.3 Current operations, Statoil is a technology-driven energy company primarily engaged in principal activities and oil and gas exploration and production activities. Statoil's head office markets is located in Stavanger, Norway. Statoil is the leading operator on the Norwegian continental shelf ("NCS") and also has substantial international activities. Statoil is present in several of the most important oil and gas provinces in the world, has business operations in more than 30 countries and territories, and employs about 21,350 employees and hired consultants worldwide by end of July 2016. In the second quarter of 2016, 38% of Statoil's Equity Production (as defined in Section 9.1.1 "Business Overview") came from international activities and Statoil also holds operatorships internationally.

B.4a Significant recent trends The oil market remained oversupplied into the second quarter of

1 2016. This is a remaining effect of OPEC’s decision in October 2015 to protect their market share in the face of rising US shale oil production, leading to oversupply of crude oil. However, through the first half of 2016, high refinery intake has shifted parts of the oversupply into refined products. A significant part of the oversupply is also seen within the natural gas liquids ("NGL") segment, being associated products from both oil and gas production. This has left the crude oil segment reasonably balanced, with some draws on inventories in the second quarter of 2016, but from a still very high level. The development of the price for Brent crude oil is set out in the graph below: 1

In adapting to the lower price environment, the oil industry has made substantial efficiency gains, but also cut investments in drilling and new projects. This has made the effect of natural output declines from existing fields more prominent. Low prices have also kept global demand growth quite strong, estimated by the IEA at 1.4 mmbbl per day in 2016 and 1.3 mmbbl per day in 2017.2 In sum, such effects are seen by Statoil to lead to inventory drawdown through the rest of 2016, but that inventory levels will only be back to normal towards the end of 2017. Upwards price reactions, as set by investors at the commodity exchanges, could still be seen early in this process, as the direction becomes clear. There are still large uncertainties to this view, as the projected inventory drawdowns amount to less than 1% of global demand. On the supply side, such uncertainties relate to the extent of the natural decline, new or end of current civil unrest, unplanned disruptions, and to at which price level the US shale oil industry finds it attractive to restart production. On the demand side, such uncertainties relate to economic growth and environmental regulations. Since the beginning of 2015, European gas prices have been trending downwards, as set out by the graph below3, pressurized by weak competitive fuels such as coal and oil:

1 Source oil: S&P Global Platts’ Dated Brent at close, payable source. 2 All volumetric figures (mmbbl) are from The International Energy Agency’s Oil Market Report of 13 July 2016. 3 Source gas: ICIS Heren and ECB; Description: European Natural Gas NBP Heren Gas Prices Day ahead (http://www.icis.com/energy/gas/europe/european-spot-gas-markets/), Currency provider ECB, Unit=USD/mmBtu and CME New York Mercantile Exchange Henry Hub Natural Gas Regular Trading Month 01

In addition to this, demand has been reduced by the continued absence of any significant gas use in the power sector outside of the UK, warm temperatures impacting winter heating demand. However, support has materialized in the second quarter of 2016 as disruptions to liquefied natural gas ("LNG") supply has seen lower than expected volumes delivered to Europe. This disruption is, however, only temporary and increased supply is expected. From 2016 – 2018, an estimated 30 – 40 bcm of LNG capacity will be added, annually, to the global market. This is expected to create an oversupply situation. However, Europe has a large and growing supply gap and will be in need of imports for years to come. The declining indigenous production is a key driver for this, especially the new production cap at the Groningen field in the Netherlands. At the same time, Europe’s demand for gas is expected to remain at the current level. Within the power sector there is a potential for growth as gas is expected to replace coal. This means that Europe will have a high need for gas imports under any realistic demand scenario. This provides a strong business case, both for the short as well as the long term. In the short term Statoil expects to see a well-supplied market. However, in the long term market beyond 2020, Statoil believes that the market will strengthen and the demand will pick up again increasing the prices. In the US, falling prices have allowed gas to gain market share at the expense of other fuels, particularly coal. In the short run, power pools turn on natural gas plants more often, and in the long run, natural gas plants are built, while coal plants are decommissioned. Natural gas is now the largest source of electric power generation in the US as a result, representing 33% of all generation in 2015. As a consequence of the low price environment, the industry continues to scrutinize investments plans and activity levels and is implementing further initiatives to reduce operational costs. Taking into account the outlook for continued changes in global market forces and industry structure, it is likely that the dynamics of supply and demand will remain uncertain. According to industry analysts, lower investment levels and lack of investments in exploration should contribute to a balancing of the markets, albeit there is uncertainty as to when this will happen, and at what level commodity prices will level out. Statoil has previously initiated a number of initiatives to enforce stricter financial management and improve capital efficiency. Statoil carries on these initiatives, strictly prioritizing the project portfolio

by optimizing projects to further improve its robustness as well as divesting projects that are considered non-core such as the divestment of Marcellus operated assets in the US onshore portfolio. In addition, Statoil continues to renegotiate its supplier contracts to achieve improved terms.

B.5 Description of the Group The Company is the ultimate parent company in Statoil and the business is carried out both through the Company and its wholly or partly owned subsidiaries.

B.6 Interests in the Company Shareholders owning 5% or more of the Shares have an interest in and voting rights the Company’s share capital which is notifiable pursuant to the Norwegian Securities Trading Act. As of the date of this Prospectus, there is one shareholder owning more than 5% of the Shares in the Company; the Norwegian State holds 67% of the Shares. There are no differences in voting rights between the Shares. The Company is not aware of any arrangements which may at a subsequent date result in change of control of the Company.

B.7 Selected historical key The selected historical key financial information has been financial information incorporated by reference into this Prospectus.

B.8 Selected key pro forma Not applicable. The Prospectus does not contain pro forma financial financial information information.

B.9 Profit forecast or estimate Not applicable. The Prospectus does not contain profit forecasts or estimates.

B.10 Audit report qualifications Not applicable. There are no qualifications in the audit reports.

B.11 Working capital The Company has sufficient working capital for its present requirements.

Section C - Securities

C.1 Type and class of The Company has one class of Shares in issue and all Shares securities admitted to provide equal rights in the Company. Each of the Shares carries one trading and identification vote. The Shares have been created under the Norwegian Public number Limited Liability Companies Act and are registered in book-entry form with the VPS under ISIN NO 0010096985.

C.2 Currency of issue The Shares are issued in NOK.

C.3 Number of shares in issue Prior to the Dividend Issue, the share capital of the Company is NOK and par value 8,017,365,112.50, divided into 3,206,946,045 ordinary shares each with a nominal value of NOK 2.50. All the Shares have been created under the Norwegian Public Limited Liability Companies Act, and are validly issued and fully paid.

C.4 Rights attaching to the The Company has one class of Shares in issue, and in accordance securities with the Norwegian Public Limited Liability Companies Act, all Shares in that class provide equal rights in the Company. Each of the Shares carries one vote.

C.5 Restrictions on transfer The Company's articles of association (the "Articles of Association") do not provide for any restrictions on the transfer of Shares, or a right of first refusal for the Company’s shareholders. Share transfers are not subject to approval by the Board of Directors.

C.6 Admission to trading The Company's Shares are listed on the Oslo Stock Exchange under trading symbol "STL". The Dividend Shares issued in the Dividend Issue will be listed. In addition, the Company's American Depositary Receipts ("ADR") are listed on the New York Stock Exchange ("NYSE") under the trading symbol "STO". The ADR Depositary (as defined below) will issue new ADRs to ADR-holders based on the Dividend Shares that ADR-holders are entitled to receive, which will be listed on NYSE.

C.7 Dividend policy It is Statoil's ambition to grow the annual cash dividend measured in USD per share, in line with long-term underlying earnings. The Company announces dividends on a quarterly basis. The Board of Directors approves first, second and third quarter interim dividends based on an authorisation from the annual general meeting, while the annual general meeting approves the fourth quarter (and total annual) dividend based on a proposal from the Board of Directors. When deciding the interim dividends and recommending the total annual dividend level, the Board of Directors will take into consideration expected cash flow, capital expenditure plans, financing requirements and appropriate financial flexibility. In addition to cash dividends, the Company might buy back shares as part of total distribution of capital to the shareholders. The Board of Directors updated the dividend policy in 2015 to reflect USD as the declaration currency.

Section D - Risks

D.1 Key risks specific to the Risks relating to Statoil and the industry in which Statoil Company or its industry operates • A prolonged period of low oil and/or natural gas prices could have a materially adverse effect on Statoil. • Statoil's crude and natural gas reserves are only estimates and Statoil's future production, revenues and expenditures with respect to its reserves may differ materially from these estimates. • Exploration drilling involves numerous risks, including the risk that Statoil will encounter no commercially productive oil or natural gas reservoirs. • Statoil's development projects and production activities are involved in many uncertainties and operating risks that can prevent Statoil from realising profits and cause substantial losses. • Some of Statoil's international interests are located in regions where political, social and economic instability could adversely impact Statoil's business. • Non-compliance with anti-bribery, anti-corruption and other applicable laws, including failure to meet Statoil's ethical requirements, exposes Statoil to legal liability and damage to its reputation, business and shareholder value. • Statoil is exposed to a wide range of health, safety and environmental risks that could result in significant losses. • Policy and regulatory change due to rising climate change concerns, and the physical effects of climate change,

could impact Statoil's business.

D.3 Key risks specific to the Risks related to the Shares securities • The price of the Company's Shares may experience volatility. • Existing Shareholders in other jurisdictions than Norway may have difficulties in enforcing civil liabilities. • Shareholders could be unable to exercise their voting rights for Shares registered in a nominee account. • The transfer of Shares is subject to restrictions under the securities laws of the United States and other jurisdictions. • Existing Shareholders who do not elect to receive Dividend Shares or who are unable to participate in the Dividend Issue, may experience a dilution in their shareholding.

Section E – Offer

E.1 Net proceeds and The net proceeds of the Dividend Issue if fully subscribed, will be estimated expenses USD 703 million, after deduction of costs and expenses to be borne by the Company, currently estimated to be USD 0.6 million.

E.2a Reasons for the Offering The Company considers the dividend policy an important and use of proceeds commitment to its shareholders and the dividend policy remains firm. The Scrip Dividend Programme (as defined below) is expected to strengthen the Company's financial robustness in a low price environment. This initiative comes in addition to other measures such as strict financial discipline and significant efficiency improvements. Further, the Scrip Dividend Programme is a tool to strengthen the Company's financial capacity to invest in profitable projects in a low, volatile and uncertain price environment.

E.3 Terms and conditions of The Dividend Issue comprises of up to 160,000,000 Dividend the Offering Shares, each with a nominal value of NOK 2.50. The Subscription Price for the Dividend Shares, which will be settled by way of set-off against the Net Dividend entitlement, will be in the range of NOK 50 to NOK 500 per Dividend Share. Subject to applicable securities laws, Existing Shareholders will under the Scrip Dividend Program be entitled to elect to use their Net Dividends to subscribe for Dividend Shares in the Company in whole or in part. Existing Shareholders will be allocated the number of Dividend Shares equal to the amount each Existing Shareholder has subscribed for during the Subscription Period, divided by the Subscription Price. All subscriptions will be rounded down to the nearest whole number of shares. Any part of the Net Dividend not used for subscription of Dividend Shares, will be paid in cash. Existing Shareholders who choose to receive all of their Net Dividends in Dividend Shares, but whose Net Dividend does not exceed the Subscription Price for one share will receive their Dividend paid in cash. Over-subscription and subscription of Dividend Shares by other than by Existing Shareholders will not be permitted. For the purposes of determining eligibility for participation in the Dividend Issue, the Company will look solely to its register of

shareholders as of the expiry of the Record Date. The Subscription Price is expected to be announced on or about 12 September 2016 and shall be equal to the volume-weighted average share price on Oslo Stock Exchange of the last two trading days of the subscription period, i.e. 8 and 9 September 2016, less a 5% discount. The subscription price for the ADR holders will be equal to the Subscription Price converted into USD using the Central Bank of Norway's average closing exchange rate of the last two trading days of the Subscription Period, i.e. 8 and 9 September 2016. The contribution for the Dividend Shares will be settled by way of set-off against the claim of the Net Dividend the Existing Shareholder is entitled to. The Subscription Period will commence on 29 August 2016 at 09:00 hours (CEST) and end on 9 September 2016 at 23:59 hours (CEST), unless the Subscription Period is extended. Existing Shareholders who have not subscribed for Dividend Shares at the time of expiry of the Subscription Period will be paid the total dividend amount the relevant Existing Shareholder is entitled to in cash without any action on its part, on or about 23 September 2016. The expected payment date for Dividend in USD to ADR holders is on or about 26 September 2016. The Company expects that the share capital increase pertaining to the Dividend Issue will be registered with the Norwegian Register of Business Enterprises (Nw: Foretaksregisteret) on or about 22 September 2016 and that the Dividend Shares will be delivered to the VPS accounts of the subscribers to whom they are allocated on or about 23 September 2016. Trading in the Dividend Shares on the Oslo Stock Exchange is expected to commence under the trading symbol "STL" from on or about 26 September 2016.

E.4 Material and conflicting The Company is not aware of any material or conflicting interests of interests natural and legal persons involved in the Dividend Issue.

E.5 Selling shareholder and Not applicable. All Dividend Shares will be newly issued shares and lock-up agreements no subscriber will be subject to lock-up agreements.

E.6 Dilution resulting from the The Dividend Issue is expected to result in a dilution of Existing Offering Shareholders who do not participate in the Dividend Issue of up to approximately 1.4 per cent.

E.7 Estimated expenses Not applicable. No expenses will be charged to the investor by the charged to investor Company.

2 RISK FACTORS An investment in the Shares, including the Dividend Shares, involves inherent risk. Before making an investment decision with respect to the Dividend Shares, investors should carefully consider the risk factors and all information contained in this Prospectus, including the financial statements and related notes. The risks and uncertainties described in this Section 2 "Risk factors" are the principal known risks and uncertainties faced by Statoil that the Company believes are the material risks relevant to an investment in the Shares, including the Dividend Shares. An investment in the Shares, including the Dividend Shares, is suitable only for investors who understand the risks associated with this type of investment and that, by investing in the Dividend Shares, they could lose all or part of their investment. The fact that certain negative past events associated with a given risk factor did not occur in the past does not mean that the risks and uncertainties described herein should not be considered prior to making an investment decision in respect of the Shares, including the Dividend Shares. If any of the following risks were to materialise, individually or together with other circumstances, they could have a material and adverse effect on Statoil and/or its business, results of operations, cash flows, financial condition and/or prospects, which may cause a decline in the value and trading price of the Shares, including the Dividend Shares, resulting in the loss of all or part of an investment in the Shares, including the Dividend Shares.

The order in which the risks are presented does not reflect the likelihood of their occurrence or the magnitude of their potential impact on Statoil’s business, results of operations, cash flows, financial condition and/or prospects. The risks mentioned herein could materialise individually or cumulatively.

2.1 Risks relating to Statoil and the industry in which Statoil operates 2.1.1 A prolonged period of low oil and/or natural gas price could have a materially adverse effect on Statoil The prices of oil and natural gas have fluctuated greatly in response to changes in many factors. Currently, Statoil is in a situation where oil and natural gas prices have declined substantially compared to levels seen over the last few years. There are several reasons for this decline, but fundamental market forces beyond the control of Statoil or other similar market participants have impacted and can continue to impact oil and natural gas prices in the future.

Generally, Statoil does not and will not have control over the factors that affect the prices of oil and natural gas. These factors include:

• economic and political developments in resource-producing regions;

• global and regional supply and demand;

• the ability of the Organisation of the Petroleum Exporting Countries ("OPEC") and/or other producing nations to influence global production levels and prices;

• prices of alternative fuels that affect the prices realised under Statoil's long-term gas sales contracts;

• government regulations and actions; including changes in energy and climate policies

• global economic conditions;

• war or other international conflicts;

• changes in population growth and consumer preferences;

• the price and availability of new technology; and

• weather conditions.

It is impossible to predict future price movements for oil and/or natural gas with certainty. A prolonged period of low oil and natural gas prices will adversely affect Statoil's business, the results of operations, financial condition, liquidity and Statoil's ability to finance planned capital expenditure, including possible reductions in capital expenditures which could lead to reduced reserve replacement. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators could, if deemed to have longer term impact, lead to further reviews for impairment of Statoil's oil and natural gas properties. Such reviews would reflect the Management's (as defined below) view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the results of Statoil's operations in the period in which it occurs. Changes in Management’s view on long-term oil and/or natural gas prices or further material reductions in oil, gas and/or product prices could have an adverse impact on the economic viability of projects that are planned or in development.

2.1.2 Statoil’s proved crude and natural gas reserves are only estimates and Statoil’s future production, revenues and expenditures with respect to its reserves may differ materially from these estimates The reliability of proved reserve estimates depends on:

• the quality and quantity of Statoil’s geological, technical and economic data;

• the production performance of Statoil’s reservoirs;

• extensive engineering judgments; and

• whether the prevailing tax rules and other government regulations, contracts and oil, gas and other prices will remain the same as on the date estimates are made.

Proved reserves are estimated based on the U.S. Securities and Exchange Commission ("SEC") requirements and may therefore differ substantially from Statoil’s view on expected reserves.

Many of the factors, assumptions and variables involved in estimating reserves are beyond Statoil’s control and may prove to be incorrect over time. The results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in Statoil’s reserve data. The prices used for proved reserves are defined by the SEC and are calculated based on a 12 month unweighted arithmetic average of the first-day-of-the-month price for each month during the reporting year, leading to a forward price strongly linked to last year’s price environment. Fluctuations in oil and gas prices will have a direct impact on Statoil’s proved reserves. For fields governed by production sharing agreements ("PSAs"), a lower price may lead to higher entitlement to the production and increased reserves for those fields. Adversely, a lower price environment may also lead to lower activity resulting in reduced reserves. For PSAs these two effects may to some degree offset each other. In addition a low price environment may result in earlier shutdown due to uneconomic production. This will affect both PSAs and fields with concession types of agreement.

2.1.3 Exploration drilling involves numerous risks, including the risk that Statoil will encounter no commercially productive oil or natural gas reservoirs Statoil's exploration activities include accessing new acreage and maturing resources through high risk exploration drilling activities. These risks include risks associated with the execution of drilling and seismic operations and those associated with maturing unproven resources.

New acreage is primarily acquired through concessions, bidding rounds and acquisitions. Geological interpretations and successful exploration drilling and appraisal work leads to maturing and commercially attractive resources. Additionally, Statoil also needs to be focused on optimising its rig capacity by thoughtful deployment and redeployment. Given these risks and operational requirements, Statoil may not effectively acquire acreage, successfully conduct its drilling and appraisal work or optimise its rig capacity, which could result in a material adverse effect on the results of its operations and financial condition. Exploration activities involve the risk of accidents and environmental incidents. Exploration activities also involve technical challenges related to operating in harsh environments as well as technologically demanding subsurface/geological challenges which Statoil may not effectively manage. Failure to discover and operate commercially productive oil or natural gas reservoirs could materially adversely affect Statoil's business, results of operations and financial condition.

2.1.4 If Statoil fails to acquire or discover and develop additional reserves, its reserves and production will decline materially from their current levels Successful implementation of Statoil's strategy for value growth is critically dependent on sustaining its long- term reserve replacement. If upstream resources are not progressed to proved reserves in a timely manner, Statoil’s reserve base and thereby future production will gradually decline and future revenue will be reduced.

Statoil's future production is highly dependent on its success in acquiring or finding and developing additional reserves adding value. If unsuccessful, future total proved reserves and production will decline.

If the low price environment continues for a substantial time, this may result in undeveloped acreage not being considered economically viable and consequently discovered resources not being matured to reserves. This may also lead to exploration areas not being explored for new resources and subsequently not being matured for development resulting in less future proved reserves. Successful implementation of Statoil’s improvement initiatives may partly offset this effect to some degree making new exploration areas and undeveloped acreage more economically attractive for exploration and development.

In a number of resource-rich countries, national oil companies control a significant proportion of oil and gas reserves that remain to be developed. To the extent that national oil companies choose to develop their oil and gas resources without the participation of international oil companies, or if Statoil is unable to develop partnerships with national oil companies, its ability to find and acquire or develop additional reserves will be more limited.

2.1.5 Statoil is exposed to a wide range of health, safety and environmental risks that could result in significant losses Exploration for, and the development, production, processing and transportation of oil and natural gas can be hazardous and technical integrity failures, operational failures, natural disasters or other occurrences can result in: loss of life, oil spills, gas leaks, loss of containment of hazardous materials, water contamination, blowouts, cratering, fires and equipment failure, among other things.

The risks associated with Statoil's activities are affected by the difficult geographies, climate zones and environmentally sensitive regions in which Statoil operates. All modes of transportation of hydrocarbons - including road, rail, sea or pipeline - are particularly susceptible to a loss of containment of hydrocarbons and other hazardous materials, and, given the high volumes involved, these could represent a significant risk to people and the environment. Offshore operations and transportation are subject to marine perils, including severe storms and other adverse weather conditions and vessel collisions. Onshore operations and transportation are subject to adverse weather conditions and accidents. Both onshore and offshore operations and transportation are subject to interruptions, restrictions or termination by government authorities based on safety, environmental or other considerations.

2.1.6 Policy and regulatory change due to rising climate change concerns, and the physical effects of climate change, could impact Statoil’s business Statoil expects and is preparing for policy and regulatory changes targeted at reducing greenhouse gas emissions of its upstream operations/activities. Statoil expects greenhouse gas emission costs to increase from current levels beyond 2020 and to have a wider geographical range than today. There is continuing uncertainty over these regulatory and policy developments, including the mechanisms that will be employed, and the level of global co-ordination and hence efficiency and uniformity of measures. This in turn leads to uncertainty over the eventual long-term implications to development project cost or operating cost and constraints. As an example, new technological solutions could be required. This could result in increased cost or longer lead times, or have an impact on investment decisions for future projects. Climate related policy changes may also reduce access to prospective geographical areas in the future and affect the demand for and prices of Statoil's products.

Regulatory changes and other factors may encourage the development of low-carbon energy technologies such as renewable energy which could impact the demand for oil and gas, particularly in specific regions. As an example, development of battery technologies could allow more intermittent renewables to be used in the

power sector. This could especially impact Statoil's gas sales, particularly if subsidies of renewable energy in Europe were to increase.

Statoil carefully monitors and assesses the potential impact of climate change. Developments in climate change could have a significant impact on Statoil's financial performance, profitability and outlook, whether directly through changes in taxation and regulation, or indirectly through changes in consumer behaviour.

Statoil has assessed the sensitivity of its project portfolio (Equity Production and expected production from accessed exploration acreage) against the assumptions regarding commodity and carbon prices in the International Energy Agency’s ("IEA") Current Policies scenario, the IEA New Policies scenario and the IEA 450 scenario, as laid out in their "World Economic Outlook 2015" report. The assessment demonstrated that the IEA’s "450 ppm scenario",4 which is compatible with a global warming of maximum of two degrees Celsius with more than 50% probability, could have a negative impact of approximately 5% on Statoil’s net present value compared to Statoil’s internal planning assumptions as of December 2015. This assessment is based on Statoil’s and the IEA’s assumptions which may not be accurate and which are likely to change over time as new information becomes available. Accordingly, there can be no assurance that the assessment, which is presented in Statoil's 2015 Sustainability report, is a reliable indicator of the actual impact of climate change on Statoil.

It is not possible to predict the exact magnitude of the physical impact of climate change on Statoil's operations. However, effects of climate change could result in less stable weather patterns, which would result in more severe storms and other weather conditions that could interfere with Statoil's operations. Changes in physical climate parameters could impact the costs of Statoil's operations, for example through restrained water availability and prolonged droughts, or through increasing frequency of other extreme weather events.

2.1.7 Statoil is exposed to risk as a result of its hydraulic fracturing usage Statoil's US operations use hydraulic fracturing which is subject to a range of applicable federal, state and local laws, including those discussed under Section 2.1.22 "Legal and regulatory risks". Fracturing is an important and common practice that is used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. Statoil's hydraulic fracturing and fluid handling operations are designed and operated to minimise the risk, if any, of subsurface migration of hydraulic fracturing fluids and spillage or mishandling of hydraulic fracturing fluids, however, a proven case of subsurface migration of hydraulic fracturing fluids or a case of spillage or mishandling of hydraulic fracturing fluids during these activities could potentially subject Statoil to civil and/or criminal liability and the possibility of substantial costs, including environmental remediation, depending on the circumstances of the underground migration, spillage, or mishandling, the nature and scope of the underground migration, spillage, or mishandling, and the applicable laws and regulations.

In addition, various states and local governments have implemented, or are considering, increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, disclosure requirements and temporary or permanent bans. New or further changes in laws and regulations imposing reporting obligations on, or otherwise banning or limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells in shale formations, cause operational delays, increase costs of regulatory compliance or in exploration and production, which could adversely affect Statoil's US onshore business and the demand for fracturing services.

2.1.8 Statoil is exposed to security threats that could have a materially adverse effect on Statoil’s results of operations, assets or financial condition Although Statoil has security barriers, policies and risk management processes in places which are designed to protect its assets, including its information systems and digital infrastructure, against a range of security threats, no assurances can be made that such attacks will not occur and adversely impact its operations. Threats to Statoil’s industrial control systems are not limited by geography as Statoil’s digital infrastructure is accessible globally, and incidents in the industry in recent years have shown that parties who are able to circumvent barriers aimed at securing industrial control systems are capable and willing to perform attacks that destroy, disrupt or otherwise compromise operations. Security threats such as acts of terrorism and cyber-

4 http://www.iea.org/publications/scenariosandprojections/

attacks against Statoil's production and exploration facilities, offices, pipelines, means of transportation or computer systems or breaches of Statoil's security system, could result in significant losses. Failure to manage the foregoing risks could result in injury or loss of life, damage to the environment, damage to or the destruction of wells and production facilities, pipelines and other property, may affect the confidentiality, integrity or availability of its information systems and digital infrastructure, including those critical to Statoil’s operations. Statoil could face, among other things, regulatory action, legal liability, damage to its reputation, a significant reduction in revenues, an increase in costs, a shutdown of operations and a loss of its investments in affected areas. Statoil does not purchase cyber risks insurance because the available insurance products do not provide satisfactory coverage.

2.1.9 Statoil’s crisis management systems may prove inadequate Statoil has crisis management plans and capability to deal with emergencies at every level of its operations. If Statoil does not respond or is perceived not to have responded in an appropriate manner to either an external or internal crisis, its business, operations and reputation could be severely affected. For Statoil's most important activities, it has also developed business continuity plans to carry on or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed time frame could prolong the impact of any disruption and could severely affect Statoil's business and operations.

2.1.10 Statoil encounters competition from other oil and gas companies in all areas of its operations Some of Statoil's larger, financially stronger competitors may be able to pay more to gain access to resources, while its smaller competitors may be able to move faster and gain earlier access than Statoil. Gaining access to profitable resources either through the acquisition of licences, exploratory prospects or producing properties is key to ensuring the long-term health and sustainability of the business and Statoil's failure to do so could have an adverse impact on its performance.

Technology is a key competitive advantage in Statoil's industry and a larger company may be able to invest more in developing or acquiring intellectual property rights to technology that Statoil may require. Should Statoil's innovation lag behind the industry, its performance could be impeded.

2.1.11 Statoil’s development projects and production activities are involved in many uncertainties and operating risks that can prevent Statoil from realising profits and cause substantial losses. Oil and gas projects may be curtailed, delayed or cancelled for many reasons, including equipment shortages or failures, natural hazards, unexpected drilling conditions or reservoir characteristics, irregularities in geological formations, accidents, mechanical and technical difficulties or challenges due to new technology. This is particularly relevant because of the physical environments in which some of Statoil’s projects are situated. Many of Statoil's development and production projects are located in deep waters or other harsh environments - such as the Gulf of Mexico in the US, the Flemish Pass in Canada or the Barents Sea in Norway, or have challenging field characteristics such as its heavy oil projects in Brazil (Peregrino), Norway (Grane) and the UK (Mariner). In US onshore, low regional prices may cause certain areas to be unprofitable and Statoil may curtail production until prices recover. There is therefore a risk that Statoil undertakes development projects that do not yield expected returns, especially in the current environment of decreasing oil and gas prices combined with the relatively high levels of tax and government take in several jurisdictions, including Norway.

Capital expenditures in the oil and gas industry have increased over the last few years due to a high activity level and more complex and capital intensive development projects. This, combined with prolonged low oil and gas prices, could reduce the returns and erode the profitability of some of Statoil's projects and capital programs.

As a response to these challenges, Statoil will need at all times to evaluate profitability and robustness of projects and consider postponing or stopping projects, adjusting strategies and targets or withdrawing from certain geographical areas.

2.1.12 Statoil faces challenges in achieving its strategic objective of successfully exploiting profitable growth opportunities An important element of Statoil's strategy is to continue to pursue attractive and profitable growth opportunities available to it by both enhancing and repositioning its asset portfolio and expanding into new markets. The opportunities that Statoil is actively pursuing may involve the acquisition of businesses or properties that complement or expand its existing portfolio. The challenges related to the renewal of Statoil's upstream portfolio is growing due to increasing global competition for access to opportunities.

Statoil's ability to successfully implement this strategy will depend on a variety of factors, including its ability to:

• identify acceptable opportunities;

• negotiate favourable terms;

• develop new market opportunities or acquire properties or businesses promptly and profitably;

• integrate acquired properties or businesses into Statoil's operations;

• arrange financing, if necessary; and

• comply with legal regulations.

As Statoil pursues business opportunities in new and existing markets, it anticipates significant investments and costs in connection with the development of such opportunities. Statoil may incur or assume unanticipated liabilities, losses or costs associated with assets or businesses acquired. Any failure by Statoil to successfully pursue and exploit new business opportunities could result in financial losses and inhibit growth. Any such new projects Statoil acquires will require additional capital expenditure and will increase the cost of its discoveries and development. These projects may also have different risk profiles than Statoil's existing portfolio. These and other effects of such acquisitions could result in Statoil having to revise either or both of Statoil's forecasts with respect to unit production costs and production.

In addition, the pursuit of acquisitions or new business opportunities could divert financial and management resources away from Statoil's day-to-day operations to the integration of acquired operations or properties. Statoil may require additional debt or equity financing to undertake or consummate future acquisitions or projects, and such financing may not be available on terms satisfactory to Statoil, if at all, and it may, in the case of equity, be dilutive to Statoil's earnings per share.

2.1.13 The profitability of Statoil’s oil and gas production may be affected by limited transportation infrastructure when a field is in a remote location Statoil's ability to exploit economically any discovered petroleum resources beyond its proved reserves will depend, among other factors, on the availability of the infrastructure required to transport oil and gas to potential buyers at a commercially acceptable price. Oil is transported by vessels, rail or pipelines to refineries, and natural gas is usually transported by pipeline or by vessels (for liquid natural gas) to processing plants and end users. Statoil may not be successful in its efforts to secure transportation and markets for all of its potential production.

2.1.14 Some of Statoil’s international interests are located in regions where political, social and economic instability could adversely impact Statoil’s business Statoil has assets and operations located in politically, socially and economically diverse regions around the world where potential developments such as expropriation, nationalisation of property, unilateral change of contracts or regulations, civil strife, strikes, political unrest, war, terrorism, border disputes, guerrilla activities, insurrections, piracy and the imposition of international sanctions or other events could occur. Political risks and security threats require continuous monitoring. Adverse and hostile actions against Statoil's staff, its facilities, its transportation systems and its digital infrastructure (cybersecurity) could cause harm to people and disrupt Statoil's operations and further business opportunities in these or other regions, lead to a decline in

production and otherwise adversely affect Statoil's business. This could have a materially adverse effect on Statoil's results of operations and its financial condition.

2.1.15 Statoil’s operations are subject to dynamic political and legal factors in the countries in which it operates Statoil has assets in a number of countries with emerging or transitioning economies that, in part or in whole, lack well-functioning and reliable legal systems, where the enforcement of contractual rights is uncertain or where the governmental and regulatory framework is subject to unexpected change. Statoil's exploration and production activities in these countries are often undertaken together with national oil companies and are subject to a significant degree of state control. In recent years, governments and national oil companies in some regions have begun to exercise greater authority and impose more stringent conditions on companies engaged in exploration and production activities. Intervention by governments in such countries can take a wide variety of forms, including:

• restrictions on exploration, production, imports and exports;

• the awarding or denial of exploration and production interests;

• the imposition of specific seismic and/or drilling obligations;

• price and exchange controls;

• tax or royalty increases, including retroactive claims;

• nationalisation or expropriation of Statoil's assets;

• unilateral cancellation or modification of Statoil's licence or contractual rights;

• the renegotiation of contracts;

• payment delays; and

• currency exchange restrictions or currency devaluation.

The likelihood of these occurrences and their overall effect on Statoil vary greatly from country to country and are hard to predict. If such risks materialise, they could cause Statoil to incur material costs and/or cause Statoil's production to decrease, potentially having a materially adverse effect on Statoil's operations or financial condition.

2.1.16 Statoil is exposed to potentially adverse changes in the tax regimes of each jurisdiction in which Statoil operates Statoil has business operations in many countries around the world. Changes in the tax laws of the countries in which Statoil operates could have a material adverse effect on its liquidity and results of operations.

2.1.17 Non-compliance with anti-bribery, anti-corruption and other applicable laws, including failure to meet Statoil’s ethical requirements, exposes Statoil to legal liability and damage to its reputation, business and shareholder value Statoil has activities in countries which present corruption risks and which may have weak legal institutions, lack of control and transparency. In addition, governments play a significant role in the oil and gas sector, through ownership of resources, participation, licensing and local content which leads to a high level of interaction with public officials. Statoil is, through its international activities, subject to anti-corruption and bribery laws in multiple jurisdictions, including the Norwegian Penal code, the US Foreign Corrupt Practices Act and the UK Bribery Act. A violation of any applicable anti-corruption and bribery laws could expose Statoil to investigations from multiple authorities, and any violations of laws may lead to criminal and/or civil liability with substantial fines. Incidents of non-compliance with applicable anti-corruption and bribery laws and regulations and the Statoil Code of Conduct could be damaging to Statoil's reputation, competitiveness and shareholder value.

2.1.18 Statoil insurance cover may not provide adequate protection Statoil maintains insurance coverage that includes coverage for physical damage to its oil and gas properties, third-party liability, workers' compensation and employers' liability, general liability, sudden pollution and other coverage. Statoil's insurance coverage includes deductibles that must be met prior to recovery. Statoil's external insurance is subject to caps, exclusions and limitations, and there is no assurance that such coverage will adequately protect Statoil against liability from all potential consequences and damages.

2.1.19 Statoil’s efficiency change agenda may impact the development of Statoil’s business and its financial results In 2014, Statoil announced an extensive efficiency change strategy in order to improve efficiency across the organisation in light of the decline in oil and gas prices. Two programmes were launched, the Statoil Technical Efficiency Programme and the organisational efficiency programme. There is a risk of Statoil not being able to define and implement the activities related to cost savings without adversely effecting Statoil’s business goals or achieving the necessary cost savings and increases in efficiency.

2.1.20 Statoil may fail to secure the right level of workforce competence and capacity over the short to medium term The external uncertainty of the future of the oil industry in light of reduced oil and natural gas prices and climate policy changes, creates a risk in ensuring a robust workforce through industry cycles. The oil industry is a long-term business and needs to take a long-term perspective on workforce capacity and competence. Given the current extensive change agenda there is a risk that Statoil will fail to secure the right level of workforce competence and capacity.

2.1.21 Statoil’s activities in certain countries may be affected by international sanctions Statoil, like other major international energy companies, has a geographically diverse portfolio of reserves and operational sites, which may expose its business and financial affairs to political and economic risks, including operations in areas subject to international sanctions or with sanctioned parties.

Russia Statoil holds a 30% non-operating interest in a production sharing agreement related to the Kharyaga field in the Nenets Autonomous Area in the Russian Federation. The Kharyaga field produces conventional oil from the Timan Pechora basin onshore in North West Russia. Statoil is further engaged in a strategic cooperation with Rosneft Oil Company ("Rosneft") including a joint cooperation project aimed at undertaking seismic surveys and geological exploration, appraisal, development and production of potential hydrocarbons in four licences on the Russian continental shelf - the Magadan 1, Lisyansky and Kashevarovsky licences in the Sea of Okhotsk (south of the Arctic Circle), and the Perseevsky licence in the Barents Sea (north of the Arctic Circle). Additionally there are currently two joint cooperation projects onshore; pilot drilling and testing of the onshore heavy oil reservoir layer PK1 in the North Komsomolsky discovery, and the Domanik Sediments Difficult-to- Extract Hydrocarbons Project, aimed at pilot drilling and testing of the limestone Domanik formation in the Russian Volga-Urals basin. For each of these projects, Rosneft holds the majority interest, while Statoil holds a minority interest.

Sanctions imposed by Norway, the European Union ("EU") and the USA target, among others, Russia’s financial and energy sectors, including certain companies such as Rosneft and various affiliates, and specific activities related to oil exploration and production in the Arctic offshore area, and in deep water or shale formation projects. Aspects of those measures affect Statoil’s business activities in Russia. The continued progress and financing of the joint projects are, in part, dependent on Statoil and the joint ventures securing various governmental authorisations and clarifications from such governmental authorities also going forward. Statoil continues to pursue its projects within the limitations of current sanctions. However, due to current and possible future sanctions, there is no certainty that the projects can be progressed and concluded as initially planned.

General The legislation and rules governing sanctions are complex, constantly evolving and may not be consistent across jurisdictions. Changes in any of these laws or policies or the implementation thereof can be unpredictable. Statoil's business is dynamic and the above facts, accordingly, may change over time. Moreover,

the description does not fully reflect all parts of Statoil's business where a particular focus on sanctions compliance might be warranted. Lastly, it should be understood that Statoil in the future could also decide to take part in additional business activity also involving sanctioned targets or markets in various parts of the world whilst still remaining compliant with applicable sanctions laws. Statoil is committed to doing business in compliance with all applicable laws; however, there can be no assurance that Statoil or affiliates of Statoil or their respective officers, directors, employees or agents are not in violation of such laws. Any such violation could result in substantial civil and/or criminal penalties and might materially adversely affect Statoil's business and results of operations or financial condition.

2.1.22 Legal and regulatory risks Compliance with health, safety and environmental laws and regulations that apply to Statoil's operations could materially increase its costs. The enactment of such laws and regulations in the future is uncertain.

Statoil incurs, and expects to continue to incur, substantial capital, operating, maintenance and remediation costs relating to compliance with increasingly complex laws and regulations for the protection of the environment and human health and safety, including:

• costs as a result of stricter climate regulations and a higher price on greenhouse gas emissions;

• costs of preventing, controlling, eliminating or reducing certain types of emissions to air and discharges to the sea, including costs incurred in connection with government action to address the risk of spills and concerns about the impacts of climate change;

• remediation of environmental contamination and adverse impacts caused by Statoil's activities or accidents at various facilities owned or previously owned by Statoil and at third-party sites where Statoil's products or waste have been handled or disposed of;

• compensation of persons and/or entities claiming damages as a result of Statoil's activities or accidents; and

• costs in connection with the decommissioning of drilling platforms and other facilities.

Furthermore, in countries where Statoil operates or expects to operate in the near future, new laws and regulations, the imposition of stricter requirements on licences, increasingly strict enforcement of or new interpretations of existing laws and regulations, the aftermath of operational catastrophes in which Statoil or members of its industry are involved or the discovery of previously unknown contamination may require future expenditure in order to, among other things:

• modify operations;

• install pollution control equipment;

• implement additional safety measures;

• perform site clean-ups;

• curtail or cease certain operations;

• temporarily shut down Statoil's facilities;

• meet technical requirements;

• increase monitoring, training, record-keeping and contingency planning; and

• establish credentials in order to be permitted to commence drilling.

Compliance with laws, regulations and obligations relating to climate change, emissions allowances and other environmental regulations could result in substantial capital expenditure, reduced profitability as a result of changes in operating costs, and adverse effects on revenue generation and strategic growth opportunities. Statoil regularly assesses how changes in regulations, including introduction of stringent climate policies, may impact the oil price, the costs of developing new oil and gas assets, and the demand for oil and gas.

Many of Statoil's mature fields are producing increasing quantities of water with oil and gas. Statoil's ability to dispose of this water in environmentally acceptable ways may have an impact on its oil and gas production. Statoil's investments in North American onshore producing assets will be subject to evolving regulations which are common to all energy companies with investments in this region. This could affect Statoil's operations and profitability with respect to these operations.

If Statoil does not succeed in overcoming the perceived trade-off between global access to energy and the protection or improvement of the natural environment, Statoil could fail to live up to its aspirations of zero or minimal damage to the environment and of contributing to human progress.

Statoil is exposed to risk of supervision, review and sanctions for violations of regulatory laws at the supranational and national level. These include, among others, competition and antitrust laws and financial and trading.

Statoil conducts its activities in multiple jurisdictions and its products are marketed and traded worldwide. It is therefore subject to many local and international laws and regulations including those relating to competition and antitrust, finance and trade, among others. Statoil is exposed to changes in those laws and regulations and to the outcome of any investigations conducted by governmental, international or other regulatory authorities. Violations of applicable laws and regulations may lead to substantial fines and/or sanctions. Statoil is also exposed to financial review from financial supervisory authorities such as the Norwegian FSA and the SEC. Reviews performed by these authorities could result in changes to previous accounts and future accounting policies.

Statoil is listed on both the Oslo Stock Exchange and NYSE, and is registered with the SEC. Statoil is required to comply with the continuing obligations of these regulatory authorities, and violation of these obligations may result in imposition of fines or other sanctions.

The Petroleum Safety Authority Norway ("PSAN") supervises all aspects of Statoil's operations, from exploration drilling through development and operation, to cessation and removal. Its regulatory authority covers the whole NCS as well as petroleum-related plants on land in Norway. Statoil is exposed to supervision from PSAN, and such supervision could result in audit reports, orders and investigations.

The formation of a competitive internal gas market within the EU and the general liberalisation of European gas markets could adversely affect Statoil's business.

The continuing liberalisation of EU gas markets following legislative instruments rolled out in 2011 and the implementation of these legislative instruments by member states, could create new business opportunities for Statoil, but could also affect Statoil's market position or result in a reduction in prices in Statoil's gas sales contracts. Statoil's exposure to hub gas prices has increased and correspondingly increased Statoil’s exposure to price volatility. Statoil continually monitors its contractual obligations and makes efforts to negotiate the most competitive pricing and other conditions available in the market.

The EU-wide quantity of carbon allowances issued each year under the emission trading scheme for greenhouse gas emission allowances began to decrease in a linear manner in 2013. The emission trading scheme can have a positive or negative impact on Statoil, depending on the price of carbon, which will consequently have an impact on the development of gas-fired power generation in the EU. Until now, the carbon price has been too low to replace coal with gas fired generation capacity. This effect has been worsened by heavy subsidising of renewables which has caused gas fired power plants to shut down. Current EU climate and energy policies do not address this problem, but there is a tendency towards more market based subsidies in the new guidelines on environment and energy aid.

Political and economic policies of the Norwegian State could affect Statoil’s business.

The Norwegian State plays an active role in the management of NCS hydrocarbon resources. In addition to its direct participation in petroleum activities through the State's direct financial interest ("SDFI") and its indirect impact through legislation, such as tax and environmental laws and regulations, the Norwegian State, among other things, awards licences for exploration, production and transportation, approves exploration and development projects and applications for production rates for individual fields and may, if important public interests are at stake, also instruct Statoil and other oil companies to reduce petroleum production. Furthermore, in the production licences in which the SDFI holds an interest, the Norwegian State has the power to direct petroleum licences' actions in certain circumstances.

If the Norwegian State were to take additional action under its activities on the NCS or to change laws, regulations, policies or practices relating to the oil and gas industry, Statoil's NCS exploration, development and production activities and the results of its operations could be affected.

In the ordinary course of business, companies in the Statoil group are subject to a number of other loss contingencies arising from litigation and claims raised by governmental and private parties, for instance contractors, tax authorities, land owners for on-shore activities and buyers of Statoil’s products.

2.1.23 Risk related to state ownership The interests of Statoil’s majority shareholder, the Norwegian State, may not always be aligned with the interests of Statoil’s other shareholders, and this may affect Statoil’s decisions relating to the NCS.

The Norwegian Parliament, known as the "Storting", and the Norwegian State have resolved that the Norwegian State's shares in Statoil and the SDFI's interest in NCS licences must be managed in accordance with a coordinated ownership strategy for the Norwegian State's oil and gas interests. Under this strategy, the Norwegian State has required Statoil to continue to market the Norwegian State's oil and gas together with Statoil's own oil and gas as a single economic unit.

Pursuant to this coordinated ownership strategy, the Norwegian State requires Statoil, in its activities on the NCS, to take account of the Norwegian State's interests in all decisions that may affect the development and marketing of Statoil's own and the Norwegian State's oil and gas.

The Norwegian State directly held 67% of Statoil's ordinary shares as of the date of this Prospectus. Based on the Norwegian Public Limited Companies Act, the Norwegian State effectively has the power to influence the outcome of any vote of shareholders due to the percentage of Statoil's shares it owns, including amending its articles of association and electing all non-employee members of the corporate assembly of the Company (the "Corporate Assembly"). The employees are entitled to be represented by up to one-third of the members of the Board of Directors and one-third of the Corporate Assembly.

The Corporate Assembly is responsible for electing the Board of Directors. It also makes recommendations to the general meeting concerning the Board of Directors' proposals relating to the Company's annual accounts, balance sheet, allocation of profit and coverage of loss. The interests of the Norwegian State in deciding these and other matters and the factors it considers when casting its votes, especially under the coordinated ownership strategy for the SDFI and Statoil's shares held by the Norwegian State, could be different from the interests of Statoil's other shareholders.

If the Norwegian State's coordinated ownership strategy is not implemented and pursued in the future, then Statoil's mandate to continue to sell the Norwegian State's oil and gas together with its own oil and gas as a single economic unit is likely to be prejudiced. Loss of the mandate to sell the SDFI's oil and gas could have an adverse effect on Statoil's position in the markets in which it operates.

2.2 Financial risks 2.2.1 General Statoil’s financial results depend on a number of factors, most significantly those that affect the price it receives for its products and its oil and gas production. These risk factors are covered in Section 2.1 "Risks relating to Statoil and the industry in which Statoil operates".

The financial risks described in this Section includes currency risk, liquidity risk, foreign exchange rate risk and credit risk, all of which are components that directly could negatively influence Statoil’s cash flow and results, although with less magnitude than some of the risks discussed earlier. Statoil has implemented procedures to efficiently manage the Statoil's financial risk exposure.

2.2.2 Liquidity risk Statoil’s business faces liquidity risks, meaning Statoil could come into a situation where it does not have sufficient liquidity to cover its financial obligations. In order to ensure that Statoil has financial resources to meet its short-term requirements, Statoil maintains an appropriate liquidity reserve. The liquidity reserve is held as a combination of cash and cash equivalents, current financial investments, as well as committed, unused credit facilities. As per 30 June 2016, Statoil had USD 16.0 billion of cash and cash equivalents and current financial investments.

Short-term funding needs will normally be covered by borrowing, utilizing a USD 5.0 billion US commercial paper program which is backed by a revolving credit facility ("RCF") of USD 5.0 billion, maturing in 2021.5

2.2.3 Currency risk Statoil's business faces foreign exchange risks and this is managed with USD as the base currency. Statoil has a large percentage of its revenues and cash receipts denominated in USD, while sales of gas and refined products are to a large extent also denominated in EUR and GBP. Further, Statoil pays a large portion of its income taxes, and a substantial share of Statoil's operating expenses and capital expenditures, in NOK. The majority of Statoil's long-term debt has USD exposure.

Movements in FX rates could negatively influence Statoil’s cash flow and results. Foreign exchange risk is managed at corporate level in accordance with established policies and mandates.

An investor holding Statoil shares is thus mainly exposed towards USD. Any movement in currency rates versus USD could lead to fluctuations in Statoil’s results and this could impact the share price. For example, a strengthened NOK versus USD will mean higher NOK denominated operational expenditure and capital expenditure and vice versa. A weakened EUR versus USD will mean lower income from EUR denominated sales and vice versa. For investors on the Oslo Stock Exchange, a strengthened NOK versus USD will mean lower NOK dividend payments and vice versa.

2.2.4 Interest rate risk Bonds are normally issued at fixed rates in a variety of currencies (i.a. USD, EUR and GBP). Statoil manages its interests rates exposure related to its long-term debt based on risk and reward considerations from an enterprise risk management perspective. This means that the interest rate exposure may vary from time to time. Currently a significant part of the long-term debt is converted to floating USD exposure by using interest rate swaps and cross-currency swaps. Mark-to-market effects on these derivatives could have a significant impact on Statoil’s financial results. Floating rate exposure on the long-term debt means that movements in interest rates could negatively influence Statoil’s cash flow and results.

2.2.5 Credit risk Credit risk is the risk that Statoil's customers or counterparties will cause Statoil financial loss by failing to honour their obligations. Credit risk arises from credit exposures with customer accounts receivables as well as from financial investments, derivative financial instruments and deposits with financial institutions. If a counterparty fails to honour its obligation, such a loss could impact Statoil cash flow and results.

Prior to entering into transactions with new counterparties, Statoil's credit policy requires all counterparties to be formally identified and approved. In addition, all sales, trading and financial counterparties are assigned internal credit ratings as well as exposure limits.

5 In June 2016, Statoil exercised its first of two one-year RCF extension options. Further, in July 2016, Statoil upsized its US commercial paper program, so that the program size is aligned with the RCF.

Statoil uses risk mitigation tools to reduce or control credit risk both on a counterparty and portfolio level. The main tools include bank and parental guarantees, prepayments and cash collateral.

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

2.3 Risks related to the Shares and the Dividend Issue 2.3.1 Risk related to volatility of share price The price of the Company’s shares may experience volatility. The trading price of the Shares could fluctuate significantly in response to a number of factors beyond the Company’s control, including quarterly variations in operating results, adverse business developments, changes in financial estimates and investment recommendations or ratings by securities analysts, significant contracts, publicity about Statoil, its products and services or its competitors, lawsuits, unforeseen liabilities, changes to the regulatory environment in which it operates or general market conditions.

Moreover, in recent years, the stock market in general has experienced large price and volume fluctuations. These broad market fluctuations may adversely affect the Company’s share price, regardless of its operating results.

2.3.2 Limitation of ability to make claims against the Company The Company is a public limited liability company incorporated under the laws of Norway. The rights of holders of Shares are governed by Norwegian law and by the articles of association. These rights might differ from the rights of shareholders in other jurisdictions. In particular, Norwegian law limits the circumstances under which shareholders of Norwegian companies may bring derivative actions. Under Norwegian law, any action brought by the Company in respect of wrongful acts committed against the Company takes precedent over actions brought by shareholders in respect of such acts. In addition, it may be difficult to prevail in a claim against the Company under, or to enforce liabilities predicated upon, securities laws in other jurisdictions.

2.3.3 Risks related to enforceability of civil liabilities The Company is organised under the laws of Norway. It may be difficult for investors in other jurisdictions to effect service of process within other jurisdictions upon the Company or the Company’s directors and executive officers and to enforce against the Company or its directors and executive officers judgments obtained in non- Norwegian courts.

2.3.4 Investors may not be able to exercise their voting rights for Shares registered in a nominee account. Beneficial owners of the Shares that are registered in a nominee account (such as through brokers, dealers or other third parties) may not be able to vote for such Shares unless their ownership is re-registered in their names with the VPS prior to the Company’s general meetings. The Company cannot guarantee that beneficial owners of the Shares will receive the notice of a general meeting of shareholders of the Company in time to instruct their nominees to either effect a re-registration of their Shares or otherwise vote for their Shares in the manner desired by such beneficial owners.

2.3.5 The transfer of Shares is subject to restrictions under the securities laws of the United States and other jurisdictions. The Shares have not been registered under the U.S. Securities Act or any US state securities laws or any other jurisdiction outside of Norway and are not expected to be registered in the future. As such, the Shares, including the Dividend Shares, may not be offered or sold except pursuant to an exemption from the registration requirements of the U.S. Securities Act and applicable securities laws. See Section 16 "Selling and transfer restrictions".

2.3.6 Existing Shareholders who do not elect to receive Dividend Issue may experience dilution in their shareholding To the extent that an Existing Shareholder does not elect to participate in the Dividend Issue prior to the expiry of the Subscription Period, whether by choice or due to a failure to comply with procedures set forth in Section 5.7 "Subscription procedures", or to the extent that an Existing Shareholder is not permitted to subscribe for Dividend Shares as further described in Section 16 "Selling and transfer restrictions", such shareholder’s proportionate ownership and voting interests in Statoil after the completion of the Dividend Issue will be diluted.

3 RESPONSIBILITY FOR THE PROSPECTUS This Prospectus has been prepared in connection with the Dividend Issue described herein and the listing of the Dividend Shares on the Oslo Stock Exchange.

The Board of Directors of the Company hereby declare that, having taken all reasonable care to ensure that such is the case, the information contained in this Prospectus is, to the best of our knowledge in accordance with the facts and contains no omissions likely to affect its import.

Stavanger, 27 August 2016

The Board of Directors of Statoil ASA

______Øystein Løseth Roy Alexander Franklin Chairman Deputy chair

______Jakob Stausholm Bjørn Tore Godal Member Member

______Maria Johanna Oudeman Rebekka Glasser Herlofsen Member Member

______Wenche Marie Agerup Jeroen van der Veer Member Member

______Lill-Heidi Bakkerud Ingrid Elisabeth Di Valerio Member Member

______Stig Lægreid Member

4 GENERAL INFORMATION 4.1 Other important investor information The information contained herein is current as of the date hereof and subject to change, completion and amendment without notice. In accordance with section 7-15 of the Norwegian Securities Trading Act, significant new factors, material mistakes or inaccuracies relating to the information included in this Prospectus, which are capable of affecting the assessment by investors of the Dividend Shares between the time of approval of this Prospectus by the Norwegian FSA and the listing of the Dividend Shares on the Oslo Stock Exchange, will be included in a supplement to this Prospectus. Neither the publication nor distribution of this Prospectus, nor the sale of any Dividend Share, shall under any circumstances imply that there has been no change in Statoil’s affairs or that the information herein is correct as of any date subsequent to the date of this Prospectus.

No person is authorised to give information or to make any representation concerning the Company or in connection with the Dividend Issue or the sale of the Dividend Shares other than as contained in this Prospectus. If any such information is given or made, it must not be relied upon as having been authorised by the Company or the Receiving Agent or by any of the affiliates, representatives, advisors or selling agents of any of the foregoing.

The Company has furnished the information in this Prospectus. No representation or warranty, express or implied is made by the Receiving Agent as to the accuracy, completeness or verification of the information set forth herein, and nothing contained in this Prospectus is, or shall be relied upon as, a promise or representation in this respect, whether as to the past or the future. The Receiving Agent assume no responsibility for the accuracy or completeness or the verification of this Prospectus and accordingly disclaim, to the fullest extent permitted by applicable law, any and all liability whether arising in tort, contract or otherwise which they might otherwise be found to have in respect of this Prospectus or any such statement.

None of the Company or the Receiving Agent or any of their respective affiliates, representatives, advisers or selling agents, is making any representation to any offeree or purchaser of the Dividend Shares regarding the legality of an investment in the Dividend Shares. Each investor should consult with his or her own advisors as to the legal, tax, business, financial and related aspects of a purchase of the Dividend Shares.

Investing in the Dividend Shares involve a high degree of risk, see Section 2 "Risk factors" beginning on page 8.

4.2 Financial information Statoil’s financial statements for the years ended 31 December 2015, 2014 and 2013 (the "Financial Statements") have been incorporated by reference in to this Prospectus, see Section 17 "Incorporation by reference and documents on display".

The Financial Statements have been audited by KPMG AS, as set forth in their reports thereon, also included by reference to this Prospectus. The auditor reports for the years ended 31 December 2015, 2014 and 2013 are all unqualified.

The financial information included in Section 10.1 "Capitalisation and indebtedness" has been derived from Statoil’s unaudited second quarter 2016 report published on 27 July 2016 (the "Interim Financial Statements"). The Interim Financial Statements has been incorporated by reference into this Prospectus, see Section 17 "Incorporation by reference and documents on display".

4.3 Industry and market data This Prospectus contains statistics, data, statements and other information relating to markets, market sizes, market shares, market positions and other industry data pertaining to Statoil’s business and the industries and markets in which it operates. Unless otherwise indicated, such information reflects Statoil’s estimates based on analysis of multiple sources, including data compiled by professional organisations, consultants and analysts and information otherwise obtained from other third party sources, such as annual and interim financial statements and other presentations published by listed companies operating within the same industry as Statoil, as well as Statoil’s internal data and its own experience, or on a combination of the foregoing.

Although Statoil believes its estimates to be reasonable, these estimates have not been verified by any independent sources (with the exception of mineral data, see Section 4.5 "Mineral reporting standards" below), and Statoil cannot assure prospective investors as to their accuracy or that a third party using different methods to assemble, analyse or compute market data would obtain the same results. In addition, behaviour, preferences and trends in the marketplace tend to change. Statoil does not intend, and does not assume any obligations to update industry or market data set forth in this Prospectus.

Industry publications or reports generally state that the information they contain has been obtained from sources believed to be reliable, but the accuracy and completeness of such information is not guaranteed. Statoil has not independently verified and cannot give any assurances as to the accuracy of market data contained in this Prospectus that was extracted from these industry publications or reports and reproduced herein. Market data and statistics are inherently predictive and subject to uncertainty and not necessarily reflective of actual market conditions. Such statistics are based on market research, which itself is based on sampling and subjective judgments by both the researchers and the respondents, including judgments about what types of products and transactions should be included in the relevant market.

As a result, prospective investors should be aware that statistics, data, statements and other information relating to markets, market sizes, market shares, market positions and other industry data in this Prospectus and projections, assumptions and estimates based on such information may not be reliable indicators of Statoil’s future performance and the future performance of the industry in which it operates. Such indicators are necessarily subject to a high degree of uncertainty and risk due to the limitations described above and to a variety of other factors, including those described in Section 2 "Risk factors" and elsewhere in this Prospectus.

4.4 Confirmation regarding sources The Company confirms that when information in this Prospectus has been sourced from a third party it has been accurately reproduced and as far as the Company is aware and is able to ascertain from the information published by that third party, no facts have been omitted which would render the reproduced information inaccurate or misleading.

4.5 Mineral reporting standards As all operators on the NCS, Statoil is obliged to apply the Norwegian classification system as published by the Norwegian Petroleum Directorate in communication with Norwegian authorities.

In addition Statoil is required to report reserves in accordance with the SEC regulations in Statoil's financial disclosures. These requirements for oil and gas reporting are part of the US Securities Act and the Energy Policy and Conservation Act of 1975. In 2010, the SEC revised their oil and gas reporting requirements in order to align them with current practices and changes in technology in the oil and gas industry.

The SEC requires oil and gas companies to report reserves in accordance with regulation S-X Part 210, §210.4- 10 Financial accounting and reporting for oil and gas producing activities pursuant to the Federal securities laws and the Energy Policy and Conservation Act of 1975 and regulation S-K Part 229, Subpart 229.1200- Disclosure by Registrants Engaged in Oil and Gas Producing Activities. These are requirements that have to be followed by all oil and gas companies filing an annual report to the SEC.

The definitions of proved reserves according to SEC are as follows: Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

• The area of the reservoir considered as proved includes:

ο The area identified by drilling and limited by fluid contacts, if any, and

ο Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

• In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons ("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

• Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

• Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

ο Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

ο The project has been approved for development by all necessary parties and entities, including governmental entities.

• Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

• Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

• Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

• Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

• Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

• Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

The SEC definitions of reserves and resources are similar, and sometimes identical, to the Petroleum Resource Management System ("PRMS") reporting standard published by the Society of Petroleum Engineering ("SPE") in its terminology. However, the definitions and requirements behind the different terms are stricter under the SEC regime, and the reserves categories are described in text only. All reporting companies are required to disclose proved reserves (highest degree of certainty) for all their proved properties, including changes to the reserves from year to year. In addition, the registrant must disclose a net present value calculation related to the proved reserves (Standardised measure of discounted future net cash flow). Disclosure of probable and possible reserves is allowed since 2010, but not required.

Statoil does, in line with its peers, only disclose proved reserves in its Annual report on Form 20-F. The reserves disclosure includes estimates for three consecutive years, including change categories from year to year as defined by the SEC. The numbers disclosed are estimated by Statoil’s own experts. However, an independent external evaluation is also performed each year (currently by the firm DeGolyer and MacNaughton) and an audit report summarising their evaluation and results is filed as an exhibit to the Annual report on Form 20-F. DeGolyer and MacNaughton business address is 5001 Spring Valley Road, Suite 800 East, Dallas, Texas 75244. DeGolyer and MacNaughton is one of the leading independent consulting firms focused on the petroleum industry and with particular expertise within resources assessments, reserves consulting, reservoir modeling, geologic and petrophysical analyses and financial forecasting for petroleum discoveries. DeGolyer and MacNaughton does not have any interest in the issuer. DeGolyer and MacNaughton has consented to the Statoil’s use and presentation of their reports and findings, including publication of whole reports or excerpts thereof.

In Section 9 "The business of Statoil and mineral reserves", the operations of each reporting segment are presented. Underlying activities or business clusters are presented according to how the reporting segment organises its operations. The Exploration business area's activities, which include group discoveries and the appraisal of new exploration resources, are presented as part of the various development and production reporting segments (Development and Production Norway, and Development and Production International).

As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based on geographical areas. The geographical areas are defined by the SEC as individual country, groups of countries within a continent, and a continent. Reserves must be disclosed separately for any country containing 15% or more of the registrant’s proved reserves. No other country than Norway contains proved reserves approaching 15% of total proved reserves. In compliance with this, Statoil reports proved reserves in Norway, Eurasia excluding Norway, Africa, and the Americas, and these sub- divisions can also be found in this Prospectus. Each of the Americas, Africa and Eurasia comprise of a number of jurisdictions in which Statoil has production in a various degree. References to specific projects outside Norway are made based on an assessment of their materiality and importance for Statoil based on value, production and operatorship.

While these units of accounting are used for reserve reporting, the reporting segments stated in Section 9.1.3 "Reporting segments" are used for accounting purposes.

4.6 Equivalent measures Equivalent measures are based upon:

1 barrel equals 0.134 tonnes of oil (33 degrees API) 1 barrel equals 42 US gallons 1 barrel equals 0.159 standard cubic metres 1 barrel of oil equivalent equals 1 barrel of crude oil 1 barrel of oil equivalent equals 159 standard cubic metres of natural gas 1 barrel of oil equivalent equals 5,612 cubic feet of natural gas 1 barrel of oil equivalent equals 0.0837 tonnes of NGLs 1 billion standard cubic metres of natural gas equals 1 million standard cubic metres of oil equivalent 1 cubic metre equals 35.3 cubic feet 1 kilometre equals 0.62 miles 1 square kilometre equals 0.39 square miles

1 square kilometre equals 247.105 acres 1 cubic metre of natural gas equals 1 standard cubic metre of natural gas 1,000 standard cubic meter gas equals 1 standard cubic meter oil equivalent 1,000 standard cubic metres of natural gas equals 6.29 boe 1 standard cubic foot equals 0.0283 standard cubic metres 1 standard cubic foot equals 1000 British thermal units (btu) 1 tonne of NGLs equals 1.9 standard cubic metres of oil equivalent 1 degree Celsius equals minus 32 plus five-ninths of the number of degrees Fahrenheit

4.7 USD/NOK exchange rates Amounts reported in NOK are converted to USD with a conversion rate as per 19 August 2016 (1 USD= 8.2154 NOK).

4.8 Cautionary note regarding forward-looking statements Statements contained in this Prospectus, particularly those regarding Statoil’s possible or assumed future performance, results of operations and cash flows, reserves and growth, and other trends and projections are "forward-looking statements" that involve risks and uncertainties. In some cases, words such as "ambition", "continue", "could", "estimate", "expect", "focus", "likely", "may", "outlook", "plan", "strategy", "will", "guidance" and similar expressions are used to identify forward-looking statements. All statements other than statements of historical fact, including, among others, statements regarding future financial position, results of operations and cash flows; future financial ratios and information; future financial or operational portfolio or performance; future market position and conditions; business strategy; growth strategy; sales, trading and market strategies; research and development initiatives and strategy; projections and future impact related to efficiency programmes, market outlook and future economic projections and assumptions; competitive position; projected regularity and performance levels; expectations related to its recent transactions and projects, completion and results of acquisitions, disposals and other material contractual arrangements; reserve information; future levels, timing or development of capacity, reserves or resources; future decline of mature fields; planned maintenance (and the effects thereof); oil and gas production forecasts and reporting; domestic and international growth, expectations and development of production, projects, pipelines or resources; estimates related to production and development levels and dates; operational expectations, estimates, schedules and costs; exploration and development activities, plans and expectations; projections and expectations for upstream and downstream activities; oil, gas, alternative fuel and energy prices; oil, gas, alternative fuel and energy supply and demand; natural gas contract prices; timing of gas off-take; technological innovation, implementation, position and expectations; projected operational costs or savings; projected unit of production cost; its ability to create or improve value; future sources of financing; exploration and project development expenditure; effectiveness of its internal policies and plans; its ability to manage its risk exposure; its liquidity levels and management; estimated or future liabilities, obligations or expenses and how such liabilities, obligations and expenses are structured; expected impact of currency and interest rate fluctuations; expectations related to contractual or financial counterparties; capital expenditure estimates and expectations; projected outcome, objectives of management for future operations; impact of PSA effects; projected impact or timing of administrative or governmental rules, decisions, standards or laws (including taxation laws); estimated costs of removal and abandonment; estimated lease payments, gas transport commitments and future impact of legal proceedings are forward-looking statements.

These forward-looking statements appear in a number of places throughout this Prospectus, including, without limitation, in Section 8 "Industry and market overview" and Section 9 "The business of Statoil and mineral reserves", and included statements regarding Statoil's intentions, beliefs or current expectations concerning, among other things, goals, objectives, financial condition and results of operations, liquidity, outlook and prospects, growth, strategies, impact of regulatory initiatives, capital resources and capital expenditure and dividend targets, and the industry trends and developments in the markets in which Statoil operates.

These forward-looking statements reflect current views of Statoil 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. You should not place undue reliance on these forward-looking statements. Statoil's actual results could differ materially from those anticipated in the forward-looking statements for many reasons. There are a number of factors that could cause actual results and developments to differ materially

from those expressed or implied by these forward-looking statements, including, without limitation, levels of industry product supply, demand and pricing of oil and or natural gas; inability to exploit growth or investment opportunities; material differences from reserves estimates; unsuccessful drilling; inability to discover and develop additional reserves; delays and disruptions in operations; ineffectiveness of crisis management systems; health, safety and environmental risks, price and availability of alternative fuels; competition from other oil and gas companies; operational delays or disruptions; geological or technical difficulties the development and use of new technology; the actions of field partners; limited transportation infrastructure when a field is in a remote location; security threats on its information system and digital infrastructure; currency exchange rate and interest rate fluctuations; the political and economic policies of Norway and other oil-producing countries; EU legislation; general economic conditions; political and social stability and economic growth in relevant areas of the world; global political events and actions, including war, terrorism and sanctions; security breaches; changes or uncertainty in or non-compliance with laws and governmental regulations; adverse changes in tax regimes; inadequate insurance coverage; the actions of governments (including the Norwegian state as majority shareholder); counterparty defaults; natural disasters and adverse weather conditions, climate change, and other changes to business conditions; ability to secure the right level of workforce competence and capacity; relevant governmental approvals and other factors discussed elsewhere in this Prospectus.

Actual results could differ materially from those expressed or implied in forward-looking statements. Statoil does not undertake an obligation to update or revise publicly any forward-looking statements. Additional factors which could cause actual results and developments to differ from those expressed or implied by the forward-looking statements are included in Section 2 "Risk factors" of this Prospectus. These factors may not be exhaustive and should be read in conjunction with the other cautionary statements included in this Prospectus. Investors should evaluate all forward-looking statements made in this Prospectus in the context of these risks and uncertainties.

5 TERMS OF THE DIVIDEND ISSUE 5.1 The Dividend Issue On 11 May 2016, the general meeting of the Company approved a two-year scrip dividend programme commencing from the fourth quarter 2015 (the Scrip Dividend Programme) and authorised the board of directors of the Company to (i) distribute dividend based on the approved annual accounts for 2015 and (ii) to increase the share capital in connection with payment of dividend for first quarter to third quarter 2016. In accordance with the authorisations granted by the general meeting, the Board of Directors resolved on 26 April 2016 to distribute a Dividend of USD 0.2201 per Share to the holders of the Company's Shares as of expiry of 9 August 2016, as registered with the Company’s shareholder register with the VPS as of expiry of 11 August 2016 (the Record Date) (the Existing Shareholders). Existing Shareholders whose shares trade on the Oslo Stock Exchange will receive their Dividend in NOK. The NOK dividend was communicated four business days after the Record Date and amounts to NOK 1.8255 per Share. Furthermore, the Board of Directors resolved to continue the Scrip Dividend Programme for the first quarter 2016, and resolved on 26 July 2016 to increase the share capital of the company in order to offer the Dividend Shares with a discount rate of 5%. The Dividend with a deduction for any withholding tax (Net Dividend) is accordingly subject to optional settlement in Dividend Shares by participation in the Dividend Issue as a part of the Scrip Dividend Programme.

Subject to applicable securities laws, Existing Shareholders will be entitled to elect to use the Net Dividends that the relevant Existing Shareholder is entitled to in order to subscribe for Dividend Shares in the Company in whole or in part. Existing Shareholders will be allocated the number of Dividend Shares equal to the amount each Existing Shareholder has subscribed for during the Subscription Period, divided by the Subscription Price. All subscriptions will be rounded down to the nearest whole number of shares. Any part of the Net Dividend not used for subscription of Dividend Shares, will be paid in cash. Existing Shareholders who choose to receive all of their Net Dividends in Dividend Shares, but whose Net Dividend does not exceed the Subscription Price for one share will receive their Dividend paid in cash. Over-subscription and subscription of Dividend Shares by other than by Existing Shareholders will not be permitted. For the purposes of determining eligibility for participation in the Dividend Issue, the Company will look solely to its register of shareholders as of the expiry of the Record Date.

The contribution for the Dividend Shares will be settled by way of set-off against the claim of the Net Dividend the Existing Shareholder is entitled to.

The Existing Shareholders who have not subscribed for Dividend Shares at the time of expiry of the Subscription Period will be paid the total Dividend amount the relevant Existing Shareholder is entitled to in cash without any action on its part.

The Dividend Issue comprises of up to 160,000,000 Dividend Shares, each with a nominal value of NOK 2.50. The Subscription Price for the Dividend Shares, which will be settled by way of set-off against the Net Dividend entitlement, will be in the range of NOK 50 to NOK 500 per Dividend Share. The Subscription Price is expected to be announced on or about 12 September 2016 and shall be equal to the volume-weighted average share price on Oslo Stock Exchange of the last two trading days of the subscription period, i.e. 8 and 9 September 2016, less a 5% discount, as further set out in Section 5.3 "Subscription Price". The subscription price for the ADR holders will be equal to the Subscription Price converted into USD using the Central Bank of Norway's USD exchange rate over the last two trading days of the Subscription Period, i.e. 8 and 9 September 2016.

The table below sets out certain indicative key dates for the Dividend Issue, subject to change:

Date Last day of trading in the Shares inclusive of right to participate in the Dividend Issue (cut-off date) 9 August 2016 First day of trading in the Shares excluding right to participate in the Dividend Issue (ex. date) 10 August 2016 Record Date for determining the Existing Shareholders 11 August 2016 Subscription Period commences 29 August 2016 Subscription Period ends 9 September 2016 Registration of the capital increase and issuance of the Dividend Shares 22 September 2016 Delivery of the Dividend Shares 23 September 2016 Cash payment of dividend to Oslo Stock Exchange shareholders 23 September2016

29 Date Cash payment of dividend to ADR holders 26 September 2016 Listing and commencement of trading of the Dividend Shares on the Oslo Stock Exchange 26 September 2016 First day of trading in the issued ADRs on the New York Stock Exchange 26 September 2016

5.2 Resolutions to undertake and implement the Dividend Issue On 11 May 2016, the annual general meeting of the Company passed the following resolution to authorise the board of directors to increase the share capital of the Company:

"The general meeting of Statoil ASA hereby authorises the board of directors to increase the share capital in the company in accordance with section 10-14 of the Norwegian Public Limited Companies Act, on the following conditions:

1. The share capital may, in one or more rounds, be increased by a total of up to NOK 1,200,000,000.

2. The authorisation may only be utilized to increase the share capital in connection with the implementation of Statoil ASA's scrip dividend programme for first quarter to third quarter 2016.

3. The authorisation encompasses increase of share capital by way of set-off in accordance with section 10-2 of the Norwegian Public Limited Companies Act. The subscription price may be in both NOK and USD.

4. The authorisation shall be valid until the next annual general meeting, but not beyond 30 June 2017."

In accordance with the authorisation granted by the general meeting, the Board of Directors passed the following resolution on 26 July 2016:

1. The share capital is increased with an amount of minimum NOK 2.50 and maximum NOK 400,000,000. The new shares shall have a nominal value of NOK 2.50.

2. Subscription price:

a. For shareholders on Oslo Stock Exchange (Oslo Børs) the subscription price is equal to the volume-weighted average share price on Oslo Stock Exchange of the last two trading days of the subscription period for the dividend issue, with a deduction for a discount of 5%. The subscription price may not be lower than NOK 50 or higher than NOK 500 per share.

b. For ADR-holders under the ADR program in the US, the subscription price is equal to the subscription price for the shareholders on Oslo Stock Exchange converted into USD based on an average of the Central Bank of Norway’s USD exchange rate over the last two trading days of the subscription period. The subscription price may not be lower than USD 5 or higher than USD 50 per share.

3. Only shareholders of Statoil as of the expiry of 9 August 2016, as registered in Statoil’s shareholder register with the Norwegian Central Securities Depository (VPS) as of expiry of 11 August 2016, are entitled to subscribe for shares.

4. The new shares may not be subscribed for by shareholders in jurisdictions in which an offer to subscribe would be unlawful for the relevant shareholder.

5. Subscription of the new shares shall be carried out in accordance with the following:

a. Each of these shareholders can choose to receive their dividend wholly or partially in cash or newly issued shares and therefore are entitled to use in whole or in part the net dividends that the relevant shareholder is entitled to for the first quarter of 2016, to subscribe for shares in the company. The contribution will be settled by way of set-off against the subscribers’ entitlement to net dividend from the company. Dividend in USD which shall be used as contribution shall be converted into NOK by using the same exchange rate between USD and NOK as set out under

item 2 b) above. All subscriptions will be rounded down to the nearest whole number of shares. Any part of the net dividend not used to settle the subscribed shares, shall be paid in cash.

b. The Norwegian State has undertaken to participate in the dividend offer by using the part of its quarterly dividend to subscribe for the number of shares that is required to maintain its ownership interest of 67% in Statoil.

6. Each shareholder will be allocated the number of shares equal to the amount each shareholder has subscribed for during the subscription period, cf. item 5 above, divided by the subscription price, cf. item 2 above. No fractional shares will be allocated.

7. The subscription period shall commence at the latest on or about 29 August 2016. The subscription period shall be at least 10 business days. Subscription of shares shall take place electronically or on a designated subscription form within the expiry of the subscription period.

8. ADR-holders under the ADR program in the US may make their election through Deutsche Bank as the depositary and receiving agent for the ADR program.

9. The new shares give shareholders rights in the company, including the right to dividends, from the registration of the share capital increase in the Norwegian Register of Business Enterprises. At the same time, section 3 of the Articles of Association shall be amended to reflect the new share capital.

10. The estimated costs for the share capital increase are NOK 5 million.

5.3 Subscription Price The Subscription Price in the Dividend Issue will be between NOK 50 and NOK 500 per Dividend Share.

The Subscription Price shall be equal to the volume-weighted average share price on Oslo Stock Exchange of the last two trading days of the Subscription Period, i.e. 8 and 9 September 2016 unless the Subscription Period is extended, less a 5% discount. The volume-weighted average share price for the two days will be calculated by summarizing the volume-weighted average share price for each day (calculated separately) and then divided by two. The subscription price for the ADR holders will be equal to the Subscription Price converted into USD using the average of the Central Bank of Norway's USD exchange rate on the last two trading day of the Subscription Period, i.e. 8 and 9 September 2016 unless the Subscription Period is extended. The Subscription Price is expected to be announced on or about 12 September 2016 in the form of a stock exchange notification from the Company through the Oslo Stock Exchange information system and at the Company’s website (www.statoil.com).

The Subscription Period may be extended, which will affect the calculation of the Subscription Price. Any extension of the Subscription Period will be announced at the earliest convenience in the form of a stock exchange notification from the Company through the Oslo Stock Exchange information system and at the Company’s website (www.statoil.com).

5.4 Subscription Period The Subscription Period will commence on 29 August 2016 at 09:00 hours (CEST) and end on 9 September 2016 at 23:59 hours (CEST). The Subscription Period may at Statoil's sole discretion and for any reason be extended beyond the set time, but will in no event be extended beyond 30 September 2016. Any extension of the Subscription Period will be announced at the earliest convenience in the form of a stock exchange notification from the Company through the Oslo Stock Exchange information system and at the Company’s website (www.statoil.com).

5.5 Record Date for Existing Shareholders Shareholders who are registered in the Company’s shareholder register in the VPS as of the expiry of 11 August 2016 (the Record Date) will, subject to applicable securities laws (see Section 16 "Selling and transfer restrictions), be entitled to participate in the Dividend Issue. Provided that the delivery of traded Shares was made with ordinary T+2 settlement in the VPS, Shares that were acquired on or before the cut-off date 9 August 2016 will give the right to participate in the Dividend Issue, whereas Shares that were acquired

31 from and including 10 August 2016 will not give the right to participate in the Dividend Issue. However, for the purposes of determining eligibility to participate in the Dividend Issue, the Company will look solely to its register of shareholders in the VPS as of expiry of the Record Date.

5.6 Entitlement to subscription of Dividend Shares Existing Shareholders can choose to receive their Net Dividend wholly or partially in cash or Dividend Shares. Therefore they are entitled to use their Net Dividend, in whole or in part, at the Existing Shareholders' sole discretion, to subscribe for Dividend Shares in the Company. Existing Shareholders will be allocated the number of Dividend Shares equal to the amount each Existing Shareholder has subscribed for during the Subscription Period, divided by the Subscription Price. All subscriptions will be rounded down to the nearest whole number of shares. Over-subscription and subscription of Dividend Shares by other than Existing Shareholders will not be permitted.

Existing Shareholders who want to participate in the Dividend Issue must do so in accordance with procedures for subscription as set out in this Prospectus before the expiry of the Subscription Period on 9 September 2016 at 23:59 hours (CEST), or if the Subscription Period is extended, before 23:59 hours (CEST) on the last day of the extended subscription period.

Existing Shareholders who have not subscribed for Dividend Shares at the time of expiry of the Subscription Period will be paid the total Dividend amount the relevant Existing Shareholder is entitled to in cash without any action on its part, on or around 23 September 2016. The expected payment date for Dividends in USD to US ADR holders is on or about 26 September 2016. The Existing Shareholders who do not participate in the Dividend Issue will experience a dilution of its shareholding; see Section 6.2 "Dilution".

5.7 Subscription procedures 5.7.1 Subscription for holders of shares in the VPS Subscriptions for Dividend Shares can be made electronically via VPS’ online subscription system. A link to the VPS subscription system can be found on www.statoil.com/scrip. All Existing Shareholders who are considered eligible to subscribe for Dividend Shares have or will receive a letter from the Company with personal log in details to the VPS subscription system. Subscription for Dividend Shares may also be registered via VPS Investor Service, if you have an active account, or by completing and submitting a correctly completed subscription form as set out in Appendix B to DNB Bank ASA (the Receiving Agent), during the Subscription Period. All shareholders who have received personal log in details from the Company are encouraged to subscribe for Dividend Shares through the VPS online subscription system by following the link on the Company’s web site, www.statoil.com/scrip or through their personal VPS account.

Online subscriptions must be registered, or, in the case of subscriptions on subscription forms, correctly completed subscription forms received by the Receiving Agent set out below, no later than 23:59 hours (CEST) on 9 September 2016, or if the Subscription Period is extended, no later than 23:59 hours (CEST) on the last day of the extended subscription period.

DNB Bank ASA DNB Markets, Registrars Department P.O. Box 1600 Sentrum N-0021 Oslo

Tel.: +47 23 26 80 20

The Company may not be held responsible for postal delays, unavailable fax lines, internet lines or servers or other logistical or technical problems that may result in subscriptions not being received in time or at all by the relevant subscription office. Subscription forms received after the end of the Subscription Period and/or incomplete or incorrect subscription forms and any subscription that may be unlawful may be disregarded at the sole discretion of the Company without notice to the subscriber.

Subscriptions made by submitting the subscription form to the Receiving Agent are binding and irrevocable, and cannot be withdrawn, cancelled or modified by the subscriber after having been received by the relevant

subscription office. Subscriptions made electronically through the VPS online subscription system may be changed and modified by the subscriber throughout the Subscription Period. Subscriptions made through VPS will however be binding and irrevocable and cannot be withdrawn, cancelled or modified following the expiry of the Subscription Period.

The subscriber is responsible for the correctness of the information entered on the subscription form, or in the case of applications through the VPS online subscription system, the online subscription registration. By signing and submitting a subscription form, or by registration of a subscription with the VPS online subscription system, the subscribers confirm and warrant that they have read this Prospectus and are eligible to subscribe for Dividend Shares under the terms set forth herein.

Over-subscription and subscription of Dividend Shares other than by Existing Shareholders will not be permitted.

All subscriptions in the Dividend Issue will be treated in the same manner regardless of whether the subscription is made by delivery of a subscription form to the Receiving Agent or through the VPS online subscription system. If a subscriber makes a subscription both through the VPS online subscription system and by submitting the subscription form, the electronic subscription will prevail regardless of which subscription was made last.

5.7.2 Subscription for ADR-holders ADR-holders under the ADR program in the US may make their election through Deutsche Bank Trust Company Americas, an indirect wholly owned subsidiary of Deutsche Bank A.G., ("Deutsche Bank" or "ADR Depositary") as the depositary for the ADR program.

5.8 Financial intermediaries 5.8.1 General Persons or entities holding Shares in the Company through financial intermediaries (i.e., brokers, custodians and nominees) should read this Section. All questions concerning the timeliness, validity and form of instructions to a financial intermediary in relation to the subscription of Dividend Shares should be determined by the financial intermediary in accordance with its usual customer relations procedure or as it otherwise notifies each beneficial shareholder. The Company is not liable for any action or failure to act by a financial intermediary through which Shares are held.

If a shareholder holds Shares registered through a financial intermediary as of expiry of the Record Date, the financial intermediary will customarily give the shareholder details on the Net Dividend that it will be entitled to use to subscribe for Dividend Shares in the Dividend Issue. The relevant financial intermediary will customarily supply each shareholder with this information in accordance with its usual customer relations procedures. Shareholders holding their Shares through a financial intermediary should contact the financial intermediary if they have received no information with respect to the Dividend Issue.

Shareholders who hold their Shares through a financial intermediary and who are ineligible for participation in the Dividend Issue due to the selling restrictions set forth in Section 16 "Selling and transfer restrictions", will not be entitled to subscribe for or be allocated Dividend Shares in the Dividend Issue.

5.8.2 Subscription Period The time by which notification of instructions for subscription of Dividend Shares must validly be given to a financial intermediary may be earlier than the expiry of the Subscription Period. Such deadline will depend on the financial intermediary. Shareholders who hold their shares through a financial intermediary should contact their financial intermediary if they are in any doubt with respect to such deadlines.

5.8.3 Subscription Shareholders, who are eligible for participation in the Dividend Issue and who hold their Shares through a financial intermediary and wish to subscribe for Dividend Shares in the Dividend Issue, should instruct their financial intermediary to subscribe for Dividend Shares in accordance with the applicable instructions received

33 from such financial intermediary. The financial intermediary will be responsible for collecting exercise instructions from the shareholders and for informing the Company of their subscription instructions.

5.9 Allocation of Dividend Shares Allocation of the Dividend Shares will take place on or about 23 September 2016 and the number of Dividend Shares to each Existing Shareholders will be calculated by dividing the amount each Existing Shareholder has subscribed for during the Subscription Period, by the Subscription Price. No fractional Dividend Shares will be allocated. The difference between the total Subscription Price used for subscription of Dividend Shares and the claim for Dividend will be paid to the shareholders in cash. The Company reserves the right to round off or reject any subscription for Dividend Shares which a subscriber is not entitled to subscribe for.

The result of the Dividend Issue is expected to be published on or about 22 September 2016 in the form of a stock exchange notification from the Company through the Oslo Stock Exchange information system and at the Company’s website (www.statoil.com).

Notification of allocated Dividend Shares is expected to be distributed from VPS on or about 24 September 2016. At the same time, subscribers who have access to VPS Investor Services will be able to see how many Dividend Shares they have been allocated.

5.10 Settlement of the Dividend Shares With the registration of a subscription with the VPS online subscription system, or by signing and submitting a subscription form, the subscriber declares and agrees that the Subscription Price for the Dividend Shares shall be settled by way of set-off against the Net Dividend the Existing Shareholder is entitled to pursuant to the resolution of the Board of Directors 26 April 2016 approving the Dividend.

5.11 Existing Shareholders subject to withholding tax Dividends paid to Non-Norwegian Individual Shareholders (as defined in Section 14.2.1 "Taxation of Dividends") are as a main rule subject to Norwegian withholding tax at a rate of 25 per cent, see Section 14.2.1 "Taxation of Dividends". In accordance with the present administrative system in Norway, the Company will deduct the withholding tax at the applicable rate when dividends are paid directly to an eligible Non- Norwegian Shareholder, based on information registered with the VPS. Dividends paid to Non-Norwegian Shareholders in respect of nominee registered shares are not eligible for reduced treaty withholding tax rate at the time of payment unless the nominee, by agreeing to provide certain information regarding beneficial owner, has obtained approval for reduced treaty withholding tax rate from the Norwegian Central Office for Foreign Tax Affairs (Nw: Sentralskattekontoret for utenlandssaker). The withholding obligation lies with the company distributing the dividends and the Company assumes this obligation. See Section 14.2.1 "Taxation of dividends".

Where the dividend to an Existing Shareholder is subject to withholding tax, the withholding tax will accordingly be deducted in advance of calculating the amount the Existing Shareholder is entitled to subscribe for in the Dividend Issue.

5.12 Delivery; VPS registration; admission to trading The Company expects that the share capital increase pertaining to the Dividend Issue will be registered with the Norwegian Register of Business Enterprises on or about 22 September 2016 and that the Dividend Shares will be delivered to the VPS accounts of the subscribers to whom they are allocated on or about 23 September 2016. On or about the same date, the Dividend Shares that ADR-holders elected to receive will be delivered to DNB Bank ASA as custodian under the ADR program. The ADR Depositary will issue new ADRs to such ADR- holders through the Depositary Trust Company, including through the Direct Registration System, or otherwise in book-entry form on the books of the ADR Depositary. The final deadline for registration of the share capital increase pertaining to the Dividend Issue in the Norwegian Register of Business Enterprises, and hence for the subsequent delivery of the Dividend Shares, is, pursuant to the Norwegian Public Limited Liability Companies Act, three months from the expiry of the Subscription Period (i.e. 9 December 2016).

The Dividend Shares will be registered in the VPS under ISIN NO 0010096985. Trading in the Dividend Shares on the Oslo Stock Exchange is expected to commence under the trading symbol "STL" from on or about

34 26 September 2016. Trading in ADRs on the New York Stock Exchange is expected to commence under the trading symbol "STO" on or about 26 September 2016. The Dividend Shares may not be transferred before the registration of the Dividend Issue in the Norwegian Register of Business Enterprises and the registration of the Dividend Shares in the VPS have taken place.

The Company’s registrar with the VPS is DNB Bank ASA, Registrars Department.

5.13 Rights conferred by the Shares The Dividend Shares issued through the Dividend Issue will be ordinary Shares in the Company having a par value of NOK 2.50 each and will be registered with the VPS in book-entry form. The Dividend Shares will rank pari passu in all respects with the existing Shares of the Company and will carry full shareholder rights in the Company from the time of registration of the share capital increase pertaining to the Dividend Issue with the Norwegian Register of Business Enterprises; and be issued pursuant to the Norwegian Public Limited Liability Companies Act. The Dividend Shares will be eligible for any dividends which the Company may declare after said registration. All Shares, including the Dividend Shares, will be freely transferrable and have voting rights and other rights and obligations which are standard under the Norwegian Public Limited Liability Companies Act, and be governed by Norwegian law.

5.14 Selling and transfer restrictions Participation in the Dividend Issue is, and the Dividend Shares are, subject to the selling and transfer restrictions set forth in Section 16 "Selling and transfer restrictions".

5.15 Participation of the Norwegian State and members of the Management, the Corporate Assembly and the Board of Directors in the Dividend Issue Statoil and the Norwegian State represented by the Ministry of Petroleum and Energy ("MPE"), have entered into a two-year agreement with the Company whereby the MPE undertakes that the Norwegian State shall use the part of its quarterly dividend to subscribe for the number of shares that is required to maintain its ownership interest of 67% in Statoil. Any part of the Dividend not used as settlement for Dividend Shares by the Norwegian State shall be paid in cash.

The following members of the Board of Directors have made legal binding commitments to subscribe for shares for their entire Net Dividend amount in all of Statoil's upcoming dividend issues under the Scrip Dividend Programme, including the Dividend Issue: Wenche Agerup, Lill-Heidi Bakkerud, Stig Lægreid, Jakob Stausholm and Øystein Løseth. In addition, Ingrid Elisabeth Di Valerio has made legal binding commitment to subscribe for shares for her entire Net Dividend amount of the first year of the Scrip Dividend Programme, including the Dividend Issue.

The following members of the Management have made legal binding commitments to subscribe for shares for their entire Net Dividend amount in all of Statoil's upcoming dividend issues under the Scrip Dividend Programme, including the Dividend Issue: Lars Christian Bacher, Timothy Dodson, Hans Jakob Hegge, John Knight, Arne Sigve Nylund, Anders Opedal, Torgrim Reitan, Irene Rummelhoff, Eldar Sætre, Jens Økland and Margareth Øvrum.

Furthermore, the Company expects that most of the members of the Corporate Assembly owning Shares in the Company will participate for the respective portions in the Dividend Issue. Except for this, the Company is not aware of any other major Shareholders of the Company or members of the Management, supervisory or administrative bodies that intend to subscribe for Dividend Shares in the Dividend Issue, or whether any person intends to subscribe for more than 5 per cent of the Dividend Issue.

5.16 Interests of natural and legal persons in the Dividend Issue The Company is not aware of any material or conflicting interests of natural and legal persons involved in the Dividend Issue.

5.17 Governing law and jurisdiction The terms and conditions of the Dividend Issue as set out in this Prospectus shall be governed by and construed in accordance with Norwegian law. The courts of Norway, with Stavanger as legal venue, shall have

35 exclusive jurisdiction to settle any dispute which may arise out of or in connection with the Dividend Issue or this Prospectus.

36 6 USE OF THE PROCEEDS; REASONS FOR THE DIVIDEND ISSUE 6.1 Use of the proceeds The Dividend Issue will not accrue proceeds as such, but reduce the cash outflow related to the Company's distribution of Dividend. The reduced cash outflow, which in the following will be referred to as "proceeds", will be used for general corporate purposes. Assuming the Dividend Issue is subscribed in full, the gross proceeds of the Dividend Issue will be approximately USD 704 million. The Company estimates that the total expenses in connection with the share capital increase (the Dividend Issue), which will be borne by the Company, will be approximately USD 0.6 million. Hence, the net proceeds of the Dividend Issue, if fully subscribed, will be USD 703 million.

The Company considers the dividend policy an important commitment to its shareholders and the dividend policy remains firm. Anchored in the dividend policy, the Board of Directors proposed to introduce a two-year scrip dividend programme starting from the fourth quarter 2015 (the Scrip Dividend Programme), which was approved by the annual general meeting on 11 May 2016. The Scrip Dividend Programme is envisaged to cover all distributions of dividends until and including the third quarter 2017. If the conditions for the Scrip Dividend Programme change, e.g. if the market conditions change considerably or if it turns out that few shareholders choose to receive their dividend in shares instead of cash, the Board of Directors may, at their sole discretion, resolve to not offer dividend shares for a particular quarter or to cancel the Scrip Dividend Programme. The Scrip Dividend Programme is expected to strengthen the Company's financial robustness in a low price environment. This initiative comes in addition to other measures such as strict financial discipline and significant efficiency improvements. Further, the Scrip Dividend Programme is a tool to strengthen the Company's financial capacity to invest in profitable projects in a low, volatile and uncertain price environment.

6.2 Dilution The estimated percentage split of the Company's share capital following the Dividend Issue; split by pre- Dividend Issue share capital and the share capital to be issued in the Dividend Issue and assuming that the Dividend Issue is fully subscribed is shown below:

Pre-Dividend Issue share capital...... 98.6 per cent

Dividend Issue share capital...... 1.4 per cent

If fully subscribed, the Dividend Issue will not result in a dilution of Existing Shareholders. On the basis that the Dividend Issue is not fully subscribed, Existing Shareholders who do not participate in the Dividend Issue are expected to experience a dilution of up to approximately 1.4 per cent.

7 DIVIDEND AND DIVIDEND POLICY 7.1 Dividend policy It is the Company's ambition to grow the annual cash dividend, measured in USD per share, in line with long- term underlying earnings.

The Company announces dividends on a quarterly basis. The Board of Directors approves first, second and third quarter interim dividends based on an authorisation from the annual general meeting while the annual general meeting approves the fourth quarter (and total annual) dividend based on a proposal from the Board of Directors. When deciding the interim dividends and recommending the total annual dividend level, the Board of Directors will take into consideration expected cash flow, capital expenditure plans, financing requirements and appropriate financial flexibility. In addition to cash dividends, the Company might buy back shares as part of total distribution of capital to the shareholders.

The Board of Directors updated the dividend policy in 2015 to reflect USD as the declaration currency. The dividend amount in NOK per share will be communicated four business days after the record date for shareholders at Oslo Stock Exchange.

On 11 May 2016 the general meeting of the Company approved to introduce a two-year scrip dividend programme (the Scrip Dividend Programme) commencing from the fourth quarter of 2015. The Scrip Dividend Programme offers shareholders the option to receive all or part of the quarterly dividend in cash or in newly issued shares in Statoil. The general meeting authorised the Board of Directors to resolve quarterly dividend payments until the next ordinary annual general meeting.

The shareholders at the annual general meeting may vote to reduce, but may not increase, the fourth quarter dividend proposed by the Board of Directors. It is the Company’s intention to have the one-year authorisation that mandates the Board of Directors to approve quarterly dividends renewed annually at the annual general meeting. The Company announces dividend payments in connection with quarterly results. Payment of quarterly dividends is expected to take place approximately five months after the announcement of each quarterly dividend.

Although the Company currently intends to pay quarterly dividends on its ordinary shares, the Company cannot give an assurance that dividends will be paid, or predict the amount of any dividends. Future dividends will depend on a number of factors prevailing at the time the Board of Directors considers any dividend payment.

7.2 Dividend history In 2014, Statoil implemented quarterly dividend payments and from the second quarter 2015, Statoil implemented USD as dividend declaration currency.

The following table shows declared cash dividend amounts on a per share basis and in aggregate since 2011.

Ordinary dividend per share

Fiscal Total year Currency 1Q Currency 2Q Currency 3Q Currency 4Q Currency annual

2011 NOK 6.5000

2012 NOK 6.7500

2013 NOK 7.0000

2014 NOK 1.8000 NOK 1.8000 NOK 1.8000 NOK 1.8000 NOK 7.2000

2015 NOK 1.8000 NOK 1.8000

2015 USD 0.2201 USD 0.2201 USD 0.2201 USD 0.6603

2016 USD 0.2201 USD 0.2201

The following table shows the results, i.e. the take up of shares and cash respectively, of the previous dividend issues under the Scrip Dividend Programme.

Results of the Scrip Dividend Programme

Quarter Net Dividend in shares Net Dividend in cash

4Q 2015 43% 57%

7.3 Share repurchase In addition to a cash dividend, the Company may buy back shares as part of its total distribution of capital to its shareholders. For the year 2015, and similarly for the years 2010 to 2014, the Board of Directors was authorised by the annual general meeting to repurchase Shares in the market for subsequent annulment. The Company has not undertaken any share repurchase based on these authorisations. The authorisation was renewed at the annual general meeting on 11 May 2016.

7.4 Legal constraints on the distribution of dividend Dividends may be paid in cash or in some instances in kind. The Norwegian Public Limited Companies Act provides the following constraints on the distribution of dividends applicable to the Company:

Section 8-1 of the Norwegian Public Limited Companies Act provides that the Company may distribute dividends to the extent that the Company’s net assets following the distribution cover (i) the share capital, (ii) the reserve for valuation variances and (iii) the reserve for unrealised gains. The amount of any receivable held by the Company which is secured by a pledge over Shares in the Company, as well as the aggregate amount of credit and security which, pursuant to section 8–7 to 8-10 of the Norwegian Public Limited Companies Act fall within the limits of distributable equity, shall be deducted from the distributable amount.

The calculation of the distributable equity shall be made on the basis of the balance sheet included in the approved annual accounts for the last financial year, provided, however, that the registered share capital as of the date of the resolution to distribute dividends shall be applied. Following the approval of the annual accounts for the last financial year, the annual general meeting may also authorise the Board of Directors to declare dividends on the basis of the Company’s annual accounts. Dividends may also be resolved by the general meeting based on an interim balance sheet which has been prepared and audited in accordance with the provisions applying to the annual accounts and with a balance sheet date not further into the past than six months before the date of the general meeting’s resolution.

Dividends can only be distributed to the extent that the Company’s equity and liquidity following the distribution is considered sound.

The Norwegian Public Limited Companies Act does not provide for any time limit after which entitlement to dividends lapses. Subject to various exceptions, Norwegian law provides a limitation period of three years from the date on which an obligation is due. There are no dividend restrictions or specific procedures for non- Norwegian resident shareholders to claim dividends. For a description of withholding tax on dividends applicable to non-Norwegian residents, see Section 14.2.1 "Taxation on dividends".

7.5 Manner of dividend payments Dividend payments to shareholders on Oslo Stock Exchange will be made in NOK. ADR holder’s dividend payments will be made in USD. Payments to shareholders on Oslo Stock Exchange through VPS and ADR holders through the Depositary, will in most cases be credited to the relevant shareholders’ accounts.

39 8 INDUSTRY AND MARKET OVERVIEW Certain of the information in this Section relating to market environment, market developments, growth rates, market trends, industry trends, competition and similar information are estimates based on data compiled by professional organisations, consultants and analysts; in addition to market data from other external and publicly available sources, and Statoil's knowledge of the markets, see Section 4.3 "Industry and market data". The following discussion contains forward-looking Statements, see Section 4.8 "Cautionary note regarding forward-looking statements". Any forecast information and other forward-looking statements in this Section are not guarantees of future outcomes and these future outcomes could differ materially from current expectations. Numerous factors could cause or contribute to such differences, see Section 2 "Risk factors" for further details.

8.1 Introduction This Section includes a brief description of the principal markets in which Statoil competes. No significant changes impacting these markets have occurred since the end of the period covered by the latest published audited financial statements. Statoil creates value by accessing, exploring, developing and producing energy sources globally, and by enhancing value of such production through its mid- and downstream activities.

Fundamental changes are happening in the oil and gas industry. The industry faces new challenges such as increased pressure on margins, changing patterns of energy supply and consumption, geopolitical instability and rising climate change concerns. Key factors affecting competition are oil and gas supply and demand, exploration and production costs, global production levels, alternative fuels, and environmental and governmental regulations. In addition, Statoil competes to develop wind energy opportunities.

Statoil competes with large integrated oil and gas companies, as well as with independent and state-owned companies, in both upstream and downstream activities. Statoil’s peers used in communication with investors are OMV, Marathon, Anadarko, BP, Repsol, Total, ConocoPhillips, Eni, ExxonMobil, Chevron and Royal Dutch Shell.

Statoil is involved in a range of activities throughout the value chain. Upstream activities are located both in Norway and internationally and involve the acquisition of assets and licenses for exploration, development and production of oil and gas. Mid- and downstream activities are located both in Norway and internationally and include refinery- and pipeline operation, marketing and trading of crude oil, refined products and natural gas.

Even after supplying Statoil’s own refineries at Mongstad and Kalundborg, Statoil is among the world’s major net sellers of crude oil, trading around two million barrels of crude oil and condensate daily. For crude produced at the NCS, the main market is North West Europe. Crude produced in Latin America is mainly sold into North America and Asia, while North American production is sold domestically. Crude produced in West Africa can be sold into all markets. Most of the volumes are sold in the spot market. All sales are against publicly quoted market prices, with negotiated price differentials to these. Such differentials will vary with the type of crude oil.

Statoil produces around 15 million tons of refined products annually. Statoil also sells around three million tons of NGL from the Kårstø processing plant, and 0.4 million tons from its North American operation. Products include LPG, ethane, naphtha, gasoline, road and marine diesel, fuel oil and coke. Sales in Scandinavia are mainly through a term contract with Statoil’s earlier retail chain, now Circle K. Remaining volumes are sold on a spot basis, to retail chains, directly to end users and to traders. Gasoline is mainly exported to the US, West Africa or Asia. Naphtha and LPG is partly exported, mainly to Asia, the rest being sold in North West Europe. Due to good harbour and storage facilities, both Mongstad and Kårstø are well suited for intercontinental trade.

Statoil markets gas mainly in three regions. The core market for gas for Statoil is North West Europe with its proximity to the NCS and the well-developed pipeline network. Secondly, the US gas market has become increasingly important with the growth of US shale gas and Statoil’s upstream position. Finally, Statoil is selling spot LNG cargoes in the global LNG market. Asia is the largest LNG market with the highest expected growth. However, Statoil is currently a minor player in this market and the majority of LNG cargoes is sold in Europe.

In North West Europe, the gas is sold both under bilateral medium- and long-term agreements as well as on the spot market. As the market matured Statoil has restructured the contract portfolio to better reflect the

current developments. Sales contracts have become less complicated and more standardized reducing operating cost. The typical counterparties for bilateral contracts are end-users, retailers and wholesale companies for utilisation within the heat and power, industry, residential and commercial as well as transportation segments. For spot contracts the typical counterparties are utilities, trading houses and producers, as well as exchange based trading giving access to more financial players.

Gas in the US is primarily produced in the Marcellus/Utica area of the Northeast, but also in the Eagle Ford (Texas), Bakken (North Dakota) and offshore Gulf of Mexico. Sales are made in a combination of spot and term contracts. Counterparties include distribution companies, power generators and exporters (LNG), as well as marketing firms. Statoil’s production represents approximately 1% of US natural gas output.6

In Asia, Statoil’s LNG counterparties fall into two categories. These are national/regional utilities and LNG traders with existing long term sales contracts into Asia.

Statoil’s global production in 2015 was split 41% on gas and 59% on oil. Please refer to the below illustration for a split of how Statoil’s products are used.7

Statoil's ability to remain competitive will depend, among other things, on the Management's continuing to focus on reducing unit costs and improving efficiency, and maintaining long-term growth in reserves and production through continuing technological innovation. It will also depend on Statoil's ability to seize international opportunities in areas where its competitors may also be actively pursuing exploration and development opportunities. Statoil believes it is in a position to compete effectively in each of its business segments.

8.2 Market overview Global economic growth measured through growth of gross domestic product ("GDP")8 eased in 2015, to 2.5% from 2.7% in 2014. This largely reflects weakness in non-OECD economies where activity decelerated over the year. Growth in the advanced economies, on the other hand, held up relatively well at around 2%, supporting overall economic growth and energy demand.

The underlying fundamentals of the United States economy remained sound and GDP growth logged 2.4% in 2015, which was the same growth rate as in 2014. GDP growth accelerated to 1.7% in the Eurozone,

6 Source: Wood MacKenzie and IEA 7 Statoil sustainability report 2015, page 20, http://www.statoil.com/no/InvestorCentre/AnnualReport/AnnualReport2015/Documents/DownloadCentreFiles/01_KeyDownloa ds/2015_Sustainability_report.pdf 8 GDP figures are collected from IMF’s "World Economic Outlook" updated report issued 19 July 2016, page 9.

supported by low energy prices, reduced fiscal headwinds, more monetary stimulus and a weak euro. UK GDP growth slowed in 2015 to 2.2%, whereas Japan grew by 0.5%. Deep recessions have emerged in Brazil and Russia, whilst China continues on an intended path of structural reforms and a consequent gradual deceleration. Net commodity importers such as India are doing better and India’s GDP growth rate of 7.6% outpaced China’s 6.9% in 2015.

Several major forces are at play in the global economy and will continue to affect demand, including soft commodity prices and persistently low interest rates, increasingly divergent monetary policies across major economies, and weak world trade. The global economic situation continues to be fragile, with development partly driven by uncertain political environments in key countries and regions, in addition to normal supply and demand factors. According to the IMF, the global GDP development is expected to be modest this year and grow by 2.5%, where non-OECD countries contribute the most to growth.

8.3 Crude oil markets9 The global commodity markets have been experiencing a lack of balance, driven by over-supply of resources and feeble demand. This is also the case for the energy markets (oil, gas and coal).

Since the summer of 2014 the crude oil supply growth has outpaced the growth in global oil demand and the oil market remained oversupplied in to the second quarter of 2016.

Global oil demand grew by 1.85 mmbbl per day in 2015, driven by a colder than normal winter in the US and Northern Europe and the lower prices of crude oil. Demand growth in absolute terms was highest in China, despite 2015 being a challenging year for Chinese stock markets and the Chinese economy in general.

The record high demand and solid demand growth in 2015, was not enough to balance the situation as supply grew more over the same period. Non-OPEC producers have proven to be resilient to lower prices and grew production by 1.3 mmbbl per day in 2015 while OPEC added 1.1 mmbbl per day to their production, mainly from Saudi Arabia and Iraq. The supply of crude oil from non-OPEC countries (in particular from US shale oil) grew quickly through 2014, and the production have been kept at a high level longer than anticipated, as a result of new projects coming on stream in several markets as well as industry initiatives directed towards keeping an elevated production level when prices were tumbling. In addition, production from OPEC and in particular from Iraq and Saudi Arabia has increased. Since the latter half of 2014, the increased production from Saudi Arabia has been a conscious change of strategy with regards to regulating the market. Lower crude oil price level in 2015, averaging at USD 52/bbl for Brent10, was seen to impact the non-OPEC producers in the last quarter of 2015 when production growth almost flattened out year-on-year, down from an average growth of 1.8 mmbbl per day in the previous three quarters.

The oversupply led to record high oil storage levels, which put downward pressure on crude prices, with a bottom level in mid-January just below USD 26/bbl 2016. From there the price of Brent Blend crude oil rose to above 50 USD/bbl on 6 June 2016, and has since remained in the 45 - 55 USD/bbl range. For a description of the development in 2016, see Section 8.3.3 "Recent development and trends in the crude oil markets".

8.3.1 Oil prices High volatility characterised the oil market in 2015, while the participants endeavoured to find the new price level of crude oil, with the price of Brent in a range between USD 66/bbl in May to USD 35/bbl at the end of December. Although oil demand increased by 1.85 mmbbl per day, much due to a cold winter and low prices, the market remained oversupplied throughout the whole year, with total supply growth of 2.4 mmbbl per day of production. As a consequence, the global oil stocks were at historically high levels by year-end.

The average price for dated Brent crude in 2015 was USD 52.4/bbl, down 47% from 2014. The price was at USD 55/bbl in the beginning of 2015, on a downward trajectory. Signs of a downturn in the Chinese economy and the nuclear deal between P5+111 and Iran contributed to a declining market sentiment. The 168th OPEC meeting took place early December 2015, where no action was agreed by the OPEC member countries and the

9 All volumetric figures (mmbbl) are from The International Energy Agency’s Oil Market Report of 14 June 2016. 10 S&P Global Platts’ Dated Brent price quote 2015 close, payable source. 11 China, France, Russia, the United Kingdom, and the United States; plus Germany.

price of Brent went below USD 40/bbl for the first time since the spring of 2009. The dated Brent price was USD 36/bbl on 31 December 2015, a year-end level not seen for a decade. The futures market for Brent at the Intercontinental Exchange (ICE) was in contango throughout 2015.12

Although the conflict level in Syria increased further and the armed conflict in Yemen added tension in the Middle East, geopolitical events had less effect on the crude oil prices in 2015, compared with the previous year.

2015 was an eventful year for North American (NA) crude. The price of US Western Texas Intermediate ("WTI") crude, as quoted at the Cushing tank farm in Oklahoma, averaged USD 49/bbl in 2015, down 47% from 2014. The price of WTI was USD 53/bbl at the beginning of the year. On 31 December 2015 the WTI price was at USD 37/bbl, roughly at par with first month Brent. With low crude prices through 2015, rig counts dropped and production growth faltered. At the same time, crude inventories continued to grow, further weighing on crude prices. New pipeline and crude distillation capacity, coupled with slower production growth, created a tighter balance for US light crude, easing the large price discounts of inland crudes relative to Brent. The easing of discounts challenged the economics of more expensive transport solutions such as rail relative to pipeline, such that crude by rail loadings declined dramatically during 2015. In late 2015, the US government passed legislation allowing unrestricted export of crude oil for the first time since the 1970s. Unrestricted US crude exports will provide producers with greater access to higher value global crude markets and could impact price differentials in the medium-term.

8.3.2 Refining margins Refinery margins in Northwest Europe, as calculated against dated Brent crude, were well above normal in 2015. One reason for the strength was the weak crude oil market, with dated Brent priced below the first forward month at the ICE exchange throughout the year. Further, the price differentials vs. Brent for the crude oils actually used were lower than last year. The other main factor was a very strong gasoline market. Low price levels at the pump led to rising demand in the US, and gasoline demand in Europe stopped falling. Changes to the Chinese economy led to more emphasis on the consumer sector. New car sales in China almost matched that of the US, and some 80% were net additions to the fleet. Chinese gasoline demand therefore rose almost as much as in the US, and strong growth was also seen in India and Pakistan. This demand growth led to capacity constraints at refineries, in particular for high-octane components. Europe, being in net surplus on gasoline, was able to export more into these markets, with parts of it going as high-octane components at strong price premiums. For naphtha, which is a feedstock both for the petrochemical industry and for making gasoline, Asian demand for imports from Europe rose through the year and gave very strong margins here. On the other hand, new refineries in Asia and the Middle East were geared towards diesel production. New diesel volumes exported to Europe led to rising inventory levels here, despite a quite strong demand growth. The situation became dramatic in the fourth quarter of 2015, when high refinery throughputs in order to make enough gasoline and naphtha led to excess diesel production. This made diesel tanks go full and the diesel margin decreased. LPG was oversupplied due to high exports from the US. Heavy fuel oil was oversupplied due to declining demand. However, against the low Brent crude oil prices, both products were sold at historically normal margins.

12 Contango is a condition where forward prices exceed spot prices, so the forward curve is upward sloping.

8.3.3 Recent development and trends in the crude oil markets The price of Brent crude oil dipped below USD 26 bbl on 20 January 2016. It then rose to above USD 50 bbl on 6 June 2016, but has since remained rangebound just below that level. With no physical shortage of crude oil, the rise was mainly driven by investors positioning for a tighter market later. From 50 USD/bbl, conflicting market data have made the further direction less clear to investors, and kept price stable. The development of the price for Brent crude oil is set out in the graph below: 13

The overall oil market comprises crude oil, refined products and NGL, and was generally oversupplied in the first half of 2016. Within this period, the actual crude oil market is seen to be the tightest part, with draws on inventories through the period. The oil industry has adapted to the lower price level partly by substantial efficiency gains, but also by cutting field investments. As existing oil fields will have a certain natural decline rate, the lack of new drilling has made that effect more prominent. Low investments have made US crude production go 1 million barrel per day below last year at the end of the second quarter of 2016. Within OPEC, such effects plus civil unrest have kept output almost unchanged through 2016, despite sharp rises from Iraq and Iran.

The demand for crude oil, i.e. refinery intake, stayed high through the first half of 2016, on quite strong refinery margins. However, this led to an oversupply of refined products and a sharp drop in refinery margins in July 2016. As such, a part of the crude oil surplus has been shifted to the products side through the first half of 2016. Further, high overall inventories are also due to the NGL (ethane, LPG) side, which remains heavily oversupplied with prices only supported by parity to natural gas on a USD/kWh basis.

Refineries will have to cut back on crude oil intake to rebalance the product markets. The crude oil market in the rest of 2016 and into 2017 will then be a balance between such weaker demand and constraints on field production due to natural decline and lack of funds for investments. Statoil estimates that supply constraints will be the strongest force, leading to further draws on crude oil inventories. While there are large inventory volumes to draw before the market reaches physical tightness, sign of such draws should make investors start buying crude oil futures contracts and help lift prices from the paper side.

Within this time frame, a price rise will be capped when the level becomes high enough to make US shale oil production profitable. Shale oil fields can be started up rather quickly.

From 2017 the market’s perception of cost of new supplies is expected to be the main driver of price formation, once the commercial oil stocks have come down to a normal level.

In the years to come, it is expected that the demand for crude oil will continue to increase to record levels, with a growth level of about 1 mmbbl per day per year towards 2020. Together with the natural decline in production from existing fields, postponement of investments and other industry adaptions as well as low OPEC

13 Source oil: S&P Global Platts’ Dated Brent at close, payable source.

spare-production capacity, this will lead to a tighter market in the medium-term. The market situation when the imbalance has been reversed remains difficult to predict.

8.4 Natural gas markets As indicated in Section 8.1 "Introduction", Statoil is marketing gas in three main regions globally. The core market for Statoil is North West Europe due to the proximity and developed infrastructure on the NCS. The US gas market is also of high importance to Statoil based on the size following the US shale revolution and due to Statoil’s upstream position 14. Although the Asian gas market has the highest growth, Statoil has a minor position in this market.

Oversupply is the theme of global gas markets, and prices have been weak as a result. A build-up of LNG capacity in Australia and the United States has been one conduit to bring these ample supplies to market.

In the United States, 2016 began with weak weather-related demand and abundant supply which combined to push prices to the lowest levels in over a decade. As the year has progressed, supply has begun to fall, the weather impact has turned bullish, LNG exports have started and power demand remains robust as prices have started their recovery. Looking forward, investments in LNG exports, petrochemicals and gas power plants, combined with the decommissioning of coal plants, point to stronger demand, tighter balances and strengthening of prices in the medium-term.

The demand growth in Asia is comparatively weak and with the new LNG liquefaction capacity additions that will start production between now and 2020 there is a heightened risk of oversupply. In Japan and South Korea new coal-to-power capacity is being built. In South Korea new nuclear capacity will also come on line, and Japan has decided to restart part of their nuclear power fleet. The gas demand growth in China and other emerging markets has slowed, and lower and more competitive process have contributed to this development. The European market has been well supplied with higher pipeline supplies, and with the new LNG liquefaction coming on stream this will keep gas prices low. Lower prices for a sustained period of time will spur new gas demand, in particular in emerging economies, which in the longer term will stimulate prices when demand is catching up with production capacity.

For a description of the development in 2016, see Section 8.4.5 "Recent trends and development in the natural gas market".

8.4.1 Natural gas prices Natural gas prices fell during 2015 in most markets. European gas prices reached the lowest level since early 2010. Reasons include weak demand, good supplies and low prices for coal, oil and other competing fuels. Henry Hub gas prices in the United States also declined during 2015, and the prices at year-end were at the lowest level since the 1990s.

8.4.2 Gas Prices – Europe European gas markets prices have averaged (USD 4.4/mmBtu15) in the first half of 2016, a 40% reduction from the first half of 2015. Prices have been forced lower by strong supply levels with Norwegian and Russian exports of pipeline gas remaining at, or near to, record levels in 2016. This has helped offset reduced EU indigenous production which has declined, primarily, due to the Dutch Government’s capping of the Groningen field in order to reduce seismic activity. Demand levels have been slightly increased vs last year, particularly in the UK where gas to power demand has increased as gas prices have become more competitive due to higher carbon costs than the continent. Thus far, the impacts of "Brexit" have been limited to movements relating to currency fluctuations. In terms of market influence, movements in oil, and the announcement that Centrica’s Rough storage facility will be unavailable for winter supply has had a much more marked impact on gas prices.

The gas markets have historically been regional, based on that gas is mainly transported from producing regions with a certain proximity to consuming regions through pipelines. LNG is a way of transporting gas and represents only 10% of the global gas market. Prices in the various regions have been influenced by the

14 Statoil's share of the gas production in US is just above 1%. Source: Wood MacKenzie and IEA. 15 Source: Monthly and annual averages of Heren NBP Day Ahead price assessment, Bank of England spot FX rates used. Obtained 17 June 2016, payable source.

45 supply/demand fundamentals within these regions, and therefore pricing is not homogenous between the regions. Following the Fukushima disaster the European and Asian gas prices have experienced wide price differentials as the LNG demand in Asia peaked. This triggered a new supply wave of LNG, and currently the prices in these two markets are, on average, at relative parity.

8.4.3 Gas prices – North America Henry Hub prices hit a low of USD 1.7/mmBtu in March 2016 before rebounding to USD 2.8/mmBtu in July 2016. US gas producers responded to the low prices by withdrawing rigs. Since the drilling peak set in September 2014, rigs drilling for gas have declined by over 75%.16 The power sector has responded to the price environment by turning on natural gas-fired generation and turning off coal burners.

8.4.4 Global LNG prices Global LNG prices, which are determined by a combination of crude oil – since the larger share of long term contracts have prices linked to crude oil –, prices at European gas hubs, and LNG supply and demand fundamentals, have decreased by more than 32% since 2015, and year-to-date average is (USD 4.9/mmBtu) compared with yearly average of USD 7.5/mmBtu in 2015.17 Several new LNG plants will add more capacity between now and 2020, and the global market is set to grow by more than 50% in size. As underlying demand for LNG is not expected to grow in line with capacity, periods with supply push will emerge.

16 Source: Rigs – Baker Hughes http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother 17 Source: S&P Global Platts’ Japan-Korea-Marker assessment, 20 June 2016, payable source.

46 8.4.5 Recent trends and development in the natural gas market Since the beginning of 2015 European gas prices have been trending downwards, as set out by the graph18 below, pressurized by weak competitive fuels such as coal and oil.

In the US, falling prices have allowed gas to gain market share at the expense of other fuels, particularly coal. In the short run, power pools turn on natural gas plants more often, and in the long run, natural gas plants are built, while coal plants are decommissioned. Natural gas is now the largest source of electric power generation in the US as a result, representing 33% of all generation in early 201620.

As a consequence of the low price environment, the industry continues to scrutinize investments plans and activity levels and is implementing further initiatives to reduce operational costs. Taking into account the outlook for continued changes in global market forces and industry structure, it is likely that the dynamics of supply and demand will remain uncertain. According to industry analysts, lower investment levels and lack of investments in exploration should contribute to a balancing of the markets, albeit there is uncertainty as to when this will happen, and at what level commodity prices will level out.

Statoil has previously initiated a number of initiatives to enforce stricter financial management and improve capital efficiency. Statoil carries on these initiatives, strictly prioritizing the project portfolio by optimizing

18 Source: ICIS Heren and ECB; Description: European Natural Gas NBP Heren Gas Prices Day ahead (http://www.icis.com/energy/gas/europe/european-spot-gas-markets/), Currency provider ECB, Unit=USD/mmBtu and CME New York Mercantile Exchange Henry Hub Natural Gas Regular Trading Month 01 19 LNG Growth : IEA Medium Term Gas Outlook 2016. 20 Source: Power Generation – http://www.eia.gov/electricity/data/browser/

47 projects to further improve its robustness as well as divesting projects that are considered non-core such as the divestment of Marcellus operated assets in the US onshore portfolio. In addition, Statoil continues to renegotiate its supplier contracts to achieve improved rates.

8.5 Response to market situation Statoil has initiated several initiatives to safeguard financial flexibility. Statoil’s exploration activities have been reduced both as a result of fewer prospects and lower prices. In 2014 Statoil drilled more than 50 exploration wells, investing USD 3.5 billion in exploration activities. In 2015 Statoil reduced the level of exploration to USD 3.0 billion, drilling 39 wells. In 2016 Statoil estimates a total exploration activity level of around USD 1.8 billion, excluding signature bonuses.

Organic capital expenditures are defined as Statoil’s capital expenditure, excluding acquisitions and capital leases. In 2014 Statoil reported organic capital expenditures of around USD 20 billion, and since then Statoil has actively reduced the organic capital expenditures by halting or postponing projects and reduced activity. In 2015 organic capital expenditures was reported at USD 14.7 billion and in 2016 Statoil expects to spend USD around 12 billion on organic capital expenditures.

For more information on as to how Statoil is adapting to the challenging markets, see Section 10.5 "Improved efficiency".

9 THE BUSINESS OF STATOIL AND MINERAL RESERVES 9.1 Introduction of Statoil 9.1.1 Business overview Statoil ASA is a public limited liability company organised under the laws of Norway and subject to the provisions of the Norwegian Public Limited Liability Companies Act. The Company was formed in 1972 by a decision of the Norwegian parliament and was listed on the stock exchanges in Oslo and New York in 2001. The Norwegian State is the largest shareholder in the Company, with a direct ownership interest of 67%.

Statoil is a technology-driven energy company primarily engaged in oil and gas exploration and production activities. Statoil's head office is located in Stavanger, Norway. Statoil is the leading operator on the NCS and also has substantial international activities.21 Statoil is present in several of the most important oil and gas provinces in the world, has business operations in more than 30 countries and territories, and employs about 21,350 employees and hired consultants worldwide by the end of July 2016. In 2015, 37% of Statoil's Equity Production came from international activities outside NCS and Statoil also holds operatorships internationally.22 The production from NCS was 62% of the total Equity Production in the second quarter of 2016, while the international production was 38%. In the second quarter of 2016, production from the NCS was 1,211 mboe per day. Equity Production outside of Norway was 748 mboe per day in the second quarter of 2016, in line with the first quarter last year, adjusted for transactions.23

Statoil's access to oil and gas in the form of equity, governmental and third party volumes makes Statoil a substantial marketer of these commodities. Processing and refining are also part of the operations. Statoil is also participating in projects that focus on other forms of energy, such as offshore wind and carbon capture and storage, in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change.

9.1.2 Corporate structure Statoil's operations are managed through the following business areas:

• Development and Production Norway ("DPN"), which comprises Statoil's upstream activities on the NCS;

• Development and Production International ("DPI"), which comprises Statoil's worldwide upstream activities that are not included in the DPN and Development and Production USA business areas;

• Development and Production USA ("DPUSA"), which comprises Statoil's upstream activities in the USA and Mexico;

• Marketing, Midstream and Processing ("MMP") which comprises Statoil's marketing and trading of oil products and natural gas, transportation, processing and manufacturing, and the development of oil and gas value chains;

• Technology, Projects and Drilling ("TPD"), responsible for safe, efficient and cost-competitive project and well delivery worldwide. Furthermore, TPD drives Statoil’s research and technology development

21 This statement is based on the number of fields operated on the NCS whereby Statoil operates 47 out of 82 producing fields at year end 2015. Furthermore, 38% of Statoil's production is outside the NCS, see the second quarter 2016 report page 8,http://www.statoil.com/no/InvestorCentre/QuarterlyResults/2016/Downloads/Financial%20statement%20and%20review%2 02Q%202016.pdf 22 Statoil’s annual report for 2015, page 4. 23 Throughout the Prospectus the terms "Equity Production" and "Entitlement Production" are used. "Equity Production" is production that correspond to Statoil's percentage ownership in a particular field. "Entitlement Production", on the other hand, represent Statoil's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the UK, Canada and Brazil. The overview of equity production provides additional information for readers.

• Exploration ("EXP"), 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"), which is responsible for wind parks, carbon capture and storage as well as other renewable energy and low-carbon energy solutions; and

• Global Strategy and Business Development ("GSB"), which sets the corporate strategy, and executes business development and merger and acquisition (M&A) activities for Statoil.

9.1.3 Reporting segments Statoil reports its business in the following reporting segments: Development and Production Norway (DPN); Development and Production International (DPI), which combines the DPI and DPUSA business areas; Marketing, Midstream and Processing (MMP); and Other.

The Other reporting segment includes activities in New Energy Solutions (NES), Technology, Projects and Drilling (TPD), Global Strategy and Business Development (GSB) and Corporate staffs and support functions. Activities relating to project development and the Exploration (EXP) business area are allocated to, and presented in, the respective development and production segments.

The Sections below provide information mainly about the reporting segments DPN and DPI. The information includes statistics and the subtotals and totals in some of the tables may not equal the sum of the amounts shown in the text due to rounding.

9.1.4 Production cost and realised prices The following table presents realised sales prices per year-end from Statoil's annual report 2015 on Form 20-F ("Form 20-F") which have been incorporated by reference, see Section 17.1 "Cross reference table":

Eurasia excluding Norway Norway Africa Americas

Year ended 31 December 2015 Average sales price oil and condensate in USD/bbl 52.2 50.7 49.4 39.4 Average sales price NGL in USD/bbl 30.1 - 26.2 12.5 Average sales price natural gas in NOK/Sm3 2.2 1.4 1.7 0.8

Year ended 31 December 2014 Average sales price oil and condensate in USD/bbl 98.3 101.3 95.6 78.3 Average sales price NGL in USD/bbl 59.3 - 59.7 37.3 Average sales price natural gas in NOK/Sm3 2.3 1.3 2.2 1.0

Year ended 31 December 2013 Average sales price oil and condensate in USD/bbl 109.1 110.5 107.3 89.1 Average sales price NGL in USD/bbl 67.4 - 69.7 59.2 Average sales price natural gas in NOK/Sm3 2.4 0.9 2.1 0.8

The following table presents prices from the Interim Financial Statements for the second quarter 2016 which have been incorporated by reference, see Section 17.1 "Cross reference table":

Operational data Quarters Change First half Change 2Q 2016 1Q 2016 2Q 2015 2Q on 2Q 2016 2015

Prices

Average Brent oil price (USD/bbl) 45.6 33.9 61.9 (26%) 39.8 57.8 (31%)

DPN average liquids price (USD/bbl) 41.2 30.7 56.3 (27%) 35.6 53.1 (33%)

DPI average liquids price (USD/bbl) 37.1 25.6 53.4 (30%) 31.5 48.1 (34%)

Group average liquids price (USD/bbl) 39.4 28.7 55.0 (28%) 33.9 50.9 (33%)

Group average liquids price (NOK/bbl) 325.4 248.0 426.7 (24%) 286.5 394.9 (27%)

Transfer price natural gas (USD/mmBtu) 2.90 4.00 4.99 (42%) 3.51 5.50 (36%) Average invoiced gas prices - Europe (USD/mmBtu) 4.95 5.45 7.24 (32%) 5.23 7.61 (31%) Average invoiced gas prices - North America (USD/mmBtu) 1.67 2.29 2.10 (20%) 1.98 3.28 (40%)

Refining reference margin (USD/bbl) 5.2 4.3 9.6 (46%) 4.8 8.4 (43%)

The following table presents production cost per year-end from Form 20-F:

Eurasia Average production cost in NOK per boe based on excluding entitlement volumes Norway Norway Africa Americas Total

2015 47 79 61 62 52 2014 53 64 64 52 55 2013 50 53 59 46 51

9.2 Development and Production Norway (DPN) 9.2.1 DPN overview DPN is responsible for field development and operational activities on the NCS. Statoil's Equity Production and Entitlement Production on the NCS was 1,232 mboe per day in 2015. That was about 68% of Statoil's total Entitlement Production and 62.5% of Statoil's Equity Production. In the first half of 2016, production from the NCS was 1,266 mboe per day.

DPN has from January 2016 organised the production operations into three business clusters: Operations North (Barents Sea and Norwegian Sea) located in Harstad, Operations West (North Sea) located in Bergen and Operation South (North Sea) located in Stavanger. Partner-operated fields cover the entire NCS and are internally included in the Operations South business cluster. When possible, the fields in each cluster use common infrastructure, such as production installations and oil and gas transport facilities. This reduces the investments required to develop new fields. DPN’s efforts in these core areas also focus on finding and developing smaller fields through the use of existing infrastructure and on increasing production by improving the recovery factor.

DPN is also working to extend production from Statoil's existing fields through improved reservoir management and the application of new technology.

Key events and portfolio developments in the period from January 2016 and up to 26 August 2016:

• In January 2016, Statoil announced the acquisition of 11.93% of the shares and votes in Lundin Petroleum AB for a total purchase price of SEK 4.6 billion (USD 0.5 billion). The shares were at that point accounted for as a non-current financial investment at fair value.

• On 19 January 2016, Statoil was awarded interests in 24 licences in the Awards in Predefined Areas ("APA") round 2015 on the NCS, 13 of those as operator and 11 as partner.

• On 12 March 2016, the Goliat field located in the Barent Sea came on stream. Eni Norge is operator with an ownership interest of 65%, while Statoil is partner with the remaining share of 35%.

• Drilling of the first well for the first phase of the Johan Sverdrup field development commenced on 1 March 2016.

• In May 2016, Statoil, announced divestment of its entire 15% interest in the Edvard Grieg field on the NCS for an increased shareholding in Lundin Petroleum AB. The transaction also includes divestment of a 9% interest in the Edvard Grieg Oil pipeline and a 6% interest in the Utsira High Gas

52 pipeline, and in addition payment of a cash consideration of USD 68 million to Lundin Petroleum AB. Following completion of the transaction Statoil will own 20.1% of the shares in Lundin Petroleum AB. The effective date of the divestment of these assets is 1 January 2016. The transaction was approved by Lundin Petroleum AB’s extraordinary general meeting on 30 May 2016. The transaction closed end of June 2016.

• The Plan for Development and Operations ("PDO") for Oseberg Vestflanken 2 was approved by the MPE on 9 June 2016.

• Due to structural integrity issues on Njord A, the project "Njord Future" is established to secure long term production for both the Njord and Hyme fields. In June 2016, the Njord field was temporary shut in, and both Njord A and Njord Bravo will be towed to shore during the third quarter of 2016 for upgrade.

• In May 2016, Statoil was awarded five licenses in the 23rd concession round on the NCS, four as operator and one as partner.

• On 9 August 2016, Statoil and its partners submitted the Plan for Development and Operation (PDO) and the Field Development Plan (FDP) for the Utgard (formerly Alfa Sentral) gas and condensate discovery in the North Sea to Norwegian and UK authorities.

• On 19 August 2016, Statoil and its partners submitted the plan for development and operation of the Byrding (formerly Astero) oil and gas discovery to the MPE. Byrding will be developed as a subsea installation with one well, drilled from an existing well template on Fram H-Nord.

• In August 2016, Statoil updated cost estimates for Johan Sverdrup. The investment costs for the first phase are currently estimated at NOK 99 billion (USD 12.1 billion), a reduction of NOK 24 billion (USD 2.9 billion) since the PDO for phase 1 was submitted in February 2015. The Johan Sverdrup project will be developed in several phases and the full-field investment estimate has been reduced from a range of NOK 170-220 billion (USD 20.7-26.8 billion) to NOK 140-170 billion (USD 17.0-20.7 billion) since the PDO for phase 1 was submitted.

• Statoil has so far in 2016 made seven small discoveries on the NCS.

It should be noted that acquisitions that are subject to approval from authorities and thus not has been completed as of the date of this Prospectus, not have been included or reflected in any tables, estimates or otherwise in this Prospectus unless otherwise explicitly stated.

9.2.2 Fields in production on the NCS 9.2.2.1 Overview The following table shows DPN's average daily Entitlement Production of oil, including NGL and condensates, and natural gas for the years ending 31 December 2015, 2014 and 2013. Field areas are groups of fields operated as a single entity.

For the year ended 31 December

2015 2014 2013

Oil and Natural Oil and Natural Oil and Natural NGL gas Total NGL gas Total NGL gas Total Area production mmbbl mmcm mboe/day mmbbl mmcm mboe/day mmbbl mmcm mboe/day

Operations North 145 24 296 162 24 315 150 20 278 Operations West 267 51 591 264 43 535 290 48 589 Operations South 134 13 214 107 11 177 94 12 167 Partner Operated Fields 50 13 132 55 16 157 58 20 182

Total 595 101 1,232 588 95 1,184 591 99 1,217

The following table shows the NCS production by fields and field areas in which Statoil was participating as of 31 December 2015.

Average daily Statoil's production Geographical equity Licence in 2015 Business cluster area interest in % Operator On stream expiry date mboe/day

Operations North Snøhvit The Barents Sea 36.79 Statoil 2007 2035 47.1 Norne The Norwegian Sea 39.10 Statoil 1997 2026 5.9 Alve The Norwegian Sea 85.00 Statoil 2009 2029 10.6 Urd The Norwegian Sea 63.95 Statoil 2005 2026 14.2 Åsgard The Norwegian Sea 34.57 Statoil 1999 2027 92.1 Morvin The Norwegian Sea 64.00 Statoil 2010 2027 16.3 Mikkel The Norwegian Sea 43.97 Statoil 2003 2020 1) 14.3 Tyrihans The Norwegian Sea 58.84 Statoil 2009 2029 49.6 Kristin The Norwegian Sea 55.30 Statoil 2005 2033 2) 24.5 Heidrun The Norwegian Sea 13.04 Statoil 1995 2024 3) 8.7 Njord The Norwegian Sea 20.00 Statoil 1997 2021 4) 6.1 Hyme The Norwegian Sea 35.00 Statoil 2013 2014 5) 6.2

Total Operations North 295.6

Operations West Troll Phase 1 (Gas) The North Sea 30.58 Statoil 1996 2030 185.2 Troll Phase 2 (Oil) The North Sea 30.58 Statoil 1995 2030 38.2 Fram The North Sea 45.00 Statoil 2003 2024 16.9 Fram H Nord The North Sea 49.20 Statoil 2014 2024 2.3 Oseberg The North Sea 49.30 Statoil 1988 2031 86.4 Tune The North Sea 50.00 Statoil 2002 2032 6) 1.9 Gullfaks The North Sea 51.00 Statoil 1986 2036 69.4 Gimle The North Sea 65.13 Statoil 2006 2034 7) 2.6 Kvitebjørn The North Sea 39.55 Statoil 2004 2031 64.0 Valemon The North Sea 57.76 Statoil 2015 2031 16.4 Visund The North Sea 53.20 Statoil 1999 2034 48.5 Grane The North Sea 36.66 Statoil 2003 2030 45.8 Volve The North Sea 59.60 Statoil 2008 2028 10.0 Veslefrikk The North Sea 18.00 Statoil 1989 2020 8) 3.1

Total Operations West 590.5

Operations South Sleipner Vest The North Sea 58.35 Statoil 1996 2028 49.2 Sleipner Øst The North Sea 59.60 Statoil 1993 2028 10.1 Gungne The North Sea 62.00 Statoil 1996 2028 6.1 Gudrun The North Sea 36.00 Statoil 2014 2028 9) 44.4 Statfjord Unit The North Sea 44.34 Statoil 1979 2026 42.6 Statfjord Øst The North Sea 31.69 Statoil 1994 2026 10) 1.3 Statfjord Nord The North Sea 21.88 Statoil 1995 2026 1.2 Sygna The North Sea 30.71 Statoil 2000 2026 10) 0.8 Snorre The North Sea 33.28 Statoil 1992 2015 11) 35.6 Vigdis area The North Sea 41.50 Statoil 1997 2024 14.6 Tordis area The North Sea 41.50 Statoil 1994 2024 8.2

Total Operations

South 214.0

Average daily production Statoil's equity Licence in 2015 Business cluster Geographical area interest in % Operator On stream expiry date mboe/day

Partner Operated Fields Ormen Lange The Norwegian Sea 25.35 Shell 2007 2041 12) 47.8 Skarv The Norwegian Sea 36.17 BP Norge AS 2013 2033 13) 46.8 Ekofisk area The North Sea 7.60 ConocoPhillips 1971 2028 14.3 Marulk The North Sea 50.00 Eni Norge 2012 2025 13.2 Vilje The North Sea 28.85 Det Norske 2008 2021 4.0 Sigyn The North Sea 60.00 ExxonMobil 2002 2022 3.8 Ringhorne Øst The North Sea 14.82 ExxonMobil 2006 2030 1.7 Lundin Norway Edvard Grieg The North Sea 15.00 AS 2015 2029 0.4

Total Partner Operated Fields 131.9

Total 1,232.0

1) PL092 expires in 2020 and PL121 expires in 2022. 2) PL134B expires in 2027 and PL199 expires in 2033. 3) PL095 expires in 2024 and PL124 expires in 2025. 4) PL107 expires in 2021 and PL132 expires in 2023. 5) PL348 expires in 2029. 6) PL034 expires in 2020. PL053 expires in 2031 and PL190 in 2032. 7) PL120B expires in 2034 and PL050DS expires in 2023. 8) PL052 expires in 2020 and PL053 in 2031. 9) The 2015 Statoil farm down transaction with Repsol completed 31 December 2015 (From ownership interest 51% to 36% at Gudrun field) 10) PL037 expires in 2026 and PL089 expires in 2024. 11) PL089 expires in 2024 and PL057 expires in 2016. 12) PL209/250 expires in 2041 and PL208 expires in 2040. 13) PL212/262 expires in 2033 and PL159 expires in 2029.

Reported production per field for second quarter 2016 is shown in the table below: Equity Production volumes, mboe/day Statoil-operated fields Statoil share Liquid Gas Total Alve 85.00 % 3.7 5.3 8,9 Fram 1) 9.9 2.8 12.6 Gimle 65.13 % 0.5 0.4 1.0 Grane 2) 41.4 0.0 41.4 Gudrun 36.00 % 26.2 11.7 37.9 Gullfaks 51.00 % 49.2 36.8 86.0 Heidrun 13.04 % 7.7 1.6 9.4 Heimdal 3) 0.1 0.6 0.7 Huldra 19.88 % 0.0 0.0 0.0 Kristin 55.30 % 12.1 9.9 22.0 Kvitebjørn 39.55 % 11.8 41.7 53.6 Mikkel 43.97 % 7.2 10.2 17.4 Morvin 64.00 % 8.9 3.8 12.8 Njord 20.00 % 1.2 1.2 2.3 Norne 4) 12.1 1.7 13.8 Hyme 35.00 % 2.6 0.4 2.9 Oseberg 5) 59.2 17.1 76.3 Sleipner 6) 13.9 42.9 56.8 Snorre 7) 33.6 0.0 33.6 Snøhvit 36.79 % 9.1 39.1 48.2 Statfjord 8) 26.2 18.2 44.4 Tordis 41.50 % 10.8 0.0 10.8 Troll Gass 30.58 % 9.3 130.2 139.5 Troll Olje 30.58 % 38.4 0.0 38.4 Tyrihans 58.84 % 26.4 25.3 51.7 Valemon 53.78 % 2.5 27.1 29.7 Veslefrikk 18.00 % 2.1 1.2 3.3 Vigdis 41.50 % 13.2 0.4 13.5 Visund 53.20 % 32.8 23.7 56.5 Volve 59.60 % 4.5 0.4 4.9 Åsgard 34.57 % 36.0 62.3 98.3 Total Statoil-operated 512.5 516.2 1,028.7

Partner -operated fields Statoil share Liquid Gas Total Edvard Grieg 15.00 % 9.3 1.0 10.210) Vilje 28.85 % 4.7 0.0 4.7 Ekofisk 7.60 % 8.7 1.4 10.1 Enoch 11.78 % 0.1 0.0 0.1 Ormen Lange 9) 4.5 72.9 77.4 Ringhorne Øst 14.82 % 1.3 0.0 1.3 Sigyn 60.00 % 0.9 1.8 2.6 Skarv 36.17 % 21.2 25.8 47.0 Marulk 50.00 % 2.7 10.8 13.6 Goliat 35.00 % 15.4 0.0 15.4 Total partner-operated 68.8 113.7 182.5

Total Equity Production 581.38 630.0 1,211.3

1) Fram 45%, Fram H- North 49.2% 2) Grane changed ownership interest from 36.66% to 36.613% 20 January 2016. Make-up period from 1 February 2015 to end January 2017. For 2016: 36.0311%. Svalin 57% 3) Statoil share of the reservoir and production at Heimdal is 19.87 %. The ownership interest of the topside facilities is 29.443% 4) Norne 39.10%, Urd 63.95%, Skuld 63.95% 5) Oseberg 49.3%, Tune 50.0% 6) Sleipner Vest 58.35%, Sleipner Øst 59.60%, Gungne 62.00%. Gudrun changed ownership interest 1 January2016 from 56% to 36% 7) Snorre changed ownership interest 1January 2014 from 33.33% to 33.28%. Make-up period finalized 1 January 2016. 8) Statfjord Unit 44.34%, Statfjord Nord 21.88%, Statfjord Øst 31.69%, Sygna 30.71%. 9) Ormen Lange changed ownershare 1 July 2013 from 28.9169% to 25.342%. Make up period ended 15 February 2016 10) Second quarter reported production from Edvard Grieg is not affected by the swap with Lundin end of June 2016

9.2.2.2 Operations North The Norwegian Sea region is characterised by petroleum reserves located at water depths between 340 and 380 metres. In the Barents Sea the petroleum reserves are located at water depths between 310 and 340 meters. Main focus is to capitalise existing fields through profitable realisation of increased oil recovery and

successful implementation of new developments. The Norwegian Sea is a significant contributor to Statoil’s Equity production. There is still exploration potential in the area.

Snøhvit was the first field developed in the Barents Sea. It is one of the first major developments using onshore production facilities. All offshore installations are subsea. The natural gas is transported to shore and then processed at Statoil's LNG plant on Melkøya. The LNG is shipped to customers in Europe, Asia, North and South America in tankers. The CO2 in the feed-gas from Snøhvit and Albatross is removed due to freezing constraints in the process system. To reduce carbon dioxide emissions to the air the removed CO2 is liquefied, transported through a pipeline, and then injected into a storage reservoir in Snøhvit. The LNG plant has produced according to plan in 2015 and in 2016, with high production efficiency, improved HSE results and enhanced cost efficiency. The project Askeladd (formerly Snøhvit future phases) has been established to maintain a plateau production to feed the Hammerfest LNG plant. Early August 2016, the drilling of a new injection well for CO2 gas started. Next, a production well will be drilled to continue to fully utilize the LNG plant.

Norne is an oil field in the Norwegian Sea. The field has been developed using a floating production, storage and offloading vessel ("FPSO") connected to subsea templates. Alve, Marulk, Urd and Skuld are tie-in fields connected to the Norne FPSO.

The Åsgard field includes the Åsgard A production and storage ship for oil, the Åsgard B semi-submersible floating production platform for gas, and the Åsgard C storage vessel for condensate. In September 2015 Statoil started the world first subsea gas compressor on Åsgard. The compressor increases the Åsgard recovery rate and thereby extending the reservoirs’ productive lives. Mikkel and Morvin are tie-ins to Åsgard.

Tyrihans is a subsea field with five templates. The well stream of oil and gas is tied back to Kristin for processing. Tyrihans receives seawater injection from Kristin and gas injection from Åsgard B.

Kristin is a gas and condensate field. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir are among the highest of all developed fields on the NCS.

Heidrun is developed with a floating concrete tension leg platform. The oil is transferred to the floating storage unit, Heidrun B.

The Njord field is located in the Norwegian Sea and the field has been developed with a floating steel platform unit, Njord A, with both drilling and processing facilities. The subsea field Hyme is tied back to Njord A. Snilehorn is an oil discovery made in 2013 and is located about 15 kilometres east of the Njord field and the Snilehorn discovery is planned developed as a subsea tie-back to the Njord facilities.

Due to structural integrity issues on Njord A the project "Njord Future" is established to secure long term production for both the Njord and Hyme fields and to act as a tie-in host candidate for discoveries in the area. On 4 June 2016, the Njord field was temporary shut in, and both Njord A and Njord Bravo will be towed to shore during the third quarter of 2016 for upgrade.

9.2.2.3 Operations West Operation West produces approximately half of Statoil’s Equity Production in Norway. Its main focus is prolonging and increasing production through increased oil recovery, exploration and new field developments.

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

The Oseberg area includes the Oseberg Field Centre, Oseberg C, Oseberg East and Oseberg South production platforms. Oil and gas from the satellites are transported in pipelines to the Oseberg Field Centre for processing and transportation.

The Delta2 facilities project on Oseberg Field Centre was completed in 2015. Drilling operations related to the project have been on-going throughout 2015 and were finalised in January 2016. The PDO for the Oseberg Vestblanken 2 project was sanctioned by the Norwegian government on 9 June 2016 without any comments. The project consists of an unmanned wellhead platform with ten well slots. In addition, two existing subsea wells will be reused. DG424 is scheduled for second quarter 2018.

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

Drilling of the new Gullfaks South Increased Oil Recovery (GSO IOR) project wells is ongoing and operations on the satellites will continue with a mobile rig until September 2016.

The Gullfaks Rimfaksdalen project develops the Rutil reservoir through two gas producers drilled from one new standard 4-slot template. The PDO was submitted in 2014, and production start is expected in the third quarter of 2016.

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

The Valemon field is a gas and condensate field between Kvitebjørn and Gullfaks South. Valemon is built as a normally not manned, fixed steel platform with separation facilities for gas, condensate and water. The condensate is piped to Kvitebjørn for stabilisation and from there to the Mongstad refinery near Bergen.

Visund is an oil and gas field development that includes floating drilling, production and living quarter units and two subsea templates, in the northern and southern parts of the field.

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

The Heimdal platforms are a hub for the processing and distribution of gas to the European gas markets. The hub consists of an integrated steel platform and a riser platform. During 2015 Heimdal has plugged and abandoned its former production wells in the main reservoir. Heimdal started production in 2016 from one new well drilled from the modular rig which was temporarily installed for plugging and abandonment activity.

9.2.2.4 Operations South Operation South represents a mature oil and gas province. However, it still remains a significant contributor to Statoil’s Equity Production and new fields are under development in the area. Main focus in the area is to capitalise on existing fields through profitable realisation of increased oil potential and successful implementation of new developments.

Sleipner consists of the Sleipner East, Gungne and Sleipner West gas and condensate fields. The gas from Sleipner has a high level of CO2. This is extracted at the field and re-injected into a sand layer beneath the seabed and will reduce carbon dioxide emissions to the air. Sleipner also processes gas, condensate and oil from Gudrun, Volve and Sigyn. The Gina Krog field, currently under development, will also be tied back to Sleipner.

The Gudrun field is a separate steel jacket-based process platform for separation of oil and gas, with separate pipelines transporting gas and partly stabilised oil from Gudrun to Sleipner.

Statfjord has been developed using three fully integrated platforms supported by gravity-based structures with concrete storage cells and an offshore loading system. Statfjord North, Statfjord Øst and Sygna are satellite fields have all been developed using subsea templates tied back to Statfjord C.

24 Decision gate 4 – Decision to start operation

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

9.2.2.5 Partner-operated fields Partner-operated fields account for approximately 11% of Statoil's total oil and gas production on the NCS. The main producing fields are Ormen Lange, Skarv and Ekofisk. Statoil's partner operated fields NCS portfolio is organised under Operations South.

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

Skarv is an oil and gas field located in the Norwegian Sea, with BP as operator. The field development includes subsea production system connected to a floating production, storage and offloading vessel (FPSO).

Ekofisk is operated by ConocoPhillips. It consists of the Ekofisk, Eldfisk and Embla fields, and Tor. The Eldfisk II project delivered a new PDQ platform early 2015 that will serve as Eldfisk field center.

Edvard Grieg is an oil field located in the Utsira High Area. The field development includes a fixed steel jacket with processing and export facilities. Edvard Grieg is operated by Lundin. Production started on 28 November 2015 according to plan. On 3 May 2016, Statoil announced divestment of its entire 15% interest in the Edvard Grieg field on the NCS for an increased shareholding in Lundin Petroleum AB. The transaction was approved by Lundin Petroleum AB’s Extraordinary General Meeting 30 May 2016 and the transaction was closed in the end of June 2016.

Goliat is the first oil field to be developed in the Barents Sea. The field development includes subsea wells tied back to a circular floating production, storage and offloading vessel (FPSO). The oil is offloaded to shuttle tankers. The Goliat development is operated by Eni Norge and the production started up 12 March 2016.

9.2.3 Exploration on the NCS In addition to producing areas, Statoil operates a significant number of exploration licences. Exploration takes place in undeveloped frontier areas as well as near existing infrastructure and producing fields. The table below is updated as of 31 December 2015.

Number of Number of Number of New New licenses licenses licenses licenses licenses Square km Square km Change (NCS (Statoil (Statoil (Statoil (Statoil Area (NCS Total) (Statoil) vs 2014 Total) equity) operated) equity) operated)1

North Sea 43,928 13,884 (1,006) 304 125 95 9 7 Norwegian Sea 37,784 12,581 (1,681) 144 79 55 9 4 Barents Sea 32,998 13,802 (135) 63 31 19 1 - NCS total 114,710 40,267 (2,822) 511 235 169 19 11

1 This column lists the new licenses which officially were approved on 6 February 2015. Of the new licenses granted to Statoil as operator in 2015, eight of the APA 2014 licenses and the three other APAs were license expansions which are regarded as own licenses.

Statoil has continued high exploration activity on the NCS. An extensive drilling program in 2015 resulted in 21 completed wells, 25 of which 10 were discoveries. A total of 16 wells were Statoil operated. As of the end of July 2016 Statoil has completed ten wells, of which seven were discoveries. A total of eight wells were Statoil operated.

In January 2016, Statoil was awarded interests in 24 licences in the Awards in Predefined Areas (APA) round 2015 on the NCS, 13 of those as operator and 11 as partner. Statoil was awarded new licences in all three NCS provinces – North Sea, Norwegian Sea and the Barents Sea.

25 All numbers of wells in this Section are gross number of wells, i.e not taking into account Statoil’s working interest in the licenses.

In May 2016, Statoil was awarded interests in five licenses in the 23rd concession round on the NCS, four as operator and one as partner. The award covers five commitments wells – one in the vicinity of Statoil’s existing position, and four in the south-eastern part of the Barents Sea, providing access to interesting acreage in a new area on the NCS. South-East Barents Sea is the first new exploration acreage area opened on the NCS since 1994. Statoil and 15 other companies cooperate in the Barents Sea Exploration Collaboration (BaSEC) project to find common solutions for exploration operations in the Barents Sea and to ensure cost-effectiveness and good safety standards.

In general, Statoil’s exploration strategy on the NCS is reflected in its diverse exploration portfolio, which ranges from frontier drilling to infra-structure led exploration close to existing infrastructure.

The table below shows the gross number of exploratory wells drilled on the NCS in first seven months of 2016 and in the last three years:

As per end of 2015 2014 2013 July 2016

North Sea Statoil operated exploratory 8 11 11 11 Partner operated exploratory 1 3 7 10

Norwegian Sea Statoil operated exploratory 0 5 0 7 Partner operated exploratory 0 1 1 1

Barents Sea Statoil operated exploratory 0 0 9 2 Partner operated exploratory 1 1 1 4

Totals Exploratory 8 21 29 35 Exploration extension wells 2 3 2 7

In the North Sea, Statoil participated in 14 exploration wells during 2015 26 with seven discoveries. Statoil operated eleven of the exploration wells. In the Norwegian Sea, Statoil participated in six exploration wells. Statoil operated five of the exploration wells with three discoveries. There were no Statoil operated wells in 2015 in the Barents Sea. One partner operated well was completed in 2015. By the end of July 2016 Statoil has drilled nine exploration wells in the North Sea, eight Statoil operated with six discoveries. One partner operated well is currently ongoing. In addition one partner operated well is completed with a positive result in the Barents Sea.

26 All numbers of wells in this section are gross number of wells, i.e not taking into account Statoil’s working interest in the licenses.

9.2.4 Fields under development on the NCS 9.2.4.1 Main sanctioned development projects on the NCS and selected major pre-sanction projects The table below shows some key figures for Statoil’s major development projects on the NCS.

Sanctioned projects Operator Statoil's equity share Time of sanction Production start

Aasta Hansteen Statoil 51.00% 2013 2018 Johan Sverdrup Statoil 40.03% 2015 2019 Gina Krog Statoil 58.70% 2012 2017 Ivar Aasen Det Norske 41.47% 2012 2016 Martin Linge Total 19.00% 2011 2018

Johan Sverdrup is an oil discovery in the southern part of the North Sea, approximately 140 km west of Stavanger. A plan for development and operation was submitted in February 2015 and approved by the Norwegian authorities in August 2015.

Phase 1 of the development includes a field centre with four platforms and three water injection templates connected to the field centre via flowlines and umbilicals. Main power will be supplied from shore. Gas will be transported via a new gas pipeline to Statpipe and further to the Kårstø plant. Stabilised oil will be exported in a new pipeline to the Mongstad terminal. The drilling of the first well started early March 2016. The expected production start-up is in the fourth quarter of 2019. The investment costs for the first phase are currently estimated at NOK 99 billion (USD 12.1 billion). The Johan Sverdrup future phases include additional processing capacity to tie back and process the well streams from the not yet developed parts of the field to the east (Avaldsnes), south (Kvitsøy) and north (Geitungen). The full-field investment cost estimate has been reduced from a range of NOK 170-220 billion (USD 20.7-26.8 billion) to NOK 140-170 billion (USD 17.0-20.7 billion) since the PDO for phase 1 was submitted in February 2015. Statoil and its partners have also agreed on expanding the production capacity on Johan Sverdrup by expanding an extra processing platform on the field centre. The final investment decision and submission of PDO for full-field development are planned to be in the second half of 2018. Production start-up for full-field development is planned for 2020, in accordance with the PDO for phase 1 submitted in February 2015.

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

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

Johan Castberg is a vast oil discovery in the Norwegian Barents Sea. The development project includes oil discoveries made in April 2011 (Skrugard), January 2012 (Havis) and May 2014 (Drivis) in PL532, located in the Barents Sea, 240 km northwest of Hammerfest and 100 km north of the Snøhvit field. Johan Castberg is a mature project opportunity in this area, with a clearly defined timeline. In early 2016, the partners selected FPSO as the concept to be matured further towards the final investment decision currently scheduled for the end of 2017.

Utgard (previously Alfa Sentral) is a gas and condensate field in the North sea spanning the NCS/UKCS border and is located 21 km west of the Sleipner field centre. The field was discovered in 1982. On 9 August 2016, Statoil and its partners submitted the Plan for Development and Operation (PDO) and the Field Development Plan (FDP) to Norwegian and UK authorities. Production is expected to start at the end of 2019. The Utgard field development includes a standard subsea template and a 21 km pipeline routing the production from two wells to the Sleipner T platform. The gas will be exported through the Gassled system either to the UK or the

continent. The condensate will be transported through the existing Sleipner condensate pipeline to the Gassled facilities at Kårstø for processing and export.

On 19 August 2016, Statoil and its partners submitted the plan for development and operation of the Byrding (formerly Astero) oil and gas discovery to the MPE. Byrding will be developed as a subsea installation with one well, drilled from an existing well template on Fram H-Nord. Production is expected to start in the third quarter of 2017.

The Trestakk project is aimed at developing an oil discovery with some associated gas on Haltenbanken. The proposed development solution is a subsea tie-back to Åsgard A comprising one subsea template and one satellite.

For the Snorre 2040 expansion, Statoil is together with its partners progressing to mature a subsea solution development concept, including a tie back to Snorre A platform.

In the southern part of the North Sea, Statoil made in July 2012 a high impact gas and condensate discovery called King Lear. Statoil is the operator, and has a high working interest at 77.8%. King Lear is a deep, high pressure, high temperature discovery, and is consequently a challenging development with high well cost. Statoil is currently evaluating development solutions and tie-in possibilities for a potential around 2025.

Ivar Aasen is an oil and gas field located in the Utsira High Area. The development includes a fixed steel jacket platform with partial processing and living quarters tied in as a satellite to Edvard Grieg for further processing and export. The Ivar Aasen development is operated by Det norske, the operator expects production start-up in the fourth quarter of 2016.

Martin Linge is an oil and high pressure and high temperatures gas field, operated by Total, near the British sector in the North Sea. The development includes a fixed steel jacket platform with processing and export facilities. Electrical power will be supplied from Kollsnes. The operator expects production start-up in 2018.

9.2.4.2 Redevelopment on the NCS - Improved oil recovery (IOR) In 2015, Statoil started the world’s first subsea gas compression plant at the Åsgard field, the Smørbukk South Extension project, also in the Åsgard field, started production, and two new topside compressors on Troll A started operating. In the Tampen area, the Gullfaks Sør Oil IOR project (GSO) started production and Gullfaks B lifetime extension project, extending Gullfaks B drilling campaign until 2032, started operation.

Statoil will continue its efforts to maximise recovery from existing fields in 2016. So far, new IOR wells have been sanctioned on e.g. Kvitebjørn, Statfjord Nord, Statfjord Øst and Visund, and also the Tyrihans prolonged water- and gas injection projects have been sanctioned and will become operational in 2016.

This far, several IOR projects have been put into operation, e.g. The Oseberg Øst TSV, providing mud and cuttings handling system enabling Oseberg Øst to drill the wells necessary to develop the field.

The Gullfaks subsea compression project is the second largest subsea gas compression project being developed by Statoil on the NCS. Subsea gas compression will have a significant impact on the Gullfaks field as this technology, combined with conventional low-pressure production, is expected to lift the recovery rate from the Gullfaks South Brent reservoir from 62% to 74%.

The Ormen Lange onshore compression project being executed as part of the overall expansion of the Nyhamna facility to handle third-party gas entering the plant through the new Polarled pipeline. The two 37 MW onshore compressors are scheduled for start-up in July 2017.

The Polarled pipeline project is headed by Statoil and comprises a new gas pipeline from Aasta Hansteen to Nyhavna and modifications of the Nyhamna plant (operated by Shell). The 480-kilometre-long new gas pipeline from the Norwegian Sea to the Nyhamna processing plant will enable gas transport from areas without a current infrastructure.

These projects are all examples of Statoil’s efforts to maximise recovery from existing fields. They have also opened opportunities for technology application to realise volumes from other fields with similar conditions.

9.2.5 Decommissioning on the NCS Under the Norwegian Petroleum Act, the Norwegian government has imposed strict procedures for removal and disposal of offshore oil and gas installations. The Convention for the Protection of the Marine Environment of the Northeast Atlantic ("OSPAR") stipulates similar procedures.

Glitne ceased production in February 2013 and decommissioning of the field has been ongoing 2013-2015. Permanent plugging and abandonment of the seven wells completed in October 2014. All facilities/equipment were removed from the field in 2015. Safety zones in the area have been repealed and national maps updated.

Huldra ceased production in September 2014, after 13 years in production. Permanent plugging and abandonment of six wells is planned for 2016 and the plan is that the Huldra topside facilities will be removed in 2019.

Yttergryta is a subsea field with one production well that ceased production in 2013. Permanent plugging of the well was completed early in 2015.

In 2015 there were permanent plugging and abandonment operations at Statfjord Øst, Statfjord A, Sleipner and Tordis. In addition, Åsgard decommissioned part of the Midgard flowline loop in 2015.

In 2016, there has been permanent plugging and abandonment operations on Ekofisk, Statfjord and Volve.

On Heimdal a modular drilling rig has been successfully installed in order to plug and abandon all 12 former production wells at the Heimdal main reservoir. The plug and abandonment project started in the fourth quarter 2014, and is scheduled to be finalised by second quarter 2016.

9.2.6 Accessibility of the NCS On the NCS, the larger fields are typically developed as stand-alone units with one or several platforms or floating production and storage units combined with subsea well templates. Smaller fields close to existing infrastructure are often developed as satellites with subsea facilities and tied back to an existing host platform. There are a wide variety of facilities installed, depending on the size, complexity and location of the hydrocarbon accumulations.

From many of the fields on the NCS, the produced oil is loaded on to shuttle tankers at the field or host facilities and shipped directly to refineries or terminals from where it can be distributed to the market. There are also fields which the produced oil and other liquids (such as condensate or NGL) are transported to shore via pipelines, for instance from the Sleipner area in the North Sea.

Gas is mainly transported through the offshore pipeline system on the NCS which is the largest of its kind in the world. It extends a total of 8,100 kilometres and connects fields with processing facilities on the Norwegian mainland and with six landing points in France, Germany, Belgium and the UK.

Statoil is responsible for the technical operation of important parts of the Norwegian pipeline network on behalf of the state operator, Gassco.

Statoil has technical operating responsibility for Europe’s largest gas processing plant at Kårstø, north of Stavanger, and at the Kollsnes plant outside Bergen. Gassco is the operator of both of these processing plants. Both facilities play a key role in the treatment and transportation of gas from the NCS.

The process separates the wet components such as condensate, ethane, propane, butane and naphtha, which is shipped to customers around the world.

Dry gas (primarily methane) is transported in pipelines to customers in Europe.

The gas produced from the Snøhvit field in the Barents Sea, is sent ashore through a pipeline to Melkøya near Hammerfest. Here the gas is processed before being cooled down to liquid form and shipped to customers around the world.

The non-sanctioned discoveries in Johan Castberg are situated approx. 100 kilometres north of the Snøhvit- field in the Barents Sea. The partners are currently working on maturing a development tied into a floating production, storage and offloading vessel (FPSO), Alternative solutions for transport of the crude are studied, either directly to the market or an onshore terminal that could support multiple fields in the Barents Sea.

9.3 Development and Production International (DPI) 9.3.1 DPI overview Statoil is present in several of the most important oil and gas provinces in the world. The business areas encompassed in the DPI reporting segment are responsible for all development and production of oil and gas outside the NCS.

In 2015 and the first half of 2016, DPI has been engaged in production in 11 countries: Algeria, Angola, Azerbaijan, Brazil, Canada, Ireland, Nigeria, Russia, the UK, the US, and Venezuela. In 2015 and in first half 2016 DPI produced 37% of Statoil's total Equity Production of oil and gas.

Statoil has exploration licenses in North America (Canada and US), South America and sub-Saharan Africa (Angola, Brazil, Colombia, Mozambique, Nicaragua, Suriname, South Africa, Uruguay and Tanzania), North Africa (Algeria and Libya), Europe and Asia (Azerbaijan, Greenland, Indonesia, Ireland, Myanmar, Russia and the UK) as well as Oceania (Australia and New Zealand). The main development projects in which DPI is involved are in Brazil, Canada, the UK, and the US.

Statoil also has representative offices in Kazakhstan, Mexico and United Arab Emirates.

Statoil closed its office in Iran in 2013 but has residual payment obligations for tax and social security under legacy contracts in Iran. These will be dealt with in accordance with all applicable sanctions.

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

Key events and portfolio developments in the period from January 2016 and up to 26 August 2016:

• At the Capital Market Update on 4 February 2016, Statoil communicated a three-year transformation plan for the US business. In 2014, Statoil estimated that the US business would have needed a WTI oil price of USD 90/bbl to show a positive net operating profit. In 2015, the price required was reduced to around USD 80/bbl. The ambition is to deliver positive net operating income in 2018 at a WTI oil price of USD 50/bbl. This ambition relates to total onshore and offshore activities, based on offshore projects either producing or being developed and further development of the onshore business. To achieve this ambition, Statoil will step up improvement initiatives across the organization, with a particular focus on operational efficiency and cost reductions, including reducing onshore opex per boe by 25% and selling, general and administration costs by 20% per boe compared with 2015 level.

• A similar ambition was communicated at the Capital Market Update on 4 February 2016 for the international business outside of the US. Statoil’s ambition, to achieve positive net operating income in 2016 at a Brent oil price of around USD 46/bbl27. Statoil aims to deliver positive net operating income in 2018 at a Brent oil price of USD 40-43/bbl. To achieve this, Statoil and its partners will continue to improve performance and efficiency, reduce costs and renegotiate contracts to capture market effects, optimize transportation and logistics, further improve drilling operations and continue to work closely with its partners throughout its non US international portfolio.

• In February 2016, the In Salah Gas joint venture announced the start- up of operations at the In Salah Southern Fields project in Algeria.

• In February 2016, Statoil acquired 15% working interest from operator Total in offshore exploration block 14 in Uruguay. The partnership completed the drilling of the Raya prospect in June 2016.

• In February 2016, Statoil acquired 35% working interest from operator Tullow in offshore exploration block 15 in Uruguay.

27 Before exploration expenses

• In February 2016, Statoil agreed with OMV to acquire a 30% working interest in Petroleum Exploration Permit 57073 in New Zealand. OMV will remain the operator with a 70% working interest.

• In March 2016, Statoil completed the purchase of 31% of the UK continental shelf licence (P312) of Utgard, previously named Alfa Sentral, a field which spans the UK-Norway maritime border. On 1 June 2016, Statoil agreed to acquire JX Nippon’s 45% equity share in, and operatorship of UK licence P312, and on 22 June 2016 the transaction was completed. Through this transaction Statoil now has a 100% interest in UK P312 which, with Norwegian Continental Shelf licence PL046, comprises the Utgard field.

• In March 2016, Statoil was awarded six licensing options in Ireland’s 2015 Atlantic Margin Licensing Round. Statoil will be the operator of four licensing options and partner in two. BM-

• In April 2016, Statoil together with operator Repsol Sinopec and partner Petrobras completed the last appraisal well Gavea A1 in block BM-C-33 in the Campos basin in Brazil.

• In April 2016, Julia oil field's first oil was produced. Julia is located in the Walker Ridge area of the Gulf of Mexico near Jack and St Malo. Statoil has a 50% working interest.

• In May 2016, it was announced that Statoil had agreed to divest its operated properties in the Marcellus area onshore US to EQT Corporation for USD 407 million in cash. The transaction was completed in July 2016.

• In May 2016, Statoil entered into a binding letter agreement regarding two exploration licenses in the Thrace region in the north-western part of Turkey. Statoil will have a 50% interest in the Banarli licenses, while the operator Valeura Energy Inc. will keep the remaining 50%. The agreement is pending governmental approval, which is expected by the end of September 2016.

• In May 2016, Statoil finalized a 19-month exploration drilling program offshore New Foundland. The purpose of the drilling program was to increase the robustness of the Bay du Nord project and to test new areas of the Flemish Pass Basin.

• On 29 July 2016, Statoil announced acquisition of Petrobras’ 66% operated interest in Brazilian offshore licence (BM-S-8) in the Santos Basin containing a substantial part of the Carcará pre-salt ("Pre-Salt")28 oil discovery, one of the ten largest oil discoveries in the world recent years. 29 Statoil estimates the recoverable volumes within the BM-S-8 licence to be in the range of 700-1300 million boe. The partners in the BM-S-8 licence are Petrogal Brasil (14%), Barra Energia (10%) and Queiroz Galvao E&P (10%). The total consideration for the acquisition is USD 2.5 billion. Half of it will be paid upon closing of the transaction, with the remainder being paid when certain milestones have been met. These are partly related to the licence award, but mainly to the future unitisation of Carcará. The effective date for the transaction is 1 July 2016. Closing is subject to customary conditions, including partners’ and government approval. The licence is in its final exploration phase with one remaining exploration commitment well to be drilled by 2018.

• On 1 August 2016, Statoil announced a further sale of non-core assets in its US onshore portfolio in the US state of West Virginia to Antero Resources Corporation for approximately USD 96 million in cash. Statoil’s net acreage included in this transaction is approximately 11,500 acreas and its average working interest in 19%. The transaction is expected to close by third quarter of 2016, subject to certain conditions being met.

28 Pre-salt is a generic term that defines all rocks deposited prior to a regional salt layer accumulated during the opening of the South Atlantic Ocean. Some of these deposits contain large amounts of high quality hydrocarbons in a unique carbonate reservoir with excellent properties and very high productivity, such as the giant fields discovered in Santos and Campos basins in Brazil. The salt that covers this reservoir acts as seal and insulation. In the Brazilian deep water margin, deposition of this pre-salt reservoir layer covers around 150.000 square kilometers. 29 Source: IHS Energy database extracted 10 August 2016, payable source.

9.3.2 International production Statoil's Entitlement Production outside Norway was about 32% of Statoil's total Entitlement Production in 2015 and in the first half of 2016. The following table shows DPI's average daily Entitlement Production of liquids and natural gas for the years ending 31 December 2015, 2014 and 2013. Entitlement Production figures are after deductions for production sharing and profit sharing. For US assets Entitlement Production are expressed net of royalty interests. For all other countries royalties paid in-cash are included in Entitlement Production and royalties payable in-kind are excluded.

For the year ended 31 December Entitlement Production 2015 2014 2013

Oil and NGL (mboe per day) 436 383 354 Natural gas (mmcm per day) 23 26 23 Total (mboe per day) 580 546 502

The table below provides information about the fields that contributed to production in 2015.

Average daily Average daily Statoil's Equity Entitlement equity On Licence Production Production Field interest in % Operator stream expiry date mboe/day mboe/day

North America 282.3 239.7 US: Marcellus 1) Varies Statoil/others 2008 HBP2) 115.7 96.9 US: Bakken 1) Varies Statoil/others 2011 HBP2) 61.6 49.3 US: Eagle Ford 1) Varies Statoil 2010 HBP2) 34.7 26.6 US: Tahiti 25.00 Chevron 2009 HBP2) 16.9 13.9 US: Caesar Tonga 23.55 Anadarko 2012 HBP2) 9.1 8.7 US: St. Malo 21.50 Chevron 2014 HBP2) 7.6 7.6 US: Jack 25.00 Chevron 2014 HBP2) 6.6 6.6 Canada: Leismer Demo 100.00 Statoil 2010 HBP2) 19.9 19.9 Canada: Terra Nova 15.00 Suncor 2002 2022 5.4 5.4 Canada: Hibernia/Hibernia southern extension3) Varies HMDC 1997 2027 4.8 4.8

South America 43.5 43.5 Brazil: Peregrino 60.00 Statoil 2011 2034 43.5 43.5

Sub-Saharan Africa 273.3 197.8 Angola, Block 17 23.33 Total 2001 2022-344) 161.9 113.9 Angola, Block 15 13.33 ExxonMobil 2004 2026-324) 41.8 22.6 Angola, Block 31 13.33 BP 2012 2031 20.9 19.0 Angola: Block 4/055) 20.00 Sonangol P&P 2009 2026 1.4 1.3 Nigeria: Agbami 20.21 Chevron 2008 2024 47.3 41.0

North Africa 49.6 43.6 Algeria: In Salah 31.85 Sonatrach/BP/Statoil 2004 2027 32.5 30.6 Algeria: In Amenas 45.90 Sonatrach/BP/Statoil 2006 2022 17.1 13.3 Libya: Mabruk 12.50 Mabruk Oil Operations 1995 2033 0.0 (0.0)6) Libya: Murzuq 10.00 Akakus Oil Operations 2003 2033 0.0 (0.2)6)

Europe and Asia 78.3 43.9

Azerbaijan: ACG 8.56 BP 1997 2024 54.3 24.2 Azerbaijan: Shah Deniz 7) 15.50 BP 2006 2041 12.0 10.0 Russia: Kharyaga 30.00 Total 1999 2032 9.4 7.1 UK: Alba 17.00 Chevron 1994 2018 2.5 2.5 UK: Jupiter 30.00 ConocoPhillips 1995 HBP2) 0.1 0.1 Ireland: Corrib8) 36.50 Shell 2015 2031 0.0 0.0

Total Development and Production International (DPI) 727.0 568.5

Equity accounted production Venezuela: Petrocedeño9) 9.68 Petrocedeño 2008 2033 11.6 11.6

Total Development and Production International (DPI) including share of equity accounted production 738.7 580.2

1) Statoil’s actual working interest can vary depending on wells and area 2) Held by Production (HBP): A company’s right to own and operate an oil and gas lease is perpetuated beyond its original primary term, as long thereafter as oil and gas is produced in paying quantities. In the case of Canada, besides continue being in production status, other

regulatory requirements must be met 3) Statoil's working interests are 5.0% in Hibernia and 9.0% in Hibernia southern extension 4) Varies by field 5) Statoil relinquished Block 4/05 in September 2015 6) Zero production in 2015, adjustment of 2014 volume 7) Statoil divested the asset on 30 April 2015 8) New gas field which started production on 30 December 2015

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

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

Average daily Average daily Equity Entitlement Production Country Production mboe/day1) mboe/day

North America 282.3 239.7 US 252.2 209.6 Canada 30.1 30.1

South America 43.5 43.5 Brazil 43.5 43.5

Sub-Saharan Africa 273.3 197.8 Angola 226.0 156.8 Nigeria 47.3 41.0

North Africa 49.6 43.6 Algeria 49.6 43.9 Libya 0.0 -0.3

Europe and Asia 78.3 43.9 Azerbaijan 66.3 34.2 Russia 9.4 7.1 UK 2.6 2.6

Total Development and Production International (DPI) 727.0 568.5

Equity accounted production Venezuela: Petrocedeño2) 11.6 11.6

Total Development and Production International (DPI) including share of equity accounted production 738.7 580.2

1) In PSA countries Statoil's share of capital expenditures and operational expenses are computed on the basis of equity production. 2) Petrocedeño is accounted for pursuant to the equity accounting method.

Reported Equity Production per field for second quarter 2016 is shown in the table below: Equity Production volumes, mboe/day

Field Statoil share Liquid Gas Total

ACG 8.56 % 56.4 56.4 Agbami 20.21 % 49.4 49.4 Alba 17.00 % 3.1 3.1 Bakken Varies 44.0 5.1 49.1 Block 15, Angola1) 13.33 % 42.9 42.9 Block 17, Angola2) 23.33 % 151.7 151.7 Block 31, Angola3) 13.33 % 20.1 20.1 Caesar Tonga 23.55 % 11.1 1.4 12.5 Corrib 36.50 % 16.5 16.5 Eagle Ford Varies 27.1 15.8 42.9 Heidelberg 12.00 % 1.2 0.1 1.3 Hibernia 5.00 % 3.9 3.9 Hibernia South 9.00 % 4.2 4.2 In Amenas 45.90 % 16.7 16.7 In Salah 31.85 % 40.6 40.6

Jack 25.00 % 8.9 0.2 9.1 Julia 50.00 % 4.4 0.0 4.4 Jupiter 30.00 % 0.1 0.1 Kharyaga 30.00 % 8.5 8.5 Leismer Demo 100.00 % 17.2 17.2 Marcellus Varies 13.7 108.8 122.5 Peregrino 60.00 % 35.2 35.2 Petrocedeño4) 9.68 % 10.6 10.6 St.Malo 21.50 % 10.9 0.2 11.1 Terra Nova 15.00 % 2.1 2.1 Tahiti 25.00 % 14.8 0.9 15.7 Total 558.0 189.8 747.8 1) Production on fields Kizomba A, Kizomba B, Kizomba Sattelites Phase 1&2, Marimba, Mondo and Saxi Batuque. 2) Production on fields CLOV, Dalia, Girassol, Pazflor and Rosa. 3) Production on field PSVM. 4) *Petrocedeño is an associated company

The table below provides information about production per country in for the second quarter 2016:

Average daily equity production Country mboe/day

North America 296.1 US 268.6 Canada 27.5

South America 35.2 Brazil 35.2

Sub-Saharan Africa 264.0 Angola 214.6 Nigeria 49.4

North Africa 57.3 Algeria 57.3 Libya 0.0

Europe and Asia 84.6 Azerbaijan 56.4 Ireland 16.5 Russia 8.5 UK 3.2

Total Development and Production International (DPI) 737.2

Equity accounted production Venezuela: Petrocedeño 1) 10.6

Total Development and Production International (DPI) including share of equity accounted production 747.8

1) Petrocedeño is accounted for pursuant to the equity accounting method.

The following sections provide information about the main producing assets internationally.

9.3.2.1 North America Production in North America comprises the US and Canada.

US Statoil is positioned in the fast-growing US onshore oil and gas industry. Statoil has had strong growth in production within US shale since entering the first play in 2008.

Statoil entered the Marcellus shale gas play, located in the Appalachian region in north east US, in 2008 through a partnership with Chesapeake Energy Corporation, acquiring 32.5% of Chesapeake's 1.8 million acres in Marcellus. Statoil has continued to acquire and optimize the acreage within the play, with a net acreage position of 410,000 acres. Over the last two years Statoil has optimised its Marcellus portfolio by divesting some of its non-core acreage. These divestments allow capital to be focused on core activities in Statoil. In December 2014, Statoil agreed to reduce its working interest in its non-operated southern Marcellus asset from 29% to 23% in a USD 394 million transaction with Southwestern Energy. In May 2016, Statoil announced that it has agreed to divest its operated properties in Marcellus West Virginia to EQT Corporation for USD 407 million in cash. Statoil retains its operated properties in the US state of Ohio and its non-operated Marcellus positions. The transaction was completed in July 2016.

On 1 August 2016 Statoil announced a further sale of non-core assets in its US onshore portfolio in West Virginia to Antero Resources Corporation for approximately USD 96 million in cash. Statoil’s net acreage included in this transaction is approximately 11,500 acres and its average working interest is 19%. The transaction is expected to close by third quarter of 2016, subject to certain conditions being met.

Statoil entered the Eagle Ford shale formation located in southwest Texas in 2010. Through agreements with Enduring Resources LLC, Common Resources and Talisman Energy Inc., Statoil acquired 67,000 net acres. In 2013, Statoil became operator for 50% of the Eagle Ford acreage and took over full operatorship in 2016 as part of a global transaction in December 2015 with Repsol, which acquired Talisman in May 2015. Statoil increased its working interest to 63% representing an addition of 15,000 net acres for a total of 72,000 leaseholds. Statoil's joint venture partner, Repsol, continues to hold 37% working interest.

Statoil entered the Bakken tight oil play through the acquisition of Brigham Exploration Company in December 2011. Statoil's net acreage position in Bakken and Three Forks shale formation at the end of 2015 was 249,000 acres.

The following table displays the expiration profile for Statoil’s US onshore acreage for which HBP requirements so far are not satisfied and where the leaseholds will expire if drilling is not performed:

Bakken Eagle Ford Marcellus 30 Net Acreage per 30.06.2016 249,000 71,000 344,000 Expiration in 2016 0.2% 0.4% 5.6% Expiration in 2017 3.5% 1.9% 13.5% Expiration in 2018 and beyond 0.0% 0.6% 11.6%

These figures are subject to change as Statoil or its partners continue to drill wells, extend leases in desired areas, and buy, sell, or trade acreage.

Statoil’s onshore business plans are based on a continuous evaluation of the acreage in all assets and the development plans for acreage in its portfolio are based on a large number of factors.

30 The 23,099.83 net acres in New York will expire due to the fracking moratorium as there will be no opportunity to HBP and Statoil does not plan to pay for extensions of the lease term. These acres are not included in the expiration numbers above as they have been excluded already in Statoil's current business plans.

The following net acreage figures represent the decrease per asset for 2014 and 2015 based on the data contained in Form 20-F. This represents acreage that has expired and also accounts for additional acreage acquired through new infill or bolt on leasing and trades:

2014 2015 Bakken 47,000 16,000 Marcellus (does not include sale to EQT closed in July) 92,000 109,000 Eagle Ford 9,000 Added 13,000 (Repsol acquisition)

In the first half of 2016, approximately 62,500 net acres of Marcellus operated acreage in West Virginia were divested to EQT Corporation and 11,500 net acres of Marcellus non operated acreage in West Virginia were divested to Antero Resources Corporation.

Drilling plans and amount of completed wells will vary pending on price level in the market, cost of drilling and completions and portfolio considerations. Primarily driven by current oil and gas price level, the activity level in the onshore in 2015 and 2016 is reduced significantly when compared to the last few years. There have also been significant operational improvements in the US onshore portfolio in this period, among others reducing time and cost to drill and complete wells.

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

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

• The Caesar Tonga oil field is located in the Green Canyon area. As of 31 December 2015, there were six producing wells tied back to the Anadarko-operated Constitution spar host, and additional production wells will be phased in over time.

• The Jack and St. Malo oil fields are located in the Walker Ridge area. The fields are subsea tie-backs to the Chevron operated Walker Ridge Regional Host facility. The first production was achieved in December 2014. As of 31 December 2015, there were three wells producing on Jack and three wells producing for St. Malo. Additional production wells will be phased in over time.

• The Heidelberg oil field lies south of the Tahiti-Caesar Tonga trend of Miocene fields in Green Canyon. Heidelberg first oil was achieved on 14 January 2016.

• The Julia oil field is located in the Walker Ridge area of the Gulf of Mexico near Jack and St Malo, and is developed with subsea wells tied back to the shared JSM host facility. The first oil was achieved in April 2016.

Canada Statoil entered the Alberta oil sands in 2007 through an acquisition of North American Oil Sands Corporation.

In May, 2014, Statoil and PTTEP completed a transaction to divide their respective interests in the Kai Kos Dehseh (KKD) oil sands project with an effective date of 1 January 2013.

Following the transaction with PTTEP, Statoil continues as operator and 100% working interest owner for the Leismer and Corner projects which together comprise 123,200 net acres of oil sands leases in Alberta. The Leismer Demonstration Plant (LDP) is the first phase of the KKD development and has been in operation since 2010. The in-situ technology known as SAGD (steam assisted gravity drainage), injects steam into the oil bearing formation to recover bitumen which is then pumped to the surface. Further oil sands development could involve expanding production capacity of the Leismer facility and/or the greenfield development of the Corner project. At this time, there are no near term plans to further develop either project.

In addition, 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, Hibernia and Hibernia Southern Extension. In

December 2015, Statoil's ownership interest in Hibernia Southern Extension was reduced from 10.5% to 9.0% due to a redetermination process.

9.3.2.2 South America Statoil's production activities in South America comprise the Peregrino operatorship in Brazil and the Petrocedeño project in Venezuela.

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

Venezuela Petrocedeño produces extra-heavy crude oil from the Junin area in the Orinoco Belt. The oil is transported through pipeline to a plant at the Jose Industrial Complex at the coast nearby Puerta La Cruz where it is upgraded into a light crude and exported.

9.3.2.3 Sub-Saharan Africa Angola The deep water blocks 17, 15, 31 and 4/05 contributed with 40% of Statoil’s equity liquid production outside Norway in 2015. Each block is governed by PSAs which set out the rights and obligations of the Parties, including mechanisms for sharing of the production with the Angolan state oil company Sonangol.

Block 17 comprises production from four FPSOs; CLOV, Dalia, Girassol and Pazflor.

Block 15 has production from four FPSOs: Kizomba A, Kizomba B, Kizomba C-Mondo, and Kizomba C-Saxi Batuque. In April 2015, the Kizomba Satellites phase 2 project, which consists of the fields Bavuka, Kakocha, and Mondo South started production. The fields are developed with subsea wells and infrastructure tied back to the Kizomba B and Mondo FPSO vessels.

Block 31 has production from the PSVM FPSO.

Statoil had production from the Gimboa FPSO on Block 4/05 until Statoil exited the Block in September 2015.

The FPSOs serve as production hubs and receive oil from a large number of wells and more than one field each. In 2015 and 2016, new wells were added and set into production on Block 15, Block 17 and Block 31.

Nigeria In Nigeria, Statoil has a 20.2% working interest in the Agbami deep water field which is located 110 km off the coast of the Central Niger Delta region. The field is developed with subsea wells connected to an FPSO. The Agbami field straddles the two licenses OML 127 and OML 128 and is operated by Chevron under a Unit Agreement. Statoil has 53.85% working interest in OML 128.

Through its ownership in OML 128 in Nigeria, Statoil is party to an ownership interest redetermination process for the Agbami field. In October 2015 Statoil received the expert’s final ruling which implies a reduction of 5.17 percentage points in Statoil’s equity interest in the field from 20.21% to 15.04%. In 2013, Statoil initiated arbitration proceedings to set aside interim decisions made by the expert in the redetermination process, but this was declined by the arbitration tribunal in its November 2015 judgment. Statoil has initiated proceedings before the Federal High Court in Lagos to set aside the arbitration award, and also initiated a new arbitration to set aside the expert’s final ruling. As of 31 December 2015 Statoil has made a provision of NOK 9.5 billion (USD 1.2 billion), net of tax, which reflects a reduction of 5.17 percentage points in Statoil’s equity interest in the Agbami field.

9.3.2.4 North Africa Algeria The In Salah onshore gas development, in which Statoil has a working interest of 31.85%, is Algeria's third- largest gas development. A PSA including mechanisms for revenue sharing, governs the rights and obligations of the Parties and establishes a joint operatorship between Sonatrach, BP and Statoil.

In February 2016, the In Salah Gas joint venture announced the introduction of gas in the In Salah Southern Fields processing facilities. Gas export from the project started in March. This project, which is led by Statoil on behalf of the Joint Venture, will mature the remaining four discoveries into production. The southern fields (Gour Mahmoud, In Salah, Garet el Befinat and Hassi Moumene) will tie in to existing facilities in the northern fields.

The In Amenas onshore development is the fourth-largest gas development in Algeria. It also contains significant liquid volumes. The facilities are operated through a joint operatorship between Sonatrach, BP and Statoil, where Statoil's share of financing the investments (working interest) is 45.9%. A PSA, including mechanisms for revenue sharing, governs the rights and obligations of the Parties and establishes a joint operatorship between Sonatrach, BP and Statoil.

The In Amenas plant has between April 2013 and July 2016 produced from two out of three trains. The production has been relatively stable. The third train, which also was damaged in the January 2013 terrorist attack, restarted in July 2016. The train will not add new production before new compressors are completed later this year.

Libya There has not been any oil production from the Mabruk or the Murzuq assets in 2015 and 2016 due to the security situation in the country.

9.3.2.5 Europe and Asia Statoil's production in Europe and Asia encompasses Azerbaijan, Russia, the United Kingdom and Ireland.

Azerbaijan The Azeri-Chirag-Gunashli (ACG) oil field in the Caspian Sea has production from 6 fixed platforms. The oil is transported through pipelines to the Sangachal onshore terminal near Baku. From the terminal the oil is exported to the world markets.

Statoil has an 8.7% stake in the 1,760 km Baku-Tbilisi-Ceyhan (BTC) oil pipeline that is used to transport ACG oil to the southern Turkish port of Ceyhan.

In April 2015, Statoil completed the sale of its remaining 15.5% working interest in Shah Deniz and the South Caucasus Pipeline (SCP) to the Malaysian oil and gas company PETRONAS.

Russia The Kharyaga oil field is located onshore in the Timan Pechora basin in north-west Russia. The field is governed by a PSA. In July 2016 Total announced a transfer of 20% working interest and operatorship of Kharyaga field to the Russian company Zarubezhneft. The changes are effective from 1 August 2016.

United Kingdom The Alba oil field is located in the central part of the UK North Sea. Jupiter is a gas field located in the southern part of the UK North Sea. The decommissioning of the Jupiter wells is planned to start in the second half of 2016.

Ireland In December 2015 production started on Corrib gas field off Ireland’s northwest coast. Corrib consists of a subsea development with a pipeline to an onshore processing terminal from which gas will be transported to the Irish market. The onshore processing terminal is located approximately 9 km inland.

9.3.3 International exploration Statoil continued with significant international exploration activity in 2015 and the first half of 2016 and accessed new acreage in Russia, Mozambique, Nicaragua, Flemish Pass basin and Nova Scotia in East Coast Canada, South Africa Uruguay, Ireland, New Zealand, Turkey and Brazil. The accesses of new acreages in Mozambique, Turkey and Brazil are subject to governmental approval.

In 2015, Statoil carried out significant international exploration activity, as is shown by the Statoil's involvement in 18 completed wells (including both Statoil-operated and partner-operated activities). Eight wells (exploration and appraisal) were announced as discoveries in the period, including the Piri 2, Tangawizi 2 and Mdalasini (Statoil-operated) discoveries in Tanzania. As of the end of July 2016 Statoil has been involved in eight completed wells (including both Statoil-operated and partner-operated activities) of which one well has been announced as a discovery: Baccalieu in Canada.

The table below shows the gross number of exploratory wells drilled internationally in the first seven months of 2016 and in the last three years.

As per end of July 2016 2015 2014 2013

North America - Statoil operated 5 8 3 7 - Partner operated 0 0 0 4 South America/sub-Saharan Africa - Statoil operated 0 3 8 6 - Partner operated 2 5 9 4 North Africa - Statoil operated 0 0 0 0 - Partner operated 0 0 0 1 Europe and Asia - Statoil operated 0 2 2 0 - Partner operated 1 0 1 2

Total 8 18 23 24

The regions where Statoil has exploration activity are presented below.

North America US In 2015 Statoil operated five wells in the Gulf of Mexico (Yeti-1, Yeti Side track, Yeti Appraisal, Thorvald-1 and Power Nap). Yeti-1 and side-track was a discovery. The Yeti appraisal well has confirmed the discovery made by the two first wells, and the full Yeti discovery is now under evaluation. Power Nap was ongoing at year end and is currently under evaluation.

Statoil cancelled the contract for the Discoverer Americas rig in December 2015. Statoil was in the current environment unable to secure additional activity for the rig for the remainder of the contract period, ending in May 2016.

Canada The Bay du Nord discovery (EL1112) has advanced Flemish Pass to become a core area in Statoil’s global exploration portfolio. Statoil continues to assess the feasibility of a development in this area. A better understanding of the resource and economics of the region, through activities such as the recently completed drilling program, is required before a decision for a commercial development can be made.

In May 2016, Statoil, along with partners, finalized a 19-month exploration drilling program offshore Newfoundland. The drilling program included four exploration wells in close vicinity of the 2013 Bay du Nord discovery, as well as three appraisal wells on the discovery. In addition, two exploration wells were drilled in areas outside the Bay du Nord discovery. The drilling program has resulted in two discoveries of oil at the Bay de Verde and Baccalieu prospects in the Bay du Nord area. Bay de Verde was completed in 2015. The appraisal and near-field exploration of the Bay du Nord discovery has reduced key reservoir uncertainties. Statoil’s assessment of the commercial potential of the Bay du Nord discovery is ongoing.

Statoil and its partners were the successful bidders for six exploration licences in the Flemish Pass Basin, offshore Newfoundland, and two licences offshore Nova Scotia in East Coast Canada in 2015. Statoil will operate seven of the eight leases awarded.

South America and sub-Saharan Africa Angola Statoil acquired an acreage position in the Pre-Salt play of the Kwanza Basin in 2011 with the operatorship in Block 38 and 39 and a partner position in Blocks 22, 25 and 40. The work program included eight commitment wells, two Statoil operated and six partner operated. So far six wells have been completed, including the two Statoil operated wells (2014). In 2015 two partner operated wells were drilled, Umbundu in block 40, Catchimanha in Block 22. Two partner operated commitment wells remain. The partnership is updating the regional understanding in Kwanza, integrating all well results and evaluating all possible plays in the two blocks to propose a way forward to the authorities. The two Statoil operated wells did not result in commercial discoveries and Statoil sees limited potential in the Statoil operated acreage. Costs related to this activity are also being reduced accordingly.

Brazil All exploratory well operations during 2015 were conducted on BM-C-33 license as part of Pão de Açucar and Seat appraisal activities. The Pão de Açucar discovery was fully evaluated by drilling two wells (PdA-A1 and PdA-A2) and performing a successful drill stem test ("DST") on PdA-A2. The Seat-2 well was re-entered to perform a DST. In April 2016, the last appraisal well in BM-C-33, Gavea A1 was completed with successful drill stem test (DST). The well encountered a hydrocarbon column of 175 meters. The consortium will now evaluate the sub-surface data and assess lean and cost-effective developments projects. In agreement with its licence partners, Statoil will assume operatorship of the BM-C-33 licence subject to receiving government approval.

On 29 July 2016 Statoil announced acquisition of Petrobras’ 66% operated interest in Brazilian offshore licence (BM-S-8) in the Santos Basin containing a substantial part of the Carcará Pre-Salt oil discovery, one of the ten largest oil discoveries in the world recent years. 31 Carcará was discovered in 2012, on the geological trend of the nearby Lula field and Libra area. One discovery has been made to date on the BM-S-8 block whereof an Oil Column32 of several hundred meters were detected. Two appraisal wells were drilled in 2015 confirming the discovery. It is a world-class discovery of high-quality oil of around 30° API and with associated gas in a thick reservoir with excellent properties. The total consideration for the acquisition is USD 2.5 billion. Half of it will be paid upon closing of the transaction, with the remainder being paid when certain milestones have been met. These are partly related to the licence award, but mainly to the future unitisation of Carcará. The effective date for the transaction is 1 July 2016. The expected closing of the transaction is around year end 2016. Closing is subject to customary conditions, including partners’ and government approval. In addition to the Carcará discovery, BM-S-8 holds exploration upside that may significantly increase its resource base. The licence is in its final exploration phase. There is currently no infrastructure in place in the license. Further plans for investment decision as well as development concept will be worked on post the closing of the transaction. Remaining work commitment in the block, prior to declaration of commerciality in 2018, consist of one exploration well and one well test.

Colombia Statoil has accessed three licences in 2014, representing access in relatively frontier acreage. In the COL-4 licence, an environmental and social impact study has been completed.

Statoil farmed-in33 to a 10% equity share in the Tayrona licence and a 20% share in the Gua Off licence in 2014. The Orca-1 well in the Tayrona licence was announced as a gas discovery in 2014.

31 Source: IHS Energy database extracted 10 August 2016, payable source. 32 Oil cColumn: The column height of a segment is the vertical distance from the shallowest depth of the structure /reservoir to the oil water contact 33 Farm-in is a process whereby a company joins another company or joint venture participating in a block or field. The company farming in is granted a working interest in the field or block in return for cash/or carry through an exploration programme.

Uruguay In February 2016, Statoil acquired 15% working interest from operator Total in offshore exploration block 14 in Uruguay. Total has acquired new 3D seismic data covering the block. The partnership completed the drilling of the Raya prospect in June 2016.

In February 2016, Statoil acquired 35% equity interest from operator Tullow in offshore exploration block 15 in Uruguay. The other partner is Inpex with 30%.

Mozambique The 5th licence round was announced during the third quarter of 2015. Statoil together with partners submitted a winning bid in the A5-A block located in the Angoche area. Eni Mozambico is the operator of the joint venture with 34% working interest. Statoil’s equity is 25.5%. Final award is expected in 2016 subject to successful negotiations.

Tanzania The Tanzania drilling campaign using the Discoverer Americas rig was completed in 2015 after having drilled the Mdalasini prospect and the Tangawizi-2 appraisal well. The discoveries of natural gas in Mdalasini-1, Piri-1, Piri-2 and Giligiliani-1 have increased the total in-place volumes in Block 2. There is no infrastructure in place for Block 2 and the current plan is to develop the discoveries with a subsea to shore solution and an onshore LNG plant together with the partners in Block 1 and 4. The discovery is still in an early and immature stage, with detailed cost estimates and timelines yet to be defined.

South Africa Statoil completed a farm-in transaction in October 2015 with ExxonMobil acquiring a 35% interest in the ER 12/3/154 Tugela South Exploration Right. The operator is Exxon with 40% equity. The farm-in represents a country entry for Statoil into South Africa. Statoil intends to participate at an early phase of exploration with a step-wise exploration programme.

Nicaragua In 2015, Statoil together with partner Empresa Nicaraguense del Petroleo (Petronic) was awarded four licences offshore the Nicaraguan Pacific. Statoil is the operator with 85% equity with the Petronic holding the remaining equity. 2D seismic data has been acquired and processed during 2015 and subsurface studies are underway.

Algeria Statoil and Shell were awarded the Timissit licence in the Berkin basin onshore Algeria in September 2014. Statoil is the operator with 30% equity.

The work commitment (up to the first exit point in 2018) is 3D seismic and two vertical wells.

Europe (excluding Norway), Asia and Australia UK In 2014 Statoil was awarded interests in 12 exploration licences in the UK 28th licensing round, nine as operator. Licences were awarded both in mature parts of the Central North Sea, such as in the vicinity of the Mariner and Bressay projects, and in plays largely untested in UK waters. 11 of the licences are in the North Sea and one is west of the Hebrides. In 2015 two exploration wells were drilled. The Boatswain well in licence P1758 west of the Mariner field was a discovery. The Wall well in licence P2067 was dry. Work now continues to mature the broader UK exploration portfolio.

Ireland In March 2016 Statoil was awarded six licensing options in Ireland’s 2015 Atlantic Margin Licensing Round. Statoil will be the operator of four licensing options and partner in two licensing options, operated by ExxonMobil Exploration and Production Ireland (Offshore South) Limited. Work programme commitments are limited to 2D and 3D seismic surveys to be acquired during 2016 and 2017. The analysis of seismic data will then determine whether the Statoil will seek to convert the licensing options into Frontier Exploration Licenses, enabling possible exploration drilling at a later stage. Statoil has had a presence in Ireland since 1992. Currently, Statoil's main asset in Ireland is a 36.5% working interest in the Shell operated Corrib gas field off the country’s north-west coast.

Turkey Statoil entered into a binding letter agreement regarding two exploration licenses in the Thrace region in the north-western part of Turkey in May 2016. Statoil will have a 50% working interest in the Banarli licenses, while the operator Valeura Energy Inc. will keep the remaining 50%. The work programme consists of several phases, where the first includes the commitment of drilling one exploration well, with planned spud late 2016 or early 2017. The exploration phase will test unconventional gas potential in the deep parts of the basin. The agreement is pending governmental approval, which is expected by the end of September 2016.

Greenland Statoil, along with partners ConocoPhillips and Nunaoil, was awarded block 6 in the East Greenland licence round in December 2013. Statoil is the operator of the block. The licence has a 16-year exploration period.

Russia Statoil is engaged in a strategic cooperation with Rosneft including a joint cooperation project aimed at undertaking seismic surveys and geological exploration, appraisal, development and production of potential hydrocarbons in four licences on the Russian continental shelf - the Magadan 1, Lisyansky and Kashevarovsky licences in the Sea of Okhotsk (south of the Arctic Circle), and the Perseevsky licence in the Barents Sea (north of the Arctic Circle). Two exploration wells are to be drilled in the Magadan 1 and Lisyansky licences in 2016. Drilling of Lisyansky was completed in July 2016 and drilling of Magadan is currently ongoing. Additionally there are two joint cooperation projects onshore; pilot drilling and testing of the onshore heavy oil reservoir layer PK1 in the North Komsomolsky discovery, and the Domanik Sediments Difficult-to-Extract Hydrocarbons Project, aimed at pilot drilling and testing of the limestone Domanik formation in the Russian Volga-Urals basin. For each of these projects, Rosneft holds the majority interest, while Statoil holds a minority interest.

Azerbaijan The Joint Study Agreement with SOCAR for the North Absheron area was completed in 2014. Exploration screening and prospect evaluation is being carried out on an ongoing basis for Azerbaijan offshore areas in order to identify new access opportunities.

Indonesia Statoil signed the offshore Aru Trough I PSC licence agreement in May 2015. The licence is adjacent to Statoil’s existing exploration acreage in the Aru and West Papua IV licences. This is a low-cost access route into a frontier area with potential where Statoil is already present. This position strengthens the optionality in Statoil’s long-term portfolio and secures potential upsides from existing exploration acreage.

Myanmar Statoil and ConocoPhillips were awarded one exploration block (AD-10) in the Myanmar waters of the Bay of Bengal in 2014. A production sharing contract was signed in May 2015. Statoil (as operator) has completed the IEE (Initial Environmental Examination) and has set up a country office in Yangon.

Australia In the Ceduna sub-basin in the Great Australian Bight, Statoil holds 30% working interest in four exploration licences with BP as operator.

In October 2014, Statoil obtained 100% equity share in an exploration licence in the Exmouth Plateau in North Carnarvon basin.

New Zealand Statoil is operator with 100% equity share in petroleum exploration permits 55781 and 57057 in the Reinga Basin offshore Northland’s west coast. The licences were awarded in the New Zealand Block Offer 2013 and 2014 respectively.

The work programme is designed to fully evaluate the prospectivity of the licences in a step-wise manner within the 15-year licence time frame. Statoil completed 2D seismic data early 2015. Following an analysis and interpretation of this data, Statoil will decide whether to enter into the second exploration phase by mid-2017.

In the New Zealand Block Offer 2014 Statoil was also awarded 50% working interest in blocks 57083, 57085 and 57087 with Chevron as operator. The licences are located in the East Coast and Pegasus basins, southeast off New Zealand’s North Island. The partnership is committed to acquire 2D seismic and 3D seismic within the first exploration period.

In February 2016, Statoil acquired a 30% working interest in block 57073 were OMV will remain the operator with a 70% working interest. The permit covers an area of 9,800 square kilometres in the East Coast Basin.

Faroe Islands Following disappointing exploration activities, Statoil have relinquished all licences. The Statoil office in Torshavn closed down in 2015.

9.3.4 Fields under development internationally This Section covers selected projects under development and significant pre-sanctioned projects.

Statoil's Time of Production Sanctioned projects Operator equity share sanctioning start

US: Stampede Hess 25.00% 2014 2018 US: Big Foot Chevron 27.50% 2010 2018 Canada: Hebron Exxon Mobil 9.01% 2012 2017 Algeria: In Amenas Compression project Sonatrach/BP/Statoil 45.90% 2010 2016 UK, Mariner Statoil 65.11% 2012 2018 Brazil, Peregrino Phase II Statoil 60.00% 2015 2020

9.3.4.1 North America Statoil has a number of significant on-going development projects in North America.

US Gulf of Mexico The Stampede oil field is located in the Green Canyon area. The development includes a tension-leg platform (TLP) with downhole gas lift and water injection from start of production. The first oil is expected in 2018.

The Big Foot oil field is located in Walker Ridge area. The development includes a dry tree TLP with a drilling rig. The operator Chevron expects first oil from Big Foot in 2018. Initial plans called for production to start in late 2015, however, installation was halted and the TLP moved to sheltered waters following damage to subsea installation tendons in late May 2015.

US Onshore US Onshore operations use hydraulic fracturing to liberate resources. Despite reduction in investment and activity level in recent years in shale plays Bakken, Eagle Ford and Marcellus, production growth continues. The increase in onshore production despite investment reduction is attributed to higher recovery per well due to enhanced completion and improved operational efficiency. See Section 9.3.2.1 "North America" for further information.

Canada The Hebron field is located in the Jeanne d'Arc basin offshore Newfoundland near the partner-operated producing fields Terra Nova, Hibernia and Hibernia Southern Extension. The Hebron field will be developed using a fixed gravity base structure (GBS) and first oil is expected in 2017. Effective 1 January 2016, Statoil’s working interest in Hebron was reduced from 9.7% to 9.0% due to a redetermination process.

Statoil has made oil discoveries in the Flemish Pass offshore Newfoundland comprising the Bay du Nord project, and work is on-going to assess options for developing this project. Statoil is the operator of Bay du Nord and holds a 65% working interest.

9.3.4.2 South America In December 2014, Statoil approved the investment decision for the development of the second phase of the Peregrino oil field. In January 2015, the Plan of Development (PoD) was submitted to the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) for approval. Peregrino Phase II project includes the Peregrino South and South West discoveries.

Peregrino Phase II will enhance production from the Peregrino field by increasing the number of production wells from a new area (Peregrino Southwest), which today is not reachable by the existent platforms A and B. A total of 22 wells, 15 oil producers and seven water injectors, are planned to be drilled as part of the phase II development. The wells in the phase II development will be drilled from a new wellhead platform, with a tie-in solution to the existing FPSO.

Since the investment decision, the Company has optimised the development solution and benefited from lower service costs. This has led to a current total cost estimate for the development of Peregrino Phase II (100%) of USD 2.8 billion. Project execution started 1 April 2016 and expected production start is in the fourth quarter of 2020.

9.3.4.3 Sub-Saharan Africa In Sub-Saharan Africa, Statoil is participating in the planning and development of Block 2 in Tanzania. Statoil has during 2012-2015 made a total of eight deepwater gas discoveries in Block 2 offshore Tanzania, of which six have been defined as high impact. These are Zafarani, Lavani, Tangawizi, Mronge, Piri and Mdalasini. Statoil is the operator of Block 2 and holds a 65% working interest. Work is on-going to assess options for developing the discoveries, including the construction of an onshore LNG plant jointly with the co-ventures in Blocks 1 and 4 operated by BG Tanzania (100% owned by Shell).

9.3.4.4 North Africa In 2015, Statoil's field developments in the North Africa were in Algeria.

The In Amenas Gas Compression project in Algeria, which is led by BP, was sanctioned in late 2010. The compressors are expected to come on stream in the fourth quarter of 2016. This will make it possible to reduce wellhead pressure and maintain plateau production. The In Amenas facilities are operated through a joint operatorship between Sonatrach, BP and Statoil.

In February 2016, the In Salah Gas joint venture announced the start-up of operations at the In Salah Southern Fields project in Algeria. For more information see Section 9.3.2.4 "North Africa".

9.3.4.5 Europe and Asia In Europe and Asia, Statoil is participating in the planning and development of projects in the UK.

Statoil is the operator for the Mariner heavy oil project. In December 2012, Statoil made the investment decision to develop the Mariner oil field. The field development plan was approved by the UK authorities in February 2013. The concept selected includes a production, drilling and quarters platform based on a steel jacket, with a floating storage unit. Statoil expects production start in 2018.

The field development plan for Mariner includes a possibility of a future subsea tie-in of Mariner East, a small heavy oil discovery. Statoil is the operator of Mariner East.

Following completion of the farm down of 20.89% of P.726 (Mariner East) and 28.89% of P.979 (Mariner South) by Statoil to JX Nippon in third quarter 2015, Statoil holds a 65.11% working interest in all Mariner licences.

Statoil is the operator for, and holds an 81.6% working interest in Bressay. Bressay is also a heavy oil discovery. In March 2016, Statoil decided to pause the concept selection work on Bressay due to challenging market conditions. Statoil and the partner Shell will develop a new work program aimed at securing an extension of the licenses to allow progression of the project in a new time frame. In June 2015, the UK Government’s Department of Energy and Climate Change (DECC) confirmed an extension for License P920 on

the UK Continental Shelf enabling continued work on the Bressay project. The Bressay discovery stretches over four licenses. One of them, P920, was due to expire in July 2015 but is now extended to December 2016.

9.3.5 Accessibility internationally 9.3.5.1 Europe and Asia In the UK and Ireland, all fields and field developments currently under evaluation are located offshore. As for Norway, oil and other liquids are typically shipped to shore by shuttle tankers, while gas is transported to shore and to the market via pipe lines. Examples are the Shell operated Corrib field offshore Ireland, which started production in late 2015, where the produced gas is transported via pipeline to an onshore gas processing terminal from where it is exported to the Irish grid, and the Statoil operated Mariner field in the UK, which is currently under development, where the oil will be shipped to shore by shuttle tankers.

In Azerbaijan, the Azeri-Chirag-Gunashli (ACG) oil field in the Caspian Sea has production from six fixed platforms. The oil is transported through pipelines to the Sangachal onshore terminal near Baku. From the terminal the oil is exported to the world markets. Statoil has an 8.7% stake in the Baku-Tbilisi-Ceyhan (BTC) oil pipeline that is used to transport ACG oil to the southern Turkish port of Ceyhan.

From the onshore oil field development Kharyaga in Russia, the oil is transported through pipelines to the Primorsk oil terminal, from where it is shipped to the market by the Baltic Sea.

9.3.5.2 The Americas In the Americas, Statoil is involved in oil and gas producing activities both offshore and onshore.

North America is dominated by the US, where Statoil among the largest lease holders in the Gulf of Mexico and involved in many of the largest offshore fields currently under development. Statoil also has significant ownerships in the onshore Eagle Ford, Marcellus and Bakken shale and tight rock formations.

In the Gulf of Mexico, the majority of the fields are developed with some kind of floating production unit. From these, the produced oil and gas is transported to shore through different pipe line systems, sometimes via other platforms operating as third party hubs.

The onshore plays cover large areas, and both liquids and gas are produced from several different sites. Most of the oil and gas produced from these sites is transported to different markets through pipe lines. Gas from the Northern Marcellus production area is transported to Manhattan, New York. Here Statoil has entered in to transportation agreements with Tennessee Gas Pipeline and Texas Eastern Transmission. Gas from Marcellus is also transported north to the US/Canadian border under a gas transportation agreement with the National Fuel Gas Supply Corporation. Over the last two years Statoil has optimised its Marcellus portfolio by divesting some of its non-core acreage. These divestments allow capital to be focused on core activities in Statoil. The Bakken asset has an extensive gathering system to transport and market its resources, including approximately 700 miles of pipeline and several unit trains.

In Canada, Statoil has interests in producing fields and fields under development both offshore the province of Newfoundland and Labrador, where oil is produced from Terra Nova, Hibernia and Hibernia Southern Extension projects, and from the onshore Leismer project in the Alberta oil sands. The offshore facilities include subsea wells connected to large fixed platforms and floating production and storage units from which oil is offloaded to shuttle tankers. In the Leismer project, oil is produced using the in-situ technology known as SAGD (steam assisted gravity drainage), which injects steam into the oil bearing formation to recover bitumen emulsion which is pumped to the surface. The Leismer wells are drilled from surface well pads, which are connected to central processing and steam generation facilities through in-field pipe lines. Recovered bitumen is blended with a lighter hydrocarbon diluent and is shipped by third party pipeline to the Edmonton area where it would be sold to third party downstream customers for further processing or shipment to other markets.

In South America, oil is produced from the Statoil operated Peregrino field offshore Brazil, and from the Petrocedeño extra-heavy crude project onshore in Venezuela. On Peregrino, the oil is produced from two wellhead platforms and is processed on the Peregrino FPSO. The produced oil is offloaded from the FPSO by shuttle tankers.

Petrocedeño produces extra-heavy crude oil from the Junin area in the Orinoco Belt. The oil is transported through pipeline to a plant at the Jose Industrial Complex at the coast nearby Puerta La Cruz where it is upgraded into a light crude and exported.

9.3.5.3 Africa Statoil's involvement in Africa includes onshore activities in Algeria and Libya, and offshore activities outside the coasts of Angola and Nigeria.

The In Amenas onshore development is the fourth-largest gas field in Algeria. In addition to dry gas, it contains significant liquid volumes of LPG and condensate. The In Amenas infrastructure includes a gas treatment plant composed of three processing trains. The production facility is connected to the Sonatrach distribution system through three export pipelines for dry gas, LPG and condensate.

The In Salah gas development includes several fields, and the gas is transported through flowlines and trunklines to a central processing facility from which it is exported through pipeline to Hassi R’Mel.

In Libya, there has not been any oil production from the Mabruk or the Murzuq assets in 2015 and 2016 due to the security situation in the country.

In Angola, Statoil is partner in several producing fields in blocks 15, 17, and 31. Due to the deep water conditions, all fields are developed with subsea wells connected to floating production, storage and offloading operation units (FPSOs). The FPSOs serve as production hubs and receive oil from a large number of wells and more than one field each. From these the produced oil is offloaded to tankers for export to the market.

In Nigeria, Statoil is partner in the Agbami deep water field which is located off the coast of the Central Niger Delta region. The field is developed with subsea wells connected to an FPSO from which the oil is offloaded to tankers.

In Tanzania, Statoil is the operator of the deep water Block 2, which is located in the Indian Ocean 100 km off the southern part of Tanzania at 2500 meters sea depth. There is no infrastructure in place, and the current plan is to develop the discoveries with a subsea to shore solution and an onshore LNG plant to be developed together with the partners in Block 1 & 4. The Block 2 exploration is in the second extension period and that has duration till June 2018.

9.4 Expected economic lifetime Expected economic lifetime for a field or a license will vary over the life of a field and may be shorter or longer than the expiry date set out in the terms of the license or expected at the time of investment decision or production start.

Following the first development phase and the first oil, the understanding of the reservoirs and technology required for extraction of in-field volumes will mature and new volumes might be included due to successful exploration within the license/field or from tie-ins from other adjacent licenses. Normally operators will work continuously to evaluate new prospects and projects for development or propose increased recovery methods to the license partnerships.

For example, a successful application of increased recovery methods may achieve significantly higher recovery rates than originally factored into the reserve estimates potentially increasing field life by 10 to 20 years, while others might not be so successful. The commodity prices at the time of decision-making will also impact the assessment. As price expectations will vary over time, these will affect the expected lifetime positively or negatively. Field life estimates are also dependent on the Company’s and partners’ capital expenditure plans and whether spending additional capital to extend field life is consistent with the respective plans for return on capital.

Abandonment and decommissioning are subject to decisions in the various partnerships/joint ventures which will not be decided until the field is on decline and costs related to the abandonment will depend on rates for relevant equipment for abandonment work as well as technology development. There may also be different

views in the partnerships whether to invest in order to prolong the lifetime should that be technically possible in order to increase recovery.

To the extent the economic lifetime may exceed the license expiry date, the partners will in most jurisdictions depend on authorities’ approval for an extension. Authorities may set requirements for granting such extension, which again may influence the decision making in the licenses.

The table below sets out Statoil’s current estimated economic lifetime for Statoil operated fields based on a materiality of 40,000 boe per day Entitlement Production of 2015 production level for producing fields and expected level of production for fields under development. These producing fields represent around 70% of 2015 Entitlement Production. It should be noted that these estimates have not been discussed or approved by relevant partners or authorities and hence only represents Statoil’s best estimates at the date of this Prospectus.

The estimates of economic lifetime are presented in ranges per two years, five years or beyond 2051 due to the considerable uncertainty in estimating a production profile over a long period of time. Shareholders should take due consideration to the uncertainties and risks related to these forward-looking statements and reference is also made to Section 4.8 "Cautionary note regarding forward-looking statements".

Material fields Estimated last year of production Aasta Hansteen 2026-2030 Åsgard 2031-2035 Bakken Beyond 2051 Grane 2041-2045 Gullfaks 2031-2035 Johan Sverdrup Beyond 2051 Kvitebjørn 2041-2045 Marcellus Beyond 2051 Ormen Lange 2036-2040 Oseberg 2041-2045 Peregrino 2036-2040 Skarv 2031-2035 Snøhvit Beyond 2051 Sleipner Øst 2023-2025 Sleipner Vest 2023-2025 Statfjord unit 2023-2025 Troll Beyond 2051 Tyrihans 2031-2035 Visund 2031-2035

In addition, Block 17 in Angola and the Agbami field in Nigeria have each an entitlement production above 40,000 boe per day.

As described in Section 9.3.2 "International production", the expiry date varies by the fields within Angola Block 17 in the period 2022-2034. Statoil expects the economic life-time of Block 17 to be beyond 2034.

As described in Section 9.3.2 "International production", the expiry date is 2024 for Agbami. Statoil expects the economic life-time of Agbami to be beyond 2024.

9.5 Proved oil and gas reserves 9.5.1 Introduction Proved reserves are estimated and updated at year end. Section 9.5 “Proved oil and gas reserves” includes tables with proved reserves for year-end 2013, 2014 and 2015.

Proved oil and gas reserves were estimated to be 5,060 mmboe at year end 2015, compared to 5,359 mmboe at the end of 2014.

Statoil's oil and gas reserves have been estimated by its qualified professionals in accordance with industry standards under the requirements of the SEC, Rule 4-10 of Regulation S-X. Statements of reserves are forward-looking statements, see Section 4.8 "Cautionary note regarding forward-looking statements". This reporting standard is recognised by Oslo Stock Exchange for reserves reporting and is in line with the Petroleum Resource Management System (PRMS) reporting standard published by the Society of Petroleum Engineering (SPE) and others.

The determination of these reserves is part of an ongoing process subject to continual revision as additional information becomes available. Estimates of proved reserve quantities are judgemental in nature and therefore imprecise and change over time as new information becomes available. Reserves and contingent resources that are identified, but not yet mature enough to be classified as proved reserves, are excluded from the calculations. Statoil's proved reserves are recognised under various forms of contractual agreements, including production sharing agreements (PSAs) where Statoil's share of reserves can vary due to commodity prices or other factors. Reserves from agreements such as PSAs and buy back agreements are based on the volumes to which Statoil has access (cost oil and profit oil), limited to available market access. At 31 December 2015, 9% of total proved reserves were related to such agreements (15% of total oil, condensate and NGL reserves and 3% of total gas reserves). This compares with 12% and 14% of total proved reserves for 2014 and 2013, respectively. Net entitlement oil and gas production from fields with such agreements was 104 million boe during 2015 (95 million boe for 2014 and 93 million boe for 2013).

Statoil is recording, as proved reserves, volumes equivalent to Statoil's tax liabilities under negotiated fiscal arrangements (PSAs) where the tax is paid on behalf of Statoil. Reserves are net of royalty oil paid in kind and quantities consumed during production.

Proved reserves are calculated based on existing economic conditions, including a 12-month average price prior to the end of the reporting period, unless prices are defined by contractual arrangements. The proved reserves at year end 2015 have been determined based on a Brent blend price equivalent of USD 54.17/bbl, compared to USD 101.27/bbl and USD 108.02/bbl for 2014 and 2013 respectively. The significant decrease in commodity prices affects the profitable reserves to be recovered from accumulations resulting in reduced reserves. The negative revisions due to price are in general a result of earlier economic cut-off. For fields with a production-sharing type of agreement this is to some degree offset by higher entitlement to the reserves. These changes are all included in the revision category in the reserves tables, giving a net reduction of Statoil’s proved reserves at year end.

Reserves are presented by geographical area, defined as country or continent containing 15% or more of total proved reserves. Norway contains 75% of total proved reserves at 31 December 2015 and no other country contains reserves approaching 15% of total proved reserves. Accordingly, the Management has determined that the most meaningful presentation of geographical areas would be Norway and the continents of Eurasia (excluding Norway), Africa and Americas.

Changes in proved reserves estimates are most commonly the result of revisions of estimates due to observed production performance, extensions of proved areas through drilling activities or the inclusion of proved reserves in new discoveries through the sanctioning of new development projects. These are sources of additions to proved reserves that are the result of continuous business processes and can be expected to continue to add reserves in the future.

Proved reserves can also be added or subtracted through the acquisition or disposal of assets. Changes in proved reserves can also be due to factors outside management control, such as changes in oil and gas prices. Lower oil and gas prices normally allow less oil and gas to be recovered from the accumulations. However for fields with production sharing agreements (PSAs) and similar contracts a reduced oil price may result in higher entitlement to the produced volume. These changes are included in the revisions category in the table below.

The principles for booking proved gas reserves are limited to contracted gas sales or gas with access to a robust gas market.

In Norway and the UK, Statoil recognises reserves as proved when a development plan is submitted, as there is reasonable certainty that such a plan will be approved by the regulatory authorities. Outside these territories, reserves are generally booked as proved when regulatory approval is received, or when such approval is imminent. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years. Undrilled well locations onshore are generally booked as proved undeveloped reserves when a development plan has been adopted and the well locations are scheduled to be drilled within five years,

Approximately 89% of Statoil's proved reserves are located in OECD countries. Norway is by far the most important contributor in this category, followed by the United States of America (US), Canada, Ireland and the United Kingdom (UK).

Of Statoil's total proved reserves, 9% are related to production-sharing agreements (PSAs) in non-OECD countries such as Azerbaijan, Angola, Algeria, Nigeria, Libya and Russia. Other non-OECD reserves are related to concessions in Brazil and Venezuela, representing less than 3% of Statoil's total proved reserves. These are included in proved reserves in the Americas.

Significant changes in Statoil's proved reserves in 2015 were:

• Negative revisions due to lower commodity prices compared to last year, which resulted in a reduction of approximately 350 million boe. A large portion of this is related to undeveloped fields where lower commodity prices resulted in earlier economic cut-off, such as the Mariner field in the UK which is under development and is expected to start production in 2018, and uneconomic undeveloped well locations onshore US. The negative revisions are partly offset by positive revisions due to better performance of producing fields, maturing of improved recovery projects, and reduced uncertainty due to further drilling and production experience. The net effect of the positive and negative revisions is a reduction of 42 million boe in 2015. The estimated reduction due to change in prices is a rough estimate derived by using last year’s prices on this year’s volume base. In the calculation no adjustments have been made for the possible effect on the activity level, operating cost or development cost.

• Proved reserves from new discoveries have also been added through the sanctioning of new field development projects in 2015, Johan Sverdrup being the largest contributor. The new projects added a total of 476 million boe.

• Further drilling in the Bakken, Marcellus and Eagle Ford onshore plays in the US increased the proved reserves in 2015, and some of these additions are presented as extensions. Extension of proved area on existing field added a total of 150 million boe of new proved reserves in 2015.

• The net effect of purchase and sale reduced the reserves by 221 million boe in 2015.

• The 2015 Entitlement Production was 662 million boe, an increase of 4.3% compared to 2014. New discoveries with proved reserves booked in 2015 are all expected to start production within a period of five years.

The acquisitions and divestments completed since year end 2015 may affect Statoil’s proved reserves at year end 2016. These effects are not included in the numbers given in this section, but updated proved reserves estimate will be communicated through the fourth quarter 2016 announcement.

Summary of proved reserves as of 31 December 2015

Proved reserves Oil and Natural Total oil Condensate NGL Gas and gas Reserves category (mmboe) (mmboe) (bcf) (mmboe)

Developed

Norway 505 235 10,664 2,641

Eurasia excluding Norway 48 - 32 53

Africa 248 9 206 294

Americas 303 45 999 526

Total Developed proved reserves 1,104 290 11,901 3,515

Undeveloped

Norway 711 56 2,278 1,173

Eurasia excluding Norway 29 - 161 57

Africa 30 6 160 64

Americas 217 12 124 251

Total Undeveloped proved reserves 987 74 2,723 1,546

Total proved reserves 2,091 364 14,624 5,060

Statoil's proved reserves of bitumen in the Americas are included as oil in the table above since they represent less than 2% of Statoil's proved reserves, which is regarded as immaterial.

The basis for equivalents is presented in Section 4.6 "Equivalent measures".

9.5.2 Reserves replacement The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves divided by produced volumes in any given period. The following table presents the changes in reserves in each category relating to the reserve replacement ratio for the years 2015, 2014 and 2013.

For the year ended 31 December

(million boe) 2015 2014 2013

Revisions and improved recovery (42) 356 395 Extensions and discoveries 627 253 523 Purchase of petroleum-in-place 13 20 14 Sales of petroleum-in-place (235) (233) (131)

Total reserve additions 363 395 802 Production (662) (635) (625)

Net change in proved reserves (299) (240) 177

The reserves replacement ratio for 2015 was 0.55 compared to 0.62 in 2014. The 2015 reserves replacement ratio, excluding purchases and sales of petroleum in place, was 0.88. The average replacement ratio for the last three years was 0.81, or 1.10 excluding purchases and sales.

For the year ended 31 December Reserves replacement ratio (including purchases and sales) 2015 2014 2013

Annual 0.55 0.62 1.28 Three-year-average 0.81 0.97 1.15

The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, sensitivity related to the timing of project sanctions and the time lag between exploration expenditure and the booking of reserves.

9.5.3 Proved reserves in Norway A total of 3,814 million boe is recognised as proved reserves in 58 fields and field development projects on the NCS, representing 75% of Statoil's total proved reserves. Of these, 54 fields and field areas are currently in production, 42 of which are operated by Statoil. Four new field development projects added reserves during 2015, Johan Sverdrup, Oseberg Vestflanken 2, Fram C- Øst Brent and Opal categorised as extensions and discoveries. Production experience, further drilling and improved recovery on several of Statoil's producing fields in Norway also contributed positively to the revisions of the proved reserves in 2015.

Sales of reserves are related to the agreement with Repsol. This has reduced Statoil's share of proved reserves on Gudrun.

Of the proved reserves on the NCS, 2,641 million boe, or 69%, are proved developed reserves. Of the total proved reserves in this area, 60% are gas reserves related to large offshore gas fields such as Troll, Snøhvit, Oseberg, Ormen Lange, Tyrihans, Visund, Aasta Hansteen and Åsgard and 40% are liquid reserves.

9.5.4 Proved reserves in Eurasia, excluding Norway In this area, Statoil has proved reserves of 111 million boe related to four fields and field developments in Azerbaijan, the UK, Ireland and Russia. Eurasia excluding Norway represents 2% of Statoil's total proved reserves, Azerbaijan being the main contributor with the Azeri-Chirag-Gunashli fields. All fields are producing. The effect of the farm out of Shah Deniz reduced the proved reserves at year end 2015.

Proved undeveloped reserves were reduced due to negative revisions linked to lower commodity prices resulting in earlier economic cut-off for the fields, primarily the Mariner field in the UK which is under development and is expected to start production in 2018.

Of the proved reserves in Eurasia, 53 million boe or 48% are proved developed reserves. Of the total proved reserves in this area, 69% are liquid reserves and 31% are gas reserves.

9.5.5 Proved reserves in Africa Statoil recognises proved reserves of 358 million boe related to 29 fields and field developments in several West and North African countries, including Algeria, Angola, Libya and Nigeria. Africa represents 7% of Statoil's total proved reserves. Angola is the primary contributor to the proved reserves in this area, with 24 of the 29 fields.

In Angola, Statoil has proved reserves in three blocks, Block 15, Block 17 and Block 31, with production from all blocks. During 2015 Statoil exited Block 4/05, Gimboa is therefore removed from proved reserves this year.

All fields are in production in Algeria and Nigeria. Murzuq and Mabruk are currently not producing due to the unrest in Libya.

The disputed equity determination at Agbami will potentially alter Statoil's equity share in this field. The effect on the proved reserves will be included once the redetermination is finalised and the effect is known.

Of the total proved reserves in Africa, 294 million boe, or 82%, are proved developed reserves. Of the total proved reserves in this area, 82% are liquid reserves and 18% are gas reserves.

9.5.6 Proved reserves in the Americas In North and South America, Statoil has proved reserves equal to 777 million boe in a total of 17 fields and field development projects. This represents 15% of Statoil's total proved reserves. Ten of these fields are located in the US, seven of which are offshore field developments in the Gulf of Mexico and three are onshore tight reservoir assets. Five are located in Canada and two in South America. In the US, four of the seven fields in the Gulf of Mexico are in production. Field development is ongoing on Big Foot, Heidelberg and Stampede. The onshore tight reservoir assets Marcellus, Eagle Ford and Bakken are all in production. In Canada, proved reserves are related both to offshore field developments, and to the Leismer field in the Kai Kos Dehseh oil sands project in Alberta.

Proved undeveloped reserves were reduced due to negative revisions linked to lower commodity prices, primarily resulting in undeveloped well locations onshore US becoming uneconomic.

Several transactions were completed during 2015, both purchases and sales. The largest were the transaction with Southwestern Energy reducing the reserves in Marcellus, and the agreement with Repsol increasing the reserves in Eagle Ford. The transactions offset each other and the net effect on proved reserves is zero.

Of the total proved reserves in the Americas, 526 million boe, or 68%, are proved developed reserves. Of the total proved reserves in this area, 74% are liquid reserves and 26% gas reserves.

9.5.7 Development of reserves In 2015, approximately 438 million boe were converted from undeveloped to developed proved reserves.

The start-up of production from Edvard Grieg, Oseberg Delta 2 and Valemon in Norway together with Bavuca and Kakocha in Angola and Corrib in Ireland increased the developed reserves by 69 million boe during 2015. The rest of the converted volume is related to development activities on producing fields.

Net proved reserves in million barrels oil equivalent Total Developed Undeveloped

At 31 December 2014 5,359 3,725 1,635

Revisions and improved recovery (42) 96 (138)

Extensions and discoveries 627 - 627

Purchase of reserves-in-place 13 6 7

Sales of reserves-in-place (235) (88) (147)

Production (662) (662) -

Moved from undeveloped to developed - 438 (438)

At 31 December 2015 5,060 3,515 1,546

The new development projects in Norway, added a total of 476 million boe of proved undeveloped reserves in 2015, the largest being Johan Sverdrup. Further drilling in the Bakken, Marcellus and Eagle Ford onshore plays in the US increased the proved area and added proved undeveloped reserves. These additions are categorised as extensions and together with extensions on existing fields and new discoveries this added a total of 627 million boe of proved undeveloped reserves.

Revision of estimate on existing fields added 96 million boe proved developed reserves and reduced proved undeveloped reserves by 138 million boe. These revisions are based on new information available either from drilling of new wells or from production experience, resulting in an improved understanding of the fields. The negative revisions are mainly linked to lower commodity prices resulting in earlier economic cut-off for the fields and undeveloped well locations becoming uneconomic.

The net effect of the transactions done in 2015, reduced the proved undeveloped reserves by 139 million boe.

Oil and Natural Condensat NGL gas Total

(mmboe) (mmboe) (bcf) (mmboe)

2015 Proved reserves end of year 2,091 364 14,624 5,060

Developed 1,104 290 11,901 3,515

Undeveloped 987 74 2,723 1,546

2014 Proved reserves end of year 1,942 403 16,919 5,359

Developed 1,156 310 12,677 3,725

Undeveloped 786 93 4,242 1,635

2013 Proved reserves end of year 1,877 441 18,416 5,600

Developed 1,052 330 13,073 3,711

Undeveloped 826 111 5,343 1,888

As of 31 December 2015, the total proved undeveloped reserves amounted to 1,546 million boe, 76% of which are related to fields in Norway. The Troll, Snøhvit, Visund, Grane and Oseberg fields, which have continuous development activities, represent the largest undeveloped assets in Norway together with fields not yet in production, such as Johan Sverdrup, Aasta Hansteen, Gina Krogh, Ivar Aasen and Goliat. The largest assets with respect to undeveloped proved reserves outside Norway are Bakken and Stampede in the US, Peregrino in Brazil, Hebron in Canada, Corrib in Ireland and In Salah in Algeria.

In 2015, Statoil incurred NOK 85 billion (USD 10.3 billion) in development costs relating to assets carrying proved reserves, NOK 70 billion (USD 8.5 billion) of which was related to proved undeveloped reserves.

Large fields with continuous development activity may contain reserves that are expected to remain undeveloped for five years or more. Examples are Johan Sverdrup, Troll, Snøhvit, Gina Krogh and Aasta Hansteen in Norway. These are large field developments with several billion dollars invested in complex infrastructure and with continuous development that will require extensive, sustained drilling of wells for a long period of time. It is highly unlikely that these field development projects will be prematurely terminated, since this would result in a significant loss of capital.

Additional information about proved oil and gas reserves is provided in 9.5.11 "Supplementary oil and gas information".

9.5.8 Preparations of reserves estimates Statoil's annual reporting process for proved reserves is coordinated by a central team. The corporate reserves management ("CRM") team consists of qualified professionals in geosciences, reservoir and production technology and financial evaluation. The team has an average of more than 20 years' experience in the oil and gas industry. CRM reports to the senior vice president of finance and control in the Technology, Drilling and Projects business area and is thus independent of the Development & Production business areas in Norway, North America and International. All the reserves estimates have been prepared by Statoil's technical staff.

Although the CRM team reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and Statoil's corporate standards. Information about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other information related to proved oil and gas reserves, is collected from the local asset teams and checked by CRM for consistency and conformity with applicable standards. The final numbers for each asset are quality-controlled and approved by the responsible asset manager, before aggregation to the required reporting level by CRM.

The aggregated results are submitted for approval to the relevant business area management teams and the corporate executive committee.

Petroleum engineering consultants DeGolyer and MacNaughton have carried out an independent evaluation of Statoil's proved reserves as of 31 December 2015.

9.5.9 Operational statistics Operational statistics include information about acreage and the number of wells drilled.

9.5.9.1 Developed and undeveloped acreage The table below shows the total gross and net developed and undeveloped oil and gas acreage, in which Statoil had interests at 31 December 2015.

A gross value reflects wells or acreage in which Statoil has working interests (presented as 100%). The net value corresponds to the sum of the fractional working interests owned in gross wells or acres.

Eurasia At 31 December 2015 excluding (in thousands of acres) Norway Norway Africa Americas Oceania Total

Developed and undeveloped oil and gas acreage Acreage developed - gross 871 90 858 494 - 2,312 - net 322 21 271 114 - 729 Acreage undeveloped - gross 9,038 41,146 13,569 23,075 18,531 105,359 - net 3,419 17,495 4,637 10,073 11,160 46,784

The largest concentrations of developed acreage in Norway are in the Troll, Skarv, Snøhvit, Ormen Lange and Oseberg areas. In Africa, the Algerian gas development projects In Amenas and In Salah represent the largest concentrations of developed acreage (gross and net).

Statoil's largest undeveloped acreage concentration is in Russia with 18% of the total acreage and 48% of the total acreage in Eurasia excluding Norway. In Russia, Statoil participates in a joint venture with Rosneft. The net acreage given in the table above represents Statoil’s share of the joint venture. The largest concentration of undeveloped acreage in the Americas is Nicaragua, with 33% of the total for this geographic area. In Africa, the largest acreage concentration is in Angola, representing 56% of the total for this geographic area.

Statoil holds acreage in numerous concessions, blocks and leases. The terms and conditions regarding expiration dates vary significantly from property to property. Work programs are designed to ensure that the exploration potential of any property is fully evaluated before expiration.

Acreage related to several of these concessions, blocks and leases are scheduled to expire within the next three years. Any acreage which has already been evaluated to be non-profitable may be relinquished prior to the current expiration date. In other cases, Statoil may decide to apply for an extension if more time is needed in order to fully evaluate the potential of the properties. Historically, Statoil has generally been successful in obtaining such extensions.

Most of the undeveloped acreage that will expire within the next three years is related to early exploration activities where no production is expected in the foreseeable future. The expiration of these leases, blocks and concessions will therefore not have any material impact on Statoil's reserves.

9.5.9.2 Productive oil and gas wells The number of gross and net productive oil and gas wells, in which Statoil had interests at 31 December 2015, are shown in the table below.

Eurasia excluding At 31 December 2015 Norway Norway Africa Americas Total

Number of productive oil and gas wells Oil wells - gross 821 166 468 3,130 4,585 - net 281.4 24.2 71.3 706.4 1,083.2 Gas wells - gross 189 6 85 1,953 2,233 - net 81.6 1.9 32.7 486.3 602.4

The total gross number of productive wells as of end 2015 includes 383 oil wells and 12 gas wells with multiple completions or wells with more than one branch.

9.5.9.3 Net productive and dry oil and gas wells drilled The following tables show the net 34 productive and dry exploratory and development oil and gas wells completed or abandoned by Statoil in the past three years. Productive wells include exploratory wells in which hydrocarbons were discovered, and where drilling or completion has been suspended pending further evaluation. A dry well is one found to be incapable of producing sufficient quantities to justify completion as an oil or gas well.

34 Net means numbers taking into account Statoil’s working interest in the license.

Eurasia excluding Norway Norway Africa Americas Oceania Total

Year 2015 Net productive and dry exploratory wells drilled 10.2 1.0 2.5 2.6 - 16.3 - Net dry exploratory wells drilled 4.6 0.4 0.5 0.9 - 6.4 - Net productive exploratory wells drilled 5.6 0.7 2.0 1.7 - 9.9

Net productive and dry development wells drilled 32.1 4.1 10.6 228.8 - 275.6 - Net dry development wells drilled 3.6 - 4.3 0.3 - 8.2 - Net productive development wells drilled 28.6 4.1 6.3 228.5 - 267.4

Year 2014 Net productive and dry exploratory wells drilled 12.0 1.0 4.7 3.4 3.6 24.7 - Net dry exploratory wells drilled 3.4 1.0 2.7 1.6 3.6 12.2 - Net productive exploratory wells drilled 8.6 - 2.0 1.9 - 12.5

Net productive and dry development wells drilled 26.9 2.7 8.5 386.1 - 424.2 - Net dry development wells drilled 3.5 - 1.1 1.2 - 5.8 - Net productive development wells drilled 23.4 2.7 7.4 384.9 - 418.4

Year 2013 Net productive and dry exploratory wells drilled 19.3 0.3 2.2 2.3 - 24.0 - Net dry exploratory wells drilled 7.3 0.3 2.2 2.3 - 12.0 - Net productive exploratory wells drilled 12.0 - - - - 12.0

Net productive and dry development wells drilled 26.7 2.3 5.9 321.9 - 356.7 - Net dry development wells drilled 1.7 - 0.7 1.3 - 3.7 353.1 - Net productive development wells drilled 24.9 2.3 5.3 320.6 -

9.5.9.4 Exploratory and development drilling in process The following table shows the number of exploratory and development oil and gas wells in the process of being drilled by Statoil at 31 December 2015.

Eurasia excluding At 31 December 2015 Norway Norway Africa Americas Total

Number of wells in progress Development wells - gross 68 4 13 202 287 - net 24.5 0.3 2.7 67.7 95.2 Exploratory wells - gross 1 - - 8 9 - net 0.4 - - 5.4 5.8

The following table shows the number of firm exploration well commitments (gross) under the licenses for the next 3 years:35

Within 1 year 1-3 years (2017-2019) More than 3 years (2016) (2020+) Norway 0 8 2 Eurasia (excluding Norway) 1 8 1 Africa 2 10 1 Americas 0 11 0 Total 3 37 4

9.5.10 Delivery commitments This section describes the long-term NCS commitments for the contract gas years 2015-2018.

On behalf of the Norwegian State's direct financial interest (SDFI), Statoil is responsible for managing, transporting and selling the Norwegian state's oil and gas from the NCS. These reserves are sold in conjunction with Statoil's own reserves. As part of this arrangement, Statoil delivers gas to customers under various types of sales contracts. In order to meet the commitments, Statoil utilises a field supply schedule that ensures the highest possible total value for Statoil and SDFI's joint portfolio of oil and gas.

The majority of Statoil's gas volumes in Norway are sold under long-term contracts with take-or-pay clauses. Statoil's and SDFI's annual delivery commitments under these agreements are expressed as the sum of the expected off-take under these contracts. As of 31 December 2015, the long-term commitments from NCS for the Statoil/SDFI arrangement totalled approximately 14.51 trillion cubic feet (tcf) (411 bcm).

Statoil and SDFI's delivery commitments, expressed as the sum of expected off-take for the gas years 2015, 2016, 2017 and 2018, are 2.28, 1.89, 1.56 and 1.22 tcf (64.7, 53.5, 44.2 and 44.0 bcm), respectively. The remaining volumes are sold to large industrial end users or on the short-term market.

Statoil's currently developed gas reserves in Norway are more than sufficient to meet Statoil's share of these commitments for the next three years.

35 The overview does not include the commitment well to be drilled by 2018 under the BM-S-8 licence in the Santos Basin in Brazil.

9.5.11 Supplementary oil and gas information The following tables reflect the estimated proved reserves of oil and gas at 31 December 2012 through 2015, and the changes therein.

Consolidated companies Equity accounted Total Eurasia excluding Norway Norway Africa Americas Subtotal Americas Total

Net proved oil and condensate reserves in million barrels oil equivalent At 31 December 2012 968 193 281 395 1 837 82 1 919

Revisions and improved recovery 133 16 40 18 207 (16) 191 Extensions and discoveries 19 47 8 34 108 - 108 Purchase of reserves-in-place 13 - - - 13 - 13 Sales of reserves-in-place (40) (15) - (2) (57) - (57) Production (174) (15) (58) (46) (294) (4) (298)

At 31 December 2013 918 227 271 399 1 815 63 1 877 - - - - - Revisions and improved recovery 143 10 85 (4) 235 (3) 232 Extensions and discoveries 3 - 5 145 153 - 153 Purchase of reserves-in-place - - - 20 20 - 20 Sales of reserves-in-place (5) (27) (2) - (34) - (34) Production (173) (14) (64) (51) (301) (4) (306)

At 31 December 2014 886 196 296 508 1 887 55 1 942

Revisions and improved recovery 71 (68) 57 (54) 5 (5) 0 Extensions and discoveries 437 - - 74 511 - 511 Purchase of reserves-in-place - - - 4 4 - 4 Sales of reserves-in-place (4) (38) - (1) (43) - (43) Production (174) (13) (75) (57) (319) (4) (324)

At 31 December 2015 1 216 76 278 474 2 045 46 2 091

Proved reserves of bitumen in Americas, representing less than 2% of Statoil's proved reserves, is included as oil in the table above.

Consolidated companies Equity accounted Total Eurasia excluding Norway Norway Africa Americas Subtotal Americas Total

Net proved NGL reserves in million barrels oil equivalent At 31 December 2012 405 - 18 47 469 - 469

Revisions and improved recovery 25 - (0) 4 28 - 28 Extensions and discoveries 1 - - 10 11 - 11 Purchase of reserves-in-place 0 - - - 0 - 0 Sales of reserves-in-place (21) - - - (21) - (21) Production (42) - (1) (4) (47) - (47)

At 31 December 2013 368 - 16 56 441 - 441

Revisions and improved recovery (2) - 1 5 4 - 4 Extensions and discoveries 3 - - 18 21 - 21 Purchase of reserves-in-place ------Sales of reserves-in-place (10) - - (2) (12) - (12) Production (42) - (2) (7) (51) - (51)

At 31 December 2014 318 - 15 69 403 - 403

Revisions and improved recovery 7 - 3 (20) (10) - (10) Extensions and discoveries 11 - - 16 27 - 27 Purchase of reserves-in-place - - - 4 4 - 4 Sales of reserves-in-place (1) - - (5) (5) - (5) Production (44) - (3) (7) (54) - (54)

At 31 December 2015 291 - 15 57 364 - 364

Consolidated companies Equity accounted Total Eurasia excluding Norway Norway Africa Americas Subtotal Americas Total

Net proved reserves in million barrels oil equivalent At 31 December 2012 4 046 296 360 639 5 340 82 5 422

Revisions and improved recovery 227 49 44 90 411 (16) 395 Extensions and discoveries 183 268 8 64 523 - 523 Purchase of reserves-in-place 14 - - - 14 - 14 Sales of reserves-in-place (113) (15) - (2) (131) - (131) Production (441) (28) (66) (85) (621) (4) (625)

At 31 December 2013 3 916 569 346 705 5 537 63 5 600 - - - - - Revisions and improved recovery 219 16 87 36 359 (3) 356 Extensions and discoveries 20 - 5 227 253 - 253 Purchase of reserves-in-place - - - 20 20 - 20 Sales of reserves-in-place (78) (148) (2) (5) (233) - (233) Production (434) (24) (72) (102) (631) (4) (635)

At 31 December 2014 3 644 413 364 882 5 304 55 5 359

Revisions and improved recovery 146 (72) 83 (194) (37) (5) (42) Extensions and discoveries 480 - - 146 627 - 627 Purchase of reserves-in-place - - - 13 13 - 13 Sales of reserves-in-place (6) (215) - (13) (235) - (235) Production (450) (16) (88) (103) (658) (4) (662)

At 31 December 2015 3 814 111 358 731 5 014 46 5 060

Proved reserves of bitumen in Americas, representing less than 2% of Statoil's proved reserves, is included as oil in the table above.

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

9.6 Applicable laws and regulations for Norway 9.6.1 Norwegian petroleum laws and licencing system The principal laws governing Statoil’s petroleum activities in Norway are the Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act. The legal basis for the government regulation of the petroleum sector is set forth in section 1-1 of the Petroleum Act, which states that the proprietary right to subsea petroleum deposits is vested in the Norwegian State.

The Petroleum Act provides the overall principles applicable for operations on the NCS and the legal framework for the licensing system, whereby petroleum activities such as exploration and production cannot be carried out unless a licence has been awarded. The Petroleum Act also regulates exploration, development, production, transportation of petroleum, decommissioning, liabilities etc., and more detailed regulation on these issues are set forth in regulations issued under the Petroleum Act, which are also supplemented by other statutes such as the Working Environment Act and the Pollution Protection Act. The Petroleum Taxation Act sets out the legal basis for taxation of offshore petroleum activities.

Norway is not a member of the European Union (EU), but Norway is a member of the European Free Trade Association (EFTA). The EU and the EFTA Member States have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, which provides for the inclusion of EU legislation covering the four freedoms - the free movement of goods, services, persons and capital - in the national law of the EFTA Member States (except Switzerland). An increasing volume of regulations affecting Statoil is adopted in the EU and then applied to Norway under the EEA Agreement. As a Norwegian company operating within both EFTA and the EU, Statoil’s business activities are subject to both the EFTA Convention governing intra-EFTA trade and EU laws and regulations adopted pursuant to the EEA Agreement.

The ultimate regulatory authority with respect to the petroleum activities on the NCS is exercised by the Storting. The overall responsibility for ensuring that the petroleum activities are carried out in accordance with the regulatory framework laid down by the Storting, rests with MPE. Subordinated to the MPE is the NPD whose activities relate to resource management and day-to-day issues. The PSAN, the regulatory authority for technical and operational safety, including emergency preparedness, and for the working environment, is subordinated to the Ministry of Labour. Policy and legislation concerning taxation of the petroleum industry is handled by MoF and annual tax assessments are carried out by the Oil Taxation Office. The Norwegian Environment Agency ("NEA") has regulatory responsibility for pollution caused by petroleum activities on the NCS.

The Storting's role in relation to the petroleum sector affects 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 MPE. 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 contemplates to issue additional shares which 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 Section 2.1.23 "Risks related to state ownership".

• Oil and gas operations on the NCS are subject to extensive regulations, which sets out the rights and obligation of the licensees and the operator and ensures the Norwegian State supervision and control over the petroleum activities, through all phases of the operations, in addition to ensuring that the Norwegian State obtains tax revenues from such activities in accordance with the Norwegian petroleum taxation regime. 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.

9.6.2 The Norwegian licencing system The Norwegian offshore licensing system comprises various licences, approvals and agreements. Companies can apply for an exploration licence, for the purpose of exploration activities, typically performing geological and other surveys. Such licence does not give any exclusive rights in the relevant area, or any preferential right when production licences are granted.

Production licences are the key document in the licensing system set forth under the Petroleum Act, and give the licensee(s) an exclusive right to explore for (including exploration drilling), develop and produce petroleum within a specified geographical area. Production licences are normally awarded for an initial phase, up to 10 years, but can be shorter. During this initial phase, the licensees must meet specified work obligations set out in the licence, for example to carry out certain exploration drilling activities. If the licensees fulfil the obligations set out in the initial license period, they are entitled to require that the licence be prolonged for a period specified at the time when the licence is awarded, typically 30 years.

There are two systems for awarding licences on the NCS. Licences may be awarded in licensing rounds, which normally are arranged every second year. In addition, as from 2003, unlicensed acreage in mature areas on the NCS is opened for application in annual award procedures. This award system ensures that very large areas close to existing and planned infrastructure are available for the industry. This area will be expanded as new areas mature.

To be eligible for award of a production licence, the companies must fulfil certain criteria regarding technical and geological competence and sufficient financial strength.

A production licence can be awarded to one or several oil companies, such companies becoming licensees upon such an award. One of the conditions of the award of a production license is that the licensees enter into an agreement for petroleum activities. Such agreement consists of certain specific provisions, which set out e.g. the voting rules in the license, and the standard joint operation agreement (the "JOA") and the accounting agreement. The latter regulates the accounting and financial aspects of the license joint venture. The JOA governs the relationship between the licensees, as it forms the basis for day-to-day management of the activities, allocation of cost, decision making processes, the operators’ duties etc. The licensees are primarily liable to each other on a pro rata basis, secondarily jointly and severally liable for all obligations by virtue of the licence activities. The operator will issue cash calls to the licensees in order to have sufficient funds to meet the licence’s obligations. A management committee is established as the supreme body of the license joint venture, in which all licensees are represented. All petroleum produced is allocated to the licensees in accordance with their shares in the licence. One of them is appointed by the MPE as operator, who becomes responsible for the daily operations of the parties’ joint activities in accordance with the terms for the production licence.

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. To Statoil's knowledge, this power of veto has never been used.

Interests in production licences may be transferred directly or indirectly subject to the consent of MPE and approval by the Norwegian Ministry of Finance ("MoF"). In most licences, there are no pre-emption rights in favour of the other licensees. The exception is that Petoro AS, on behalf of the Norwegian State, has pre- emption rights in all licences.

Prior to commencement field development activities, 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 MPE.

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 the joint operating agreements.

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, MPE 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 9.2 "Development and Production Norway (DPN)".

9.6.3 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. For further information regarding marketing and sale of the Norwegian State's (SDFI) oil and gas, see also Section 9.6.5 "SDFI oil and gas marketing and sale" below.

Most of Statoil’s and the Norwegian State's gas produced on the NCS is sold under gas contracts to customers in the EU. The EU internal energy market has been high on the European Commission's agenda, and this market has thus been subject to continuous legislative initiatives.

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

To ensure neutrality, the petroleum regulations also stipulate that all booking and allocation of capacity is administrated by Gassco AS, an independent system operator wholly owned by the Norwegian State. Spare capacity is released and allocated to shippers by Gassco based on standard procedures. Capacity that has already been allocated to a shipper may also be transferred bilaterally between shippers.

The tariffs for the use of capacity in the transport system are determined by applying a formula set out in separate tariff regulations stipulated by the MPE. The tariffs are paid on the basis of booked capacity, not on the basis of the volumes actually transported. MPE's main objective when setting the tariffs is to ensure that the profits are extracted from the production fields on the NCS and not from the transport system.

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

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

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

At an extraordinary general meeting held on 27 February 2001, the Norwegian State, as sole shareholder, revised Statoil’s articles of association by adding a new article that requires Statoil to continue to market and sell the Norwegian State's oil and gas together with its own oil and gas. At an extraordinary general meeting

100

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

The Norwegian State has a coordinated ownership strategy aimed at maximising the aggregate value of its ownership interests in Statoil and the Norwegian State's oil and gas assets, which is reflected in the Owner's Instruction.

The principal provisions of the Owner's Instruction are set out below:

(i) 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.

(ii) Statoil’s main tasks under the Owner's Instruction are to market and sell the Norwegian State's oil and gas and to carry out all the necessary related activities, other than those carried out jointly with other licensees under production licences. This includes, but is not limited to, responsibility for processing, transport and marketing.

(iii) The Norwegian State does not pay Statoil a specific consideration for performing these tasks, but reimburses its proportionate share of certain costs, which, under the Owner's Instruction, may be Statoil’s actual costs or an amount specifically agreed.

(iv) Payment to the Norwegian State for sales of the Norwegian State's natural gas, both to Statoil and to third parties, is based either on the prices achieved, a net back formula or market value. Statoil purchases all of the Norwegian State's oil and NGL. Pricing of the crude oil is based on market- reflective prices. NGL prices are based on either achieved prices, market value or market-reflective prices.

(v) To ensure neutral weighting between the Norwegian State's and Statoil’s own natural gas volumes, a list has been established for deciding the lifting priority between each individual field. The different fields are ranked in accordance with their assumed total value creation for the Norwegian State and Statoil, assuming that all of the fields meet Statoil's profitability requirements if it participates as a licensee and the Norwegian State's profitability requirements if the State is a licensee. Within each individual field in which both the Norwegian State and Statoil are licensees, the Norwegian State and Statoil will deliver volumes and share income in proportion to its respective participating interests.

The Norwegian State's oil and NGL is lifted together with Statoil's oil and NGL in accordance with applicable lifting procedures for each individual field and terminal.

(vi) The Norwegian State may at any time utilise its position as majority shareholder of Statoil to withdraw or amend the Owner's Instruction.

9.6.6 Environmental conditions 9.6.6.1 HSE regulation Statoil’s petroleum operations are subject to extensive laws and regulations relating to health, safety and the environment ("HSE").

In Norway, under the Petroleum Act, Statoil’s oil and gas operations must be conducted in compliance with a reasonable standard of care, taking into consideration the safety of employees, the environment and the economic values represented by installations and vessels. The Petroleum Act specifically requires that petroleum operations be carried out in such a manner that a high level of safety is maintained and developed in step with technological developments. Statoil is also required at all times to have a plan to deal with emergency situations in Statoil's petroleum operations. During an emergency, the Norwegian Ministry of Labour/Norwegian Ministry of Fisheries and Coastal Affairs/Norwegian Coastal Administration may decide that other parties should provide the necessary resources, or otherwise adopt measures to obtain the necessary resources, to deal with the emergency for the licensees' account.

101

9.6.6.2 Liability for pollution damage Chapter 7 of the Petroleum Act imposes strict liability for pollution damage for all licensees, and a licensee is liable for pollution damage without regard to fault. However, if it is demonstrated that an inevitable event of nature, act of war, exercise of public authority or a similar force majeure event has contributed to a considerable degree to the damage or its extent under circumstances which are beyond the control of the liable party, the liability may be reduced to the extent it is reasonable, with particular consideration to the scope of the activity, the situation of the party that has sustained damage and the opportunity for taking out insurance on both sides.

A claim against the license holders for compensation relating to pollution damage shall initially be directed to the operator, which in accordance with the terms of the joint operating agreement,- will distribute the claim to the other licensees in accordance with their participating interest in the license. If any of the licensees fails to cover his share, the liability relating to this share shall be allocated proportionately between the others licensees. Furthermore, the statutory regulations also restrict the licensees’ right to claim recourse in cases where pollution damage is caused by their contractors’ act or omissions.

As a holder of licences on the NCS, Statoil is subject to statutory strict liability under the Petroleum Act in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of Statoil's licences. This means that anyone within the state or the delineation of the NCS who suffers losses or damage as a result of pollution caused by operations in any of Statoil's NCS licence areas can claim compensation from Statoil without having to demonstrate that the damage is due to any fault on Statoil's part.

9.6.6.3 Discharge permits Emissions and discharges from Norwegian petroleum activities are regulated through several acts, including the Petroleum Act, the CO2 Tax Act, the Sales Tax Act, the Greenhouse Gas Emission Trading Act and the Pollution Control Act. Discharge of oil and chemicals in relation to exploration, development and production of oil and natural gas are regulated under the Pollution Control Act (the "Pollution Act"). In accordance with the provisions of the Pollution Act, the operator must apply for a discharge permit from relevant authorities on behalf of the license group in order to discharge any pollutants into the water. Further, the Petroleum Act states that burning of gas in flares beyond what is necessary to ensure normal operations is not permitted without approval from the MPE. All operators on the NSC are under an obligation to and responsible for establishing sufficient procedures for the monitoring and reporting of any discharge into the sea. The Climate and Pollution Agency, the Norwegian Petroleum Directorate and the Norwegian Oil Industry Association have established a joint database for reporting emissions to air and discharges to sea from the petroleum activities, «Environmental Web» (EW). All operators on the NCS report emission and discharge data directly into the database.

9.6.6.4 Emission regulations – reduction of carbon emissions Statoil's operations in Norway are subject to emissions taxes as well as emissions allowances granted for Statoil's larger European operations under the emissions trading scheme. The agreed strengthening of the EU's emission trading scheme may result in a significant reduction in the total emissions from relevant energy and industry installations which includes Statoil’s installations at the NCS. The price of the emissions allowances is also expected to increase significantly towards 2030. At the 21st Conference of Parties in Paris in December 2015, 195 countries adopted a new universally applicable climate agreement, to be effective from 2020. The Norwegian Parliament decided that Norway should negotiate with the EU to develop the terms for collective delivery of a 40% reduction in greenhouse gas emissions by 2030 compared to 1990. Individual countries’ climate plans, the so-called ‘Intended Nationally Determined Contributions’, are to be strengthened every five years. The implications for the industry are not yet clear, however requirements to reduce emissions could imply increased costs.

The EU Fuel Quality Directive 2009/30/EC and its Implementation Directive 2015/652/EU require fuel suppliers to reduce their carbon intensity for transportation fuels by 6% in 2020 compared to the baseline of 2010. Fuel suppliers can use biofuels, low carbon fuels (e.g. natural gas), charging of electric vehicles and upstream emission reductions to achieve the target. Member States may set penalties on fuels suppliers for not achieving the target. The EU Commission will submit a non-legislative guidance document before April 2017 which will

102

propose common principles on verification and accounting of upstream emissions reductions. The regulation could indirectly impact Statoil if it results in incentives for service station companies to increase the share of biofuels versus fossil fuels.

Statoil incorporates a cost for carbon in the assessment of all new projects. This guides Statoil's strategy and its investment decisions. For investment decisions pertaining to oil and gas projects in Norway, Statoil includes an internal cost of USD 64 per tonne of CO2-equivalent (based on the average annual exchange rate in 2015), based on the cost of the Norwegian CO2 tax. In 2014, Statoil began to apply an internal cost of USD 50 per tonne of CO2-equivalent in its investment decisions for all new oil and gas projects outside of Norway.

9.6.6.5 Decommissioning and abandonment The Petroleum Act requires licensees to submit a decommissioning plan to MPE between two and five years before the licence expires or is relinquished, or use of a petroleum installation will be terminated permanently. A decommissioning plan consists of two parts: an impact assessment and plans for disposing of the installations.

The impact assessment must provide an overview of the possible environmental and other impacts of the shutdown process. The disposal part must contain detailed plans for closing down operations and decommissioning installations in the best possible way.

Cessation of petroleum activities and decommissioning are governed by Chapter 5 of the Petroleum Act and Chapter 6 of the Petroleum Regulations. In addition, Norway is bound by international law and guidelines. In this context, Decision 98/3 under the OSPAR Convention is particularly important to the Norwegian authorities. The decision generally prohibits leaving disused offshore installations in place, with limited exceptions.

9.6.7 Taxation of Statoil in Norway 9.6.7.1 Introduction Statoil's Norwegian petroleum activities are subject to ordinary corporate income tax and to a special petroleum tax. In addition, there are taxes on both carbon dioxide emissions and emissions of nitrogen oxide (NOx).

9.6.7.2 Corporate income tax Statoil’s profits, both from offshore oil and natural gas activities and from onshore activities, are subject to Norwegian corporate income tax. The standard corporate income tax rate has been reduced from 27% in 2015 to 25% in 2016. Statoil’s profits are computed in accordance with ordinary Norwegian corporate income tax rules, subject to certain modifications that apply to companies engaged in petroleum operations. Gross revenue from oil production is determined on the basis of norm prices. Norm prices are decided on a daily basis by the Petroleum Price Board, and published quarterly. The Petroleum Tax Act states that the norm prices shall correspond to the prices that could have been obtained in a sale of petroleum between independent parties in a free market.

The maximum rate of depreciation of development costs relating to offshore production installations and pipelines is 16.67% per year. Depreciation starts when the cost is incurred. Exploration costs may be deducted in the year in which they are incurred. Financial costs related to the offshore activity are calculated directly based on a formula set out in the Petroleum Tax Act. The financial costs deductible under the offshore tax regime are the total interest costs and exchange gains and losses related to interest-bearing debt multiplied by 50% of the tax values covered by the petroleum tax regime divided by the average interest-bearing debt. All other financial costs and income are allocated to the onshore tax regime.

Abandonment costs incurred can be deducted as operating expenses. Such costs are tax deductible when the costs are incurred, i.e. when the abandonment or decommissioning is carried out by the Company.

Any tax losses can be carried forward indefinitely against subsequent income earned. 50% of losses relating to activity conducted onshore in Norway can be deducted from NCS income subject to the standard income tax rate (reduced from 27% in 2015 to 25% in 2016). Losses on foreign activities cannot be deducted from NCS income.

103

By using group contributions between Norwegian companies in which Statoil holds more than 90% of the shares and votes, tax losses and taxable income can be offset to a great extent. Group distributions are not deductible from Statoil’s NCS income.

Dividends received are subject to tax in Norway. The basis for taxation is 3% of the dividends received, which is subject to the standard income tax rate (reduced from 27% in 2015 to 25% in 2016). Dividends received from Norwegian companies and from similar companies resident in the EEA for tax purposes, in which the recipient holds more than 90% of the shares and votes, are fully exempt from tax. Dividends from companies resident in the EEA that are not similar to Norwegian companies, companies in low-tax countries and portfolio investments outside the EEA will, under certain circumstances, be subject to the standard income tax rate (reduced from 27% in 2015 to 25% in 2016) based on the full amounts received.

Capital gains from the realisation of shares are exempt from tax. Exceptions apply to shares held in companies resident in low-tax countries or portfolio investments in companies resident outside the EEA for tax purposes, where, under certain circumstances, capital gains will be subject to the standard income tax rate (reduced from 27% in 2015 to 25% in 2016) and capital losses will be deductible.

9.6.7.3 Special petroleum tax A special petroleum tax is levied on profits from petroleum production and pipeline transportation on the NCS. The special petroleum tax rate has been increased from 51% in 2015 to 53% in 2016. The special petroleum tax rate is applied to relevant income in addition to the standard income tax rate, resulting in a 78% marginal tax rate on income subject to the special petroleum tax. The basis for computing the special petroleum tax is the same as for income subject to ordinary corporate income tax, except that onshore losses are not deductible from the special petroleum tax basis, and a tax-free allowance, or uplift, is granted at a rate of 5.5% per year. The uplift is computed on the basis of the original capitalised cost of offshore production installations. The uplift can be deducted from taxable income for a period of four years, starting in the year in which the capital expenditure is incurred. Unused uplift can be carried forward indefinitely. For further information see note 9 Income taxes in the financial statements for 2015, which have been incorporated by reference, see Section 17.1 "Cross reference table".

9.6.8 Other economic conditions In addition, other economical obligations related to exploration and production of oil and gas on the NCS applies. For further information see Section 9.7.6 "Economic conditions", which also applies to Norway.

9.7 Applicable regulations and taxation outside Norway 9.7.1 Introduction Statoil's international petroleum activities are subject to local legislation and tax. Currently, Statoil is subject to two main regimes applicable to petroleum activities worldwide:

• Fiscal regulation of Statoil’s upstream operations is generally based on corporate income tax regimes; and/or

• production sharing agreements (PSAs).

Royalty payments may be applicable under both regimes. Statoil is also subject to excess (or "windfall") profit tax in some of the countries in which it produces crude oil or condensate. A general description of these regimes is provided below in Section 9.7.2 "Summary of main regimes outside Norway" and a more detailed description of the applicable regulations in each of the Americas, Africa and Eurasia have been provided below in Section 9.7.3 "The Americas", Section 9.7.4 "Africa" and Section 9.7.5 "Europe and Asia (except Norway)".

With business operations in more than 30 countries, Statoil is subject to a wide variety of HSE laws and regulations concerning its products, operations and activities. Laws and regulations may be jurisdiction specific, but also international regulations, conventions or treaties, as well as EU directives and regulations, are relevant.

104

As each of the Americas, Africa and Eurasia comprise of a number of jurisdictions in which Statoil has production in a various degree, a detailed description of applicable regulations has only been included for jurisdictions that are deemed to be material and important to Statoil based on value, production and operatorship. International production contributed with 32% of Statoil’s total Entitlement Production in 2015.

9.7.2 Summary of main regimes outside Norway 9.7.2.1 Production sharing agreements (PSAs) Under a PSA, the host government typically retains the right to the hydrocarbons in place. The contractor receives a share of the production for services performed. The contractor carries all costs through the exploration, development and production phase and receives a share of the production to recover its costs. Normally, the contractors carry the exploration costs and risk prior to a commercial discovery and are then entitled to recover those costs during the production phase. The remaining share of the production "the profit share" is split between the government and the contractor. Under a PSA the host government retains the right to the hydrocarbons in place. The state's share of profit oil typically increases based on a success factor, such as surpassing certain specified internal rates of return, production rates or accumulated production. The contractor is usually subject to income tax on its own share of the profit oil. Fiscal provisions in a PSA are to a large extent negotiable and are unique to each PSA. The PSAs are normally governed by domestic law but disputes between the government and the contactor are to be resolved through international arbitration.

PSAs are normally awarded to the contractor parties after bidding rounds announced by the government. Companies can bid individually or as a group after having entered into joint bidding agreements. Main bid parameters are a minimum exploration programme and signature bonuses. Normally the contractor under a PSA consists of several companies. The relationship between these companies is regulated through joint operating agreements where each companies participating interest is set. The contractor’s costs and the share of petroleum are allocated to the companies based on their participating interest under the joint operating agreements.

9.7.2.2 Income tax regimes Under an income tax regime, companies are granted licences by the government to extract petroleum, similar to the Norwegian system, see Section 9.6.2 "The Norwegian licencing system". In the US, as land also is owned by private persons, leases are also entered with private individuals. Typically the licensees are offered to pre-qualified companies following bidding rounds. The criteria for the evaluation of bidding offers under these regimes can be the level of offered signature bonus (bid amount), minimum exploration programme, and/or local content. The successful bidder(s) will receive a right to explore, develop and produce petroleum within a specified geographical area and a limited period of time in exchange for those commitments. The terms of the licences are usually not negotiable. The fiscal regime may entitle the state to royalties, which are generally assessed on gross revenue from production, and a profit tax, which is generally based on the company's net taxable income from production as defined in a country's domestic tax legislation. In some countries, income from petroleum activities is also subject to a special petroleum tax in addition to ordinary corporate tax. In general, the fiscal terms surrounding these licences are non-negotiable and the company is subject to legislative changes in the tax laws.

9.7.3 The Americas In the Americas, US and Brazil are the main contributors to Statoil's international production where US is by far the highest contributor in 2015. For additional information, see Section 9.3.2 "International production".

9.7.3.1 United States Petroleum activities in US are extensively regulated by multiple agencies in the US federal government, and by tribal, state and local regulation. The US government directly regulates development of hydrocarbons on federal lands, in the US Gulf of Mexico, and in other offshore areas. Different federal agencies directly regulate portions of the industry, and other general regulations related to environmental, safety, and physical controls apply to all aspects of the industry. In addition to regulation by the US federal government, any activities on US tribal lands (indigenous persons’ semi-sovereign territory) are regulated by governments and agencies in those areas. Very significantly for Statoil’s US onshore interests, each individual state has its own regulations of all aspects of hydrocarbon development within its borders. A recent trend also includes local municipalities adopting their own hydrocarbon regulations.

105

In US, hydrocarbon interests are considered as private property right. In areas owned by the US government, that means that the government owns the minerals in its capacity as land owner. This includes most offshore development, although near-shore minerals are owned by the individual adjoining states. Similarly, tribal governments and state governments own minerals under lands which are directly owned by those governmental units. The federal government, and each tribal and state government, establish the terms of their own leases, including the length of time of the lease, the royalty rate, and other terms. A very significant percentage of onshore minerals (the vast majority in every state in which Statoil has onshore interests), including hydrocarbons, belong to private individuals.

In order to explore for or develop hydrocarbons, a company must enter into a lease agreement from the governmental agency for federal, state or tribal land, and for private lands, from each one of the individuals owning the minerals the company wishes to develop. For federal lands, leases are awarded through periodic auctions held by the Bureau of Land Management (BLM) (onshore) and the Bureau of Ocean Energy Management (BOEM) (offshore). Similar state agencies award leases for state-owned lands. Private owners of mineral rights negotiate leases with operators. In each lease, the lessor retains a royalty interest in the production from the leased area (if any). The lessee owns a working interest and has the right to explore and produce oil and gas. A lessee incurs all the costs and liabilities, but will share only the portion of the revenue that is net of costs and expenses and not reserved to the lessor through its royalty interest. If for example the drilling is unsuccessful the lessee may not obtain any revenue, but remains responsible for all the costs of drilling and subsequently plugging the well.

The terms of each lease vary, including length and royalty rate. Leases typically have a primary term for a specified number of years (from one to ten years) and a conditional secondary term that is tied to the production life of the properties. Unless the operator drills wells or undertakes specific actions stated in the lease (or pays an additional fee instead of such actions) the lease will terminate at the end of the term. If oil and gas is being produced in paying quantities at the end of the primary term or the operator satisfies other obligations specified in the agreement, the lease typically continues beyond the primary term (Held By Production "HBP"), which is the current term for all Statoil’s producing assets in the US, see Section 9.3.2 "International production", (footnote 2 to the second table). Leases typically involve paying the lessor both signing bonus based on the number of leased acres and royalty payment based on the production.

Key federal agencies that may have jurisdiction over the extraction of oil and gas include: 1) Department of Interior (DOI), which regulates the extraction of oil and gas from federal lands; 2) Bureau of Land Management (BLM), which regulates oil development, exploration, and production on federal onshore properties; 3) Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), which manage offshore oil production operations; 4) Office of Natural Resources Revenue (ONRR), which collects royalties owed to the government for onshore and offshore production; 5) Bureau of Indian Affairs (BIA), which, along with the BLM, regulates oil development of native Indian lands; 6) Federal Energy Regulatory Commission (FERC), which regulates inter-state pipelines; 7) Department of Energy (DOE), which handles the Strategic Petroleum Reserve, conducts energy research, and gathers and analyses energy industry data; and, 8) Environmental Protection Agency (EPA), which provides oversight for environmental, health, and safety issues.

Each state has its own agencies that regulate the development, exploration, and production of oil and gas activities. These state agencies issue drilling permits and control pipeline transportation within state boundaries. Particularly relevant to Statoil’s US onshore activities, these state agencies include: 1) Railroad Commission of Texas; 2) Pennsylvania Department of Environmental Protection's Office of Oil and Gas Management; 3) Ohio Department of Natural Resources, Division of Oil and Gas; 4) West Virginia Department of Environmental Protection; and 5) North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division. In addition, some state utility departments handle pipeline transportation within state boundaries, and each state also has its own department regulating environmental, health, and safety issues arising from oil and gas operations.

Enforcement of regulation is as varied as the regulatory regimes that govern hydrocarbon development. Each federal and state agency has its own enforcement powers, which include the ability to assess fines, stop operations, debar (revocation of the right to operate), and assess criminal penalties against companies and individuals. In addition, many statues and regulations give private rights of action to private individuals, and all

106

interactions between companies and individuals are subject to general US contract and tort law, which results in a very high incidence of litigation for all aspects of the hydrocarbon industry.

The fiscal regime in North America entitles the state to income tax and royalties where the state is the lessor. Federal tax regulations also provide numerous special rules and deductions relating to the income taxes charged for exploration and production of oil and gas.

In the US, the Environmental Protection Agency has taken steps to regulate greenhouse gas emissions under the Clean Air Act authority by proposing a clean power plan. The plan aims to reduce emissions from the US power sector by setting performance standards for power plants. The regulation, if approved, could stimulate increased gas demand. In 2015, the EPA also proposed new source performance standards, in addition to those issued in 2012, targeting volatile organic compound emissions, that are intended to further reduce oil and gas methane emissions. This could imply additional costs for oil and gas producers.

9.7.3.2 Brazil Prior to 1995, the exploration and exploitation of oil and gas resources in Brazil were government monopolies carried out exclusively by Petróleo Brasileiro SA (Petrobras). In 1995 the Brazilian Constitution was amended allowing the federal government to contract state or privately-owned company to carry out the activities related to the upstream and downstream segments of the Brazilian oil and gas sector.

Additionally, Federal Law N. 9,478/1997 (the Petroleum Law) established a new regulatory framework and introduced new regulatory agencies for the oil and gas sector: the National Agency of Oil, Natural Gas and Biofuels (ANP) and the National Council of Energy Policy (CNPE).

The CNPE is an advisory entity linked do the Brazilian President. CNPE's function is to propose to the president's policies specific measures to promote the rational use of energy resources; reviewing energy matrixes for different regions of Brazil and setting guidelines. ANP was created to regulate the oil and natural gas sector and to promote the development and production of oil and natural gas in Brazil’s sedimentary basins through a transparent and competitive bidding process. Such entities are subordinated to the Ministry of Mines and Energy (MME).

Since 1999, following the opening of the market, ANP has conducted 13 bidding rounds for exploration blocks under the concession regime in which companies holding concession rights to explore the resources are entitled to the property of their production.

All state-owned and private oil companies may participate in the concession bidding rounds. The tender protocol issued for each bidding round contains the draft of the concession agreement that the winners must adhere to without the possibility of negotiating its terms, i.e., all the concession agreements signed under a certain bidding round contain the same general provisions and only differ in the particular items presented in the offers. The tender protocol also establishes all the technical, financial and legal requirements with which a concessionaire must comply. There is no restriction on foreign participation, provided that the foreign investor incorporates a company under the Brazilian law and complies with the requirements established by the ANP.

Bidding offers may be submitted by companies individually or jointly in consortium. In case of a consortium, a qualified operator among them shall be indicated. The criteria for the evaluation of bidding offers under the concession regime are: (a) signature bonus; (b) minimum exploration programme; and (c) local content.

In general terms, concessions are granted for the total period of 30 years and typically the exploration phase lasts from two to eight years, usually divided into different periods with specific commitments, while the production phase may last 27 years as of the declaration of commerciality. Concessionaires are entitled to request the extension of each of these phases, subject to ANP approval.

In order to perform the exploration and exploitation of oil and gas resources, the companies must obtain an environmental license granted by the Federal Environmental Protection Agency (IBAMA), which, together with ANP, is responsible for the safety and environmental regulations regarding upstream activities.

107

The environmental licensing procedure in Brazil embraces the analysis of documents, projects and environmental studies submitted by the entrepreneur. Brazilian regulation also imposes the presentation of an environmental impact assessment and an environmental impact assessment report (EIA/RIMA) by the entrepreneur, which is mandatory for facilities that perform activities of significant environmental impact.

The performance of upstream activities without the necessary environmental licensing may subject the company to administrative and criminal sanctions.

In addition to MME, CNPE, ANP and IBAMA, oil and gas activities in Brazil are also subject to the rules and regulations of the Ministry of Labor, Navy, Tax and custom authorities, National Health Surveillance Agency (ANVISA), Federal Police, among others.

REPETRO is a special custom regime, which aims at reducing the tax burden on the investments for research, exploration and production of oil and gas fields, onshore or offshore. It is only applicable to the goods that are directly related to oil and gas research and exploration. The eligible goods are listed by Brazilian tax authorities.

REPETRO permits the total suspension of payment of federal taxes due on import of equipment and materials temporarily admitted to Brazil. REPETRO also permits the Brazilian companies to treat the sale of equipment and materials produced in Brazil to foreign companies, to be used locally, as a fictitious export. Such equipment and materials may be subsequently admitted in Brazil under the REPETRO temporary import regime and be granted with its tax benefits. Drawback is also included in REPETRO, permitting the suspension of taxes levied on the import of raw materials, inputs and parts to be applied on the manufacturing of equipment and materials to be fictitious exported and subsequently admitted under REPETRO.

In all these situations listed above, the imported items have a limited time to stay within the Brazilian territory – which corresponds to the term of the concession (in case the applicant is the concessionaire) or the term of the services agreement (in case the applicant is a contractor of the concessionaire) – and once such time has elapsed they must be re-exported, or definitely imported with the payment of suspended taxes, or destroyed.

Such regime will only be granted until 31 December 2020, according to the latest updating in the REPETRO legislation. Accordingly, there is a currently discussion between the legal scholars if REPETRO benefits would be extinct from such date or if 2020 would be a final term for the companies to request these benefits. Until now, the RFB has not issued a position.

Income and capital gains earned by Brazilian legal entities are subject to Corporate Income Tax and Social Contribution on Net Profits. Gains realized by a non-resident on the sale or disposal of any assets located in Brazil are subject to withholding income tax.

The Social Security Financing Contribution and the contribution to the Social Integration Program are federal taxes levied on monthly gross revenues.

9.7.4 Africa After the US, Angola was the second highest contributor to Statoil’s international production in 2015.

9.7.4.1 Angola Under the Angolan Constitution, the State is the owner of all national resources within the Angolan jurisdiction. Consequently, all mining rights are exclusively assigned to the National Concessionaire.

In Angola, the oil and gas sector is first and foremost regulated by the Ministry of Petroleum, which is responsible for the coordination, supervision and control of activities related to the oil and gas sector and in setting their policies and guidelines. Under the Petroleum Activities Act 10/04 (PAL), the government, through the Ministry of Petroleum is responsible for granting concessions for the exploration and exploitation of hydrocarbons and the granting of prospecting licenses.

In 1976, the Angolan government incorporated Sonangol as public company to control the exploitation of hydrocarbons in Angola. The legislation establishes that all oil mineral rights belong to the state and that the

108

state oil company Sonangol is the sole concessionaire (the National Concessionaire) of rights to all exploration and production activities. Sonangol is also the entity responsible for exploration, production, manufacturing, transportation and marketing of hydrocarbons and its derivatives in Angola. Sonangol's activities are supervised by the Angolan Ministry of Petroleum. The petroleum concession is issued by the Angolan government through publication of a concession decree that will establish the term of the license and its different periods and phases.

The National Concessionaire may carry out petroleum operations on its own or may associate with companies – both national and foreign – which can also participate directly in the oil block, either as an operator or as a partner provided that are of recognized capacity, technical knowledge and financial capability, and such may take the following forms (a) Corporation; (b) Consortium; (c) PSAs; and (d) Risk Service Agreements. To date, Sonangol has entered into arrangements with third parties only by way of a PSA which is the current association for Statoil’s presence in Angola.

PAL contemplates both bid rounds and open tenders, although typically a request for proposal to tender is provided to a limited number of international oil companies ("IOCs"). The bid parameters are a minimum exploration programme and the level of signature bonuses.

The PSA sets out the relevant production sharing terms. Sonangol in its role as National Concessionaire is a party to all PSAs executed in Angola and it is contractually entitled to receive part of the profits made under the terms and conditions established in each PSC. The terms of the PSA entered into are then approved by the concession decree. There is model form PSA (the Model PSA), which forms the basis for negotiations. Under the Model PSA, the contractor may recover the costs of petroleum operations out of an agreed percentage of the available production. Unrecovered costs can be carried forward, and the balance of petroleum produced and saved and not used in petroleum operations or for cost recovery is shared between Sonangol and the contractor in an agreed ratio according to the after tax, nominal rate of return achieved by the contractor group at the end of the preceding calendar quarter. The nominal rate of return is determined by applying an agreed rate of return to the contractor’s cumulative net cash flow. Cumulative net cash flow is the market value of the contractor’s share of petroleum production (cost oil and profit oil) less Petroleum Income Tax and less development expenditures and production expenditures.

Petroleum operations in Angola may only be carried out under a prospecting license or a petroleum concession. With regards to the prospecting license, any Angolan or foreign company with the necessary technical knowledge and financial capability may apply to the Ministry of Petroleum for the issuance of a three-year license (exceptionally extendable at the request of the licensee) to determine the petroleum potential of a given area. The prospecting license includes geological, geochemical and geophysical research, and the processing, analysis and interpretation of the acquired data, as well as regional studies and mapping, for the purpose of locating oil and natural gas fields, but does not does grant the holder any preferential rights in relation to the subsequent entry into an agreement with Sonangol regarding the exploration for and exploitation of hydrocarbons in the area to which the prospecting license relates

The operator of the petroleum operations in respect of an area is appointed in the relevant concession decree after having been proposed as the operator by Sonangol. To be appointed as operator, a party will need to demonstrate the requisite technical and financial capability. Under the terms of the Model PSA, the exploration period and production periods are biddable items. The exploration period can be extended once. Following a declaration of a commercial discovery, a development and production plan must be approved by the Ministry and the start of commercial production requires a further approval.

The Petroleum Taxation Law 13/04 (PTL) provides the fiscal framework generally applicable to petroleum operations in Angola. When petroleum operations are carried out under a PSA, Petroleum Income Tax is the only tax in respect of petroleum production

According with Environmental Framework Law 5/98 and with Decree 39/00 regulating the Environmental Protection From Oil Activities, all projects to be developed within the scope of the oil and gas sector require the presentation of a number of different reports and studies. The most important report is an Environmental Impact Assessment. Angola has ratified the following international treaties related to safety and environmental protection on the oil and gas activities; a) International Convention on Civil Liability for Oil Pollution Damage;

109

b) International Convention Relating to Intervention on the High Seas in Cases of Oil Pollution Casualties; c) International Convention on Oil Pollution Preparedness, Response and Co-operation.

The Environmental Framework Law and respective regulations requires that companies and individuals wishing to carry out any activities that may harm the environment complete an environment impact assessment prior to commencing those activities. It also imposes a strict-liability standard, stating that anyone that causes damage to the environment, irrespective of fault shall be required to repair the damage and compensate the state. It is up to the court system to assess the seriousness of the damages, by recourse to experts.

The Environmental Framework Law also determines that those carrying out potentially dangerous activities, including petroleum exploration and production activities, shall perform environmental impact studies (as per the environmental impact assess regulations), and carry an insurance policy to cover the inherent risks.

The PAL includes an express provision on environmental protection, which states that in carrying out their operations, entities engaged in oil and gas exploration and production "shall take all necessary measures to protect the environment." Exploration and production companies must submit to the Ministry of Petroleum all statutorily required plans, specifying the practical measures they will implement, including environmental impact studies, environmental audits, as well as risk-management and environmental-recovery plans.

9.7.4.2 Tanzania The regulatory regime in Tanzania is based on PSAs between the Government of Tanzania, TPDC (the national oil company) and the Contractor (the IOCs), and the Petroleum Act 2015 ("PA15") supplemented by tax and other relevant legislation. Under PA15 the Minister of Energy and Minerals grants upstream licences to TPDC, which is the licence holder, but which contracts the operations to the IOCs. The current exploration licence has a duration of 11 years (4 + 4 + 3 years) and there are certain commitments to conduct seismic studies and drill exploration wells in the two extension periods. For development of discoveries a development licence of initially 25 years will be granted. This licence can be extended once with 20 years. For a situation where the development concept is not sufficiently matured at the expiry of the exploration licence, the PSA provides that a new exploration licence shall be granted. Such licence shall bridge the gap until a development plan can be completed and an exploration license applied for and granted.

In addition to set out the exploration commitments, the right to cost recovery and production sharing and how TPDC and the Contractor shall cooperate, the PSA contains regulation on tax and fiscal matters, local content and training, stabilization of terms and dispute resolution through arbitration. The PSA is supplemented by the PA15. This new act replaced the Petroleum Exploration and Production Act of 1980. The PA15 set the regulatory framework and it covers the full petroleum value chain (up-, mid- and downstream). The PA15 introduced an upstream and a downstream regulator, PURA and EWURA, respectively. The introduction of PURA which shall oversee the upstream operations and advice and the Minister on resources management etc., has the implication that TPDC is transformed from a combination of regulator and oil company to national oil company with certain exclusive rights.

The PA15 is a comprehensive act and an important milestone for Tanzania. Its provisions do, however, not fully cater for an integrated value chain development consisting of a deep offshore developments and an onshore LNG plant. Furthermore, PA15 was enacted in a rush, and many provisions of the act are vague, inconsistent or insufficient. The PSAs are recognised ("grandfathered") under PA15 and provide a reasonable basis for the petroleum activities to date. However, the PSAs of Block 2 and Blocks 1 & 4 do not contemplate a joint, onshore LNG development, and they have shortcomings in the details of regulation which are required for a complex and integrated gas and LNG development. The partners have therefore set as a requirement that a Host Government Agreement ("HGA") between the Government of Tanzania and the sponsors (the IOCs and TPDC) is established to provide for the tailor-made solutions and the predictability need for undertaking the major investment. Furthermore certain modifications/supplements to the PSAs as well as bespoke legislation (derogating from PA15 and other applicable legislation) will also be required.

The HGA, similarly to the PSAs, will be an investment agreement. The content of the HGA will build on the PSAs but take into account the differences in the type of activity undertaken under the agreement, for instance it is anticipated that the economic model for the LNG plant be based on a tolling tariff. The purpose of the HGA will be to secure a financeable LNG project and lifetime stable and reliable framework conditions.

110

9.7.5 Europe and Asia (except Norway) Statoil's production in Europe and Asia encompasses Azerbaijan, Russia, Ireland and the United Kingdom, all of which have different regulation and tax regimes. Eurasia excluding Norway contributed in 2015 with less than 3.2% of Statoil's total production, with Azerbaijan being the main contributor. Statoil's production in Eurasia (excluding Norway) does accordingly not provide substantial contributions compared to Statoil's total production.

9.7.6 Economic conditions The economical obligations related to exploration and production of oil and gas, will depend on the type of petroleum activities carried out, and there are different economic conditions which will apply to exploration, field development and production. Although the local regulatory regimes may differ, conditions for exploring and producing oil and gas also have some similarities worldwide. In most licences and PSAs there will be more than one participant and their relation will be regulated by joint operating agreements or similar. In the exploration phase, the participating companies usually have committed to a work programme that has to be fulfilled. A work programme will typically consist of obligation to acquire seismic and or drill one or more exploration wells. In case the programme is not fulfilled, the licence period will expire. If the exploration is successful, the partners will usually pursue development. In some countries, a new application has to be filed while in some other the licence is renewed. The development will subject to an investment decision by the participating companies. In most licences, a party not being willing to invest has the possibility to withdraw from the licence and assign its interest free of charge. If a positive development decision has been taken, the participating companies will have an obligation to contribute their share. In the production phase, there will be a continuous obligation to provide funds for the operations. A corresponding interest to the produced oil and gas will be allocated to each participating company with an obligation to lift its entitlement according to an agreed or defined lifting schedule. In some countries participating company may take its entitlement in kind and trade in own name and risk, while in other countries there is only a sole state owned company that has a permit to trade. Consequently the participating company will only have right to the value of the petroleum sold. In the decommission phase, there is normally an obligation to remove installations as further regulated by the relevant state. There is often a joint liability among the participating company for this decommissioning which again may be secured by third party financial security.

Throughout all phases, there is usually a possibility to assign the interest to a third party.

Licence/field specific information is normally confidential due to provisions in the applicable participating and joint operation agreements.

9.8 Material contracts Statoil has no material contracts, other than contracts entered into in the ordinary course of business, to which the Company or any member of Statoil is a party, for the last year immediately preceding publication of this Prospectus. Nor does Statoil have any other contract, other than entered into in the ordinary course of business, which contains any provision under which Statoil has any obligation or entitlement which is material to the Company or any member of Statoil.

Below is a summary of the main categories of contracts entered into by Statoil in ordinary course of business:

• Exploration, development and production activities worldwide are dependent on permits, awards, concessions from authorities and agreements with partners or authorities. Details of this framework are described in Section 9.6 "Applicable laws and regulations for Norway" and Section 0 "Applicable regulations and taxation outside Norway".

• Also within NES, Statoil is a party to a number of agreements including but not limited to shareholder agreements and joint venture agreements.

• Statoil in its capacity as operator of a large number of licences and fields enters into numerous contracts with suppliers of goods and services within the following main categories: drilling and well which among other includes procurement of mobile drilling units, capital projects (e.g. to large contracts for engineering, construction and installation of platforms, transportation of these or part

111

of these, hook-up of the installation, agreements for heavy lifting, agreements for pipeline fabrication and installation ), operations (amongst other floatels, maintenance and modifications, offshore transportation, stand –by and supply vessels) and business support. The total global spend under such contracts in 2015 was around NOK 171 billion (USD 20.8 billion).

• Statoil mainly transports the products it produces to the market via pipeline, vessels or railcars. Transportation via pipeline is either performed using capacity in pipelines owned by Statoil or by purchasing transportation capacity in pipelines owned by third parties or by third party joint ventures (where Statoil may be one of the co-owners). To a large extent pipeline capacity is heavily regulated granting third parties access to the transportation capacity on an objective and transparent basis, so-called third party access regulations. Capacity for transportation via vessels or rail-cars is provided via various leasing arrangements, such as charter parties for vessels and other leasing arrangements for railcars.

• The main products that Statoil markets are crude oil, NGLs, refined products, natural gas and electricity generated from off-shore wind mills. For all of these products there are regional or worldwide liquid marked places where the products are sold over commodity exchanges, on physical HUBs or over the counter with bespoke third parties ("OTC"). Sales are performed under a variety of different contracts from standardized exchange/HUB based contracts to bespoke individual OTC contracts.

• Mergers, acquisitions and divestments are performed as part of Statoil’s ordinary course of business. For further information of recent transactions see Section 9.2.1 "DPN overview", Section 9.3.1 "DPI overview", Section 10.3.2 "Historical investments" and Section 10.3.4 "Future investments".

9.9 Dependency on licences, patents etc. The Company’s core activity is to explore, develop and produce energy sources globally, mainly oil and gas sources. Access and title to such sources is dependent on licenses, awards, permits and agreements issued by governmental bodies.

Statoil owns approximately 600 patent families. The Statoil patent portfolio comprises a wide range of different patents and patent applications, both apparatus patents (covering equipment technology) and method patents. The patent families are mostly within a wide range of oil and gas technology areas, spanning from pipeline, subsea compression equipment and systems, valves technologies, to different work methods/processes and seismic and data interpretation technologies. Statoil also owns a group of patents related to wind technology (Hywind concept). The patents are extended to countries relevant for Statoil’s business, typically between 5 and 10 countries; however some are extended to a larger number of countries. Some Statoil patents are kept and used exclusively by Statoil, while some are licensed out to suppliers and/or other operators.

However, notwithstanding that some licenses, awards, permits, patents and agreements are particularly important to the Company’s profitability; the Company is not dependent on one single license, award, permit, patent or agreement.

9.10 Legal and arbitration proceedings In the ordinary course of business, companies in the Statoil group are subject to a number of other loss contingencies arising from litigation and claims raised by governmental and private parties, for instance contractors, tax authorities, land owners for on-shore activities and buyers of Statoil’s products.

The Company is currently not aware of any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened) or claims in the 12 months prior to the date of this Prospectus, which may have, or have had in the recent past, individually or aggregate, significant effects on the Statoil’s financial position or profitability or on the results of its operations or liquidity, including the legal proceedings described below in this Section and the redetermination related to OML128 in Nigeria mentioned in Section 9.3.2.3 "Sub-Saharan Africa".

Statoil is currently defending multiple, but individually immaterial, royalty litigations and arbitrations, some on behalf of large classes of mineral owners, relating to its operated and non-operated positions in the Marcellus

112

and Eagle Ford shale plays. Mineral owners in these proceedings generally allege that Statoil has breached their oil and gas leases by first paying royalty on the basis of an impermissibly-low unit price, and second taking prohibited and/or excessive deductions for post-production costs. The cases are in various procedural stages and are typical disputes for oil companies in the US onshore business. None of the litigations or arbitrations is currently set for trial or final hearing and Statoil does not consider that these litigations or arbitrations, individually or aggregate, have a significant effect on Statoil.

113

10 FINANCIAL INFORMATION 10.1 Capitalisation and indebtedness 10.1.1 Introduction The information presented below should be read in conjunction with the other parts of this Prospectus, in particular the Financial Statements and the Interim Financial Statements, which have been incorporated by reference, see Section 17.1 "Cross reference table".

This Section provides information about Statoil’s unaudited consolidated capitalisation and net financial indebtedness on an actual basis as at 30 June 2016. There has been no material change to Statoil’s unaudited consolidated capitalisation and net financial indebtedness since 30 June 2016. This Section does not show the effects of the Dividend Issue.

As from first quarter 2016, Statoil changed its presentation currency to USD.

10.1.2 Capitalisation1 As at 30 June 2016

Actual In USD millions (unaudited) Indebtedness Total current debt: 15,349 Guaranteed Secured Unguaranteed and unsecured 15,349 Total non-current debt: 55,449 Guaranteed Secured2 50 Unguaranteed and unsecured 55,400 Total indebtedness 70,798 Shareholders’ equity Share capital 1,145 Legal reserves Other reserves3 39,094 Total shareholders’ equity 40,239 Total capitalisation 111,037

1) Both interest bearing and non-interest bearing elements are included in table. Statoil's reported net debt to capital employed in its annual financial statements on form 20-F and interim quarterly report only includes interest-bearing debt.

2) A secured bank loan in NOK has been secured by real estate and land with a total book value of NOK 0.6 billion (USD 0.7 million) 3) Other reserves include additional paid in capital, retained earnings, currency translation adjustment, available for sale financial assets and non- controlling interest

114

10.1.3 Indebtedness1 As at 30 June 2016

In USD millions Actual (unaudited) (A) Cash 1,117 (B) Cash equivalents 5,644 (C) Trading securities2 9,220 (D) Liquidity (A)+(B)+(C) 15,982 (E) Current financial receivables3 6,268 (F) Current bank debt 16 (G) Current portion of non-current debt 945 (H) Other current financial debt 14,383 (I) Current financial debt (F)+(G)+(H)4 15,344 (J) Net current financial indebtedness (I)-(E)-(D) -6,906 (K) Non-current bank loans 97 (L) Bonds issued 29,290 (M) Other non-current loans 26,062 (N) Non-current financial indebtedness (K)+(L)+(M)5 55,449 (O) Net financial indebtedness (J)+(N) 48,544

1) Both interest bearing and non-interest bearing elements included in table. Statoil's reported net debt to capital employed in its annual financial statements on form 20-F and interim quarterly report only includes interest-bearing debt.

2) Includes Statoil Forsikring AS current financial investment

3) Current financial receivable include trade and other receivables, derivative financial instruments

4) Current financial debt include Trade and other payables, current tax payable, finance debt, derivative financial instruments

5) Non-current financial indebtedness include finance debt, deferred tax liabilities, pension liabilities, provisions, derivative financial instruments.

10.2 Working capital statement As of the date of this Prospectus, the Company is of the opinion that Statoil’s working capital is sufficient for its present requirements and for at least the next twelve months from the date of this Prospectus.

10.3 Summary of investments 10.3.1 Introduction Statoil's portfolio consists of a large number of assets at different geographical locations, with varying financial commitment, fiscal framework and maturity. Each project and investment case is sanctioned and developed individually, within a framework which allows the Company to develop a robust and profitable portfolio of assets with an acceptable risk profile.

Statoil is continuing its focus on increased efficiency and strict capital discipline. Over the last years, Statoil has actively worked to reshape and improve the development project portfolio to increase the Company’s robustness and profitability. Projects have been stopped, divested or postponed. Projects have been challenged to optimise their development solution by refocusing and reworking concepts and cost assumptions. As result, average break-even prices have been significantly improved.

In 2013, the average break-even price for Statoil's operated non-sanctioned offshore projects (volume weighted) with planned start up by 2022 was equivalent to a Brent price of USD 70/bbl. As communicated at the Capital Markets Update on 4 February 2016, the average break-even Brent price of Statoil operated non- sanctioned projects with planned start up by 2022 has been reduced by around USD 30/bbl. In 2013, only 29% of this project portfolio had a break-even below USD 50/bbl. In the beginning of 2016, 82% of the same portfolio is estimated to have a break-even below USD 50/bbl. Following the decision to pause the Bressay project on the UK shelf, all non-sanctioned Statoil-operated projects with start up by 2022 are located on the NCS.

115

Furthermore, Statoil is working to mature development solutions for non-sanctioned operated projects in an early phase of development (i.e. with start up after 2022), in light of new industry realities and uncertainties (see Section 8 "Industry and market overview" for more details).

Statoil is working with its partners operating its non-sanctioned international projects to define optimal development solutions in line with changing local and global market conditions. Communication around these projects is the responsibility of the operator.

While the financial results were affected by low oil and gas prices in the second quarter of 2016, the operational performance with production growth and progress on project development and execution are in accordance with plans as communicated at the capital market update in February 2016. Strict prioritization, good results from Statoil's improvement programme and more effective drilling operations allows Statoil to lower its 2016 capital expenditures. The expected total organic investment level for 2016 is reduced from USD 13 billion to around USD 12 billion. The average organic investment level for 2016-2017 is expected to be between USD 11.5-13.5 billion. For the period 2018-2019, Statoil expects an average organic investment level in the range of USD 10-16 billion. This is in line with the communicated levels at the Capital Market update in February 2016. The final investment levels will be determined by market conditions in both periods. Statoil will adjust the activity level (and corresponding organic investments) to maintain a robust financial position for Statoil, while at the same time delivering profitable projects.

Statoil’s portfolio provides significant flexibility. With a large portfolio of unsanctioned projects, Statoil has the ability to optimize the timing of investment decisions of future developments. Furthermore, offshore drilling and well plans, as well as the activity level in US onshore portfolio can be adjusted on an ongoing basis. In 2015, Statoil used this flexibility and reduced organic investments to USD 14.7 billion compared to the guiding of USD 18 billion (from Capital Market Update 2015). Statoil’s portfolio provides approximately USD 2 billion of average flexibility during the period 2016-2017. For the period 2018-2019, the average capex flexibility is estimated to be USD 4-6 billion. Investment levels and the degree of flexibility for the period 2016-2019 are shown in the figure below. Beyond 2019, the flexibility further increase as decisions to invest has yet to be taken.

In addition to organic investments, portfolio transactions, i.e. acquisitions and disposals of licenses and assets, are an integrated part of Statoil’s strategy.

116

10.3.2 Historical investments Statoil has continuously a number of development projects including investments in producing assets, as well as new development projects. In the first half of 2016 the gross investments were around USD 6.7 billion (see table below for split per segment) whereof organic investments were USD 5.3 billion. The projects with the largest investments in the first half of 2016 were Johan Sverdrup, Mariner, Gullfaks and Gina Krog.

Development Development Marketing, First half of 2016 and Production and Production Midstream and (USD billion) Norway International Processing Other Gross investments split per reporting segment 3.98 2.10 0.28 0.31

Statoil acquired 11.93% of the shares in Lundin Petroleum AB for a total purchase price of SEK 4.6 billion (USD 0.6 billion) in the first quarter of 2016. On 3 May 2016, Statoil announced divestment of its entire 15% working interest in the Edvard Grieg field on NCS for an increased shareholding in Lundin Petroleum AB. The transaction also includes divestment of a 9% working interest in the Edvard Grieg Oil pipeline and a 6% working interest in the Utsira High Gas pipeline, and in addition payment of a cash consideration of USD 68 million to Lundin Petroleum AB. Following completion of the transaction Statoil will own 20.1%of the shares in Lundin Petroleum AB. The transaction was closed 30 June 2016.

10.3.3 Ongoing investments On-going investments include both producing assets and projects under development as well as capitalised exploration. Main uncertainties to the investment levels are related to progress on development projects and drilling, currency impacts and market effects.

The figure to the left gives an illustration of Statoil’s expected organic capital investments (excluding inorganic activities i.e. acquisitions) for the period 2016 and 2017. Of the total investments, around 90% are expected to be upstream, and of these upstream investments, around 55% are planned on the NCS. International upstream investments are expected to be 45% of total investments. Approximately 65% of total investments are expected to be in Statoil operated assets. Around half of the investments are expected to be in new assets with the remaining half in producing assets including increased oil recovery investments, US onshore, capitalized exploration and within Marketing, midstream and processing (MMP) and Other. 1) Producing assets including Increased Oil Recovery The MMP segment as well as Other, including renewables, is expected to be around 10% of the total organic investments in 2016/2017.

In Norway, a substantial proportion of Statoil's 2016 capital expenditures will be spent on on-going development projects such as Johan Sverdrup, Gina Krog and Aasta Hansteen, in addition to various extensions, modifications and improvements on currently producing fields like Gullfaks, Oseberg and Troll.

The Johan Sverdrup phase 1 project has since the plan for development and operations (PDO) in February 2015 lowered expected capital expenditure from NOK 123 billion (USD 15.0 billion) (NOK 49.3 billion (USD 6.0 billion) Statoil share) to NOK 99 billion (USD 12.1 billion) (NOK 39.6 billion (USD 4.8 billion) Statoil share). The expected capital expenditure for Aasta Hansteen is NOK 37 billion (USD 4.5 billion) (NOK 18.9 billion (USD 2.3 billion) Statoil share) and Gina Krog NOK 31 billion (USD 3.8 billion) (NOK 18.2 billion (USD 2.2 billion) for Statoil's share). All NOK figures are nominal.

Internationally the largest projects in 2016 are Mariner in the UK, Julia and Stampede in the Gulf of Mexico and onshore activities in Bakken, Eagle Ford and Marcellus in the US. For the largest investment, Mariner, the full field investment is expected around USD 7.7 billion (USD 5 billion for Statoil's share), measured in real 2012 USD.

117

In Marketing, midstream and processing (MMP) segment Statoil estimates that most of the 2016 capital expenditures will be spent on Polarled and Johan Sverdrup export pipelines, in addition to processing and transportation solutions related to Bakken, Marcellus and Eagle Ford in the US.

In the Other segment, investments in the Dudgeon offshore wind farm project will be the largest in 2016. The final investment decision for Dudgeon was made in mid-2014. The project consists of 67 (6MW) turbines installed offshore, and production start is expected in 2017. The investment in Dudgeon is equity accounted. Hywind pilot park consists of 5 (6MW) floating offshore turbines. The final investment decision was made in late 2015, and production start is expected in 2017. In addition, Statoil has entered into a joint venture with E.ON to develop the Arkona offshore wind power project with total expected project investments of EUR 600 million for Statoil's share.

10.3.4 Future investments 10.3.4.1 Contractual commitments related to future investments Statoil has contractual commitments related to future investments. However, the contractual commitments are only a part of the total investment level which has the flexibility to be adjusted, and the flexibility is increasing out in time. This flexibility is partly dependent on the capital expenditure Statoil's partners in joint ventures agree to commit to.

Statoil has contractual commitments36 related to future investments of around NOK 62 billion (USD 7.5 billion), of which NOK 31 billion (USD 3.8 billion) is due in 2016. NOK 31 (USD 3.8 billion) is due thereafter, of which the main commitments are due in 2017. NOK 39 billion (USD 4.7 billion) is related to DPN and NOK 18 billion (USD 2.2 billion) to DPI.

10.3.4.2 Non sanctioned discoveries and future investments Exploration is considered the primary tool for filling the pipeline of new future investment opportunities. Since 2010, the Company has made high-impact discoveries in four different countries: Norway, Tanzania, Canada and Brazil which may develop and entail future investments from Statoil. A high-impact discovery is defined as a discovery which at least satisfies one of the following two criteria:

(i) Estimated gross recoverable resources of more than 250 million boe

(ii) Estimated recoverable resources net to Statoil of more than 100 million boe

The maturation of the high-impact discoveries have varied significantly, due to issues such as assumed commerciality, technical challenges and risks, need for appraisal drilling and potential for additional discoveries from exploration that could become part of a development.

Two of the high-impact discoveries, Johan Sverdrup and Peregrino South, are the only two high-impact discoveries that have been matured into development phase. These projects are described in Section 9.2.4.1 "Main sanctioned development projects on the NCS" and 9.3.4 "Fields under development internationally" for fields under development.

Johan Castberg Of the non-sanctioned high-impact discoveries, Johan Castberg in the Norwegian Barents Sea, is considered the most mature project opportunity, with a clear defined timeline and a more mature cost estimate than the other discoveries. The Johan Castberg project consists of three discoveries: Skrugard (discovered April 2011), Havis (discovered January 2012) and Drivis (discovered May 2014). Early 2016, the Johan Castberg partners selected FPSO as the concept to be matured further towards final investment decision currently scheduled by

36 Contractual commitments are reported as of 31 December 2015. The amount reported includes all minimum commitments that have been entered into and are still outstanding at year end. Minimum commitments include all firm contractual commitments that Statoil has legally entered into with external parties. The reporting includes an allocation between next year (i.e. 2016) and thereafter (i.e. after 2016). Future commitments include both joint venture related and non-joint venture related commitments. Joint venture (JV) related commitments include commitments directly related to upstream activities and related JV activities. The contractual commitments consist of investment in both tangible and intangible assets.

118

end 2017. Total gross capital expenditure is estimated at NOK 50-60 billion (USD 6.1-7.3 billion). Production start is expected by end 2022. Statoil holds a 50% working interest in Johan Castberg.

Other NCS projects For the Snorre 2040 project, Statoil is together with partners progressing to mature a subsea solution development project, including a tie back to the Snorre A platform.

In the southern part of the North Sea, Statoil made in July 2012 a high-impact gas and condensate discovery called King Lear. Statoil is operator, and has a high working interest at 77.8%. King Lear is a deep, high pressure, high temperature discovery, and is consequently a challenging development with high well cost. Statoil is currently evaluating development solutions and tie-in possibilities for a potential development around 2025.

Tanzania In Tanzania Block 2, Statoil has during 2012-2015 made a total of eight deepwater gas discoveries, of which six have been defined as high-impact. These are Zafarani, Lavani, Tangawizi, Mronge, Piri and Mdalasini. Statoil currently holds 65% working interest, but Tanzania Petroleum Development Corporation (TPDC) has under the Production Sharing Agreement (PSA) a 10% back-in right in the case of a commercial development, which eventually could imply a reduction in Statoil’s working interest to 58.5%. A gas addendum to the PSA secures the right to export gas beyond a domestic gas supply obligation of up to 10%.

While the offshore part of the development will be through a subsea development, the Tanzanian authorities have requested a joint onshore LNG export facility developed between Block 2 and other offshore blocks operated by BG Tanzania (fully-owned subsidiary by Shell). The partners are in agreement that the fiscal, commercial and legal framework for the onshore part of the project needs to be clarified before further detailed technical work will be conducted. Accordingly, a milestone based approach (as opposed to a technically driven schedule) has been adopted with no firm timeline. For the partners an agreement on the key terms in the Host Government Agreement (HGA) with the Government of Tanzania is a requirement for moving into the FEED- phase.37 Subject to progress on the HGA, the current planning estimates are start of FEED in mid-2018, at the earliest. If achieved, final investment decision could be reached earliest in 2020 and first gas/LNG could be produced 2025-2026.

Bay du Nord In August/September 2013, Statoil announced the high-impact discovery Bay du Nord in Flemish Pass, offshore East Coast Canada. Bay du Nord was Statoil’s third operated discovery in Flemish Pass, following Mizzen and Harpoon West. It contains light oil, has excellent reservoir qualities with high porosity and high permeability. While technical characteristics are very good, the discovery is remotely located 500 km offshore St. Johns, Newfoundland, which suggests higher commercial volume threshold than similar discoveries in areas with existing infrastructure and/or closer to shore.

To gain better understanding about the regional resource potential, Statoil commenced in November 2014 a 9- well exploration and appraisal programme for the Bay du Nord area. In the second quarter of 2016, Statoil and its partners have completed a 19-month drilling program offshore Newfoundland. Of the 9 wells completed,2 oil discoveries were made at the Bay de Verde and Baccalieu prospects. Next steps will then be to evaluate the results and assess potential development solutions based on the subsurface potential. Statoil holds 65% in Bay du Nord.

Brazil Three discoveries have been made in deepwater block BM-C-33, Pre-Salt Campos basin in Brazil. One of the discoveries, Pão de Açucardiscovered in 2012, is defined as a high-impact discovery. The operator Repsol Sinopec Brasil recently completed a four-well appraisal program for the block. The next step is to mature the subsurface, and to assess lean and cost-effective potential development solutions. Subject to approval from Brazilian authorities, Statoil expects to take over the operatorship of the block in third quarter 2016. Statoil holds 35% working interest in BM-C-33.

37 FEED: Front end engineering design.

119

On 29 July 2016, Statoil announced the agreement to acquire Petrobras’ 66% operated interest of the BM-S-8 offshore licence in Brazil in the highly prolific Santos basin. The license includes a substantial part of the Carcará oil discovery, one of the ten largest discoveries in the world in the recent years. 38 Carcará was discovered in 2012, on the geological trend of the nearby Lula field and Libra area. It is a world-class discovery of high-quality oil of around 30° API and with associated gas in a thick reservoir with excellent properties. The total consideration for the acquisition is USD 2.5 billion. Half of it will be paid upon closing of the transaction, with the remainder being paid when certain milestones have been met. These are partly related to the licence award, but mainly to the future unitisation of Carcará. The effective date for the transaction is 1 July 2016 and closing is subject to customary conditions including partners’ and government approval. The expected closing of the transaction is around year-end 2016 and will be financed as part of normal operations. Further plans for investment decision as well as development concept will be worked on post the closing of the transaction. Remaining work commitment in the block, prior to declaration of commerciality in 2018, consist of one exploration well and one well test.

To secure further growth options, Statoil will continue with significant exploration activities both on NCS and internationally. Even though the exploration spending has been reduced over the last years, the expected total exploration spend for 2016 is around USD 1.8 billion where half of the wells is expected to be drilled on the NCS. Over time, approximately 1/3 of the exploration activity is capitalized and this part is included in the investments. Seismic costs are expensed and are not part of the investments.

10.3.5 Asset retirement obligations Statoil has obligations to decommission and remove offshore installations at the end of the production period. It is difficult to estimate the costs and the timing of these decommissioning and removal activities, which are based on current regulations and technology, and consider relevant risks and uncertainties. Most of the removal activities are many years into the future, and the removal technology and costs are constantly changing. The estimates include assumptions of the time required and the day rates for rigs, marine operations and heavy lift vessels that can vary considerably depending on the assumed removal complexity. Furthermore, the production period of a specific field is influenced by several factors such as the oil price, increased oil recovery potential, tie-in of new discoveries and life extension cost. In addition some installations might continue to operate as processing facilities for other fields after own production shut-down. As a result, the initial recognition of the liability and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgement.

The total provisions for future asset retirement obligations at 31 December 2015 have been estimated to NOK 95 billion (USD 11.4 billion). Expected timing of the asset retirement obligations:

(In NOK/USD billion) Asset retirement obligations 2016 - 2020 12.2 (USD 1.5) 2021 - 2025 16.9 (USD 2.0) 2026 - 2030 16.1 (USD 1.9) 2031 - 2035 25.5 (USD 3.1) Thereafter 24.2 (USD 2.1)

At 31 December 2015 95.0 (USD 11.4)

The majority of the assets in Statoil’s portfolio will end the production many years into the future. The average life time of the asset portfolio will therefore be defined by the long term view of the oil and gas prices as well as the corresponding production cost development in addition to the expected production profile. The current fluctuations in the oil and gas prices have not changed Statoil’s view of the long term prices; hence, the impact from the current low oil prices is limited on the expected average life time of the asset portfolio.

Fields that may be subject to a decommissioning decision within the next 5 years represent less than 0.5 % of Statoil’s total proved reserves.

38 Source: IHS Energy database extracted 10 August 2016, payable source.

120

10.4 Financing of capital expenditures Statoil finances its capital expenditures by internally generated funds and by external long-term funding, primarily by issuing corporate bonds. Project financing may be used in cases involving joint ventures with other companies.

Long-term funding is raised when Statoil identifies a need for such financing based on its business activities, cash flows and required financial flexibility or when market conditions are considered to be favourable. As discussed in Section 10.3 "Summary of investments", Statoil has significant flexibility to adjust capital expenditures in the project portfolio. This portfolio flexibility offers an opportunity to balance cash flow from operations with cash outflow to capital expenditures and dividend, being cash flow neutral at USD 60/boe in 2017 and USD 50/boe in 2018. Statoil had. as per 30 June 2016. USD 16.0 billion of cash and cash equivalents and current financial investments. Such a strong liquidity position provides amble opportunities to manage longer periods without raising new external long-term funding, also at prices below cash flow neutral levels indicated above.

To facilitate efficient access to long-term financing, Statoil has an unlimited U.S Shelf Registration Statement filed with the Securities and Exchange Commission (SEC) as well a Euro Medium-Term Note Programme (limited to EUR 20.0 billion) listed on the London Stock Exchange. Statoil’s bonds are generally unconditionally guaranteed by Statoil Petroleum AS. As per 30 June 2016 the total outstanding long-term bond debt was USD 30.1 billion.

Statoil’s last bond transaction was undertaken in February 2015, when Statoil issued bonds with maturities from 4 to 20 years for a total amount of EUR 3.75 billion (USD 4.2 billion). The bonds were issued in EUR and swapped into USD. This transaction served to pre-fund future commitments at a time of favourable market pricing.

Short-term funding needs will normally be covered by borrowing utilizing a USD 5.0 billion US Commercial Paper Program which is backed by a revolving credit facility (RCF) of USD 5.0 billion, maturing in 2021.39 All of Statoil’s 21 core banks participate in the RCF. As at the date of this Prospectus the RCF is fully undrawn.

10.5 Improved efficiency The last decade the oil and gas upstream industry has experienced increased costs pressure and capital intensity in new development projects. The result has been increased pressure on margins and an increasing break-even price of new projects. Statoil started in 2014 its technical efficiency program ("STEP") to increase its own technical efficiency, and communicated at the capital market day in February 2014 an ambition of USD 1.3 billion in annual improvements from 2016 and onwards to the cost and capital expenditure base. This ambition was increased at the capital market day in February 2015 to annual impact of USD 1.7 billion from 2016 and onwards. Progress on efficiency program is going well and Statoil delivered in 2015, annual improvements of USD 1.9 billion, more than and ahead of the 2016 ambition of USD 1.7 billion in annual improvements.

At the capital market day in February 2016, the ambition for annual improvements was increased to USD 2.5 billion in annual improvements from 2016 and onwards. The focus is on delivering faster and deeper cost reductions. The main elements expected to deliver these savings are increased efficiencies within offshore and onshore drilling/well, modification and facility investments, lower offshore and onshore operational costs and sales, general and administration costs.

By reworking and challenging project concepts, Statoil has reduced the break-even Brent equivalent price on the own operated unsanctioned project portfolio (comparing 2013 with 2016 own operated unsanctioned project portfolio (volume weighted) with expected production start-up by end 2022) by around USD 30/bbl. This is in line with Statoil's priority to preparing to invest in next-generation portfolio. This will give the basis for capturing the upturn in oil and gas prices, by sustaining the efficiency gains and investing in attractive projects to benefit from the expected price recovery.

39 In June 2016, Statoil exercised its first of two one year RCF extension options. Further, in July 2016, Statoil upsized its US Commercial Paper Program so that the program size is aligned with the RCF.

121

In parallel to the STEP program an organisational efficiency programme ("OE") was started to target efficiency gains through leaner and more effective ways of working and organising. The OE programme sets requirements and provide a framework for planning and execution of organisational efficiency projects in the organisation. Upon delivery of the organisational efficiency potential at the end of 2016 the Statoil workforce will have been reduced by close to 20% over a period of 3 years. From 2017 the ambition is to shift from corporate programmes to continuous improvement driven by the line to ensure competitiveness at all times.

10.6 Significant changes There have been no significant changes in the financial or trading position of Statoil since the latest published financial information, which has been incorporated by reference, see Section 17.1 "Cross reference table".

122

11 BOARD OF DIRECTORS, MANAGEMENT, EMPLOYEES AND CORPORATE GOVERNANCE 11.1 Introduction The Board of Directors is responsible for the overall management of Statoil and for supervising the Company's activities in general. The Board of Directors act on behalf of the Company in all matters. In accordance with Norwegian law, the Board of Directors is responsible for, among other things, supervising the general and day- to-day management of the Company's business; ensuring proper organisation, preparing plans and budgets for its activities; ensuring that the Company's activities, accounts and asset management are subject to adequate controls and to undertake investigations necessary to ensure compliance with its duties. The Board of Directors handles matters of major importance or of an extraordinary nature. However, it may require the executive management of the Company (the "Management") to refer any matter to it. On the other hand, the Board of Directors may delegate such matters as it deems fit to the Management. The Board of Directors appoints the president and chief executive officer ("CEO"), and stipulates the work instructions, powers of attorney and terms and conditions of employment for the CEO. The members of the Board of Directors are elected for a period of up to two years.

The Company's Management has the overall responsibility for the day-to-day management of Statoil's operations in accordance with instructions set out by the Board of Directors. 40 Among other responsibilities, the Company's CEO is responsible for keeping the Company’s accounts in accordance with existing Norwegian legislation and regulations and for managing the Company's assets in a responsible manner. In addition, at least once a month the Company's CEO must brief the Board of Directors about the Company's activities, financial position and operating results. The CEO is responsible for developing Statoil's business strategy and presenting it to the Board of Directors for decision, for the execution of the business strategy and for cultivating a performance-driven, values-based culture.

The CEO appoints the corporate executive committee (the "CEC"). Members of the CEC have a collective duty to safeguard and promote Statoil's corporate interests and to provide the CEO with the best possible basis for deciding the Company's direction, making decisions and executing and following up business activities. In addition, each of the CEC members is head of a specific business area or staff function.

The Corporate Assembly has a duty to oversee the Board of Directors and the CEO in their management of the Company. Norwegian company law imposes a fiduciary duty on the Corporate Assembly to its shareholders. The Corporate Assembly communicates to the general meeting its recommendations concerning the Board of Directors’ proposals about the Company's annual accounts, balance sheets, allocation of profits and coverage of losses. The Corporate Assembly's responsibilities also include a supervisory role towards the Board of Directors and the CEO's management of the Company. The Corporate Assembly renders decisions, based on the Board of Director’s proposals, in matters related to substantial investments, measured in terms of the total resources of the Company, and matters regarding rationalizations or restructurings of the operations of the Company that will result in a major change or reorganization of the workforce. Furthermore, the Corporate Assembly is responsible for electing the Board of Directors and the chair of the Board of Directors. The term of office of the Corporate Assembly members is normally two years.

11.2 Board of Directors 11.2.1 Members of the Board of Directors Pursuant to the Articles of Association, the Board of Directors consists of between nine and 11 members. The Management is not represented on the Board of Directors.

The members of the Board of Directors are elected by the Corporate Assembly. At present, Statoil's Board of Directors consists of 11 members. As required by Norwegian company law, the Company's employees are entitled to be represented by three members of the Board of Directors. The Board of Directors has three sub- committees - the "audit committee", 41 "the safety, sustainability and ethics committee", 42 and "the

40 Rules of procedure of the Board of Directors (www.statoil.com/board). 41 Instructions for the Board of Directors' audit committee (www.statoil.com/auditcommittee) 42 Instructions for the Board of Director's safety, sustainability and ethics committee (www.statoil.com/ssecommittee)

123

compensation and executive development committee". 43 The Company’s registered business address, Forusbeen 50, 4035 Stavanger, Norway, serves as the c/o address for the members of the Board of Directors in relation to their directorship of the Company.

There are no service contracts that provide for benefits upon termination of office for members of the Board of Directors. The Board of Directors has determined that, in its judgment, all of the shareholder representatives on the Board of Directors, except for Wenche Agerup, are considered independent.44

The names, positions and current term of office for members of the Board of Directors as at the date of this Prospectus are set out in the table below.

Name Position Served since

Øystein Løseth Chair, Shareholder-elected 1 October 2014 (Chair since 1 July 2015)

Roy Franklin Deputy chair, Shareholder-elected 1 July 2015

Bjørn Tore Godal Member, Shareholder-elected 1 September 2010

Jakob Stausholm Member, Shareholder-elected 1 July 2009

Maria Johanna Oudeman Member, Shareholder-elected 15 September 2012

Wenche Agerup Member, Shareholder-elected 21 August 2015

Rebekka Glasser Herlofsen Member, Shareholder-elected 19 March 2015

Jeroen van der Veer Member, Shareholder-elected 18 March 2016

Ingrid Elisabeth di Valerio Member, Employee-elected 1 July 2013

Stig Lægreid Member, Employee-elected 1 July 2013

Lill-Heidi Bakkerud Member, Employee-elected 2004

In addition, there are four employee-elected deputy members of the Board of Directors who attend board meetings in the event an employee-elected member of the Board of Directors is unable to attend.

The composition of the Board of Directors is in compliance with the independence requirements of the Norwegian Code of Practice as of 30 October 2014 (the "Norwegian Corporate Governance Code"). The Norwegian Corporate Governance Code provides that a board member is generally considered to be independent when he or she does not have any personal, material business or other contacts that may influence the decisions he or she makes as a board member.

Set out below are brief biographies of the board members of the Company, along with disclosures about the companies and partnerships of which each director has been member of the administrative, management and supervisory bodies in the previous five years.

43 Instructions for the Board of Director's compensation and executive development committee (www.statoil.com/compensationcommittee) 44 The board of directors have concluded that Wenche Agerup should not be considered an independent board member, since she in the period 1 June 2014 until 31 December 2014 was a member of the executive management in Norsk Hydro ASA at the same time as Irene Rummelhoff, today a member of Statoil’s corporate executive committee, was a member of the board’s compensation committee in Norsk Hydro. The conclusion follows from the NYSE regulations for listed companies which Statoil, as a NYSE listed company, follows.

124

Øystein Løseth, chair of the Board of Directors Mr. Løseth has been a member of the Board of Directors since 1 October 2014, and chair of the Board of Directors and the Board of Directors' compensation and executive development committee since 1 July 2015. Between 2010 and 2014 Mr. Løseth held the position as CEO, and before that as a First Senior Executive Vice President since 2009, of Vattenfall AB. Mr. Løseth has extensive management experience from NUON, a Dutch energy company, Statkraft and Statoil, within strategy and business development among others. He is currently also chair of the board of directors of Eidsiva Energi AS and Hunton Fiber AS. Mr. Løseth graduated as M.Sc. from the Norwegian University of Science and Technology and has a degree in Economics from BI Norwegian School of Management in Bergen. Mr. Løseth is a Norwegian citizen and resident in Norway.

Current directorships and senior management Statoil ASA (chair of the Board of Directors), Eidsiva Energi positions ...... AS (chair of the board) and Hunton Fiber AS (chair of the board).

Previous directorships and senior management Vattenfall AB (CEO). positions last five years ......

Roy Franklin, deputy chair of the Board of Directors Mr. Franklin has been deputy chair of the Board of Directors, chair of the Board of Directors' safety, sustainability and ethics committee and member of the Board of Directors' audit committee from 1 July 2015. Mr. Franklin was also previously a member of the board of StatoilHydro from October 2007 and Statoil from November 2009 until June 2013. Mr. Franklin is a non-executive chair of the board of Cuadrilla Resources Holdings Limited, a privately held UK company focusing on unconventional energy sources. He is also a board member of the Australian oil and gas company Santos Ltd, the private equity firm Kerogen Capital Ltd and the London-based international engineering company Amec Foster Wheeler. Mr. Franklin has broad experience from management positions in several countries, including positions with BP, Paladin Resources plc and Clyde Petroleum plc. Mr. Franklin holds a Bachelor of science in geology from the University of Southampton, UK. Mr. Franklin is a UK citizen and resident in UK.

Current directorships and senior management Statoil ASA (deputy chair of the Board of Directors), positions ...... Cuadrilla Resources Holdings Limited (chair of the board), Santos Ltd (board member), Kerogen Capital Ltd (board member) and Amec Foster Wheeler (board member).

Previous directorships and senior management Boart Longyear Limited (board member) and OMV AG positions last five years ...... (member of the supervisory board).

Bjørn Tore Godal, board member Mr. Godal has been a member of the Board of Directors since 1 September 2010 and is a member of the Board of Directors' compensation and executive development committee and the Board of Directors' safety, sustainability and ethics committee. He is currently also the chair of the Council of the Norwegian Defence University College (NDUC) and vice chair of the Fridtjof Nansen Institute. Mr. Godal was a member of the Norwegian Parliament for 15 years during the period 1986-2001. From 2003-2007, he was Norway's ambassador to Germany and from 2007-2010, he was special adviser for international energy and climate issues at the Ministry of Foreign Affairs. Since 2014, Mr. Godal has led a government-appointed committee responsible for the evaluation of the civil and military contribution from Norway in Afghanistan in the period 2001 - 2014. Mr. Godal has a Bachelor of Arts degree in political science, history and sociology from the University of Oslo. Mr. Godal is a Norwegian citizen and resident in Norway.

Current directorships and senior management Statoil ASA (board member), Norwegian Defence University positions ...... College ( c hair) and Fridtjof Nansen Institute (vice chair).

Previous directorships and senior management Government-appointed evaluation committee of Norway's positions last five years ...... civil and military contribution in Afghanistan (chair).

Jakob Stausholm, board member Mr. Stausholm has been a member of the Board of Directors since July 2009 and is also the chair of the Board of Directors' audit committee. Mr. Stausholm is Chief Strategy & Transformation Officer of Maersk Line, the

125

largest container shipping company in the world and part of A.P. Moller – Maersk Group. From 2008 to 2011, Stausholm was CFO of the global facility services provider ISS A/S. Before joining ISS's corporate executive committee, he was employed by the Shell Group for 19 years and held a number of management positions, including vice president finance for the group's exploration and production in Asia and the Pacific, chief internal auditor and CFO of group subsidiaries. Mr. Stausholm holds a M.Sc. in economics from the University of Copenhagen. Mr. Stausholm is a Danish citizen and resident in Denmark.

Current directorships and senior management Statoil ASA (board member) and Maersk Line (Chief positions ...... Strategy & Transformation Officer).

Previous directorships and senior management ISS A/S (CFO). positions last five years ......

Maria Johanna Oudeman, board member Ms. Oudeman has been a member of the Board of Directors since 15 September 2012 and is a member of the Board of Directors' compensation and executive development committee. Ms. Oudeman is currently a member of the boards of Solvay SA, Het Concertgebouw, Rijksmuseum and SHV Holdings. Moreover, Ms. Oudeman is the President of Utrecht University in the Netherlands, one of Europe's leading universities. From 2010 to 2013, Ms. Oudeman was a member of the Executive Committee of Akzo Nobel, responsible for HR and Organisational Development. Before joining Akzo Nobel, Ms. Oudeman was Executive Director Strip Products Division at Corus Group, now Tata Steel Europe. Ms. Oudeman has extensive experience as a line manager in the steel industry and considerable international business experience. Ms. Oudeman has a law degree from Rijksuniversiteit Groningen in the Netherlands and an MBA in Business Administration from the University of Rochester, New York, USA and Erasmus University, Rotterdam, the Netherlands. Ms. Oudeman is a Dutch citizen, and resident in the Netherlands.

Current directorships and senior management Statoil ASA (board member), Solvay SA (board member), positions ...... Het Concertgebouw (board member), Rijksmuseum (board member), and SHV Holdings (board member).

Previous directorships and senior management Akzo Nobel (Member of the Executive Committee), ABN positions last five years ...... AMRO Bank (supervisory board member) and Royal Ten Cate (supervisory board member).

Wenche Agerup, board member Ms. Agerup has been a member of the Board of Directors since 21 August 2015. Ms. Agerup is also member of the Board of Director’s compensation and executive development committee and the Board of Directors' safety, sustainability and ethics committee. Ms. Agerup is currently a board member in the seismic company TGS ASA. Moreover she is an Executive Vice President and the Chief Corporate Affairs Officer in Telenor ASA. Ms. Agerup was the Executive Vice President for Corporate Staffs and the General Counsel of Norsk Hydro ASA from 2010 to 31 December 2014, and has held various executive roles in Hydro since 1997. Ms. Agerup holds a MA in Law from the University of Oslo, Norway and a Master of Business Administration from Babson College, USA. Ms. Agerup is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (board member), TGS ASA (board member) and positions ...... Telenor ASA (Executive Vice President and Chief Corporate Affairs Officer).

Previous directorships and senior management Norsk Hydro ASA (Executive Vice President for Corporate positions last five years ...... Staffs and General Counsel).

126

Rebekka Glasser Herlofsen, board member Ms. Herlofsen has been a member of the Board of Directors since 19 March 2015 and is a member of the Board of Directors' audit committee. In addition, Ms. Herlofsen is a member of the board of directors of DNV Holding, DNV Foundation, DNV GL, and member of the committee for tax and capital in the Norwegian Shipowners' Association. Since 2012, Ms. Herlofsen has been the CFO in the Norwegian shipping company Torvald Klaveness. Before that, Ms. Herlofsen was the CFO of Norwegian Energy Company ASA and Business Development Director in Bergesen d.y. ASA / BW Gas ASA. She has broad financial and strategic experience from several corporations and board directorships. Ms. Herlofsen holds a MSc in Economics and Business Administration (Nw: siviløkonom) and Certified Financial Analyst Program from the Norwegian School of Economics, and attended the Breakthrough Program for Top Executives at IMD business school, Switzerland. Ms. Herlofsen is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (board member), DNV Holding (board member), positions ...... DNV Foundation (board member), DNV GL (board member), the committee for tax and capital in the Norwegian Shipowners' Association (member) and Torvald Klaveness (CFO).

Previous directorships and senior management Norwegian Energy Company ASA (CFO) and Cermaq ASA positions last five years ...... (chair).

Jeroen van der Veer, board member Mr. van der Veer has been a member of the Board of Directors since 19 March 2016 and is a member of the Board of Directors’ audit committee. In addition, Mr. van der Veer is the chair of the supervisory boards of ING Bank NV and Royal Philips Electronics, chair of the supervisory councils of the Technical University of Delft and Platform Beta Techniek, chair of the advisory board of Rotterdam Climate Initiative, as well as a board member in Boskalis Westminster Groep NV and Het Concertgebouw. Mr. van der Veer was the CEO in the international oil and gas company Royal Dutch Shell Plc (Shell) in the period 2004 to 2009, when he retired. Mr. van der Veer thereafter continued as a non-executive director on the board of Shell until 2013. He started to work for Shell in 1971 and has experience within all sectors of the business and has significant competence within corporate governance. Mr. van der Veer has a degree in Mechanical Engineering (MSc) from Delft University of Technology, Netherlands and a degree in Economics (MSc) from Erasmus University, Rotterdam, Netherlands. Since 2005 he holds an honorary doctorate from the University of Port Harcourt, Nigeria. Mr. van der Veer is a Dutch citizen and resident in the Netherlands.

Current directorships and senior management Statoil ASA (board member), ING Bank NV (chair of positions ...... supervisory board), Royal Philips Electronics (chair of supervisory board), Platform Beta Techniek (chair of supervisory council), Het Concertgebouw (board member), Rotterdam Climate Initiative (chair of the advisory board), Technical University of Delft (chair of supervisory council) and Boskalis Westminster Groep NV (board member).

Previous directorships and senior management Royal Dutch Shell (non-executive director), Unilever NV/Plc positions last five years ...... (vice-chair /senior independent director), ING Group (independent vice-chair) and EIT - European Institute of Innovation & Technology (member of governing board).

127

Ingrid Elisabeth di Valerio, board member Ms. di Valerio has been a member of the Board of Directors since 2013. Ms. di Valerio is also a member of the Board of Directors' audit committee. In addition, Ms. di Valerio is a board member of Tekna's central nomination committee. Ms. de Valerio has been employed by Statoil since 2005 and works within materials discipline for Technology, Projects & Drilling. Moreover, Ms. di Valerio was Tekna's main representative in Statoil from 2008 to 2013, and she also sat on Tekna's central board from 2005 to 2013. Ms. de Valerio is a chartered engineer (mathematics and physics) who studied at the Norwegian University of Science and Technology in Trondheim. Ms. di Valerio is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (board member), and Tekna's central positions ...... nomination committee (member).

Previous directorships and senior management Tekna's central committee (member), First Scandinavia positions last five years ...... (board member) and Montanus AS (board member).

Stig Lægreid, board member Mr. Lægreid has been a member of the Board of Directors since 1 July 2013. Mr. Lægreid is also a member of the Board of Directors' safety, sustainability and ethics committee. In addition, Mr. Lægreid is a member of NITO's negotiation committee for private sector. Mr. Lægreid has been employed in ÅSV and Norsk Hydro since 1985, mainly occupied as project engineer and constructor for production of primary metals until 2005 and from 2005 as weight estimator for platform design. He is now a full-time employee representative as the leader of NITO, Statoil. Mr. Lægreid holds a bachelor degree in mechanical construction from Oslo Ingeniørhøyskole. Mr. Lægreid is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (member) and NITO's negotiation committee for positions ...... private sector (member).

Previous directorships and senior management Not applicable. positions last five years ......

Lill-Heidi Bakkerud, board member Ms. Bakkerud has been a member of the Board of Directors from 1998 to 2002, and again since 2004. She is also a member of the Board of Directors' safety, sustainability and ethics committee. In addition, Ms. Bakkerud is a member of the executive committee of the Industry Energy trade union and holds a number of offices as a result of this. Ms. Bakkerud has worked as a process technician at the petrochemical plant in Bamble and on the Gullfaks field in the North Sea. She is now a full-time employee representative as the leader of Industy Energy Statoil branch. Ms. Bakkerud has a craft certificate as a process/chemistry worker. Ms. Bakkerud is a Norwegian citizen, and lives in Norway.

Current directorships and senior management Statoil ASA (board member) and the executive committee positions ...... of the Industry Energy trade union (member).

Previous directorships and senior management Not applicable. positions last five years ......

11.3 Management 11.3.1 Members of the senior management The Company’s Management comprises the CEO and ten executives: Employed with Name Position Statoil since

Eldar Sætre President and CEO 1980

Lars Christian Bacher Executive vice president, Development & Production International 1991

Arne Sigve Nylund Executive vice president, Development & Production Norway 1987

Torgrim Reitan Executive vice president, Development & Production USA 1995

Hans Jakob Hegge Executive vice president and CFO 1995

Margareth Øvrum Executive vice president Technology, Projects & Drilling 1982

128

Employed with Name Position Statoil since

Tim Dodson Executive vice president, Exploration 1985

Jens Økland Executive vice president of Marketing, Midstream & Processing 1994

John Knight Executive vice president, Global Strategy & Business Development 2002

Anders Opedal Executive vice president and COO 1997

Irene Rummelhoff Executive vice president, New Energy Solutions 1991

Set out below are brief biographies of the members of the Management, along with disclosures about the companies and partnerships of which each member of the Management has been member of the administrative, management and supervisory bodies in the previous five years. The Company’s registered business address, Forusbeen 50, 4035 Stavanger, Norway, serves as the c/o address for the members of the Management in relation to their employment with the Company.

Eldar Sætre, President and CEO Mr. Sætre has been the Company's President and CEO since 15 October 2014. In addition, he serves as a member of the board of Strømberg Gruppen AS and Trucknor AS. Mr. Sætre joined Statoil in 1980. Mr. Sætre has been executive vice president and CFO from October 2003 until December 2010, and executive vice president for marketing, processing & renewable energy from 2011 until 2014. Mr. Sætre holds a MA in business economics from the Norwegian School of Economics and Business administration (NHH) in Bergen. Mr. Sætre is a Norwegian citizen and resident in Norway.

Current directorships and senior management Statoil ASA (President and CEO), Strømberg Gruppen AS positions ...... (board m ember) and Trucknor AS (board member).

Previous directorships and senior management Statoil ASA (Executive vice president for Marketing, positions last five years ...... processing & renewable energy).

Lars Christian Bacher, Executive Vice President, Development & Production International Mr. Bacher has been the executive vice president for Development & Production International (DPI) since 1 September 2012. Mr. Bacher joined Statoil in 1991 and has held a number of leading positions in Statoil, including that of platform manager on the Norne and Statfjord fields on the NCS. He was in charge of the merger process involving the offshore installations of Norsk Hydro and Statoil. Mr. Bacher has also been senior vice president for Gullfaks operations and subsequently for the Tampen area. His most recent position, which he held from September 2009, was as senior vice president for Statoil's Canadian operations within Development & Production North America. Mr. Bacher holds a Master of Science in chemical engineering from the Norwegian Institute of Technology (NTH), and a business degree in Finance from the Norwegian School of Economics and Business Administration (NHH). Mr. Bacher is a Norwegian citizen and resident in Norway.

Current directorships and senior management Statoil ASA (Executive vice president, DPI). positions ......

Previous directorships and senior management Statoil ASA (Senior vice president Development & positions last five years ...... Production North America).

Arne Sigve Nylund, Executive Vice President, Development & Production Norway Mr. Nylund has been the executive vice president for Development & Production Norway (DPN) since 1 January 2014. In addition, he is a member of the board of directors of The Norwegian Oil & Gas Association (Norsk Olje & Gass). Mr. Nylund was employed by Mobil Exploration Inc. from 1983-1987. Since 1987 he has held several central management positions in Statoil ASA. Mr. Nylund is a mechanical engineer from Stavanger College of Engineering with further qualifications in operational technology from Rogaland Regional College/University of Stavanger (UiS). Moreover he is a business graduate of the Norwegian School of Business and Management (NHH). Mr. Nylund is a Norwegian citizen and resident in Norway.

129

Current directorships and senior management Statoil ASA (Executive vice president, DPN) and The positions ...... Norwegian Oil & Gas Association (board member). Previous directorships and senior management Statoil ASA (Senior vice president Manufacturing and positions last five years ...... Marketing and Manufacturing, Processing and Renewable Energy – Processing and Manufacturing).

Torgrim Reitan, Executive Vice President, Development & Production USA Mr. Reitan has been the executive vice president for Development & Production USA since 1 August 2015. From January 2011 to 1 August 2015 he held the position as an executive vice president and CFO. Mr. Reitan has held several managerial positions in Statoil, including senior vice president in trading and operations in the Natural Gas business area (2009-2010), senior vice president in performance management and analysis (2007-2009) and senior vice president in performance management, tax and M&A (2005-2007). From 1995 to 2004, he held various positions in the Natural Gas business area and corporate functions in Statoil. Mr. Reitan holds a master of science degree from the Norwegian School of Economics and Business Administration. Mr. Reitan is a Norwegian citizen, and lives in the USA.

Current directorships and senior management Statoil ASA (Executive vice president, Development & positions ...... Production USA). Previous directorships and senior management Statoil ASA (Executive vice president and CFO). positions last five years ......

Hans Jakob Hegge, Executive Vice President and Chief Financial Officer Mr. Hegge has been an executive vice president and the Company's CFO since 1 August 2015. He has held several managerial positions in Statoil, including senior vice president for Operations North in Development and Production Norway (2013-2015), senior vice president for Operations East in Development and Production Norway (2011-2013), senior vice president for Operational Development in Development and Production Norway (2009-2011) and senior vice president for Global Business Services in Chief Financial Officer area (2005-2009). From 1995 to 2004 Mr. Hegge held various positions Development and Production Norway, Natural Gas business area and corporate functions in Statoil. Mr. Hegge holds a Master of Science degree from the Norwegian school of Economics and Business Administration. Mr. Hegge is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (Executive vice president and CFO). positions ...... Previous directorships and senior management Statoil ASA (Senior vice president for Operations North in positions last five years ...... Development and Production Norway (2013-2015) and Senior vice president for Operations East in Development and Production Norway (2011-2013).

Margareth Øvrum, Executive Vice President, Technology, Projects & Drilling Ms. Øvrum has been the executive vice president for Technology, Projects & Drilling since January 2011. Øvrum has been a member of the corporate executive committee since 2003 as executive vice president first for Health, Safety and the Environment and thereafter for Technology and New Energy. In addition, she serves as a member of the board of directors of Atlas Copco AB (Sweden), Alfa Laval (Sweden) and FMC (US). Ms. Øvrum has worked for Statoil since 1982 and was the company's first female platform manager, on the Gullfaks field. Moreover she was senior vice president for operations for Veslefrikk and vice president of operations support for the NCS. Ms. Øvrum holds a Master's degree in engineering from the Norwegian Institute of Technology (NTH) in Trondheim, specialising in technical physics. Ms. Øvrum is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (Executive vice president, Technology, Projects positions ...... & Drilling ), Atlas Copco AB (board member), Alfa Laval (board member) and FMC (board member). Previous directorships and senior management Not applicable. positions last five years ......

130

Tim Dodson, Executive Vice President, Exploration Mr. Dodson has been the executive vice president for Exploration since 1 January 2011. Mr. Dodson has worked in Statoil since 1985 and held central management positions in the company, including positions of senior vice president for Global Exploration, Exploration Norway and the technology Arena. Moreover, Mr. Dodson holds a bachelors degree of science in geology and geography from the University of Keele. Mr. Dodson is a British citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (Executive vice president, Exploration). positions ...... Previous directorships and senior management Not applicable. positions last five years ......

Jens Økland, Executive Vice President of Marketing, Midstream & Processing Mr. Økland has been the executive vice president for Marketing, Midstream & Processing since 1 June 2015. Mr. Økland joined Statoil in 1994 and has mainly worked in the midstream and downstream sectors. Before becoming executive vice president of MMP, Mr. Økland worked as vice president of operations for the Åsgård area in Development and Production Norway. Åsgård ranks among the largest developments on the NCS, supplying about 11 bcm of gas annually to Europe. Previously Mr. Økland was senior vice president of Statoil's largest gas portfolio and supply business in North America, marketing and developing infrastructure solutions for equity and non-equity production. Before heading up Statoil's downstream gas division in North America, he had senior marketing and business development positions within natural gas in Europe mainly focusing on Germany, Statoil's largest gas market. Mr. Økland holds an MSc in business from BI Norwegian Business School. Mr. Økland is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (Executive vice president of Marketing, positions ...... Midstream & Processing). Previous directorships and senior management Statoil ASA (Vice president of operations for the Åsgård positions last five years ...... area DPN, Senior vice president MMP).

John Knight, Executive Vice President, Global Strategy & Business Development Mr. Knight has been the executive vice president for Global Strategy & Business Development since 1 January 2011. Mr. Knight is a member on the advisory board of the Columbia University Center on Global Energy Policy in New York. In addition, he serves as a chair of ONS16 Conference Committee in Stavanger, Norway and is a Governor of the Ditchely Foundation and a member of the Advisory Committee of Lloyd’s Register in London. Mr. Knight has held several central managerial positions in International Operations in Statoil since 2002, mainly in business development. Between 1987 and 2002, he held various positions in energy investment banking. From 1977 to 1987, he qualified and worked as a barrister/lawyer, and was employed by Shell Petroleum in London during the period 1985-1987. Mr. Knight has first and post-graduate degrees in law from Cambridge University and the Inns of Court School of Law in London. Mr. Knight is a British citizen, and resident in England.

Current directorships and senior management Statoil ASA (Executive vice president, Global Strategy & positions ...... Business Development), Columbia University Center on Global Energy Policy (member of the advisory board) ONS16 Conference Committee (chair), Ditchley Foundation (Governor) and Lloyd’s Register (member of the Advisory committee). Previous directorships and senior management Imperial College Business School MsC Climate Change positions last five years ...... Management and Finance (member of the advisory board).

Anders Opedal, Executive Vice President and Chief Operating Officer Mr. Opedal has been executive vice president and the Company's COO since 1 April 2015. Mr. Opedal joined Statoil in 1997 as a petroleum engineer in the Statfjord operations. He has held a range of positions in Drilling and well, Procurement and projects. In 2011 he took on the role as senior vice president for Projects in Technology, Projects and Drilling responsible for Statoil's approximately NOK 300 billion (USD 36.5 billion) project portfolio. Before joining Statoil, Mr. Opedal worked for Schlumberger and Baker Hughes. Moreover, Mr.

131

Opedal holds a MBA from Heriot-Watt University and an engineering degree from NTH. Mr. Opedal is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (Executive vice president and management positions ...... COO). Previous directorships and senior management Statoil ASA (Senior vice president Technology, Projects and positions last five years ...... Drilling).

Irene Rummelhoff, Executive Vice President, New Energy Solutions Ms. Rummelhoff has been executive vice president, New Energy Solutions since 1 June 2015. In addition, she is the deputy chair of the board of directors of Norsk Hydro ASA. Ms. Rummelhoff joined Statoil in 1991. She has held a number of management positions within international business development, exploration, and the downstream business in Statoil. Ms. Rummelhoff holds a Master's degree in petroleum geosciences from the Norwegian Institute of Technology (NTH). Ms. Rummelhoff is a Norwegian citizen, and resident in Norway.

Current directorships and senior management Statoil ASA (Executive vice president, New Energy positions ...... Solutions) , Norsk Hydro ASA (deputy chair). Previous directorships and senior management Statoil ASA (Senior Vice President Strategy and Business positions last five years ...... Development & Production North America and Senior vice president Exploration, NCS).

11.4 Corporate Assembly Pursuant to the Articles of Association, the Corporate Assembly normally consists of 18 members. Twelve members with four deputy members are nominated by the nomination committee and elected at the general meeting of shareholders, and six members, three observers and deputy members are elected by and from among the employees. Such employees are non-executive personnel.

Members of the Corporate Assembly are normally elected for a term of two years. Members of the Board of Directors and the general manager cannot be members of the Corporate Assembly, but they are entitled to attend and to speak at meetings of the Corporate Assembly unless the Corporate Assembly decides otherwise in individual cases.

At the annual general meeting 11 May 2016, all of the 12 shareholder-elected members were up for election. The names, positions and current term of office of the members of the Corporate Assembly as at the date of this Prospectus are set out in the table below. All members of the Corporate Assembly are residents in Norway. Members of the Corporate Assembly do not have service contracts with the Company or its subsidiaries providing for benefits upon termination of office. The Company’s registered business address, Forusbeen 50, 4035 Stavanger, Norway, serves as the c/o address for the members of the Corporate Assembly in relation to their membership in the Corporate Assembly.

Name Position Served since

Tone Lunde Bakker Chair, shareholder-elected member 2014 (Chair since 2016)

Nils Bastiansen Deputy chair, shareholder-elected member 2016

Greger Mannsverk Member, shareholder-elected 2002

Steinar Olsen Member, shareholder-elected 2007

Ingvald Strømmen Member, shareholder-elected 2006

Rune Bjerke Member, shareholder-elected 2007

Siri Kalvig Member, shareholder-elected 2010

Terje Venold Member, shareholder-elected 2014

Kjersti Kleven Member, shareholder-elected 2014

Birgitte Ringstad Vartdal Member, shareholder-elected 2016

Jarle Roth Member, shareholder-elected 2016

Kathrine Næss Member, shareholder-elected 2016

132

Name Position Served since

Brit Gunn Ersland Member, employee-elected 2011

Steinar Kåre Dale Member, employee-elected 2013

Per Martin Labråthen Member, employee-elected 2007

Anne K.S. Horneland Member, employee-elected 2006

Jan-Eirik Feste Member, employee-elected 2008

Hilde Møllerstad Member, employee-elected 2013

Tone Lunde Bakker, chair of the Corporate Assembly Ms. Bakker has been a member of the Corporate Assembly and the nomination committee since 14 May 2014, and was elected as new chair for the Corporate Assembly on 7 June 2016. Ms. Bakker currently holds the position as Global Head of Cash Management in Danske Bank. In addition, Ms. Bakker is a member of Transaction Banking Management Team in Danske Bank Group and serves as a board member and member of the audit committee and the risk committee in Eksportfinans ASA.

Current directorships and senior management Eksportfinans ASA (board member) and Danske Bank Group positions ...... (member of transaction bank management team). Previous directorships and senior management FinansNorge (board member), Danica Pensjonsforsikring AS positions last five years ...... (deputy chair of the board), Krogsveen Eiendomsmegling AS (chair of the board), Danske Bank Norway (member of executive board and country manager).

Nils Bastiansen, deputy chair of the Corporate Assembly Mr. Bastiansen has been a member of the Corporate Assembly since 12 May 2016 and was elected as new deputy chair for the Corporate Assembly on 7 June 2016. Mr. Bastiansen is currently the executive director of equities in Folketrygdfondet and is responsible for the fund’s equity investments. Mr. Bastiansen has worked for Folketrygdfondet since 1995. Before joining the organisation, he was a stockbroker at Unibank Securities in Copenhagen and DnB Fonds in Oslo. Mr. Bastiansen holds a Master of Business and Marketing from Handelsakademiet in Oslo, and a Master of International Management degree from Thunderbird School of Global Management, Arizona, USA. He is also an authorised financial analyst with a Master of Business Administration in finance from Norwegian School of Economics and Business Administration in Bergen.

Current directorships and senior management Folketrygdfondet (executive director of equities). positions ...... Previous directorships and senior management Not applicable. positions last five years ......

Greger Mannsverk, member Mr. Mannsverk has been a member of the Corporate Assembly since 10 May 2006. Mr. Mannsverk's principal activities outside the Company are as CEO for Kimek AS and Kimek Offshore AS. In additions, Mr. Mannsverk holds the position as CEO of Kimek Holding AS, Kimek Offshore Resources A/S and Kirkenes Fish AS. Mr. Mannsverk has extensive experience as board member and is currently a member of the board of several companies.

Current directorships and senior management Kimek AS (CEO), Kimek Holding AS (CEO), Kimek Offshore positions ...... AS (CEO), Kimek Offshore Resources AS (CEO), Kirkenes Fish AS (CEO), Arctic Offshore AS (board member), Ballspark AS (board member), Bugøynes Eiendom as (board member), Kirkenes Agency AS (board member), Kirkenes Maritime Park AS (board member), Kirkenes Base AS (board member), Mælen AS (board member), NB Drift AS (board member), Neidenelven Eiendom AS (board member), Pro Barents AS (board member), Sør-Varanger Turistutvikling AS (board member), Norway King Crab Production AS (board member), Troika Seafood AS (board

133

member), Sør Varanger Invest AS (board member), GT Finans AS (board member), Sparebanken Nord Norge (board member), GTI Eiendom AS (board member) , Finnmarksrøya AS, Kirkenes Fish AS, Norway Shrimp AS and Norway King Crab AS. Previous directorships and senior management Not applicable. positions last five years ......

Steinar Olsen, member Mr. Olsen has been a member of the Corporate Assembly since 5 July 2007, and outside the Company he acts as an independent investor and advisor. Mr. Olsen has extensive experience as a board member and member of corporate assemblies, and he is currently a board member or the chair of several companies.

Current directorships and senior management Jemso AS (chair of the board and company owner), Det positions ...... Stavangerske Dampskibsselskap (DSD) (board member), Folke Hermansens Fond for kreftforskning ved SUS (board member), Herfo Finans AS (board member), Fyrholmen Finans AS (board member), Progressus AS (board member), 2020Park AS (chair of the board), Allseas Norway AS (board member), Res. Gruppe Internasjonale relasjoner, Næringsforeningen i Stavangerregionen (leader), and Alu Rehab AS (board member). Previous directorships and senior management Anchor/MI Drilling Fluids Denmark ApS/MISWACO Danmark positions last five years ...... Aps (chair of the board), Folke Hermansen AS (board member), MISWACO Norge AS (chair of the board), Nordbar Minerals AS (Chair), Foodclicker AS (chair of the board), Risavika Havn AS (chair of the board), GMC Holding AS (board member), MI Epcon AS (chair of the board), Smith International Norway AS (chair of the board).

Ingvald Strømmen, member Mr. Strømmen has been a member of the Corporate Assembly since 10 May 2006. Mr. Strømmen is the Dean of the Faculty of Engineering Science and Technology, NTNU. In addition, he is currently a member of the board of directors of Leiv Eriksson Nyskapning AS, SINTEF Energi, SINTEF Petroleum and SINTEF Byggforsk.

Current directorships and senior management Leiv Eriksson Nyskapning AS (board member) , SINTEF positions ...... Energi (board member), SINTEF Petroleum (board member) and SINTEF Byggforsk (board member) Previous directorships and senior management Not applicable positions last five years ......

Rune Bjerke, member Mr. Bjerke has been a member of the Corporate Assembly since 1 October 2007. Mr. Bjerke is the CEO of DNB Bank ASA. In addition, he is currently the chair of Doorstep AS, a board member of Finansnæringens Servicekontor FNS and Finansnæringens Fellesorganisasjon FNO, and a member of the council of Stipendienfonds E.ON Ruhrgas.

Current directorships and senior management DNB Bank ASA (CEO), Doorstep AS (chair), positions ...... Finansnæringens Servicekontor FNS (board member), Finansnæringens Fellesorganisasjon FNO (board member), Stipendienfonds E.ON Ruhrgas (member of council). Previous directorships and senior management Orkla (member of the corporate assembly). positions last five years ......

Siri M. Kalvig, member Ms. Kalvig has been a member of the Corporate Assembly since 19 May 2010. She is an associated professor of the University of Stavanger. In addition, she is the chair and owner of Orkan Invest AS, the co-owner and

134

board member of Norsk Vind Energi AS, Shoreline AS, Gwind AS and Sensonomic AS. Ms Kalvig is also the CEO and owner of SK Housing 1 AS, co-owner of Nytorget utvikling AS and a board member of Ryfylke Eiendom AS.

Current directorships and senior management University of Stavanger (Associated professor), Orkan positions ...... Invest AS (chair of the board and owner), Norsk Vind Energi AS (board member and co-owner), Shoreline AS (board member and co-owner), Gwind AS (board member and Co- owner), SK Housing 1 AS (CEO and the main owner), Ryfylke Eiendom AS (board member). Previous directorships and senior management StormGeo (employee and board member), Kings Bay positions last five years ...... (board member 2012-2013), and SK Housing AS (board member and co-owner).

Terje Venold, member Mr. Venold has been a member of the Corporate Assembly since 14 May 2014. He is a professional consultant and board member and currently holds the position as chair of the corporate assembly and nomination committee of Norsk Hydro ASA, Storebrand ASA and Borregaard ASA. He is also a board member of Ahlsell AB and Sporveien Oslo AS, in addition to chair of the board of Karriere I Balanse AS. Previously Mr. Venold was the President and CEO of Veidekke ASA.

Current directorships and senior management Ahlsell AB (board member), Sporveien Oslo AS (member of positions ...... the board and audit Committee), Norsk Hydro ASA (chair of the corporate assembly and the nomination committee), Storebrand ASA (chair of the nomination committee), Borregaard ASA (chair of the nomination committee), Karriere I Balanse AS (co-owner and chair of the board) Previous directorships and senior management Veidekke ASA (President and CEO 1989-2013), Norwegian positions last five years ...... Association for Share Promotion (chair of the board 2005- 2016), BI Norwegian Business School (chair of the board 2009-2015), Storebrand ASA (chair of the corporate assembly 2007-2016), Orkla ASA (deputy chair of the corporate assembly 2013-2015)

Kjersti Kleven, member Ms. Kleven has been a member of the Corporate Assembly since 14 may 2014. Ms. Kleven is the co-owner of Kleven Maritime AS, in addition to a professional investor through John Kleven AS. Ms. Kleven holds different board positions such as chair of the board for Kleven Verft AS, Myklebust Verft AS, Kleiva Shipinvest II, Kleven Maritime Holding AS, John Kleven AS and Nordvest Datakompetanse AS and deputy chair of the board of Ekornes ASA and board member for inter alia Kleven Maritime Finans AS, Rem Fortress AS, Ulsteinvik Utvikling AS.

Current directorships and senior management Kleven Maritime AS (chair of the board, co-owner through positions ...... Kleven Maritime Holding AS), Kleven Verft AS (chair of the Board), Myklebust Verft AS (chair of the board), Kleven Maritime Finans AS (board member), Kleiva Shipinvest II (chair of the board), Rem Fortress AS (board member), Kleven Maritime Holding AS (chair of the board, co-owner through John Kleven AS), John Kleven AS (chair of the board 50% owner), Ekornes ASA (deputy chair of the board), Ulsteinvik Utvikling AS (board member), Sparebanken Møre (chair of the general assembly), Ikuben (board member), Strategisk råd for maritime utvikling (member), Johbo AS (board member) and Nordvest Datakompetanse AS (chair of the board and 100% owner) Previous directorships and senior management Norsk Industri, Maritim bransjeforening (chair of the board positions last five years ...... 2009-2016 board member 2008-2009), Norsk Industri (chair of the board 2013-2015 board member 2010-2013)

135

and Rapp Marine Group AS (board member 2012-2014)

Birgitte Ringstad Vartdal, member Ms. Vartdal has been a member of the Corporate Assembly since 12 May 2016. She was formerly a deputy member of the Corporate Assembly. Ms. Vartdal has been the CEO of Golden Ocean Management AS, the management company of the stock listed company Golden Ocean Group Limited, from April 2016. Before that she served six years as CFO for the same company. She also serves as a member of the board of directors of Golden Ocean Management AS. Ms. Vartdal is the chair of the board of directors of Sevan Drilling Ltd and a board member of Marine Harvest ASA, Kvart Invest AS and Vartdal Fiskeriselskap AS.

Current directorships and senior management Golden Ocean Management AS (CEO and board member), positions ...... Sevan Drilling Ltd (chair of the board of directors), Marine Harvest ASA (board member), Kvart Invest AS (board member) and Vartdal Fiskeriselskap AS (board member). Previous directorships and senior management Golden Ocean Management AS (CFO and board member), positions last five years ...... Sevan Drilling ASA (interim CEO), Sevan Drilling Ltd (board member) and Sevan Drilling ASA (board member).

Jarle Roth, member Mr. Roth has been a member of the Corporate Assembly since 12 May 2016. Mr. Roth is, as of August 2016, the CEO of Arendal Fossekompani from. Mr. Roth has previously been CEO for Eksportkreditt, the deputy chief executive of Umoe Gruppen, CEO of Unitor ASA and Umoe-Harding Group. Mr. Roth is deputy chair of the board of directors of Ekornes ASA and is a board member of Kongsberg Gruppen ASA. Mr. Roth holds a MA in business economics from the Norwegian School of Economics and Business administration (NHH) in Bergen.

Current directorships and senior management Arendals Fossekompani ASA (CEO), Ekornes ASA (deputy positions ...... chair) and Kongsberg Gruppen ASA (member). Previous directorships and senior management Eksportkreditt (CEO), Umoe Gruppen (deputy CEO), Unitor positions last five years ...... ASA (CEO) and Umoe-Harding Group (CEO).

Kathrine Næss, member Ms. Næss has been a member of the Corporate Assembly since 12 May 2016. Ms. Næss is director of the aluminium factory Alcoa in Mosjøen and has worked with Alcoa since 2006. Ms. Næss holds a MA in business administration from Trondheim Business School.

Current directorships and senior management Alcoa (director). positions ...... Previous directorships and senior management Not applicable. positions last five years ......

Brit Gunn Ersland, member Ms. Ersland has been a member of the Corporate Assembly since May 2015. Mrs. Ersland has been employed with Statoil since 1997. She was previously a leading engineer before she became project leader in DPN. Besides her employment with Statoil, Mrs. Ersland is the CEO and a board member of Erstek AS.

Current directorships and senior management Erstek AS (CEO, Board member). positions ...... Previous directorships and senior management Not applicable. positions last five years ......

Steinar Kåre Dale, member Mr. Dale has been a member of the Corporate Assembly since May 2013. Mr. Dale has been employed with Statoil since 2001, and before that he was hired by Statoil on contract. Mr. Dale works as a senior analyst on IT infrastructure in GBS.

Current directorships and senior management Not applicable. positions ......

136

Previous directorships and senior management Not applicable. positions last five years ......

Per Martin Labråthen, member Mr. Labråthen has been a member of the Corporate Assembly since May 2009. Mr. Labråthen was originally a process technician at Gullfaks C, and is currently a full-time local union representative for the trade union Industri Energi in Statoil.

Current directorships and senior management Not applicable . positions ...... Previous directorships and senior management Not applicable. positions last five years ......

Anne K. S. Horneland, member Ms. Horneland has been a member of the Corporate Assembly since 2006. Ms. Horneland has been employed with Statoil since 1982. She is currently a full-time local union representative for the trade union Industri Energi in Statoil.

Current directorships and senior management Not applicable . positions ...... Previous directorships and senior management Not applicable. positions last five years ......

Jan Eirik Feste, member Mr. Feste has been a member of the Corporate Assembly since May 2009. Mr. Feste began his career in Statoil as management technician, and is currently a full-time local union representative as leader for SAFE in Statoil.

Current directorships and senior management Not applicable. positions ...... Previous directorships and senior management Not applicable. positions last five years ......

Hilde Møllerstad, member Ms. Møllerstad has been a member of the Corporate Assembly since May 2013. Ms. Møllerstad was a leading engineer up to 2013 when she entered her current role as project leader for Petec (DPI).

Current directorships and senior management Not applicable. positions ...... Previous directorships and senior management Not applicable. positions last five years ......

11.5 Incentive schemes In 2004, the Board of Directors resolved to establish a share saving plan equal for all employees of Statoil, in line with its competitors. The purpose of this plan was to strengthen a good business culture and encourage loyalty through employees becoming part-owners of the Company. Statoil's share saving plan provides employees with the opportunity to purchase Statoil shares through monthly salary deductions and a contribution by Statoil. If the shares are kept for two full calendar years of continued employment, following the year of purchase, the employees will be allocated one bonus share for each one they have purchased. Shares transferred to employees are acquired by the Company in the market.

Statoil’s remuneration concept for the Management consists of three main elements; (i) fixed remuneration (base salary) and as applicable cash compensation, (ii) variable pay (annual variable pay (and long-term Incentive ("LTI")) and (iii) benefits (primarily pension, insurance and share savings plan). The LTI system is a monetary compensation calculated as a portion of the participant’s base salary; with a maximum annual grant at 30% of fixed remuneration. The LTI grant level is differentiated related to position level. On behalf of the participant, the Company acquires shares equivalent to the net annual amount. The grant is subject to a three

137

year lock-in period and then released for the participant’s disposal. The purpose of the LTI system is to strengthen the alignment of top management and shareholder interests and to retain key employees.

11.6 Shareholding and share options There are no options held by the members of the Board of Directors or the Management. The table below set out an overview of shares held by the Board of Directors, the Management and members of the Corporate Assembly as of 22 August 2016:

Name Position Shares Øystein Løseth Chair of the Board of Directors 1,013 Jakob Stausholm Member of the Board of Directors 50,589 Wenche Agerup Member of the Board of Directors 2,456 Lill-Heidi Bakkerud Member of the Board of Directors 167 Ingrid Elisabeth di Valerio Member of the Board of Directors 3,345 Stig Lægreid Member of the Board of Directors 1,832 Eldar Sætre CEO 45,473 Hans Jakob Hegge CFO 23,691 Anders Opedal COO 15,199 Lars Christian Bacher Executive vice president Development and Production International (DPI) 19,530 Torgrim Reitan Executive vice president Development and Production USA (DPUSA) 29,887 John Knight Executive vice president Global Strategy and Business Development (GSB) 95,007 Tim Dodson Executive vice president, Exploration (EXP) 27,838 Margareth Øvrum Executive vice president Technology, Projects and Drilling (TPD) 40,735 Arne Sigve Nylund Executive vice president Development and production Norway (DPN) 11,013 Jens Økland Executive vice president Marketing, Midstream and Processing (MMP) 13,568 Irene Rummelhoff Executive vice president New Energy Solutions (NES) 19,992 Terje Venold Member of the Corporate Assembly 506 Jarle Roth Member of the Corporate Assembly 43 Brit Gunn Ersland Member of the Corporate Assembly 1,944 Steinar Kåre Dale Member of the Corporate Assembly 2,873 Per Martin Labråthen Member of the Corporate Assembly 902 Anne K.S. Horneland Member of the Corporate Assembly 5,119 Jan-Eirik Feste Member of the Corporate Assembly 1,186 Hilde Møllerstad Member of the Corporate Assembly 3,218 Total shareholding in Statoil ASA 417,126

11.7 Conflicts of interests etc. During the last five years preceding the date of this Prospectus, none of the members of the Board of Directors, the Corporate Assembly nor any member of Management has, or had, as applicable:

• any convictions in relation to indictable offences or convictions in relation to fraudulent offences;

• received any official public incrimination and/or sanctions by any statutory or regulatory authorities (including designated professional bodies) or was disqualified by a court from acting as a member of the administrative, management or supervisory bodies of a company or from acting in the management or conduct of the affairs of any company, or

• been declared bankrupt or been associated with any bankruptcy, receivership or liquidation in his or her capacity as a founder, director or senior manager of a company.

To the Company’s knowledge, there are currently no actual or potential conflicts of interest between the Company and the private interests or other duties of any of the members of the Management and the Board of Directors, including any family relationships between such persons.

138

12 RELATED PARTY TRANSACTIONS This Section provides information certain transactions which Statoil is, or has been, subject to with its related parties following 31 December 2015.

12.1 Transactions with the Norwegian State The Norwegian State is the majority shareholder of Statoil and also holds major investments in other Norwegian companies. As of the date of this Prospectus the Norwegian State had an ownership interest in Statoil of 67.0% (excluding Folketrygdfondet, the Norwegian national insurance fund, of 3.21%). This ownership structure means that Statoil participates in transactions with many parties that are under a common ownership structure and therefore meet the definition of a related party. All transactions are considered to be on an arm's length basis.

Total purchases of oil and natural gas liquids from the Norwegian State amounted to USD 2.7 billion for the period starting 1 January 2016 up to 30 June 2016. The Company sells in its own name, but for the Norwegian State’s account and risk, the Norwegian State’s gas production. These transactions are presented net. For further information please see note 2 Significant accounting policies in the financial statements for 2015 which have been incorporated by reference, see Section 17.1 "Cross reference table".

12.2 Other transactions In relation to its ordinary business operations Statoil enters into contracts such as pipeline transport, gas storage and processing of petroleum products, with companies in which Statoil has ownership interests. Such transactions are carried out on an arm's length basis and are included within the applicable captions in the Consolidated statement of income. Gassled and certain other infrastructure assets are operated by Gassco AS, which is an entity under common control by MPE. Gassco’s activities are performed on behalf of and for the risk and reward of pipeline and terminal owners, and capacity payments flow through Gassco to the respective owners. These related party transactions with Gassco have no impact on the Company's reported Revenues. Statoil payments that flowed through Gassco in this respect amounted to USD 0.5 billion for the period starting 1 January 2016 up to 30 June 2016.

139

13 CORPORATE INFORMATION; SHARES AND SHARE CAPTAL; SHAREHOLDERS 13.1 Incorporation; registration number; registered office and other Company information The Company is a Norwegian public limited liability company (nw: allmennaksjeselskap), incorporated under the laws of Norway and in accordance with the Norwegian Public Limited Liability Companies Act. The Company’s business registration number is 923 609 016. The Company was incorporated on 18 September 1972. The legal and commercial name of the Company is Statoil ASA.

The head office and registered address of the Company is Forusbeen 50, 4035 Stavanger, Norway, its telephone number +47 51 99 00 00 and its website is http://www.statoil.com.

13.2 Share capital and share capital history As of the date of this Prospectus, the Company’s share capital is NOK 8,017,365,112.50, divided into 3,206,946,045 shares each with a nominal value of NOK 2.50. All the Shares have been created under the Norwegian Public Limited Companies Act, and are validly issued and fully paid. The Company’s Shares are freely transferable.

The table below shows the development in the Company's share capital for the period from 1 January 2013 to the date hereof:

Nominal Number of Date of Type of Change in share value shares New number New share registration change capital (NOK) (NOK) issued of shares capital (NOK)

23 June 2016 Share capital 45,747,355 2.50 18,298,942 3,206,946,045 8,017,365,112.50 increase (dividend issue)

13.3 Shareholder rights The Company has one class of Shares in issue, and in accordance with the Norwegian Public Limited Companies Act, all Shares in that class provide equal rights in the Company, including the right to dividend. Each of the Shares carries one vote. The rights attaching to the Shares are described in Section 13.10 "The Articles of Association" and Section 13.11 "Certain aspects of Norwegian law".

13.4 Legal structure The Company is the ultimate parent company in the Statoil group and the business is carried out both through the Company and its wholly or partly owned subsidiaries. The main activities in the Company are trading activities and corporate functions. Most of Statoil's subsidiaries are private limited liability companies incorporated under the laws of Norway, but subsidiaries are also incorporated under the laws of other jurisdictions than Norway. The following table sets out information about the Company’s significant subsidiaries:

Country of Ownership Company incorporation Activity interest

Statholding AS Norway Holding company 100% Statoil Angola Block 15 AS Norway Participating in the Block 15 license in Angola 100% Statoil Angola Block 17 AS Norway Participating in the Block 17 license in Angola 100% Statoil Angola Block 31 AS Norway Participating in the Block 31 license in Angola 100% Statoil Angola Block 38 AS Norway Participating in the Block 38 license in Angola 100% Statoil Angola Block 39 AS Norway Participating in the Block 39 license in Angola 100% Statoil Angola Block 40 AS Norway Participating in the Block 40 license in Angola 100% Statoil Apsheron AS Norway Holding company for the Azeri, Chirag, Gunashli (ACG) 100% license in Azerbaijan Statoil BTC Finance AS Norway Participating in the Baku-Tbilisi-Ceyhan oil pipeline 100% Statoil Coordination Centre NV Belgium Financing activities 100% Statoil Denmark AS Denmark Refining activities (Kalundborg refinery) 100%

140

Country of Ownership Company incorporation Activity interest

Statoil Deutschland GmbH Germany Transportation and storage of natural gas 100% Statoil do Brasil Ltda Brazil Participating in exploration licenses in Brazil 100% Statoil Exploration Ireland Ltd. Ireland Participating principally in the Corrib license in Ireland 100% Statoil Forsikring AS Norway Insurance activities 100% Statoil Indonesia Karama AS Norway Participating in the Karama license in Indonesia 100% Statoil New Energy AS Norway Holding company 100% Statoil Nigeria AS Norway Participating in the OML 127 and 128 licenses in 100% Nigeria Statoil Norsk LNG AS Norway Holding company 100% Statoil North Africa Gas AS Norway Participating in the In Salah license in Algeria 100% Statoil North Africa Oil AS Norway Participating in the In Amenas license in Algeria 100% Statoil OTS AB Sweden Storage activities 100% Statoil Petroleum AS Norway Participating in licenses on the Norwegian Continental 100% Shelf Statoil Tanzania AS Norway Participating in the Block 2 license in Tanzania 100% Statoil Technology Invest AS Norway Investment company 100% Statoil UK Ltd United Participating in licenses on the UK Continental Shelf 100% Kingdom and trading activities Statoil Venture AS Norway Venture activities 100% Statoil Metanol ANS Norway Production of methanol 82% Mongstad Refining DA Norway Refining activity (Mongstad) 79% Mongstad Terminal DA Norway Storage activities (Mongstad) 65% Tjeldbergodden Luftgassfabrikk DA Norway Air separation activities 51% Vestprosessen DA Norway Transportation of NGL 34%

13.5 Major shareholders The table below shows the Company’s 20 largest shareholders as recorded in the shareholders’ register of the Company with the VPS as of 23 August 2016, the last practical date prior to the date of this Prospectus.

Name % Holding Olje- og Energidepartementet 67.00 2,148,653,850 Folketrygdfondet 3.21 102,991,747 Clearstream Banking 2.68 86,042,678 Deutsche Bank Trust S/A Depositary Receipt 2.57 82,462,146 State Street Bank & S/A SSB Client Omni 0.81 25,904,000 State Street Bank AN A/C West Non-Treaty 0.76 24,327,645 UBS Switzerland AG A/C Omnibus Disclosure 0.60 19,113,402 State Street Bank AN A/C Client Omnibus F 0.58 18,681,533 Euroclear Bank S.A./25% Clients 0.54 17,470,528 Skandinaviska Enskilda SEB S.A. Client Asse. 0.39 12,522,585 State Street Bank & A/C Client Fund Numb 0.37 11,958,976 The Northern Trust C Non-Treaty Account 0.34 11,030,280 J.P. Morgan Chase Ba A/C Vanguard BBH LEN 0.33 10,572,011 KLP AksjeNorge Indeks 0.33 10,566,208 Invesco Funds BNY Mellon (Luxembourg) 0.32 10,286,913 The Bank of New York BNY MELLON 0.32 10,153,868 Statoil ASA 0.31 9,976,152 J.P. Morgan Chase Ba A/C US Resident Non 0.31 9,812,291 Fidelity Funds-Europ 0.30 9,726,144 State Street Bank AN A/C Client Omnibus D 0.29 9,396,039 Total 82.36 2,641,648,996

141

As of the date of this Prospectus, the Company owns 9,976,152 treasury shares with a nominal value of NOK 2.50 and a book value of NOK 1,399,010,809. The average cost price of Statoil’s treasury shares is NOK 140.24 per share.

Shareholders owning 5% or more of the Shares have an interest in the Company’s share capital which is notifiable pursuant to the Norwegian Securities Trading Act. See Section 15.7 "Disclosure obligations" for a description of the disclosure obligations under the Norwegian Securities Trading Act. The Norwegian State is to Statoil’s knowledge the only shareholder in the Company with a notifiable shareholding in Statoil, holding 67% of the shares.

As the Norwegian State owns 67% of the Shares in the Company, the Norwegian State would have the ability to significantly influence the matters submitted for vote of the shareholders of the Company. No particular measures are initiated to ensure that control is not abused by large shareholders, but the Norwegian Public Limited Liability Companies Act provides certain protections against the abuse by a major shareholder of the minority shareholders of a Norwegian public limited liability company. For a discussion of such protections see Section 13.11 "Certain aspects of Norwegian law - Minority Rights".

The major shareholders of the Company do not have different voting rights than the other shareholders of the Company. Other than as mentioned above, the Company is not aware of any persons or entities that, directly or indirectly, jointly or severally, will exercise or could exercise control over the Company. The Company is not aware of any arrangements the operation of which may at a subsequent date result in a change of control of the Company.

13.6 Authorisation to distribute dividend based on approved annual accounts for 2015 At the Company’s annual general meeting held on 11 May 2016, the general meeting granted the following authorisation to the Board of Directors:

"The general meeting of Statoil ASA hereby authorises the board of directors to resolve the payments of dividend based on the company’s approved annual accounts for 2015, cf. the Norwegian Public Limited Liability Companies Act section 8-2, second paragraph.

The board of directors shall, when using the authorisation, make its decisions in accordance with the company’s approved dividend policy. The board of directors shall before each decision to approve the payment of dividends consider if the company, after the payment of dividends, will have sufficient equity and liquidity.

As further set out in agenda item 8 below, shareholders may choose to receive their dividend wholly or partially in cash or in newly issued shares.

The authorisation is valid until the next annual general meeting, but not beyond 30 June 2017."

13.7 Authorisation to increase the share capital and to issue Shares At the Company’s annual general meeting held on 11 May 2016, the general meeting granted the following authorisation to the Board of Directors:

1. The share capital may, in one or more rounds, be increased by a total of up to NOK 1,200,000,000.

2. The authorisation may only be utilized to increase the share capital in connection with the implementation of Statoil ASA's scrip dividend programme for first quarter to third quarter 2016.

142

4. The authorisation shall be valid until the next annual general meeting, but not beyond 30 June 2017."

13.8 Authorisation to acquire Statoil ASA shares in the market to continue operation of the share savings plan for employees At the Company’s annual general meeting held on 11 May 2016, the general meeting granted the following authorisation to the Board of Directors:

"The board of directors is authorised on behalf of the company to acquire Statoil shares in the market. The authorisation may be used to acquire own shares at a total nominal value of up to NOK 42,000,000. The minimum and maximum amount that may be paid per share will be NOK 50 and 500 respectively.

Shares acquired pursuant to this authorisation may only be used for sale and transfer to employees of the Statoil group as part of the group’s share saving plan, as approved by the board of directors.

The authorisation is valid until the next annual general meeting, but not beyond 30 June 2017. This authorisation replaces the previous authorisation to acquire own shares for implementation of the share saving plan for employees granted by the annual general meeting on 19 May 2015."

13.9 Authorisation to acquire Statoil ASA shares in the market for subsequent annulment At the Company’s annual general meeting held on 11 May 2016, the general meeting granted the following authorisation to the Board of Directors:

"The board of directors of Statoil is hereby authorised to acquire in the market on behalf of the company, Statoil shares with a face value of up to NOK 187,500,000. The minimum and maximum amount that can be paid per share will be NOK 50 and NOK 500, respectively. Within these limits, the board of directors shall itself decide at what price and at what time such acquisition shall take place.

Own shares acquired pursuant to this authorisation may only be used for annulment through a reduction on the company’s share capital, pursuant to the Public Limited Liability Companies Act section 12-1.

The authorisation is valid until the next annual general meeting, but not beyond 30 June 2017."

13.10 The Articles of Association The Articles of Association are set out in Appendix A to this Prospectus. Below is a summary of provisions of the Articles of Association.

Objective of the Company The objective of the company is to engage in exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products, and other forms of energy, as well as other business. The activities may also be carried out through participation in or cooperation with other companies.

Registered office The Company’s registered office is in the municipality of Stavanger, Norway.

143

Share capital and nominal value The Company's share capital is NOK 8,017,365,112.50 divided into 3,206,946,045 shares each with a nominal value of NOK 2.50.

Board of Directors and the Corporate Assembly The Board of Directors of the Company shall consist of 9-11 members. The Board of Directors, including the chair and the deputy chair, shall be elected by the Corporate Assembly. The Company shall have a Corporate Assembly consisting of 18 members and deputy members, whereby 2/3 is elected by the general meeting and 1/3 is elected by the employees.

Restrictions on transfer of Shares The Articles of Association do not provide for any restrictions on the transfer of Shares, or a right of first refusal for the Company. Share transfers are not subject to approval by the Board of Directors.

The Articles of Association does not set out conditions that are more significant than what is required by the Norwegian Public Limited Liability Companies Act when it comes to actions necessary to change the rights of holders of the Shares.

General manager The Board of Directors appoint the Company’s CEO and stipulate his/her salary.

General meetings The annual general meeting shall address and decide the following matters:

• Adoption of the annual report and accounts, including the declaration of dividends.

• Any other matters which are referred to the annual general meeting by statute law or the Articles of Association.

If documents related to matters that shall be dealt with by the general meeting is made available for the shareholders on the Company's webpage, the general requirements in the Norwegian Public Limited Liability Companies Act that the documents shall be sent to all shareholders does not apply. This includes documents that according to law shall be included in or attached to the notice for a general meeting. A shareholder may nevertheless request that documents relating to matters to be deliberated by the general meeting are forwarded to him or her.

Marketing Instructions The Company shall be responsible for the marketing and sale of the state’s petroleum which is produced from the state’s direct financial interest (SDFI) on the NCS, as well as for the marketing and sale of petroleum paid as royalty in accordance with the Petroleum Act of 29 November 1996 No 72. On 25th May 2001 and 11th May 2016 the annual general meeting of the Company adopted further instructions concerning the marketing and sale.

13.11 Certain aspects of Norwegian law General meetings Through the general meeting, shareholders exercise supreme authority in a Norwegian company. In accordance with Norwegian law, the annual general meeting of shareholders is required to be held each year on or prior to 30 June. Norwegian law requires that a written notice of annual general meetings setting forth the time of, the venue for and the agenda of the meeting shall be sent to all shareholders with a known address no later than 21 days before the annual general meeting shall be held. This rule applies to all Norwegian public limited liability company listed on a stock exchange or a regulated market, unless the articles of association stipulate a longer deadline, which is not currently the case for the Company.

A shareholder may vote at the general meeting either in person or by proxy appointed at their own discretion. In accordance with the requirements of the Norwegian Securities Trading Act, the Company will include a proxy

144

form with notices of general meetings. All of the Company’s shareholders who are registered in the register of shareholders maintained with the VPS as of the date of the general meeting, or who have otherwise reported and documented ownership to Shares, are entitled to participate at general meetings, without any requirement of pre-registration.

Apart from the annual general meeting, extraordinary general meetings of shareholders may be held if the Board of Directors considers it necessary. An extraordinary general meeting of shareholders must also be convened if, in order to discuss a specified matter, the auditor or shareholders representing at least 5% of the share capital demands this in writing. The requirements for notice and admission to the annual general meeting also apply to extraordinary general meetings. However, the annual general meeting of a Norwegian public limited company may with a majority of at least two-thirds of the aggregate number of votes cast as well as at least two-thirds of the share capital represented at a general meeting resolve that extraordinary general meetings may be convened with a fourteen days’ notice period until the next annual general meeting provided the company has procedures in place allowing shareholders to vote electronically.

Voting rights – amendments to the Articles of Association Each of the Company’s Shares carries one vote. In general, decisions that shareholders are entitled to make under Norwegian law or the Articles of Association may be made by a simple majority of the votes cast. In the case of elections or appointments, the person(s) who receive(s) the greatest number of votes cast are elected. However, as required under Norwegian law, certain decisions, including resolutions to waive preferential rights to subscribe in connection with any share issue in the Company, to approve a merger or demerger of the Company, to amend the Articles of Association, to authorise an increase or reduction in the share capital, to authorise an issuance of convertible loans or warrants by the Company or to authorise the Board of Directors to purchase Shares and hold them as treasury shares or to dissolve the Company, must receive the approval of at least two-thirds of the aggregate number of votes cast as well as at least two-thirds of the share capital represented at a general meeting. Norwegian law further requires that certain decisions, which have the effect of substantially altering the rights and preferences of any shares or class of shares, receive the approval by the holders of such shares or class of shares as well as the majority required for amending the Articles of Association.

Decisions that (i) would reduce the rights of some or all of the Company’s shareholders in respect of dividend payments or other rights to assets or (ii) restrict the transferability of the Shares, require that at least 90% of the share capital represented at the general meeting in question vote in favour of the resolution, as well as the majority required for amending the Articles of Association.

In general, only a shareholder registered in the VPS is entitled to vote for such Shares. Beneficial owners of the Shares that are registered in the name of a nominee are generally not entitled to vote under Norwegian law, nor is any person who is designated in the VPS register as the holder of such Shares as nominees. Investors should note that there are varying opinions as to the interpretation of the right to vote on nominee registered shares. In the Company’s view, a nominee may not meet or vote for Shares registered on a nominee account (NOM-account). A shareholder must, in order to be eligible to register, meet and vote for such Shares at the general meeting, transfer the Shares from such nominee-account to an account in the shareholder’s name. Such registration must appear on a transcript from the VPS at the latest at the date of the general meeting.

There are no quorum requirements that apply to the general meetings.

Additional issuances and preferential rights If the Company issues any new Shares, including bonus share issues, the Articles of Association must be amended, which requires the same vote as other amendments to the Articles of Association. In addition, under Norwegian law, the Company’s shareholders have a preferential right to subscribe for new Shares issued by the Company. Preferential rights may be derogated from by resolution in a general meeting passed by the same vote required to amend the Articles of Association. A derogation of the shareholders’ preferential rights in respect of bonus issues requires the approval of all outstanding Shares.

The general meeting may, by the same vote as is required for amending the Articles of Association, authorise the Board of Directors to issue new Shares, and to derogate from the preferential rights of shareholders in connection with such issuances. Such authorisation may be effective for a maximum of two years, and the

145

nominal value of the Shares to be issued may not exceed 50% of the registered nominal share capital when the authorisation is registered with the Norwegian Register of Business Enterprises.

Under Norwegian law, the Company may increase its share capital by a bonus share issue, subject to approval by the Company’s shareholders, by transfer from the Company’s distributable equity and thus the share capital increase does not require any payment of a subscription price by the shareholders. Any bonus issues may be affected either by issuing new shares to the Company’s existing shareholders or by increasing the nominal value of the Company’s outstanding Shares.

Issuance of new Shares to shareholders who are citizens or residents of the United States upon the exercise of preferential rights may require the Company to file a registration statement in the United States under United States securities laws. Should the Company in such a situation decide not to file a registration statement, the Company’s U.S. shareholders may not be able to exercise their preferential rights. If a U.S. shareholder is ineligible to participate in a rights offering, such shareholder would not receive the rights at all and the Company would seek to sell such rights on the shareholder’s behalf.

Minority rights Norwegian law sets forth a number of protections for minority shareholders of the Company, including but not limited to those described in this paragraph and the description of general meetings as set out above. Any of the Company’s shareholders may petition Norwegian courts to have a decision of the Board of Directors or the Company’s shareholders made at the general meeting declared invalid on the grounds that it unreasonably favours certain shareholders or third parties to the detriment of other shareholders or the Company itself. The Company’s shareholders may also petition the courts to dissolve the Company as a result of such decisions to the extent particularly strong reasons are considered by the court to make necessary dissolution of the Company.

Minority shareholders holding 5% or more of the Company’s share capital have a right to demand in writing that the Board of Directors convene an extraordinary general meeting to discuss or resolve specific matters. In addition, any of the Company’s shareholders may in writing demand that the Company place an item on the agenda for any general meeting as long as the Board of Directors is notified within seven days before the deadline for convening the general meeting and the demand is accompanied with a proposed resolution or a reason for why the item shall be on the agenda. If the notice has been issued when such a written demand is presented, a renewed notice must be issued if the deadline for issuing notice of the general meeting has not expired.

Rights of redemption and repurchase of Shares The share capital of the Company may be reduced by reducing the nominal value of the Shares or by cancelling Shares. Such a decision requires the approval of at least two-thirds of the aggregate number of votes cast and at least two-thirds of the share capital represented at a general meeting. Redemption of individual Shares requires the consent of the holders of the Shares to be redeemed.

The Company may purchase its own Shares provided that the Board of Directors has been granted an authorisation to do so by a general meeting with the approval of at least two-thirds of the aggregate number of votes cast and at least two-thirds of the share capital represented at the meeting. The aggregate nominal value of treasury shares so acquired, and held by the Company must not exceed 10% of the Company’s share capital, and treasury shares may only be acquired if the Company’s distributable equity, according to the latest adopted balance sheet, exceeds the consideration to be paid for the shares. The authorisation by the general meeting of the Company’s shareholders cannot be granted for a period exceeding two years.

Shareholder vote on certain reorganisations A decision of the Company’s shareholders to merge with another company or to demerge requires a resolution by the general meeting of the shareholders passed by at least two-thirds of the aggregate votes cast and at least two-thirds of the share capital represented at the general meeting. A merger plan, or demerger plan signed by the Board of Directors along with certain other required documentation, would have to be sent to all the Company’s shareholders, or if the Articles of Association stipulate that, made available to the shareholders on the company’s website, at least one month prior to the general meeting to pass upon the matter.

146

Liability of the members of the Board of Directors Members of the Board of Directors owe a fiduciary duty to the Company and its shareholders. Such fiduciary duty requires that the board members act in the best interests of the Company when exercising their functions and exercise a general duty of loyalty and care towards the Company. Their principal task is to safeguard the interests of the Company.

Members of the Board of Directors may each be held liable for any damage they negligently or wilfully cause the Company. Norwegian law permits the general meeting to discharge any such person from liability, but such discharge is not binding on the Company if substantially correct and complete information was not provided at the general meeting of the Company’s shareholders passing upon the matter. If a resolution to discharge the members of the Board of Directors from liability or not to pursue claims against such a person has been passed by a general meeting with a smaller majority than that required to amend the Articles of Association, shareholders representing more than 10% of the share capital or, if there are more than 100 shareholders, more than 10% of the shareholders may pursue the claim on the Company’s behalf and in its name. The cost of any such action is not the Company’s responsibility but can be recovered from any proceeds the Company receives as a result of the action. If the decision to discharge any of the members of the Board of Directors from liability or not to pursue claims against the members of the Board of Directors is made by such a majority as is necessary to amend the Articles of Association, the minority shareholders of the Company cannot pursue such claim in the Company’s name.

Indemnification of the member of the Board of Directors Neither Norwegian law nor the Articles of Association contains any provision concerning indemnification by the Company of the Board of Directors. The Company is permitted to purchase insurance for the members of the Board of Directors against certain liabilities that they may incur in their capacity as such.

Distribution of assets on liquidation Under Norwegian law, the Company may be wound-up by a resolution of the Company’s shareholders at the general meeting passed by at least two-thirds of the aggregate votes cast and at least two-thirds of the share capital represented at the meeting. In the event of liquidation, the Shares rank equally in the event of a return on capital.

147

14 TAXATION Set out below is a summary of certain Norwegian tax matters related to an investment in the Company. The summary regarding Norwegian taxation is based on Norwegian laws, rules, and regulations in force in Norway as at the date of this Prospectus, which may be subject to any changes in law occurring after such date. Such changes could possibly be made on a retrospective basis. The summary does not address foreign tax laws.

The following summary is of a general nature and does not purport to be a comprehensive description of all the Norwegian tax considerations that may be relevant for a decision to acquire, own or dispose of Shares, including Shares held under the ADR program. Shareholders who wish to clarify their own tax situation should consult with and rely upon their own tax advisers. Shareholders resident in jurisdictions other than Norway and shareholders who cease to be resident in Norway for tax purposes (due to domestic tax law or tax treaty) should specifically consult with and rely upon their own tax advisers with respect to the tax position in their country of residence and the tax consequences related to ceasing to be resident in Norway for tax purposes.

Please note that for the purpose of the summary below, a reference to a Norwegian or Non-Norwegian shareholder refers to the tax residency rather than the nationality of the shareholder.

14.1 Norwegian shareholders 14.1.1 Taxation of dividends Shareholders who are limited liability companies or similar corporate entities resident in Norway for tax purposes ("Norwegian Corporate Shareholders") are comprised by the Norwegian participation exemption method. Under the exemption, only 3 per cent of the dividend income from shares in Norwegian limited liability companies is taxed as ordinary income (25 per cent flat rate), implying that such dividends are effectively taxed at a rate of 0.75 per cent.

Dividends distributed to shareholders who are individuals resident in Norway for tax purposes ("Norwegian Individual Shareholders") are taxable as ordinary income (25 per cent flat rate) to the extent the dividend exceeds a basic tax-free allowance. However, the taxable dividend after reduction with the tax-free allowance shall be adjusted by a factor of 1.15, resulting in a marginal effective tax rate of 28.75 per cent. The tax-free allowance is calculated on a share-by-share basis. The allowance for each share is equal to the cost price of the share multiplied by a determined risk-free interest rate based on the effective rate after tax of interest on treasury bills (Nw: "statskasseveksler") with three months’ maturity. The allowance is calculated for each calendar year, and it is allocated solely to Norwegian Individual Shareholders holding shares at the expiration of the relevant income year. Norwegian Individual Shareholders who transfer shares will thus not be entitled to deduct any calculated allowance related to the year of transfer. Any part of the calculated allowance one year exceeding the dividend distributed on the share ("unused allowance") may be carried forward and set off against future dividends received on (or gains upon realisation of, see below) the same share. Any unused allowance will also be included in the basis for calculating the allowance on the same share in the following years.

14.1.2 Taxation on realisation of shares Sale, redemption or other disposal of shares is considered a realisation for Norwegian tax purposes.

Capital gains generated by Norwegian Corporate Shareholders through a realisation of shares qualifying for Norwegian participation exemption, including the shares in the Company, are exempt from tax. Losses upon the realisation of shares and costs incurred in connection with the purchase and realisation of such shares are not tax deductible for Norwegian Corporate Shareholders.

Capital gains or losses generated by Norwegian Individual Shareholders through realisation of shares is taxable or tax deductible in Norway. Such capital gain or loss is included in or deducted from the shareholder’s ordinary income in the year of realisation. Ordinary income is taxable at a rate of currently 25 per cent. However, the taxable capital gain (after reduction with the tax-free allowance, cf. below) or tax deductible loss shall be adjusted by a factor of 1.15, resulting in a marginal effective tax rate of 28.75 per cent. The gain is subject to tax and the loss is tax deductible irrespective of the duration of the ownership and the number of shares disposed of. The taxable gain/deductible loss is calculated per share, as the difference between the consideration for the share and the Norwegian Individual Shareholder’s cost price of the share, including any

148

costs incurred in relation to the acquisition or realisation of the share. If the Norwegian Individual Shareholder owns shares acquired at different points in time, the shares that were first acquired will be regarded as the first to be disposed of (the "first in first out"-principle). From any capital gain, Norwegian Individual Shareholders are entitled to deduct a calculated allowance, provided that such allowance has not already been used to reduce taxable dividend income. Please refer to Section 14.1.1 "Taxation of dividends" above for a description of the calculation of the allowance. The unused allowance may only be deducted in order to reduce a taxable gain, and cannot increase or produce a deductible loss, i.e., any unused allowance exceeding the capital gain upon the realisation of a share will be annulled.

14.1.3 Net wealth tax The value of shares is included in the basis for the computation of net wealth tax imposed on Norwegian Individual Shareholders. Currently, the marginal net wealth tax rate is 0.85% of the value assessed. The value for assessment purposes for listed shares is equal to the listed value as of 1 January in the year of assessment (i.e. the year following the relevant fiscal year).

Norwegian Corporate Shareholders are not subject to net wealth tax.

14.2 Non-Norwegian Shareholders 14.2.1 Taxation of dividends Dividends distributed to shareholders that are not resident in Norway for tax purposes ("Non-Norwegian Shareholders") from a Norwegian limited liability company are as a general rule subject to Norwegian withholding tax at a rate of 25 per cent. The withholding tax rate of 25 per cent is normally reduced through tax treaties between Norway and the country in which the shareholder is resident.

Dividends distributed to Non-Norwegian Shareholders that are limited liability companies or similar corporate entities ("Non-Norwegian Corporate Shareholders") resident within the EEA for tax purposes, are exempt from Norwegian withholding tax when the shareholder is the beneficial owner of the shares and genuinely established and performing genuine economic business activities within the relevant EEA jurisdiction, provided that Norway is entitled to receive information from the state of residence pursuant to a tax treaty or other international treaty. If no such treaty exists with the state of residence, the shareholder may instead present a confirmation issued by the tax authorities of the state of residence verifying the documentation. If the Non- Norwegian Corporate Shareholder holds the shares in connection with business activities in Norway, the shareholder will be subject to the same taxation as a Norwegian Corporate Shareholder, as described above.

Non-Norwegian Shareholders who are individuals ("Non-Norwegian Individual Shareholders") resident within the EEA for tax purposes may apply individually to Norwegian tax authorities for a refund for an amount corresponding to the calculated tax-free allowance in respect of each individual share, please see Section 14.1.1 "Taxation of Dividends" above. However, the deduction for the tax-free allowance does not apply in the event that the withholding tax rate, pursuant to an applicable tax treaty, leads to a lower taxation on the dividends than the withholding tax rate of 25 per cent less the tax-free allowance. If a Non-Norwegian Individual Shareholder is carrying on business activities in Norway and the shares are effectively connected with such activities, the shareholder will be subject to the same taxation of dividends as a Norwegian Individual Shareholder, as described above.

Non-Norwegian Shareholders who have suffered a higher withholding tax than set out in an applicable tax treaty may apply individually to the Norwegian tax authorities for a refund of the excess withholding tax deducted.

Nominee registered shares, including shares held under the ADR program, will be subject to withholding tax at a rate of 25 per cent unless the nominee has obtained approval from the Norwegian Tax Directorate for the dividend to be subject to a lower withholding tax rate. To obtain such approval the nominee is required to file a summary to the tax authorities including all beneficial owners that are subject to withholding tax at a reduced rate. Deutsche Bank, acting as depositary for redistribution to shareholders under the ADR program, has been granted permission by the Norwegian tax authorities to receive dividends from the Company for redistribution to a beneficial owner of shares under the ADR program at the applicable treaty withholding rate, if the

149

beneficial owner has provided Deutsche Bank with appropriate documentation establishing such shareholder's eligibility for the benefits under the tax treaty with Norway.

The withholding obligation in respect of dividends distributed to Non-Norwegian Shareholders and on nominee registered shares lies with the company distributing the dividends and the Company assumes this obligation.

Non-Norwegian Shareholders should consult their own advisers regarding the availability of treaty benefits in respect of dividend payments.

14.2.2 Taxation on realization of shares Capital gains derived from the sale or other disposal of shares in the Company by Non-Norwegian Corporate Shareholders are not subject to taxation in Norway, and losses are not tax deductible.

Gains from the sale or other disposal of shares in the Company by a Non-Norwegian Individual Shareholder will not be subject to tax in Norway and losses will not be tax deductible, unless the Non-Norwegian Individual Shareholder holds the shares in connection with business activities carried out or managed from Norway. Such taxation may be limited according to an applicable tax treaty or other specific regulations.

14.2.3 Net wealth tax Shareholders not resident in Norway for tax purposes are not subject to Norwegian net wealth tax with respect to the shares, unless the shareholder is an individual and the shareholding is effectively connected to the conduct of trade or business in Norway.

14.3 VAT and transfer taxes etc. No transfer taxes, stamp duty or similar taxes are currently imposed in Norway on purchase, issuance, disposal or redemption of shares. Further, there is no VAT on transfer of shares.

14.4 Inheritance Tax There is no Norwegian inheritance or gift tax on transfer of shares as from the income year 2014.

150

15 SECURITIES TRADING IN NORWAY 15.1 Introduction The Oslo Stock Exchange was established in 1819 and is the principal market in which shares, bonds and other financial instruments are traded in Norway.

The Oslo Stock Exchange has entered into a strategic cooperation with the London Stock Exchange group with regards to, inter alia, trading systems for equities, fixed income and derivatives.

15.2 Trading and settlement Trading of equities on the Oslo Stock Exchange is carried out in the electronic trading system Millennium Exchange. This trading system is in use by all markets operated by the London Stock Exchange, including the Borsa Italiana, as well as by the Johannesburg Stock Exchange.

Official trading on the Oslo Stock Exchange takes place between 09:00 hours (CET/CEST) and 16.20 hours (CET/CEST) each trading day, with pre-trade period between 08:15 hours (CET/CEST) and 09:00 hours (CET/CEST), closing auction from 16:20 hours (CET/CEST) to 16:25 hours (CET/CEST) and a post trade period from 16:25 hours (CET/CEST) to 17:30 hours (CET/CEST). Reporting of after exchange trades can be done until 17:30 hours (CET/CEST).

The settlement period for trading on the Oslo Stock Exchange is two trading days (T+2). This means that securities will be settled on the investor’s account in VPS two days after the transaction, and that the seller will receive payment after two days.

Oslo Clearing ASA, a wholly-owned subsidiary of SIX x-clear AG, a company in the SIX group, has a license from the Norwegian FSA to act as a central clearing service, and has from 18 June 2010 offered clearing and counterparty services for equity trading on the Oslo Stock Exchange.

Investment services in Norway may only be provided by Norwegian investment firms holding a license under the Norwegian Securities Trading Act, branches of investment firms from an EEA member state or investment firms from outside the EEA that have been licensed to operate in Norway. Investment firms in an EEA member state may also provide cross-border investment services into Norway.

It is possible for investment firms to undertake market-making activities in shares listed in Norway if they have a license to this effect under the Norwegian Securities Trading Act, or in the case of investment firms in an EEA member state, a license to carry out market-making activities in their home jurisdiction. Such market-making activities will be governed by the regulations of the Norwegian Securities Trading Act relating to brokers’ trading for their own account. However, such market-making activities do not as such require notification to the Norwegian FSA or the Oslo Stock Exchange except for the general obligation of investment firms that are members of the Oslo Stock Exchange to report all trades in stock exchange listed securities.

15.3 Information, control and surveillance Under Norwegian law, the Oslo Stock Exchange is required to perform a number of surveillance and control functions. The Surveillance and Corporate Control unit of the Oslo Stock Exchange monitors all market activity on a continuous basis. Market surveillance systems are largely automated, promptly warning department personnel of abnormal market developments.

The Norwegian FSA controls the issuance of securities in both the equity and bond markets in Norway and evaluates whether the issuance documentation contains the required information and whether it would otherwise be unlawful to carry out the issuance.

Under Norwegian law, a company that is listed on a Norwegian regulated market, or has applied for listing on such market, must promptly release any inside information directly concerning the company (i.e., precise information about financial instruments, the issuer thereof or other matters which are likely to have a significant effect on the price of the relevant financial instruments or related financial instruments, and which are not publicly available or commonly known in the market). A company may, however, delay the release of such information in order not to prejudice its legitimate interests, provided that it is able to ensure the

151

confidentiality of the information and that the delayed release would not be likely to mislead the public. The Oslo Stock Exchange may levy fines on companies violating these requirements.

15.4 The VPS and transfer of shares The Company’s principal share register is operated through the VPS. The VPS is the Norwegian paperless centralised securities register. It is a computerised book-keeping system in which the ownership of, and all transactions relating to, Norwegian listed shares must be recorded. The VPS and the Oslo Stock Exchange are both wholly-owned by Oslo Børs VPS Holding ASA.

All transactions relating to securities registered with the VPS are made through computerised book entries. No physical share certificates are, or may be, issued. The VPS confirms each entry by sending a transcript to the registered shareholder irrespective of any beneficial ownership. To give effect to such entries, the individual shareholder must establish a share account with a Norwegian account agent. Norwegian banks, Norges Bank (being, Norway’s central bank), authorised securities brokers in Norway and Norwegian branches of credit institutions established within the EEA are allowed to act as account agents.

As a matter of Norwegian law, the entry of a transaction in the VPS is prima facie evidence in determining the legal rights of parties as against the issuing company or any third party claiming an interest in the given security. A transferee or assignee of shares may not exercise the rights of a shareholder with respect to such shares unless such transferee or assignee has registered such shareholding or has reported and shown evidence of such share acquisition, and the acquisition is not prevented by law, the relevant company’s articles of association or otherwise.

The VPS is liable for any loss suffered as a result of faulty registration or an amendment to, or deletion of, rights in respect of registered securities unless the error is caused by matters outside the VPS’ control which the VPS could not reasonably be expected to avoid or overcome the consequences of. Damages payable by the VPS may, however, be reduced in the event of contributory negligence by the aggrieved party.

The VPS must provide information to the Norwegian FSA on an ongoing basis, as well as any information that the Norwegian FSA requests. Further, Norwegian tax authorities may require certain information from the VPS regarding any individual’s holdings of securities, including information about dividends and interest payments.

15.5 Shareholder register – Norwegian law Under Norwegian law, shares are registered in the name of the beneficial owner of the shares. As a general rule, there are no arrangements for nominee registration and Norwegian shareholders are not allowed to register their shares in VPS through a nominee. However, foreign shareholders may register their shares in the VPS in the name of a nominee (bank or other nominee) approved by the Norwegian FSA. An approved and registered nominee has a duty to provide information on demand about beneficial shareholders to the company and to the Norwegian authorities. In case of registration by nominees, the registration in the VPS must show that the registered owner is a nominee. A registered nominee has the right to receive dividends and other distributions, but cannot vote in general meetings on behalf of the beneficial owners.

15.6 Foreign investment in shares listed in Norway Foreign investors may trade shares listed on the Oslo Stock Exchange through any broker that is a member of the Oslo Stock Exchange, whether Norwegian or foreign.

15.7 Disclosure obligations If a person’s, entity’s or consolidated group’s proportion of the total issued shares and/or rights to shares in a company listed on a regulated market in Norway (with Norway as its home state, which will be the case for the Company) reaches, exceeds or falls below the respective thresholds of 5%, 10%, 15%, 20%, 25%, 1/3, 50%, 2/3 or 90% of the share capital or the voting rights of that company, the person, entity or group in question has an obligation under the Norwegian Securities Trading Act to notify the Oslo Stock Exchange and the issuer immediately. The same applies if the disclosure thresholds are passed due to other circumstances, such as a change in the company’s share capital.

152

15.8 Insider trading According to Norwegian law, subscription for, purchase, sale or exchange of financial instruments that are listed, or subject to the application for listing, on a Norwegian regulated market, or incitement to such dispositions, must not be undertaken by anyone who has inside information, as defined in Section 3-2 of the Norwegian Securities Trading Act. The same applies to the entry into, purchase, sale or exchange of options or futures/forward contracts or equivalent rights whose value is connected to such financial instruments or incitement to such dispositions.

15.9 Mandatory offer requirement The Norwegian Securities Trading Act requires any person, entity or consolidated group that becomes the owner of shares representing more than one-third of the voting rights of a company listed on a Norwegian regulated market (with the exception of certain foreign companies not including the Company) to, within four weeks, make an unconditional general offer for the purchase of the remaining shares in that company. A mandatory offer obligation may also be triggered where a party acquires the right to become the owner of shares that, together with the party’s own shareholding, represent more than one-third of the voting rights in the company and the Oslo Stock Exchange decides that this is regarded as an effective acquisition of the shares in question.

The mandatory offer obligation ceases to apply if the person, entity or consolidated group sells the portion of the shares that exceeds the relevant threshold within four weeks of the date on which the mandatory offer obligation was triggered.

When a mandatory offer obligation is triggered, the person subject to the obligation is required to immediately notify the Oslo Stock Exchange and the company in question accordingly. The notification is required to state whether an offer will be made to acquire the remaining shares in the company or whether a sale will take place. As a rule, a notification to the effect that an offer will be made cannot be retracted. The offer and the offer document required are subject to approval by the Oslo Stock Exchange before the offer is submitted to the shareholders or made public.

The offer price per share must be at least as high as the highest price paid or agreed by the offeror for the shares in the six-month period prior to the date the threshold was exceeded. If the acquirer acquires or agrees to acquire additional shares at a higher price prior to the expiration of the mandatory offer period, the acquirer is obliged to restate its offer at such higher price. A mandatory offer must be in cash or contain a cash alternative at least equivalent to any other consideration offered.

In case of failure to make a mandatory offer or to sell the portion of the shares that exceeds the relevant threshold within four weeks, the Oslo Stock Exchange may force the acquirer to sell the shares exceeding the threshold by public auction. Moreover, a shareholder who fails to make an offer may not, as long as the mandatory offer obligation remains in force, exercise rights in the company, such as voting in a general meeting, without the consent of a majority of the remaining shareholders. The shareholder may, however, exercise his/her/its rights to dividends and pre-emption rights in the event of a share capital increase. If the shareholder neglects his/her/its duty to make a mandatory offer, the Oslo Stock Exchange may impose a cumulative daily fine that runs until the circumstance has been rectified.

Any person, entity or consolidated group that owns shares representing more than one-third of the votes in a company listed on a Norwegian regulated market (with the exception of certain foreign companies not including the Company) is obliged to make an offer to purchase the remaining shares of the company (repeated offer obligation) if the person, entity or consolidated group through acquisition becomes the owner of shares representing 40%, or more of the votes in the company. The same applies correspondingly if the person, entity or consolidated group through acquisition becomes the owner of shares representing 50% or more of the votes in the company. The mandatory offer obligation ceases to apply if the person, entity or consolidated group sells the portion of the shares which exceeds the relevant threshold within four weeks of the date on which the mandatory offer obligation was triggered.

Any person, entity or consolidated group that has passed any of the above mentioned thresholds in such a way as not to trigger the mandatory bid obligation, and has therefore not previously made an offer for the

153

remaining shares in the company in accordance with the mandatory offer rules is, as a main rule, obliged to make a mandatory offer in the event of a subsequent acquisition of shares in the company.

15.10 Compulsory acquisition Pursuant to the Norwegian Public Limited Companies Act and the Norwegian Securities Trading Act, a shareholder who, directly or through subsidiaries, acquires shares representing 90% or more of the total number of issued shares in a Norwegian public limited liability company, as well as 90% or more of the total voting rights, has a right, and each remaining minority shareholder of the company has a right to require such majority shareholder, to effect a compulsory acquisition for cash of the shares not already owned by such majority shareholder. Through such compulsory acquisition the majority shareholder becomes the owner of the remaining shares with immediate effect.

If a shareholder acquires shares representing more than 90% of the total number of issued shares, as well as more than 90% of the total voting rights, through a voluntary offer in accordance with the Securities Trading Act, a compulsory acquisition can, subject to the following conditions, be carried out without such shareholder being obliged to make a mandatory offer: (i) the compulsory acquisition is commenced no later than four weeks after the acquisition of shares through the voluntary offer, (ii) the price offered per share is equal to or higher than what the offer price would have been in a mandatory offer, and (iii) the settlement is guaranteed by a financial institution authorised to provide such guarantees in Norway.

A majority shareholder who effects a compulsory acquisition is required to offer the minority shareholders a specific price per share, the determination of which is at the discretion of the majority shareholder. However, where the offeror, after making a mandatory or voluntary offer, has acquired more than 90% of the voting shares of a company and a corresponding proportion of the votes that can be cast at the general meeting, and the offeror pursuant to Section 4-25 of the Norwegian Public Limited Companies Act completes a compulsory acquisition of the remaining shares within three months after the expiry of the offer period, it follows from the Norwegian Securities Trading Act that the redemption price shall be determined on the basis of the offer price for the mandatory/voluntary offer unless specific reasons indicate another price.

Should any minority shareholder not accept the offered price, such minority shareholder may, within a specified deadline of not less than two months, request that the price be set by a Norwegian court. The cost of such court procedure will, as a general rule, be the responsibility of the majority shareholder, and the relevant court will have full discretion in determining the consideration to be paid to the minority shareholder as a result of the compulsory acquisition.

Absent a request for a Norwegian court to set the price or any other objection to the price being offered, the minority shareholders would be deemed to have accepted the offered price after the expiry of the specified deadline.

15.11 Foreign exchange controls There are currently no foreign exchange control restrictions in Norway that would potentially restrict the payment of dividends to a shareholder outside Norway, and there are currently no restrictions that would affect the right of shareholders of a company that has its shares registered with the VPS who are not residents in Norway to dispose of their shares and receive the proceeds from a disposal outside Norway. There is no maximum transferable amount either to or from Norway, although transferring banks are required to submit reports on foreign currency exchange transactions into and out of Norway into a central data register maintained by the Norwegian customs and excise authorities. The Norwegian police, tax authorities, customs and excise authorities, the National Insurance Administration and the Norwegian FSA have electronic access to the data in this register.

154

16 SELLING AND TRANSFER RESTRICTIONS 16.1 General The issue of Dividend Shares to persons located in, or resident of countries other than Norway, may be affected by the laws of the relevant jurisdiction. Existing Shareholders should consult their professional advisors as to whether they require any governmental or other consents or need to observe any other formalities to enable them to subscribe for Dividend Shares.

Receipt of this Prospectus shall not constitute an offer in those jurisdictions in which it would be illegal to make an offer and, in those circumstances, this Prospectus is for information only and should not be copied or redistributed. Except as otherwise disclosed in this Prospectus, if an Existing Shareholder receives a copy of this Prospectus in any territory other than Norway, such Existing Shareholder may not treat this Prospectus as constituting an invitation or offer to it, or a grant of Dividend Shares, unless, in the relevant jurisdiction, such an invitation, offer or grant could lawfully be made to that Existing Shareholder without contravention of any unfulfilled registration or other legal requirements. Accordingly, if an Existing Shareholder receives a copy of this Prospectus, the Existing Shareholder should not distribute or send the same, or transfer the Dividend Shares to any person or in or into any jurisdiction where to do so would or might contravene local securities laws or regulations. If the Existing Shareholder forwards this Prospectus into any such territories (whether under a contractual or legal obligation or otherwise), the Existing Shareholder should direct the recipient's attention to the contents of this Section 16 "Selling and transfer restrictions".

Except as otherwise noted in this Prospectus and subject to certain exceptions: (i) the Dividend Shares being offered in the Dividend Issue may not be offered, sold, resold, transferred or delivered, directly or indirectly, in or into, any jurisdiction in which it would not be permissible to offer the Dividend Shares; and (ii) this Prospectus shall not be accessed by any person in any jurisdiction in which it would not be permissible to offer the Dividend Shares.

If an Existing Shareholder subscribes for Dividend Shares and unless the Company in its sole discretion determines otherwise on a case-by-case basis, that Existing Shareholder will be deemed to have made or, in some cases, be required to make, the following representations and warranties to the Company and any person acting on the Company's or its behalf: a) the Existing Shareholder is not restricted from receiving the Dividend Shares pursuant to the regulatory and legal requirements of any applicable foreign jurisdiction; and b) the Existing Shareholder is not acting, and has not acted, for the account or benefit of a person to which the Dividend Issue cannot be lawfully made.

The Company and its affiliates and others will rely upon the truth and accuracy of the above acknowledgements, agreements and representations, and agree that, if any of the acknowledgements, agreements or representations deemed to have been made by its subscription of Dividend Shares is no longer accurate, it will promptly notify the Company. Any provision of false information or subsequent breach of these representations and warranties may subject the Existing Shareholder to liability.

If a person is acting on behalf of a holder of shares in the Company (including, without limitation, as a nominee, custodian or trustee), that person will be required to provide the foregoing representations and warranties to the Company with respect to the subscription of Dividend Shares on behalf of the holder. If such person cannot or is unable to provide the foregoing representations and warranties, the Company will not be bound to accept subscription by or to authorise the allocation of any of the Dividend Shares to that person or the person on whose behalf the other is acting. Subject to the specific restrictions described below, if a holder of shares in the Company (including, without limitation, their nominees, custodians or trustees) is located in, or resident of, a country outside Norway and wishes to subscribe for Dividend Shares, the holder of shares in the Company must satisfy itself as to full observance of the applicable laws of any relevant territory including obtaining any requisite governmental or other consents, observing any other requisite formalities and paying any issue, transfer or other taxes due in such territories.

155

The Company reserves the right to reject any subscription (or revocation of such subscription) in the name of any person who provides an address in a jurisdiction in which the Dividend Issue cannot be lawfully made, or who is unable to represent or warrant that such person is not located or residing in such jurisdiction. Furthermore, the Company reserves the right, with sole and absolute discretion, to treat as invalid any subscription or purported subscription of Dividend Shares which appears to have been executed, effected or dispatched in a manner that may involve a breach or violation of the laws or regulations of any jurisdiction.

Notwithstanding any other provision of this Prospectus, the Company reserves the right to permit an Existing Shareholder to subscribe for Dividend Shares if the Company, in its absolute discretion, is satisfied that the transaction in question is exempt from or not subject to the laws or regulations giving rise to the restrictions in question. Applicable exemptions in certain jurisdictions are described further below. In any such case, the Company does not accept any liability for any actions that an Existing Shareholder takes or for any consequences that it may suffer as a result of the Company accepting the Existing Shareholder’s subscription of Dividend Shares.

Neither the Company nor its representatives, is making any representation to any subscriber or purchaser of Dividend Shares regarding the legality of an investment in the Dividend Shares by such offeree, subscriber or purchaser under the laws applicable to such offeree, subscriber or purchaser. Each Existing Shareholder should consult its own advisors before subscribing for Dividend Shares.

A further description of certain restrictions in relation to the Dividend Shares in certain jurisdictions is set out below. The information set out in this Section 16 "Selling and transfer restrictions" is intended as a general guide only. If you are in any doubt about any of the contents of these restrictions, or whether any of these restrictions apply to you, you should obtain independent professional advice without delay.

16.2 European Economic Area In relation to each member state of the European Economic Area ("EEA") which has implemented the EU Prospectus Directive, (each, a "Relevant Member State") no Dividend Shares which are the subject of the offering contemplated by this Prospectus have been offered or will be offered to the public in that Relevant Member State, except (i) in Norway once the Prospectus has been approved by the Norwegian FSA and published in accordance with the Prospectus Directive and the relevant provisions of the Norwegian Securities Trading Act; and (ii) in that Relevant Member State at any time under the following exemptions under the Prospectus Directive, if they are implemented in that Relevant Member State:

(i) to legal entities which are qualified investors as defined in the Prospectus Directive;

(ii) to fewer than 150 natural or legal persons (other than qualified investors as defined in the Prospectus Directive); or

(iii) in any other circumstances falling within Article 3(2) of the Prospectus Directive, provided that no such offer of Dividend Shares shall result in a requirement for the publication by the Company of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purpose of the expression 'an offer of shares to the public' in relation to any Dividend Shares in any Relevant Member State means a communication to persons in any form and by any means of sufficient information on the terms of the offer and the Dividend Shares to be offered so as to enable an investor to decide to purchase or subscribe for any Dividend Shares, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State.

16.3 United Kingdom The offer of the Dividend Shares in the United Kingdom is being made pursuant to an exemption under Article 4(1)(d) of the Prospectus Directive from the requirement to publish a prospectus and this Prospectus has not been, and will not be, filed or reviewed by the UK Financial Conduct Authority (the "FCA") or the United Kingdom Listing Authority nor will it be notified to the FCA by the competent authority of another Relevant Member State of the EEA that has approved it in order to benefit from the passporting procedure provided for in the Prospectus Directive. The Company does not intend to publish a prospectus for use in the United

156

Kingdom and this Prospectus which has been prepared under Norwegian law for the purposes of the offer of the Dividend Shares in Norway must not be used in connection with the offer of the Dividend Shares in the United Kingdom. The Company has made available to shareholders in the United Kingdom a separate document containing information on the number and nature of the shares and the reasons for and details of the offer, prepared in accordance with Rule 1.2.2(4) of the Prospectus Rules published by the UK FCA under Part VI of UK Financial Services and Markets Act 2000, which implements Article 4(1)(d) of the Prospectus Directive in the United Kingdom.

16.4 Germany This Prospectus does not constitute a Prospectus Directive-compliant prospectus in accordance with the German Securities Prospectus Act (Wertpapierprospektgesetz ("WpPG")) and does therefore not allow any public offering in the Federal Republic of Germany ("Germany") or via passporting pursuant to Section 17 and Section 18 WpPG in any other Relevant Member State. No action has been or will be taken in Germany that would permit a public offering of the Dividend Shares, or distribution of a prospectus or any other offering material relating to the Dividend Shares. In particular, no prospectus (Prospekt) within the meaning of the WpPG or any other applicable laws in Germany, has been or will be published in Germany, nor has this Prospectus been filed with or approved by the German Federal Financial Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht) for publication in Germany.

Therefore, in Germany, the offer of Dividend Shares is addressed solely to Existing Shareholders who are qualified investors (qualifizierte Anleger) within the meaning of Section 2 no. 6 WpPG in reliance on the exemption from the obligation to publish a prospectus under Section 3 para. 2 sentence 1 no. 1 WpPG in connection with Section 2 no. 6 WpPG, and the Dividend Shares may not be, and are not, publicly offered. In Germany, this Prospectus and any other document relating to the Dividend Shares, including any information contained therein, may not be forwarded or distributed to the public or to non-qualified investors (nicht qualifizierte Anleger) and may not be used in connection with any offer for subscription or sale of the Dividend Shares to the public or to non-qualified investors. This Prospectus and any other document relating to the Dividend Shares are strictly confidential and may not be distributed to any other person or entity.

16.5 France The Dividend Shares may not be offered or subscribed or caused to be offered or subscribed, directly or indirectly, to the public in France. Neither this Prospectus, which has not been submitted to the clearance procedure of the French Autorité des marchés financiers (the "AMF"), nor notified to the AMF by a competent authority of another Relevant Member State of the EEA that has approved it in order to benefit from the passport procedure provided for in the Prospectus Directive as implemented in France and in the Relevant Member State, nor any other offering material or information contained therein relating to the Dividend Shares, may be released, issued or distributed or caused to be released, issued or distributed, directly or indirectly, to the public in France, or used in connection with any offer for subscription, exchange or sale of the Dividend Shares to the public in France.

Any such offers and distributions may be made in France only to Existing Shareholders who are (i) qualified investors (investisseurs qualifiés) acting for their own account, and/or to (ii) fewer than 150 natural or legal persons (other than qualified investors) acting for their own account, all as defined in, and in accordance with, Articles L.411-2, II and D.411-1, D.411-4, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier.

In the event that the Dividend Shares subscribed by investors listed above are offered or resold, directly or indirectly, to the public in France, the conditions relating to public offers set forth in Articles L.411-1, L.411-2, L. 412-1 and L. 621-8 to L. 621-8-3 of the French Code monétaire et financier must be complied with. Investors in France and persons into whose possession offering materials come must inform themselves about, and observe, any such restrictions.

16.6 Switzerland The Dividend Shares may not be offered, sold or advertised, directly or indirectly, in or from Switzerland, other than to any person who has confirmed to be an Existing Shareholder in circumstances which do not constitute a public offer or require the publication of a prospectus (as defined below) pursuant to applicable Swiss law and

157

regulations. Neither this document nor any other offering or marketing material relating to the Dividend Issue constitutes a prospectus as such term is understood pursuant to article 652a of the Swiss Federal Code of Obligations or a listing prospectus within the meaning of the listing rules of the SIX Swiss Exchange Ltd., and neither this document nor any other offering or marketing material relating to the Dividend Issue may be publicly distributed or otherwise made publicly available in Switzerland.

16.7 Canada The Dividend Shares have not been and will not be qualified for distribution under the securities legislation of any province or territory of Canada. None of the Dividend Shares will be directly or indirectly offered for subscription or purchase, taken up, sold, delivered, distributed, renounced or transferred in or into Canada. Therefore the Dividend Issue will not be made within Canada and neither this Prospectus nor any other subscription document will be sent to, nor will any Dividend Shares be credited to an account of, or on behalf of, any shareholder who is resident in or who has a registered address in Canada. Any person resident in Canada who obtains a copy of this Prospectus or any other subscription document is required to disregard them.

16.8 Singapore The offer of Dividend Shares by the Company is made only to and directed at, and the Dividend Shares are only available to, persons in Singapore who are Existing Shareholders, i.e. existing holders of the Shares previously issued by the Company.

This Prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this Prospectus the subscription form and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the Dividend Shares may not be circulated or distributed, nor may the Dividend Shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to existing holders of Shares pursuant to Section 273(1)(cd)(i) of the Securities and Futures Act, Chapter 289 of Singapore (the "SFA") or (ii) pursuant to, and in accordance with the conditions of, an exemption under any provision of Subdivision (4) of Division 1 of Part XIII of the SFA, other than an exemption in Section 280 of the SFA.

16.9 Japan The Dividend Shares have not been and will not be registered under the Financial Instrument and Exchange Law of Japan, as amended (the "FIEL"). The Dividend Shares may not be offered or sold, directly or indirectly, in Japan or to or for the benefit of any resident of Japan (including any person resident in Japan or any corporation or other entity organized under the laws of Japan) or to others for reoffering or resale, directly or indirectly, in Japan or to or for the benefit of any resident of Japan, except pursuant to an exemption from the registration requirements of the FIEL and otherwise in compliance with the FIEL and other relevant laws, regulations and governmental guidelines of Japan.

16.10 Hong Kong The contents of this document have not been reviewed by any regulatory authority in Hong Kong. You are advised to exercise caution in relation to the offer.

This document neither constitute a "prospectus" (as defined in section 2(1) of the Companies (Winding Up and Miscellaneous Provisions) Ordinance (Cap. 32 of the Laws of Hong Kong), nor is it an advertisement, invitation or document containing an advertisement or invitation falling within the meaning of section 103 of the Securities and Futures Ordinance (Cap. 571 of the Laws of Hong Kong). The Dividend Shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies (Winding Up and Miscellaneous Provisions) Ordinance or an invitation to the public within the meaning of the Securities and Futures Ordinance, or (ii) to "professional investors" within the meaning of the Securities and Futures Ordinance and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a "prospectus" within the meaning of the Companies (Winding Up and Miscellaneous Provisions) Ordinance. No advertisement, invitation or document relating to these Dividend Shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are

158

likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to securities which are or are intended to be disposed of only to persons outside Hong Kong or only to "professional investors" within the meaning of the Securities and Futures Ordinance and any rules made thereunder.

This document is strictly confidential to the person to whom it is addressed and must not be distributed, published, reproduced or disclosed (in whole or in part) by you to any other person in Hong Kong or used for any purpose in Hong Kong other than in connection with your consideration of the offer.

159

17 INCORPORATION BY REFERENCE AND DOCUMENTS ON DISPLAY The Norwegian Securities Trading Act and the Norwegian Securities Trading Regulations, implementing Commission Regulation (EC) no. 809/2004 implementing Directive 2003/71/EC of the European Parliament and of the Council of 4 November 2003 regarding information contained in prospectuses as well as the format, incorporation by reference and publication of such prospectuses and dissemination of advertisements, allow the Company to incorporate by reference information into this Prospectus that has been previously filed with Oslo Stock Exchange or the Norwegian FSA in other documents. The Company's consolidated financial statements as of and for the years ended 31 December 2013, 2014 and 2015 and the audit reports in respect of these financial statements, are by this reference incorporated as a part of this Prospectus. Accordingly, this Prospectus is to be read in conjunction with these documents.

17.1 Cross reference table The information incorporated by reference in this Prospectus should be read in connection with the following cross reference table. References in the table to "Annex" and "Items" are references to the disclosure requirements as set forth in the Norwegian Securities Trading Act cf. the Norwegian Securities Trading Regulations by reference to such Annex (and Item therein) of Commission Regulation (EC) no. 809/2004.

Section in the Disclosure Page (P) in reference Prospectus requirement Reference document and link document Annual report on Form 20F http://www.statoil.com/no/InvestorCentre/AnnualReport/A Section 9 - - nnualReport2015/Documents/DownloadCentreFiles/01_Ke yDownloads/Annual_report_on_form_20-F.pdf Interim and Financial statements second quarter 2016 P 10 - 11 (Results of other financial http://www.statoil.com/no/InvestorCentre/QuarterlyResult operation) Section 10 information s/2016/Downloads/Financial%20statement%20and%20re P 12 (Balance sheet) (Annex XXIII, view%202Q%202016.pdf P 15 – 18 (Notes) section 15.6) Financial statements 2015 P 23 - 24 (Results of http://www.statoil.com/no/InvestorCentre/AnnualReport/A operation) nnualReport2015/Documents/DownloadCentreFiles/01_Ke P 25 (Balance sheet) Audited yDownloads/Statutory_report_2015.pdf P 28 – 80 (Notes) historical Financial statements 2014 P 23 - 24 (Results of financial http://www.statoil.com/no/InvestorCentre/AnnualReport/A operation) Section 10 information nnualReport2014/Documents/DownloadCentreFiles/01_Ke P 25 (Balance sheet) (Annex XXIII, yDownloads/Statutory_report_2014.pdf P 28 – 78 (Notes) section 15.1 and 15.3) Financial statements 2013 P 20 - 21 (Results of http://www.statoil.com/no/InvestorCentre/AnnualReport/A operation) nnualReport2013/Documents/DownloadCentreFiles/01_Ke P 22 (Balance sheet) yDownloads/StatutoryReport.pdf P 25 – 79 (Notes) Auditor’s report 2015: http://www.statoil.com/no/InvestorCentre/AnnualReport/A P 113 - 114 nnualReport2015/Documents/DownloadCentreFiles/01_Ke Auditing of yDownloads/Statutory_report_2015.pdf historical annual Auditor’s report 2014: financial http://www.statoil.com/no/InvestorCentre/AnnualReport/A Section 10 P 114 - 115 information nnualReport2014/Documents/DownloadCentreFiles/01_Ke (Annex XXIII, yDownloads/Statutory_report_2014.pdf section 15.4) Auditor’s report 2013: http://www.statoil.com/no/InvestorCentre/AnnualReport/A P 116 - 117 nnualReport2014/Documents/DownloadCentreFiles/01_Ke yDownloads/Statutory_report_2014.pdf

17.2 Documents on display For twelve months from the date of this Prospectus, copies of the following documents will be available for inspection at the Company's registered office during normal business hours from Monday through Friday each week (except public holidays):

• The Articles of Association.

• The Company's Financial Statements, and the related auditor reports thereto.

• The Company's Interim Financial Statements.

• This Prospectus.

160

18 ADDITIONAL INFORMATION 18.1 Independent auditors The Company's independent auditors are KPMG AS, which has registration no. 935 174 627 and their registered address at Sørkedalsveien 6, Oslo, Norway. KPMG AS was elected as the Company’s independent auditor in May 2012. The partners of KPMG AS are members of The Norwegian Institute of Public Accountants (Nw. Den Norske Revisorforening).

KPMG AS has audited the Company’s financial statements for 2013, 2014 and 2015 incorporated by reference in this Prospectus.

18.2 Receiving Agent DNB Bank ASA is the Receiving Agent for this Dividend Issue.

18.3 Legal advisor Advokatfirmaet Thommessen AS is acting as Norwegian legal advisor to the Company in connection with the Dividend Issue.

161

19 NORWEGIAN SUMMARY Sammendrag består av informasjon som skal gis i form av "Elementer". Elementene er nummerert i punktene A – E (A.1 – E.7) nedenfor. Dette sammendraget inneholder alle Elementer som skal være inkludert i et sammendrag for denne type verdipapir og utsteder. Som følge av at enkelte Elementer ikke må beskrives, kan det være huller i nummereringen av Elementene. Selv om man kan være pålagt å innta et Element i sammendraget på grunn av typen verdipapir og utsteder, er det mulig at det ikke kan gis relevant informasjon knyttet til Elementet. I så fall er det inntatt en kort beskrivelse av Elementet i sammendraget sammen med benevnelsen "ikke aktuelt".

I dette norske sammendraget skal definerte ord og uttrykk (angitt med stor forbokstav) som er oversatt til norsk forstås i samsvar med tilsvarende engelskspråklige ord eller uttrykk slik disse er definert i det engelskspråklige Prospektet. Noen eksempler på slike engelskspråklige motstykker til definerte ord og uttrykk som er oversatt til norsk, er som følger: Med "Prospektet" forstås "Prospectus", med "Selskapet" forstås "Company", med "Utbytteaksjeprogram" forstås "Scrip Dividend Programme", med "Utbytteemisjon" forstås "Dividend Issue", med "Aksjene" forstås "Shares", med "Utbytteaksjer" forstås "Dividend Shares", med "Eksisterende Aksjeeier" forstås "Existing Shareholders", med "Tegningskurs" forstås "Subscription Price", med "Netto Utbytte" forstås "Net Dividend", med ""Tegningsperioden" forstås "Subscription Period", med "Eierregistreringsdato" forstås "Record Date", og med "ADR-depositar" forstås "ADR Depositary".

Avsnitt A – Introduksjon og advarsel

A.1 Advarsel Dette sammendraget bør leses som en innledning til Prospektet; enhver beslutning om å investere i verdipapirene bør baseres på investorens vurdering av Prospektet i sin helhet; dersom et krav knyttet til informasjonen i prospektet fremsettes for en domstol, kan saksøkende investor, i henhold til nasjonal lovgivning i sitt Medlemsland, bli pålagt å dekke kostnadene med å oversette Prospektet før rettsforhandlingene igangsettes; og kun de personer som har satt opp sammendraget, herunder oversatt dette, kan pådra seg sivilrettslig ansvar, men kun dersom sammendraget er misvisende, ikke korrekt eller usammenhengende når det leses i sammenheng med de øvrige deler av Prospektet eller dersom sammendraget, når det leses sammen med de øvrige andre deler av Prospektet, ikke gir slik nøkkelinformasjon som investorene behøver når de vurderer om de skal investere i slike verdipapirer.

A.2 Advarsel Ikke aktuelt. Selskapet har ikke gitt samtykke til bruk av prospektet for påfølgende annenhåndssalg eller endelig plassering av aksjene.

Avsnitt B - Utsteder

B.1 Juridisk og Statoil ASA forretningsnavn

B.2 Hjemstat og rettslig Selskapet er et allmennaksjeselskap, stiftet i Norge i henhold til organisering, lovgivning allmennaksjeloven, og med organisasjonsnummer 923 609 016. og stiftelsesland Selskapets forretningsadresse er Forusbeen 50, 4035, Stavanger, Norge.

B.3 Eksisterende virksomhet, Statoil er et teknologidrevet energiselskap som primært er engasjert hovedaktiviteter og i olje- og gassproduksjon. Statoils hovedkontor er i Stavanger, markeder Norge. Statoil er den ledende operatøren på norsk sokkel og har også en betydelig internasjonal virksomhet. Statoil er tilstedeværende i flere av de viktigste olje og gass områdene i verden, har forretningsvirksomhet i flere enn 30 land og territorier, og sysselsetter omkring 21,350 ansatte verden rundt ved utgangen av juli 2016. I andre kvartal 2016 kom 38 % av Statoils

162

egenproduksjon fra den internasjonale virksomheten og Selskapet har også operatørskap internasjonalt.

B.4a Vesentlige aktuelle Tilbudsoverskuddet i oljemarkedet fortsatte inn i 2. kvartal 2016 trender som et resultat av motstandsdyktig skiferproduksjon fra USA, i tillegg til at OPEC forsvarer sine markedsandeler. Råoljeprisen har imidlertid styrket seg i løpet av 2016 siden bunnen i februar 2016 som vist i grafen under.45

Det nåværende oljeprisnivået er ikke bærekraftig, både med hensyn til langsiktige produksjonskostnader, samt likviditetssituasjonen for industrien, men industrien er i ferd med å tilpasse seg situasjonen. Atten måneder med priser mer eller mindre under USD 60/fat har medført betydelige kutt i oljeselskapenes investeringer, som igjen medfører fallende produksjon utenfor OPEC. Hvis prisene faller tilbake til USD 30-40/fat, vil dette ytterligere forsterkes i 2016. Industrien har i tillegg til kutt i antall ansatte annonsert omfattende utsettelser og reduksjoner i investeringsprogrammene – som igjen vil påvirke fremtidige produksjonsnivåer. I tillegg vil de lave prisene bidra til en vekst i etterspørselen på rundt 1.3 millioner fat per dag. Disse faktorene vil gradvis bidra til et strammere marked og lavere lagernivåer. Dette vil igjen bidra til økte priser. Hvor raskt disse endringene vil synes på markedsprisene, og i hvilken grad det vil bane vei for økte priser, er vanskelig å forutse. IEAs syn er at veksten i lagring av råolje vil stoppe opp og at en reversering vil starte i begynnelsen av 2017. Statoil estimerer at tilbud og etterspørsel vil være i balanse i løpet av 2. halvdel av 2016, mens det er behov for ytterligere ett år for å ta kommersielle oljelagre ned til normale nivåer. Fra 2017 er det markedets oppfatning at kostnader for nye fat vil være hovedårsaken til prisdannelsen, så snart kommersielle oljelagre har kommet ned mot mer normale nivåer. I årene som kommer er det forventet at etterspørselen etter olje vil øke til rekordnivåer, med en veksttakt på rundt 1 million fat per dag per år frem mot 2020. I kombinasjon med naturlig produksjonsnedgang, utsettelser av investeringer og andre tilpasninger industrien har gjort, i tillegg til en lav overskuddskapasitet i OPEC, vil dette medføre et strammere marked i årene som kommer. Markedsutviklingen etter at ubalansen er reversert forblir vanskelig å forutse.

45 Kilde olje: S&P Global Platts’ Dated Brent at close, payable source.

163

Europeiske gasspriser har siden 2015 sunket, som vist i grafen nedenfor 46 , da gassmarkedet har kommet under press fra konkurrerende energibærere som kull og olje.

Videre har etterspørsel etter gass i den europeiske kraftsektoren, utenom Storbritannia, blitt redusert på grunn av varmt vær. Noe prisstøtte har man sett i andre kvartal av 2016 da forsyning av LNG har vært lavere enn antatt. Men dette vil ikke vedvare da årlig økning i global kapasitet til å produsere LNG vil ligge et sted mellom 30 til 40 milliarder kubikkmeter gass per år i perioden mellom 2016 og 2018. Dette vil skape en situasjon der det globale LNG markedet er overforsynt til etter 2020. I samme periode vil gapet mellom forsyning og etterspørsel øke i Europa. Synkende innenlands produksjon er hovedårsak, og restriksjoner i produksjon fra Groningen-feltet i Nederland har bidratt betydelig til dette. Etterspørsel forventes å være stabil i denne perioden, og i kraftsektoren kan gass fremover erstatte kull. Sånn sett er utsiktene for gassmarkedene lyse på mellomlang og lang sikt. Men perioden frem mot 2020 vil være preget av stor tilgjengelighet på gass. I perioden etter 2020 tror Statoil at etterspørsel og priser skal stige. I USA har prisene falt og ført til at gass har tatt en større markedsandel på bekostning av andre energibærer som for eksempel kull. På kort sikt vil gass brukes mer der gass kan substituere kull, og på lengre sikt vil flere gasskraftverk bygges, mens kullkraftverk vil avvikles. Gass har nå med 33 % av all kraftproduksjon i USA den største andelen i kraftsektoren. En følge av lave priser er at industrien nå nøye vurderer investeringsplaner og aktivitetsnivå, og setter i kraft ulike initiativ for å redusere operasjonelle kostnader. Gitt de endringer man kan observere i markedskrefter og industristruktur så vil et syn på fremtidig forsyning og etterspørsel være forbundet med usikkerhet. Et lavere investeringsnivå og mangel på ny-investering vil, ifølge industrianalytikere, bidra til at markedet balanseres, men det er usikkert når, og på hvilket prisnivå. Statoil har tidligere innført en rekke tiltak for å sikre en strengere finansiell styring og forbedre kapitaleffektiviteten. Statoil vil fortsette med disse tiltakene, og gjøre en streng prioritering av porteføljen ved å optimalisere prosjekter for å skape en større

46 Kilde gass: ICIS Heren and ECB; Description: European Natural Gas NBP Heren Gas Prices Day ahead (http://www.icis.com/energy/gas/europe/european-spot-gas-markets/), Currency provider ECB, Unit=USD/MMBtu and CME New York Mercantile Exchange Henry Hub Natural Gas Regular Trading Month 01

164

robusthet, samt selge seg ut av prosjekter som ikke anses å være innenfor Statoil sitt kjerneområde, som for eksempel eierskap i Marcellus-operasjonen i den amerikanske porteføljen. I tillegg vil Statoil fortsette å reforhandle med leverandører for å oppnå bedre betingelser.

B.5 Beskrivelsen av Statoil Selskapet er morselskapet i Statoil-konsernet og forretningsvirksomheten drives både gjennom Selskapet og gjennom dets heleide og deleide datterselskap.

B.6 Interesser i utsteder og Aksjeeiere som eier 5 % eller mer av Aksjene, har et eierskap i stemmeretter Selskapets aksjekapital som er meldepliktig etter verdipapirhandelloven. Per dato for dette Prospektet, er det én aksjeeier som eier mer enn 5% av Aksjene i Selskapet; den norske stat eier 67 % av Aksjene. Det er ikke forskjeller i stemmerettigheter mellom Aksjene. Selskapet kjenner ikke til noen forhold som på et senere tidspunkt vil føre til kontrollskifte i Selskapet.

B.7 Utvalgt historisk finansiell Den utvalgte historiske finansielle informasjonen har blitt nøkkelinformasjon inkorporert ved henvisning i dette Prospektet.

B.8 Utvalgt pro forma Ikke aktuelt. Prospektet inneholder ingen pro forma finansiell finansiell informasjon. nøkkelinformasjon

B.9 Resultatprognose eller Ikke aktuelt. Prospektet inneholder ikke noen resultatprognose eller estimat noe estimat.

B.10 Forbehold i Ikke aktuelt. Det er ingen forbehold i revisjonsrapportene. revisjonsrapport

B.11 Arbeidskapital Selskapet har tilstrekkelig arbeidskapital for sine gjeldende forpliktelser.

Avsnitt C - Verdipapirene

C.1 Type og klasse verdipapir Selskapet har én aksjeklasse og alle Aksjer har like rettigheter i tatt opp til notering og Selskapet. Hver Aksje har én stemme. Aksjene er utstedt i henhold identifikasjonsnummer til allmennaksjeloven og er registrert i VPS under ISIN NO 0010096985.

C.2 Valuta på utstedelse Aksjene er utstedt i NOK.

C.3 Antall aksjer utstedt og Forutfor Utbytteemisjonen er aksjekapitalen i Selskapet NOK pålydende verdi 8 017 365 112,50 fordelt på 3 206 946 045 ordinære aksjer hver med pålydende NOK 2,50. Alle Aksjene er utstedt i henhold til allmennaksjeloven og er gyldig utstedt og fullt innbetalt.

C.4 Rettigheter knyttet til Selskapet har én aksjeklasse og i henhold til allmennaksjeloven har verdipapirene alle Aksjer like rettigheter i Selskapet. Hver Aksje har én stemme.

C.5 Begrensninger i Vedtektene setter ingen restriksjoner i Aksjenes omsettelighet, eller verdipapirenes forkjøpsrett for Selskapet. Aksjenes omsettelighet er ikke betinget omsettelighet av samtykke fra Selskapets styre.

C.6 Opptak til notering Aksjene i Selskapet er notert på Oslo Børs under ticker "STL". Utbytteaksjene som utstedes i Utbytteemisjonen vil bli notert. I tillegg er Selskapets American Depositary Receipts (ADR) notert på New York Stock Exchange (NYSE) under ticker "STO". ADR-

165

depositaren vil utstede nye ADR til ADR-holdere basert på Utbytteaksjene som ADR-holdere er berettiget til å motta, som vil bli notert på NYSE.

C.7 Utbyttepolitikk Det er Statoils ambisjon å øke det årlige kontantutbyttet målt i USD per aksje i tråd med langsiktig underliggende fortjeneste. Selskapet annonserer utbytte kvartalsvis. Styret vedtar utbytte for første til tredje kvartal basert på en fullmakt fra generalforsamlingen, mens generalforsamlingen vedtar utbytte for fjerde kvartal (og samlet året), basert på styrets anbefaling. Når styret beslutter de kvartalsvise utbyttene og anbefaler det totale årlige utbyttenivået, tar styret i betraktning forventet kontantstrøm, planer for investeringer, finansieringsforpliktelser og hensiktsmessig finansiell fleksibilitet. I tillegg til kontantutbytte, kan Selskapet kjøpe tilbake aksjer som en del av den totale fordelingen av kapital til aksjeeierne. Styret oppdaterte utbyttepolitikken i 2015 for å reflektere at utbytte deklareres i USD.

Avsnitt D - Risiko

D.1 Vesentlige risiki knyttet til Risiko knyttet til Statoil og bransjen som Statoil opererer i Selskapet eller dets • En forlenget periode med lav olje- og/eller gasspris kan bransje ha en vesentlig negativ effekt på Statoil. • Statoils råolje- og naturgassreserver er kun estimater og Statoils fremtidige produksjon, inntekter og kostnader med hensyn til reservene kan avvike vesentlig fra disse estimatene. • Prøveboring involverer et stort antall risiko, inkludert risikoen for at Statoil vil ikke vil finne olje- og gassreservoarer som kan utvinnes kommersielt. • Statoils utviklingsprosjekter og produksjonsaktivitet er omfattet av mange usikkerhetsmomenter og operasjonsrisikoer som kan forhindre Statoil fra å realisere fortjenester og som kan medføre vesentlig tap. • Noen av Statoils internasjonale interesser er lokalisert i regioner hvor det er politisk, sosial og økonomisk ustabilitet som kan påvirke Statoils forretningsvirksomhet negativt. • Brudd på anti-bestikkelse-, anti-korrupsjonslovgivning og annen lovgivning, inkludert brudd på Statoils etiske krav, eksponerer Statoil for rettslig ansvar og skade på Statoils omdømme, virksomhet og børsverdi. • Statoil er eksponert for en rekke helse, sikkerhet og miljørisikoer som kan resultere i vesentlige tap. • Politiske og regulatoriske endringer som følge en økende bekymring for klimaendringer, og den fysiske effekten av klimaendringer, kan påvirke Statoils virksomhet.

D.3 Vesentlige risiki knyttet til Risiko knyttet til Aksjene verdipapirene • Prisen på Selskapets Aksjer kan være volatil. • Eksisterende Aksjeeiere er i andre jurisdiksjoner kan ha vanskeligheter med å håndheve erstatningsansvar. • Aksjeeiere kan være ute av stand til å utøve sine stemmerettigheter for Aksjer som er registret på en forvalterkonto.

166

• Overføring av Aksjer er gjenstand for restriksjoner i henhold til verdipapirlovgivning i USA og andre jurisdiksjoner. • Eksisterende Aksjeeiere som ikke velger å motta Utbytteaksjer eller som ikke kan delta i Utbytteemisjonen kan oppleve utvanning av sin aksjebeholdning.

Avsnitt E – Tilbudet

E.1 Nettoproveny og estimerte Dersom Utbytteemisjonen blir fulltegnet, vil nettoproveny være USD kostnader 703 millioner etter fradrag for kostnader og utgifter som Selskapet skal bære, estimert til USD 0.6 millioner.

E.2a Bakgrunnen for Tilbudet Styret vurderer utbyttepolitikken som en viktig forpliktelse overfor og bruk av provenyet Selskapets investorer og vil holde utbyttepolitikken fast. Utbytteaksjeprogrammet forventes å styrke Statoils finansielle robusthet i en situasjon med lave olje- og gasspriser. Dette er et tiltak i tillegg til andre virkemidler slik som streng finansiell disiplin og betydelige effektiviseringstiltak. Videre er Utbytteaksjeprogrammet et verktøy for å styrke Statoils finansielle kapasitet til å kunne investere i lønnsomme prosjekter i en situasjon med lave, variable og usikre priser.

E.3 Vilkår og betingelser for Utbytteemisjonen omfatter opp til 160 000 000 Utbytteaksjer, hver tilbudet med pålydende NOK 2,50. Tegningskursen for Utbytteaksjene, som vil bli gjort opp ved motregning av det Netto Utbyttet aksjeeierne er berettiget til, vil være mellom NOK 50 og NOK 500 per Utbytteaksje. Eksisterende Aksjeeiere har rett til å velge å benytte hele eller deler av det Netto Utbyttet som den Eksisterende Aksjeeieren er berettiget til å motta, til å tegne seg for Utbytteaksjer i Selskapet. Eksisterende Aksjeeieren vil bli tildelt det antall Utbytteaksjer som tilsvarer det beløp hver Eksisterende Aksjeeier har tegnet seg for i løpet av Tegningsperioden, delt på Tegningskursen. Alle tegninger vil bli rundet ned til nærmeste hele aksje. Den del av Netto Utbytte som ikke er benyttet til å tegne aksjer, vil bli utbetalt i kontanter. Eksisterende Aksjeeiere som velger å motta sitt Netto Utbytte i Utbytteaksjer, men hvor Netto Utbyttet ikke overstiger Tegningskursen for én aksje, vil få utbetalt utbyttet i kontanter. Overtegning eller tegning av Utbytteaksjer av andre enn Eksisterende Aksjeeiere er ikke tillatt. For å avgjøre hvem som er berettiget til å delta i Utbytteemisjonen, vil Selskapet utelukkende se hen til aksjeeierregisteret per utløpet av Eierregistreringsdatoen. Det er forventet at Tegningskursen vil bli annonsert omkring 12. september 2016 og Tegningskursen skal tilsvare volumvektet gjennomsnittlig aksjekurs på Oslo Børs de siste to handelsdagene i Tegningsperioden, dvs. 8. og 9. september 2016, fratrukket en rabatt på 5 %. For ADR-holdere skal tegningskursen tilsvare Tegningskursen i NOK omregnet til USD basert på gjennomsnittet av Norges Banks USD valutakurs de siste to dagene i Tegningsperioden, dvs. 8. og 9. september 2016. Innskuddet for Utbytteaksjene vil bli gjort opp ved motregning av kravet på det Netto Utbytte som den Eksisterende Aksjeeieren er berettiget til. Tegningsperioden vil starte 29. august 2016 kl. 09.00 og avsluttes

167

9. september 2016 kl. 23.59, med mindre Tegningsperioden blir forlenget. Eksisterende Aksjeeiere som ikke har tegnet seg for Utbytteaksjer på tidspunktet for utløpet av Tegningsperioden, vil få utbetalt sitt Netto Utbytte i kontanter uten å måtte foreta seg noe, omkring 23. september 2016. Forventet utbetalingsdag for utbytte i USD til ADR-holdere er omkring 26. september 2016. Selskapet forventer at kapitalforhøyelsen vedrørende Utbytteemisjonen vil bli registrert i Foretaksregisteret omkring 22. september 2016 og at Utbytteaksjene vil bli levert til tegnernes VPS- kontoer omkring 23. september 2016. Handel i Utbytteaksjene på Oslo Børs er forventet å starte under ticker "STL" omkring 26. september 2016.

E.4 Vesentlige og Selskapet er ikke kjent med noen vesentlige eller motstridende motstridende interesser interesser hos noen fysiske eller juridiske personer involvert i Utbytteemisjonen.

E.5 Selgende aksjonær og Ikke aktuelt. Alle Utbytteaksjene vil være nyutstedte aksjer og ingen bindingsavtaler tegner vil være underlagt bindingsavtaler.

E.6 Utvanning som følge av Utbytteemisjonen er forventet å resultere i en utvanning på inntil Tilbudet omtrent 1,4 % av Eksisterende Aksjeeiere som ikke deltar i Utbytteemisjonen.

E.7 Estimerte kostnader som Ikke aktuelt. Ingen kostnader vil bli belastet investoren fra vil kreves fra investorene Selskapet.

168 20 DEFINITIONS

ADR American Depositary Receipts ADR Depositary Deutsche Bank Trust Company Americas ADR-holders Holders of ADRs AMF The French Autorité des marchés financiers APA Awards in Predefined Areas bbls Barrels bcm Billion cubic metres Board of Directors The board of directors of Statoil ASA boe Barrels of oil equivalent. A measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the basis of energy content bopd Barrels of oil per day boepd Barrels of oil equivalent per day CEC The corporate executive committee CEO President and Chief Executive Officer CET Central European Time CEST Central European Summer Time CFO Chief financial officer Company Statoil ASA COO Chief operating officer Corporate Assembly The corporate assembly of Statoil ASA CRM Corporate reserves management Deutsche Bank Deutsche Bank Trust Company Americas Dividend Dividend of USD 0.2201 (NOK 1.8255) per Share for the first quarter 2016 Dividend Issue Issue of up to 160,000,000 Dividend Shares in connection with the payment of Dividend under the scrip dividend program Dividend Shares Up to 160,000,000 new Shares in the Company each with a nominal value of NOK 2.50 issued in connection with the Dividend Issue DPI Development and Production International DPN Development and Production Norway DPUSA Development and Production USA DST Drill stem test EBIDTA Earnings before interest, taxes, depreciation and amortization EEA European Economic Area Eni Norge Eni Norge AS Entitlement Production Statoil's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil Equity Production Production that correspond to Statoil's percentage ownership in a particular field EU European Union EU Prospectus Directive Commission Regulation (EC) no. 809/2004 implementing Directive 2003/71/EC of the European Parliament and of the Council of 4 November 2003 regarding information contained in prospectuses, as amended, and as implemented in Norway EUR Euro Existing Shareholders Holders of the Company’s Shares as of expiry of 9 August 2016 as registered with the Company’s shareholder register with the Norwegian Central Securities Depositary (Nw. Verdipapirsentralen) as of expiry of 11 August 2016 EXP Exploration Farmed-in Farm-in is a process whereby a company joins another company or joint venture participating in a block or field. The company farming in is granted a working interest in the field or block in return for cash/or carry through an exploration programme. FCA The UK Financial Conduct Authority FEED Front end engineering design FSMA Financial Services and Markets Act 2000 FIEL Financial Instruments and Exchange Law of Japan Financial Information The Annual Financial Statements and the Interim Financial Information together Financial Statements Statoil's financial statements for the years ended 31 December 2015, 2014 and 2013 Form 20-F Statoil's annual report 2015 on Form 20-F

169 Forward-looking statements Statements that reflect Statoil's current views with respect to possible or assumed future performance, results of operations and cash flows, reserves and growth, and other trends and projections. These forward-looking statements may be identified by the use of forward-looking terminology, such as the terms "anticipates", "assumes", "believes", "can", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "should", "will", "would" or, in each case, their negative, or other variations or comparable terminology. These forward-looking statements are not historic facts. FPSO Floating production, storage and offload vessel GBP British pound sterling GDP Gross domestic product GSB Global Strategy and Business Development HBP Held by production. 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. HGA Host Government Agreement HKO Highest known oil HSE Health, safety and environment HTHP High-temperature/high-pressure IAS International Accounting Standard IEA International Energy Agency Interim Financial Statements The Company's unaudited second quarter 2016 report published on 27 July 2016 and related notes IOR Improved oil recovery. Actual measures resulting in an increased oil recovery factor from a reservoir as compared with the expected value at a certain reference point in time. IOR comprises both of conventional and emerging technologies IOCs International oil companies JOA Joint operation agreement LKH Lowes known hydrocarbons LNG Liquefied natural gas. Lean gas - primarily methane - converted to liquid form through refrigeration to minus 163 degrees celsius under atmospheric pressures LPG Liquefied petroleum gas. Consists primarily of propane and butane, which turn liquid under a pressure of six to seven atmospheres. LPG is shipped in special vessels. LTI long-term incentive mbbl Thousand barrels mboe Thousands of barrels of oil equivalent mmbbl Million barrels mmboe Million barrels of oil equivalent mmBtu One million BTU (British Thermal Unit) Management The executive management of Statoil ASA MMP Marketing, Midstream and Processing MoF Norwegian Ministry of Finance MPE Norwegian Ministry of Petroleum and Energy Natural gas Petroleum that consists principally of light hydrocarbons. It can be divided into 1) lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and 2) wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure NCS Norwegian continental shelf NEA The Norwegian Environment Agency NES New Energy Solutions Net Dividend Dividend with a deduction of any applicable withholding tax NGL Natural gas liquids. Light hydrocarbons mainly consisting of ethane, propane and butane which are liquid under pressure at normal temperature. NOK Norwegian kroner Non-Norwegian Shareholders Shareholders that are not resident in Norway for tax purposes Non-Norwegian Corporate Shareholders Shareholders who are limited liability companies (and certain other entities) not resident in Norway for tax purposes Non-Norwegian Individual Shareholders Shareholders who are individuals not resident in Norway for tax purposes Norwegian Corporate Governance Code Norwegian Code of Practice dated 30 October 2014 Norwegian Corporate Shareholders Shareholders who are limited liability companies (and similar entities) resident in Norway for tax purposes Norwegian FSA Financial Supervisory Authority of Norway Norwegian Individual Shareholders Shareholders who are individuals resident in Norway for tax purposes Norwegian Public Limited Liability The Norwegian Public Limited Liability Companies Act of 13 June 1997 no. 45 (nw: Companies Act Allmennaksjeloven)

170 Norwegian Securities Trading Act The Norwegian Securities Trading Act of 29 June 2007 no. 75 OE Statoil's Organisational Efficiency programme OECD Organisation of Economic Co-Operation and Development OPEC Organisation of the Petroleum Exporting Countries OSPAR The Convention for the Protection of the Marine Environment of the Northeast Atlantic OTC Over the counter NYSE New York Stock Exchange Oil Column The column height of a segment is the vertical distance from the shallowest depth of the structure /reservoir to the oil water contact Oslo Stock Exchange Oslo Børs Owner's Instruction Instruction from the Norwegian State to Statoil setting out specific terms for the marketing and sale of the Norwegian State's oil and gas PA15 Petroleum Act 2015 of Tanzania Payment Date Payment date for the Offer shares PDO Plan for Development and Operations Pollution Act Pollution Control Act of 13 March 1981 no. 6 PRMS Petroleum Resource Management System Prospectus This Prospectus dated 27 August 2016, prepared in connection with the Dividend Issue and listing of the Dividend Shares Prospectus Directive Directive 2003/71/EC of the European Parliament and of the Council of 4 November 2003 (and amendments thereto, including the 2010 PD Amending Directive). Pre-Salt Pre-salt is a generic term that defines all rocks deposited prior to a regional salt layer accumulated during the opening of the South Atlantic Ocean. Some of these deposits contain large amounts of high quality hydrocarbons in a unique carbonate reservoir with excellent properties and very high productivity. The salt that covers this reservoir acts as seal and insulation. PSAs Production sharing agreements PSAN Petroleum Safety Authority Norway RCF The revolving credit facility entered into by Statoil ASA Receiving Agent DNB Bank ASA Record Date 11 August 2016, the date of which showing the Existing Shareholders registered in the Company's shareholder register in the VPS as of the end of 9 August 2016 Regulation S Regulation S under the U.S. Securities Act Relevant Member State Any EEA member state that has implemented the EU Prospectus Directive, other than Norway Rosneft Rosneft Oil Company SCP South Caucasus Pipeline Scrip Dividend Programme The two-year scrip dividend programme in Statoil ASA commencing from the fourth quarter 2015. SDFI The State's direct financial interest SEC U.S. Securities and Exchange Commission SFA The Securities and Futures Act of Singapore Sm3 Standard cubic meters SPE Society of Petroleum Engineering Shares The shares of the Company Statoil Statoil ASA together with its consolidated subsidiaries STEP Statoil's Technical Efficiency program the Storting The Norwegian Parliament Subscription Form Form of Subscription Form attached hereto as Appendix B (English version) and Appendix C (Norwegian version) Subscription Period From 09:00 hours (CEST) on 29 August 2016 to 23:59 hours (CEST) on 9 September 2016, or as otherwise extended by the Company Subscription Price The volume-weighted average share price over the last two trading days on Oslo Stock Exchange of the Subscription Period for the Dividend Issue, with a deduction for a discount of 5% TAP Trans Adriatic Pipeline AG TLP Tension leg platform TPD Technology, Projects and Drilling USD United States Dollar U.S. Securities Act The United States Securities Act of 1933, as amended VPS The Norwegian Central Securities Depositary (Nw. Verdipapirsentralen) VPS account An account held with the VPS Register to register ownership of securities WpPG The German Securities Prospectus Act (Wertpapierprospektgesetz) WTI Western Texas Intermediate

171 APPENDIX A – ARTICLES OF ASSOCIATION

A1 Vedtekter for Statoil ASA

Gjeldende fra 11. mai 2016

§ 1

Selskapets navn er Statoil ASA. Selskapet er et allmennaksjeselskap.

Statoil ASAs virksomhet er å drive undersøkelse etter og utvinning, transport, foredling og markedsføring av petroleum, avledede produkter og andre energiformer, samt annen virksomhet. Virksomheten kan også drives gjennom deltakelse i eller i samarbeid med andre selskaper.

§ 2

Selskapets forretningskontor er i Stavanger kommune.

§ 3

Selskapets aksjekapital er kr 8.017.365.112,50 fordelt på 3.206.946.045 aksjer à kr 2,50.

§ 4

Selskapets styre skal ha 9 - 11 medlemmer. Styrets medlemmer, herunder leder og nestleder, velges av bedriftsforsamlingen. For ansatterepresentantene kan velges varamedlemmer i samsvar med regler gitt i eller i medhold av allmennaksjeloven. Styrets medlemmer velges for inntil to år.

§ 5

Selskapets firma tegnes av styreleder alene, konsernsjef alene eller to styremedlemmer i fellesskap. Styret kan meddele prokura.

§ 6

Styret ansetter selskapets konsernsjef og fastsetter dennes lønn.

§ 7

Selskapet skal ha en bedriftsforsamling på 18 medlemmer samt varamedlemmer. 12 medlemmer og fire varamedlemmer for disse velges av generalforsamlingen. Seks medlemmer og tilhørende

A2 varamedlemmer for disse velges av og blant selskapets ansatte i samsvar med regler gitt i eller i medhold av allmennaksjeloven. Bedriftsforsamlingen velger en leder og en nestleder blant sine medlemmer. Bedriftsforsamlingen møtes minst to ganger om året.

§ 8

Ordinær generalforsamling holdes hvert år innen utgangen av juni måned. Generalforsamlinger holdes i Stavanger kommune eller Oslo kommune.

§ 9

Dokumenter som gjelder saker som skal behandles i selskapets generalforsamling, derunder dokumenter som etter lov skal inntas i eller vedlegges innkallingen til generalforsamlingen, trenger ikke sendes til aksjeeierne dersom dokumentene er tilgjengelige på selskapets hjemmeside. En aksjeeier kan likevel kreve å få tilsendt dokumenter som gjelder saker som skal behandles i generalforsamlingen.

I den ordinære generalforsamling skal følgende spørsmål behandles og avgjøres:

1. Godkjennelse av årsregnskap og årsberetning, herunder utdeling av utbytte.

2. Andre saker som etter lov eller vedtekter hører under generalforsamlingen.

Aksjeeiere kan avgi sin stemme skriftlig, herunder ved bruk av elektronisk kommunikasjon, i en periode før generalforsamlingen. Styret kan fastsette nærmere retningslinjer for slik forhåndsstemming. Det skal fremgå av generalforsamlingsinnkallingen hvilke retningslinjer som er fastsatt.

§ 10

Selskapet skal forestå avsetningen av statens petroleum som produseres fra statens deltagerandeler i utvinningstillatelser på norsk kontinental sokkel (SDØE), samt petroleum som erlegges som produksjonsavgift i henhold til lov om petroleumsvirksomhet av 29. november 1996 nr. 72. Selskapets generalforsamling kan med alminnelig flertall fastsette instruks for avsetningen.

§ 11

Valgkomiteens oppgaver er å avgi innstilling til

1. generalforsamlingen om valg av aksjonærvalgte medlemmer og varamedlemmer av bedriftsforsamlingen og honorar til medlemmer av bedriftsforsamlingen;

2. generalforsamlingen om valg av og honorar til medlemmer av valgkomiteen;

A3 3. bedriftsforsamlingen om valg av aksjonærvalgte medlemmer til styret og honorar til medlemmer av styret; og

4. bedriftsforsamlingen om valg av leder og nestleder for bedriftsforsamlingen.

Styrets leder og konsernsjef skal, uten å ha stemmerett, innkalles til minst ett møte i valgkomiteen før den avgir sin endelige innstilling. Valgkomiteen består av fire medlemmer som skal være aksjeeiere eller representanter for aksjeeiere og som skal være uavhengige av styret og den daglige ledelse. Valgkomiteens medlemmer, herunder dens leder, velges av generalforsamlingen. Valgkomiteens leder og ett annet medlem skal velges blant bedriftsforsamlingens aksjonærvalgte medlemmer. Valgkomiteens medlemmer velges normalt for to år. Personlige varamedlemmer for ett eller flere av valgkomiteens medlemmer kan velges etter de samme kriterier som beskrevet ovenfor. Et varamedlem møter kun for medlemmet dersom medlemmets verv opphører før funksjonstiden er ute.

Dersom vervet for et medlem av valgkomiteen opphører før funksjonstiden er ute, kan valg av nytt medlem utstå til neste ordinære generalforsamling. Dersom medlemmet har personlig varamedlem, vil vedkommende varamedlem fungere som medlem av valgkomiteen frem til nytt valg er avholdt. Dersom leders verv opphører før funksjonstiden er ute velger komiteen blant sine medlemmer en ny leder som fungerer til neste generalforsamling.

Generalforsamlingen fastsetter godtgjørelse til valgkomiteens medlemmer. Valgkomiteens kostnader bæres av selskapet. Generalforsamlingen kan vedta instruks for valgkomiteen.

A4 APPENDIX B – SUBSCRIPTION FORM IN ENGLISH

B1 STATOIL ASA SUBSCRIPTION FORM DIVIDEND ISSUE Securities no. ISIN NO 0010096985

General information: This Subscription Form is to be completed and submitted by shareholders of Statoil ASA ("Statoil" or the "Company") located in, or resident of, Norway wishing to receive Dividend Shares (as defined below) in lieu of a cash dividend in whole or in part for the first quarter 2016 dividend, pursuant to the terms and conditions of the scrip dividend program (the “Dividend Issue”) as resolved by the Board of Directors on 26 July 2016 in accordance with the authorisations approved by the ordinary general meeting of the Company on 11 May 2016 and as outlined in the prospectus dated 27 August 2016 (the "Prospectus") prepared by Statoil. The Prospectus contains a Norwegian summary. The notice of, and minutes from, the ordinary general meeting of 11 May 2016 (with appendices), the Company’s articles of association and annual accounts and annual reports for the last two years are available on the Company’s website www.statoil.com. The resolution to increase the share capital by the Board of Directors in accordance with the authorisations resolved by the ordinary general meeting on 11 May 2016 may be found in the Prospectus which can be found at www.statoil.com/scrip. All announcements referred to in this Subscription Form will be made through Oslo Børs’ information system under the Company’s ticker “STL”. Subscription procedures: The subscription period will commence on 09:00 hours CEST on 29 August 2016 and end on 9 Sepember 2016 at 23:59 hours (CEST) (the “Subscription Period”). Shareholders which Statoil considers eligible to subscribe for shares under the Dividend Issue (the “Dividend Shares") have received a letter with a reference number and a password, and are encouraged to subscribe for Dividend Shares through the VPS online subscription system by following the link on www.statoil.com/scrip. Subscriptions in the Dividend Issue may also be made by using this Subscription Form which is attached to the Prospectus as Appendix B (Subscription form in Norwegian) and Appendix C (Subscription form). Correctly completed subscription forms must be received before expiry of the subscription period by DNB Bank ASA, DNB Markets, Registrars Department, P.O. Box 1600 Sentrum, N-0021 Oslo, Norway (the ” Receiving Agent”). The subscriber is responsible for the correctness of the information filled in on the subscription form. Subscription Forms that are incomplete or incorrectly completed, or which are received following expiry of the Subscription Period or any subscription that may be unlawful may be disregarded at the sole discretion of the Company and/or the Receiving Agent without notice to the subscriber. Subscriptions made through the VPS online subscription system must be duly registered and subscriptions made on subscription forms must be duly received by the Receiving Agent by 9 September 2016 at 23:59 hours (CEST), unless the Subscription Period is extended. Neither the Company nor the Receiving Agent may be held responsible for postal delays, unavailable fax lines, internet lines or servers or any other logistical or technical problems that may result in subscriptions not being received in time or at all. Subscriptions made by submitting the Subscription Form to the Receiving Agent are binding and irrevocable, and cannot be withdrawn, cancelled or modified by the subscriber after having been received by the Receiving Agent. Subscriptions made electronically through the VPS online subscription system may be changed or cancelled by the subscriber up to the expiry of the Subscription Period. If a subscriber makes a subscription for Dividend Shares both through the VPS online subscription system and by submitting the Subscription Form, the electronic subscription will prevail regardless of which subscription was made last. Subscription price: For shareholders on Oslo Børs the subscription price shall be set to the volume-weighted average share price on Oslo Børs of the last two trading days of the subscription period for the dividend issue, with a deduction for a discount of 5%. The subscription price may not be lower than NOK 50 or higher than NOK 500 per share. Right to Dividend Shares: Shareholders as of expiry of 9 August 2016, i.e. shareholders who are registered in the Company’s shareholder register in the VPS as of expiry of 11 August 2016 (the “Existing Shareholders”) will be entitled to choose to use their Net Dividend for the first quarter of 2016, in whole or in part, to subscribe for Dividend Shares in the Company. The Dividend Shares may not be subscribed by shareholders located in, or resident of, jurisdictions in which the Dividend Issue would be unlawful subject to the applicable laws. Oversubscription or subscription of Dividend Shares by other than Existing Shareholders is not permitted. Any part of the Net Dividend not used for subscription of Dividend Shares, will be paid in cash. Existing Shareholders who have not subscribed for Dividend Shares at the time of expiry of the Subscription Period will be paid their Net Dividend amount in cash without any action on their part. Allocation of Dividend Shares: Allocation of the Dividend Shares will take place on or about 23 September 2016 and the Existing Shareholders will be allocated the number of Dividend Shares equal to the amount each Existing Shareholder has subscribed for during the Subscription Period, divided by the Subscription Price. No fractional Dividend Shares will be allocated. Notification of allocated Dividend Shares is expected to be distributed in a letter from the VPS Investor Service on or about 23 September 2016. At the same time, shareholders who have access to VPS investor services will be able to see how many Dividend Shares they have been allocated. Settlement: By registering a subscription in the VPS online subscription system or by signing and submitting a Subscription Form, the subscriber declares that the Subscription Price for the Dividend Shares will be settled by way of set-off against the Net Dividend that the subscriber is entitled to according to the resolution by the Board of Directors of 26 April 2016 regarding distribution of a dividend of USD 0.2201 per share for the first quarter of 2016. All subscriptions will be rounded down to the nearest whole number of shares. Any part of the Net Dividend not used for subscription of Dividend Shares, will be paid in cash.

PLEASE SEE PAGE 2 OF THIS SUBSCRIPTION FORM FOR OTHER PROVISIONS THAT ALSO APPLY TO THE SUBSCRIPTION

DETAILS OF THE SUBSCRIPTION Subscriber’s VPS account: I/we hereby subscribe for Dividend Shares for:

my total Net Dividend amount for the first quarter 2016

part of my Net Dividend amount, total NOK: ______

I/we hereby irrevocably (i) subscribe for the number of Dividend Shares corresponding to the amount set out above subject to the terms and conditions set out in this Subscription Form and in the Prospectus, (ii) authorise and instruct the Receiving Agent to take all actions required to effectuate the transactions contemplated by this Subscription Form and ensure delivery of the Dividend Shares to me/us in the VPS on my/our behalf (iii) declare that the Subscription Price for the Dividend Shares shall be settled by way of set-off against the Net Dividend from the Company which I/we am/are entitled to according to the resolution by the Board of Directors of 26 April 2016 regarding distribution of a dividend of USD 0.2201 per share for the first quarter of 2016, (iv) confirm and warrant to have read the Prospectus and that I/we am/are eligible to subscribe for Dividend Shares under the terms and conditions set forth therein.

Place and date Binding signature must be dated in the Subscription Period. The subscriber must have legal capacity. When signed on behalf of a company or pursuant to an authorisation, documentation in the form of a company certificate or power of attorney must be enclosed. INFORMATION ON THE SUBSCRIBER – ALL FIELDS MUST BE COMPLETED First name

Surname/Company name Street address

Post code (ZIP code)/District (State)/ Country Personal ID number/ (Social Security Number)/Organization number Nationality/State or Country of Incorporation E-mail address

Daytime telephone number

B2 ADDITIONAL GUIDELINES FOR THE SUBSCRIBER

Regulatory issues: In accordance with the Markets in Financial Instruments Directive (“MiFID”) of the European Union, Norwegian law imposes requirements in relation to business investments. In this respect, the Receiving Agent must categorize all new clients in one of three categories: eligible counterparties, professional clients and non- professional clients. All subscribers in the Dividend Issue who are not existing clients of the Receiving Agent will be categorized as non-professional clients. Subscribers can, by written request to the Receiving Agent, ask to be categorized as a professional client if the subscriber fulfils the applicable requirements of the Norwegian Securities Trading Act. For further information about the categorization, the subscriber may contact the Receiving Agent. The subscriber represents that he/she/it is capable of evaluating the merits and risks of a decision to invest in the Company by subscribing for Dividend Shares, and is able to bear the economic risk, and to withstand a complete loss, of an investment in the Dividend Shares.

Selling Restrictions: The distribution of Dividend Shares to Existing Shareholders located in, or resident of, countries other than Norway, may be affected by the laws of the relevant jurisdiction. A description of certain restrictions in relation to the Dividend Shares in certain jurisdictions is set out in Section 16 "Selling and transfer restrictions" in the Prospectus. The information set out in the Prospectus is intended as a general guide only. If you are in any doubt about any of the contents of these restrictions, or whether any of these restrictions apply to you, you should obtain independent professional advice without delay.

If an Existing Shareholder subscribes for Dividend Shares and unless the Company in its sole discretion determines otherwise on a case-by-case basis, that Existing Shareholder will be deemed to have made or, in some cases, be required to make, the following representations and warranties to the Company and any person acting on the Company's or its behalf: a) the Existing Shareholder is not restricted from receiving Dividend Shares pursuant to the Terms and Conditions and the regulatory and legal requirements of any applicable foreign jurisdiction; and b) the Existing Shareholder is not acting, and has not acted, for the account or benefit of a person to which the Dividend Issue cannot be lawfully made.

The Company and its affiliates and others will rely upon the truth and accuracy of the above acknowledgements, agreements and representations and agrees that, if any of the acknowledgements, agreements or representations deemed to have been made by its subscription of Dividend Shares is no longer accurate, it will promptly notify the Company. Any provision of false information or subsequent breach of these representations and warranties may subject the Existing Shareholder to liability.

Notwithstanding any other provision of this document or of the Prospectus, the Company reserves the right to permit an Existing Shareholder to subscribe for Dividend Shares if the Company, in its absolute discretion, is satisfied that the Existing Shareholder in question is exempt from or not subject to the laws or regulations giving rise to restrictions on the ability to subscribe for Dividend Shares. In any such case, the Company does not accept any liability for any actions that an Existing Shareholder takes or for any consequences that it may suffer as a result of the Company accepting the Existing Shareholder’s subscription of Dividend Shares.

Neither the Company nor its representatives, is making any representation to any subscriber of Dividend Shares regarding the legality of an investment in the Dividend Shares by such subscriber under the laws applicable to such subscriber. Each Existing Shareholder should consult its own advisors before subscribing for Dividend Shares.

Execution Only: The Receiving Agent will treat the Subscription Form as an execution-only instruction. The Receiving Agent is not required to determine whether an investment in the Dividend Shares is appropriate or not for the subscriber. Hence, the subscriber will not benefit from the protection of the relevant conduct of business rules in accordance with the Norwegian Securities Trading Act.

B3 APPENDIX C – SUBSCRIPTION FORM IN NORWEGIAN

C1 STATOIL ASA TEGNINGSBLANKETT UTBYTTEMISJON ISIN NO 0010096985

Generell informasjon: Denne Tegningsblanketten skal fylles ut og sendes inn av aksjonærer i Statoil ASA ("Statoil" eller "Selskapet") som befinner seg i eller er bosatt i Norge og som ønsker å motta Utbytteaksjer (som definert nedenfor) helt eller delvis i stedet for kontantutbytte for første kvartal 2016 i henhold til vilkårene og betingelsene for utbytteaksjeprogrammet ("Utbytteemisjonen") som vedtatt av styret den 26. juli 2016 i henhold til fullmakt gitt av den ordinære generalforsamlingen i Selskapet 11. mai 2016 og som fremgår av prospektet datert 27. august 2016 (“Prospektet”), som er utarbeidet av Statoil. Prospektet inneholder også et norsk sammendrag. Innkallingen til og protokollen fra den ordinære generalforsamlingen avholdt 11. mai 2016, Selskapets vedtekter, samt årsregnskap og årsberetning for de to siste årene er tilgjengelige på Selskapets hjemmeside, www.statoil.com. Styrets vedtak om å forhøye aksjekapitalen i henhold til fullmaktene gitt på den ordinære generalforsamlingen 11. mai 2016 er inkludert i Prospektet som kan finnes på www.statoil.com/scrip. Alle offentliggjøringer som refereres til i denne tegningsblanketten vil skje gjennom Oslo Børs' informasjonssystem under Selskapets ticker "STL". Tegningsprosedyre: Tegningsperioden er fra kl. 09.00 norsk tid den 29. august 2016 til kl. 23:59 norsk tid den 9. september 2016 (“Tegningsperioden”). Aksjonærer Statoil anser for å ha rett til å tegne aksjer i Utbytteemisjonen ("Utbytteaksjer") har fått tilsendt et brev med referansenummer og passord, og anbefales å foreta tegning av Utbytteaksjer gjennom VPS’ online tegningssystem ved å følge linken på www.statoil.com/utbytteaksje. Tegninger i Utbyttemisjonen kan også foretas ved å bruke denne Tegningsblanketten som også er vedlagt Prospektet som Appendix B (Subscription form in Norwegian) eller Appendix C (Subscription form). Korrekt utfylt tegningsblankett må være mottatt før utløpet av Tegningsperioden av DNB Bank ASA, DNB Markets, Verdipapirservice, Postboks 1600 Sentrum, N- 0021 Oslo, Norge ("Oppgjørsansvarlig"). Tegneren er ansvarlig for riktigheten av informasjonen som er fylt inn i tegningsblanketten. Tegningsblanketter som er ufullstendige eller uriktig utfylt eller som mottas etter utløpet av Tegningsperioden, og enhver tegning som kan være ulovlig, kan bli avvist av Selskapet og/eller Oppgjørsansvarlig uten nærmere varsel. Tegninger som gjøres gjennom VPS’ online tegningssystem må være registrert, og tegninger som gjøres på tegningsblanketter må være mottatt av Oppgjørsansvarlig, innen kl. 23:59 norsk tid den 9. september 2016, med mindre Tegningsperioden forlenges. Verken Selskapet eller Oppgjørsansvarlig kan holdes ansvarlig for forsinkelser i postgang, utilgjengelige fakslinjer, internettlinjer eller servere eller andre logistikkproblemer eller tekniske problemer som kan resultere i at tegninger ikke blir mottatt i tide eller i det hele tatt. Tegninger som er gjort ved innsending av tegningsblanketten til Oppgjørsansvarlig er bindende og ugjenkallelige, og kan ikke trekkes, kanselleres eller endres av tegneren etter at tegningen er mottatt av Oppgjørsansvarlig. Tegninger som er gjort elektronisk gjennom VPS’ online tegningssystem kan endres eller kanselleres frem til utløpet av Tegningsperioden. Dersom tegneren tegner seg for Utbytteaksjer både via VPS' online tegningssystem og ved innsending av tegningsblanketten, vil det være den elektroniske tegningen som gjelder uavhengig av hvilken tegning som ble gjort sist. Tegningskurs: For aksjonærer på Oslo Børs skal tegningskursen fastsettes til et beløp som tilsvarer volumvektet gjennomsnittlig aksjekurs på Oslo Børs de siste to handelsdagene i tegningsperioden for utbytteemisjonen, fratrukket en rabatt på 5 %. Tegningskursen kan likevel ikke være lavere enn NOK 50 eller høyere enn NOK 500 per aksje. Rett til utbytteaksjer: Aksjeeiere per utløpet av 9. august 2016, det vil si aksjeeiere som er registrert i Statoils aksjeeierregister i Verdipapirsentralen (VPS) per utløpet av 11. august 2016 ("Eksisterende Aksjeeiere") vil være berettiget til å velge å benytte hele eller deler av sitt Netto Utbytte for første kvartal 2016 til å tegne Utbytteaksjer i Selskapet. Utbytteaksjene kan ikke tegnes av aksjeeiere som befinner seg i eller som er bosatt i jurisdiksjoner hvor Utbytteemisjonen vil være ulovlig i henhold til gjeldende rett. Overtegning eller tegning av Utbytteaksjer av andre enn Eksisterende Aksjeeiere er ikke tillatt. Den del av det Netto Utbyttet som ikke er benyttet til å tegne aksjer, vil bli utbetalt i kontanter. Aksjeeiere som har tegnet seg for Utbytteaksjer, men hvor Netto Utbytte ikke overstiger tegningskursen for én aksje, vil få utbetalt utbyttet i kontanter. Aksjeeiere som ikke har tegnet seg for utbytteaksjer på tidspunktet for utløpet av tegningsperioden, vil få utbetalt sitt Netto Utbytte i kontanter uten å måtte foreta seg noe. Tildeling av Utbytteaksjer: Tildeling av Utbytteaksjer vil skje omkring 23. september 2016 og hver Eksisterende Aksjeeier vil bli allokert det antall aksjer som fremkommer ved å dele det beløp vedkommende har tegnet seg for i Tegningsperioden på tegningskursen. Ingen brøkdelsaksjer vil bli allokert. Underretning om antall tildelte Utbytteaksjer er forventet å bli distribuert per post fra VPS Investorservice omkring 23. september 2016. Samtidig vil aksjeeiere med tilgang til VPS Investorservice kunne se hvor mange Utbytteaksjer de har blitt tildelt. Oppgjør: Ved å registrere en tegning via VPS’ online tegningssystem eller ved å signere og sende inn en tegningsblankett erklærer tegneren at tegningskursen for Utbytteaksjene kan gjøres opp ved motregning mot hele eller deler av det Netto Utbyttet som tegneren er berettiget til i henhold til styrets beslutning 26. april 2016 om utdeling av utbytte for første kvartal 2016 på USD 0,2201 per aksje. Alle tegninger vil bli rundet ned til nærmeste hele aksje. Den del av det Netto Utbyttet som ikke er benyttet til å tegne aksjer, vil bli utbetalt i kontanter.

VENNLIGST SE SIDE 2 AV TEGNINGSBLANKETTEN FOR YTTERLIGERE VILKÅR SOM GJELDER FOR TEGNINGEN

DETALJER OM TEGNINGEN Tegnerens VPS-konto: Jeg/vi tegner herved Utbytteaksjer for:

hele mitt Netto Utbytte for første kvartal 2016

deler av mitt Netto Utbytte, totalt NOK: ______

Herved (i) foretar jeg/vi, i henhold til vilkårene og betingelsene som fremgår av denne tegningsblanketten og av Prospektet, en ugjenkallelig tegning av det antall Utbytteaksjer tilsvarende beløpet angitt overfor, (ii) gir jeg/vi Oppgjørsansvarlig ugjenkallelig fullmakt til å gjennomføre enhver handling som er nødvendig for å effektuere transaksjonen som fremgår av denne tegningsblanketten, og sikre levering av Utbytteaksjene i VPS på mine/våre vegne, (iii) erklærer jeg/vi at tegningskursen for Utbytteaksjene skal gjøres opp ved motregning av mitt/vårt krav på Netto Utbytte fra Selskapet som jeg/vi er berettiget til i henhold til styrets beslutning 26. april 2016 om utdeling av utbytte for første kvartal 2016 på USD 0,2201 per aksje, og (iv) bekrefter og garanterer jeg/vi ugjenkallelig å ha lest Prospektet og at jeg/vi er kvalifiserte til å tegne Utbytteaksjer på de vilkår som der fremgår.

Dato og sted Bindende signatur Må være datert i Tegningsperioden Undertegneren må være myndig. Dersom tegningsblanketten undertegnes på vegne av Tegneren, må det vedlegges dokumentasjon i form av firmaattest eller fullmakt for at undertegner har slik kompetanse. INFORMASJON OM TEGNEREN – ALLE FELTER MÅ FYLLES UT Fornavn

Etternavn/Foretaksnavn

Adresse (for foretak: registrert forretningsadresse) Postnummer og sted

Fødselsnummer (11 siffer) / organisasjonsnummer (9 siffer) Nasjonalitet

E-postadresse

Telefonnummer (dagtid)

C2 RETNINGSLINJER FOR TEGNEREN

Regulatoriske spørsmål: I overensstemmelse med EU-direktivet “Markets in Financial Instruments” (“MiFID”), oppstiller lov 29. juni 2007 nr. 75 om verdipapirhandel (“Verdipapirhandelloven”) med tilhørende forskrifter, krav relatert til finansielle investeringer. I den forbindelse må Oppgjørsansvarlig kategorisere alle nye kunder i en av tre kategorier; kvalifiserte motparter, profesjonelle og ikke-profesjonelle kunder. Alle tegnere som tegner Utbytteaksjer i Utbytteemisjonen og som ikke allerede er kunde hos Oppgjørsansvarlig, vil bli kategorisert som ikke-profesjonell kunde. Tegneren kan ved skriftlig henvendelse til Oppgjørsansvarlig anmode om å bli kategorisert som profesjonell kunde dersom Verdipapirhandellovens vilkår for dette er oppfylt. For ytterligere informasjon om kundekategorisering kan tegneren kontakte Oppgjørsansvarlig. Tegneren bekrefter herved å inneha tilstrekkelig kunnskap og erfaring om finansielle og forretningsmessige forhold for å kunne evaluere risikoen ved å investere i Selskapet gjennom å tegne Utbytteaksjer, og tegneren bekrefter å være i stand til å ta den økonomiske risikoen og tåle et fullstendig tap av sin investering i Selskapet.

Restriksjoner på salg og overdragelse: Tildeling av Utbytteaksjer til personer som befinner seg i eller som er bosatt i et annet land enn Norge, kan bli påvirket av lovgivningen i den relevante jurisdiksjonen. Kapittel 16 "Selling and transfer restrictions" i Prospektet inneholder en beskrivelse av begrensninger i enkelte jurisdiksjoner i forbindelse med Utbytteaksjene. Beskrivelsen i Prospektet har bare til hensikt å gi generell veiledning. Dersom du er i tvil om innholdet i disse begrensningene, eller om noen av disse begrensningene gjelder for deg, bør du søke uavhengig, profesjonell rådgivning umiddelbart.

Dersom en Eksisterende Aksjeeier tegner seg for Utbytteaksjer, og med mindre Selskapet etter eget skjønn beslutter noe annet fra sak til sak, anses den Eksisterende Aksjeeieren for å ha gitt, og i noen tilfeller for å være påkrevd å gi, følgende bekreftelser og garantier til Selskapet og enhver person som handler på Selskapets vegne: a) den Eksisterende Aksjeeieren er ikke avskåret fra å motta Utbytteaksjer i henhold til de vilkår og betingelser som gjelder for Utbytteemisjonen og etter de regulatoriske og lovbestemte krav som følger av lovgivningen i den aktuelle jurisdiksjonen; og b) den Eksisterende Aksjeeieren handler ikke, og har ikke handlet, på vegne av eller for regningen til en person som ikke lovlig kan delta i Utbytteemisjonen.

Selskapet og dets tilknyttede selskaper og andre vil belage seg på at de overnevnte bekreftelser og garantier er sanne og korrekte. Tegneren samtykker i dersom noen av bekreftelsene eller garantiene som er gjort i forbindelse med tegningen av Utbytteaksjer ikke lenger er korrekte, skal tegneren snarest varsle Selskapet. Å gi falsk informasjon eller etterfølgende brudd på disse bekreftelsene og garantiene kan medføre ansvar for den Eksisterende Aksjeeieren.

Dersom en person som handler på vegne av en aksjeeier (inkludert, men ikke begrenset til, i egenskap av å være forvalter), skal vedkommende avgi de overnevnte bekreftelser og garantier til Selskapet med hensyn til tegning av Utbytteaksjer på vegne av aksjeeieren. Dersom vedkommende ikke kan eller er ute av stand til å gi de overnevnte bekreftelser og garantier, vil Selskapet ikke være bundet til å akseptere tegningen av eller å autorisere tildeling av Utbytteaksjer til vedkommende eller til personen som den andre handler på vegne av. Dersom en aksjeeier (inkludert, men ikke begrenset til, dens forvalter) befinner seg utenfor Norge og ønsker å tegne seg for Utbytteaksjer, må aksjeeieren tilfredsstille og overholde gjeldende lovgivning i den aktuelle jurisdiksjonen, inkludert å få enhver nødvendig myndighetsgodkjennelse eller annet samtykke, tilfredsstille andre formalitetskrav og betale alle skatter og avgifter som gjelder i slike jurisdiksjoner.

Selskapet forbeholder seg retten til å avvise enhver tegning (eller annullering av slik tegning) foretatt en av en person som oppgir en adresse i en jurisdiksjon hvor Utbytteemisjonen ikke lovlig kan rettes, eller som ikke er i stand til å bekrefte eller garantere at vedkommende ikke befinner seg i eller er bosatt i en slik jurisdiksjon. Selskapet forbeholder seg videre retten til, etter eget skjønn, å anse enhver tegning av Utbytteaksjer som tilsynelatende har blitt utført, effektuert eller ekspedert på en måte som kan innebære et brudd på lover eller forskrifter i en jurisdiksjon for ugyldig.

Til tross for andre bestemmelser i dette dokumentet eller i Prospektet, forbeholder Selskapet seg retten til å tillate at en Eksisterende Aksjeeier tegner seg for Utbytteaksjer i Selskapet, dersom Selskapet, etter sitt eget skjønn, finner at den aktuelle Eksisterende Aksjeeieren er unntatt fra eller ikke underlagt lover eller forskrifter som pålegger begrensninger på adgangen til å tegne Utbytteaksjer. Selskapet påtar seg ikke noe ansvar for handlinger foretatt av en Eksisterende Aksjeeier eller for noen konsekvenser som vedkommende blir utsatt for som en følge av at Selskapet aksepterer den Eksisterende Aksjeeieren tegning av Ubytteaksjer.

Verken Selskapet eller dets representanter, gir en forsikring til tegnere av Utbytteaksjer vedrørende lovligheten av vedkommende tegners investering i Utbytteaksjene etter den anvendelige lovgivningen for vedkommende tegner. Enhver Eksisterende Aksjeeier bør konsultere sine egne rådgivere før tegning av Utbytteaksjer.

Kun utførelse: Oppgjørsansvarlig vil kun behandle tegningsblanketten som en instruksjon om å gjennomføre tegningen. Oppgjørsansvarlig er ikke forpliktet til å vurdere om tegneren bør investere i Utbytteaksjene eller ikke. Tegneren vil følgelig ikke dra fordeler av den beskyttelse som gis i de relevante regler som fremgår av den norske Verdipapirhandelloven.

C3 REGISTERED OFFICE

Statoil ASA Forusbeen 50 4035 Stavanger NORWAY

RECEIVING AGENT

DNB Bank ASA DNB Markets, Registrars Department P.O. Box 1600 Sentrum N-0021 Oslo NORWAY